[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 [www.gpo.gov]
[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:
     Federal eRulemaking Portal: https://www.regulations.gov 
(our preferred method). Follow the online instructions for submitting 
comments.
     Email: [email protected]. Include Docket ID No. EPA-
HQ-OAR-2023-0072 in the subject line of the message.
     Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2023-0072.
     Mail: U.S. Environmental Protection Agency, EPA Docket 
Center, Docket ID No. EPA-HQ-OAR-2023-0072, Mail Code 28221T, 1200 
Pennsylvania Avenue NW, Washington, DC 20460.
     Hand/Courier Delivery: EPA Docket Center, WJC West 
Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004. 
The Docket Center's hours of operation are 8:30 a.m.-4:30 p.m., Monday-
Friday (except Federal holidays).
    Instructions: All submissions received must include the Docket ID 
No. for this rulemaking. Comments received may be posted without change 
to https://www.regulations.gov, including any personal information 
provided. For detailed instructions on sending comments and additional 
information on the rulemaking process, see the SUPPLEMENTARY 
INFORMATION section of this document.

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

SUPPLEMENTARY INFORMATION: 
    Participation in virtual public hearing. The public hearing will be 
held via virtual platform on June 13, 2023 and June 14, 2023 and will 
convene at 11:00 a.m. Eastern Time (ET) and conclude at 7:00 p.m. ET 
each day. If the EPA receives a high volume of registrations for the 
public hearing, the EPA may continue the public hearing on June 15, 
2023. On each hearing day, the EPA may close a session 15 minutes after 
the last pre-registered speaker has testified if there are no 
additional speakers. The EPA will announce further details at https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.
    The EPA will begin pre-registering speakers for the hearing no 
later than 1 business day following the publication of this document in 
the Federal Register. The EPA will accept registrations on an 
individual basis. To register to speak at the virtual hearing, please 
use the online registration form available at https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power or contact the public hearing team 
at (888) 372-8699 or by email at [email protected]. The last 
day to pre-register to speak at the hearing will be June 6, 2023. Prior 
to the hearing, the EPA will post a general agenda that will list pre-
registered speakers in approximate order at: https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.
    The EPA will make every effort to follow the schedule as closely as 
possible on the day of the hearing; however, please plan for the 
hearings to run either ahead of schedule or behind schedule.
    Each commenter will have 4 minutes to provide oral testimony. The 
EPA encourages commenters to provide the EPA with a copy of their oral 
testimony by submitting the text of your oral testimony as written 
comments to the rulemaking docket.
    The EPA may ask clarifying questions during the oral presentations 
but will not respond to the presentations at that time. Written 
statements and supporting information submitted during the comment 
period will be considered with the same weight as oral testimony and 
supporting information presented at the public hearing.
    Please note that any updates made to any aspect of the hearing will 
be posted online at https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power. While the EPA expects the hearing to go forward as described in 
this section, please monitor our website or contact the public hearing 
team at (888) 372-8699 or by email at [email protected] 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 Regulations.gov index. Although listed in the index, 
some information is not publicly available, e.g., Confidential Business 
Information (CBI) or other information whose disclosure is restricted 
by statute. Certain other material, such as copyrighted material, is 
not placed on the internet and will be publicly available only in hard 
copy.
    Written Comments. Direct your comments to Docket ID No. EPA-HQ-OAR-
2023-0072 at https://www.regulations.gov (our preferred method), or the 
other methods identified in the ADDRESSES section. Once submitted, 
comments cannot be edited or removed from the docket. The EPA may 
publish any comment received to its public docket. Do not submit to the 
EPA's docket at https://www.regulations.gov any information you 
consider to be Confidential Business Information (CBI) or other 
information whose disclosure is restricted by statute. This type of 
information should be submitted as discussed in the Submitting CBI 
section of this document.
    Multimedia submissions (audio, video, etc.) must be accompanied by 
a written comment. The written comment is considered the official 
comment and should include discussion of all points you wish to make. 
The EPA will generally not consider comments or comment contents 
located outside of the primary submission (i.e., on the Web, cloud, or 
other file sharing system). Please visit https://www.epa.gov/dockets/commenting-epa-dockets for additional submission methods; the full EPA 
public comment policy; information about CBI or multimedia submissions; 
and general guidance on making effective comments.
    The https://www.regulations.gov website allows you to submit your 
comment anonymously, which means the EPA will not know your identity or 
contact information unless you provide it in the body of your comment. 
If you send an email comment directly to the EPA without going through 
https://www.regulations.gov, your email address will be automatically 
captured and included as part of the comment that is placed in the 
public docket and made available on the internet. If you submit an 
electronic comment, the EPA recommends that you include your name and 
other contact information in the body of your comment and with any 
digital storage media you submit. If the EPA cannot read your comment 
due to technical difficulties and cannot contact you for clarification, 
the EPA may not be able to consider your comment. Electronic files 
should not include special characters or any form of encryption and 
should be free of any defects or viruses.
    Submitting CBI. Do not submit information containing CBI to the EPA 
through https://www.regulations.gov. Clearly mark the part or all of 
the information that you claim to be CBI. For CBI information on any 
digital storage media that you mail to the EPA, note the docket ID, 
mark the outside of the digital storage media as CBI, and identify 
electronically within the digital storage media the specific 
information that is claimed as CBI. In addition to one complete version 
of the comments that includes information claimed as CBI, you must 
submit a copy of the comments that does not contain the information 
claimed as CBI directly to the public docket through the procedures 
outlined in Written Comments section of this document. If you submit 
any digital storage media that does not contain CBI, mark the outside 
of the digital storage media clearly that it does not contain CBI and 
note the docket ID. Information not marked as CBI will be included in 
the public docket and the EPA's electronic public docket without prior 
notice. Information marked as CBI will not be disclosed except in 
accordance with procedures set forth in 40 Code of Federal Regulations 
(CFR) part 2.
    Our preferred method to receive CBI is for it to be transmitted 
electronically using email attachments, File Transfer Protocol (FTP), 
or other online file sharing services (e.g., Dropbox, OneDrive, Google 
Drive). Electronic submissions must be transmitted directly to the 
OAQPS CBI Office at the email address [email protected] 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 [email protected] 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
CO2 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 CO2e 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
NOX 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

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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\ https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions.
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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 CO2/MMBtu 
to 160 lb CO2/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.
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    \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 CO2/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 CO2 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 
CO2/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 
CO2/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 
CO2/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 CO2/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 CO2 with 
an associated standard of 90 lb CO2/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 CO2/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 CO2/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 CO2. 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 CO2 with an associated degree of emission 
limitation of an 88.4 percent reduction in emission rate (lb 
CO2/MWh-gross basis). As explained in detail in this 
proposal, CCS with 90 percent capture of CO2 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 CO2/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 CO2/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 CO2/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 CO2; 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\ https://www.congress.gov/bill/117th-congress/house-bill/4346.
---------------------------------------------------------------------------

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

[[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 (NOX), sulfur dioxide 
(SO2), and fine particulate matter (PM2.5). These 
reductions in health-harming pollution would result in significant 
public health benefits including avoided premature deaths, reductions 
in new asthma cases and incidences of asthma symptoms, reductions in 
hospital admissions and emergency department visits, and reductions in 
lost work and school days.
    The EPA has also evaluated how the air quality impacts associated 
with these proposals would be distributed, with particular focus on 
potentially vulnerable populations. As discussed in section 6 of the 
RIA, these proposals are anticipated to lead to modest but widespread 
reductions in ambient levels of PM2.5 for a large majority 
of the nation's population, as well as reductions in ambient 
PM2.5 exposures that are similar in magnitude across all 
racial, ethnic, income and linguistic groups. Similarly, the EPA found 
that the proposed standards are anticipated to lead to modest but 
widespread reductions in ambient levels of ground-level ozone for the 
majority of the nation's population, and that in all but one of the 
years evaluated the proposed standards would lead to reductions in 
ambient ozone exposures across all demographic groups. Although these 
reductions in PM2.5 and ozone exposures are small relative 
to baseline levels, and although disparities in PM2.5 and 
ozone exposure would continue to persist following these proposals, the 
EPA's analysis indicates that the air quality benefits of these 
proposals would be broadly distributed.
    Where authorized under section 111 of the Clean Air Act, the EPA 
has also incorporated provisions in these proposals to better address 
the needs and concerns of communities with environmental justice 
concerns. Specifically, the EPA's proposed emission guidelines for 
existing steam EGUs as well as existing fossil fuel-fired stationary 
combustion turbines would require states to undertake meaningful 
engagement with affected stakeholders, including communities that are 
most affected by and vulnerable to emissions from these EGUs. These 
meaningful engagement requirements are intended to ensure that the 
perspectives, priorities, and concerns of affected communities are 
included in the process of establishing and implementing standards of 
performance for existing EGUs, including decisions about compliance 
strategies and compliance flexibilities that may be included in a State 
plan.
    In the Agency's pre-proposal outreach, some environmental justice 
organizations and community representatives raised strongly held 
concerns about the potential health, environmental, and safety impacts 
of CCS. The EPA believes that deployment of CCS can take place in a 
manner that is protective of public health, safety, and the 
environment, and should include early and meaningful engagement with 
affected communities and the public. As stated in the Council on 
Environmental Quality's (CEQ) February 2022 Carbon Capture, 
Utilization, and Sequestration Guidance, ``the successful widespread 
deployment of responsible CCUS will require strong and effective 
permitting, efficient regulatory regimes, meaningful public engagement 
early in the review and deployment process, and measures to safeguard 
public health and the environment.'' See 87 FR 8808 (February 16, 
2022).
    The EPA gave close consideration to these concerns as it developed 
its proposed determinations on the BSER for these proposed NSPS and 
emission guidelines, and addresses certain of the substantive issues 
that were raised in pre-proposal discussions in sections 
VII.F.3.b.iii(C) and X.D.1.a.iii of this preamble. As explained in 
these sections, the EPA is proposing to determine that CCS is the BSER 
for certain subcategories of new and existing EGUs based on its 
consideration of all of the statutory criteria for BSER, including 
emission reductions, cost, energy requirements, and non-air health and 
environmental considerations. In evaluating concerns raised by 
stakeholders in connection with CCS, the EPA is mindful that Federal 
agencies have ``taken actions in the past decade to develop a robust 
CCUS regulatory framework to protect the environment and public health 
across multiple statutes.'' \6\
---------------------------------------------------------------------------

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

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

[[Page 33248]]

EPA's Greenhouse Gas Reporting Program; and safety regulations for 
CO2 pipelines administered by the Pipeline and Hazardous 
Materials and Safety Administration (PHMSA). With respect to air 
emissions, some CCS projects may also require pre-construction 
permitting under the Clean Air Act's New Source Review (NSR) program 
and the adoption of additional emission limitations for non-GHG air 
pollutants based on applicable control technology requirements. The EPA 
invites public comment and feedback from stakeholders on all aspects of 
its proposed determination that CCS represents the BSER for certain new 
and existing fossil fuel-fired EGUs, including its evaluation of the 
various regulatory frameworks that apply to CCS.
    CEQ's guidance, and the EPA's evaluation of BSER, recognizes that 
multiple Federal agencies have responsibility for regulating and 
permitting CCS projects, along with State and Tribal governments. The 
EPA is committed to working with Federal, State, and Tribal partners to 
ensure the responsible deployment of CCS, to protect communities from 
pollution, and to foster meaningful engagement with communities. This 
can be facilitated through the existing detailed regulatory framework 
for CCS projects and further supported through robust and meaningful 
public engagement early in the project development process. 
Furthermore, the EPA is requesting comment on what assistance states 
and pertinent stakeholders may need in conducting meaningful engagement 
with affected communities to ensure that there are adequate 
opportunities for public input on decisions to implement emissions 
control technology (including but not limited to CCS or low-GHG 
hydrogen).

II. General Information

A. Action Applicability

    The source category that is the subject of these actions is 
comprised of the fossil fuel-fired electric utility generating units 
regulated under CAA section 111. The North American Industry 
Classification System (NAICS) codes for the source category are 221112 
and 921150. The list of categories and NAICS codes is not intended to 
be exhaustive, but rather provides a guide for readers regarding the 
entities that these proposed actions are likely to affect.
    The proposed amendments to 40 CFR part 60, subpart TTTT, once 
promulgated, will be directly applicable to affected facilities that 
began construction after January 8, 2014, and affected facilities that 
began reconstruction or modification after June 18, 2014. The proposed 
NSPS, proposed to be codified in 40 CFR part 60, subpart TTTTa, once 
promulgated, will be directly applicable to affected facilities that 
begin construction or reconstruction after the date of publication of 
the proposed standards in the Federal Register. Federal, State, local, 
and Tribal government entities that own and/or operate EGUs subject to 
40 CFR part 60, subparts TTTT or TTTTa would be affected by these 
proposed amendments and standards.
    The proposed emission guidelines for GHG emissions from fossil 
fuel-fired EGUs proposed to be codified in 40 CFR part 60, subpart 
UUUUb, once promulgated, will be applicable to states in the 
development and submittal of State plans pursuant to CAA section 
111(d). After the EPA promulgates a final emission guideline, each 
State that has one or more designated facilities must develop, adopt, 
and submit to the EPA a State plan under CAA section 111(d). The term 
``designated facility'' means ``any existing facility . . . which emits 
a designated pollutant and which would be subject to a standard of 
performance for that pollutant if the existing facility were an 
affected facility.'' See 40 CFR 60.21a(b). If a State fails to submit a 
plan or the EPA determines that a State plan is not satisfactory, the 
EPA has the authority to establish a Federal CAA section 111(d) plan in 
such instances.
    Under the Tribal Authority Rule adopted by the EPA, Tribes may seek 
authority to implement a plan under CAA section 111(d) in a manner 
similar to a State. See 40 CFR part 49, subpart A. Tribes may, but are 
not required to, seek approval for treatment in a manner similar to a 
State for purposes of developing a Tribal Implementation Plan (TIP) 
implementing an emission guideline. If a Tribe does not seek and obtain 
the authority from the EPA to establish a TIP, the EPA has the 
authority to establish a Federal CAA section 111(d) plan for designated 
facilities that are located in areas of Indian country. A Federal plan 
would apply to all designated facilities located in the areas of Indian 
country covered by the Federal plan unless and until the EPA approves a 
TIP applicable to those facilities.

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

    In addition to being available in the docket, an electronic copy of 
this action is available on the internet at https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power. Following publication in the 
Federal Register, the EPA will post the Federal Register version of the 
proposals and key technical documents at this same website.
    Memoranda showing the edits that would be necessary to incorporate 
the changes to 40 CFR part 60, subpart TTTT and UUUUa and new 40 CFR 
part 60, subparts TTTTa and UUUUb proposed in these actions are 
available in the docket (Docket ID No. EPA-HQ-OAR-2023-0072). Following 
signature by the EPA Administrator, the EPA also will post a copy of 
the documents at https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.

C. Organization and Approach for These Proposed Rules

    This rulemaking includes several proposed actions: (1) The EPA's 
proposed amendments to the Standards of Performance for Greenhouse Gas 
Emissions From New, Modified, and Reconstructed Stationary Sources: 
Electric Utility Generating Units (80 FR 64510; October 23, 2015) (2015 
NSPS) and (2) proposed requirements for GHG emissions from new and 
reconstructed fossil fuel-fired stationary combustion turbine EGUs. 
These actions also (3) propose to repeal the ACE Rule (84 FR 32523; 
July 8, 2019), (4) propose new emission guidelines for states in 
developing plans to reduce GHG emissions from existing fossil fuel-
fired steam generating EGUs, which include both coal-fired and oil- and 
natural gas-fired steam generating EGUs, and (5) propose new emission 
guidelines for states in developing plans to reduce GHG emissions from 
existing fossil fuel-fired stationary combustion turbines. The EPA 
proposes that each of these actions function independently and are 
therefore severable. The EPA invites comment on the question of which 
portions of these proposed rules, if any, should be severable.
    Section III of this preamble provides updated information on the 
impacts of climate change. In section IV, the EPA provides a summary of 
recent developments in emissions controls and the electric power 
sector. Section V presents a summary of the statutory background and 
regulatory history. In section VI, the EPA summarizes stakeholder 
outreach efforts. In section VII, the EPA describes the proposed BSERs, 
standards of performance, and associated requirements for new and 
reconstructed fossil fuel-fired stationary combustion turbine EGUs. In 
section

[[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 (CO2), methane (CH4), 
nitrous oxide (N2O), hydrofluorocarbons (HFCs), 
perfluorocarbons (PFCs), and sulfur hexafluoride (SF6)--
``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.
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    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 https://www.epa.gov/climate-indicators.
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     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.
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     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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     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.
---------------------------------------------------------------------------

    \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. 
https://dio.org/10.17226/21852.
    \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. https://doi.org/10.17226/24651.
    \21\ National Academies of Sciences, Engineering, and Medicine. 
2019. Climate Change and Ecosystems. Washington, DC: The National 
Academies Press. https://doi.org/10.17226/25504.
---------------------------------------------------------------------------

     National Oceanic and Atmospheric Administration's (NOAA) 
annual State of the Climate reports published by the Bulletin of the 
American Meteorological Society,\22\ most recently in August of 2022.
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    \22\ Blunden, J. and T. Boyer, Eds., 2022: ``State of the 
Climate in 2021.'' Bull. Amer. Meteor. Soc., 103 (8), Si-S465, 
https://doi.org/10.1175/2022BAMSStateoftheClimate.1.
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     EPA Climate Change and Social Vulnerability in the United 
States: A Focus on Six Impacts (2021).\23\
---------------------------------------------------------------------------

    \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, 
CO2, 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 
CO2 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, 
https://doi.org/10.1175/2022BAMSStateoftheClimate.1.
    \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 CO2 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 
CO2 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 CO2 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. 
https://www.nifc.gov/sites/default/files/document-media/TotalFires.pdf.
    \47\ USGCRP, 2018.
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    Some GHGs also have impacts beyond those mediated through climate 
change. For example, elevated concentrations of CO2 
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, https://dx.doi.org/10.7930/J0ZP4417.
    \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 https://www.epa.gov/cira/fredi. Documentation has been subject to both a 
public review comment period and an independent expert peer review, 
following EPA peer-review guidelines.
    \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. https://doi.org/10.1007/s10584-021-03048-6, (2) Supplementary Material for the Regulatory 
Impact Analysis for the Supplemental Proposed Rulemaking, 
``Standards of Performance for New, Reconstructed, and Modified 
Sources and Emissions Guidelines for Existing Sources: Oil and 
Natural Gas Sector Climate Review,'' Docket ID No. EPA-HQ-OAR-2021-
0317, September 2022, (3) The Long-Term Strategy of the United 
States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050. 
Published by the U.S. Department of State and the U.S. Executive 
Office of the President, Washington DC. November 2021, (4) Climate 
Risk Exposure: An Assessment of the Federal Government's Financial 
Risks to Climate Change, White Paper, Office of Management and 
Budget, April 2022.
    \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 https://www.epa.gov/cira/fredi.
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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 https://www.nerc.com/AboutNERC/keyplayers/PublishingImages/NERC%20Interconnections.pdf.
    \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. https://www.eia.gov/electricity/data/php.
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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 (H2), 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 CO2 from EGUs. CCS has 
three major components: CO2 capture, transportation, and 
sequestration/storage. Generally, the capture processes most applicable 
to combustion turbines and utility boilers remove CO2 from 
the exhaust gas after combustion. The exhaust gases from most 
combustion processes are at atmospheric pressure with relatively low 
concentrations of CO2. Most post-combustion capture systems 
utilize liquid solvents (most commonly amine-based) in a scrubber 
column to absorb the CO2 from the flue gas.\61\ The 
CO2-rich solvent is then regenerated by heating the solvent 
to release the captured CO2. The high purity CO2 
is then compressed and transported, generally through pipelines, to a 
site for geologic sequestration (i.e., the long-term containment of 
CO2 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 CO2 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 CO2 capture is most common, but 
as discussed later in this preamble, there are also pre-combustion 
CO2 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. https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-and-Costs-for-CCS-2021-1.pdf.
_____________________________________-

    There are several examples of the application of CCS at EGUs, some 
of which are noted here with further detail provided in section 
VII.F.3.b.iii(A) of this preamble. These include SaskPower's Boundary 
Dam Unit 3, a 110-MW lignite-fired unit in Saskatchewan, Canada, which 
has achieved CO2 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. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191.
    \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.
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    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 CO2 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 CO2 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 
CO2 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. https://www.energy.gov/fecm/articles/carbon-capture-opportunities-natural-gas-fired-power-systems.
    \67\ Buli, N. (2021, May 10). SSE, Equinor plan new gas power 
plant with carbon capture in Scotland. Reuters. https://www.reuters.com/business/sustainable-business/sse-equinor-plan-new-gas-power-plant-with-carbon-capture-scotland-2021-05-11/.
    \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. 
https://www.cpv.com/2022/09/16/multi-billion-dollar-combinedcycle-natural-gas-power-station-with-carbon-capture-announced-in-west-virginia/.
---------------------------------------------------------------------------

    In developing these proposals, the EPA reviewed the current state 
of CCS technology and costs, including the use of CCS with both steam 
generating units and combustion turbines. This review is reflected in 
the BSER discussions later in this preamble and is further detailed in 
the accompanying RIA and technical support documents titled, GHG 
Mitigation Measures for Steam Generating Units and GHG Mitigation 
Measures--Carbon Capture and Storage for Combustion Turbines. The three 
documents are included in the rulemaking docket.

D. Natural Gas Co-Firing

    For a coal-fired steam generating unit, the substitution of natural 
gas for some of the coal so that the unit fires a combination of coal 
and natural gas is known as ``natural gas co-firing.'' Most existing 
coal-fired steam generating units can be modified to co-fire natural 
gas in any desired proportion with coal. Generally, the modification of 
existing boilers to enable or increase natural gas firing typically 
involves the installation of new gas burners and related boiler 
modifications as well as the construction of natural gas supply 
pipelines. In recent years, the cost of natural gas co-firing has 
declined because the expected difference between coal and gas prices 
has decreased to about $1/MMBtu and recent analyses support lower 
capital costs for modifying existing boilers to co-fire with natural 
gas, as discussed in section X.D.2 of this preamble.
    In developing these proposals, the EPA reviewed in detail the 
current state of natural gas co-firing technology and costs. This 
review is reflected in the BSER discussions later in this preamble and 
is further detailed in the accompanying RIA and GHG Mitigation Measures 
for Steam Generating Units TSD. Both documents are included in the 
rulemaking docket.

E. Hydrogen Co-Firing

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

[[Page 33255]]

a fuel to generate electricity. Hydrogen contains no carbon, and when 
combusted in a turbine, produces zero direct CO2 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\ https://clkrep.lacity.org/onlinedocs/2023/23-0039_rpt_DWP_02-03-2023.pdf.
    \70\ https://www.forbes.com/sites/mitsubishiheavyindustries/2021/07/30/eager-to-become-hydrogen-ready-power-plants-turn-to-dual-fuel-turbines/?sh=38ddea053476.
    \71\ https://www.nexteraenergy.com/content/dam/nee/us/en/pdf/NextEraEnergyZeroCarbonBlueprint.pdf.
    \72\ https://www.duke-energy.com/_/media/PDFs/our-company/Climate-Report-2022.pdf.
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    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\ 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/.
    \74\ GE-powered gas-fired plant in Ohio now burning hydrogen 
(power-eng.com).
    \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.
---------------------------------------------------------------------------

    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. https://www.eia.gov/todayinenergy/detail.php?id=25392.
    \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. https://www.energy.gov/sites/default/files/2022-08/8.18%20InflationReductionAct_Factsheet_Final.pdf.
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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. https://www.eia.gov/totalenergy/data/annual/.
---------------------------------------------------------------------------

    The broad trends throughout the power sector can also be seen in 
the number of commitments and announced plans of many EGU owners and 
operators across the industry to decarbonize--spanning all types of 
companies in all locations. Moreover, State governments, which 
traditionally regulate investment decisions regarding electricity 
generation, have implemented their own policies to reduce GHG emissions 
from power generation.
    Additional analysis of the utility power sector, including 
projections of future power sector behavior and the impacts of these 
proposed rules, is discussed in more detail in section XV of this 
preamble, in the accompanying RIA, and in the Power Sector Trends 
technical support document (TSD). The latter two documents are 
available in the rulemaking docket. Consistent with analyses done by 
other energy modelers, the RIA and TSD demonstrate that the sector 
trend of moving away from coal-fired generation is likely to continue 
and that non-emitting technologies may eventually displace certain 
natural gas-fired combustion turbines.
3. Trends in Coal-Fired Generation
    Coal-fired steam generating units have historically been the 
nation's foremost source of electricity, but coal-fired generation has 
declined steadily since its peak approximately 20 years ago.\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. https://www.eia.gov/todayinenergy/detail.php?id=25392.
    \80\ U.S. Energy Information Administration (EIA). Electric 
Generators Inventory, Form EIA-860M, Inventory of Operating 
Generators and Inventory of Retired Generators, March 2022. https://www.eia.gov/electricity/data/eia860m/.
    \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. https://www.eia.gov/todayinenergy/detail.php?id=44636.
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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. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
    \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. https://www.eia.gov/todayinenergy/detail.php?id=42155.
    \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. https://www.eia.gov/electricity/data/eia860m/.
    \88\ U.S. Environmental Protection Agency. National Electric 
Energy Data System (NEEDS) v6. October 2022. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
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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. https://eia.gov/coal/annual/pdf/tableES1.pdf.
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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. https://www.eia.gov/energyexplained/natural-gas/.
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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. https://www.eia.gov/energyexplained/natural-gas/where-our-natural-gas-comes-from.php.
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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. https://www.eia.gov/energyexplained/natural-gas/prices.php.
    \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. https://www.eia.gov/electricity/data/eia860m/.
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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. https://www.eia.gov/todayinenergy/detail.php?id=55419.
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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. https://www.eia.gov/totalenergy/data/monthly/.
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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. https://www.energy.gov/eere/wind/articles/land-based-wind-market-report-2022-edition.
    \99\ Lawrence Berkeley National Laboratory (LBNL), Utility-Scale 
Solar Technical Brief, 2022 Edition, September 2022. https://emp.lbl.gov/utility-scale-solar.
    \100\ https://www.nrel.gov/news/program/2021/documenting-a-decade-of-cost-declines-for-pv-systems.html.
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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. https://www.eia.gov/electricity/data/eia860m/.
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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. https://www.eia.gov/electricity/data/eia860/.
    \103\ U.S. Energy Information Administration (EIA). Annual 
Electric Power Industry Report, 2021 Form EIA-861. https://www.eia.gov/electricity/data/eia861/.
    \104\ U.S. Energy Information Administration (EIA). Annual 
Electric Generator Report, 2019 Form EIA-860. https://www.eia.gov/analysis/studies/electricity/batterystorage/.
    \105\ U.S. Energy Information Administration (EIA). Today in 
Energy. U.S. battery storage capacity will increase significantly by 
2025. December 2022. https://www.eia.gov/todayinenergy/detail.php?id=54939.
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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. https://www.eia.gov/electricity/data/eia860m/.
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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. https://www.nrc.gov/reactors/operating/licensing/renewal/subsequent-license-renewal.html.
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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. https://thebreakthrough.imgix.net/Advancing-Nuclear-Energy_v3-compressed.pdf.
    \110\ Derr, E. (July 29, 2022). Energy Studies and Models Show 
Advanced Nuclear as the Backbone of Our Carbon-Free Future. Nuclear 
Energy Institute (NEI). https://www.nei.org/news/2022/studies-and-models-show-demand-for-adv-nuclear.
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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 CO2, 
CH4, N2O, HFCs, PFCs, and SF6. Of 
these, CO2 is the most abundant, accounting for 80 percent 
of all GHGs present in the atmosphere. This abundance of CO2 
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. https://www.epa.gov/ghgemissions/overview-greenhouse-gases#carbon-dioxide.
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    The amount of CO2 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 CO2 in 
relation to the energy they produce when combusted. The amount of 
CO2 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 
CO2 emitted per million British thermal units of energy 
produced, when combusted, natural gas is the lowest compared to other 
fossil fuels at 117 lb CO2/MMBtu.112 113 The 
average for coal is 216 lb CO2/MMBtu, but varies between 206 
to 229 lb CO2/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 CO2/MMBtu.
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    \112\ Natural gas is primarily CH4, which has a 
higher hydrogen to carbon atomic ratio, relative to other fuels, and 
thus, produces the least CO2 per unit of heat released. 
In addition to a lower CO2 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 CO2/kWh and 0.91 lb 
CO2/kWh, respectively. www.eia.gov/tools/faqs/faq.php?id=74&t=11.
    \113\ Values reflect the carbon content on a per unit of energy 
produced on a higher heating value (HHV) combustion basis and are 
not reflective of recovered useful energy from any particular 
technology.
    \114\ Energy Information Administration (EIA). Carbon Dioxide 
Emissions Coefficients. https://www.eia.gov/environment/emissions/co2_vol_mass.php.
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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 CO2 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. https://cfpub.epa.gov/ghgdata.
    \116\ Sinks are a physical unit or process that stores GHGs, 
such as forests or underground or deep-sea reservoirs of carbon 
dioxide.
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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 CO2e). 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 CO2 emissions, the power 
sector was responsible for 30.6 percent (1,541 MMT CO2e) of 
the nation's 2021 total.
    CO2 emissions from the power sector have declined by 36 
percent since 2005 (when the power sector reached annual emissions of 
2,400 MMT CO2, its historical peak to date).\117\ The 
reduction in CO2 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, CO2 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 CO2 
emissions were below 1,000 MMT. In 2020, emissions of CO2 
from coal-fired EGUs measured 788 MMT before rebounding in 2021 to 909 
MMT due to increased demand. By contrast, CO2 emissions from 
natural gas-fired generation have almost doubled since 2005, increasing 
from 319 MMT to 613 MMT in 2021, and CO2 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. https://cfpub.epa.gov/ghgdata/inventoryexplorer/#electricitygeneration/entiresector/allgas/category/all.
    \118\ U.S. Energy Information Administration (EIA). Monthly 
Energy Review, table 11.6. September 2022. https://www.eia.gov/totalenergy/data/monthly/pdf/sec11.pdf.
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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 CO2 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 CO2 
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 CO2 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 CO2 in the U.S., and, despite 
the emission reductions since 2005, current CO2 levels 
continue to endanger human health and welfare. Further, as sources in 
other sectors of the economy turn to electrification to decarbonize, 
future CO2 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 CO2 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\ https://www.congress.gov/bill/117th-congress/house-bill/3684/text.
    \121\ https://gfoaorg.cdn.prismic.io/gfoaorg/0727aa5a-308f-4ef0-addf-140fd43acfb5_BUILDING-A-BETTER-AMERICA-V2.pdf.
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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\ https://www.congress.gov/bill/117th-congress/house-bill/5376/text..
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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 CO2, 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 CO2 captured and 
securely stored in geologic formations and $60/metric ton for 
CO2 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 
CO2 capture design capacity of not less than 75 percent of 
the baseline CO2 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. 
https://www.globalccsinstitute.com/wp-content/uploads/2019/05/LCFS-and-CCS-Protocol_digital_version-2.pdf.
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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 H2 for 0.0 to 0.45 kilograms of CO2-
equivalent emitted per kilogram of low-GHG hydrogen produced (kg 
CO2e/kg H2) down to $0.6/kg H2 for 2.5 
to 4.0 kg CO2e/kg H2 (assuming wage and 
apprenticeship requirements are met). Projects with GHG emissions 
greater than 4.0 kg CO2e/kg H2 are not eligible. 
According to the DOE, current costs for hydrogen produced from 
renewable energy are approximately $5/kg H2.\125\ These 
production costs could decline by 2025 to between $2.5 and $2.7/kg 
H2 (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. https://www.energy.gov/eere/fuelcells/hydrogen-shot.
    \126\ U.S. Department of Energy (DOE). Pathways to Commercial 
Liftoff: Clean Hydrogen, March 2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies.
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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 
CO2 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. https://rhg.com/research/climate-clean-energy-inflation-reduction-act/.
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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. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies.
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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 CO2 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:
     Xcel Energy: 80 percent reduction in CO2 
emissions by 2030 and 100 percent carbon-free by 2050. This includes a 
commitment to close or repower all remaining coal-fired EGUs by 
2030.\134\
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    \134\ Xcel Energy is based in Minnesota with operations in 
Colorado, Michigan, New Mexico, North Dakota, South Dakota, Texas, 
and Wisconsin. 2018 Integrated Resource Plan at https://www.xcelenergy.com/staticfiles/xe-responsive/Company/Rates%20&%20Regulations/Resource%20Plans/2018-SPS-NM-Integrated-Resource-Plan.pdf.
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     DTE Energy: 65 percent reduction in CO2 
emissions by 2028, 90 percent reduction by 2040, and net-zero carbon 
emissions by 2050.\135\
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    \135\ DTE Energy is based in Michigan. Our Bold Goal for 
Michigan's Clean Energy Future at https://dtecleanenergy.com/.
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     Ameren Energy: 60 percent reduction in CO2 by 
2030, 85 percent reduction by 2040, and net-zero carbon emissions by 
2045.\136\
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    \136\ Ameren is based in Illinois and Missouri. 2022 Integrated 
Resource Plan at https://www.ameren.com/missouri/company/environment-and-sustainability/integrated-resource-plan.
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     Consumers Energy: 60 percent reduction in CO2 
by 2025 and net-zero carbon emissions by 2040. This includes the 
retirement of all coal-fired units by 2025.\137\
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    \137\ Consumers Energy is based in Michigan. Integrated Resource 
Plan at https://s26.q4cdn.com/888045447/files/doc_presentations/2021/06/2021-Integrated-Resource-Plan.pdf.
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     Southern Company: 50 percent reduction in CO2 
by 2030 (relative to 2007 levels) and net-zero carbon emissions by 
2050.\138\
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    \138\ Southern Company is based in Georgia with operations in 
Alabama and Mississippi. https://www.southerncompany.com/sustainability/net-zero-and-environmental-priorities/net-zero-transition.html.
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     Duke Energy: 70 percent reduction in CO2 by 
2030 and net-zero carbon

[[Page 33263]]

emissions by 2050. All coal-fired units will retire by 2035.\139\
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    \139\ Duke Energy is based in North Carolina with operations in 
South Carolina, Florida, Indiana, Ohio, and Kentucky. NC IRP Fact 
Sheet at https://p-scapi.duke-energy.com/-/media/pdfs/our-company/202296-nc-irp-fact-sheet.pdf.
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     Minnesota Power (Allete Inc.): 70 percent renewable energy 
by 2030, 80 percent reduction in CO2 and coal-free by 2035, 
and 100 percent carbon-free by 2050.\140\
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    \140\ Allete Energy is based in Minnesota with operations in 
Wisconsin and North Dakota. Integrated Resource Plan at: https://www.edockets.state.mn.us/EFiling/edockets/searchDocuments.do?method=showPoup&documentId=%7b70795F77-0000-C41E-A71C-FD089119967C%7d&documentTitle=20212-170583-01.
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     First Energy: 30 percent reduction in CO2 by 
2030 (relative to 2019 levels) and net-zero carbon emissions by 
2050.\141\
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    \141\ First Energy is based in Ohio with operations in 
Pennsylvania, West Virginia, and New Jersey. https://www.firstenergycorp.com/content/dam/environmental/files/climate-strategy.pdf.
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     American Electric Power: 80 percent reduction in 
CO2 by 2030 and net-zero carbon emissions by 2045.\142\
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    \142\ American Electric Power (AEP) is based in Ohio with 
operations in Arkansas, Indiana, Kentucky, Louisiana, Michigan, 
Oklahoma, Tennessee, Texas, Virginia, and West Virginia. Clean 
Energy Future at https://www.aep.com/about/ourstory/cleanenergy.
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     Alliant Energy: 50 percent reduction in CO2 by 
2030 and net-zero carbon emissions by 2050; will retire final coal-
fired EGU by 2040.\143\
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    \143\ Alliant Energy has operations in Iowa and Wisconsin. See 
Our Sustainable Energy Plan at https://www.alliantenergy.com/cleanenergy/ourenergyvision/poweringwhatsnext/sustainableenergyplan.
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     Tennessee Valley Authority: 70 percent reduction in 
CO2 by 2030, 80 percent reduction by 2035, and net-zero 
carbon emissions by 2050.\144\
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    \144\ Tennessee Valley Authority (TVA) is based in Tennessee 
with operations in Alabama, Georgia, Kentucky, Mississippi, North 
Carolina, and Virginia. See https://www.tva.com/newsroom/press-releases/tva-charts-path-to-clean-energy-future.
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     NextEra Energy: 70 percent reduction in CO2 by 
2025, 82 percent reduction by 2030, 87 percent reduction by 2035, 94 
percent reduction by 2040, and carbon-free by 2045.\145\
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    \145\ NextEra Energy. See https://newsroom.nexteraenergy.com/2022-06-14-NextEra-Energy-sets-industry-leading-Real-Zero-TM-goal-to-eliminate-carbon-emissions-from-its-operations,-leverage-low-cost-renewables-to-drive-energy-affordability-for-customers.
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    The geographic footprint of zero or net-zero carbon commitments 
made by utilities, their parent companies, or in response to a State 
clean energy requirement, covers portions of 47 states and includes 75 
percent of U.S. customer accounts.\146\ These statements are often made 
as part of long-term planning processes with considerable stakeholder 
involvement, including regulators.
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    \146\ Smart Electric Power Alliance Utility Carbon Tracker. See 
https://sepapower.org/utility-transformation-challenge/utility-carbon-reduction-tracker/. Accessed January 12, 2023.
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3. State Actions To Reduce Power Sector GHG Emissions
    States across the country have taken the lead in efforts to reduce 
GHG emissions from the power sector. These actions include commitments 
that require utilities to expand renewable and clean energy production 
through the adoption of renewable portfolio standards (RPS) and clean 
energy standards (CES), as well as other measures tailored to 
decarbonize State power systems enacted in specific legislation.
    Twenty-nine states and the District of Columbia have enforceable 
RPS.\147\ RPS require a percentage of electricity that utilities sell 
to come from eligible renewable sources like wind and solar rather than 
from fossil fuel-based sources like coal and natural gas. Fifteen 
states have RPS targets that are at or well above 50 percent. Eight of 
these states--California, Illinois, Massachusetts, Maryland, Minnesota, 
New Jersey, Nevada, and Oregon--have targets ranging from 50 percent to 
just below 70 percent. Four states--Maine, New Mexico, New York, and 
Vermont--have RPS targets greater than or equal to 70 percent but below 
100 percent, and three states--Hawaii, Rhode Island, and Virginia plus 
the District of Columbia--have 100 percent RPS requirements. Most of 
these ambitious targets fall during the next decade. Ten states and the 
District of Columbia have final targets that mature between 2025 and 
2033, while the remaining five states impose peak requirements between 
2040 and 2050. Resources that are eligible under an RPS vary by State 
and are determined by the State's existing energy production and 
possibility for renewable energy development. For example, Colorado's 
RPS includes a range of resources such as solar, wind, emissions-
neutral coal mine methane and other sources as qualifying renewable 
energy sources. Hawaii's includes, but is not limited to, solar, wind, 
and energy produced from falling water, ocean water, waves, and water 
currents. RPS in some other states include landfill gas, animal wastes, 
CHP, and energy efficiency.\148\
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    \147\ DSIRE, Renewable Portfolio Standards and Clean Energy 
Standards (2022). https://ncsolarcen-prod.s3.amazonaws.com/wp-content/uploads/2022/11/RPS-CES-Nov2022.pdf.
    \148\ NCSL (2021). State Renewable Portfolio Standards and 
Goals. https://www.ncsl.org/research/energy/renewable-portfolio-standards.aspx.
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    States are also shifting their generating fleets away from fossil 
fuel generating resources through the adoption of CES. A CES requires a 
percentage of retail electricity to come from sources that are defined 
as clean. Unlike an RPS, which defines eligible generation in terms of 
the renewable attributes of its energy source, CES eligibility is based 
on the GHG emission attributes of the generation itself, typically with 
a zero or net-zero carbon emissions requirement. Twenty-one states have 
adopted some form of clean energy requirement or goal with 17 of those 
states setting 100 percent targets. In nearly all cases, the CES 
applies in addition to the State's other RPS requirements. Seven 
states, including California, Colorado, Minnesota, New York, 
Washington, Oregon, and Arizona, have a zero or net-zero carbon 
emissions requirement with most target dates falling in 2040, 2045, or 
2050. Two states--New Mexico and Massachusetts--have 80 percent clean 
energy requirements that must be met in 2045 and 2050, respectively. 
Ten additional states, including Connecticut, New Jersey, Nevada, 
Wisconsin, Illinois, Maine, North Carolina, Nebraska, Louisiana, and 
Michigan, have 100 percent clean energy goals with target dates falling 
in either 2040 or 2050. Like an RPS, CES resource eligibility can vary 
from State to State. One key difference between an RPS and a CES is the 
extent to which a CES can allow for resources like nuclear and CCS-
enabled coal and natural gas, which are not renewable but have low or 
zero direct GHG emission attributes that make them CES eligible.
    In addition, states across the U.S. have announced specific 
legislation aimed at reducing GHG emissions. In California, Senate Bill 
32, passed in 2016, was a landmark legislation that requires California 
to reduce its economy-wide GHG emissions to 1990 levels by 2020, 40 
percent below 1990 levels by 2030, and 80 percent below 1990 levels by 
2050. Senate Bill 100, passed in 2018, requires California to procure 
60 percent of all electricity from renewable sources by 2030 and plan 
for 100 percent from carbon-free sources by 2045. Senate Bills 605 and 
1383, passed in 2016, require a reduction in emissions of short-lived 
climate pollutants like methane by 40 to 50 percent below 2013 levels 
by 2030.\149\ Achieving California's established goal

[[Page 33264]]

of carbon-free electricity by 2045 requires emissions to be balanced by 
carbon sequestration, capture, or other technologies. Senate Bill 905, 
passed in 2022, requires the California Air Resources Board to 
establish programs for permitting CCS projects.\150\ Senate Bill 905, 
also passed in 2022, prevents the use of captured CO2 for 
enhanced oil recovery within California.
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    \149\ Berkeley Law. California Climate Policy Dashboard. https://www.law.berkeley.edu/research/clee/research/climate/climate-policy-dashboard.
    \150\ Berkeley Law. California Climate Policy Dashboard. https://www.law.berkeley.edu/research/clee/research/climate/climate-policy-dashboard.
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    In New York, The Climate Leadership and Community Protection Act, 
passed in 2019, sets several climate targets. The most important goals 
include an 85 percent reduction in GHG emissions by 2050, 100 percent 
zero-emission electricity by 2040, and 70 percent renewable energy by 
2030. Other targets include 9,000 MW of offshore wind by 2035, 3,000 MW 
of energy storage by 2030, and 6,000 MW of solar by 2025.\151\
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    \151\ New York State. Our Progress. https://climate.ny.gov/Our-Progress.
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    Washington State's Climate Commitment Act sets a target of reducing 
GHG emissions by 95 percent by 2050. The State is required to reduce 
emissions to 1990 levels by 2020, 45 percent below 1990 levels by 2030, 
70 percent below 1990 levels by 2040, and 95 percent below 1990 levels 
by 2050. This also includes achieving net-zero emissions by 2050.\152\
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    \152\ Department of Ecology Washington State. Greenhouse Gases. 
https://ecology.wa.gov/Air-Climate/Climate-change/Tracking-greenhouse-gases.
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    In addition to the prevalence of State RPS and CES programs 
outlined above, several states developed regulatory programs to retain 
nuclear power plants to preserve the significant amount of zero-
emission output the plants provide, especially as many nuclear plants 
face downward economic pressures resulting from ultra-low natural gas 
spot prices combined with increasing NGCC capacity. Between 2016 and 
2021, New York, New Jersey, Connecticut, and Illinois took action to 
retain their nuclear power stations by providing State-level financial 
incentives. Retention of nuclear power plants is another strategy that 
some states have used to ensure an increasing market share for zero-
emission electricity generation. As discussed earlier, the IRA included 
a zero-emission nuclear power production credit in section 13105, also 
referred to as IRC section 45U.\153\
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    \153\ http://uscode.house.gov/view.xhtml?req=(title:26%20section:45U%20edition:prelim).
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    In the past two years, State actions have generally increased their 
decarbonization ambitions. For example, legislation in Illinois and 
North Carolina requires a transition away from GHG-emitting generation. 
Illinois' Climate and Equitable Jobs Act, which became law on September 
25, 2021, requires all private coal-fired or oil-fired power plants to 
reach zero carbon emissions by 2030, municipal coal-fired plants to 
reach zero carbon emissions by 2045, and natural gas-fired plants to 
reach zero carbon emissions by 2045.\154\ On October 13, 2021, North 
Carolina passed House Bill 951 that required the North Carolina 
Utilities Commission to ``take all reasonable steps to achieve a 
seventy percent (70%) reduction in emissions of carbon dioxide 
(CO2) emitted in the State from electric generating 
facilities owned or operated by electric public utilities from 2005 
levels by the year 2030 and carbon neutrality by the year 2050.'' \155\
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    \154\ State of Illinois General Assembly. Public Act 102-0662: 
Climate and Equitable Jobs Act. 2021. https://www.ilga.gov/legislation/publicacts/102/PDF/102-0662.pdf.
    \155\ General Assembly of North Carolina, House Bill 951 (2021). 
https://www.ncleg.gov/Sessions/2021/Bills/House/PDF/H951v5.pdf.
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1. Projections of Power Sector Trends

    Projections for the U.S. power sector--based on the landscape of 
market forces in addition to the known actions of Congress, utilities, 
and states--have indicated that the ongoing transition will continue 
for specific fuel types and EGUs. 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), provides 
projections out to 2050 on future outcomes of the electric power 
sector. For more information on the details of this modeling, see the 
model documentation.\156\
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    \156\ U.S. Environmental Protection Agency. Post-IRA 2022 
Reference Case EPA's Power Sector Modeling Platform v6 Using IPM. 
April 2023. https://www.epa.gov/power-sector-modeling/post-ira-2022-reference-case.
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    Since the passage of the IRA in August 2022, the EPA has engaged 
with many external partners, including other governmental entities, 
academia, non-governmental organizations (NGOs), and industry, to 
understand the impacts that the IRA will have on power sector GHG 
emissions. In addition to engaging in several workgroups, the EPA has 
contributed to two separate journal articles that include multi-model 
comparisons of IRA impacts across several state-of-the-art models of 
the U.S. energy system and electricity sector 157 158 and 
participated in public events exploring modeling assumptions for the 
IRA.\159\ The EPA plans to continue collaborating with stakeholders, 
conducting external engagements, and using information gathered to 
refine modeling of the IRA. As such, the EPA is soliciting comment on 
power sector modeling of the IRA, including the assumptions and 
potential impacts, including assumptions about growth in electric 
demand, rates at which renewable generation can be built, and cost and 
performance assumptions about all relevant technologies, including 
carbon capture, renewables, energy storage and other generation 
technologies.
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    \157\ Bistline, et al. (2023). ``Emissions and Energy System 
Impacts of the Inflation Reduction Act of 2022,'' Under Review.
    \158\ Bistline, et al. (2023). ``Power Sector Impacts of the 
Inflation Reduction Act of 2022,'' In Preparation.
    \159\ Resource for the Future (2023). ``Future Generation: 
Exploring the New Baseline for Electricity in the Presence of the 
Inflation Reduction Act.'' https://www.rff.org/events/rff-live/future-generation-exploring-the-new-baseline-for-electricity-in-the-presence-of-the-inflation-reduction-act/.
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    While much of the discussion below focuses on the EPA's post-IRA 
2022 reference case, many other analyses show similar trends,\160\ and 
these trends are consistent with utility IRPs and public GHG reduction 
commitments, as well as State actions, both of which were described in 
the previous sections.
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    \160\ A wide variety of modeling teams have assessed baselines 
with IRA. The baseline estimated here is generally in line with 
these other estimates. Bistline, et al. (2023). ``Power Sector 
Impacts of the Inflation Reduction Act of 2022,'' In Preparation.
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1. Projections for Coal-Fired Generation
    In the post-IRA 2022 reference case, coal-fired steam EGU capacity 
is projected to fall from 210 GW in 2021 \161\ to 44 GW in 2035, of 
which 11 GW includes retrofit CCS. Generation from coal-fired steam 
generating units is projected to also fall from 898 thousand GWh in 
2021 \162\ to 120 thousand GWh by 2035. This change in generation 
reflects the anticipated continued decline in projected coal-fired 
steam generating unit capacity as well as a steady decline in annual 
operation of those EGUs that remain online, with capacity factors 
falling from approximately 41 percent in 2021 to 15 percent in 2035. By 
2050, coal-fired steam generating unit capacity is projected to 
diminish further, with only 10 GW, or less than 5 percent of 2021

[[Page 33265]]

capacity (and approximately 3 percent of the 2010 capacity), still in 
operation across the continental U.S. These projections are driven by 
the eroding economic opportunities for coal-fired steam generating 
units to operate, the continued aging of the fleet of coal-fired steam 
generating units, and the continued availability and expansion of low-
cost alternatives, like natural gas, renewable technologies, and energy 
storage.
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    \161\ U.S. Energy Information Administration (EIA), Electric 
Power Annual, table 4.3. November 2022. https://www.eia.gov/electricity/annual/.
    \162\ U.S. Energy Information Administration (EIA), Electric 
Power Annual, table 3.1.A. November 2022. https://www.eia.gov/electricity/annual/.
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    In 2020, there was a total of 1,439 million metric tons of 
CO2 from the power sector with coal-fired sources 
contributing to over half of those emissions. In the post-IRA 2022 
reference case, power sector related CO2 emission are 
projected to fall to 608 million metric tons by 2035, of which 8 
percent is projected to come from coal-fired sources in 2035.
2. Projections for Natural Gas-Fired Generation
    As described in the post-IRA 2022 reference case, natural gas-fired 
capacity is expected to continue to buildout during the next decade 
with 61 GW of new capacity projected to come online by 2035 and 309 GW 
of new capacity by 2050. By 2035, the new natural gas capacity is 
comprised of 24 GW of simple cycle combustion turbines and 37 GW of 
combined cycle combustion turbines. By 2050, most of the incremental 
new capacity is projected to come just from simple cycle combustion 
turbines. This also represents a higher rate of new simple cycle 
combustion turbine builds compared to the reference periods (i.e., 
2000-2006 and 2007-2021) discussed previously in this section.
    It should be noted that despite this increase in capacity, both 
overall generation and emissions from the natural gas-fired capacity 
are projected to decline. Generation from natural gas units is 
projected to fall from 1,579 thousand GWh in 2021 \163\ to 1,402 
thousand GWh by 2035. Power sector related CO2 emissions 
from natural gas-fired EGUs were 615 million metric tons in 2021.\164\ 
By 2035, emission levels are projected to reach 527 million metric 
tons, 93 percent of which comes from NGCC sources.
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    \163\ U.S. Energy Information Administration (EIA), Electric 
Power Annual, table 3.1.A. November 2022. https://www.eia.gov/electricity/annual/.
    \164\ U.S. Environmental Protection Agency, Inventory of U.S. 
Greenhouse Gas Emission Sources and Sinks. February 2023. https://www.epa.gov/system/files/documents/2023-02/US-GHG-Inventory-2023-Main-Text.pdf.
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    The decline in generation and emissions is driven by a projected 
decline in NGCC capacity factors. In model projections, NGCC units have 
a capacity factor early in the projection period of 64 percent, but by 
2035, capacity factor projections fall to 50 percent as many of these 
units switch from base load operation to more intermediate load 
operation to support the integration of variable renewable energy 
resources. Natural gas simple cycle combustion turbine capacity factors 
also fall, although since they are used primarily as a peaking resource 
and their capacity factors are already below 10 percent annually, their 
impact on generation and emissions changes are less notable.
    Some of the reasons for this continued growth in natural gas-fired 
capacity include anticipated sustained lower fuel costs and the greater 
efficiency and flexibility offered by combustion turbines. Simple cycle 
combustion turbines operate at lower efficiencies but offer fast 
startup times to meet peaking load demands. In addition, combustion 
turbines, along with energy storage technologies, support the expansion 
of renewable electricity by meeting demand during peak periods and 
providing flexibility around the variability of renewable generation 
and electricity demand. In the longer term, as renewables and battery 
storage grow, they are anticipated to outcompete the need for natural 
gas-fired generation and the overall utilization of natural gas-fired 
capacity is expected to decline.
3. Projections for Renewable Generation
    The EIA's Short-Term Energy Outlook (STEO) suggests that the U.S. 
will continue its expansion of wind and solar renewable capacity with 
most of the growth in electricity capacity additions in the next 2 
years to come from renewable energy sources.\165\ The EIA projects 
utility-scale solar capacity to grow by approximately 29 GW in 2023 and 
by 35 GW in 2024 wind generating capacity to grow by 7 GW in 2023 and 
by 7.5 GW in 2024. These increases in new renewable capacity will 
continue to reduce the demand for fossil fuel-fired generation.
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    \165\ U.S. Energy Information Administration (EIA). Short-Term 
Energy Outlook, March 2023. https://www.eia.gov/outlooks/steo/.
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    In the post-IRA 2022 reference case projections, shows that this 
short-term trend in renewable capacity is expected to continue. Non-
hydroelectric utility-scale renewable capacity is projected to increase 
from 209 GW in 2021 to 668 GW by 2035 and then to 1,293 GW by 2050. 
This capacity growth is comprised mostly of wind and solar. The post-
IRA 2022 reference case shows projections of 399 GW of wind capacity by 
2035 and 748 GW by 2050. Utility-scale solar capacity has a similar 
trajectory with 263 GW by 2035 and 539 GW by 2050 and small-scale or 
distributed solar capacity (e.g., rooftop solar) similarly increases 
from 33 GW in 2021 to 198 GW in 2050.\166\ In total, non-hydroelectric 
utility-scale renewable generation is projected to produce 45 percent 
of electricity generation by 2035 in the post-IRA 2022 reference case.
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    \166\ U.S. Energy Information Administration (EIA), Electric 
Power Annual, table 4.3. November 2022. https://www.eia.gov/electricity/annual/.
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4. Projections for Energy Storage
    According to EIA, the capacity of battery energy storage is 
expected to increase by 10 times between 2019 and 2023, of which 6 GW 
of battery storage capacity is planned to be co-located with solar 
generation.\167\ The benefit of paring energy storage systems with 
solar capacity deployment is that the batteries can recharge throughout 
the middle of the day when surplus energy is available. Then this 
stored energy can be discharged during peak hours, supporting grid 
reliability and potentially displacing higher emitting generation. This 
also reduces curtailment of renewable energy when generation exceeds 
demand.
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    \167\ U.S. Energy Information Administration (EIA). Preliminary 
Monthly Electric Generator Inventory, December 2020 Form EIA-860M. 
https://www.eia.gov/analysis/studies/electricity/batterstorage/.
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    The build out of energy storage is projected to continue in the 
long-term, enabling the integration of renewable technologies with 
lower emission consequences. The post-IRA 2022 reference case shows 
projections of 97 GW of energy storage to be available on the grid by 
2035 and 152 GW by 2050.
5. Projections for Nuclear Energy
    The post-IRA 2022 reference case shows a steady decline in nuclear 
generating capacity, dropping from 96 GW in 2021 to 84 GW or by 12 
percent by 2035. In the short-term, capacity reductions are expected to 
be delayed in part due to programs passed as part of the IIJA and IRA. 
These acts, along with several State programs, support the continued 
use of existing nuclear facilities by providing payments that

[[Page 33266]]

will likely keep reactors in affected regions profitable for the next 
5-10 years.168 169 After 2035, the EPA projects nuclear 
capacity retirements to occur as EGUs begin to age out of operation, 
and by 2050, the nuclear fleet is projected to reduce by more than 
half, to 45 GW. However, breakthrough technologies like small modular 
reactors, if successful, could result in higher levels of nuclear 
capacity than discussed here. For example, output from advanced nuclear 
generation could range from negligible to as high as 3,600 terawatt-
hours per year by 2050.\170\
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    \168\ ``Constellation Making Major Investments in Two Illinois 
Nuclear Plants to Increase Clean Energy Output.'' Constellation 
Energy Corporation. February 21, 2023. https://www.constellationenergy.com/newsroom/2023/Constellation-Making-Major-Investment-in-Two-Illinois-Nuclear-Plants-to-Increase-Clean-Energy-Output.html.
    \169\ Singer, S. (February 22, 2023). PSEG to consider nuclear 
plant investments, capitalizing on the IRA's production tax credits, 
CEO says. Utility Dive. https://www.utilitydive.com/news/pseg-ira-nuclear-production-tax-credits/643221/.
    \170\ ``Advancing Nuclear Energy Evaluating Deployment, 
Investment, and Impact in America's Clean Energy Future'' 
Breakthrough Institute, July 6, 2022.
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V. Statutory Background and Regulatory History for CAA Section 111

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

    The EPA's authority for and obligation to issue these proposed 
rules is CAA section 111, which establishes mechanisms for controlling 
emissions of air pollutants from new and existing stationary sources. 
CAA section 111(b)(1)(A) requires the EPA Administrator to promulgate a 
list of categories of stationary sources that the Administrator, in his 
or her judgment, finds ``causes, or contributes significantly to, air 
pollution which may reasonably be anticipated to endanger public health 
or welfare.'' The EPA has the authority to define the scope of the 
source categories, determine the pollutants for which standards should 
be developed, and distinguish among classes, types, and sizes within 
categories in establishing the standards.
1. Regulation of Emissions From New Sources
    Once the EPA lists a source category, the EPA must, under CAA 
section 111(b)(1)(B), establish ``standards of performance'' for 
emissions of air pollutants from new sources (including modified and 
reconstructed sources) in the source category. Under CAA section 
111(a)(2), a ``new source'' is defined as ``any stationary source, the 
construction or modification of which is commenced after the 
publication of regulations (or, if earlier, proposed regulations) 
prescribing a standard of performance under this section, which will be 
applicable to such source.'' Under CAA section 111(a)(3), a 
``stationary source'' is defined as ``any building, structure, 
facility, or installation which emits or may emit any air pollutant.'' 
Under CAA section 111(a)(4), ``modification'' means any physical change 
in, or change in the method of operation of, a stationary source which 
increases the amount of any air pollutant emitted by such source or 
which results in the emission of any air pollutant not previously 
emitted. While this provision treats modified sources as new sources, 
EPA regulations also treat a source that undergoes ``reconstruction'' 
as a new source. Under the provisions in 40 CFR 60.15, 
``reconstruction'' means the replacement of components of an existing 
facility such that: (1) The fixed capital cost of the new components 
exceeds 50 percent of the fixed capital cost that would be required to 
construct a comparable entirely new facility; and (2) it is 
technologically and economically feasible to meet the applicable 
standards. Pursuant to CAA section 111(b)(1)(B), the standards of 
performance or revisions thereof shall become effective upon 
promulgation.
    The standards of performance for new sources are referred to as new 
source performance standards, or NSPS. The NSPS are national 
requirements that apply directly to the sources subject to them.
    In setting or revising a performance standard, CAA section 
111(a)(1) provides that performance standards are to reflect ``the 
degree of emission limitation achievable through the application of the 
best system of emission reduction which (taking into account the cost 
of achieving such reduction and any nonair quality health and 
environmental impact and energy requirements) the Administrator 
determines has been adequately demonstrated.'' The term ``standard of 
performance'' in CAA 111(a)(1) makes clear that the EPA is to determine 
both the ``best system of emission reduction . . . adequately 
demonstrated'' (BSER) for the regulated sources in the source category 
and the ``degree of emission limitation achievable through the 
application of the [BSER].'' West Virginia v. EPA, 142 S. Ct. 2587, 
2601 (2022). To determine the BSER, the EPA first identifies the 
``system[s] of emission reduction'' that are ``adequately 
demonstrated,'' and then determines the ``best'' of those systems, 
``taking into account'' factors including ``cost,'' ``nonair quality 
health and environmental impact,'' and ``energy requirements.'' The EPA 
then derives from that system an ``achievable'' ``degree of emission 
limitation.'' The EPA must then, under CAA section 111(b)(1)(B), 
promulgate ``standard[s] for emissions''--the NSPS--that reflect that 
level of stringency.
2. Regulation of Emissions From Existing Sources
    When the EPA establishes a standard for emissions of an air 
pollutant from new sources within a category, it must also, under CAA 
section 111(d), regulate emissions of that pollutant from existing 
sources within the same category, unless the pollutant is regulated 
under the National Ambient Air Quality Standards (NAAQS) program, under 
CAA sections 108-110, or the National Emission Standards for Hazardous 
Air Pollutants (NESHAP) program, under CAA section 112. See CAA section 
111(d)(1)(A)(i) and (ii); West Virginia, 142 S. Ct. at 2601.
    CAA section 111(d) establishes a framework of ``cooperative 
federalism for the regulation of existing sources.'' American Lung 
Ass'n, 985 F.3d at 931. CAA sections 111(d)(1)(A)-(B) require ``[t]he 
Administrator . . . to prescribe regulations'' that require ``[e]ach 
state . . . to submit to [EPA] a plan . . . which establishes standards 
of performance for any existing stationary source for'' the air 
pollutant at issue, and which ``provides for the implementation and 
enforcement of such standards of performance.'' CAA section 111(a)(6) 
defines an ``existing source'' as ``any stationary source other than a 
new source.''
    To meet these requirements, the EPA promulgates ``emission 
guidelines'' that identify the BSER and the degree of emission 
limitation achievable through the application of the BSER. Each State 
must then establish standards of performance for its sources that 
reflect that level of stringency. However, the states need not compel 
regulated sources to adopt the particular components of the BSER 
itself. The EPA's emission guidelines must also permit a State, ``in 
applying a standard of performance to any particular source,'' to 
``take into consideration, among other factors, the remaining useful 
life of the existing source to which such standard applies.'' 42 U.S.C. 
7411(d)(1). Once a State receives the EPA's approval of its plan, the 
provisions in the plan become federally enforceable against the source, 
in the same manner as the provisions of an approved State 
Implementation Plan (SIP) under the Act. If a State elects not to 
submit a plan or submits a plan that

[[Page 33267]]

the EPA does not find ``satisfactory,'' the EPA must promulgate a plan 
that establishes Federal standards of performance for the State's 
existing sources. CAA section 111(d)(2)(A).
3. EPA Review of Requirements
    CAA section 111(b)(1)(B) requires the EPA to ``at least every 8 
years, review and, if appropriate, revise'' new source performance 
standards. However, the Administrator need not review any such standard 
if the ``Administrator determines that such review is not appropriate 
in light of readily available information on the efficacy'' of the 
standard. Id. When conducting a review of an NSPS, the EPA has the 
discretion and authority to add emission limits for pollutants or 
emission sources not currently regulated for that source category. CAA 
section 111 does not by its terms require the EPA to review emission 
guidelines for existing sources, but the EPA retains the authority to 
do so. See 81 FR 59276, 59277 (August 29, 2016) (explaining legal 
authority to review emission guidelines for municipal solid waste 
landfills).

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

    The EPA has listed more than 60 stationary source categories under 
CAA section 111(b)(1)(A). See 40 CFR part 60, subparts Cb-OOOO. In 
1971, the EPA listed fossil fuel-fired EGUs (which includes natural 
gas, petroleum, and coal) that use steam-generating boilers in a 
category under CAA section 111(b)(1)(A). See 36 FR 5931 (March 31, 
1971) (listing ``fossil fuel-fired steam generators of more than 250 
million Btu per hour heat input''). In 1977, the EPA listed fossil 
fuel-fired combustion turbines, which can be used in EGUs, in a 
category under CAA section 111(b)(1)(A). See 42 FR 53657 (October 3, 
1977) (listing ``stationary gas turbines'').
    In 2015, the EPA promulgated two rules that addressed 
CO2 emissions from fossil fuel-fired EGUs. The first 
promulgated standards of performance for new fossil fuel-fired EGUs. 
``Standards of Performance for Greenhouse Gas Emissions From New, 
Modified, and Reconstructed Stationary Sources: Electric Utility 
Generating Units; Final Rule,'' (80 FR 64510; October 23, 2015) (2015 
NSPS). The second promulgated emission guidelines for existing sources. 
``Carbon Pollution Emission Guidelines for Existing Stationary Sources: 
Electric Utility Generating Units; Final Rule,'' (80 FR 64662; October 
23, 2015) (Clean Power Plan, or CPP).
1. 2015 NSPS
    In 2015, the EPA promulgated an NSPS to limit emissions of GHGs, 
manifested as CO2, from newly constructed, modified, and 
reconstructed fossil fuel-fired electric utility steam generating 
units, i.e., utility boilers and IGCC EGUs, and newly constructed and 
reconstructed stationary combustion turbine EGUs. These final standards 
are codified in 40 CFR part 60, subpart TTTT.
    In promulgating the NSPS for newly constructed fossil fuel-fired 
steam generating units, the EPA determined the BSER to be a new, highly 
efficient, supercritical pulverized coal (SCPC) EGU that implements 
post-combustion partial CCS technology. The EPA concluded that CCS was 
adequately demonstrated (including being technically feasible) and 
widely available and could be implemented at reasonable cost. The EPA 
identified natural gas co-firing and IGCC technology (either with 
natural gas co-firing or implementing partial CCS) as alternative 
methods of compliance.
    The 2015 NSPS included standards of performance for steam 
generating units that undergo a ``reconstruction'' as well as units 
that implement ``large modifications,'' (i.e., modifications resulting 
in an increase in hourly CO2 emissions of more than 10 
percent). The 2015 NSPS did not establish standards of performance for 
steam generating units that undertake ``small modifications'' (i.e., 
modifications resulting in an increase in hourly CO2 
emissions of less than or equal to 10 percent), due to the limited 
information available to inform the analysis of a BSER and 
corresponding standard of performance.
    The 2015 NSPS also finalized standards of performance for newly 
constructed and reconstructed stationary combustion turbine EGUs. For 
newly constructed and reconstructed base load natural gas-fired 
stationary combustion turbines, the EPA finalized a standard based on 
efficient NGCC technology as the BSER. For newly constructed and 
reconstructed non-base load natural gas-fired stationary combustion 
turbines and for both base load and non-base load multi-fuel-fired 
stationary combustion turbines, the EPA finalized a heat input-based 
standard based on the use of lower emitting fuels (referred to as clean 
fuels in the 2015 NSPS). The EPA did not promulgate final standards of 
performance for modified stationary combustion turbines due to lack of 
information. These standards remain in effect today.
    The EPA received six petitions for reconsideration of the 2015 
NSPS. On May 6, 2016 (81 FR 27442), the EPA denied five of the 
petitions on the basis they did not satisfy the statutory conditions 
for reconsideration under CAA section 307(d)(7)(B), and deferred action 
on one petition that raised the issue of the treatment of biomass.
    Multiple parties also filed petitions for judicial review of the 
2015 NSPS in the D.C. Circuit. These cases have been briefed and, on 
the EPA's motion, are being held in abeyance while the Agency reviews 
the rule and considers whether to propose revisions to it.
    In the 2015 NSPS, the EPA noted that it was authorized to regulate 
GHGs from the fossil fuel-fired EGU source categories because it had 
listed those source categories under CAA section 111(b)(1)(A). The EPA 
added that CAA section 111 did not require it to make a determination 
that GHGs from EGUs contribute significantly to dangerous air pollution 
(a pollutant-specific significant contribution finding), but in the 
alternative, the EPA did make that finding. It explained that 
``[greenhouse gas] air pollution may reasonably be anticipated to 
endanger public health or welfare,'' 80 FR 64530 (October 23, 2015) and 
emphasized that power plants are ``by far the largest emitters'' of 
greenhouse gases among stationary sources in the U.S. Id. at 64522. In 
American Lung Ass'n v. EPA, 985 F.3d 977 (D.C. Cir. 2021), the court 
held that even if the EPA were required to determine that 
CO2 from fossil fuel-fired EGUs contributes significantly to 
dangerous air pollution--and the court emphasized that it was not 
deciding that the EPA was required to make such a pollutant-specific 
determination--the determination in the alternative that the EPA made 
in the 2015 NSPS was not arbitrary and capricious and, accordingly, the 
EPA had a sufficient basis to regulate greenhouse gases from EGUs under 
CAA section 111(d) in the ACE Rule. The EPA is not reopening or 
soliciting comment on any of those determinations in the 2015 NSPS 
concerning its rational basis to regulate GHG emissions from EGUs or 
its alternative finding that GHG emissions from EGUs contribute 
significantly to dangerous air pollution.
2. 2018 Proposal To Revise the 2015 NSPS
    In 2018, the EPA proposed to revise the NSPS for new, modified, and 
reconstructed fossil fuel-fired steam generating units and IGCC units. 
``Review of Standards of Performance

[[Page 33268]]

for Greenhouse Gas Emissions From New, Modified, and Reconstructed 
Stationary Sources: Electric Utility Generating Units; Proposed Rule,'' 
(83 FR 65424; December 20, 2018) (2018 NSPS Proposal). The EPA proposed 
to revise the NSPS for newly constructed units, based on a revised BSER 
of a highly efficient SCPC, without partial CCS. The EPA also proposed 
to revise the NSPS for modified and reconstructed units. The EPA has 
not taken further action on this proposed rule.\171\
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    \171\ In the 2018 NSPS Proposal, the EPA solicited comment on 
whether it is required to make a determination that GHGs from a 
source category contribute significantly to dangerous air pollution 
as a predicate to promulgating a NSPS for GHG emissions from that 
source category for the first time. 83 FR 65432 (December 20, 2018). 
The EPA subsequently issued a final rule that provided that it would 
not regulate GHGs under CAA section 111 from a source category 
unless the GHGs from the category exceed 3 percent of total U.S. GHG 
emissions, on grounds that GHGs emitted in a lesser amount do not 
contribute significantly to dangerous air pollution. 86 FR 2652 
(January, 13 2021). Shortly afterwards, the D.C. Circuit granted an 
unopposed motion by the EPA for voluntary vacatur and remand of the 
final rule. California v. EPA, No. 21-1035, doc. 1893155 (D.C. Cir. 
April 5, 2021).
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3. Clean Power Plan
    With the promulgation of the 2015 NSPS, the EPA also incurred a 
statutory obligation under CAA section 111(d) to issue emission 
guidelines for GHG emissions from existing fossil fuel-fired steam 
generating EGUs and stationary combustion turbine EGUs, which the EPA 
initially fulfilled with the promulgation of the CPP. See 80 FR 64662 
(October 23, 2015). The EPA first determined that the BSER included 
three types of measures: (1) Improving heat rate (i.e., the amount of 
fuel that must be burned to generate a unit of electricity) at coal-
fired steam plants; (2) substituting increased generation from lower-
emitting NGCC plants for generation from higher-emitting steam plants 
(which are primarily coal-fired); and (3) substituting increased 
generation from new renewable energy sources for generation from fossil 
fuel-fired steam plants and combustion turbines. See 80 FR 64667 
(October 23, 2015). The latter two measures are known as ``generation 
shifting'' because they involve shifting electricity generation from 
higher-emitting sources to lower-emitting ones. See 80 FR 64728-29 
(October 23, 2015).
    The EPA based this BSER determination on a technical record that 
evaluated generation-shifting, including its cost-effectiveness, 
against the relevant statutory criteria for BSER and on a legal 
interpretation that the term ``system'' in CAA section 111(a)(1) is 
sufficiently broad to encompass shifting of generation from higher-
emitting to lower-emitting sources. See 80 FR 64720 (October 23, 2015). 
The EPA then determined the ``degree of emission limitation achievable 
through the application of the [BSER],'' CAA section 111(a)(1), 
expressed as emission performance rates. See 80 FR 64667 (October 23, 
2015). The EPA explained that a State would ``have to ensure, through 
its plan, that the emission standards it establishes for its sources 
individually, in the aggregate, or in combination with other measures 
undertaken by the [S]tate, represent the equivalent of'' those 
performance rates (80 FR 64667; October 23, 2015). Neither states nor 
sources were required to apply the specific measures identified in the 
BSER (80 FR 64667; October 23, 2015), and states could include trading 
or averaging programs in their State plans for compliance. See 80 FR 
64840 (October 23, 2015).
    Numerous states and private parties petitioned for review of the 
CPP before the D.C. Circuit. On February 9, 2016, the U.S. Supreme 
Court stayed the rule pending review, West Virginia v. EPA, 577 U.S. 
1126 (2016), and the D.C. Circuit held the litigation in abeyance, and 
ultimately dismissed it, as the EPA reassessed its position. American 
Lung Ass'n, 985 F.3d at 937.
4. The CPP Repeal and ACE Rule
    In 2019, the EPA repealed the CPP and replaced it with the ACE 
Rule. In contrast to its interpretation of CAA section 111 in the CPP, 
in the ACE Rule the EPA determined that the statutory ``text and 
reasonable inferences from it'' make ``clear'' that a ``system'' of 
emission reduction under CAA section 111(a)(1) ``is limited to measures 
that can be applied to and at the level of the individual source,'' (84 
FR 32529; July 8, 2019); that is, the system must be limited to control 
measures that could be applied at and to each source to reduce 
emissions at each source. See 84 FR 32523-24 (July 8, 2019). 
Specifically, the ACE Rule argued that the requirements in CAA sections 
111(d)(1), (a)(3), and (a)(6), that each State establish a standard of 
performance ``for'' ``any existing source,'' defined, in general, as 
any ``building . . . [or] facility,'' and the requirement in CAA 
section 111(a)(1) that the degree of emission limitation must be 
``achievable'' through the ``application'' of the BSER, by their terms, 
impose this limitation. The EPA concluded that generation shifting is 
not such a control measure. See 84 FR 32546 (July 8, 2019). Based on 
its view that the CPP was a ``major rule,'' the EPA further determined 
that, absent ``a clear statement from Congress,'' the term ```system of 
emission reduction''' should not be read to encompass ``generation-
shifting measures.'' See 84 FR 32529 (July 8, 2019). The EPA 
acknowledged, however, that ``[m]arket-based forces ha[d] already led 
to significant generation shifting in the power sector,'' (84 FR 32532; 
July 8, 2019), and that there was ``likely to be no difference between 
a world where the CPP is implemented and one where it is not.'' See 84 
FR 32561 (July 8, 2019); the Regulatory Impact Analysis for the Repeal 
of the Clean Power Plan, and the Emission Guidelines for Greenhouse Gas 
Emissions from Existing Electric Utility Generating Units, 2-1 to 2-
5.\172\
---------------------------------------------------------------------------

    \172\ https://www.epa.gov/sites/default/files/2019-06/documents/utilities_ria_final_cpp_repeal_and_ace_2019-06.pdf.
---------------------------------------------------------------------------

    In addition, the EPA promulgated in the ACE Rule a new set of 
emission guidelines for existing coal-fired steam-generating EGUs. See 
84 FR 32532 (July 8, 2019). In light of ``the legal interpretation 
adopted in the repeal of the CPP,'' (84 FR 32532; July 8, 2019)--which 
``limit[ed] `standards of performance' to systems that can be applied 
at and to a stationary source,'' (84 FR 32534; July 8, 2019)--the EPA 
found the BSER to be heat rate improvements alone. See 84 FR 32535 
(July 8, 2019). The EPA listed various technologies that could improve 
heat rate (84 FR 32536; July 8, 2019), and identified the ``degree of 
emission limitation achievable'' by ``providing ranges of expected 
[emission] reductions associated with each of the technologies.'' See 
84 FR 32537-38 (July 8, 2019).
    The EPA also stated that, under the ACE Rule, compliance measures 
that the State plans could authorize the sources to implement ``should 
correspond with the approach used to set the standard in the first 
place,'' (84 FR 32556; July 8, 2019), and therefore must ``apply at and 
to an individual source and reduce emissions from that source.'' See 84 
FR 32555-56 (July 8, 2019). The EPA concluded that various measures 
besides generation shifting--including averaging (i.e., allowing 
multiple sources to average their emissions to meet an emission-
reduction goal), and trading (i.e., allowing sources to exchange 
emission credits or allowances)--did not meet that requirement. The EPA 
therefore barred states from using such measures in their plans. See 84 
FR 32556 (July 8, 2019).

[[Page 33269]]

5. D.C. Circuit Decision in American Lung Association v. EPA Concerning 
the CPP Repeal and ACE Rule
    Numerous states and private parties petitioned for review of the 
CPP Repeal and ACE Rule. In 2021, the D.C. Circuit vacated the ACE 
Rule, including the CPP Repeal. American Lung Ass'n v. EPA, 985 F.3d 
914 (D.C. Cir. 2021). The court held, among other things, that CAA 
section 111(d) does not limit the EPA, in determining the BSER, to 
measures applied at and to an individual source. The court noted that 
``the sole ground on which the EPA defends its abandonment of the [CPP] 
in favor of the ACE Rule is that the text of [CAA section 111] is clear 
and unambiguous in constraining the EPA to use only improvements at and 
to existing sources in its [BSER].'' 985 F.3d at 944. The court found 
``nothing in the text, structure, history, or purpose of [CAA section 
111] that compels the reading the EPA adopted.'' 985 F.3d at 957. The 
court explained that contrary to the ACE Rule, the above-noted 
requirements in CAA section 111 that each State must establish a 
standard of performance ``for'' any existing ``building . . . [or] 
facility,'' mean that the State must establish standards applicable to 
each regulated stationary source; and the requirements that the degree 
of emission limitation must be achievable through the ``application'' 
of the BSER could be read to mean that the sources must be able to 
apply the system to reduce emissions across the source category. None 
of these requirements, the court further explained, can be read to 
mandate that the BSER is limited to some measure that each source can 
apply to its own facility to reduce its own emissions in a specified 
amount. 985 F.3d at 944-51. The court likewise rejected the view that 
the CPP's use of generation-shifting implicated a ``major question'' 
requiring unambiguous authorization by Congress. 985 F.3d at 958-68.
    Having rejected the CPP Repeal Rule's view, also reflected in the 
ACE Rule, that CAA section 111 unambiguously requires that the BSER be 
``one that can be applied to and at the individual source,'' the court 
also ``reject[ed] the ACE Rule's exclusion from [CAA section 111(d)] of 
compliance measures'' that do not meet that requirement. 985 F.3d at 
957. Thus, the court held that CAA section 111 does not preclude states 
from allowing trading or averaging. The court explained that the ACE 
Rule's premise for its view that compliance measures are limited to 
measures applied at and to an individual source is that BSER measures 
are so limited, but the court further stated that this premise was 
invalid. The court added that in any event, CAA section 111(d) says 
nothing about the type of compliance measures states may adopt, 
regardless of what the EPA identifies as the BSER. Id. at 957-58.
    The D.C. Circuit concluded that, because the EPA had relied on an 
``erroneous legal premise,'' both the CPP Repeal Rule and the ACE Rule 
should be vacated. 985 F.3d at 995. The court did not decide, however, 
``whether the approach of the ACE Rule is a permissible reading of the 
statute as a matter of agency discretion,'' 985 F.3d at 944, and 
instead ``remanded to the EPA so that the Agency may `consider the 
question afresh,' '' 985 F.3d at 995 (citations omitted). The court 
also rejected the arguments that the EPA cannot regulate CO2 
emissions from coal-fired power plants under CAA section 111(d) at all 
because it had already regulated mercury emissions from coal-fired 
power plants under CAA section 112. 985 F.3d at 988. In addition, the 
court held that that the 2015 NSPS included a valid determination that 
greenhouse gases from the EGU source category contributed significantly 
to dangerous air pollution, which provided a sufficient basis for a CAA 
section 111(d) rule regulating greenhouse gases from existing fossil 
fuel-fired EGUs. Id. at 977.
    Because the D.C. Circuit vacated the ACE Rule on the grounds noted 
above, it did not address the numerous other challenges to the ACE 
Rule, including the arguments by Petitioners that the heat rate 
improvement BSER was inadequate because of the limited amount of 
reductions it achieved and because the ACE Rule failed to include an 
appropriately specific degree of emission limitation.
    Upon a motion from the EPA, the D.C. Circuit agreed to stay its 
mandate with respect to vacatur of the CPP Repeal, American Lung Assn 
v. EPA, No. 19-1140, Order (February 22, 2021), so that the CPP 
remained repealed. In its motion, the EPA explained that the CPP should 
remain repealed because the deadline for states to submit their plans 
under the CPP had long since passed. In addition, and most importantly, 
because of ongoing changes in electricity generation--in particular, 
retirements of coal-fired electricity generation--the emissions 
reductions that the CPP was projected to achieve had already been 
achieved by 2021. American Lung Assn v. EPA, No. 19-1140, Respondents' 
Motion for a Partial Stay of Issuance of the Mandate (February 12, 
2021). Therefore, following the D.C. Circuit's decision, no EPA rule 
under CAA section 111 to reduce GHGs from existing fossil fuel-fired 
EGUs remained in place.
6. U.S. Supreme Court Decision in West Virginia v. EPA Concerning the 
CPP
    In 2022, the U.S. Supreme Court reversed the D.C. Circuit's vacatur 
of the ACE Rule's embedded repeal of the CPP. West Virginia v. EPA, 142 
S. Ct. 2587 (2022). The Supreme Court made clear that CAA section 111 
authorizes the EPA to determine the BSER and the degree of emission 
limitation that State plans must achieve. Id. at 2601-02. However, the 
Supreme Court invalidated the CPP's generation-shifting BSER under the 
major questions doctrine. The Court characterized the generation-
shifting BSER as ``restructuring the Nation's overall mix of 
electricity generation,'' and stated that the EPA's claim that CAA 
section 111 authorized it to promulgate generation shifting as the BSER 
was ``not only unprecedented; it also effected a fundamental revision 
of the statute, changing it from one sort of scheme of regulation into 
an entirely different kind.'' Id. at 2612 (internal quotation marks, 
brackets, and citation omitted). The Court explained that the EPA, in 
prior rules under CAA section 111, had set emissions limits based on 
``measures that would reduce pollution by causing the regulated source 
to operate more cleanly.'' Id. at 2610. The Court noted with approval 
those ``more traditional air pollution control measures,'' and gave as 
examples ``fuel-switching'' and ``add-on controls,'' which, the Court 
observed, the EPA had considered in the CPP. Id. at 2611 (internal 
quotations marks and citation omitted). In contrast, the Court 
continued, generation-shifting was ``unprecedented'' because ``[r]ather 
than focus on improving the performance of individual sources, it would 
improve the overall power system by lowering the carbon intensity of 
power generation. And it would do that by forcing a shift throughout 
the power grid from one type of energy source to another.'' Id. at 
2611-12 (internal quotation marks, emphasis, and citation omitted). The 
Court also emphasized that the adoption of generation shifting was 
based on a ``very different kind of policy judgment [than prior CAA 
section 111 rules]: that it would be `best' if coal made up a much 
smaller share of national electricity generation.'' Id. at 2612. The 
Court recognized that a rule based on traditional measures ``may end up 
causing an incidental loss of coal's market share,'' but emphasized 
that the

[[Page 33270]]

CPP was ``obvious[ly] differen[t]'' because, with its generation-
shifting BSER, it ``simply announc[ed] what the market share of coal, 
natural gas, wind, and solar must be, and then require[ed] plants to 
reduce operations or subsidize their competitors to get there.'' Id. at 
2613 n. 4. Beyond highlighting the novelty of generation shifting, the 
Court also emphasized ``the magnitude and consequence'' of the CPP. Id. 
at 2616. It noted ``the magnitude of this unprecedented power over 
American industry,'' id. at 2612 (internal quotation marks and citation 
omitted), and added that the EPA's adoption of generation shifting 
``represent[ed] a transformative expansion in its regulatory 
authority.'' Id. at 2610 (internal quotation marks and citation 
omitted). The Court also viewed the CPP as promulgating ``a program 
that . . . Congress had considered and rejected multiple times.'' Id. 
at 2614 (internal quotation marks and citation omitted). The Court 
explained that ``[a]t bottom, the [CPP] essentially adopted a cap-and-
trade scheme, or set of state cap-and-trade schemes, for carbon,'' and 
that Congress ``has consistently rejected proposals to amend the Clean 
Air Act to create such a program.'' Id.
    For these and related reasons, the Court viewed the CPP as raising 
a major question, and therefore, under the major questions doctrine, 
required ``clear congressional authorization'' as a basis. Id. 
(internal quotation marks and citation omitted). The EPA had defended 
generation shifting as qualifying as a ``system of emission reduction'' 
under CAA section 111(a)(1), but the Court found that the term 
``system'' is ``a vague statutory grant [that] is not close to the sort 
of clear authorization required'' under the doctrine, id., and, on that 
basis, invalidated the CPP.
    The Court declined to address the D.C. Circuit's conclusion that 
the text of CAA section 111 did not limit the type of ``system'' the 
EPA could consider as the BSER to measures applied at and to an 
individual source. See id. at 2615 (``We have no occasion to decide 
whether the statutory phrase `system of emission reduction' refers 
exclusively to measures that improve the pollution performance of 
individual sources, such that all other actions are ineligible to 
qualify as the BSER.'' (emphasis in original)). Nor did the Court 
address the scope of the States' compliance flexibilities.

C. Detailed Discussion of CAA Section 111 Requirements

    This section discusses in more detail the key requirements of CAA 
section 111 for both new and existing sources that are relevant for 
these rulemakings.
Approach to the Source Category and Subcategorizing
    CAA section 111 requires the EPA first to list stationary source 
categories that cause or contribute to air pollution which may 
reasonably be anticipated to endanger public health or welfare and then 
to regulate new sources within each such source category. CAA section 
111(b)(2) grants the EPA discretion whether to ``distinguish among 
classes, types, and sizes within categories of new sources for the 
purpose of establishing [new source] standards,'' which we refer to as 
``subcategorizing.'' The D.C. Circuit has stated that whether and how 
to subcategorize is a decision for which the EPA is entitled to a 
``high degree of deference'' because it entails ``scientific 
judgement.'' Lignite Energy Council v. EPA, 198 F3d 930, 933 (D.C. Cir. 
1999); see Sierra Cub, v. Costle, 657 F.2d 298, 318-19 (D.C. Cir. 
1981).
    Although CAA section 111(d)(1) does not by its terms address 
subcategorization, the EPA interprets it to authorize the Agency to 
exercise discretion as to whether and, if so, how to subcategorize, for 
the following reasons. CAA section 111(d)(1) provides a broad grant of 
authority to the EPA, directing it to ``prescribe regulations which 
shall establish a procedure . . . under which each State shall submit 
to the Administrator a plan [with standards of performance for existing 
sources.]'' The EPA promulgates emission guidelines under this 
provision directing the States to regulate existing sources. The 
Supreme Court has recognized the breadth of authority that CAA section 
111(d) grants the EPA:

    Although the States set the actual rules governing existing 
power plants, EPA itself still retains the primary regulatory role 
in Section 111(d). The Agency, not the States, decides the amount of 
pollution reduction that must ultimately be achieved. It does so by 
again determining, as when setting the new source rules, ``the best 
system of emission reduction . . . that has been adequately 
demonstrated for [existing covered] facilities.''

West Virginia, 142 S. Ct. at 2601-02 (citations omitted). That this 
broad authority under CAA section 111(d) includes subcategorization 
follows from the fact that these provisions authorize the EPA to 
determine the BSER. Subcategorizing is a mechanism for determining 
different controls to be the BSER for different sets of sources. This 
is clear from CAA section 111(b)(2) itself, which authorizes the EPA to 
subcategorize new sources ``for the purpose of establishing . . . 
standards.'' In addition, the EPA's implementing regulations under CAA 
section 111(d), promulgated in 1975, 40 FR 53340 (November 17, 1975), 
provide that the Administrator will specify different emission 
guidelines or compliance times or both ``for different sizes, types, 
and classes of designated facilities when costs of control, physical 
limitations, geographical location, or [based on] similar factors.'' 
\173\ In promulgating this provision, the EPA made clear the purpose of 
subcategorization is to tailor the BSER for different sets of sources:
---------------------------------------------------------------------------

    \173\ 40 CFR 60.22(b)(5), 60.22a(b)(5). Because the definition 
of subcategories depends on characteristics relevant to the BSER, 
and because those characteristics can differ as between new and 
existing sources, the EPA may establish different subcategories as 
between new and existing sources.

    EPA's emission guidelines will reflect subcategorization within 
source categories where appropriate, taking into account differences 
in sizes and types of facilities and similar considerations, 
including differences in control costs that may be involved for 
sources located in different parts of the country. Thus, EPA's 
emission guidelines will in effect be tailored to what is reasonably 
---------------------------------------------------------------------------
achievable by particular classes of existing sources. . . .

Id. at 53343.
    The EPA's authority to ``distinguish among classes, types, and 
sizes within categories,'' as provided under CAA section 111(b)(2), 
generally allows the Agency to place types of sources into 
subcategories when they have characteristics that are relevant to the 
controls they can apply to reduce their emissions. This is consistent 
with the commonly understood meaning of the term ``type'' in CAA 
section 111(b)(2): ``a particular kind, class, or group,'' or 
``qualities common to a number of individuals that distinguish them as 
an identifiable class.'' See https://www.merriam-webster.com/dictionary/type. That is, subcategorization is appropriate for a set of 
sources that have qualities in common that are relevant for determining 
what controls are appropriate for those sources. And where the 
qualities in common are not relevant for determining what controls are 
appropriate, subcategorization is not appropriate. This view is 
consistent with the D.C. Circuit's interpretation of CAA section 
112(d)(1), which is a subcategorization provision that is substantially 
similar to CAA section 111(b)(2). In NRDC v. EPA, 489 F.3d 1364, 1375-
76 (D.C. Cir. 2007), the court upheld the EPA's decision under CAA 
section 112(d)(1) not to subcategorize sources subject to control 
requirements under CAA section 112(d)(3), known as the maximum 
achievable control technology (MACT) floor, on the basis of

[[Page 33271]]

costs. That was because the EPA is not authorized to consider costs in 
setting the MACT floor.\174\
---------------------------------------------------------------------------

    \174\ See Chem. Mfrs. Ass'n v. NRDC, 470 U.S. 116, 131 (1985) 
(Court interprets similar subcategorization provision under the 
Clean Water Act to grant the EPA broad discretion).
---------------------------------------------------------------------------

    The EPA has developed subcategories in numerous rulemakings under 
CAA section 111 since it began promulgating them in the 1970s. These 
rulemakings have included subcategories on the basis of the size of the 
sources, see 40 CFR 60.40b(b)(1)-(2) (subcategorizing certain coal-
fired steam generating units on the basis of heat input capacity); the 
types of fuel combusted, see Sierra Cub, v. EPA, 657 F.2d 298, 318-19 
(D.C. Cir. 1981) (upholding a rulemaking that established different 
NSPS ``for utility plants that burn coal of varying sulfur content''), 
2015 NSPS, 80 FR 64510, 64602 (table 15) (October 23, 2015) 
(subdividing new combustion turbines on the basis of type of fuel 
combusted); the types of equipment used to produce products, see 81 FR 
35824 (June 3, 2016) (promulgating separate NSPS for many types of oil 
and gas sources, such as centrifugal compressors, pneumatic 
controllers, and well sites); types of manufacturing processes used to 
produce product, see 42 FR 12022 (March 1, 1977) (announcing 
availability of final guideline document for control of atmospheric 
fluoride emissions from existing phosphate fertilizer plants) and 
``Final Guideline Document: Control of Fluoride Emissions From Existing 
Phosphate Fertilizer Plants, EPA-450/2-77-005 1-7 to 1-9, including 
table 1-2 (applying different control requirements for different 
manufacturing operations for phosphate fertilizer); levels of 
utilization of the sources, see 2015 NSPS, 80 FR 64510, 64602 (table 
15) (October 23, 2015) (dividing new natural gas-fired combustion 
turbines into the subcategories of base load and non-base load); the 
activity level of the sources, see 81 FR 59276, 59278-79 (August 29, 
2016) (dividing municipal solid waste landfills into the subcategories 
of active and closed landfills); and geographic location of the 
sources, see 71 FR 38482 (July 6, 2006) (SO2 NSPS for 
stationary combustion turbines subcategories turbines on the basis of 
whether they are located in, for example, a continental area, a 
noncontinental area, the part of Alaska north of the Arctic Circle, and 
the rest of Alaska), see also Sierra Club v. Costle, 657 F.2d 298, 330 
(D.C. Cir. 1981) (stating that the EPA could create different 
subcategories for new sources in the Eastern and Western U.S. for 
requirements that depend on water-intensive controls). As these 
references indicate, the EPA has subcategorized many times in 
rulemaking under CAA sections 111(b) and 111(d) and based on a wide 
variety of physical, locational, and operational characteristics. It 
should also be noted that in some instances, the EPA has declined to 
subcategorize. Lignite Energy Council, 198 F.3d at 933 (upholding EPA 
decision not to subcategorize utility boilers for purposes of 
NOX NSPS on grounds that the decision was not arbitrary and 
capricious).
    Regardless of whether the EPA subcategorizes within a source 
category for purposes of determining the BSER and the emission 
performance level for the emission guideline, a State retains certain 
flexibility in assigning standards of performance to its affected EGUs. 
The statutory framework for CAA section 111(d) emission guidelines, and 
the flexibilities available to States within that framework, are 
discussed below.
D.C. Circuit Order To Reinstate the ACE Rule
    On October 27, 2022, the D.C. Circuit responded to the U.S. Supreme 
Court's reversal by recalling its mandate for the vacatur of the ACE 
Rule. American Lung Ass'n v. EPA, No. 19-1140, Order (October 27, 
2022). Accordingly, at that time, the ACE Rule came back into effect. 
The court also revised its judgment to deny petitions for review 
challenging the CPP Repeal Rule, consistent with the West Virginia 
decision, so that the CPP remains repealed. The court took further 
action denying several of the petitions for review unaffected by the 
Supreme Court's decision in West Virginia, which means that certain 
parts of its 2021 decision in American Lung Ass'n remain valid. These 
parts include the holding that the EPA's prior regulation of mercury 
emissions from coal-fired electric power plants under CAA section 112 
does not preclude the Agency from regulating CO2 from coal-
fired electric power plants under CAA section 111, and the holding, 
discussed above, that the 2015 NSPS included a valid significant 
contribution determination and therefore provided a sufficient basis 
for a CAA section 111(d) rule regulating greenhouse gases from existing 
fossil fuel-fired EGUs. The court's holding to invalidate amendments to 
the implementing regulations applicable to emission guidelines under 
CAA section 111(d) that extended the preexisting schedules for State 
and Federal actions and sources' compliance, also remains valid. Based 
on the EPA's stated intention to replace the ACE Rule, the court stayed 
further proceedings with respect to the ACE Rule, including the various 
challenges that its BSER was flawed because it did not achieve 
sufficient emission reductions and failed to specify an appropriately 
specific degree of emission limitation.
3. Key Elements of Determining a Standard of Performance
    Congress first included the definition of ``standard of 
performance'' when enacting CAA section 111 in the 1970 Clean Air Act 
Amendments (CAAA), amended it in the 1977 CAAA, and then amended it 
again in the 1990 CAAA to largely restore the definition as it read in 
the 1970 CAAA. The current text of CAA section 111(a)(1) reads: ``The 
term `standard of performance' means a standard for emission of air 
pollutants which reflects the degree of emission limitation achievable 
through the application of the best system of emission reduction which 
(taking into account the cost of achieving such reduction and any non-
air quality health and environmental impact and energy requirements) 
the Administrator determines has been adequately demonstrated.'' The 
D.C. Circuit has reviewed CAA section 111 rulemakings on numerous 
occasions since 1973,\175\ and has developed a body of caselaw that 
interprets the term ``standard of performance,'' as discussed 
throughout this preamble.
---------------------------------------------------------------------------

    \175\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C. 
Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. 
Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981); 
Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999); 
Portland Cement Ass'n v. EPA, 665 F.3d 177 (D.C. Cir. 2011); 
American Lung Ass'n v. EPA, 985 F.3d 914 (D.C. Cir. 2021), rev'd in 
part, West Virginia v. EPA, 142 S. Ct. 2587 (2022). See also 
Delaware v. EPA, No. 13-1093 (D.C. Cir. May 1, 2015).
---------------------------------------------------------------------------

    The basis for standards of performance, whether promulgated by the 
EPA under CAA section 111(b) or established by the States under CAA 
section 111(d), is that the EPA determines the ``degree of emission 
limitation'' that is ``achievable'' by the sources by application of a 
``system of emission reduction'' that the EPA determines is 
``adequately demonstrated,'' ``taking into account'' the factors of 
``cost . . . nonair quality health and environmental impact and energy 
requirements,'' and that the EPA determines to be the ``best.'' The 
D.C. Circuit has stated that in determining the ``best'' system, the 
EPA must also take into account ``the amount of air

[[Page 33272]]

pollution'' \176\ reduced and the role of ``technological innovation.'' 
\177\ The determination of the ``best'' system entails weighing the 
various factors against each other, and the D.C. Circuit has emphasized 
that the EPA has discretion in weighing the factors.178 179
---------------------------------------------------------------------------

    \176\ See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 
1981).
    \177\ See Sierra Club v. Costle, 657 F.2d at 347.
    \178\ See Lignite Energy Council, 198 F.3d at 933.
    \179\ Although CAA section 111(a)(1) may be read to state that 
the factors enumerated in the parenthetical are part of the 
``adequately demonstrated'' determination, the D.C. Circuit's case 
law may be read to treat them as part of the ``best'' determination. 
See Sierra Club v. Costle, 657 F.2d at 330 (recognizing that CAA 
section 111 gives the EPA authority ``when determining the best 
technological system to weigh cost, energy, and environmental 
impacts''). Nevertheless, it does not appear that those two 
approaches would lead to different outcomes. See, e.g., Lignite 
Energy Council, 198 F.3d at 933 (rejecting challenge to the EPA's 
cost assessment of the ``best demonstrated system''). Regardless of 
whether the factors are part of the ``adequately demonstrated'' 
determination or the ``best'' determination, our analysis and 
outcome would be the same.
---------------------------------------------------------------------------

    The EPA's overall approach to determining the BSER and degree of 
emission limitation achievable, which incorporates the various 
elements, is as follows: The EPA identifies ``system[s] of emission 
reduction'' that have been ``adequately demonstrated'' for a particular 
source category and determines the ``best'' of these systems after 
evaluating the amount of reductions, costs, any nonair health and 
environmental impacts, and energy requirements. As discussed below, for 
each of numerous subcategories, the EPA followed this approach to 
propose the BSER on the basis that the identified costs are reasonable 
and that the proposed BSER is rational in light of the statutory 
factors and other impacts, including the amount of emission reductions, 
that the EPA examined in its BSER analysis, consistent with governing 
precedent.
    After determining the BSER, the EPA determines an achievable 
emission limit based on application of the BSER.\180\ For a CAA section 
111(b) rule, we determine the standard of performance that reflects the 
achievable emission limit. For a CAA section 111(d) rule, the States 
have the obligation of establishing standards of performance for the 
affected sources that reflect the degree of emission limitation that 
the EPA has determined. As discussed below, the EPA proposed these 
determinations in association with each of the proposed BSER 
determinations.
---------------------------------------------------------------------------

    \180\ See, e.g., Oil and Natural Gas Sector: New Source 
Performance Standards and National Emission Standards for Hazardous 
Air pollutants Reviews (77 FR 49490, 49494; August 16, 2012) 
(describing the three-step analysis in setting a standard of 
performance).
---------------------------------------------------------------------------

    The remainder of this subsection discusses each element in our 
general analytical approach.
a. System of Emission Reduction
    The CAA does not define the phrase ``system of emission 
reduction.'' In West Virginia v. EPA, the Supreme Court recognized that 
historically, the EPA had looked to ``measures that improve the 
pollution performance of individual sources and followed a 
``technology-based approach'' in identifying systems of emission 
reduction. In particular, the Court identified ``the sort of `systems 
of emission reduction' [the EPA] had always before selected,'' which 
included `` `efficiency improvements, fuel-switching,' and `add-on 
controls'.'' 142 S. Ct. at 2611 (quoting the Clean Power Plan).\181\ 
Section 111 itself recognizes that such systems may include off-site 
activities that may reduce a source's pollution contribution, 
identifying ``precombustion cleaning or treatment of fuels'' as a 
``system'' of ``emission reduction.'' 42 U.S.C. 7411(a)(7)(B). A 
``system of emission reduction'' thus, at a minimum, includes measures 
that an individual source applies that improve the emissions 
performance of that source. Measures are fairly characterized as 
improving the pollution performance of a source where they reduce the 
individual source's overall contribution to pollution.
---------------------------------------------------------------------------

    \181\ As noted in section V.B.4 of this preamble, the ACE Rule 
adopted the interpretation that CAA section 111(a)(1), by its plain 
language, limits ``system of emission reduction'' to those control 
measures that could be applied at and to each source to reduce 
emissions at each source. 84 FR 32523-24 (July 8, 2019). The EPA has 
proposed to reject that interpretation as too narrow. See 
``Implementing Regulations under 40 CFR part 60 Subpart Ba Adoption 
and Submittal of State Plans for Designated Facilities: Proposed 
Rule,'' 87 FR 79176, 79208 (December 23, 2022).
---------------------------------------------------------------------------

    In West Virginia, the Supreme Court did not define the term 
``system of emissions reduction,'' and so did not rule on whether 
``system of emission reduction'' is limited to those measures that the 
EPA has historically relied upon. It did go on to apply the major 
questions doctrine to hold that the term ``system'' does not provide 
the requisite clear authorization to support the Clean Power Plan's 
BSER, which the Court described as ``carbon emissions caps based on a 
generation shifting approach.'' Id. at 2614. While the Court did not 
define the outer bounds of the meaning of ``system,'' systems of 
emissions reduction like fuel switching, add-on controls, and 
efficiency improvements fall comfortably within the scope of prior 
practice as recognized by the Supreme Court.
b. ``Adequately Demonstrated''
    Under CAA section 111(a)(1), an essential, although not sufficient, 
condition for a ``system of emission reduction'' to serve as the basis 
for an ``achievable'' emission limitation, is that the Administrator 
must determine that the system is ``adequately demonstrated.'' This 
means, according to the D.C. Circuit, that the system is ``one which 
has been shown to be reasonably reliable, reasonably efficient, and 
which can reasonably be expected to serve the interests of pollution 
control without becoming exorbitantly costly in an economic or 
environmental way.'' \182\ It does not mean that the system ``must be 
in actual routine use somewhere.'' \183\ Rather, the court has said, 
``[t]he Administrator may make a projection based on existing 
technology, though that projection is subject to the restraints of 
reasonableness and cannot be based on `crystal ball' inquiry.'' \184\ 
Similarly, the EPA may ``hold the industry to a standard of improved 
design and operational advances, so long as there is substantial 
evidence that such improvements are feasible.'' \185\ Ultimately, the 
analysis ``is partially dependent on `lead time,' '' that is, ``the 
time in which the technology will have to be available.'' \186\ The 
caselaw is clear that the EPA may treat a set of control measures as 
``adequately demonstrated'' regardless of whether the measures are in 
widespread commercial use. For example, the D.C. Circuit upheld the 
EPA's determination that selective catalytic reduction (SCR) was 
adequately demonstrated to reduce NOX emissions from coal-
fired industrial boilers, even though it was a ``new technology.'' The 
court explained that ``section 111 `looks toward what may fairly be 
projected for the regulated future, rather than the state of the art at 
present.' '' Lignite Energy Council, 198 F.3d at 934 (citing Portland 
Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973)). The 
Court added that the EPA may determine that control measures are 
``adequately demonstrated'' through a ``reasonable

[[Page 33273]]

extrapolation of [the control measures'] performance in other 
industries.'' Id.
---------------------------------------------------------------------------

    \182\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. 
Cir. 1973), cert. denied, 416 U.S. 969 (1974).
    \183\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973) (citations omitted) (discussing the Senate and 
House bills and reports from which the language in CAA section 111 
grew).
    \184\ Ibid.
    \185\ Sierra Club v. Costle, 657 F.2d 298, 364 (D.C. Cir. 1981).
    \186\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973) (citations omitted).
---------------------------------------------------------------------------

    The D.C. Circuit's view that the EPA may determine a ``system of 
emission reduction'' to be ``adequately demonstrated'' if the EPA 
reasonably projects that it will be available by a future date certain, 
is well-grounded in the purposes of CAA section 111 to reduce dangerous 
air pollutants. This view recognizes that pollution control systems may 
be complex and may require a predictable amount of time for sources 
across the source category to be able to design, acquire, install, and 
begin to operate them. In some instances, the control technology may be 
available, but the installation may be a multi-year process. For 
example, an existing coal-fired steam generating unit may require 
several years to plan, design, and install a Flue Gas Desulfurization 
(FGD) wet scrubber for the control of sulfur dioxide (SO2) 
emissions. Under these circumstances, common sense dictates that the 
EPA may promulgate a rulemaking that imposes a standard on the sources, 
but establishes the date for compliance as a date-certain in the 
future, consistent with the period of time the source needs to install 
and start operating the control equipment. In other circumstances, a 
system of emission reduction may be well-recognized as effective in 
controlling pollutants emitted by a large source category, but 
manufacturers may require a predictable amount of time to manufacture 
enough control equipment to cover the source category. In still other 
circumstances, the infrastructure needed to support the system so that 
it will cover sources across the category--whether physical 
infrastructure such as pipelines or human infrastructure such as 
skilled labor to install the equipment--may require a predictable 
amount of time to build out or develop in sufficient quantity to 
achieve such coverage. In all of these circumstances, adopting 
requirements under CAA section 111 at the time that the EPA is able to 
reasonably project the future deployment of the system of emission 
reduction, and establishing the date of compliance as a date-certain in 
the future, serves the statutory purposes of protecting against 
dangerous air pollution by ensuring that sources take action to control 
their emissions as soon as practicable. It should also be noted that 
because pollution control invariably entails additional cost, in some 
cases, the EPA's promulgation of regulatory requirements may be an 
essential trigger for the sometimes lengthy process of implementing 
pollution controls. In these cases, delaying the promulgation of the 
regulatory requirements until the pollution controls can be immediately 
deployed would be futile.
c. Costs
    Under CAA section 111(a)(1), in determining whether a particular 
emission control is the ``best system of emission reduction . . . 
adequately demonstrated,'' the EPA is required to take into account 
``the cost of achieving [the emission] reduction.'' By its terms, this 
provision makes clear that the cost that the EPA must take into account 
is the cost to the affected source of the system of emission reduction. 
Although the Clean Air Act does not describe how the EPA is to account 
for costs, the D.C. Circuit has formulated the cost standard in various 
ways.\187\ It has stated that the EPA may not adopt a standard the cost 
of which would be ``exorbitant,'' \188\ ``greater than the industry 
could bear and survive,'' \189\ ``excessive,'' \190\ or 
``unreasonable.'' \191\ These formulations appear to be synonymous, and 
for convenience, in these rulemakings, we are treating them as 
synonymous with reasonableness as well, so that a control technology 
may be considered the ``best system of emission reduction . . . 
adequately demonstrated'' if its costs are reasonable, but cannot be 
considered the best system if its costs are unreasonable.\192\
---------------------------------------------------------------------------

    \187\ 79 FR 1430, 1464 (January 8, 2014).
    \188\ Lignite Energy Council, 198 F.3d at 933.
    \189\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 
1975).
    \190\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \191\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \192\ These cost formulations are consistent with the 
legislative history of CAA section 111. The 1977 House Committee 
Report noted:
    In the [1970] Congress [sic: Congress's] view, it was only right 
that the costs of applying best practicable control technology be 
considered by the owner of a large new source of pollution as a 
normal and proper expense of doing business.
    1977 House Committee Report at 184. Similarly, the 1970 Senate 
Committee Report stated:
    The implicit consideration of economic factors in determining 
whether technology is ``available'' should not affect the usefulness 
of this section. The overriding purpose of this section would be to 
prevent new air pollution problems, and toward that end, maximum 
feasible control of new sources at the time of their construction is 
seen by the committee as the most effective and, in the long run, 
the least expensive approach.
    S. Comm. Rep. No. 91-1196 at 16.
---------------------------------------------------------------------------

    The D.C. Circuit has repeatedly upheld the EPA's consideration of 
cost in reviewing standards of performance. In several cases, the court 
upheld standards that entailed significant costs, consistent with 
Congress's view that ``the costs of applying best practicable control 
technology be considered by the owner of a large new source of 
pollution as a normal and proper expense of doing business.'' \193\ See 
Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir. 
1973); \194\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 387-88 
(D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298, 313 (D.C. Cir. 
1981) (upholding NSPS imposing controls on SO2 emissions 
from coal-fired power plants when the ``cost of the new controls . . . 
is substantial. EPA estimates that utilities will have to spend tens of 
billions of dollars by 1995 on pollution control under the new 
NSPS.'').
---------------------------------------------------------------------------

    \193\ 1977 House Committee Report at 184.
    \194\ The costs for these standards were described in the 
rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 5769 
(March 21, 1972).
---------------------------------------------------------------------------

    In its CAA section 111 rulemakings, the EPA has frequently used a 
cost-effectiveness metric, which determines the cost in dollars for 
each ton or other quantity of the regulated air pollutant removed 
through the system of emission reduction. See, e.g., 81 FR 35824 (June 
3, 2016) (NSPS for GHG and VOC emissions for the oil and natural gas 
source category); 71 FR 9866, 9870 (February 27, 2006) (NSPS for 
NOX, SO2, and PM emissions from fossil fuel-fired 
electric utility steam generating units); 61 FR 9905, 9910 (March 12, 
1996) (NSPS and emissions guidelines for nonmethane organic compounds 
and landfill gas from new and existing municipal solid waste 
landfills); 50 FR 40158 (October 1, 1985) (NSPS for SO2 
emissions from sweetening and sulfur recovery units in natural gas 
processing plants). This metric allows the EPA to compare the amount a 
regulation would require sources to pay to reduce a particular 
pollutant across regulations and industries. In rules for the electric 
power sector, a metric that determines the dollar increase in the cost 
of a megawatt hour of electricity generated by the affected sources due 
to the emission controls, shows the cost of controls relative to the 
output of electricity. See section VII.F.3.b.iii(B)(5) of this 
preamble, which discusses $/MWh costs of the March 15, 2023 Good 
Neighbor Plan for the 2015 Ozone NAAQS and the Cross-State Air 
Pollution Rule (CSAPR) 76 FR 48208 (August 8, 2011). This metric 
facilitates comparing costs across regulations and pollutants. In this 
proposal, as explained herein, the EPA looks at both of these metrics 
to assess the cost reasonableness of the proposed requirements.

[[Page 33274]]

d. Non-Air Quality Health and Environmental Impact and Energy 
Requirements
    Under CAA section 111(a)(1), the EPA is required to take into 
account ``any nonair quality health and environmental impact and energy 
requirements'' in determining the BSER. Non-air quality health and 
environmental impacts may include the impacts of the disposal of 
byproducts of the air pollution controls, or requirements of the air 
pollution control equipment for water. Portland Cement Ass'n v. 
Ruckelshaus, 465 F.2d 375, 387-88 (D.C. Cir. 1973), cert. denied, 417 
U.S. 921 (1974). Energy requirements may include the impact, if any, of 
the air pollution controls on the source's own energy needs.
e. Sector or Nationwide Component of Factors in Determining the BSER
    Another component of the D.C. Circuit's interpretations of CAA 
section 111 is that the EPA may consider the various factors it is 
required to consider on a national or regional level and over time, and 
not only on a plant-specific level at the time of the rulemaking.\195\ 
The D.C. Circuit based this interpretation--which it made in the 1981 
Sierra Club v. Costle case regarding the NSPS for new power plants--on 
a review of the legislative history, stating,
---------------------------------------------------------------------------

    \195\ See 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club 
v. Costle, 657 F.2d at 351).

    [T]he Reports from both Houses on the Senate and House bills 
illustrate very clearly that Congress itself was using a long-term 
lens with a broad focus on future costs, environmental and energy 
effects of different technological systems when it discussed section 
111.\196\
---------------------------------------------------------------------------

    \196\ Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) 
(citing legislative history).

    The court has upheld EPA rules that the EPA ``justified . . . in 
terms of the policies of the Act,'' including balancing long-term 
national and regional impacts. For example, the court upheld a standard 
of performance for SO2 emissions from new coal-fired power 
---------------------------------------------------------------------------
plants on grounds that it--

reflects a balance in environmental, economic, and energy 
consideration by being sufficiently stringent to bring about 
substantial reductions in SO2 emissions (3 million tons 
in 1995) yet does so at reasonable costs without significant energy 
penalties. . . .\197\
---------------------------------------------------------------------------

    \197\ Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 FR 
33583-33584; June 11, 1979).

    The EPA interprets this caselaw to authorize it to assess the 
impacts of the controls it is considering as the BSER, including their 
costs and implications for the energy system, on a sector-wide, 
regional, or national basis, as appropriate. For example, the EPA may 
assess whether controls it is considering would create risks to the 
reliability of the electricity system in a particular area or 
nationwide and, if they would, to reject those controls as the BSER.
f. ``Best''
    In determining which adequately demonstrated system of emission 
reduction is the ``best,'' the D.C. Circuit has made clear that the EPA 
has broad discretion. Specifically, in Sierra Club v. Costle, 657 F.2d 
298 (D.C. Cir. 1981), the court explained that ``section 111(a) 
explicitly instructs the EPA to balance multiple concerns when 
promulgating a NSPS,'' \198\ and emphasized that ``[t]he text gives the 
EPA broad discretion to weigh different factors in setting the 
standard,'' including the amount of emission reductions, the cost of 
the controls, and the non-air quality environmental impacts and energy 
requirements.\199\ In Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. 
Cir. 1999), the court reiterated:
---------------------------------------------------------------------------

    \198\ Sierra Club v. Costle, 657 F.2d at 319.
    \199\ Sierra Club v. Costle, 657 F.2d at 321; see also New York 
v. Reilly, 969 F.2d at 1150 (because Congress did not assign the 
specific weight the Administrator should assign to the statutory 
elements, ``the Administrator is free to exercise [her] discretion'' 
in promulgating an NSPS).

    Because section 111 does not set forth the weight that should be 
assigned to each of these factors, we have granted the agency a 
great degree of discretion in balancing them. . .-. EPA's choice [of 
the `best system'] will be sustained unless the environmental or 
economic costs of using the technology are exorbitant. . . . EPA 
[has] considerable discretion under section 111.\200\
---------------------------------------------------------------------------

    \200\ Lignite Energy Council, 198 F.3d at 933 (paragraphing 
revised for convenience). See New York v. Reilly, 969 F.2d 1147, 
1150 (D.C. Cir. 1992) (``Because Congress did not assign the 
specific weight the Administrator should accord each of these 
factors, the Administrator is free to exercise his discretion in 
this area.''); see also NRDC v. EPA, 25 F.3d 1063, 1071 (D.C. Cir. 
1994) (The EPA did not err in its final balancing because ``neither 
RCRA nor EPA's regulations purports to assign any particular weight 
to the factors listed in subsection (a)(3). That being the case, the 
Administrator was free to emphasize or deemphasize particular 
factors, constrained only by the requirements of reasoned agency 
decisionmaking.'').

See AEP v. Connecticut, 564 U.S. 410, 427 (2011) (under CAA section 
111, ``The appropriate amount of regulation in any particular 
greenhouse gas-producing sector cannot be prescribed in a vacuum: . . . 
informed assessment of competing interests is required. Along with the 
environmental benefit potentially achievable, our Nation's energy needs 
and the possibility of economic disruption must weigh in the balance. 
The Clean Air Act entrusts such complex balancing to the EPA in the 
first instance, in combination with State regulators. Each ``standard 
of performance'' the EPA sets must ``tak[e] into account the cost of 
achieving [emissions] reduction and any nonair quality health and 
environmental impact and energy requirements.'' (paragraphing revised; 
citations omitted)).
    Moreover, the D.C. Circuit has also read ``best'' to authorize the 
EPA to consider factors in addition to the ones enumerated in CAA 
section 111(a)(1), that further the purpose of the statute. In Portland 
Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973), the D.C. 
Circuit held that under CAA section 111(a)(1) as it read prior to the 
enactment of the 1977 CAA Amendments that added a requirement that the 
EPA take account of non-air quality environmental impacts, the EPA must 
consider ``counter-productive environmental effects'' in determining 
the BSER. Id. at 385. The court elaborated: ``The standard of the `best 
system' is comprehensive, and we cannot imagine that Congress intended 
that `best' could apply to a system which did more damage to water than 
it prevented to air.'' Id., n.42. In Sierra Club v. Costle, 657 F.2d 
298, 326, 346-47 (D.C. Cir. 1981), the court added that the EPA must 
consider the amount of emission reductions and technology advancement 
in determining BSER.
    The court's view that ``best'' includes additional factors that 
further the purpose of CAA section 111 is a reasonable interpretation 
of that term in its statutory context. The purpose of CAA section 111 
is to reduce emissions of air pollutants that endanger public health or 
welfare. CAA section 111(b)(1)(A). The court reasonably surmised that 
the EPA's determination of whether a system of emission reduction that 
reduced certain air pollutants is ``best'' should be informed by 
impacts that the system may have on other pollutants that affect public 
or welfare. Portland Cement Ass'n, 486 F.2d at 385. The Supreme Court 
confirmed the D.C. Circuit's approach in Michigan v. EPA 576 U.S. 743 
(2015), explaining that administrative agencies must engage in 
``reasoned decisionmaking'' that, in the case of pollution control, 
cannot be based on technologies that ``do even more damage to human 
health'' than the emissions they eliminate. Id. at 751-52. After 
Portland Cement Ass'n, Congress revised CAA section 111(a)(1) to make 
explicit that in determining whether a system of emission reduction is 
the ``best,'' the EPA should account for non-air quality health and 
environmental impacts. By the same token, the EPA

[[Page 33275]]

takes the position that in determining whether a system of emission 
reduction is the ``best,'' the EPA may account for the impacts of the 
system on air pollutants other than the ones that are the subject of 
the CAA section 111 regulation.\201\ We discuss immediately below other 
factors that the D.C. Circuit has held the EPA should account for in 
determining what system is the ``best.''
---------------------------------------------------------------------------

    \201\ See generally ``Standards of Performance for New, 
Reconstructed, and Modified Sources and Emissions Guidelines for 
Existing Sources: Oil and Natural Gas Sector Climate Review--
Supplemental Notice of Proposed Rulemaking,'' 87 FR 74702, 74765 
(December 6, 2022) (proposing the BSER for reducing methane and VOC 
emissions from natural gas-driven controllers in the oil and natural 
gas sector on the basis of, among other things, impacts on emissions 
of criteria pollutants). In this preamble, for convenience, the EPA 
generally discusses the effects of controls on non-GHG air 
pollutants along with the effects of controls on non-air quality 
health and environmental impacts.
---------------------------------------------------------------------------

g. Amount of Emissions Reductions
    Consideration of the amount of emissions from the category of 
sources or the amount of emission reductions achieved as factors the 
EPA must consider in determining the ``best system of emission 
reduction'' is implicit in the plain language of CAA section 
111(a)(1)--the EPA must choose the best system of emission reduction. 
Indeed, consistent with this plain language and the purpose of CAA 
section 111, the D.C. Circuit has stated that the EPA must consider the 
quantity of emissions at issue. See Sierra Club v. Costle, 657 F.2d 
298, 326 (D.C. Cir. 1981) (``we can think of no sensible interpretation 
of the statutory words ``best . . . system'' which would not 
incorporate the amount of air pollution as a relevant factor to be 
weighed when determining the optimal standard for controlling . . . 
emissions'').\202\ The fact that the purpose of a ``system of emission 
reduction'' is to reduce emissions, and that the term itself explicitly 
incorporates the concept of reducing emissions, supports the court's 
view that in determining whether a ``system of emission reduction'' is 
the ``best,'' the EPA must consider the amount of emission reductions 
that the system would yield. Even if the EPA were not required to 
consider the amount of emission reductions, the EPA has the discretion 
to do so, on grounds that either the term ``system of emission 
reduction'' or the term ``best'' may reasonably be read to allow that 
discretion.
---------------------------------------------------------------------------

    \202\ Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was 
governed by the 1977 CAAA version of the definition of ``standard of 
performance,'' which revised the phrase ``best system of emission 
reduction'' to read, ``best technological system of continuous 
emission reduction.'' As noted above, the 1990 CAAA deleted 
``technological'' and ``continuous'' and thereby returned the phrase 
to how it read under the 1970 CAAA. The court's interpretation of 
the 1977 CAAA phrase in Sierra Club v. Costle to require 
consideration of the amount of air emissions focused on the term 
``best'', and the terms ``technological'' and ``continuous'' were 
irrelevant to its analysis. It thus remains valid for the 1990 CAAA 
phrase ``best system of emission reduction.''
---------------------------------------------------------------------------

h. Expanded Use and Development of Technology
    The D.C. Circuit has long held that Congress intended for CAA 
section 111 to create incentives for new technology and therefore that 
the EPA is required to consider technological innovation as one of the 
factors in determining the ``best system of emission reduction.'' See 
Sierra Club v. Costle, 657 F.2d at 346-47. The court has grounded its 
reading in the statutory text of CAA 111(a)(1), defining the term 
``standard of performance''.\203\ In addition, the court's 
interpretation finds support in the legislative history.\204\ The 
legislative history identifies three different ways that Congress 
designed CAA section 111 to authorize standards of performance that 
promote technological improvement: (1) The development of technology 
that may be treated as the ``best system of emission reduction . . . 
adequately demonstrated;'' under CAA section 111(a)(1); \205\ (2) the 
expanded use of the best demonstrated technology; \206\ and (3) the 
development of emerging technology.\207\ Even if the EPA were not 
required to consider technological innovation as part of its 
determination of the BSER, it would be reasonable for the EPA to 
consider it because technological innovation may be considered an 
element of the term ``best,'' particularly in light of Congress's 
emphasis on technological innovation.
---------------------------------------------------------------------------

    \203\ Sierra Club v. Costle, 657 F.2d at 346 (``Our 
interpretation of section 111(a) is that the mandated balancing of 
cost, energy, and nonair quality health and environmental factors 
embraces consideration of technological innovation as part of that 
balance. The statutory factors which EPA must weigh are broadly 
defined and include within their ambit subfactors such as 
technological innovation.'').
    \204\ See S. Rep. No. 91-1196 at 16 (1970) (``Standards of 
performance should provide an incentive for industries to work 
toward constant improvement in techniques for preventing and 
controlling emissions from stationary sources''); S. Rep. No. 95-127 
at 17 (1977) (cited in Sierra Club v. Costle, 657 F.2d at 346 n. 
174) (``The section 111 Standards of Performance . . . sought to 
assure the use of available technology and to stimulate the 
development of new technology'').
    \205\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973) (the best system of emission reduction must ``look[ 
] toward what may fairly be projected for the regulated future, 
rather than the state of the art at present'').
    \206\ 1970 Senate Committee Report No. 91-1196 at 15 (``The 
maximum use of available means of preventing and controlling air 
pollution is essential to the elimination of new pollution 
problems'').
    \207\ Sierra Club v. Costle, 657 F.2d at 351 (upholding a 
standard of performance designed to promote the use of an emerging 
technology).
---------------------------------------------------------------------------

i. Achievability of the Degree of Emission Limitation
    For new sources, CAA section 111(b)(1)(B) and (a)(1) provides that 
the EPA must establish ``standards of performance,'' which are 
standards for emissions that reflect the degree of emission limitation 
that is ``achievable'' through the application of the BSER. According 
to the D.C. Circuit, a standard of performance is ``achievable'' if a 
technology can reasonably be projected to be available to an individual 
source at the time it is constructed that will allow it to meet the 
standard.\208\ Moreover, according to the court, ``[a]n achievable 
standard is one which is within the realm of the adequately 
demonstrated system's efficiency and which, while not at a level that 
is purely theoretical or experimental, need not necessarily be 
routinely achieved within the industry prior to its adoption.'' \209\ 
To be achievable, a standard ``must be capable of being met under most 
adverse conditions which can reasonably be expected to recur and which 
are not or cannot be taken into account in determining the `costs' of 
compliance.'' \210\ To show a standard is achievable, the EPA must 
``(1) identify variable conditions that might contribute to the amount 
of expected emissions, and (2) establish that the test data relied on 
by the agency are representative of potential industry-wide 
performance, given the range of variables that affect the achievability 
of the standard.'' \211\
---------------------------------------------------------------------------

    \208\ Sierra Club v. Costle, 657 F.2d 298, 364, n. 276 (D.C. 
Cir. 1981).
    \209\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 
(D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974).
    \210\ Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433, n.46 (D.C. 
Cir. 1980).
    \211\ Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981) 
(citing Nat'l Lime Ass'n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). In 
considering the representativeness of the source tested, the EPA may 
consider such variables as the `` `feedstock, operation, size and 
age' of the source.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433 
(D.C. Cir. 1980). Moreover, it may be sufficient to ``generalize 
from a sample of one when one is the only available sample, or when 
that one is shown to be representative of the regulated industry 
along relevant parameters.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 
434, n.52 (D.C. Cir. 1980).
---------------------------------------------------------------------------

    Although the D.C. Circuit established these standards for 
achievability in cases concerning CAA section 111(b) new source 
standards of performance, generally comparable standards for 
achievability should apply under CAA section 111(d), although the BSER 
may differ as between new and existing sources due to, for example, 
higher costs

[[Page 33276]]

of retrofit. 40 FR 53340 (November 17, 1975). For existing sources, CAA 
section 111(d)(1) requires the EPA to establish requirements for State 
plans that, in turn, must include ``standards of performance.'' As the 
Supreme Court has recognized, this provision requires the EPA to 
promulgate emission guidelines that determine the BSER for a source 
category and then identify the degree of emission limitation achievable 
by application of the BSER. See West Virginia v. EPA, 142 S. Ct. 2587, 
2601-02 (2022).\212\
---------------------------------------------------------------------------

    \212\ 40 CFR 60.21(e), 60.21a(e).
---------------------------------------------------------------------------

    The EPA has promulgated emission guidelines on the basis that the 
existing sources can achieve the degree of emission limitation 
described therein, even though under the RULOF provision of CAA section 
111(d)(1), the State retains discretion to apply standards of 
performance to individual sources that are more or less stringent, 
which indicates that Congress recognized that the EPA may promulgate 
emission guidelines that are consistent with CAA section 111(d) even 
though certain individual sources may not be able to achieve the degree 
of emission limitation identified therein by applying the controls that 
the EPA determined to be the BSER. Note further that this requirement 
that the emission limitation be ``achievable'' based on the ``best 
system of emission reduction . . . adequately demonstrated'' indicates 
that the technology or other measures that the EPA identifies as the 
BSER must be technically feasible.
4. EPA Promulgation of Emission Guidelines for States To Establish 
Standards of Performance
    CAA section 111(d)(1) directs the EPA to promulgate regulations 
establishing a CAA section 110-like procedure under which States submit 
State plans that establish ``standards of performance'' for emissions 
of certain air pollutants from sources which, if they were new sources, 
would be regulated under CAA section 111(b), and that implement and 
enforce those standards of performance. The term ``standard of 
performance'' is defined under CAA section 111(a)(1), quoted above. 
Thus, CAA sections 111(a)(1) and (d)(1) collectively require the EPA to 
determine the BSER for the existing sources and, based on the BSER, to 
establish emission guidelines that identify the minimum amount of 
emission limitation that a State, in its State plan, must impose on its 
existing sources through standards of performance. Consistent with 
these CAA requirements, the EPA's regulations require that the EPA's 
guidelines reflect--

the degree of emission limitation achievable through the application 
of the best system of emission reduction which (taking into account 
the cost of such reduction and any non-air quality health and 
environmental impact and energy requirements) the Administrator has 
determined has been adequately demonstrated from designated 
facilities.\213\
---------------------------------------------------------------------------

    \213\ 40 CFR 60.21a(e).

    Following the EPA's promulgation of emission guidelines, each State 
must determine the standards of performance for its existing sources, 
which the EPA's regulations call ``designated facilities.'' \214\ While 
the EPA specifies in emission guidelines the degree of emission 
limitation achievable through application of the best system of 
emission reduction, which it may express as a presumptive standard of 
performance, a State retains discretion in applying such a presumptive 
standard of performance to any particular designated facility. CAA 
section 111(d)(1) requires the EPA's regulations to ``permit the State 
in applying a standard of performance to any particular source . . . to 
take into consideration, among other factors, the remaining useful life 
the . . . source . . . .'' Consistent with this statutory direction, 
the EPA's regulations provide requirements for States that wish to 
apply standards of performance that deviate from an emission guideline. 
In December 2022, the EPA proposed to clarify these requirements, 
including the three circumstances under which States can invoke a 
particular source's remaining useful life and other factors (RULOF), to 
apply a less stringent standard of performance. These proposed 
clarifications provided:
---------------------------------------------------------------------------

    \214\ 40 CFR 60.21a(b), 60.24a(b).

    The State may apply a standard of performance to a particular 
source that is less stringent than otherwise required by an 
applicable emission guideline, taking into consideration remaining 
useful life and other factors, provided that the State demonstrates 
with respect to each such facility (or class of such facilities) 
that it cannot reasonably apply the best system of emission 
reduction to achieve the degree of emission limitation determined by 
the EPA, based on:
    (1) Unreasonable cost of control resulting from plant age, 
location, or basic process design;
    (2) Physical impossibility or technical infeasibility of 
installing necessary control equipment; or
    (3) Other circumstances specific to the facilities (or class of 
facilities) that are fundamentally different from the information 
considered in the determination of the best system of emission 
reduction in the emission guidelines.

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-
0002 (proposed 40 CFR 60.24a(e)).\215\ In addition, under CAA sections 
111(d) and 116, the State is authorized to establish a standard of 
performance for any particular source that is more stringent than the 
presumptive standards contained in the EPA's emission guidelines.\216\ 
Thus, for any particular source, a State may apply a standard of 
performance that is either more stringent or less stringent than the 
presumptive standards of performance in the emission guidelines. The 
State must include the standards of performance in their State plans 
and submit the plans to the EPA for review.\217\ Under CAA section 
111(d)(2)(A), the EPA approves State plans that are determined to be 
``satisfactory.''
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    \215\ The EPA intends to finalize the December 2022 proposed 
revisions to the CAA section 111 implementation regulations in 40 
CFR part 60, subpart Ba, including any changes made in response to 
public comments, prior to promulgating these emission guidelines. 
Thus, 40 CFR part 60, subpart Ba, as revised, would apply to these 
emission guidelines.
    \216\ 40 CFR 60.24a(f). The EPA's December 2022 proposed 
revisions to 40 CFR part 60, subpart Ba reflect its current 
interpretation that the EPA has the authority to review and approve 
plans that include standards of performance that are more stringent 
than the presumptive standards in the EPA's emission guidelines, 
thus making those more stringent requirements federally enforceable. 
87 FR 79204 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-
0002 (proposed 40 CFR 60.24a(m), (n)). In addition, CAA section 116 
authorizes the state to set standards of performance for all of its 
sources that, together, are more stringent than the EPA's emission 
guidelines.
    \217\ 40 CFR 60.23a. In January 2021, the D.C. Circuit Court of 
Appeals vacated the three-year deadline for state plan submissions 
of a final emission guideline in 40 CFR 60.23a(a)(1). The EPA's 
December 2022 proposed revisions to subpart Ba would revise 60.23a 
to, inter alia, provide for a fifteen-month submission deadline. 87 
FR 79182 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-
0002 (proposed 40 CFR 60.23a(a)).
---------------------------------------------------------------------------

IV. Stakeholder Engagement

    Prior to proposing these actions, the EPA conducted outreach to a 
broad range of stakeholders. The EPA also opened a non-regulatory pre-
proposal docket to solicit public input on the Agency's efforts to 
reduce GHG emissions from new and existing EGUs.\218\ For additional 
details on stakeholder engagement, see the memorandum in the docket 
titled Stakeholder Outreach.
---------------------------------------------------------------------------

    \218\ Docket ID No. EPA-HQ-OAR-2022-0723.
---------------------------------------------------------------------------

    The EPA conducted two rounds of outreach to gather input for these 
proposals. In the first round of outreach, in early 2022, the EPA 
sought input in a variety of formats and settings from States, Tribal 
nations, and a broad range

[[Page 33277]]

of stakeholders on the state of the power sector and how the Agency's 
regulatory actions affect those trends. This outreach included State 
energy and environmental regulators; Tribal air regulators; power 
companies and trade associations representing investor-owned utilities, 
rural electric cooperatives, and municipal power agencies; 
environmental justice and community organizations; and labor, 
environmental, and public health organizations. A second round of 
outreach took place in August and September 2022, and focused on 
seeking input specific to this rulemaking. The EPA asked to hear 
perspectives, priorities, and feedback around five guiding questions, 
and encouraged public input to the nonregulatory docket (Docket ID No. 
EPA-HQ-OAR-2022-0723) on these questions as well.
    The EPA also regularly interacts with other Federal agencies and 
departments whose activities intersect with the power sector, and in 
the course of developing these proposed rules the Agency conducted 
multiple discussions with these agencies to benefit from their 
expertise and to explore the potential interaction of these proposed 
rules with their independent missions and initiatives. Among other 
things, these discussions focused on the impacts of proposed 
investments in energy technology by the Department of Energy and 
Department of Treasury on the technical and economic analyses 
underlying this proposal. In addition, the EPA evaluated structures in 
these proposals to address reliability considerations with the 
Department of Energy.

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

A. Overview

    This section discusses and proposes requirements for stationary 
combustion turbine EGUs that commence construction or reconstruction 
after the date of publication of this proposed action. The EPA is 
proposing that those requirements will be codified in 40 CFR part 60, 
subpart TTTTa. The EPA explains in section VII.B the two basic turbine 
technologies in use in the power sector and covered by 40 CFR part 60, 
subpart TTTT, simple cycle turbines and combined cycle turbines. It 
further explains how these technologies are used in the three 
subcategories of low load turbines, intermediate load turbines, and 
base load turbines. Section VII.C provides an overview of how 
stationary combustion turbines have been previously regulated and how 
the EPA recently took comment on a proposed white paper on GHG 
mitigation options for stationary combustion turbines. Section VII.D 
discusses the EPA's decision to revisit the standards for turbines as 
part of the statutorily required 8-year review. Section VII.E discusses 
changes that the EPA is proposing in both applicability and 
subcategories in the new proposed 40 CFR part 60, subpart TTTTa as 
compared to those codified in 40 CFR part 60, subpart TTTT. Most 
notably, for natural gas-fired combustion turbines, the EPA is 
proposing three subcategories, a low load subcategory, an intermediate 
load subcategory, and a base load subcategory.
    Section VII.F discusses the EPA's determination of the BSER for 
each of the subcategories of turbines. For low load combustion 
turbines, the EPA continues to believe that use of lower emitting fuels 
is the appropriate BSER. For intermediate load turbines, the EPA 
believes that both highly efficient generation and co-firing low-GHG 
hydrogen are appropriate components of the BSER, and that there will be 
enough low-GHG hydrogen at a reasonable price to supply the combustion 
turbines that would need to use it in 2032. For this reason, the EPA is 
proposing a two-component BSER for intermediate load combustion 
turbines, and a two-phase standard of performance. The first component 
of the BSER would be highly efficient generation (based on the 
performance of a highly efficient simple cycle turbine), with a 
corresponding first-phase standard of performance. The second component 
of the BSER is co-firing 30 percent (by volume) low-GHG hydrogen, along 
with continued use of highly efficient generation, with a corresponding 
second-phase standard of performance. The EPA is also soliciting 
comment on whether intermediate load combustion turbines should be 
subject to a more stringent third-phase standard based on higher levels 
of low-GHG hydrogen co-firing by 2038. Additionally, the EPA is 
soliciting comment on whether the electric sales threshold used to 
define intermediate and base load units should be reduced further.
    For base load turbines, the EPA likewise believes that the BSER 
includes multiple components that correspond to a multi-phase standard 
of performance. This is appropriate based on consideration of the 
manufacturing and installation capabilities within the larger EGU 
category and other industries, and considerations of projected 
operation of combustion turbines in the future. For base load turbines, 
the EPA is proposing two BSER pathways with corresponding standards of 
performance that new and reconstructed stationary combustion turbines 
may take--one BSER pathway is based on the use of 90 percent CCS and a 
separate BSER pathway is based on co-firing low-GHG hydrogen. The EPA 
proposes that the first component of the BSER for both pathways is 
highly efficient generation (based on the performance of a highly 
efficient combined cycle unit) and the second component of the BSER is 
based on the use of either 90 percent CCS in 2035 or co-firing 30 
percent (by volume) low-GHG hydrogen in 2032, along with continued use 
of highly efficient generation for both pathways. For base load 
turbines that are subject to a second phase standard of performance 
based on a highly efficient combined cycle unit co-firing 30 percent 
(by volume) low-GHG hydrogen, the EPA proposes that those units also 
meet a third phase component of the BSER based on the co-firing of 96 
percent (by volume) low-GHG hydrogen by 2038. These two BSER pathways 
both offer significant opportunities to reduce GHG emissions even 
though they may be available on slightly different timescales. The EPA 
seeks comment specifically on the percentages of hydrogen co-firing and 
CO2 capture, the dates that meet the statutory BSER criteria 
for each pathway, 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 of 90 lb CO2/MWh-gross based on the 
application of CCS with 90 percent capture, which could also be met by 
co-firing 96 percent low-GHG hydrogen.
    For both intermediate load and base load turbines, the standards of 
performance corresponding to both components of the BSER would apply to 
all new and reconstructed sources that commence construction or 
reconstruction after the publication date of this proposal. The EPA 
occasionally refers to these standards of performance as the phase-1, 
phase-2, or phase-3 standards.

B. Combustion Turbine Technology

    For purposes of 40 CFR part 60, subparts TTTT and TTTTa, stationary 
combustion turbines include both simple cycle and combined cycle EGUs. 
Simple cycle turbines operate in the Brayton thermodynamic cycle and 
include three primary components: a

[[Page 33278]]

multistage compressor, a combustion chamber (i.e., combustor), and a 
turbine. The compressor is used to supply large volumes of high-
pressure air to the combustion chamber. The combustion chamber converts 
fuel to heat and expands the now heated, compressed air to create shaft 
work. The shaft work drives an electric generator to produce 
electricity. Combustion turbines that recover their high-temperature 
exhaust--instead of venting it directly to the atmosphere--are combined 
cycle EGUs and can obtain additional useful electric output. A combined 
cycle EGU includes a heat recovery steam generator (HRSG) operating in 
the Rankine thermodynamic cycle. The HRSG receives the high-temperature 
exhaust and converts the heat to mechanical energy by producing steam 
that is then fed into a steam turbine that, in turn, drives a second 
electric generator. As the thermal efficiency of a stationary 
combustion turbine EGU is increased, less fuel is burned to produce the 
same amount of electricity, with a corresponding decrease in fuel costs 
and lower emissions of CO2 and, generally, of other air 
pollutants. The greater the output of electric energy for a given 
amount of fuel energy input, the higher the efficiency of the electric 
generation process.
    Combustion turbines serve various roles in the power sector. Some 
combustion turbines operate at low annual capacity factors and are 
available to provide temporary power during periods of high load 
demand. These turbines are often referred to as ``peaking units.'' Some 
combustion turbines operate at intermediate annual capacity factors and 
are often referred to as cycling or load-following units. Other 
combustion turbines operate at high annual capacity factors to serve 
base load demand and are often referred to as base load units. In this 
proposal, the EPA refers to these types of combustion turbines as low 
load, intermediate load, and base load, respectively.
    Low load combustion turbines provide reserve capacity, support grid 
reliability, and generally provide power during periods of peak 
electric demand. As such, the units may operate at or near their full 
capacity, but only for short periods, as needed. Because these units 
only operate occasionally, capital expenses are a major factor in the 
overall cost of electricity, and often, the lowest capital cost (and 
generally less efficient) simple cycle EGUs are intended for use only 
during periods of peak electric demand. Due to their low efficiency, 
these units require more fuel per MWh of electricity produced and their 
operating costs tend to be higher. Because of the higher operating 
costs, they are generally some of the last units in the dispatch order. 
Important characteristics for low load combustion turbines include 
their low capital costs, their ability to start and quickly ramp to 
full load, and their ability to operate at partial loads while 
maintaining acceptable emission rates and efficiencies. The ability to 
start and quickly attain full load is important to maximize revenue 
during periods of peak electric prices and to meet sudden shifts in 
demand. In contrast, under steady-state conditions, more efficient 
combined cycle EGUs are dispatched ahead of low load turbines and often 
operate at higher capacity factors.
    Highly efficient simple cycle turbines and fast-start combined 
cycle turbines both offer different advantages and disadvantages when 
operating at intermediate loads. One of the roles of these intermediate 
or load-following EGUs is to provide dispatchable backup power to 
support variable renewable generating sources. A developer's decision 
of whether to build a simple cycle combustion turbine or a combined 
cycle combustion turbine to serve intermediate load demand would be 
based on several factors related to the intended operation of the unit. 
These factors include how frequently the unit is expected to cycle 
between starts and stops, the predominant load level at which the unit 
is expected to operate, and whether this level of operation is expected 
to remain consistent or is expected to vary over the lifetime of the 
unit. While the owner/operator of an individual combustion turbine 
controls whether and how that unit will operate over time, they do not 
necessarily control the precise timing of dispatch for the unit in any 
given day or hour. Such short-term dispatch decisions are often made by 
regional grid operators that determine, on a moment-to-moment basis, 
which available individual units should operate to balance supply and 
demand and other requirements in an optimal manner, based on operating 
costs, price bids, and/or operational characteristics. However, 
operating permits for simple cycle turbines often contain restrictions 
on the annual hours of operation that owners/operators incorporate into 
longer term operating plans and short-term dispatch decisions.
    Intermediate load combustion turbines vary their generation, 
especially during transition periods between low and high electric 
demand. Both high-efficiency simple cycle combustion turbines and fast-
start combined cycle combustion turbines can fill this cycling role. 
While the ability to start and quickly ramp is important, efficiency is 
also an important characteristic. These combustion turbines generally 
have higher capital costs than low load combustion turbines but are 
generally less expensive to operate.
    Base load combustion turbines are designed to operate for extended 
periods at high loads with infrequent starts and stops. Quick start 
capability and low capital costs are less important than low operating 
costs. High-efficiency combined cycle combustion turbines typically 
fill the role of base load combustion turbines.
    The increase in generation from variable renewable energy sources 
during the past decade has impacted the way in which firm dispatchable 
generating resources operate.\219\ For example, the electric output 
from wind and solar generating sources fluctuates daily and seasonally 
due to increases and decreases in the wind speed or solar intensity. 
Due to this variable nature of wind and solar, firm dispatchable 
electric generating units are used to ensure the reliability of the 
electric grid. This requires technologies such as dispatchable power 
plants to start and stop and change load more frequently than was 
previously needed. Important characteristics of combustion turbines 
that provide firm backup capacity are the ability to start and stop 
quickly and the ability to quickly change loads. Natural gas-fired 
combustion turbines are much more flexible than coal-fired utility 
boilers in this regard and have played an important role in ensuring 
electric supply and demand are in balance during the past decade.
---------------------------------------------------------------------------

    \219\ Dispatchable EGUs can be turned on and off and adjust the 
amount of power supplied to the electric grid based on the demand 
for electricity. Variable (sometimes referred to as intermittent) 
EGUs supply electricity based on external factors that are not 
controlled by the owner/operator of the EGU.
---------------------------------------------------------------------------

    As discussed in section IV.F.2 of this preamble and in the 
accompanying RIA, the post-IRA 2022 reference case projects that 
natural gas-fired combustion turbines will continue to play an 
important role in meeting electricity demand. However, that role is 
projected to evolve as additional renewable and non-renewable low-GHG 
generation and energy storage technologies are added to the grid. 
Energy storage technologies can store energy during periods when 
generation from renewable resources is high relative to demand and 
provide electricity to the grid during other periods. This could reduce 
the need for fossil fuel-fired firm dispatchable power plants to start 
and stop as frequently. Consequently, in the future, natural gas-

[[Page 33279]]

fired stationary combustion turbine EGUs may run at more stable 
operation and, thus, more efficiently (i.e., at higher duty cycles and 
for longer periods of operation per start). The EPA is soliciting 
comment on whether this a likely scenario.

C. Overview of Regulation of Stationary Combustion Turbines for GHGs

    As explained earlier in this preamble, the EPA originally regulated 
stationary combustion turbine EGUs for emissions of GHGs in 2015 under 
40 CFR part 60, subpart TTTT. In 40 CFR part 60, subpart TTTT, the EPA 
created three subcategories, two for natural gas-fired combustion 
turbines and one for multi-fuel-fired combustion turbines. For natural 
gas-fired turbines, the EPA created a subcategory for base load 
turbines and a separate subcategory for non-base load turbines. Base 
load turbines were defined as combustion turbines with electric sales 
greater than a site-specific electric sales threshold that is based on 
the design efficiency of the combustion turbine. Non-base load turbines 
were defined as combustion turbines with a capacity factor less than or 
equal to the site-specific electric sales threshold. For base load 
turbines, the EPA set a standard of 1,000 lb CO2/MWh-gross 
based on efficient combined cycle turbine technology and for non-base 
load and multi-fuel-fired turbines, the EPA set a standard based on the 
use of lower emitting fuels that varied from 120 lb CO2/
MMBtu to 160 lb CO2/MMBtu depending upon whether the turbine 
burned primarily natural gas or other lower emitting fuels.
    On April 21, 2022, the EPA issued an informational draft white 
paper, titled Available and Emerging Technologies for Reducing 
Greenhouse Gas Emissions from Combustion Turbine Electric Generating 
Units.\220\ The draft document included discussion of the basic types 
of available stationary combustion turbines as well as factors that 
influence GHG emission rates from these sources. The technology 
discussion in the draft white paper included information on an array of 
new and existing control technologies and potential reduction measures 
for GHG emissions. These reduction measures included: the GHG reduction 
potential of various efficiency improvements; technologies capable of 
firing or co-firing alternative fuels such as hydrogen; the ongoing 
advancement of CCS projects with NGCC units; and the co-location of 
technologies that do not emit onsite GHG emissions with EGUs, such as 
onsite renewables or short-duration energy storage.
---------------------------------------------------------------------------

    \220\ https://www.epa.gov/stationary-sources-air-pollution/white-paper-available-and-emerging-technologies-reducing.
---------------------------------------------------------------------------

    The EPA provided an opportunity for the public to comment on this 
white paper to inform its approach to this proposed rulemaking. More 
than 30 groups or individuals provided public comments on the topics 
and technologies discussed in the draft white paper. Commenters 
included representatives from utilities, technology providers, trade 
associations, States, regulatory agencies, NGOs, and public health 
advocates. The information provided in the public comments was 
beneficial in enabling the EPA to review the current NSPS for new 
stationary combustion turbines and to develop the proposed revisions 
described in this preamble.

D. Eight-Year Review of NSPS

    CAA section 111(b)(1)(B) requires the Administrator to ``at least 
every 8 years, review and, if appropriate, revise [the NSPS] . . .'' 
The provision further provides that ``the Administrator need not review 
any such standard if the Administrator determines that such review is 
not appropriate in light of readily available information on the 
efficacy of such [NSPS].''
    The EPA promulgated the NSPS for GHG emissions for stationary 
combustion turbines in 2015. Announcements and modeling projections 
show companies are building new fossil fuel-fired combustion turbines 
and plan to continue building additional capacity. Because the 
emissions from this capacity have the potential to be large and these 
units are likely to have long lives (25 years or more), the EPA 
believes it is important to consider options to reduce emissions from 
these new units. In addition, the EPA is aware of developments 
concerning the types of control measures that may be available to 
reduce GHG emissions from new stationary combustion turbines. 
Accordingly, the EPA is proceeding to review and is proposing updated 
NSPS for newly constructed and reconstructed fossil fuel-fired 
stationary combustion turbines.

E. Applicability Requirements and Subcategorization

    This section describes the proposed amendments to the specific 
applicability criteria for non-fossil fuel-fired EGUs, industrial EGUs, 
CHP EGUs, and combustion turbines EGUs not connected to a natural gas 
pipeline. The EPA is also proposing certain changes to the 
applicability requirements for stationary combustion turbines affected 
by this proposal as compared to those for sources affected by the 2015 
NSPS. The proposed changes are described below and include the 
elimination of the multi-fuel-fired subcategory, further binning non-
base load combustion turbines into low and intermediate load 
subcategories, and lowering the electric sales threshold for base load 
combustion turbines.
1. Applicability Requirements
    In general, the EPA refers to fossil fuel-fired EGUs that would be 
subject to a CAA section 111 NSPS as ``affected'' EGUs or units. An EGU 
is any fossil fuel-fired electric utility steam generating unit (i.e., 
a utility boiler or IGCC unit) or stationary combustion turbine (in 
either simple cycle or combined cycle configuration). To be considered 
an affected EGU under the current NSPS at 40 CFR part 60, subpart TTTT, 
the unit must meet the following applicability criteria: The unit must: 
(1) Be capable of combusting more than 250 million British thermal 
units per hour (MMBtu/h) (260 gigajoules per hour (GJ/h)) of heat input 
of fossil fuel (either alone or in combination with any other fuel); 
and (2) serve a generator capable of supplying more than 25 MW net to a 
utility distribution system (i.e., for sale to the grid).\221\ However, 
40 CFR part 60, subpart TTTT includes applicability exemptions for 
certain EGUs, including: (1) Non-fossil fuel-fired units subject to a 
federally enforceable permit that limits the use of fossil fuels to 10 
percent or less of their heat input capacity on an annual basis; (2) 
CHP units that are subject to a federally enforceable permit limiting 
annual net electric sales to no more than either the unit's design 
efficiency multiplied by its potential electric output, or 219,000 
megawatt-hours (MWh), whichever is greater; (3) stationary combustion 
turbines that are not physically capable of combusting natural gas 
(e.g., those that are not connected to a natural gas pipeline); (4) 
utility boilers and IGCC units that have always been subject to a 
federally enforceable permit limiting annual net electric sales to one-
third or less of their potential electric output (e.g., limiting hours 
of operation to less than 2,920 hours annually) or limiting annual 
electric sales to 219,000 MWh or less; (5) municipal waste combustors 
that are subject to 40 CFR part 60, subpart Eb; (6) commercial or 
industrial solid waste incineration units subject to 40 CFR part 60, 
subpart CCCC; and (7)

[[Page 33280]]

certain projects under development, as discussed below.
---------------------------------------------------------------------------

    \221\ The EPA refers to the capability to combust 250 MMBtu/h of 
fossil fuel as the ``base load rating criterion.'' Note that 250 
MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
---------------------------------------------------------------------------

a. Revisions to 40 CFR Part 60, Subpart TTTT
    The EPA is proposing to amend 40 CFR 60.5508 and 60.5509 to reflect 
that 40 CFR part 60, subpart TTTT will remain applicable to steam 
generating EGUs and IGCC units constructed after January 8, 2014 or 
reconstructed after June 18, 2014. The EPA is also proposing that 
stationary combustion turbines that commenced construction after 
January 8, 2014 or reconstruction after June 18, 2014 and before May 
23, 2023 that meet the relevant applicability criteria would be subject 
to 40 CFR part 60, subpart TTTT. Upon promulgation of 40 CFR part 60, 
subpart TTTTa, stationary combustion turbines that commence 
construction or reconstruction after May 23, 2023 and meet the relevant 
applicability criteria will be subject to 40 CFR part 60, subpart 
TTTTa.
b. Revisions to 40 CFR Part 60, Subpart TTTT That Would Also Be 
Included in 40 CFR Part 60, Subpart TTTTa
    The EPA is proposing that 40 CFR part 60, subpart TTTT and 40 CFR 
part 60, subpart TTTTa use similar regulatory text except where 
specifically stated. This section describes proposed amendments that 
would be included in both subparts.
i. Applicability to Non-Fossil Fuel-Fired EGUs
    The current non-fossil applicability exemption in 40 CFR part 60, 
subpart TTTT is based strictly on the combustion of non-fossil fuels 
(e.g., biomass). To be considered a non-fossil fuel-fired EGU, the EGU 
must both (1) Be capable of combusting more than 50 percent non-fossil 
fuel and (2) be subject to a federally enforceable permit condition 
limiting the annual capacity factor for all fossil fuels combined of 10 
percent (0.10) or less. The current language does not take heat input 
from non-combustion sources (e.g., solar thermal) into account. Certain 
solar thermal installations have natural gas backup burners larger than 
250 MMBtu/h. As currently written, these solar thermal installations 
would not be eligible to be considered non-fossil units because they 
are not capable of deriving more than 50 percent of their heat input 
from the combustion of non-fossil fuels. Therefore, solar thermal 
installations that include backup burners could meet the applicability 
criteria of 40 CFR part 60, subpart TTTT even if the burners are 
limited to an annual capacity factor of 10 percent or less. These EGUs 
would readily comply with the standard of performance, but the 
reporting and recordkeeping would increase costs for these EGUs.
    The EPA is proposing several amendments to align the applicability 
criteria with the original intent to cover only fossil fuel-fired EGUs. 
This would ensure that solar thermal EGUs with natural gas backup 
burners, like other types of non-fossil fuel-fired units in which most 
of their energy is derived from non-fossil fuel sources, are not 
subject to the requirements of 40 CFR part 60, subparts TTTT or TTTTa. 
Amending the applicability language to include heat input derived from 
non-combustion sources would allow these facilities to avoid the 
requirements of 40 CFR part 60, subparts TTTT or TTTTa by limiting the 
use of the natural gas burners to less than 10 percent of the capacity 
factor of the backup burners. Specifically, the EPA is proposing to 
amend the definition of non-fossil fuel-fired EGUs from EGUs capable of 
``combusting 50 percent or more non-fossil fuel'' to EGUs capable of 
``deriving 50 percent or more of the heat input from non-fossil fuel at 
the base load rating.'' (emphasis added). The definition of base load 
rating would also be amended to include the heat input from non-
combustion sources (e.g., solar thermal).
    The proposed amended non-fossil fuel applicability language 
changing ``combusting'' to ``deriving'' will ensure that 40 CFR part 
60, subparts TTTT and TTTTa cover the fossil fuel-fired EGUs, properly 
understood, that the original rule was intended to cover, while 
minimizing unnecessary costs to EGUs fueled primarily by steam 
generated without combustion (e.g., through the use of solar thermal). 
The corresponding change in the base load rating to include the heat 
input from non-combustion sources is necessary to determine the 
relative heat input from fossil fuel and non-fossil fuel sources.
ii. Industrial EGUs
(A) Applicability to Industrial EGUs
    In simple terms, the current applicability provisions in 40 CFR 
part 60, subpart TTTT require that an EGU be capable of combusting more 
than 250 MMBtu/h of fossil fuel and be capable of selling 25 MW to a 
utility distribution system to be subject to 40 CFR part 60, subpart 
TTTT. These applicability provisions exclude industrial EGUs. However, 
the definition of an EGU also includes ``integrated equipment that 
provides electricity or useful thermal output.'' This language 
facilitates the integration of non-emitting generation and avoids 
energy inputs from non-affected facilities being used in the emission 
calculation without also considering the emissions of those facilities 
(e.g., an auxiliary boiler providing steam to a primary boiler). This 
language could result in certain large processes being included as part 
of the EGU and meeting the applicability criteria. For example, the 
high-temperature exhaust from an industrial process (e.g., calcining 
kilns, dryer, metals processing, or carbon black production facilities) 
that consumes fossil fuel could be sent to a HRSG to produce 
electricity. If the industrial process is more than 250 MMBtu/h heat 
input and the electric sales exceed the applicability criteria, then 
the unit could be subject to 40 CFR part 60, subparts TTTT or TTTTa. 
This is potentially problematic for multiple reasons. First, it is 
difficult to determine the useful output of the EGU (i.e., HRSG) since 
part of the useful output is included in the industrial process. In 
addition, the fossil fuel that is combusted might have a relatively 
high CO2 emissions rate on a lb/MMBtu basis, making it 
potentially problematic to meet the standard of performance using 
efficient generation. This could result in the owner/operator reducing 
the electric output of the industrial facility to avoid the 
applicability criteria. Finally, the compliance costs associated with 
40 CFR part 60, subparts TTTT or TTTTa could discourage the development 
of environmentally beneficial projects.
    To avoid these outcomes, the EPA is proposing to amend the 
applicability provision that exempts EGUs where greater than 50 percent 
of the heat input is derived from an industrial process that does not 
produce any electrical or mechanical output or useful thermal output 
that is used outside the affected EGU.\222\ Reducing the output or not 
developing industrial electric generating projects where the majority 
of the heat input is derived from the industrial process itself would 
not necessarily result in reductions in GHG emissions from the 
industrial facility. However, the electricity that would have been 
produced from the industrial project could still be needed. Therefore, 
projects of this type provide significant environmental benefit with 
little if any additional emissions. Including these types of projects 
would result in regulatory burden without any

[[Page 33281]]

associated environmental benefit and could discourage project 
development, leading to potential overall increases in GHG emissions.
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    \222\ Auxiliary equipment such as boilers or combustion turbines 
that provide heat or electricity to the primary EGU (including to 
any control equipment) would still be considered integrated 
equipment and included as part of the affected facility.
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(B) Industrial EGUs Electric Sales Threshold Permit Requirement
    The current electric sales applicability exemption in 40 CFR part 
60, subpart TTTT for non-CHP steam generating units includes the 
provision that EGUs have ``always been subject to a federally 
enforceable permit limiting annual net electric sales to one-third or 
less of their potential electric output (e.g., limiting hours of 
operation to less than 2,920 hours annually) or limiting annual 
electric sales to 219,000 MWh or less'' (emphasis added). The 
justification for this restriction includes that the 40 CFR part 60, 
subpart Da applicability language includes ``constructed for the 
purpose of . . .'' and the Agency concluded that the intent was defined 
by permit conditions (80 FR 64544; October 23, 2015). This 
applicability criterion is important for determining applicability with 
both the new source CAA section 111(b) requirements and if existing 
steam generating units are subject to the existing source CAA section 
111(d) requirements. For steam generating units that commenced 
construction after September 18, 1978, the applicability of 40 CFR part 
60, subpart Da, would be relatively clear by what criteria pollutant 
NSPS is applicable to the facility. However, for steam generating units 
that commenced construction prior to September 18, 1978, or where the 
owner/operator determined that criteria pollutant NSPS applicability 
was not critical to the project (e.g., emission controls were 
sufficient to comply with either the EGU or industrial boiler criteria 
pollutant NSPS), owners/operators might not have requested an electric 
sales permit restriction be included in the operating permit. Under the 
current applicability language, some onsite EGUs could be covered by 
the existing source CAA section 111(d) requirements even if they have 
never sold electricity to the grid. To avoid covering these industrial 
EGUs, the EPA is proposing to amend the electric sales exemption in 40 
CFR part 60, subparts TTTT and TTTTa to read, ``annual net-electric 
sales have never exceeded one-third of its potential electric output or 
219,000 MWh, whichever is greater, and is'' (the ``always been'' would 
be deleted) subject to a federally enforceable permit limiting annual 
net electric sales to one-third or less of their potential electric 
output (e.g., limiting hours of operation to less than 2,920 hours 
annually) or limiting annual electric sales to 219,000 MWh or less'' 
(emphasis added). EGUs that reduce current generation would continue to 
be covered as long as they sold more than one-third of their potential 
electric output at some time in the past. The proposed revisions would 
simply make it possible for an owner/operator of an existing industrial 
EGU to provide evidence to the Administrator that the facility has 
never sold electricity in excess of the electricity sales threshold and 
to modify their permit to limit sales in the future. Without the 
amendment, owners/operators of any non-CHP industrial EGU capable of 
selling 25 MW would be subject to the existing source CAA section 
111(d) requirements even if they have never sold any electricity. 
Therefore, the EPA is proposing the exemption to eliminate the 
requirement that existing industrial EGUs must have always been subject 
to a permit restriction limiting net electric sales.
iii. Determination of the Design Efficiency
    The design efficiency (i.e., the efficiency of converting thermal 
energy to useful energy output) of a combustion turbine is used to 
determine the electric sales applicability threshold and is relevant to 
both new and existing EGUs.\223\ The sales criteria are based in part 
on the individual EGU design efficiency. Three methods for determining 
the design efficiency are currently provided in 40 CFR part 60, subpart 
TTTT.\224\ Since the 2015 NSPS was finalized, the EPA has become aware 
that owners/operators of certain existing EGUs do not have records of 
the original design efficiency. These units are not able to readily 
determine whether they meet the applicability criteria and are 
therefore subject to the CAA section 111(d) requirements for existing 
sources in the same way that 111(b) sources would be able to determine 
if the facility meets the applicability criteria. Many of these EGUs 
are CHP units and it is likely they do not meet the applicability 
criteria. However, the language in the 2015 NSPS would require them to 
conduct additional testing to demonstrate this. The requirement would 
result in burden to the regulated community without any environmental 
benefit. The electricity generating market has changed, in some cases 
dramatically, during the lifetime of existing EGUs, especially 
concerning ownership. As a result of acquisitions and mergers, original 
EGU design efficiency documentation as well as performance guarantee 
results that affirmed the design efficiency, may no longer exist. 
Moreover, such documentation and results may not be relevant for 
current EGU efficiencies, as changes to original EGU configurations, 
upon which the original design efficiencies were based, render those 
original design efficiencies moot, meaning that there would be little 
reason to maintain former design efficiency documentation since it 
would not comport with the efficiency associated with current EGU 
configurations. As the three specified methods would rely on 
documentation from the original EGU configuration performance guarantee 
testing, and results from that documentation may no longer exist or be 
relevant, it is appropriate to allow other means to demonstrate EGU 
design efficiency. To reduce compliance burden, the EPA is proposing in 
40 CFR part 60, subparts TTTT and TTTTa to allow alternative methods as 
approved by the Administrator on a case-by-case basis. Owners/operators 
of EGUs would petition the Administrator in writing to use an alternate 
method to determine the design efficiency. The Administrator's 
discretion is intentionally left broad and could extend to other 
American Society of Mechanical Engineers (ASME) or International 
Organization for Standardization (ISO) methods as well as to operating 
data to demonstrate the design efficiency of the EGU. The EPA is also 
proposing to change the applicability of paragraph 60.8(b) in table 3 
of 40 CFR part 60, subpart TTTT from ``no'' to ``yes'' and that the 
applicability of paragraph 60.8(b) in table 3 of 40 CFR part 60, 
subpart TTTTa is ``yes.'' This would allow the Administrator to approve 
alternatives to the test methods specified in 40 CFR part 60, subparts 
TTTT and TTTTa.
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    \223\ While the EPA could specifically allow different methods 
to determine the design efficiency in the 111(d) existing source 
emission guidelines, the Agency is proposing to align the criteria 
for regulatory clarity.
    \224\ 40 CFR part 60, subpart TTTT currently lists ASME PTC 22 
Gas Turbines, ASME PTC 46 Overall Plant Performance, and ISO 2314 
Gas turbines acceptance tests as approved methods to determine the 
design efficiency.
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c. Applicability for 40 CFR Part 60, Subpart TTTTa
    This section describes proposed amendments that would only be 
incorporated into 40 CFR part 60, subpart TTTTa and would differ from 
the requirements in 40 CFR part 60, subpart TTTT.
i. Proposed Applicability
    Section 111 of the CAA defines a new or modified source for 
purposes of a given NSPS as any stationary source

[[Page 33282]]

that commences construction or modification after the publication of 
the proposed regulation. Thus, any standards of performance the Agency 
finalizes as part of this rulemaking will apply to EGUs that commence 
construction or reconstruction after the date of this proposal. EGUs 
that commenced construction after the date of the proposal for the 2015 
NSPS and by the date of this proposal will remain subject to the 
standards of performance promulgated in the 2015 NSPS. A modification 
is any physical change in, or change in the method of operation of, an 
existing source that increases the amount of any air pollutant emitted 
to which a standard applies.\225\ The NSPS General Provisions (40 CFR 
part 60, subpart A) provide that an existing source is considered a new 
source if it undertakes a reconstruction.\226\
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    \225\ 40 CFR 60.2.
    \226\ 40 CFR 60.15(a).
---------------------------------------------------------------------------

    The EPA is proposing the same applicability requirements in 40 CFR 
part 60, subpart TTTTa as the applicability requirements in 40 CFR part 
60, subpart TTTT. The stationary combustion turbine must meet the 
following applicability criteria: The stationary combustion turbine 
must: (1) Be capable of combusting more than 250 million British 
thermal units per hour (MMBtu/h) (260 gigajoules per hour (GJ/h)) of 
heat input of fossil fuel (either alone or in combination with any 
other fuel); and (2) serve a generator capable of supplying more than 
25 MW net to a utility distribution system (i.e., for sale to the 
grid).\227\ In addition, the EPA is proposing in 40 CFR part 60, 
subpart TTTTa to include applicability exemptions for stationary 
combustion turbines that are: (1) Capable of deriving 50 percent or 
more of the heat input from non-fossil fuel at the base load rating and 
subject to a federally enforceable permit condition limiting the annual 
capacity factor for all fossil fuels combined of 10 percent (0.10) or 
less; (2) combined heat and power units subject to a federally 
enforceable permit condition limiting annual net-electric sales to no 
more than 219,000 MWh or the product of the design efficiency and the 
potential electric output, whichever is greater; (3) serving a 
generator along with other steam generating unit(s), IGCC, or 
stationary combustion turbine(s) where the effective generation 
capacity is 25 MW or less; (4) municipal waste combustors that are 
subject to 40 CFR part 60, subpart Eb; (5) commercial or industrial 
solid waste incineration units subject to 40 CFR part 60, subpart CCCC; 
and (6) deriving greater than 50 percent of heat input from an 
industrial process that does not produce any electrical or mechanical 
output that is used outside the affected stationary combustion turbine.
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    \227\ The EPA refers to the capability to combust 250 MMBtu/h of 
fossil fuel as the ``base load rating criterion.'' Note that 250 
MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
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    The EPA is proposing to apply the same requirements to combustion 
turbines in non-continental areas (i.e., Hawaii, the Virgin Islands, 
Guam, American Samoa, the Commonwealth of Puerto Rico, and the Northern 
Mariana Islands) and non-contiguous areas (non-continental areas and 
Alaska) as the EPA is proposing for comparable units in the contiguous 
48 States. However, new units in non-continental and non-contiguous 
areas may operate on small, isolated electric grids, may operate 
differently from units in the contiguous 48 States, and may have 
limited access to certain components of the proposed BSER due to their 
uniquely isolated geography or infrastructure. Therefore, the EPA is 
soliciting comment on whether combustion turbines in non-continental 
and non-contiguous areas should be subject to different requirements.
ii. Applicability to CHP Units
    For 40 CFR part 60, subpart TTTT, owner/operators of CHP units 
calculate net electric sales and net energy output using an approach 
that includes ``at least 20.0 percent of the total gross or net energy 
output consists of electric or direct mechanical output.'' It is 
unlikely that a CHP unit with a relatively low electric output (i.e., 
less than 20.0 percent) would meet the applicability criteria. However, 
if a CHP unit with less than 20.0 percent of the total output 
consisting of electricity were to meet the applicability criteria, the 
net electric sales and net energy output would be calculated the same 
as for a traditional non-CHP EGU. Even so, it is not clear that these 
CHP units would have less environmental benefit per unit of electricity 
produced than more traditional CHP units. For 40 CFR part 60, subpart 
TTTTa, the EPA is proposing to eliminate the restriction that CHP units 
produce at least 20.0 percent electrical or mechanical output to 
qualify for the CHP-specific method for calculating net electric sales 
and net energy output.
    In the 2015 NSPS, the EPA did not issue standards of performance 
for certain types of sources--including industrial CHP units and CHPs 
that are subject to a federally enforceable permit limiting annual net 
electric sales to no more than the unit's design efficiency multiplied 
by its potential electric output, or 219,000 MWh or less, whichever is 
greater. For CHP units, the approach in 40 CFR part 60, subpart TTTT 
for determining net electric sales for applicability purposes allows 
the owner/operator to subtract the purchased power of the thermal host 
facility. The intent of the approach is to determine applicability 
similarly for third-party developers and CHP units owned by the thermal 
host facility.\228\ However, as written in 40 CFR part 60, subpart 
TTTT, each third-party CHP unit would subtract the entire electricity 
use of the thermal host facility when determining its net electric 
sales. It is clearly not the intent of the provision to allow multiple 
third-party developers that serve the same thermal host to all subtract 
the purchased power of the thermal host facility when determining net 
electric sales. This would result in counting the purchased power 
multiple times. In addition, it is not the intent of the provision to 
allow a CHP developer to provide a trivial amount of useful thermal 
output to multiple thermal hosts and then subtract all the thermal 
hosts' purchased power when determining net electric sales for 
applicability purposes. The proposed approach in 40 CFR part 60, 
subpart TTTTa would set a limit to the amount of thermal host purchased 
power that a third-party CHP developer can subtract for electric sales 
when determining net electric sales equivalent to the percentage of 
useful thermal output provided to the host facility by the specific CHP 
unit. This approach would eliminate both circumvention of the intended 
applicability by sales of trivial amounts of useful thermal output and 
double counting of thermal host-purchased power.
---------------------------------------------------------------------------

    \228\ For contractual reasons, many developers of CHP units sell 
all the generated electricity to the electricity distribution grid 
even though in actuality a significant portion of the generated 
electricity is used onsite. Owners/operators of both the CHP unit 
and thermal host can subtract the site purchased power when 
determining net electric sales. Third party developers that do not 
own the thermal host can also subtract the purchased power of the 
thermal host when determining net electric sales for applicability 
purposes.
---------------------------------------------------------------------------

    Finally, to avoid potential double counting of electric sales, the 
EPA is proposing that for CHP units determining net electric sales, 
purchased power of the host facility would be determined based on the 
percentage of thermal power provided to the host facility by the 
specific CHP facility.
iii. Non-Natural Gas Stationary Combustion Turbines
    There is currently an exemption in 40 CFR part 60, subpart TTTT for

[[Page 33283]]

stationary combustion turbines that are not physically capable of 
combusting natural gas (e.g., those that are not connected to a natural 
gas pipeline). While combustion turbines not connected to a natural gas 
pipeline meet the general applicability of 40 CFR part 60, subpart 
TTTT, these units are not subject to any of the requirements. The EPA 
is proposing requirements for new and reconstructed combustion turbines 
that are not capable of combusting natural gas. As described in the 
standards of performance section, the Agency is proposing that owners/
operators of combustion turbines burning fuels with a higher heat input 
emission rate than natural gas would adjust the natural gas-fired 
emissions rate by the ratio of the heat input-based emission rates. The 
overall result is that new stationary combustion turbines combusting 
fuels with higher GHG emissions rates than natural gas on a lb 
CO2/MMBtu basis would have to maintain the same efficiency 
compared to a natural gas-fired combustion turbine and comply with a 
standard of performance based on the identified BSER. Therefore, the 
EPA is not including in 40 CFR part 60, subpart TTTTa, the exemption 
for stationary combustion turbines that are not physically capable of 
combusting natural gas.

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

    In this section, the EPA describes the technologies it is proposing 
to determine are the BSER for each of the subcategories of new and 
reconstructed combustion turbines that commence construction after the 
date of this proposal, and explains its basis for proposing those 
controls, and not others, as the BSER. The controls that the EPA is 
evaluating include combusting non-hydrogen lower emitting fuels (e.g., 
natural gas and distillate oil), using highly efficient generation, 
using CCS, and co-firing with low-GHG hydrogen.
    For the low-load subcategory, the EPA is proposing the use of lower 
emitting fuels as the BSER. For the intermediate load subcategory, the 
EPA is proposing an approach under which the BSER is made up of two 
components that each represent a different set of controls, and that 
form the basis of standards of performance that apply in multiple 
phases. That is, affected facilities--which are facilities that 
commence construction or reconstruction after the date of this proposed 
rulemaking--must meet the first phase of the standard of performance, 
which is based on the application of the first component of the BSER, 
highly efficient generation, by the date the rule is finalized; and 
then meet the second and more stringent phase of the standard of 
performance, which is based on co-firing 30 percent (by volume) low-GHG 
hydrogen by 2032. The EPA is also soliciting comment on whether the 
intermediate load subcategory should apply a third component of BSER, 
which is co-firing 96 percent (by volume) low-GHG hydrogen by 2038. In 
addition, the EPA is also soliciting comment on whether the low load 
subcategory should apply the second component of BSER, which is co-
firing 30 percent (by volume) low-GHG hydrogen by 2032. These latter 
components of BSER would also include the continued application of 
highly efficient generation.
    For the base load subcategory, the EPA is also proposing a multi-
component BSER and an associated multi-phase standard of performance. 
The first component of the BSER, as with intermediate load combustion 
turbines, is highly efficient generation. New base load combustion 
turbines would be required to meet a phase one standard of performance 
based on the application of the first component of the BSER upon 
initial startup of the source. Subsequently, EPA is proposing two 
technology pathways as potential BSER for base load combustion 
turbines, with corresponding standards of performance. The first 
technology pathway is based on 90 percent CCS, which base load 
combustion turbines may install and begin to operate to meet the 
standard of performance by 2035. The second technology pathway is based 
on co-firing low-GHG hydrogen, which EPA proposes base load combustion 
turbines may undertake in two steps--by co-firing 30 percent (by 
volume) low-GHG hydrogen to meet the second phase of the standard of 
performance by 2032 and, then by co-firing 96 percent (by volume) low-
GHG hydrogen to meet the third phase of the standard of performance by 
2038. Throughout, base load turbines, like intermediate load turbines, 
would remain subject to the BSER of highly efficient generation.
    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 but recognizes that building the 
infrastructure required to support widespread use of CCS and low-GHG 
hydrogen in the power sector will take place on a multi-year time 
scale. Accordingly, newly constructed or reconstructed facilities must 
be aware of their need to ramp toward more stringent phases of the 
standards, which reflect application of the more stringent controls in 
the BSER, either through use of co-firing a lower level of low-GHG 
hydrogen by 2032 and a higher level of low-GHG hydrogen by 2038 or 
through use of CCS by 2035. The EPA is also soliciting comment on the 
potential for an earlier compliance date for the second phase, for 
instance, 2030 for units co-firing 30 percent hydrogen by volume and 
2032 for units installing CCS.
    For the base load subcategory, the EPA is proposing both potential 
BSER pathways because it believes there may be more than one viable 
BSER pathway for base load combustion turbines to significantly reduce 
their CO2 emissions and believes there is value in receiving 
comment on, and potentially finalizing, both BSER pathways to enable 
project developers to elect how they will reduce their CO2 
emissions on timeframes that make sense for each BSER pathway. The EPA 
recognizes that standards of performance are technology neutral and 
that if the EPA finalizes a standard based on application of CCS, units 
could meet that standard using co-firing of low-GHG hydrogen. The EPA 
solicits comment on whether co-firing of low-GHG hydrogen should be 
considered a compliance pathway for sources to meet a single standard 
of performance based on application of CCS rather than a separate BSER 
pathway. The EPA believes that there will be earlier opportunities for 
units to begin co-firing lower amounts of low-GHG hydrogen than to 
install and begin operating 90 percent CCS systems. However, it will 
likely take a longer timeframe for those units to then ramp up to co-
firing significant quantities of low-GHG hydrogen. Therefore, in this 
proposal, the EPA presents these pathways as separate subcategories, 
while soliciting comment on the option of finalizing a single standard 
of performance based on application of CCS.
    Specifically, with respect to the first phase of the standards of 
performance, for both the intermediate load and base load 
subcategories, the EPA is proposing that the BSER is highly efficient 
generating technology--combined cycle technology for the base load 
subcategories and simple cycle technology for the intermediate load 
subcategory--as well as operating and maintaining it efficiently. The 
EPA sometimes refers to highly efficient generating technology in 
combination with the best operating and

[[Page 33284]]

maintenance practices as highly efficient generation.
    The affected sources must meet standards based on this efficient 
generating technology upon the effective date of the final rule. With 
respect to the second phase of the standards of performance, for base 
load combustion turbines adopting the CCS pathway, the BSER includes 
the use of 90 percent CCS. These sources would be required to meet 
standards of performance by 2035 that reflect application of both 
components of the BSER--highly efficient generation and CCS--and thus 
are more stringent. For base load combustion turbines adopting the low-
GHG hydrogen co-firing pathway and for intermediate load combustion 
turbines, the BSER includes co-firing 30 percent by volume (12 percent 
by heat input) low-GHG hydrogen. These sources would be required to 
meet second phase standards of performance by 2032 that reflect the 
application of both components of the BSER--in this case, highly 
efficient generation and co-firing 30 percent (by volume) low-GHG 
hydrogen--and that are, again, more stringent. Finally, for base load 
combustion turbines adopting the low-GHG hydrogen co-firing pathway, 
the BSER also includes a third component--co-firing 96 percent (by 
volume) low-GHG hydrogen. These sources would be required to meet a 
third phase standard of performance equivalent to that for the affected 
sources applying CCS as a second component of the BSER. These sources 
would be required to meet that equivalent standard of performance 
reflecting the application of highly efficient generation and co-firing 
high levels of low-GHG hydrogen. Table 1 summarizes the proposed BSER 
for combustion turbine EGUs that commence construction or 
reconstruction after publication of this proposal. The EPA is also 
proposing standards of performance based on those BSER for each 
subcategory, as discussed in section VII.G.

                               Table 1--Proposed BSER for Combustion Turbine EGUs
----------------------------------------------------------------------------------------------------------------
                                                         1st Component       2nd Component       3rd Component
           Subcategory                   Fuel                BSER                BSER                BSER
----------------------------------------------------------------------------------------------------------------
Low Load *......................  All Fuels.........  Lower emitting      N/A...............  N/A
                                                       fuels.
Intermediate Load...............  All Fuels.........  Highly Efficient    30 percent (by      N/A
                                                       Generation.         volume) Low-GHG
                                                                           Hydrogen Co-
                                                                           firing by 2032.
Base Load.......................  Sources adopting    Highly Efficient    90 percent CCS by   N/A
                                   the CCS pathway.    Generation.         2035.
                                  Sources adopting    ..................  30 percent (by      96 percent (by
                                   the low-GHG                             volume) Low-GHG     volume) Low-GHG
                                   hydrogen co-                            Hydrogen Co-        Hydrogen Co-
                                   firing pathway.                         firing by 2032.     firing by 2038
----------------------------------------------------------------------------------------------------------------
* The low load subcategory has a single-component BSER consisting of fuels that emit lower GHG emissions.

1. BSER for Low Load Subcategory
    This section describes the proposed BSER for the low load (i.e., 
peaking) subcategory, which is the use of lower emitting fuels. For 
this proposed rule, the Agency proposes to determine that the use of 
lower emitting fuels, which the EPA determined to be the BSER for the 
non-base load subcategory in the 2015 NSPS, is the BSER for this low 
load subcategory in the standards of performance proposed in this 
action. As explained above, the EPA is proposing to narrow the 
definition of the low load subcategory by lowering the electric sales 
threshold (as compared to the electric sales threshold for non-base 
load combustion turbines in the 2015 NSPS), so that turbines with 
higher electric sales would be placed in the proposed intermediate load 
subcategory and therefore be subject to a more stringent standards 
based on the more stringent component of the BSER. Unlike the proposals 
for intermediate and base load combustion turbines, the proposed low 
load subcategory includes only a single-phase BSER component.
a. Background: The Non-Base Load Subcategory in the 2015 NSPS
    The 2015 NSPS defined non-base load natural gas-fired EGUs as 
stationary combustion turbines that (1) Burn more than 90 percent 
natural gas and (2) have net electric sales equal to or less than their 
design efficiency (not to exceed 50 percent) multiplied by their 
potential electric output (80 FR 64601; October 23, 2015). These are 
calculated on 12-operating-month and 3-year rolling average bases. The 
EPA also determined in the 2015 NSPS that the BSER for newly 
constructed and reconstructed non-base load natural gas-fired 
stationary combustion turbines is the use of lower emitting fuels. Id. 
at 64515. These lower emitting fuels are primarily natural gas with a 
small allowance for distillate oil (i.e., Nos. 1 and 2 fuel oils), 
which have been widely used in stationary combustion turbine EGUs for 
decades.
    The EPA also determined in the 2015 NSPS that the standard of 
performance for sources in this subcategory is a heat input-based 
standard of 120 lb CO2/MMBtu. The EPA established this 
clean-fuels BSER for this subcategory because of the variability in the 
operation in non-base load combustion turbines and the challenges 
involved in determining a uniform output-based standard that all new 
and reconstructed non-base load units could achieve.
    Specifically, in the 2015 NSPS, the EPA recognized that a BSER for 
the non-base load subcategory based on the use of lower emitting fuels 
results in limited GHG reductions, but further recognized that an 
output-based standard of performance could not reasonably be applied to 
the subcategory. The EPA explained that a combustion turbine operating 
at a low capacity factor could operate with multiple starts and stops, 
and that its emission rate would be highly dependent on how it was 
operated and not its design efficiency. Moreover, combustion turbines 
with low annual capacity factors typically operated differently from 
each other, and therefore had different emission rates. The EPA 
recognized that, as a result, it would not be possible to determine a 
standard of performance that could reasonably apply to all combustion 
turbines in the subcategory. For that reason, the EPA further 
recognized, efficient design \229\ and operation would not qualify as 
the BSER; rather, the BSER should be lower

[[Page 33285]]

emitting fuels and the associated standard of performance should be 
based on heat input. Since the 2015 NSPS, all newly constructed simple 
cycle turbines have been non-base load units and thus have become 
subject to this standard of performance.
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    \229\ Important characteristics for minimizing emissions from 
low load combustion turbines include the ability to operate 
efficiently while operating at part load conditions and the ability 
to rapidly achieve maximum efficiency to minimize periods of 
operation at lower efficiencies. These characteristics do not 
necessarily always align with higher design efficiencies that are 
determined under steady state full load conditions.
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b. Proposed BSER
    Consistent with the rationale of the 2015 NSPS, the EPA proposes 
that the use of fuels with an emissions rate of less than 160 lb 
CO2/MMBtu (i.e., lower emitting fuels) meets the BSER 
requirements for the low load subcategory. Use of these fuels is 
technically feasible for combustion turbines. Natural gas comprises the 
majority of the heat input for simple cycle turbines and is the lowest 
cost fossil fuel. In the 2015 NSPS, the EPA determined that natural gas 
comprised 96 percent of the heat input for simple cycle turbines. See 
80 FR 64616 (October 23, 2015). Therefore, a BSER based on the use of 
natural gas and/or distillate oil would have minimal, if any, costs to 
regulated entities. The use of lower emitting fuels would not have any 
significant adverse energy requirements or non-air quality or 
environmental impacts, as the EPA determined in the 2015 NSPS. Id. at 
64616. In addition, the use of fuels meeting this criterion would 
result in some emission reductions by limiting the use of fuels with 
higher carbon content, such as residual oil, as the EPA also explained 
in the 2015 NSPS. Id. Although the use of fuels meeting this criterion 
would not advance technology, in light of the other reasons described 
here, the EPA proposes that the use of natural gas, Nos. 1 and 2 fuel 
oils, and other fuels \230\ currently specified in 40 CFR part 60, 
subpart TTTT, qualify as the BSER for new and reconstructed combustion 
turbine EGUs in the low load subcategory. The EPA is also proposing to 
add low-GHG hydrogen to the list of fuels meeting the uniform fuels 
criteria in 40 CFR part 60, subpart TTTTa. The addition of low-GHG 
hydrogen (and fuels derived from hydrogen) to 40 CFR part 60, subpart 
TTTTa would simplify the recordkeeping and reporting requirements for 
low load combustion turbines that elect to burn low-GHG hydrogen. As 
described in section VII.F, a component of the BSER for certain 
subcategories in subpart TTTTa is based on the use of low-GHG hydrogen. 
An owner/operator of a subpart TTTTa affected combustion turbine that 
combusts hydrogen for compliance purposes not meeting the definition of 
low-GHG hydrogen would be in violation of the subpart TTTTa 
requirements.
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    \230\ The BSER for multi-fuel-fired combustion turbines subject 
to 40 CFR part 60, subpart TTTT is also the use of fuels with an 
emissions rate of 160 lb CO2/MMBtu or less. The use of 
these fuels would demonstrate compliance with the low load 
subcategory.
---------------------------------------------------------------------------

    For the reasons discussed in the 2015 NSPS and noted above, the EPA 
is not proposing that efficient design and operation qualify as the 
BSER for the low load subcategory. The EPA is not proposing high-
efficiency simple cycle or combined cycle turbine design and operation 
as the BSER for the low load subcategory because they are not 
necessarily cost reasonable and would not necessarily result in 
emission reductions. High efficiency combustion turbines have higher 
initial costs compared to lower efficiency combustion turbines. The 
cost of combustion turbine engines is dependent upon many factors, but 
the EPA estimates that the capital cost of a high-efficiency simple 
cycle turbine is 5 percent more than that of a comparable lower 
efficiency simple cycle turbine. Assuming all other costs are the same 
and that the high-efficiency simple cycle turbine uses 6 percent less 
fuel, it would not necessarily be cost reasonable to use a high-
efficiency simple cycle turbine until the combustion turbine is 
operated at a 12-operating-month capacity factor of approximately 20 
percent. At lower capacity factors, the CO2 abatement costs 
on both a $/ton and $/MW basis increase rapidly.\231\ Further, the 
emission rate of a low load combustion turbine is highly dependent upon 
the way the combustion turbine is operated. If the combustion turbine 
is frequently operated at part load conditions with frequent starts and 
stops, a combustion turbine with a high design efficiency, which is 
determined at full load steady state conditions, would not necessarily 
emit at a lower GHG rate than a combustion turbine with a lower design 
efficiency.
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    \231\ The cost effectiveness calculation is highly dependent 
upon assumptions concerning the increase in capital costs, the 
decrease in heat rate, and the price of natural gas.
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    The EPA solicits comment on whether, and the extent to which, high-
efficiency designs also operate more efficiently at part loads and can 
start more quickly and reach the desired load more rapidly than 
combustion turbines with less efficient design efficiencies. If high-
efficiency simple cycle turbines do operate at higher part-load 
efficiencies and are able to reach the intended operating load more 
quickly, the use of highly efficient simple cycle turbines for low load 
applications would result in lower GHG reductions. In addition, the EPA 
solicits comment on the cost premium of high-efficiency simple cycle 
turbines. If the use of highly efficient simple cycle turbines results 
in GHG reductions at reasonable cost, their use could qualify as the 
BSER for low load combustion turbines. The EPA is soliciting comment on 
whether the BSER for new low load combustion turbines should be the use 
of high efficiency simple cycle technology. However, since the method 
of operation has a substantial impact on the emissions rate, it may not 
be feasible for to prescribe or enforce a single numerical standard of 
performance for affected sources strictly based on design efficiency. 
Accordingly, the EPA solicits comment on whether it would be 
appropriate to promulgate such a requirement as a design standard 
pursuant to CAA section 111(h). Pursuant to such a design standard, 
compliance would be demonstrated (i) initially, through an emissions 
test and (ii) subsequently, based on the use of lower emitting fuels. 
The initial full load performance test for natural gas-fired low load 
combustion turbines the EPA is considering is 1,150 lb CO2/
MWh-gross or 1,100 lb CO2/MWh-gross.\232\ Combustion turbine 
manufacturers conduct testing on their products and the initial 
performance test is equivalent to a design efficiency of approximately 
35 and 36 percent, respectively. According to Gas Turbine World 2021, 
approximately three-fourths of simple cycle combustion turbines have 
design efficiencies of 35 percent or higher and half of simple cycle 
combustion turbines have design efficiencies of 36 percent or higher. 
The EPA is soliciting comment on if the initial performance test for 
low load combustion turbines could be conducted by the manufacturer 
certifying the design GHG emissions rate or if the owner or operator 
should be required to conduct separate testing to verify the emissions 
rate. The EPA notes that even if the Agency determines that a 
manufacturer design efficiency-based emissions requirement is 
appropriate for new low load combustion turbines, owners/operators 
would also have the option to either comply with the intermediate load 
standard of performance on a continuous basis or conduct an initial 
performance test as an alternative to purchasing a combustion turbine 
that

[[Page 33286]]

achieves the specified design efficiency. For example, owners/operators 
could elect to cofire low-GHG hydrogen or install integrated renewable 
generation as an alternative to purchasing a combustion turbine that 
meets the specified design efficiency.
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    \232\ The initial full load compliance test would be a 3-hour 
performance test and the measured emissions rate would be corrected 
to ISO conditions.
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    The EPA expects that units in the low load subcategory will be 
simple cycle turbines. The capital cost of a combined cycle EGU is 
approximately 250 percent that of a comparable sized simple cycle EGU 
and would not be recovered by reduced fuel costs if operated as low 
load units. Furthermore, low load combustion turbines start and stop so 
frequently that there might not be sufficient periods of continuous 
operation for the HRSG to begin generating steam to operate the steam 
turbine enough to significantly lower the emissions rate of the EGU.
    The EPA is not proposing the use of CCS or hydrogen co-firing as 
the BSER (or as a component of the BSER) for low load combustion 
turbines.\233\ As described in the section discussing the second 
component of BSER for the intermediate load subcategory, the EPA is not 
proposing that CCS is the BSER for simple cycle combustion turbines 
based on the Agency's assessment that CCS may not be cost-effective for 
such combustion turbines when operated at intermediate load. This 
rationale applies with even greater force for low load combustion 
turbines. In addition, currently available post-combustion amine-based 
carbon capture systems require that the exhaust from a combustion 
turbine be cooled prior to entering the carbon capture equipment. The 
most energy efficient way to do this is to use a HSRG, which is an 
integral component of a combined cycle turbine system but is not 
incorporated in a simple cycle unit. For these reasons, the Agency is 
not proposing that CCS qualifies as the BSER for this subcategory of 
sources.
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    \233\ The EPA will not finalize the use of CCS or hydrogen co-
firing as the BSER (or as a component of the BSER) for low load 
combustion turbines unless it first issues a subsequent notice of 
proposed rulemaking further evaluating such measures for that 
subcategory.
---------------------------------------------------------------------------

    The EPA is not proposing low-GHG hydrogen co-firing as the BSER for 
low load combustion turbines because not all new combustion turbines 
can necessarily co-fire higher percentages of hydrogen, there are 
potential infrastructure issues specific to low load combustion 
turbines, and at the relatively infrequent levels of utilization that 
characterize the low load subcategory, a low-GHG hydrogen co-firing 
BSER would not necessarily result in cost-effective GHG reductions for 
all low load combustion turbines. As discussed later in this section, 
the announced hydrogen co-firing combustion turbine projects appear to 
be intermediate and base load combustion turbines. Manufacturers may 
focus initial research and development for hydrogen co-firing on 
combustion turbines that operate at higher capacity factors and that 
can achieve higher levels of overall GHG reductions. The EPA is 
soliciting comment on whether this development could limit the 
availability of low load combustion turbines that are capable of 
burning higher percentages of hydrogen. The EPA is also soliciting 
comment on technologies to reduce potential costs and technical 
challenges for the transport and storage of hydrogen for owners/
operators of low load combustion turbines. In particular, the EPA is 
soliciting comment on approaches that could be used for owners/
operators of low load combustion turbines located in high demand 
centers (e.g., dense urban areas). To the extent these factors are not 
significant, the EPA is soliciting comment, with the intention of 
determining whether it would be appropriate to consider such a 
requirement in a future rulemaking, on whether the EPA should add a 
second component of the BSER for low load combustion turbines, based on 
hydrogen co-firing that would begin in 2032. The hydrogen co-firing 
requirement would be a separate requirement in addition to the proposed 
lower emitting fuels requirement. Based on simple cycle turbines that 
recently commenced operation, the average 12-operating-month capacity 
factor of low load combustion turbines would be less than 8 percent. If 
hydrogen co-firing were to qualify as the BSER, based on historical 
trends for construction of new simple cycle turbines and the operation 
of those turbines in 2021, a BSER based on 30 percent low-GHG hydrogen 
co-firing by volume for low load combustion turbines would result in 
annual reductions of 49,000 tons of CO2.
2. BSER for Base Load and Intermediate Load Subcategories--First 
Component
    This section describes the first component of the EPA's proposed 
BSER for newly constructed and reconstructed combustion turbines in the 
base load and intermediate load subcategories. For combustion turbines 
in the intermediate load subcategory, this first component of the BSER 
is the use of high-efficiency simple cycle turbine technology in 
combination with the best operating and maintenance practices. For 
combustion turbines in the base load subcategory, the first component 
of the BSER is the use of high-efficiency combined cycle technology in 
combination with the best operating and maintenance practices.
a. Lower Emitting Fuels
    The EPA is not proposing lower emitting fuels as the BSER for 
intermediate load or base load EGUs because, as described earlier in 
this section, it would achieve few GHG emission reductions compared to 
highly efficient generation.
b. Highly Efficient Generation
    The use of highly efficient generating technology in combination 
with the best operating and maintenance practices has been demonstrated 
by multiple facilities for decades. Notably, over time, as technologies 
have improved, what is considered highly efficient has changed as well. 
Highly efficient generating technology is available and offered by 
multiple vendors for both simple cycle and combined cycle combustion 
turbines. Both types of turbines can also employ best operating and 
maintenance practices, which include routine operating and maintenance 
practices that minimize fuel use.
    For simple cycle combustion turbines, manufacturers continue to 
improve the efficiency by increasing firing temperature, increasing 
pressure ratios, using intercooling on the air compressor, and adopting 
other measures. These improved designs allow for improved operating 
efficiencies and reduced emission rates. Design efficiencies of simple 
cycle combustion turbines range from 33 to 40 percent. Best operating 
practices for simple cycle combustion turbines include proper 
maintenance of the combustion turbine flow path components and the use 
of inlet air cooling to reduce efficiency losses during periods of high 
ambient temperatures.
    For combined cycle turbines, high-efficiency technology uses a 
highly efficient combustion turbine engine matched with a high-
efficiency HRSG. The most efficient combined cycle EGUs use HRSG with 
three different steam pressures and incorporate a steam reheat cycle to 
maximize the efficiency of the Rankine cycle. It is not necessarily 
practical for owner/operators of combined cycle facilities using a 
turbine engine with an exhaust temperature below 593 [deg]C or a steam 
turbine engine smaller than 60 MW to incorporate a steam reheat cycle. 
Smaller combustion turbine engines, less than those rated at 
approximately 2,000 MMBtu/h, tend to have lower

[[Page 33287]]

exhaust temperatures and are paired with steam turbines of 60 MW or 
less. These smaller combined cycle units are limited to using triple-
pressure steam without a reheat cycle. This reduces the overall 
efficiency of the combined cycle unit by approximately 2 percent. 
Therefore, the EPA is proposing less stringent standards of performance 
for smaller combined cycle EGUs with base load ratings of less than 
2,000 MMBtu/h relative to those for larger combined cycle combustion 
turbine EGUs. High efficiency also includes, but is not limited to, the 
use of the most efficient steam turbine and minimizing energy losses 
using insulation and blowdown heat recovery. Best operating and 
maintenance practices include, but are not limited to, minimizing steam 
leaks, minimizing air infiltration, and cleaning and maintaining heat 
transfer surfaces.
    New technologies are available for new simple and combined cycle 
EGUs that could reduce emissions beyond what is currently being 
achieved by the best performing EGUs. For example, pressure gain 
combustion in the turbine engine would increase the efficiency of both 
simple and combined cycle EGUs. For combined cycle EGUs, the HRSG could 
be designed to utilize supercritical steam conditions or to utilize 
supercritical CO2 as the working fluid instead of water; 
useful thermal output could be recovered from a compressor intercooler 
and boiler blowdown; and fuel preheating could be implemented. For 
additional information on these and other technologies that could 
reduce the emissions rate of new combustion turbines, see the Efficient 
Generation at Combustion Turbine Electric Generating Units TSD, which 
is available in the rulemaking docket. The EPA is soliciting comment on 
whether these technologies should be incorporated into a standard of 
performance based on an efficient generation BSER. To the extent 
commenters support the inclusion of emission reductions from the use of 
these technologies, the EPA requests that cost information and 
potential emission reductions be included.
i. Adequately Demonstrated
    The EPA proposes that highly efficient simple cycle and combined 
cycle designs are adequately demonstrated because highly efficient 
simple cycle EGUs and highly efficient combined cycle EGUs have been 
demonstrated by multiple facilities for decades, the efficiency 
improvements of the most efficient designs are incremental in nature 
and do not change in any significant way how the combustion turbine is 
operated or maintained, and the levels of efficiency that the EPA is 
proposing have been achieved by many recently constructed turbines. 
Approximately 14 percent of simple cycle and combined cycle combustion 
turbines that have commenced operation since 2015 have maintained 
emission rates below the proposed standards, demonstrating that the 
efficient generation technology described in this BSER is commercially 
available and that the standards of performance the EPA is proposing 
are achievable.
ii. Costs
    In general, advanced generation technologies enhance operational 
efficiency compared to lower efficiency designs. Such technologies 
present little incremental capital cost compared to other types of 
technologies that may be considered for new and reconstructed sources. 
In addition, more efficient designs have lower fuel costs that offset 
at least a portion of the increase in capital costs.
    For the intermediate load subcategory, the EPA proposes that the 
costs of high-efficiency simple cycle combustion turbines are 
reasonable. As described in the subcategory section, the cost of 
combustion turbine engines is dependent upon many factors, but the EPA 
estimates that that the capital cost of a high-efficiency simple cycle 
turbine is 5 percent more than a comparable lower efficiency simple 
cycle turbine. Assuming all other costs are the same and that the high-
efficiency simple cycle turbine uses 6 percent less fuel, high-
efficiency simple cycle combustion turbines have a lower LCOE compared 
to standard efficiency simple cycle combustion turbines at a 12-
operating-month capacity factor of approximately 20 percent. Therefore, 
a BSER based on the use of high-efficiency simple cycle combustion 
turbines for intermediate load combustion turbines would have minimal, 
if any, overall compliance costs since the capital costs would be 
recovered through reduced fuel costs. The EPA considered but is not 
proposing combined cycle unit design for combustion turbines in the 
intermediate subcategory because the capital cost of a combined cycle 
EGU is approximately 250 percent that of a comparable-sized simple 
cycle EGU and because the amount of GHG reductions that could be 
achieved by operating combined cycle EGUs as intermediate load EGUs is 
unclear. Furthermore, intermediate load combustion turbines start and 
stop so frequently that there might not be sufficient periods of 
continuous operation where the HRSG would have sufficient time to 
generate steam to operate the steam turbine enough to significantly 
lower the emissions rate of the EGU.
    For the base load subcategory, the EPA proposes that the cost of 
high-efficiency combined cycle EGUs is reasonable. While the capital 
costs of a higher efficiency combined cycle EGUs are 1.9 percent higher 
than standard efficiency combined cycle EGUs, fuel use is 2.6 percent 
lower.\234\ The reduction in fuel costs fully offset the capital costs 
at capacity factors of 40 percent or greater over the expected 30-year 
life of the facility. Therefore, a BSER based on the use of high-
efficiency combined cycle combustion turbines for base load combustion 
turbines would have minimal, if any, overall compliance costs since the 
capital costs would be recovered through reduced fuel costs over the 
expected 30-year life of the facility. For additional information on 
costs, see the Efficient Generation at Combustion Turbine Electric 
Generating Units TSD, which is available in the rulemaking docket.
---------------------------------------------------------------------------

    \234\ Cost And Performance Baseline for Fossil Energy Plants 
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 4A 
(October 2022), https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_101422.pdf.
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iii. Non-Air Quality Health and Environmental Impact and Energy 
Requirements
    Use of highly efficient simple cycle and combined cycle generation 
reduces all non-air quality health and environmental impacts and energy 
requirements as compared to use of less efficient generation. Even when 
operating at the same input-based emissions rate, the more efficient a 
unit is, the less fuel is required to produce the same level of output; 
and, as a result, emissions are reduced for all pollutants. The use of 
highly efficient simple cycle turbines, compared to the use of less 
efficient simple cycle turbines, reduces all pollutants. Similarly, the 
use of high-efficiency combined combustion turbines, compared to the 
use of less efficient combine cycle turbines, reduces all pollutants. 
By the same token, because improved efficiency allows for more 
electricity generation from the same amount of fuel, it will not have 
any adverse effects on energy requirements.
    Designating highly efficient generation as part of the BSER for new 
and reconstructed base load and intermediate load combustion turbines 
will not have significant impacts on the

[[Page 33288]]

nationwide supply of electricity, electricity prices, or the structure 
of the electric power sector. On a nationwide basis, the additional 
costs of the use of highly efficient generation will be small because 
the technology does not add significant costs and at least some of 
those costs are offset by reduced fuel costs. In addition, at least 
some of these new combustion turbines would be expected to incorporate 
highly efficient generation technology in any event.
iv. Extent of Reductions in CO2 Emissions
    The EPA estimated the potential emission reductions associated with 
a standard that reflects the application of highly efficient generation 
as BSER for the intermediate load and base load subcategories. As 
discussed in section VII.G, the EPA determined that the standards of 
performance reflecting this BSER are 1,150 lb CO2/MWh-gross 
for intermediate load and 770 lb CO2/MWh-gross for large 
base load combustion turbines.
    Between 2015 and 2021, an average of 16 simple cycle turbines 
commenced operation per year. Of these, the EPA estimates that an 
average of six operated at greater than a 20 percent capacity factor on 
a 12-operating-month basis and thus would be considered intermediate 
load combustion turbines. For recent intermediate load simple cycle 
turbines, the EPA determined that the weighted average maximum 12-
operating-month emissions rate \235\ is 1,250 lb CO2/MWh-
gross. This is 8.3 percent higher than the proposed intermediate load 
standard of 1,150 lb CO2/MWh-gross. Therefore, the EPA 
estimates that the proposed standard of performance based on the 
application of the proposed BSER for intermediate load combustion 
turbines would reduce the GHG emissions from those sources by 8.3 
percent annually. Based on historical trends for construction of new 
simple cycle turbines and the operation of those turbines in 2021, the 
proposed standards for intermediate load combustion turbines would 
result in annual reductions of 44,000 tons of CO2 as well as 
13 tons of NOX. For the base load subcategory, the weighted 
average maximum 12-operating-month emissions rate of large (base load 
ratings of 2,000 MMBtu/h or more) NGCC combustion turbines that 
commenced operation since 2015 has been 810 lb CO2/MWh-
gross. This is 5 percent higher than the proposed standard of 770 lb 
CO2/MWh-gross for large base load combustion turbines. The 
only small, combined cycle combustion turbine (base load rating of 593 
MMBtu/h) reporting emissions that commenced operation since 2015 has 
had a reported annual emissions rate of 870 lb CO2/MWh-
gross, which is slightly lower than the proposed standard of 875 lb 
CO2/MWh-gross for a small base load combustion turbine with 
a base load rating of 593 MMBtu/h. Therefore, the EPA estimates that 
the proposed standards would require owners/operators to construct and 
maintain highly efficient combined cycle combustion turbines that would 
result in reductions in emissions of approximately 5 percent for new 
large stationary combustion EGUs and maintaining best performing 
emission rates for new small stationary combustion EGUs. Using 
historical trends for new combined cycle turbines and the operation of 
those combustion turbines in 2021, the proposed standards for base load 
combustion turbines would result in annual reductions of 940,000 tons 
of CO2 as well as 75 tons of NOX.
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    \235\ The EPA is defining the achievable emissions rate as 
either the maximum 12-operating-month or the 99th percent confidence 
12-operating-month emissions rate. The weighted average maximum 
emissions rate is the heat input weighted overall average of the 
maximum emission rates.
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v. Promotion of the Development and Implementation of Technology
    The EPA also considered the potential impact of selecting highly 
efficient generation technology as the BSER in promoting the 
development and implementation of improved control technology. This 
technology is more efficient than the average new generation technology 
and determining it to be a component of the BSER will advance its 
penetration throughout the industry. Accordingly, consideration of this 
factor supports the EPA's proposal to determine this technology to be 
the first component of the BSER.
c. Low-GHG Hydrogen and CCS
    For reasons discussed in sections VII.F.3.b.v (CCS) and 
VII.F.3.c.vi (low-GHG hydrogen), the EPA is not proposing either CCS or 
co-firing low-GHG hydrogen as the first component of the BSER for 
intermediate load or base load EGUs.
d. Proposed BSER
    The EPA proposes that highly efficient generating technology in 
combination with the best operating and maintenance practices is the 
first component BSER for base load and intermediate load combustion 
turbines and the phase 1 standards of performance are based on the 
application of that technology. Specifically, the use of highly 
efficient simple cycle technology in combination with the best 
operating and maintenance practices is the first component of the BSER 
for intermediate load combustion turbines. The use of highly efficient 
combined cycle technology in combination with best operating and 
maintenance practices is the first component of the BSER for base load 
combustion turbines.
    Highly efficient generation qualifies as a component of the BSER 
because it is adequately demonstrated, it can be implemented at 
reasonable cost, it achieves emission reductions, and it does not have 
significant adverse non-air quality health or environmental impacts or 
significant adverse energy requirements. The fact that it promotes 
greater use of advanced technology provides additional support; 
however, the EPA would consider highly efficient generation to be a 
component of the BSER for base load and intermediate load combustion 
turbines even without taking this factor into account.
3. BSER for Base Load and Intermediate Load Subcategories--Second and 
Third Components
    This section describes the proposed second (and in some cases 
third) component of the BSER for base load and intermediate load 
combustion turbines, which would be reflected in the second phase (and 
in some cases third phase) standards of performance. The proposed 
second component of the BSER for base load combustion turbines that are 
adopting the CCS pathway is the use of 90 percent CCS; and the 
corresponding standard of performance would apply beginning in 2035. 
The second component of the BSER for base load combustion turbines that 
are adopting the low-GHG hydrogen co-firing pathway and for 
intermediate load combustion turbines is co-firing 30 percent (by 
volume) low-GHG hydrogen and the corresponding standard of performance 
would apply beginning in 2032. The third component of the BSER would 
apply only to base load combustion turbines that are subject to a 
second phase standard that is based on co-firing 30 percent (by volume) 
low-GHG hydrogen. For those sources, the third component of the BSER is 
co-firing 96 percent (by volume) low-GHG hydrogen and the corresponding 
standard of performance would apply beginning in 2038. The EPA is also 
soliciting comment on whether intermediate load combustion turbines 
should be subject to a more stringent third phase standard based on 96 
percent low-GHG hydrogen co-firing by 2038. A BSER based on 96 percent 
co-firing would result in a standard of

[[Page 33289]]

performance of 140 lb CO2/MWh-gross for a natural gas-fired 
intermediate load combustion turbine.
a. Authority To Promulgate a Multi-Part BSER and Standard of 
Performance
    The EPA's proposed approach of promulgating standards of 
performance that apply in multiple phases, based on determining the 
BSER to be a set of controls with multiple components, is consistent 
with CAA section 111(b). That provision authorizes the EPA to 
promulgate ``standards of performance,'' CAA section 111(b)(1)(B), 
defined, in the singular, as ``a standard for emissions of air 
pollutants which reflects the degree of emission limitation achievable 
through the application of the [BSER].'' CAA section 111(a)(1). CAA 
section 111(b)(1)(B) further provides, ``[s]tandards of performance . . 
. shall become effective upon promulgation.'' In this rulemaking, the 
EPA is proposing to determine that the BSER is a set of controls that, 
depending on the subcategory, include either highly efficient 
generation plus use of CCS or highly efficient generation plus co-
firing low-GHG hydrogen. The EPA is further proposing that affected 
sources can apply the first component of the BSER--highly efficient 
generation--by the effective date of the final rule and can apply both 
the first and second components of the BSER--highly efficient 
generation in combination with co-firing 30 percent (by volume) low-GHG 
hydrogen and highly efficient generation in combination with 90 percent 
CCS--in 2032 and 2035, respectively. The EPA is also proposing that 
certain sources can apply the third component of the BSER--co-firing 96 
percent (by volume) low-GHG hydrogen--by 2038.
    Accordingly, the EPA is proposing standards of performance that 
reflect the application of this multi-component BSER and that take the 
form of standards of performance that affected sources must comply with 
in either two or three phases. Affected sources must comply with the 
first phase standards that are based on the application of the first 
component of the BSER upon initial startup of the facility. The second 
phase standards are based on the application of both the first and 
second components of the BSER by 2032 (for those sources utilizing co-
firing low-GHG hydrogen) and by 2035 (for those sources utilizing CCS). 
The third phase standards are only applicable to those sources that are 
subject to a second phase standard of performance based on the highly 
efficient generation in combination with co-firing 30 percent (by 
volume) low-GHG hydrogen. The third phase standards for those sources 
are based on the application of the first component of the BSER and on 
the third component, which is co-firing 96 percent (by volume) low-GHG 
hydrogen by 2038. In this manner, this multi-phase standard of 
performance ``become[s] effective upon promulgation.'' CAA section 
111(b)(1)(B). That is, upon promulgation, affected sources become 
subject to a standard of performance that limits their emissions 
immediately, which is the first phase of the standard of performance, 
and they also become subject to more stringent standards beginning in 
2032 or later, which are the second and in some cases third phase of 
the standard of performance.
    D.C. Circuit caselaw supports the proposition that CAA section 111 
authorizes the EPA to determine that controls qualify as the BSER--
including meeting the ``adequately demonstrated'' criterion--even if 
the controls require some amount of ``lead time,'' which the court has 
defined as ``the time in which the technology will have to be 
available.'' \236\ The caselaw's interpretation of ``adequately 
demonstrated'' to accommodate lead time accords with common sense and 
the practical experience of certain types of controls, discussed below. 
Consistent with this caselaw, the phased implementation of the 
standards of performance in this rule ensures that facilities have 
sufficient lead time for planning and implementation of the use of CCS 
or low GHG-hydrogen-based controls necessary to comply with the second 
phase of the standards, and thereby ensures that the standards are 
achievable. Indeed, interpreting CAA section 111 to preclude phased 
implementation of standards of performance would be tantamount to 
interpreting the provision to preclude standards based on lead time, 
which would be contrary to the D.C. Circuit caselaw and common sense.
---------------------------------------------------------------------------

    \236\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973) (citations omitted).
---------------------------------------------------------------------------

    The EPA has promulgated several prior rulemakings under CAA section 
111(b) that have similarly provided the regulated sector with lead time 
to accommodate the availability of technology, which also serve as 
precedent for the two-phase implementation approach proposed in this 
rule. See 81 FR 59332 (August 29, 2016) (establishing standards for 
municipal solid waste landfills with 30-month compliance timeframe for 
installation of control device, with interim milestones); 80 FR 13672, 
13676 (March 16, 2015) (establishing stepped compliance approach to 
wood heaters standards to permit manufacturers lead time to develop, 
test, field evaluate and certify current technologies to meet Step 2 
emission limits); 78 FR 58416, 58420 (September 23, 2013) (establishing 
multi-phased compliance deadlines for revised storage vessel standards 
to permit sufficient time for production of necessary supply of control 
devices and for trained personnel to perform installation); 77 FR 
56422, 56450 (September 12, 2012) (establishing standards for petroleum 
refineries, with 3-year compliance timeframe for installation of 
control devices); 71 FR 39154, 39158 (July 11, 2006) (establishing 
standards for stationary compression ignition internal combustion 
engines, with 2 to 3-year compliance timeframe and up to 6 years for 
certain emergency fire pump engines); 70 FR 28606, 28617 (March 18, 
2005) (establishing two-phase caps for mercury standards of performance 
from new and existing coal-fired electric utility steam generating 
units based on timeframe when additional control technologies were 
projected to be adequately demonstrated).\237\ Cf. 80 FR 64662, 64743 
(October 23, 2015) (establishing interim compliance period to phase in 
final power sector GHG standards to allow time for planning and 
investment necessary for implementation activities).\238\ In each 
action, the standards and compliance timelines were effective upon the 
final rule, with affected facilities required to comply consistent with 
the phased compliance deadline specified in each action.
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    \237\ Cf. New Jersey v. EPA, 517 F.3d 574, 583-584 (D.C. Cir. 
2008) (vacating rule on other grounds).
    \238\ Cf. West Virginia v. EPA, 142 S. Ct. 2587 (2022) (vacating 
rule on other grounds).
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    It should be noted that the multi-phased implementation of the 
standards of performance that the EPA is proposing in this rule, like 
the delayed or multi-phased standards in prior rules just described, is 
distinct from the promulgation of revised standards of performance 
under the 8-year review provision of CAA section 111(b)(1)(B). As 
discussed in section VII.F, the EPA has determined that the proposed 
BSER--highly efficient generation and use of CCS or highly efficient 
generation and co-firing low-GHG hydrogen--meet all of the statutory 
criteria and are adequately demonstrated for the compliance timeframes 
being proposed. Thus, the second and third phases of the standard of 
performance, if finalized, would apply to affected facilities that 
commence construction after the date of

[[Page 33290]]

this proposal. In contrast, when the EPA later reviews and (if 
appropriate) revises a standard of performance under the 8-year review 
provision, then affected sources that commence construction after the 
date of that proposal of the revised standard of performance would be 
subject to that standard, but not sources that commenced construction 
earlier.
    Similarly, the multi-phased implementation of the standard of 
performance that the EPA is proposing in this rule is also distinct 
from the promulgation of emission guidelines for existing sources under 
CAA section 111(d). Emission guidelines only apply to existing sources, 
which are defined in CAA section 111(a)(6) as ``any stationary source 
other than a new source.'' Because new sources are defined relative to 
the proposal of standards pursuant to CAA section 111(b)(1)(B), 
standards of performance adopted pursuant to emission guidelines will 
only apply to sources constructed before the date of these proposed 
standards of performance for new sources.
b. BSER for Base Load Subcategory of Combustion Turbines Adopting the 
CCS Pathway--Second Component
    This section describes the second component of the BSER for the 
base load subcategory of combustion turbines that are adopting the CCS 
pathway. This subcategory is expected to include highly efficient 
combined cycle combustion turbines that primarily combust fossil fuels, 
and therefore have higher levels of CO2 in the exhaust.
    The EPA is proposing the use of CCS as the second component of the 
BSER for these combustion turbines. A detailed discussion of CCS 
follows. It should be noted that the EPA is also proposing use of CCS 
as the BSER for existing long-term coal-fired steam generating units 
(i.e., coal-fired utility boilers), as discussed in section X.D of this 
preamble, as well as for large and frequently operated existing 
stationary combustion turbines. Many aspects of CCS are common to new 
combined cycle combustion turbines, existing long-term steam generating 
units, and existing stationary combustion turbines, and the following 
discussion details those common aspects and considerations.
i. Lower Emitting Fuels
    The EPA is not proposing lower emitting fuels as the second 
component of the BSER for base load combustion turbines because it 
would achieve few emission reductions, compared to highly efficient 
generation in combination with the use of CCS.
ii. Highly Efficient Generation
    For the reasons described above, the EPA is proposing that highly 
efficient generation technology in combination with best operating and 
maintenance practices continues to be a component of the BSER that is 
reflected in the second phase of the standards of performance for base 
load combustion turbine EGUs that are adopting the CCS pathway. Highly 
efficient generation reduces fuel use and the amount of CO2 
that must be captured by a CCS system. Since less flue gas needs to be 
treated, physically smaller carbon capture equipment may be used--
potentially reducing capital, fixed, and operating costs.
iii. CCS
    In this section of the preamble, the EPA provides a description of 
the components of CCS and evaluates it against the criteria to qualify 
as the BSER. CCS has three major components: CO2 capture, 
transportation, and sequestration/storage. Post-combustion capture 
processes remove CO2 from the exhaust gas of a combustion 
system, such as a combustion turbine or a utility boiler. This 
technology is referred to as ``post-combustion capture'' because 
CO2 is a product of the combustion of the primary fuel and 
the capture takes place after the combustion of that fuel. The exhaust 
gases from most combustion processes are at atmospheric pressure and 
are moved through the flue gas duct system by fans. The concentration 
of CO2 in most fossil fuel combustion flue gas streams is 
somewhat dilute. Most post-combustion capture systems utilize liquid 
solvents--most commonly amine-based solvents--that separate the 
CO2 from the flue gas in CO2 scrubber systems 
using chemical absorption (or chemisorption). In a chemisorption-based 
separation process, the flue gas is processed through the 
CO2 scrubber and the CO2 is absorbed by the 
liquid solvent. The CO2-rich solvent is then regenerated by 
heating the solvent to release the captured CO2.
    Another technology, oxy-combustion, uses a purified oxygen stream 
from an air separation unit (often diluted with recycled CO2 
to control the flame temperature) to combust the fuel and produce a 
higher concentration of CO2 in the flue gas, as opposed to 
combustion with oxygen in air which contains 80 percent nitrogen. The 
high purity CO2 is then compressed and transported, 
generally through pipelines, to a site for geologic sequestration 
(i.e., the long-term containment of CO2 in subsurface 
geologic formations). These sequestration sites are widely available 
across the nation, and the EPA has developed a comprehensive regulatory 
structure to oversee geological sequestration projects and assure their 
safety and effectiveness. See 80 FR 64549 (October 23, 2015).
(A) Adequately Demonstrated
    For new base load combustion turbines, the EPA proposes that CCS 
with a 90 percent capture rate, beginning in 2035, meets the BSER 
criteria. This amount of CCS is feasible and has been adequately 
demonstrated. The use of CCS at this level can be implemented at 
reasonable cost because it allows affected sources to maximize the 
benefits of the IRC section 45Q tax credit, and sources can maintain it 
over time by capturing a higher percentage at certain times in order to 
offset a lower capture rate at other times due to, for example, the 
need to undertake maintenance or due to unplanned capture system 
outages. Higher capture rates may be possible--the 2022 NETL Baseline 
report evaluated capture rates at 90 and 95 percent with marginal 
differences in cost. The Agency is soliciting comment on the range of 
the capture rate of CO2 at the stack from 90 to 95 percent 
or greater. The EPA also notes that the operating availability (the 
fraction of time CCS equipment is operational relative to the operation 
of the combustion turbine) may be less than 100 percent and is 
therefore soliciting comment on a range in emission reduction from 75 
to 90 percent, as further discussed in section VII.G.2 of this 
preamble.
    The EPA previously determined ``partial CCS'' to be a component of 
the BSER (in combination with the use of a highly efficient 
supercritical utility boiler) for new coal-fired steam generating units 
as part of the 2015 NSPS (80 FR 64538; October 23, 2015).\239\ As 
described in that action, reiterated in this section of the preamble, 
and detailed further in accompanying TSDs available in the docket for 
this rulemaking, numerous projects demonstrate the feasibility and 
effectiveness of CCS technology.
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    \239\ In the present action, the EPA is not re-opening any 
aspect of the CCS determinations in the 2015 NSPS.
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    In the 2015 NSPS, the EPA considered coal-fired industrial projects 
that had installed at least some components of CCS technology. In doing 
so, the EPA recognized that some of those projects had received 
assistance in the form of grants, loan guarantees, and Federal tax 
credits for investment in ``clean coal technology,'' under provisions 
of the

[[Page 33291]]

Energy Policy Act of 2005 (``EPAct05''). See 80 FR 64541-42 (October 
23, 2015). (The EPA refers to projects that received assistance under 
that legislation as ``EPAct05-assisted projects.'') The EPA further 
recognized that the EPAct05 included provisions that constrained how 
the EPA could rely on EPAct05-assisted projects in determining whether 
technology is adequately demonstrated for the purposes of CAA section 
111.\240\ The EPA went on to provide a legal interpretation of those 
constraints. Under that legal interpretation, ``these provisions [in 
the EPAct05] . . . preclude the EPA from relying solely on the 
experience of facilities that received [EPAct05] assistance, but [do] 
not . . . preclude the EPA from relying on the experience of such 
facilities in conjunction with other information.'' \241\ Id. at 64541-
42. In the present action, the EPA is applying the same legal 
interpretation and is not reopening it for comment.
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    \240\ The relevant EPAct05 provisions include the following: 
Section 402(i) of the EPAct05, codified at 42 U.S.C. 15962(a), 
provides as follows:
    ``No technology, or level of emission reduction, solely by 
reason of the use of the technology, or the achievement of the 
emission reduction, by 1 or more facilities receiving assistance 
under this Act, shall be considered to be adequately demonstrated [ 
] for purposes of section 111 of the Clean Air Act . . . .''
    IRC section 48A(g), as added by EPAct05 1307(b), provides as 
follows:
    ``No use of technology (or level of emission reduction solely by 
reason of the use of the technology), and no achievement of any 
emission reduction by the demonstration of any technology or 
performance level, by or at one or more facilities with respect to 
which a credit is allowed under this section, shall be considered to 
indicate that the technology or performance level is adequately 
demonstrated [ ] for purposes of section 111 of the Clean Air Act . 
. . .''
    Section 421(a) states:
    ``No technology, or level of emission reduction, shall be 
treated as adequately demonstrated for purpose [sic] of section 7411 
of this title, . . . solely by reason of the use of such technology, 
or the achievement of such emission reduction, by one or more 
facilities receiving assistance under section 13572(a)(1) of this 
title.''
    \241\ In the 2015 NSPS, the EPA adopted several other legal 
interpretations of these EPAct05 provisions as well, which it is not 
reopening in this rule. See 80 FR 64541 (October 23, 2015).
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(1) CO2 Capture Technology
    The EPA is proposing that the CO2 capture component of 
CCS has been adequately demonstrated and is technically feasible based 
on the demonstration of the technology at existing coal-fired steam 
generating units and industrial sources in addition to combustion 
turbines. While the EPA would propose that the CO2 capture 
component of CCS is adequately demonstrated on those bases alone, this 
determination is further corroborated by EPAct05-assisted projects.
    Various technologies may be used to capture CO2, the 
details of which are described in the GHG Mitigation Measures for Steam 
Generating Units TSD, which is available in the rulemaking docket.\242\ 
For post-combustion capture, these technologies include solvent-based 
methods (e.g., amines, chilled ammonia), solid sorbent-based methods, 
membrane filtration, pressure-swing adsorption, and cryogenic 
methods.\243\ Lastly, as noted above, oxy-combustion uses a purified 
oxygen stream from an air separation unit (often diluted with recycled 
CO2 to control the flame temperature) to combust the fuel 
and produce a higher concentration of CO2 in the flue gas, 
as opposed to combustion with oxygen in air which contains 80 percent 
nitrogen. The CO2 can then be separated by the 
aforementioned CO2 capture methods. Of the available capture 
technologies, solvent-based processes have been the most widely 
demonstrated at commercial scale for post-combustion capture and are 
applicable to use with either combustion turbines or steam generating 
units.
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    \242\ Technologies to capture CO2 are also discussed 
in the GHG Mitigation Measures--Carbon Capture and Storage for 
Combustion Turbines TSD.
    \243\ For pre-combustion capture (as is applicable to an IGCC 
unit), syngas produced by gasification passes through a water-gas 
shift catalyst to produce a gas stream with a higher concentration 
of hydrogen and CO2. The higher CO2 
concentration relative to conventional combustion flue gas reduces 
the demands (power, heating, and cooling) of the subsequent 
CO2 capture process (e.g., solid sorbent-based or 
solvent-based capture), the treated hydrogen can then be combusted 
in the unit.
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    Solvent-based capture processes usually use an amine (e.g., 
monoethanolamine, MEA). Carbon capture occurs by reactive absorption of 
the CO2 from the flue gas into the amine solution in an 
absorption column. The amine reacts with the CO2 but will 
also react with potential contaminants in the flue gas, including 
SO2. After absorption, the CO2-rich amine 
solution passes to the solvent regeneration column, while the treated 
gas passes through a water and/or acid wash column to limit emission of 
amines or other byproducts. In the solvent regeneration column, the 
solution is heated (using steam) to release the absorbed 
CO2. The released CO2 is then compressed and 
transported offsite, usually by pipeline. The amine solution from the 
regenerating column is cooled and sent back to the absorption column, 
and any spent solvent is replenished with new solvent.
(2) Capture Demonstrations at Coal-Fired Steam Generating Units and 
Industrial Processes
    The function, design, and operation of post-combustion 
CO2 capture equipment is similar, although not identical, 
for both steam generating units and combustion turbines. As a result, 
application of CO2 capture at existing coal-fired steam 
generating units helps demonstrate the adequacy of the CO2 
capture component of CCS.
    SaskPower's Boundary Dam Unit 3, a 110 MW lignite-fired unit in 
Saskatchewan, Canada, has demonstrated CO2 capture rates of 
90 percent using an amine-based post-combustion capture system 
retrofitted to the existing steam generating unit. The capture plant, 
which began operation in 2014, was the first full-scale CO2 
capture system retrofit on an existing coal-fired power plant. It uses 
the amine-based Shell CANSOLV process, with integrated heat and power 
from the steam generating unit.\244\ While successfully demonstrating 
the commercial-scale feasibility of 90 percent capture rates, the plant 
has also provided valuable lessons learned for the next generation of 
capture plants. A feasibility study for SaskPower's Shand Power Station 
indicated achievable capture rates of 97 percent, even at lower 
loads.\245\
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    \244\ Giannaris, S., et al. Proceedings of the 15th 
International Conference on Greenhouse Gas Control Technologies 
(March 15-18, 2021). SaskPower's Boundary Dam Unit 3 Carbon Capture 
Facility--The Journey to Achieving Reliability. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191.
    \245\ International CCS Knowledge Centre. The Shand CCS 
Feasibility Study Public Report. https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
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    For all industrial processes, operational availability (the percent 
of time a unit operates relative to its planned operation) is usually 
less than 100 percent due to unplanned maintenance and other factors. 
As a first-of-a-kind commercial-scale project, Boundary Dam Unit 3 
experienced some additional challenges with availability during its 
initial years of operation, due to the fouling of heat exchangers and 
issues with its CO2 compressor.\246\ However, identifying 
and correcting those problems has improved the operational availability 
of the capture system. The facility has reported greater than 90 
percent capture system

[[Page 33292]]

availability in the second and third quarters of 2022.\247\ Currently, 
newly constructed and retrofit CO2 capture systems are 
anticipated to have operational availability of around 90 percent, on 
the same order of that is expected at coal-fired steam generating 
units. The EPA is soliciting comment on information relevant to the 
expected operational availability of new and retrofit CO2 
capture systems.
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    \246\ S&P Global Market Intelligence (January 6, 2022). Only 
still-operating carbon capture project battled technical issues in 
2021. https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/only-still-operating-carbon-capture-project-battled-technical-issues-in-2021-68302671.
    \247\ SaskPower (October 18, 2022). BD3 Status Update: Q3 2022. 
https://www.saskpower.com/about-us/our-company/blog/2022/bd3-status-update-q3-2022.
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    Several other projects have successfully demonstrated the capture 
component of CCS at electricity generating plants and other industrial 
facilities, some of which were previously noted in the discussion in 
the 2015 NSPS (80 FR 64548-54; October 23, 2015). Amine-based carbon 
capture has been demonstrated at AES's Warrior Run (Cumberland, 
Maryland) and Shady Point (Panama, Oklahoma) coal-fired power plants, 
with the captured CO2 being sold for use in the food 
processing industry.\248\ At the 180-MW Warrior Run plant, 
approximately 10 percent of the plant's CO2 emissions (about 
110,000 metric tons of CO2 per year) has been captured since 
2000 and sold to the food and beverage industry. AES's 320-MW coal-
fired Shady Point plant captured CO2 from an approximate 5 
percent slipstream (about 66,000 metric tons of CO2 per 
year) from 2001 through around 2019.\249\ These facilities, which have 
operated for multiple years, clearly show the technical feasibility of 
post-combustion carbon capture.
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    \248\ 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.
    \249\ Shady Point Plant (River Valley) was sold to Oklahoma Gas 
and Electric in 2019. https://www.oklahoman.com/story/business/columns/2019/05/23/oklahoma-gas-and-electric-acquires-aes-shady-point-after-federal-approval/60454346007/.
---------------------------------------------------------------------------

    The capture component of CCS has also been demonstrated at other 
industrial processes. Since 1978, the Searles Valley Minerals soda ash 
plant in Trona, California, has used an amine-based system to capture 
approximately 270,000 metric tons of CO2 per year from the 
flue gas of a coal-fired industrial power plant that generates steam 
and power for onsite use. The captured CO2 is used for the 
carbonation of brine in the process of producing soda ash.\250\
---------------------------------------------------------------------------

    \250\ IEA (2009), World Energy Outlook 2009, OECD/IEA, Paris.
---------------------------------------------------------------------------

    The Quest CO2 capture facility in Alberta, Canada, uses 
amine-based CO2 capture retrofitted to three existing steam 
methane reformers at the Scotford Upgrader facility (operated by Shell 
Canada Energy) to capture and sequester approximately 80 percent of the 
CO2 in the produced syngas.\251\ The Quest facility has been 
operating since 2015 and captures approximately 1 million metric tons 
of CO2 per year.
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    \251\ Quest Carbon Capture and Storage Project Annual Summary 
Report, Alberta Department of Energy: 2021. https://open.alberta.ca/publications/quest-carbon-capture-and-storage-project-annual-report-2021.
---------------------------------------------------------------------------

(3) Capture Demonstrations at Combustion Turbines
    While most demonstrations of CCS have been for applications other 
than combustion turbines, CCS has been successfully applied to an 
existing combined cycle EGU and several other projects are in 
development, as discussed immediately below. Currently available post-
combustion amine-based carbon capture systems require that the flue gas 
be cooled prior to entering the carbon capture equipment. This holds 
true for the exhaust from a combustion turbine. The most energy 
efficient way to do this is to use a HSRG--which, as explained above, 
is an integral component of a combined cycle turbine system--to 
generate additional useful output. Because simple cycle combustion 
turbines do not incorporate a HRSG, the Agency is not considering the 
use of CCS as a potential component of the BSER for them.
(a) CCS on Combined Cycle EGUs
    Examples of the use of CCS on combined cycle EGUs include the 
Bellingham Energy Center in south central Massachusetts and the 
proposed Peterhead Power Station in Scotland. The Bellingham plant used 
Fluor's Econamine FG Plus\SM\ capture system and demonstrated the 
commercial viability of carbon capture on a combined cycle combustion 
turbine EGU using first-generation technology. The 40-MW slipstream 
capture facility operated from 1991 to 2005 and captured 85 to 95 
percent of the CO2 in the slipstream for use in the food 
industry.\252\ In Scotland, the proposed 900-MW Peterhead Power Station 
combined cycle EGU with CCS is in the planning stages of development. 
It is anticipated that the power plant will be operational by the end 
of the 2020s and will have the potential to capture 90 percent of the 
CO2 emitting from the combined cycle facility and sequester 
up to 1.5 million metric tons of CO2 annually. A storage 
site being developed 62 miles off the Scottish North Sea coast might 
serve as a destination for the captured CO2.\253\ Moreover, 
an 1,800-MW NGCC 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 feasibility was partially credited 
to the expanded IRC section 45Q tax credit for sequestered 
CO2 provided through the IRA.\254\
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    \252\ U.S. Department of Energy (DOE). Carbon Capture 
Opportunities for Natural Gas Fired Power Systems. https://www.energy.gov/fecm/articles/carbon-capture-opportunities-natural-gas-fired-power-systems.
    \253\ Buli, N. (2021, May 10). SSE, Equinor plan new gas power 
plant with carbon capture in Scotland. Reuters. https://www.reuters.com/business/sustainable-business/sse-equinor-plan-new-gas-power-plant-with-carbon-capture-scotland-2021-05-11/.
    \254\ Competitive Power Ventures (2022). Multi-Billion Dollar 
Combined Cycle Natural Gas Power Station with Carbon Capture 
Announced in West Virginia. Press Release. September 16, 2022. 
https://www.cpv.com/2022/09/16/multi-billion-dollar-combinedcycle-natural-gas-power-station-with-carbon-capture-announced-in-west-virginia/.
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(b) Net Power Cycle
    In addition, there are several planned projects using the NET Power 
Cycle.\255\ The NET Power Cycle is a proprietary process for producing 
electricity that combusts a fuel with purified oxygen and uses 
supercritical CO2 as the working fluid instead of water/
steam. This cycle is designed to achieve thermal efficiencies of up to 
59 percent.\256\ Potential advantages of this cycle are that it emits 
no NOX and produces a stream of high-purity CO2 
\257\ that can be delivered by pipeline to a storage or sequestration 
site without extensive processing. A 50-MW (thermal) test facility in 
La Porte, Texas was completed in 2018 and was synchronized to the grid 
in 2021. There are several announced commercial projects proposing to 
use the NET Power Cycle. These include the 280-MW Broadwing Clean 
Energy Complex in Illinois, and several international projects.
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    \255\ https://netpower.com/technology/. The Net Power Cycle was 
formerly referred to as the Allam-Fetvedt cycle.
    \256\ Yellen, D. (2020, May 25). Allam Cycle carbon capture gas 
plants: 11 percent more efficient, all CO2 captured. 
Energy Post. https://energypost.eu/allam-cycle-carbon-capture-gas-plants-11-more-efficient-all-co2-captured/.
    \257\ This allows for capture of over 97 percent of the 
CO2 emissions. www.netpower.com.
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(4) EPAct05-Assisted CO2 Capture Projects
    While the EPA is proposing that the capture component of CCS is 
adequately demonstrated based solely on the other demonstrations of 
CO2 capture discussed in this preamble, adequate 
demonstration of CO2 capture technology is further 
corroborated by

[[Page 33293]]

CO2 capture projects assisted by grants, loan guarantees, 
and Federal tax credits for ``clean coal technology'' authorized by the 
EPAct05. 80 FR 64541-42 (October 23, 2015).
(a) EPAct05-Assisted CO2 Capture Projects at Coal-Fired 
Steam Generating Units
    Petra Nova is a 240 MW-equivalent capture facility that is the 
first at-scale application of carbon capture at a coal-fired power 
plant in the U.S. The system is located at the W.A. Parish Generating 
Station in Thompsons, Texas, and began operation in 2017, successfully 
capturing and sequestering CO2 for several years. Although 
the system was put into reserve shutdown (i.e., idled) in May 2020, 
citing the poor economics of utilizing captured CO2 for 
enhanced oil recovery (EOR) at that time, there are reports of plans to 
restart the capture system.\258\ A final report from National Energy 
Technology (NETL) details the success of the project and what was 
learned from this first-of-a-kind demonstration at scale.\259\ The 
project used Mitsubishi Heavy Industry's proprietary KM-CDR 
Process[supreg], a process that is similar to an amine-based solvent 
process but that uses a proprietary solvent and is optimized for 
CO2 capture from a coal-fired generator's flue gas. During 
its operation, the project successfully captured 92.4 percent of the 
CO2 from the slip stream of flue gas processed with 99.08 
percent of the captured CO2 sequestered by EOR. Plant Barry 
in Mobile, Alabama, began using the KM-CDR Process[supreg] in 2011 for 
a fully integrated 25-MW CCS project with a capture rate of 90 
percent.\260\ The CCS project at Plant Barry captured approximately 
165,000 tons of CO2 annually, which is then transported via 
pipeline and sequestered underground in geologic formations. See 80 FR 
64552 (October 23, 2015).
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    \258\ ``The World's Largest Carbon Capture Plant Gets a Second 
Chance in Texas'' Bloomberg News, February 8, 2023. https://www.bloomberg.com/news/articles/2023-02-08/the-world-s-largest-carbon-capture-plant-gets-a-second-chance-in-texas?leadSource=uverify%20wall.
    \259\ W.A. Parish Post-Combustion CO2 Capture and 
Sequestration Demonstration Project, Final Scientific/Technical 
Report (March 2020). https://www.osti.gov/servlets/purl/1608572.
    \260\ U.S. Department of Energy (DOE). National Energy 
Technology Laboratory (NETL). https://www.netl.doe.gov/node/1741.
---------------------------------------------------------------------------

(b) EPAct05-Assisted CO2 Capture Projects at Stationary 
Combustion Turbines
    There are several EPAct05-assisted projects related to NGCC units 
including: 261 262 263 264 265
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    \261\ General Electric (GE) (2022). U.S. Department of Energy 
Awards $5.7 Million for GE-Led Carbon Capture Technology Integration 
Project Targeting to Achieve 95% Reduction of Carbon Emissions. 
Press Release. February 15, 2022. https://www.ge.com/news/press-releases/us-department-of-energy-awards-57-million-for-ge-led-carbon-capture-technology.
    \262\ Larson, A. (2022). GE-Led Carbon Capture Project at 
Southern Company Site Gets DOE Funding. Power. https://www.powermag.com/ge-led-carbon-capture-project-at-southern-company-site-gets-doe-funding/.
    \263\ U.S. Department of Energy (DOE) (2021). DOE Invests $45 
Million to Decarbonize the Natural Gas Power and Industrial Sectors 
Using Carbon Capture and Storage. October 6, 2021. https://www.energy.gov/articles/doe-invests-45-million-decarbonize-natural-gas-power-and-industrial-sectors-using-carbon.
    \264\ DOE (2022). Additional Selections for Funding Opportunity 
Announcement 2515. Office of Fossil Energy and Carbon Management. 
https://www.energy.gov/fecm/additional-selections-funding-opportunity-announcement-2515.
    \265\ DOE (2019). FOA 2058: Front-End Engineering Design (FEED) 
Studies for Carbon Capture Systems on Coal and Natural Gas Power 
Plants. Office of Fossil Energy and Carbon Management. https://www.energy.gov/fecm/foa-2058-front-end-engineering-design-feed-studies-carbon-capture-systems-coal-and-natural-gas.
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     General Electric (GE) (Bucks, Alabama) was awarded 
$5,771,670 to retrofit an NGCC facility with CCS technology to capture 
95 percent of CO2 and is targeting commercial deployment by 
2030.
     Wood Environmental & Infrastructure Solutions (Blue Bell, 
Pennsylvania) was awarded $4,000,000 to complete an engineering design 
study for CO2 capture at the Shell Chemicals Complex. The 
aim is to reduce CO2 emissions by 95 percent using post-
combustion technology to capture CO2 from several plants, 
including an onsite natural gas CHP plant.
     General Electric Company, GE Research (Niskayuna, New 
York) was awarded $1,499,992 to develop a design to capture 95 percent 
of CO2 from NGCC flue gas with the potential to reduce 
electricity costs by at least 15 percent.
     SRI International (Menlo Park, California) was awarded 
$1,499,759 to design, build, and test a technology that can capture at 
least 95 percent of CO2 while demonstrating a 20 percent 
cost reduction compared to existing NGCC carbon capture.
     CORMETECH, Inc. (Charlotte, North Carolina) was awarded 
$2,500,000 to further develop, optimize, and test a new, lower cost 
technology to capture CO2 from NGCC flue gas and improve 
scalability to large NGCC plants.
     TDA Research, Inc. (Wheat Ridge, Colorado) was awarded 
$2,500,000 to build and test a post-combustion capture process to 
improve the performance of NGCC flue gas CO2 capture.
     GE Gas Power (Schenectady, New York) was awarded 
$5,771,670 to perform an engineering design study to incorporate a 95 
percent CO2 capture solution for an existing NGCC site while 
providing lower costs and scalability to other sites.
     Electric Power Research Institute (EPRI) (Palo Alto, 
California) was awarded $5,842,517 to complete a study to retrofit a 
700-Mwe NGCC with a carbon capture system to capture 95 percent of 
CO2.
     Gas Technology Institute (Des Plaines, Illinois) was 
awarded $1,000,000 to develop membrane technology capable of capturing 
more than 97 percent of NGCC CO2 flue gas and demonstrate 
upwards of 40 percent reduction in costs.
     RTI International (Research Triangle Park, North Carolina) 
was awarded $1,000,000 to test a novel non-aqueous solvent technology 
aimed at demonstrating 97 percent capture efficiency from simulated 
NGCC flue gas.
     Tampa Electric Company (Tampa, Florida) was awarded 
$5,588,173 to conduct a study retrofitting Polk Power Station with 
post-combustion CO2 capture technology aiming to achieve a 
95 percent capture rate.
    There are also several announced NET Power Cycle based 
CO2 capture projects that are EPAct05-assisted. These 
include the 280-MW Coyote Clean Power Project on the Southern Ute 
Indian Reservation in Colorado and a 300-MW project located near 
Occidental's Permian Basin operations close to Odessa, Texas. 
Commercial operation of the facility near Odessa, Texas is expected in 
2026.
(5) CO2 Transport
(a) Demonstration of CO2 Transport
    The majority of CO2 transported in the U.S. is 
transported through pipelines. Pipeline transport of CO2 has 
been occurring for nearly 60 years, and over this time, the design, 
construction, and operational requirements for CO2 pipelines 
have been demonstrated.\266\ Moreover, the U.S. CO2 pipeline 
network has steadily expanded, and appears primed to continue to do so. 
The Pipeline and Hazardous Materials

[[Page 33294]]

Safety Administration (PHMSA) reported that 5,339 miles of 
CO2 pipelines were in operation in 2021, a 13 percent 
increase in CO2 pipeline miles since 2011.\267\ Moreover, 
several major projects have recently been announced to expand the 
CO2 pipeline network across the U.S. For example, the 
Midwest Carbon Express has proposed to add more than 2,000 miles of 
dedicated CO2 pipeline in Iowa, Nebraska, North Dakota, 
South Dakota, and Minnesota. The Midwest Carbon Express is projected to 
begin operations in 2024.\268\ Another example is the Heartland 
Greenway project, which has proposed to add more than 1,300 miles of 
dedicated CO2 pipeline in Iowa, Nebraska, South Dakota, 
Minnesota, and Illinois. The Heartland Greenway project is projected to 
start its initial system commissioning in the second quarter of 
2025.\269\ The proximity to existing or planned CO2 
pipelines and geologic sequestration sites can be a factor to consider 
in the construction of stationary combustion turbines, and pipeline 
expansion, when needed, has been proven to be 
feasible.270 271 The IIJA also included substantial support 
for CO2 transportation infrastructure.
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    \266\ For additional information on CO2 
transportation infrastructure project timelines, costs and other 
details, please see the GHG Mitigation Measures for Steam Generating 
Units TSD.
    \267\ U.S. Department of Transportation, Pipeline and Hazardous 
Material Safety Administration, ``Hazardous Annual Liquid Data.'' 
2021. https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
    \268\ Beach, Jeff. ``World's Largest Carbon Capture Pipeline 
Aims to Connect 31 Ethanol Plants, Cut across Upper Midwest.'' 
Agweek, December 6, 2021. https://www.agweek.com/business/worlds-largest-carbon-capture-pipeline-aims-to-connect-31-ethanol-plants-cut-across-upper-midwest.
    \269\ Navigator CO2, ``NavCO2 Fact 
Sheet.'' 2022. https://d3o151.p3cdn1.secureserver.net/wp-content/uploads/2022/08/HG-Fact-Sheet-vFINAL.pdf.
    \270\ For additional information regarding planned or announced 
pipelines please see section 4.6.1.2 of the GHG Mitigation Measures 
for Steam Generating Units TSD.
    \271\ U.S. Department of Transportation, Pipeline and Hazardous 
Material Safety Administration, ``Hazardous Annual Liquid Data.'' 
2021. https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
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(b) Security of CO2 Transport
    The safety of existing and new CO2 pipelines that 
transport CO2 in a supercritical state is exclusively 
regulated by PHMSA. These regulations include standards related to 
pipeline design, construction, and testing, operations and maintenance, 
operator reporting requirements, operator qualifications, corrosion 
control and pipeline integrity management, incident reporting and 
response, and public awareness and communications. PHMSA has regulatory 
authority to conduct inspections of supercritical CO2 
pipeline operations and issue notices to operators in the event of 
operator noncompliance with regulatory requirements.\272\ Furthermore, 
PHMSA initiated a rulemaking in 2022 to develop and implement new 
measures to strengthen its safety oversight of supercritical 
CO2 pipelines following investigation into a CO2 
pipeline failure in Satartia, Mississippi in 2020.\273\ Following that 
incident, PHMSA also issued a Notice of Probable Violation, Proposed 
Civil Penalty, and Proposed Compliance Order (Notice) to the operator 
related to probable violations of Federal pipeline safety regulations. 
The Notice was ultimately resolved through a Consent Agreement between 
PHMSA and the operator that includes the assessment of civil penalties 
and identifies actions for the operator to take to address the alleged 
violations and risk conditions.\274\ PHMSA has further issued an 
updated nationwide advisory bulletin to all pipeline operators, and 
solicited research proposals to strengthen CO2 pipeline 
safety.\275\ Additionally, certain States have authority delegated from 
the U.S. Department of Transportation to conduct safety inspections and 
enforce State and Federal pipeline safety regulations for intrastate 
CO2 pipelines.276 277 These CO2 
pipeline controls, in addition to the PHMSA standards, ensure that 
captured CO2 will be securely conveyed to a sequestration 
site.
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    \272\ See generally 49 CFR 190-199.
    \273\ PHMSA, ``PHMSA Announces New Safety Measures to Protect 
Americans From Carbon Dioxide Pipeline Failures After Satartia, MS 
Leak.'' 2022. https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americans-carbon-dioxide-pipeline-failures.
    \274\ Consent Order, Denbury Gulf Coast Pipelines, LLC, CPF No. 
4-2022-017-NOPV (U.S. Dep't of Transp. Mar. 24, 2023). https://primis.phmsa.dot.gov/comm/reports/enforce/CaseDetail_cpf_42022017NOPV.html?nocache=7208.
    \275\ Ibid.
    \276\ New Mexico Public Regulation Commission. 2023. 
Transportation Pipeline Safety. New Mexico Public Regulation 
Commission, Bureau of Pipeline Safety. https://www.nm-prc.org/transportation/pipeline-safety.
    \277\ Texas Railroad Commission. 2023. Oversight & Safety 
Division. Texas Railroad Commission. https://www.rrc.texas.gov/about-us/organization-and-activities/rrc-divisions/oversight-safety-division.
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    States are also directly involved in siting proposed CO2 
pipeline projects. CO2 pipeline siting authorities, 
landowner rights, and eminent domain laws reside with the States and 
vary from State to State. Pipeline developers may secure rights-of-way 
for proposed projects through voluntary agreements with landowners; 
pipeline developers may also secure rights-of-way through eminent 
domain authority, which typically accompanies siting permits from State 
utility regulators with jurisdiction over CO2 pipeline 
siting.\278\
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    \278\ Congressional Research Service. 2022. Carbon Dioxide 
Pipelines: Safety Issues, June 3, 2022. https://crsreports.congress.gov/product/pdf/IN/IN11944.
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    Transportation of CO2 via pipeline is the most viable 
and cost-effective method at the scale needed for sequestration of 
captured EGU CO2 emissions. However, CO2 can also 
be liquified and transported via vessel (e.g., ship), highway (e.g., 
cargo tank, portable tank), ship, or rail (e.g., tank cars) when 
pipelines are not available. Liquefied natural gas and liquefied 
petroleum gases are already routinely transported via ship at a large 
scale, and the properties of liquified CO2 are not 
significantly different.\279\ In fact, the food and beverage as well as 
specialty gas industries already have experience transporting 
CO2 by rail.\280\ Highway road tankers and rail 
transportation can provide for the transport of smaller quantities of 
CO2 and can be used in tandem with other modes of 
transportation to move CO2 captured from an EGU.\281\
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    \279\ Intergovernmental Panel on Climate Change. (2005). Special 
Report on Carbon Dioxide Capture and Storage.
    \280\ EU CCUS Projects Network. (2019). Briefing on Carbon 
Dioxide Specifications for Transport. https://www.ccusnetwork.eu/sites/default/files/TG3_Briefing-CO2-Specifications-for-Transport.pdf.
    \281\ Ibid.
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(6) Geologic Sequestration of CO2
(a) Security of Sequestration
    Geologic sequestration (or storage), which is the long-term 
containment of a CO2 stream in subsurface geologic 
formations, is well proven and broadly available in many locations 
across the U.S. Independent analyses of the potential availability of 
geologic sequestration capacity in the United States have been 
conducted by DOE, and the U.S. Geological Survey (USGS) has also 
undertaken a comprehensive assessment of geologic sequestration 
resources in the U.S.282 283 Geologic sequestration is based 
on a demonstrated understanding of the trapping processes that retain 
CO2 in the subsurface; most importantly, geologic 
sequestration occurs securely when the CO2 is trapped under 
a low permeability

[[Page 33295]]

seal. There have been numerous efforts demonstrating successful 
geologic sequestration projects in the U.S. and overseas, and the U.S. 
has developed a detailed set of regulatory requirements to ensure the 
security of sequestered CO2.
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    \282\ U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition, 
September 2015. https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
    \283\ U.S. Geological Survey Geologic Carbon Dioxide Storage 
Resources Assessment Team, 2013, National assessment of geologic 
carbon dioxide storage resources--Summary: U.S. Geological Survey 
Factsheet 2013-3020. http://pubs.usgs.gov/fs/2013/3020/.
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(i) Demonstration of Geologic Sequestration
    Existing project and regulatory experience, along with other 
information, indicate that geologic sequestration is a viable long-term 
CO2 sequestration option. The effectiveness of long-term 
trapping of CO2 has been demonstrated by natural analogues 
in a range of geologic settings where CO2 has remained 
trapped for millions of years.\284\ For example, CO2 has 
been trapped for more than 65 million years in the Jackson Dome, 
located near Jackson, Mississippi.\285\ Other examples of natural 
CO2 sources include the Bravo Dome and the McElmo Dome in 
New Mexico and Colorado, respectively.\286\ These naturally occurring 
sequestration sites demonstrate the feasibility of containing the large 
volumes of CO2 that may be captured from fossil fuel-fired 
EGUs, as these sites have held volumes of CO2 that are much 
larger than the volume of CO2 expected to be captured from a 
fossil fuel-fired EGU over the course of its useful life. In 2010, the 
DOE estimated CO2 reserves of 594 million metric tons at 
Jackson Dome, 424 million metric tons at Bravo Dome, and 530 million 
metric tons at McElmo Dome.\287\ Between 2000 and 2020, the Department 
of Energy-sponsored research totaling $1 billion to prove carbon 
storage technologies and enable large-scale deployment. Research 
conducted through the Department of Energy's Regional Carbon 
Sequestration Partnerships has demonstrated geologic sequestration 
through a series of field research projects that increased in scale 
over time, injecting more than 11 million tons of CO2 with 
no indications of negative impacts to either human health or the 
environment.\288\ Building on this experience, the Department of Energy 
launched the Carbon Storage Assurance Facility Enterprise (CarbonSAFE) 
Initiative in 2016 to demonstrate how knowledge from the Regional 
Carbon Sequestration Partnerships can be applied to commercial-scale 
safe storage. This initiative is furthering the development and 
refinement of technologies and techniques critical to the 
characterization of potential sequestration sites greater than 50 
million tons.\289\
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    \284\ Holloway, S., et al. Natural Emissions of CO2 
from the Geosphere and their Bearing on the Geological Storage of 
Carbon Dioxide. 2007. Energy 32: 1194-1201.
    \285\ Intergovernmental Panel on Climate Change. (2005). Special 
Report on Carbon Dioxide Capture and Storage.
    \286\ See K.J. Sathaye, M.A. Hesse, M. Cassidy, D.F. Stockli, 
``Constraints on the magnitude and rate of CO2 
dissolution at Bravo Dome natural gas field.'' Proceedings of the 
National Academy of Sciences 111, 15332-15337. 2014. and Kinder 
Morgan. ``Carbon Dioxide (CO2) Operations; CO2 
Supply.'' https://www.kindermorgan.com/Operations/CO2/Index.
    \287\ DiPietro, P., et al. 2012. ``A Note on Sources of 
CO2 Supply for Enhanced-Oil Recovery Operations.'' SPE 
Economics & Management.
    \288\ Safe Geologic Storage of Captured Carbon Dioxide--DOE's 
Carbon Storage R&D Program: Two Decades in Review,'' National Energy 
Technology Laboratory, Pittsburgh, April 13, 2020. https://www.netl.doe.gov/sites/default/files/Safe%20Geologic%20Storage%20of%20Captured%20Carbon%20Dioxide_April%2015%202020_FINAL.pdf.
    \289\ https://netl.doe.gov/carbon-management/carbon-storage/carbonsafe.
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    Numerous additional saline facilities are under development across 
the United States. The Great Plains Synfuel Plant currently captures 2 
million metric tons of CO2 per year, which is used for 
enhanced oil recovery (EOR); a planned addition of saline sequestration 
for this facility is expected to increase the amount captured and 
sequestered (through both geologic sequestration and EOR) to 3.5 
million metric tons of CO2 per year.\290\ The EPA is 
currently reviewing Underground Injection Control (UIC) Class VI 
geologic sequestration well permit applications for proposed 
sequestration sites in at least seven States.291 292
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    \290\ Basin Electric Power Cooperative. ``Great Plains Synfuels 
Plant Potential to Be Largest Coal-Based Carbon Capture and Storage 
Project to Use Geologic Storage,'' September 9, 2021. https://www.basinelectric.com/News-Center/news-releases/Great-Plains-Synfuels-Plant-potential-to-be-largest-coal-based-carbon-capture-and-storage-project-to-use-geologic-storage.
    \291\ UIC regulations for Class VI wells facilitate the 
injection of CO2 for geologic sequestration while 
protecting human health and the environment by ensuring the 
protection of underground sources of drinking water. The major 
components to be included in UIC Class VI permits are detailed 
further in section VII.F.3.b.iii.
    \292\ U.S. EPA Class VI Underground Injection Control (UIC) 
Class VI Wells Permitted by EPA as of January 12, 2023. https://www.epa.gov/uic/class-vi-wells-permitted-epa.
---------------------------------------------------------------------------

    Geologic sequestration has been proven to be successful and safe in 
projects internationally. The oldest international facility has 
geologically sequestered CO2 for over twenty years. In 
Norway, facilities conduct offshore sequestration under the Norwegian 
continental shelf.\293\ In addition, the Sleipner CO2 
Storage facility in the North Sea, which began operations in 1996, 
injects around 1 million metric tons of CO2 per year from 
natural gas processing.\294\ The Snohvit CO2 Storage 
facility in the Barents Sea, which began operations in 2008, injects 
around 0.7 million metric tons of CO2 per year from natural 
gas processing. The SaskPower carbon capture and storage facility at 
Boundary Dam Power Station in Saskatchewan, Canada had, as of mid-2022, 
captured 4.6 million tons of CO2 since it began operating in 
2014.\295\ Other international sequestration facilities in operation 
include Glacier Gas Plant MCCS (Canada),\296\ Quest (Canada), and Qatar 
LNG CCS (Qatar).
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    \293\ Intergovernmental Panel on Climate Change. (2005). Special 
Report on Carbon Dioxide Capture and Storage.
    \294\ Zapantis, Alex, Noora Al Amer, Ian Havercroft, Ruth Ivory-
Moore, Matt Steyn, Xiaoliang Yang, Ruth Gebremedhin, et al. ``Global 
Status of CCS 2022.'' Global CCS Institute, 2022. https://status22.globalccsinstitute.com/2022-status-report/introduction/.
    \295\ Boundary Dam Carbon Capture Project. https://www.saskpower.com/Our-Power-Future/Infrastructure-Projects/Carbon-Capture-and-Storage/Boundary-Dam-Carbon-Capture-Project.
    \296\ Zapantis, Alex, Noora Al Amer, Ian Havercroft, Ruth Ivory-
Moore, Matt Steyn, Xiaoliang Yang, Ruth Gebremedhin, et al. ``Global 
Status of CCS 2022.'' Global CCS Institute, 2022. https://status22.globalccsinstitute.com.
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(ii) EPAct05-Assisted Geologic Sequestration Projects
    While the EPA is proposing that the sequestration component of CCS 
is adequately demonstrated based solely on the other demonstrations of 
geologic sequestration discussed in this preamble, adequate 
demonstration of geologic sequestration is further corroborated by 
geologic sequestration currently operational and planned projects 
assisted by grants, loan guarantees, and Federal tax credits for 
``clean coal technology'' authorized by the EPAct05. 80 FR 64541-42 
(October 23, 2015).
    Two saline sequestration facilities are currently in operation in 
the U.S. and several are under development.\297\ The Illinois 
Industrial Carbon Capture and Storage Project began injecting 
CO2 from ethanol production into the Mount Simon Sandstone 
in April 2017. The project has the potential to store up to 5.5 million 
metric tons of CO2,\298\ and, according to the facility's 
report to the EPA's GHGRP, as of 2021, 2.5 million metric tons of 
CO2 had been injected

[[Page 33296]]

into the saline reservoir.\299\ The Red Trail Energy CCS facility in 
North Dakota, which is the first saline sequestration facility in the 
U.S. to operate under a State-led regulatory authority for carbon 
storage, began injecting CO2 from ethanol production in 
2022.\300\ This project is expected to inject a total of 3.7 million 
tons of CO2 over its lifetime.\301\
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    \297\ Zapantis, Alex, Noora Al Amer, Ian Havercroft, Ruth Ivory-
Moore, Matt Steyn, Xiaoliang Yang, Ruth Gebremedhin, et al. ``Global 
Status of CCS 2022.'' Global CCS Institute, 2022. https://status22.globalccsinstitute.com/.
    \298\ Archer Daniels Midland, Monitoring, Reporting, and 
Verification Plan CCS#2, 2017. https://www.epa.gov/sites/default/files/2017-01/documents/adm_mrv_plan.pdf.
    \299\ EPA Greenhouse Gas Reporting Program. Data reported as of 
August 12, 2022.
    \300\ Zapantis, Alex, Noora Al Amer, Ian Havercroft, Ruth Ivory-
Moore, Matt Steyn, Xiaoliang Yang, Ruth Gebremedhin, et al. ``Global 
Status of CCS 2022.'' Global CCS Institute, 2022. https://status22.globalccsinstitute.com.
    \301\ North Dakota Industrial Commission, NDIC Case No. 28848--
Draft Permit Fact Sheet and Storage Facility Permit Application.'' 
https://www.dmr.nd.gov/oilgas/GeoStorageofCO2.asp. This injection 
well is permitted by North Dakota.
---------------------------------------------------------------------------

    There are additional planned geologic sequestration facilities 
across the United States.\302\ Project Tundra, a saline sequestration 
project planned at the lignite-fired Milton R. Young Station in North 
Dakota is projected to capture 4 million metric tons of CO2 
annually.\303\ Finally, in Wyoming, Class VI permit applications have 
been filed for a proposed saline sequestration facility located in 
Southwestern Wyoming. At full capacity, the facility will permanently 
store up to 5 million metric tons of CO2 annually from 
industrial facilities in the Nugget saline sandstone reservoir.\304\
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    \302\ In addition, Denbury Resources injected CO2 
into a depleted oil and gas reservoir at a rate greater than 1.2 
million tons/year as part of a DOE Southeast Regional Carbon 
Sequestration Partnership study. The Texas Bureau of Economic 
Geology tested a wide range of surface and subsurface monitoring 
tools and approaches to document sequestration efficiency and 
sequestration permanence at the Cranfield oilfield in Mississippi. 
Texas Bureau of Economic Geology, ``Cranfield Log.'' https://www.beg.utexas.edu/gccc/research/cranfield.
    \303\ Project Tundra. ``Project Tundra.'' https://www.projecttundrand.com/.
    \304\ Wyoming DEQ Class VI Permit Applications. https://deq.wyoming.gov/water-quality/groundwater/uic/class-vi/.
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(iii) Security of Geologic Sequestration
    Regulatory oversight of geologic sequestration is built upon an 
understanding of the proven mechanisms by which CO2 is 
retained in geologic formations. These mechanisms include (1) 
Structural and stratigraphic trapping (generally trapping below a low 
permeability confining layer); (2) residual CO2 trapping 
(retention as an immobile phase trapped in the pore spaces of the 
geologic formation); (3) solubility trapping (dissolution in the in 
situ formation fluids); (4) mineral trapping (reaction with the 
minerals in the geologic formation and confining layer to produce 
carbonate minerals); and (5) preferential adsorption trapping 
(adsorption onto organic matter in coal and shale).
    Based on the understanding developed from natural analogs and 
existing projects, the security of sequestered CO2 is 
expected to increase over time after injection ceases.\305\ This is due 
to trapping mechanisms that reduce CO2 mobility over time, 
e.g., physical CO2 trapping by a low-permeability geologic 
seal or chemical trapping by conversion or adsorption.\306\ In 
addition, site characterization, site operations, and monitoring 
strategies as required through the Underground Injection Control (UIC) 
Program and the GHGRP, discussed below, work in combination to ensure 
security and transparency.
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    \305\ ``Report of the Interagency Task Force on Carbon Capture 
and Storage.'' 2010. https://www.osti.gov/servlets/purl/985209.
    \306\ See, e.g., Intergovernmental Panel on Climate Change. 
(2005). Special Report on Carbon Dioxide Capture and Storage.
---------------------------------------------------------------------------

    The UIC Program, the GHGRP and other regulatory requirements 
comprise a detailed regulatory framework for facilitating geologic 
sequestration in the U.S., according to a 2021 report from the Council 
on Environmental Quality (CEQ). This framework is already in place and 
capable of reviewing and permitting CCS activities.\307\
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    \307\ CEQ. ``Council on Environmental Quality Report to Congress 
on Carbon Capture, Utilization, and Sequestration.'' 2021. https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
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    This regulatory framework includes the UIC Class VI well 
regulations, promulgated under the authority of the Safe Drinking Water 
Act (SDWA); and the GHGRP, promulgated under the authority of the CAA. 
The requirements of the UIC and GHGRP programs work together to ensure 
that sequestered CO2 will remain securely stored 
underground. The UIC regulations facilitate the injection of 
CO2 for geologic sequestration while protecting human health 
and the environment by ensuring the protection of underground sources 
of drinking water (USDW). These regulations are built upon nearly a 
half-century of Federal experience regulating underground injection 
wells, and many additional years of State UIC program expertise. The 
IIJA established a program to assist States and Tribal regulatory 
authorities interested in Class VI primacy.\308\ As the EPA considers 
Class VI primacy applications, it has indicated that it will require 
approaches that balance the use of geologic sequestration with 
mitigation of impacts on vulnerable communities. States and Tribes 
applying for Class VI primacy are asked to support communities by 
implementing an inclusive public participation process, considering 
environmental justice impacts on communities, enforcing Class VI 
regulatory protections and incorporating other mitigation 
measures.\309\
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    \308\ On April 27, 2023, the EPA Administrator signed a proposed 
rule to approve the State of Louisiana's request to have primacy for 
UIC Class VI wells within the state. Louisiana is the third state to 
request primacy for UIC Class VI wells. https://www.epa.gov/uic/primary-enforcement-authority-underground-injection-control-program-0.
    \309\ EPA. Letter from the EPA Administrator Michael S. Regan to 
U.S. State Governors. December 9, 2022. https://www.epa.gov/system/files/documents/2022-12/AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
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    To complement the UIC regulations, the EPA included in the GHGRP 
air-side monitoring and reporting requirements for CO2 
capture, underground injection, and geologic sequestration. These 
requirements are included in 40 CFR part 98, subpart RR, also referred 
to as ``GHGRP subpart RR.''
    The GHGRP subpart RR requirements provide the monitoring mechanisms 
to identify, quantify, and address potential leakage. The EPA designed 
them to complement and build on UIC monitoring and testing 
requirements. Although the regulations for the UIC program are designed 
to ensure protection of USDWs from endangerment, the practical effect 
of these GHGRP subpart RR requirements is that they also prevent 
releases of CO2 to the atmosphere.\310\
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    \310\ In 2022, EPA proposed a new GHGRP subpart, ``Geologic 
Sequestration of Carbon Dioxide with Enhanced Oil Recovery (EOR) 
Using ISO 27916'' (or GHGRP subpart VV). For more information on 
proposed GHGRP subpart VV, see section VII.K.2 of this preamble.
---------------------------------------------------------------------------

    Major components to be included in UIC Class VI permits are site 
characterization, area of review,\311\ corrective action,\312\ well 
construction and operation, testing and monitoring, financial 
responsibility, post-injection site care, well plugging, emergency and 
remedial response, and site closure. Reporting under GHGRP subpart RR 
is required for, but not limited to, all facilities that have received 
a UIC Class VI permit for injection of CO2.\313\ GHGRP 
subpart RR requires facilities

[[Page 33297]]

meeting the source category definition (40 CFR 98.440) for any well or 
group of wells to report basic information on the mass of 
CO2 received for injection; develop and implement an EPA-
approved monitoring, reporting, and verification (MRV) plan; report the 
mass of CO2 sequestered using a mass balance approach; and 
report annual monitoring activities.314 315 316 317 Although 
deep subsurface monitoring is required for UIC Class VI wells at 40 CFR 
146.90 and is the primary means of determining if there are any leaks 
to a USDW, and is generally effective in doing so, the surface air and 
soil gas monitoring employed under a GHGRP subpart RR MRV Plan can be 
utilized in addition to subsurface monitoring required under 40 CFR 
146.90, if required by the UIC Program Director under 40 CFR 146.90(h), 
to further ensure protection of USDWs.\318\ The MRV plan includes five 
major components: a delineation of monitoring areas based on the 
CO2 plume location; an identification and evaluation of the 
potential surface leakage pathways and an assessment of the likelihood, 
magnitude, and timing, of surface leakage of CO2 through 
these pathways; a strategy for detecting and quantifying any surface 
leakage of CO2 in the event leakage occurs; an approach for 
establishing the expected baselines for monitoring CO2 
surface leakage; and, a summary of considerations made to calculate 
site-specific variables for the mass balance equation.\319\
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    \311\ Per 40 CFR 146.84(a), the area of review is the region 
surrounding the geologic sequestration project where USDWs may be 
endangered by the injection activity. The area of review is 
delineated using computational modeling that accounts for the 
physical and chemical properties of all phases of the injected 
carbon dioxide stream and is based on available site 
characterization, monitoring, and operational data.
    \312\ UIC permitting authorities may require corrective action 
for existing wells within the area of review to ensure protection of 
underground sources of drinking water.
    \313\ 40 CFR 98.440.
    \314\ 40 CFR 98.446.
    \315\ 40 CFR 98.448.
    \316\ 40 CFR 98.446(f)(9) and (10).
    \317\ 40 CFR 98.446(f)(12).
    \318\ See 75 FR 77263 (December 10, 2010).
    \319\ 40 CFR 98.448(a).
---------------------------------------------------------------------------

    Geologic sequestration efforts on Federal lands as well as those 
efforts that are directly supported with Federal funds may need to 
comply with other regulations, depending on the nature of the 
project.\320\
---------------------------------------------------------------------------

    \320\ CEQ. ``Council on Environmental Quality Report to Congress 
on Carbon Capture, Utilization, and Sequestration.'' 2021. https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
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(b) Broad Availability of Sequestration
    Geologic sequestration potential for CO2 is widespread 
and available throughout the U.S. Nearly every State in the U.S. has or 
is in close proximity to formations with geologic sequestration 
potential, including areas offshore. These areas include deep saline 
formation, unmineable coal seams, and oil and gas reservoirs. Moreover, 
the amount of storage capacity can readily accommodate the amount of 
CO2 for which sequestration could be required under this 
proposed rule.
    The DOE and the United States Geological Survey (USGS) have 
independently conducted preliminary analyses of the availability and 
potential CO2 sequestration resources in the U.S. The DOE 
estimates are compiled in the DOE's National Carbon Sequestration 
Database and Geographic Information System (NATCARB) using volumetric 
models and are published in its Carbon Utilization and Sequestration 
Atlas (NETL Atlas).\321\ The DOE estimates that areas of the U.S. with 
appropriate geology have a sequestration potential of at least 2,400 
billion to over 21,000 billion metric tons of CO2 in deep 
saline formations, unmineable coal seams, and oil and gas 
reservoirs.\322\ The USGS assessment estimates a mean of 3,000 billion 
metric tons of subsurface CO2 sequestration potential across 
the U.S.\323\
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    \321\ U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition, 
September 2015. https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
    \322\ Ibid.
    \323\ U.S. Geological Survey Geologic Carbon Dioxide Storage 
Resources Assessment Team, National assessment of geologic carbon 
dioxide storage resources--Summary: U.S. Geological Survey Factsheet 
2013-3020. 2013. https://pubs.usgs.gov/fs/2013/3020/.
---------------------------------------------------------------------------

    With respect to deep saline formations, the DOE estimates a 
sequestration potential of at least 2,200 billion metric tons of 
CO2 in these formations in the U.S. At least 37 States have 
geologic characteristics that are amenable to deep saline 
sequestration, and an additional 6 States are within 100 kilometers of 
potentially amenable deep saline formations in either onshore or 
offshore locations.324 325
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    \324\ Alaska has deep saline formation storage capacity, geology 
amenable to EOR operations, and potential geologic sequestration 
capacity in unmineable coal seams.
    \325\ The U.S. DOE NETL Carbon Storage Atlas, Fifth Edition did 
not assess deep saline formation potential for Alaska, Connecticut, 
Hawaii, Maine, Massachusetts, Nevada, New Hampshire, Rhode Island, 
and Vermont. We are assuming for purposes of our analysis here that 
they do not have storage potential in this type of formation.
---------------------------------------------------------------------------

    Unmineable coal seams offer another potential option for geologic 
sequestration of CO2. Enhanced coalbed methane recovery is 
the process of injecting and storing CO2 in unmineable coal 
seams to enhance methane recovery. These operations take advantage of 
the preferential chemical affinity of coal for CO2 relative 
to the methane that is naturally found on the surfaces of coal. When 
CO2 is injected, it is adsorbed to the coal surface and 
releases methane that can then be captured and produced. This process 
effectively ``locks'' the CO2 to the coal, where it remains 
stored. States with the potential for sequestration in unmineable coal 
seams include Iowa and Missouri, which have little to no saline 
sequestration potential and have existing coal-fired EGUs. Unmineable 
coal seams have a sequestration potential of at least 54 billion metric 
tons of CO2, or 2 percent of total potential in the U.S., 
and are located in 22 States.\326\
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    \326\ U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition, 
September 2015. https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
---------------------------------------------------------------------------

    The potential for CO2 sequestration in unmineable coal 
seams has been demonstrated in small-scale demonstration projects, 
including the Allison Unit pilot project in New Mexico, which injected 
a total of 270,000 tons of CO2 over a six-year period (1995-
2001). Further, DOE Regional Carbon Sequestration Partnership projects 
have injected CO2 volumes in unmineable coal seams ranging 
from 90 tons to 16,700 tons, and completed site characterization, 
injection, and post-injection monitoring for sites.327 328 
DOE has judged unmineable coal seams worthy of inclusion in the NETL 
Atlas.\329\
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    \327\ M. Godec et al., ``CO2-ECBM: A Review of its 
Status and Global Potential,'' Energy Procedia 63: 5858-5869 (2014). 
https://doi.org/10.1016/j.egypro.2014.11.619.
    \328\ N. Ripepi et al., ``Central Appalachian Basin 
Unconventional (Coal/Organic Shale) Reservoir Small Scale 
CO2 Injection,'' US DOE/NETL Annual Carbon Storage and 
Oil and Natural Gas Technologies Review Meeting (2017). https://www.netl.doe.gov/sites/default/files/event-proceedings/2017/carbon-storage-oil-and-natural-gas/thur/Nino-Ripepi-VirginiaTech.DOEMeeting.CoalShaleUpdate.8.3.2017.pdf.
    \329\ U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition, 
September 2015. https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
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    Although the large-scale injection of CO2 in coal seams 
can lead to swelling of coal, the literature also suggests that there 
are available technologies and techniques to compensate for the 
resulting reduction in injectivity.\330\ Further, the reduced 
injectivity can be anticipated and accommodated in sizing and 
characterizing prospective sequestration sites.
---------------------------------------------------------------------------

    \330\ Xiachun Li & Zhi-Ming Fang, ``Current Status and Technical 
Challenges of CO2 Storage in Coal Seams and Enhanced 
Coalbed Methane Recovery: An Overview,'' International Journal of 
Coal Science & Technology, 93, 99 (2014) (suggesting existing 
technologies that can be used to address injectivity reduction in 
unmineable coal seams).
---------------------------------------------------------------------------

    There is sufficient technical basis and scientific evidence that 
depleted oil and gas reservoirs represent another option for geologic 
storage. The reservoir characteristics of older fields are well known 
as a result of exploration and many years of hydrocarbon production 
and, in many areas, infrastructure

[[Page 33298]]

already exists for CO2 transportation and storage.\331\ 
Other types of geologic formations such as organic rich shale and 
basalt may also have the ability to store CO2, and DOE is 
continuing to evaluate their potential sequestration capacity and 
efficacy.\332\
---------------------------------------------------------------------------

    \331\ Intergovernmental Panel on Climate Change. (2005). Special 
Report on Carbon Dioxide Capture and Storage.
    \332\ Goodman, A., et al. ``Methodology for Assessing 
CO2 Storage Potential of Organic-Rich Shale Formations.'' 
Energy Procedia, 12th International Conference on Greenhouse Gas 
Control Technologies, GHGT-12, 63 (2014): 5178-84. https://doi.org/10.1016/j.egypro.2014.11.548. NETL DOE. ``Big Sky Carbon 
Sequestration Partnership.'' https://netl.doe.gov/coal/carbon-storage/atlas/bscsp. Schaef, T., and McGrail, P. ``Sequestration of 
CO2 in Basalt Formations.'' Pacific Northwest National 
Laboratory, NETL, DOE, 2013. https://www.netl.doe.gov/sites/default/files/event-proceedings/2013/carbon%20storage/8-00-Schaef-58159-Task-1-082213.pdf.
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    The EPA performed a geographic availability analysis in which the 
Agency examined areas of the country with sequestration potential in 
deep saline formations, unmineable coal seams, and oil and gas 
reservoirs; information on existing and probable, planned or under 
study CO2 pipelines; and areas within a 100-kilometer (km) 
(62-mile) area of locations with sequestration potential. The distance 
of 100 km is consistent with the assumptions underlying the NETL cost 
estimates for transporting CO2 by pipeline.\333\ Overall, 
the EPA found that there are 43 States containing areas within 100 km 
from currently assessed onshore or offshore storage resources in deep 
saline formations, unmineable coal seams, and depleted oil and gas 
reservoirs. There are additional areas that have not yet been assessed 
and may provide additional infrastructure capability.\334\
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    \333\ Although a 100 km pipeline is used in this analysis, this 
does not represent a technical limitation, but rather a 
standardization used for NETL cost estimates. As noted in the GHG 
Mitigation Measures for Steam Generating Units TSD, large pipelines 
connect CO2 sources in south central Colorado, northeast 
New Mexico, and Mississippi to Texas, Oklahoma, New Mexico, Utah, 
and Louisiana. Additionally, as noted in section VII.F.3.b.iii.(5) 
of this preamble, CO2 can by transported via other modes 
such as ship, road tanker, or rail tank cars.
    \334\ GHG Mitigation Measures for Steam Generating Units TSD, 
chapter 4.6.2. As discussed in the TSD, geologic sequestration 
potential has not yet been assessed for Connecticut, Hawaii, Nevada, 
New Hampshire, Rhode Island, and Vermont, and may provide additional 
infrastructure capability.
---------------------------------------------------------------------------

    As described in the 2015 NSPS, electricity demand in States that 
may not have geologic sequestration sites may be served by new 
generation, including new base load combustion turbines, built in 
nearby areas with geologic sequestration, and this electricity can be 
delivered through transmission lines.\335\ This approach has long been 
used in the electricity sector because siting an EGU away from a load 
center and transmitting the generation long distances to the load area 
can be less expensive and easier to permit than siting the EGU near the 
load area.
---------------------------------------------------------------------------

    \335\ This was described as ``coal-by-wire'' in the 2015 NSPS.
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    In many of the areas without reasonable access to geologic 
sequestration, utilities, electric cooperatives, and municipalities 
have a history of joint ownership of electricity generation outside the 
region or contracting with electricity generation in outside areas to 
meet demand. Some of the areas are in Regional Transmission 
Organizations (RTOs),\336\ which engage in planning as well as 
balancing supply and demand in real time throughout the RTO's 
territory. Accordingly, generating resources in one part of the RTO can 
serve load in other parts of the RTO, as well as load outside of the 
RTO. For example, the Prairie State Generating Plant, a 1,600-MW coal-
fired EGU in Illinois that is currently considering retrofitting with 
CCS, serves load in eight different States from the Midwest to the mid-
Atlantic.\337\ The Intermountain Power Project, a coal-fired plant 
located in Delta, Utah, that is converting to burn hydrogen and natural 
gas, serves customers in both Utah and California.\338\
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    \336\ In this discussion, the term RTO indicates both ISOs and 
RTOs.
    \337\ https://prairiestateenergycampus.com/about/ownership/.
    \338\ https://www.ipautah.com/participants-services-area/.
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(B) Costs
    The EPA has evaluated the costs of CCS for new combined cycle 
units, including the cost of installing and operating CO2 
capture equipment as well as the costs of transport and storage. The 
EPA has also compared the costs of CCS for new combined cycle units to 
other control costs, in part derived from other rulemakings that the 
EPA has determined to be cost reasonable, and the costs are comparable. 
Based on these analyses, the EPA is proposing that the costs of CCS for 
new combined cycle units are reasonable. Certain elements of the 
transport and storage costs are similar for new combustion turbines and 
existing steam generating units. In this section, the EPA outlines 
these costs and identifies the considerations specific to new 
combustion turbines. These costs are significantly reduced by the IRC 
section 45Q tax credit. For additional details on the EPA's CCS costing 
analysis see the GHG Mitigation Measures for Steam Generating Units 
TSD, which is available in the rulemaking docket.
(1) Capture Costs
    According to the NETL Fossil Energy Baseline Report (October 2022 
revision), before accounting for the IRC section 45Q tax credit for 
sequestered CO2, using a 90 percent capture amine-based 
post-combustion CO2 capture system increases the capital 
costs of a new combined cycle EGU by 115 percent on a $/kW basis, 
increases the heat rate by 13 percent, increases incremental operating 
costs by 35 percent, and derates the unit (i.e., decreases the capacity 
available to generate useful output) by 11 percent.\339\ For a base 
load combustion turbine, carbon capture increases the LCOE by 61 
percent (an increase of 27 $/MWh) and has an estimated cost of $81/ton 
($89/metric ton) of onsite CO2 reduction.\340\ The NETL 
costs are based on the use of a second generation amine-based capture 
system without exhaust gas recirculation (EGR) and does not take into 
account further cost reductions that can be expected to occur as post-
combustion capture systems are more widely deployed.
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    \339\ CCS reduced the net output of the NETL F class combined 
cycle EGU from 726 MW to 645 MW.
    \340\ These calculations use a service life of 30 years, an 
interest rate of 7.0 percent, a natural gas price of $3.69/MMBtu, 
and a capacity factor of 65 percent. These costs do not include 
CO2 transport, storage, or monitoring costs.
---------------------------------------------------------------------------

    The flue gas from NGCC EGUs differs from that of a coal-fired EGUs 
in several ways that impact the cost of CO2 capture. These 
include that the CO2 concentration is approximately one-
third, the volumetric flow rate on a per MW basis is larger, and the 
oxygen concentration is approximately 3 times that of a coal-fired EGU. 
The higher amount of excess oxygen has the potential to reduce the 
efficiency of amine-based solvents that are susceptible to oxidation. 
Other important factors include that the lower concentrations of 
CO2 reduce the efficiency of the capture process and that 
the larger volumetric flow rates require a larger CO2 
absorber, which increases the capital cost of the capture process. 
Exhaust gas recirculation (EGR), also referred to as flue gas 
recirculation (FGR), is a process that addresses all of these issues. 
EGR diverts some of the combustion turbine exhaust gas back into the 
inlet stream for the combustion turbine. Doing so increases the 
CO2 concentration and decreases the O2 
concentration in the

[[Page 33299]]

exhaust stream and decreases the flow rate, producing more favorable 
conditions for CCS. One study found that EGR can decrease the capital 
costs of a combined cycle EGU with CCS by 6.4 percent, decrease the 
heat rate by 2.5 percent, decrease the LCOE by 3.4 percent, and 
decrease the overall CO2 capture costs by 11 percent 
relative to a combined cycle EGU without EGR.\341\
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    \341\ Energy Procedia. (2014). Impact of exhaust gas 
recirculation on combustion turbines. Energy and economic analysis 
of the CO2 capture from flue gas of combined cycle power 
plants. https://www.sciencedirect.com/science/article/pii/S1876610214001234.
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    Furthermore, the EPA expects that the costs of capture systems will 
also decrease over the rest of this decade and continue to decrease 
afterwards. As part of the plan to reduce the costs of CO2 
capture, the DOE is funding multiple projects to advance CCS 
technology.\342\ It should be noted that these projects are EPAct05-
assisted. The EPA proposes that the rest of the information it has is 
sufficient to support a determination that the costs of capture systems 
are reasonable, and that CCS is adequately demonstrated. These EPAct05-
assisted projects provide additional confirmation for this proposal 
because they will contribute to improvements in the costs of CCS. These 
include projects falling under carbon capture research and development, 
engineering-scale testing of carbon capture technologies, and 
engineering design studies for carbon capture systems. The projects 
will aim to capture CO2 from various point sources, 
including NGCC units, cement manufacturing plants, and iron and steel 
plants. The general aim is to reach 95 percent or greater capture of 
CO2, to lower the costs of the technologies, and to prove 
feasible scalability at the industrial scale for these new 
technologies. Some projects are designed solely to develop new carbon 
capture technologies, while others are designed to apply existing 
technologies at the industrial scale. For a list of notable projects, 
see section VII.F.3.b.iii(A)(4)(b) of this preamble.
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    \342\ The DOE has also previously funded FEED studies for NGCC 
facilities. These include FEED studies at existing NGCC facilities 
at Panda Energy Fund in Texas, Elk Hills Power Plant in Kern County, 
California, Deer Park Energy Center in Texas, Delta Energy Center in 
Pittsburg, California, and utilization of a Piperazine Advanced 
Stripper (PZAS) process for CO2 capture conducted by The 
University of Texas at Austin.
---------------------------------------------------------------------------

    Although current post-combustion CO2 capture projects 
have primarily been based on amine capture systems, there are multiple 
alternate capture technologies in development--many of which are funded 
through industry research programs--that could have reductions in 
capital, operating, and auxiliary power requirements and could reduce 
the cost of capture significantly or improve performance. More 
specifically, post combustion carbon capture systems generally fall 
into one of several categories: solvents, sorbents, membranes, 
cryogenic, and molten carbonate fuel cells \343\ systems. It is 
expected that as CCS infrastructure increases, technologies from each 
of these categories will become more economically competitive. For 
example, advancements in solvents, that are potentially direct 
substitutes for current amine-solvents, will reduce auxiliary energy 
requirements and reduce both operating and capital costs, and thereby, 
increasing the economic competitiveness of CCS.\344\ Planned large-
scale projects, pilot plants, and research initiatives will also 
decrease the capital and operating costs of future CCS technologies.
---------------------------------------------------------------------------

    \343\ Molten carbonate fuel cells are configured for emissions 
capture through a process where the flue gas from an EGU is routed 
through the molten carbonate fuel cell that concentrates the 
CO2 as a side reaction during the electric generation 
process in the fuel cell. FuelCell Energy, Inc. (2018). SureSource 
Capture. https://www.fuelcellenergy.com/recovery-2/suresource-capture/.
    \344\ DOE. Carbon Capture, Transport, & Storage. Supply Chain 
Deep Dive Assessment. February 24, 2022. https://www.energy.gov/sites/default/files/2022-02/Carbon%20Capture%20Supply%20Chain%20Report%20-%20Final.pdf.
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    In general, CCS costs have been declining as carbon capture 
technology advances.\345\ While the cost of capture has been largely 
dependent on the concentration of CO2 in the gas stream, 
advancements in varying individual CCS technologies tend to drive down 
the cost of capture for other CCS technologies. The increase in CCS 
investment is already driving down the costs of near-future CCS 
technologies. The Global CCS Institute has tracked publicly available 
information on previously studied, executed, and proposed 
CO2 capture projects.\346\ The cost of CO2 
capture from low-to-medium partial pressure sources such as coal-fired 
power generation has been trending downward over the past decade, and 
is projected to fall by 50 percent by 2025 compared to 2010. This is 
driven by the familiar learning-processes that accompany the deployment 
of any industrial technology. Studies of the cost of capture and 
compression of CO2 from power stations completed ten years 
ago averaged around $95/metric ton ($2020). Comparable studies 
completed in 2018/2019 estimated capture and compression costs could 
fall to approximately $50/metric ton CO2 by 2025. Current 
target pricing for announced projects at coal-fired steam generating 
units is approximately $40/metric ton on average, compared to Boundary 
Dam whose actual costs were reported to be $105/metric ton, noting that 
these estimates do not include the impact of the 45Q tax credit as 
enhanced by the IRA. Additionally, IEA suggests this trend will 
continue in the future as technology advancements ``spill over'' into 
other projects to reduce costs.\347\ Policies in the IIJA and IRA are 
further increasing investment in CCS technology that can accelerate the 
pace of innovation and deployment.
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    \345\ International Energy Agency (IEA) (2020). CCUS in Clean 
Energy Transitions-A new era for CCUS. https://www.iea.org/reports/ccus-in-clean-energy-transitions/a-new-era-for-ccus.
    \346\ Technology Readiness and Costs of CCS (2021). Global CCS 
Institute. https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-and-Costs-for-CCS-2021-1.pdf.
    \347\ International Energy Agency (IEA) (2020). CCUS in Clean 
Energy Transitions-CCUS technology innovation. https://www.iea.org/reports/ccus-in-clean-energy-transitions/a-new-era-for-ccus.
---------------------------------------------------------------------------

(2) CO2 Transport and Sequestration Costs
    NETL's ``Quality Guidelines for Energy System Studies; Carbon 
Dioxide Transport and Sequestration Costs in NETL Studies'' provides an 
estimation of transport costs based on the CO2 Transport 
Cost Model.\348\ The CO2 Transport Cost Model estimates 
costs for a single point-to-point pipeline. Estimated costs reflect 
pipeline capital costs, related capital expenditures, and operations 
and maintenance costs.
---------------------------------------------------------------------------

    \348\ Grant, T., et al. ``Quality Guidelines for Energy System 
Studies; Carbon Dioxide Transport and Storage Costs in NETL 
Studies.'' National Energy Technology Laboratory. 2019. https://www.netl.doe.gov/energy-analysis/details?id=3743.
---------------------------------------------------------------------------

    NETL's Quality Guidelines also provide an estimate of sequestration 
costs. These costs reflect the cost of site screening and evaluation, 
permitting and construction costs, the cost of injection wells, the 
cost of injection equipment, operation and maintenance costs, pore 
volume acquisition expense, and long-term liability protection. 
Permitting and construction costs also reflect the regulatory 
requirements of the UIC Class VI program and GHGRP subpart RR for 
geologic sequestration of CO2 in deep saline formations. 
NETL calculates these sequestration costs on the basis of generic plant 
locations in the Midwest, Texas, North Dakota, and Montana, as 
described in the NETL energy system studies that utilize the coal found 
in Illinois, East Texas, Williston, and Powder River basins.\349\
---------------------------------------------------------------------------

    \349\ National Energy Technology Laboratory (NETL), ``FE/NETL 
CO2 Saline Storage Cost Model (2017),'' U.S. Department of Energy, 
DOE/NETL-2018-1871, 30 September 2017. https://netl.doe.gov/energy-analysis/details?id=2403.

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[[Page 33300]]

    There are two primary cost drivers for a CO2 
sequestration project: the rate of injection of the CO2 into 
the reservoir and the areal extent of the CO2 plume in the 
reservoir. The rate of injection depends, in part, on the thickness of 
the reservoir and its permeability. Thick, permeable reservoirs provide 
for better injection and fewer injection wells. The areal extent of the 
CO2 plume depends on the sequestration capacity of the 
reservoir. Thick, porous reservoirs with a good sequestration 
coefficient will present a small areal extent for the CO2 
plume and have lower testing and monitoring costs. NETL's Quality 
Guidelines model costs for a given cumulative storage potential.\350\
---------------------------------------------------------------------------

    \350\ Details on CO2 transportation and sequestration 
costs can be found in the GHG Mitigation Measures for Steam 
Generating Units TSD.
---------------------------------------------------------------------------

    In addition, provisions in the IIJA and IRA are expected to 
significantly increase the CO2 pipeline infrastructure and 
development of sequestration sites, which, in turn, are expected to 
result in further cost reductions for the application of CCS at a new 
combined cycle EGUs. The IIJA establishes a new Carbon Dioxide 
Transportation Infrastructure Finance and Innovation program to provide 
direct loans, loan guarantees, and grants to CO2 
infrastructure projects, such as pipelines, rail transport, ships and 
barges.\351\ The IIJA also establishes a new Regional Direct Air 
Capture Hubs program which includes funds to support four large-scale, 
regional direct air capture hubs and more broadly support projects that 
could be developed into a regional or inter-regional network to 
facilitate sequestration or utilization.\352\ DOE is additionally 
implementing IIJA section 40305 (Carbon Storage Validation and Testing) 
through its CarbonSAFE initiative, which aims to further development of 
geographically widespread, commercial-scale, safe storage.\353\ The IRA 
increases and extends the IRC section 45Q tax credit, discussed next.
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    \351\ Department of Energy. ``Biden-Harris Administration 
Announces $2 Billion from Bipartisan Infrastructure Law to Finance 
Carbon Dioxide Transportation Infrastructure.'' (2022). https://www.energy.gov/articles/biden-harris-administration-announces-2-billion-bipartisan-infrastructure-law-finance.
    \352\ Department of Energy. ``Regional Direct Air Capture 
Hubs.'' (2022). https://www.energy.gov/oced/regional-direct-air-capture-hubs.
    \353\ For more information, see the NETL announcement. https://www.netl.doe.gov/node/12405.
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(3) IRC Section 45Q Tax Credit
    In determining the cost of CCS, the EPA is taking into account the 
tax credit provided under IRC section 45Q, as revised by the IRA. The 
tax credit is available at $85/metric ton ($77/ton) and offsets a 
significant portion of the capture, transport, and sequestration costs 
noted above.
    It is reasonable to take the tax credit into account because it 
reduces the cost of the controls to the source, which has a significant 
effect on the actual cost of installing and operating CCS. In addition, 
all sources that install CCS to meet the requirements of these 
proposals are eligible for the tax credit. The legislative history of 
the IRA makes clear that Congress was well aware that the EPA may 
promulgate rulemaking under CAA section 111 based on CCS and explicitly 
stated that the EPA should consider the tax credit to reduce the costs 
of CCUS (i.e., CCS). Rep. Frank Pallone, the chair of the House Energy 
& Commerce Committee, included a statement in the Congressional Record 
when the House adopted the IRA in which he explained: ``The tax credit[ 
] for CCUS . . . included in this Act may also figure into CAA Section 
111 GHG regulations for new and existing industrial sources[.] . . . 
Congress anticipates that EPA may consider CCUS . . . as [a] candidate[ 
] for BSER for electric generating plants . . . . Further, Congress 
anticipates that EPA may consider the impact of the CCUS . . . tax 
credit[ ] in lowering the costs of [that] measure[ ].'' 168 Cong. Rec. 
E879 (August 26, 2022) (statement of Rep. Frank Pallone).
    In the 2015 NSPS, in which the EPA determined partial CCS to be the 
BSER for GHGs from new coal-fired steam generating EGUs, the EPA 
recognized that the IRC section 45Q tax credit or other tax incentives 
could factor into the cost of the controls to the sources. 
Specifically, the EPA calculated the cost of partial CCS on the basis 
of cost calculations from NETL, which included ``a range of assumptions 
including the projected capital costs, the cost of financing the 
project, the fixed and variable O&M costs, the projected fuel costs, 
and incorporation of any incentives such as tax credits or favorable 
financing that may be available to the project developer.'' 80 FR 64570 
(October 23, 2015).\354\
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    \354\ In fact, because of limits on the availability of the IRC 
section 45Q tax credit at the time of the 2015 NSPS, the EPA did not 
factor it into the cost calculation for partial CCS. 80 FR 64558-64 
(October 23, 2015).
---------------------------------------------------------------------------

    Similarly, in the 2015 NSPS, the EPA also recognized that revenues 
from utilizing captured CO2 for EOR would reduce the cost of 
CCS to the sources, although the EPA did not account for potential EOR 
revenues for purposes of determining the BSER. Id. at 64563-64. In 
other rules, the EPA has considered revenues from sale of the by-
products of emission controls to affect the costs of the emission 
controls. For example, in the 2016 Oil and Gas Methane Rule, the EPA 
determined that certain control requirements would reduce natural gas 
leaks and therefore result in the collection of recovered natural gas 
that could be sold; and the EPA further determined that revenues from 
the sale of the recovered natural gas reduces the cost of controls. See 
81 FR 35824 (June 3, 2016). In a 2011 action concerning a regional haze 
SIP, the EPA recognized that a NOX control would alter the 
chemical composition of fly ash that the source had previously sold, so 
that it could no longer be sold; and as a result, the EPA further 
determined that the cost of the NOX control should include 
the foregone revenues from the fly ash sales. 76 FR 58570, 58603 
(September 21, 2011). In the 2016 emission guidelines for landfill gas 
from municipal solid waste landfills, the EPA reduced the costs of 
controls by accounting for revenue from the sale of electricity 
produced from the landfill gas collected through the controls. 81 FR 
59276, 19679 (August 29, 2016).
    The amount of the IRC section 45Q tax credit that the EPA is taking 
into account is $85/metric ton for CO2 that is captured and 
geologically stored. This amount is available to the affected source as 
long as it meets the prevailing wage and apprenticeship requirements of 
IRC section 45Q(h)(3)-(4). The legislative history to the IRA 
specifically stated that when the EPA considers CCS as the BSER for GHG 
emissions from industrial sources in CAA section 111 rulemaking, the 
EPA should determine the cost of CCS by assuming that the sources would 
meet those prevailing wage and apprenticeship requirements. 168 Cong. 
Rec. E879 (August 26, 2022) (statement of Rep. Frank Pallone). If 
prevailing wage and apprenticeship requirements are not met, the value 
of the IRC section 45Q tax credit falls to $17/metric ton. The 
substantially higher credit available provides a considerable incentive 
to meeting the prevailing wage and apprenticeship requirements. 
Therefore, the EPA assumes that investors maximize the value of the IRC 
section 45Q tax credit at $85/metric ton by meeting those requirements.
(4) Total Costs of CCS
    In a typical NSPS analysis, the EPA amortizes costs over the 
expected life of

[[Page 33301]]

the affected facility and assumes constant revenue and expenses over 
that period of time. This analysis is different because the IRC section 
45Q tax credits for the sequestration of CO2 are only 
available for combustion turbines that commence construction by the end 
of 2032 and are available for 12 years. The construction timeframe is 
within the NSPS review cycle, and the EPA has determined that it is 
appropriate to include the credits as part of the CCS costing analysis. 
Since the duration of the tax credit is less than the expected life of 
a new base load combustion turbine, the EPA conducted the costing 
analysis assuming a 30-year useful life and a separate analysis 
assuming the capital costs are amortized over a 12-year period. For the 
30-year analysis, the EPA used a discount rate of 3.8 percent for the 
45Q tax credits to get an effective 30-year value of $41/ton.
    Even considering that the IRC section 45Q tax credits are currently 
available for only 12 years and would, therefore, only offset costs for 
a portion of a new NGCC turbine's expected operating life, the current 
overall CO2 abatement costs of CCS of a 90 percent capture 
amine-based post combustion capture system, accounting for the tax 
credit, are $44/ton ($49/metric ton) and the increase in the LCOE is 
$15/MWh.\355\ These costs assume a stable 30-year operating life, 
transport, storage, and monitoring costs of $10/metric ton, and do not 
include any revenues from sale of the CO2 following the 12-
year period when the IRC section 45Q tax credit is available. An 
alternate costing approach is to assume all capital costs are amortized 
during the 12-year period when tax credits are available. These tax 
credits are a significant source of revenue and would lower the 
incremental generating costs of the unit. Therefore, under the 12-year 
costing approach the EPA increased the assumed annual capacity factor 
from 65 to 75 percent. The 12-year CO2 abatement costs are 
$19/ton ($21/metric ton) and the increase in the LCOE is $6/MWh. These 
costs are for a combined cycle unit with a base load rating of 4,600 
MMBtu/h with an output of approximately 700 MW.\356\ These costs could 
be higher for small units and lower for larger units. For additional 
details on the CCS costing analysis see the GHG Mitigation Measures--
Carbon Capture and Storage for Combustion Turbines TSD, which is 
available in the rulemaking docket. The EPA is soliciting comment on 
whether the CCS transport, storage, and monitoring costs are 
appropriate for determining the BSER costs for combustion turbines.
---------------------------------------------------------------------------

    \355\ The EPA used 3.76 percent discount factor to levelized the 
45Q tax credits to an annual value of $45.4/metric ton. These 
calculations use a service life of 30 years, an interest rate of 7.0 
percent, a natural gas price of $3.69/MMBtu, a capacity factor of 65 
percent, and a transport, storage, and monitoring cost of $10/metric 
ton.
    \356\ The output of the model combined cycle EGU without CCS is 
726 MW. The auxiliary load of CCS reduces the net out to 645 MW.
---------------------------------------------------------------------------

(5) Comparison to Other Costs of Controls
    In assessing cost reasonableness for the BSER determination for 
this rule, the EPA compares the costs of GHG control measures to 
control costs that the EPA has previously determined to be reasonable. 
This includes comparison to the costs of controls at EGUs for other air 
pollutants, such as SO2 and NOX, and costs of 
controls for GHGs in other industries. The costs presented in this 
section of the preamble are in 2019 dollars.\357\
---------------------------------------------------------------------------

    \357\ The EPA used the NETL Baseline Report costs directly for 
the combustion turbine model plant BSER analysis. Even though these 
costs are in 2018 dollars, the adjustment to 2019 dollars (1.018 
using the U.S. GDP Implicit Price Deflator) is well within the 
uncertainty range of the report and the minor adjustment would not 
impact the EPA's BSER determination.
---------------------------------------------------------------------------

    At different times, many coal-fired steam generating units have 
been required to install and operate flue gas desulfurization (FGD) 
equipment--that is, wet or dry scrubbers--to reduce their 
SO2 emissions or SCR to reduce their NOX 
emissions. The EPA compares these control costs across technologies--
steam generating units and combustion turbines--because these costs are 
indicative of what is reasonable for the power sector in general. The 
fact that EPA required these controls in prior rules, and that many 
EGUs subsequently installed and operated these controls, provide 
evidence that these costs are reasonable, and as a result, the cost of 
these controls provides a benchmark to assess the reasonableness of the 
costs of the controls in this preamble. In the 2011 Cross-State Air 
Pollution Rule (CSAPR) (76 FR 48208; August 8, 2011), the EPA estimated 
the annualized costs to install and operate wet FGD retrofits on 
existing coal-fired steam generating units. Using those same cost 
equations and assumptions (i.e., a 63 percent annual capacity factor--
the average value in 2011) for retrofitting wet FGD on a representative 
700 to 300 MW coal-fired steam generating unit results in annualized 
costs of $14.80 to $18.50/MWh of generation, respectively.\358\ In the 
March 15, 2023 Good Neighbor Plan for the 2015 Ozone NAAQs (2023 GNP), 
the EPA estimated the annualized costs to install and operate SCR 
retrofits on existing coal-fired steam generating units. Using those 
same cost equations and assumptions (including a 56 percent annual 
capacity factor--a representative value in that rulemaking) to retrofit 
SCR on a representative 700 to 300 MW coal-fired steam generating unit 
results in annualized costs of $10.60 to $11.80/MWh of generation, 
respectively.\359\ Finally, using current cost equations and 
assumptions (including a 50 percent annual capacity factor, and 
otherwise consistent with the 2023 GNP) for retrofitting wet FGD on a 
representative 700 to 300 MW coal-fired steam generating unit results 
in annualized costs of $23.20 to $29.00/MWh of generation, 
respectively.\360\
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    \358\ For additional details, see https://www.epa.gov/power-sector-modeling/documentation-integrated-planning-model-ipm-base-case-v410.
    \359\ For additional details, see https://www.epa.gov/system/files/documents/2023-01/Updated%20Summer%202021%20Reference%20Case%20Incremental%20Documentation%20for%20the%202015%20Ozone%20NAAQS%20Actions_0.pdf.
    \360\ Ibid.
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    Finally, the EPA compares costs to the costs for GHG controls in 
rulemakings for other industries. In the 2016 NSPS regulating GHGs for 
the Crude Oil and Natural Gas source category, the EPA found the costs 
of reducing methane emissions of $2,447/ton to be reasonable (80 FR 
56627; September 18, 2015).\361\ Converted to a ton of CO2e 
reduced basis, those costs are expressed as $98/ton of CO2e 
reduced.\362\
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    \361\ The EPA finalized the 2016 NSPS GHGs for the Crude Oil and 
Natural Gas source category at 81 FR 35824 (June 3, 2016). The EPA 
included cost information in the proposed rulemaking, at 80 FR 56627 
(September 18, 2015).
    \362\ Based on the 100-year global warming potential for methane 
of 25 used in the GHGRP (40 CFR 98 Subpart A, Table A-1).
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    The costs for CCS applied to a representative new base load 
stationary combustion turbine EGU are generally lower than the above-
described costs, which supports the EPA's view that the CCS costs are 
reasonable. The CCS costs range from $6 to $15/MWh of generation or $19 
to $44/ton of CO2 reduced (depending on the amortization 
period).
 (C) Non-Air Quality Health and Environmental Impact and Energy 
Requirements
    In this section of the preamble, the EPA explains that it does not 
expect the use of CCS for new combined cycle combustion turbines to 
have unreasonable adverse consequences related to non-air quality 
health and environmental impact and energy requirements to combined 
cycle combustion turbines. The EPA first discusses energy requirements, 
and then considers non-GHG emissions impacts

[[Page 33302]]

and water use impacts, resulting from the capture, transport, and 
sequestration of CO2.
    With respect to energy requirements, including a 90 percent or 
greater carbon capture system in the design of a new NGCC will increase 
the parasitic/auxiliary energy demand and reduce its net power output. 
A utility that wants to construct an NGCC unit to provide 500 MWe-net 
of power could build a 500 MWe-net plant knowing that it will be de-
rated by 11 percent (to a 444 MWe-net plant) with the installation and 
operation of CCS. In the alternative, the project developer could build 
a larger 563 MWe-net NGCC plant knowing that, with the installation of 
the carbon capture system, the unit will still be able to provide 500 
MWe-net of power to the grid. Although the use of CCS imposes 
additional energy demands on the affected units, those units are able 
to accommodate those demands by scaling larger, as needed.
    Regardless of whether a unit is scaled larger, the installation and 
operation of CCS itself does not impact the unit's potential-to-emit 
any of the criteria or hazardous air pollutants. In other words, a new 
base load stationary combustion turbine EGU constructed using highly 
efficient generation (the first component of the BSER) would not see an 
increase in emissions of criteria or hazardous air pollutants as a 
direct result of installing and using 90 percent or greater 
CO2 capture CCS to meet the second phase standard of 
performance.\363\
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    \363\ While the absolute onsite mass emissions would not 
increase from the second component of the BSER, the emissions rate 
on a lb/MWh-net basis would increase by 13 percent.
---------------------------------------------------------------------------

    Scaling a unit larger to provide heat and power to the 
CO2 capture equipment would have the potential to increase 
non-GHG air emissions. However, most of them would be mitigated or 
adequately controlled by equipment needed to meet other CAA 
requirements. In general, the emission rates and flue gas 
concentrations of most non-GHG pollutants from the combustion of 
natural gas in stationary combustion turbines are relatively low 
compared to the combustion of oil or coal in boilers. As such, it is 
not necessary to use an FGD to pretreat the flue gas prior to 
CO2 removal in the CO2 scrubber column. The 
sulfur content of natural gas is low relative to oil or coal and 
resulting SO2 emissions are therefore also relatively low. 
Similarly, PM emissions from combustion of natural gas in a combustion 
turbine are relatively low. Furthermore, the high combustion efficiency 
of combustion turbines results in relatively low organic-HAP emissions, 
and there are likely few, if any, metallic-HAP emissions from 
combustion of natural gas. Additionally, combustion turbines at major 
sources of HAP are subject to the stationary combustion turbine NESHAP, 
which includes limits for formaldehyde emissions for new sources that 
may require installation of an oxidation catalyst (87 FR 13183; March 
9, 2022). Regarding NOX emissions, in most cases, the 
combustion turbines in new combined cycle units will be equipped with 
low-NOX burners to control flame temperature and reduce 
NOX formation. Additionally, new combined cycle units may be 
subject to major NSR requirements for NOX emissions, which 
may necessitate the installation of SCR to comply with a control 
technology determination by the permitting authority. See section 
XIII.A of this preamble for additional details regarding implications 
for the NSR program. Although NOX concentrations may be 
controlled by SCR, for some amine solvents NOX in the post-
combustion flue gas can react in the CO2 scrubber to form 
nitrosamines. A conventional multistage water wash or acid wash and a 
mist eliminator at the exit of the CO2 scrubber is effective 
at removal of gaseous amine and amine degradation products (e.g., 
nitrosamine) emissions.364 365
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    \364\ Sharma, S., Azzi, M., ``A critical review of existing 
strategies for emission control in the monoethanolamine-based carbon 
capture process and some recommendations for improved strategies,'' 
Fuel, 121, 178 (2014).
    \365\ Mertens, J., et al., ``Understanding ethanolamine (MEA) 
and ammonia emissions from amine-based post combustion carbon 
capture: Lessons learned from field tests,'' Int'l J. of GHG 
Control, 13, 72 (2013).
---------------------------------------------------------------------------

    Stakeholders have shared with the EPA concerns about the safety of 
CCS projects and that historically disadvantaged and overburdened 
communities may bear a disproportionate environmental burden associated 
with CCS projects.\366\ For the reasons noted above, the EPA does not 
expect CCS projects to result in uncontrolled or substantial increases 
in emissions of non-GHG air pollutants from new combustion turbines. 
The EPA is committed to working with its fellow agencies to foster 
meaningful engagement with communities and protect communities from 
pollution. 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 technological 
deployment process. Furthermore, the EPA is soliciting comment on 
additional ways that may be identified to responsibly advance the 
deployment of CCS and ensure meaningful engagement with local 
communities.
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    \366\ In outreach with potentially vulnerable communities, 
residents have voiced two primary concerns. First, there is the 
concern that their communities have experienced historically 
disproportionate burdens from the environmental impacts of energy 
production, and second, that as the sector evolves to use new 
technologies such as CCS and hydrogen, they may continue to face 
disproportionate burden. This is discussed further in section XIV.E 
of this preamble.
---------------------------------------------------------------------------

    The use of water for cooling presents an additional issue. Due to 
their relatively high efficiency, combined cycle EGUs have relatively 
small cooling requirements compared to other base load EGUs. According 
to NETL, a combined cycle EGU without CCS requires 190 gallons of 
cooling water per MWh of electricity. CCS increases the cooling water 
requirements due both to the decreased efficiency and the cooling 
requirements for the CCS process to 290 gallons per MWh, an increase of 
about 50 percent. However, because NGCC units require limited amounts 
of cooling water, the absolute amount of increase in cooling water 
required due to use of CCS does not present unsurmountable concerns. In 
addition, many combined cycle EGUs currently use dry cooling 
technologies and the use of dry or hybrid cooling technologies for the 
CO2 capture process would reduce the need for additional 
cooling water. Therefore, the EPA is proposing that the additional 
cooling water requirements from CCS are reasonable.
    As noted in section VII.F.3 of this preamble, PHMSA oversight of 
supercritical CO2 pipeline safety protects against 
environmental release during transport and UIC Class VI regulations 
under the SDWA in tandem with GHGRP requirements ensure the protection 
of USDWs and the security of geologic sequestration.
(D) Impacts on the Energy Sector
    The EPA does not believe that determining CCS to be BSER for base 
load units will cause reliability concerns, for two independent 
reasons. First, the EPA is proposing that the costs of CCS are 
reasonable and comparable to other controls the electric power industry 
has used without significant effects on reliability. Second, while CCS 
is adequately demonstrated and cost reasonable, the current proposal 
allows companies that want to build a base load combined cycle 
combustion turbine a second pathway to meet its requirements: building 
a unit that co-fires low-GHG hydrogen in the appropriate amount. In 
fact, companies are pursing both of these options,

[[Page 33303]]

including units with CCS, in various stages of development. The EPA 
also expects there to be considerable interest in building intermediate 
load and peaker units to meet market demand for dispatchable 
generation. Indeed, the portion of the combustion turbine fleet that is 
operating at base load is declining as shown in the EPA's reference 
case modeling (post-IRA 2022 reference case, see section IV.F of the 
preamble). Finally, combined cycle units are only one of many options 
that companies have to build new generation. For instance, in 2023, 
combined cycle units are only expected to represent 14 percent of all 
new generating capacity built in the US and only a portion of that is 
natural gas combined cycle capacity.\367\ Finally, several companies 
have recently announced plans to move away from new combined cycle 
projects in favor of more non-base load combustion turbines, 
renewables, and battery storage. For example, Xcel recently announced 
plans to build new renewable power generation instead of the combined 
cycle plant it had initially proposed to replace the retiring Sherco 
coal-fired plant.\368\ For these reasons, determining CCS to be the 
BSER for base load units will not cause reliability concerns.
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    \367\ https://www.eia.gov/todayinenergy/detail.php?id=55419.
    \368\ https://cubminnesota.org/xcel-is-no-longer-pursuing-gas-power-plant-proposes-more-renewable-power/.
---------------------------------------------------------------------------

(E) Extent of Reductions in CO2 Emissions
    Designating CCS as a component of the BSER for certain base load 
combustion turbine EGUs prevents large amounts of CO2 
emissions. For example, a new base load combined cycle EGU without CCS 
could be expected to emit 45 million tons of CO2 over its 
operating life. Use of CCS would avoid the release of nearly 41 million 
tons of CO2 over the operating life of the combined cycle 
EGU. However, due to the auxiliary/parasitic energy requirements of the 
carbon capture system, capturing 90 percent of the CO2 does 
not result in a corresponding 90 percent reduction in CO2 
emissions. According to the NETL baseline report, adding a 90 percent 
CO2 capture system increases the EGU's gross heat rate by 7 
percent and the unit's net heat rate by 13 percent. Since more fuel 
would be consumed in the CCS case, the gross and net emissions rates 
are reduced by 89.3 percent and 88.7 percent respectively.
(F) Promotion of the Development and Implementation of Technology
    The EPA also considered whether determining CCS to be a component 
of the BSER for new base load combustion turbines will advance the 
technological development of CCS and concluded that this factor 
supports our BSER determination. A standard of performance based on 
highly efficient generation in combination with the use of CCS--
combined with the availability of 45Q tax credits and investments in 
supporting CCS infrastructure from the IIJA--should incentivize 
additional use of CCS, which should incentivize cost reductions through 
the development and use of better performing solvents or sorbents. 
While solvent-based CO2 capture has been adequately 
demonstrated at the commercial scale, a determination that a component 
of the BSER for new base load stationary combustion turbine (and long 
term coal-fired steam generating units) is the use of CCS will also 
likely incentivize the deployment of alternative CO2 capture 
techniques at scale. Moreover, as noted above, the cost of CCS has 
fallen in recent years and is expected to continue to fall; and further 
implementation of the technology can be expected to lead to additional 
cost reductions, due to added experience and cost efficiencies through 
scaling.
    The experience gained by utilizing CCS with stationary combustion 
turbine EGUs, with their lower CO2 flue gas concentration 
relative to other industrial sources such as coal-fired EGUs, will 
advance capture technology with other lower CO2 
concentration sources. The EIA 2023 Annual Energy Outlook projects that 
almost 862 billion kWh of electricity will be generated from natural 
gas-fired sources in 2040.\369\ Much of that generation is projected to 
come from existing combined cycle EGUs and further development of 
carbon capture technologies could facilitate increased retrofitting of 
those EGUs.
---------------------------------------------------------------------------

    \369\ Does not include 114 billion kilowatt hours from natural 
gas-fired CHP projected in AEO 2023.
---------------------------------------------------------------------------

(G) Proposed BSER
    The Agency proposes that for new natural gas-fired base load 
combustion turbines, an efficient stationary combined cycle combustion 
turbine utilizing CCS at a capture rate of 90 percent, beginning in 
2035, qualifies as the BSER because it is adequately demonstrated; it 
entails reasonable costs taking account of the IRC section 45Q tax 
credit, it achieves significant emission reductions, and it does not 
have significant adverse non-air quality health or environmental 
impacts or significant adverse energy requirements, including on a 
nationwide basis. The fact that it promotes useful technology provides 
additional, although not essential, support for this proposal.
iv. Low-GHG Hydrogen
    As discussed, the EPA is proposing two BSER pathways that new 
stationary combustion turbines may take--one that is based on the use 
of 90 percent CCS and a separate BSER pathway based upon co-firing low-
GHG hydrogen. In this section, the EPA explains why it believes that 
CCS could form the basis of the BSER. In section VII.F.3.c, we discuss 
why we believe burning low-GHG hydrogen could also form the basis of 
the BSER.
v. Basis for Proposal of a Second Component of BSER, Based on CCS, in 
2035
    When considering whether a technology should be BSER, the EPA must 
consider both unit level and nationwide questions. At the unit level, 
the EPA must ask whether the technology is proven, can be implemented 
at reasonable cost, and achieves emission reductions without causing 
other significant environmental or energy issues. With regard to CCS at 
the unit level, the EPA believes there is ample evidence to conclude 
that it is available and cost reasonable (with the 45Q tax credits) 
today, and that a well-sited individual new unit could meet the 
standard of performance based on the application of 90 percent CCS on 
the startup date of the facility. However, when looking at the 
technology from a nationwide basis, the EPA must take larger system-
wide impacts into consideration. For CCS, this includes questions about 
the development and availability of infrastructure for transportation 
and storage \370\ as well as considerations related to the lead time 
needed to scale manufacturing and the installation of carbon capture 
equipment to meet the amount of capacity potentially subject to this 
proposed BSER (in addition to meeting IRA-driven demand for CCS in 
other sectors).
---------------------------------------------------------------------------

    \370\ For further information on timing associated with 
CO2 transport and storage design, engineering, and 
construction, see GHG Mitigation Measures for Steam Generating Units 
TSD, chapter 4.7.1.
---------------------------------------------------------------------------

    The EPA considered establishing the start of phase 2 of the 
standard of performance as early as 2030 on the assumption that 
projects that commence construction in the period immediately following 
this rulemaking will need at least that amount of time to implement the 
BSER. However, the EPA is also

[[Page 33304]]

proposing to determine that the BSER for long-term coal-fired steam 
generating units (those that will be in operation beyond 2040) is the 
use of 90 percent capture CCS and that the associated standard of 
performance for those units is effective beginning in 2030. The EPA is 
also aware that a significant number of new base load combined cycle 
stationary combustion turbines are projected to be constructed by 2030, 
and that there are other, non-power sector industries that will also be 
pursuing implementation of CCS in that timeframe. The EPA believes that 
while CCS poses low supply chain risk due to the required 
infrastructure relying on common and readily available raw materials 
and CCS infrastructure can be supplied in large part by domestic 
components,\371\ the deployment of CCS infrastructure, including the 
demand for the manufacturing and installation of CCS equipment and 
CO2 pipeline infrastructure, and the demand for conducting 
sequestration site characterization and permitting, should be 
prioritized for the higher GHG-emitting fleet of existing long-term 
coal-fired steam generating units. The EPA also understands that many 
utilities and power generating companies are trying to assess their 
near-term and long-term base load generating needs and may have useful 
information to provide to the record that would help to assess the 
demand for CCS. Therefore, in consideration of these factors, the EPA 
is proposing that phase 2 of the standard of performance begin in 2035 
to ensure achievability of the standard. The EPA also recognizes that 
commenters may have more information about implementing CCS on a 
broader scale that would help to assess whether 2030 or 2035 (or 
somewhere in between) would be an appropriate start date for phase 2 of 
the standards of performance that are based, in part, on the use of 
CCS. For this reason, the EPA solicits comment on whether the 
compliance date for phase 2 of the standards of performance should 
begin earlier than 2035, including as early as 2030.
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    \371\ U.S. Department of Energy, Achieving American Leadership 
in the Carbon Capture, Transport, and Storage Supply Chain, March 
23, 2022 (DOE/OP-0001-1). https://www.energy.gov/sites/default/files/2022-03/Carbon%20Capture%20factsheet.pdf.
---------------------------------------------------------------------------

c. BSER for Base Load Subcategory of Combustion Turbines Adopting the 
Low-GHG Hydrogen Co-Firing Pathway and Intermediate Load Subcategory--
Second and Third Components
    This section describes the second and third components of the EPA's 
proposed BSER for the subcategory of base load combustion turbines that 
are adopting the low-GHG hydrogen co-firing pathway and the second 
component for combustion turbines in the intermediate load subcategory. 
For both subcategories, the EPA is proposing that the second component 
of the BSER is co-firing 30 percent (by volume) low-GHG hydrogen and 
that sources meet a corresponding standard of performance beginning in 
2032. For base load combustion turbines in this subcategory of sources 
that adopt the low-GHG hydrogen co-firing pathway, the EPA is proposing 
that the third component of the BSER is co-firing 96 percent (by 
volume) low-GHG hydrogen and that sources meet a corresponding standard 
of performance beginning in 2038. The EPA is also soliciting comment on 
whether, in lieu of providing a subcategory for base load combustion 
turbines that adopt the low-GHG hydrogen co-firing pathway, a single 
BSER for base load combustion turbines should be selected based on 
application of CCS with 90 percent capture--which could also be met by 
co-firing 96 percent (by volume) low-GHG hydrogen. The first part of 
this section is a background discussion concerning several key aspects 
of the hydrogen industry as it is currently developing. At the outset, 
the EPA summarizes the activities of some power producers and turbine 
manufacturers to develop and demonstrate hydrogen co-firing as a viable 
decarbonization technology for the power sector. The EPA then discusses 
the GHG emissions performance of stationary combustion turbines when 
hydrogen is used as a fuel. This discussion includes the different 
methods of production and the associated GHG emissions for each. The 
second part of this section describes the proposed second component of 
the BSER, which is co-firing 30 percent (by volume) low-GHG hydrogen 
and the third component of the BSER, which, for certain units, is co-
firing 96 percent (by volume) low-GHG hydrogen.
    The EPA is also proposing a definition of low-GHG hydrogen. The EPA 
is proposing that hydrogen qualifies as low-GHG hydrogen if it is 
produced through a process that results in a GHG emission rate of less 
than 0.45 kilograms of CO2 equivalent per kilogram of 
hydrogen (kg CO2e/kg H2) on a well-to-gate basis 
consistent with the system boundary established in IRC section 45V 
(Credit for Production of Clean Hydrogen) of the IRA. Hydrogen produced 
by electrolysis (splitting water into hydrogen and oxygen) using non-
emitting energy sources such as solar, wind, nuclear, and hydroelectric 
power, can produce hydrogen with carbon intensities lower than 0.45 kg 
CO2e/kg H2, which could qualify as low-GHG 
hydrogen for the purposes of this proposed BSER.\372\ However, the EPA 
is also soliciting comment on whether a specific definition of low-GHG 
hydrogen should be included in the final rule. The third part of this 
section explains why the EPA proposes that co-firing 30 percent (by 
volume) low-GHG hydrogen qualifies as a component of the BSER. Co-
firing 30 percent (by volume) hydrogen is technically feasible and 
well-demonstrated in new combustion turbines, it will be supported by 
an adequate supply of hydrogen by 2032, it will be of reasonable cost, 
it will ensure reductions of GHG emissions, and it will be consistent 
with the other BSER factors. The EPA also includes in this section an 
explanation of why the Agency thinks that highly efficient generating 
technology combined with co-firing only low-GHG hydrogen is the 
``best'' system of emission reduction, taking into account the 
statutory considerations. This third part of this section also explains 
why the EPA proposes that co-firing 96 percent (by volume) low-GHG 
hydrogen qualifies as a third component of the BSER for base load 
combustion turbines that are subject to a second phase standard of 
performance based on co-firing 30 percent (by volume) low-GHG hydrogen. 
The EPA proposes that co-firing 96 percent (by volume) low-GHG hydrogen 
is technically feasible and well-demonstrated in new combustion 
turbines, it will be supported by an adequate supply of low-GHG 
hydrogen by 2038, it will be of reasonable cost, it will ensure 
reductions of GHG emissions, and it will be consistent with the other 
BSER factors.
---------------------------------------------------------------------------

    \372\ U.S. Department of Energy (DOE). Pathways to Commercial 
Liftoff: Clean Hydrogen, March 2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies.
---------------------------------------------------------------------------

i. Lower Emitting Fuels
    The EPA is not proposing lower emitting fuels as the second 
component of BSER for base load or intermediate load combustion 
turbines because it would achieve few emission reductions compared to 
co-firing low-GHG hydrogen.
ii. Highly Efficient Generation
    For the reasons described above, the EPA is proposing that highly 
efficient generation technology in combination with best operating and 
maintenance practices continues to be a component of the BSER that is 
reflected in the

[[Page 33305]]

second phase of the standards of performance for base load turbines 
that are adopting the low-GHG hydrogen co-firing pathway and 
intermediate load combustion turbines. Highly efficient generation 
reduces fuel use as well as the absolute amount and cost of low-GHG 
hydrogen that would be required to comply with the second phase 
standards.
iii. CCS
    The EPA is not proposing the use of CCS as a component of the BSER 
for base load turbines combusting that are adopting low-GHG hydrogen 
co-firing or intermediate load combustion turbines. As described 
previously, simple cycle technology is the most common combustion 
turbine technology applicable to the intermediate load subcategory and 
the Agency is limiting consideration of CCS to base load combined cycle 
EGUs. Intermediate load combustion turbines tend to start and stop 
frequently and have relatively short periods of continuous operation. 
CCS systems could have difficulty starting fast enough to get 
significant levels of CO2 capture. The EPA solicits comment 
on flexible CCS technologies that could be used by intermediate load 
combustion turbines. In addition, the CCS equipment could essentially 
remain idle for much of the time while these intermediate units are not 
running. For these reasons, CCS would be less cost-effective for 
intermediate load combustion turbine EGUs--particularly at much lower 
capacity factors--as compared to base load combined cycle units that 
are not on the pathway to combusting 96 percent (by volume) low-GHG 
hydrogen.
    With respect to base load combustion turbine EGUs, as explained 
previously, the EPA is proposing two BSER pathways that new base load 
stationary combustion turbines may take--one that is based on the use 
of 90 percent CCS and a separate BSER pathway based upon co-firing low-
GHG. In this section, the EPA explains why it believes that co-firing 
with low-GHG hydrogen could form the basis of the BSER. In section 
VII.C.3.b.iii, we discuss why we believe CCS could also form the basis 
of the BSER.
iv. Background Discussion of Hydrogen and the Electric Power Sector, 
Hydrogen Co-Firing in Combustion Turbines, and Hydrogen Production 
Processes
    Hydrogen in the United States is primarily used for refining 
petroleum and producing fertilizer, with smaller amounts also used in 
sectors like metals treatment, processing foods, and production of 
specialty chemicals.\373\ In recent years, applications of hydrogen 
have expanded to include co-firing in combustion turbines used to 
generate electricity. In fact, many models of existing combustion 
turbines that are used for electricity generation have successfully 
demonstrated the ability to co-fire blends of 5 to 10 percent hydrogen 
by volume without modification to the combustion system. Furthermore, 
combustion of hydrogen blends as high as 20 to 30 percent by volume are 
being tested and demonstrated; and new turbine designs that can 
accommodate co-firing much greater percentages of hydrogen are being 
developed.
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    \373\ U.S. Department of Energy (DOE). National Clean Hydrogen 
Strategy and Roadmap. September 2022. https://www.hydrogen.energy.gov/pdfs/clean-hydrogen-strategy-roadmap.pdf.
---------------------------------------------------------------------------

    Several power producers made financial investments and began work 
on hydrogen co-firing projects prior to passage of the IRA in August 
2022. For example, in early 2021, the Intermountain Power Agency (IPA) 
project in Utah began the transition away from operating an 1,800-MW 
coal-fired steam generating unit to an 840-MW combined cycle combustion 
turbine that will integrate 30 percent by volume hydrogen co-firing at 
startup in 2025.\374\ IPA and its partners have announced plans to 
produce low-GHG hydrogen via solar-powered electrolysis with storage in 
underground geologic formations en route to combusting 100 percent low-
GHG hydrogen in the combined cycle unit by 2045. IPA also has 
agreements to sell its electricity to the Los Angeles Department of 
Water and Power.
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    \374\ Intermountain Power Agency (2022). https://www.ipautah.com/ipp-renewed/.
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    Another example is the Long Ridge Energy Generation Project in 
Ohio.\375\ The 485-MW combined cycle combustion turbine became 
operational in 2021 and is designed to transition to 100 percent 
hydrogen in the future.\376\ The unit successfully co-fired 5 percent 
by volume hydrogen in March 2022.377 378 The planned next 
step for Long Ridge is to co-fire 20 percent by volume hydrogen with 
the existing turbine design, which has been commercially available 
since 2017 and can co-fire 15 to 20 percent by volume hydrogen without 
modification.\379\ Furthermore, in June 2022, Southern Company 
successfully demonstrated the co-firing of a 20 percent by volume 
hydrogen blend at Georgia Power's Plant McDonough-Atkinson. The co-
firing demonstration was performed on a combustion turbine at partial 
and full loads and produced a 7 percent reduction in CO2 
emissions.\380\ In September 2022, the New York Power Authority (NYPA) 
successfully co-fired a 44 percent by volume blend of hydrogen in a 
retrofitted combustion turbine. According to the Electric Power 
Research Institute (EPRI), the project demonstrated a 14 percent 
reduction in CO2 at a 35 percent by volume hydrogen blend. 
The unit's existing SCR controlled NOX emissions within 
permit limits.381 382 383 We note other projects to develop 
combustion turbines that co-fire hydrogen in section IV.E of this 
preamble.
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    \375\ Hering, G. (2021). First major US hydrogen-burning power 
plant nears completion in Ohio. S&P Global Market Intelligence. 
https://www.spglobal.com/platts/en/market-insights/latest-news/electric-power/081221-first-major-us-hydrogen-burning-power-plant-nears-completion-in-ohio.
    \376\ McGraw, D. (2021). World science community watching as 
natural gas-hydrogen power plant comes to Hannibal, Ohio. Ohio 
Capital Journal. https://ohiocapitaljournal.com/2021/08/27/world-science-community-watching-as-natural-gas-hydrogen-power-plant-comes-to-hannibal-ohio/.
    \377\ McGraw, D. (2021). World science community watching as 
natural gas-hydrogen power plant comes to Hannibal, Ohio. Ohio 
Capital Journal. https://ohiocapitaljournal.com/2021/08/27/world-science-community-watching-as-natural-gas-hydrogen-power-plant-comes-to-hannibal-ohio/.
    \378\ Defrank, Robert (2022). Cleaner Future in Sight: Long 
Ridge Energy Terminal in Monroe County Begins Blending Hydrogen. 
https://www.theintelligencer.net/news/community/2022/04/cleaner-future-in-sight-long-ridge-energy-terminal-in-monroe-county-begins-blending-hydrogen.
    \379\ Patel, S. (April 22, 2022). First Hydrogen Burn at Long 
Ridge HA-Class Gas Turbine Marks Triumph for GE. Power. https://www.powermag.com/nypa-ge-successfully-pilot-hydrogen-retrofit-at-aeroderivative-gas-turbine/.
    \380\ Patel, S. (2022). Southern Co. Gas-Fired Demonstration 
Validates 20% Hydrogen Fuel Blend. https://www.powermag.com/southern-co-gas-fired-demonstration-validates-20-hydrogen-fuel-blend/.
    \381\ Palmer, W., & Nelson, B. (2021). An H2 Future: GE and New 
York power authority advancing green hydrogen initiative. https://www.ge.com/news/reports/an-h2-future-ge-and-new-york-power-authority-advancing-green-hydrogen-initiative.
    \382\ Van Voorhis, S. (2021). New York to test green hydrogen at 
Long Island power plant. Utility Dive. https://www.utilitydive.com/news/new-york-to-test-green-hydrogen-at-long-island-power-plant/603130/.
    \383\ Electric Power Research Institute (EPRI). (2022, September 
15). Hydrogen Co-Firing Demonstration at New York Power Authority's 
Brentwood Site: GE LM6000 Gas Turbine. Low Carbon Resources 
Initiative. https://www.epri.com/research/products/000000003002025166.
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    Other power producers have implemented large low-GHG hydrogen plans 
that integrate multiple elements of their generating assets. In 
Florida, NextEra announced in June 2022 a comprehensive carbon 
emissions reduction plan that will eventually convert 16 GW of natural 
gas-fired generation to operate on low-GHG hydrogen as part of the 
utility's 2045

[[Page 33306]]

GHG reduction goal.\384\ Also, NextEra's Cavendish NextGen Hydrogen Hub 
will produce hydrogen with a 25-MW electrolyzer system powered by solar 
energy and the hydrogen will then be co-fired by combustion turbines at 
Florida Power and Light's 1.75-GW Okeechobee power plant.\385\
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    \384\ NextEra Energy (2022). Zero Carbon Blueprint. https://www.nexteraenergy.com/content/dam/nee/us/en/pdf/NextEraEnergyZeroCarbonBlueprint.pdf.
    \385\ Clean Energy Group. Hydrogen Projects in the U.S. https://www.cleanegroup.org/ceg-projects/hydrogen/projects-in-the-us/.
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    One of the first power producers to invest in hydrogen as a fuel 
for combustion turbines was Entergy, which reached an agreement with 
turbine manufacturer Mitsubishi Power in 2020 to develop hydrogen-
capable combined cycle facilities that include low-GHG hydrogen 
production, storage, and transportation components.\386\ In October 
2022, Entergy and New Fortress Energy announced plans to collaborate on 
a renewable energy and 120-MW hydrogen production plant in southeast 
Texas.\387\ The partnership includes electricity transmission 
infrastructure as well as the development of renewable energy resources 
and the offtake of low-GHG hydrogen. A feature of the agreement is the 
potential to supply hydrogen to Entergy's Orange County Advanced Power 
Station, which received approval from the Public Utility Commission of 
Texas in November 2022.\388\ The 1,115-MW power plant will replace end-
of-life gas generation with new combined cycle combustion turbines that 
are ready to co-fire hydrogen with the ability to move to 100 percent 
hydrogen in the future. Construction will begin in 2023 and the project 
will be completed in 2026.
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    \386\ Mitsubishi Power Americas. (September 23, 2020). 
Mitsubishi Power and Entergy to Collaborate and Help Decarbonize 
Utilities in Four States. https://power.mhi.com/regions/amer/news/20200923.html.
    \387\ Entergy. (October 19, 2022). Entergy Texas and New 
Fortress Energy partner to advance hydrogen economy in Southeast 
Texas. https://www.entergynewsroom.com/news/entergy-texas-new-fortress-energy-partner-advance-hydrogen-economy-in-southeast-texas/
.
    \388\ Entergy. (November 28, 2022). Entergy Texas receives 
approval to build a cleaner, more reliable power station in 
Southeast Texas. https://www.entergynewsroom.com/news/entergy-texas-receives-approval-build-cleaner-more-reliable-power-station-in-southeast-texas/.
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    Hydrogen offers unique solutions for decarbonization because of its 
potential to provide dispatchable, clean energy with long-term storage 
and seasonal capabilities. For example, hydrogen is an energy carrier 
that can provide long-term storage of low-GHG energy that can be co-
fired in combustion turbines and used to balance load with the 
increasing volumes of variable generation.\389\ These services can 
enhance the reliability of the power system while facilitating the 
integration of variable renewable energy resources and supporting 
decarbonization of the electric grid. Hydrogen has the potential to 
mitigate curtailment, which is the deliberate reduction of electric 
output below what could have been produced. Curtailment often occurs 
when RTOs need to balance the grid's energy supply to meet demand. For 
example, in 2020, the California Independent System Operator (CAISO) 
curtailed an estimated 1.5 million MWh of solar generation.\390\ 
Curtailment will likely increase as the capacity of variable generation 
continues to expand. One technology with the potential to reduce 
curtailment is energy storage, and some power producers envision a role 
for hydrogen to supplement natural gas as a fuel to support the 
balancing and reliability of an increasingly decarbonized electric 
grid.
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    \389\ For example, when the sun is not shining and/or the wind 
is not blowing.
    \390\ Walton, R. (August 25, 2021). CAISO forced to curtail 15% 
of California utility-scale solar in March, 5% last year. Power 
Engineering. https://www.power-eng.com/solar/caiso-forced-to-curtail-15-of-california-utility-scale-solar-in-march-5-last-year/#gref.
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    Rapid progress is being made, and, due to the demonstrated ability 
of new and existing combustion turbines to co-fire hydrogen, other 
utility owners/operators have publicly made long-term commitments to 
hydrogen co-firing and have identified the technology as a key 
component of their future operations and GHG reduction strategies. As 
highlighted by the earlier examples, the outlook expressed by multiple 
power producers and developers includes a future generation asset mix 
that retains combustion turbines fired exclusively with hydrogen. 
Utilities in vertically integrated States and merchant generators in 
wholesale markets rely on combustion turbines to provide reliable, 
dispatchable power.
    Hydrogen gas released into the atmosphere will also have climate 
and air quality effects through atmospheric chemical reactions. In 
particular, hydrogen is known to react with the hydroxyl radical, 
reducing concentrations of the hydroxyl radical in the atmosphere. 
Because the hydroxyl radical is important for the destruction of many 
other gases, a reduction in hydroxyl radical concentrations will lead 
to increased lifetimes of many other gases--including methane and 
tropospheric ozone. This means that hydrogen gas emissions can also 
indirectly contribute to warming through increasing concentrations of 
methane and ozone. Hydrogen is not a greenhouse gas as defined by the 
Framework Convention on Climate Change under the IPCC, and its 
secondary impacts on warming should mitigate over time as methane 
emissions are controlled. Even as hydrogen scales and much larger 
volumes are consumed, with the attendant potential for emissions of 
hydrogen to oxidize in the atmosphere, we expect the benefits of low-
GHG hydrogen as part of a BSER pathway to outweigh any such effects in 
the future.
v. Hydrogen Production Processes and Associated Levels of GHG Emissions
    Hydrogen is used in industrial processes, and as discussed 
previously, in recent years, applications of hydrogen co-firing have 
expanded to include stationary combustion turbines used to generate 
electricity. However, at present, nearly all industrial hydrogen is 
produced via methods that are GHG-intensive. To fully evaluate the 
potential GHG emission reductions from co-firing low-GHG hydrogen in a 
combustion turbine EGU, it is important to consider the different 
processes of producing the hydrogen and the GHG emissions associated 
with each process. The following discussion highlights the primary 
methods of hydrogen production as well as the sources of energy used 
during production and the level of GHG emissions that result from each 
production method. The varying levels of CO2 emissions 
associated with hydrogen production are well-recognized, and 
stakeholders routinely refer to hydrogen on the basis of the different 
production processes and their different GHG intensities.\391\
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    \391\ Some organizations have developed a convention for 
labeling each hydrogen production method, based on the GHG emissions 
associated with each method, according to a color scheme. The color 
labels are insufficiently specific for the purposes of this proposed 
rule, so the EPA generally does not refer to hydrogen using this 
color convention.
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    More than 95 percent of the dedicated hydrogen currently produced 
in the U.S. originates from natural gas using steam methane reforming 
(SMR). This method produces hydrogen by adding steam and heat to 
natural gas in the presence of a catalyst. Methane reacts with the 
steam to produce hydrogen, carbon monoxide (CO), and trace amounts of 
CO2. Further, the CO byproduct is routed to a second 
process, known as a water-gas shift reaction, to react with more steam 
to create additional hydrogen and CO2. After these 
processes, the CO2 is removed from the gas stream, leaving

[[Page 33307]]

almost pure hydrogen.\392\ CO2 emissions are generated from 
the conversion process itself and from the creation of the thermal 
energy and steam (assuming the boilers are fueled by natural gas) or 
external energy sources powering the production process. Because the 
thermal efficiency of SMR of natural gas is generally 80 percent or 
less,\393\ less overall energy is in the produced hydrogen than in the 
natural gas required to produce the hydrogen. Therefore, the use of 
hydrogen produced through SMR in a combustion turbine would consume 
more natural gas than would have been consumed if the combustion 
turbine had burned the natural gas directly. Therefore, co-firing 
hydrogen derived from SMR based on fossil fuels without CCS results in 
higher overall CO2 emissions than using the natural gas 
directly in the EGU.
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    \392\ U.S. Department of Energy (DOE) (n.d.). Hydrogen 
Production: Natural Gas Reforming. https://www.energy.gov/eere/fuelells/hydrogen-production-natural-gas-reforming. For each kg of 
hydrogen produced through SMR, 4.5 kg of water is consumed.
    \393\ Thermal efficiency is the amount of energy in the 
production (e.g., hydrogen) compared to the energy input to the 
process (e.g., natural gas). At an efficiency of 80 percent, the 
product contains 80 percent of the energy input and 20 percent is 
lost.
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    The GHG emissions from hydrogen production via SMR can be 
controlled with CCS technology at different points in the production 
process. There are varying levels of CO2 capture for 
different techniques, but typically a range of 65 to 90 percent is 
viable.\394\ The autothermal reforming (ATR) of methane is a similar 
technology to SMR, but ATR utilizes natural gas in the process itself 
without an external heat source.\395\ CCS can also be applied to ATR.
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    \394\ Powell, D. (2020). Focus on Blue Hydrogen. Gaffney Cline. 
https://www.gaffneycline.com/sites/g/files/cozyhq681/files/2021-08/Focus_on_Blue_Hydrogen_Aug2020.pdf.
    \395\ ``Comparative assessment of blue hydrogen from steam 
methane reforming, autothermal reforming, and natural gas 
decomposition technologies for natural gas production regions,'' 
Energy Conversion and Management, February 15, 2022.
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    Another process to produce hydrogen is methane pyrolysis. Methane 
pyrolysis is the thermal decomposition of methane in the absence (or 
near absence) of oxygen, which produces hydrogen and solid carbon 
(i.e., carbon black) as the only byproducts. Pyrolysis uses energy to 
power its hydrogen production process, and therefore the level of its 
overall GHG emissions depends on the carbon intensity of its energy 
inputs. For SMR, ATR, and pyrolysis technologies, emissions from 
methane extraction, production, and transportation are also significant 
aspects of their GHG emissions footprints.\396\
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    \396\ In addition, methane extraction operations are known to 
contribute to air toxics including benzene, ethylbenzene, and n-
hexane. https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/basic-information-oil-and-natural-gas.
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    In contrast to the three methods discussed above, electrolysis does 
not use methane as a feedstock. In electrolysis, hydrogen is produced 
by splitting water into its components, hydrogen and oxygen 
(O2), via electricity. During electrolysis, a negatively 
charged cathode and positively charged anode are submerged in water and 
an electric current is passed through the water. The result is hydrogen 
molecules appearing at the negative cathodes and O2 
appearing at the positive anodes. Electrolysis does not emit GHG 
emissions at the hydrogen production site; the overall GHG emissions 
associated with electrolysis are instead dependent upon the source of 
the energy used to decompose the water.\397\ According to the DOE, 
electrolysis powered by fossil fuel energy supplied by the electric 
grid, based on a national average, would generate overall GHG emissions 
double those of hydrogen produced via SMR without 
CCS.398 399 However, electrolysis powered by wind, solar, 
hydroelectric, or nuclear energy is generally considered to lower 
overall GHG emissions.400 401 402 It should be noted that 
electrolytic systems utilizing even a small portion of grid-based 
electricity may not have lower overall GHG emissions and carbon 
intensities than SMR without CCS.\403\ This concern is likely to be 
mitigated over time as the carbon intensity of the grid declines, given 
the influx of new renewable generation--the EPA's post-IRA 2022 
reference case projects a lower carbon intensity of the grid---coupled 
with expected retirements of higher-emitting sources. Naturally 
occurring hydrogen stored in subsurface geologic formations is also 
gaining attention as a potential low-GHG source of hydrogen.
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    \397\ Similarly, the overall GHG emissions associated with 
methane pyrolysis are dependent upon the source of the energy used 
to decompose the methane and is a key factor to whether it qualifies 
as low-GHG hydrogen.
    \398\ DOE (2022). DOE National Clean Hydrogen Strategy and 
Roadmap. Draft--September 2022. https://www.hydrogen.energy.gov/pdfs/clean-hydrogen-strategy-roadmap.pdf.
    \399\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 
2023: https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf. From the Liftoff 
report, ``Carbon intensities are based on data from the Carnegie 
Mellon Power Sector Carbon Index as well as national averages in 
grid mix carbon intensity--in some states, grid carbon intensity can 
be as high as 40 kg CO2e/kg H2.''
    \400\ U.S. Department of Energy (DOE) (n.d.). Hydrogen 
Production: Electrolysis. https://www.energy.gov/eere/fuelcells/hydrogen-production-electrolysis.
    \401\ For each kg of hydrogen produced through electrolysis, 9 
kg of byproduct oxygen are also produced and 9 kg of purified water 
are consumed. To reduce the cost of hydrogen production, this 
byproduct oxygen could be captured and sold. For each gallon of 
water consumed, 0.057 MMBtu of hydrogen is produced. According to 
the water use requirements for combined cycle EGUs with cooling 
towers, if this hydrogen is later used to produce electricity in a 
combined cycle EGU, overall water requirements would be greater than 
a combined cycle EGU with CCUS.
    \402\ Electrolysis and other technologies that break apart water 
to form hydrogen and oxygen consume more water than SMR without CCS. 
Resource Assessment for Hydrogen Production. National Renewable 
Energy Laboratory (NREL/TP-5400-77198, July 2020). https://www.nrel.gov/docs/fy20osti/77198.pdf. Aside from methane pyrolysis 
and byproduct hydrogen, other hydrogen production methods consume 
water during the production process and indirectly due to 
electricity generation upstream. The moisture present in coal and 
biomass could be recovered and used in the water gas shift reaction 
to reduce (or eliminate) water requirements.
    \403\ U.S. Department of Energy (DOE). Pathways to Commercial 
Liftoff: Clean Hydrogen. March 2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies.
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vi. The EPA's Proposed BSER and Definition of Low-GHG Hydrogen
    The EPA is proposing that the second component of the BSER for new 
combustion turbines in the relevant subcategories is co-firing 30 
percent (by volume) low-GHG hydrogen and that sources meet a 
corresponding standard of performance by 2032. The EPA is also 
proposing that new base load combustion turbines that are subject to a 
standard of performance based on co-firing 30 percent (by volume) low-
GHG hydrogen in 2032 must also meet a more stringent standard of 
performance based on a BSER of co-firing 96 percent (by volume) low-GHG 
hydrogen by 2038. This section describes the factors the EPA considered 
in determining what level of co-firing qualifies as a component of the 
BSER for affected sources and the timing for when that level of co-
firing could be technically feasible and of reasonable cost. Key 
factors informing this determination include the magnitude of 
CO2 emission reductions at the combustion turbines, the 
availability of combustion turbines capable of co-firing hydrogen, 
potential infrastructure limitations, and access to low-GHG hydrogen.
    The relationship between the volume of hydrogen fired and the 
reduction in CO2 stack emissions is exponential. At low 
levels of co-firing there are modest emission reduction benefits, but 
these reduction benefits amplify as the volume of hydrogen increases 
due to the lower energy density of hydrogen

[[Page 33308]]

compared to natural gas. For example, co-firing 10 percent hydrogen by 
volume yields approximately a 3 percent CO2 reduction at the 
stack, co-firing 30 percent hydrogen yields a 12 percent CO2 
reduction, co-firing 75 percent hydrogen yields a 49 percent 
CO2 reduction, and at 100 percent hydrogen co-firing there 
are zero CO2 emissions at the stack.
    Importantly, co-firing 30 percent hydrogen by volume is consistent 
with existing technologies across multiple combustion turbine designs 
and should be considered a minimal level for evaluation as a system of 
emission reduction. While all major manufacturers are developing 
combustion turbines that can co-fire higher volumes of hydrogen, some 
combustion turbine models are already able to co-fire relatively high 
percentages.\404\ Several currently available new combustion turbine 
models can burn up to 75 percent hydrogen by volume.\405\ Combustion 
turbine designs capable of co-firing 30 percent hydrogen by volume are 
available from multiple manufacturers at multiple sizes. As such, a 
BSER that included co-firing 30 percent hydrogen by volume would not 
pose challenges for near-term implementation for the EPA's proposed 
second phase standards beginning in 2032. The EPA is soliciting comment 
on whether the new and reconstructed combustion turbines will have 
available combustion turbine designs that would allow higher levels of 
hydrogen co-firing, such as 50 percent or more by volume by 2030 or 
2032. If such combustion turbines are sufficiently available, this 
would support moving forward the starting compliance date of the second 
phase of the standards of performance and/or increasing the percent of 
hydrogen co-firing assumed in establishing the standards.
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    \404\ Mitsubishi Power Americas. https://power.mhi.com/special/hydrogen/article_1.
    \405\ Overcoming technical challenges of hydrogen power plants 
for the energy transition. https://www.nsenergybusiness.com.
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    Because the cost of natural gas is lower than the cost of hydrogen, 
most new combustion turbines are not, at the present time, designed to 
burn 100 percent hydrogen when they are placed into service. However, 
some turbines are available now that can combust 100 percent hydrogen 
in the future and there is significant evidence that such turbines will 
be more widely available by the 2030s.\406\ Multiple vendors have 
indicated that they intend to have turbines available that fire 100 
percent hydrogen in that timeframe.407 408 409 For example, 
as noted in section IV.E of this preamble, the 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.\410\ The Intermountain Power Project, also noted in section IV.E 
of this preamble, commenced construction in 2022 on an 840-MW M501 JAC 
Mitsubishi Hitachi Power Systems combustion turbine designed to operate 
using 30 percent (by volume) hydrogen upon startup. The plant is 
projected to be operational by July 2025 and to transition to 100 
percent hydrogen by 2045.\411\ Several existing gas turbine 
technologies are capable of operating with 100 percent hydrogen, 
including Siemens Energy's SGT-A35 and General Electric's B, E, and F 
class gas turbines.\412\ Comments submitted to the EPA's non-regulatory 
docket confirm that at the present time, existing units can be 
retrofitted to operate using 100 percent hydrogen. DOE's National 
Energy Technology Lab states: Based on data from a literature survey 
and input from manufacturers, NETL has found that today's modern gas 
turbines can reliably combust 30-60 percent hydrogen fuels with similar 
NOX emissions as compared to their pure natural gas 
counterparts. Public and private research is underway to produce a 100 
percent hydrogen-fueled turbine. NETL anticipates that industry will 
achieve this technology by around 2030 based on current research 
progress and publicly announced forecasts.'' \413\ Turbine projects 
that have recently been built and that are currently under construction 
(such as the Longview turbine and the Intermountain Power Project 
discussed elsewhere in this preamble) are being developed with the 
understanding that these technology advances will be retrofittable to 
these types of turbines. It is worth noting that in many cases, 
existing turbines are able to co-fire large amounts of hydrogen without 
significant re-engineering. This is because their burners are developed 
relatively simply and are able to combust large amounts of hydrogen. In 
retrospect almost all new turbines are designed with more sophisticated 
burners that closely control the mixture of air and fuel to maximize 
efficiency while limiting nitrogen oxide generation. Because hydrogen 
has very different characteristics than natural gas such as higher 
flame temperature, these burners need to be re-engineered to 
accommodate large amounts of hydrogen 414 415 For more 
information about the status of combustion turbines with respect to 
combusting hydrogen see the TSD, ``Hydrogen in Combustion Turbine 
EGUs,'' in the docket for this rulemaking.
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    \406\ https://www.dieselgasturbine.com/news/siemens-energy-explores-gas-turbines-future-in-net-zero-energy-mix/8024799.article.
    \407\ Mitsubishi highlights four hydrogen projects at CERAWeek. 
https://www.power-eng.com/hydrogen/mitsubishi-power-highlights-four-hydrogen-projects/#gref.
    \408\ 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. Docket comments noted, 
``Retrofits using existing technology are available to achieve 50-
100% hydrogen combustion by volume at some generators.''
    \409\ Siemens Energy to provide hydrogen-capable turbines to 
back up utility-scale solar installation in Nebraska. https://press.siemens-energy.com/global/en/pressrelease/siemens-energy-provide-hydrogen-capable-turbines-back-utility-scale-solar-installation.
    \410\ https://clkrep.lacity.org/onlinedocs/2023/23-0039_rpt_DWP_02-03-2023.pdf.
    \411\ IPP Renewed--Intermountain Power Agency.ipautah.com.
    \412\ ICF. Retrofitting Gas Turbine Facilities for Hydrogen 
Blending.
    \413\ National Energy Technology Laboratory, A Literature Review 
of Hydrogen and Natural GAS Turbines: Current State of the Art With 
Regard to Performance and NOX Control (DOE/NETL-2022/
3812), August 12, 2022. https://netl.doe.gov/sites/default/files/publication/A-Literature-Review-of-Hydrogen-and-Natural-Gas-Turbines-081222.pdf; Department of Energy, National Energy 
Technology Laboratory, ``Experts Discuss Use of Hydrogen-Fueled 
Turbines to Drive Clean Energy'' September 15, 2022. https://netl.doe.gov/node/12058.
    \414\ Siemens Energy, ``Ten Fundamentals to Hydrogen Readiness'' 
September 2022. https://www.siemens-energy.com/global/en/news/magazine/2022/hydrogen-ready.html.
    \415\ General Electric, ``Hydrogen-Fueled Gas Turbines'' https://www.ge.com/content/dam/gepower-new/global/en_US/downloads/gas-new-site/future-of-energy/hydrogen-overview.pdf.
---------------------------------------------------------------------------

    Access to low-GHG hydrogen, however, is also an important component 
of the BSER analysis. Midstream infrastructure limitations and the 
adequacy and availability of hydrogen storage facilities currently 
present obstacles and increase prices for delivered low-GHG hydrogen. 
This is part of the rationale for why the EPA is not proposing hydrogen 
co-firing as part of the first component of the BSER. Moving gas via 
pipeline tends to be the least expensive transport and today there are 
1,600 miles of dedicated hydrogen pipeline infrastructure.\416\ As 
noted later in a section of this preamble, based on industry 
announcements, many electrolytic hydrogen production projects will be 
sited near existing

[[Page 33309]]

infrastructure and, in certain cases, will provide combustion turbines 
access to supply and delivery solutions. Hydrogen blending into 
existing natural gas pipelines presents another mode of transport and 
distribution that is actively in use in Hawaii and under exploration in 
other areas of the country.\417\ On-road distribution methods include 
gas-phase trucking and liquid hydrogen trucking, the latter requiring 
cooling and compression prior to transport. Different regional 
distribution solutions may emerge initially in response to localized 
hydrogen demand.
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    \416\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
    \417\ https://www.hawaiigas.com/clean-energy/decarbonization.
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    Gaseous and liquified hydrogen storage technologies are developing, 
along with lined hard rock storage and limited but promising geologic 
salt cavern storage. Increased storage capacity and market demand for 
low-GHG hydrogen is anticipated in response to Federal H2Hub 
investments as low-GHG hydrogen develops from a localized fuel into a 
national commodity.
    Given the growth in the hydrogen sector and Federal funding for the 
H2Hubs, which will explicitly explore and incentivize hydrogen 
distribution, the EPA therefore believes hydrogen distribution and 
storage infrastructure will not present a barrier to access for new 
combustion turbines opting to co-fire 30 percent low-GHG hydrogen by 
volume in 2032 and to co-fire 96 percent low-GHG hydrogen by volume in 
2038. The EPA is soliciting comment on the expected low-GHG hydrogen 
availability by those dates. The EPA is also soliciting comment on 
whether hydrogen infrastructure is likely to be sufficiently developed 
by 2030 to provide access to low-GHG hydrogen for new and reconstructed 
combustion turbines. If so, this would support moving forward the 
compliance date of the second phase of the standards of performance 
and/or increase the percent of hydrogen co-firing assumed in 
establishing the standards.
    Whether there will be sufficient volumes of low-GHG hydrogen for 
new sources to co-fire 30 percent by volume between 2030 and 2032 and 
then for some base load sources to co-fire 96 percent by 2038 will 
depend on the deployment of additional low-GHG electric generation 
sources, the growth of electrolyzer capacity, and market demand. Along 
with the power sector, the industrial and transportation sectors are 
also advancing hydrogen-ready technologies. Industries and policymakers 
in those sectors are actively planning to use hydrogen to drive 
decarbonization. For the industrial sector where hydrogen is a chemical 
input to the process or a replacement for liquid fuels, multiple 
projection pathways are being considered as approaches to lower the GHG 
intensity of these sectors. The production pathways for the industrial 
sector include, but are not limited to, fossil-derived hydrogen in 
combination with CCS. However, due to thermodynamic inefficiencies in 
using hydrogen to produce electricity, it is likely that only a 
specific type of low-GHG hydrogen will be used in the power sector. 
Announcements of co-firing applications support this assertion, and as 
discussed in another section of this preamble, the power sector is 
already focused on utilizing low-GHG hydrogen, electricity generators 
are likely to have ample access to low-GHG hydrogen and in sufficient 
quantities to support 30 percent co-firing by 2032 and 96 percent by 
2038. The DOE's estimates of clean hydrogen production volumes of 10 
MMT by 2030 and 20 MMT by 2040, referenced throughout this rulemaking, 
do not apportion which type of hydrogen is likely to be produced, just 
that it is `clean.' \418\ The available credits for the lowest GHG 
hydrogen production tier under IRC section 45V tax subsidies going into 
effect in 2023, as outlined in another section of this preamble, are 
three times higher than the credit values allotted for other hydrogen 
production tiers in IRC section 45V. This incentive can be combined 
with additional monetization access through direct pay and 
transferability, and therefore has the potential to drive significant 
volumes of electrolytic hydrogen, which is likely to be considered as 
low-GHG hydrogen in this proposal.\419\ The EPA's hydrogen co-firing 
BSER proposal, if finalized, would create a significant additional 
demand driver for electrolytic hydrogen not considered in the DOE's 
hydrogen production goals of 10 MMT by 2030 and 20 MMT by 2040. Indeed, 
high volumes of electrolytic hydrogen were central to pathways enabling 
the power sector to achieve net-zero emissions by 2035 according to 
analysis by the National Renewable Energy Laboratory (NREL).\420\ These 
incentives will be multiplied by investments through the DOE's H2Hub 
program. Electrolytic production costs, inclusive of the 45V PTC, are 
estimated to fall to less than $0.40/kg by 2030; this could translate 
to delivered cost of hydrogen for combustion turbines in 2030 between 
$0.70/kg and $1.15/kg depending on storage and distribution costs.\421\ 
The EPA is soliciting comment on whether sufficient quantities of low-
GHG hydrogen are likely to be available at reasonable costs by 2030. If 
so, this would support moving forward the compliance date of the second 
component of the BSER and/or increase the percent of hydrogen co-firing 
assumed in establishing the standard of performance.
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    \418\ DOE, as required by the IIJA, proposed a Clean Hydrogen 
Production Standard (CHPS) of having an overall emissions rate of 4 
kg CO2e/kg H2. CHPS is not an actual standard, 
rather a non-binding tool for DOE's internal use with selecting 
projects under the H2Hubs program. DOE's proposed CHPS can be found 
at https://www.hydrogen.energy.gov/pdfs/clean-hydrogen-production-standard.pdf.
    \419\ ``The Hydrogen Credit Catalyst: How US Treasury guidance 
on a new tax credit could shape the clean hydrogen economy, the 
future of American industry, and orient the power sector for full 
decarbonization,'' Rocky Mountain Institute, February 27, 2023.
    \420\ Denholm, Paul, Patrick Brown, Wesley Cole, et al. 2022. 
Examining Supply-Side Options to Achieve 100% Clean Electricity by 
2035. Golden, CO: National Renewable Energy Laboratory. NREL/
TP[1]6A40-81644. https://www.nrel.gov/docs/fy22osti/81644.pdf.
    \421\ U.S. Department of Energy (DOE). Pathways to Commercial 
Liftoff: Clean Hydrogen. March 2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
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    As discussed earlier, an important feature of hydrogen as a 
potential fuel for combustion turbines is the level of GHG emissions 
generated during the production process, with different processes 
resulting in different levels of GHG emissions. The EPA proposes to 
conclude that co-firing with low-GHG hydrogen (but not other forms of 
hydrogen) appropriately considers the statutory factors and constitutes 
the ``best'' system of emission reduction. Here, the EPA discusses the 
proposed definition of low-GHG hydrogen. In the IIJA and IRA, Congress 
established programs to support the development of low-GHG hydrogen, 
including section 40314 of the IIJA which established a $8 billion 
Clean Hydrogen Hubs H2Hubs program, the $500 million Clean Hydrogen 
Manufacturing and Recycling Program, and a $1 billion Clean Hydrogen 
Electrolysis Program to further electrolysis development. Section 40315 
of the IIJA required DOE to establish a non-regulatory Clean Hydrogen 
Production Standard (CHPS). Most recently, in the IRA, section 13204, 
Congress authorized the clean hydrogen production tax credit (45V). 
Several Federal agencies, including the EPA, are implementing those 
programs. DOE consulted the EPA while developing its proposed CHPS, 
which included examining various hydrogen production processes and the 
spectrum of resulting overall carbon intensities.

[[Page 33310]]

That collaborative process provided useful points of reference for the 
EPA to use in proposing a definition in this rulemaking.
    In enacting the IRA, Congress recognized that different methods of 
hydrogen production generate different amounts of GHG emissions and 
sought to encourage lower-emitting production methods through the 
multi-tier hydrogen production tax credit (IRC section 45V). The IRC 
section 45V tax credits provide four tiers of tax credits, and thus 
award the highest amount of tax credits to the hydrogen production 
processes with the lowest estimated GHG emissions. The highest tier of 
the credits is $3/kg H2 for 0.0 to 0.45 kg CO2e/
kg H2 produced, and the lowest is $0.6/kg H2 for 
2.5 to 4.0 kg CO2e/kg H2.\422\ Congress also 
provided a definition of ``clean hydrogen'' in section 822 of the IIJA. 
This provision sets out a non-binding goal intended for use in 
development of the DOE's Clean Hydrogen Production Standard (CHPS) and 
DOE's funding programs to promote promising new hydrogen technologies.
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    \422\ These amounts assume that wage and apprenticeship 
requirements are met.
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    Several Federal agencies are engaging in low-GHG hydrogen-related 
efforts, some of which implement the IRA and IIJA provisions. As 
discussed earlier in this section, the DOE is working on a Clean 
Hydrogen Production Standard,\423\ an $8 billion Clean Hydrogen Hub 
solicitation,\424\ and several hydrogen-related research and 
development grant programs.\425\ The Department of the Treasury is 
taking public comment on examining appropriate parameters for 
evaluating overall emissions associated with hydrogen production 
pathways as it prepares to implement IRC section 45V.\426\ Within the 
EPA, there are rulemaking efforts that could impact low-GHG hydrogen 
production pathways, namely the proposed and supplemental oil and gas 
emission guidelines to reduce methane emissions.
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    \423\ U.S. Department of Energy (DOE). (September 22, 2022). 
Clean Hydrogen Production Standard. Hydrogen and Fuel Cell 
Technologies Office. https://www.energy.gov/eere/fuelcells/articles/clean-hydrogen-production-standard.
    \424\ https://www.energy.gov/oced/regional-clean-hydrogen-hubs.
    \425\ https://www.hydrogen.energy.gov/funding_opportunities.html.
    \426\ https://home.treasury.gov/news/press-releases/jy0993.
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    The IIJA includes both a textual definition of ``clean hydrogen'' 
and requires the DOE to develop a Clean Hydrogen Production Standard: 
these two references are related but distinct. Upon review of the 
reference points that these legislative provisions and Agency programs 
provide, it is apparent that the clean hydrogen definition in section 
822 of the IIJA is not appropriate for the purposes of this rule. As 
noted, this provision sets a non-binding goal for use in the 
development of the DOE's Clean Hydrogen Production Standard (CHPS) and 
the DOE's funding programs to promote promising new hydrogen 
technologies. The definition of clean hydrogen in the IIJA is limited 
to GHGs emitted at the hydrogen production site and is therefore not 
intended to consider overall GHG emissions associated with that 
production method. According to the IIJA, clean hydrogen as defined as 
part of the CHPS is ``. . . hydrogen produced with a carbon intensity 
equal to or less than 2 kilograms of carbon dioxide-equivalent produced 
at the site of production per kilogram of hydrogen produced'' (emphasis 
added). A significant portion of the GHG emissions associated with 
hydrogen derived from natural gas originates from upstream methane 
emissions, which are not accounted for in the CHPS definition.\427\ 
That definition was taken into consideration, along with multiple other 
data points, for development of the CHPS. In CHPS draft guidance, a 
target of 4 kg CO2e/kg H2 on a well-to-gate 
basis, which aligns with full range of the IRC section 45V definition 
in the IRA.\428\
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    \427\ Infrastructure Investment and Jobs Act of 20211Law 
PUBL058.PS (https://www.congress.gov).
    \428\ U.S. Department of Energy Clean Hydrogen Production 
Standard (CHPS) Draft Guidance
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    In contrast, the EPA believes that the highest tier of the IRC 
section 45V(b)(2) production tax credit is salient for purposes of the 
present rule. That provision provides the highest available amount of 
production tax credit for hydrogen produced through a process that has 
a GHG emissions rate of 0.45 kg CO2e/kg H2 or 
less, from well-to-gate. As explained further below, the EPA proposes 
that co-firing hydrogen that meets this criterion qualifies as a 
component of the ``best'' system of emission reduction, taking into 
account the statutory considerations. Thus, consistent with the tiered 
approach and system boundaries in the IRA definition of clean hydrogen, 
the EPA is proposing that low-GHG hydrogen is hydrogen that is produced 
through a process that has a GHG emissions rate of 0.45 kg 
CO2e/kg H2 or less, from well-to-gate. Each of 
the subsequent hydrogen production categories outlined in 45V(b)(2) 
convey increasingly higher amounts of GHG emissions (from a well-to-
gate analysis), making them less suitable to be a component of the 
BSER.
    Electrolyzers with various low-GHG energy inputs, like solar, wind, 
hydroelectric, and nuclear, appear most likely to produce hydrogen that 
would meet the 0.45 kg CO2e/kg H2 or less, from 
well-to-gate criteria.\429\ Hydrogen production pathways using methane 
as a feedstock induce upstream methane emissions associated with 
extraction, production, and transport of the methane. SMR and ATR also 
release heating and process-related CO2 emissions that are 
difficult to capture at high rates economically. High contributions to 
overall GHG emission rates may disqualify certain hydrogen production 
pathways from producing low-GHG hydrogen. The EPA recognizes that the 
pace and scale of government programs and private research suggest that 
we will gain significant experience and knowledge on this topic during 
the timeframe of this proposed rulemaking. Accordingly, the EPA is 
soliciting comment broadly on its proposed definition for low-GHG 
hydrogen, and on alternative approaches, to ensure that co-firing low-
GHG hydrogen minimizes GHG emissions, and that combustion turbines 
subject to this standard utilize only low-GHG hydrogen.
---------------------------------------------------------------------------

    \429\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
---------------------------------------------------------------------------

    The EPA is also taking comment on whether it is necessary to 
provide a definition of low-GHG hydrogen in this rule. Given the 
incentives provided in both the IRA and IIJA for low-GHG hydrogen 
production and the current trajectory of hydrogen use in the power 
sector, by 2032, the start date for compliance with the proposed second 
phase of the standards for this rule, low-GHG hydrogen may be the most 
common source of hydrogen available for electricity production. For the 
most part, companies that have announced that they are exploring the 
use of hydrogen co-firing have stated that they intend to use low-GHG 
hydrogen. These power suppliers include NextEra, Los Angeles Department 
of Power and Water, and New York Power Authority, as discussed earlier 
in this section. Many utilities and merchant generators own nuclear, 
wind, solar, and hydroelectric generating sources as well as combustion 
turbines. The EPA has identified an emerging trend in which energy 
companies with this broad collection of generation assets are planning 
to produce low-GHG hydrogen for sale and to use a portion of it to fuel 
their stationary combustion turbines. This emerging trend lends support 
to the view that the power sector is likely

[[Page 33311]]

to have access to and will choose to utilize low-GHG hydrogen for its 
co-firing applications. Some NGOs have expressed concern that existing 
non-emitting assets will channel electricity from the grid toward 
electrolyzers, potentially increasing marginal electricity generation 
from assets with higher carbon intensities. The EPA agrees these are 
important issues that should be considered as levels of excess zero 
carbon-emitting generation vary diurnally and by region. The EPA notes 
that these concerns should mitigate over time as the carbon intensity 
of the grid is projected to decline.
    Moreover, by the next decade, costs for low-GHG hydrogen are 
expected to be competitive with higher-GHG forms of hydrogen given 
declines due to learning and the IRC section 45V subsidies. Given the 
tax credits in IRC section 45V(b)(2)(D) of $3/kg H2 for 
hydrogen with GHG emissions of less than 0.45 kg CO2e/kg 
H2, and substantial DOE grant programs to drive down costs 
of clean hydrogen, some entities project the delivered costs of 
electrolytic low-GHG hydrogen to range from $1/kg H2 to $0/
kg H2 or less.430 431 432 These projections are 
more optimistic than, but still comparable to, DOE projections of 2030 
for delivered costs of electrolytic low-GHG hydrogen in the range of 
$0.70/kg to $1.15/kg for power sector applications, given R&D 
advancements and economies of scale.\433\ A growing number of studies 
are demonstrating more efficient and less expensive techniques to 
produce low-GHG electrolytic hydrogen; and, tax credits and market 
forces are expected to accelerate innovation and drive down costs even 
further over the next decade.434 435 436 The combination of 
competitive pricing and widespread net-zero commitments throughout the 
utility and merchant electricity generation market has the potential to 
drive future hydrogen co-firing applications to be low-GHG 
hydrogen.\437\ The EPA is therefore soliciting comment on whether low-
GHG hydrogen needs to be defined as part of the BSER in this proposed 
rulemaking.
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    \430\ ``US green hydrogen costs to reach sub-zero under IRA: 
longer-term price impacts remain uncertain,'' S&P Global Commodity 
Insights, September 29, 2022.
    \431\ ``DOE Funding Opportunity Targets Clean Hydrogen 
Technologies'' American Public Power, January 31, 2023.
    \432\ With the 45V PTC, delivered costs of hydrogen are 
projected to fall in the range of $0.70/kg to $1.15/kg for power 
sector applications.
    \433\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
    \434\ ``Sound waves boost green hydrogen production,'' Power 
Engineering, January 4, 2023.
    \435\ ``Direct seawater electrolysis by adjusting the local 
reaction environment of a catalyst,'' Nature Energy, January 30, 
2023.
    \436\ https://h2new.energy.gov/.
    \437\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
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vii. Justification for Proposing 30 Percent Co-Firing Low-GHG Hydrogen 
and 96 Percent Co-Firing Low-GHG Hydrogen as Components of the BSER
    The EPA is proposing that co-firing 30 percent low-GHG hydrogen, as 
proposed to be defined above, by new combustion turbines in the 
relevant subcategories, by 2032, meets the requirements under CAA 
section 111(a)(1) to qualify as a component of the BSER. Similarly, the 
EPA is proposing that co-firing 96 percent low-GHG hydrogen by new base 
load combustion turbines in the relevant subcategory, by 2038, also 
meets the requirements under CAA section 111(a)(1) to qualify as a 
component of the BSER. As discussed below, co-firing 30 percent low-GHG 
hydrogen is adequately demonstrated because it is feasible and well-
demonstrated for new combustion turbines to co-fire that percentage of 
hydrogen and multiple combustion turbine vendors have targets to have 
100 percent hydrogen-capable combustion turbines available by around 
2030 and are selling combustion turbines today with the intention of 
those combustion turbines being retrofittable to 100 percent hydrogen 
firing.438 439 Several project developers have announced 
plans to transition from lower levels of co-firing up to firing with 
100 percent hydrogen.
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    \438\ https://www.powermag.com/first-hydrogen-burn-at-long-ridge-ha-class-gas-turbine-marks-triumph-for-ge/.
    \439\ https://www.doosan.com/en/media-center/press-release_view?id=20172449.
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    The EPA proposes that co-firing 30 percent low-GHG hydrogen by 2032 
and 96 percent by 2038 qualify as a BSER pathway for new baseload 
combustion turbines. For the reasons discussed next, the EPA proposes 
that co-firing low-GHG hydrogen on that pathway is adequately 
demonstrated in light of the capability of combustion turbines to co-
fire hydrogen and the EPA's reasonable expectation that adequate 
quantities of low-GHG hydrogen will be available by 2032 and 2038 and 
at reasonable cost. Moreover, combusting hydrogen will achieve 
reductions because it does not produce GHG emissions and will not have 
adverse non-air quality health or environmental impacts or energy 
requirements, including on the nationwide energy sector. Because the 
production of low-GHG hydrogen generates the fewest GHG emissions, the 
EPA proposes that co-firing low-GHG hydrogen, and not other types of 
hydrogen, qualifies as the ``best'' system of emission reduction. The 
fact that co-firing low GHG hydrogen creates market demand for, and 
advances the development of, low-GHG hydrogen, a fuel that is useful 
for reducing emissions in the power sector and other industries, 
provides further support for this proposal.
(A) Adequately Demonstrated
    As part of the present rulemaking, the EPA evaluated the ability of 
new combustion turbines to operate with certain percentages (by volume) 
of hydrogen blended into their fuel systems. This evaluation included 
an analysis of the technical challenges of co-firing hydrogen in a 
combustion turbine EGU to generate electricity. The EPA also evaluated 
available information to determine if adequate quantities of low-GHG 
hydrogen can be reasonably expected to be available for combustion 
turbine EGUs by 2032.
    Although industrial combustion turbines have been burning byproduct 
fuels containing large percentages of hydrogen for decades, utility 
combustion turbines have only recently begun to co-fire smaller amounts 
of hydrogen as a fuel to generate electricity. The primary technical 
challenges of hydrogen co-firing are related to certain physical 
characteristics of the gas. When hydrogen fuel is combusted, it 
produces a higher flame speed than the flame speed produced with the 
combustion of natural gas; and hydrogen typically combusts at a faster 
rate than natural gas. When the combustion speed is faster than the 
flow rate of the fuel, a phenomenon known as ``flashback'' can occur, 
which can lead to upstream complications.\440\ Hydrogen also has a 
higher flame temperature and a wider flammability range compared to 
natural gas.\441\
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    \440\ Inoue, K., Miyamoto, K., Domen, S., Tamura, I., Kawakami, 
T., & Tanimura, S. (2018). Development of Hydrogen and Natural Gas 
Co-firing Gas Turbine. Mitsubishi Heavy Industries Technical Review. 
Volume 55, No. 2. June 2018.https://power.mhi.com/randd/technical-review/pdf/index_66e.pdf.
    \441\ Andersson, M., Larfeldt, J., Larsson, A. (2013). Co-firing 
with hydrogen in industrial gas turbines. http://sgc.camero.se/ckfinder/userfiles/files/SGC256(1).pdf.
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    The industrial combustion turbines currently burning hydrogen are 
smaller than the larger utility combustion turbines and use diffusion 
flame combustion, often in combination with water injection, for 
NOX control. While

[[Page 33312]]

water injection requires demineralized water and is generally only a 
NOX control option for simple cycle turbines, existing 
simple cycle combustion turbines have successfully demonstrated that 
relatively high levels of hydrogen can be co-fired in combustion 
turbines using diffusion flame and supports the EPA's proposal to 
determine that co-firing 30 percent hydrogen is technically feasible 
for new base load and intermediate load stationary combustion turbine 
EGUs by 2032 and that co-firing higher levels--up to 96 percent by 
volume--is feasible by 2038. The EPA solicits comment on these proposed 
findings.
    The more commonly used NOX combustion control for base 
load combined cycle turbines is dry low NOX (DLN) 
combustion. Even though the ability to co-fire hydrogen in combustion 
turbines that are using DLN combustors to reduce emissions of 
NOX is currently more limited, all major combustion turbine 
manufacturers have developed DLN combustors for utility EGUs that can 
co-fire hydrogen.\442\ Moreover, the major combustion turbine 
manufacturers are designing combustion turbines that will be capable of 
combusting 100 percent hydrogen by 2030, with DLN designs that assure 
acceptable levels of NOX emissions.443 444 
Several developers have announced installations with plans to initially 
co-fire lower percentages of low-GHG hydrogen by volume before 
gradually increasing their co-firing percentages--to as high as 100 
percent in some cases--depending on the pace of the anticipated 
expansion of low-GHG hydrogen production processes and associated 
infrastructure. The goals of equipment manufacturers and the fact that 
existing combined cycle combustion turbines have successfully 
demonstrated the ability to co-fire various percentages of hydrogen 
supports the EPA's proposal to determine that co-firing 30 percent 
hydrogen is technically feasible for new base load stationary 
combustion turbine EGUs by 2032 and that co-firing 96 percent hydrogen 
is technically feasible for new base load stationary combustion turbine 
EGUs by 2038.
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    \442\ Siemens Energy (2021). Overcoming technical challenges of 
hydrogen power plants for the energy transition. NS Energy. https://www.nsenergybusiness.com/news/overcoming-technical-challenges-of-hydrogen-power-plants-for-energy-transition/.
    \443\ Simon, F. (2021). GE eyes 100% hydrogen-fueled power 
plants by 2030. https://www.euractiv.com/section/energy/news/ge-eyes-100-hydrogen-fuelled-power-plants-by-2030/.
    \444\ Patel, S. (2020). Siemens' Roadmap to 100% Hydrogen Gas 
Turbines. https://www.powermag.com/siemens-roadmap-to-100-hydrogen-gas-turbines/.
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    The combustion characteristics of hydrogen can lead to localized 
higher temperatures during the combustion process. These ``hotspots'' 
can increase emissions of the criteria pollutant NOX.\445\ 
NOX emissions resulting from the combustion of high 
percentage by volume blends of hydrogen are also of concern in many 
regions of the country. For turbines using diffusion flame combustion, 
water or steam injection is used to control emissions of 
NOX. The level of water injection can be varied for 
different levels of NOX control and adjustments can be made 
to address any potential increases in NOX that would occur 
from co-firing hydrogen in combustion turbines using diffusion flame 
combustion. As stated previously, all major combustion turbine 
manufacturers have developed DLN combustors for utility EGUs that can 
co-fire hydrogen and are designing combustion turbines that will be 
capable of combusting 100 percent hydrogen by 2030, with DLN designs 
that assure acceptable levels of NOX emissions. In addition, 
EGR in diffusion flame combustion turbines reduces the oxygen 
concentration in the combustor and limits combustion temperatures and 
NOX formation. Furthermore, while combustion controls can 
achieve low levels of NOX, many new intermediate load and 
base load combustion turbines using DLN combustion also use selective 
catalytic reduction (SCR) to reduce NOX emissions even 
further. The design level of control from SCR can be tied to the 
exhaust gas concentration. At higher levels of incoming NOX, 
either the reagent injection rate can be increased and/or the size of 
the catalyst bed can be increased.\446\ The EPA has concluded that any 
potential increases in NOX emissions do not change the 
Agency's view that on balance, co-firing low-GHG hydrogen qualifies as 
a component of the BSER.
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    \445\ Guarco, J., Langstine, B., Turner, M. (2018). Practical 
Consideration for Firing Hydrogen Versus Natural Gas. Combustion 
Engineering Association. https://cea.org.uk/practical-considerations-for-firing-hydrogen-versus-natural-gas/.
    \446\ Siemens Energy (2021). Overcoming technical challenges of 
hydrogen power plants for the energy transition. NS Energy. https://www.nsenergybusiness.com/news/overcoming-technical-challenges-of-hydrogen-power-plants-for-energy-transition/.
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    As noted above, at present, most of the hydrogen produced in the 
U.S. is produced for the industrial sector through SMR, which is a high 
GHG-emitting process. Limited quantities of hydrogen are currently 
being produced via SMR with CCS, which reduces some, but not all, of 
the associated GHG-emitting processes. Only small-scale facilities are 
currently producing hydrogen through electrolysis with renewable or 
nuclear energy, and as described below, much larger facilities are 
under development.
    However, as also noted above, incentives in recent Federal 
legislation are anticipated to significantly increase the availability 
of low-GHG hydrogen by 2032, including for the utility power sector. 
The IIJA, enacted in 2021, allocated more than $9 billion to the DOE 
for research, development, and demonstration of low-GHG hydrogen 
technologies and the creation of at least four regional low-GHG 
hydrogen hubs. The DOE has indicated its intention to fund between six 
and 10 hubs.\447\ In addition, the IRA provided significant incentives 
to invest in low-GHG hydrogen production (For additional discussion of 
the IIJA and/or IRA, see section IV.E of this preamble.)
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    \447\ IIJA authorized a total of $9.5B for hydrogen related 
programs ($8 billion for Clean Hydrogen Hubs H2Hubs, $1B for 
electrolyzer research and development and $500 million for hydrogen-
related manufacturing incentives). See also: U.S. Dept. of Energy, 
Regional Clean Hydrogen Hubs. https://www.energy.gov/oced/regional-clean-hydrogen-hubs.
---------------------------------------------------------------------------

    Programs from the IIJA and IRA have been successful in prompting 
the development of new low-GHG hydrogen projects and infrastructure. As 
of August 2022, 374 new projects had been announced that would produce 
2.2 megatons (Mt) of low-GHG hydrogen annually, which represents a 21 
percent increase over current output.\448\ Examples include:
---------------------------------------------------------------------------

    \448\ Energy Futures Initiative (February 2023). U.S. Hydrogen 
Demand Action Plan. https://energyfuturesinitiative.org/reports/.
---------------------------------------------------------------------------

     In June 2022, the DOE issued a $504.4 million loan 
guarantee to finance Advanced Clean Energy Storage (ACES), a low-GHG 
hydrogen production and long-term storage facility in Delta, Utah.\449\ 
The facility will use 220 MW of electrolyzers powered by renewable 
energy to produce low-GHG hydrogen. The hydrogen will be stored in salt 
caverns and serve as a long-term fuel supply for the combustion turbine 
at the Intermountain Power Agency (IPA) project, which is described 
earlier in this section.
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    \449\ U.S. Department of Energy (DOE). (2022). Loan Office 
Programs. Advanced Clean Energy Storage. https://www.energy.gov/lpo/advanced-clean-energy-storage.
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     In January 2023, NextEra announced an 800-MW solar project 
in the central U.S. to support the development of low-GHG hydrogen as 
well as plans to produce its own low-

[[Page 33313]]

GHG hydrogen at a facility in Arizona.\450\
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    \450\ Penrod, Emma. (January 30, 2023). NextEra charts path for 
renewables expansion, but campaign finance allegations loom in the 
background. Utility Dive. https://www.utilitydive.com/news/nextera-renewables-expansion-green-hydrogen-solar-alleged-campaign-finance-violation/641475/.
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     In New York, Constellation (formerly Exelon Generation) is 
exploring the potential benefits of integrating onsite low-GHG hydrogen 
production, storage, and usage at its Nine Mile Point nuclear station. 
The project is funded by a DOE grant and includes partners such as Nel 
Hydrogen, Argonne National Laboratory, Idaho National Laboratory, and 
the National Renewable Energy Laboratory. The project is expected to 
generate an economical supply of low-GHG hydrogen that will be safely 
captured, stored, and potentially taken to market as a source of power 
for other purposes, including industrial applications such as 
transportation.\451\
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    \451\ https://www.exeloncorp.com/newsroom/Pages/DOE-Grant-to-Support-Hydrogen-Production-Project-at-Nine-Mile-Point.aspx.
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     Bloom Energy began installation of a 240-kW electrolyzer 
at Xcel Energy's Prairie Island nuclear plant in Minnesota in September 
2022 to produce low-GHG hydrogen. The demonstration project, designed 
to create ``immediate and scalable pathways'' for producing cost-
effective hydrogen, is expected to be operational in 2024 and is also 
funded with a DOE grant.\452\
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    \452\ https://www.utilitydive.com/news/bloom-energy-hydrogen-xcel-nuclear-prairie-island/632148/.
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     In California, Sempra subsidiary SoCalGas has announced 
plans to develop the nation's largest hydrogen infrastructure system 
called ``Angeles Link.'' When operational, the project will provide 
enough hydrogen to convert up to four natural gas-fired power plants. 
Developers predict the increased access to hydrogen will also displace 
3 million gallons of diesel fuel from heavy-duty 
trucks.453 454
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    \453\ https://www.socalgas.com/sustainability/hydrogen/angeles-link.
    \454\ Penrod, Emma. (February 18, 2022). SoCalGas begins 
developing 100% clean hydrogen pipeline system. Utility Dive. 
https://www.utilitydive.com/news/socalgas-begins-developing-100-clean-hydrogen-pipeline-system/619170/.
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     In December 2022, Air Products and AES announced plans to 
build a $4-billion low-GHG hydrogen production facility at the site of 
a former coal-fired power plant in Texas.455 456 The plant 
is expected to be completed in 2027, and once operational, will produce 
approximately 200 metric tons of low-GHG hydrogen per day from 
electrolyzers powered by 1.4 GW of wind and solar energy, as noted 
earlier. This follows an announcement by Air Products in October 2022 
to invest $500 million in a low-GHG hydrogen production facility in New 
York. This 35 metric-ton-per-day project is also expected to be 
operational by 2027, and in July 2022, received approval from the New 
York Power Authority for 94 MW of hydroelectric power.\457\
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    \455\ McCoy, Michael. (December 8, 2022). Air Products plans big 
green hydrogen plant in U.S. Chemical and Engineering News. https://cen.acs.org/energy/hydrogen-power/Air-Products-plans-big-green/100/web/2022/12.
    \456\ Air Products (December 8, 2022). Air Products and AES 
Announce Plans to Invest Approximately $4 Billion to Build First 
Mega-scale Green Hydrogen Production Facility in Texas. https://www.airproducts.com/news-center/2022/12/1208-air-products-and-aes-to-invest-to-build-first-mega-scale-green-hydrogen-facility-in-texas/.
    \457\ Air Products (October 6, 2022). Air Products to Invest 
About $500 Million to Build Green Hydrogen Production Facility in 
New York. https://www.airproducts.com/news-center/2022/10/1006-air-products-to-build-green-hydrogen-production-facility-in-new-york.
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     The DOE National Clean Hydrogen Strategy and Roadmap 
identified a plausible path forward for the production of 10 MMT of 
low-GHG hydrogen annually by 2030, 20 MMT annually by 2040, and 50 MMT 
annually by 2050.
     The NREL Clean Grid 2035 analysis examined several 
pathways for the power sector to reach net-zero emissions by 2035: each 
of those pathways included at least 10 MMT of electrolytic hydrogen by 
2035, demonstrating how electrolytic hydrogen technologies support 
rapid grid decarbonization.\458\
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    \458\ Denholm, Paul, Patrick Brown, Wesley Cole, et al. 2022. 
Examining Supply-Side Options to Achieve 100% Clean Electricity by 
2035. Golden, CO: National Renewable Energy Laboratory NREL/
TP[1]6A40-81644. https://www.nrel.gov/docs/fy22osti/81644.pdf.
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     The H2@Scale is a DOE initiative that brings together 
stakeholders to advance affordable hydrogen production, transport, 
storage, and utilization to enable decarbonization and revenue 
opportunities across multiple sectors.
    These legislative actions, utility initiatives, and industrial 
sector production and infrastructure projects indicate that sufficient 
low-GHG hydrogen and sufficient distribution infrastructure can 
reasonably be expected to be available by 2032, when offtake scales 
after 2030,\459\ so that, at a minimum, the majority of new combustion 
turbines could co-fire low-GHG hydrogen. The EPA specifically solicits 
comment on whether rural areas and small utility distribution systems 
(serving 50,000 customers or less) can expect to have access to low-GHG 
hydrogen. To the extent low-GHG hydrogen might be less available in 
rural areas compared to areas with higher population densities, the EPA 
solicits comment if sufficient electric transmission capacity is 
available, or could be constructed, such that electricity generated 
from low-GHG hydrogen could be transmitted to these rural areas.
---------------------------------------------------------------------------

    \459\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
---------------------------------------------------------------------------

    By 2035, substantial additional amounts of renewable energy are 
expected to be available, which can support the production of low-GHG 
hydrogen through electrolysis.
(B) Costs
    There are three sets of potential costs associated with co-firing 
hydrogen in combustion turbines: (1) The capital costs of combustion 
turbines that have the capability of co-firing hydrogen; (2) pipeline 
infrastructure to deliver hydrogen; and (3) the fuel costs related to 
production of low-GHG hydrogen.
    As stated previously, manufacturers are already developing 
combustion turbines that can co-fire up to 100 percent hydrogen. 
Accordingly, this limits the amount of additional costs needed to allow 
combustion turbines to co-fire 30 percent (by volume) hydrogen and, 
later, 96 percent (by volume). According to data from EPRI's US-REGEN 
model, the heat rate of a hydrogen-fired combustion turbine model plant 
is 5 percent higher and the capital, fixed, and non-fuel variable costs 
are 10 percent higher than a natural gas-fired combustion turbine.\460\ 
However, the EPA is soliciting comment on what additional costs would 
be required to ensure that combustion turbines are able to co-fire 
between 30 to 96 percent (by volume) hydrogen and if there are 
efficiency impacts from co-firing hydrogen.
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    \460\ https://us-regen-docs.epri.com/v2021a/assumptions/electricity-generation.html#new-generation-capacity.
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    With respect to pipeline infrastructure, there are approximately 
1,600 miles of dedicated hydrogen pipelines currently operating in the 
U.S. Existing natural gas infrastructure may be capable of accepting 
blends of hydrogen with modest investments, but the actual limits will 
vary depending on pipeline materials, age, and operating conditions. 
Due to the lower energy density of hydrogen relative to natural gas, 
the piping required to deliver pure hydrogen would have to be larger, 
and the material used to construct the piping could need to be 
specifically designed

[[Page 33314]]

to be able to handle higher concentrations of hydrogen that would 
prevent embrittlement and leaks. These risks can be mitigated through 
deployment of new pipeline infrastructure designed for compatibility 
with hydrogen in support of a new combustion turbine installation. The 
majority of announced combustion turbine EGU projects proposing to co-
fire hydrogen are located close to the source of hydrogen. Therefore, 
the fuel delivery systems (i.e., pipes) for new combustion turbines can 
be designed to transport hydrogen without additional costs. Therefore, 
the EPA proposes that co-firing rates of 30 percent and up to 100 
percent by volume would have limited, if any, additional capital costs 
for new combustion turbine EGU projects. The EPA is soliciting comment 
on if additional infrastructure costs, such as bulk hydrogen storage in 
salt caverns, should be accounted for when determining the costs of 
hydrogen co-firing.
    The primary cost for co-firing hydrogen is the cost of hydrogen 
relative to natural gas. The cost of delivered hydrogen depends on the 
technology used to produce the hydrogen and the cost to transport the 
hydrogen to the end user. For context, the DOE National Clean Hydrogen 
Strategy and Roadmap cites the current cost of low-GHG electrolytic 
hydrogen production at approximately $5/kg. The DOE has established a 
goal of reducing the cost of low-GHG hydrogen production to $1/kg 
(equivalent to $7.4/MMBtu) by 2030, which is approximately the same as 
the current production costs of hydrogen from SMR. Using $1/kg 
(equivalent to $7.4/MMBtu) as the delivered cost of low-GHG hydrogen, 
co-firing 30 percent (by volume) hydrogen in a combined cycle EGU 
operating at a capacity factor of 65 percent would increase both the 
levelized cost of electricity (LCOE) by $2.9/MWh.\461\ This is a 6 
percent increase from the baseline LCOE. A 96 percent (by volume) co-
firing rate increases the LCOE by $21/MWh, a 47 percent increase in the 
baseline LCOE. Regardless of the level of hydrogen co-firing, the 
CO2 abatement cost is $64/ton ($70/metric ton) at the 
affected facility.\462\ For an aeroderivative simple cycle combustion 
turbine operating at a capacity factor of 40 percent, co-firing 30 
percent hydrogen increases the LCOE by $4.1/MWh, representing a 5 
percent increase from the baseline LCOE. A 96 percent (by volume) co-
firing rate increases the LCOE by $30/MWh, a 31 percent increase in the 
baseline LCOE.
---------------------------------------------------------------------------

    \461\ The EIA long-term natural gas price for utilities is 
$3.69/MMBtu.
    \462\ The abatement cost of co-firing low-GHG hydrogen is 
determined by the relative delivered cost of the low-GHG hydrogen 
and natural gas.
---------------------------------------------------------------------------

    However, DOE's projected goal of $1/kg production costs (equivalent 
to $7.4/MMBtu) for low-GHG hydrogen was established prior to the IIJA 
incentives and IRA tax subsidies for low-GHG hydrogen production, CCS, 
and generation from renewable sources. These subsidies could be 
equivalent to, or even exceed, the production costs of low-GHG 
hydrogen. Even when the cost to transport the hydrogen from the 
production facility to the end user is accounted for, the cost of low-
GHG hydrogen to the end user could be less than $1/kg. Assuming a 
delivered price of $0.75/kg ($5.6/MMBtu), the CO2 abatement 
costs for co-firing hydrogen would be $32/ton ($35/metric ton). For a 
combined cycle EGU, the LCOE increase would be $1.4/MWh and $11/MWh for 
the 30 percent and 96 percent (by volume) cases, respectively. For a 
simple cycle EGU, the LCOE would be $2.1/MWh and $15/MWh for the 30 
percent and 96 percent (by volume) cases, respectively. If the 
delivered cost of low-GHG hydrogen is $0.50/kg ($3.7/MMBtu), this would 
represent cost parity with natural gas and abatement costs would be 
zero.
    The EPA is proposing to determine that the increase in operating 
costs from a BSER based on low-GHG hydrogen is reasonable.
(C) Non-Air Quality Health and Environmental Impact and Energy 
Requirements
    The co-firing of hydrogen in combustion turbines in the amounts 
that the EPA proposes as the BSER would not have adverse non-air 
quality health and environmental impacts. It would result in 
NOX emissions, but those emissions can be controlled, as 
described in section VII.F.3.c.vii.(A) of this preamble.
    In addition, co-firing hydrogen in the amounts proposed would not 
have adverse impacts on energy requirements, including either the 
requirements of the combustion turbines to obtain fuel or on the energy 
sector more broadly, particularly with respect to reliability. As 
discussed in sections VII.F.3.c.vii.(A)-(B), combustion turbines can be 
constructed to co-fire high volumes of hydrogen in lieu of natural gas, 
and the EPA expects that low-GHG hydrogen will be available in 
sufficient quantities and at reasonable cost. Any impact on the energy 
sector would be further mitigated by the large amounts of existing 
generation that would not be subject to requirements in this rule and 
the projected new capacity in the base case modeling.
(D) Extent of Reductions in CO2 Emissions
    The site-specific reduction in CO2 emissions achieved by 
a combustion turbine co-firing hydrogen is dependent on the volume of 
hydrogen blended into the fuel system. Due to the lower energy density 
by volume of hydrogen compared to natural gas, an affected source that 
combusts 30 percent by volume hydrogen with natural gas would achieve 
approximately a 12 percent reduction in CO2 emissions versus 
firing 100 percent natural gas.\463\ A source combusting 100 percent 
hydrogen would have zero CO2 stack emissions because 
hydrogen contains no carbon, as previously discussed. A source co-
firing 96 percent by volume hydrogen (approximately 89 percent by heat 
input) would achieve an approximate 90 percent CO2 emission 
reduction, which is roughly equivalent to the emission reduction 
achieved by sources utilizing 90 percent CCS.
---------------------------------------------------------------------------

    \463\ The energy density by volume of hydrogen is lower than 
natural gas.
---------------------------------------------------------------------------

(E) Promotion of the Development and Implementation of Technology
    Determining co-firing 30 percent (by volume) low-GHG hydrogen by 
2032 and co-firing 96 percent (by volume) to be components of the BSER 
would generally advance technology development in both the production 
of low-GHG hydrogen and the use of hydrogen in combustion turbines. 
This would facilitate co-firing larger amounts of low-GHG hydrogen and 
facilitate co-firing low-GHG hydrogen in existing combustion turbines. 
Developing new configurations for flame dimensions and turbine 
modifications to adjust for the characteristics unique to hydrogen 
combustion are technology forcing advancements that industry appears to 
be already leaning into based on the project announcements. Thus, co-
firing low-GHG hydrogen fulfills the requirements of BSER to generally 
advance technology development. In addition, co-firing 30 percent (by 
volume) low-GHG hydrogen by 2032 would promote additional technology 
development and infrastructure to facilitate co-firing at higher 
amounts of low-GHG hydrogen in 2038. As discussed in the preceding 
section, there are multiple combustion turbine projects planned by 
industry to co-fire hydrogen initially and progress to firing with 100 
percent hydrogen. Fueling combustion turbines with 100 percent hydrogen 
would eliminate all carbon

[[Page 33315]]

dioxide stack emissions. It would also promote reliability because it 
would provide grid operators with asset options, in addition to battery 
and energy storage, capable of voltage support and frequency 
regulation. These are asset characteristics that will be required in 
increasing capacities as more variable generation is deployed.
(F) Basis for Proposing Co-Firing Low-GHG Hydrogen, Not Other Types of 
Hydrogen, as the ``Best'' System of Emissions Reduction
    In this section, the EPA explains further why the type of hydrogen 
co-fired as a component of the BSER must be limited to low-GHG 
hydrogen, and not include other types of hydrogen. The EPA explains 
further the proposed definition of low-GHG hydrogen as 0.45 kg 
CO2e/kg H2 or less from the production of 
hydrogen, from well-to-gate. Finally, the Agency summarizes the 
reasons, described above, for the proposal that co-firing 30 percent 
low-GHG hydrogen meets the criteria under CAA section 111 as the BSER.
(1) Limitation of Co-Firing to Low-GHG Hydrogen
    Hydrogen is a zero-GHG emitting fuel when combusted, so that co-
firing it in a combustion turbine in place of natural gas reduces GHG 
emissions at the stack. Co-firing low-emitting fuels--sometimes 
referred to as clean fuels--is a traditional type of emissions control, 
and recognized as a system of emission reduction under CAA section 111. 
In West Virginia v. EPA, the Supreme Court noted that in the EPA's 
prior CAA section 111 actions, the Agency has treated ``measures that 
improve the pollution performance of individual sources'' as 
``system[s] of emission reduction,'' 142 S. Ct. at 2615,\464\ and 
further noted with approval a statement the EPA made in the Clean Power 
Plan that ``fuel-switching'' was one of the ``more traditional air 
pollution control measures.'' 142 S. Ct. at 2611 (quoting 80 FR 64784; 
October 23, 2015). The EPA has relied on lower-emitting fuels as the 
BSER in several CAA section 111 rules. See 44 FR 33580, 33593 (June 11, 
1979) (coal that undergoes washing prior to its combustion to remove 
sulfur, so that its combustion emits fewer SO2 emissions); 
72 FR 32742 (June 13, 2007) (same); 80 FR 64510 (October 23, 2015) 
(natural gas and clean fuel oil). Co-firing hydrogen in a combustion 
turbine in place of natural gas reduces GHG emissions at the source and 
therefore plainly qualifies as a ``system of emission reduction.'' This 
is true even if that phrase is narrowly defined to be limited to 
controls measures that can be applied at and to the source and that 
reduce emissions from the source, as the ACE Rule provided, or if it is 
defined more broadly.\465\
---------------------------------------------------------------------------

    \464\ As discussed in section V.B.4 of this preamble, the ACE 
Rule took the position that under CAA section 111(a)(1), a ``system 
of emission reduction'' must be limited to measures that apply at or 
to the source. 84 FR 32524 (July 8, 2019).
    \465\ Co-firing hydrogen in place of fossil fuel (generally, 
natural gas in a combustion turbine) may be contrasted with co-
firing biomass in place of fossil fuel (generally, coal in a steam 
generating unit). The ACE Rule rejected co-firing biomass as a 
potential BSER for existing coal-fired steam generating units. The 
rule explained that co-firing biomass does not meet the definition 
of a ``system of emission reduction,'' under the ACE Rule's 
interpretation of that term, because co-firing biomass in place of 
coal at a steam generating unit does not reduce emissions emitted 
from that source; rather, any emission reductions rely on accounting 
for activities that occur upstream. 84 FR 32546 (July 8, 2019). In 
contrast, as discussed in the accompanying text, co-firing hydrogen 
in place of natural gas at a combustion turbine achieves emission 
reductions at the source. For that reason, co-firing hydrogen 
qualifies as a ``system of emission reduction,'' even as the ACE 
Rule defined the term. As noted in section V.C.3.a of this preamble, 
the EPA has proposed to reject that definition as too narrow.
---------------------------------------------------------------------------

    In the present proposal, the EPA recognizes that even though the 
combustion of hydrogen is zero-GHG emitting, its production entails a 
range of GHG emissions, from low to high, depending on the method. As 
noted in VII.F.3.c.v of this preamble, these differences in GHG 
emissions from the different methods of hydrogen production are well-
recognized in the energy sector, and, in fact, hydrogen is generally 
characterized by its production method and the attendant level of GHG 
emissions.
    Accordingly, the EPA is proposing to require that to qualify as the 
``best'' system of emission reduction, the hydrogen that is co-fired 
must be low-GHG hydrogen, as defined above. This is because the purpose 
of CAA section 111 is to reduce pollution that endangers human health 
and welfare to the extent achievable, CAA section 111(b), through 
promulgation of standards of performance that reflect the ``best'' 
system of emission reduction that, taking into account certain factors, 
is adequately demonstrated. CAA section 111(a)(1). Co-firing hydrogen 
at combustion turbines when that hydrogen is produced with large 
amounts of GHG emissions would ultimately result in increasing overall 
GHG emissions, compared to combusting solely natural gas at the 
combustion turbine. To avoid this anomalous outcome, in evaluating a 
``system of emission reduction'' of co-firing hydrogen, the GHG 
emissions from producing the hydrogen should be recognized to determine 
whether co-firing that hydrogen is the ``best'' system of emission 
reduction, within the meaning of CAA section 111(a)(1). The EPA 
recognizes that the production of low-GHG hydrogen also results in 
fewer emissions of other air pollutants, although it also requires the 
use of more water, compared to other methods of producing hydrogen, in 
particular, ones involving methane, as discussed in section VII.F.3.c.v 
of this preamble. All these factors, considered together, point towards 
co-firing low-GHG hydrogen, and not other types of hydrogen, as the 
``best'' system of emission reduction.
    D.C. Circuit caselaw supports applying the term ``best'' in this 
manner. In several cases decided under CAA section 111(a)(1) as enacted 
by the 1970 CAA Amendments, which did not provide that the EPA must 
consider non-air quality health and environmental impacts in 
determining the BSER,\466\ the court stated that the EPA must consider 
whether byproducts of pollution control equipment could cause 
environmental damage in determining whether the pollution control 
equipment qualified as the best system of emission reduction. See 
Portland Cement Ass'n v. Ruckelshaus, 465 F.2d 375, 385 n.42 (D.C. Cir. 
1973), cert. denied, 417 U.S. 921 (1974) (stating that ``[t]he standard 
of the `best system' is comprehensive, and we cannot imagine that 
Congress intended that `best' could apply to a system which did more 
damage to water than it prevented to air''); Essex Chemical Corp. v. 
Ruckelshaus, 486 F.2d 427, 439 (D.C. Cir. 1973) (remanding because the 
EPA failed to consider ``the significant land or water pollution 
potential'' from byproducts of air pollution control equipment). The 
situation here is analogous because a standard that allowed for co-
firing with other hydrogen would create more damage (in the form of GHG 
emissions) than it prevented, the precise problem CAA section 111 is 
intended to address. Considering the overall emissions impact of the 
production of fuel used by the affected facility to lower its

[[Page 33316]]

emissions--here, hydrogen--is consistent with considering the 
environmental impacts of the byproducts of pollution control technology 
used by the affected facility to lower its emissions.
---------------------------------------------------------------------------

    \466\ As enacted under the 1970 CAA Amendments, CAA section 
111(a)(1) read as follows:
    The term ``standard of performance'' means a standard for 
emissions of air pollutants which reflects the degree of emission 
limitation achievable through the application of the best system of 
emission reduction which (taking into account the cost of achieving 
such reduction) the Administrator determines has been adequately 
demonstrated.
    In the 1977 CAA Amendments, Congress revised section 111(a)(1) 
to incorporate a reference to ``non-air quality health and 
environmental impacts,'' and Congress retained that phrase in the 
1990 CAA Amendments when it revised CAA section 111(a)(1) to read as 
it currently does.
---------------------------------------------------------------------------

    In addition, the EPA's proposed determination that co-firing low-
GHG hydrogen qualifies as the BSER is supported by the IRA and its 
legislative history. In the IRA, Congress enacted or expanded tax 
credits to encourage the production and use of low-GHG hydrogen.\467\ 
In addition, as discussed in section IV.E.1 of this preamble, IRA 
section 60107 added new CAA section 135, LEEP. This provision provides 
$1 million for the EPA to assess the GHG emissions reductions from 
changes in domestic electricity generation and use anticipated to occur 
annually through fiscal year 2031; and further provides $18 million for 
the EPA to promulgate additional CAA rules to ensure GHG emissions 
reductions that go beyond the reductions expected in that assessment. 
CAA section 135(a)(5)-(6). The legislative history of this provision 
makes clear that Congress anticipated that the EPA could promulgate 
rules under CAA section 111(b) to ensure GHG emissions reductions from 
fossil fuel-fired electricity generation. 168 Cong. Rec. E879 (August 
26, 2022) (statement of Rep. Frank Pallone, Jr.). The legislative 
history goes on to state that ``Congress anticipates that EPA may 
consider . . . clean hydrogen as [a] candidate[ ] for BSER for electric 
generating plants. . . .'' Id.
---------------------------------------------------------------------------

    \467\ These tax credits include IRC section 45V (tax credit for 
production of hydrogen through low- or zero-emitting processes), IRC 
section 48 (tax credit for investment in energy storage property, 
including hydrogen production), IRC section 45Q (tax credit for 
CO2 sequestration from industrial processes, including 
hydrogen production); and the use of hydrogen in transportation 
applications, IRC section 45Z (clean fuel production tax credit), 
IRC section 40B (sustainable aviation fuel credit).
---------------------------------------------------------------------------

    Most broadly, proposing that only low-GHG hydrogen qualifies as 
part of the co-firing BSER is required by the ``reasoned 
decisionmaking'' that the Supreme Court has long held, including 
recently in Michigan v. EPA, 576 U.S. 743 (2015), that ``[f]ederal 
administrative agencies are required to engage in.'' Id. at 751 
(internal quotation marks omitted and citation omitted). In Michigan, 
the Court held that CAA section 112(n)(1)(A), which directs the EPA to 
regulate hazardous air pollutants from coal-fired power plants if the 
EPA ``finds such regulation is appropriate and necessary,'' must be 
interpreted to require the EPA to consider the costs of the regulation. 
The Court explained that if the EPA failed to consider cost, it could 
promulgate a regulation to eliminate power plant emissions harmful to 
human health but do so through the use of technologies that ``do even 
more damage to human health'' than the emissions they eliminate. Id. at 
752. The Court emphasized, ``No regulation is `appropriate' if it does 
significantly more harm than good.'' Id. Here, as explained above, 
permitting EGUs to burn high-GHG hydrogen would ``do even more damage 
to human health'' than the emissions eliminated and therefore could not 
be considered ``reasoned decisionmaking.'' Id. at 751. Likewise, the 
Supreme Court has long said that an agency engaged in reasoned 
decisionmaking may not ignore ``an important aspect of the problem.'' 
Motor Vehicles Mfrs. Ass'n v. State Farm Auto Ins. Co., 463 U.S. 29, 43 
(1983). Permitting EGUs to burn high-GHG hydrogen to meet the standard 
of performance here would ignore an important aspect of the problem 
being addressed, contrary to reasoned decisionmaking.
    The proposed standard of performance that is founded upon a BSER of 
burning hydrogen and the requirement that owners and operators seeking 
to burn hydrogen use low-GHG hydrogen are distinct requirements that 
could function independently. It may not be necessary to require that 
only low-GHG hydrogen be used to comply for owners and operators 
choosing this pathway included in the BSER in order to be confident 
that low-GHG hydrogen will be used to meet the standard. Incentives in 
the IRA may render production of low-GHG hydrogen less costly than 
higher-GHG hydrogen at some point, thus pushing the hydrogen market 
toward low-GHG hydrogen. In addition, the EPA may also initiate a 
rulemaking to regulate GHG emissions from hydrogen production under 
section 111 of the CAA. The EPA solicits comment on whether it is 
necessary to define and require low-GHG in this rulemaking. Similarly, 
the EPA also solicits comment as to whether the low-GHG hydrogen 
requirement could be treated as severable from the remainder of the 
standard such that the standard could function without this 
requirement.
(2) Definition of Low-GHG Hydrogen
    As noted in section VII.F.3.c.vi of this preamble, the EPA proposes 
a definition for low-GHG hydrogen that aligns with the highest of the 
four tiers of tax credit available for hydrogen production, IRC section 
45V(b)(2)(D). Under this provision, taxpayers are eligible for a tax 
credit of $3 per kilogram of hydrogen that is produced with a GHG 
emissions rate of 0.45 kg CO2e/kg H2 or less, 
from well-to-gate. This amount is three times higher than the amount 
for the next tier of credit, which is for hydrogen produced with a GHG 
emissions rate between 1.5 and 0.45 kg CO2e/kg 
H2, from well-to-gate, IRC section 45V(b)(2)(C); and four 
and five times higher than the amount for the next two tiers of credit, 
respectively. IRC section 45V(b)(2)(B), (A). With these provisions, 
Congress indicated its judgement as to what constitutes the lowest-GHG 
hydrogen production, and its intention to incentivize production of 
that type of hydrogen. Congress's views inform the EPA's proposal to 
define low-GHG hydrogen for purposes the BSER for this CAA section 111 
rulemaking consistent with IRC section 45V(b)(2)(D).
    It should be noted that the EPA is not proposing that the ``clean 
hydrogen'' definition in section 822 of the IIJA is appropriate for the 
EPA's regulatory purposes. This definition is designed for a non-
regulatory purpose. It sets out a non-binding goal, not a standard or a 
regulatory definition, intended for use in development of the DOE's 
CHPS and funding programs to promote promising new hydrogen 
technologies.
    For the reasons discussed above, co-firing low-GHG hydrogen 
qualifies as the BSER because it is adequately demonstrated, is of 
reasonable cost, does not have adverse non-air quality health or 
environmental impacts or energy requirements--in fact, it offers 
potential benefits to the energy sector--and reduces GHG emissions. The 
fact that this control promotes the advancement of hydrogen co-firing 
in combustion turbines provides additional support for proposing it as 
part of the BSER. Finally, Congress's direction to choose the ``best'' 
system of emissions reduction and principles of reasoned decision-
making dictate that the standard should be based on burning low-GHG 
hydrogen, and not using other forms of hydrogen.
4. Other Options for BSER
    The EPA considered several other systems of emission reduction as 
candidates for the BSER for combustion turbines, but is not proposing 
them as the BSER. They include CHP and the hybrid power plant, as 
discussed below.
a. Combined Heat and Power (CHP)
    CHP, also known as cogeneration, is the simultaneous production of 
electricity and/or mechanical energy and useful thermal output from a 
single fuel. CHP requires less fuel to produce a given energy output, 
and because less fuel is burned to produce each unit of energy output, 
CHP has lower emission rates and can be more economic than

[[Page 33317]]

separate electric and thermal generation. However, a critical 
requirement for a CHP facility is that it primarily generates thermal 
output and generates electricity as a byproduct and must therefore be 
physically close to a thermal host that can consistently accept the 
useful thermal output. It can be particularly difficult to locate a 
thermal host with sufficiently large thermal demands such that the 
useful thermal output would impact the emissions rate. The refining, 
chemical manufacturing, pulp and paper, food processing, and district 
energy systems tend to have large thermal demands. However, the thermal 
demand at these facilities is generally only sufficient to support a 
smaller EGU, approximately a maximum of several hundred MW. This would 
limit the geographically available locations where new generation could 
be constructed in addition to limiting its size. Furthermore, even if a 
sufficiently large thermal host were in close proximity, the owner/
operator of the EGU would be required to rely on the continued 
operation of the thermal host for the life of the EGU. If the thermal 
host were to shut down, the EGU could be unable to comply with the 
standard of performance. This reality would likely result in difficulty 
in securing funding for the construction of the EGU and could also lead 
the thermal host to demand discount pricing for the delivered useful 
thermal output. For these reasons, the EPA is not proposing CHP as the 
BSER.
b. Hybrid Power Plant
    Hybrid power plants combine two or more forms of energy input into 
a single facility with an integrated mix of complementary generation 
methods. While there are multiple types of hybrid power plants, the 
most relevant type for this proposal is the integration of solar energy 
(e.g., concentrating solar thermal) with a fossil fuel-fired EGU. Both 
coal-fired and NGCC EGUs have operated using the integration of 
concentrating solar thermal energy for use in boiler feed water 
heating, preheating makeup water, and/or producing steam for use in the 
steam turbine or to power the boiler feed pumps.
    One of the benefits of integrating solar thermal with a fossil 
fuel-fired EGU is the lower capital and operation and maintenance (O&M) 
costs of the solar thermal technology. This is due to the ability to 
use equipment (e.g., HRSG, steam turbine, condenser, etc.) already 
included at the fossil fuel-fired EGU. Another advantage is the 
improved electrical generation efficiency of the non-emitting 
generation. For example, solar thermal often produces steam at 
relatively low temperatures and pressures, and the conversion of the 
thermal energy in the steam to electricity is relatively low. In a 
hybrid power plant, the lower quality steam is heated to higher 
temperatures and pressures in the boiler (or HSRG) prior to expansion 
in the steam turbine, where it produces electricity. Upgrading the 
relatively low-grade steam produced by the solar thermal facility in 
the boiler improves the relative conversion efficiencies of the solar 
thermal to electricity process. The primary incremental costs of the 
non-emitting generation in a hybrid power plant are the costs of the 
mirrors, additional piping, and a steam turbine that is 10 to 20 
percent larger than that in a comparable fossil-only EGU to accommodate 
the additional steam load during sunny hours. A drawback of integrating 
solar thermal is that the larger steam turbine will operate at part 
loads and reduced efficiency when no steam is provided from the solar 
thermal panels (i.e., the night and cloudy weather). This limits the 
amount of solar thermal that can be integrated into the steam cycle at 
a fossil fuel-fired EGU.
    In the 2018 Annual Energy Outlook,\468\ the levelized cost of 
concentrated solar power (CSP) without transmission costs or tax 
credits is $161/MWh. Integrating solar thermal into a fossil fuel-fired 
EGU reduces the capital cost and O&M expenses of the CSP portion by 25 
and 67 percent compared to a stand-alone CSP EGU respectively.\469\ 
This results in an effective LCOE for the integrated CSP of $104/MWh. 
Assuming the integrated CSP is sized to provide 10 percent of the 
maximum steam turbine output and the relative capacity factors of a 
NGCC and the CSP (those capacity factors are 65 and 25 percent, 
respectively) the overall annual generation due to the concentrating 
solar thermal would be 3 percent of the hybrid EGU output. This would 
result in a three percent reduction in the overall CO2 
emissions and a one percent increase in the LCOE, without accounting 
for any reduction in the steam turbine efficiency. However, these costs 
do not account for potential reductions in the steam turbine efficiency 
due to being oversized relative to a non-hybrid EGU. A 2011 technical 
report by the National Renewable Energy Laboratory (NREL) cited 
analyses indicating solar-augmentation of fossil power stations is not 
cost-effective, although likely less expensive and containing less 
project risk than a stand-alone solar thermal plant. Similarly, while 
commenters stated that solar augmentation has been successfully 
integrated at coal-fired plants to improve overall unit efficiency, 
commenters did not provide any new information on costs or indicate 
that such augmentation is cost-effective. The EPA is soliciting comment 
on updated costs for hybrid power plants and if the use of hybrid power 
plants could be incorporated as part of the BSER for base load 
combustion turbines.
---------------------------------------------------------------------------

    \468\ EIA, Annual Energy Outlook 2018, February 6, 2018. https://www.eia.gov/outlooks/aeo/.
    \469\ B. Alqahtani and D. Pati[ntilde]o-Echeverri, Duke 
University, Nicholas School of the Environment, ``Integrated Solar 
Combined Cycle Power Plants: Paving the Way for Thermal Solar,'' 
Applied Energy 169:927-936 (2016).
---------------------------------------------------------------------------

    In addition, solar thermal facilities require locations with 
abundant sunshine and significant land area in order to collect the 
thermal energy. Existing concentrated solar power projects in the U.S. 
are primarily located in California, Arizona, and Nevada with smaller 
projects in Florida, Hawaii, Utah, and Colorado. NREL's 2011 technical 
report on the solar-augment potential of fossil-fired power plants 
examined regions of the U.S. with ``good solar resource as defined by 
their direct normal insolation (DNI)'' and identified sixteen States as 
meeting that criterion: Alabama, Arizona, California, Colorado, 
Florida, Georgia, Louisiana, Mississippi, Nevada, New Mexico, North 
Carolina, Oklahoma, South Carolina, Tennessee, Texas, and Utah. The 
technical report explained that annual average DNI has a significant 
effect on the performance of a solar-augmented fossil plant, with 
higher average DNI translating into the ability of a hybrid power plant 
to produce more steam for augmenting the plant. The technical report 
used a points-based system and assigned the most points for high solar 
resource values. An examination of a NREL-generated DNI map of the U.S. 
reveals that States with the highest DNI values are located in the 
southwestern U.S., with only portions of Arizona, California, Nevada, 
New Mexico, and Texas (plus Hawaii) having solar resources that would 
have been assigned the highest points by the NREL technical report (7 
kWh/m2/day or greater).
    The EPA is not proposing hybrid power plants as the BSER because of 
gaps in the EPA's knowledge about costs, and concerns about the cost-
effectiveness of the technology, as noted above.
5. Subcategories
    Stationary combustion turbines are defined in the 2015 NSPS to 
include

[[Page 33318]]

both simple cycle and combined cycle EGUs. In addition, 40 CFR part 60, 
subpart TTTT includes three subcategories for combustion turbines--
natural gas-fired base load EGUs, natural gas-fired non-base load EGUs, 
and multi-fuel-fired EGUs. Base load EGUs are those that sell 
electricity in excess of the site-specific electric sales threshold to 
an electric distribution network on both a 12-operating-month and 3-
year rolling average basis. Non-base load EGUs are those that sell 
electricity at or less than the site-specific electric sales threshold 
to an electric distribution network on both a 12-operating-month and 3-
year rolling average basis. Multi-fuel-fired EGUs combust 10 percent or 
more (by heat input) of fuels not meeting the definition of natural gas 
on a 12-operating-month rolling average basis.
a. Legal Basis for Subcategorization
    As noted in section V.C.1, CAA section 111(b)(2) provides that the 
EPA ``may distinguish among classes, types, and sizes within categories 
of new sources for the purpose of establishing . . . standards [of 
performance].'' The D.C. Circuit has held that the EPA has broad 
discretion in determining whether and how to subcategorize under CAA 
section 111(b)(2). Lignite Energy Council, 198 F3d at 933. As also 
noted in section V.C.1, in prior CAA section 111 rules, the EPA has 
subcategorized on numerous bases, including, among other things, fuel 
type and load.
b. Electric Sales Subcategorization (Low, Intermediate, and Base Load 
Combustion Turbines)
    As noted earlier, in the 2015 NSPS, the EPA established separate 
standards for natural gas-fired base load and non-base load stationary 
combustion turbines. The electric sales threshold distinguishing the 
two subcategories is based on the design efficiency of individual 
combustion turbines. A combustion turbine qualifies as a non-base load 
turbine, and is thus subject to a less stringent standard of 
performance, if it has net electric sales equal to or less than the 
design efficiency of the turbine (not to exceed 50 percent) multiplied 
by the potential electric output (80 FR 64601; October 23, 2015). If 
the net electric sales exceed that level on both a 12-operating month 
and 3 calendar year basis, then the combustion turbine is in the base 
load combustion subcategory and is subject to a more stringent standard 
of performance. Subcategory applicability can change on a month-to-
month basis since applicability is determined each operating month. For 
additional discussion on this approach, see the 2015 NSPS (80 FR 64609-
12; October 23, 2015). The 2015 NSPS non-base load subcategory is broad 
and includes combustion turbines that assure grid reliability by 
providing electricity during periods of peak electric demand. These 
peaking turbines tend to have low annual capacity factors and sell a 
small amount of their potential electric output. The non-base load 
subcategory in the 2015 NSPS also includes combustion turbines that 
operate at intermediate annual capacity factors but are not considered 
base load EGUs. These intermediate load EGUs provide a variety of 
services, including providing dispatchable power to support variable 
generation from renewable sources of electricity. The need for this 
service has been expanding as the amount of electricity from wind and 
solar continues to grow. In the 2015 NSPS, the EPA determined the BSER 
for the non-base load subcategory to be the use of lower emitting fuels 
(e.g., natural gas and Nos. 1 and 2 fuel oils). In 2015, the EPA 
explained that efficient generation did not qualify as the BSER due in 
part to the challenge of determining an achievable output-based 
CO2 emissions rate for all combustion turbines in this 
subcategory.
    In this action, the EPA is proposing changes to the subcategories 
in 40 CFR part 60, subpart TTTTa that will be applicable to sources 
that commence construction or reconstruction after the date of this 
proposed rulemaking. First, the Agency is proposing the definition of 
design efficiency so that the heat input calculation of an EGU is based 
on the higher heating value (HHV) of the fuel instead of the lower 
heating value (LHV), as explained immediately below. It is important to 
note that this would have the effect of lowering the electric sales 
threshold. In addition, the EPA is proposing to further divide the non-
base load subcategory into separate intermediate and low load 
subcategories.
i. Higher Heating Value as the Basis for Calculation of the Design 
Efficiency
    The heat rate is the amount of energy used by an EGU to generate 
one kWh of electricity and is often provided in units of Btu/kWh. As 
the thermal efficiency of a combustion turbine EGU is increased, less 
fuel is burned per kWh generated and there is a corresponding decrease 
in emissions of CO2 and other air pollutants. The electric 
energy output as a fraction of the fuel energy input expressed as a 
percentage is a common practice for reporting the unit's efficiency. 
The greater the output of electric energy for a given amount of fuel 
energy input, the higher the efficiency of the electric generation 
process. Lower heat rates are associated with more efficient power 
generating plants.
    Efficiency can be calculated using the HHV or the LHV of the fuel. 
The HHV is the heating value directly determined by calorimetric 
measurement of the fuel in the laboratory. The LHV is calculated using 
a formula to account for the moisture in the combustion gas (i.e., 
subtracting the energy required to vaporize the water in the flue gas) 
and is a lower value than the HHV. Consequently, the HHV efficiency for 
a given EGU is always lower than the corresponding LHV efficiency 
because the reported heat input for the HHV is larger. For U.S. 
pipeline natural gas, the HHV heating value is approximately 10 percent 
higher than the corresponding LHV heating value and varies slightly 
based on the actual constituent composition of the natural gas.\470\ 
The EPA default is to reference all technologies on a HHV basis,\471\ 
and the Agency is proposing to base the heat input calculation of an 
EGU on HHV for purposes of the definition of design efficiency. 
However, it should be recognized that manufacturers of combustion 
turbines typically use the LHV to express the efficiency of combustion 
turbines.\472\
---------------------------------------------------------------------------

    \470\ The HHV of natural gas is 1.108 times the LHV of natural 
gas. Therefore, the HHV efficiency is equal to the LHV efficiency 
divided by 1.108. For example, an EGU with a LHV efficiency of 59.4 
percent is equal to a HHV efficiency of 53.6 percent. The HHV/LHV 
ratio is dependent on the composition of the natural gas (i.e., the 
percentage of each chemical species (e.g., methane, ethane, propane, 
etc.)) within the pipeline and will slightly move the ratio.
    \471\ Natural gas is also sold on a HHV basis.
    \472\ European plants tend to report thermal efficiency based on 
the LHV of the fuel rather than the HHV for both combustion turbines 
and steam generating EGUs. In the U.S., boiler efficiency is 
typically reported on a HHV basis.
---------------------------------------------------------------------------

    Similarly, the electric energy output for an EGU can be expressed 
as either of two measured values. One value relates to the amount of 
total electric power generated by the EGU, or gross output. However, a 
portion of this electricity must be used by the EGU facility to operate 
the unit, including compressors, pumps, fans, electric motors, and 
pollution control equipment. This within-facility electrical demand, 
often referred to as the parasitic load or auxiliary load, reduces the 
amount of power that can be delivered to the transmission grid for 
distribution and sale to customers. Consequently, electric energy 
output may also be expressed in terms of net

[[Page 33319]]

output, which reflects the EGU gross output minus its parasitic 
load.\473\
---------------------------------------------------------------------------

    \473\ It is important to note that net output values reflect the 
net output delivered to the electric grid and not the net output 
delivered to the end user. Electricity is lost as it is transmitted 
from the point of generation to the end user and these ``line 
loses'' increase the farther the power is transmitted. 40 CFR part 
60, subpart TTTT provides a way to account for the environmental 
benefit of reduced line losses by crediting CHP EGUs, which are 
typically located close to large electric load centers. See 40 CFR 
60.5540(a)(5)(i) and the definitions of gross energy output and net 
energy output in 40 CFR 60.5580.
---------------------------------------------------------------------------

    When using efficiency to compare the effectiveness of different 
combustion turbine EGU configurations and the applicable GHG emissions 
control technologies, it is important to ensure that all efficiencies 
are calculated using the same type of heating value (i.e., HHV or LHV) 
and the same basis of electric energy output (i.e., MWh-gross or MWh-
net). Most emissions data are available on a gross output basis and the 
EPA is proposing output-based standards based on gross output. However, 
to recognize the superior environmental benefit of minimizing 
auxiliary/parasitic loads, the Agency is proposing to include optional 
equivalent standards on a net output basis. To convert from gross to 
net-output based standards, the EPA used a 1 percent auxiliary load for 
simple cycle turbines, a 2 percent auxiliary load for combined cycle 
turbines, and a 7 percent auxiliary load for combined cycle EGUs using 
90 percent CCS.
ii. Lowering the Threshold Between the Base Load and Non-Base Load 
Subcategories
    The subpart TTTT distinction between a base load and non-base load 
combustion turbine is determined by the unit's actual electric sales 
relative to its potential electric sales, assuming the EGU is operated 
continuously (i.e., percent electric sales). Specifically, stationary 
combustion turbines are categorized as non-base load and are 
subsequently subject to a less stringent standard of performance, if 
they have net electric sales equal to or less than their design 
efficiency (not to exceed 50 percent) multiplied by their potential 
electric output (80 FR 64601; October 23, 2015). Because the electric 
sales threshold is based in part on the design efficiency of the EGU, 
more efficient combustion turbine EGUs can sell a higher percentage of 
their potential electric output while remaining in the non-base load 
subcategory. This approach recognizes both the environmental benefit of 
combustion turbines with higher design efficiencies and provides 
flexibility to the regulated community. In the 2015 NSPS, it was 
unclear how often high-efficiency simple cycle EGUs would be called 
upon to support increased generation from variable renewable generating 
resources. Therefore, the Agency determined it was appropriate to 
provide maximum flexibility to the regulated community. To do this, the 
Agency based the numeric value of the design efficiency, which is used 
to calculate the electric sales threshold, on the LHV efficiency. This 
had the impact of allowing combustion turbines to sell a greater share 
of their potential electric output while remaining in the non-base load 
subcategory.
    For the reasons noted below, the EPA is proposing in 40 CFR part 
60, subpart TTTTa that the design efficiency be based on the HHV 
efficiency instead of LHV efficiency and that the 50 percent maximum 
and 33 percent minimum restriction not be included. When determining 
the potential electric output used in calculating the electric sales 
threshold in 40 CFR part 60, subpart TTTT, design efficiencies of 
greater than 50 percent are reduced to 50 percent and design 
efficiencies of less than 33 percent are increased to 33 percent for 
determining electric sales threshold subcategorization criteria. The 50 
percent criterion was established to limit non-base load EGUs from 
selling greater than 55 percent of their potential electric sales.\474\ 
The 33 percent criterion is included to be consistent with 
applicability thresholds in the electric utility criteria pollutant 
NSPS (40 CFR part 60, subpart Da). Neither of those criteria are 
appropriate for 40 CFR part 60, subpart TTTTa, and the EPA is not 
proposing that they be used to determine the electric sales threshold. 
By basing the electric sales threshold on the HHV design efficiency, 
the 50 percent restriction is no longer appropriate because currently 
available combined cycle designs operating as intermediate load 
combustion turbines would be limited to selling 55 percent of their 
potential electric output. If this restriction were maintained, it 
would reduce the regulatory incentive for manufacturers to invest in 
programs to develop higher efficiency combustion turbines. The EPA is 
also proposing to eliminate the 33 percent minimum design efficiency in 
the calculation of the potential electric output. The EPA is unaware of 
any new combustion turbines with design efficiencies of less than 33 
percent; and this will likely have no cost or emissions impact. 
However, this provides assurance that new combustion turbines will 
maximize design efficiencies. Because of this relationship between the 
electric sales threshold and the design efficiency of an individual 
EGU, the proposed definition of design efficiency would have the effect 
of lowering the electric sales threshold between the base load and non-
base load subcategories. For combined cycle EGUs, the current base load 
electric sales threshold is 55 percent. Proposing the definition of the 
design efficiency to be based on HHV would make the base load electric 
sales threshold for combined cycle EGUs between 46 and 55 percent.\475\ 
The current electric sales threshold for simple cycle turbines (i.e., 
non-base load) peaks in a range of 40 to 49 percent of potential 
electric sales. Under the proposed definition, simple cycle turbines 
would be able to sell no more than between 33 and 40 percent of their 
potential electric output without moving into the base load 
subcategory. A design efficiency definition based on the HHV will have 
the effect of decreasing the electric sales threshold in relative terms 
by 19 percent and absolute terms by 7 to 9 percent.\476\ The EPA is 
soliciting comment on whether the intermediate/base load electric sales 
threshold should be reduced further. The EPA is considering a range 
that would lower the base load electric sales threshold for simple 
cycle combustion turbines to between 29 to 35 percent (depending on the 
design efficiency) and to between 40 to 49 percent for combined cycle 
combustion turbines (depending on the design efficiency). This would be 
equivalent to reducing the design efficiency by 6 percent (e.g., 
multiplying by 0.94) when determining the electric sales threshold.
---------------------------------------------------------------------------

    \474\ While the design efficiency is capped at 50 percent on a 
LHV basis, the base load rating (maximum heat input of the 
combustion turbine) is on a HHV basis. This mixture of LHV and HHV 
results in the electric sales threshold being 11 percent higher than 
the design efficiency. The design efficiency of all new combined 
cycle EGUs exceed 50 percent on a LHV basis.
    \475\ The electric sales threshold for combined cycle EGUs with 
the highest design efficiencies would remain at 55 percent.
    \476\ The design efficiency appears twice in the equation used 
to determine the electric sales threshold. Amending the design 
efficiency to use the HHV numeric value results in a larger 
reduction in the electric sales threshold than the difference 
between the HHV and LHV design efficiency.
---------------------------------------------------------------------------

    The EPA determined that proposing to lower the electric sales 
threshold is appropriate for new combustion turbines because, as will 
be discussed later, the first component of BSER for both intermediate 
load and base load turbines is based on highly efficient generation. 
Combined cycle units are significantly more efficient than simple cycle 
turbines; and therefore, in general,

[[Page 33320]]

the EPA should be focusing its determination of the BSER for base load 
units on that more efficient technology. In the 2015 NSPS, the EPA used 
a higher sales threshold because of the argument that less efficient 
simple cycle turbine technology served a unique role that could not be 
served by more efficient combined cycle technology. At the time, the 
EPA determined that a BSER based exclusively on that more efficient 
technology could exclude the building of simple cycle turbines that are 
needed to maintain electric reliability. With improvements to the ramp 
rates for combined cycle units and with integrated renewable/energy 
storage projects becoming more common, these less efficient simple 
cycle turbines are no longer the only technology that can serve this 
purpose. Further, as EGUs operate more, they have more hours of steady 
state operation relative to hours of startup/cycling. Amending the 
electric sales threshold would result in GHG reductions by assuring 
that the most efficient generating and lowest emitting combustion 
turbine technology is used for each subcategory. Therefore, the 
proposed change to calculate the design efficiency on a HHV basis will 
result in additional emission reductions at reasonable costs.
    Based on EIA 2022 model plants, combined cycle EGUs have a lower 
levelized cost of electricity (LCOE) at capacity factors above 
approximately 40 percent compared to simple cycle EGUs operating at the 
same capacity factors. This supports the proposed base load electric 
threshold of 40 percent for simple cycle turbines because it would be 
cost effective for owners/operators of simple cycle turbines to add 
heat recovery if they elected to operate their unit as a base load 
unit. Furthermore, based on an analysis of monthly emission rates, 
recently constructed combined cycle EGUs maintain a 12-operating-month 
emissions rates at 12-operating-month capacity factors of less than 55 
percent (the base load electric sales threshold in subpart TTTT) 
relative to operation at higher capacity factors. Therefore, the base 
load subcategory operating range could be expanded in subpart TTTTa 
without impacting the stringency of the numeric standard. However, at 
12-operating-month capacity factors of less than approximately 50 
percent, emission rates of combined cycle EGUs increase relative to 
operation at a higher capacity factor. It takes longer for a HRSG to 
begin producing steam that can be used to generate additional 
electricity than the time it takes a combustion engine to reach full 
power. Under operating conditions with a significant number of starts 
and stops, typical of intermediate and especially low load combustion 
turbines, there may not be enough time for the HRSG to generate steam 
that can be used for additional electrical generation. To maximize 
overall efficiency, combined cycle EGUs often use combustion turbine 
engines that are less efficient than the most efficient simple cycle 
combustion turbine engines. Under operating conditions with frequent 
starts and stops where the HRSG does not have sufficient time to begin 
generating additional electricity, a combined cycle EGU may be no more 
efficient than a highly efficient simple cycle EGU. Above capacity 
factors of approximately 40 percent, the average run time per start for 
combined cycle EGUs tends to increase significantly and the HRSG would 
be available to contribute additional electric generation. For more 
information on the impact of capacity factors on the emission rates of 
combined cycle EGUs see the Efficient Generation at Combustion Turbine 
Electric Generating Units TSD, which is available in the rulemaking 
docket.
    After the 2015 NSPS was finalized, some stakeholders expressed 
concerns about the approach for distinguishing between base load and 
non-base load turbines. They posited a scenario in which increased 
utilization of wind and solar resources, combined with low natural gas 
prices, would create the need for certain types of simple cycle 
turbines to operate for longer time periods than had been contemplated 
when the 2015 NSPS was being developed. Specifically, stakeholders have 
claimed that in some regional electricity markets with large amounts of 
variable renewable generation, some of the most efficient new simple 
cycle turbines--aeroderivative turbines--could be called on to operate 
at capacity factors greater than their design efficiency. However, if 
those new simple cycle turbines were to operate at those higher 
capacity factors, they would become subject to the more stringent 
standard of performance for base load turbines. As a result, according 
to these stakeholders, the new aeroderivative turbines would have to 
curtail their generation and instead, less-efficient existing turbines 
would be called upon to run by the regional grid operators, which would 
result in overall higher emissions. The EPA evaluated the operation of 
simple cycle turbines in areas of the country with relatively large 
amounts of variable renewable generation and did not find a strong 
correlation between the percentage of generation from the renewable 
sources and the 12-operating-month capacity factors of simple cycle 
turbines. In addition, the vast majority of simple cycle turbines that 
commenced operation between 2010 and 2016 (the most recent simple cycle 
combustion turbines not subject to 40 CFR part 60, subpart TTTT) have 
operated well below the base load electric sales threshold in 40 CRF 
part 60, subpart TTTT. Therefore, the Agency does not believe that the 
concerns expressed by stakeholders necessitates any revisions to the 
regulatory scheme. In fact, as noted above, the EPA is proposing that 
the electric sales threshold can be lowered without impairing the 
availability of simple cycle turbines where needed, including to 
support the integration of variable generation. The EPA believes that 
the proposed threshold is not overly restrictive since a simple cycle 
turbine could operate on average for more than 8 hours a day.
iii. Low and Intermediate Load Subcategories
    The EPA is proposing in 40 CFR part 60, subpart TTTTa to create a 
low load subcategory to include combustion turbines that operate only 
during periods of peak electric demand (i.e., peaking units) which 
would be separate from the intermediate load subcategory. Low load 
combustion turbines also provide ramping capability and other ancillary 
serves to support grid reliability. The EPA evaluated the operation of 
recently constructed simple cycle turbines to understand how they 
operate and to determine at what electric sales level or capacity 
factor their emissions rate is relatively steady. (Note that for 
purposes of this discussion, we use the terms ``electric sales'' and 
``capacity factor'' interchangeably.) Peaking units only operate for 
short periods of time and potentially at relatively low duty 
cycles.\477\ This type of operation reduces the efficiency and 
increases the emissions rate, regardless of the design efficiency of 
the combustion turbine or how it is maintained. For this reason, it is 
difficult to establish a reasonable output-based standard of 
performance for peaking units.
---------------------------------------------------------------------------

    \477\ The duty cycle is the average operating capacity factor. 
For example, if an EGU operates at 75 percent of the fully rated 
capacity, the duty cycle would be 75 percent regardless of how often 
the EGU actually operates. The capacity factor is a measure of how 
much an EGU is operated relative to how much it could potentially 
have been operated.
---------------------------------------------------------------------------

    To determine the electric sales threshold--that is, to distinguish

[[Page 33321]]

between the intermediate load and low load subcategories--the EPA 
evaluated capacity factor electric sales thresholds of 10 percent, 15 
percent, 20 percent, and 25 percent. The EPA found the 10 percent level 
problematic for two reasons. First, simple cycle combustion turbines 
operating at that level or lower have highly variable emission rates, 
and therefore it would be difficult for the EPA to establish a 
meaningful output-based standard of performance. In addition, only one-
third of simple cycle turbines that have commenced operation since 2015 
have maintained 12-operating-month capacity factors of less than 10 
percent. Therefore, setting the threshold at this level would bring 
most new simple cycle turbines into the intermediate load subcategory, 
which would subject them to a more stringent emission rate which is 
only achievable for simple cycle combustion turbines operating at 
higher capacity factors. This could create a situation where simple 
cycle turbines might not be able to comply with the intermediate load 
standard of performance while operating at the low end of the 
intermediate load capacity factor subcategorization criteria.
    Importantly, based on the EPA's review of hourly emissions data, 
above a 15 percent capacity factor, GHG emission rates for many simple 
cycle combustion turbines begin to stabilize, see the Simple Cycle 
Stationary Combustion Turbine EGUs TSD, which is available in the 
rulemaking docket. At higher capacity factors, more time is typically 
spent at steady state operation rather than ramping up and down; and, 
emission rates tend to be lower while in steady state operation. 
Approximately 60 percent of recently constructed simple cycle turbines 
have maintained 12-operating-month capacity factors of 15 percent or 
less while two-thirds of recently constructed simple cycle turbines 
have operated at capacity factors of 20 percent or less; and, the 
emission rates clearly stabilize for the majority of simple cycle 
turbines operating at capacity factors of greater than 20 percent. 
Nearly 80 percent of recently constructed simple cycle turbines 
maintain maximum 12-operating-month capacity factors of 25 percent or 
less. Based on this information, the EPA is proposing the low load 
electric sales threshold--again, the dividing line to distinguish 
between the intermediate- and low-load subcategories--to be 20 percent 
and is soliciting comment on a range of 15 to 25 percent. The EPA is 
also soliciting comment on whether the low load electric sales 
threshold should be determined by a site-specific threshold based on 
three quarters of the design efficiency of the combustion turbine.\478\ 
Under this approach, simple cycle combustion turbines selling less than 
18 to 22 percent of their potential electric output (depending on the 
design efficiency) would still be considered low load combustion 
turbines. This ``sliding scale'' electric sales threshold approach is 
similar to the approach the EPA used in the 2015 NSPS to recognize the 
environmental benefit of installing the most efficient combustion 
turbines for low load applications. Using this approach, combined cycle 
EGUs would be able to sell between 26 to 31 percent of their potential 
electric output while still being considered low load combustion 
turbines.
---------------------------------------------------------------------------

    \478\ The calculation used to determine the electric sales 
threshold includes both the design efficiency and the base load 
rating. Since the base load rating stays the same when adjusting the 
numeric value of the design efficiency for applicability purposes, 
adjustments to the design efficiency has twice the impact. 
Specifically, using three quarters of the design efficiency reduces 
the electric sales threshold by half.
---------------------------------------------------------------------------

    Placing low load and intermediate load combustion turbines into 
separate subcategories is consistent with how these units are operated 
and how emissions from these units can be quantified and controlled. 
Consistent with the 2015 NSPS, the BSER analysis for base load 
combustion turbine EGUs assumes the use of combined cycle technology 
and the BSER analysis for intermediate and low load combustion turbine 
EGUs assumes the use of simple cycle technology. However, the Agency 
notes that combined cycle EGUs can elect to operate at lower levels of 
electric sales and be classified as intermediate or peaking EGUs. In 
this case, owners/operators of combined cycle EGUs would be required to 
comply with the standards of performance for intermediate or peaking 
EGUs.
c. Multi-Fuel-Fired Combustion Turbines
    40 CFR part 60, subpart TTTT subcategorizes multi-fuel-fired 
combustion turbines as EGUs that combust 10 percent or more of fuels 
not meeting the definition of natural gas on a 12-operating-month 
rolling average basis. The BSER for this subcategory is the use of 
lower emitting fuels with a corresponding heat input-based standard of 
performance of 120 to 160 lb CO2/MMBtu, depending on the 
fuel, for newly constructed and reconstructed multi-fuel-fired 
stationary combustion turbines.\479\ Lower emitting fuels for these 
units include natural gas, ethylene, propane, naphtha, jet fuel 
kerosene, Nos. 1 and 2 fuel oils, biodiesel, and landfill gas. The 
definition of natural gas in 40 CFR part 60, subpart TTTT includes fuel 
that maintains a gaseous state at ISO conditions, is composed of 70 
percent by volume or more methane, and has a heating value of between 
35 and 41 megajoules (MJ) per dry standard cubic meter (dscm, m\3\) 
(950 and 1,100 British thermal units (Btu) per dry standard cubic 
foot). Natural gas typically contains 95 percent methane and has a 
heating value of 1,050 Btu/lb.\480\ A potential issue with the multi-
fuel subcategory is that owners/operators of simple cycle turbines can 
elect to burn 10 percent non-natural gas fuels, such as Nos. 1 or 2 
fuel oil, and thereby remain in that subcategory, regardless of their 
electric sales. As a result, they would remain subject to the less 
stringent standard that applies to multi-fuel-fired sources, the lower 
emitting fuels standard. This could allow less efficient combustion 
turbine designs to operate as base load units without having to improve 
efficiency and could allow EGUs to avoid the need for efficient design 
or best operating and maintenance practices. These potential 
circumventions would result in higher GHG emissions.
---------------------------------------------------------------------------

    \479\ Combustion turbines co-firing natural gas with other fuels 
must determine fuel-based site-specific standards at the end of each 
operating month. The site-specific standards depend on the amount of 
co-fired natural gas. 80 FR 64616 (October 23, 2015).
    \480\ Note that 40 CFR part 60, subpart TTTT combustion turbines 
co-firing 25 percent hydrogen by volume could be subcategorized as 
multi-fuel-fired EGUs because the percent methane by volume could 
fall below 70 percent, the heating value could fall below 35 MJ/Sm3, 
and 10 percent of the heat input could be coming from a fuel not 
meeting the definition of natural gas.
---------------------------------------------------------------------------

    To avoid these concerns, the EPA is proposing to eliminate the 
multi-fuel subcategory for low, intermediate, and base load combustion 
turbines in 40 CFR part 60, subpart TTTTa. This would mean that new 
multi-fuel-fired turbines that commence construction or reconstruction 
after the date of this proposal will fall within a particular 
subcategory depending on their level of electric sales. The EPA also 
proposes that the performance standards for each subcategory be 
adjusted appropriately for multi-fuel-fired turbines to reflect the 
application of the BSER for the subcategories to turbines burning fuels 
with higher GHG emission rates than natural gas. To be consistent with 
the definition of lower emitting fuels in the 2015 Rule, the maximum 
allowable heat input-based emissions rate would be 160 lb 
CO2/MMBtu. For example, a standard of performance based on 
efficient generation would be 33 percent

[[Page 33322]]

higher for a fuel oil-fired combustion turbine compared to a natural 
gas-fired combustion turbine. This would assure that the BSER, in this 
case efficient generation, is applied, while at the same time 
accounting for the use of multiple fuels. As explained in section 
VII.F, in the second phase of the NSPS, the EPA is proposing to further 
subcategorize base load combustion turbines based on whether the 
combustion turbine is combusting hydrogen. During the first phase of 
the NSPS, all base load combustion turbines would be in a single 
subcategory. Table 2 summarizes the proposed electric sales 
subcategories for combustion turbines.

   Table 2--Proposed Sales Thresholds for Subcategories of Combustion
                              Turbine EGUs
------------------------------------------------------------------------
                                    Electric sales threshold (percent of
            Subcategory                   potential electric sales)
------------------------------------------------------------------------
Low Load..........................  <=20 percent.
Intermediate Load.................  >20 percent and <=site-specific
                                     value determined based on the
                                     design efficiency of the affected
                                     facility.
                                     Between ~ 33 to 40 percent
                                     for simple cycle combustion
                                     turbines.
                                     Between ~ 45 to 55 percent
                                     for combined cycle combustion
                                     turbines.
Base Load.........................  >Site-specific value determined
                                     based on the design efficiency of
                                     the affected facility.
                                     Between ~ 33 to 40 percent
                                     for simple cycle combustion
                                     turbines.
                                     Between ~ 45 to 55 percent
                                     for combined cycle combustion
                                     turbines.
------------------------------------------------------------------------

G. Proposed Standards of Performance

    Once the EPA has determined that a particular system or technology 
represents BSER, the CAA authorizes the Administrator to establish 
standards of performance for new units that reflect the degree of 
emission limitation achievable through the application of that BSER. As 
noted above, the EPA proposes that because the technology for reducing 
GHG emissions from combustion turbines is advancing rapidly, a multi-
phase set of standards of performance, which reflect a multi-component 
BSER, is appropriate for base load and intermediate load combustion 
turbines. Under this approach, for the first phase of the standards, 
which applies as of the effective date the final rule, the BSER is 
highly efficient generation for both base load and intermediate load 
combustion turbines. During this phase, owners/operators of EGUs will 
be subject to a numeric standard of performance that is representative 
of the performance of the best performing EGUs in the subcategory. For 
the second phase of the standards, beginning in 2032 and 2035 
respectively, the BSER for base load turbines includes either 30 
percent low-GHG hydrogen co-firing or 90 percent capture CCS, and 
beginning in 2032 the BSER for intermediate load EGUs includes 30 
percent low-GHG hydrogen co-firing. The affected EGUs would be subject 
to either an emissions rate that reflects continued use of highly 
efficient generation coupled with CCS, or one that reflects continued 
use of highly efficient generation coupled with co-firing low-GHG 
hydrogen. For the third phase of the standards, beginning in 2038 for 
base load turbines that began co-firing 30 percent low-GHG hydrogen in 
2032, the BSER includes co-firing 96 percent low-GHG hydrogen. In 
addition, the EPA is proposing a single component BSER, applicable from 
the date of proposal, for low load combustion turbines.
1. Phase-1 Standards
    The first component of the BSER is the use of highly efficient 
combined cycle technology for base load EGUs in combination with the 
best operating and maintenance practices, the use of highly efficient 
simple cycle technology in combination with the best operating and 
maintenance practices for intermediate load EGUs, and the use of lower 
emitting fuels for low load EGUs.
    For new and reconstructed natural gas-fired base load combustion 
turbine EGUs, the EPA proposes to find that the most efficient 
available combined cycle technology--which qualifies as the BSER for 
base load combustion turbines--supports a standard of 770 lb 
CO2/MWh-gross for large natural gas-fired EGUs (i.e., those 
with a nameplate heat input greater than 2,000 MMBtu/h) and 900 lb 
CO2/MWh-gross for natural gas-fired small EGUs (i.e., those 
with a nameplate base load rating of 250 MMBtu/h). The proposed 
standard of performance for natural gas-fired base load EGUs with base 
load ratings between 250 MMBtu/h and 2,000 MMBtu/h would be between 900 
and 770 lb CO2/MWh-gross and be determined based on the base 
load rating of the combustion turbine.\481\ The EPA proposes to find 
that the most efficient available simple cycle technology--which 
qualifies as the BSER for intermediate load combustion turbines--
supports a standard of 1,150 lb CO2/MWh-gross for natural 
gas-fired EGUs. For new and reconstructed low load combustion turbines, 
the EPA proposes to find that the use of lower emitting fuels--which 
qualifies as the BSER--supports a standard that ranges from 120 lb 
CO2/MMBtu to 160 lb CO2/MMBtu depending on the 
fuel burned. The EPA proposes these standards to apply at all times and 
compliance to be determined on a 12-operating-month rolling average 
basis.
---------------------------------------------------------------------------

    \481\ A new small natural gas-fired base load EGU would 
determine the facility emissions rate by taking the difference in 
the base load rating and 250 MMBtu/h, multiplying that number by 
0.0743 lb CO2/(MW * MMBtu), and subtracting that number 
from 900 lb CO2/MWh-gross. The emissions rate for a NGCC 
EGU with a base load rating of 1,000 MMBtu/h is 900 lb 
CO2/MWh-gross minus 750 MMBtu/h (1,000 MMBtu/h-250 MMBtu/
h) times 0.0743 lb CO2/(MW * MMBtu), which results in an 
emissions rate of 844 lb CO2/MWh-gross.
---------------------------------------------------------------------------

    The EPA has determined that these standards of performance are 
achievable specifically for natural gas-fired base load and 
intermediate load combustion turbine EGUs. However, combustion turbine 
EGUs burn a variety of fuels, including fuel oil during natural gas 
curtailments. Owners/operators of combustion turbines burning fuels 
other than natural gas would not necessarily be able to comply with the 
proposed standards for base load and intermediate load natural gas-
fired combustion turbines using highly efficient generation. Therefore, 
the Agency is proposing that owners/operators of combustion turbines 
burning fuels other than natural gas may elect to use the ratio of the 
heat input-based emissions rate of the specific fuel(s) burned to the 
heat input-based emissions rate of natural gas to determine a site-
specific standard of performance for the operating period. For example, 
the NSPS emissions rate for a large base load combustion turbine 
burning 100 percent distillate oil during the 12-operaitng month period 
would be 1,070 lb CO2/MWh-gross.\482\
---------------------------------------------------------------------------

    \482\ The heat input-based emission rates of natural gas and 
distillate oil are 117 and 163 lb CO2/MMBtu, 
respectively. The ratio of the heat input-based emission rates 
(1.39) is multiplied by the natural gas-fired standard of 
performance (770 lb CO2/MWh) to get the applicable 
emissions rate (1,070 lb CO2/MWh).

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

[[Page 33323]]

    To determine what emission rates are currently achieved by existing 
high-efficiency combined cycle EGUs and simple cycle EGUs, the EPA 
reviewed 12-operating-month generation and CO2 emissions 
data from 2015 through 2021 for all combined and simple cycle EGUs that 
submitted continuous emissions monitoring system (CEMS) data to the 
EPA's emissions collection and monitoring plan system (ECMPS). The data 
were sorted by the lowest maximum 12-operating-month emissions rate for 
each unit to identify long-term emission rates on a lb CO2/
MWh-gross basis that have been demonstrated by the existing combined 
cycle and simple cycle EGU fleets. Since an NSPS is a never-to-exceed 
standard, the EPA is proposing that use of long-term data are more 
appropriate than shorter term data in determining an achievable 
standard. These long-term averages account for degradation and variable 
operating conditions, and the EGUs should be able to maintain their 
current emission rates, as long as the units are properly maintained. 
While annual emission rates indicate a particular standard is 
achievable for certain EGUs in the short term, they are not necessarily 
representative of emission rates that can be maintained over an 
extended period using highly efficient generating technology in 
combination with best operating and maintenance practices.
    To determine the 12-operating-month average emissions rate that is 
achievable by application of the BSER, the EPA calculated 12-month 
CO2 emission rates by dividing the sum of the CO2 
emissions by the sum of the gross electrical energy output over the 
same period. The EPA did this separately for combined cycle EGUs and 
simple cycle EGUs to determine the emissions rate for the base load and 
intermediate load subcategories, respectively.
    For base load combustion turbines, the EPA evaluated three emission 
rates: 730, 770, and 800 lb CO2/MWh-gross. An emissions rate 
of 730 lb CO2/MWh-gross has been demonstrated by a single 
combined cycle facility--the Okeechobee Clean Energy Center. This 
facility is a large 3-on-1 combined cycle EGU that commenced operation 
in 2019 and uses a recirculating cooling tower for the steam cycle. 
Each turbine is rated at 380 MW and the three HRSGs feed a single steam 
turbine of 550 MW. The EPA is not proposing to use the emissions rate 
of this EGU to determine the standard of performance, for multiple 
reasons. The Okeechobee Clean Energy Center uses a 3-on-1 multi-shaft 
configuration but, many combined cycle EGUs use a 1-on-1 configuration. 
Combined cycle EGUs using a 1-on-1 configuration can be designed such 
that both the combustion turbine and steam turbine are arranged on one 
shaft and drive the same generator. This configuration has potential 
capital cost and maintenance costs savings and a smaller plant 
footprint that can be particularly important for combustion turbines 
enclosed in a building. In addition, a single shaft configuration has 
higher net efficiencies when operated at part load than a multi-shaft 
configuration. Basing the standard of performance on the performance of 
multi-shaft combined cycle EGUs could limit the ability of owners/
operators to construct new combined cycle EGUs in space-constrained 
areas (typically urban areas \483\) and combined cycle EGUs with the 
best performance when operated as intermediate load EGUs.\484\ Either 
of these outcomes could result in greater overall emissions from the 
power sector. An advantage of multi-shaft (2-on-1 and 3-on-1) 
configurations is that the turbine engine can be installed initially 
and run as a simple cycle EGU, with the HRSG and steam turbines added 
at a later date, all of which allows for more flexibility for the 
regulated community. In addition, a single large steam turbine can 
generate electricity more efficiently than multiple smaller steam 
turbines, increasing the overall efficiency of comparably sized 
combined cycle EGUs. According to Gas Turbine World 2021, multi-shaft 
combined cycle EGUs have design efficiencies that are 0.7 percent 
higher than single shaft combined cycle EGUs using the same turbine 
engine.\485\
---------------------------------------------------------------------------

    \483\ Generating electricity closer to electricity demand can 
reduce stress on the electric grid, reducing line losses and freeing 
up transmission capacity to support additional generation from 
variable renewable sources. Further, combined cycle EGUs located in 
urban areas could be designed as CHP EGUs, which have potential 
environmental and economic benefits.
    \484\ Power sector modeling projects that combined cycle EGUs 
will operate at lower capacity factors in the future. Combined cycle 
EGUs with lower base load efficiencies, but higher part load 
efficiencies could have lower overall emission rates.
    \485\ According to the data in Gas Turbine World 2021, while 
there is a design efficiency advantage of going from a 1-on-1 
configuration to a 2-on-1 configuration (assuming the same turbine 
engine) there is no efficiency advantage of 3-on-1 configurations 
compared to 2-on-1 configurations.
---------------------------------------------------------------------------

    The efficiency of the Rankine cycle (i.e., HRSG plus the steam 
turbine) is determined in part by the ability to cool the working fluid 
(e.g., steam) after it has been expanded through the turbine. All else 
equal, the lower the temperature that can be achieved, the more 
efficient the Rankine cycle. The Okeechobee Clean Energy Center used a 
recirculating cooling system, which can achieve lower temperatures than 
EGUs using dry cooling systems and therefore would be more efficient 
and have a lower emissions rate. However dry cooling systems have lower 
water requirements and therefore could be the preferred technology in 
arid regions or in areas where water requirements could have 
significant ecological impacts. Therefore, the EPA proposes that the 
efficient generation standard for base load EGUs should account for the 
use of dry cooling.
    Finally, the Okeechobee Clean Energy Center is a relatively new EGU 
and full efficiency degradation might not be accounted for in the 
emissions analysis. Therefore, the EPA is not proposing that an 
emissions rate of 730 lb CO2/MWh-gross is an appropriate 
nationwide standard. However, the EPA is soliciting comment on whether 
the use of alternate working fluid, such as supercritical 
CO2, or other potential efficiency improvements would make 
this emissions rate an appropriate standard of performance for base 
load combustion turbines.
    An emissions rate of 770 lb CO2/MWh-gross has been 
demonstrated by 14 percent of recently constructed combined cycle EGUs. 
These turbines include combined cycle EGUs using 1-on-1 configurations 
and dry cooling, are manufactured by multiple companies, and have long-
term emissions data that fully account for potential degradation in 
efficiency. One of the best performing large combined cycle EGUs that 
has maintained an emissions rate of 770 lb CO2/MWh-gross is 
the Dresden plant, located in Ohio.\486\ This 2-on-1 combined cycle 
facility, uses a recirculating cooling tower, and has maintained an 
emissions rate of 765 lb CO2/MWh-gross, measured over 12 
operating months with 99 percent confidence. The turbine engines are 
rated at 2,250 MMBtu/h, which demonstrates that the standard of 770 lb 
CO2/MWh-gross is achievable at a heat input rating of 2,000 
MMBtu/h. In addition, while a 2-on-1 configuration and a cooling tower 
are more efficient than a 1-on-1 configuration and dry cooling, the 
Dresden Energy Facility does not use the most efficient combined cycle 
design currently available. Multiple more efficient designs have been 
developed since the

[[Page 33324]]

Dresden Energy Facility commenced operation a decade ago that more than 
offset these efficiency losses. Therefore, the EPA proposes that while 
the Dresden combined cycle EGUs uses a 2-on-1 configuration with a 
cooling tower, it demonstrates that an emissions rate of 770 lb 
CO2/MWh-gross is achievable for all new large combined cycle 
EGUs. For additional information on the EPA analysis of emission rates 
for high efficiency base load combined cycle EGUs, see the Efficient 
Generation at Combustion Turbine Electric Generating Units TSD, which 
is available in the rulemaking docket.
---------------------------------------------------------------------------

    \486\ The Dresden Energy Facility is listed as being located in 
Muskingum County, Ohio, as being owned by the Appalachian Power 
Company, as having commenced commercial operation in late 2011. The 
facility ID (ORISPL) is 55350 1A and 1B.
---------------------------------------------------------------------------

    The EPA is not proposing an emissions rate of 800 lb 
CO2/MWh-gross because it does not represent the most 
efficient combined cycle EGUs designs. Nearly half of recently 
constructed combined cycle EGUs have maintained an emissions rate of 
800 lb CO2/MWh-gross. However, the EPA is soliciting comment 
on whether this higher emissions rate is appropriate on grounds that it 
would increase flexibility and reduce costs to the regulated community 
by allowing more available designs to operate as base load combustion 
turbines.
    With respect to small combined cycle combustion turbines, the best 
performing unit is the Holland Energy Park facility in Holland, 
Michigan, which commenced operation in 2017 and uses a 2-on-1 
configuration and a cooling tower.\487\ The 50 MW turbine engines have 
individual heat input ratings of 590 MMBtu/h and serve a single 45 MW 
steam turbine. The facility has maintained a 12-operating month, 99 
percent confidence emissions rate of 870 lb CO2/MWh-gross. 
This long-term data accounts for degradation and variable operating 
conditions and demonstrates that a base load combustion turbine EGU 
with a turbine rated at 250 MMBtu/h should be able to maintain an 
emissions rate of 900 lb CO2/MWh-gross.\488\ In addition, 
there is a commercially available HRSG that uses supercritical 
CO2 instead of steam as the working fluid. This HRSG would 
be significantly more efficient than the HRSG that uses dual pressure 
steam, which is common for small combined cycle EGUs.\489\ When these 
efficiency improvements are accounted for, a new small natural gas-
fired combined cycle EGU would be able to maintain an emissions rate of 
850 lb CO2/MWh-gross. Therefore, the Agency is soliciting 
comment on whether the small natural gas-fired base load combustion 
turbine standard of performance should be 850 lb CO2/MWh-
gross.
---------------------------------------------------------------------------

    \487\ The Holland Park Energy Center is a CHP system that uses 
hot water in the cooling system for a snow melt system that uses a 
warm water piping system to heat the downtown sidewalks to clear the 
snow during the winter. Since this useful thermal output is low 
temperature, it does not materially reduce the electrical efficiency 
of the EGU. If the useful thermal output were accounted for, the 
emissions rate of the Holland Energy Park would be lower. The 
facility ID (ORISPL) is 59093 10 and 11.
    \488\ To estimate an achievable emissions rate for an efficient 
combined cycle EGU at 250 MMBtu/h the EPA assumed a linear 
relationship for combined cycle efficiency with turbine engines with 
base load ratings of less than 2,000 MMBtu/h.
    \489\ If the combustion turbine engine exhaust temperature is 
500[deg]C or greater, a HRSG using 3 pressure steam without a reheat 
cycle could potentially provide an even greater increase in 
efficiency (relative to a HRSG using 2 pressure steam without a 
reheat cycle).
---------------------------------------------------------------------------

    In summary, the Agency solicits comment on the following range of 
potential standards of performance:
     New and reconstructed natural gas-fired base load 
combustion turbines with a heat input rating that is greater than 2,000 
MMBtu/h: a range of 730-800 lb CO2/MWh-gross;
     New and reconstructed natural gas-fired base load 
combustion turbines with a heat input rating of 250 MMBtu/h: a range of 
850 to 900 lb CO2/MWh-gross.
    For intermediate load combustion turbines, the EPA evaluated the 
performance of recently constructed high efficiency natural gas-fired 
simple cycle EGUs. The EPA evaluated three emission rates for the 
intermediate load standard of performance: 1,200, 1,150, and 1,100 lb 
CO2/MWh-gross. Sixty two percent of recently constructed 
intermediate load simple cycle EGUs have maintained an emissions rate 
of 1,200 lb CO2/MWh-gross, 17 percent have maintained an 
emissions rate of 1,150 lb CO2/MWh-gross, and 6 percent have 
maintained an emissions rate of 1,100 lb CO2/MWh-gross. 
However, the units that have maintained an emissions rate of 1,100 lb 
CO2/MWh-gross generally have a single large aeroderivative 
combustion turbine design. In contrast, the ones that have maintained 
an emission rate of 1,150 lb CO2/MWh-gross have multiple 
different designs, including an industrial frame combustion turbine 
design, and are made by multiple manufacturers. Therefore, the EPA is 
proposing an intermediate load standard of performance of 1,150 lb 
CO2/MWh-gross. The Agency is soliciting comment on whether 
the standard should be 1,100 lb CO2/MWh-gross, or whether 
that would result in unacceptably high costs because currently only a 
single design for a large aeroderivative simple cycle turbine would be 
able to meet this standard. The Agency is also soliciting comment on a 
standard of performance of 1,200 lb CO2/MWh-gross. While 
this would achieve fewer GHG reductions, it would increase flexibility, 
and potentially reduce costs, to the regulated community by allowing 
the currently available designs to operate as intermediate load 
combustion turbines. For additional information on the EPA analysis of 
emission rates for high efficiency intermediate load simple cycle EGUs, 
see the Efficient Generation at Combustion Turbine Electric Generating 
Units TSD, which is available in the rulemaking docket
    The EPA is also soliciting comment on whether the use of steam 
injection is applicable to intermediate load combustion turbines. Steam 
injection is the use of a relatively low cost HRSG to produce steam 
that is injected into the combustion chamber of the combustion turbine 
engine instead of using a separate steam turbine.\490\ Advantages of 
steam injection include improved efficiency and increases the output of 
the combustion turbine as well as reducing NOX emissions. 
Combustion turbines using steam injection have characteristics in-
between simple cycle and combined cycle combustion turbines. They are 
more efficient, but more complex and have higher capital costs than 
simple cycle combustion turbines without steam injection. Combustion 
turbines using steam injection are simpler and have lower capital costs 
than combined EGUs but have lower efficiencies. The EPA is aware of a 
single combustion turbine that is using steam injection that has 
maintained a 12-operaitng month emission rates of less than 1,000 lb 
CO2/MWh-gross. The EPA requests that commenters include 
information on whether this technology would be applicable to 
intermediate load combustion turbines and could be part of either the 
first or second component of the BSER along with cost information.\491\
---------------------------------------------------------------------------

    \490\ A steam injected combustion turbine would be considered a 
combined cycle combustion turbine (for NSPS purposes) because energy 
from the turbine engine exhaust is recovered in a HRSG and that 
energy is used to generate additional electricity.
    \491\ The second component of the BSER, 30 percent low-GHG 
hydrogen co-firing, would reduce the emissions rate to 880 lb 
CO2/MWh-gross.
---------------------------------------------------------------------------

2. Phase-2 Standards
    The use of CCS and hydrogen co-firing are both approaches 
developers are considering to reduce GHG emissions beyond highly 
efficient generation. However, as noted above, these approaches apply 
to different subcategories and are not applicable to

[[Page 33325]]

the same EGUs. The proposed phase-2 standards are in table 3.

                Table 3--Phase-2 Standards of Performance
------------------------------------------------------------------------
                                                          Standard of
           Subcategory                   BSER             performance
------------------------------------------------------------------------
Low load........................  Lower emitting      120-160 lb CO2/
                                   fuels.              MMBtu.
Intermediate load...............  Highly efficient    1,000 lb CO2/MWh-
                                   simple cycle        gross.
                                   technology
                                   coupled with co-
                                   firing 30 percent
                                   (by volume) low-
                                   GHG hydrogen.
Base load adopting the CCS        Highly efficient    90 lb CO2/MWh-
 pathway.                          combined cycle      gross.
                                   technology
                                   coupled with 90
                                   percent CCS.
Base load adopting the low-GHG    Highly efficient    680 lb CO2/MWh-
 hydrogen co-firing pathway.       combined cycle      gross.
                                   technology
                                   coupled with co-
                                   firing 30 percent
                                   (by volume) low-
                                   GHG hydrogen.
------------------------------------------------------------------------

    Co-firing 30 percent by volume low-GHG hydrogen reduces emissions 
by 12 percent. The EPA applied this percent reduction to the emission 
rates for the intermediate load and base load units adopting the low-
GHG hydrogen co-firing pathway subcategories, to determine the phase-1 
standards. For the base load combustion turbines adopting the CCS 
subcategory, the EPA reduced the emissions rate by 89 percent to 
determine the CCS based phase-2 standards.\492\ The CCS percent 
reduction is based on a CCS system capturing 90 percent of the emitting 
CO2 being operational anytime the combustion turbine is 
operating. However, if the carbon capture equipment has lower 
availability/reliability than the combustion turbine or the CCS 
equipment takes longer to startup than the combustion turbine itself 
there would be periods of operation where the CO2 emissions 
would not be controlled by the carbon capture equipment. As noted in 
section VII.F.3.b.iii(A)(2) of this preamble, the operating 
availability (i.e., the amount of time a process operates relative to 
the amount of time it planned to operate) of industrial processes is 
usually less than 100 percent. Assuming that CO2 capture 
achieves 90 percent capture when available to operate, that CCS is 
available to operate 90 percent of the time the combustion turbine is 
operating, and that the combustion turbine operates the same whether or 
not CCS is available to operate, total emission reductions would be 81 
percent. Higher levels of emission reduction could occur for higher 
capture rates coupled with higher levels of operating availability 
relative to operation of the combustion turbine. If the combustion 
turbine were not permitted to operate when CCS was unavailable, there 
may be local reliability consequences or issues during startup or 
shutdown, and the EPA is soliciting comment on how to balance these 
issues. Additionally, the EPA is soliciting comment on the range of 
reduction in emission rate of 75 to 90 percent.
---------------------------------------------------------------------------

    \492\ The 89 percent reduction from CCS accounts for the 
increased auxiliary load of a 90 percent post combustion amine-based 
capture system. Due to rounding, the proposed numeric standards of 
performance do not necessarily match the standards that would be 
determined by applying the percent reduction to the phase 1 
standards.
---------------------------------------------------------------------------

    The standards of performance for the intermediate and base load 
combustion turbines would also be adjusted based on the uncontrolled 
emission rates of the fuels relative to natural gas. For 100 percent 
distillate oil-fired combustion turbines, the emission rates would be 
1,300 lb CO2/MWh-gross, 120 lb CO2/MWh-gross, and 
910 lb CO2/MWh-gross for the intermediate load, non low-GHG 
hydrogen co-firing base load, and low-GHG hydrogen co-firing base load 
subcategories respectively.
3. Phase-3 Standards
    The third component of the BSER is applicable to owner/operators of 
base load combustion turbines that elect to implement early GHG 
reductions (i.e., comply with an emissions rate of 680 lb 
CO2/MWh-gross starting in January 2032). The phase 3 BSER 
standard of performance increases the GHG reduction requirements and is 
based on co-firing 96 percent by volume low-GHG hydrogen in addition to 
the use of highly efficient combined cycle technology in combination 
with the best operating and maintenance practices. The proposed phase-3 
standards are in table 4.

                Table 4--Phase-3 Standards of Performance
------------------------------------------------------------------------
                                                          Standard of
           Subcategory                   BSER             performance
------------------------------------------------------------------------
Base load electing to implement   Highly efficient    90 lb CO2/MWh-
 early GHG reductions.             combined cycle      gross.
                                   technology
                                   coupled with co-
                                   firing 89 percent
                                   (by heat input)
                                   low-GHG hydrogen.
------------------------------------------------------------------------

    Co-firing 89 percent by heat input (96 percent by volume) low-GHG 
hydrogen reduces GHG emissions by 89 percent. The EPA applied this 
percent reduction to the emission rates for base load under phase 1 of 
the BSER. Similar to the phase 1 and 2 standards of performance, the 
numeric standard would be adjusted based on the uncontrolled emission 
rates of the fuels relative to natural gas. For 100 percent distillate 
oil-fired combustion turbines, the emission rates would be 120 lb 
CO2/MWh-gross.
    As a variation on proposing the date for meeting this standard as 
2038, the EPA solicits comment on proposing the date as 2035, coupled 
with authorizing an approach for crediting early reductions, under 
which a source that achieves reductions due to co-firing low-GHG 
hydrogen starting in 2032 may apply credit for those reductions to its 
emission rate beginning in 2035. Another, more stringent, variation of 
this approach would be to allow credit only for reductions below the 
emission rate otherwise required by 2032. Other

[[Page 33326]]

variations would allow sources to generate credits from reductions from 
co-firing low-GHG hydrogen, or from any other reductions below their 
standard of performance, in any year before 2035. In this manner, the 
source would be authorized to comply with its 2035 standard in part 
through use of credits generated by making reductions beginning in 
2032. Under such an approach, early credits could only be used by the 
unit that generated those credits. For instance, a unit co-firing 30 
percent low-GHG hydrogen prior to 2035 would be able to generate 
credits that it could use in 2035 and beyond. This would allow a unit 
co-firing low-GHG hydrogen to ramp up the amount it co-fired over time, 
while still achieving the same amount of emission reductions that would 
have been achieved had the unit co-fired enough low-GHG hydrogen (e.g., 
96 percent by volume) starting in 2035. Another variation on this 
approach would be to treat such a crediting scheme as a compliance 
alternative to the CCS BSER by showing equivalent emission reductions, 
rather than the standard itself.
    The EPA proposes the following mechanism to ensure that affected 
sources in the base load subcategory comply with the applicable 
standard of performance in the event that the EPA finalizes both the 
CCS pathway (that is, the use of 90-percent-capture CCS by 2035) and 
the low-GHG hydrogen pathway (that is, co-firing 30 percent low-GHG 
hydrogen by 2032 and 96 percent by 2038). The EPA proposes that 
affected sources must notify the EPA by January 1, 2031, which pathway 
they are selecting, and thus which standard they intend to comply with. 
If they select the low-GHG hydrogen pathway, they must comply with the 
applicable standard based on co-firing 30 percent hydrogen (by volume) 
in 2032 through 2037. In addition, in 2033 through 2037, they must be 
prepared to demonstrate that they complied with the applicable standard 
based on co-firing 30 percent low-GHG hydrogen in the preceding years, 
beginning in 2032. In 2038, they must comply with the applicable 
standard based on co-firing 96 percent (by volume) now-GHG hydrogen.

H. Reconstructed Stationary Combustion Turbines

    In the previous sections, the EPA explained the background of and 
requirements for new and reconstructed stationary combustion turbines 
and evaluated various control technology configurations to determine 
the BSER. Because the BSER is the same for new and reconstructed 
stationary combustion turbines, the Agency is proposing to use the same 
emissions analysis for both new and reconstructed stationary combustion 
turbines. For each of the subcategories, the EPA is proposing that the 
proposed BSER results in the same standard of performance for new 
stationary combustion turbines and reconstructed stationary combustion 
turbines. Since reconstructed turbines could likely incorporate 
technologies to co-fire hydrogen as part of the reconstruction process 
at little or no cost, the low-GHG hydrogen co-firing would likely to be 
similar to those for newly constructed combustion turbines. For CCS, 
the EPA approximated the cost to add CCS to a reconstructed combustion 
turbine by increasing the capital costs of the carbon capture equipment 
by 10 percent relative to the costs for a newly constructed combustion 
turbine. This increases the capital cost from $949/kW to $1,044/
kW.\493\ Using a 12-year amortization period, a 90 percent-capture 
amine-based post combustion CCS system increases the LCOE by $8.5/MWh 
and has overall CO2 abatement costs of $25/ton ($28/metric 
ton).
---------------------------------------------------------------------------

    \493\ The kW value used as reference for the costs is the output 
from the combined cycle EGU prior to the installation of the CCS.
---------------------------------------------------------------------------

    A reconstructed stationary combustion turbine is not required to 
meet the standards if doing so is deemed to be ``technologically and 
economically'' infeasible.\494\ This provision requires a case-by-case 
reconstruction determination in the light of considerations of economic 
and technological feasibility. However, this case-by-case determination 
would consider the identified BSER, as well as technologies the EPA 
considered, but rejected, as BSER for a nationwide rule. One or more of 
these technologies could be technically feasible and of reasonable 
cost, depending on site-specific considerations and if so, would likely 
result in sufficient GHG reductions to comply with the applicable 
reconstructed standards. Finally, in some cases, equipment upgrades, 
and best operating practices would result in sufficient reductions to 
achieve the reconstructed standards.
---------------------------------------------------------------------------

    \494\ 40 CFR 60.15(b)(2).
---------------------------------------------------------------------------

I. Modified Stationary Combustion Turbines

    CAA section 111(a)(4) defines a ``modification'' as ``any physical 
change in, or change in the method of operation of, a stationary 
source'' that either ``increases the amount of any air pollutant 
emitted by such source or . . . results in the emission of any air 
pollutant not previously emitted.'' Certain types of physical or 
operational changes are exempt from consideration as a modification. 
Those are described in 40 CFR 60.2, 60.14(e).
    In the 2015 NSPS, the EPA did not finalize standards of performance 
for stationary combustion turbines that conduct modifications; instead, 
the EPA concluded that it was prudent to delay issuing standards until 
the Agency could gather more information (80 FR 64515; October 23, 
2015). There were several reasons for this determination: few sources 
had undertaken NSPS modifications in the past, the EPA had little 
information concerning them, and available information indicated that 
few owners/operators of existing combustion turbines would undertake 
NSPS modifications in the future; and since the Agency eliminated 
proposed subcategories for small EGUs in the 2015 NSPS, questions were 
raised as to whether smaller existing combustion turbines that 
undertake a modification could meet the final performance standard of 
1,000 lb CO2/MWh-gross.
    It continues to be the case that the EPA is aware of no evidence 
indicating that owners/operators of combustion turbines intend to 
undertake actions that could qualify as NSPS modifications in the 
future. EPA is not proposing, or soliciting comment on whether it 
should propose, standards of performance for modifications of 
combustion turbines.

J. Startup, Shutdown, and Malfunction

    In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. 
Cir. 2008), the U.S. Court of Appeals for the District of Columbia 
Circuit (D.C. Circuit) vacated portions of two provisions in the EPA's 
CAA section 112 regulations governing the emissions of HAP during 
periods of SSM. Specifically, the court vacated the SSM exemption 
contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that, the 
SSM exemption violates the requirement under section 302(k) of the CAA 
that some CAA section 112 standard apply continuously. Consistent with 
Sierra Club v. EPA, the EPA is proposing standards in this rule that 
apply at all times. The NSPS general provisions in 40 CFR 60.11(c) 
currently exclude opacity requirements during periods of startup, 
shutdown, and malfunction and the provision in 40 CFR 60.8(c) contains 
an exemption from non-opacity standards. These general provision 
requirements would automatically apply to the standards set in an NSPS, 
unless the regulation specifically overrides these general provisions. 
The NSPS subpart TTTT (40

[[Page 33327]]

CFR part 60 subpart TTTT), does not contain an opacity standard, thus, 
the requirements at 40 CFR 60.11(c) are not applicable. The NSPS 
subpart TTTT also overrides 40 CFR 60.8(c) in table 3 and requires that 
sources comply with the standard(s) at all times. In reviewing NSPS 
subpart TTTT and proposing the new NSPS subpart TTTTa, the EPA is 
proposing to retain in subpart TTTTa the requirements that sources 
comply with the standard(s) at all times. Therefore, the EPA is 
proposing in table 3 of the new subpart TTTTa to override the general 
provisions for SSM provisions. The EPA is proposing that all standards 
in subpart TTTTa apply at all times.
    The EPA has attempted to ensure that the general provisions we are 
proposing to override are inappropriate, unnecessary, or redundant in 
the absence of the SSM exemption. The EPA is specifically seeking 
comment on whether we have successfully done so.
    In proposing the standards in this rule, the EPA has taken into 
account startup and shutdown periods and, for the reasons explained in 
this section of the preamble, has not proposed alternate standards for 
those periods. The EPA analysis of achievable standards of performance 
used CEMS data that includes all period of operation. Since periods of 
startup, shutdown, and malfunction were not excluded from the analysis, 
the EPA is not proposing alternate standard for those periods of 
operation.
    Periods of startup, normal operations, and shutdown are all 
predictable and routine aspects of a source's operations. Malfunctions, 
in contrast, are neither predictable nor routine. Instead, they are, by 
definition, sudden, infrequent, and not reasonably preventable failures 
of emissions control, process, or monitoring equipment. (40 CFR 60.2). 
The EPA interprets CAA section 111 as not requiring emissions that 
occur during periods of malfunction to be factored into development of 
CAA section 111 standards. Nothing in CAA section 111 or in case law 
requires that the EPA consider malfunctions when determining what 
standards of performance reflect the degree of emission limitation 
achievable through ``the application of the best system of emission 
reduction'' that the EPA determines is adequately demonstrated. While 
the EPA accounts for variability in setting standards of performance, 
nothing in CAA section 111 requires the Agency to consider malfunctions 
as part of that analysis. The EPA is not required to treat a 
malfunction in the same manner as the type of variation in performance 
that occurs during routine operations of a source. A malfunction is a 
failure of the source to perform in a ``normal or usual manner'' and no 
statutory language compels the EPA to consider such events in setting 
CAA section 111 standards of performance. The EPA's approach to 
malfunctions in the analogous circumstances (setting ``achievable'' 
standards under CAA section 112) has been upheld as reasonable by the 
D.C. Circuit in U.S. Sugar Corp. v. EPA, 830 F.3d 579, 606-610 (2016).

K. Testing and Monitoring Requirements

    Because the NSPS reflects the application of the best system of 
emission reduction under conditions of proper operation and 
maintenance, in doing the NSPS review, the EPA also evaluates and 
determines the proper testing, monitoring, recordkeeping and reporting 
requirements needed to ensure compliance with the NSPS. This section 
will include a discussion on the current testing and monitoring 
requirements of the NSPS and any additions the EPA is proposing to 
include in 40 CFR part 60, subpart TTTTa.
1. General Requirements
    The current rule allows three approaches for determining compliance 
with its emissions limits: Continuous measurement using CO2 
CEMS and flow measurements for all EGUs; calculations using hourly heat 
input and `F' factors \495\ for EGUs firing uniform oil or gas or non-
uniform fuels; or Tier 3 calculations using fuel use and carbon content 
as described in GHGRP regulations for EGUs firing non-uniform fuels. 
The first two approaches are in use for carbon dioxide by the Acid Rain 
program (40 CFR part 75), to which most, if not all, of the EGUs 
affected by NSPS subpart TTTT are already subject, while the last 
approach is in use for carbon dioxide, nitrous oxide, and methane 
reporting from stationary fuel combustion sources (40 CFR part 98, 
subpart C).
---------------------------------------------------------------------------

    \495\ An F factor is the ratio of the gas volume of the products 
of combustion to the heat content of the fuel.
---------------------------------------------------------------------------

    The EPA believes continuing the use of these familiar approaches 
already in use by other programs represents a cost-effective means of 
obtaining quality assured data requisite for determining carbon dioxide 
mass emissions. Therefore, no changes to the current ways of collecting 
carbon dioxide and associated data needed for mass determination, such 
as flow rates, fuel heat content, fuel carbon content, and the like, 
are proposed. Because no changes are proposed and because the cost and 
burden for EGU owners or operators are already accounted for by other 
rulemakings, this aspect of the proposed rule is designed to have 
minimal, if any, cost or burden associated with carbon dioxide testing 
and monitoring. In addition, the proposal contains no changes to 
measurement and testing requirements for determining electrical output, 
both gross and net, as well as thermal output, to current existing 
requirements.
    However, the EPA requests comment on whether continuous carbon 
dioxide and flow measurements should become the sole means of 
compliance for this rule. Such a switch would increase costs for those 
EGU owners or operators who are currently relying on the oil- or gas-
fired or non-uniform fuel-fired calculation-based approaches for 
compliance. By way of reference, the annualized cost associated with 
adoption and use of continuous carbon dioxide and flow measurements 
where none now exist is estimated to be about $52,000. To the extent 
that the rule were to mandate continuous carbon dioxide and flow 
measurements in accordance with what is currently allowed as one option 
and that an EGU lacked this instrumentation, its owner or operator 
would need to incur this annual cost to obtain such information and to 
keep the instrumentation calibrated.
2. Requirements for Sources Implementing CCS
    The CCS process is also subject to monitoring and reporting 
requirements under the EPA's GHGRP (40 CFR part 98). The GHGRP requires 
reporting of facility-level GHG data and other relevant information 
from large sources and suppliers in the U.S. The ``suppliers of carbon 
dioxide'' source category of the GHGRP (GHGRP subpart PP) requires 
those affected facilities with production process units that capture a 
CO2 stream for purposes of supplying CO2 for 
commercial applications or that capture and maintain custody of a 
CO2 stream in order to sequester or otherwise inject it 
underground to report the mass of CO2 captured and supplied. 
Facilities that inject a CO2 stream underground for long-
term containment in subsurface geologic formations report quantities of 
CO2 sequestered under the ``geologic sequestration of carbon 
dioxide'' source category of the GHGRP (GHGRP subpart RR). In 2022, to 
complement GHGRP subpart RR, the EPA proposed the ``geologic 
sequestration of carbon dioxide with enhanced oil recovery (EOR) using 
ISO 27916'' source category of the GHGRP (GHGRP subpart VV) to provide 
an alternative method of

[[Page 33328]]

reporting geologic sequestration in association with 
EOR.496 497 498
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    \496\ 87 FR 36920 (June 21, 2022).
    \497\ International Standards Organization (ISO) standard 
designated as CSA Group (CSA)/American National Standards Institute 
(ANSI) ISO 27916:2019, Carbon Dioxide Capture, Transportation and 
Geological Storage--Carbon Dioxide Storage Using Enhanced Oil 
Recovery (CO2-EOR) (referred to as ``CSA/ANSI ISO 27916:2019'').
    \498\ As described in 87 FR 36920 (June 21, 2022), both subpart 
RR and proposed subpart VV (CSA/ANSI ISO 27916:2019) require an 
assessment and monitoring of potential leakage pathways; 
quantification of inputs, losses, and storage through a mass balance 
approach; and documentation of steps and approaches used to 
establish these quantities. Primary differences relate to the terms 
in their respective mass balance equations, how each defines 
leakage, and when facilities may discontinue reporting.
---------------------------------------------------------------------------

    The current rule leverages the regulatory requirements under GHGRP 
subpart RR and does not reference GHGRP subpart VV. The EPA is 
proposing that any affected unit that employs CCS technology that 
captures enough CO2 to meet the proposed standard and 
injects the captured CO2 underground must report under GHGRP 
subpart RR or proposed GHGRP subpart VV. If the emitting EGU sends the 
captured CO2 offsite, it must assure that the CO2 
is managed at a facility subject to the GHGRP requirements, and the 
facility injecting the CO2 underground must report under 
GHGRP subpart RR or proposed GHGRP subpart VV. This proposal does not 
change any of the requirements to obtain or comply with a UIC permit 
for facilities that are subject to the EPA's UIC program under the Safe 
Drinking Water Act.
    The EPA also notes that compliance with the standard is determined 
exclusively by the tons of CO2 captured by the emitting EGU. 
The tons of CO2 sequestered by the geologic sequestration 
site are not part of that calculation, though the EPA anticipates that 
the quantity of CO2 sequestered will be substantially 
similar to the quantity captured. However, to verify that the 
CO2 captured at the emitting EGU is sent to a geologic 
sequestration site, we are leveraging regulatory reporting requirements 
under the GHGRP. The BSER is determined to be adequately demonstrated 
based solely on geologic sequestration that is not associated with EOR. 
However, EGUs also have the compliance option to send CO2 to 
EOR facilities that report under GHGRP subpart RR or proposed GHGRP 
subpart VV. We also emphasize that this proposal does not involve 
regulation of downstream recipients of captured CO2. That 
is, the regulatory standard applies exclusively to the emitting EGU, 
not to any downstream user or recipient of the captured CO2. 
The requirement that the emitting EGU assure that captured 
CO2 is managed at an entity subject to the GHGRP 
requirements is thus exclusively an element of enforcement of the EGU 
standard. This will avoid duplicative monitoring, reporting, and 
verification requirements between this proposal and the GHGRP, while 
also ensuring that the facility injecting and sequestering the 
CO2 (which may not necessarily be the EGU) maintains 
responsibility for these requirements. Similarly, the existing 
regulatory requirements applicable to geologic sequestration are not 
part of the proposed rule.
3. Requirements for Sources Co-Firing Low-GHG Hydrogen
    Because the EPA is basing its proposed definition of low-GHG 
hydrogen consistent with IRC section 45V(b)(2)(D), it is reasonable, if 
possible and practicable, for the EPA to adopt, in whole or in part, 
the eligibility, monitoring, verification, and reporting protocols 
associated with IRC section 45V(b)(2)(D) when finalized by Treasury for 
the production of low-GHG hydrogen, and apply those protocols, as 
applicable, to requirements the EPA establishes for the demonstration 
by EGUs that they are using low-GHG hydrogen. Adopting very similar 
requirements for demonstrations by EGUs that they are using low-GHG 
hydrogen would help ensure there are not dueling eligibility 
requirements for low-GHG hydrogen production with overall emissions 
rates of 0.45 kg CO2e/kg H2 or less. Adopting 
similar methods for assessing GHG emissions associated with hydrogen 
production pathways would create clarity and certainty and reduce 
confusion.
    The EPA is taking comment on its proposal to closely follow 
Treasury protocols in determining how EGUs demonstrate compliance with 
the fuel characteristics required in this rulemaking. The EPA is taking 
comment on what forms of acceptable mechanisms and documentary evidence 
should be required for EGUs to demonstrate compliance with the 
obligation to co-fire low-GHG hydrogen, including proof of production 
pathway, overall emissions calculations or modeling results and input, 
purchasing agreements, contracts, and energy attribute certificates. 
Given the complexities of tracking produced hydrogen and the public 
interest in such data, the EPA is also taking comment on whether EGUs 
should be required to make fully transparent their sources of low-GHG 
hydrogen and the corresponding quantities procured. The EPA is also 
seeking comment on requiring that EGUs using low-GHG hydrogen 
demonstrate that their hydrogen is exclusively from facilities that 
only produce low-GHG hydrogen, as a means of reducing demonstration 
burden and opportunities for double counting that could otherwise occur 
for hydrogen purchased from facilities that produce multiple types of 
hydrogen and the complex recordkeeping and documentation that would be 
necessary to reliably verify that the hydrogen purchased from such 
facilities qualifies. The EPA solicits comment on a mechanism to 
operationalize such a provision.
    Treasury is currently developing implementing rules for IRC section 
45V. Congress specified that tax credit eligibility for the credit 
tiers (45V(b)(2)(A), 45(V)(b)(2)(B), 45(b)(2)(C), and 45V(b)(2)(D)) 
should be based on an assessment of the estimated well-to-gate \499\ 
GHG emissions of hydrogen production, determined based on the most 
recent Greenhouse gases, Regulated Emissions, and Energy use in 
Transportation model (GREET model) or a successor model as determined 
by the Secretary of Treasury. Consistent with its proposal to define 
low-GHG hydrogen consistent with IRC section 45V(b)(2)(D), the EPA is 
also proposing that, for the purpose of demonstrating compliance with 
the requirement to combust low-GHG hydrogen under this NSPS, the 
maximum extent possible the same methodology specified in IRC section 
45V and requirements currently under development should apply. One 
example would be requiring that the owner/operator of the combustion 
turbine obtain from the hydrogen producer from which they purchase low-
GHG hydrogen the hydrogen producer's calculation of GHG levels 
associated with its hydrogen production using the GREET well-to-gate 
analysis. The GREET model is well established, designed to adapt to 
evolving knowledge, and capable of including technological advances. 
The EPA solicits comment on whether the Agency should consider 
unrelated or third-party verification as part of the standards required 
for EGUs to demonstrate compliance. Given the

[[Page 33329]]

sequential timing of EPA and Treasury processes, the EPA may take 
further action, after promulgation of this NSPS, to provide additional 
guidance on application of Treasury's framework for IRC section 45V to 
this particular context. The EPA requests comment on its proposal to 
adopt as much as possible the methodology specified in IRC section 45V 
and any associated implementing requirements established by Treasury, 
once the methodology and implementing requirements are finalized, as 
part of the obligations for EGUs to demonstrate compliance with the 
requirement to combust low-GHG hydrogen under this NSPS.
---------------------------------------------------------------------------

    \499\ Well-to-gate analysis of lifecycle GHG emissions 
represents a smaller scope than cradle-to-grave analysis. Well-to-
gate emissions of hydrogen production include those associated with 
fossil fuel or electricity feedstock production and delivery to the 
hydrogen facility; the hydrogen production process itself; and any 
associated CCS applied at the hydrogen production facility. Well-to-
gate analysis does not consider emissions associated with the 
manufacture or end-of-life of the hydrogen production facility or 
facilities providing feedstock inputs to the hydrogen production 
facility. Nor does it consider emissions associated with 
transportation, distribution, and use of hydrogen beyond the 
production facility.
---------------------------------------------------------------------------

    Although proposing to incorporate as much as possible Treasury's 
eligibility, monitoring, reporting, and verification protocols, the EPA 
recognizes that Treasury protocols concern hydrogen production, whereas 
the EPA's proposed requirements apply to affected EGUs that use the 
hydrogen to demonstrate compliance with the low-GHG hydrogen co-firing 
obligations. The EPA is also taking comment on several underlying 
policy issues relevant to ensuring that hydrogen used to comply with 
this rule is low-GHG hydrogen. One reason that the EPA is considering 
whether an alternative method to the Treasury guidance may be needed to 
determine whether hydrogen meets the requirements to be considered low-
GHG is because hydrogen production facilities that begin construction 
after 2032 will not be eligible for the tax credits. The EPA wants to 
make sure a pathway exists for low-GHG hydrogen to be used for 
compliance purposes even if the producer began construction after 2032 
and is not receiving tax credits.
    Given this and other uncertainties, the EPA is taking comment on 
issues that would be relevant should the Agency develop its own 
protocols for EGUs to demonstrate compliance with the overall emissions 
rate in IRC section 45V(b)(2)(D) for co-firing as BSER in this 
rulemaking.
    The EPA is also taking comment on strategies the EPA could adopt to 
inform its own eligibility, monitoring, reporting and verification 
protocols for ensuring compliance with the 0.45 kg CO2e/kg 
H2 or less emission rate for compliance with the low-GHG 
provisions of this rule, if the EPA does not adopt Treasury's 
protocols. The purpose of these strategies would be to ensure that EGUs 
are using only low-GHG hydrogen, i.e., hydrogen that results in GHG 
emissions of less than 0.45 kg CO2 per kg H2. The 
EPA is taking comment on the appropriateness of requiring EGUs to 
provide verification that the hydrogen they use complies with this 
standard, as demonstrated by the GREET model for estimating the GHG 
emissions associated with hydrogen production from well-to-gate, and to 
what extent EGUs should be required to verify the accuracy of the 
energy inputs and conclusions of the GREET model for the hydrogen used 
by the EGU to comply with this rule.
    Several important considerations with respect to determining 
overall GHG emissions rates for hydrogen production pathways have been 
raised by researchers and have been picked up in trade press 
coverage.500 501 Given the importance of these issues, the 
recent accumulation of relevant research, and the range of stakeholder 
positions, the EPA is taking comment on the need for (and design of) 
approaches and appropriate timeframes for allowing EGUs to meet 
requirements for geographic and temporal alignment requirements to 
verify that the hydrogen used by the EGU is compliant with this 
rulemaking, recognizing that EPA's low-GHG standard for compliance 
would not begin until 2032. The EPA is soliciting comment on these 
issues, as they relate to co-firing low-GHG hydrogen in combustion 
turbines and the requisite need to only utilize the lowest-GHG hydrogen 
in these applications as specified in IRC section 45V, specifically IRC 
section 45V(b)(2)(D). The EPA notes this is one of multiple forthcoming 
opportunities for public comment on this suite of issues, and the EPA's 
proposal is specific to low-GHG hydrogen in the context of qualifying a 
co-firing fuel as part of BSER.
---------------------------------------------------------------------------

    \500\ Without Sufficient Guardrails, the Hydrogen Tax Credit 
Could Increase Emissions--Union of Concerned Scientists. ucsusa.org.
    \501\ Hydrogen's Power Grid Demands Under Scrutiny in Tax 
Credit. bloomberglaw.com.
---------------------------------------------------------------------------

    It is important to note that the landscape for methane emissions 
monitoring and mitigation is changing rapidly. For example, the EPA is 
in the process of developing enhanced data reporting requirements for 
petroleum and natural gas systems under its GHGRP, and is in the 
process of finalizing requirements under New Source Performance 
Standards and Emission Guidelines for the oil and gas sector that will 
result in mitigation of methane emissions. With these changes, it is 
expected that the quality of data to verify methane emissions will 
improve and methane emissions rates will change over time. Adequately 
identifying and accounting for overall emissions associated with 
methane-based feedstocks is essential in the determination of accurate 
overall emissions rates to comply with the low-GHG hydrogen standards 
in this rule. The EPA is taking comment on how methane leak rates can 
be appropriately quantified and conservatively estimated given the 
inherent uncertainties and wide range of basin-specific 
characteristics. The EPA is soliciting comment on whether EGUs should 
be required to produce a demonstration of augmented in-situ monitoring 
requirements to determine upstream emissions when methane feedstock is 
used for low-GHG hydrogen used by the EGU for compliance with this 
rule. The EPA is also taking comment on whether EGUs should use a 
default assumption for upstream methane leak rates in the event 
monitoring protocols are not finalized as part of this rulemaking, and 
what an appropriate default leak rate should be, including what 
evidence would be necessary for the EGU to deviate from that default 
assumption. The EPA is also taking comment on the appropriateness of 
requiring EGUs to provide CEMS data for SMR or ATR processes seeking to 
produce qualifying low-GHG hydrogen for co-firing to ensure the amount 
of carbon captured by CCS is properly and consistently monitored and 
outage rates and times are recorded and considered. The EPA is 
soliciting comment on providing EGUs with a representative and climate-
protective default assumption for carbon capture rates associated with 
SMR and ATR hydrogen pathways, inclusive of outages, if CCS is used for 
low-GHG hydrogen production as part of this rulemaking, including what 
evidence would be necessary for the EGU to deviate from that default 
assumption. These topics are particularly important to ensuring use of 
low-GHG hydrogen given the DOE estimate that by 2050, reformation-based 
production with CCS may account for 50-80 percent of total U.S. 
hydrogen production.\502\ The EPA is taking comment on requiring 
substantiation of energy inputs used in any overall GHG emissions 
assessment for hydrogen production used by EGUs for compliance with 
this requirement.
---------------------------------------------------------------------------

    \502\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
---------------------------------------------------------------------------

    In comparison with petrochemical-based hydrogen production pathways 
discussed above, electrolyzer-based hydrogen production has the 
potential for lower-GHG hydrogen because the technology is based on 
splitting water (H2O) molecules rather than splitting 
hydrocarbons (e.g., CH4).\503\ For EGUs

[[Page 33330]]

relying on hydrogen produced using this pathway, the EPA is seeking 
comment on the method for assuring that energy inputs to that 
production are consistent with the low-GHG hydrogen standard that EGUs 
would be required to meet under this rule. Specifically, the EPA is 
taking comment on requiring EGUs to provide substantiation of low-GHG 
energy inputs into any overall emissions assessment for electrolytic 
hydrogen production pathways for hydrogen used by the EGUs to comply 
with the low-GHG hydrogen standard in this rule. Energy Attribute 
Certificates (EACs) (EACs from renewable sources are sometimes known as 
Renewable Energy Credits or RECs) are produced for each megawatt hour 
of low-GHG generation and therefore offer a measurable, auditable, and 
verifiable approach for determining the GHG emissions associated with 
the energy used to make the low-GHG hydrogen. EACs with specific 
attributes are commonly used in the electricity markets to substantiate 
corporate clean energy commitments and use, as well as for utility 
compliance with State RPS and CES programs. The EPA is taking comment 
on requiring EGUs to provide EAC verification for low-GHG emission 
energy inputs into GHG emissions assessments for hydrogen used by that 
EGU to comply with the low-GHG standard in this rule, for all hydrogen 
pathways. The EPA is seeking comment on allowing EGUs to use EACs as 
part of the documentation required for verifying the use of low-GHG 
hydrogen.
---------------------------------------------------------------------------

    \503\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
---------------------------------------------------------------------------

    The EPA is taking comment on allowing EGUs to comply with the low-
GHG hydrogen standard in this rule if they demonstrate that the 
hydrogen used is produced from: (1) dedicated low-GHG emitting 
electricity from a generator sited on the utility side of a meter that 
is contractually obligated to a electrolyzer, (2) a generator 
collocated with an electrolyzer and sited behind a common utility 
meter, or (3) a generator whereby the electrolyzer and generator are 
collocated but not interconnected to the grid and have no grid 
exchanges of power. The EPA is also taking comment on approaches for 
EGUs to demonstrate that purchased hydrogen produced from an 
electrolyzer could meet the low-GHG standard, in whole or part, through 
an allotment of zero emitting electricity to a portion of the 
electrolyzer's hydrogen output. Many announced hydrogen production 
projects pair electrolyzers with renewable (including hydroelectric) or 
nuclear energy, which are likely capable of producing low-GHG hydrogen. 
Wind and solar renewable generation sources are variable, and nuclear 
units go offline for refueling purposes. In these cases, and others, 
grid-based electricity, which often has a high carbon intensity might 
be pursued in combination with EACs for each megawatt hour of grid-
based energy used. Aligning the time and place (temporal and geographic 
alignment) of EACs used to allocate and describe delivered grid-based 
electricity consumed could potentially help ensure that hydrogen used 
is low-GHG hydrogen.\504\ Some degree of alignment geographically, for 
example delivery of power to the balancing authority in which the 
electricity is consumed by the electrolyzer, could ensure that EACs 
used are representative of the allocation of the energy mix consumed by 
the electrolyzers. However, alignment could also entail trade-offs, 
about which the EPA would like more information.
---------------------------------------------------------------------------

    \504\ ``How Can Hydrogen Producers Show That They Are 
``Clean''?, Resources for the Future, October 27, 2022.
---------------------------------------------------------------------------

    In the case of temporal matching, the central issue is whether a 
producer must obtain sufficient EACs to match the total electricity 
demand of the electrolyzer on an annual basis corresponding to an 
overall emissions rates of 0.45 kg CO2e/kg H2 or less, or 
whether the producer must verify that it has obtained an EAC for low 
carbon generation on a more granular timeframe, such as an hourly or 
monthly basis, for each time period the electrolyzer is running. In 
other words, how can book and claim methods for grid-connected systems 
be developed to reliably claim total energy input emissions are 
equivalent to a pure off-grid zero-carbon emitting system. 
Considerations around how grid-based electricity can effectively assure 
zero-carbon emitting energy inputs as validated by EACs have received 
greater attention since passage of the IRA. Solutions offered by 
researchers at Princeton University include requiring new grid-based 
hydrogen producers to match 100 percent of electricity consumption on 
an hourly basis with new carbon-free generation (substantiated through 
EACs with hourly attributes), with an estimated cost impact of $1/
kg.\505\ Other research analyzing near-term emissions benefits of 
hourly EAC alignment with respect to IRC section 45V implementation is 
growing, with some divergent views about the emissions benefits of more 
precise alignment requirements.\506\ Several research papers have 
focused on the expense, trade-offs, and benefits of phasing in new and 
hourly EAC alignment requirements.\507\ An MIT Energy Initiative 
Working Paper examined emissions benefits of hourly alignment and 
supported a `` `a phased approach'. . . annual matching in the near 
term with a re-evaluation leaning towards hourly matching later on in 
the decade''.\508\ A Rhodium Report found that while ``[r]equiring a 
high degree of stringency across regional, temporal, and additionality 
variables on day one . . . increases the total subsidized cost of 
hydrogen production'' in the initial phase of the program, and 
concludes that ultimately ``policymakers can't ignore the long-term 
emissions risk'' and recommends, ``[t]o construct emissions guardrails, 
the IRS can establish target dates for ratcheting up the certainty on 
key implementation details like a transition to more temporally 
granular matching. Such phase-in approaches give the hydrogen and power 
industries the signposts they need to develop the tracking tools, 
calculation approaches, contract language, and other key elements to 
assure green hydrogen contributes to decarbonization.'' \509\ This 
analysis did not consider potential system-wide emissions impacts if 
costs present a near-term barrier to electrolytic hydrogen production, 
and reformation-based methods continue to dominate hydrogen production 
market share moving forward. Other research, for example from 
Princeton, supports hourly time-matching, additionality, and location 
requirements--arguing that all three pillars are important in ensuring 
low-GHG outcomes and that additional costs are not unreasonable. 
Research by Energy Innovation aligns with the Princeton study with 
respect to locational and additionality requirements and diverges in 
its recommendation of phasing in hourly EAC requirements by 2026.\510\
---------------------------------------------------------------------------

    \505\ Princeton Citation: Minimizing emissions from grid-based 
hydrogen production in the United States--IOPscience January 2023.
    \506\ American Council on Renewable Energy (ACORE), ``Analysis 
of Hourly & Annual GHG Emissions: Accounting for Hydrogen 
Production'', April 2023. acore.org.
    \507\ Energy Futures Initiative, ``The Hydrogen Demand Action 
Plan'', February 2023. https://energyfuturesinitiative.org/wp-content/uploads/sites/2/2023/02/EFI-Hydrogen-Hubs-FINAL-2-1.pdf.
    \508\ MIT Energy Initiative, April 2023 ``Producing hydrogen 
from electricity: How modeling additionality drives the emissions 
impact of time-matching requirements'' Anna Cybulsky, Michael 
Giovanniello, Tim Schittekatte, Dharik S. Mallapragada.
    \509\ Rhodium Group, ``Scaling Green Hydrogen in a post-IRA 
World'' March 16, 2023. https://rhg.com/research/scaling-clean-hydrogen-ira/.
    \510\ https://energyinnovation.org/wp-content/uploads/2023/04/Smart-Design-Of-45V-Hydrogen-Production-Tax-Credit-Will-Reduce-Emissions-And-Grow-The-Industry.pdf.

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

[[Page 33331]]

    The European Commission proposed a phased-in approach to defining 
what constitutes `renewable hydrogen' for the European Union (EU). The 
EU framework includes multiple components including temporal alignment 
requirements: monthly EAC alignment is required at the onset of the 
program, and hourly EAC alignment requirements are phased-in by 
2030.511 512 An impact assessment of the temporal alignment 
requirements is to be completed in 2028 and could impact the timing of 
the hourly EAC phase-in requirements. The EU hydrogen requirements and 
conditions will apply to domestic producers and imports and do not 
expire. EAC alignment requirements impact both new and existing 
projects. Geographic alignment for EACs is required at the onset of the 
EU program, whereas vintage requirements necessitating new zero-carbon 
emitting energy source-based generation, often called `additional', are 
phased in after 2028. The EU proposal was released in February and must 
be approved by the European Parliament and the Council of the EU within 
four months: amendments to the underlying policy are not permitted. 
Notably, unlike the United States, the EU has a carbon policy for power 
sector emissions that could help ensure that additional electricity 
demand from hydrogen production does not result in additional power 
sector CO2 emissions. The EU and stakeholders examining 
costs and benefits of temporal EAC alignment requirements generally 
find that hourly EAC alignment is preferred before the 2032 proposed 
effective date of hydrogen co-firing requirements in this proposed 
rule, with most converging on or before 2030.513 514
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    \511\ C_2023_1087_1_EN_ACT_part1_v8.pdf. (europa.eu)
    \512\ European Commission, ``Commission sets out rules for 
renewable hydrogen'' Brussels, February 13, 2023. See: Hydrogen 
(europa.eu), Delegated regulation on Union methodology for RFNBOs. 
(europa.eu)
    \513\ https://energyinnovation.org/wp-content/uploads/2023/04/Smart-Design-Of-45V-Hydrogen-Production-Tax-Credit-Will-Reduce-Emissions-And-Grow-The-Industry.pdf.
    \514\ April 12, 2023, memorandum, ``How annual matching for the 
Inflation Reduction Act's (IRA) 45V clean hydrogen tax credit can 
accelerate progress towards the Biden administration's 
decarbonization and clean hydrogen goals'' signed by 23 companies, 
addressed to Treasury Secretary Janet Yellen, Energy Secretary 
Jennifer Granholm and Senior Advisor to the President for Clean 
Energy Innovation and Implementation Mr. John Podesta, indicated an 
openness to examine hourly EAC requirements in 2032 or earlier and 
asserted, ``recent studies warn that overly stringent temporal 
matching would hinder the development of clean hydrogen industry.''
---------------------------------------------------------------------------

    The EPA is soliciting comment on requiring EGUs to use geographic 
and temporal alignment approaches for EAC-related requirements and the 
appropriate timing and trade-offs of such approaches. The EPA is 
soliciting comment on the appropriateness of requiring geographic 
alignment for EACs used in conjunction with energy inputs at the 
balancing authority level at the onset of the compliance period for 
BSER in 2032. Similarly, the EPA is soliciting comments on the 
appropriateness of requiring hourly EAC alignment requirements at the 
onset of the compliance period for BSER in 2032. Relatedly, the EPA is 
taking comment on whether any hourly EAC alignment requirements should 
affect both existing and new projects beginning in 2032, regardless of 
when a project became operational and a recipient of IRC section 45V 
credits.
    Hourly tracking systems are evolving to meet this need in real 
time. For example, PJM announced it would introduce EACs with hourly 
data stamping for low-GHG generators in March 2023. M-RETS, a regional 
attribute tracking system headquartered in the Midwest, has also 
introduced the capability to track hourly energy attributes. While 
several tracking systems are announcing or have started issuing hourly 
EACs, standardized methods, and nationwide coverage is still 
developing. Recognizing that the timing of EPA's proposed regulations 
would not require such tracking systems to be fully functional until 
the 2030s, the EPA is taking comment on the suitability of emerging and 
differentiated tracking systems to provide the infrastructure for 
hourly energy attribute tracking for EGUs complying with low-GHG 
hydrogen standards. The EPA is also taking comment on the need for 
energy attribute tracking systems to uniformly approach the issuance, 
allocation, tracking and retirement of hourly EACs using similar 
approaches to ensure a common and consistent national practice.

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

    The EPA is soliciting comment on appropriate mechanisms to ensure 
that the low-GHG hydrogen used by EGUs is actually low-GHG, and guard 
against EGU use of hydrogen that is falsely claimed to be low-GHG 
hydrogen. The EPA solicits comment on whether EGUs should be required 
to provide an independent third-party verification that hydrogen the 
EGU uses to comply with this regulation meets the requirements for low-
GHG hydrogen. EPA also solicits comment on whether any such verifying 
third party must hold an active accreditation from an accrediting body, 
such as the California Air Resources Board's Low Carbon Fuels Standards 
Program or the International Standards Organization 14064 Code. EPA 
seeks comment on any other mechanisms to ensure that hydrogen used by 
EGUs meets the low-GHG standard and what the remedy should be if an EGU 
uses hydrogen that is determined not to meet the definition of low-GHG 
hydrogen.

M. Recordkeeping and Reporting Requirements

    The current rule (subpart TTTT of 40 CFR part 60) requires EGU 
owners or operators to prepare reports in accordance with the Acid Rain 
Program's ECMPS and, for the EGUs relying on the compliance approaches 
contained in Appendix G of 40 CFR part 75, with the reporting 
requirements of that Appendix. Such reports are to be submitted 
quarterly. The EPA believes all EGU owners and operators have extensive 
experience in using the ECMPS and use of a familiar system ensures 
quick and effective rollout of the program in today's proposal. Because 
all EGUs are expected to be covered by and included in the ECMPS, 
minimal, if any, costs for reporting are expected for this proposal. In 
the unlikely event that a specific EGU is not already covered by and 
included in the ECMPS, the estimated annual per unit cost would be 
about $8,500.
    The current rule's recordkeeping requirements at 40 CFR part 
60.5560 rely on a combination of general provision requirements (see 40 
CFR 60.7(b) and (f)), requirements at subpart F of 40 CFR part 75, and 
an explicit list of items, including data and calculations; the EPA 
proposes to retain those existing subpart TTTT of 40 CFR part 60 
requirements in the new NSPS subpart TTTTa of 40 CFR part 60. The 
annual cost of those recordkeeping requirements would be the same 
amount as is required for subpart TTTT of 40 CFR part 60 recordkeeping. 
As the recordkeeping in subpart TTTT of 40 CFR part 60 will be replaced 
by similar recordkeeping in subpart TTTTa of 40 CFR part 60 upon 
promulgation, this annual cost for recordkeeping will be maintained.

N. Additional Solicitations of Comment and Proposed Requirements

    This section includes additional issues the Agency is specifically 
soliciting comment on. It also provides a summary of some of the key 
considerations the EPA is soliciting comment on with respect to the

[[Page 33332]]

proposed CAA section 111(b) requirements.
1. CCS and Co-Firing Low-GHG Hydrogen as BSER for the Base Load 
Subcategory
    As described above, the EPA is proposing to establish two 
subcategories with different standards for the base load subcategory, 
each based on a different BSER pathway. The first is based on a BSER of 
CCS with 90 percent capture by 2035. The second is based on a BSER of 
co-firing 30 percent (by volume) low-GHG hydrogen by 2032 and co-firing 
96 percent (by volume) by 2038. (Both pathways include efficient 
equipment and operation and maintenance as an initial component of the 
BSER.) In other sections of this preamble, the EPA solicits comment on 
variations in the amount of emissions reduction and the dates for 
compliance for each pathway.
    The EPA believes that if it finalizes a subcategory approach with 
different standards in which sources may choose between the two 
standards and BSER pathways, each must achieve environmentally 
comparable emission reductions. Thus, if the EPA determines based on 
all of the statutory considerations that CCS with 90 percent capture 
qualifies as the BSER for base load combustion sources, then co-firing 
hydrogen could qualify as well only if it also achieves comparable 
reductions. Because the emissions standards are technology neutral, if 
the two pathways can achieve the same emissions reductions at the same 
time, there would be no need to establish separate subcategories and 
standards as sources could adopt either BSER pathway to meet the 
standard. But the EPA also believes that these two technologies may 
achieve comparable emissions reductions at slightly different times, 
thus potentially necessitating two alternate standards. 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. From the perspective of an individual turbine, the 
proposed co-firing with low-GHG hydrogen-based standard results in 
earlier emission reductions because it takes effect in 2032, three 
years before the CCS-based standard, but the low-GHG hydrogen-based 
standard could also result in fewer total emission reductions because 
the 90 percent emission rate reduction is not required until 2038, 
three years after the CCS-based standard. Although early emission 
reductions have value in addressing climate change, it is the 
cumulative impact of the emission reductions that is of primary 
importance given the short time-scale over which those early reductions 
are occurring. The EPA also solicits comment on the potential benefits 
of prescribing two separate standards for new base load combustion 
turbines. Owners and operators of new combustion turbine EGUs are 
currently pursuing both CCS and co-firing with low-GHG hydrogen as 
approaches for reducing GHG emissions, and both require the development 
of infrastructure that may proceed at a different pace and scale and 
achieve emissions reductions on different timelines with respect to 
each technology. Although both CCS and co-firing with low-GHG hydrogen 
are, or are expected to be, broadly available throughout the United 
States, the EPA solicits comment on whether individual locations where 
new base load combustion turbines might be constructed might lend 
themselves more to one technology than the other (based on pipeline 
availability, proximity to hydrogen production or geologic 
sequestration sites, etc.). The EPA recognizes that the design of CAA 
section 111--whereby sources decide which emissions controls they use 
to meet standards of performance--provides sources with operational 
flexibility so long as they achieve the standard. A subcategory 
approach, however, may allow the EPA to consider the potentially 
differing scale and pace at which these technologies can achieve 
environmentally equivalent emissions reductions and whether there are 
characteristics of units that make one or the other pathways ``best'' 
for those types of units.
    As an alternative to the proposed approach of two standards and 
BSER pathways for the base load subcategory, the EPA is soliciting 
comment on having a single standard, which would be based on CCS with 
90 percent capture (along with efficiency as the initial component of 
the BSER). Under this alternative, the EPA would not establish a 
separate base load subcategory for combustion turbines that adopt the 
low-GHG hydrogen co-firing pathway.
    The EPA solicits comment on whether finalizing a single, CCS-based 
standard for the baseload subcategory better reflects the more likely 
uses of hydrogen as a source of fuel in new combustion turbines. The 
EPA has proposed a standard for base load combustion turbines that 
adopt the low-GHG hydrogen co-firing in part because the Agency 
understands a number of power companies are actively developing 
combustion turbines that are designed to co-fire hydrogen. However, the 
Agency recognizes that power companies may ultimately come to utilize 
low-GHG hydrogen as a storage fuel reserved for intermediate load 
combustion turbines that support variable renewable generation, rather 
than for combustion turbines that generate at base load. An approach in 
which the EPA establishes a single CCS-based second phase standard for 
base load combustion turbines, along with a second phase standard for 
intermediate load combustion turbines that is based on low-GHG hydrogen 
as a component of the BSER, would align with this potential scenario. 
In addition, if an owner or operator of a new combustion turbine does 
seek to utilize low-GHG hydrogen for base load generation, a single 
CCS-based second phase standard for base load combustion turbines would 
not preclude owners and operators from utilizing low-GHG hydrogen as a 
means of compliance. Owners/operators could also comply with a CCS-
based standard by co-firing 96 percent (by volume) low-GHG hydrogen 
from the outset of the second phase--rather than the proposed approach 
that would delay requirements for this level of co-firing until 2038.
2. Co-Firing Low-GHG Hydrogen as BSER for Intermediate Load Combined 
Cycle and Simple Cycle Subcategories
    The EPA is also soliciting comment on subcategorizing intermediate 
load combustion turbines into an intermediate load combined cycle 
subcategory and an intermediate load simple cycle subcategory. The BSER 
for both subcategories would be two components: (1) Highly efficient 
generation (either combined cycle technology or simple cycle 
technology, respectively) and (2) co-firing 30 percent (by volume) low-
GHG hydrogen, with the first component applying when the source 
commences operation and the second component applying in the year 2032. 
Dividing the intermediate load subcategory into these two subcategories 
would assure that intermediate load combined cycle turbines would have 
a more stringent standard of performance--that is, expressed in a lower 
lb CO2/MWh--than intermediate load simple cycle turbines.
3. Integrated Onsite Generation and Energy Storage
    Integrated equipment is currently included as part of the affected 
facility and the EPA is soliciting comment on the best approach to 
recognizing the

[[Page 33333]]

environmental benefits of onsite integrated non-emitting generation and 
energy storage. The EPA is proposing regulatory text to clarify that 
the output from integrated renewables is included as output when 
determining the NSPS emissions rate. The EPA is also proposing that the 
output from the integrated renewable generation is not included when 
determining the net electric sales for applicability purposes. In the 
alternative, the EPA is soliciting comment on whether instead of 
exempting the generation from the integrated renewables from counting 
toward electric sales, the potential output from the integrated 
renewables would be included when determining the design efficiency of 
the facility. Since the design efficiency is used when determining the 
electric sales threshold this would increase the allowable electric 
sales for subcategorization purposes. Including the integrated 
renewables when determining the design efficiency of the affected 
facility would have the impact of increasing the operational 
flexibility of owners/operators of intermediate load combustion 
turbines. Renewables typically have much lower 12-operating month 
capacity factors than the intermediate electric sales threshold so 
could allow the turbine engine itself to operate at a higher capacity 
factor while still being considered an intermediate load EGU. 
Conversely, if the integrated renewables operate at a 12-operating 
month capacity factor of greater than 20 percent that would reduce the 
ability of a peaking turbine engine to operate while still remaining in 
the low load subcategory. However, even if a combustion turbine engine 
itself were to operate at a capacity factor of less than 20 percent and 
become categorized as an intermediate load combustion turbine when the 
output form the integrated renewables are considered, the output from 
the integrated renewables could lower the emissions rate such that the 
affected facility would be in compliance with the intermediate load 
standard of performance.
    For integrated energy storage technologies, the EPA is soliciting 
comment on including the rated output of the energy storage when 
determining the design efficiency of the affected facility. Similar to 
integrated renewables, this would increase the flexibility of owner/
operators to operate at higher capacity factors while remaining in the 
low and intermediate load subcategories. The EPA is not proposing that 
the output from the energy storage be considered in either determining 
the NSPS emissions rate or as net electric sales for subcategorization 
applicability purposes. While additional energy storage will allow for 
integration of additional variable renewable generation, the energy 
storage devices could be charged using grid supplied electricity that 
is generated from other types of generation. Therefore, this is not 
necessarily stored low-GHG electricity.
4. Definition of System Emergency
    40 CFR part 60, subpart TTTT (and the proposed 40 CFR part 60, 
subpart TTTTa) include a provision that electricity sold during hours 
of operation when a unit is called upon to operate due to a system 
emergency is not counted toward the percentage electric sales 
subcategorization threshold.\515\ The EPA concluded that this exclusion 
is necessary to provide flexibility, to maintain system reliability, 
and to minimize overall costs to the sector (80 FR 64612; October 23, 
2015). Some in the regulated community have informed the Agency that 
additional clarification on a system emergency would need to be 
determined and documented for compliance purposes. The intent is that 
the local grid operator would determine which EGUs are essential to 
maintain grid reliability. The EPA is soliciting comments on amending 
the definition of system emergency to clarify how it would be 
implemented. The current text is any abnormal system condition that the 
RTO, Independent System Operators (ISO) or control area Administrator 
determines requires immediate automatic or manual action to prevent or 
limit loss of transmission facilities or generators that could 
adversely affect the reliability of the power system and therefore call 
for maximum generation resources to operate in the affected area, or 
for the specific affected EGU to operate to avert loss of load.
---------------------------------------------------------------------------

    \515\ Electricity sold by units that are not called upon to 
operate due to a system emergency (e.g., units already operating 
when the system emergency is declared) is counted toward the 
percentage electric sales threshold.
---------------------------------------------------------------------------

5. Definition of Natural Gas
    40 CFR part 60, subpart TTTT (and the proposed 40 CFR part 60, 
subpart TTTTa) include a definition of natural gas. Natural gas is a 
fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), 
composed of at least 70 percent methane by volume or that has a gross 
calorific value between 35 and 41 megajoules (MJ) per dry standard 
cubic meter (950 and 1,100 Btu per dry standard cubic foot), that 
maintains a gaseous state under ISO conditions. Finally, natural gas 
does not include the following gaseous fuels: Landfill gas, digester 
gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, 
producer gas, coke oven gas, or any gaseous fuel produced in a process 
which might result in highly variable CO2 content or heating 
value. The EPA is soliciting comment on if the exclusions for specific 
gases such as landfill gas, etc. are necessary of if they should be 
deleted. If landfill gas, coal-derived gas, or other gases are 
processed to meet the methane and heating value content of pipeline 
quality natural gas they could be mixed into the pipeline network and 
it is the intent that this mixture be considered natural gas for the 
purposes of 40 CFR part 60, subpart TTTT and the proposed 40 CFR part 
60, subpart TTTTa.
6. Summary of Solicitation of Comment on BSER Variations
    This section summarizes the variations on the subcategories and on 
BSER for combustion turbines on which the EPA is soliciting comment. It 
is intended to highlight certain aspects of the proposal the Agency is 
soliciting comment on and is not intended to cover all aspects of the 
proposal.
    For the low load subcategory, the EPA is soliciting comment on:
     An electric sales threshold of between 15 to 25 percent 
for all combustion turbines regardless of the specific design 
efficiency.
     An electric sales threshold based on three quarters of the 
design efficiency of the combustion turbine. This would result in 
electric sales thresholds of 18 to 22 percent for simple cycle turbines 
and 26 to 31 percent for combined cycle turbines.
     Applying a second component of BSER, co-firing 30 percent 
(by volume) low-GHG hydrogen by 2032.
    For the intermediate load subcategory, the EPA is soliciting 
comment on:
     An efficiency-based standard of performance of between 
1,000 to 1,200 lb CO2/MWh-gross.
     The use of steam injection as part of the first BSER 
component.
     An electric sales threshold based on 94 percent of the 
design efficiency. This would result in electric sales thresholds of 29 
to 35 percent for simple cycle turbines and 40 to 49 percent for 
combined cycle turbines.
     A hydrogen co-firing range of 30 to 50 percent by volume 
as the second component of the BSER.
     Beginning implementation of the second component of the 
BSER (i.e., hydrogen co-firing) as early as 2030.
     The second component of the BSER would establish separate 
subcategories

[[Page 33334]]

for simple and combined cycle intermediate load combustion turbines, 
both based on co-firing low-GHG hydrogen.
     Adding a third phase standard based on higher levels of 
low-GHG hydrogen co-firing by 2038.
    For the base load subcategory, the EPA is soliciting comment on:
     An efficiency-based standard of performance of between 730 
to 800 lb CO2/MWh-gross for large combustion turbines.
     An efficiency-based standard of performance of between 850 
to 900 lb CO2/MWh-gross for small combustion turbines.
     Beginning implementation of the second component of the 
BSER (i.e., CCS or hydrogen co-firing) as early as 2030.
     Beginning implementation of the third component of the co-
firing low-GHG hydrogen-based BSER earlier than 2038.
     Whether the third component of the hydrogen BSER should be 
96 percent by volume or a lower volume--note that if it is a lower 
volume that raises issues as to whether the BSER would be appropriate 
if EPA found that a CCS BSER of 90% for NGCCs was generally applicable
     A hydrogen co-firing range of 30 to 50 percent as the 
second component of the BSER for combustion turbines co-firing 
hydrogen.
     A single standard based on either a CCS-based BSER or a 
co-firing low-GHG-hydrogen based BSER for all base load combustion 
turbines.
     A carbon capture rate of 90 to 95 percent as the second 
component of the CCS-based BSER.

O. Compliance Dates

    The EPA is proposing that affected sources that commenced 
construction or reconstruction after May 23, 2023, would need to meet 
the requirements of 40 CFR part 60, subpart TTTTa upon startup of the 
new or reconstructed affected facility or the effective date of the 
final rule, whichever is later. This proposed compliance schedule is 
consistent with the requirements in section 111 of the CAA.

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

A. 2018 NSPS Proposal

    The EPA promulgated NSPS for GHG emissions from fossil fuel-fired 
steam generating units in 2015. 80 FR 64510 (October 23, 2015). As 
discussed in section V.B.2 of this preamble, on December 20, 2018, the 
EPA proposed amendments that would revise the determination of the BSER 
for control of GHG emissions from newly constructed coal-fired steam 
generating units in 40 CFR part 60, subpart TTTT (83 FR 65424; December 
20, 2018). The EPA is not reopening for comment or soliciting comment 
on the 2018 NSPS Proposal, and intends to further address it in a 
separate action.
1. Additional Amendments
    The EPA is proposing multiple less significant amendments. These 
amendments would be either strictly editorial and would not change any 
of the requirements of 40 CFR part 60, subpart TTTT or are intended to 
add additional compliance flexibility. The proposed amendments would 
also be incorporated into the proposed subpart TTTTa. For additional 
information on these amendments, see the redline strikeout version of 
the rule showing the proposed amendments. First, the EPA is proposing 
editorial amendments to define acronyms the first time they are used in 
the regulatory text. Second, the EPA is proposing to add International 
System of Units (SI) equivalent for owners/operators of stationary 
combustion turbines complying with a heat input-based standard. Third, 
the EPA is proposing to fix errors in the current 40 CFR part 60, 
subpart TTTT regulatory text referring to part 63 instead of part 60. 
Fourth, as a practical matter owners/operators of stationary combustion 
turbines subject to the heat input-based standard of performance need 
to maintain records of electric sales to demonstrate that they are not 
subject to the output-based standard of performance. Therefore, the EPA 
is proposing to add a specific requirement that owner/operators 
maintain records of electric sales to demonstrate they did not sell 
electricity above the threshold that would trigger the output-based 
standard. Next, the EPA is proposing to update the ANSI, ASME, and ASTM 
test methods to include more recent versions of the test methods. 
Finally, the EPA is proposing to add additional compliance 
flexibilities for EGUs either serving a common electric generator or 
using a common stack. Specifically, for EGUs serving a common electric 
generator, the EPA is soliciting comment on whether the Administrator 
should be able to approve alternate methods for determining energy 
output. For EGUs using a common stack, the EPA is soliciting comment on 
whether specific procedures should be added for apportioning the 
emissions and/or if the Administrator should be able to approve site-
specific alternate procedures.

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

1. New Construction and Reconstruction
    The EPA promulgated NSPS for GHG emissions from fossil fuel-fired 
steam generating units in 2015. As noted in section IV.F, the EPA is 
not aware of any plans by any companies to undertake new construction 
of a new fossil fuel-fired steam generating unit, or to undertake a 
reconstruction of an existing fossil fuel-fired steam generating unit, 
that would be subject to the 2015 NSPS for steam generating units. 
Accordingly, the EPA does not consider it necessary, nor a good use of 
agency resources, to review the NSPS for new construction or 
reconstruction. See ``New Source Performance Standards (NSPS) Review: 
Advanced notice of proposed rulemaking,'' 76 FR 65653, 65658 (October 
24, 2011) (suggesting it may not be necessary for the EPA to review an 
NSPS when no new construction, modification, or reconstruction is 
expected in the source category). Should events change and the EPA 
learns that companies plan to undertake construction of a new fossil 
fuel-fired steam generating unit or reconstruction of an existing 
fossil fuel-fired steam generating unit, the EPA would consider 
reviewing these standards.
2. Modifications
    In the 2015 NSPS, the EPA issued final standards for a steam 
generating unit that implements a ``large modification,'' defined as a 
physical change, or change in the method of operation, that results in 
an increase in hourly CO2 emissions of more than 10 percent 
when compared to the source's highest hourly emissions in the previous 
5 years. Such a modified steam generating unit is required to meet a 
unit-specific CO2 emission limit determined by that unit's 
best demonstrated historical performance (in the years from 2002 to the 
time of the modification). The 2015 NSPS did not include standards for 
a steam generating unit that implements a ``small modification,'' 
defined as a change that results in an increase in hourly 
CO2 emissions of less than or equal to 10 percent when 
compared to the source's highest hourly emissions in the previous 5 
years. 80 FR 64514 (October 23, 2015).
    In the 2015 NSPS, the EPA explained its basis for promulgating this 
rule as follows. The EPA has historically been notified of only a 
limited number of NSPS modifications involving fossil steam generating 
units and therefore predicted that very few of these units

[[Page 33335]]

would trigger the modification provisions and be subject to the 
proposed standards. Given the limited information that we have about 
past modifications, the agency has concluded that it lacks sufficient 
information to establish standards of performance for all types of 
modifications at steam generating units at this time. Instead, the EPA 
has determined that it is appropriate to establish standards of 
performance at this time for larger modifications, such as major 
facility upgrades involving, for example, the refurbishing or 
replacement of steam turbines and other equipment upgrades that result 
in substantial increases in a unit's hourly CO2 emissions 
rate. The agency has determined, based on its review of public comments 
and other publicly available information, that it has adequate 
information regarding the types of modifications that could result in 
large increases in hourly CO2 emissions, as well as on the 
types of measures available to control emissions from sources that 
undergo such modifications, and on the costs and effectiveness of such 
control measures, upon which to establish standards of performance for 
modifications with large emissions increases at this time. Id. at 
64597-98. The EPA is not reopening any aspect of these determinations 
concerning modifications in the 2015 NSPS, except, as noted below, for 
the BSER and associated requirements for large modifications.
    Because the EPA has not promulgated a NSPS for small modifications, 
any existing steam generating unit that undertakes a change that 
increases its hourly CO2 emissions rate by 10 percent or 
less would continue to be treated as an existing source that is subject 
to the CAA section 111(d) requirements being proposed today.
    With respect to large modifications, we explained in the 2015 NSPS 
that they are rare, but there is record evidence indicating that they 
may occur. Id. at 64598. Because the EPA is proposing requirements for 
existing sources that are, on their face, more stringent than the 
requirements for large modifications, the EPA believes it is 
appropriate to review and revise the latter requirements to minimize 
the anomalous incentive that an existing source could have to undertake 
a large modification for the purpose of avoiding the more stringent 
requirements that it would be subject to if it remained an existing 
source. Accordingly, the EPA is proposing to revise the BSER for large 
modifications to mirror the BSER for the subcategory of coal-fired 
steam generating units that plan to operate past December 31, 2039, 
that is, the use of CCS with 90 percent capture of CO2. The 
EPA believes that it is reasonable to assume that any existing source 
that invests in a physical change or change in the method of operation 
that would qualify as a large modification expects to continue to 
operate past 2039. Accordingly, the EPA proposes that CCS with 90 
percent capture qualifies as the BSER for such a source for the same 
reasons that it qualifies as the BSER for existing sources that plan to 
operate past December 31, 2039. The EPA discusses these reasons in 
section X.D.1.a. The EPA is proposing to determine that CCS with 90 
percent capture qualifies as the BSER for large modifications, and not 
the controls determined to be the BSER in the 2015 NSPS, due to the 
recent reductions in the cost of CCS. The EPA does not believe there 
are any considerations relative to a source undertaking a large 
modification that point towards a control system other than CCS with 90 
percent capture qualifying as the BSER. The Agency solicits comment on 
this issue.
    By the same token, the EPA is proposing that the degree of emission 
limitation associated with CCS with 90 percent capture is an 88.4 
percent reduction in emission rate (lb CO2/MWh-gross basis), 
the same as proposed for existing sources with CCS with 90 percent 
capture. See section X.D.1.a.iv. Based on this degree of emission 
limitation, the EPA is proposing that the standard of performance for 
steam generating units that undertake large modifications after the 
date of publication of this proposal is a unit-specific emission limit 
determined by an 88.4 percent reduction in the unit's best historical 
annual CO2 emission rate (from 2002 to the date of the 
modification). The EPA is proposing that an owner/operator of a 
modified steam generating unit comply with the proposed emissions rate 
upon startup of the modified affected facility or the effective date of 
the final rule, whichever is later. The EPA is proposing the same 
testing, monitoring, and reporting requirements as are currently in 40 
CFR part 60, subpart TTTT.

C. Projects Under Development

    Finally, during the 2015 NSPS rulemaking, the EPA identified the 
Plant Washington project in Georgia and the Holcomb 2 project in Kansas 
as EGU ``projects under development'' based on representations by 
developers that the projects had commenced construction prior to the 
proposal of the 2015 NSPS and, thus, would not be new sources subject 
to the final NSPS (80 FR 64542-43; October 23, 2015). The EPA did not 
set a performance standard at the time but committed to doing so if new 
information about the projects became available. These projects were 
never constructed and are no longer expected to be constructed.
    The Plant Washington project was to be an 850-MW supercritical 
coal-fired EGU. The Environmental Protection Division (EPD) of the 
Georgia Department of Natural Resources issued air and water permits 
for the project in 2010 and issued amended permits in 
2014.516 517 518 In 2016, developers filed a request with 
the EPD to extend the construction commencement deadline specified in 
the amended permit, but the director of the EPD denied the request, 
effectively canceling the approval of the construction permit and 
revoking the plant's amended air quality permit.\519\
---------------------------------------------------------------------------

    \516\ https://www.gpb.org/news/2010/07/26/judge-rejects-coal-plant-permits.
    \517\ https://www.southernenvironment.org/press-release/court-rules-ga-failed-to-set-safe-limits-on-pollutants-from-coal-plant/.
    \518\ https://permitsearch.gaepd.org/permit.aspx?id=PDF-OP-22139.
    \519\ https://www.southernenvironment.org/wp-content/uploads/legacy/words_docs/EPD_Plant_Washington_Denial_Letter.pdf.
---------------------------------------------------------------------------

    The Holcomb 2 project was intended to be a single 895-MW coal-fired 
EGU and received permits in 2009 (after earlier proposals sought 
approval for development of more than one unit). In 2020, after 
developers announced they would no longer pursue the Holcomb 2 
expansion project, the air permits were allowed to expire, effectively 
canceling the project.
    For these reasons, the EPA is proposing to remove these projects 
under the applicability exclusions in subpart TTTT.

IX. Proposed ACE Rule Repeal

    The EPA is proposing to repeal the ACE Rule. A general summary of 
the ACE Rule, including its regulatory and judicial history, is 
included in section V.B of this preamble. The repeal of the ACE Rule is 
intended to stand alone and be severable from the other aspects of this 
rule. The EPA proposes to repeal the ACE Rule on three grounds that 
together, and each independently, justify the rule's repeal. First, as 
a policy matter, the EPA believes that the suite of heat rate 
improvements (HRI) the ACE Rule selected as the BSER should be 
reexamined and are no longer an appropriate BSER for existing coal-
fired EGUs. The EPA concludes that the suite of HRI set forth in the 
ACE Rule provide

[[Page 33336]]

negligible CO2 reductions at best and, in many cases, could 
increase CO2 emissions because of the rebound effect, as 
explained in section X.D.5.a. These concerns taken together, along with 
new evidence, and the EPA's experience in implementing the ACE Rule, 
cast doubt on the ACE Rule's minimal projected emission reductions and 
increase the likelihood that the ACE Rule could make CO2 
pollution worse. As a result, the EPA has determined it is appropriate 
to repeal the rule, and to reevaluate whether other technologies 
constitute the BSER.
    Second, the ACE Rule rejected CCS and natural gas co-firing as the 
BSER for reasons that no longer apply. This rule should be repealed so 
that EPA may determine the BSER based on evaluating all the candidate 
technologies. Since the ACE Rule was promulgated, changes in the power 
industry, developments in the costs of controls, and new Federal 
subsidies have made these other technologies more broadly available and 
less expensive. The EPA is now proposing that these technologies are 
the BSER for certain subcategories of sources, as described in section 
X of this preamble.
    Third, the EPA concludes that the ACE Rule conflicted with CAA 
section 111 and the EPA's implementing regulations because it did not 
specifically identify the BSER or the ``degree of emission limitation 
achievable though application of the [BSER],'' but set forth an 
indeterminate range of values. Thus, the rule did not provide the 
States with adequate guidance on the degree of emission limitation that 
must be reflected in the standards of performance so that a State plan 
would be approvable by the EPA. Along with this, the ACE Rule also 
improperly departed from the statutory framework of CAA section 111(d) 
by categorically precluding States from allowing their sources to 
comply with standards of performance by trading or averaging. Properly 
construed, CAA section 111(d) gives States discretion to provide 
sources with certain compliance flexibilities, including trading or 
averaging in appropriate circumstances so long as the other 
requirements of section 111 are met as described below.

A. Summary of Selected Features of the ACE Rule

    The ACE Rule determined that the BSER for coal-fired EGUs was a 
``list of `candidate technologies,' '' consisting of seven types of the 
``most impactful HRI technologies, equipment upgrades, and best 
operating and maintenance practices,'' (84 FR 32536; July 8, 2019), 
including, among others, ``Boiler Feed Pumps'' and ``Redesign/Replace 
Economizer.'' Id. at 32537 (table 1). The rule provided a range of 
improvements in heat rate that each of the seven ``candidate 
technologies'' could achieve if applied to coal-fired EGUs of different 
capacities. For six of the technologies, the expected level of 
improvement in heat rate ranged from 0.1-0.4 percent to 1.0-2.9 
percent, and for the seventh technology, ``Improved Operating and 
Maintenance (O&M) Practices,'' the range was ``0 to >2%.'' Id. The ACE 
Rule explained that States must review each of their designated 
facilities, on either a source-by-source or group-of-sources basis, and 
``evaluate the applicability of each of the candidate technologies.'' 
Id. at 32550. States were to use the list of HRI technologies ``as 
guidance but will be expected to conduct unit-specific evaluations of 
HRI potential, technical feasibility, and applicability for each of the 
BSER candidate technologies.'' Id. at 32538.
    The ACE Rule emphasized that States had ``inherent flexibility'' in 
undertaking this task with ``a wide range of potential outcomes.'' Id. 
at 32542. The ACE Rule provided that States could conclude that it was 
not appropriate to apply some technologies. Id. at 32550. Moreover, if 
a State did decide to apply a particular technology to a particular 
source, the State could determine the level of heat rate improvement 
from the technology to be anywhere within the range that the EPA had 
identified for that technology, or even outside that range. Id. at 
32551. The ACE Rule stated that after the State evaluated the 
technologies and calculated the amount of HRI in this way, it should 
determine the standard of performance that the source could achieve, 
Id. at 32550, and then adjust that standard further based on the 
application of source-specific factors such as remaining useful life. 
Id. at 32551.
    The ACE Rule then identified the process by which States had to 
take these actions. States must ``evaluat[e] each'' of the seven 
candidate technologies and provide a summary, which ``include[s] an 
evaluation of the . . . degree of emission limitation achievable 
through application of the technologies.'' Id. at 32580. Then, the 
State must provide a variety of information about each power plant, 
including, the plant's ``annual generation,'' ``CO2 
emissions,'' ``[f]uel use, fuel price, and carbon content,'' 
``operation and maintenance costs,'' ``[h]eat rates,'' ``[e]lectric 
generating capacity,'' and the ``timeline for implementation,'' among 
other information. Id. at 32581. The EPA explained that the purpose of 
this data was to allow the Agency to ``adequately and appropriately 
review the plan to determine whether it is satisfactory.'' Id. at 
32558.
    The ACE Rule projected a very low level of overall emission 
reduction if States generally applied the set of candidate technologies 
to their sources. The rule was projected to achieve a less-than-1-
percent reduction in power-sector CO2 emissions by 
2030.\520\ Further, the EPA also projected that it would increase 
CO2 emissions from power plants in 15 States and the 
District of Columbia because of the ``rebound effect'' as sources 
implemented HRI measures and became more efficient. This phenomenon is 
explained in more detail in section X.D.5.a.\521\
---------------------------------------------------------------------------

    \520\ ACE Rule RIA 3-11, table 3-3.
    \521\ The rebound effect becomes evident by comparing the 
results of the ACE Rule IPM runs for the 2018 reference case, EPA, 
IPM State-Level Emissions: EPAv6 November 2018 Reference Case, EPA-
HQ-OAR-2017-0355-26720, and for the ``Illustrative ACE Scenario. IPM 
State-Level Emissions: Illustrative ACE Scenario, EPA-HQ-OAR-2017-
0355-26724.
---------------------------------------------------------------------------

    The ACE Rule considered several other control measures as the BSER, 
including co-firing with natural gas and CCS, but rejected them. The 
ACE Rule rejected co-firing with natural gas primarily on grounds that 
it was too costly in general, and especially for sources that have 
limited or no access to natural gas. 84 FR 32545 (July 8, 2019). The 
rule also concluded that generating electricity by co-firing natural 
gas in a utility boiler would be an inefficient use of the gas when 
compared to combusting it in a combustion turbine. Id. The ACE Rule 
rejected CCS on grounds that it was too costly. Id. at 32548. The rule 
identified the high capital and operating costs of CCS and noted the 
fact that the IRC 45Q tax credit, as it then applied, would provide 
only limited benefit to sources. Id. at 32548-49.
    In addition, the ACE Rule interpreted CAA section 111 to preclude 
States from allowing their sources to trade or average to demonstrate 
compliance with their standards of performance. Id. at 32556-57.

B. Developments Undermining ACE Rule's Projected Emission Reductions

    The EPA's first basis for proposing to repeal the ACE Rule is that 
there is doubt that the rule would achieve even the limited emissions 
reductions projected at the time of promulgation if it were implemented 
now, and implementation could increase CO2

[[Page 33337]]

emissions instead. Thus, the EPA concludes that as a matter of the 
Agency's policy judgment it is appropriate to repeal the rule and 
evaluate whether other technologies qualify as the BSER given new 
factual developments. This action is consistent with the Supreme 
Court's instruction in FCC v. Fox Television Stations, Inc., 556 U.S. 
502 (2009), where the Supreme Court explained that an agency issuing a 
new policy ``need not demonstrate to a court's satisfaction that the 
reasons for the new policy are better than the reasons for the old 
one.'' Instead, ``it suffices that the new policy is permissible under 
the statute, that there are good reasons for it, and that the agency 
believes it to be better, which the conscious change of course 
adequately indicates.'' Id. at 514-16 (emphasis in original; citation 
omitted).
    Two factors, taken together, undermine the ACE Rule's projected 
emission reductions and create the risk that implementation of the ACE 
Rule could increase--rather than reduce--CO2 emissions from 
coal-fired EGUs. First, HRI technologies achieve only limited GHG 
emission reductions. The ACE Rule projected that if States generally 
applied the set of candidate technologies to their sources, the rule 
would achieve a less-than-1-percent reduction in power-sector 
CO2 emissions by 2030.\522\ The EPA now doubts that even 
these minimal reductions would be achieved. The ACE Rule's projected 
benefits were premised in part on a 2009 technical report by Sargent & 
Lundy that evaluated the effects of HRI technologies. In 2023, Sargent 
& Lundy issued an updated report which details that the HRI selected as 
the BSER in the ACE Rule would bring fewer emissions reductions than 
estimated in 2009. The 2023 report concludes that, with few exceptions, 
HRI technologies are less effective at reducing CO2 
emissions than assumed in 2009. And most sources had already optimized 
application of HRIs, and so there are fewer opportunities to reduce 
emissions than previously anticipated.
---------------------------------------------------------------------------

    \522\ ACE Rule RIA 3-11, table 3-3.
---------------------------------------------------------------------------

    Second, for a subset of sources, HRI are likely to cause a rebound 
effect leading to an increase in GHG emissions for those sources for 
the reasons explained in section X.D.5.a. The estimate of the rebound 
effect was quite pronounced in the ACE Rule's own analysis--the rule 
projected that it would increase CO2 emissions from power 
plants in 15 States and the District of Columbia. Specifically, the EPA 
prepared modeling projections to understand the impacts of the ACE 
Rule. These projections assumed that, consistent with the rule, sources 
would impose a small degree of efficiency improvements. The modeling 
showed that the rule would not result in absolute emissions reductions 
across all affected sources, and some would instead increase absolute 
emissions. See EPA, IPM State-Level Emissions: EPAv6 November 2018 
Reference Case, EPA-HQ-OAR-2017-0355-26720 (providing ACE reference 
case); IPM State-Level Emissions: Illustrative ACE Scenario, EPA-HQ-
OAR-2017-0355-26724 (providing illustrative scenario).
    Despite the fact that the ACE Rule was projected to increase 
emissions in many States, these States were nevertheless obligated 
under the rule to assemble detailed State plans that evaluated 
available technologies and the performance of each existing coal-fired 
power plant, as described in section IX.A of this preamble. For 
example, the State was required to analyze the plant's ``annual 
generation,'' ``CO2 emissions,'' ``[f]uel use, fuel price, 
and carbon content,'' ``operation and maintenance costs,'' ``[h]eat 
rates,'' ``[e]lectric generating capacity,'' and the ``timeline for 
implementation,'' among other information. 84 FR 32581 (July 8, 2019). 
This evaluation and the imposition of standards of performance was 
mandated even though the State plan would lead to an increase rather 
than decrease CO2 emissions.
    In this context, the data undermining the ACE Rule's limited, 
projected emission reductions along with the risk that implementation 
of the rule could increase CO2 pollution raises doubts that 
the HRI satisfies the statutory criteria to constitute the BSER for 
this category of sources. The core element of the BSER analysis is 
whether the emission reduction technology selected reduces emissions. 
See Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 441 (D.C. Cir. 
1973) (noting ``counter productive environmental effects'' questioned 
whether the BSER selected was in fact the ``best'').
    The EPA's experience in implementing the ACE Rule reinforces these 
concerns. After the ACE Rule was promulgated, one State drafted a State 
plan that set forth a standard of performance that allowed the affected 
source to increase its emission rate. The draft partial plan would have 
applied to one source, the Longview Power, LLC facility, and would have 
established a standard of performance, based on the State's 
consideration of the ``candidate technologies,'' that was higher (i.e., 
less stringent) than the source's historical emission rate. Thus, the 
draft plan would not have achieved any emission reductions from the 
source, and instead would have allowed the source to increase its 
emissions, if it was finalized.\523\
---------------------------------------------------------------------------

    \523\ West Virginia CAA Sec.  111(d) Partial Plan for Greenhouse 
Gas Emissions from Existing Electric Utility Generating Units 
(EGUs), https://dep.wv.gov/daq/publicnoticeandcomment/Documents/Proposed%20WV%20ACE%20State%20Partial%20Plan.pdf.
---------------------------------------------------------------------------

    Because there is doubt that the minimal reductions projected by the 
ACE Rule would be achieved, and because the rebound effect could lead 
to an increase in emissions for many sources in many States, the EPA 
concludes that it is appropriate to repeal the ACE Rule and reevaluate 
the BSER for this category of sources.

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

    Since the promulgation of the ACE Rule in 2019, the factual 
underpinnings of the rule have changed in several ways, and lead EPA to 
propose that HRI are not the BSER for coal-fired power plants.
    Along with changes in the anticipated reductions from HRI, it makes 
sense for the EPA to reexamine the BSER because the costs of two 
control measures, co-firing with natural gas and CCS, have fallen 
substantially for sources with longer-term operating horizons such that 
the EPA may determine that these measures satisfy the requirements for 
the BSER for the source categories identified below. As noted, the ACE 
Rule rejected natural gas co-firing as the BSER on grounds that it was 
too costly and would lead to inefficient use of natural gas. But as 
discussed in section X.D.2.b.ii of this preamble, the costs of natural 
gas co-firing have substantially decreased, and the EPA is proposing 
that the costs of co-firing 40 percent by volume natural gas are 
reasonable for existing coal-fired EGUs in the medium-term subcategory, 
i.e., units that plan to operate during, in general, the 2032 to 2040 
period. In addition, the changed circumstances, including that natural 
gas is available in greater amounts, and there are fewer coal-fired 
EGUs, mitigates the concerns the ACE Rule identified about inefficient 
use of natural gas. See section X.D.2.b.iii(B).
    Similarly, the ACE Rule rejected CCS as the BSER on grounds that it 
was too costly. But as discussed in section X.D.1.b.ii of this 
preamble, the costs of CCS have substantially declined, partly because 
of developments in the technology that have lowered capital costs, and 
partly because the IRA extended and increased the IRC section 45Q tax 
credit so that it defrays a higher

[[Page 33338]]

portion of the costs of CCS. Accordingly, for coal-fired EGUs that will 
continue to operate past 2040, the EPA is proposing that the costs of 
CCS, which have fallen to approximately $7-$12/MWh, are reasonable.
    The reductions from these two technologies are substantial. For 
long-term coal-fired steam generating units, the BSER of 90 percent 
capture CCS results in substantial CO2 emissions reductions 
amounting to emission rates that are 88.4 percent lower on a lb/MWh-
gross basis and 87.1 percent lower on a lb/MWh-net basis compared to 
units without capture, as described in section X.D.4 of this preamble. 
And for the BSER for medium-term units, 40 percent natural gas co-
firing achieves reductions of 16 percent, as described in section 
X.D.2.b.iv of this preamble.
    Given the availability of more effective, cost-reasonable 
technology, the EPA concludes that HRIs are not the BSER for all coal-
fired EGUs.
    The EPA is thus proposing to adopt a new policy and change its 
regulatory scheme for coal-fired power plants. As discussed in section 
X.C.3 of this preamble, the EPA is proposing to subcategorize coal-
fired power plants according to the time that they will continue to 
operate. For sources in the imminent-term and near-term subcategories--
which include sources that, in general, have federally enforceable 
commitments to permanently cease operations by 2032 or 2035, 
respectively--the EPA is proposing that the BSER is routine methods of 
operation and maintenance, with associated presumptive standards of 
performance that do not permit an increased emission rate and are not 
anticipated to have a rebound effect; and the EPA is soliciting comment 
on whether co-firing some amount of natural gas should be part of the 
BSER. For sources in the medium-term subcategory--which includes 
sources that are not in the other subcategories and that have a 
federally enforceable commitment to permanently cease operations by 
2040--the EPA is proposing that the BSER is co-firing 40 percent by 
volume natural gas. The EPA concludes this control measure is 
appropriate because it achieves substantial reductions at reasonable 
cost. In addition, the EPA believes that because a large supply of 
natural gas is available, devoting part of this supply for fuel for a 
coal-fired steam generating unit in place of a percentage of the coal 
burned at the unit is an appropriate use of natural gas and will not 
adversely impact the energy system, as described in section 
X.D.2.b.iii(B) of this preamble.
    For sources in the long-term subcategory--which includes sources 
that do not have a federally enforceable commitment to permanently 
cease operations by 2040--the EPA is proposing that the BSER is CCS 
with 90 percent capture of CO2. The EPA believes that this 
control measure is appropriate because it achieves substantial 
reductions at reasonable cost, as described in section X.D.1.c of this 
preamble.
    The EPA is not proposing HRI as the BSER for any coal-fired EGUs. 
As discussed in section X.D.5.a, the EPA does not consider HRIs an 
appropriate BSER for the imminent-term and near-term subcategories 
because these technologies would achieve few, if any, emissions 
reductions and may increase emissions due to the rebound effect. The 
EPA is proposing to reject HRI as the BSER for the medium-term and 
long-term subcategories because HRI could also lead to a rebound 
effect. Most importantly, changed circumstances show that co-firing 
natural gas and CCS are available at reasonable cost, and will achieve 
more GHG emissions reductions. Accordingly, the EPA believes that HRI 
do not qualify as the BSER for any coal-fired EGUs, and that other 
approaches meet the statutory standard. For these reasons, the EPA 
proposes to repeal the ACE Rule.

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

    The third independent reason why the EPA is proposing to repeal the 
ACE Rule is that the rule did not identify with sufficient specificity 
the BSER or the degree of emission limitation achievable through the 
application of the BSER. Thus, States lacked adequate guidance on the 
BSER they should consider and level of emission reduction that the 
standards of performance must achieve. The ACE Rule determined the BSER 
to be a suite of HRI ``candidate technologies,'' but did not identify 
with specificity the degree of emission limitation States should apply 
in developing standards of performance for their sources. As a result, 
the ACE Rule conflicted with CAA section 111 and the implementing 
regulations, and thus failed to provide States adequate guidance so 
that they could ensure that their State plans were satisfactory and 
approvable by the EPA.
    CAA section 111 and the EPA's long-standing implementing 
regulations establish a clear process for the EPA and States to 
regulate emissions of certain air pollutants from existing sources. 
``The statute directs EPA to (1) `determine[ ],' taking into account 
various factors, the `best system of emission reduction which . . . has 
been adequately demonstrated,' (2) ascertain the `degree of emission 
limitation achievable through the application' of that system, and (3) 
impose an emissions limit on new stationary sources that `reflects' 
that amount.'' West Virginia v. EPA, 142 S. Ct. 2587, 2601 (2022) 
(quoting 42 U.S.C. 7411(d)). Further, ``[a]lthough the States set the 
actual rules governing existing power plants, EPA itself still retains 
the primary regulatory role in Section 111(d) . . . [and] decides the 
amount of pollution reduction that must ultimately be achieved.'' Id. 
at 2602.
    Once the EPA makes these determinations, the State must establish 
``standards of performance'' for its sources that are based on the 
degree of emission limitation that the EPA determines in the emissions 
guidelines. CAA section 111(a)(1) makes this clear through its 
definition of ``standard of performance'' as ``a standard for emissions 
of air pollutants which reflects the degree of emission limitation 
achievable through the application of the [BSER].'' After the EPA 
determines the BSER, 40 CFR 60.22(b)(5), and the degree of emission 
limitation achievable from application of the BSER, ``the States then 
submit plans containing the emissions restrictions that they intend to 
adopt and enforce in order not to exceed the permissible level of 
pollution established by EPA.'' 142 S. Ct. at 2602 (citing 40 CFR 
60.23, 60.24; 42 U.S.C. 7411(d)(1)).
    The EPA then reviews the plan and approves it if the standards of 
performance are ``satisfactory,'' under CAA section 111(d)(2)(A). The 
EPA's long-standing implementing regulations make clear that the EPA's 
basis for determining whether the plan is ``satisfactory'' includes 
that the plan must contain ``emission standards . . . no less stringent 
than the corresponding emission guideline(s).'' 40 CFR 60.24(c). The 
EPA's revised implementing regulations contain the same requirement. 40 
CFR 60.24a(c). In addition, under CAA section 111(d)(1), in ``applying 
a standard of performance to any particular source'' a State may 
consider, ``among other factors, the remaining useful life of the 
existing source to which such standard applies.'' This is also known as 
the RULOF provision and is discussed in section XII.D.2.
    In the ACE Rule, the EPA recognized that the CAA required it to 
determine the BSER and identify the degree of emission limitation 
achievable through application of the BSER. 84 FR 32537

[[Page 33339]]

(July 8, 2019). But the rule did not make those determinations. Rather, 
the ACE Rule described the BSER as a list of ``candidate 
technologies.'' And the rule described the degree of emission 
limitation achievable by application of the BSER as ranges of 
reductions from the HRI technologies. The rule thus shifted the 
responsibility for determining the BSER and degree of emission 
limitation achievable from the EPA to the States. Accordingly, the ACE 
Rule did not meet the CAA section 111 requirement that the EPA 
determine the BSER or the degree of emission limitation from 
application of the BSER.
    As described above, the ACE Rule identified the HRI in the form of 
a list of seven ``candidate technologies,'' accompanied by a wide range 
of percentage improvements to heat rate that these technologies could 
provide. Indeed, for one of them, improved O&M practices (that is, 
operation and management practices), the range was ``0 to >2%'', which 
is effectively unbounded. 84 FR 32537 (table 1) (July 8, 2019). The ACE 
Rule was clear that this list was simply the starting point for a State 
to calculate the standards of performance for its sources. That is, the 
seven sets of technologies were ``candidate[s]'' that the State could, 
but was not required to, apply and if the State did choose to apply one 
or more of them, the State could do so in a manner that yielded any 
percentage of heat rate improvement within the range that the EPA 
identified, or even outside that range, if the State chose. Thus, as a 
practical matter, the ACE Rule did not determine the BSER or any degree 
of emission limitation from application of the BSER, and so States had 
no guidance on how to craft approvable State plans. In this way, EPA 
effectively abdicated its responsibilities, and directed each State to 
determine for its sources what the BSER would be (that is, which HRI 
technologies should be applied to the source and with what intensity), 
and, based on that, what the degree of emission limitation achievable 
by application of the BSER. See 84 FR 32537-38 (July 8, 2019).
    The only constraints that the ACE Rule imposed on the States were 
procedural ones, and those did not give the EPA any benchmark to 
determine whether a plan could be approved or give the States any 
certainty on whether their plan would be approved. As noted above, when 
a State submitted its plan, it needed to show that it evaluated each 
candidate technology for each source or group of sources, explain how 
it determined the degree of emission limitation achievable, and include 
data about the sources. But because the ACE Rule did not identify a 
BSER or include a degree of emission limitation that the standards must 
reflect, the States lacked specific guidance on how to craft adequate 
standards of performance, and the EPA had no benchmark against which to 
evaluate whether a State's submission was ``satisfactory'' under CAA 
section 111(d)(2)(A). Thus, the EPA's review of State plans was 
essentially a standardless exercise, notwithstanding the Agency's 
longstanding view that it was ``essential'' that ``EPA review . . . 
[state] plans for their substantive adequacy.'' 40 FR 53342-43 
(November 17, 1975). In 1975, the EPA explained that it was not 
appropriate to limit its review based ``solely on procedural criteria'' 
because otherwise ``states could set extremely lenient standards . . . 
so long as EPA's procedural requirements were met.'' Id. at 53343.
    Finally, the ACE Rule's approach to determining the BSER and degree 
of emission limitation departed from prior emission guidelines under 
CAA section 111(d), in which the EPA included a numeric degree of 
emission limitation. See, e.g., 42 FR 55796, 55797 (October 18, 1977) 
(limiting emission rate of acid mist from sulfuric acid plants to 0.25 
grams per kilogram of acid); 44 FR 29828, 29829 (May 22, 1979) 
(limiting concentrations of total reduced sulfur from most of the 
subcategories of kraft pulp mills, such as digester systems and lime 
kilns, to 5, 20, or 25 ppm over 12-hour averages); 61 FR 9905, 9919 
(March 12, 1996) (limiting concentration of non-methane organic 
compounds from solid waste landfills to 20 parts per million by volume 
or 98-percent reduction). In the ACE Rule, the EPA did not grapple with 
this change in position as required by FCC v. Fox Television Stations, 
Inc., 556 U.S. 502 (2009), or explain why it was appropriate to provide 
a boundless degree of emission limitation achievable in this context.
    For this reason, the EPA proposes to repeal the ACE Rule. Its 
failure to determine the BSER and the associated degree of emission 
limitation achievable from application of the BSER deviated from CAA 
section 111 and the implementing regulations. Without these 
determinations, the ACE Rule lacked any benchmark that would guide the 
States in developing their State plans, and by which the EPA could 
determine whether those State plans were satisfactory.

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

    While not an independent basis for repeal, the ACE Rule also 
interpreted CAA section 111(d) to bar States from allowing emissions 
trading or averaging among their sources in all cases, which further 
shows that the ACE Rule misconstrued section 111(d) and the appropriate 
roles for the EPA and for the States. A trading program might allocate 
allowances authorizing a particular level of emissions; a facility 
would not need to reduce its emissions so long as it traded for 
sufficient allowances. And an averaging program, for example, might 
require a group of facilities to reduce their average emissions to a 
particular level. So long as some facilities reduced their emissions 
sufficiently below that level, it would not be necessary for every 
facility to reduce its emissions. Cf. Chevron U.S.A., Inc. v. Natural 
Res. Def. Council, Inc., 467 U.S. 837, 863 n.37 (1984) (explaining the 
` ``bubble' or `netting' concept). CAA section 111(d) accords States 
discretion in developing State plans, and allows States to include 
compliance flexibilities like trading or averaging in circumstances the 
EPA has determined are appropriate, as long as the plan achieves 
equivalent emissions reductions to the EPA's emission guidelines. The 
ACE Rule's legal interpretation that CAA section 111(d) always 
precludes the State from adopting those flexibilities was incorrect.
    Under CAA section 111, EPA promulgates emission guidelines that 
identify the degree of emission limitation achievable through the 
application of the BSER as determined by the Administrator. Each State 
must then ``submit to the Administrator a plan'' to achieve the degree 
of emission limitation identified by EPA. 42 U.S.C. 7411(d)(a). That 
plan must ``establish[ ] standards of performance for any existing 
source'' that emits certain air pollutants, and also ``provide[ ] for 
the implementation and enforcement of such standards of performance.'' 
Under CAA section 111(a)(1), a ``standard of performance'' is defined 
as ``a standard for emissions of air pollutants which reflects the 
degree of emission limitation achievable through the application of the 
[BSER].'' Although such standards of performance must ``reflect[ ] the 
degree of emission limitation achievable through the application of the 
[BSER],'' 42 U.S.C. 7411(a)(1), States need not compel regulated 
sources to adopt the particular components of the BSER itself.
    The ACE Rule interpreted CAA section 111(a)(1) and (d) to preclude 
States from allowing their sources to trade or average to demonstrate 
compliance with their standards of performance. 84 FR 32556-57 (July 8,

[[Page 33340]]

2019). The ACE Rule based this interpretation on its view that CAA 
section 111 limits the type of ``system'' that the EPA may select as 
the BSER to ``measures that apply at and to an individual source and 
reduce emissions from that source.'' Id. at 32523-24. The ACE Rule also 
concluded that the compliance measures the States include in their 
plans ``should correspond with the approach used to set the standard in 
the first place,'' and therefore must also be limited to measures that 
apply at and to an individual source and reduce emissions from that 
source. Id. at 32556.
    In its recently published notice of proposed rulemaking to amend 
the CAA section 111(d) implementing regulations, the EPA has proposed 
to determine that the ACE Rule's legal interpretation as to the type of 
``system'' that may be selected as a BSER, and the universal 
prohibition of trading and averaging, was incorrect. ``Implementing 
Regulations under 40 CFR part 60 Subpart Ba Adoption and Submittal of 
State Plans for Designated Facilities: Proposed Rule,'' 87 FR 79176, 
79207-79208 (December 23, 2022). As discussed in that document, no 
provision in CAA section 111(d), by its terms, precludes States from 
having flexibility in determining which measures will best achieve 
compliance with the EPA's emission guidelines.
    Specifically, the plain language of section 111(d) does not 
affirmatively bar States from considering averaging and trading as a 
compliance measure where appropriate for a particular emission 
guideline. Under section 111(d)(1), States must ``establish[ ],'' 
``implement[ ],'' and ``enforce[ ]'' ``standards of performance for any 
existing source.'' A State plan that specifies what each existing 
source must do to satisfy plan requirements is naturally characterized 
as establishing ``standards of performance for [each] existing 
source,'' even if measures like trading and averaging are identified as 
potential means of compliance. Trading and averaging programs may be 
appropriate as a policy matter as well because, in some circumstances, 
they can help to ensure that costs are reasonable by enabling market 
force to identify the facilities whose emissions can be reduced most 
cost-effectively. Nothing in the text of section 111 precludes States 
from considering a source's acquisition of allowances in implementing 
and enforcing a standard of performance for that particular source, so 
long as the State plan achieves the required level of emission 
reductions.
    Further supporting this statutory interpretation, section 111(d) 
requires a ``procedure similar to that provided by Section 7410.'' 
Consideration of the section 110 framework reinforces the absence of 
any mandate that States consider only compliance measures that apply at 
and to an individual source. ``States have `wide discretion' in 
formulating their plans'' under section 110. Alaska Dep't of Envtl. 
Conservation v. EPA, 540 U.S. 461, 470 (2004) (citation omitted); see 
Union Elec. Co. v. EPA, 427 U.S. 246, 269 (1976) (``Congress plainly 
left with the States, so long as the national standards were met, the 
power to deter-mine which sources would be burdened by regulation and 
to what extent.''); Train v. Natural Res. Def. Council, Inc., 421 U.S. 
60, 79 (1975) (``[S]o long as the ultimate effect of a State's choice 
of emission limitations is compliance with the national standards for 
ambient air, the State is at liberty to adopt whatever mix of emission 
limitations it deems best suited to its particular situation.''). 
Exercising that discretion, States have included measures that do not 
apply at or to a source in their section 1410 plans. For example, 
States have employed NOX and SO2 trading programs 
to comply with section 7410(a)(2)(D)(i)(I), the ``Good Neighbor 
Provision.'' Section 110 thus does not distinguish between measures 
that do or don't apply at or to a source for compliance, and there is 
no sound reason to read section 111's comparably broad language 
differently.
    Such flexibility is consistent with the framework of cooperative 
federalism that CAA section 111(d) establishes, which vests States with 
substantial discretion. As the U.S. Supreme Court has explained, CAA 
section 111(d) ``envisions extensive cooperation between federal and 
state authorities, generally permitting each State to take the first 
cut at determining how best to achieve EPA emissions standards within 
its domain.'' American Elec. Power Co. v. Connecticut, 564 U.S. 410, 
428 (2011) (citations omitted).
    To be sure, as discussed above, EPA retains an important role in 
reviewing State plans for adequacy. Under 111(d), each State must 
``submit to the Administrator a plan'' to achieve the degree of 
emission limitation identified by EPA. That plan must ``establish[ ] 
standards of performance for any existing source for [the] air 
pollutant'' and also ``provide[ ] for the implementation and 
enforcement of such standards of performance.'' Id. If a State elects 
not to submit a plan, or submits a plan that EPA does not find 
``satisfactory,'' EPA must promulgate a plan that establishes Federal 
standards of performance for the State's existing sources. 42 U.S.C. 
7411(d)(2)(A). Thus, the flexibility that CAA section 111(d) grants to 
States in adopting measures for their State plans is not unfettered. As 
the Supreme Court stated in West Virginia, ``The Agency, not the 
States, decides the amount of pollution reduction that must ultimately 
be achieved.'' 142 S. Ct. at 2602. State plans then must contain 
``emissions restrictions that they intend to adopt and enforce in order 
not to exceed the permissible level of pollution established by EPA.'' 
Id. Thus, EPA bears the burden of ensuring that the permissible level 
of pollution is not exceeded by any State plan. When a compliance 
flexibility compromises the ability of the State plan to achieve the 
necessary emission reductions, then the EPA may reasonably preclude 
reliance on such measures, or otherwise conclude that the State plan is 
not satisfactory.
    Thus, the EPA proposed to disagree with the ACE Rule's conclusion 
that State plan compliance measures must always apply at and to an 
individual source and reduce emissions of that source. As noted in 
section V.B.6, the U.S. Supreme Court in West Virginia v. EPA, 142 S. 
Ct. 2587 (2022), did not address the scope of the States' compliance 
flexibilities in developing State plans. The Court also declined to 
address whether CAA section 111 limits the type of ``system'' the EPA 
may consider to measures that apply substantially at and to an 
individual source. See id. at 2615.
    For these reasons, in its notice of proposed rulemaking to amend 
the CAA section 111(d) implementing regulations, EPA proposes to 
interpret CAA section 111 as permitting each State to adopt measures 
that allow its sources to meet their emissions limits in the aggregate, 
when the EPA determines, in any particular emission guideline, that it 
is appropriate to do so, given, inter alia, the pollution, sources, and 
standards of performance at issue. Thus, it is the EPA's proposed 
position that CAA 111(d) authorizes the EPA to approve State plans 
under particular emission guidelines that achieve the requisite 
emission limitation through the aggregate reductions from those 
sources, including through trading or averaging where appropriate for a 
particular emission guideline and consistent with the intended 
environmental outcomes of the guideline. As discussed in section XII.E, 
the EPA is proposing to allow trading and averaging under the proposed 
emission guidelines and requesting comment on whether and how such 
compliance mechanisms could be

[[Page 33341]]

implemented to ensure equivalency with the emission reductions that 
would be achieved if each affected source was achieving its applicable 
standard of performance.
    The ACE Rule's flawed legal interpretation that CAA section 111(d) 
universally precludes States from emissions trading is incorrect and 
adds to EPA's rationale for proposing to repeal the rule.

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

A. Overview

    In this section of the preamble, the EPA explains the basis for its 
proposed emission guidelines for GHG emissions from existing fossil 
fuel-fired steam generating units for States' use in plan development. 
This includes proposing different subcategories of designated 
facilities, the BSER for each subcategory, and the degree of emission 
limitation achievable by application of each proposed BSER. The EPA is 
proposing subcategories for steam generating units based on the type 
and amount of fossil fuel (i.e., coal, oil, and natural gas) fired in 
the unit.
    For existing coal-fired steam generating units that plan to operate 
in the long-term, the EPA is proposing CCS with 90 percent capture as 
BSER, based on a review of emission control technologies detailed 
further in this section of the preamble and accompanying TSDs, 
available in the docket. The EPA is soliciting comment on a range of 
maximum capture rates (90 to 95 percent or greater) and, to potentially 
account for the amount of time the capture equipment operates relative 
to operation of the steam generating unit, a slightly lower achievable 
degree of emission limitation (75 to 90 percent reduction in average 
annual emission rate, defined in terms of pounds of CO2 per 
unit of generation).
    During the EPA's engagement with stakeholders to inform this 
proposed rule, industry stakeholders noted that many coal-fired sources 
have plans to permanently cease operation in the coming years, and that 
GHG control technologies might not be cost reasonable for those units 
operating on shorter timeframes. These stakeholders recommended that 
the emission guidelines account for industry plans for permanently 
ceasing operation of coal-fired steam generating units by establishing 
a ``subcategory pathway'' with less stringent requirements.
    Consistent with this stakeholder input, the EPA proposes to provide 
subcategories for coal-fired steam generating units planning to 
permanently cease operations in the 2030s. The EPA recognizes that the 
cost reasonableness of GHG control technology options differ depending 
on a coal-fired steam generating unit's expected operating time 
horizon. Accordingly, the EPA is proposing to divide the subcategory 
for coal-fired units into additional subcategories based on operating 
horizon (i.e., dates for electing to permanently cease operation) and, 
for one of those subcategories, load level (i.e., annual capacity 
factor), with a separate BSER and degree of emission limitation 
corresponding to each subcategory. For long-term coal-fired units, the 
EPA is proposing that CCS satisfies the BSER criteria, as noted above. 
For medium-term units, the EPA is proposing natural gas co-firing at 40 
percent of annual heat input as BSER. The EPA is soliciting comment on 
the percent of natural gas co-firing from 30 to 50 percent and the 
degree of emission limitation defined by a reduction in emission rate 
from 12 to 20 percent. For imminent-term and near-term coal-fired steam 
generating units, the EPA is proposing a BSER of routine methods of 
operation and maintenance. Because of differences in performance 
between units, the EPA is proposing to determine the associated degree 
of emission limitation as no increase in emission rate. For imminent-
term and near-term coal-fired steam generating units, the EPA is also 
soliciting comment on a potential BSER based on low levels of natural 
gas co-firing.
    For natural gas- and oil-fired steam generating units, the EPA is 
proposing a BSER of routine methods of operation and maintenance and a 
degree of emission limitation of no increase in emission rate. Further, 
the EPA is proposing to divide subcategories for oil- and natural gas-
fired units based on capacity and, in some cases, geographic location. 
Because natural gas- and oil-fired steam generating units with similar 
annual capacity factors perform similarly to one another, the EPA is 
proposing presumptive standards of performance of 1,300 lb 
CO2/MWh-gross for base load units (i.e., those with annual 
capacity factors greater than 45 percent) and 1,500 lb CO2/
MWh-gross for intermediate load units (i.e., those with annual capacity 
factors between 8 and 45 percent). Because natural gas- and oil-fired 
steam generating units with low load have large variations in emission 
rate, the EPA is not proposing a BSER or degree of emission limitation 
for those units in this action. However, the EPA is soliciting comment 
on a potential BSER of ``uniform fuels'' and degree of emission 
limitation defined on a heat input basis by 120 to 130 lb 
CO2/MMBtu for low load natural gas-fired steam generating 
units and 150 to 170 lb CO2/MMBtu for low load oil-fired 
steam generating units. Also, because non-continental oil-fired steam 
generating units operate at intermediate and base load, and because 
there are relatively few of those units for which to define a limit on 
a fleet-wide basis, the EPA is proposing a degree of emission 
limitation for those units of no increase in emission rate and 
presumptive standards based on unit-specific emission rates, as 
detailed in section XII of this preamble. The EPA is soliciting comment 
on ranges of annual capacity factors to define the thresholds between 
the load levels and ranges in the degrees of emission limitation, as 
specified in section X.E of this preamble.
    It should be noted that the EPA is proposing a compliance date of 
January 1, 2030, as discussed in section XII of this preamble on State 
plan development.
    The remainder of this section is organized into the following 
subsections. Subsection B describes the proposed applicability 
requirements for existing steam generating units. Subsection C provides 
the explanation for the proposed subcategories. Subsection D contains, 
for coal-fired steam generating units, a summary of the systems 
considered for the BSER, detailed discussion of the systems and other 
options considered, and explanation and justification for the 
determination of BSER and degree of emission limitation. Subsection E 
contains, for natural gas- and oil-fired steam generating units, a 
summary of the systems considered for the BSER, detailed discussion of 
the systems and other options considered, and explanation and 
justification for the determination of BSER and degree of emission 
limitation.

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

    For the emission guidelines, the EPA is proposing that a designated 
facility \524\ is any fossil fuel-fired electric utility steam 
generating unit (i.e., utility boiler or IGCC unit) that: (1) Was in 
operation or had commenced construction on or

[[Page 33342]]

before January 8, 2014; \525\ (2) serves a generator capable of selling 
greater than 25 MW to a utility power distribution system; and (3) has 
a base load rating greater than 260 GJ/h (250 MMBtu/h) heat input of 
fossil fuel (either alone or in combination with any other fuel). 
Consistent with the implementing regulations, the term ``designated 
facility'' is used throughout this preamble to refer to the sources 
affected by these emission guidelines.\526\ For this action, consistent 
with prior CAA section 111 rulemakings concerning EGUs, the term 
``designated facility'' refers to a single EGU that is affected by 
these emission guidelines. The rationale for this proposal concerning 
applicability is the same as that for 40 CFR part 60, subpart TTTT (80 
FR 64543-44; October 23, 2015). The EPA incorporates that discussion by 
reference here.
---------------------------------------------------------------------------

    \524\ 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).
    \525\ Under CAA section 111, the determination of whether a 
source is a new source or an existing source (and thus potentially a 
designated facility) is based on the date that the EPA proposes to 
establish standards of performance for new sources.
    \526\ The EPA recognizes, however, that the word ``facility'' is 
often understood colloquially to refer to a single power plant, 
which may have one or more EGUs co-located within the plant's 
boundaries.
---------------------------------------------------------------------------

    Section 111(a)(6) of the CAA defines an ``existing source'' as 
``any stationary source other than a new source.'' Therefore, the 
emission guidelines would not apply to any EGUs that are new after 
January 8, 2014, or reconstructed after June 18, 2014, the 
applicability dates of 40 CFR part 60, subpart TTTT. Moreover, because 
the EPA is now proposing revised standards of performance for coal-
fired steam generating units that undertake a modification, a modified 
source would be considered ``new,'' and therefore not subject to these 
emission guidelines, if the modification occurs after the date this 
proposal is published in the Federal Register. Any source that has 
modified prior to that date would be considered an existing source that 
is subject to these emission guidelines.
    In addition, the EPA is proposing to include in the applicability 
requirements of the emission guidelines the same exemptions as 
discussed for 40 CFR part 60, subpart TTTT in section VII.E.1 of this 
preamble. Designated EGUs that may be excluded from a State plan are: 
(1) Units that are subject to 40 CFR part 60, subpart TTTT, as a result 
of commencing a qualifying modification or reconstruction; (2) steam 
generating units subject to a federally enforceable permit limiting 
net-electric sales to one-third or less of their potential electric 
output or 219,000 MWh or less on an annual basis and annual net-
electric sales have never exceeded one-third or less of their potential 
electric output or 219,000 MWh; (3) non-fossil fuel units (i.e., units 
that are capable of deriving at least 50 percent of heat input from 
non-fossil fuel at the base load rating) that are subject to a 
federally enforceable permit limiting fossil fuel use to 10 percent or 
less of the annual capacity factor; (4) CHP units that are subject to a 
federally enforceable permit limiting annual net-electric sales to no 
more than either 219,000 MWh or the product of the design efficiency 
and the potential electric output, whichever is greater; (5) units that 
serve a generator along with other steam generating unit(s), where the 
effective generation capacity (determined based on a prorated output of 
the base load rating of each steam generating unit) is 25 MW or less; 
(6) municipal waste combustor units subject to 40 CFR part 60, subpart 
Eb; (7) commercial or industrial solid waste incineration units that 
are subject to 40 CFR part 60, subpart CCCC; or (8) EGUs that derive 
greater than 50 percent of the heat input from an industrial process 
that does not produce any electrical or mechanical output or useful 
thermal output that is used outside the affected EGU. The EPA solicits 
comment on the proposed definition of ``designated facility'' and 
applicability exemptions for fossil fuel-fired steam generating units.
    The exemptions listed above at (4), (5), (6), and (7) are among the 
current exemptions at 40 CFR 60.5509(b), as discussed in section 
VII.E.1 of this preamble. The exemptions listed above at (2), (3), and 
(8) are exemptions the EPA is proposing to revise for 40 CFR part 60, 
subpart TTTT, and the rationale for proposing the exemptions is in 
section VII.E.1 of this preamble. For consistency with the 
applicability requirements in 40 CFR part 60, subpart TTTT, we are 
proposing these same exemptions for the applicability of the emission 
guidelines.
    The EPA is, in general, proposing the same emission guidelines for 
fossil fuel-fired steam generating units in non-continental areas 
(i.e., Hawaii, the Virgin Islands, Guam, American Samoa, the 
Commonwealth of Puerto Rico, and the Northern Mariana Islands) and non-
contiguous areas (non-continental areas and Alaska) as the EPA is 
proposing for comparable units in the contiguous 48 States. However, 
units in non-continental and non-contiguous areas operate on small, 
isolated electric grids, may operate differently from units in the 
contiguous 48 States, and may have limited access to certain components 
of the proposed BSER due to their uniquely isolated geography or 
infrastructure. Therefore, the EPA is soliciting comment on the 
proposed BSER and degrees of emission limitation for units in non-
continental and non-contiguous areas, and the EPA is soliciting comment 
on whether those units in non-continental and non-contiguous areas 
should be subject to different, if any, requirements.
    The EPA notes that existing IGCC units are included in the proposed 
applicability requirements and that, in section X.C.1 of this preamble, 
the EPA is proposing to include those units in the subcategory of coal-
fired steam generating units. IGCC units gasify coal or solid fossil 
fuel (e.g., pet coke) to produce syngas (a mixture of carbon monoxide 
and hydrogen), and either burn the syngas directly in a combined cycle 
unit or use a catalyst for water-gas shift (WGS) to produce a pre-
combustion gas stream with a higher concentration of CO2 and 
hydrogen, which can be burned in a hydrogen turbine combined cycle 
unit. As described in section X.D of this preamble, the proposed BSER 
for coal-fired steam generating units includes co-firing natural gas 
and CCS, depending on their operating horizon. The few IGCC units that 
now operate in the U.S. either burn natural gas exclusively--and as 
such operate as natural gas combined cycle units--or in amounts near to 
the 40 percent level of the natural gas co-firing BSER. Additionally, 
IGCC units are suitable for pre-combustion CO2 capture. 
Because the CO2 concentration in the pre-combustion gas, 
after WGS, is high relative to coal-combustion flue gas, pre-combustion 
CO2 capture for IGCC units can be performed using either an 
amine-based capture process or a physical absorption capture process. 
For these reasons, the EPA is not proposing to distinguish IGCC units 
from other coal-fired steam generating EGUs, so that the BSER of co-
firing for medium-term coal-fired units and CCS for long-term coal-
fired units apply to IGCC units.\527\
---------------------------------------------------------------------------

    \527\ For additional details on pre-combustion CO2 
capture, please see the GHG Mitigation Measures for Steam Generating 
Units TSD.
---------------------------------------------------------------------------

C. Subcategorization of Fossil Fuel-Fired Steam Generating Units

    Steam generating units can have a broad range of technical and 
operational differences. Based on these differences, they may be 
subcategorized, and different BSER and degrees of emission limitation 
may be applicable to different subcategories. Subcategorizing allows 
for determining the most appropriate

[[Page 33343]]

control requirements for a given class of steam generating unit. 
Therefore, the EPA is proposing subcategories for steam generating 
units based on fossil fuel type, operating horizon and load level, and 
is proposing different BSER and degrees of emission limitation for 
those different subcategories. The EPA notes that in section XII.B of 
this preamble comment is solicited on the compliance deadline (i.e., 
January 1, 2030), for imminent-term and near-term coal-fired steam 
generating units, and different subcategories of natural gas- and oil-
fired steam generating units.
1. Subcategorization by Fossil Fuel Type
    In this action, the EPA is proposing definitions for subcategories 
of existing fossil fuel-fired steam generating units based on the type 
and amount of fossil fuel used in the unit. The subcategory definitions 
proposed for these emission guidelines are based on the definitions in 
40 CFR part 63, subpart UUUUU, and using the fossil fuel definitions in 
40 CFR part 60, subpart TTTT.
    A coal-fired steam generating unit is an electric utility steam 
generating unit or IGCC unit that meets the definition of ``fossil 
fuel-fired'' and that burns coal for more than 10.0 percent of the 
average annual heat input during the 3 calendar years prior to the 
proposed compliance deadline (i.e., January 1, 2030), or for more than 
15.0 percent of the annual heat input during any one of those calendar 
years, or that retains the capability to fire coal after December 31, 
2029.
    An oil-fired steam generating unit is an electric utility steam 
generating unit meeting the definition of ``fossil fuel-fired'' that is 
not a coal-fired steam generating unit and that burns oil for more than 
10.0 percent of the average annual heat input during the 3 calendar 
years prior to the proposed compliance deadline (i.e., January 1, 
2030), or for more than 15.0 percent of the annual heat input during 
any one of those calendar years, and that no longer retains the 
capability to fire coal after December 31, 2029.
    A natural gas-fired steam generating unit is an electric utility 
steam generating unit meeting the definition of ``fossil fuel-fired'' 
that is not a coal-fired or oil-fired steam generating unit and that 
burns natural gas for more than 10.0 percent of the average annual heat 
input during the 3 calendar years prior to the proposed compliance 
deadline (i.e., January 1, 2030), or for more than 15.0 percent of the 
annual heat input during any one of those calendar years, and that no 
longer retains the capability to fire coal after December 31, 2029.
2. Subcategorization of Natural Gas- and Oil-Fired Steam Generating 
Units by Load Level
    The EPA is also proposing additional subcategories for oil-fired 
and natural gas-fired steam generating units, based on load levels: 
``low'' load, defined by annual capacity factors less than 8 percent; 
``intermediate'' load, defined by annual capacity factors greater than 
or equal to 8 percent and less than 45 percent; and ``base'' load, 
defined by annual capacity factors greater than or equal to 45 percent. 
In addition, the EPA is soliciting comment on a range from 5 to 20 
percent to define the threshold value between low and intermediate load 
and a range from 40 to 50 percent to define the threshold value between 
intermediate and base load. Because non-continental oil-fired units may 
operate differently, the EPA is proposing a separate subcategory for 
intermediate and base load non-continental oil-fired units. The 
rationale for the proposed load thresholds and other subcategories is 
detailed in the description of the BSER for oil- and natural gas-fired 
steam generating units in section X.E of this preamble.
3. Subcategorization of Coal-Fired Steam Generating Units by Operating 
Horizon and Load Level
    The EPA is proposing CCS with 90 percent capture as BSER for 
existing coal-fired steam generating units that will operate in the 
long-term (i.e., those that intend to operate on or after January 1, 
2040), as detailed in section X.D of this preamble. CCS is adequately 
demonstrated at coal-fired steam generating units, is cost reasonable, 
achieves meaningful reductions in GHG emissions, and meets the other 
criteria for the BSER. The EPA is soliciting comment on a range of 
maximum capture rates (90 to 95 percent or greater) and, to potentially 
account for the amount of time the capture equipment operates relative 
to operation of the steam generating unit, a slightly lower achievable 
degree of emission limitation (75 to 90 percent reduction in average 
annual emission rate, defined in terms of pounds of CO2 per 
unit of generation).
    During the EPA's engagement with stakeholders to inform this 
proposed rule, industry commenters to the pre-proposal docket noted 
that many sources have plans to permanently cease operation in the 
coming years, and that GHG control technologies might not be cost 
reasonable for those units operating on shorter timeframes. Further, 
industry stakeholders recommended that the emission guidelines account 
for industry plans for permanently ceasing operation of coal-fired 
steam generating units by establishing a ``subcategory pathway.'' 
Specifically, industry stakeholders requested that, ``[The] EPA should 
provide a subcategory pathway for units to decommission/repower into 
the early 2030s, which would include enforceable shutdown obligations, 
as part of an approach to existing unit guidelines.'' The stakeholders 
cited, as a precedent, the EPA's creation of--

    targeted subcategories for unit closures in other contexts, most 
notably the cessation of coal subcategory in the 2020 Clean Water 
Act (CWA) steam electric effluent guidelines . . . that allows for 
decommissioning/repowering by December 31, 2028. This subcategory 
allows those facilities that have already filed closure commitments 
to continue on a path to decommission/repower these assets without 
installing additional control equipment that could extend the lives 
of these units to support cost recovery.

    EPA-HQ-OAR-2022-0723-0024. In subsequent comment, industry 
stakeholders reiterated that, ``[The] EPA should proactively include a 
subcategory that allows for units to opt-in to a federally enforceable 
retirement commitment as part of compliance with regulations for 
existing sources under CAA section 111(d).'' EPA-HQ-OAR-2022-0723-0038. 
Thus, industry stakeholders recommended that EPA allow existing sources 
that are on a path to near term retirement to continue on that path 
without having to install additional control equipment.
    The proposed emission guidelines are aligned with this 
recommendation. Many fossil fuel-fired steam generating units have 
plans to cease operations, are part of utilities with commitments to 
net zero power by certain dates, or are in States or localities with 
commitments to net zero power by certain dates. Over one-third of 
existing coal-fired steam generating capacity has planned to cease 
operation by 2032, and approximately half of the capacity has planned 
to cease operations by 2040.\528\ These plans are part of the industry 
trend, described in section IV.F and IV.I, in which owners and 
operators of the nation's coal fleet, much of it aging, are replacing 
their units with natural gas combustion turbines and, increasingly, 
renewable energy.
---------------------------------------------------------------------------

    \528\ See the Power Sector Trends TSD.
---------------------------------------------------------------------------

    As industry stakeholders have pointed out, in previous rulemakings, 
the EPA has allowed coal-fired EGUs with plans to voluntarily cease 
operations in the near future to continue with their plans without 
having to install pollution control equipment. In addition to the 2020 
CWA steam electric

[[Page 33344]]

effluent guidelines these stakeholders cite, the EPA has also approved 
regional haze State implementation plans in which coal-fired EGUs that 
voluntarily committed to cease operations by a certain date were not 
subject to more stringent controls.\529\
---------------------------------------------------------------------------

    \529\ See, e.g., 76 FR 12651, 12660-63 (March 8, 2011) (best 
available retrofit technology requirements for Oregon source based 
on enforceable retirement that were to be made federally enforceable 
in state implementation plan).
---------------------------------------------------------------------------

    The EPA proposes to take the approach requested by industry 
stakeholders in this rulemaking. The EPA recognizes that the cost 
reasonableness of GHG control technology options differ depending on a 
coal-fired steam generating unit's expected operating time horizon. 
Certain technologies that are cost reasonable for EGUs that intend to 
operate for the long term are less cost reasonable for EGUs with 
shorter operating horizons because of shorter amortization periods and, 
for CCS, less time to utilize the IRC section 45Q tax credit.
    Accordingly, the EPA is proposing to divide the subcategory for 
coal-fired units into additional subcategories based on operating 
horizon (i.e., dates for electing to permanently cease operation) and, 
for one of those subcategories, load level (i.e., annual capacity 
factor), with a separate BSER and degree of emission limitation 
corresponding to each subcategory. Coal-fired steam generating units 
would be able to opt into these subcategories if they elect to commit 
to permanently ceasing operations by a certain date (and, in the case 
of one subcategory, elect to commit to an annual capacity factor 
limitation), and also elect to make such commitments federally 
enforceable and continuing by including them in the State plan.
    Specifically, the EPA is proposing four subcategories for steam 
generating units by operating horizon (i.e., enforceable commitments to 
permanently cease operations) and, in one case, by load level (i.e., 
annual capacity factor) as well. ``Imminent-term'' steam generating 
units are those that (1) Have elected to commit to permanently cease 
operations prior to January 1, 2032, and (2) elect to make that 
commitment federally enforceable and continuing by having it included 
in the State plan.\530\ ``Near-term'' steam generating units are those 
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 conditions federally 
enforceable and continuing by having them included in the State plan. 
``Medium-term'' steam generating units are those that (1) Operate after 
December 31, 2031, (2) have elected to commit to permanently cease 
operations prior to January 1, 2040, (3) elect to make that commitment 
federally enforceable and continuing by having it included in the State 
plan, and (4) do not meet the definition of near-term units. ``Long-
term'' steam generating units are those that have not elected to commit 
to permanently cease operations prior to January 1, 2040. Details 
regarding the implementation of subcategories in State plans are 
available in section XII.D of this preamble.
---------------------------------------------------------------------------

    \530\ Operating conditions that are within the control of a 
source must, under a range of CAA programs, be made federally 
enforceable in order for a source to rely on them as the basis for a 
less stringent standard. See, e.g., 76 FR 12651, 12660-63 (March 8, 
2011) (best available retrofit technology requirements for Oregon 
source based on enforceable retirement that were to be made 
federally enforceable in state implementation plan); Guidance on 
Regional Haze State Implementation Plans for the Second 
Implementation Period at 34, EPA-457/B-19-003, August 2019 (to the 
extent a state relies on an enforceable shutdown date for a 
reasonable progress determination, that measure would need to be 
included in the SIP and/or be federally enforceable); 84 FR 32520, 
32558 (July 8, 2019) (to the extent a state relies on a source's 
retirement date for a standard of performance under 111(d), that 
date must be included in the state plan and will thus be made 
federally enforceable); 87 FR 79176, 79200-01 (December 23, 2022) 
(proposed revisions to CAA section 111(d) implementing regulations 
would require States to include operating conditions, including 
retirements, in their state plans whenever the state seeks to rely 
on that operating condition as the basis for a less stringent 
standard).
---------------------------------------------------------------------------

    The EPA is proposing the imminent-term subcategory based on a 2-
year operating horizon from the proposed compliance deadline (January 
1, 2030, see section XII.B for additional details). This proposed 
subcategory is designed to accommodate units with operating horizons 
short enough that no additional CO2 control measures would 
be cost reasonable. The EPA is proposing the near-term subcategory to 
provide an alternative option for units that intend to operate for a 
slightly longer horizon but as peaking units, i.e., that intend to run 
at lower load levels. The load level of 20 percent for the near-term 
subcategory is based on spreading an average 2 years of generation 
(i.e., 50 percent in each year, a typical load level) that would occur 
under the imminent-term subcategory over the 5-year operating horizon 
of the near-term subcategory. The EPA also solicits comment on whether 
the existence of the near-term subcategory makes the imminent-term 
subcategory unnecessary. More specifically, the EPA requests comment on 
the potential to remove the imminent-term subcategory, which as 
proposed includes coal-fired steam generating units that have elected 
to commit to permanently cease operations prior to January 1, 2032. The 
EPA is considering an option in which these units would instead be 
included in the near-term subcategory (units that have elected to 
commit to permanently cease operations before January 1, 2035 and 
commit to adopt an annual capacity factor limit of 20 percent) or the 
medium-term subcategory (units that have elected to commit to 
permanently cease operations before January 1, 2040 and that are not 
near-term units). The EPA further requests comment on an alternative, 
modified approach for units in the imminent-term subcategory that could 
take into account how units intending to cease operations operate in 
practice in the period leading up to such cessation. For instance, in 
their last few years of operation, those units may operate less than 
they have historically operated, lowering their total CO2 
mass emissions, but at the same time raising their emission rate 
(because lower utilization may result in lower efficiency). The EPA 
solicits comment on whether it would be appropriate for the imminent-
term units' standards of performance to reflect the reduced utilization 
and higher emission rates through the use of an annual mass emission 
limitation. Such a limitation would account for lower utilization, but 
also allow greater flexibility with regard to hourly emission rate.
    The EPA is proposing the 10-year operating horizon (i.e., January 
1, 2040) as the threshold between medium-term and long-term 
subcategories because long-term units will have a longer amortization 
period and may be better able to fully utilize the IRC section 45Q tax 
credit. For the analysis of BSER costs of CCS for long-term units, the 
EPA assumes a 12-year amortization period as this is commensurate with 
the time period the IRC section 45Q tax credit would be available. 
Based on the cost analysis performed under that assumption, the EPA is 
proposing the costs of CCS for long-term coal-fired units are 
reasonable, as detailed in section X.D.1.a.ii of this preamble. To 
support the 10-year operating horizon threshold, the costs for a 10-
year amortization period are shown here. For a 10-year amortization 
period, assuming a 50 percent capacity factor, costs of CCS for a 
representative unit are $31/ton of CO2 reduced or $27/MWh of 
generation. Assuming a 70 percent capacity factor, costs of CCS for a 
representative unit are $6/ton of CO2

[[Page 33345]]

reduced or $5/MWh of generation. For the population of units planning 
to operate on or after January 1, 2030, the fleet average costs 
assuming a 50 percent capacity factor are $24/ton of CO2 
reduced or $22/MWh. For the population of units planning to operate on 
or after January 1, 2030, the fleet average costs assuming a 70 percent 
capacity factor are -$3/ton of CO2 reduced or -$2/MWh. Costs 
vary depending on capacity factor assumptions, but are in either case 
generally comparable to the costs detailed in section 
VII.F.3.b.iii(B)(5) of this preamble of other controls on EGUs ($10.60 
to $29.00/MWh) and less than the costs in the 2016 NSPS regulating GHGs 
for the Crude Oil and Natural Gas source category of $98/ton of 
CO2e reduced (80 FR 56627; September 18, 2015). The EPA is 
soliciting comment on the dates and load levels used to define the 
coal-fired subcategories and is seeking data and analysis on the impact 
of those alternative dates and load levels on the compliance 
requirements. As noted in section X.D.1.a.ii(C) of this preamble, the 
costs for CCS may be reasonable for units with amortization periods as 
short as 8 years. Therefore, the EPA is specifically soliciting comment 
on an operating horizon of between 8 and 10 years (i.e., January 1, 
2038, to January 1, 2040) to define the date for the threshold between 
medium-term and long-term coal-fired steam generating units.
4. Legal Basis for Subcategorization
    As noted in section V of this preamble, the EPA has broad authority 
under CAA section 111(d) to identify subcategories. As also noted in 
section V, the EPA's authority to ``distinguish among classes, types, 
and sizes within categories,'' as provided under CAA section 111(b)(2) 
and as we interpret CAA section 111(d) to provide as well, generally 
allows the Agency to place types of sources into subcategories when 
they have characteristics that are relevant to the controls that the 
EPA may determine to be the BSER for those sources. One element of the 
BSER is cost reasonableness. See CAA section 111(d)(1) (requiring the 
EPA, in setting the BSER, to ``tak[e] into account the cost of 
achieving such reduction''). As noted in section V, the EPA's long-
standing regulations under CAA section 111(d) explicitly recognize that 
subcategorizing may be appropriate for sources based on the ``costs of 
control.'' \531\ Subcategorizing on the basis of operating horizon is 
consistent with a central characteristic of the coal-fired power 
industry that is relevant for determining the cost reasonableness of 
control requirements: A large percentage of the industry has announced, 
or is expected to announce, dates for ceasing operation, and the fact 
that many coal-fired steam generating units intend to cease operation 
affects what controls are ``best'' for different subcategories. Whether 
the costs of control are reasonable depends in part on the period of 
time over which the affected sources can amortize those costs. Sources 
that have shorter operating horizons will have less time to amortize 
capital costs and the controls will thereby be less cost-effective and 
therefore may not qualify as the BSER.\532\
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    \531\ 40 CFR 60.22(b)(5), 60.22a(b)(5).
    \532\ Steam Electric Reconsideration Rule, 85 FR 64650, 64679 
(October 13, 2020) (distinguishes between EGUs retiring before 2028 
and EGUs remaining in operation after that time).
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    In addition, subcategorizing by length of period of continued 
operation is similar to two other bases for subcategorization on which 
the EPA has relied in prior rules, each of which implicates the cost 
reasonableness of controls: The first is load level, noted in section 
X.C of this preamble. For example, in the 2015 NSPS, the EPA divided 
new natural gas-fired combustion turbines into the subcategories of 
base load and non-base load. 80 FR 64510, 64602 (table 15) (October 23, 
2015). The EPA did so because the control technologies that were 
``best''-including consideration of feasibility and cost-
reasonableness--depended on how much the unit operated. The load level, 
which relates to the amount of product produced on a yearly or other 
basis, bears similarity to a limit on a period of continued operation, 
which concerns the amount of time remaining to produce the product. In 
both cases, certain technologies may not be cost reasonable because of 
the capacity to produce product--i.e., because the costs are spread 
over less product produced.
    The second is fuel type, as also noted in section X.C of this 
preamble. The 2015 NSPS provides an example of this type of 
subcategorization as well. There, the EPA divided new combustion 
turbines into subcategories on the basis of type of fuel combusted. Id. 
Subcategorizing on the basis of the type of fuel combusted may be 
appropriate when different controls have different costs, depending on 
the type of fuel, so that the cost-reasonableness of the control 
depends on the type of fuel. In that way, it is similar to 
subcategorizing by operating horizon because in both cases, the 
subcategory is based upon the cost reasonableness of controls. 
Subcategorizing by fuel type presents an additional analogy to the 
present case of subcategorizing on the basis of the length of time when 
the source will continue to operate because this timeframe is 
tantamount to the length of time when the source will continue to 
combust the fuel. Subcategorizing on this basis may be appropriate when 
different controls for a particular fuel have different costs, 
depending on the length of time when the fuel will continue to be 
combusted, so that the cost-reasonableness of controls depends on that 
timeframe. Some prior EPA rules for coal-fired sources have made 
explicit the link between length of time for continued operation and 
type of fuel combusted by codifying federally enforceable retirement 
dates as the dates by which the source must ``cease burning coal.'' 
\533\
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    \533\ See 79 FR 5031, 5192 (January 30, 2014) (explaining that 
``[t]he construction permit issued by Wyoming requires Naughton Unit 
3 to cease burning coal by December 31, 2017 and to be retrofitted 
to natural gas as its fuel source by June 30, 2018'' (emphasis 
added)).
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    It should be noted that subcategorizing on the basis of operating 
horizon does not preclude a State from considering RULOF in applying a 
standard of performance to a particular source. EPA's authority to set 
BSER for a source category (including subcategories) and a State's 
authority to invoke RULOF for individual sources within a category or 
subcategory are distinct. EPA's statutory obligation is to determine a 
generally applicable BSER for a source category, and where that source 
category encompasses different classes, types, or sizes of sources, to 
set generally applicable BSERs for subcategories accounting for those 
differences. By contrast, States' authority to invoke RULOF is premised 
on the State's ability to take into account the characteristics of a 
particular source that may differ from the assumptions EPA made in 
determining BSER generally. As noted above, the EPA is proposing these 
subcategories in response to requests by power sector representatives 
that this rule accommodate the fact that there is a class of sources 
that plans to voluntarily cease operations in the near term. Although 
the EPA has designed the subcategories to accommodate those requests, a 
particular source may still present source-specific considerations--
whether related to its remaining useful life or other factors--that the 
State may consider relevant for the application of that particular 
source's standard of performance, and that the State should

[[Page 33346]]

address as described in section XII.D.2 of this preamble.

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

    The EPA evaluated two primary control technologies as potentially 
representing the BSER for existing coal-fired steam generating units: 
CCS and natural gas co-firing. This section of the preamble discusses 
each of these alternatives, based on the criteria described in section 
V.C of this preamble.
    The EPA is proposing CCS with 90 percent capture as BSER for long-
term coal-fired steam generating units, that is, ones that are expected 
to continue to operate past 2039, because CCS can achieve an 
appropriate amount of emission reductions and satisfies the other BSER 
criteria. Because CCS is less cost reasonable for EGUs that do not plan 
to operate in the long term, the EPA is proposing other measures as 
BSER for the other subcategories of existing coal-fired steam 
generating units.
    Specifically, for medium-term units, that is, ones that have 
elected to commit to permanently cease operations after December 31, 
2031, and before January 1, 2040, and are not near-term units, the EPA 
is proposing a BSER of 40 percent natural gas co-firing on a heat input 
basis. However, the EPA is taking comment on the operating horizon 
(i.e., between 8 and 10 years, instead of the proposed 10-year 
operating horizon) that defines the threshold date between medium-term 
and long-term coal-fired steam generating units, and it is possible 
that the costs of CCS may be considered reasonable for some portion of 
the units that may be covered by the medium-term subcategory as 
proposed.
    For imminent-term and near-term units, that is, ones that have 
elected to commit to permanently cease operations before January 1, 
2032, and between December 31, 2031, and January 1, 2035, coupled with 
an annual capacity factor limit, respectively, the EPA is proposing a 
BSER of routine methods of operation and maintenance that maintain 
current emission rates. The EPA is also soliciting comment on a 
potential BSER based on low levels of natural gas co-firing for 
imminent- and near-term units.
1. Long-Term Coal-Fired Steam Generating Units
    In this section of the preamble, the EPA evaluates CCS and natural 
gas co-firing as potential BSER for long-term coal-fired steam 
generating units.
    The EPA is proposing CCS with 90 percent capture of CO2 
at the stack as BSER for long-term coal-fired steam generating units. 
The Agency is taking comment on the range of the amount of capture of 
CO2 from 90 to 95 percent or greater. CCS achieves 
substantial reductions in emissions and can capture and permanently 
sequester more than 90 percent of CO2 emitted by coal-fired 
steam generating units. The technology is adequately demonstrated, as 
indicated by the facts that it has been operated at scale and is widely 
applicable to sources, and there are vast sequestration opportunities 
across the continental U.S. Additionally, the costs for CCS are 
reasonable, in light of recent technology cost declines and policies 
including the tax credit under IRC section 45Q. Moreover, the non-air 
quality health and environmental impacts and energy requirements of CCS 
are not unreasonably adverse. These factors provide the basis for 
proposing CCS as BSER for these sources. In addition, determining CCS 
as the BSER promotes this useful GHG emission control technology.
    The EPA also evaluated natural gas co-firing at 40 percent of heat 
input as a potential BSER for long-term coal-fired steam generating 
units. While the unit level emission rate reductions of 16 percent 
achieved by 40 percent natural gas co-firing are reasonable, those 
reductions are substantially less than CCS with 90 percent capture of 
CO2. Therefore, because CCS achieves more reductions at the 
unit level and is cost reasonable, the EPA is not proposing natural gas 
co-firing as the BSER for these units.
a. CCS
    In this section of the preamble, the EPA evaluates the use of CCS 
as the BSER for existing long-term coal-fired steam generating units. 
This section incorporates by reference the parts of section 
VII.F.3.b.iii of this preamble that discuss the aspects of CCS that are 
common to new combustion turbines and existing steam generating units. 
This section also discusses additional aspects of CCS that are relevant 
for existing steam generating units and, in particular, long-term 
units.
i. Adequately Demonstrated
    The EPA is proposing that CCS is technically feasible and has been 
adequately demonstrated, based on the utilization of the technology at 
existing coal-fired steam generating units and industrial sources in 
addition to combustion turbines. While the EPA would propose that CCS 
is adequately demonstrated on those bases alone, this determination is 
further corroborated by EPAct05-assisted projects.
    The fundamental CCS technology has been in existence for decades, 
and the industry has extensive experience with and knowledge about it. 
Indeed, even without the requirements proposed here, the EPA projects 
that 9 GW of coal-fired steam generating units would apply CCS by 2030. 
Thus, the EPA will explain how existing and planned fossil fuel-fired 
electric power plants and other industrial projects that have installed 
or expect to install some or all of the components of CCS technology 
support the EPA's proposed determination that CCS is adequately 
demonstrated for existing coal-fired power plants, and the EPA will 
explain how EPAct05-assisted projects support that proposed 
determination, consistent with the legal interpretation of the EPAct05 
in section VII.F.3.b.iii(A) of this preamble.
(A) CO2 Capture Technology
    The technology of CO2 capture, in general, is detailed 
in accompanying TSDs (available in the docket) and in section 
VII.F.3.b.iii of this preamble. As noted there, solvent-based (i.e., 
amine-based) post-combustion CO2 capture is the technology 
that is most applicable at existing coal-fired steam generating units. 
Technology considerations specific to existing coal-fired steam 
generating units, including energy demands, non-GHG emissions, and 
water use and siting, are discussed in section X.D.1.a.iii of this 
preamble. As detailed in section VII.F.3.b.iii(A) of this preamble, the 
CO2 capture component of CCS has been demonstrated at 
existing coal-fired steam generating units, industrial processes, and 
existing combustion turbines. In particular, SaskPower's Boundary Dam 
Unit 3 has demonstrated capture rates of 90 percent of the 
CO2 in flue gas using solvent-based post-combustion capture 
retrofitted to existing coal-fired steam generating units. While the 
EPA would propose that the CO2 capture component of CCS is 
adequately demonstrated on the basis of Boundary Dam Unit 3 alone, 
CO2 capture has been further demonstrated at other coal-
fired steam generating units (CO2 capture from slipstreams 
of AES's Warrior Run and Shady Point) and industrial processes (e.g., 
Quest CO2 capture project), detailed descriptions of which 
are provided in section VII.F.3.b.iii(A)(2) of this preamble. The core 
technology of CO2 capture applied to combustion turbines is 
similar to that of coal-fired steam generating units (i.e., both may 
use amine solvent-based methods); therefore the demonstration of 
CO2 capture at combustion turbines (e.g., the Bellingham, 
Massachusetts,

[[Page 33347]]

combined cycle unit), as detailed in section VII.F.3.b.iii(A)(3) of 
this preamble, provide additional support for the adequate 
demonstration of CO2 capture for coal-fired steam generating 
units. Finally, EPAct05-assisted CO2 capture projects (e.g., 
Petra Nova) further corroborate the adequate demonstration of 
CO2 capture.
(B) CO2 Transport
    As discussed in section VII.F.3.b.iii of this preamble, 
CO2 pipelines are available and their network is expanding 
in the U.S., and the safety of existing and new supercritical 
CO2 pipelines is comprehensively regulated by PHMSA.\534\ 
Other modes of CO2 transportation also exist.
---------------------------------------------------------------------------

    \534\ PHMSA additionally initiated a rulemaking in 2022 to 
develop and implement new measures to strengthen its safety 
oversight of CO2 pipelines following investigation into a 
CO2 pipeline failure in Satartia, Mississippi in 2020. 
For more information, see: https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americans-carbon-dioxide-pipeline-failures.
---------------------------------------------------------------------------

    Based on data from DOE/NETL studies of storage resources, 77 
percent of existing coal-fired steam generating units that have planned 
operation during or after 2030 are within 80 km (50 miles) of potential 
saline sequestration sites, and another 5 percent are within 100 km (62 
miles) of potential sequestration sites.\535\ Additionally, of the 
coal-fired steam generating units with planned operation during or 
after 2030, 90 percent are located within 100 km of one or more types 
of sequestration formations, including deep saline, unmineable coal 
seams, and oil and gas reservoirs. This distance is consistent with the 
distances referenced in studies that form the basis for transport cost 
estimates in this proposal.536 537 As noted in section 
VII.F.3.b.iii(A)(5) of this preamble, areas without reasonable access 
to pipelines for geologic sequestration can transport CO2 to 
sequestration sites via other transportation modes such as ship, road 
tanker, or rail tank cars.
---------------------------------------------------------------------------

    \535\ Sequestration potential as it relates to distance from 
existing resources is a key part of the EPA's regular power sector 
modeling development, using data from DOE/NETL studies. For details 
please see Chapter 6 of the IPM documentation available at: https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
    \536\ The pipeline diameter was sized for this to be achieved 
without the need for recompression stages along the pipeline length.
    \537\ Note that the determination that the BSER has been 
adequately demonstrated does not require that every source in the 
long-term coal-fired steam generating unit subcategory be within 100 
km of CO2 storage.
---------------------------------------------------------------------------

(C) Geologic Sequestration of CO2
    Geologic sequestration (i.e., the long-term containment of a 
CO2 stream in subsurface geologic formations) is well proven 
and broadly available throughout the U.S. Geologic sequestration is 
based on a demonstrated understanding of the processes that affect the 
fate of CO2 in the subsurface. As discussed in section 
VII.F.3.a.iii of this preamble, there have been numerous instances of 
geologic sequestration in the U.S. and overseas, and the U.S. has 
developed a detailed set of regulatory requirements to ensure the 
security of sequestered CO2. This regulatory framework 
includes the UIC Class VI well regulations, which are under the 
authority of SDWA, and the GHGRP, under the authority of the CAA.
    Geologic sequestration potential for CO2 is widespread 
and available throughout the U.S. Through an availability analysis of 
sequestration potential in the U.S. based on resources from the DOE, 
the USGS, and the EPA, the EPA found that there are 43 States with 
access to, or are within 100 km from, onshore or offshore storage in 
deep saline formations, unmineable coal seams, and depleted oil and gas 
reservoirs.
    Sequestration potential as it relates to distance from existing 
resources is a key part of the EPA's regular power sector modeling 
development, using data from DOE/NETL studies.\538\ These data show 
that of the coal-fired steam generating units with planned operation 
during or after 2030, 60 percent are located within the boundary of a 
saline reservoir, 77 percent are located within 40 miles (80 km) of the 
boundary of a saline reservoir, and 82 percent are located within 62 
miles (100 km) of a saline reservoir. Additionally, of the coal-fired 
steam generating units with planned operation during or after 2030, 90 
percent are located within 100 km of any of the considered formations, 
including deep saline, unmineable coal seams, and oil and gas 
reservoirs.539 540 As noted in section VII.F.3.b.iii(A)(5) 
of this preamble, areas without reasonable access to pipelines for 
geologic sequestration can transport CO2 to sequestration 
sites via other transportation modes such as ship, road tanker, or rail 
tank cars.
---------------------------------------------------------------------------

    \538\ For details, please see Chapter 6 of the IPM 
documentation. https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
    \539\ The distance of 100 km is consistent with the assumptions 
underlying the NETL cost estimates for transporting CO2 
by pipeline.
    \540\ Note that the determination that the BSER has been 
adequately demonstrated does not require that every source in the 
long-term coal-fired steam generating unit subcategory be within 100 
km of CO2 storage.
---------------------------------------------------------------------------

ii. Costs
    The EPA has analyzed the costs of CCS for existing coal-fired long-
term sources, including costs for CO2 capture, transport, 
and sequestration. The EPA is proposing that this analysis demonstrates 
that the costs of CCS for these sources are reasonable. The EPA also 
evaluated costs assuming a higher capacity factor of 70 percent 
(resulting in lower costs) and different amortization periods, as 
discussed in section X.D.1.a.ii(C) of this preamble. The EPA is 
soliciting comment on the assumptions in the cost analysis, 
particularly with respect to the capacity factor assumption. As 
elsewhere in this section of the preamble, costs are presented in 2019 
dollars.
    The EPA assessed costs of CCS for a reference unit as well as the 
average cost for the fleet of coal-fired steam generating units with 
planned operation during or after 2030. The reference unit, which 
represents an average unit in the fleet, has a 400 MW-gross nameplate 
capacity and a 10,000 Btu/kWh heat rate. Applying CCS to the reference 
unit with a 12-year amortization period and assuming a 50 percent 
annual capacity factor--a typical value for the fleet--results in 
annualized total costs that can be expressed as an abatement cost of 
$14/ton of CO2 reduced and an incremental cost of 
electricity of $12/MWh. Included in these estimates is the EPA's 
assessment that the transport and storage costs are roughly $30/ton, on 
average for the reference unit. For the fleet of coal-fired steam 
generating units with planned operation during or after 2030, and 
assuming a 12-year amortization period and 50 percent annual capacity 
factor and including source specific transport and storage costs, the 
average total costs of CCS are $8/ton of CO2 reduced and $7/
MWh. These total costs also account for the IRC section 45Q tax credit, 
a detailed discussion of which is provided in section 
VII.F.3.b.iii(B)(3) of this preamble. Compared to the representative 
costs of controls detailed in section VII.F.3.b.iii(B)(5) of this 
preamble (i.e., emission control costs on EGUs of $10.60 to $29/MWh and 
the costs in the 2016 NSPS regulating GHGs for the Crude Oil and 
Natural Gas source category of $98/ton of CO2e reduced (80 
FR 56627; September 18, 2015)) the costs for CCS on long-term coal-
fired steam generating units are similar or better. Based on all of 
these analyses, the EPA is proposing that for the purposes of the BSER 
analysis, CCS is cost reasonable for long-term coal-fired steam 
generating units. The EPA also evaluated costs of CCS under

[[Page 33348]]

various other assumptions of amortization period and annual capacity 
factor. Finally, it is noted that these CCS costs are lower than those 
in prior rulemakings due to the IRC section 45Q tax credit and 
reductions in the cost of the technology.
(A) CO2 Capture Costs at Existing Coal-Fired Steam 
Generating Units
    A variety of sources provide information for the cost of CCS 
systems, and they generally agree around a range of cost. The EPA has 
relied heavily on information recently developed by NETL, in the U.S. 
Department of Energy, in particular, ``Cost and Performance Baseline 
for Fossil Energy Plants,'' \541\ and the ``Pulverized Coal Carbon 
Capture Retrofit Database.'' \542\ In addition, the EPA developed an 
independent engineering cost assessment for CCS retrofits, with support 
from Sargent and Lundy.\543\
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    \541\ https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_101422.pdf.
    \542\ https://netl.doe.gov/energy-analysis/details?id=69db8281-593f-4b2e-ac68-061b17574fb8.
    \543\ Detailed cost information, assessment of technology 
options, and demonstration of cost reasonableness can be found in 
the GHG Mitigation Measures for Steam Generating Units TSD.
---------------------------------------------------------------------------

(B) CO2 Transport and Sequestration Costs
    As discussed in section VII.F.3.b.iii of this preamble, NETL's 
``Quality Guidelines for Energy System Studies; Carbon Dioxide 
Transport and Sequestration Costs in NETL Studies'' is one of the more 
comprehensive sources of information on CO2 transport and 
storage costs available. The Quality Guidelines provide an estimation 
of transport costs for a single point-to-point pipeline. Estimated 
costs reflect pipeline capital costs, related capital expenditures, and 
operations and maintenance costs.\544\ These Quality Guidelines also 
provide an estimate of sequestration costs reflecting the cost of site 
screening and evaluation, permitting and construction costs, the cost 
of injection wells, the cost of injection equipment, operation and 
maintenance costs, pore volume acquisition expense, and long-term 
liability protection. NETL's Quality Guidelines model costs for a given 
cumulative storage potential.\545\
---------------------------------------------------------------------------

    \544\ Grant, T., et al. ``Quality Guidelines for Energy System 
Studies; Carbon Dioxide Transport and Storage Costs in NETL 
Studies.'' National Energy Technology Laboratory. 2019. https://www.netl.doe.gov/energy-analysis/details?id=3743.
    \545\ Details on CO2 transportation and sequestration 
costs can be found in the GHG Mitigation Measures for Steam 
Generating Units TSD.
---------------------------------------------------------------------------

(C) Amortization Period and Annual Capacity Factor
    In the EPA's cost analysis for long-term coal-fired steam 
generating units, the EPA assumes a 12-year amortization period and a 
50 percent annual capacity factor. The 12-year amortization period is 
consistent with the period of time during which the IRC section 45Q tax 
credit can be claimed and the 50 percent annual capacity factor is 
consistent with the historical fleet average. However, increases in 
utilization are likely to occur for units that apply CCS due to the 
incentives provided by the IRC section 45Q tax credit. Therefore, the 
EPA also assessed the costs for CCS retrofitted to existing coal-fired 
steam generating units assuming a 70 percent annual capacity factor. 
For a 70 percent annual capacity factor and a 12-year amortization 
period, the costs for the reference unit are negative at -$8/ton of 
CO2 reduced and -$7/MWh. The negative costs indicate that 
the value of the 45Q tax credit more than offsets the costs to install 
and operate CCS. For either capacity factor assumption, the $/MWh costs 
are comparable to or less than the costs for other controls ($10.60-
$29.00/MWh) which are detailed in section VII.F.3.b.iii(B)(5) of this 
preamble.
    As noted in section X.C.3 of this preamble, the EPA is also taking 
comment on the operating horizon that defines the threshold date 
between the definition of medium-term and long-term coal-fired steam 
generating units, specifically an operating horizon between 8 and 10 
years (i.e., January 1, 2038 to January 1, 2040), instead of the 
proposed 10-year operating horizon. For a 70 percent annual capacity 
factor and an 8-year amortization period, annualized costs of applying 
CCS for the reference unit are $24/ton of CO2 reduced and 
$21/MWh, and it is possible that the cost of generation may be 
reasonable relative to the representative cost for wet FGD. However, 
CCS may be less cost favorable for units with shorter amortization 
periods. For a 70 percent annual capacity factor and a 7-year 
amortization period, costs for the reference unit are $39/ton of 
CO2 reduced and $34/MWh. Additional details of the cost 
analysis are available in the GHG Mitigation Measures for Steam 
Generating Units TSD.
(D) Comparison to Costs for CCS in Prior Rulemakings
    In the CPP and ACE Rule, the EPA determined that CCS did not 
qualify as the BSER due to cost considerations. Two key developments 
have led the EPA to reevaluate this conclusion: the costs of CCS 
technology have fallen and the extension and increase in the IRC 
section 45Q tax credit, as included in the IRA, in effect provide a 
significant stream of revenue for sequestered CO2 emissions. 
The CPP and ACE Rule relied on a 2015 NETL report estimating the cost 
of CCS. NETL has issued updated reports to incorporate the latest 
information available, most recently in 2022, which show cost 
reductions. The 2015 report estimated incremental levelized cost of CCS 
at a new pulverized coal facility relative to a new facility without 
CCS at $74/MWh (2022$),\546\ while the 2022 report estimated 
incremental levelized cost at $44/MWh (2022$).\547\ Additionally, the 
IRA increased the IRC section 45Q tax credit from $50/metric ton to 
$85/metric ton (and, in the case of EOR or certain industrial uses, 
from $35/metric ton to $60/metric ton), assuming prevailing wage and 
apprenticeship conditions are met. The IRA also enhanced the realized 
value of the tax credit through the direct pay and transferability 
monetization options described in section IV.E.1. The combination of 
lower costs and higher tax credits significantly improves the cost 
effectiveness of CCS for purposes of determining whether it qualifies 
as the BSER.
---------------------------------------------------------------------------

    \546\ Cost And Performance Baseline for Fossil Energy Plants 
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 3 
(July 2015). https://www.netl.doe.gov/projects/files/CostandPerformanceBaselineforFossilEnergyPlantsVolume1aBitCoalPCandNaturalGastoElectRev3_070615.pdf.
    \547\ Cost And Performance Baseline for Fossil Energy Plants 
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 4A 
(October 2022). https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_101422.pdf.
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iii. Non-Air Quality Health and Environmental Impact and Energy 
Requirements
    CCS for steam generating units is not expected to have unreasonable 
adverse consequences related to non-air quality health and 
environmental impacts or energy requirements. The EPA has considered 
non-GHG emissions impacts, the water use impacts, the transport and 
sequestration of captured CO2, and energy requirements 
resulting from CCS. Because the non-air quality health and 
environmental impacts are closely related to the energy requirements, 
the latter are discussed first.
    As noted in section VII.F.3.b.iii(C) of this preamble, stakeholders 
have shared with the EPA concerns about the safety of CCS projects and 
concerns that their communities may bear a

[[Page 33349]]

disproportionate environmental burden associated with CCS projects. The 
EPA is committed to working with its fellow agencies to foster 
meaningful engagement with communities and protect communities from 
pollution through the responsible deployment of CCS. 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 technological deployment process. CCS projects 
undertaken pursuant to these emission guidelines will, if the EPA 
finalizes proposed revisions to the CAA section 111 implementing 
regulations,\548\ be subject to requirements for meaningful engagement 
as part of the State plan development process. See section XII.F.1.b of 
this preamble for additional details.
---------------------------------------------------------------------------

    \548\ 87 FR 79176, 79190-92 (December 23, 2022).
---------------------------------------------------------------------------

(A) Energy Requirements

    For a steam generating unit with 90 percent amine-based 
CO2 capture, parasitic/auxiliary energy demand increases and 
the net power output decreases. Amine-based CO2 capture is 
an energy-intensive process. In particular, the solvent regeneration 
process requires substantial amounts of heat in the form of steam and 
CO2 compression requires a large amount of electricity. Heat 
and power for the CO2 capture equipment can be provided 
either by using the steam and electricity produced by the steam 
generating unit or by an auxiliary cogeneration unit. However, any 
auxiliary source of heat and power is part of the ``designated 
facility,'' along with the steam generating unit. The standards of 
performance apply to the designated facility. Thus, any CO2 
emissions from the connected auxiliary equipment need to be captured or 
they will increase the facility's emission rate.
    Using integrated heat and power can reduce the capacity (i.e., the 
amount of electricity that a unit can distribute to the grid) of an 
approximately 474 MW-net (501 MW-gross) coal-fired steam generating 
unit without CCS to approximately 425 MW-net with CCS and contributes 
to a reduction in net efficiency of 23 percent.\549\ For retrofits of 
CCS on existing sources, the ductwork for flue gas and piping for heat 
integration to overcome potential spatial constraints are a component 
of efficiency reduction. The EPA notes that slightly greater efficiency 
reductions than in the 2016 NETL retrofit report are assumed for the 
BSER cost analyses, as detailed in the GHG Mitigation Measures for 
Steam Generating Units TSD, available in the docket. Despite decreases 
in efficiency, IRC section 45Q tax credits provide an incentive for 
increased generation with full operation of CCS because the credits are 
proportional to the amount of captured and sequestered CO2 
emissions and not to the amount of electricity generated. The Agency is 
proposing that the energy penalty is relatively minor compared to the 
GHG benefits of CCS and, therefore, does not disqualify CCS as being 
considered the BSER for existing coal-fired steam generating units.
---------------------------------------------------------------------------

    \549\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon 
Capture Retrofits.'' May 31, 2016.https://www.netl.doe.gov/energy-analysis/details?id=d335ce79-84ee-4a0b-a27b-c1a64edbb866.
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    Additionally, the EPA considered the impacts on the power sector, 
on a nationwide and long-term basis, of determining CCS to be the BSER 
for long-term coal-fired steam generating units. The EPA is proposing 
that designating CCS as the BSER for existing long-term coal-fired 
steam generating units would have limited and non-adverse impacts on 
the long-term structure of the power sector. Absent the requirements 
defined in this action, the EPA projects that 9 GW of coal-fired steam 
generating units would apply CCS by 2030 and 35 GW of coal-fired steam 
generating units, some without controls, would remain in operation in 
2040. Designating CCS to be the BSER for existing long-term coal-fired 
steam generating units would likely result in more of the coal-fired 
steam generating unit capacity applying CCS. The time available before 
the compliance deadline of January 1, 2030, provides for adequate 
resource planning, including accounting for the downtime necessary to 
install the CO2 capture equipment at long-term coal-fired 
steam generating units. While the IRC 45Q tax credit is available, 
long-term coal-fired steam generating units are anticipated to run at 
base load conditions. Total generation from coal-fired steam generating 
units in the other subcategories would gradually decrease over an 
extended period of time through 2039, subject to the commitments those 
units have chosen to adopt. Any decreases in the amount of generation 
from coal-fired steam generating units, whether locally or more 
broadly, are compensated for by increased generation from other 
sources. Additionally, for the long-term units applying CCS, the EPA is 
proposing the increase in the annualized cost of generation for those 
units is reasonable. Therefore, the EPA is proposing that there would 
be no unreasonable impacts on the reliability of electricity 
generation. A broader discussion of reliability impacts of the proposed 
actions is available in section XIV.F of this preamble. Finally, 
changes in the amount of generation from coal-fired steam generating 
units may contribute to additional generation from combined cycle 
combustion turbines. Since these EGUs have lower GHG and criteria 
pollutant emission rates than existing coal-fired steam generating 
units, overall emissions from the power sector would likely decrease.
(B) Non-GHG Emissions
    For amine-based CO2 capture retrofits to coal-fired 
steam generating units, decreased efficiency and increased utilization 
would otherwise result in increases of non-GHG emissions; however, 
importantly, most of those impacts would be mitigated by the flue gas 
conditioning required by the CO2 capture process and by 
other control equipment that the units already have or may need to 
install to meet other CAA requirements. Decreases in efficiency result 
in increases in the relative amount of coal combusted per amount of 
electricity generated and would otherwise result in increases in the 
amount of non-GHG pollutants emitted per amount of electricity 
generated. Additionally, increased utilization would otherwise result 
in increases in total non-GHG emissions. However, substantial flue gas 
conditioning, particularly to remove SO2, is critical to 
limiting solvent degradation and maintaining reliable operation of the 
capture plant. To achieve the necessary limits on SO2 levels 
in the flue gas for the capture process, steam generating units will 
need to add an FGD column, if they do not already have one, and may 
need an additional polishing column (i.e., quencher). A wet FGD column 
and a polishing column will also reduce the emission rate of 
particulate matter. Additional improvements in particulate matter 
removal may also be necessary to reduce the fouling of other components 
(e.g., heat exchangers) of the capture process. NOX 
emissions can cause solvent degradation and nitrosamine formation by 
chemical absorption of NOX, depending on the chemical 
structure of the solvent. The DOE's Carbon Management Pathway report 
notes that monitoring and emission controls for such degradation 
products are currently part of standard operating procedures for amine-
based CO2 capture systems.\550\

[[Page 33350]]

A conventional multistage water or acid wash and mist eliminator at the 
exit of the CO2 scrubber is effective at removal of gaseous 
amine and amine degradation products (e.g., nitrosamine) 
emissions.551 552 NOX levels of the flue gas 
required to avoid solvent degradation and nitrosamine formation in the 
CO2 scrubber vary. For most units, the requisite limits on 
NOX levels to assure that the CO2 capture process 
functions properly may be met by the existing NOX combustion 
controls, and those units may not need to install SCR for process 
purposes. However, most existing coal-fired steam generating units 
either already have SCR or will be covered by proposed Federal 
Implementation Plan (FIP) requirements regulating interstate transport 
of NOX (as an ozone precursors) from EGUs. See 87 FR 20036 
(April 6, 2022). For units not otherwise required to have SCR, an 
increase in utilization from a CO2 capture retrofit could 
result in increased NOX emissions at the source that, 
depending on the quantity of the emissions increase, may trigger major 
NSR permitting requirements. Under this scenario, the permitting 
authority may determine that the NSR permit requires the installation 
of SCR for those units, based on applying the requirements of major 
NSR. Alternatively, a State could, as part of its State plan, develop 
enforceable conditions for a source expected to trigger major NSR that 
would effectively limit the unit's ability to increase its emissions in 
amounts that would trigger major NSR. Under this scenario, with no 
major NSR requirements applying due to the limit on the emissions 
increase, the permitting authority may conclude for minor NSR purposes 
that installation of SCR is not required for the units. See section 
XIII.A of this preamble for additional discussion of the NSR program.
---------------------------------------------------------------------------

    \550\ U.S. Department of Energy (DOE). Pathways to Commercial 
Liftoff: Carbon Management. https://liftoff.energy.gov/wp-content/uploads/2023/04/20230424-Liftoff-Carbon-Management-vPUB_update.pdf.
    \551\ Sharma, S., Azzi, M., ``A critical review of existing 
strategies for emission control in the monoethanolamine-based carbon 
capture process and some recommendations for improved strategies,'' 
Fuel, 121, 178 (2014).
    \552\ Mertens, J., et al., ``Understanding ethanolamine (MEA) 
and ammonia emissions from amine-based post combustion carbon 
capture: Lessons learned from field tests,'' Int'l J. of GHG 
Control, 13, 72 (2013).
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(C) Water Use and Siting
    Water consumption at the plant increases when applying carbon 
capture, due to solvent water makeup and cooling demand. Water 
consumption can increase by 36 percent on a gross basis.\553\ A 
separate cooling water system dedicated to a CO2 capture 
plant may be necessary. However, the amount of water consumption 
depends on the design of the cooling system. For example, the cooling 
system cited in the CCS feasibility study for SaskPower's Shand Power 
station would rely entirely on water condensed from the flue gas and 
thus would not require any increase in external water consumption.\554\ 
Regions with limited water supply may rely on dry or hybrid cooling 
systems, although, in areas with adequate water, wet cooling systems 
can be more effective.
---------------------------------------------------------------------------

    \553\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon 
Capture Retrofits.'' May 31, 2016. https://www.netl.doe.gov/energy-analysis/details?id=e818549c-a565-4cbc-94db-442a1c2a70a9.
    \554\ International CCS Knowledge Centre. The Shand CCS 
Feasibility Study Public Report. https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
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    With respect to siting considerations, CO2 capture 
systems have a sizeable physical footprint and a consequent land-use 
requirement. The EPA is proposing that the water use and siting 
requirements are manageable and therefore the EPA does not expect any 
of these considerations to preclude coal-fired power plants generally 
from being able to install and operate CCS. However, the EPA is 
soliciting comment on these issues.
(D) Transport and Geologic Sequestration
    As noted in section VII.F.3.b.iii of this preamble, PHMSA oversight 
of supercritical CO2 pipeline safety protects against 
environmental release during transport and UIC Class VI regulations 
under the SDWA, in tandem with GHGRP subpart RR requirements, ensure 
the protection of USDWs and the security of geologic sequestration.
iv. Extent of Reductions in CO2 Emissions
    CCS can be applied to coal-fired steam generating units at the 
source and reduce the CO2 emission rate by 90 percent or 
more. Increased steam and power demand have a small impact on the 
reduction in emission rate that occurs with 90 percent capture. 
According to the 2016 NETL Retrofit report, 90 percent capture will 
result in emission rates that are 88.4 percent lower on a lb/MWh-gross 
basis and 87.1 percent lower on a lb/MWh-net basis compared to units 
without capture.\555\ After capture, CO2 can be transported 
and securely sequestered.\556\ Although steam generating units with 
CO2 capture will have an incentive to operate at higher 
utilization because the cost to install the CCS system is largely fixed 
and the IRC section 45Q tax credit increases based on the amount of 
CO2 captured and sequestered, any increase in utilization 
will be far outweighed by the substantial reductions in emission rate.
---------------------------------------------------------------------------

    \555\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon 
Capture Retrofits.'' May 31, 2016. https://www.netl.doe.gov/energy-analysis/details?id=e818549c-a565-4cbc-94db-442a1c2a70a9.
    \556\ Intergovernmental Panel on Climate Change. (2005). Special 
Report on Carbon Dioxide Capture and Storage.
---------------------------------------------------------------------------

v. Technology Advancement
    The EPA considered the potential impact of designating CCS as the 
BSER for long-term coal-fired steam generating units on technology 
advancement, and the EPA is proposing that designating CCS as the BSER 
will provide for meaningful advancement of CCS technology, for many of 
the same reasons as noted in section VII.F.3.b.iii(F) of this preamble.
vi. Comparison With 2015 NSPS for Newly Constructed Coal-Fired EGUs
    In the 2015 NSPS, the EPA determined that the BSER for newly 
constructed coal-fired EGUs was based on CCS with 16-23 percent 
capture, based on the type of coal combusted, and consequently, the EPA 
promulgated standards of performance of 1,400 lb CO2/MWh-g. 80 FR 64512 
(Table 1), 64513 (October 23, 2015). The EPA made those determinations 
based on the costs of CCS at the time of that rulemaking. In general, 
those costs were significantly higher than at present, due to recent 
technology cost declines as well as related policies, including the IRC 
section 45Q tax credit for CCS, which was not available at that time 
for purposes of consideration during the development of the NSPS. Id. 
at 64562 (Table 8). Based on of these higher costs, the EPA determined 
that 16-23 percent capture qualified as the BSER, and not a 
significantly higher percentage of capture. Given the substantial 
differences in the cost of CCS during the time of the 2015 NSPS and the 
present time, the capture percentage of the 2015 NSPS necessarily 
differed from the capture percentage in this proposal, and, by the same 
token, the associated degree of emission limitation and resulting 
standards of performance necessarily differ as well.
b. Natural Gas Co-Firing
    The EPA also evaluated natural gas co-firing at 40 percent of the 
heat input as the potential BSER for long-term coal-fired steam 
generating units. Because

[[Page 33351]]

the EPA is proposing natural gas co-firing as the BSER for medium-term 
units, details that are common to medium-term and long-term units are 
discussed in section X.D.2.b of the preamble. Based on the discussion 
therein, the EPA is proposing that natural gas co-firing is adequately 
demonstrated and that the non-air quality health and environmental 
effects and energy requirements are not unreasonable. The costs of 
natural gas co-firing for a long-term unit may also be reasonable. For 
example, for a representative unit with a 10-year amortization period, 
the cost of reductions is $53/ton of CO2. Finally, while 40 
percent natural gas co-firing achieves unit-level emission rate 
reductions of 16 percent, those reductions are less than CCS with 90 
percent capture. Therefore, because CCS achieves more reductions at the 
unit level and is proposed as cost reasonable for long-term units, the 
EPA is not proposing natural gas co-firing as the BSER for long-term 
coal-fired steam generating units.
c. Conclusion
    The EPA proposes that CCS at a capture rate of 90 percent is the 
BSER for long-term coal-fired steam generating units because CCS is 
adequately demonstrated, as indicated by the facts that it has been 
operated at scale and is widely applicable to sources and that there 
are vast sequestration opportunities across the continental U.S. 
Additionally, accounting for recent technology cost declines as well as 
policies including the tax credit under IRC section 45Q, the costs for 
CCS are reasonable. Moreover, any adverse non-air quality health and 
environmental impacts and energy requirements of CCS, including impacts 
on the power sector on a nationwide basis, are limited and are 
outweighed by the benefits of the significant GHG emission reductions 
at reasonable cost. In contrast, co-firing 40 percent natural gas would 
achieve far fewer emission reductions without improving the cost 
effectiveness of the control strategy. These considerations provide the 
basis for proposing CCS as the best of the systems of emission 
reduction for long-term coal-fired power plants. In addition, 
determining CCS as the BSER promotes this useful control technology. 
Although the EPA believes that long-lived coal-fired power plants will 
generally be able to implement and operate CCS within the cost 
parameters calculated as part of the BSER analysis, and therefore that 
they would be able to meet a standard of performance based on CCS with 
90 percent capture, the EPA solicits comment on whether particular 
plants would be unable to do so, including details of the circumstances 
that might make retrofitting with CCS unreasonable or infeasible.
2. Medium-Term Coal-Fired Steam Generating Units
    In this section of the preamble, the EPA evaluates CCS and natural 
gas co-firing as potential BSER for medium-term coal-fired steam 
generating units.
    In section X.D.1.a of this preamble, the EPA evaluated CCS with 90 
percent capture of CO2 as the BSER for long-term coal-fired 
steam generating units. Much of this evaluation is relevant for medium-
term units. However, because they have shorter operating horizons and, 
as a result, a shorter period for amortization and for collecting the 
IRC section 45Q tax credits, CCS would be less cost effective for those 
units. Therefore, the EPA is not proposing CCS as BSER for medium-term 
coal-fired steam generating units.
    Instead, the EPA is proposing that 40 percent natural gas co-firing 
on a heat input basis is the BSER for medium-term coal-fired steam 
generating units. Co-firing 40 percent natural gas, on an annual 
average heat input basis, results in a 16 percent reduction in 
CO2 emission rate. The technology has been adequately 
demonstrated, can be implemented at reasonable cost, does not have 
adverse non-air quality health and environmental impacts or energy 
requirements, and achieves meaningful reductions in CO2 
emissions. Co-firing also advances useful control technology and has 
acceptable national and long-term impacts on the energy sector, which 
provide additional, although not essential, support for treating it as 
the BSER.
a. CCS
    In this section of the preamble, the EPA evaluates the use of CCS 
as the BSER for existing medium-term coal-fired steam generating units. 
This evaluation is much the same as the evaluation for long-term units, 
with the important difference of costs.
    For long-term units, as discussed earlier in this preamble, the 
EPA's analysis used to evaluate the reasonableness of CCS costs employs 
a 12-year amortization period, which is consistent with the period of 
time during which the IRC section 45Q tax credit can be claimed. 
However, existing coal-fired steam generating units that have elected 
to commit to permanently cease operations prior to 2040--ones in the 
medium-term subcategory, as well as in the near-term, and imminent-term 
subcategories--would have a shorter period to amortize capital costs 
and also would not be able to fully utilize the IRC section 45Q tax 
credit. As a result, for these sources, the cost effectiveness of CCS 
is less favorable. As noted in section X.D.1.a.ii(C) of this preamble, 
for a 70 percent annual capacity factor and a 7-year amortization 
period, costs for the reference unit are $39/ton of CO2 
reduced and $34/MWh. This $/MWh generation cost is less favorable 
relative to the representative cost ($/MWh) for wet FGD, the costs for 
which are detailed in section VII.F.3.b.iii(B)(5). Due to the higher 
incremental cost of generation, the EPA is not proposing CCS as the 
BSER for medium-term coal-fired steam generating units.
    While the EPA is not proposing CCS as BSER for the proposed 
subcategory of medium-term units, the EPA is taking comment on the 
operating horizon (i.e., between 8 and 10 years, instead of the 
proposed 10-year operating horizon) that most appropriately defines the 
threshold date between medium-term and long-term units and the EPA is 
also taking comment on the level of costs of CCS that should be 
considered reasonable.
b. Natural Gas Co-Firing
    In this section of the preamble, the EPA evaluates natural gas co-
firing as potential BSER for medium-term coal-fired steam generating 
units. Considerations that are common to the proposed subcategories of 
existing coal-fired steam generating units are discussed in section 
X.D.1.a of the preamble, in addition to considerations that are 
specific to medium-term units.
    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.'' The EPA is 
proposing natural gas co-firing at a level of 40 percent of annual heat 
input as BSER for medium-term coal-fired steam generating units.
i. Adequately Demonstrated
    The EPA is proposing to find that natural gas co-firing at the 
level of 40 percent of annual heat input is adequately demonstrated for 
coal-fired steam generating units. Many existing coal-fired steam 
generating units already use some amount of natural gas, and several 
have co-fired at relatively high levels at or above 40 percent of heat 
input in recent years.
(A) Boiler Modifications
    Most existing coal-fired steam generating units can be modified to 
co-fire natural gas in any desired proportion with coal, up to 100 
percent

[[Page 33352]]

natural gas. 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, including, for 
example, new fuel supply lines and modifications to existing air ducts. 
The introduction of natural gas as a fuel can reduce boiler efficiency 
slightly, due in large part to the relatively high hydrogen content of 
natural gas. However, since the reduction in coal can result in reduced 
auxiliary power demand, the overall impact on net heat rate can range 
from a 2 percent increase to a 2 percent decrease.
    It is common practice for steam generating units to have the 
capability to burn multiple fuels onsite, and of the 565 coal-fired 
steam generating units operating at the end of 2021, 249 of them 
reported consuming natural gas as a fuel or startup source. Coal-fired 
steam generating units often use natural gas or oil as a startup fuel, 
to warm the units up before running them at full capacity with coal. 
While startup fuels are generally used at low levels (up to roughly 1 
percent of capacity on an annual average basis), some coal-fired steam 
generating units have co-fired natural gas at considerably higher 
shares. Based on hourly reported CO2 emission rates from the 
start of 2015 through the end of 2020, 29 coal-fired steam generating 
units co-fired with natural gas at rates at or above 60 percent of 
capacity on an hourly basis.\557\ The capability of those units on an 
hourly basis is indicative of the extent of boiler burner modifications 
and sizing and capacity of natural gas pipelines to those units, and 
implies that those units are technically capable of co-firing at least 
60 percent natural gas on a heat input basis on average over the course 
of an extended period (e.g., a year). Additionally, during that same 
2015 through 2020 period, 29 coal-fired steam generating units co-fired 
natural gas at over 40 percent on an annual heat input basis. Because 
of the number of units that have demonstrated co-firing above 40 
percent of heat input, the EPA is proposing that co-firing at 40 
percent is adequately demonstrated. A more detailed discussion of the 
record of natural gas co-firing, including current trends, at coal-
fired steam generating units is included in the GHG Mitigation Measures 
for Steam Generating Units TSD.
---------------------------------------------------------------------------

    \557\ U.S. Environmental Protection Agency (EPA). ``Power Sector 
Emissions Data.'' Washington, DC: Office of Atmospheric Protection, 
Clean Air Markets Division. Available from EPA's Air Markets Program 
Data website: https://campd.epa.gov.
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(B) Natural Gas Pipeline Development
    In addition to any potential boiler modifications, the supply of 
natural gas is necessary to enable co-firing at existing coal-fired 
steam boilers. As discussed in the previous section, many plants 
already have at least some access to natural gas. In order to increase 
natural gas access beyond current levels, many will find it necessary 
to construct natural gas supply pipelines.
    The U.S. natural gas pipeline network consists of approximately 3 
million miles of pipelines that connect natural gas production with 
consumers of natural gas. To increase natural gas consumption at a 
coal-fired boiler without sufficient existing natural gas access, it is 
necessary to connect the facility to the natural gas pipeline 
transmission network via the construction of a lateral pipeline. The 
cost of doing so is a function of the total necessary pipeline capacity 
(which is characterized by the length, size, and number of laterals) 
and the location of the plant relative to the existing pipeline 
transmission network. The EPA estimated the costs associated with 
developing new lateral pipeline capacity sufficient to meet 60 percent 
of the net summer capacity at each coal-fired steam generating unit. As 
discussed in the GHG Mitigation Measures for Steam Generating Units 
TSD, the EPA estimates that this lateral capacity would be sufficient 
to enable each unit to achieve 40 percent natural gas co-firing on an 
annual average basis.
    The EPA considered the availability of the upstream natural gas 
pipeline capacity to satisfy the assumed co-firing demand implied by 
these new laterals. This analysis included pipeline development at all 
EGUs that could be included in this subcategory. The EPA's assessment 
reviewed the reasonableness of each assumed new lateral by determining 
whether the peak gas capacity of that lateral could be satisfied 
without modification of the transmission pipeline systems to which it 
is assumed to be connected. This analysis found that most, if not all, 
existing pipeline systems are currently able to meet the peak needs 
implied by these new laterals in aggregate, assuming that each existing 
coal-fired unit in the analysis co-fired with natural gas at a level 
implied by these new laterals, or 60 percent of net summer generating 
capacity. While this is a reasonable assumption for the analysis to 
support this mitigation measure in the BSER context, it is also a 
conservative assumption that overstates the amount of natural gas co-
firing expected under the proposed rule.
    The maximum amount of pipeline capacity, if all coal-fired steam 
capacity in the medium-term subcategory implemented the proposed BSER 
by co-firing 40 percent natural gas, would be a fraction of the 
pipeline capacity constructed recently. The EPA estimates that this 
maximum total capacity would be about 17.3 billion cubic feet per day, 
which would require almost 4,000 miles of pipeline costing roughly 
$13.3 billion. Over 5 years, this maximum total incremental pipeline 
capacity would amount to 800 miles per year and approximately $2.7 
billion per year in capital expenditures, on average. By comparison, 
based on data collected by EIA, the total annual mileage of natural gas 
pipelines constructed over the 2017-2021 period ranged from 
approximately 1,000 to 2,500 miles per year, with a total capacity of 
10 to 25 billion cubic feet per day. This represents an estimated 
annual investment of up to nearly $15 billion. These historical annual 
values are much higher than the maximum annual values that could be 
expected under this proposed BSER measure--which, as noted above, 
represent a conservative estimate that overstates the amount of co-
firing that the EPA projects would occur under this proposed rule.
    These conservatively high estimates of pipeline requirements also 
compare favorably to industry projections of future pipeline capacity 
additions. Based on a review of a 2018 industry report, titled ``North 
America Midstream Infrastructure through 2035: Significant Development 
Continues,'' investment in midstream infrastructure development is 
expected to average about $37 billion per year through 2035, which is 
lower than historical levels. Approximately $10 to $20 billion annually 
is expected to be invested in natural gas pipelines through 2035. This 
report also projects that an average of over 1,400 miles of new natural 
gas pipeline will be built through 2035, which is similar to the 
approximately 1,670 miles that were built on average from 2013 to 2017. 
These values are considerably greater than the average annual 
expenditure of $2.7 billion on 800 miles per year of new pipeline 
construction that would be necessary for the entire operational fleet 
of coal-fired steam generating units to co-fire with natural gas. The 
actual pipeline investment for this subcategory would be substantially 
lower.
ii. Costs
    The capital costs associated with the addition of new gas burners 
and other necessary boiler modifications depend on the extent to which 
the current boiler is already able to co-fire with some

[[Page 33353]]

natural gas and on the amount of gas co-firing desired. The EPA 
estimates that, on average, the total capital cost associated with 
modifying existing boilers to operate at up to 100 percent of heat 
input using natural gas is approximately $52/kW. These costs could be 
higher or lower, depending on the equipment that is already installed 
and the expected impact on heat rate or steam temperature.
    While fixed O&M (FOM) costs can potentially decrease as a result of 
decreasing the amount of coal consumed, it is common for plants to 
maintain operation of one coal pulverizer at all times, which is 
necessary for maintaining several coal burners in continuous service. 
In this case, coal handling equipment would be required to operate 
continuously and therefore natural gas co-firing would have limited 
effect on reducing the coal-related FOM costs. Although, as noted, 
coal-related FOM costs have the potential to decrease, the EPA does not 
anticipate a significant increase in impact on FOM costs related to co-
firing with natural gas.
    In addition to capital and FOM cost impacts, any additional natural 
gas co-firing would result in incremental costs related to the 
differential in fuel cost, taking into consideration the difference in 
delivered coal and gas prices, as well as any potential impact on the 
overall net heat rate. The EPA's post-IRA 2022 reference case projects 
that in 2030, the average delivered price of coal will be $1.47/MMBtu 
and the average delivered price of natural gas will be $2.53/MMBtu. 
Thus, assuming the same level of generation and no impact on heat rate, 
the additional fuel cost would be above $1/MMBtu on average in 2030. 
The total additional fuel cost could increase or decrease depending on 
the potential impact on net heat rate. An increase in net heat rate, 
for example, would result in more fuel required to produce a given 
amount of generation and thus additional cost. In the GHG Mitigation 
Measures for Steam Generating Units TSD, the EPA's cost estimates 
assume a 1 percent increase in net heat rate.
    Finally, for plants without sufficient access to natural gas, it is 
also necessary to construct new natural gas pipelines (``laterals''). 
Pipeline costs are typically expressed in terms of dollars per inch of 
pipeline diameter per mile of pipeline distance (i.e., dollars per 
inch-mile), reflecting the fact that costs increase with larger 
diameters and longer pipelines. On average, the cost for lateral 
development within the contiguous U.S. is approximately $280,000 per 
inch-mile (2019$), which can vary based on site-specific factors. The 
total pipeline cost for each coal-fired steam generating unit is a 
function of this cost, as well as a function of the necessary pipeline 
capacity and the location of the plant relative to the existing 
pipeline transmission network. The pipeline capacity required depends 
on the amount of co-firing desired as well as on the desired level of 
generation--a higher degree of co-firing while operating at full load 
would require more pipeline capacity than a lower degree of co-firing 
while operating at partial load. It is reasonable to assume that most 
plant owners would develop sufficient pipeline capacity to deliver the 
maximum amount of desired gas use in any moment, enabling higher levels 
of co-firing during periods of lower fuel price differentials. Once the 
necessary pipeline capacity is determined, the total lateral cost can 
be estimated by considering the location of each plant relative to the 
existing natural gas transmission pipelines as well as the available 
excess capacity of each of those existing pipelines. For purposes of 
the cost reasonableness estimates as follows, the EPA assumes pipeline 
costs of $92/kW, which is the median value of all unit-level pipeline 
cost estimates, as explained in the GHG Mitigation Measures for Steam 
Generating Units TSD. The range in costs reflects a range in the 
amortization period of the capital costs over 6 to 10 years, which is 
consistent with the amount of time over which the units in the medium-
term subcategory could be operational.
    The EPA sums the natural gas co-firing costs as follows: For a 
typical base load coal-fired steam generating unit in 2030, the EPA 
estimates that the cost of co-firing with 40 percent natural gas on an 
annual average basis is approximately $53 to $66/ton CO2 
reduced, or $9 to $12/MWh, respective to amortization periods of 10 to 
6 years. This estimate is based on the characteristics of a typical 
coal-fired unit in 2021 (400 MW capacity and an average heat rate of 
10,500 Btu/kWh) operating at a typical capacity factor of about 50 
percent, and it assumes a pipeline cost of $92/kW, as discussed earlier 
in this preamble.
    Based on the coal-fired steam generating units that existed in 2021 
and that do not have known plans to cease operations or convert to gas 
by 2030, and assuming that each of those units continues to operate at 
the same level in 2030 as it operated in 2017-2021, on average, the EPA 
estimates that the weighted average cost of co-firing with 40 percent 
natural gas on an annual average basis is approximately $64 to $78/ton 
CO2 reduced, or $11 to $14/MWh. The $/ton cost estimate is 
lower than average for approximately 82 GW, and the $/MWh cost estimate 
is lower than average for 86 GW (about 69 percent and 72 percent, 
respectively, of the relevant coal fleet). These estimates and all 
underlying assumptions are explained in detail in the GHG Mitigation 
Measures for Steam Generating Units TSD.
    As was described in section X.D.1 of this preamble, the EPA has 
compared the estimated costs discussed in section X.D.2 of this 
preamble to costs that coal-fired steam generating units have incurred 
to install controls that reduce other air pollutants, such as 
SO2. Compared to the representative costs of controls 
detailed in section VII.F.3.b.iii(B)(5) of this preamble (i.e., 
emission control costs on EGUs of $10.60 to $29/MWh and the costs in 
the 2016 NSPS regulating GHGs for the Crude Oil and Natural Gas source 
category of $98/ton of CO2e reduced (80 FR 56627; September 
18, 2015)), both estimates of annualized costs of natural gas co-firing 
(approximately $53-$66/ton or $9-$12/MWh for a typical unit and $64-
$78/ton or $11-$14/MWh on average)) are comparable or lower. The range 
of cost effectiveness estimates presented in this section is lower than 
previously estimated by the EPA in the proposed CPP, for several 
reasons. Since then, the expected difference between coal and gas 
prices has decreased significantly, from over $3/MMBtu to about $1/
MMBtu in this proposal. Additionally, a recent analysis performed by 
Sargent and Lundy for the EPA supports a considerably lower capital 
cost for modifying existing boilers to co-fire with natural gas. The 
EPA also recently conducted a highly detailed facility-level analysis 
of natural gas pipeline costs, the median value of which is slightly 
lower than the value used by the EPA previously to approximate the cost 
of co-firing at a representative unit.
    Based on the cost analysis presented in this section, the EPA is 
proposing that the costs of natural gas co-firing are reasonable for 
the medium-term coal-fired steam generating unit subcategory.
iii. Non-Air Quality Health and Environmental Impact and Energy 
Requirements
    Natural gas co-firing for steam generating units is not expected to 
have any significant adverse consequences related to non-air quality 
health and environmental impacts or energy requirements.

[[Page 33354]]

(A) Non-GHG Emissions
    Non-GHG emissions are reduced when steam generating units co-fire 
with natural gas because less coal is combusted. SO2, 
PM2.5, acid gas, mercury and other hazardous air pollutant 
emissions that result from coal combustion are reduced proportionally 
to the amount of natural gas consumed, i.e., under this proposal, by 40 
percent. Natural gas combustion does produce NOX emissions, 
but in lesser amounts than from coal-firing. However, the magnitude of 
this reduction is dependent on the combustion system modifications that 
are implemented to facilitate natural gas co-firing.
    Additionally, sufficient regulations exist related to natural gas 
pipelines and transport that assure natural gas can be safely 
transported with minimal risk of environmental release. PHMSA develops 
and enforces regulations for the safe, reliable, and environmentally 
sound operation of the nation's 2.6 million mile pipeline 
transportation system. Recently, PHMSA finalized a rule that will 
improve the safety and strengthen the environmental protection of more 
than 300,000 miles of onshore gas transmission pipelines.\558\ PHMSA 
also recently promulgated a rule covering natural gas 
transmission,\559\ as well as a rule that significantly expanded the 
scope of safety and reporting requirements for more than 400,000 miles 
of previously unregulated gas gathering lines.\560\ Additionally, FERC 
oversees the development of new natural gas pipelines.
---------------------------------------------------------------------------

    \558\ Pipeline Safety: Safety of Gas Transmission Pipelines: 
Repair Criteria, Integrity Management Improvements, Cathodic 
Protection, Management of Change, and Other Related Amendments (87 
FR 52224; August 24, 2022).
    \559\ Pipeline Safety: Safety of Gas Transmission Pipelines: 
MAOP Reconfirmation, Expansion of Assessment Requirements, and Other 
Related Amendments (84 FR 52180; October 1, 2019).
    \560\ Pipeline Safety: Safety of Gas Gathering Pipelines: 
Extension of Reporting Requirements, Regulation of Large, High-
Pressure Lines, and Other Related Amendments (86 FR 63266; November 
15, 2021).
---------------------------------------------------------------------------

(B) Energy Requirements
    The introduction of natural gas co-firing will cause steam boilers 
to be slightly less efficient due to the high hydrogen content of 
natural gas. Co-firing at levels between 20 percent and 100 percent can 
be expected to decrease boiler efficiency between 1 percent and 5 
percent. However, despite the decrease in boiler efficiency, the 
overall net output efficiency of a steam generating unit that switches 
from coal- to natural gas-firing may change only slightly, in either a 
positive or negative direction. Since co-firing reduces coal 
consumption, the auxiliary power demand related to coal handling and 
emissions controls typically decreases as well. While a site-specific 
analysis would be required to determine the overall net impact of these 
countervailing factors, generally the effect of co-firing on net unit 
heat rate can vary within approximately plus or minus 2 percent.
    The EPA previously determined in the ACE Rule (84 FR 32520 at 
32545; July 8, 2019) that ``co-firing natural gas in coal-fired utility 
boilers is not the best or most efficient use of natural gas and [. . 
.] can lead to less efficient operation of utility boilers.'' That 
determination was informed by the more limited supply of natural gas, 
and the larger amount of coal-fired EGU capacity and generation, in 
2019. Since that determination, the expected supply of natural gas has 
expanded considerably, and the capacity and generation of the existing 
coal-fired fleet has decreased, reducing the total mass of natural gas 
that might be required for sources to implement this measure. 
Additionally, the natural gas co-firing measure is now being proposed 
for a medium-term coal-fired steam generating unit subcategory, a group 
of units that will operate at most for 10 years following the 
compliance date, which would further reduce the total amount of 
required natural gas.
    Furthermore, regarding the efficient operation of boilers, the ACE 
determination was based on the observation that ``co-firing can 
negatively impact a unit's heat rate (efficiency) due to the high 
hydrogen content of natural gas and the resulting production of water 
as a combustion by-product.'' That finding does not consider the fact 
that the effect of co-firing on net unit heat rate can vary within 
approximately plus or minus 2 percent, and therefore the net impact on 
overall utility boiler efficiency for each steam generating unit is 
uncertain.
    For all of these reasons, the EPA is proposing that natural gas co-
firing at medium-term coal-fired steam generating units does not result 
in any significant adverse consequences related to energy requirements.
    Additionally, the EPA considered longer term impacts on the energy 
sector, and the EPA is proposing these impacts are reasonable. 
Designating natural gas co-firing as the BSER for medium-term coal-
fired steam generating units would not have significant adverse impacts 
on the structure of the energy sector. Steam generating units that 
currently are coal-fired would be able to remain primarily coal-fired. 
The replacement of some coal with natural gas as fuel in these sources 
would not have significant adverse effects on the price of natural gas 
or the price of electricity.
iv. Extent of Reductions in CO2 Emissions
    One of the primary benefits of natural gas co-firing is emission 
reduction. CO2 emissions are reduced by approximately 4 
percent for every additional 10 percent of co-firing. When shifting 
from 100 percent coal to 60 percent coal and 40 percent natural gas, 
CO2 stack emissions are reduced by approximately 16 percent. 
Non-CO2 emissions are reduced as well, as noted earlier in 
this preamble.
v. Technology Advancement
    Natural gas co-firing is already well-established and widely used 
by coal-fired steam boiler generating units. As a result, this proposed 
rule is not likely to lead to technological advances or cost reductions 
in the components of natural gas co-firing, including modifications to 
boilers and pipeline construction. However, greater use of natural gas 
co-firing may lead to improvements in the efficiency of conducting 
natural gas co-firing and operating the associated equipment.
c. Conclusion
    The EPA proposes that natural gas co-firing at 40 percent of heat 
input is the BSER for medium-term coal-fired steam generating units 
because natural gas co-firing is adequately demonstrated, as indicated 
by the facts that it has been operated at scale and is widely 
applicable to sources. Additionally, the costs for natural gas co-
firing are reasonable. Moreover, any adverse non-air quality health and 
environmental impacts and energy requirements of natural gas co-firing 
are limited and are outweighed by the benefits of the emission 
reductions at reasonable cost. In contrast, CCS, although achieving 
greater emission reductions, would be less cost-effective, in general, 
for the proposed subcategory of medium-term units.
    While the EPA is not proposing CCS as BSER for the proposed 
subcategory definition of medium-term units, the EPA is taking comment 
on the operating horizons that define the threshold date between 
medium-term and long-term units (i.e., between 8 and 10 years, instead 
of the proposed 10-year operating horizon) and on what amount of costs 
should be considered reasonable.

[[Page 33355]]

3. Imminent-Term and Near-Term Coal-Fired Steam Generating Units
    In this section of the preamble, the EPA evaluates CCS, natural gas 
co-firing, low levels of natural gas co-firing, and routine methods of 
operation and maintenance as the BSER for imminent-term and near-term 
coal-fired steam generating units. Primarily because of the effect of a 
short operating horizon on the cost of controls for these units, the 
EPA proposes routine methods of operation and maintenance as the BSER.
a. CCS
    As noted in section X.D.2.a of this preamble, the EPA is not 
proposing CCS for medium-term units due to $/MWh costs being less 
favorable based on the appropriate cost metrics. Because of the shorter 
operating horizons for imminent-term and near-term coal-fired steam 
generating units, CCS is less cost favorable for them than for medium-
term units. Therefore, the EPA is not proposing CCS as BSER for 
imminent-term or near-term coal-fired steam generating units. 
Additional details of cost values for amortization periods 
representative of imminent-term and near-term units are available in 
the GHG Mitigation Measures for Steam Generating Units TSD.
b. Natural Gas Co-Firing
i. Natural Gas Co-Firing at 40 Percent
    Much of the discussion of natural gas co-firing in section X.D.2.b 
of this preamble for medium-term units is relevant for imminent-term 
and near-term units, except that natural gas co-firing is less cost 
effective for the latter units because of their short operating 
horizons, particularly on a $/ton of CO2 reduced basis. For 
a 2-year amortization period, annualized costs for the representative 
unit are $130/ton of CO2 reduced and $23/MWh of generation. 
Therefore, the EPA is not proposing natural gas co-firing as BSER for 
imminent-term or near-term units. Additional details of cost are 
available in the GHG Mitigation Measures for Steam Generating Units 
TSD.
ii. Natural Gas Co-Firing at Low Levels of Heat Input
    Although higher levels of natural gas co-firing may be less cost 
effective for imminent-term and near-term units, it is possible that 
lower levels of natural gas co-firing may be cost reasonable. Many 
units have demonstrated the ability to co-fire with natural gas over 
short periods of time and operating with those same levels of natural 
gas co-firing over longer periods of time (i.e., annually) may achieve 
emission reductions. A low level of natural gas co-firing (up to 10 
percent of annual heat input) is adequately demonstrated and may be 
broadly achievable, may achieve reductions in GHG emissions, may be of 
reasonable cost, and is unlikely to cause unreasonable adverse non-air 
quality health and environmental impacts or result in substantial 
energy requirements. Therefore, the EPA is soliciting comment on low 
levels of natural gas co-firing as a potential component of the BSER 
for imminent-term and near-term coal-fired steam generating units.
    The EPA recognizes that different coal-fired units may be already 
capable of different natural gas co-firing rates (as discussed in 
section X.D.2.b.i of this preamble) and is therefore soliciting comment 
on defining a potential BSER on the basis of the maximum hourly heat 
input of natural gas fired in the unit (MMBtu/hr) relative to the 
maximum hourly heat input the unit is capable of (i.e., the nameplate 
capacity on an MMBtu/hr basis). Alternatively, the EPA is soliciting 
comment on a fixed value of annual heat input percentage that 
represents a low level of natural gas co-firing, as well as the 
definition of a low level of natural gas co-firing that is based on the 
characteristics of an existing facility (e.g., the capacity of the 
existing pipeline). The EPA is also soliciting comment on a degree of 
emission limitation resulting from low levels of natural gas co-firing, 
as detailed in section X.D.4.c of this preamble.
(1) Adequately Demonstrated
    For many of the same reasons stated in section X.D.2.b.i of this 
preamble for natural gas co-firing at higher levels, natural gas co-
firing at low levels is adequately demonstrated. The EPA also 
identified that 369 of the 565 EGUs operating at the end of 2021 have 
either reported natural gas as a fuel source, are located at a plant 
with a natural gas generator, and/or are located at a plant with a 
natural gas pipeline connection. A large percentage of the existing 
fleet of coal-fired steam generating units would therefore likely be 
able to co-fire natural gas at low levels without having to make boiler 
modifications or build additional pipelines.
(2) Costs
    The costs of low levels of natural gas co-firing may be reasonable 
because low levels of natural gas co-firing likely require little, if 
any, capital investment. Additionally, the relatively small increase in 
natural gas fuel use would only result in a modest increase in total 
fuel cost.
(3) Non-Air Quality Health and Environmental Impact and Energy 
Requirements
    For many of the same reasons stated in section X.D.2.b.iii of this 
preamble, low levels of natural gas co-firing are unlikely to cause 
unreasonable adverse non-air quality health and environmental impacts 
or result in substantial energy requirements. Furthermore, low levels 
of natural gas co-firing may require only limited construction of 
additional infrastructure as existing pipeline laterals to the units 
should be of sufficient size to achieve low levels of natural gas co-
firing.
(4) Extent of Reductions in CO2 Emissions
    The emission reductions achieved at the unit from low levels of 
natural gas co-firing of 1 to 10 percent may be relatively low at 
around 0.4 to 4 percent, respectively. However, these are likely on 
average greater than the emission reductions that could be achievable 
by other technologies, such as HRI. Furthermore, because the efficiency 
of the unit is not increased as with HRI, the unit likely does not move 
up in dispatch order, and it is likely the unit would not be subject to 
the rebound effect. See section X.D.5 of this preamble for a discussion 
of HRI.
(5) Technology Advancement
    Low levels of natural gas co-firing do not advance useful control 
technology, for reasons similar to those discussed in section X.D.2.b.v 
of this preamble.
c. Routine Methods of Operation and Maintenance
    For the imminent-term and near-term coal-fired steam generating 
units, the EPA is proposing that the BSER is routine methods of 
operation and maintenance already occurring at the unit, so as to 
maintain the current unit-specific CO2 emission rates 
(expressed as lb CO2/MWh).
    Routine methods of operation and maintenance are adequately 
demonstrated because units already operate by those methods. They will 
not result in additional costs from any controls, and will not create 
adverse non-air quality health and environmental impacts or energy 
requirements. They will not achieve CO2 emission reductions 
at the unit level relative to current performance, but they can prevent 
worsening of emission rates over time. Although they do not advance 
useful control technology, they do not have adverse impacts on the 
energy sector from a nationwide or long-term perspective.

[[Page 33356]]

4. Degree of Emission Limitation
    Under CAA section 111(d), once the EPA determines the BSER, it must 
determine the ``degree of emission limitation'' achievable by the 
application of the BSER. States then determine standards of performance 
and include them in the State plans, based on the specified degree of 
emission limitation. Proposed presumptive standards of performance are 
detailed in section XII.D of this preamble. There is substantial 
variation in emission rates among coal-fired steam generating units--
the range is, approximately, from 1,700 lb CO2/MWh-gross to 
2,500 lb CO2/MWh-gross--which makes it challenging to 
determine a single, uniform emission limit. Accordingly, for each of 
the four subcategories of coal-fired steam generating units, the EPA is 
proposing to determine the degree of emission limitation by a 
percentage change in emission rate, as follows:
a. Long-Term Coal-Fired Steam Generating Units
    As discussed earlier in this preamble, the EPA is proposing the 
BSER for long-term coal-fired steam generating units as ``full-
capture'' CCS, defined as 90 percent capture of the CO2 in 
the flue gas. The degree of emission limitation achievable by applying 
this BSER can be determined on a rate basis. A capture rate of 90 
percent results in reductions in the emission rate of 88.4 percent on a 
lb CO2/MWh-gross basis, and this reduction in emission rate 
can be observed over an extended period (e.g., an annual calendar-year 
basis). Therefore, the EPA is proposing that the degree of emission 
limitation for long-term units is an 88.4 percent reduction in emission 
rate on a lb CO2/MWh-gross basis over an extended period 
(e.g., an annual calendar-year basis).
    As noted in section X.D.1.a of this preamble, new CO2 
capture retrofits on existing coal-fired steam generating units may 
achieve capture rates greater than 90 percent, and the EPA is taking 
comment on a range of capture rates that may be achievable. As noted in 
section VII.F.3.b.iii(A)(2) of this preamble, the operating 
availability (i.e., the amount of time a process operates relative to 
the amount of time it planned to operate) of industrial processes is 
usually less than 100 percent. Assuming that CO2 capture 
achieves 90 percent capture when available to operate, that CCS is 
available to operate 90 percent of the time the coal-fired steam 
generating unit is operating, and that the steam generating unit 
operates the same whether or not CCS is available to operate, total 
emission reductions would be 81 percent. Higher levels of emission 
reduction could occur for higher capture rates coupled with higher 
levels of operating availability relative to operation of the steam 
generating unit. If the steam generating unit were not permitted to 
operate when CCS was unavailable, there may be local reliability 
consequences, and the EPA is soliciting comment on how to balance these 
issues. Additionally, the EPA is soliciting comment on a range of the 
degree of emission limitation achievable, in the form of a reduction in 
emission rate of 75 to 90 percent when determined over an extended 
period (e.g., an annual calendar-year basis).
b. Medium-Term Coal-Fired Steam Generating Units
    As discussed earlier in this preamble, the BSER for medium-term 
coal-fired steam generating units is 40 percent natural gas co-firing. 
The application of 40 percent natural gas co-firing results in 
reductions in the emission rate of 16 percent. Therefore, the degree of 
emission limitation for these units is a 16 percent reduction in 
emission rate on a lb CO2/MWh-gross basis over an extended 
period (e.g., an annual calendar-year basis).
c. Imminent-Term and Near-Term Coal-Fired Steam Generating Units
    As discussed above, the BSER for imminent-term and near-term coal-
fired steam generating units is routine methods of operation and 
maintenance. Application of this BSER results in no increase in 
emission rate. Thus, the degree of emission limitation corresponding to 
the application of the BSER is no increase in emission rate on a lb 
CO2/MWh-gross basis over an extended period (e.g., an annual 
calendar-year basis).
    Because the EPA is soliciting comment on low levels of natural gas 
co-firing as a potential BSER for imminent-term and near-term units, 
the EPA is also soliciting comment on the degree of emission limitation 
that may be achievable by application of low levels of natural gas co-
firing. The EPA is soliciting comment on degrees of emission limitation 
defined by reductions in emission rate on a lb CO2/MWh-gross 
basis that are equal to the percent of heat input times 0.4, the 
percent of reduction in emission rate that may be achieved for each 
percent of natural gas heat input. For example, for natural gas co-
firing at 1 to 10 percent, this results in a degree of emission 
limitation of 0.4 to 4 percent reduction in emission rate on a lb 
CO2/MWh-gross basis (over an extended period of time). More 
specifically, the EPA solicits comment on the degree of emission 
limitation based on the calculation method defined in the preceding 
text up to a 4 percent reduction in emission rate (lb CO2/
MWh-gross) over an extended period of time. Alternatively, as the EPA 
is also soliciting comment on a fixed percent of low levels of natural 
gas co-firing, the EPA is additionally soliciting comment on a fixed 
degree of emission limitation based on the same calculation method. 
Because the reductions in GHG emissions from low levels of natural gas 
co-firing are relatively low and may be challenging to measure, the EPA 
is also soliciting comment on a degree of emission limitation defined 
on a percent of heat input basis, although the EPA also recognizes that 
measurement of fuel flow may also have challenges.
5. Other Emission Reduction Measures
a. Heat Rate Improvements
    Heat rate is a measure of efficiency that is commonly used in the 
power sector. The heat rate is the amount of energy input, measured in 
Btu, required to generate one kWh of electricity. The lower an EGU's 
heat rate, the more efficiently it operates. As a result, an EGU with a 
lower heat rate will consume less fuel and emit lower amounts of 
CO2 and other air pollutants per kWh generated as compared 
to a less efficient unit. HRI measures include a variety of technology 
upgrades and operating practices that may achieve CO2 
emission rate reductions of 0.1 to 5 percent for individual EGUs. The 
EPA considered HRI to be part of the BSER in the CPP and to be the BSER 
in the ACE Rule. However, the reductions that may be achieved by HRI 
are small relative to the reductions from natural gas co-firing and 
CCS. Also, some facilities that apply HRI would, as a result of their 
increased efficiency, increase their utilization and therefore increase 
their CO2 emissions (as well as emissions of other air 
pollutants), a phenomenon that the EPA has termed the ``rebound 
effect.'' Therefore, the EPA is not proposing HRI as a part of BSER.
i. CO2 Reductions From HRI in Prior Rulemakings
    In the CPP, the EPA quantified emission reductions achievable 
through heat rate improvements on a regional basis by an analysis of 
historical emission rate data, taking into consideration operating load 
and ambient temperature. The Agency concluded that EGUs can achieve on 
average a 4.3 percent improvement in the Eastern Interconnection, a 2.1

[[Page 33357]]

percent improvement in the Western Interconnection, and a 2.3 percent 
improvement in the Texas Interconnection. See 80 FR 64789 (October 23, 
2015). The Agency then applied all three of the building blocks to 2012 
baseline data and quantified, in the form of CO2 emission 
rates, the reductions achievable in each interconnection in 2030, and 
then selected the least stringent as a national performance rate. Id. 
at 64811-19. The EPA noted that building block 1 measures could not by 
themselves constitute the BSER because the quantity of emission 
reductions achieved would be too small and because of the potential for 
an increase in emissions due to increased utilization (i.e., the 
``rebound effect'').
    A description of the ACE Rule is detailed in section IX of this 
preamble.
ii. Updated CO2 Reductions From HRI
    The HRI measures include improvements to the boiler island (e.g., 
neural network system, intelligent sootblower system), improvements to 
the steam turbine (e.g., turbine overhaul and upgrade), and other 
equipment upgrades (e.g., variable frequency drives). Some regular 
practices that may recover degradation in heat rate to recent levels--
but that do not result in upgrades in heat rate over recent design 
levels and are therefore not HRI measures--include practices such as 
in-kind replacements and regular surface cleaning (e.g., descaling, 
fouling removal). Specific details of the HRI measures are described in 
the GHG Mitigation Measures for Steam Generating Units TSD and an 
updated 2023 Sargent and Lundy HRI report (Heat Rate Improvement Method 
Costs and Limitations Memo), available in the docket. Most HRI upgrade 
measures achieve reductions in heat rate of less than 1 percent. In 
general, the 2023 Sargent and Lundy HRI report, which updates the 2009 
Sargent and Lundy HRI report, shows that HRI achieve less reductions 
than indicated in the 2009 report, and shows that several HRI either 
have limited applicability or have already been applied at many units. 
Steam path overhaul and upgrade may achieve reductions up to 5.15 
percent, with the average being around 1.5 percent. Different 
combinations of HRI measures do not necessarily result in cumulative 
reductions in emission rate (e.g., intelligent sootblowing systems 
combined with neural network systems). Some of the HRI measures (e.g., 
variable frequency drives) only impact heat rate on a net generation 
basis by reducing the parasitic load on the unit and would thereby not 
be observable for emission rates measured on a gross basis. Assuming 
many of the HRI measures could be applied to the same unit, adding 
together the upper range of some of the HRI percentages could yield an 
emission rate reduction of around 5 percent. However, the reductions 
that the fleet could achieve on average are likely much smaller. As 
noted, the 2023 Sargent and Lundy HRI report notes that, in many cases, 
units have already applied HRI upgrades or that those upgrades would 
not be applicable to all units. The unit level reductions in emission 
rate from HRI are small relative to CCS or natural gas co-firing. In 
the CPP and ACE Rule, the EPA viewed CCS and natural gas co-firing as 
too costly to qualify as the BSER; those costs have fallen since those 
rules and, as a result, CCS and natural gas co-firing do qualify as the 
BSER for the long-term and medium-term subcategories, respectively.
iii. Potential for Rebound in CO2 Emissions
    Reductions achieved on a rate basis from HRI may not result in 
overall emission reductions and could instead cause a ``rebound 
effect'' from increased utilization. A rebound effect would occur 
where, because of an improvement in its heat rate, a steam generating 
unit experiences a reduction in variable operating costs that makes the 
unit more competitive relative to other EGUs and consequently raises 
the unit's output. The increase in the unit's CO2 emissions 
associated with the increase in output would offset the reduction in 
the unit's CO2 emissions caused by the decrease in its heat 
rate and rate of CO2 emissions per unit of output. The 
extent of the offset would depend on the extent to which the unit's 
generation increased. The CPP did not consider HRI to be BSER on its 
own, in part because of the potential for a rebound effect. Analysis 
for the ACE Rule, where HRI was the entire BSER, observed a rebound 
effect for certain sources in some cases. In this action, where 
different subcategories of units are proposed to be subject to 
different BSER measures, steam generating units in a hypothetical 
subcategory with HRI as BSER could experience a rebound effect. Because 
of this potential for perverse GHG emission outcomes resulting from 
deployment of HRI at certain steam generating units, coupled with the 
relatively minor overall GHG emission reductions that would be expected 
from this measure, the EPA is not proposing HRI as the BSER for any 
subcategory of existing coal-fired steam generating units.

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

    In this section of the preamble, the EPA is addressing natural gas- 
and oil-fired steam generating units. The EPA is proposing the BSER and 
degree of emission limitation achievable by application of the BSER for 
those units and identifying the associated emission rates that States 
may apply to these units. For the reasons described here, the EPA is 
proposing subcategories based on load level (i.e., annual capacity 
factor), specifically, units that are base load, intermediate load, and 
low load. At this time, the EPA is not proposing requirements for low 
load units but is taking comment on a BSER of lower emitting fuels for 
those units. The EPA is proposing routine methods of operation and 
maintenance as BSER for intermediate and base load units. Applying that 
BSER would not achieve emission reductions but would prevent increases 
in emission rates. The EPA is proposing presumptive standards of 
performance that differ between intermediate and base load units due to 
their differences in operation, as detailed in section XII.D.1.b.v of 
this preamble. The EPA is also proposing a separate subcategory for 
non-continental oil-fired steam generating units, which operate 
differently from continental units, with presumptive standards of 
performance detailed in section XII.D.1.b.vi of this preamble.
    Natural gas- and oil-fired steam generating units combust natural 
gas or distillate fuel oil or residual fuel oil in a boiler to produce 
steam for a turbine that drives a generator to create electricity. In 
non-continental areas, existing natural gas- and oil-fired steam 
generating units may provide base load power, but in the continental 
U.S., most existing units operate in a load-following manner. There are 
approximately 200 natural gas-fired steam generating units and fewer 
than 30 oil-fired steam generating units in operation in the 
continental U.S. Fuel costs and inefficiency relative to other 
technologies (e.g., combustion turbines) result in operation at lower 
annual capacity factors for most units. Based on data reported to EIA 
and CAMD for the contiguous U.S., for natural gas-fired steam 
generating units in 2019, the average annual capacity factor was less 
than 15 percent and 90 percent of units had annual capacity factors 
less than 35 percent. For oil-fired steam generating units in 2019, no 
units had annual capacity factors above 8 percent. Additionally, their 
load-following method of operation results in frequent cycling and a 
greater proportion of time

[[Page 33358]]

spent at low hourly capacities, when generation is less efficient. 
Furthermore, because startup times for most boilers are usually long, 
natural gas steam generating units may operate in standby mode between 
periods of peak demand. Operating in standby mode requires combusting 
fuel to keep the boiler warm, and this further reduces the efficiency 
of natural gas combustion.
    Unlike coal-fired steam generating units, the CO2 
emission rates of oil- and natural gas-fired steam generating units 
that have similar annual capacity factors do not vary considerably 
between units. This is partly due to the more uniform qualities (e.g., 
carbon content) of the fuel used. However, the emission rates for units 
that have different annual capacity factors do vary considerably, as 
detailed in the Natural Gas- and Oil-fired Steam Generating Unit TSD. 
Low annual capacity factor units cycle frequently, have a greater 
proportion of CO2 emissions that may be attributed to 
startup, and have a greater proportion of generation at inefficient 
hourly capacities. Intermediate annual capacity factor units operate 
more often at higher hourly capacities, where CO2 emission 
rates are lower. High annual capacity factor units operate still more 
at base load conditions, where units are more efficient and 
CO2 emission rates are lower. Based on these performance 
differences between these load levels, the EPA is, in general, 
proposing to divide natural gas- and oil-fired steam generating units 
into three subcategories each--low load, intermediate load, and base 
load--as specified in section X.C.2 of this preamble: ``low'' load is 
defined by annual capacity factors less than 8 percent, 
``intermediate'' load is defined by annual capacity factors greater 
than or equal to 8 percent and less than 45 percent, and ``base'' load 
is defined by annual capacity factors greater than 45 percent.
1. Options Considered for BSER
    The EPA has considered various methods for controlling 
CO2 emissions from natural gas- and oil-fired steam 
generating units to determine whether they meet the criteria for BSER. 
Co-firing natural gas cannot be the BSER for these units because 
natural gas- and oil-fired steam generating units already fire large 
proportions of natural gas. Most natural gas-fired steam generating 
units fire more than 90 percent natural gas on a heat input basis, and 
any oil-fired steam generating units that would potentially operate 
above an annual capacity factor of around 15 percent would combust 
natural gas as a large proportion of their fuel as well. Nor is CCS a 
candidate for BSER. The utilization of most gas-fired units, and likely 
all oil-fired units, is relatively low, and as a result, the amount of 
CO2 available to be captured is low. However, the capture 
equipment would still need to be sized for the nameplate capacity of 
the unit. Therefore, the capital and operating costs of CCS would be 
high relative to the amount of CO2 available to be captured. 
Additionally, again due to lower utilization, the amount of IRC section 
45Q tax credits that owner/operators could claim would be low. Because 
of the relatively high costs and the relatively low cumulative emission 
reduction potential for these natural gas- and oil-fired steam 
generating units, the EPA is not proposing CCS as the BSER for them.
    The EPA has reviewed other possible controls but is not proposing 
any of them as the BSER for natural gas- and oil-fired units either. 
Co-firing hydrogen in a boiler is technically possible, but, for the 
same reasons discussed in section VII of this preamble, the only 
hydrogen that could be considered for the BSER would be low-GHG 
hydrogen, and there is limited availability of that hydrogen now and in 
the near future. Additionally, for natural gas-fired steam generating 
units, setting a future standard based on hydrogen would have limited 
GHG reduction benefits given the low utilization of natural gas- and 
oil-fired steam generating units. Lastly, HRI for these types of units 
would face many of the same issues as for coal-fired steam generating 
units; in particular, HRI could result in a rebound effect that would 
increase emissions.
    However, the EPA recognizes that natural gas- and oil-fired steam 
generating units could possibly, over time, operate more, in response 
to other changes in the power sector. Additionally, some coal-fired 
steam generating units have converted to 100 percent natural gas-fired, 
and it is possible that more may do so in the future. Moreover, in part 
because the fleet continues to age, the plants may operate with 
degrading emission rates. In light of these possibilities, identifying 
the BSER and degrees of emission limitation for these sources would be 
useful to provide clarity and prevent backsliding in GHG performance. 
Therefore, the EPA is proposing BSER for intermediate and base load 
natural gas- and oil-fired steam generating units to be routine methods 
of operation and maintenance, such that the sources could maintain the 
emission rates (on a lb/MWh-gross basis) currently maintained by the 
majority of the fleet across discrete ranges of annual capacity factor. 
The EPA is proposing this BSER for intermediate load and base load 
natural gas- and oil-fired steam generating units, regardless of the 
operating horizon of the unit.
    A BSER based on routine methods of operation and maintenance is 
adequately demonstrated because units already operate with those 
practices. There are no or negligible additional costs because there is 
no additional technology that units are required to apply and there is 
no change in operation or maintenance that units must perform. 
Similarly, there are no adverse non-air quality health and 
environmental impacts or adverse impacts on energy requirements. Nor do 
they have adverse impacts on the energy sector from a nationwide or 
long-term perspective. The EPA's initial modeling, which supports this 
proposed rule, indicates that by 2040, a number of natural gas-fired 
steam generating units have remained in operation since 2030, although 
at reduced annual capacity factors. There are no CO2 
reductions that may be achieved at the unit level, but applying the 
BSER should preclude increases in emission rates. Routine methods of 
operation and maintenance do not advance useful control technology, but 
this point is not significant enough to offset their benefits.
    The EPA is also taking comment on, but not proposing, a BSER of 
lower emitting fuels for low load natural gas- and oil-fired steam 
generating units. As noted earlier in this preamble, non-coal fossil 
fuels combusted in utility boilers typically include natural gas, 
distillate fuel oil (i.e., fuel oil No. 1 and No. 2), and residual fuel 
oil (i.e., fuel oil No. 5 and No. 6). The EPA previously established 
heat-input based fuel composition as BSER in the 2015 NSPS (termed 
``clean fuels'' in that rulemaking) for new non-base load natural gas- 
and multi-fuel-fired stationary combustion turbines (80 FR 64615-17; 
October 23, 2015), and the EPA is similarly proposing lower emitting 
fuels as BSER for new low load combustion turbines as described in 
section VII of this preamble. For low load natural gas- and oil-fired 
steam generating units, the high variability in emission rates 
associated with the variability of load at the lower-load levels limits 
the benefits of a BSER based on routine maintenance and operation. That 
is because the high variability in emission rates would make it 
challenging to determine an emission rate (i.e., on a lb 
CO2/MWh-gross basis) that could serve as the presumptive 
standard of performance that would reflect application of a BSER of 
routine operation and maintenance.

[[Page 33359]]

On the other hand, for those units, a BSER of ``uniform fuels'' and an 
associated presumptive standard of performance based on a heat input 
basis, as described in section XII.D of this preamble, may be 
reasonable. The EPA is soliciting comment on the fuel types that would 
constitute ``uniform fuels'' specific to low load natural gas- and oil-
fired steam generating units.
2. Degree of Emission Limitation
    As discussed above, because the proposed BSER for base load and 
intermediate load natural gas- and oil-fired steam generating plants is 
routine operation and maintenance, which the units are, by definition, 
already employing, the degree of emission limitation by application of 
this BSER is no increase in emission rate on a lb CO2/MWh-
gross basis over an extended period of time (e.g., an annual calendar 
year).

F. Summary

    The EPA has evaluated options for BSER for GHG emissions for fossil 
fuel-fired steam generating units. The EPA is proposing 
subcategorization of steam generating units by the type of fossil fuel 
fired in the unit, and, for each fuel type, further levels of 
subcategorization. For each subcategory, the EPA is proposing a BSER 
and resulting degree of emission limitation achievable by application 
of that BSER, as summarized in table 5, with presumptively approvable 
standards of performance for use in State plan development (see section 
XII of this preamble for details) included for completeness. For coal-
fired steam generating units that plan to operate in the long-term, the 
EPA is proposing a BSER of CCS with 90 percent capture of 
CO2. In response to industry stakeholder input and 
recognizing that the cost effectiveness of controls depends on a unit's 
expected operating time horizon, which dictates the amortization period 
for the capital costs of the controls, the EPA is proposing other BSER 
for coal-fired units with shorter operating horizons while taking 
comment on what dates most appropriately define the thresholds between 
these different subcategories. For the different subcategories of 
natural gas- and oil-fired units, the EPA is proposing BSERs based on 
routine methods of operation and maintenance. The EPA solicits comment 
on the proposed BSER and degrees of emission limitation, as well as the 
proposed subcategorization, including the potential to remove the 
imminent-term subcategory and include units with earlier commitments to 
permanently cease operations in either the near-term or medium-term 
subcategory. It is noted that for imminent-term and near-term coal-
fired steam generating units, the EPA is also soliciting comment on 
potential BSERs based on co-firing low levels of natural gas.
---------------------------------------------------------------------------

    \561\ Presumptive standards of performance are discussed in 
detail in section XII of the preamble. While States establish 
standards of performance for sources the EPA provides presumptively 
approvable standards of performance based on the degree of emission 
limitation achievable through application of the BSER for each 
subcategory. Inclusion in this table is for completeness.

                         Table 5--Summary of Proposed BSER, Subcategories, and Degrees of Emission Limitation for Affected EGUs
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                Presumptively       Ranges in values on
           Affected EGUs             Subcategory definition           BSER             Degree of emission    approvable standard      which the EPA is
                                                                                           limitation        of performance \561\    soliciting comment
--------------------------------------------------------------------------------------------------------------------------------------------------------
Long-term existing coal-fired steam  Coal-fired steam        CCS with 90 percent     88.4 percent           88.4 percent           The achievable
 generating units.                    generating units that   capture of CO2.         reduction in           reduction in annual    capture rate from 90
                                      have not elected to                             emission rate (lb      emission rate (lb      to 95 percent or
                                      commit to permanently                           CO2/MWh-gross).        CO2/MWh-gross) from    greater and the
                                      cease operations by                                                    the unit-specific      achievable degree of
                                      January 1, 2040.                                                       baseline.              emission limitation
                                                                                                                                    defined by a
                                                                                                                                    reduction in
                                                                                                                                    emission rate from
                                                                                                                                    75 to 90 percent.
Medium-term existing coal-fired      Coal-fired steam        Natural gas co-firing   A 16 percent           A 16 percent           The percent of
 steam generating units.              generating units that   at 40 percent of the    reduction in           reduction in annual    natural gas co-
                                      have elected to         heat input to the       emission rate (lb      emission rate (lb      firing from 30 to 50
                                      commit to permanently   unit.                   CO2/MWh-gross).        CO2/MWh-gross) from    percent and the
                                      cease operations                                                       the unit-specific      degree of emission
                                      after December 31,                                                     baseline.              limitation from 12
                                      2031, and before                                                                              to 20 percent.
                                      January 1, 2040, and
                                      that are not near-
                                      term units.
Near-term existing coal-fired steam  Coal-fired steam        Routine methods of      No increase in         An emission rate       The presumptive
 generating units.                    generating units that   operation.              emission rate (lb      limit (lb CO2/MWh-     standard: 0 to 2
                                      have elected to                                 CO2/MWh-gross).        gross) defined by      standard deviations
                                      commit to permanently                                                  the unit-specific      in annual emission
                                      cease operations                                                       baseline.              rate above or 0 to
                                      after December 31,                                                                            10 percent above the
                                      2031, and before                                                                              unit-specific
                                      January 1, 2035, and                                                                          baseline.
                                      commit to adopt an
                                      annual capacity
                                      factor limit of 20
                                      percent.
Imminent-term existing coal-fired    Coal-fired steam        Routine methods of      No increase in         An emission rate       The presumptive
 steam generating units.              generating units that   operation.              emission rate (lb      limit (lb CO2/MWh-     standard: 0 to 2
                                      have elected to                                 CO2/MWh-gross).        gross) defined by      standard deviations
                                      commit to permanently                                                  the unit-specific      in annual emission
                                      cease operations                                                       baseline.              rate above or 0 to
                                      before January 1,                                                                             10 percent above the
                                      2032.                                                                                         unit-specific
                                                                                                                                    baseline.

[[Page 33360]]

 
Base load continental existing oil-  Oil-fired steam         Routine methods of      No increase in         An annual emission     The threshold between
 fired steam generating units.        generating units with   operation and           emission rate (lb      rate limit of 1,300    intermediate and
                                      an annual capacity      maintenance.            CO2/MWh-gross).        lb CO2/MWh-gross.      base load from 40 to
                                      factor greater than                                                                           50 percent annual
                                      or equal to 45                                                                                capacity factor; the
                                      percent.                                                                                      degree of emission
                                                                                                                                    limitation from
                                                                                                                                    1,250 lb CO2/MWh-
                                                                                                                                    gross to 1,800 lb
                                                                                                                                    CO2/MWh-gross.
Intermediate load continental        Oil-fired steam         Routine methods of      No increase in         An annual emission     The degree of
 existing oil-fired steam             generating units with   operation and           emission rate (lb      rate limit of 1,500    emission limitation
 generating units.                    an annual capacity      maintenance.            CO2/MWh-gross).        lb CO2/MWh-gross.      from 1,400 lb CO2/
                                      factor greater than                                                                           MWh-gross to 2,000
                                      or equal to 8 percent                                                                         lb CO2/MWh-gross.
                                      and less than 45
                                      percent.
Low load (continental and non-       Oil-fired steam         None proposed.........  .....................  .....................  The threshold between
 continental) existing oil-fired      generating units with                                                                         low and intermediate
 steam generating units.              an annual capacity                                                                            load from 5 to 20
                                      factor less than 8                                                                            percent annual
                                      percent.                                                                                      capacity factor.
Intermediate and base load non-      Non-continental oil-    Routine methods of      No increase in         An emission rate       The presumptive
 continental existing oil-fired       fired steam             operation and           emission rate (lb      limit (lb CO2/MWh-     standard: 0 to 2
 steam generating units.              generating units with   maintenance.            CO2/MWh-gross).        gross) defined by      standard deviations
                                      an annual capacity                                                     the unit-specific      in annual emission
                                      factor greater than                                                    baseline.              rate above or 0 to
                                      or equal to 8 percent.                                                                        10 percent above the
                                                                                                                                    unit-specific
                                                                                                                                    baseline.
Base load existing natural gas-      Natural gas-fired       Routine methods of      No increase in         An annual emission     The threshold between
 fired steam generating units.        steam generating        operation and           emission rate (lb      rate limit of 1,300    intermediate and
                                      units with an annual    maintenance.            CO2/MWh-gross).        lb CO2/MWh-gross.      base load from 40 to
                                      capacity factor                                                                               50 percent annual
                                      greater than or equal                                                                         capacity factor; The
                                      to 45 percent.                                                                                acceptable standard
                                                                                                                                    from 1,250 lb CO2/
                                                                                                                                    MWh-gross to 1,400
                                                                                                                                    lb CO2/MWh-gross.
Intermediate load existing natural   Natural gas-fired       Routine methods of      No increase in         An annual emission     The acceptable
 gas-fired steam generating units.    steam generating        operation and           emission rate (lb      rate limit of 1,500    standard from 1,400
                                      units with an annual    maintenance.            CO2/MWh-gross).        lb CO2/MWh-gross.      lb CO2/MWh-gross to
                                      capacity factor                                                                               1,600 lb CO2/MWh-
                                      greater than or equal                                                                         gross.
                                      to 8 percent and less
                                      than 45 percent.
Low load existing natural gas-fired  Natural gas-fired       None proposed.........  .....................  .....................  The threshold between
 steam generating units.              steam generating                                                                              low and intermediate
                                      units with an annual                                                                          load from 5 to 20
                                      capacity factor less                                                                          percent annual
                                      than 8 percent.                                                                               capacity factor.
--------------------------------------------------------------------------------------------------------------------------------------------------------

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

A. Overview

    Because the EPA has established NSPS for GHG emissions from new 
fossil fuel-fired stationary combustion turbines under CAA section 
111(b), it has an obligation to also establish emission guidelines for 
GHG emissions from existing fossil-fuel fired stationary combustion 
turbines under CAA section 111(d). Existing fossil fuel-fired 
stationary combustion turbines already represent a significant share of 
GHG emissions from EGUs and are quickly becoming the largest source of 
GHG emissions from the power sector. As other fossil fuel-fired EGUs 
reduce utilization or retire, at least some of this generation may 
shift to the existing combustion turbine fleet with significant GHG 
emission implications, particularly if the latter is not subject to 
limits on GHG emissions. For these reasons, the EPA intends to 
discharge its obligation to prescribe emission guidelines for these 
sources as expeditiously as practicable. In this document, the EPA is 
proposing emission guidelines for certain existing fossil fuel-fired 
stationary combustion turbines and soliciting comment on approaches 
that could be used to establish emission guidelines for the remaining 
units in the fleet.
    In considering how to address this problem, the EPA believes there 
are at least two key factors to consider. The first is that determining 
the BSER and issuing emission guidelines covering these units sooner 
rather than later is important to address the GHG emissions from this 
growing portion of the inventory. The second is related to the size of 
the affected fleet and the implications for the feasibility and timing 
of implementing potential candidates for BSER. As discussed later in 
this section, there are at least three technologies that could be 
applied to reduce GHGs from existing combustion turbines (CCS, hydrogen 
co-firing, and heat rate improvements), all of which are available 
today and are being pursued to at least some degree by owners and 
operators of these sources. Although the EPA believes that these 
technologies are available and adequately demonstrated at the level of 
individual existing combustion turbines, emission guidelines for these 
sources must also consider how much of the fleet could reasonably 
implement

[[Page 33361]]

one or more of these potential BSER approaches in a given time frame.
    Furthermore, the EPA is aware that grid operators and power 
companies currently rely on existing fossil fuel-fired combustion 
turbines as a flexible and readily dispatchable resource that plays a 
key role in fulfilling resource adequacy and operational reliability 
needs. Although advancements in energy storage and accelerated 
development and deployment of zero-emitting resources may diminish 
reliance on existing fossil fuel-fired combustion turbines for 
reliability purposes over time, it is imperative that emission 
guidelines for these sources not impair the reliability of the bulk 
power system. For these reasons, the EPA believes that it is important 
that a BSER determination and associated emission guidelines for 
existing fossil fuel-fired combustion turbines rely on GHG control 
options that can be feasibly and cost-effectively implemented at a 
scale commensurate with the size of the regulated fleet, and provide 
sufficient operational flexibility and lead time to allow for smooth 
implementation of the GHG emission limitations that preserves system 
reliability.
    Given the large size of the existing combustion turbine fleet and 
the lead time required to develop CCS and hydrogen-related 
infrastructure, the EPA believes the BSER for this category entails 
significant lead time for application of CCS or low-GHG hydrogen co-
firing. As a result, the EPA is planning to break the existing 
combustion turbine category into two segments, and is focusing this 
proposal on the largest and most frequently operated (e.g., base load) 
existing combustion turbines that have the highest GHG emissions on an 
annual basis. For these large and frequently operated existing 
combustion turbines, the EPA is proposing to determine that the BSER 
consists of either application of CCS by 2035, or application of low-
GHG hydrogen co-firing beginning in 2032, based on an evaluation of the 
statutory BSER criteria that mirrors EPA's evaluation of the BSER for 
new base load combustion turbines. This focused approach will limit GHG 
emissions from the highest-emitting existing natural gas combustion 
turbines, while allowing sufficient lead time for application of CCS or 
low-GHG hydrogen co-firing and limiting the amount of affected capacity 
to a degree that is consistent with the availability of these two GHG 
mitigation technologies. The EPA intends to undertake a separate 
rulemaking as expeditiously as practicable that addresses emissions 
from the remaining combustion turbines.
    In this document, the EPA is soliciting comment on both the scope 
of these proposed emission guidelines (in other words, the 
applicability thresholds that would determine which existing combustion 
turbines are in the first segment) as well as the BSER for units 
covered in this rulemaking. In section XII of this preamble, the EPA is 
also taking comment on the associated State plan requirements 
associated with the BSER for existing fossil fuel-fired turbines.
    As described in more detail below, the EPA is proposing to 
determine that the BSER for large and frequently operated existing 
stationary combustion turbines is the same as for the proposed second 
phase of requirements for new base load combustion turbines. 
Accordingly, the EPA is proposing emission guidelines for these 
existing stationary combustion turbines that would require either that 
these sources achieve a degree of emission limitation consistent with 
the use of CCS by 2035, or achieve a degree of emission limitation 
reflecting the utilization of 30 percent low-GHG hydrogen by volume by 
2032 (increasing to 96 percent low-GHG hydrogen by volume by 2038).
    The EPA believes that it is important to stagger CCS requirements 
for existing coal-fired units and new and existing fossil fuel-fired 
turbines to allow time for both deployment of CCS infrastructure and to 
accommodate increased demand for specialized engineering and 
construction labor needed to build CCS equipment. The EPA also believes 
that because coal-fired units emit more CO2/MWh, that to the 
extent that there are limitations to the amount of CCS that can be 
installed by 2030 it makes sense to focus a CCS BSER on those coal-
fired units first. A 2035 compliance timeframe would allow for 
staggering of resources needed to install CCS while still allowing 
existing turbines to take advantage of the IRC section 45Q tax credits 
to make CCS controls more cost-effective or to use hydrogen, produced 
at facilities eligible for the 45V tax credits, making hydrogen co-
firing more cost effective.\562\ In the rest of this section, the EPA 
proposes regulations for the first segment and solicits comment on 
specific elements of the approach. This section also briefly discusses 
what BSER might look like for units in the second rulemaking, and 
requests comments that could inform the development of a rulemaking 
defining BSER, degrees of emission limitation, compliance deadlines and 
other elements of an emission guideline for those units at a later 
date.
---------------------------------------------------------------------------

    \562\ CCS projects that commence construction as late as 
December 31, 2032 can qualify for the 45Q tax credit.
---------------------------------------------------------------------------

    As explained in more detail later in this section, the EPA is 
proposing that the first segment it would cover would be units greater 
than 300 MW with an annual capacity factor of greater than 50 percent. 
The EPA projects that 37 GW of capacity would meet these criteria in 
2035, representing 14 percent of the projected existing combustion 
turbine capacity and 23 percent of the projected generation from 
existing combustion turbines in 2035. As is explained further below, 
the EPA is proposing this capacity factor and capacity threshold after 
weighing the quantity of emissions from these units and considerations 
about the feasibility of installing significant amounts of CCS and/or 
hydrogen co-firing. In short, these units offer the best opportunity to 
achieve significant emissions reduction consistent with what the EPA 
believes these technologies will be capable of on a national scale. 
Similar to its proposal for new base load turbines, the EPA is 
proposing that BSER for those existing sources be both pathways, that 
is CCS with 90 percent capture in 2035 and clean hydrogen combusting 30 
percent by volume in 2032 and 96 percent by volume in 2038. 
Alternatively, as with the proposal for new base load turbines, the EPA 
is taking comment on whether to finalize a BSER with a single pathway 
based on application of CCS with 90 percent capture, which could also 
be met by co-firing with low-GHG hydrogen as a compliance option, or 
vice-versa. The EPA is also taking comment on whether the compliance 
date should begin earlier, including as early as 2030.\563\
---------------------------------------------------------------------------

    \563\ If we finalize one of these variations, the state plan 
requirements may change accordingly.
---------------------------------------------------------------------------

    The EPA has promulgated several prior rulemakings under both CAA 
section 111(b) and section 111(d) that provide the regulated sector 
with lead time to accommodate the time needed to deploy control 
technology. Section VII.F.3.a of this preamble discusses, in the 
section 111(b) context, precedent for rulemakings that provide such 
lead time. For additional examples under CAA section 111(d), see 70 FR 
28606, 28619 (May 18, 2005) (establishing emission guidelines for 
electric utility steam generating units, with a 13-year compliance 
timeframe for a second control phase); 61 FR 9905, 9919 (March 12, 
1996) (establishing emission guidelines for municipal solid waste 
landfills, with a 2.5-year compliance

[[Page 33362]]

timeframe); 62 FR 48348, 48381 (September 15, 1997) (establishing 
emission guidelines for hospital/medical/infectious waste incinerators, 
with up to 3 years after State plan approval for facilities to install 
control equipment). Section XI.B provides background information 
concerning the composition of the current fossil fuel-fired stationary 
combustion turbine fleet and how it is expected to change in the near 
future. In section XI.C, the EPA proposes an approach for units covered 
in this rulemaking and in section XI.D, the EPA summarizes the key 
topics for which we are soliciting comment relative to existing 
combustion turbines. Finally, section XI.E, outlines a potential 
approach for units covered in a second rulemaking

B. The Existing Stationary Combustion Turbine Fleet

    In 2021, existing combustion turbines represented 37 percent of the 
GHG emissions from the power sector and 40 percent of the generation 
from the power sector. In the EPA's updated baseline projections for 
the power sector, they represent 74 percent of the GHG emissions and 25 
percent of the generation in 2035. In EPA's modeling of the 2035 
control case, in which both existing fossil fuel-fired EGUs and new 
stationary combustion turbine EGUs are subject to the emissions 
limitations proposed in this action but existing combustion turbine 
EGUs are left uncontrolled, load shifting from those two categories of 
sources to the existing combustion turbines results in an increase in 
the share of the emissions from existing combustion turbines (including 
combined cycle and simple cycle combustion turbines) to 82 percent 
while their share of generation remains 25 percent. Moreover, in that 
control case, existing combined cycle combustion turbines are 
responsible for 71 percent of the CO2 emissions from the 
power sector.
    In the EPA's modeling in support of these rules, we see two trends 
that are important relative to existing combustion turbines. First, the 
EPA's analysis of the reference case (which includes the impacts of IRA 
without considering the GHG limitation requirements proposed in these 
rules) projects a long-term decline in generation and emissions from 
existing combustion turbines relative to current generation and 
emissions. In this reference case, combined cycle generation falls in 
each model run year from 2028 through 2050, and it falls by more than 
50 percent between 2030 and 2045. Generation from existing simple cycle 
combustion turbines is projected to peak in 2030 before declining by 
more than 70 percent by 2045. While generation falls from turbines, 
this is primarily caused by declining capacity factors, not through 
retirements.
    Historical data shows a wide range of variation in both the heat 
rate and the GHG emission rates among both existing combined cycle 
combustion turbines and existing simple cycle combustion turbines. The 
GHG emission rates for existing combined cycle units range from as low 
as 644 lb CO2/MWh-gross to as high as 1,891 lb 
CO2/MWh-gross, and annual capacity factors range from as low 
as 1 percent to as high as 85 percent. While there is some correlation 
between units with low-GHG emission rates (e.g., more efficient units) 
and utilization, some low efficiency combined cycle units have 
historically operated at very high capacity factors. For instance, two 
of the highest operating units (at 85 percent capacity utilization) 
have GHG emission rates of nearly 1,200 lb/MWh-gross.
C. BSER for Base Load Turbines Over 300 MW
    As noted earlier, the EPA is adopting an approach in which existing 
combustion turbines would be regulated in two segments. The proposed 
emission guidelines presented in this document focus on the first 
segment, which comprises the base load units (e.g., those operated at 
capacity factors of greater than 50 percent) over 300 MW. The EPA 
intends to undertake a separate rulemaking to address the second 
segment, comprising the remainder of the existing fossil fuel-fired 
stationary combustion fleet, as expeditiously as practicable.
    Because the first segment would be focused on the largest most 
frequently used units, the EPA is proposing that the BSER for these 
units would be CCS or a BSER based upon burning low-GHG hydrogen. As is 
the case for new base load combustion turbines, each of these sets of 
controls is adequately demonstrated, of reasonable cost, and consistent 
with the other criteria to qualify as the BSER.
    Because the second segment would include both smaller more 
frequently used units and less frequently used units, in that action, 
the EPA anticipates considering a broader range of technologies 
including heat rate improvements. This approach recognizes the 
imperatives (the urgent need to reduce greenhouse gases), the 
opportunities (including the availability of IRC section 45Q tax 
credits incentivizing CCS installation as long as sources commence 
construction by January 1, 2033), and the need for infrastructure for 
CCS and co-firing low-GHG hydrogen to be deployed at a broader scale if 
these BSER technologies are to be deployed broadly at smaller and less 
frequently operated existing combustion turbines.
    The EPA is proposing emission guidelines for units with a capacity 
factor greater than 50 percent and a capacity of greater than 300 MW, 
but is also taking comment on whether that capacity factor threshold or 
capacity threshold should be lower (for instance 40 percent for the 
capacity factor and 200 MW or 100 MW for the capacity). The EPA is 
proposing that 300 MW is the appropriate threshold for applicability 
because it focuses on the units with the highest emissions where CCS is 
likely to be most cost effective. As an important first step towards 
abating emissions from the existing turbine fleet and recognizing that 
at least some project developers are considering the use of clean 
hydrogen in base load turbines \564\ and recognizing that there are 
likely limits to the clean hydrogen supply in the mid-term, the EPA 
believes that it is appropriate to also propose a clean hydrogen BSER 
for the same set of units. Table 6 provides information from IPM 
detailing the amount of capacity and generation from the 2035 IPM 
projected control case that would be covered under various capacity 
thresholds.
---------------------------------------------------------------------------

    \564\ As one developer notes, ``the plant will be capable of 
supporting a balanced and diverse power generation portfolio in the 
future; from energy storage capable of accommodating seasonal 
fluctuations from renewable energy, to cost effective, dispatchable 
intermediate and baseload power.'' https://www.longridgeenergy.com/news/2020-10-13-long-ridge-energy-terminal-partners-with-new-fortress-energy-and-ge-to-transition-power-plant-to-zero-carbon-hydrogen.

[[Page 33363]]



    Table 6--Key Characteristics for Baseload Combined Cycle Units of
                           Various Capacities
------------------------------------------------------------------------
                                                 Percentage   Percentage
 NGCC units projected to run at a                 of total     of total
 capacity factor of greater than     Capacity       NGCC         NGCC
50 percent and at a capacity size      (GW)       capacity    generation
           greater than                             (%)          (%)
------------------------------------------------------------------------
100 MW...........................          134           49           78
200 MW...........................           85           31           51
300 MW...........................           37           14           23
400 MW...........................           12            4           10
500 MW...........................            6            2            7
------------------------------------------------------------------------

    The EPA believes this approach would ensure that GHG emissions 
limitations are implemented first at the subset of existing fossil 
fuel-fired combustion turbines that contributes the most to GHG 
emissions, and where the benefits of implementing GHG controls would be 
greatest.
    The EPA believes there are three sets of controls that could 
potentially qualify as the BSER for the group of large and frequently-
operated combustion turbines covered in the first rulemaking. Those 
controls are heat rate/efficiency improvements, co-firing low-GHG 
hydrogen, and use of CCS. We discuss each of these below, and in the 
course of each discussion explain why we are proposing that the 
following controls qualify as the BSER: co-firing with low-GHG hydrogen 
in the amounts of 30 percent (by volume) by 2032 and 96 percent (by 
volume) by 2038, and the use of CCS with 90 percent capture by 2035.
1. Heat-Rate Improvements
    The EPA believes that heat rate improvements for existing 
combustion turbines are broadly applicable today. Heat rate/efficiency 
improvements can be divided into two types. The first type involves 
smaller scale improvements to existing combustion turbines. The second 
type involves more comprehensive upgrades of the combustion turbines.
    Smaller scale efficiency improvements can include measures such as 
inlet fogging and inlet cooling. Both of these techniques can achieve 
about 2 percent improvements in heat rate. Inlet chilling costs 
approximately $19/kW and is also accompanied by a capacity increase of 
11 percent. Inlet fogging is approximately $0.93/kW and is accompanied 
by a capacity increase of 6 percent.\565\ These small-scale efficiency 
improvements would likely result in an average 2 percent improvement in 
the heat rate of affected existing combustion turbines.
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    \565\ https://www.andovertechnology.com/wp-content/uploads/2021/03/C_18_EDF_FINAL.pdf.
---------------------------------------------------------------------------

    More comprehensive efficiency upgrades to combustion turbines are 
also possible. An upgrade to the combustion turbine can result in a 
heat rate improvement of 3.0 percent and a capacity increase of 13 
percent for $172/kW, while an upgrade to the steam turbine can result 
in a heat rate improvement of 3.2 percent with a capacity increase of 3 
percent for $130/kW. These more comprehensive efficiency improvements 
would likely result in an average efficiency improvement of 6 percent 
for affected existing stationary combustion turbines. The EPA is not 
proposing HRI improvements for units greater than 300 MW because they 
achieve significantly less emission reductions than either CCS or co-
firing hydrogen, but believes that some units may choose to make these 
upgrades as part of their response to installing CCS and/or co-firing 
hydrogen. The EPA is taking comment on whether HRI should be considered 
BSER (or a component of BSER) for combined cycle units with a capacity 
factor of greater than 50 percent and a capacity of less than 300 MW as 
part of this initial rulemaking.
2. Co-Firing Low-GHG Hydrogen
a. Overview
    The EPA is proposing that for existing combined cycle combustion 
turbines that operate at capacity factors of greater than 50 percent 
and that are greater than 300 MW, co-firing 30 percent low-GHG hydrogen 
by 2032 and 96 percent by 2038 qualifies as the BSER, for largely the 
same reasons that apply to new combined cycle turbines, as discussed in 
section VII.F.3.c.vii of this preamble. Co-firing hydrogen at these 
levels is adequately demonstrated, as indicated by announced plans of 
manufacturers and generators to undertake retrofit projects for 
hydrogen co-firing. These plans also indicate that the costs of 
retrofitting are reasonable. The analysis concerning the costs of low-
GHG hydrogen for existing turbines is comparable to the analysis for 
new turbines. See section VII.F.3.c.vii.(B) of this preamble. Co-firing 
with low-GHG hydrogen at existing turbines also has comparable non-air 
quality environmental impacts and energy requirements, and comparable 
emissions reductions as co-firing with low-GHG hydrogen at new 
turbines. See sections VII.F.3.c.vii.(C)-(D) of this preamble. For 
these reasons, the EPA is proposing that co-firing with low-GHG 
hydrogen qualifies as the BSER. The fact that doing so will also 
advance the development and deployment of this low-emitting technology 
further supports this proposal.
b. Adequately Demonstrated
    Co-firing with low-GHG hydrogen is feasible in combustion turbines 
that are currently being produced. Manufacturers have developed 
retrofits to allow existing combustion turbines to combust up to 100 
percent hydrogen, and some companies have announced plans to retrofit 
their existing turbines to combust hydrogen. In section VII.F.3.c of 
this preamble, the EPA proposes co-firing of low-GHG hydrogen as BSER 
for certain new base load combustion turbines. A number of the examples 
that the EPA cites as evidence that companies are developing combined 
cycle turbines to co-fire hydrogen either are existing turbines that 
companies are planning to retrofit to burn hydrogen or are already 
under construction, and would, therefore, be classified as existing 
turbines under this rule. Because new combined cycle turbines that 
operate at capacity factors of greater than 50 percent are similar to 
existing combined cycle turbines that operate at capacity factors of 
greater than 50 percent, the EPA is proposing a similar BSER pathway 
for existing combustion turbines, based upon co-firing 30 percent (by 
volume) low-GHG hydrogen in 2032 and ramping up thereafter to 96 
percent (by volume) low-GHG hydrogen in 2038.
    There are two key questions related to whether co-firing low-GHG 
hydrogen in existing combustion turbines is

[[Page 33364]]

adequately demonstrated. The first question is whether existing 
combustion turbines are capable of co-firing significant amounts of 
hydrogen and/or if they can be retrofitted to do so. The second 
question is whether there will be an adequate supply of low-GHG 
hydrogen. These points are discussed below.
i. Capability of Existing Turbines To Co-Fire Hydrogen
    There are at least three lines of evidence that demonstrate that 
co-firing low-GHG hydrogen in existing turbines is possible today (with 
a number of them already able to fire 100 percent hydrogen) and that by 
approximately 2030, many additional turbine models will have the 
capability to co-fire 100 percent hydrogen. First, information from 
turbine vendors indicates that they already have significant experience 
in operating turbines with hydrogen; some of their existing turbine 
models can co-fire hydrogen; and/or they are currently engaged in 
projects to upgrade existing turbines to co-fire hydrogen. Second, test 
burns have been completed on several existing utility turbines. Third, 
several utilities have indicated plans to retrofit existing turbines to 
co-fire hydrogen.
    Existing turbine vendors including GE, Mitsubishi, and Siemens have 
indicated that their turbines can currently co-fire some amounts of 
hydrogen; and, they have plans to expand those capabilities. GE has 
indicated that most of their product line can currently be configured 
to co-fire significant amounts of hydrogen.\566\ Siemens is currently 
offering retrofit packages for many of its existing turbines that will 
allow them to combust up to 75 percent hydrogen.\567\ Mitsubishi also 
offers retrofit packages that could allow for up to 100 percent firing 
of hydrogen.\568\
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    \566\ https://www.ge.com/gas-power/future-of-energy/hydrogen-fueled-gas-turbines?utm_campaign=h2&utm_medium=cpc&utm_source=google&utm_content=eta&utm_term=Ge%20gas%20turbine%20hydrogen&gad=1&gclid=EAIaIQobChMIqMaL6IXG_gIVhsjjBx2gPgb-EAAYASAAEgK61PD_BwE and https://www.ge.com/content/dam/gepower-new/global/en_US/downloads/gas-new-site/future-of-energy/hydrogen-overview.pdf.
    \567\ https://assets.siemens-energy.com/siemens/assets/api/uuid:66b2b6a3-7cdc-404d-9ab0-ddcfbe4adf02/hydrogenflyer.pdf?ste_sid=81945e06dd4f27fd626614f9b954e3f4.
    \568\ https://solutions.mhi.com/clean-fuels/hydrogen-gas-turbine/.
---------------------------------------------------------------------------

    Section VII.F.3.c.vii(A) of this preamble includes discussion of 
how retrofitting existing turbines to co-fire with increasing amounts 
of hydrogen is adequately demonstrated. Several turbines currently in 
operation have the capability to co-fire hydrogen up to 30 percent 
without modifications. Other existing turbine models would need 
modifications to enable co-firing between 50 and 100 percent.
    Moreover, several existing combined cycle turbines have 
demonstrated the ability to co-fire some amounts of hydrogen. The Long 
Ridge Energy Terminal tested 5 percent hydrogen co-firing at the 485-MW 
combined cycle plant on a GE HA-class (GE 7HA.02) in 2022. The turbine 
is designed to enable a transition to 100 percent hydrogen fuel. This 
example is particularly salient given the large capacity of the unit. 
No modifications should be required for this turbine model, which has 
been available since 2017, to operate with between 5 and 20 percent 
hydrogen co-firing. Higher hydrogen co-firing concentrations will 
require some modification.\569\
---------------------------------------------------------------------------

    \569\ https://www.powermag.com/first-hydrogen-burn-at-long-ridge-ha-class-gas-turbine-marks-triumph-for-ge/.
---------------------------------------------------------------------------

    Southern Company has also demonstrated hydrogen co-firing on a 
Mitsubishi, M501G turbine. The demonstration involved co-firing 20 
percent hydrogen (by volume), was successful at both full and partial 
load, and demonstrated compliance with emissions requirements without 
impacting maintenance intervals.\570\ Other test burns have 
demonstrated the ability to fire up to 80 percent hydrogen without 
emissions excursions.\571\
---------------------------------------------------------------------------

    \570\ https://www.powermag.com/southern-co-gas-fired-demonstration-validates-20-hydrogen-fuel-blend/.
    \571\ https://www.ccj-online.com/real-world-experience-firing-hydrogen-natural-gas-mixtures/.
---------------------------------------------------------------------------

    Several utilities are exploring the use of hydrogen in their 
existing turbine fleet. For example, Constellation Energy, which owns a 
fleet of 23 gas-fired turbines with a combined total capacity of 8.6 
GW, asserts that retrofitting existing turbines to co-fire hydrogen is 
technically feasible with existing turbine models: ``Based on our 
assessments, retrofits using available technology can allow hydrogen 
blending at 50-100 percent by volume in select generators. These 
retrofits, which include burner and additional balance-of-plant 
modifications, allow for more substantial CO2 emissions 
reductions.'' \572\ Florida Power and Light (FPL) intends to convert 16 
GW of existing turbine capacity to run on 100 percent hydrogen by 
2045.\573\ They are currently developing a 25 MW electrolyzer project 
at the Cavendish Energy Center.\574\
---------------------------------------------------------------------------

    \572\ 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.
    \573\ https://cleanenergy.org/blog/nextera-sets-goal-to-decarbonize-proposes-big-transition-for-florida-power-light/.
    \574\ https://dailyenergyinsider.com/news/34040-florida-power-light-taps-cummins-for-its-green-hydrogen-facility/.
---------------------------------------------------------------------------

    One concern with hydrogen co-firing is that, because it burns at a 
higher temperature, it has the potential to generate more thermal NOx. 
The most commonly used NOX combustion control for base load 
combined cycle turbines is dry low NOX (DLN) combustion. 
Even though the ability to co-fire hydrogen in combustion turbines that 
are using DLN combustors to reduce emissions of NOX is 
currently more limited, all major combustion turbine manufacturers have 
developed DLN combustors for utility EGUs that can co-fire 
hydrogen.\575\ Moreover, the major combustion turbine manufacturers are 
designing combustion turbines that will be capable of combusting 100 
percent hydrogen by approximately 2030, with DLN designs that assure 
acceptable levels of NOX emissions.576 577
---------------------------------------------------------------------------

    \575\ Siemens Energy (2021). Overcoming technical challenges of 
hydrogen power plants for the energy transition. NS Energy. https://www.nsenergybusiness.com/news/overcoming-technical-challenges-of-hydrogen-power-plants-for-energy-transition/.
    \576\ Simon, F. (2021). GE eyes 100% hydrogen-fueled power 
plants by 2030. https://www.euractiv.com/section/energy/news/ge-eyes-100-hydrogen-fuelled-power-plants-by-2030/.
    \577\ Patel, S. (2020). Siemens' Roadmap to 100% Hydrogen Gas 
Turbines. https://www.powermag.com/siemens-roadmap-to-100-hydrogen-gas-turbines/.
---------------------------------------------------------------------------

ii. Availability of Low-GHG Hydrogen
    The EPA is proposing that the BSER for existing combustion turbines 
includes co-firing 30 percent (by volume) low-GHG hydrogen by 2032 and 
96 percent (by volume) by 2038. The EPA is proposing to define low-GHG 
hydrogen as hydrogen that is produced with overall carbon emissions of 
less than 0.45 kg CO2e/kgH2 from well-to-gate. Electrolytic 
hydrogen produced using zero-carbon emitting energy sources is the most 
likely, but not the only, form of hydrogen anticipated to meet this 
proposed definition.\578\
---------------------------------------------------------------------------

    \578\ DOE, Pathways to Commercial Liftoff: Clean Hydrogen (March 
2023).
---------------------------------------------------------------------------

    Suitable volumes of low-GHG hydrogen are expected to be produced by 
the 2032 and 2038 timeframes to satisfy the demand driven by this 
proposed rule. As referenced throughout this proposal, DOE's clean 
hydrogen production estimates are 10 MMT annually of clean hydrogen by 
2030, and 20 MMT annually by 2040. There is reason to believe actual 
produced

[[Page 33365]]

low-GHG hydrogen will exceed those levels. Announced clean hydrogen 
production projects total 12 MMT annually for 2030.\579\ In fact, 
hydrogen production could outpace DOE's projections if demand markets 
across sectors, including the power sector, grow rapidly and emerge 
simultaneously with cost declines across the value chain.\580\ Over 
time, the emergence of the self-sustaining low-GHG hydrogen markets are 
predicted to be established as demand for low-GHG solidifies and 
anchors the market, ensuring low-GHG production even after the PTC 
sunsets. Given the magnitude of the PTC for low-GHG hydrogen, $3/kg, 
electrolytic hydrogen production is expected to accelerate, accounting 
for between 70 and 95 percent of hydrogen production in 2030, and 
between 30 and 50 percent in 2040.\581\
---------------------------------------------------------------------------

    \579\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf. Figure 8 of the 
Liftoff Report represents compiled clean hydrogen projects with 
aggregated 2030 production exceeding 12 MMT annually.
    \580\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf. Figure 13 presents 
modeling of hydrogen production volumes under various scenarios, 
including projections of 20MMT in 2030, and 42 MMT in 2040 based on 
high end of ranges for end use demand which assumes additional ramp 
up in policy support for decarbonization--which is consistent with 
this proposal to reduce emissions from the power sector, as well as 
EPA's proposed Greenhouse Gas Emissions Standards for Heavy-Duty 
Vehicle.
    \581\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf. Figure 14 of the 
Liftoff report projects the split of hydrogen production in future 
years between electrolytic and SMR.
---------------------------------------------------------------------------

    Further, multiple utilities are pursuing projects to secure 
supplies of electrolyzer-based hydrogen for their power projects. As 
mentioned earlier in this proposal, Intermountain Power is working with 
partners to develop an integrated hydrogen turbine, a hydrogen 
production facility, and a hydrogen storage facility in Delta, Utah. 
All three components of the project are under construction and are 
scheduled to be operational by 2025, with the turbine combusting 30 
percent (by volume) low-GHG hydrogen at startup.\582\ FPL has announced 
plans to build 30 GW of excess solar to supply clean hydrogen 
production to power its turbines and to sell to other customers.\583\ 
Entergy has entered into multiple agreements to explore the use of 
existing and new renewable generating assets and transmission to supply 
zero GHG electricity to developers of hydrogen production plants.\584\ 
Multiple US utilities are collaborating to develop hydrogen hubs.\585\
---------------------------------------------------------------------------

    \582\ https://www.ipautah.com/ipp-renewed/.
    \583\ https://cleanenergy.org/blog/nextera-sets-goal-to-decarbonize-proposes-big-transition-for-florida-power-light/.
    \584\ https://www.entergynewsroom.com/news/entergy-texas-new-fortress-energy-partner-advance-hydrogen-economy-in-southeast-texas/ 
and https://www.entergynewsroom.com/news/entergy-texas-monarch-energy-collaborate-advance-southeast-texas-energy-infrastructure-1323187465/.
    \585\ https://news.duke-energy.com/releases/major-southeast-utilities-establish-hydrogen-hub-coalition.
---------------------------------------------------------------------------

c. Costs
    The fact that existing sources are already planning to combust low-
GHG hydrogen, even in the absence of a regulatory requirement, is an 
indication that the costs of co-firing are reasonable.
    The EPA has also developed a more specific description of the 
costs, which follows. It incorporates some components of the analysis 
of costs of co-firing low-GHG hydrogen for new turbines, as discussed 
in section VII.F.3.c.vii(B) of this preamble.
    There are three sets of potential costs associated with 
retrofitting combustion turbines to co-fire hydrogen: (1) Capital costs 
of retrofitting combustion turbines to have the capability of co-firing 
hydrogen; (2) pipeline infrastructure to deliver hydrogen; and (3) the 
fuel costs related to production of low-GHG hydrogen. While many 
combustion turbines are able to fire lower volume blends of hydrogen 
with natural gas, not all have the capacity or on-site infrastructure 
necessary to blend higher volumes of hydrogen. The primary costs that 
combustion turbines would incur would be the fuel costs for low-GHG 
hydrogen, along with limited capital retrofit costs, in order to co-
fire hydrogen at the 30 percent and 96 percent levels that the EPA is 
proposing as the BSER.
    One company, Constellation Energy Corporation, has estimated the 
costs to retrofit existing plants to co-fire hydrogen and has indicated 
that they are reasonable: ``We expect $10-$60/kW in retrofit costs to 
achieve 30-60% hydrogen blending by volume at our power plants. At 
blend levels in the range of 60-100%, OEMs have suggested pricing of 
roughly $100/kW.'' \586\ The EPA estimates that if low-GHG hydrogen is 
available at a delivered price of $1/kg,\587\ co-firing 30 percent 
hydrogen in a combined cycle EGU operating at a capacity factor of 65 
percent would increase the levelized cost of electricity (LCOE) by 
$2.9/MWh and a 96 percent co-firing rate would increase the LCOE by 
$21/MWh.\588\ Regardless of the level of hydrogen co-firing, the 
CO2 abatement cost is $64/ton ($70/metric ton) at the 
affected facility.\589\ For an aeroderivative simple cycle combustion 
turbine operating at a capacity factor of 40 percent, the EPA estimates 
co-firing 30 percent low-GHG hydrogen would increase the LCOE by $4.1/
MWh, and a 96 percent co-firing rate would increase the LCOE by $30/
MWh. At a delivered price of $0.75/kg, the CO2 abatement 
costs for co-firing hydrogen would be $32/ton ($35/metric ton). For a 
combined cycle EGU, the EPA estimates the LCOE increase would be $1.4/
MWh and $11/MWh for the 30 percent and 96 percent cases, respectively. 
For a simple cycle EGU, the EPA estimates the LCOE increase would be 
$2.1/MWh and $15/MWh for the 30 percent and 96 percent cases, 
respectively.
---------------------------------------------------------------------------

    \586\ 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, June 6, 2022).
    \587\ The delivered price includes the purchase cost of the fuel 
and its transportation costs and the 45V tax credit.
    \588\ The EIA long-term natural gas price for utilities is 
$3.69/MMBtu.
    \589\ The abatement cost of co-firing low-GHG hydrogen is 
determined by the relative delivered cost of the low-GHG hydrogen 
and natural gas.
---------------------------------------------------------------------------

    The EPA is soliciting comment on what additional costs would be 
required to ensure that combustion turbines are able to co-fire between 
30 to 96 percent low-GHG hydrogen and if there are efficiency impacts 
from co-firing hydrogen. Retrofits to add the capacity to combust 
higher volumes of hydrogen could include retrofitting the combustor, 
increasing the size of the fuel piping, and upgrades to minimize fuel 
leakage, hydrogen storage and blending equipment, upgraded control 
systems, modification to the continuous emissions monitoring system, 
safety upgrades and leakage detectors, modification of the HRSG to 
accept higher temperature exhaust, and NOX control 
modifications (e.g., upgraded premix combustion technologies).\590\ 
According to model plant estimates in EPRI's US-REGEN model, the heat 
rate of a hydrogen-fired combustion turbine is 5 percent higher than a 
comparable natural gas-fired combustion turbine. Furthermore, for 
hydrogen-fired combustion turbines relative to a comparable natural 
gas-fired combustion turbine, the capital costs are

[[Page 33366]]

approximately $70/kW higher, the fixed operating costs are 
approximately $1/year per kW higher, and the non-fuel variable 
operating costs are approximately $0.5/MWh higher.\591\ While these 
costs are for new combustion turbines, the amounts could be higher for 
retrofits to combustion turbines. To the extent it is appropriate to 
account for additional costs associated with a hydrogen co-firing BSER 
for existing combustion turbines, the EPA is soliciting comment on 
whether capital and fixed costs should be increased by 9 percent, 
consistent with the NETL estimated retrofit costs of CCS relative to 
new combustion turbines.
---------------------------------------------------------------------------

    \590\ Simon, Nima, Retrofitting Gas Turbine Facilities for 
Hydrogen Blending. November 2, 2022. https://www.icf.com/insights/energy/retrofitting-gas-turbines-hydrogen-blending.
    \591\ https://us-regen-docs.epri.com/v2021a/assumptions/electricity-generation.html#new-generation-capacity.
---------------------------------------------------------------------------

    The EPA is proposing to determine that the increase in operating 
costs from a BSER based on low-GHG hydrogen is reasonable.
d. Non-Air Quality Health and Environmental Impact and Energy 
Requirements
    The co-firing of hydrogen in combustion turbines in the amounts 
that the EPA proposes as the BSER would not have adverse non-air 
quality health and environmental impacts. It would potentially result 
in increased production of NOX, but those NOX 
emissions can be controlled, as described in sections VII.F.3.c.vii.(A) 
and XI.C.2.b.i of this preamble.
    In addition, co-firing hydrogen in the amounts proposed would not 
have adverse impacts on energy requirements, including either the 
requirements of the combustion turbines to obtain fuel or on the energy 
sector more broadly, particularly with respect to reliability. As 
discussed in sections VII.F.3.c.vii.(A)-(B) and XI.C.2.b.-c. of this 
preamble, combustion turbines can be constructed to co-fire high 
volumes of hydrogen in lieu of natural gas, and the EPA expects that 
low-GHG hydrogen will be available in sufficient quantities and at 
reasonable cost. Any impact on the energy sector would be further 
mitigated by the large amounts of existing generation that would not be 
subject to requirements in this rule and the projected new capacity in 
the base case modeling.
e. Extent of Reductions in CO2 Emissions
    The site-specific reduction in CO2 emissions achieved by 
a combustion turbine co-firing hydrogen is dependent on the volume of 
hydrogen blended into the fuel system. Due to the lower energy density 
by volume of hydrogen compared to natural gas, an affected source that 
combusts 30 percent by volume hydrogen with natural gas would achieve 
approximately a 12 percent reduction in CO2 emissions versus 
firing 100 percent natural gas.\592\ A source combusting 100 percent 
hydrogen would have zero CO2 stack emissions because 
hydrogen contains no carbon, as previously discussed. A source co-
firing 96 percent by volume hydrogen (approximately 89 percent by heat 
input) would achieve an approximate 90 percent CO2 emission 
reduction, which is roughly equivalent to the emission reduction 
achieved by sources utilizing 90 percent CCS.
---------------------------------------------------------------------------

    \592\ The energy density by volume of hydrogen is lower than 
natural gas.
---------------------------------------------------------------------------

f. Promotion of the Development and Implementation of Technology
    Determining co-firing 30 percent (by volume) low-GHG hydrogen by 
2032 and co-firing 96 percent (by volume) to be components of the BSER 
would generally advance technology development in both the production 
of low-GHG hydrogen and the use of hydrogen in combustion turbines, for 
the same reasons discussed with respect to new combustion turbines in 
section VII.F.3.c.vii.(E) of this preamble.
g. Summary
    The EPA proposes that co-firing 30 percent low-GHG hydrogen by 2032 
and 96 percent by 2038 qualify as a BSER pathway for large and 
frequently-used existing combustion turbines. For the reasons discussed 
above, the EPA proposes that co-firing low-GHG hydrogen on that pathway 
is adequately demonstrated in light of the capability of combustion 
turbines to co-fire hydrogen and the EPA's reasonable expectation that 
adequate quantities of low-GHG hydrogen will be available by 2032 and 
2038 and at reasonable cost. Moreover, combusting hydrogen will achieve 
reductions because it does not produce GHG emissions and will not have 
adverse non-air quality health or environmental impacts or energy 
requirements, including on the nationwide energy sector. Primarily 
because the production of low-GHG hydrogen generates the fewest GHG 
emissions, the EPA proposes that co-firing low-GHG hydrogen, and not 
other types of hydrogen, qualify as the ``best'' system of emission 
reduction. See section VII.F.3.c.vii(F) of this preamble. The fact that 
co-firing low GHG hydrogen creates market demand for, and advances the 
development of, low-GHG hydrogen, a fuel that is useful for reducing 
emissions in the power sector and other industries, provides further 
support for this proposal.
    Similar to new base load combined cycle turbines, the EPA is also 
taking comment on an alternative approach in which the BSER for these 
units would be based on CCS with 90 percent capture, for the reasons 
discussed next, but units could follow a pathway that would enable them 
to achieve the same reductions using low-GHG hydrogen.
3. CCS
a. Overview
    The EPA believes that CCS is an effective mitigation measure for 
existing combustion turbines and that it would be most cost-effective 
for units that are frequently operating. As discussed in section 
VII.F.3.b.iii.(A) of this preamble, multiple companies are considering 
adding CCS to existing fossil fuel-fired power plants and multiple 
companies have performed FEED studies evaluating the feasibility of 
installing CCS on an existing combined cycle unit. As also discussed 
there, CO2 pipelines are available and their network is 
expanding in the U.S., the safety of existing and new supercritical 
CO2 pipelines is comprehensively regulated by PHMSA, and 
areas without reasonable access to pipelines for geologic sequestration 
can transport CO2 to sequestration sites via other 
transportation modes. As also discussed there, geologic sequestration 
of CO2 is well proven, broadly available throughout the 
U.S., and there is a detailed set of regulatory requirements to ensure 
the security of sequestered CO2. For these reasons, the EPA 
proposes that CCS with 90 percent capture is adequately demonstrated 
for existing combustion turbines.
    The EPA further proposes that CCS is cost-reasonable for existing 
turbines that are greater than 300 MW and operate at greater than 50 
percent capacity. The EPA believes that many existing combined cycle 
units are likely to be able to install and operate CCS within the costs 
that the EPA found to be reasonable for new stationary combustion 
turbines and existing coal-fired steam generating units. Certain parts 
of the cost calculation should be much the same as for new sources, 
including the costs for transportation and sequestration as well as the 
availability of the IRC section 45Q tax credit, although the costs for 
retrofitting capture equipment may in some cases be higher. See section 
VII.F.3.b.iii.(B) of this preamble. NETL estimates that the capital 
cost of CCS retrofits on combined cycle EGUs is 9 percent

[[Page 33367]]

higher than for new combined cycle EGUs.\593\ The additional capital 
costs increase the LCOE of the retrofit CCS by an additional $1.5/MWh 
compared to an installation at a new combined cycle EGU, which is 
consistent with control costs that EPA has found to be reasonable in 
other rulemakings, as noted in section VII.F.3.b.iii.(B)(5).
---------------------------------------------------------------------------

    \593\ Tommy Schmitt, Sally Homsy, National Energy Technology 
Laboratory, Cost and Performance of Retrofitting NGCC Units for 
Carbon Capture--Revision 3, March 17, 2023 (DOE/NETL-2023/3848).
---------------------------------------------------------------------------

    The ability to cost-effectively apply CCS was a significant 
consideration in the EPA's selection of proposed capacity and 
utilization thresholds to determine which existing turbines would be 
covered by these proposed emission guidelines. The EPA considered two 
primary factors in evaluating an appropriate capacity threshold. The 
first is emission reduction potential. As the capacity threshold 
decreases a larger amount of the existing fleet is covered and overall 
emission reduction potential increases. For instance, at a 500 MW 
threshold, only 2 percent of the capacity and 7 percent of the 
emissions are covered. The second factor the EPA considered was 
capacity to build CCS. In 2030, the EPA projects that approximately 12 
GW of coal-fired generation will likely install CCS (including both CCS 
being installed to meet requirements of this rule and CCS that EPA 
projects would occur even without the requirements proposed here). 
There are likely to also be a number of other CCS projects for other 
industries developed in the 2023 through 2030 timeframe. Multiple 
industries including the ethanol industry and the hydrogen production 
sector have announced post combustion CCS projects in response to the 
IRA.
    The EPA believes it is reasonable to assume therefore that by 2035 
there will be a larger capability to build CCS retrofits than in 2030. 
Had the EPA proposed capacity thresholds of 400 MW or 500 MW, they 
would have only resulted in the need for a maximum of 12 GW or 6 GW of 
CCS capacity respectively by 2035 for existing gas turbines covered by 
this proposal, which is less than the CCS capacity the EPA projects in 
2030 to meet the existing coal BSER. That would likely mean foregoing 
feasible, cost-effective emissions reductions. By contrast, the 300 MW 
cutpoint that EPA is proposing would require up to 37 GW of CCS in 
2035. While this is approximately 3 times the amount of CCS that the 
EPA is projecting for coal-fired units in 2030, the EPA believes that 
300 MW is a reasonable threshold primarily because there will be 
significant time to deploy the needed infrastructure, a total of eleven 
years from the likely finalization of these guidelines. In addition, it 
is unlikely that all of the units that EPA projects would be affected 
in 2035 would choose to install CCS; some would likely choose to co-
fire low-GHG hydrogen.\594\ For these reasons, the EPA believes that 
there will be adequate capability to build enough CCS for the existing 
combustion turbine EGUs subject to a CCS BSER at a capacity threshold 
of 300 MW, given the amount of time provided.
---------------------------------------------------------------------------

    \594\ Approximately 6 GW of the capacity projected to operate at 
a capacity factor of greater than 50 percent in the EPA's modeling 
is owned by NextERA who has already announced intentions to convert 
much of their combined cycle turbines to co-fire increasing amounts 
of hydrogen.
---------------------------------------------------------------------------

    The EPA also considered a capacity threshold of 200 MW and of 100 
MW. According to the EPA's projections, a threshold of 200 MW would 
affect a total of 85 GW, and a threshold of 100 MW would affect 134 GW 
of existing combustion turbine capacity. While the EPA believes that it 
is possible that the industry could install that amount of CCS on this 
timeline, the EPA believes it is important to gather more information 
on the question of how quickly CCS can be deployed and is therefore 
taking comment on, but not proposing, a lower capacity threshold of 200 
MW or 100 MW, and taking comment on whether it would be feasible to 
install CCS and or co-fire hydrogen for the 85 GW or 134 GW of units it 
projects would be covered under those thresholds and a capacity factor 
of greater than 50 percent.
    Historical rates of emission control technology retrofits at 
existing coal-fired power plants, such as flue gas desulfurization 
(FGD), indicate that rapid deployments of such technologies in response 
to regulatory requirements have proven feasible historically in the 
United States and elsewhere. FGD was rapidly deployed in the United 
States in response to various regulatory requirements, including the 
1971 NSPS addressing SO2 emissions. Although other 
compliance options were available, FGD--a wholly new technology--was 
installed on 48 GW of coal-fired power plants between 1973 and 
1984,\595\ while the number of technology vendors went from 1 to 
16.\596\ Similarly, Germany subsequently increased its share of FGD 
from 10 to 79 percent in four years.597 598 It should be 
noted that as FGD became a more familiar technology, installation rates 
accelerated, reaching nearly 30 GW a year in the United States.\599\ A 
very rapid ramp up happened after the Clean Air Interstate Rule, for 
example, where the installed capacity increased from 131 GW in 2007 to 
200 GW in under four years.\600\ There are many differences between FGD 
and CCS, but the history of the rapid build-out of FGD generally 
supports the EPA's view that companies with the expertise to install 
complex emission control equipment can rapidly ramp up capacity in 
response to a regulatory driver.
---------------------------------------------------------------------------

    \595\ Van Ewijk, S., McDowall, W. Diffusion of flue gas 
desulfurization reveals barriers and opportunities for carbon 
capture and storage. Nat Commun 11, 4298, Figure 1 and Source Data 
(2020), available at https://doi.org/10.1038/s41467-020-18107-2.
    \596\ Taylor, et al., Regulation as Mother of Innovation, 27 Law 
& Pol'y 348, 356 (2005).
    \597\ Van Ewijk, S., McDowall, W. Diffusion of flue gas 
desulfurization reveals barriers and opportunities for carbon 
capture and storage. Nat Commun 11, 4298 (2020). https://doi.org/10.1038/s41467-020-18107-2.
    \598\ Similarly, in response to regulatory requirements over 100 
GW of coal-fired generation installed selective catalytic reduction 
(SCR) between 1999 and 2009, ramping from very low levels. Healey, 
Scaling and Cost Dynamics of Pollution Control Technologies, at 7, 
Figure 3 (2013). https://core.ac.uk/download/pdf/44737055.pdf.
    \599\ Markussan, Scaling up and Deployment of FGD in the US 
(CCS--Releasing the Potential) (2012) at v, 24.
    \600\ Electric Power Annual 2015, https://www.eia.gov/electricity/annual/archive/pdf/03482015.pdf.
---------------------------------------------------------------------------

    The EPA seeks comment on the feasibility of setting a threshold of 
100 or 200 MW and a 40 percent capacity factor in light of these 
examples and other relevant considerations. As further described below, 
the EPA further proposes that CCS with 90 percent capture for existing 
combustion turbines greater than 300 MW and operating at more than 50 
percent capacity meets the other criteria to qualify as the BSER, for 
the same reasons as it does for new combustion turbines in the baseload 
subcategory:
b. Adequately Demonstrated
    Section VII.F.3.b of this preamble includes discussion of how CCS 
with a 90 percent capture rate has been adequately demonstrated and is 
technically feasible based on the demonstration of the technology at 
existing coal-fired steam generating units and industrial sources in 
addition to combustion turbines. Notably, the function, design, and 
operation of post-combustion CO2 capture equipment is 
similar, although not identical, for both steam generating units and 
combustion turbines. As a result, application of CO2 capture 
at existing coal-fired steam generating units helps show that it is 
adequately demonstrated for combustion turbines as well.

[[Page 33368]]

    In the retrofit context, SaskPower's Boundary Dam Unit 3, a 110 MW 
lignite-fired unit in Saskatchewan, Canada, has demonstrated 
CO2 capture rates of 90 percent using an amine-based post-
combustion capture system retrofitted to the existing steam generating 
unit. The capture plant, which began operation in 2014, was the first 
full-scale CO2 capture system retrofit on an existing coal-
fired power plant.\601\ Other references detailed in section 
VII.F.3.b.iii.(A).(2) provide additional support for the demonstration 
of CO2 capture retrofits.
---------------------------------------------------------------------------

    \601\ Giannaris, S., et al., Proceedings of the 15th 
International Conference on Greenhouse Gas Control Technologies 
(March 15-18, 2021). SaskPower's Boundary Dam Unit 3 Carbon Capture 
Facility--The Journey to Achieving Reliability. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191.
---------------------------------------------------------------------------

    Moreover, section VII.F.3.b.iii.(A)(3) of this preamble describes 
how CCS has been successfully applied to a combined cycle EGU (the 
Bellingham Energy Center in south central Massachusetts) and how 
several other projects are in development. Both section 
VII.F.3.b.iii.(A)(3) of this preamble and the TSD on GHG Mitigation 
Measures--Carbon Capture and Storage for Combustion Turbines discuss 
several CCS projects under development involving retrofits to existing 
NGCC units.
    In addition to CO2 capture, the CO2 transport 
and geologic storage aspects of CCS systems are also adequately 
demonstrated, as discussed in section VII.F.3.b and section X.D.1.a of 
this preamble and in the GHG Mitigation Measures for Steam Generating 
Units TSD. Geologic sequestration potential for CO2 is 
widespread and available throughout the U.S. Nearly every State in the 
U.S. has or is in close proximity to formations with geologic 
sequestration potential, including areas offshore. These areas include 
deep saline formation, unmineable coal seams, and oil and gas 
reservoirs. Additionally, the U.S. CO2 pipeline network has 
steadily expanded (with 5,339 miles in operation in 2021, a 13 percent 
increase in CO2 pipeline miles since 2011), and appears 
primed to continue expanding, with several major projects recently 
announced across the country. Areas without reasonable access to 
pipelines for geologic sequestration can transport CO2 to 
sequestration sites via other transportation modes such as ship, road 
tanker, or rail tank cars.
c. Costs
    The EPA is proposing that the costs of CCS are reasonable for 
existing combustion turbines that are large and frequently used. As 
further discussed in the Regulatory Impact Analysis and the GHG 
Mitigation Measures--Carbon Capture and Storage for Combustion Turbines 
TSD, the EPA's approach relies on cost and performance assumptions 
consistent with the IPM post-IRA 2022 reference case.\602\ The EPA's 
baseline shows that 7 GW of existing natural gas combined cycle 
capacity retrofits with CCS in 2030, rising to 10 GW in 2035. The 
significant deployment of CCS on combined cycle natural gas EGUs in the 
absence of emission standards reinforces the cost reasonableness and 
feasibility of the proposed standards.
---------------------------------------------------------------------------

    \602\ These assumptions are detailed at: https://www.epa.gov/system/files/documents/2023-03/Chapter%206%20-%20CO2%20Capture%2C%20Storage%2C%20and%20Transport.pdf.
_____________________________________-

    Section VII.F.3.b.iii.(B) and section X.D.1.a.ii of this preamble 
discuss the cost-reasonableness of CCS technology in the context of new 
combustion turbines and existing coal-fired steam generating units. 
Additionally, a March 2023 NETL report estimates that the capital cost 
of CCS retrofits on combined cycle EGUs is 9 percent higher than for 
installation of CCS equipment on new greenfield combined cycle 
EGUs.\603\ The higher retrofit costs account for the cost premium for 
design, construction, and tie-in constraints imposed by existing plant 
layout and operation. The additional capital costs increase the LCOE of 
the retrofit CCS by an additional $2.2/MWh compared to an installation 
at a new combined cycle EGU.\604\ Assuming the same model plant, a 90 
percent-capture retrofit amine-based post combustion CCS system 
increases the LCOE by $8.6/MWh and has overall CO2 abatement 
costs of $26/ton ($28/metric ton). Similar to NETL estimates for 
greenfield CCS projects, costs at a specific plant would be expected to 
vary somewhat from this estimate, as it does not include site and 
plant-specific considerations such as seismic conditions, local labor 
costs, or local environmental regulations.
---------------------------------------------------------------------------

    \603\ Cost and Performance of Retrofitting NGCC Units for Carbon 
Capture--Revision 3 (DOE/NETL-2023/3848, March 17, 2023). https://www.netl.doe.gov/projects/files/CostandPerformanceofRetrofittingNGCCUnitsforCarbonCaptureRevision3_031723.pdf.
    \604\ These calculations use the NETL F-Class turbine, a service 
life of 12 years, an interest rate of 7.0 percent, a natural gas 
price of $3.69/MMBtu, a capacity factor of 75 percent, a transport, 
storage, and monitoring cost of $10/metric ton, and a 45Q tax credit 
of $85/metric ton.
---------------------------------------------------------------------------

d. Non-Air Quality Health and Environmental Impact and Energy 
Requirements
    As in the context of new NGCC units and existing coal-fired steam 
generating units (discussed in section VII.F.3.b.iii.(C) and section 
X.D.1.a.iii of this preamble), the EPA does not expect the use of CCS 
at large, frequently used existing combustion turbines to have 
unreasonable adverse consequences related to non-air quality health and 
environmental impact or to energy requirements.
    Regarding energy requirements, upon retrofitting an NGCC plant with 
CCS, a derate in the net plant electrical output will be incurred due 
to the parasitic/auxiliary energy demand required to run the CCS 
system, as well as steam extraction from the steam cycle to satisfy the 
CCS reboiler duty.\605\ As discussed in the TSD on GHG Mitigation 
Measures--Carbon Capture and Storage for Combustion Turbines, a recent 
NETL report has estimated that the resulting derates for 90 percent 
CO2 capture retrofits range from an 11.5 to 11.8 percent 
loss of net MWe.
---------------------------------------------------------------------------

    \605\ Cost and Performance of Retrofitting NGCC Units for Carbon 
Capture--Revision 3. (DOE/NETL--2023/3848, March 17, 2023). https://www.osti.gov/biblio/1961845.
---------------------------------------------------------------------------

    Despite decreases in efficiency, IRC section 45Q tax credits 
provide an incentive for increased generation with full operation of 
CCS because the credits are proportional to the amount of captured and 
sequestered CO2 emissions and not to the amount of 
electricity generated. The EPA is proposing that the energy penalty is 
relatively minor compared to the GHG benefits of CCS. The EPA does not 
believe that determining CCS to be BSER for large, frequently operated 
combustion turbines will cause reliability concerns. This is because of 
the limited increase in costs and energy penalty due to CCS, coupled 
with the amounts of smaller or lower capacity generation that would not 
be subject to these requirements and the projected new capacity in the 
base case modeling. For the estimated 37 GW of facilities that would 
face requirements under this proposal, if they all installed CCS 
retrofit the reduction in available capacity would be approximately 4.3 
GW, or less than 1% of the total modeled available natural gas capacity 
in 2035. Grid planners, operators, and market participants can address 
the potential, marginal impact, through development of a similarly 
small increment of accredited capacity, whether from new natural gas 
simple cycle turbine

[[Page 33369]]

deployment, new energy storage, or new sources of clean energy.
    Regarding non-air quality health and environmental impact, criteria 
or hazardous air pollutant emissions would in general be mitigated or 
adequately controlled by equipment needed to meet other CAA 
requirements, and the EPA's assessment is that the additional cooling 
water requirements from CCS at NGCC units are reasonable, as discussed 
in section VII.F.3.v.iii.(C). The EPA is committed to working with its 
fellow agencies to foster meaningful engagement with communities and 
protect communities from pollution. 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 
technological deployment process. CCS projects undertaken pursuant to 
these emission guidelines will, if the EPA finalizes proposed revisions 
to the CAA section 111 implementing regulations,\606\ be subject to 
requirements for meaningful engagement as part of the State plan 
development process. See section XII.F.1.b of this preamble for 
additional details.
---------------------------------------------------------------------------

    \606\ 87 FR 79176, 79190-92 (December 23, 2022).
---------------------------------------------------------------------------

e. Extent of Reductions in CO2 Emissions
    Designating CCS with 90 percent capture as a component of the BSER 
for large and frequently-operated combustion turbines prevents large 
amounts of CO2 emissions. According to the NETL baseline 
report, adding a 90 percent CO2 capture system increases the 
EGU's gross heat rate by 7 percent and the unit's net heat rate by 13 
percent. Since more fuel would be consumed in the CCS case, the gross 
and net emissions rates are reduced by 89.3 percent and 88.7 percent 
respectively.
f. Promotion of the Development and Implementation of Technology
    The EPA also considered whether determining CCS to be a component 
of the BSER for existing large and frequently operated combustion 
turbines will advance the technological development of CCS and 
concluded that this factor supports our BSER determination. Combined 
with the availability of 45Q tax credits and investments in supporting 
CCS infrastructure from the IIJA, this requirement should incentivize 
additional use of CCS, which should, in turn, incentivize cost 
reductions through the development and use of better performing 
solvents or sorbents. While solvent-based CO2 capture has 
been adequately demonstrated at the commercial scale, a determination 
of the BSER for certain existing combustion turbines (along with new 
baseload combustion turbines and long term coal-fired steam generating 
units) is the use of CCS will also likely incentivize the deployment of 
alternative CO2 capture techniques at scale. Moreover, as 
noted above, the cost of CCS has fallen in recent years and is expected 
to continue to fall; and further implementation of the technology can 
be expected to lead to additional cost reductions, due to added 
experience and cost efficiencies through scaling.
    The EPA seeks comment on the feasibility of setting a threshold for 
inclusion in the existing combustion turbine segment to be addressed by 
the emission guidelines proposed here of 100 or 200 MW and a 40 percent 
capacity factor in light of the examples of other historic deployment 
of pollution controls and other relevant considerations. DOE recently 
released a report discussing the State of carbon management 
technology.\607\ In that report, DOE states that with policy support 
(either via regulation or incentives) or technology premiums for low-
carbon products (e.g., low embodied carbon steel and concrete) the 
scale up of CCS technologies and pipeline and storage infrastructure 
would proceed much faster for the power sector than will proceed absent 
additional policy support or market demand.\608\ In the report, DOE 
states that regulatory developments, in particular, could play a 
dramatic role in accelerating the pathways described for industries 
with lower-purity CO2 streams such as power plants. The 
report states that absent additional incentives, CCS technology for the 
power sector is likely to significantly scale between 2030-2040 with 
pilot and demonstration technologies occurring now. As detailed in the 
report, several incentives have recently become available or been 
significantly increased that will accelerate the deployment of CCS for 
the power sector. The 45Q tax credit for CCS is a strong incentive, and 
DOE is already investing heavily through the Bipartisan Infrastructure 
Law at further demonstrating lower-purity CCS technologies such as 
those used in the power sector, which will help to decrease costs and 
establish repeatable commercial arrangements.
---------------------------------------------------------------------------

    \607\ DOE Carbon Management Demonstration and Deployment 
Pathway, April 2023, https://liftoff.energy.gov/
    \608\ The Federal Buy Clean Task Force and the First Mover's 
Coalition are both seeking to provide a clear demand signal for low 
embodied emissions products.
---------------------------------------------------------------------------

    As the DOE report discusses, CO2 pipelines also need to 
be further built out for CCS technologies to scale. CO2 
pipelines are the most mature, and often the most cost-effective 
CO2 transport technology for high volumes and will likely 
form the backbone of CO2 transport. PHMSA reported that 
5,339 miles of CO2 pipelines were in operation in 2021.\609\ 
Analogous historical build out of inter- and intrastate natural gas 
transmission pipelines demonstrates that similar levels of 
CO2 pipeline deployment are feasible. Data reported by EIA 
indicates that from 1997 to 2008 over 25,000 miles of natural gas 
transmission pipeline was constructed, averaging over 2,000 miles per 
year.\610\ Other analyses indicate that the size of CO2 
pipeline network necessary to capture over 1,000 million metric tons 
per year of CO2 emissions from large, frequently operated 
coal and natural gas EGUs ranges from 20,000 miles to 25,000 
miles.\611\ This is in line with the historical maximum deployment of 
natural gas transmission pipelines, and also does not account for any 
economies of scale from pipeline systems developed for capture from 
other non-power CO2 sources.
---------------------------------------------------------------------------

    \609\ U.S. Department of Transportation, Pipeline and Hazardous 
Material Safety Administration, ``Hazardous Annual Liquid Data.'' 
2021. https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
    \610\ https://www.eia.gov/naturalgas/pipelines/EIA-NaturalGasPipelineProjects.xlsx.
    \611\ Middleton, Richard and Bennett, Jeffrey and Ellett, Kevin 
and Ford, Michael and Johnson, Peter and Middleton, Erin and Ogland-
Hand, Jonathan and Talsma, Carl, Reaching Zero: Pathways to 
Decarbonize the US Electricity System with CCS (August 30, 2022). 
Proceedings of the 16th Greenhouse Gas Control Technologies 
Conference (GHGT-16) 23-24 Oct 2022. https://ssrn.com/abstract=4274085 or http://dx.doi.org/10.2139/ssrn.4274085.
---------------------------------------------------------------------------

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

    The EPA is seeking comment on four general areas related to 
selecting the BSER for existing combustion turbines. First, the EPA is 
soliciting comment on general assumptions about potential future 
utilization of combustion turbines. Second, the EPA is soliciting 
comment on assumptions about the appropriate group of existing 
combustion turbine units to be addressed in this rulemaking. Third, the 
EPA is requesting comment on the appropriate BSER for those turbines. 
Fourth, the EPA is requesting comment

[[Page 33370]]

on the timing of BSER requirements for existing combustion turbines.
    The EPA is seeking comment on a number of issues related to how its 
consideration of projected future utilization of combined cycles 
informed its consideration of a potential BSER for existing combustion 
turbines. First, the EPA is taking comment on its projections of how 
combustion turbines will operate in the future and the key factors that 
influence those changes in operation. While the EPA modeling shows that 
there is some increase in emissions from these units in all years 
following imposition of CAA section 111 standards on existing coal-
fired steam generating units and new stationary combustion turbines, 
that increase is much smaller in the later years. The EPA believes the 
magnitude of these trends is significantly impacted by the rate at 
which new low emitting generation comes on-line, in part incentivized 
by IRA and IIJA. The EPA is taking comment on all aspects of these 
assumptions including: the speed at which new low-emitting generation 
will come on-line and the impact that it has on likely capacity factors 
for combined cycle units (in particular the projection that capacity 
factors will grow in the 2028/30 timeframe but decrease in later 
years).
    With regard to the size and definition of the category to be 
covered in a first rulemaking covering only part of the existing 
turbine category, the EPA is also taking comment on how its assumptions 
about the potential operation of combustion turbines in future years 
coupled with considerations about the availability of infrastructure 
should inform which units should be covered in a first rulemaking. More 
specifically, the EPA is requesting comment on how to consider the rate 
of CCS (and potentially hydrogen) infrastructure development in 
determining a BSER that could potentially impact hundreds of sources. 
If, for instance, increased renewable generation and storage capacity 
were to lead to a smaller number of units operating at capacity factors 
of greater than 50 percent, the proposed BSER would not affect as many 
units and a smaller size threshold might be possible without expanding 
the amount of infrastructure needed. Conversely, if more units were 
likely to operate at a higher capacity factor, a higher capacity 
threshold might be appropriate. If the number of units likely to be 
covered by a 50 percent threshold were sufficiently small, it might be 
reasonable to include units in the intermediate category (e.g., units 
with capacity factors of between 20 percent and 50 percent) in a first 
rulemaking addressing the existing fossil fuel-fired turbine category. 
The EPA is also taking comment on a lower capacity factor threshold 
(e.g., 40 percent) and a lower capacity threshold (200 MW or 100 MW, 
and capacities between 100 and 300 MW). With regards to units with a 
capacity factor of greater than 50 percent that are under 300 MW and 
units with a capacity factor of 50 percent or less the EPA is taking 
comment on the appropriateness of CCS and/or hydrogen as a BSER. With 
regards to hydrogen, the EPA is taking comment on the appropriate level 
of and timing for hydrogen co-firing. More generally, EPA is requesting 
comment on any feasibility issues related to broader CCS deployment 
should those thresholds be adjusted such that more coal capacity is 
affected, and how such issues could be addressed.
    With regards to the BSER itself, the EPA is soliciting comment on 
the applicability of CCS retrofits to existing combustion turbines and 
its focus on base load turbines (e.g., those with a capacity factor of 
greater than 50 percent). This solicitation includes comment on whether 
particular plants would be unable to retrofit CCS, including details of 
the circumstances that might make retrofitting with CCS unreasonable or 
infeasible.
    The EPA is also taking comment on the role of low-GHG hydrogen as 
part of BSER. More specifically, the EPA is requesting comment on the 
appropriateness of low-GHG hydrogen as a BSER for combustion turbines 
larger than 300 MW with capacity factors of greater than 50 percent. 
While, as has been noted earlier in this section, a number of turbines 
already exist or are under construction that owners of combustion 
turbines have indicated may burn large amounts of hydrogen in a base 
load mode, the EPA is also aware that other proponents of low-GHG 
hydrogen use in turbines focus on it primarily as an energy storage 
device, storing renewable energy to provide electricity in times where 
renewable energy was not available. The EPA is interested in the 
question of whether, in this case, it would be likely that a combined 
cycle turbine burning low-GHG hydrogen would operate near base load, 
and whether it be prudent to have an alternative BSER or an alternative 
compliance pathway for units combusting low-GHG hydrogen and solicits 
comments on these questions. Similar to the NSPS for base load 
combustion turbines, the EPA is also taking comment on whether to 
finalize both the proposed low-GHG hydrogen BSER and the proposed CCS 
with 90 percent capture BSER, or finalize a BSER with a single pathway, 
such as based on application of CCS with 90 percent capture, which 
could also be met by co-firing with low-GHG hydrogen.
    With regard to the timing for BSER, the EPA is taking comment on a 
2035 CCS based BSER standard and whether that standard could reasonably 
be applied earlier. Similarly, the EPA is taking comment on the timing 
of a low-GHG hydrogen based BSER and whether a 30 percent low-GHG 
hydrogen standard could be implemented earlier than 2032, or if low-GHG 
hydrogen supply infrastructure development suggests it should be later. 
The EPA is taking comment on the same questions with regard to a 96 
percent low-GHG hydrogen co-firing BSER in 2038.

E. BSER for Remaining Combustion Turbines

    While the EPA believes that emission guidelines for units covered 
in the first rulemaking, proposed above, can achieve important emission 
reductions from the most frequently operating combustion turbines, the 
EPA believes that limits to infrastructure and capability to build 
carbon capture systems or co-fire large amounts of hydrogen caution 
against a first rulemaking addressing emissions from existing turbines 
covering all combustion turbines. In this section, the EPA discusses 
how developing a BSER for units in a second rulemaking could address 
units that do not meet the applicability requirements for the first 
rulemaking.
    As noted above, the EPA is taking comment on what units should be 
part of whatever action the EPA finalizes as a result of the proposal. 
Based on the units that the EPA has proposed be included, units that 
might remain uncovered include smaller baseload units (e.g., those less 
than or equal to 300 MW) and all units operating less than or equal to 
a capacity factor of 50 percent. Particularly for the remainder of the 
baseload units, the EPA is interested in whether any other units should 
have a BSER based on CCS. The EPA is also interested in the timing of 
such a requirement recognizing the tensions between an earlier 
requirement that would both achieve earlier reductions and the need to 
allow time for infrastructure to develop to support growing amounts of 
CCS.
    For intermediate turbines, the EPA is taking comment on a BSER 
similar to that for new turbines. In particular, the EPA is interested 
in comment about an appropriate pathway and timing for a BSER that 
would ultimately require 96 percent low-GHG hydrogen by volume.

[[Page 33371]]

Finally, for peaking turbines, the EPA is interested in comment about 
whether a clean hydrogen BSER would be appropriate, what the timing of 
such a requirement should be and whether there should be any phasing.
    The EPA is also interested in any comments related to: potential 
changes in operational patterns for turbines, particularly as more 
renewables and storage enter the grid. For instance, the EPA is 
interested in comments as to whether improvements in energy storage 
will reduce reliance on intermediate and peaking turbines. The EPA is 
also interested in comments on any potential technology developments 
that could impact its determination of BSER. For instance, the EPA is 
aware that in addition to electrolyzer based hydrogen and natural gas 
based hydrogen, there are other means of hydrogen production receiving 
significant attention such as naturally occurring hydrogen, and 
solicits comments on whether any of these potential technology 
developments should impact the EPA's consideration of the appropriate 
BSER for the remaining turbines.

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

A. Overview

    State plan submissions under these emission guidelines are governed 
by the requirements of 40 CFR part 60, subpart Ba (subpart Ba).\612\ 
The EPA proposed to revise certain aspects of 40 CFR part 60, subpart 
Ba, in its December 2022 proposal, ``Adoption and Submittal of State 
Plans for Designated Facilities: Implementing Regulations Under Clean 
Air Act Section 111(d)'' (proposed subpart Ba).\613\ The Agency intends 
to finalize revisions to 40 CFR part 60, subpart Ba, before 
promulgating these emission guidelines. Therefore, State plan 
development and State plan submissions under these proposed emission 
guidelines would be subject to the requirements of subpart Ba as 
revised in that future final action, including any changes the EPA 
makes to the proposal in response to public comments. To the extent the 
EPA is proposing to add to, supersede, or otherwise vary the 
requirements of subpart Ba for the purposes of these particular 
emission guidelines, those proposals are explicitly addressed in this 
section of the preamble. Unless expressly amended or superseded in 
these proposed emission guidelines, the provisions of subpart Ba, as 
revised by the EPA's forthcoming final rule, would apply.
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    \612\ 40 CFR 60.20a-60.29a.
    \613\ See 87 FR 79176 (December 23, 2022); see also id., Docket 
ID No. EPA-HQ-OAR-2021-0527-0002 (memorandum to docket containing 
proposed revisions to 40 CFR part 60, subpart Ba).
---------------------------------------------------------------------------

    This section provides information on several aspects of State plan 
development, including compliance deadlines, a presumptive methodology 
for establishing standards of performance for affected EGUs, compliance 
flexibilities, and State plan components and submission. In sections X 
and XI of this preamble, the EPA is soliciting comment on ranges for 
dates and values for defining subcategories, BSER, and degrees of 
emission limitation; those solicitations for comment extend to the 
proposed values and dates discussed in this section of the preamble. In 
section XII.B, the EPA proposes and explains its reasoning for 
compliance deadlines for affected steam generating units and affected 
combustion turbines. In section XII.C, the EPA describes its 
requirement that State plans achieve equivalent stringency to the EPA's 
BSER. Section XII.D proposes a presumptive methodology for calculating 
the standards of performance for affected EGUs based on subcategory as 
well as requirements related to invoking RULOF to apply a less 
stringent standard of performance than results from the EPA's 
presumptive methodology. Section XII.D also describes proposed 
requirements for increments of progress for affected EGUs in certain 
subcategories and milestones for affected EGUs, as well as testing and 
monitoring requirements. In section XII.E, the EPA proposes that States 
would be permitted to include trading and averaging as compliance 
measures for affected EGUs in their State plans, so long as plans 
demonstrate equivalence to the stringency that would result if each 
affected EGU was individually achieving its standard of performance. 
Finally, section XII.F describes what must be included in State plans, 
including plan components specific to these emission guidelines and 
requirements for conducting meaningful engagement.
    In this section of the preamble, the term ``affected EGU'' means 
any existing fossil fuel-fired steam generating unit or existing fossil 
fuel-fired combustion turbine EGU that meets the applicability criteria 
described in sections X and XI of this preamble. Affected EGUs would be 
covered by the proposed emission guidelines under 40 CFR part 60 
subpart UUUUb.

B. Compliance Deadlines

    The EPA is proposing a compliance date of January 1, 2030, for 
affected steam generating units. The proposed compliance date for the 
CCS combustion turbine subcategory is January 1, 2035. The proposed 
compliance dates for the first phase and second phase for the affected 
hydrogen co-fired combustion turbine subcategory are January 1, 2032, 
and January 1, 2038, respectively. This means that starting on the 
applicable compliance date, affected EGUs would be subject to standards 
of performance and other State plan requirements under these emission 
guidelines and would be required to start demonstrating compliance with 
those requirements.
    The EPA is proposing that January 1, 2030, is the soonest that 
affected steam generating units could reasonably commence compliance 
with standards of performance given the proposed State plan submission 
timeline (24 months; see section XII.F.2 of this preamble) and the 
amount of time affected EGUs in the long-term and medium-term coal-
fired steam generating unit subcategories will need to install CCS or 
natural gas co-firing, respectively. For consistency, the EPA is also 
proposing a January 1, 2030, compliance date for imminent- and near-
term coal-fired units as well as the different subcategories of natural 
gas- and oil-fired steam generating units.
    However, the EPA recognizes that the BSERs for some subcategories 
of affected steam-generating EGUs are routine methods of operation and 
maintenance, which do not require the installation of any or 
significant control equipment and can thus be applied earlier.\614\ 
Therefore, the EPA is soliciting comment on compliance dates defined by 
the date of approval of the State plan or January 1, 2030, whichever is 
earlier, for imminent-term coal-fired steam generating units, near-term 
coal-fired steam generating units, and the different subcategories of 
natural gas- and oil-fired steam generating units.
---------------------------------------------------------------------------

    \614\ The EPA is also taking comment in section X.D.3.b.ii on 
potential BSER options for imminent- and near-term affected coal-
fired steam generating units based on low levels of natural gas co-
firing.
---------------------------------------------------------------------------

    The proposed compliance timeframe for affected steam-generating 
EGUs in these proposed emission guidelines is based on the amount of 
time the EPA believes is needed to comply with standards of performance 
based on implementation of natural gas co-firing or CCS. Each of these 
systems would require several years to plan, permit, and construct. 
However, as explained further in section XII.F.2 of this preamble, the 
EPA is proposing to

[[Page 33372]]

adjust the State plan submission deadline so that certain necessary 
planning and design steps for natural gas co-firing or CCS 
implementation can take place as part of the State plan development 
process. That is, we expect that some of the planning and design steps 
described below would take place prior to State plan submission. The 
EPA believes that coordinating State plan development, submission, and 
implementation in this manner reflects how the owners/operators of 
affected EGUs and States would actually undertake the steps leading to 
ultimate deployment of a control technology and compliance with a 
standard of performance.
    The GHG Mitigation Measures for Steam Generating Units TSD 
discusses the timeframes for implementation of natural gas co-firing 
and CCS at existing coal-fired steam generating EGUs. Based on this 
analysis, it is clear that the time needed to design and implement CCS 
is an important aspect for setting a compliance date under these 
emission guidelines. CCS projects will include planning, design, and 
construction of both the carbon capture system and the transport and 
storage system; the EPA believes that all of these steps can be 
completed within roughly 5 years.\615\
---------------------------------------------------------------------------

    \615\ GHG Mitigation Measures for Steam Generating Units TSD, 
chapter 4.7.1. See Table 5 in chapter 4.7.1 for visual 
representation of the CCS and co-firing project timelines described 
in this section.
---------------------------------------------------------------------------

    Deployment of a carbon capture system starts with a technical and 
economic feasibility evaluation, including a Front End Engineering 
Design (FEED) study. The owner/operator of an affected EGU would then 
proceed to making technical and commercial arrangements, including 
arranging project financing and permitting. These initial steps do not 
need to be undertaken sequentially and may be completed in 3 years or 
less. As noted above, the EPA also believes that at least some of these 
project design and development steps, including feasibility evaluations 
and FEED studies, can and will be completed prior to State plan 
submission. The EPA believes that the commencement of CCS project 
implementation activities, including more detailed engineering work and 
procurement, construction of the carbon capture system, and startup and 
testing, will overlap with the final steps of the initial project 
design and development phase. These project implementation steps take 
approximately 3 years to complete.
    In addition to planning and implementing a carbon capture system, 
the owners/operators of affected EGUs will also have to design and 
construct a system for transporting and storing captured 
CO2. The necessary steps for implementing transport and 
storage of captured CO2 can be undertaken simultaneously 
with development of the CO2 capture system, and some of the 
steps necessary for transport and storage can additionally overlap with 
each other. The EPA thus believes design and implementation of 
CO2 transport and storage can be completed within 5 years.
    The EPA believes that the initial phases of planning and design for 
CO2 transport and storage, including site characterization 
and pipeline feasibility and design activities, can and will occur 
prior to State plan submission, i.e., as part of the State plan 
development process. First, the owner/operator of an affected EGU would 
undertake a feasibility analysis associated with CO2 
transport and storage, as well as site characterization and permitting 
of potential storage areas. These steps can overlap with each other and 
the EPA anticipates that, in total, feasibility analyses, site 
characterization, and permitting of potential storage areas will take 
2-3 years to complete. The EPA believes there is significant 
opportunity to overlap the design and planning phase for CO2 
transport and storage with the engineering and construction phase for 
transport and storage, which is anticipated to take 2-3 years. Based on 
the potential to conduct many of the design, planning, permitting, 
engineering, and construction steps, the EPA thus believes that 
affected EGUs will need approximately 5 years, from start to finish, to 
be ready to implement CO2 transport and storage.
    The EPA expects that implementation of natural gas co-firing 
projects for affected coal-fired steam-generating EGUs, including any 
necessary construction of natural gas pipelines, can be completed in 
approximately 3.5 years. As discussed in the GHG Mitigation Measures 
for Steam Generating Units TSD,\616\ any necessary boiler modifications 
to accommodate natural gas co-firing can be completed within 3 years. 
The process of planning, permitting, and construction for boiler 
modifications can occur simultaneously with the steps that owners/
operators of affected EGUs would need to undertake if construction of a 
new natural gas pipeline is needed. The time required to develop and 
construct natural gas laterals can be broken into three phases: 
planning and design; permitting and approval; and construction. It is 
reasonable to assume that the planning and design phase can typically 
be completed in a matter of months and will often be finalized in less 
than a year. The time required to complete the permitting and approval 
phase can vary. Based on a review of recent FERC data, the average time 
for pipeline projects similar in scope to the projects considered in 
this TSD is about 1.5 years and would likely not exceed 4 years. The 
EPA notes that these data may not reflect that pipeline projects may be 
completed more expeditiously in the presence of a regulatory deadline. 
Finally, the actual construction could likely be completed in less than 
1 year. Based on a sum of these estimates, the EPA believes that 3.5 
years is a reasonable timeframe for pipeline projects.
---------------------------------------------------------------------------

    \616\ GHG Mitigation Measures for Steam Generating Units TSD, 
chapters 3.2.1.4, 3.2.2.3, and 4.7.1.
---------------------------------------------------------------------------

    The EPA expects that final emission guidelines will be published in 
June 2024 and is proposing a State plan submission deadline that is 24 
months from publication, which would be June 2026. The proposed 
compliance date for affected steam generating units is January 1, 2030. 
The EPA requests comment on whether using a period of 3.5 years after 
State plan submission is appropriate for establishing a compliance 
deadline for these emission guidelines. As explained above, the EPA is 
basing this proposed timeframe on the expectation that some of the 
initial evaluation and planning steps for both natural gas co-firing 
and CCS would take place as part of State plan development, i.e., 
before the State plan submission deadline. The EPA is also requesting 
comment on potential compliance dates between 1.5 and 5.5 years after 
State plan submission (i.e., January 1, 2028, to January 1, 2032), 
including on the feasibility of completing all the steps to implement 
natural gas co-firing and CCS within a shorter or longer timeframe. To 
the extent that commenters believe more or less time after State plan 
submission is more appropriate than the proposed 3.5 years, the EPA 
requests that commenters provide information supporting the provision 
of a different compliance date. Additionally, the proposed State plan 
submission date and proposed compliance date are based on the EPA's 
anticipation that it will publish final emission guidelines for 
affected EGUs in June 2024. Should the actual date of publication of 
the final emission guidelines differ from this target, the EPA will 
adjust the State plan submission and compliance dates accordingly.
    As discussed in section XI.C of this preamble, the EPA is proposing 
to subcategorize affected existing,

[[Page 33373]]

frequently used combustion turbines that are covered under these 
emission guidelines into two subcategories: one subcategory for 
affected combustion turbine EGUs that adopt the pathway with a standard 
of performance based on CCS, referred to as the ``CCS subcategory'' and 
one subcategory for affected combustion turbine EGUs that adopt the 
pathway with a standard of performance based on hydrogen co-firing, 
referred to as the ``hydrogen co-fired subcategory.'' For affected 
combustion turbines in the CCS subcategory, the EPA is proposing a 
compliance date of January 1, 2035, which is the soonest the Agency 
believes these sources can comply with standards of performance based 
on installation and operation of CCS, given the timeframes for planning 
and construction of carbon capture and CO2 transport and 
storage systems along with other demands on the infrastructure and 
resources needed to implement CCS throughout the power sector and the 
broader economy. For affected combustion turbines in the hydrogen co-
fired subcategory, the EPA is proposing a two-phase standard of 
performance, with a proposed compliance date for the first phase of 
January 1, 2032, and for the second phase of January 1, 2038.
    For combustion turbine EGUs in the CCS subcategory, the same 
timeframes and considerations discussed for the planning and 
construction of CCS for affected coal-fired steam generating units 
apply. That is, the EPA expects that the owners or operators of 
affected combustion turbines will be able to complete the design, 
planning, permitting, engineering, and construction steps for the 
carbon capture and transport and storage systems within 5 years. As 
with affected coal-fired steam generating units, the EPA believes that 
States and owners or operators can and would take several of the 
initial steps in the design and planning processes for combustion 
turbine EGUs as part of State plan development, i.e., prior to the 
proposed State plan submission deadline in approximately June 2026.
    However, as noted in section XI.C of this preamble, the EPA is 
projecting approximately 12 GW of coal-fired generation will likely 
retrofit with CCS in order to meet the proposed January 1, 2030, 
compliance date for affected long-term coal-fired steam generating 
units. These and other CCS projects that are likely to be occurring in 
response to the IRA may take up a significant amount of the capacity to 
plan and build CCS between 2023 and 2030. The EPA anticipates that 
additional pipeline capacity will be constructed ahead of January 1, 
2030, for CO2 transport as well as for natural gas pipeline 
laterals that may be needed for affected coal-fired steam generating 
units that will co-fire with natural gas as a control strategy. Due to 
these and other overlapping demands on the capacity to design, 
construct, and operate carbon systems as well as pipeline systems, the 
EPA is proposing to find that a January 1, 2030, compliance date for 
affected combustion turbine EGUs in the CCS subcategory, although 
feasible for an individual unit, would not be the most reasonable 
deadline for all of the units that would need to install CCS. 
Therefore, the EPA is proposing to provide a compliance date for 
affected combustion turbine EGUs in the CCS subcategory that is 5 years 
after the compliance date for long-term coal-fired steam generating 
units, or January 1, 2035. The EPA requests comment on its proposed 
compliance deadline for combustion turbine EGUs in the CCS subcategory, 
including on whether an earlier or later compliance date would be more 
reasonable given the time needed to analyze, design, and construct 
carbon capture and CO2 transport and storage systems and the 
overlapping timeframes for installation of CCS on EGUs under the 
proposed CAA section 111(b) standards of performance for new combustion 
turbines and on existing coal-fired steam generating units under these 
proposed emission guidelines.
    For affected combustion turbine EGUs in the hydrogen co-fired 
subcategory, the EPA is proposing a compliance deadline for the first 
phase of January 1, 2032. As discussed in sections VII.F.3.c.v and vi 
of this preamble, currently the vast majority of hydrogen is not low-
GHG hydrogen. Midstream infrastructure limitations and the adequacy and 
availability of hydrogen storage facilities currently present obstacles 
and increase prices for delivered low-GHG hydrogen. However, given the 
growth in the hydrogen sector and Federal funding for DOE's H2Hubs, 
which will explicitly explore and incentivize hydrogen distribution, 
the EPA believes hydrogen distribution and storage infrastructure will 
not present a barrier to access for new combustion turbines opting to 
co-fire 30 percent hydrogen by volume in 2032. Legislative actions 
including the IIJA and IRA, utility initiatives, and industrial sector 
production and infrastructure projects indicate that sufficient low-GHG 
hydrogen and sufficient distribution infrastructure can reasonably be 
expected to be available by this time. On this basis, the EPA is 
proposing that compliance with the first phase of the standard, which 
is based on an affected EGU co-firing 30 percent (by volume) low-GHG 
hydrogen, will commence on January 1, 2032.
    The proposed compliance date of January 1, 2038, for the second 
phase of the standard of performance for combustion turbine EGUs in the 
hydrogen co-fired subcategory, which is based on a proposed BSER of 96 
percent (by volume) co-firing low-GHG hydrogen, is also based on an 
assessment of when sufficient quantities of such hydrogen will be 
available, as well as when turbine vendors are anticipated to have the 
equipment necessary for higher percentages of hydrogen co-firing 
available. As discussed in section VII.F.3 of this preamble, the EPA 
expects that based on technology advances, growing demand for low-GHG 
hydrogen, and the hydrogen production tax credits available under IRC 
45V(b)(2), there will be continued expansion of the hydrogen production 
and transmission network between 2032 and 2038. The EPA also notes 
that, based on the current ages of the existing combustion turbine 
fleet, the number of units that would be expected to meet their 
standards of performance in 2038 by co-firing 96 percent hydrogen (by 
volume) is likely to decline. Therefore, the EPA believes it is 
reasonable to expect that there will be sufficient low-GHG hydrogen in 
2038 to provide the quantities needed for both new and affected 
existing combustion turbines in the hydrogen co-fired subcategory to 
meet their applicable standards of performance. The EPA requests 
comment on this assessment, as well as on whether compliance dates 
other that January 1, 2032, and January 1, 2038, would be more 
reasonable for the first and second phases of the standards for 
affected units in the hydrogen co-fired subcategory, and why.

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

    As explained in section V.C of this preamble, CAA section 111(d)(1) 
requires the EPA to establish requirements for State plans that, in 
turn, must include standards of performance for existing sources. Under 
CAA section 111(a)(1), a standard of performance is ``a standard for 
emissions of air pollutants which reflects the degree of emission 
limitation achievable through the application of the best system of 
emission reduction which . . . the Administrator determines has been 
adequately demonstrated.'' That is, the

[[Page 33374]]

EPA has the responsibility to determine the best system of emission 
reduction for a given category or subcategory of sources and to 
determine the degree of emission limitation achievable through 
application of the BSER to affected sources.\617\ The level of emission 
performance required under CAA section 111 is reflected in the EPA's 
presumptive standards of performance.
---------------------------------------------------------------------------

    \617\ See, e.g., West Virginia v. EPA, 142 S. Ct. 2587, 2607 
(2022) (``In devising emissions limits for power plants, EPA first 
`determines' the `best system of emission reduction' that--taking 
into account cost, health, and other factors--it finds `has been 
adequately demonstrated.' The Agency then quantifies `the degree of 
emission limitation achievable' if that best system were applied to 
the covered source.'') (internal citations omitted).
---------------------------------------------------------------------------

    States use the EPA's presumptive standards of performance as the 
basis for establishing requirements for affected sources in their State 
plans. In order for the EPA to find a State plan ``satisfactory,'' that 
plan must address each affected source within the State and achieve the 
level of emission performance that would result if each affected source 
was achieving its presumptive standard of performance, after accounting 
for any application of RULOF.\618\ That is, while States have the 
discretion to establish the applicable standards of performance for 
affected sources in their State plans, the structure and purpose of CAA 
section 111 require that those plans achieve equivalent stringency as 
applying the EPA's presumptive standards of performance to each of 
those sources (again, after accounting for any application of RULOF).
---------------------------------------------------------------------------

    \618\ As explained in section XI.D.2 of this preamble, States 
may invoke RULOF to apply a less stringent standard of performance 
to a particular affected EGU when the state demonstrates that the 
EGU cannot reasonably apply the BSER to achieve the degree of 
emission limitation determined by the EPA. In this case, the state 
plan may not necessarily achieve the same stringency as each source 
achieving the EPA's presumptive standards of performance because 
affected EGUs for which RULOF has been invoked would have standards 
of performance less stringent than the EPA's presumptive standards.
---------------------------------------------------------------------------

    The EPA's December 2022 proposed revisions to the CAA section 111 
implementing regulations (40 CFR part 60, subpart Ba) would provide 
that States are permitted, in appropriate circumstances, to adopt 
compliance measures that allow their sources to meet their standards of 
performance in the aggregate.\619\ As with the establishment of 
standards of performance for affected sources, CAA section 111 requires 
that State plans that include such flexibilities for complying with 
standards of performance demonstrate equivalent stringency as would be 
achieved if each affected source was achieving its standard of 
performance.
---------------------------------------------------------------------------

    \619\ 87 FR 79176, 79207-08 (December 23, 2015).
---------------------------------------------------------------------------

    The requirement that State plans achieve equivalent stringency to 
the EPA's BSER and degree of emission limitation is borne out of the 
structure and purpose of CAA section 111, which is to mitigate air 
pollution that is reasonably anticipated to endanger public health or 
welfare. It achieves this purpose by requiring source categories that 
cause or contribute to dangerous air pollution to operate more cleanly. 
Unlike the Clean Air Act's NAAQS-based programs, section 111 is not 
designed to reach a level of emissions that has been deemed ``safe'' or 
``acceptable''; there is no air-quality target that tells States and 
sources when emissions have been reduced ``enough.'' Rather, CAA 
section 111 requires affected sources to reduce their emissions to the 
level that the EPA has determined is achievable through application of 
the best system of emission reduction, i.e., to achieve emission 
reductions consistent with the applicable presumptive standard of 
performance. Consistent with the statutory purpose of requiring 
affected sources to operate more cleanly, the EPA typically expresses 
presumptive standards of performance as rate-based emission 
limitations.
    In the course of complying with a rate-based standard of 
performance under a State plan, an affected source may take an action 
that removes it from the source category, e.g., by permanently ceasing 
operations. In this case, the source is no longer subject to the 
emission guidelines. An affected source may also choose to change its 
operating characteristics in a way that impacts its overall emissions, 
e.g., by changing its utilization; however, the source is still 
required to meet its rate-based standard. In either instance, the 
changes to one affected source do not implicate the obligations of 
other affected sources. Although such changes may reduce emissions from 
the source category, they do not absolve the remaining affected EGUs 
from the statutory obligation to improve their emission performance 
consistent with the level that the EPA has determined is achievable 
through application of the BSER. This fundamental statutory requirement 
applies regardless of whether a standard of performance is expressed or 
implemented as a rate- or mass-based emission limitation, or whether 
standards of performance are achieved on a source-specific or aggregate 
basis.
    In sum, consistent with the respective roles of the EPA and States 
under CAA section 111, States have discretion to establish standards of 
performance for affected sources in their State plans, and to provide 
flexibilities for affected sources to use in complying with those 
standards. However, State plans must demonstrate that they ultimately 
provide for equivalent stringency as would be achieved if each affected 
source was achieving the applicable presumptive standard of 
performance, after accounting for any application of RULOF.

D. Establishing Standards of Performance

    CAA section 111(d)(1)(A) provides that ``each State shall submit to 
the Administrator a plan which establishes standards of performance for 
any existing source''; that plan must also ``provide[ ] for the 
implementation and enforcement of such standards of performance.'' That 
is, States must use the BSER and stringency in the EPA's emission 
guidelines to establish standards of performance for each existing 
affected EGU through a State plan.
    To assist States in developing State plans that achieve the level 
of stringency required by the statute, it has been the EPA's 
longstanding practice to provide presumptively approvable standards of 
performance or a methodology for establishing such standards. For the 
purpose of these emission guidelines, the EPA is proposing a 
methodology for States to use in establishing presumptively approvable 
standards of performance for affected existing EGUs. Per CAA section 
111(a)(1), the basis of this methodology is the degree of emission 
limitation the EPA has determined is achievable through application of 
the BSER to each subcategory. The EPA anticipates and intends for most 
States to apply the presumptive standards of performance to affected 
EGUs.
    Additionally, CAA section 111(d)(1)(B) permits States to take into 
consideration a particular affected EGU's RULOF when applying a 
standard of performance to that source. The EPA's proposed revisions to 
the CAA section 111 implementing regulations at 40 CFR part 60, subpart 
Ba provide that a State would be able to apply a less stringent 
standard of performance to an affected EGU when the State can 
demonstrate that the source cannot reasonably apply the BSER to achieve 
the degree of emission limitation determined by the EPA. Proposed 
subpart Ba describes the conditions that would warrant application of a 
less stringent RULOF standard under these emission guidelines and how a 
RULOF standard

[[Page 33375]]

would be determined. Further detail about how the EPA proposes to 
implement the RULOF provision in the context of this rulemaking is 
provided in section XII.D.2 of this preamble.
    States also have the authority to apply standards of performance to 
affected EGUs that are more stringent than the EPA's presumptively 
approvable standards of performance.\620\
---------------------------------------------------------------------------

    \620\ 40 CFR 60.24a(f). The EPA has proposed to revise this 
provision to clarify that it has the obligation and authority to 
review and approve state plans that contain the more stringent 
requirements. 87 FR 79176, 79204 (December 23, 2022).
---------------------------------------------------------------------------

1. Application of Presumptive Standards
    This section of the preamble describes the EPA's approach to 
providing presumptive standards of performance for each of the 
subcategories of affected EGUs under these emission guidelines, 
including establishing baseline emission performance. Under this 
proposal, each subcategory with a proposed BSER and degree of emission 
limitation would have a corresponding methodology for establishing 
presumptively approvable standards of performance (also referred to as 
``presumptive standards of performance'' or ``presumptive standards'').
    A State, when establishing standards of performance for affected 
EGUs in its plan, would identify each affected EGU in the State and 
specify into which subcategory each EGU falls. The EPA is proposing 
that the State would then use the corresponding methodology for the 
given subcategory to calculate and apply the presumptively approvable 
standard of performance for each affected EGU.
    States also have the authority to deviate from the methodology for 
presumptively approvable standards, in order to apply a more stringent 
standard of performance through increasing the degree of emission 
limitation beyond what the EPA has determined to be achievable for 
units as a general matter (e.g., a State decides that an EGU in the 
medium-term coal-fired subcategory should co-fire 50 percent natural 
gas instead of 40 percent). Deviations to increase stringency do not 
trigger use of the RULOF mechanism, which requires States to 
demonstrate that an affected EGU cannot reasonably apply the BSER to 
achieve the degree of emission limitation determination by the 
EPA.\621\ The EPA proposes to presume that standards of performance 
that are more stringent than the EPA's presumptive standards are 
``satisfactory'' for the purposes of CAA section 111(d).
---------------------------------------------------------------------------

    \621\ 87 FR 79176, 79199 (December 23, 2022).
---------------------------------------------------------------------------

a. Establishing Baseline Emission Performance for Presumptive Standards
    For each subcategory, the proposed methodology to calculate a 
standard of performance entails establishing a baseline of 
CO2 emissions and corresponding electricity generation for 
an affected EGU and then applying the degree of emission limitation 
achievable through the application of the BSER (as established in 
section X.D and XI.C of this preamble). The methodology for 
establishing baseline emission performance for an affected EGU is 
identical in each of the subcategories but will result in a value that 
is unique to each affected EGU. To establish baseline emission 
performance for an affected EGU, the EPA is proposing that a State will 
use the CO2 mass emissions and corresponding electricity 
generation data for a given affected EGU from any continuous 8-quarter 
period from 40 CFR part 75 reporting within the 5 years immediately 
prior to the date the final rule is published in the Federal Register. 
This proposed period is based on the NSR program's definition of 
``baseline actual emissions'' for existing electric steam generating 
units. See 40 CFR 52.21(b)(48)(i). Eight quarters of 40 CFR part 75 
data corresponds to a 2-year period, but the EPA is proposing 8 
quarters of data as that corresponds to quarterly reporting according 
to 40 CFR part 75. Functionally, the EPA expects States to utilize the 
most representative 8-quarter period of data from the 5 years 
immediately preceding the date the final rule is published in the 
Federal Register. For the 8 quarters of data, the EPA is proposing that 
a State would divide the total CO2 emissions (in the form of 
pounds) over that continuous time period by the total gross electricity 
generation (in the form of MWh) over that same time period to calculate 
baseline CO2 emission performance in lb CO2 per 
MWh. As an example, a State establishing baseline emission performance 
in the year 2023 would start by evaluating the CO2 emissions 
and electricity generation data for each of its affected EGUs for 2018 
through 2022 and choosing, for each affected EGU, a continuous 8-
quarter period that it deems to be the best representation of the 
operation of that affected EGU. While the EPA will evaluate the choice 
of baseline periods chosen by States when reviewing State plan 
submissions, the EPA intends to defer to a State's reasonable exercise 
of discretion as to which 8-quarter period is representative.
    The EPA is proposing to require the use of 8 quarters during the 5-
year period prior to the date the final rule is published in the 
Federal Register as the relevant period for the baseline methodology 
for a few reasons. First, each affected EGU has unique operational 
characteristics that affect the emission performance of the EGU (load, 
geographic location, hours of operation, coal rank, unit size, etc.), 
and the EPA believes each affected EGU's emission performance baseline 
should be representative of the source-specific conditions of the 
affected EGU and how it has typically operated. Additionally, allowing 
a State to choose (likely in consultation with the owners or operators 
of affected EGUs) the 8-quarter period for assessing baseline 
performance can avoid situations in which a prolonged period of 
atypical operating conditions would otherwise skew the emissions 
baseline. Relatedly, the EPA believes that by using total mass 
CO2 emissions and total electric generation for an affected 
EGU over an 8-quarter period, any relatively short-term variability of 
data due to seasonal operations or periods of startup and shutdown, or 
other anomalous conditions, will be averaged into the calculated level 
of baseline emission performance. The baseline-setting approach of 
using total CO2 mass emissions and total electric generation 
over an 8-quarter period also aligns with the reporting and compliance 
requirements. The EPA is proposing that compliance would be 
demonstrated annually based on the lb CO2/MWh emission rate 
derived by dividing the total reported CO2 mass emissions by 
the total reported electric generation for an affected EGU during the 
compliance year, which is consistent with the expression of the degree 
of emission limitation proposed for each subcategory in sections X.D.4, 
X.E.2, and XI.C. The EPA believes that using total mass CO2 
emissions and total electric generation provides a simple and 
streamlined approach for calculating baseline emission performance 
without the need to sort and filter non-representative data; any minor 
amount of non-representative data will be subsumed and accounted for 
through implicit averaging over the course of the 8-quarter period. 
Moreover, this approach, by not sorting or filtering the data, 
eliminates any need for discretion in assessing whether the data is 
appropriate to use.
    The EPA is soliciting comment on the proposed baseline-setting 
approach and specifically on the applicability of such an approach for 
each of the different subcategories. The EPA is proposing a continuous 
8-quarter period to better average out operating variability but

[[Page 33376]]

solicits comment on whether a different time period would be more 
appropriate for assessing baseline emission performance, as well as on 
the 5-year window from which the period for baseline emission 
performance is chosen. The EPA also solicits comment on the use of 
total mass CO2 emissions and total electric generation over 
a consecutive 8-quarter time period as representative and on whether 
the EPA's proposed approach is appropriate.
    The EPA believes that using the proposed baseline-setting approach 
as the basis for establishing presumptively approvable standards of 
performance will provide certainty for States, as well as transparency 
and a streamlined process for State plan development. While this 
approach is specifically designed to be flexible enough to accommodate 
unit-specific circumstances, States retain the ability to deviate from 
the methodologies the EPA is proposing for establishing baselines of 
emission performance for affected EGUs. The EPA believes that the 
instances in which a State may need to use an alternate baseline-
setting methodology will be limited to anticipated changes in 
operation, i.e., circumstances in which historical emission performance 
is not representative of future emission performance. The EPA is 
proposing that States wishing to vary the baseline calculation for an 
affected EGU based on anticipated changes in operation, when those 
changes result in a less stringent standard of performance, must use 
the RULOF mechanism, which is designed to address such contingencies.
b. Presumptive Standards for Steam Generating Units
    As described in section X.C of this preamble, the EPA is proposing 
to first subcategorize affected existing steam generating units by fuel 
type: coal-fired and oil- or natural gas-fired steam generating units. 
The EPA is proposing further subcategorization into four subcategories 
for coal-fired steam generating units and seven subcategories for oil- 
and natural gas-fired steam generating units. As explained in section 
X.C.3, the EPA is proposing that an affected coal-fired steam 
generating unit's operating horizon determines the applicable 
subcategory in three of the four subcategories; in the case of the 
near-term subcategory, the operating horizon and load level establish 
applicability.
    The EPA notes that, as explained in section X.C.3 of this preamble, 
where the owners or operators of affected coal-fired steam-generating 
units have elected to commit to permanently cease operation (and, in 
the case of near-term operating horizon units, to limit their capacity 
factor) and have also elected to make any such commitments federally 
enforceable through inclusion in a State plan, a State may rely on such 
commitments to subcategorize coal-fired steam generating units under 
these emission guidelines. To be included in a State plan a commitment 
to cease operations or to limit capacity factor must be enforceable by 
the State, whether through State rule, agreed order, permit, or other 
legal instrument.\622\ Upon EPA approval of the State plan, that 
commitment will become federally enforceable.
---------------------------------------------------------------------------

    \622\ 40 CFR 60.26a.
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    For affected oil- and natural gas-fired steam generating units, 
subcategories are defined by load level and the type of fuel fired, as 
well as locality (i.e., continental and non-continental U.S.). There 
are four subcategories for oil-fired steam generating units based on 
different combinations of load level (base load, intermediate load, and 
low load) and locality, and three subcategories for natural gas-fired 
steam generating units based on load level (base load, intermediate, 
and low).
i. Long-Term Coal-Fired Steam Generating Units
    This section describes the EPA's proposed methodology for 
establishing presumptively approvable standards of performance for 
long-term coal-fired steam generating units. Affected coal-fired steam 
generating units that have either (1) Elected to commit to permanently 
cease operations on January 1, 2040, or later, or (2) that have not 
elected to commit to permanently cease operations as part of the 
State's plan submission, fall within this subcategory and have a 
proposed BSER of CCS with 90 percent capture and a proposed degree of 
emission limitation of 90 percent capture of the mass of CO2 
in the flue gas (i.e., the mass of CO2 after the boiler but 
before the capture equipment) over an extended period of time and an 
88.4 percent reduction in emission rate on a gross basis over an 
extended period of time. The EPA is proposing that where States use the 
methodology described here to establish standards of performance for an 
affected EGU in this subcategory, those established standards would be 
presumptively approvable when included in a State plan submission. In 
section X of this preamble, for the long-term coal-fired subcategory, 
the EPA is soliciting comment on a capture rate of 90 to 95 percent and 
a degree of emission limitation defined by a reduction in emission rate 
on a gross basis from 75 to 90 percent.
    Establishing a standard of performance for an affected coal-fired 
EGU in this subcategory consists of two steps: establishing a source-
specific level of baseline emission performance (as described above); 
and applying the level of stringency, based on the application of the 
BSER, to that level of baseline emission performance. Implementation of 
CCS with a capture rate of 90 precent translates to a level of 
stringency of an 88.4 percent reduction in CO2 emission rate 
(see section X.D.4.a of this preamble) compared to the baseline level 
of emission performance. Using the complement of 88.4 percent (i.e., 
11.6 percent) and multiplying it by the baseline level of emission 
performance results in the presumptively approvable standard of 
performance. For example, if a long-term coal-fired EGU's level of 
baseline emission performance is 2,000 lbs per MWh, it will have a 
presumptively approvable standard of performance of 232 lbs per MWh 
(2,000 lbs per MWh multiplied by 0.116).
    The EPA is also proposing that affected coal-fired EGUs in the 
long-term subcategory comply with federally enforceable increments of 
progress, which are described in section XII.D.3.a of this preamble.
    The EPA solicits comments on this proposed methodology for 
calculating presumptively approvable standards of performance for long-
term coal-fired steam generating units.
ii. Medium-Term Coal-Fired Steam Generating Units
    This section describes the EPA's proposed methodology for 
establishing presumptively approvable standards of performance for 
medium-term coal-fired steam generating units. Affected coal-fired 
steam generating units that have elected to commit to permanently cease 
operations after December 31, 2031, and before January 1, 2040, have a 
proposed BSER of 40 percent co-firing of natural gas. The EPA is 
proposing that where States use the methodology described here to 
establish standards of performance for an affected EGU in this 
subcategory, those established standards of performance would be 
presumptively approvable when included in a State plan submission.
    Establishing a standard of performance for an affected EGU in this 
subcategory consists of two steps: establishing a source-specific level 
of baseline emission performance (as described earlier in this 
preamble); and applying the level of emission reduction

[[Page 33377]]

stringency, based on the application of the BSER, to that level of 
baseline emission performance. Implementation of natural gas co-firing 
at a level of 40 percent of total annual heat input translates to a 
level of stringency of a 16 percent reduction in CO2 
emissions (see section X.D.4.b of this preamble) compared to the 
baseline level of emission performance. Using the complement of 16 
percent (i.e., 84 percent) and multiplying it by the baseline level of 
emission performance results in the presumptively approvable standard 
of performance for the affected EGU. For example, if a medium-term 
coal-fired EGU's level of baseline emission performance is 2,000 lbs 
per MWh, it will have a presumptively approvable standard of 
performance of 1,680 lbs per MWh (2,000 lbs per MWh multiplied by 
0.84). In section X of this preamble, for the medium-term coal-fired 
subcategory, the EPA is soliciting comment on a natural gas co-firing 
level of 30 to 50 percent and a degree of emission limitation from 12 
to 20 percent.
    For medium-term coal-fired steam generating units that have an 
amount of co-firing that is reflected in the baseline operation, the 
EPA is proposing that States account for such preexisting co-firing in 
adjusting the degree of emission limitation. If, for example, an EGU 
co-fires natural gas at a level of 10 percent of the total annual heat 
input during the applicable 8-quarter baseline period, the 
corresponding degree of emission limitation would be adjusted to 12 
percent (i.e., an additional 30 percent of natural gas by heat input) 
to reflect the preexisting level of natural gas co-firing. This results 
in a standard of performance based on the degree of emission limitation 
achieving an additional 30 percent co-firing beyond the 10 percent that 
is accounted for in the baseline. The EPA believes this approach is a 
more straightforward mathematical adjustment than adjusting the 
baseline to appropriately reflect a preexisting level of co-firing. 
However, the EPA solicits comment on whether the adjustment of a 
standard of performance based on preexisting levels of natural gas co-
firing should be done through the baseline. To adjust the baseline to 
account for preexisting natural gas co-firing, the State would need to 
calculate a baseline of emission performance for an EGU that removes 
the mass emissions and electric generation that are attributable to the 
natural gas portion of the fuel. With this adjusted baseline that 
removes the natural gas-fired portion, the presumptive standard of 
performance would be calculated by multiplying the adjusted baseline by 
the degree of emission limitation factor that reflects 40 percent co-
firing. The EPA is not proposing this methodology, because parsing the 
attributable emissions and electric generation associated with natural 
gas co-firing from the attributable emissions and electric generation 
associated with coal-fired generation requires manipulation of the 
emissions and electric generation data. However, the EPA solicits 
comment on whether baseline adjustment is more appropriate and also why 
that may be so.
    The standard of performance for the medium-term coal-fired 
subcategory is based on the degree of emission limitation that is 
achievable through application of the BSER to the affected EGUs in the 
subcategory and consists exclusively of the rate-based emission 
limitation. However, to qualify for inclusion in the subcategory an 
affected coal-fired steam generating unit must have elected to commit 
to permanently cease operations prior to January 1, 2040. If a State 
decides to rely on such a commitment to place an affected EGU into the 
medium-term coal-fired subcategory by making it an enforceable element 
of its State plan, the commitment to cease operations will become 
federally enforceable upon EPA approval of the plan.
    The EPA is proposing that affected coal-fired EGUs that elect to 
commit to dates to permanently cease operations for subcategory 
applicability, including EGUs in the medium-term coal-fired 
subcategory, have corresponding federally enforceable milestones with 
which they must comply. The EPA intends these milestones to assist 
affected EGUs in ensuring they are completing the necessary steps to 
comply with their State plan and commitments to dates to permanently 
cease operations. These milestones are described in detail in section 
XII.D.3.b of this preamble. Affected EGUs in this subcategory would 
also be required to comply with the federally enforceable increments of 
progress described in section XII.D.3.a of this preamble.
    The EPA solicits comment on the proposed methodology for 
calculating presumptively approvable standards of performance for 
medium-term coal-fired steam generating units, including on the 
proposed approach for adjusting a presumptively approvable standard of 
performance to accommodate preexisting natural gas co-firing.
iii. Imminent-Term Coal-Fired Steam Generating Units
    This section describes the EPA's proposed methodology for 
establishing presumptively approvable standards of performance for 
imminent-term coal-fired steam generating units. Affected coal-fired 
steam generating units that elect to commit to permanently cease 
operations before January 1, 2032, have a proposed BSER of routine 
methods of operation and maintenance. Therefore, the proposed 
presumptively approvable standard of performance is not to exceed the 
baseline emission performance of the affected EGU (as described in 
section XII.D.1.a of this preamble).
    Unlike the proposed standards of performance for the long-term and 
medium-term coal-fired steam generating units, establishing a standard 
of performance for an affected EGU in the imminent-term subcategory 
consists of just one step. The EPA is proposing that where States use 
the methodology described in section XII.D.1.a of this preamble to 
establish the baseline level of emission performance for an affected 
EGU, the emission rate described by that baseline would constitute the 
presumptively approvable standard of performance. This standard of 
performance reflects that the proposed BSER for these affected EGUs is 
routine methods of operation and maintenance and a degree of emission 
limitation equivalent to no increase in emission rate from the baseline 
level of emission performance. This also ensures that the affected EGU 
will not backslide in its emission performance.
    Although the EPA believes that the baseline performance level 
adequately accounts for variability in annual emission rate, the EPA is 
also soliciting comment on a methodology for a presumptive standard 
above the baseline emission performance. For the imminent-term coal-
fired subcategory, the EPA is soliciting comment on a presumptive 
standard that is defined by 0 to 2 standard deviations in annual 
emission rate (using the 5-year period of data) above the baseline 
emission performance, or that is 0 to 10 percent above the baseline 
emission performance.
    Because the EPA is soliciting comment on a potential BSER for this 
subcategory based on low levels of natural gas co-firing, as described 
in section X.D.3.b.ii, comment is also being solicited on the 
presumptively approvable standards for that potential BSER. The BSER is 
based on the maximum hourly heat input of natural gas fired in the unit 
(MMBtu/hr) relative to the maximum hourly heat input the

[[Page 33378]]

unit is capable of (i.e., the nameplate capacity on an MMBtu/hr basis). 
The EPA is soliciting comment on the baseline natural gas co-firing 
level being determined from the 5 years of data preceding the 
publication of the final rule, or based on engineering limitations 
(i.e., extent of startup guns or size of pipeline to unit). That 
percent of heat input results in percent reductions from the emission 
performance baseline equivalent to the percent of heat input times 0.4. 
Adjustments relative to current co-firing levels may be accounted for 
in a manner consistent with section XII.D.1.b.ii. Alternatively, the 
EPA is soliciting comment on a degree of emission limitation on a fuel 
heat input basis. For a potential BSER of low levels of natural gas co-
firing, the EPA is therefore also soliciting comment on a presumptively 
approvable standard defined on a heat input basis.
    The standard of performance for the imminent-term coal-fired 
subcategory is based on the degree of emission limitation that is 
achievable through application of the BSER to the affected EGUs in the 
subcategory and consists exclusively of the rate-based emission 
limitation. However, to qualify for inclusion in the subcategory an 
affected coal-fired EGU must have elected to commit to permanently 
cease operations prior to January 1, 2032. If a State decides to rely 
on such a commitment to place an affected EGU into the imminent-term 
coal-fired subcategory by making it an enforceable element of its State 
plan, the commitment to cease operations will become federally 
enforceable upon EPA approval of the plan.
    The EPA is also proposing that affected coal-fired steam generating 
units that have elected to commit to dates to permanently cease 
operations for subcategory applicability, including EGUs in the 
imminent-term coal-fired subcategory, have corresponding federally 
enforceable milestones with which they must comply. The EPA intends 
these milestones to assist affected EGUs in ensuring they are 
completing the necessary steps to comply with these dates in their 
State plan. These milestones are described in detail in section 
XII.D.3.b of this preamble.
    The EPA solicits comment on the proposed methodology for 
establishing presumptively approvable standards of performance for 
imminent-term coal-fired steam generating units.
iv. Near-Term Coal-Fired Steam Generating Units
    Similar to the proposed approach for establishing presumptively 
approvable standards of performance for affected EGUs in the imminent-
term coal-fired subcategory, the EPA is proposing that affected EGUs in 
the near-term coal-fired subcategory have a presumptively approvable 
standard of performance based on the baseline emission performance of 
the affected EGU (as described in section XII.D.1.a of this preamble). 
The near-term subcategory includes affected coal-fired steam generating 
units that have elected to commit to permanently cease operations after 
December 31, 2031, and before January 1, 2035, and that have elected to 
adopt an annual capacity factor limitation of 20 percent.
    The EPA is proposing that where States use the methodology 
described in section XII.D.1.a of this preamble to establish the 
baseline level of emission performance for an affected EGU, the 
emission rate described by that baseline would constitute the 
presumptively approvable standard of performance. This standard of 
performance reflects the proposed BSER of routine methods of operation 
and maintenance and a degree of emission limitation equivalent to no 
increase in emission rate. This also ensures that the affected EGU will 
not backslide in its emission performance.
    For the near-term coal-fired subcategory, the EPA is soliciting 
comment on a presumptive standard that is defined by 0 to 2 standard 
deviations in annual emission rate (using the 5-year period of data) 
above the baseline emission performance, or that is 0 to 10 percent 
above the baseline emission performance.
    Because the EPA is soliciting comment on a potential BSER for this 
subcategory based on low levels of natural gas co-firing, as described 
in section X.D.3.b.ii, comment is also being solicited on the 
presumptively approvable standards for that potential BSER. The BSER is 
based on the maximum hourly heat input of natural gas fired in the unit 
(MMBtu/hr) relative to the maximum hourly heat input the unit is 
capable of (i.e., the nameplate capacity on an MMBtu/hr basis). The EPA 
is soliciting comment on the baseline natural gas co-firing level being 
determined from the 5 years of data preceding the publication of the 
final rule, or based on engineering limitations (i.e., extent of 
startup guns or size of pipeline to unit). That percent of heat input 
results in percent reductions from the emission performance baseline 
equivalent to the percent of heat input times 0.4. Adjustments relative 
to current co-firing levels may be accounted for in a manner consistent 
with section XII.D.1.b.ii. Alternatively, the EPA is soliciting comment 
on a degree of emission limitation on a fuel heat input basis. For a 
potential BSER of low levels of natural gas co-firing, the EPA is 
therefore also soliciting comment on a presumptively approvable 
standard defined on a heat input basis.
    The standard of performance for the near-term coal-fired 
subcategory is based on the degree of emission limitation that is 
achievable through application of the BSER to the affected EGUs in the 
subcategory and consists exclusively of the rate-based emission 
limitation. However, to qualify for inclusion in the subcategory an 
affected coal-fired EGU must have elected to commit to permanently 
cease operations after December 31, 2031, and before January 1, 2035, 
and must have elected to adopt an annual capacity factor limitation of 
20 percent. If a State decides to rely on such commitments to place an 
affected EGU into the near-term coal-fired subcategory by making them 
enforceable elements of its State plan, the commitments to cease 
operations and to limit its capacity factor will become federally 
enforceable upon EPA approval of the plan.
    The EPA is also proposing that affected coal-fired EGUs that have 
elected to commit to dates to permanently cease operations for 
subcategory applicability, including EGUs in the near-term coal-fired 
subcategory, have corresponding federally enforceable milestones with 
which they must comply. The EPA intends these milestones to assist 
affected EGUs in ensuring they are completing the necessary steps to 
comply with these dates in their State plan. These milestones are 
described in detail in section XII.D.3.b of this preamble.
    The EPA solicits comment on the proposed methodology for 
establishing presumptively approvable standards of performance for 
near-term coal-fired steam generating units.
v. Natural Gas-Fired Steam Generating Units and Continental Oil-Fired 
Steam Generating Units
    This section describes the EPA's proposed methodology for 
presumptively approvable standards of performance for affected natural 
gas-fired and continental oil-fired steam generating units: low load 
natural gas-fired steam generating units, intermediate load natural 
gas- fired steam generating units, base load natural gas-fired steam 
generating units, low load oil-fired steam generating units, 
intermediate load continental oil-fired steam generating units, and 
base load continental oil-fired steam

[[Page 33379]]

generating units. It does not address non-continental intermediate oil-
fired and non-continental base load oil-fired steam generating units, 
which are described in section XII.D.1.b.vi of this preamble. The 
proposed definitions of these subcategories are discussed in section 
X.C.2 of this preamble. The proposed presumptive standards of 
performance are based on degrees of emission limitation that units are 
currently achieving, consistent with the proposed BSER of routine 
methods of operation and maintenance, which amounts to a proposed 
degree of emission limitation of no increase in emission rate.
    Unlike the approach to establishing presumptive standards of 
performance for coal-fired EGUs in these proposed emission guidelines, 
the EPA is proposing presumptive standards of performance for affected 
natural gas-fired and continental oil-fired steam generating units in 
lieu of methodologies that States would use to establish presumptive 
standards of performance. This is largely because the low variability 
in emissions data at intermediate and base load for these units and 
relatively consistent performance between these units at those load 
levels, as discussed in section X.E of this preamble and detailed in 
the Natural Gas- and Oil-fired Steam Generating Unit TSD, allows for 
the identification of a generally applicable standard of performance.
    However, for natural gas- or oil-fired steam generating units with 
low annual capacity factors, annual emission rates can be high (greater 
than 2,500 lb CO2/MWh-gross) and can vary considerably 
across units and from year to year. Despite their relatively high 
emission rates, though, overall emissions from these units are low. 
Based on these considerations, the EPA is not proposing a BSER or that 
States establish standards of performance for these units at this time. 
However, as noted above, the EPA is soliciting comment on determining a 
BSER of uniform fuels for these units. In addition, the EPA is 
soliciting comment on a presumptive standard of performance for these 
units based on heat input. Specifically, the EPA is soliciting comment 
on a range of presumptive standards of performance from 120 to 130 lb 
CO2/MMBtu for low load natural gas-fired steam generating 
units, and from 160 to 170 lb CO2/MMBtu for low load oil-
fired steam generating units.
    For intermediate load natural gas-fired units (annual capacity 
factors greater than or equal to 8 percent and less than 45 percent), 
annual emission rates are less than 1,500 lb CO2/MWh-gross 
for about 90 percent of the units. Therefore, the EPA is proposing the 
presumptive standard of performance of an annual calendar-year emission 
rate of 1,500 lb CO2/MWh-gross for these units.
    For base load natural gas-fired units (annual capacity factors 
greater than or equal to 45 percent), annual emission rates are less 
than 1,300 lb CO2/MWh-gross for about 80 percent of units. 
Therefore, the EPA is proposing the presumptive standard of performance 
of an annual calendar-year emission rate of 1,300 lb CO2/
MWh-gross for these units.
    In the continental U.S., there are few if any oil-fired steam 
generating units that operate with intermediate or high utilization. 
Liquid-oil-fired steam generating units with 24-month capacity factors 
less than 8 percent do qualify for a work practice standard in lieu of 
emission requirements under the Mercury and Air Toxics Standards rule 
(MATS) (40 CFR 63, subpart UUUUU). If oil-fired units operated at 
higher annual capacities, it is likely they would do so with 
substantial amounts of natural gas firing and have emission rates that 
are similar to steam generating units that fire only natural gas at 
those levels of utilization. There are a few natural gas-fired steam 
generating units that are near the threshold for qualifying as oil-
fired units (i.e., firing more than 15 percent oil in a given year) but 
that on average fire more than 90 percent of their heat input from 
natural gas. Therefore, the EPA is proposing the same presumptive 
standards of performance for oil-fired steam generating units as for 
natural gas-fired units, noted above.
    The EPA is also taking comment on a range of presumptive standards 
of performance for natural gas- and oil-fired steam generating units. 
Specifically, the EPA is soliciting comment on standards between (1) 
1,400 and 1,600 lb CO2/MWh-gross for intermediate load 
natural gas-fired units, (2) 1,250 and 1,400 lb CO2/MWh-
gross for base load natural gas-fired units, (3) 1,400 and 2,000 lb 
CO2/MWh-gross for intermediate load oil-fired units, and (4) 
1,250 and 1,800 lb CO2/MWh-gross for base load oil-fired 
units. The upper end of the ranges for oil-fired units is higher 
because of the limited data available for oil-fired units that operate 
at those annual capacity factors.
vi. Non-Continental Oil-Fired Steam Generating Units
    The EPA is proposing that for affected EGUs in the non-continental 
intermediate oil-fired and non-continental base load oil-fired 
subcategory, a presumptively approvable standard of performance would 
be based on baseline emission performance, consistent with the EPA's 
proposed BSER determination of routine methods of operation and 
maintenance and the proposed degree of emission limitation of no 
increase in emission rate. The EPA is proposing that where States use 
the methodology described in section XII.D.1.a of the preamble to 
establish unit-specific baseline levels of emission performance for 
affected EGUs in this subcategory, those emission rates would 
constitute presumptively approvable standards of performance when 
included in a State plan submission. This standard of performance would 
ensure no increase in the unit-specific emission rate from the baseline 
level of emission performance.
    For the intermediate and base load non-continental oil-fired 
subcategory, the EPA is soliciting comment on a presumptive standard 
that is defined by 0 to 2 standard deviations in annual emission rate 
(using the 5-year period of data) above the baseline emission 
performance, or that is 0 to 10 percent above the baseline emission 
performance.
    The EPA solicits comment on the proposed methodology for 
establishing presumptively approvable standards of performance for non-
continental oil-fired steam generating units in the intermediate and 
base load subcategories.
c. Presumptive Standards for Combustion Turbines
    As described in section XI.C, the EPA is proposing to define 
affected existing combustion turbines under these emission guidelines 
as units with a capacity greater than 300 MW and an annual capacity 
factor of greater than 50 percent. Within this set of units, the EPA is 
proposing two subcategories based on the type of fuel used: existing 
combustion turbines that adopt the pathway with a standard of 
performance based on CCS, referred to as the ``CCS subcategory'' and 
existing combustion turbines that adopt the pathway with a standard of 
performance based on hydrogen co-firing, referred to as the ``hydrogen 
co-fired subcategory.'' States, in their State plan submissions, would 
be required to assign existing combustion turbine EGUs with capacities 
greater than 300 MW and the ability to operate at an annual capacity 
factor of greater than 50 percent to one

[[Page 33380]]

subcategory or the other.\623\ States would then be required to include 
in their plans the presumptive standard of performance corresponding to 
the appropriate subcategory for each affected existing combustion 
turbine EGU. As discussed in section XII.D.2 of this preamble, States, 
in applying a standard of performance to a particular affected existing 
combustion turbine EGU, also have discretion to consider that EGU's 
remaining useful life and other factors.
---------------------------------------------------------------------------

    \623\ As explained in section XI.D of this preamble, the EPA is 
soliciting comment on, inter alia, whether to finalize both the CCS 
and hydrogen co-fired pathways for existing combustion turbines or 
whether to finalize a BSER determination with a single pathway. If 
the EPA does not finalize the proposed two-pathway approach, the 
state plan requirements for existing combustion turbines in this 
section XII of the preamble will be updated accordingly for the 
final rule.
---------------------------------------------------------------------------

    However, the EPA anticipates that some existing combustion turbine 
EGUs that are greater than 300 MW do not intend to operate at an annual 
capacity factor of greater than 50 percent starting in 2032 (the first 
proposed compliance date for affected existing combustion turbine EGUs 
under these emission guidelines). Such an EGU may elect to commit to an 
enforceable annual capacity factor limitation of less than or equal to 
50 percent. If a State elects to include such an enforceable commitment 
in its State plan, the State would not be required to have a standard 
of performance for that particular combustion turbine EGU in its plan. 
Otherwise, each affected existing combustion turbine that is greater 
than 300 MW and that has the ability to operate at an annual capacity 
factor of greater than 50 percent must have a subcategory designation 
and standard of performance in the State plan.
    The EPA is proposing that States may structure the requirements for 
affected combustion turbine EGUs in their State plans so that the 
applicable standard of performance must be met for years in which the 
unit operates above the 50 percent annual capacity factor threshold. 
States and the owners or operators of affected EGUs that have such 
contingent standards of performance would be required to ensure that an 
affected EGU has complied with its standard of performance for each 
calendar year in which it has operated at an annual capacity factor of 
greater than 50 percent. The EPA expects that if the owner or operator 
of an affected combustion turbine EGU that has a standard of 
performance believes there is a chance the EGU will operate at an 
annual capacity factor of greater than 50 percent in the upcoming 
compliance period, it will plan to meet that standard. Given this 
practical reality, the EPA is taking comment on whether it should 
require that once an affected existing combustion turbine EGU has 
exceeded the 50 percent annual capacity factor threshold and triggered 
application of its standard of performance for a given compliance 
period, that EGU must continue to meet its standard in subsequent 
compliance periods.
i. Carbon Capture and Storage Existing Combustion Turbine Generating 
Units
    This section describes the EPA's proposed methodology for 
establishing presumptively approvable standards of performance for 
existing combustion turbine EGUs that adopt the pathway with a standard 
of performance based on CCS. Affected EGUs that are assigned to this 
subcategory have a proposed BSER of CCS with 90 percent capture and a 
proposed degree of emission limitation of 90 percent capture of the 
mass of CO2 in the flue gas (i.e., the mass of 
CO2 after the turbine but before the capture equipment) over 
an extended period of time and an 89 percent reduction in emission rate 
on a gross basis over an extended period of time. The EPA is proposing 
that where States use the methodology described here to establish 
standards of performance for an affected EGU in this subcategory, those 
established standards would be presumptively approvable when included 
in a State plan submission.
    Establishing a standard of performance for an affected combustion 
turbine EGU in this subcategory consists of two steps: establishing a 
source-specific level of baseline emission performance (as described 
above); and applying the level of stringency, based on the application 
of the BSER, to that level of baseline emission performance. 
Implementation of CCS with a capture rate of 90 precent translates to a 
level of stringency of an 89 percent reduction in CO2 
emission rate (see section XI.C of this preamble) compared to the 
baseline level of emission performance. Using the complement of 89 
percent (i.e., 11 percent) and multiplying it by the baseline level of 
emission performance results in the presumptively approvable standard 
of performance. For example, if a combustion turbine EGU in this 
subcategory has a baseline level of emission performance of 1,000 lbs 
per MWh, it will have a presumptively approvable standard of 
performance of 110 lbs per MWh (1,000 lbs per MWh multiplied by 0.11).
    The EPA is also proposing that affected combustion turbines in this 
subcategory comply with federally enforceable increments of progress, 
which are described in section XII.D.3.a of this preamble.
    The EPA solicits comments on this proposed methodology for 
calculating presumptively approvable standards of performance for 
existing combustion turbines in the CCS subcategory.
ii. Hydrogen Co-Fired Existing Combustion Turbine Generating Units
    This section describes the EPA's proposed methodology for 
establishing presumptively approvable standards of performance for 
existing combustion turbines that adopt the pathway with a standard of 
performance based on hydrogen co-firing. Affected combustion turbine 
EGUs in this subcategory have a proposed BSER of hydrogen co-firing 
with two phases of stringency. In the first phase, affected EGUs in 
this subcategory co-fire hydrogen at a level of 30 percent by volume 
with a proposed degree of emission limitation of 12 percent reduction 
in emission rate on a gross basis over an extended period of time. In 
the second phase, affected EGUs in this subcategory co-fire hydrogen at 
a level of 96 percent by volume with a proposed degree of emission 
limitation of 88.4 percent reduction in emission rate on a gross basis 
over an extended period of time. As described in section XII.B, 
compliance with the first phase commences on January 1, 2032, and 
compliance with the second phase commences on January 1, 2038. The EPA 
is proposing that where States use the methodology described here to 
establish standards of performance for this subcategory, those 
established standards of performance would be presumptively approvable 
when included in a State plan submission.
    Establishing a standard of performance for an affected EGU in this 
subcategory consists of three steps: first, establishing a source-
specific level of baseline emission performance (as described earlier 
in this preamble); and second, applying the level of emission reduction 
stringency for the first phase, based on the application of the first 
phase BSER, to that level of baseline emission performance; and third, 
applying the level of emission reduction stringency for the second 
phase, based on the application of the second phase BSER, to that level 
of baseline emission performance.
    Implementation of hydrogen co-firing at a level of 30 percent by 
volume translates to a level of stringency of a 12 percent reduction in 
CO2 emissions (see

[[Page 33381]]

section XI.C of this preamble) compared to the baseline level of 
emission performance. Using the complement of 12 percent (i.e., 88 
percent) and multiplying it by the baseline level of emission 
performance results in the presumptively approvable standard of 
performance for the affected EGU. For example, if a combustion turbine 
EGU that co-fires 30 percent hydrogen (by volume) has a baseline level 
of emission performance of 1,000 lbs per MWh, it will have a 
presumptively approvable standard of performance of 880 lbs per MWh 
(1,000 lbs per MWh multiplied by 0.88) for the first phase.
    Implementation of hydrogen co-firing at a level of 96 percent by 
volume translates to a level of stringency of an 88.4 percent reduction 
in CO2 emissions (see section XI.C of this preamble) 
compared to the baseline level of emission performance. Using the 
complement of 88.4 percent (i.e., 11.6 percent) and multiplying it by 
the baseline level of emission performance results in the presumptively 
approvable standard of performance for the affected EGU. For example, 
if a combustion turbine EGU that co-fires 96 percent hydrogen (by 
volume) has a baseline level of emission performance of 1,000 lbs per 
MWh, it will have a presumptively approvable standard of performance of 
116 lbs per MWh (1,000 lbs per MWh multiplied by 0.116) for the second 
phase.
    The EPA is proposing that affected combustion turbine EGUs in this 
subcategory that meet their standards of performance using hydrogen co-
firing must co-fire with low-GHG hydrogen. States must make this an 
enforceable part of their State plans, as described in further detail 
in section XII.F.1.b.i.
    The EPA is also proposing that affected combustion turbines in this 
subcategory comply with federally enforceable increments of progress, 
which are described in section XII.D.3.a of this preamble.
    The EPA solicits comment on the proposed methodology for 
calculating presumptively approvable standards of performance for 
existing combustion turbine EGUs in the hydrogen co-fired subcategory.
2. Remaining Useful Life and Other Factors
    Under CAA section 111(d), the EPA is required to promulgate 
regulations under which States submit plans applying standards of 
performance to affected EGUs. While States establish the standards of 
performance, there is a fundamental obligation under CAA section 111(d) 
that such standards reflect the degree of emission limitation 
achievable through the application of the BSER, as determined by the 
EPA.\624\ The EPA identifies this degree of emission limitation as part 
of its emission guideline. 40 CFR 60.22a(b)(5). Thus, as described in 
section X.D of this preamble, the EPA is providing proposed 
methodologies for States to follow in determining and applying 
presumptively approvable standards of performance to affected EGUs in 
each of the subcategories covered by these emission guidelines.
---------------------------------------------------------------------------

    \624\ West Virginia v. EPA, 142 S. Ct. 2587, 2607 (2022) (``In 
devising emissions limits for power plants, EPA first `determines' 
the `best system of emission reduction' that--taking into account 
cost, health, and other factors--it finds `has been adequately 
demonstrated.' The Agency then quantifies `the degree of emission 
limitation achievable' if that best system were applied to the 
covered source.'') (internal citations omitted).
---------------------------------------------------------------------------

    While standards of performance must generally reflect the degree of 
emission limitation achievable through application of the BSER as 
determined by the EPA, CAA section 111(d)(1) also requires that the EPA 
regulations permit the States, in applying a standard of performance to 
a particular designated facility, to ``take into consideration, among 
other factors, the remaining useful life of the existing sources to 
which the standard applies.'' The EPA's implementing regulations under 
40 CFR 60.24a thus allow a State to consider a particular designated 
facility's remaining useful life and other factors in applying to that 
facility a standard of performance that is less stringent than the 
presumptive level of stringency given in an emission guideline.
    In December 2022, the EPA proposed to clarify the existing 
requirements in subpart Ba governing what a State must demonstrate in 
order to invoke RULOF and provide a less stringent standard of 
performance when submitting a State plan.\625\ Specifically, the EPA 
proposed to require the State to demonstrate that a particular facility 
cannot reasonably achieve the degree of emission limitation achievable 
through application of the BSER based on one or more of three 
delineated circumstances, and proposed to clarify those three 
circumstances. The EPA also proposed additions and further 
clarifications to the process of invoking RULOF and determining a 
standard of performance based on RULOF, to ensure that use of the 
provision does not undermine the overall presumptive level of 
stringency of the BSER, as well as to provide a clear analytical 
framework for States and the regulated community as they seek to craft 
satisfactory plans that the EPA can ultimately approve.\626\
---------------------------------------------------------------------------

    \625\ 87 FR 79176, 79196-79206 (December 23, 2022).
    \626\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002.
---------------------------------------------------------------------------

    The EPA is not soliciting comment in this rulemaking on the 
proposed revisions to the RULOF provisions in subpart Ba, which are 
subject to a separate rulemaking process. As noted in section XII.A of 
this preamble, the EPA intends to finalize revisions to subpart Ba 
prior to finalizing these emission guidelines. Those revised RULOF 
provisions, including any changes made in response to public comments, 
will apply to these emission guidelines. While the EPA is not taking 
comment on the proposed provisions of subpart Ba themselves, the EPA is 
requesting comment on how each of the RULOF provisions that the EPA 
proposed in December 2022 would be implemented in the context of these 
particular emission guidelines.
    The remainder of this section of the preamble addresses how the 
requirements associated with RULOF, as the EPA has proposed to revise 
them, would apply to States and State plans under these emission 
guidelines. First, it addresses the threshold requirements for 
considering RULOF and how those requirements would apply to an affected 
EGU under these emission guidelines. Second, it addresses how, if a 
State has appropriately invoked RULOF for a particular affected EGU 
under the previous step, it would be required to determine a source-
specific BSER and calculate a standard of performance for that affected 
EGU. Third, it discusses the proposed requirement for plans that apply 
less stringent standards of performance pursuant to RULOF to consider 
the potential pollution impacts and benefits of control to communities 
most affected by and vulnerable to emissions from the affected EGU. 
Fourth, this section addresses the proposed provisions for the standard 
for EPA review of State plans that include RULOF standards of 
performance. And, finally, it discusses the EPA's proposed 
interpretation of the Clean Air Act as laid out in the proposed 
revisions to subpart Ba that the Act allows states to adopt and enforce 
standards of performance more stringent than required by an applicable 
emission guideline, and that the EPA has the ability and authority to 
approve such standards of performance into State plans.
a. Threshold Requirements for Considering RULOF
    As discussed earlier in this preamble, CAA section 111(d)(1) 
expressly

[[Page 33382]]

requires the EPA to permit states to consider RULOF when applying a 
standard of performance to a particular affected EGU. The EPA's 
proposed revisions to the regulations governing states' use of RULOF 
would provide a clear analytical framework to ensure that its use to 
apply less stringent standards of performance for particular sources is 
consistent across states. The proposed revisions would also ensure that 
the use of RULOF does not undermine the overall presumptive level of 
stringency and the emission reduction benefits of an emission 
guideline, or undermine and render meaningless the EPA's BSER 
determination. Such a result would be contrary to the overarching 
purpose of CAA section 111(d), which is generally to achieve meaningful 
emission reductions from designated facilities, in this case affected 
EGUs, based on the BSER in order to mitigate pollution that endangers 
public health and welfare.
    To this end, proposed subpart Ba would provide that a State may 
apply a less stringent standard of performance to a particular 
facility, taking into consideration remaining useful life and other 
factors, provided that the State demonstrates with respect to that 
facility (or class of facilities) that it cannot reasonably apply the 
BSER to achieve the degree of emission limitation determined by the 
EPA. Invocation of RULOF would be required to be based on one or more 
of three circumstances: (1) Unreasonable cost of control resulting from 
plant age, location, or basic process design, (2) physical 
impossibility or technical infeasibility of installing necessary 
control equipment, or (3) other circumstances specific to the facility 
that are fundamentally different from the information considered in the 
determination of the BSER in the emission guidelines.\627\
---------------------------------------------------------------------------

    \627\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (containing proposed revisions to RULOF provisions at 
40 CFR 60.24a(e)-(n)).
---------------------------------------------------------------------------

    A State wishing to invoke RULOF in order to apply a less stringent 
standard to a particular affected EGU would be required to demonstrate 
that there are fundamental differences between that EGU and the EPA's 
BSER determination, based on consideration of the BSER factors that the 
EPA considered in its analysis. In determining the BSER and the degree 
of emission reductions achievable through application of the BSER in 
these proposed emission guidelines, the EPA considered whether a system 
of emission reduction is adequately demonstrated for the subcategory 
based on the physical possibility and technical feasibility of applying 
that system, the costs of a system of emission reduction, the non-air 
quality health and environmental impacts and energy requirements 
associated with a system of emission reduction, and the extent of 
emission reductions from a system.\628\
---------------------------------------------------------------------------

    \628\ The EPA also considered impacts on the energy sector as 
part of its BSER determinations. However, because this consideration 
does not apply at the level of a particular affected EGU, it would 
not be appropriate basis for invoking RULOF.
---------------------------------------------------------------------------

    For each subcategory, the EPA evaluated certain metrics related to 
each of these BSER factors. For example,\629\ in evaluating the costs 
associated with CCS and natural gas co-firing for existing coal-fired 
steam generating units, the EPA considered both $/ton CO2 
reduced and increases in levelized costs expressed as dollars per MWh 
electricity generation. A State wishing to invoke RULOF for a 
particular affected EGU in the long-term coal-fired subcategory based 
on unreasonable cost of control would also be required to consider the 
cost as $/ton of CO2 reduced and $/MWh electricity 
generated. The State would further have to demonstrate that the costs, 
as represented by these two metrics, for the particular affected EGU 
are fundamentally different, i.e., significantly higher, than costs the 
EPA determines to be reasonable due to that EGU's age, location, or 
basic process design.
---------------------------------------------------------------------------

    \629\ The examples are only for illustrative purposes and should 
not be interpreted to represent the difference that must exist to 
demonstrate a fundamental difference between the EPA's BSER 
determination and a particular affected EGU's circumstances.
---------------------------------------------------------------------------

    The RULOF provision, currently and as the EPA has proposed to 
revise it, also allows states to invoke RULOF based on other 
circumstances specific to an affected EGU. As an illustrative example, 
a State may wish to invoke RULOF for a medium-term coal-fired steam 
generating unit that is extremely isolated (e.g., on a small island 
more than 200 miles offshore) such that it would require construction 
of an LNG terminal and shipping of LNG by barge to have natural gas 
available to fire at the unit. In the EPA's evaluation of natural gas 
co-firing as the potential BSER for medium-term coal-fired steam 
generating units, the EPA considered the distance and cost of lateral 
pipeline builds in proposing natural gas co-firing as BSER. If a State 
can demonstrate that something unique to the source's being on a remote 
island--something that the EPA did not consider in evaluating the 
BSER--results in the affected EGU not being able to reasonably achieve 
the standard of performance, then it may be reasonable to invoke RULOF 
for that source.
    Under the EPA's proposed approach, states would not be able to 
invoke RULOF based on minor, non-fundamental differences between a 
particular affected EGU and what the EPA determined was reasonable for 
the BSER. There could be instances in which an affected EGU may not be 
able to implement the presumptively approvable standard of performance 
in accordance with the precise metrics (e.g., at exactly the same $/ton 
CO2 reduced or exactly the same distance from a pipeline 
connection) of the BSER determination but is able to do so within a 
reasonable margin. In such instances, it would not be reasonable for a 
State to apply a less stringent standard of performance.
    Many of the factors the EPA considers in its BSER determination, 
and therefore many of the factors states might consider in determining 
whether to invoke RULOF for any particular source, are reflected in the 
cost consideration. As noted previously in this section, the EPA is 
providing a range of cost evaluations for CCS and natural gas co-firing 
based on different assumptions regarding amortization period and 
capacity factor. For example, the EPA is proposing to determine that 
the cost of CCS for long-term coal-fired steam generating units is 
reasonable based on the following calculations: for a reference unit 
with a 12-year amortization period and 50 percent capacity factor the 
cost is $14/ton CO2 reduced or $12/MWh, and that the average 
cost for the fleet under the same assumptions is $8/ton CO2 
or $7/MWh. For natural gas co-firing for medium-term coal-fired steam 
generating units, the EPA is proposing to find the following costs are 
reasonable: for a reference unit with a 50 percent capacity factor and 
an amortization period ranging from 6 to 10 years, a cost of $53-$66/
ton CO2 or $9-$12/MWh. The average cost for the fleet under 
the same assumptions is $64-$78/ton CO2 or $11-$14/MWh.
    Any costs associated with any BSER for affected EGUs that the EPA 
determines are reasonable under these emission guidelines cannot be a 
basis for invoking RULOF. Additionally, costs that are not 
fundamentally different from costs that the EPA has determined are or 
could be reasonable for sources cannot be a basis for invoking RULOF. 
Thus, costs that are not fundamentally different from, e.g., $29/MWh 
(the cost for installation of wet-FGD on a 300 MW coal-fired steam 
generating unit, used for cost comparison in section X.D.1.a.ii

[[Page 33383]]

of this preamble and detailed in section VII.F.3.b.iii(B)(5) of this 
preamble) are not a basis for invoking RULOF under these emission 
guidelines. On the other hand, costs that constitute outliers, e.g., 
that are greater than the 95th percentile of costs on a fleetwide basis 
(assuming a normal distribution) or that are the same as costs the EPA 
has determined are unreasonable elsewhere under these emission 
guidelines would likely represent a valid demonstration of a 
fundamental difference and could be the basis of invoking RULOF.
    Importantly, the costs evaluated in the BSER determination are, in 
general, for representative, average units or are based on average 
values across the fleet of steam generating units. Those BSER cost 
analysis values represent the average of a distribution of costs 
including costs that are above or below the average representative 
value. On that basis, implicit in the proposed determination that those 
average representative values are reasonable is a proposed 
determination that a significant portion of the unit-specific costs 
around those average representative values are also reasonable, 
including some portion of those unit-specific costs that are above but 
not significantly different than the average representative values.
    Another example of a fundamental difference between the EPA's BSER 
determination and a particular affected EGU's circumstances could be a 
difference based on physical impossibility or technical infeasibility. 
In making BSER determinations, the EPA must find that a system is 
adequately demonstrated; among other things, this means that the BSER 
must be technically feasible for the source category. For long-term 
coal-fired steam generating units and combustion turbine EGUs in the 
CCS subcategory, the EPA determined that CCS is adequately demonstrated 
because its components can be and have been applied to the source 
category and because it is generally geographically available to 
affected EGUs. However, it may be possible that a particular affected 
EGU is physically unable to implement CCS due to, e.g., the 
impossibility of constructing a pipeline or establishing other means 
for CO2 transport. If a State can demonstrate that it is 
physically impossible or technically infeasible for this affected EGU 
to apply CCS because there are no other options to transport captured 
CO2, there is a fundamental difference between the EPA's 
BSER determination and the circumstances of this particular affected 
EGU and the State may invoke RULOF.
    The EPA has proposed under 40 CFR part 60, subpart Ba that states 
may invoke RULOF if they can demonstrate that a source cannot apply the 
BSER to achieve the degree of emission limitation determined by the EPA 
based on one or more of the three circumstances discussed earlier in 
this preamble.\630\ It thus follows that states would be able to invoke 
RULOF under these emission guidelines if they can demonstrate that an 
affected EGU can apply the BSER but cannot achieve the degree of 
emission limitation that the EPA determined is possible for the source 
category generally.
---------------------------------------------------------------------------

    \630\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(e)).
---------------------------------------------------------------------------

    However, the EPA has also proposed in subpart Ba \631\ that a State 
may not invoke RULOF to provide a less stringent standard of 
performance for a particular source if that source cannot apply the 
BSER but can reasonably implement a different system of emission 
reduction to achieve the degree of emission limitation required by the 
EPA's BSER determination. While a State may be able to demonstrate that 
the source cannot reasonably apply the BSER based on one of the three 
circumstances, it would be inappropriate to invoke RULOF to apply a 
less stringent standard of performance because the source can still 
reasonably achieve the presumptive degree of emission limitation. In 
this instance, providing a less stringent standard of performance would 
be inconsistent with the purpose of CAA section 111(d) and these 
emission guidelines.
---------------------------------------------------------------------------

    \631\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(g)).
---------------------------------------------------------------------------

    States' consideration of the remaining useful life of a particular 
source for affected coal-fired EGUs, in particular, will also be 
informed by the structure of the EPA's proposed subcategories, each of 
which has its own BSER determination under these emission guidelines. 
Under CAA section 111(d)(1) and the EPA's proposed RULOF provisions, 
states may consider an affected EGU's remaining useful life in 
determining whether application of the BSER to achieve the presumptive 
level of stringency would result in unreasonable cost resulting from 
plant age.\632\ In determining the BSER, the EPA considers costs and, 
in many instances, specifically considers annualized costs associated 
with payment of the total capital investment of the technology 
associated with the BSER. However, plant age can have considerable 
variability within a source category and the annualized costs can 
change significantly based on an affected EGU's remaining useful life 
and associated length of the capital recovery period. Thus, the costs 
of applying the BSER to an affected EGU with a short remaining life may 
differ fundamentally from the costs that the EPA found were reasonable 
in making its BSER determination.
---------------------------------------------------------------------------

    \632\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(e)(1)).
---------------------------------------------------------------------------

    As explained in section X of this preamble, these proposed emission 
guidelines include BSER determinations and presumptive standards of 
performance for affected coal-fired EGUs in four subcategories: 
imminent-term, near-term, medium-term, and long-term. Owing to the 
basis of these subcategories, the EPA's proposed BSER determinations 
for each of these subcategories already consider costs amortized 
consistent with the operating horizons of sources within each 
subcategory. The EPA therefore does not anticipate that states would be 
likely to demonstrate the need to invoke RULOF based on a particular 
coal-fired EGU's remaining useful life, although doing so is not 
prohibited under these emission guidelines. The proposed requirements 
for states and affected EGUs invoking RULOF based on remaining useful 
life are addressed in the next subsection.
    Conversely, the proposed subcategories for existing combustion 
turbines do not consider affected EGUs' operating horizons. The useful 
life of a combined cycle unit is approximately 25 to 30 years.\633\ 
More than 151 GW of combined cycle units came on-line in the 2000 to 
2010 timeframe,\634\ meaning that many of these units could potentially 
be at or nearing the end of their remaining useful lives in the 2035 to 
2040 timeframe. If an affected combustion turbine EGU has decided to 
cease operations and elects to make that cessation enforceable, the 
period over which controls would be amortized, depending on what that 
period of time is, may be short enough to invoke RULOF based on 
unreasonable cost of control.
---------------------------------------------------------------------------

    \633\ https://sargentlundy.com/wp-content/uploads/2017/05/Combined-Cycle-PowerPlant-LifeAssessment.pdf.
    \634\ U.S. Environmental Protection Agency. National Electric 
Energy Data System (NEEDS) v6. October 2022. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs-v6.
---------------------------------------------------------------------------

    The EPA is proposing to allow states to use the RULOF mechanism to 
provide a different compliance deadline for a source that can meet the 
presumptive standard of performance

[[Page 33384]]

for the applicable subcategory but cannot do so by the final compliance 
date under these emission guidelines. In such cases, a State may be 
able to demonstrate that there are ``other circumstances specific to 
the facility . . . that are fundamentally different from the 
information considered in the determination of the best system of 
emission reduction in the emission guidelines'' \635\ that make timely 
compliance impossible. However, given the relatively long lead times 
and compliance timeframes proposed in these emission guidelines, the 
EPA anticipates that these circumstances will be rare. Under the 
proposed revisions to subpart Ba, RULOF demonstrations, including those 
in support of extending a compliance deadline, would have to be based 
on information from reliable and adequately documented sources and be 
applicable to and appropriate for the affected facility.\636\
---------------------------------------------------------------------------

    \635\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(e)(3)).
    \636\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(j)).
---------------------------------------------------------------------------

    Additionally, as discussed in section XII.D.1.a of this preamble, 
the EPA is proposing a methodology for calculating an affected EGU's 
baseline emissions as part of determining its presumptively approvable 
standard of performance. The EPA explained that while the proposed 
methodology should be flexible enough to accommodate most unit-specific 
circumstances, it may not be appropriate to use recent historical 
emissions data to represent baseline emission performance when an 
affected EGU anticipates that its future operating conditions will 
change significantly. Consistent with the proposed subpart Ba, the EPA 
is proposing that states wishing to rely on an affected EGU's 
anticipated change in operating conditions as the basis for using a 
different methodology to set an emissions baseline would be required to 
use the RULOF mechanism described in this section of the preamble.
    The EPA solicits comment on the application of the RULOF provisions 
of proposed subpart Ba, both in sum and as individual, segregable 
pieces, to these emission guidelines. In particular, the EPA requests 
comment on factual circumstances in which it may or may not be 
appropriate for states to invoke RULOF for affected EGUs, given the 
proposed BSER determinations and presumptive standards of performance, 
and the EPA's proposed ``fundamental difference'' standard in the 
subpart Ba rulemaking. For the consideration of cost, the EPA requests 
comment on whether it should provide further guidance or requirements 
for determining when the costs of a control technology for a particular 
source are ``fundamentally different'' from the Agency's BSER 
determination and thus a basis for invoking RULOF. The EPA additionally 
seeks comment on any source category-specific considerations for 
invoking RULOF for affected EGUs, including any additional or different 
requirements that might be necessary to ensure that use of RULOF does 
not undermine the presumptive stringency of these emission guidelines.
b. Calculation of a Standard That Accounts for RULOF
    Subpart Ba, both the presently applicable requirements and as the 
EPA has proposed to revise them, provides that, if a State has 
demonstrated that accounting for RULOF is appropriate for a particular 
affected EGU, the State may then apply a less stringent standard to 
that EGU. The EPA's proposed revisions to subpart Ba would require 
that, in doing so, the State must determine a source-specific BSER by 
identifying all the systems of emission reduction available for the 
source and evaluating each system using the same factors and evaluation 
metrics that the EPA considered in determining the BSER for the 
applicable subcategory.\637\ As part of determining source-specific 
BSER, the State would also have to determine the degree of emission 
limitation that can be achieved by applying this source-specific BSER 
to the particular source. The State would then calculate and apply the 
standard of performance that reflects this degree of emission 
limitation.\638\
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    \637\ To the extent that a state seeks to apply RULOF to a class 
of affected EGUs that the state can demonstrate are similarly 
situated in all meaningful ways, the EPA proposes to permit the 
state to conduct an aggregate analysis of the BSER factors for the 
entire class of EGUs for which RULOF has been invoked.
    \638\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(f)).
---------------------------------------------------------------------------

    Consistent with these proposed requirements in subpart Ba, the EPA 
is proposing that states invoking RULOF would be required to evaluate 
certain controls as appropriate for subcategories of affected EGUs. The 
EPA believes these proposed requirements are necessary to ensure that 
states reasonably consider the controls that may qualify as the best 
system of emission reduction. Additionally, the EPA is proposing to 
provide the order in which states must evaluate controls. A list of 
controls, ordered from more to less stringent, can provide useful 
streamlining as states may reasonably choose to conduct a less in-depth 
evaluation of controls further down the list if they determine a more 
stringent control is the best system of emission reduction for a 
particular source. The EPA also believes that providing a list of 
controls for evaluation will provide states with clarity and certainty 
about what the Agency will find is a satisfactory source-specific BSER 
analysis pursuant to the RULOF mechanism. However, the EPA is also 
requesting comment on whether to provide lists of controls to be 
evaluated in a source-specific BSER analysis as a presumptively 
approvable approach, as opposed to requirements. Regardless of how the 
EPA finalizes the approach to controls for source-specific analyses, 
states would retain discretion to evaluate additional types of controls 
as part of a source-specific BSER determination for sources pursuant to 
RULOF.
    The EPA is proposing to require states invoking RULOF for affected 
coal-fired EGUs in the long-term subcategory to evaluate natural gas 
co-firing as a potential source-specific BSER. Additionally, if an EGU 
in the long-term subcategory can implement CCS but cannot achieve the 
degree of emission limitation prescribed by the presumptive standard of 
performance, the EPA is proposing that the State evaluate CCS with a 
source-specific degree of emission limitation as a potential BSER. The 
EPA is also proposing that states invoking RULOF for affected long-term 
and medium-term coal-fired EGUs must evaluate different levels of 
natural gas co-firing. For example, for a source in the medium-term 
subcategory that cannot reasonably co-fire 40 percent natural gas, the 
State must then evaluate lower levels of natural gas co-firing unless 
it has demonstrated that natural gas co-firing at any level is 
physically impossible or technically infeasible at the source. 
Similarly, if a State invoking RULOF for an affected EGU in the long-
term subcategory demonstrates that the EGU cannot co-fire with natural 
gas at 40 percent, the EPA is proposing that the State must then 
evaluate lower levels of co-firing as potential BSERs for the source, 
unless the State can demonstrate that it is physically impossible or 
technically infeasible for the source to co-fire natural gas. States 
may also consider additional potential source-specific BSERs for 
affected EGUs in either subcategory.
    For states invoking RULOF for affected existing combustion turbine 
EGUs, the EPA is similarly proposing a requirement to evaluate certain 
control

[[Page 33385]]

strategies as part of a source-specific BSER analysis. As a preliminary 
step, for sources in either the CCS combustion turbine subcategory or 
the hydrogen co-fired combustion turbine subcategory, the EPA is 
proposing that a State would first have to demonstrate why the affected 
EGU cannot reasonably participate in the other subcategory and meet 
that other subcategory's presumptive standard of performance. If a unit 
can reasonably comply with the presumptive standard of performance for 
the alternate source category, it must do so.
    For combustion turbines in the CCS subcategory that cannot 
reasonably comply with the presumptive standards of performance for 
either that subcategory or the hydrogen co-fired subcategory, the EPA 
is proposing that, unless a State has demonstrated that it is 
physically impossible or technically infeasible for a unit to implement 
CCS, the State must evaluate CCS with lower rates of carbon capture as 
a potential BSER. If CCS with lower rates of capture is not the BSER, 
the State would then be required to consider comprehensive turbine 
upgrades, and finally smaller scale efficiency improvements. For 
hydrogen co-fired combustion turbines that cannot reasonably comply 
with the presumptive standards of performance for either subcategory, a 
State would first analyze lower percentages of hydrogen co-firing, 
followed by comprehensive turbine upgrades, and lastly smaller scale 
efficiency improvements. States would also be free to analyze 
additional potential source-specific BSERs for affected combustion 
turbine EGUs in either subcategory.
    The EPA requests comment on the proposed requirement to consider 
certain control technologies as part of source-specific BSER 
determinations, and specifically on whether the Agency should require 
this approach as proposed or, in the alternative, provide it as a 
presumptively approvable approach to conducting a source-specific BSER 
analysis.
    The EPA notes again that, under both the proposed subpart Ba and 
CAA section 111(d),\639\ an affected EGU that cannot reasonably apply 
the EPA's BSER but can achieve the degree of emission limitation for 
the applicable subcategory through other reasonable systems of emission 
reduction cannot be given a less stringent standard of performance. In 
this case, the affected EGU's standard of performance would still 
reflect the degree of emission limitation achievable through 
application of the EPA's BSER.
---------------------------------------------------------------------------

    \639\ As discussed earlier in this preamble, permitting a state 
to apply a less stringent standard to an affected EGU that can 
achieve the degree of emission limitation the EPA determined is 
required would be inconsistent with CAA section 111(d). See also 87 
FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-
0002 (proposed revisions to RULOF provisions at 40 CFR 60.24a(g)).
---------------------------------------------------------------------------

    The EPA has proposed in its revisions to subpart Ba that specific 
requirements would apply when invoking RULOF based on an affected 
source's remaining useful life.\640\ Among other requirements, the EPA 
in an emission guideline would have to either identify the outermost 
date to cease operations for the relevant source category that 
qualifies for consideration of remaining useful life or provide a 
methodology and considerations for states to use in establishing such 
an outermost date. Proposed subpart Ba also provides that an affected 
source with a date to cease operations that is both imminent and prior 
to the outermost date could be eligible for a standard of performance 
that reflects that source's BAU. The EPA is proposing to supersede the 
application of subpart Ba for coal-fired steam generating units with 
respect to the proposed requirements to establish outermost and 
imminent dates to cease operations for invoking RULOF based on an 
affected EGU's remaining useful life. As explained earlier in this 
section of the preamble, the EPA has designed the subcategories for 
coal-fired affected EGUs under these emission guidelines to accommodate 
sources' self-identified operating horizons. This approach to 
subcategorization obviates the need to establish an outermost date to 
cease operations to guide states' and affected EGUs' consideration of 
remaining useful life. Additionally, the EPA is proposing to establish 
an imminent-term subcategory with a proposed BSER determination of 
routine operation and maintenance, which serves the same purpose as 
establishing an imminent date to cease operations under the RULOF 
provision. Although it is not anticipated that states will have a 
reason to invoke RULOF due to a coal-fired EGU's imminent date to cease 
operations based on the structure of the subcategories under these 
emission guidelines, states are not precluded from doing so based on 
unit-specific circumstances.
---------------------------------------------------------------------------

    \640\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(h), (i)).
---------------------------------------------------------------------------

    Because of the small number of sources in the oil- and natural gas-
fired steam generating unit subcategories and the diversity of 
circumstances in which they operate, the EPA is not proposing to 
establish outermost or imminent dates to cease operations for the 
purpose of considering remaining useful life for these sources. 
Regardless, because the proposed BSER determinations for these EGUs is 
routine methods of operation and maintenance (other than for low-load 
oil- and natural gas-fired steam generating units), the EPA does not 
anticipate that states will find it necessary to invoke RULOF for these 
sources.
    The EPA is also proposing to supersede the requirement in subpart 
Ba to establish imminent and outermost dates for the consideration of 
remaining useful life for affected combustion turbine EGUs. While, as 
discussed above in this section of the preamble, it is likely that some 
portion of the existing combustion turbine fleet will be reaching the 
end of its remaining useful life in the 2035 to 2040 timeframe, the 
structure of the proposed subcategories, the length of time between 
State plan submission and the compliance dates for the subcategories, 
and the staggered compliance dates for the two subcategories make it 
difficult to set a widely-applicable date or dates that represent an 
imminent cessation of operations. States would not be precluded from 
demonstrating that an affected combustion turbine EGU's remaining 
useful life is so short that it qualifies for a business-as-usual 
standard of performance (i.e., that its remaining useful life is so 
short that the cost of any control would be unreasonably high). 
Similarly, based on the proposed BSERs for the subcategories and the 
staggered nature of the proposed compliance dates for combustion 
turbine EGUs, the EPA does not believe it is helpful to set an 
outermost date for the considering of remaining useful life for these 
units. The EPA requests comment on its proposal to supersede the 
requirements in subpart Ba to set imminent and outermost dates for the 
consideration of remaining useful life for affected combustion turbine 
EGUs. If commenters believe such dates would be useful to guide states' 
consideration of remaining useful life for affected existing combustion 
turbines, the EPA further requests input on what those dates could be, 
and why.
    The proposed subpart Ba would require that any plan that applies a 
less stringent standard to a particular affected EGU based on remaining 
useful life must include the date by which the EGU commits to 
permanently cease operations as an enforceable

[[Page 33386]]

requirement.\641\ The plan would also have to include measures that 
provide for the implementation and enforcement of such a commitment. 
The EPA is not proposing to supersede this proposed requirement for the 
purpose of this emission guideline; states that include a RULOF 
standard based on an affected EGU's remaining useful life must make the 
source's voluntary commitment to permanently cease operations by a date 
certain enforceable in the State plan.
---------------------------------------------------------------------------

    \641\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(h), (i)(3)).
---------------------------------------------------------------------------

    Similarly, subpart Ba would require that if a State seeks to rely 
on a source's operating conditions, such as its restricted capacity, as 
the basis for invoking RULOF and setting a less stringent standard, the 
State plan must include that operating condition as an enforceable 
requirement.\642\ This requirement would apply to operating conditions 
that are within an affected EGU's control and is necessary to ensure 
that a source's standard of performance matches what that source can 
reasonably achieve and does not undermine the stringency of these 
emission guidelines.
---------------------------------------------------------------------------

    \642\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(h)).
---------------------------------------------------------------------------

    The proposed presumptively approvable standards of performance for 
affected EGUs in these emission guidelines are expressed in the form of 
rate-based emission limitations, specifically, as lb CO2/
MWh. Therefore, to ensure transparency and to enable the EPA, states, 
and stakeholders to ensure that RULOF standards do not undermine the 
presumptive stringency of these emission guidelines, the EPA is 
proposing to require that standards of performance determined through 
this RULOF mechanism be in the same form of rate-based emission 
limitations.\643\
---------------------------------------------------------------------------

    \643\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(f)(3)).
---------------------------------------------------------------------------

    The EPA seeks comment on implementation of the proposed subpart Ba 
requirements pertaining to determining a source-specific BSER and 
calculating a less stringent standard for sources invoking RULOF under 
these emission guidelines. It also seeks comment on the proposed 
requirements that are specific to these emission guidelines, including 
but not limited to the proposed requirement that states evaluate 
certain control options for affected coal-fired steam generating units 
in the long-term and medium-term subcategories and for affected 
combustion turbine EGUs as part of their source-specific BSER 
determination, the proposal to not provide outermost or imminent dates 
to cease operations for the consideration of remaining useful life, and 
the proposal to require RULOF standards of performance to be in the 
form of lb CO2/MWh emission limitations.
c. Consideration of Impacted Communities
    While the consideration of RULOF may warrant application of a less 
stringent standard of performance to a particular affected EGU, such 
standards have the potential to result in disparate health and 
environmental impacts to communities most affected by and vulnerable to 
impacts from those EGUs. Those communities could be put in the position 
of bearing the brunt of the greater health and environmental impacts 
resulting from an affected EGU implementing a less stringent standard 
of performance than would otherwise have been required pursuant to the 
emission guidelines. A lack of consideration of such potential outcomes 
would be antithetical to the public health and welfare goals of CAA 
section 111(d).
    Therefore, the proposed subpart Ba revisions would require that 
states applying less stringent standards of performance consider the 
potential pollution impacts and benefits of control to communities most 
affected by and vulnerable to emissions from the affected EGU in 
determining source-specific BSERs and the degree of emission limitation 
achievable through application of such BSERs.\644\ The State will have 
identified these communities as pertinent stakeholders in the process 
of meaningful engagement, which is discussed in section XII.F.1.b of 
this preamble.
---------------------------------------------------------------------------

    \644\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(k)).
---------------------------------------------------------------------------

    If the EPA finalizes the requirement under subpart Ba to consider 
the potential pollution impacts and benefits of control to the 
communities most affected by and vulnerable to emissions from a RULOF 
source communities as proposed, State plan submissions under these 
emission guidelines would have to demonstrate that the State considered 
such impacts and benefits in applying a less stringent standard of 
performance to such a source. The EPA expects that states' meaningful 
engagement with pertinent stakeholders on the State plan development 
generally will include engagement on any potential use of RULOF to 
apply less stringent standards of performance. The proposed requirement 
that states consider the potential pollution impacts and benefits of 
control in the context of a source-specific BSER analysis for a 
particular source is intended to provide for states' consideration of 
health and environmental effects on the communities that are most 
affected by and vulnerable to emissions from that particular source. As 
an example, the State plan submission could include a comparative 
analysis assessing potential BSER options for an affected EGU and the 
corresponding potential benefits to the identified communities under 
each option. If the comparative analysis shows that emissions from an 
affected EGU could be controlled at a higher cost but that such control 
benefits the communities that would otherwise be adversely impacted by 
a less stringent standard of performance, the State could balance these 
considerations and determine that a higher cost is warranted for the 
source-specific BSER.
    The plan submission under these emission guidelines must clearly 
identify the communities most affected by and vulnerable to emissions 
from the designated facility. The EPA is proposing that, in evaluating 
potential source-specific BSERs, a State must document any health or 
environmental impacts and benefits of control options and describe how 
it considered those impacts on the identified communities. Pursuant to 
the proposed meaningful engagement requirements discussed in section 
XII.F.1.b of this preamble, states' plan submissions would also be 
required to include a summary of the meaningful engagement the State 
conducted and a summary of stakeholder input received, including any 
engagement and input on RULOF sources and the calculation of less-
stringent standards of performance.
    The EPA solicits comments on additional ways in which states might 
consider potential pollution impacts and benefits of control to 
communities most affected by and vulnerable to emissions from affected 
EGUs when determining a less-stringent standard pursuant to RULOF. In 
particular, the Agency is requesting comment on metrics or information 
concerning health and environmental impacts from affected EGUs that 
states can consider in source-specific RULOF determinations. As 
discussed in section XII.F.1.b, the EPA is also requesting comment on 
tools and methodologies for identifying communities that are most 
affected by and vulnerable to emissions from affected EGUs under these 
emission guidelines.

[[Page 33387]]

d. The EPA's Standard of Review of State Plans Invoking RULOF
    Under CAA section 111(d)(2), the EPA has the obligation to 
determine whether a State plan submission is ``satisfactory.'' This 
obligation extends to all aspects of a State plan, including the 
application of less stringent standards of performance that account for 
RULOF. Pursuant to CAA section 111(d) and the proposed subpart Ba 
provisions,\645\ states carry the burden of making the demonstrations 
required under the RULOF mechanism and have the obligation to justify 
any accounting for RULOF in support of standards of performance that 
are less stringent than the proposed presumptively approvable standards 
in these emission guidelines. While the EPA has the discretion to 
supplement a State's demonstration, the EPA may also find that 
inadequacies in a State plan's demonstration are a basis for concluding 
that the plan is not ``satisfactory'' and may therefore disapprove the 
plan.
---------------------------------------------------------------------------

    \645\ CAA section 111(d)(2), 87 FR 79176 (December 23, 2022), 
Docket ID No. EPA-HQ-OAR-2021-0527-0002 (proposed revisions to RULOF 
provisions at 40 CFR 60.24a(j)).
---------------------------------------------------------------------------

    As a general matter, a less stringent standard of performance 
pursuant to RULOF must meet all other applicable requirements of 
subpart Ba and these emission guidelines.\646\
---------------------------------------------------------------------------

    \646\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(l)).
---------------------------------------------------------------------------

    In determining whether a State has met its burden in providing a 
less stringent standard of performance based on RULOF, the EPA will 
consider, among other things, the applicability and appropriateness of 
the information on which the State relied. Both a demonstration that a 
particular affected EGU meets the threshold requirements to invoke 
RULOF and the determination of a source-specific standard of 
performance entail the use of technical, cost, engineering, and other 
information. The proposed subpart Ba revisions would require states to 
use information that is applicable to and appropriate for the 
particular source at issue.\647\ This means that, when available, the 
State must use source- and site-specific information. This is 
consistent with the premise that invoking RULOF is appropriate for a 
particular source when there are fundamental differences between the 
EPA's BSER and that source's specific circumstances.
---------------------------------------------------------------------------

    \647\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(j)(1)).
---------------------------------------------------------------------------

    In some instances, site-specific information may not be available. 
In such cases, it may be reasonable for a State to use information 
from, e.g., cost, engineering, and other analyses the EPA has provided 
to support this rulemaking. The EPA is proposing that states using non-
site-specific information must explain why that information is 
reasonable to rely on to determine a less stringent standard of 
performance based on RULOF. Regardless of the information used, it must 
come from reliable and adequately documented sources, which the 
proposed subpart Ba revisions explain presumptively include sources 
published by the EPA, permits, environmental consultants, control 
technology vendors, and inspection reports.\648\
---------------------------------------------------------------------------

    \648\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(j)(2)).
---------------------------------------------------------------------------

    The EPA solicits comment on the types of source-specific and other 
information that states should be required to provide to support the 
inclusion of standards of performance based on RULOF in State plans, as 
well as on any additional sources of information that may be 
appropriate for states to use in this context.
e. Authority To Apply More Stringent Standards as Part of State Plans
    As explained in the subpart Ba notice of proposed rulemaking, the 
EPA reevaluated its interpretation of CAA sections 111(d) and 116 and, 
consistent with its revised interpretation, has proposed revisions to 
subpart Ba to clarify that states may consider RULOF to include more 
stringent standards of performance in their State plans.\649\ The 
allowance in CAA section 111(d)(1) that states may consider ``other 
factors'' does not limit states to considering only factors that may 
result in a less stringent standard of performance; other factors that 
states may wish to account for in applying a more stringent standard 
than provided in these emission guidelines include, but are not limited 
to, effects on local communities, the availability of control 
technologies that allow a particular source to achieve greater emission 
reductions, and local or State policies and requirements.
---------------------------------------------------------------------------

    \649\ 87 FR 79176, 79204 (December 23, 2022), Docket ID No. EPA-
HQ-OAR-2021-0527-0002 (proposed revisions to RULOF provisions at 40 
CFR 60.24a(m), (n)).
---------------------------------------------------------------------------

    Pursuant to proposed subpart Ba, states seeking to apply a more 
stringent standard of performance based on other factors would have to 
adequately demonstrate that the standard is in fact more stringent than 
the presumptively approvable standard of performance for the applicable 
subcategory. However, a State would not be required to conduct a 
source-specific BSER evaluation for the purpose of applying a more 
stringent standard of performance, so long as the standard will achieve 
equivalent or better emission reductions. In this case, the EPA 
believes it is appropriate to defer to the State's discretion to impose 
a more stringent standard on an individual source because such a 
standard does not have the potential to undermine the presumptive 
stringency of these emission guidelines.
    More stringent standards of performance must meet all applicable 
statutory and regulatory requirements, including that they are 
adequately demonstrated.\650\ As for all standards of performance, the 
State plan must include requirements that provide for the 
implementation and enforcement of a more stringent standard. The EPA 
has the ability and authority to review more stringent standards of 
performance and to approve them provided that the minimum requirements 
of subpart Ba and these emission guidelines are met, rendering them 
federally enforceable.
---------------------------------------------------------------------------

    \650\ 87 FR 79176, 79204 (December 23, 2022), Docket ID No. EPA-
HQ-OAR-2021-0527-0002 (proposed revisions to RULOF provisions at 40 
CFR 60.24a(m)).
---------------------------------------------------------------------------

    The EPA requests comment on the implementation of the proposed 
subpart Ba provisions pertaining to more stringent standards of 
performance in the context of these particular emission guidelines.
3. Increments of Progress and Milestones for Affected EGUs That Have 
Elected To Commit To Cease Operations
    The EPA's long-standing CAA section 111 implementing regulations at 
40 CFR part 60, subpart Ba \651\ provide that State plans must include 
legally enforceable increments of progress to achieve compliance for 
each designated facility when the compliance schedule extends more than 
a specified length of time from the State plan submission date.\652\ 
The EPA's December 2022 proposed revisions to subpart Ba would require 
increments of progress when the compliance date is more than 16 months 
after the State plan submission deadline.\653\ Under these proposed 
emission guidelines, the State plan submission date would be 24 months 
(see section XII.F.2 of this preamble) from promulgation of the 
emission

[[Page 33388]]

guidelines, which the EPA is currently anticipating will be June 2026. 
The proposed compliance dates for affected EGUs within the proposed 
subcategories all fall on or after January 1, 2030, which is more than 
16 months after the State plan submission deadline. The EPA is 
therefore proposing to require that State plans include increments of 
progress as discussed in this section. For the purpose of these 
emission guidelines, the EPA refers to pre-compliance date, federally 
enforceable requirements associated with the planning, construction, 
and operation of natural gas or hydrogen co-firing infrastructure and 
CCS as increments of progress. The EPA is also proposing separate, 
federally enforceable ``milestones'' associated with activities 
surrounding enforceable dates to permanently cease operations for steam 
generating EGUs in the imminent-term, near-term, and medium-term 
subcategories. These additional State plan requirements are intended to 
ensure that affected coal-fired steam generating units can complete the 
steps necessary to qualify for a subcategory with a less stringent BSER 
and to provide the public assurance that those steps will be concluded 
in a timely manner.
---------------------------------------------------------------------------

    \651\ See also 40 CFR 60.21(h).
    \652\ 40 CFR 60.24a(d).
    \653\ 87 FR 79176, 79204 (December 23, 2022), Docket ID No. EPA-
HQ-OAR-2021-0527-0002 (proposed revisions at 40 CFR 60.24a(d)).
---------------------------------------------------------------------------

a. Increments of Progress
    The EPA is proposing to adopt emission guideline-specific 
implementation of the five generic increments specified in the CAA 
section 111(d) implementing regulations at 40 CFR 60.21a(h). These five 
increments of progress are: (1) Submittal of a final control plan for 
the designated facility to the appropriate air pollution control 
agency; (2) Awarding of contracts for emission control systems or for 
process modifications, or issuance of orders for the purchase of 
component parts to accomplish emission control or process modification; 
(3) Initiation of on-site construction or installation of emission 
control equipment or process change; (4) Completion of on-sites 
construction or installation of emission control equipment or process 
change; and (5) Final compliance. To this end, the EPA is proposing 
that State plans must include specified enforceable increments of 
progress as required elements for coal-fired EGUs that use natural gas 
co-firing to meet the standard of performance for the medium-term 
existing coal-fired steam generating subcategory and for natural gas-
fired combustion turbine EGUs that use hydrogen co-firing to meet the 
standard of performance for hydrogen co-fired combustion turbine 
subcategory. The EPA is additionally proposing that State plans must 
include enforceable increments of progress for units that use CCS to 
meet the standard of performance for the long-term existing coal-fired 
steam generating subcategory or for the CCS combustion turbine 
subcategory.
    Some increments have been adjusted to more closely align with 
planning, engineering, and construction steps anticipated for 
designated facilities that will be complying with standards of 
performance with natural gas or hydrogen co-firing or CCS, but they 
retain the basic structure and substance of the increments in the 
general implementing regulations. In addition, consistent with 40 CFR 
60.24a(d), the EPA is proposing similar additional increments of 
progress for the long-term and medium-term coal-fired subcategories as 
well as both combustion turbine subcategories to ensure timely progress 
on the planning, permitting, and construction activities related to 
pipelines that may be required to enable full compliance with the 
applicable standard of performance. The EPA is also proposing an 
additional increment of progress related to the identification of an 
appropriate sequestration site for the long-term coal-fired subcategory 
and the CCS combustion turbine subcategory. Finally, the proposed 
emission guidelines include an additional increment of progress that 
that applies solely to the hydrogen co-fired combustion turbine 
subcategory related to securing sufficient hydrogen contract capacity 
to meet the standard of performance.
    The EPA notes that affected EGUs do not necessarily have to 
implement the EPA's BSER technology to comply with their applicable 
standards of performance. For example, affected EGUs in the medium- and 
long-term coal-fired steam generating unit subcategories may meet their 
standards of performance using approaches other than natural gas co-
firing and CCS, respectively. Where the owners or operators of affected 
EGUs select compliance approaches that deviate from the BSER technology 
associated with a subcategory requiring increments of progress, the EPA 
proposes that the State plan would be required to specify increments of 
progress for the relevant affected EGUs that are consistent with the 
increments in 40 CFR 60.21a(h), as well as dates for achieving each 
increment.
    The EPA is proposing that final compliance with the applicable 
standard of performance, also defined as the final increment of 
progress at 40 CFR 60.21a(h)(5), must occur no later than January 1, 
2030 for steam generating units in the medium-term and long-term 
subcategories, no later than January 1, 2035 for combustion turbine 
EGUs in the CCS subcategory, and no later than January 1, 2032 for 
combustion turbine EGUs in the hydrogen co-fired subcategory.\654\ For 
the remaining increments, the EPA is not proposing date-specific 
deadlines for achieving increments of progress. Instead, the EPA 
proposes that states must assign calendar day deadlines for each of the 
remaining increments for each affected EGU in their State plan 
submissions. The first increment of progress listed at 40 CFR 
60.21a(h)(1), submittal of a final control plan to the air pollution 
control agency, must be assigned the earliest calendar date deadline 
among the increments. The EPA believes that allowing states to schedule 
sources' increments of progress would provide them with flexibility to 
tailor compliance timelines to individual facilities, allow 
simultaneous work toward separate increments, and still ensure full 
performance by the compliance date. The EPA solicits comment on this 
approach as well as whether the EPA should instead finalize date-
specific deadlines or more general timeframes for achieving increments 
of progress rather than leaving the timing for most increments to State 
discretion. The EPA also seeks comment on the specific deadlines or 
timeframes that the EPA could assign to each increment under a more 
prescriptive approach.
---------------------------------------------------------------------------

    \654\ The EPA is proposing that the second phase of the standard 
of performance for existing hydrogen co-fired combustion turbines, 
which corresponds to co-firing 96 percent by volume low-GHG 
hydrogen, would start on January 1, 2038. However, the EPA is not 
proposing an increment of progress associated with this second phase 
because the Agency anticipates the relevant planning, design, and 
construction steps will have occurred ahead of the January 1, 2032 
compliance date.
---------------------------------------------------------------------------

    The EPA is not proposing increments of progress for either the 
imminent- or near-term subcategories for coal-fired steam generating 
units, or for oil- or natural gas-fired steam generating units. The 
proposed BSERs for these affected EGUs are routine operation and 
maintenance, which does not require the installation of significant new 
emission controls or operational changes. Because there is no need for 
the types of increments of progress specified in 40 CFR 60.21a(h) to 
ensure that affected EGUs in the imminent and near-term coal-fired and 
oil- and natural gas-fired subcategories can achieve full compliance by 
the compliance date, the EPA is proposing that the requirement

[[Page 33389]]

for increments of progress in 40 CFR 60.24a(d) does not apply to these 
units.
    For coal-fired steam generating units falling within the medium-
term subcategory and combustion turbine EGUs within the hydrogen co-
fired subcategory (i.e., units with proposed BSERs of co-firing clean 
fuels), the EPA proposes the following increments of progress as 
enforceable elements required to be included in a State plan: (1) 
Submission of a final control plan for the affected EGU to the 
appropriate air pollution control agency. The final control plan must 
be consistent with the subcategory declaration in the State plan and 
must include supporting analysis for the affected EGU's control 
strategy, including the design basis for modifications at the facility, 
the anticipated timeline to achieve full compliance, and the benchmarks 
the facility anticipates along the way. (2) Awarding of contracts for 
boiler or turbine modifications, or issuance of orders for the purchase 
of component parts to accomplish such modifications. Affected EGUs can 
demonstrate compliance with this increment by submitting sufficient 
evidence that the appropriate contracts have been awarded. (3) 
Initiation of onsite construction or installation of any boiler or 
turbine modifications necessary to enable natural gas co-firing at a 
level of 40 percent on an annual average basis or hydrogen co-firing at 
30 percent on an annual average basis, as appropriate for the 
applicable subcategory. (4) Completion of onsite construction of any 
boiler or turbine modifications necessary to enable natural gas co-
firing at a level of 40 percent on an annual average basis or hydrogen 
co-firing at 30 percent on an annual average basis, as appropriate for 
the applicable subcategory. (5) Final compliance with the standard of 
performance by January 1, 2030 for coal-fired steam generating units 
and by January 1, 2032 for combustion turbine EGUs.
    In addition to the five increments of progress derived from the CAA 
section 111(d) implementing regulations, the EPA is proposing an 
additional increment of progress for affected EGUs with proposed BSERs 
based on co-firing clean fuels (natural gas co-firing for medium-term 
coal-fired steam generating EGUs and hydrogen co-firing for hydrogen 
co-fired combustion turbine EGUs) to ensure timely completion of any 
pipeline infrastructure needed to transport natural gas or hydrogen to 
designated facilities within each subcategory. Affected EGUs would be 
required to demonstrate that all permitting actions related to pipeline 
construction have commenced by a date specified in the State plan. 
Evidence in support of the demonstration must include pipeline planning 
and design documentation that informed the permitting application 
process, a complete list of pipeline-related permitting applications, 
including the nature of the permit sought and the authority to which 
each permit application was submitted, an attestation that the list of 
pipeline-related permit applications is complete with respect to the 
authorizations required to operate the facility at full compliance with 
the standard of performance, and a timeline to complete all pipeline 
permitting activities.
    Affected EGUs within the hydrogen co-fired combustion turbine 
subcategory must meet an additional increment of progress to 
demonstrate they have secured access to hydrogen supplies sufficient to 
meet their anticipated 2032 fuel needs. This increment can be met by a 
capacity contract for hydrogen at volumes in 2032 consistent with the 
information provided in the final control plan and the pipeline 
specification included in the pipeline construction increment of 
progress.
    For coal-fired EGUs falling within the long-term subcategory and 
for combustion turbine EGUs falling within the CCS subcategory (i.e., 
units with proposed BSERs of CCS), the EPA proposes the following 
increments of progress as required, enforceable elements to be included 
in a State plan submission: (1) Submission of a final control plan for 
the affected EGU to the appropriate air pollution control agency. The 
final control plan must be consistent with the subcategory declaration 
in the State plan and must include supporting analysis for the affected 
EGU's control strategy, including a feasibility and/or FEED study. (2) 
Awarding of contracts for emission control systems or for process 
modifications, or issuance of orders for the purchase of component 
parts to accomplish emission control or process modification. Affected 
EGUs can demonstrate compliance with this increment by submitting 
sufficient evidence that the appropriate contracts have been awarded. 
(3) Initiation of onsite construction or installation of emission 
control equipment or process change required to achieve 90 percent 
CO2 capture on an annual basis. (4) Completion of onsite 
construction or installation of emission control equipment or process 
change required to achieve 90 percent CO2 capture on an 
annual basis. (5) Final compliance with the standard of performance by 
January 1, 2030 for coal-fired steam generating units and by January 1, 
2035 for combustion turbine EGUs.
    In addition to the five increments of progress derived from the CAA 
section 111(d) implementing regulations, the EPA is proposing two 
additional increments for affected EGUs that adopt CCS to meet the 
standard of performance for the long-term coal-fired steam generating 
unit and CCS combustion turbine subcategories. The first mirrors the 
proposed approach for the co-firing subcategories to ensure timely 
completion of pipeline infrastructure and the second is designed to 
ensure timely selection of an appropriate sequestration site. As the 
first additional increment, the EPA proposes that affected EGUs using 
CCS to comply with their standards of performance would be required to 
demonstrate that all permitting actions related to pipeline 
construction have commenced by a date specified in the State plan. 
Evidence in support of the demonstration must include pipeline planning 
and design documentation that informed the permitting process, a 
complete list of pipeline-related permitting applications, including 
the nature of the permit sought and the authority to which each permit 
application was submitted, an attestation that the list of pipeline-
related permits is complete with respect to the authorizations required 
to operate the facility at full compliance with the standard of 
performance, and a timeline to complete all pipeline permitting 
activities.
    The second proposed additional increment of progress for affected 
EGUs using CCS to comply with their standards of performance is 
formulated to ensure timely completion of site selection for geologic 
sequestration of captured CO2 from the facility. Affected 
EGUs within this subcategory must submit a report identifying the 
geographic location where CO2 will be injected underground, 
how the CO2 will be transported from the capture location to 
the storage location, and the regulatory requirements associated with 
the sequestration activities, as well as an anticipated timeline for 
completing related permitting activities.
    The EPA requests comment on the substance of each of the six 
proposed increments of progress for coal-fired steam generating units 
falling within the medium-term subcategory, the seven increments of 
progress for units within the hydrogen co-fired combustion turbine 
subcategory, and the seven increments of progress proposed for both 
subcategories that anticipate CCS adoption. The EPA seeks comment on 
whether the increments contain an

[[Page 33390]]

appropriate level of specificity to establish clear, verifiable 
criteria to ensure that states and affected EGUs are taking the steps 
necessary to reach full compliance. If commenters believe they do not, 
the EPA requests comment on the appropriate level of specificity for 
each increment. Additionally, as discussed in section XII.F.1.b.ii of 
this preamble, the EPA is proposing a requirement that each State plan 
provide for the establishment of Carbon Pollution Standards for EGUs 
websites by the owners or operators of affected EGUs. The EPA is 
further proposing that State plans must require affected EGUs with 
increments of progress to post those increments, the schedule required 
in the State plan for achieving them, and any documentation necessary 
to demonstrate that they have been achieved to this website in a timely 
manner.
b. Milestones for Affected EGUs That Have Elected To Commit To Cease 
Operations
    The EPA is proposing that State plans must include legally 
enforceable milestones for affected EGUs within the imminent-term, 
near-term, and medium-term coal-fired steam generating unit 
subcategories. As described in section X of this preamble, the 
applicability criteria for each of the subcategories of coal-fired 
steam generating units include an affected EGU's intended operating 
horizon; where owners or operators of affected EGUs have elected to 
commit to permanently cease operations by a date certain before January 
1, 2040, and, where a State further elects to include such commitments 
as an enforceable element in a State plan, such EGUs will fall into one 
of these three subcategories. Accordingly, affected EGUs in the 
imminent-term, near-term, and medium-term subcategories have BSERs that 
are specifically tailored to and dependent on their shorter operating 
horizons. The EPA is aware that there are many processes an affected 
EGU must complete in order to permanently cease operation. Therefore, 
to ensure that affected EGUs can complete the steps necessary to 
qualify for a subcategory with a less stringent standard of performance 
and to provide the public assurance that those steps will be concluded 
in a timely manner, the EPA is proposing additional State plan 
requirements, referred to as ``milestones,'' for EGUs in the imminent-
term, near-term, and medium-term subcategories.
    The proposed milestone reporting requirements count backward from 
an affected EGU's date to permanently cease operations to ensure timely 
progress toward that date. Five years before any date used to determine 
the applicable subcategory under these emission guidelines or 60 days 
after State plan submission, whichever is later, designated facilities 
must submit an Initial Milestone Report to the applicable State 
administering authority that includes the following: (1) A summary of 
the process steps required for the affected EGU to permanently cease 
operation by the date included in the State plan, including the 
approximate timing and duration of each step. (2) A list of key 
milestones, metrics that will be used to assess whether each milestone 
has been met, and calendar day deadlines for each milestone. These 
milestones must include at least the following: notice to the official 
reliability authority of the retirement date; submittal of an official 
suspension filing (or equivalent filing) made to the affected EGU's 
reliability authority; and submittal of an official retirement filing 
with the unit's reliability authority. (3) An analysis of how the 
process steps, milestones, and associated timelines included in the 
Milestone Report compare to the timelines of similar units within the 
State that have permanently ceased operations within the 10 years prior 
to the date of promulgation of these emission guidelines. (4) 
Supporting regulatory documents, including correspondence and official 
filings with the relevant regional transmission organization, balancing 
authority, public utility commission, or other applicable authority, as 
well as any filings with the SEC or notices to investors in which the 
plans for the EGU are mentioned and any integrated resource plan.
    For each of the remaining years prior to the date to permanently 
cease operations that is used to determine the applicable subcategory, 
affected EGUs must submit an annual Milestone Status Report that 
addresses the following: (1) Progress toward meeting all milestones and 
related metrics identified in the Milestone Report; and (2) supporting 
regulatory documents, including correspondence and official filings 
with the relevant regional transmission organization, balancing 
authority, public utility commission, or other applicable authority to 
demonstrate compliance with or progress toward all milestones.
    The EPA is also proposing that affected EGUs with reporting 
milestones associated with commitments to permanently cease operations 
would be required to submit a Final Milestone Status Report no later 
than 6 months following its federally enforceable date. This report 
would document any actions that the unit has taken subsequent to 
ceasing operation to ensure that such cessation is permanent, including 
any regulatory filings with applicable authorities or decommissioning 
plans. The EPA requests input on whether 6 months after the federally 
enforceable date is an appropriate period of time to capture any 
actions affected EGUs taken following cessation of operations.
    The EPA is proposing that affected EGUs with reporting milestones 
for commitments to permanently cease operations would be required to 
post their Initial Milestone Report, annual Milestone Status Reports, 
and Final Milestone Status Report, including the schedule for achieving 
milestones and any documentation necessary to demonstrate that 
milestones have been achieved, on the Carbon Pollution Standards for 
EGUs website, as described in section XII.F.1.b, within 30 business 
days of being filed.
    The EPA recognizes that applicable regulatory authorities, 
retirement processes, and retirement approval criteria will vary across 
states and affected EGUs. The proposed milestone requirements are 
intended to establish a general framework flexible enough to account 
for significant differences across jurisdictions while assuring timely 
planning toward the dates by which affected EGUs permanently cease 
operations. The EPA requests comment on this proposed approach, 
specifically whether any jurisdictions present unique State 
circumstances that should be considered when defining milestones and 
the required reporting elements.
4. Testing and Monitoring Requirements
    The EPA is proposing to require states to include in their plans a 
requirement that affected EGUs monitor and report hourly CO2 
mass emissions emitted to the atmosphere, total heat input, and total 
gross electricity output, including electricity generation and, where 
applicable, useful thermal output converted to gross MWh, in accordance 
with the 40 CFR part 75 monitoring and reporting requirements. Under 
this proposal, affected EGUs would be required to use a 40 CFR part 75 
certified monitoring methodology and report the hourly data on a 
quarterly basis, with each quarterly report due to the Administrator 30 
days after the last day in the calendar quarter. The monitoring 
requirements of 40 CFR part 75 require most fossil fuel-fired boilers 
to use a CO2 CEMS, including a CO2 concentration 
monitor and stack gas flow monitor, although some oil- and

[[Page 33391]]

natural gas-fired boilers may have options to use alternative 
measurement methodologies (e.g., fuel flow meters). A CO2 
CEMS is the most technically reliable method of emission measurement 
for EGUs that burn solid fuels, as it provides a measurement method 
that is performance based rather than equipment specific and is 
verified based on NIST traceable standards. A CEMS provides a 
continuous measurement stream that can account for variability in the 
fuels and the combustion process. Reference methods have been developed 
to ensure that all CEMS meet the same performance criteria, which helps 
to ensure consistent, accurate data. Natural gas-fired combustion 
turbines have options under appendices D and G of 40 CFR part 75 to use 
fuel flowmeters in lieu of a CO2 CEMS. The flue flowmeter 
data, paired with fuel quality data, is used to determine 
CO2 mass emissions and heat input.
    The majority of EGUs will generally have no changes to their 
monitoring and reporting requirements and will continue to monitor and 
submit emissions reports under 40 CFR part 75 as they have under 
existing programs, such as the Acid Rain Program (ARP) and the Regional 
Greenhouse Gas Initiative (RGGI)--a cooperative of several states 
formed to reduce CO2 emissions from EGUs. The majority of 
coal- and oil-fired EGUs not subject to the ARP or RGGI are subject to 
the MATS program and, therefore, will have installed stack gas flow 
monitors and/or CO2 concentration monitors necessary to 
comply with the MATS. Similarly, the majority of natural gas-fired 
combustion turbines that may be affected by this rule already use fuel 
flowmeters to monitor and report CO2 mass emissions and heat 
input under appendices D and G of 40 CFR part 75. Relying on the same 
monitors that are certified and quality-assured in accordance with 40 
CFR part 75 ensures cost efficient, consistent, and accurate data that 
may be used for different purposes for multiple regulatory programs.
    The EPA requests comment on monitoring and reporting requirements 
for captured CO2 mass emissions and net electricity output, 
and on allowable testing methods for stack gas flow rate.
    The CCS process is also subject to monitoring and reporting 
requirements under the EPA's GHGRP (40 CFR part 98). The GHGRP requires 
reporting of facility-level GHG data and other relevant information 
from large sources and suppliers in the U.S. The ``suppliers of carbon 
dioxide'' source category of the GHGRP (GHGRP subpart PP) requires 
those affected facilities with production process units that capture a 
CO2 stream for purposes of supplying CO2 for 
commercial applications or that capture and maintain custody of a 
CO2 stream in order to sequester or otherwise inject it 
underground to report the mass of CO2 captured and supplied. 
Facilities that inject a CO2 stream underground for long-
term containment in subsurface geologic formations report quantities of 
CO2 sequestered under the ``geologic sequestration of carbon 
dioxide'' source category of the GHGRP (GHGRP subpart RR). In 2022, to 
complement GHGRP subpart RR, the EPA proposed the ``geologic 
sequestration of carbon dioxide with enhanced oil recovery (EOR) using 
ISO 27916'' source category of the GHGRP (GHGRP subpart VV) to provide 
an alternative method of reporting geologic sequestration in 
association with EOR.655 656 657
---------------------------------------------------------------------------

    \655\ 87 FR 36920 (June 21, 2022).
    \656\ International Standards Organization (ISO) standard 
designated as CSA Group (CSA/American National Standards Institute 
(ANSI) ISO 27916:2019, Carbon Dioxide Capture, Transportation and 
Geological Storage--Carbon Dioxide Storage Using Enhanced Oil 
Recovery (CO2--EOR) (referred to as ``CSA/ANSI ISO 27916:2019'').
    \657\ As described in 87 FR 36920 (June 21, 2022), both subpart 
RR and proposed subpart VV (CSA/ANSI ISO 27916:2019) require an 
assessment and monitoring of potential leakage pathways; 
quantification of inputs, losses, and storage through a mass balance 
approach; and documentation of steps and approaches used to 
establish these quantities. Primary differences relate to the terms 
in their respective mass balance equations, how each defines 
leakage, and when facilities may discontinue reporting.
---------------------------------------------------------------------------

    The EPA is proposing that any affected unit that employs CCS 
technology that captures enough CO2 to meet the proposed 
standard and injects the captured CO2 underground must 
report under GHGRP subpart RR or proposed GHGRP subpart VV. If the 
emitting EGU sends the captured CO2 offsite, it must assure 
that the CO2 is managed at a facility subject to the GHGRP 
requirements, and the facility injecting the CO2 underground 
must report under GHGRP subpart RR or proposed GHGRP subpart VV. This 
proposal does not change any of the requirements to obtain or comply 
with a UIC permit for facilities that are subject to the EPA's UIC 
program under the Safe Drinking Water Act.
    The EPA also notes that compliance with the standard is determined 
exclusively by the tons of CO2 captured by the emitting EGU. 
The tons of CO2 sequestered by the geologic sequestration 
site are not part of that calculation, though the EPA anticipates that 
the quantity of CO2 sequestered will be substantially similar to the 
quantity captured. However, to verify that the CO2 captured 
at the emitting EGU is sent to a geologic sequestration site, we are 
leveraging regulatory requirements under the GHGRP. The BSER is 
determined to be adequately demonstrated based solely on geologic 
sequestration that is not associated with EOR. However, EGUs also have 
the compliance option to send CO2 to EOR facilities that 
report under GHGRP subpart RR or proposed GHGRP subpart VV. We also 
emphasize that this proposal does not involve regulation of downstream 
recipients of captured CO2. That is, the regulatory standard 
applies exclusively to the emitting EGU, not to any downstream user or 
recipient of the captured CO2. The requirement that the 
emitting EGU assure that captured CO2 is managed at an 
entity subject to the GHGRP requirements is thus exclusively an element 
of enforcement of the EGU standard. This will avoid duplicative 
monitoring, reporting, and verification requirements between this 
proposal and the GHGRP, while also ensuring that the facility injecting 
and sequestering the CO2 (which may not necessarily be the 
EGU) maintains responsibility for these requirements. Similarly, the 
existing regulatory requirements applicable to geologic sequestration 
are not part of the proposed rule.
    The EPA requests comment on the following questions related to 
additional monitoring and reporting of hourly captured CO2 
under 40 CFR part 75: (a) should EGUs with carbon capture technologies 
be required to monitor and report the hourly captured CO2 
mass emissions under 40 CFR part 75, (b) if EGUs with carbon capture 
technologies are not required to monitor and report the hourly captured 
CO2 mass emissions, the calculation procedures for total 
heat input and NOX rate in appendix F to 40 CFR part 75 may 
no longer provide accurate results; therefore, what changes might be 
necessary to accurately determine total heat input and NOX 
rate, (c) to ensure accurate and complete accounting of CO2 
mass emissions emitted to the atmosphere and captured for use or 
sequestration, at what locations should CO2 concentration 
and stack gas flow be monitored, and should other values also be 
monitored at those locations, (d) are there quality assurance 
activities outside of those required under 40 CFR part 75 for 
CO2 concentration monitors and stack gas flow monitors that 
should be required of the monitors to accurately and reliably measure 
captured CO2 mass emissions, and (e) what monitoring plan, 
quality assurance, and emissions

[[Page 33392]]

data should be reported to the EPA to support evaluation and ensure 
consistent and accurate data as it relates to CO2 emissions 
capture.
    The 40 CFR part 75 monitoring and reporting provisions require 
hourly reporting of total gross electricity output, including useful 
thermal output, but do not require the reporting of net electricity 
output. The EPA requests comment on the following questions related to 
reporting of net electricity output: (a) should EGUs be required to 
measure and report total net electricity output, including useful 
thermal output, under 40 CFR part 75, (b) what guidance should the EPA 
provide on how to measure and apportion net electricity output, (c) 
should EGUs measure and report net electricity output at the unit or 
facility level, and (d) what monitoring plan, quality assurance, and 
output data should be reported to the EPA to support evaluation and 
ensure consistent and accurate data as it relates to total net 
electricity output.
    To calculate CO2 mass emissions at a fossil fuel-fired 
boiler, the EGU typically measures CO2 concentration and 
flue gas flow rate as the exhaust gases from combustion pass through 
the stack (or duct). Under 40 CFR part 75, EGUs must complete regular 
performance tests on the flue gas flow monitor based on EPA Reference 
Method 2 or its allowable alternatives that are provided in 40 CFR part 
60, appendices A-1 and A-2. In general, the allowable alternative 
measurement methods reduce or eliminate the potential overestimation of 
stack gas flow rate that results from the use of EPA Reference Method 2 
when the specific flow conditions (e.g., angular flow) are present in 
the stack. However, EGUs with stack gas flow monitors are not required 
to use the allowable alternative measurement methods and EGUs may 
change methods at any time. The EPA requests comment on the following 
questions related to the use of EPA Reference Method 2 and its 
allowable alternatives for stack gas flow monitors under 40 CFR part 
75: (a) should or under what conditions should EGUs be required to 
conduct a flow study and choose the appropriate EPA reference method 
for each stack gas flow monitor based on the results of the study, (b) 
once an EGU selects the use of an EPA reference method for a stack gas 
flow monitor, regardless of the basis for that selection, should the 
EGU be required to continue using the same EPA reference method until a 
flow study or other engineering justification is made to change the EPA 
reference method, and (c) what additional monitoring plan, quality 
assurance, and emissions data should be reported to the EPA to support 
evaluation and ensure consistent and accurate data as it relates stack 
gas flow rate and performance of the stack gas flow monitor.

E. Compliance Flexibilities

    In developing these proposed emission guidelines, the EPA has heard 
from stakeholders seeking flexibility in complying with standards of 
performance under these emission guidelines. In particular, 
stakeholders have requested that the EPA allow states to include 
flexibilities such as averaging and market-based mechanisms in their 
State plans, as has been permitted under prior EPA rules. The EPA is 
proposing to allow states to incorporate averaging and emission trading 
into their State plans, provided that states ensure that use of these 
compliance flexibilities will result in a level of emission performance 
by the affected EGUs that is equivalent to each source individually 
achieving its standard of performance. As discussed below, the EPA also 
recognizes that the structure of the proposed subcategories and 
associated degrees of emission limitation, as well as the unique 
characteristics of the existing sources in the relevant source 
categories, will likely require that certain limitations or conditions 
be placed on the incorporation of averaging and trading in order to 
ensure that such standards are at least as stringent as the EPA's BSER. 
This section discusses considerations related to such compliance 
flexibilities in the context of this particular rule and set of 
regulated sources--existing steam generating units and existing 
combustion turbine EGUs--and solicits comment on whether certain types 
of averaging and trading maintain the stringency of the EPA's BSER.
1. Overview
    In the proposed subpart Ba revisions, ``Adoption and Submittal of 
State Plans for Designated Facilities: Implementing Regulations Under 
Clean Air Act Section 111(d)'' (87 FR 79176; December 23, 2022), the 
EPA explained that under its proposed interpretation of CAA section 
111, each State is permitted to adopt measures that allow its sources 
to meet their emission limits in the aggregate when the EPA determines, 
in any particular emission guideline, that it is appropriate to do so 
given, inter alia, the pollutant, sources, and standards of performance 
at issue. Thus, the EPA has proposed to return to its longstanding 
position that CAA section 111(d) authorizes the EPA to approve State 
plans that achieve the requisite emission limitation through aggregate 
reductions from their sources, including through trading or averaging, 
where appropriate for a particular emission guideline and consistent 
with the intended environmental outcomes of the BSER.\658\ See 87 FR 
79208 (December 23, 2022).
---------------------------------------------------------------------------

    \658\ The EPA has authorized trading or averaging as compliance 
methods in several emission guidelines. See, e.g., 40 CFR 
60.33b(d)(2) (emission guidelines for municipal waste combustors 
permit state plans to establish trading programs for NOX 
emissions); 70 FR 28606, 28617 (May 18, 2005) (Clean Air Mercury 
Rule authorized trading) (vacated on other grounds); 40 CFR 
60.24(b)(1) (subpart B CAA section 111 implementing regulations 
promulgated in 2005 allow States' standards of performance to be 
based on an ``allowance system''); 80 FR 64662, 64840 (October 23, 
2015) (CPP authorizing trading or averaging as a compliance 
strategy). In the recent supplemental proposal to promulgate 
emission guidelines for the oil and natural gas industry, the EPA 
has also proposed to allow States to permit sources to demonstrate 
compliance in the aggregate. 87 FR 74702, 74812 (December 6, 2022).
---------------------------------------------------------------------------

    Consistent with the return to this longstanding position, the EPA 
is proposing to allow states to incorporate trading and averaging in 
their State plans under these emission guidelines. States would not be 
required to allow for such compliance mechanisms in their State plans 
but could provide for trading and averaging for existing steam 
generating units and/or existing combustion turbines at their 
discretion.\659\ As discussed in section XII.C of this preamble, State 
plans must demonstrate that they achieve a level of emission 
performance by affected EGUs that is consistent with the application of 
the BSER. The EPA is therefore proposing that, in order to find that a 
State plan that includes trading or averaging is ``satisfactory,'' it 
must demonstrate that it maintains the level of emission performance 
for the source category that would be achieved if each affected EGU was 
individually achieving its presumptive standard of performance, after 
allowing for any application of RULOF. In the case of averaging, 
discussed in section XII.E.3 of this preamble, an equivalence 
demonstration would be relatively straightforward. For emission trading 
programs, ensuring equivalent emission

[[Page 33393]]

performance in the aggregate may be more difficult.
---------------------------------------------------------------------------

    \659\ The EPA notes that these flexibilities, trading and 
averaging, would be used to comply with standards of performance, 
rather than to establish standards of performance in the first 
instance. In contrast to the RULOF mechanism, which, as described in 
section XI.D.2 of this preamble, States may use to establish 
different standards of performance than those described by the EPA's 
BSER, trading or averaging may be used to demonstrate compliance 
with already established standards of performance. That is, States 
incorporating trading or averaging would not need to undergo a RULOF 
demonstration for sources participating in trading or averaging 
programs.
---------------------------------------------------------------------------

    Section XII.E.2 of this preamble discusses considerations related 
to the appropriateness of trading and averaging for affected EGUs in 
certain circumstances, e.g., affected EGUs with proposed BSERs based on 
routine methods of operation and maintenance. Section XII.E.2 of this 
preamble also discusses program design examples as well as potential 
design elements and takes comment on whether these or other designs or 
design elements could ensure that use of emission trading or averaging 
does not undermine the stringency of the EPA's BSER. However, the 
Agency is not proposing a presumptively approvable averaging or trading 
approach at this time.
    The EPA also notes that States that incorporate trading or 
averaging into their State plans would need to conduct meaningful 
engagement on this aspect of their plans with pertinent stakeholders, 
just as they would need to do for any other part of a plan. As 
discussed in greater detail in section XII.F.1.b of this preamble, 
meaningful engagement provides an opportunity for communities most 
affected by and vulnerable to the impacts of a plan to provide input, 
including input on any impacts resulting from the use of trading or 
averaging for compliance.
2. Emission Trading
    The EPA is proposing to allow State plans to include emission 
trading programs as a compliance flexibility for affected existing EGUs 
under these emission guidelines and is taking comment on whether 
certain types of trading programs could satisfy the requirement to 
maintain equivalence with source-specific application of standards of 
performance. This section discusses considerations related to affected 
EGUs under these emission guidelines and how a State could potentially 
incorporate a rate-based trading program or a mass-based trading 
program in a way that preserves the stringency of the BSER.
a. Considerations for Emission Trading in State Plans
    Emission trading has been used to achieve required emission 
reductions in the power sector for nearly 3 decades. In Title IV of the 
Clean Air Act Amendments of 1990, Congress specified the design 
elements for the Acid Rain Program, a 48-State allowance trading 
program to reduce SO2 emissions and the resulting acid 
precipitation. Building on the success of that first allowance trading 
program as a tool for addressing multi-State air pollution issues, the 
EPA has promulgated and implemented multiple allowance trading programs 
since 1998 for SO2 or NOX emissions to address 
the requirements of the CAA's good neighbor provision with respect to 
successively more stringent NAAQS for fine particulate matter and 
ozone. The EPA currently administers eight power sector emission 
trading programs that differ in pollutants, geographic regions, covered 
time periods, and levels of stringency.\660\ Annual progress reports 
demonstrate that EPA trading programs have been successful in 
mitigating the problems they were designed to address, exhibiting 
significant emission reductions and extraordinarily high levels of 
compliance.\661\ In addition, several states have implemented regional 
or intrastate CO2 emissions trading programs to address GHG 
emissions from the power sector (the RGGI and California trading 
programs, respectively).
---------------------------------------------------------------------------

    \660\ The six current CSAPR trading programs are the CSAPR 
NOX Annual Trading Program, CSAPR NOX Ozone 
Season Group 1 Trading Program, CSAPR SO2 Group 1 Trading 
Program, CSAPR SO2 Group 2 Trading Program, CSAPR 
NOX Ozone Season Group 2 Trading Program, and CSAPR 
NOX Ozone Season Group 3 Trading Program. The regulations 
for the six CSAPR programs are set forth at subparts AAAAA, BBBBB, 
CCCCC, DDDDD, EEEEE, and GGGGG, respectively, of 40 CFR part 97. The 
regulations for the Texas SO2 Trading Program are set 
forth at subpart FFFFF of 40 CFR part 97. The Acid Rain Program 
SO2 trading program is set forth in Title IV of the Clean 
Air Act Amendments of 1990.
    \661\ Environmental Protection Agency (2021). Power Sector 
Programs--Progress Report. EPA. https://www3.epa.gov/airmarkets/progress/reports/index.html.
---------------------------------------------------------------------------

    In general, emission trading programs provide flexibility for EGUs 
to secure emission reductions at a lower cost relative to more 
prescriptive forms of regulation. Emission trading can allow the owners 
and operators of EGUs to prioritize emission reduction actions where 
they are the quickest or cheapest to achieve while still meeting 
electricity demand and broader environmental and economic performance 
goals. These benefits are heightened where there is a diverse set of 
emission sources (e.g., variation in technology, fuel type, age, and 
operating parameters) included in an emission trading program. This 
diversity of sources is typically accompanied by differences in 
marginal emission abatement costs and operating parameters, resulting 
in heterogeneity in economic emission reduction opportunities that can 
be optimized through the compliance flexibility provided through 
emission trading. In addition, the EPA has observed, with the support 
of multiple independent analyses, that there is significant evidence 
that implementation of trading programs prompted greater innovation and 
deployment of clean technologies that reduce emissions and control 
costs.\662\
---------------------------------------------------------------------------

    \662\ LaCount, M.D., Haeuber, R.A., Macy, T.R., & Murray, B.A. 
(2021). Reducing Power Sector Emissions under the 1990 Clean Air Act 
Amendments: A Retrospective on 30 Years of Program Development and 
Implementation. Atmospheric Environment (Oxford, England: 1994), 
245, 1-10. https://doi.org/10.1016/j.atmosenv.2020.118012.
---------------------------------------------------------------------------

    Emission trading may also provide important benefits. Having 
flexibility to prioritize the most cost effective emission reductions 
among affected EGUs may reduce the cost of compliance as well as 
provide flexibility for fleet management, while achieving the requisite 
level of emission performance. In particular, emission trading may 
provide some short-term operational flexibility.
    At the same time, there may be challenges for implementing an 
emission trading program, especially in the context of the emission 
guidelines that the EPA is proposing here. The EPA notes that while the 
proposed emission guidelines include both steam generating units and 
combustion turbines, the fleet of affected steam generating units is 
expected to shrink under BAU projections (see section IV.F of this 
preamble), and the number of existing combustion turbines subject to 
these emission guidelines is limited (see section XI.C of this 
preamble) given the subcategory applicability thresholds. As a result, 
there is unlikely to be as much diversity in cost and emission 
performance among affected emission sources (resulting in less 
diversity in emission reduction opportunities and marginal abatement 
costs) as seen in prior emission trading programs for the electric 
power sector.
    The utility of trading under these emission guidelines may also be 
obviated somewhat by the subcategories that the EPA has proposed to 
establish for existing coal-fired steam generating units and existing 
gas combustion turbines. The specific subcategories proposed under 
these emission guidelines for steam generating units are designed to 
provide for much of the same operational flexibility as would be 
provided through trading; as a result, the EPA believes that it would 
not be appropriate to allow affected EGUs in certain subcategories--
imminent-term and near-term coal-fired steam generating units and 
natural gas- and oil-fired steam generating units--to comply with their 
standards of performance through trading. Similarly, the EPA believes 
it would not be

[[Page 33394]]

appropriate to allow affected EGUs with less-stringent, source-specific 
standards based on RULOF to comply with those standards of performance 
through trading. As discussed in section X.D.3 of this preamble, the 
proposed BSER determinations for the imminent- and near-term coal-fired 
steam generating unit subcategories are designed to take into account 
factors such as operating horizon and load level (expressed as annual 
capacity factor) and, as a result, are based on routine methods of 
operation and maintenance. Natural gas- and oil-fired steam generating 
units also have proposed BSER determinations based on routine methods 
of operation and maintenance. An emission trading program that includes 
affected EGUs that have BSERs and resulting standards of performance 
based on limited expected emission reduction potential--or, in the case 
of affected EGUs for which states have invoked RULOF, less stringent 
standards of performance--may introduce the risk of undermining the 
intended stringency of the BSER for other facilities.
    The EPA also believes that emission trading may be inappropriate 
for some subcategories of affected EGUs based on other, subcategory-
specific reasons. Affected EGUs that receive the IRC section 45Q tax 
credit for permanent sequestration of CO2 may have an 
overriding incentive to maximize both the application of the CCS 
technology and total electric generation, leading to source behavior 
that may be non-responsive to the economic incentives of a trading 
program. This consideration may be relevant for affected EGUs in the 
long-term coal-fired steam generating unit subcategory and the CCS 
combustion turbine subcategory that comply with their standards of 
performance using CCS. Additionally, the utilization applicability 
criterion for existing combustion turbines creates a barrier to 
emission trading under these emission guidelines. Specifically, 
existing combustion turbines that are greater than 300 MW qualify as 
affected EGUs and thus have applicable standards of performance only 
when they operate at an annual capacity factor of greater than 50 
percent. When they operate at an annual capacity factor of 50 percent 
or less, they are not subject to standards of performance. The EPA 
believes that the fact that units may fall in or out of a trading 
program from year to year very likely precludes their inclusion in any 
such program as a practical matter.
    The EPA requests comment on these challenges and on whether, in 
light of these and other considerations, emission trading should be 
permitted for certain subcategories and not permitted for others, and 
on whether emission trading should be limited to within certain 
subcategories, and why. In the following sections, the EPA discusses 
potential rate-based and mass-based emission trading program approaches 
that could potentially be included in a State plan and solicits comment 
on applied implementation issues in the context of these proposed 
emission guidelines and the considerations discussed in this subsection 
XII.E.2.a of the preamble.
b. Rate-Based Emission Trading
    A rate-based trading program allows affected EGUs to trade 
compliance instruments that are generated based on their emission 
performance. This section describes one method of how states could 
establish a rate-based trading program as part of a State plan. The EPA 
requests comment on whether this or another method of rate-based 
trading could demonstrate equivalent stringency as would be achieved if 
each affected EGU was achieving its standard of performance.
    In this example, affected EGUs that perform at a lower emission 
rate (lb CO2/MWh) than their standard of performance would 
be issued compliance instruments that are denominated in one ton of 
CO2. A tradable instrument denominated in another unit of 
measure, such as a MWh, is not fungible in the context of a rate-based 
emission trading program. A compliance instrument denominated in MWh 
that is awarded to one affected EGU may not represent an equivalent 
amount of emissions credit when used by another affected EGU to 
demonstrate compliance, as the CO2 emission rates (lb 
CO2/MWh) of the two affected EGUs are likely to differ. This 
may pose a challenge for states trying to demonstrate equivalence with 
the intended stringency of the BSER.
    These compliance instruments could be transferred among affected 
EGUs, making them ``tradable.'' Compliance would be demonstrated for an 
affected EGU based on a combination of its reported CO2 
emission performance (in lb CO2/MWh) and, if necessary, the 
surrender of an appropriate number of tradable compliance instruments, 
such that the demonstrated lb CO2/MWh emission performance 
is equivalent to the rate-based standard of performance for the 
affected EGU.
    Specifically, each affected EGU would have a particular standard of 
performance, based on the degree of emission limitation achievable 
through application of the BSER, with which it would have to 
demonstrate compliance. Under a rate-based trading program, affected 
EGUs performing at a CO2 emission rate below their standard 
of performance would be awarded compliance instruments at the end of 
each control period denominated in tons of CO2. The number 
of compliance instruments awarded would be equal to the difference 
between their standard of performance CO2 emission rate and 
their actual reported CO2 emission rate multiplied by their 
generation in MWh. Affected EGUs performing worse than their standard 
of performance would be required to obtain and surrender an appropriate 
number of compliance instruments when demonstrating compliance, such 
that their demonstrated CO2 emission rate is equivalent to 
their rate-based standard of performance. Transfer and use of these 
compliance instruments would be accounted for with a rate adjustment as 
each affected EGU performs its compliance demonstration.
    In general, rate-based emission trading can by design assure 
achievement of the requisite level of emission performance for affected 
sources, because reduced utilization and retirements are automatically 
accounted for in the award of the compliance instrument. By default, 
only operating affected EGUs could receive or participate in the 
trading of compliance instruments.
    The EPA is seeking comment on whether rate-based emission trading 
might be appropriate under these emission guidelines, taking into 
consideration the discussion of the appropriateness of trading for 
certain subcategories in section XII.E.2.a of this preamble. In 
particular, the EPA requests comment on whether and how a rate-based 
emission trading program could be designed to ensure equivalent 
stringency as would be achieved if each participating affected EGU was 
achieving its source-specific standard of performance, given the 
structure of the proposed subcategories and their proposed BSERs. The 
EPA also requests comment on any other methods of rate-based trading 
that would preserve the stringency of the BSER.
c. Mass-Based Emission Trading
    A mass-based trading program establishes a budget of allowable mass 
emissions for a group of affected EGUs, with tradable instruments 
(typically referred to as ``allowances'') issued to affected EGUs in 
the amount equivalent to the emission budget. Each allowance would 
represent a tradable permit to emit one ton of CO2, with 
affected EGUs required to surrender allowances in a number equal to 
their reported CO2

[[Page 33395]]

emissions during each compliance period. This section describes one 
method of how states could establish a mass-based trading program as 
part of a State plan. The EPA requests comment on whether this or 
another method of mass-based trading could ensure equivalent stringency 
as would be achieved if each participating affected EGU was achieving 
its source-specific standard of performance.
    As previously discussed, mass-based emission trading has been used 
in the power sector at the Federal, regional, and State levels for 
nearly 3 decades. Owners and operators of EGUs, utilities, and State 
agencies thus have extensive familiarity with mass-based emission 
trading, which could make the design and implementation of a mass-based 
trading program as part of a State plan relatively straightforward. 
However, this familiarity comes with an awareness on the part of states 
and the EPA of the need to tailor the design of a mass-based emission 
trading program to the situation in which it is applied. Past 
experience shows that emission budgets have often been overestimated 
when set many years in advance of the start of a program, as economic 
and technological conditions have changed significantly between the 
time the program was adopted and when compliance obligations begin. 
Projecting affected EGU fleet composition and utilization beyond the 
relative near term has become increasingly challenging, driven by 
factors including changes in relative fuel prices and continued rapid 
improvement in the cost and performance of wind and solar generation, 
along with new incentives for technology deployment provided by the 
IIJA and the IRA. Critically, if affected EGUs reduce utilization or 
exit the source category, the remaining affected EGUs face a reduced or 
eliminated obligation to improve their emission performance. In this 
case, the emission budget would be established at a level such that the 
sources would not be collectively meeting the required level of 
emission performance commensurate with each source achieving its rate-
based standard of performance.
    One program design states might employ to ensure that affected EGUs 
participating in a mass-based trading program continue to meet the 
level of emission performance prescribed by category-wide, source-
specific implementation of the rate-based standards of performance 
includes regularly adjusting emission budgets to account for sources 
that cease operations or change their utilization. One budget 
adjustment method that the EPA has developed is dynamic budgeting, as 
applied in the Good Neighbor Plan,\663\ in which budgets are updated 
annually based on recent historical generation. States could apply a 
similar dynamic budgeting process to mass-based trading implemented 
under these emission guidelines. In this context, states could 
establish an emission budget based on the unit-specific standards of 
performance of the participating affected EGUs, as described in section 
XII.D of this preamble, multiplied by each affected EGU's recent 
historical generation. The emission budget would be updated regularly 
to account for units that reduce utilization or cease operation. This 
is one way that states could assure achievement of the requisite level 
of emission performance for affected EGUs through mass-based trading, 
though the EPA acknowledges that existing State or regional mass-based 
trading programs may have developed other regular emission budget 
adjustment methods that could potentially provide similar assurance and 
might provide a model that could be applied for trading under these 
emission guidelines.
---------------------------------------------------------------------------

    \663\ The final Good Neighbor Plan was signed by the 
Administrator on March 15, 2023. At this time, the final action has 
not yet been published in the Federal Register.
---------------------------------------------------------------------------

    The EPA also acknowledges that other methods could be used to 
establish an emission budget that, in conjunction with the 
aforementioned dynamic budget approach, could achieve at least the 
requisite level of emission performance consistent with application of 
the BSER. States could use a single rate at the level of the 
subcategory or source category that is, for example, as stringent as 
the most controlled unit in the group (based on unit-specific standards 
of performance as defined in section XII.D.1) to establish the emission 
budget.
    The EPA is seeking comment on whether mass-based emission trading 
might be appropriate under these emission guidelines, taking into 
consideration the discussion of the appropriateness of trading for 
certain subcategories in section XII.E.2.a of this preamble. In 
particular, the EPA requests comment on whether and how a mass-based 
emission trading program could be designed to ensure equivalent 
stringency as each participating affected EGU achieving its source-
specific standard of performance, given the structure of the proposed 
subcategories and their proposed BSERs. The EPA is also seeking comment 
on whether the method of mass-based emission trading using dynamic 
budgeting, as discussed in this section, might be appropriate under 
these emission guidelines. The EPA is also seeking comment on other 
approaches or features that could ensure that emission budgets reflect 
the stringency that would be achieved through unit-specific application 
of rate-based standards of performance.
d. General Emission Trading Program Implementation Elements
    The EPA notes that states would need to establish procedures and 
systems necessary to implement and enforce an emission trading program, 
whether it is rate-based or mass-based, if they elect to incorporate 
emission trading into their State plans. This would include, but is not 
limited to, establishing compliance timeframes and the mechanics for 
demonstrating compliance under the program (e.g., surrender of 
compliance instruments as necessary based on monitoring and reporting 
of CO2 emissions and generation); establishing requirements 
for continuous monitoring and reporting of CO2 emissions and 
generation; and developing a tracking system for tradable compliance 
instruments. Additionally, for states implementing a mass-based 
emission trading program, State plans would need to specify how 
allowances would be distributed to participating affected EGUs.
    The EPA acknowledges that the proposed dates as of which standards 
of performance would apply for sources covered by these emission 
guidelines differ by subcategory: January 1, 2030, for all steam 
generating units; January 1, 2032, for the hydrogen co-fired combustion 
turbine subcategory; and January 1, 2035, for the CCS combustion 
turbine subcategory. If trading is permitted for two or more of these 
sets of sources, this difference could potentially pose an 
implementation challenge where a trading program includes these 
sources. To address this issue, a program could, for example, begin in 
2030 for steam generating units and bring in combustion turbine EGUs 
later, or states could delay implementation of a trading program to 
coincide with the later combustion turbine date. The Agency requests 
comment on potential ways to address this implementation issue in the 
context of a State plan, and whether this issue impacts the utility or 
feasibility of trading across subcategories.
    The EPA is also requesting comment on whether and to what extent 
there would be a desire to capitalize on the EPA's existing reporting 
and compliance tracking infrastructure to support State implementation 
of an

[[Page 33396]]

emission trading program included in a State plan.
e. Banking of Compliance Instruments
    The EPA requests comment on whether State plans should be allowed 
to provide for banking of tradable compliance instruments (hereafter 
referred to as ``allowance banking,'' although it is relevant for both 
mass-based and rate-based trading programs). Allowance banking has 
potential implications for a trading program's ability to maintain the 
requisite stringency of the standards of performance. The EPA 
recognizes that allowance banking--that is, permitting allowances that 
remain unused in one control period to be carried over for use in 
future control periods--may provide incentives for early emission 
reductions, promote operational flexibility and planning, and 
facilitate market liquidity. However, the EPA has observed that 
unrestricted allowance banking from one control period to the next 
(absent provisions that adjust future control period budgets to account 
for banked allowances) may result in a long-term allowance surplus that 
has the potential to undermine a trading program's ability to ensure 
that, at any point in time, the affected sources are achieving the 
required level of emission performance. In addition to requesting 
comment on whether the EPA should permit allowance banking, the EPA 
requests comment on the treatment of banked allowances, specifically 
whether all or only some portion of an allowance bank could be carried 
over for use in future control periods or if additional program design 
elements would be necessary to accommodate allowance banking.
f. Interstate Emission Trading
    The EPA is requesting comment on whether, and under what 
circumstances or conditions, to allow interstate emission trading under 
these emission guidelines. Given the interconnectedness of the power 
sector and given that many utilities operate in multiple states, 
interstate emission trading may increase compliance flexibility. For 
interstate emission trading programs to function successfully, all 
participating states would need to, at a minimum, use the same form of 
trading and have identical trading program requirements. There are many 
requirements for program reciprocity and approvability that would need 
to be established in the emission guidelines, in addition to providing 
mechanisms for submission and EPA review of State plans that include 
interstate trading mechanisms. Given the increased level of program 
complexity that would be necessary to accommodate interstate trading 
and the operational flexibilities already provided by the structure of 
the proposed subcategories and their proposed BSERs, the EPA requests 
comment on whether there is utility in providing for it under these 
emission guidelines. In addition, the EPA requests comment on the 
information, guidance, and requirements the EPA would need to provide 
for states to implement successful interstate emission trading 
programs.
3. Rate-Based Averaging
    The EPA is proposing to allow State plans to include rate-based 
averaging as a compliance flexibility for affected EGUs under these 
emission guidelines. This section discusses how states could 
potentially incorporate a rate-based averaging program in a way that 
preserves the stringency of the EPA's BSER as well as some 
considerations related to incorporating averaging in State plans. The 
EPA is seeking comment on one potential method, described in this 
section, as well as other methods that could maintain the required 
level of emission performance equivalent to each source individually 
achieving its standard of performance.
    Averaging allows multiple affected EGUs to jointly meet a rate-
based standard of performance. Affected EGUs participating in averaging 
could, for example, demonstrate compliance through an effective 
CO2 emission rate that is based on a gross generation-based 
weighted average of the required standards of performance of the 
affected EGUs that participate in averaging. The scope of such 
averaging could apply at the facility level or the owner or operator 
level. This method for calculating a composite rate could demonstrate 
equivalence with source-specific standards of performance.
    Averaging can provide potential benefits. First, it offers some 
flexibility for sources to target cost effective reductions at any 
affected EGU. For example, owners or operators of affected EGUs might 
target installation of emission control approaches at units that 
operate more. Second, averaging at the facility level provides greater 
ease of compliance accounting for affected EGUs with a complex stack 
configuration (such as a common- or multi-stack configuration). In such 
instances, unit-level compliance involves apportioning reported 
emissions to individual affected EGUs that share a stack based on 
electricity generation or other parameters.
    However, the EPA notes that the subcategory approach in these 
emission guidelines already provides significant operational 
flexibility for affected EGUs, potentially making the provision of 
further flexibility through averaging redundant or inappropriate, 
especially at the owner or operator level.
    The EPA is seeking comment on the utility of rate-based averaging 
as a compliance flexibility, as well as on the illustrative method for 
developing a composite standard of performance for the purposes of 
rate-based averaging. The EPA is also seeking comment on any other 
considerations related to rate-based averaging, including whether the 
scope of averaging should be limited to a certain level of aggregation 
(e.g., to facility-level rate-based averaging) or to certain 
subcategories.
4. Relationship to Existing State Programs
    The EPA recognizes that many states have adopted binding policies 
and programs (with both a supply-side and demand-side focus) under 
their own authorities that have significantly reduced CO2 
emissions from EGUs, that these policies will continue to achieve 
future emission reductions, and that states may continue to adopt new 
power sector policies addressing GHG emissions. States have exercised 
their power sector authorities for a variety of purposes, including 
economic development, energy supply and resilience goals, conventional 
and GHG pollution reduction, and generating allowance proceeds for 
investments in communities disproportionately impacted by environmental 
harms. The scope and approach of EPA's proposed emission guidelines 
differs significantly from the range of policies and programs employed 
by states to reduce power sector CO2 emissions, and this 
proposal operates more narrowly to improve the CO2 emission 
performance of a subset of EGUs within the broader electric power 
sector. The Agency recognizes the importance of State programs and 
their potential to reduce power sector CO2 emissions through 
a range of strategies broader than those proposed here pursuant to CAA 
section 111(d). The EPA seeks comment on whether there are any elements 
of the proposed emission guidelines that might interfere with the 
implementation of State requirements that limit CO2 
emissions from EGUs that may be subject to the proposed emission 
guidelines.

F. State Plan Components and Submission

    This section describes the proposed requirements for the contents 
of State plans, the proposed timing of State plan submissions, and the 
EPA's review of

[[Page 33397]]

and action on State plan submissions. This section also discusses 
issues related to the applicability of a Federal plan and timing for 
the promulgation of a Federal plan.
    As explained earlier in this preamble, the requirements of 40 CFR 
part 60, subpart Ba, govern State plan submissions under these emission 
guidelines. Where the EPA is proposing to add to, supersede, or 
otherwise vary the requirements of subpart Ba for the purposes of State 
plan submissions under these particular emission guidelines,\664\ those 
proposals are addressed explicitly in section XII.F.1.b on specific 
State plan requirements and throughout this preamble. Unless expressly 
amended or superseded in these proposed emission guidelines, the 
provisions of subpart Ba would apply.
---------------------------------------------------------------------------

    \664\ 40 CFR 60.20a(a)(1).
---------------------------------------------------------------------------

1. Components of a State Plan Submission
    The EPA is proposing that a State plan must include a number of 
discrete components. These proposed plan components include those that 
apply for all State plans pursuant to 40 CFR part 60, subpart Ba. The 
EPA is also proposing additional plan components that are specific to 
State plans submitted pursuant to these emission guidelines. For 
example, the EPA is proposing plan components that are necessary to 
implement and enforce the specific types of standards of performance 
for affected EGUs that would be adopted by a State and incorporated 
into its State plan.
a. General Components
    The CAA section 111 implementing regulations at 40 CFR part 60 
subpart Ba provide separate lists of administrative and technical 
criteria that must be met in order for a State plan submission to be 
deemed complete. The EPA's proposed revisions to subpart Ba would add 
one item to the list of administrative criteria related to meaningful 
engagement (element 9 in the list below).\665\ If that criterion is 
finalized as proposed, the complete list of applicable administrative 
completeness criteria for State plan submissions would be: (1) A formal 
letter of submittal from the Governor or the Governor's designee 
requesting EPA approval of the plan or revision thereof; (2) Evidence 
that the State has adopted the plan in the State code or body of 
regulations; or issued the permit, order, or consent agreement 
(hereafter ``document'') in final form. That evidence must include the 
date of adoption or final issuance as well as the effective date of the 
plan, if different from the adoption/issuance date; (3) Evidence that 
the State has the necessary legal authority under State law to adopt 
and implement the plan; (4) A copy of the official State regulation(s) 
or document(s) submitted for approval and incorporated by reference 
into the plan, signed, stamped, and dated by the appropriate State 
official indicating that they are fully adopted and enforceable by the 
State. The effective date of the regulation or document must, whenever 
possible, be indicated in the document itself. The State's electronic 
copy must be an exact duplicate of the hard copy. For revisions to the 
approved plan, the submission must indicate the changes made to the 
approved plan by redline/strikethrough; (5) Evidence that the State 
followed all applicable procedural requirements of the State's 
regulations, laws, and constitution in conducting and completing the 
adoption/issuance of the plan; (6) Evidence that public notice was 
given of the plan or plan revisions with procedures consistent with the 
requirements of 40 CFR 60.23, including the date of publication of such 
notice; (7) Certification that public hearing(s) were held in 
accordance with the information provided in the public notice and the 
State's laws and constitution, if applicable and consistent with the 
public hearing requirements in 40 CFR 60.23; (8) Compilation of public 
comments and the State's response thereto; and (9) Evidence of 
meaningful engagement, including a list of pertinent stakeholders, a 
summary of the engagement conducted, and a summary of stakeholder input 
received.
---------------------------------------------------------------------------

    \665\ 87 FR 79176, 79204 (December 23, 2022), Docket ID No. EPA-
HQ-OAR-2021-0527-0002 (proposed revisions at 40 CFR 60.27a(g)(2)).
---------------------------------------------------------------------------

    Pursuant to subpart Ba, the technical criteria required for all 
plans must include each of the following: \666\ (1) Description of the 
plan approach and geographic scope; (2) Identification of each 
designated facility (i.e., affected EGU); identification of standards 
of performance for each affected EGU; and monitoring, recordkeeping, 
and reporting requirements that will determine compliance by each 
designated facility; (3) Identification of compliance schedules and/or 
increments of progress; (4) Demonstration that the State plan 
submission is projected to achieve emission performance under the 
applicable emission guidelines; (5) Documentation of State 
recordkeeping and reporting requirements to determine the performance 
of the plan as a whole; and (6) Demonstration that each standard is 
quantifiable, permanent, verifiable, enforceable, and non-duplicative.
---------------------------------------------------------------------------

    \666\ 40 CFR 60.27a(g)(3)).
---------------------------------------------------------------------------

b. Specific State Plan Requirements
    To ensure that State plans submitted pursuant to these emission 
guidelines are consistent with the requirements of subpart Ba, the EPA 
is proposing regulatory requirements that would apply to all affected 
EGUs subject to a standard of performance under a State plan pursuant 
to these proposed emission guidelines, as well as requirements that 
apply to affected EGUs within specific subcategories. Standards of 
performance for affected EGUs included in a State plan must be 
quantifiable, verifiable, permanent, enforceable, and non-duplicative. 
Additionally, per CAA section 302(l), standards of performance must be 
continuous in nature. Additional proposed State plan requirements 
include:
     Identification of affected EGUs and the subcategory to 
which each affected EGU is assigned;
     Identification of standards of performance for each 
affected EGU in lb CO2/MWh-gross basis, including provisions 
for implementation and enforcement of such standards;
     Identification of enforceable increments of progress and 
milestones, as required for affected EGUs within the applicable 
subcategory, included as enforceable elements of a State plan;
     If relevant, identification of applicable enforceable 
requirements that are prerequisites for inclusion of an affected EGU in 
a specific subcategory, such as enforceable commitments to cease 
operations by a specified date or to limit annual capacity factor, 
where a State and the owner or operator of an affected EGU have chosen 
to rely on such commitments in order for the affected EGU to be 
included in a specific subcategory, included as enforceable elements of 
a State plan; and
     Identification of applicable monitoring, reporting, and 
recordkeeping requirements for affected EGUs.
    The proposed emission guidelines include requirements pertaining to 
the methodologies states must use for establishing a presumptively 
approvable standard of performance for an affected EGU within a 
respective subcategory. These proposed methodologies are specified for 
each of the subcategories of affected EGUs in section XII.D.1 of this 
preamble.

[[Page 33398]]

    The EPA notes that standards of performance for affected EGUs in a 
State plan must be representative of the level of emission performance 
that results from the application of the BSER in these emission 
guidelines. As discussed in section XII.C of this preamble, in order 
for the EPA to find a State plan ``satisfactory,'' that plan must 
achieve the level of emission performance that would result if each 
affected source was achieving its presumptive standard of performance, 
after accounting for any application of RULOF. That is, while states 
have the discretion to establish the applicable standards of 
performance for affected sources in their State plans, the structure 
and purpose of CAA section 111 require that those plans achieve an 
equivalent level of emission performance as applying the EPA's 
presumptive standards of performance to those sources (again, after 
accounting for any application of RULOF).
    The proposed emission guidelines also include requirements that 
apply to states when they invoke RULOF in applying a less stringent 
standard of performance for an affected EGU than the presumptively 
approvable standard of performance. Such requirements include a 
demonstration by the State of why an affected EGU for which the State 
invokes RULOF cannot reasonably apply the BSER. The State would also be 
required to demonstrate where and how it considered the potential 
pollution impacts and benefits of control to communities most affected 
by and vulnerable to emissions from the designated facility. The EPA 
expects that states would identify these communities, gather 
information about the potential pollution impacts and benefits of 
control, and document how they have considered that information in 
setting source-specific standards of performance for RULOF sources 
through their meaningful engagement processes.
    In addition to consideration of impacts on and benefits to affected 
communities in the context of invoking RULOF for particular sources, 
the proposed revisions to the CAA section 111 subpart Ba implementing 
regulations include requirements for public engagement on overall State 
plan development. These requirements are intended to ensure robust and 
meaningful public involvement in the plan development process and to 
ensure that those who are most affected by and vulnerable to the 
impacts of a plan will share in the benefits of the plan and are 
protected from being adversely impacted. The proposed requirements are 
in addition to the existing public notice requirements under subpart Ba 
and, if finalized, would apply to State plan development in the context 
of these emission guidelines.
    The fundamental purpose of CAA section 111 is to reduce emissions 
from categories of stationary sources that cause, or significantly 
contribute to, air pollution which may reasonably be anticipated to 
endanger public health or welfare. Therefore, a key consideration in 
the State's development of a State plan is the potential impact of the 
proposed plan requirements on public health and welfare. Meaningful 
engagement is a corollary to the longstanding requirement for public 
participation, including through public hearings, in the course of 
State plan development under CAA section 111.\667\ A robust and 
meaningful engagement process is critical to ensuring that the entire 
public has an opportunity to participate in the State plan development 
process and that states understand and consider the full range of 
impacts of a proposed plan.
---------------------------------------------------------------------------

    \667\ 40 CFR 60.23(c)-(g); 40 CFR 60.23a(c)-(h).
---------------------------------------------------------------------------

    In the subpart Ba revisions of December 2022, the EPA proposed to 
define meaningful engagement as:

    [T]timely engagement with pertinent stakeholder representation 
in the plan development or plan revision process. Such engagement 
must not be disproportionate in favor of certain stakeholders. It 
must include the development of public participation strategies to 
overcome linguistic, cultural, institutional, geographic, and other 
barriers to participation to assure pertinent stakeholder 
representation, recognizing that diverse constituencies may be 
present within any particular stakeholder community. It must include 
early outreach, sharing information, and soliciting input on the 
State plan.\668\
---------------------------------------------------------------------------

    \668\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.21a(k)).

    The EPA proposed to define that pertinent stakeholders ``include 
but are not limited to, industry, small businesses, and communities 
most affected by and/or vulnerable to the impacts of the plan or plan 
revision.'' \669\ The preamble to the proposed revisions to subpart Ba 
notes that ``increased vulnerability of communities may be 
attributable, among other reasons, to both an accumulation of negative 
and lack of positive environmental, health, economic, or social 
conditions within these populations or communities.'' \670\
---------------------------------------------------------------------------

    \669\ 87 FR 79176, 79191 (December 23, 2022), Docket ID No. EPA-
HQ-OAR-2021-0527-0002 (proposed revisions at 40 CFR 60.21a(l)).
    \670\ 87 FR 79176, 79191 (December 23, 2022).
---------------------------------------------------------------------------

    In the context of these emission guidelines, the air pollutant of 
concern is greenhouse gases and the air pollution is elevated 
concentrations of these gases in the atmosphere, which result in 
warming temperatures and other changes to the climate system that are 
leading to serious and life-threatening environmental and human health 
impacts. Thus, one set of impacts on communities that states should 
consider in identifying pertinent stakeholders is climate change 
impacts, including increased incidence of drought and flooding, damage 
to crops and disruption of associated food, fiber, and fuel production 
systems, increased incidence of pests, increased incidence of heat-
induced illness, and impacts on water availability and water quality.
    These and other such climate change-related impacts can have a 
disproportionate impact on communities and populations depending on, 
inter alia, accumulation of negative and lack of positive 
environmental, health, economic, or social conditions. The Agency 
therefore expects states' pertinent stakeholders to include not only 
owners and operators of affected EGUs but also communities within the 
State that are most affected by and/or vulnerable to the impacts of 
climate change, including those exposed to more extreme drought, 
flooding, and other severe weather impacts, including extreme heat and 
cold (states should refer to section III of this preamble, on climate 
impacts, to assist them in identifying their pertinent stakeholders).
    Additionally, communities near affected EGUs may also be affected 
by a State plan or plan revision due to impacts associated with 
implementation of that plan. For example, communities located near 
affected EGUs may be impacted by construction and operation of 
infrastructure required under a State plan. Activities related to the 
construction and operation of new natural gas, CCS, and hydrogen 
pipelines may impact individuals and communities both locally and at 
larger distances from affected EGUs but near any associated pipelines. 
Thus, communities near affected EGUs and communities near pipelines 
constructed pursuant to State plan requirements should be considered 
pertinent stakeholders and included in meaningful engagement.
    The EPA also acknowledges that employment at affected EGUs 
(including employment in operation and maintenance as well as in 
construction for installation of pollution control technology) is 
impacted by power sector trends on an ongoing basis, and states may 
choose to take energy communities into consideration as part of 
meaningful engagement. A variety of Federal

[[Page 33399]]

programs are available to support these communities.\671\
---------------------------------------------------------------------------

    \671\ An April 2023 report of the Federal Interagency Working 
Group on Coal and Power Plant Communities and Economic 
Revitalization (Energy Communities IWG) summarizes how the 
Bipartisan Infrastructure Law, CHIPS and Science Act, and Inflation 
Reduction Act have greatly increased the amount of Federal funding 
relevant to meeting the needs of energy communities, as well as how 
the Energy Communities IWG has launched an online Clearinghouse of 
broadly available Federal funding opportunities relevant for meeting 
the needs and interests of energy communities, with information on 
how energy communities can access Federal dollars and obtain 
technical assistance to make sure these new funds can connect to 
local projects in their communities. Interagency Working Group on 
Coal and Power Plant Communities and Economic Revitalization. 
``Revitalizing Energy Communities: Two-Year Report to the 
President'' (April 2023). https://energycommunities.gov/wp-content/uploads/2023/04/IWG-Two-Year-Report-to-the-President.pdf.
---------------------------------------------------------------------------

    In some cases, an affected EGU may be located near State or Tribal 
borders and impact communities in neighboring states or Tribal lands. 
In such cases, the EPA believes it could be reasonable for a State to 
identify pertinent stakeholders in the neighboring State or Tribal land 
and to work with the relevant air pollution control authority to 
conduct meaningful engagement that addresses cross-border impacts. The 
EPA solicits comment on how meaningful engagement should apply to 
pertinent stakeholders outside a State's borders.
    It is important for states to recognize and engage the communities 
most affected by and/or vulnerable to the impacts of a State plan, 
particularly as these communities may not have had a voice when the 
affected EGUs were originally constructed. Consistent with the long-
standing requirements for public engagement in State plan development, 
states should design meaningful engagement to ensure that all pertinent 
stakeholders are able to provide input on how affected EGUs in their 
State comply with their State plan requirements pursuant to these 
emission guidelines. Because these emission guidelines address air 
pollution that becomes well mixed and is long-lived in the atmosphere, 
the EPA expects states will consider communities and populations within 
the State that are both most impacted by particular affected EGUs and 
associated pipelines and that will be most affected by the overall 
stringency of State plans. (Note that the EPA addresses consideration 
of impacts of particular sources in the context of RULOF in section 
XII.D.2.c of this preamble.)
    During 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 any deployment of CCS can and 
should take place in a manner that is protective of public health, 
safety, and the environment, and that includes 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.'' \672\
---------------------------------------------------------------------------

    \672\ Carbon Capture, Utilization, and Sequestration Guidance, 
87 FR 8808, 8809 (February 16, 2022), https://www.govinfo.gov/content/pkg/FR-2022-02-16/pdf/2022-03205.pdf.
_____________________________________-

    As discussed in section V.C.3 of this preamble, the EPA is required 
to consider nonair quality health and environmental impacts, along with 
other considerations, in determining the BSER for both new and existing 
affected EGUs. In developing this proposed rulemaking, the EPA heard 
and carefully considered concerns expressed by affected communities 
regarding the possible impacts of CCS and hydrogen infrastructure in 
the context of selecting the proposed BSER. After weighing any adverse 
nonair quality health and environmental impacts of CCS and hydrogen co-
firing along with the other BSER considerations, including the 
significant amount of emission reductions that can be achieved, and the 
reasonableness of the control costs, the EPA decided to propose that 
CCS and hydrogen co-firing meet the qualifications for the BSER for 
certain subcategories of sources. See, for example, section X.D.1.a.iii 
of this preamble.
    The EPA recognizes, however, that facility- and community-specific 
circumstances, including the existence of cumulative impacts affecting 
a community's resilience or where infrastructure buildout would 
necessarily occur in an already vulnerable community, may also exist. 
The meaningful engagement process is designed to identify and enable 
consideration of these and other facility- and community-specific 
circumstances. This includes consideration of facility- and community-
specific concerns with emissions control systems, including CCS and 
hydrogen co-firing. States should design meaningful engagement to 
elicit input from pertinent stakeholders on facility- and community-
specific issues related to implementation of emissions control systems 
generally, as well as on any considerations for particular systems.
    If the revisions to subpart Ba are finalized as proposed, states 
would need to demonstrate in their State plans how they provided 
meaningful engagement with the pertinent stakeholders. This includes 
providing a list of the pertinent stakeholders, a summary of engagement 
conducted, and a summary of the stakeholder input provided, including 
information about the potential pollution impacts and benefits of 
control. As previously noted, the State must allow for balanced 
participation, including communities most vulnerable to the impacts of 
the plan. States must consider the best way to reach affected 
communities, which may include but should not be limited to 
notification through the internet. Other channels may include notice 
through newspapers, libraries, schools, hospitals, travel centers, 
community centers, places of worship, gas stations, convenience stores, 
casinos, smoke shops, Tribal Assistance for Needy Families offices, 
Indian Health Services, clinics, and/or other community health and 
social services as appropriate. The State should also consider any 
geographic, linguistic, or other barriers to participation in 
meaningful engagement for members of the public. If a State plan 
submission does not meet the required elements for notice and 
opportunity for public participation, including requirements for 
meaningful engagement, this may be grounds for the EPA to find the 
submission incomplete or to disapprove the plan. As discussed in 
section XII.F.2 of this preamble, the EPA is proposing to provide 24 
months from the date of publication of final emission guidelines for 
State plan submission, which should allow states adequate time to 
conduct meaningful engagement.
    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). The EPA is also requesting comment on any tools or 
methodologies that states may find helpful for identifying communities 
that are most affected by and vulnerable to emissions from affected 
EGUs under these emission guidelines. The EPA is also requesting 
comment on whether it would be useful for the Agency to promulgate 
minimum approvability requirements for

[[Page 33400]]

meaningful engagement that are specific to these emission guidelines 
and, if so, what those requirements should be.
i. Specific State Plan Requirements for Existing Combustion Turbines 
Co-Firing Low-GHG Hydrogen
    As discussed in section XI.C of this preamble, the EPA is proposing 
that the BSER for affected combustion turbine EGUs in the hydrogen co-
fired subcategory is co-fired 30 percent low-GHG hydrogen by volume 
starting January 1, 2032, and 96 percent low-GHG hydrogen by volume 
starting January 1, 2038. Therefore, as discussed in section 
XII.D.1.c.ii of this preamble, the EPA is proposing a rate-based 
presumptive standard of performance for the hydrogen co-fired 
subcategory based on co-firing low-GHG hydrogen at these levels. 
However, CAA section 111 does not require that sources meet their 
applicable standards of performance by implementing the BSER. 
Therefore, affected combustion turbine EGUs in the hydrogen co-fired 
subcategory do not necessarily have to meet their standards of 
performance by co-firing hydrogen. However, should they choose to 
comply in this manner, the hydrogen that they co-fire to meet their 
standards of performance must be low-GHG hydrogen. Thus, the EPA is 
proposing that State plans require that affected EGUs in the hydrogen 
co-fired subcategory that meet their standards of performance by co-
firing hydrogen demonstrate that they are co-firing low-GHG hydrogen. 
The EPA discusses its rationale for requiring low-GHG hydrogen to be 
used for compliance and its proposed definition of low-GHG hydrogen in 
sections VII.F.3.c.vi and VII.F.3.c.vii(F) of this preamble.
    Section VII.K.3 of this preamble discusses the EPA's proposal to 
closely follow Department of Treasury protocols, which are currently 
under development, in determining how affected EGUs demonstrate 
compliance with the requirement to use low-GHG hydrogen. In the context 
of the proposed CAA section 111(b) rule for new combustion turbines, 
the EPA is taking comment on what forms of acceptable mechanisms and 
documentary evidence should be required for EGUs to demonstrate 
compliance with the obligation to co-fire low-GHG hydrogen, including 
proof of production pathway, overall emissions calculations or modeling 
results and input, purchasing agreements, contracts, and attribute 
certificates. The EPA is also taking comment, in the context of the CAA 
section 111(b) rule, on whether EGUs should be required to make fully 
transparent their sources of low-GHG hydrogen and the corresponding 
quantities procured, as well as on whether the EPA should require EGUs 
to demonstrate that their hydrogen is exclusively from facilities that 
produce only low-GHG hydrogen, as a means of reducing burden and 
opportunities for double counting. The EPA proposed to mirror the 
requirements it finalizes for verification of low-GHG hydrogen for new 
combustion turbine EGUs, as discussed in section VII.K.3 of this 
preamble, in the State plan requirements for affected existing 
combustion turbine EGUs in the hydrogen co-fired subcategory under 
these emission guidelines. The EPA therefore requests comment on the 
proposed approaches for verifying that low-GHG hydrogen is used for 
complying with an applicable standard of performance discussed in 
section VII.K.3 of this preamble. Additionally, the EPA requests 
comment on any unique considerations regarding the implementation of 
such verification requirements through State plans, including whether 
any additional or different requirements may be necessary to ensure 
that affected existing combustion turbine EGUs in the hydrogen co-
firing subcategory that co-fire hydrogen to meet their standards of 
performance co-fire with low-GHG hydrogen.
ii. Specific State Plan Requirements for Transparency and Compliance 
Assurance
    The EPA is proposing or requesting comment on several requirements 
designed to help states ensure compliance by affected EGUs with 
standards of performance, as well as to assist the public in tracking 
increments of progress toward the final compliance date.
    First, the EPA is requesting comment on whether to require that an 
affected EGU's enforceable commitment to permanently cease operations, 
when a State relies on that commitment for subcategory applicability 
(e.g., a State elects to rely on an affected coal-fired steam-
generating unit's commitment to permanently cease operations by 
December 31, 2034, to meet the applicability requirements for the near-
term subcategory), must be in the form of an emission limit of 0 lb 
CO2/MWh that applies on the relevant date.\673\ Such an 
emission limit would be included in a State regulation, permit, order, 
or other acceptable legal instrument and submitted to the EPA as part 
of a State plan. If approved, the affected EGU would have a federally 
enforceable emission limit of 0 lb CO2/MWh that would become 
effective as of the date that the EGU permanently ceases operations. 
The EPA is requesting comment on whether such an emission limit would 
have any advantages or disadvantages for compliance and enforceability 
relative to the alternative, which is an enforceable commitment in a 
State plan to cease operation by a date certain.
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    \673\ As explained in section X of this preamble, an affected 
EGU's federally enforceable commitment to cease operations is not 
part of that EGU's standard of performance but is rather a 
prerequisite condition for subcategory applicability.
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    Second, the EPA is proposing that State plans that cover affected 
coal-fired steam generating units within any subcategory that is based 
on the date by which a source elects to permanently cease operations 
(i.e., imminent-term, near-term, medium-term) must include, in 
conjunction with an enforceable date, the requirement that each source 
comply with applicable State and Federal requirements for permanently 
ceasing operation of the EGU, including removal from its respective 
State's air emissions inventory and amending or revoking all applicable 
permits to reflect the permanent shutdown status of the EGU.
    Third, the EPA is proposing that each State plan must require 
owners and operators of affected EGUs to establish publicly accessible 
websites, referred to here as a ``Carbon Pollution Standards for EGUs 
website,'' to which all reporting and recordkeeping information for 
each affected EGU subject to the State plan would be posted. Although 
this information will also be required to be submitted directly to the 
EPA and the relevant State regulatory authority, the EPA is interested 
in ensuring that the information is made accessible in a timely manner 
to all pertinent stakeholders. The EPA anticipates that the owners or 
operators of a portion of the affected EGUs may already be posting 
comparable reporting and recordkeeping information to publicly 
available websites under the EPA's April 2015 Coal Combustion Residuals 
Rule,\674\ such that the burden of this website requirement for these 
units could be minimal.
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    \674\ See https://www.epa.gov/coalash/list-publicly-accessible-internet-sites-hosting-compliance-data-and-information-required for 
a list of websites for facilities posting Coal Combustion Rule 
compliance information.
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    In particular, the EPA is proposing that the owners or operators of 
affected EGUs would be required to post to their websites their 
subcategory designations and compliance schedules, including for 
increments of progress and milestones, leading up to full

[[Page 33401]]

compliance with the applicable standards of performance. Owners or 
operators would also be required to post to their websites any 
information or documentation needed to demonstrate that an increment of 
progress or milestone has been achieved. Similarly, the EPA is 
proposing that emissions data and other information needed to 
demonstrate compliance with a standard of performance would also be 
required to be posted to the Carbon Pollution Standards for EGUs 
website for an affected EGU in a timely manner. The EPA is proposing 
that all information required to be made publicly available on the 
Carbon Pollution Standards for EGUs website be posted within 30 
business days of the information becoming available to or reported by 
the owner or operator of an affected EGU. Information would have to 
remain on the website for a minimum of 10 years. The EPA solicits 
comment on these timeframes for posting and information retention, as 
well as on any concerns related to confidential business information.
    The EPA proposes that owners or operators of affected EGUs that are 
also subject to similar website reporting requirements for the Coal 
Combustion Residuals Rule may use an already established website to 
house the reporting and recordkeeping information necessary to satisfy 
its Carbon Pollution Standards for EGUs website requirements. The EPA 
solicits comment on other ways to reduce redundancy and burden while 
satisfying the objective of making it easier for pertinent stakeholders 
to access affected EGUs' reporting and recordkeeping information.
    To make it easier for the public to find the relevant Carbon 
Pollution Standards for EGUs websites, the EPA is also proposing that a 
State must establish a website that displays the links to the websites 
for all affected EGUs in its State plan.
    Fourth, to promote transparency and to assist the EPA and the 
public in assessing increments of progress under a State plan, the EPA 
is proposing that State plans must include a requirement that the owner 
or operator of each affected EGU must report any deviation from any 
federally enforceable State plan increment of progress or milestone 
within 30 business days after the owner or operator of the affected EGU 
knew or should have known of the event. In the report, the owner or 
operator of the affected EGU would be required to explain the cause or 
causes of the deviation and describe all measures taken or to be taken 
by the owner or operator of the EGU to cure the reported deviation and 
to prevent such deviations in the future, including the timeframes in 
which the owner or operator intends to cure the deviation. The owner or 
operator of the EGU must submit the report to the State regulatory 
agency and post the report to the affected EGU's Carbon Pollution 
Standards for EGUs website.
    Fifth, to aid all affected parties and stakeholders in implementing 
these emission guidelines, the EPA is explaining its intended approach 
to exercising its enforcement authorities to ensure compliance while 
addressing genuine risks to electric system reliability. In these 
emission guidelines, the EPA has included subcategories for coal-fired 
steam generating units that take into account the operating horizons of 
these units and has provided relatively long planning and compliance 
timeframes. The EPA's proposed emission guidelines for existing 
combustion turbines likewise provide extensive lead time to meet the 
proposed degrees of emission limitation and apply only to a portion of 
the fleet that exceeds certain capacity and utilization thresholds. The 
Agency therefore does not anticipate that either the need for certain 
coal-fired steam generating units and existing combustion turbines to 
install controls, or affected EGUs' preexisting decisions to 
permanently cease operations, will result in resource constraints that 
would adversely affect electric reliability.
    Nonetheless, the EPA believes it is appropriate to provide 
accommodations for potential isolated instances in which unanticipated 
factors beyond an owner or operator's control, and ability to predict 
and plan for, could have an adverse, localized impact on electric 
reliability. In such instances, affected EGUs could find themselves in 
the position of either operating in noncompliance with approved, 
federally enforceable State plan requirements or halting operations and 
thereby potentially impacting electric reliability.
    CAA section 113 authorizes the EPA to bring enforcement actions 
against sources in violation of CAA requirements, seeking injunctive 
relief, civil penalties and, in certain circumstances, other 
appropriate relief. The EPA also has the discretion to agree to 
negotiated resolutions, including administrative compliance orders 
(``ACOs'') for achieving compliance with CAA requirements, that include 
expeditious compliance schedules with enforceable compliance 
milestones. The EPA does not generally speak to the intended scope of 
its enforcement efforts, particularly in advance of a violation 
actually occurring. However, the EPA is explaining its intended 
approach to ACOs here to provide confidence both with respect to 
electric reliability and that emission reductions under these emission 
guidelines will occur as required under CAA section 111(d).
    The EPA would evaluate each request for an ACO for an affected EGU 
that is required to run in violation of a State plan requirement for 
reliability purposes on a case-by-case basis. However, as a general 
matter, the EPA anticipates that to qualify for an ACO, the owner/
operator would need to demonstrate, as a minimum, that the following 
conditions have been satisfied: \675\
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    \675\ This is a nonexclusive list of conditions. The EPA may 
choose to consider additional factors when deciding whether to enter 
an ACO in any given situation.
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     The owner/operator of the affected EGU requesting an ACO 
has requested, in writing and in a timely manner, an enforceable 
compliance schedule in an ACO.
     The owner/operator of the affected EGU requesting an ACO 
has provided the EPA written analysis and documentation of reliability 
risk if the unit were not in operation, which demonstrates that 
operation of the unit in noncompliance is critical to maintaining 
electric reliability and that failure to operate the unit would result 
in violation of the established reliability criteria for the relevant 
control area/balancing authority, or cause reserves to fall below the 
required system reserve margin.
     The owner/operator of the affected EGU requesting an ACO 
has provided the EPA with written concurrence with the reliability 
analysis from the relevant electric planning authority for the area in 
which the affected EGU is located.
     The owner/operator of the affected EGU requesting an ACO 
has demonstrated that the need to continue operating for reliability 
purposes is due to factors beyond the control of the owner/operator and 
that the owner/operator of the affected EGU has not contributed to the 
purported need for an ACO.
     The owner/operator of the affected EGU requesting an ACO 
demonstrates that it has met all applicable increments of progress and 
milestones in the State plan.
     It can be demonstrated that there is insufficient time to 
address the reliability risk and potential noncompliance through a 
State plan revision.
    If deemed appropriate to do so, the EPA would issue an ACO that 
includes

[[Page 33402]]

a compliance schedule and milestones to achieve compliance as 
expeditiously as practicable. The ACO would also include any 
operational limits, including limits on utilization reflecting the 
extent to which the unit is needed for grid reliability, and/or work 
practices necessary to minimize or mitigate any emissions to the 
maximum extent practicable during any operation of the affected EGU 
before it has achieved full compliance. The EPA reiterates that it 
would not be appropriate to request an ACO to address reliability risk 
and anticipated noncompliance in circumstances in which a State plan 
revision is possible.
    The EPA requests comment on whether to promulgate requirements in 
the final emission guidelines pertaining to the demonstrations, 
analysis, and information the owner or operator of an affected EGU 
would have to submit to the EPA in order to be considered for an ACO.
2. Timing of State Plan Submissions
    The EPA's proposed subpart Ba revisions would require states to 
submit State plans within 15 months after publication of the final 
emission guidelines.\676\ For the purpose of these particular emission 
guidelines, the EPA is proposing to supersede that timeline and is 
proposing a State plan submission deadline that is 24 months from the 
date of publication of the final emission guidelines. Crucially, these 
proposed emission guidelines apply to a relatively large and complex 
source category--existing fossil fuel-fired steam generating units and 
existing fossil fuel-fired combustion turbines. Making the decisions 
necessary for State plan development will require significant analysis, 
consultation, and coordination between states, utilities, ISOs or RTOs, 
and the owners or operators of individual affected EGUs. The power 
sector is subject to many layers of regulatory and other requirements 
under many authorities, and the decisions states make under these 
emission guidelines will necessarily have to accommodate many 
overlapping considerations and processes. States' plan development may 
be additionally complicated by the fact that, unlike some other source 
sectors to which the general CAA section 111 implementing regulations 
apply, decision-making regarding control strategies and operations for 
affected EGUs may not be solely within the purview of the owners or 
operators of those sources; at the very least, affected EGUs often must 
obtain permission before making significant or permanent changes. The 
EPA does not believe it is reasonable to expect states and affected 
EGUs to undertake the coordination and planning necessary to ensure 
that their plans for implementing these emission guidelines are 
consistent with the broader needs and trajectory of the power sector in 
the space of 15 months.
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    \676\ 87 FR 79182 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.23a(a)).
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    Additionally, prior to an owner or operator providing a suggestion 
for a subcategory and standard of performance for an affected EGU to a 
State, that owner or operator will likely need to analyze options for 
complying with the applicable BSER for the subcategory. The EPA 
anticipates that some owners or operators of affected coal-fired steam 
generating units and affected combustion turbines will do feasibility 
and FEED studies for CCS prior to committing to it as a control 
strategy in a State plan. As discussed in section XII.B of this 
preamble and in the GHG Mitigation Measures for Steam Generating Units 
TSD, FEED studies take approximately 12 months to complete,\677\ after 
which additional time is necessary to allow the conclusions from that 
study to be integrated into a State's planning process for certain 
affected EGUs. For other coal-fired steam generating units, there may 
also be planning, design, and permitting exercises that will be 
necessary for utilities to undertake prior to committing to a 
subcategory based on natural gas co-firing. While any boiler 
modifications required for affected EGUs that intend to co-fire natural 
gas are relatively straightforward, the owners or operators of EGUs in 
the medium-term subcategory may also be required to construct new 
pipelines to enable co-firing of 40 percent natural gas. Pipeline 
projects also require an initial planning and design process to 
determine feasibility and, in some cases, could involve FERC approval. 
Similar considerations apply for affected combustion turbine EGUs in 
the hydrogen co-fired subcategory with regard to any turbine upgrades 
that may be necessary to co-fire higher percentages of hydrogen and/or 
to the construction of any pipeline laterals that are necessary to 
supply the EGU with low-GHG hydrogen. Based on the approximately 12-
month period that states and the owners or operators of affected EGUs 
will likely take to assess control strategies for these units, the EPA 
does not believe it is reasonable to require State plans to be 
submitted 15 months after promulgation of these emission guidelines.
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    \677\ GHG Mitigation Measures for Steam Generating Units TSD, 
chapter 4.7.1.
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    In the proposed subpart Ba timelines for State plan submission, the 
EPA justified the generally applicable timelines in the context of 
public health and welfare impacts by proposing timelines that are as 
quick as is reasonably feasible for a generic set of emission 
guidelines under CAA section 111(d). The EPA is proposing 24 months for 
State plan timelines for these emission guidelines because 24 months is 
the quickest time that the EPA believes to be reasonably feasible for a 
State to submit a State plan based on the work and evaluation needed to 
establish which compliance strategy (such as CCS or co-firing) will be 
appropriate at a given EGU. Additionally, the EPA does not believe 
providing a longer timeline for the submission of State plans in this 
particular instance would ultimately impact how quickly the affected 
EGUs can comply with their standards of performance. As explained in 
section XII.B of this preamble and in the GHG Mitigation Measures for 
Steam Generating Units TSD, the EPA anticipates that CCS projects will 
take roughly 5 years to complete, assuming some steps are undertaken 
concurrently. If the EPA were to promulgate these emission guidelines 
in June 2024 and require State plan submissions in September 2025, the 
EPA anticipates that the soonest compliance could commence is in the 
third quarter of 2029. However, in this case, it is likely that at 
least some owners/operators of affected EGUs would have to commit to 
subcategories or control technologies before completing feasibility and 
FEED studies, which could result in the need for plan revisions and 
delayed emission reductions. In contrast, providing 24 months for State 
plan submission would mean that although plans would be due June 2026, 
owners or operators of affected EGUs would have had time to complete 
their feasibility and FEED studies and some initial planning steps 
before then. The EPA anticipates that owners or operators would need 
approximately another 3.5 years to reach full compliance, meaning that 
emission reductions would commence in the first quarter of 2030. The 
EPA does not believe that a difference of three months will adversely 
impact public health or welfare, especially when it is considered that 
providing more time for State plan development in this instance is more 
likely to ultimately result in certainty and timely emission 
reductions. The EPA solicits comment on the 24-month State planning 
period. The EPA specifically requests comments

[[Page 33403]]

from owners and operators of affected EGUs regarding the steps, and 
amount of time needed for each step, that they would have to undertake 
to determine the applicable subcategories and to plan and implement the 
associated control strategies for each of their affected EGUs. 
Additionally, the EPA requests comment on the 24-month planning period 
from states, including on any unique characteristics of the fossil 
fuel-fired EGU source category that they believe merit planning 
timeframes longer than 15 months. Through outreach, many states have 
expressed a need for longer planning periods and the EPA solicits 
comment on whether this 24-month planning period accommodates that 
need. The EPA also requests comment from potentially impacted 
communities and other pertinent stakeholders on any considerations 
related to providing a longer State plan submission timeframe under 
these emission guidelines.
    The EPA is additionally requesting comment on a potential 
bifurcated approach to State plan submissions for affected steam 
generating units and affected combustion turbine EGUs. In contrast to 
the proposed compliance deadline for steam generating units, the EPA is 
proposing compliance deadlines for combustion turbine EGUs in the CCS 
subcategory and combustion turbine EGUs in the hydrogen co-fired 
subcategory of January 1, 2035, and January 1, 2032 (with a second 
phase commencing on January 1, 2038), respectively. Despite the longer 
period between the anticipated promulgation of these emission 
guidelines and the proposed compliance deadlines for affected 
combustion turbine EGUs, the EPA is proposing that State plan 
submissions containing standards of performance and other applicable 
requirements for these units would be due 24 months after promulgation. 
Based on many of the same considerations regarding power sector 
planning and coordination discussed above, the EPA believes that 
states; owners and operators of affected EGUs; RTOs, ISOs, or other 
balancing authorities; and the public may benefit from considering the 
control strategies for all affected EGUs under these emission 
guidelines on the same timeline. Additionally, the EPA is cognizant of 
the need to achieve emission reductions and thus the public health and 
welfare benefits as soon as reasonably practicable.
    However, the EPA also acknowledges that the compliance timeframes 
for combustion turbine EGUs are likely to be longer than those for 
steam generating units under these emission guidelines due to, inter 
alia, the need to phase installation of CCS across the power sector and 
the continued ramp-up in production and transmission capacity for low-
GHG hydrogen. The EPA is therefore requesting comment on an approach in 
which states would submit two different plans on different timelines: a 
State plan addressing affected steam-generating units due 24 months 
after promulgation of these emission guidelines and a second State plan 
addressing affected combustion turbine EGUs due 36 months after 
promulgation of these emission guidelines. The EPA solicits comment on 
this staggered approach and on whether 36 months, or a longer or 
shorter period, could be an appropriate State plan submission deadline 
for combustion turbine EGUs, and why. The EPA requests that commenters 
explain if and how a longer State plan submission timeline for affected 
combustion turbine EGUs would be consistent with achieving the emission 
reductions under these emission guidelines as quickly as reasonably 
practicable, as well as on the potential interactions between the State 
plan submission time frame and the proposed compliance deadlines for 
combustion turbine EGUs. The EPA also solicits comment from potentially 
impacted communities and other pertinent stakeholders on any 
considerations related to providing a longer State plan submission 
timeframe for combustion turbine EGUs under these emission guidelines.
3. State Plan Revisions
    The EPA expects that the State plan submission deadline proposed 
under these emission guidelines would give states, utilities and 
independent power producers, and stakeholders sufficient time to 
determine in which subcategory each of the affected EGUs falls and to 
formulate and submit a State plan accordingly. However, the EPA also 
acknowledges that, despite states' best efforts to accurately reflect 
the plans of owners or operators with regard to affected EGUs at the 
time of State plan submission, such plans may subsequently change. In 
general, states have the authority and discretion to submit revised 
State plans to the EPA for approval.\678\ State plan revisions are 
generally subject to the same requirements as initial State plan 
submissions under these emission guidelines and the subpart Ba 
implementation regulations, including meaningful engagement, and the 
EPA reviews State plan revisions against the applicable requirements of 
these emission guidelines in the same manner in which it reviews 
initial State plan submissions pursuant to 40 CFR 60.27a.
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    \678\ 40 CFR 60.23a(a)(2), 60.28a.
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    Approved State plan requirements remain federally enforceable 
unless and until the EPA approves a plan revision that supersedes such 
requirements. States and affected EGUs should plan accordingly to avoid 
noncompliance.
    The EPA is proposing a State plan submission date that is 24 months 
after the publication of final emission guidelines and is proposing 
that the first compliance date for a portion of affected EGUs would be 
on January 1, 2030. A State may choose to submit a plan revision prior 
to compliance with its existing State plan requirements; however, the 
EPA reiterates that any already approved federally enforceable 
requirements, including milestones, increments of progress, and 
standards of performance, will remain in place unless and until the EPA 
approves the plan revision. The EPA requests comment on whether it 
would be helpful to states to impose a cut-off date for the submission 
of plan revisions ahead of the January 1, 2030, compliance date for 
coal-fired steam generating affected EGUs or ahead of the separate 
compliance dates for achieving the CCS-based or hydrogen co-firing-
based standards for existing combustion turbines. Such a cut-off date, 
e.g., January 1, 2028, would in effect establish a temporary moratorium 
on plan submissions in order to provide a sufficient window for the EPA 
to act on them and effectuate any changes to existing State plan 
requirements ahead of the final compliance date. State plan revisions 
would again be permitted after the final compliance date. As an 
alternative to a cut-off date for State plan revisions ahead of the 
compliance date, the EPA requests comment on the dual-path standards of 
performance approach discussed in section XII.F.4 of this preamble.
    Under the proposed emission guidelines for existing coal-fired 
steam generating units, states would place their affected coal-fired 
steam generating units into one of four subcategories based on the time 
horizons over which those EGUs elect to operate. These subcategories 
are static--affected EGUs would not be able move between subcategories 
absent a plan revision.\679\ However, the EPA

[[Page 33404]]

acknowledges that there may be instances in which a change in 
subcategory will be necessary. For affected coal-fired steam generating 
EGUs that are switching into the imminent-term, near-term, or medium-
term subcategories, the EPA proposes to require that the State include 
in its State plan revision documentation of the affected EGU's 
submission to the relevant RTO or balancing authority of the new date 
it intends to permanently cease operations, any responses from and 
studies conducted by the RTO or balancing authority addressing 
reliability and any other considerations related to ceasing operations, 
any filings with the SEC or notices to investors in which the plans for 
the EGU are mentioned, any integrated resource plan, and any other 
relevant information in support of the new date. This documentation 
must be published on the Carbon Pollution Standards for EGUs website. 
These proposed requirements are modeled on the proposed milestones for 
sources electing to commit to permanently cease operations and are 
intended to help states, stakeholders, and the EPA ensure that the 
affected EGU's change in circumstances is sufficiently certain to 
warrant a State plan revision. Because of the long lead times for 
planning and implementation of control systems for affected EGUs, 
revising a State plan after the submission deadline has the potential 
to significantly disrupt states' and affected EGUs' compliance 
strategies. The EPA therefore believes it is reasonable to require 
affected EGUs and states to provide evidence that a source's 
circumstances have in fact changed, in order for the EPA to approve a 
plan revision. Affected EGUs switching into the imminent-term, near-
term, or medium-term subcategories would also be required to comply 
with the proposed enforceable milestones applicable to those 
subcategories.
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    \679\ If the EPA finalizes an option for States to include dual 
paths for an affected coal-fired EGU or EGUs in their state plans, 
those affected EGUs would be able to choose between two 
subcategories prior to the final compliance date without the state's 
needing to revise its plan.
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    Some changes between subcategories of affected coal-fired steam 
generating EGUs, including from the long-term into the medium-term 
subcategory and from the imminent-term or near-term into the medium-
term or long-term subcategory, would entail new standards of 
performance reflecting a different add-on control strategy than 
initially anticipated. In order to avoid undermining the stringency of 
these proposed emission guidelines, the EPA expects affected EGUs 
changing subcategories before the January 1, 2030, compliance deadline 
to make every reasonable effort to meet that compliance deadline. 
However, the EPA acknowledges that, in some circumstances, it may not 
be possible to complete the necessary planning and construction within 
a shortened timeframe. Additionally, unforeseen circumstances could 
require some affected EGUs to change subcategories after the final 
compliance deadline has passed (e.g., to ensure reliability).
    In these circumstances, the EPA is proposing that states may use 
the RULOF mechanism described in section XII.D.2 of this preamble to 
adjust the compliance deadlines for affected EGUs that cannot comply 
with their applicable standards of performance by the January 1, 2030, 
deadline. The EPA expects that states may be able to demonstrate that 
the change in subcategory constitutes an ``other circumstance[ ] 
specific to the facility . . . that [is] fundamentally different from 
the information considered in the determination of the best system of 
emission reduction in the emission guidelines.'' \680\ In order to 
invoke RULOF to change a compliance deadline for an affected EGU that 
has switched subcategories, the EPA proposes that the State must first 
demonstrate that the affected EGU cannot meet the applicable 
presumptive standard of performance by the compliance deadline in these 
emission guidelines. As part of this demonstration the State would be 
required to provide evidence supporting the affected EGU's need to 
switch subcategories. The State would also be required to demonstrate 
that the need to invoke RULOF and to provide a different compliance 
deadline or less stringent standard of performance was not caused by 
self-created impossibility.
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    \680\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 
60.24a(e)(3)).
---------------------------------------------------------------------------

    Like subcategorization for affected coal-fired steam-generating 
units, states would place their affected combustion turbine EGUs into 
one of the two subcategories in their State plans, along with the 
corresponding standard of performance. These subcategory designations 
are static--affected EGUs would not be able to move between 
subcategories absent a plan revision. The EPA expects that situations 
necessitating a change in subcategory for combustion turbine EGUs will 
be far less likely than for coal-fired steam-generating units. However, 
should the need arise for an affected combustion turbine EGU to change 
subcategories in a State plan, the same considerations discussed above 
for coal-fired steam generating units would apply. If a combustion 
turbine EGU changes subcategories in a manner that entails a new 
standard of performance that is based on a different control technology 
than initially anticipated, the EPA expects the owner or operator of 
that EGU to make every reasonable effort to meet the original 
compliance deadline for the newly applicable subcategory. For 
situations in which this is impossible, the EPA is proposing that 
states could use the RULOF mechanism as described above to provide a 
revised compliance deadline. As part of its RULOF demonstration, a 
State would be required to provide evidence supporting the affected 
combustion turbine's need to switch subcategories, as well as a 
demonstration that the need to invoke RULOF and to provide a different 
compliance deadline was not caused by the owner or operator's self-
created impossibility.
    Documentation related to these demonstrations must also be posted 
to the Carbon Pollution Standards for EGUs website. For example, it 
would not be reasonable for a State that has been notified that an RTO 
requires an affected EGU to switch subcategories to wait to revise its 
SIP until the remaining useful life of that EGU is so short as to 
preclude otherwise reasonable systems of emission reduction. To this 
end, the EPA is proposing to consider when a State knew or should have 
known that an affected EGU would need to switch subcategories when 
evaluating the approvability of State plans that include RULOF 
demonstrations. The EPA is additionally proposing to consider whether 
an affected EGU has been complying with its applicable milestones and 
increments of progress when evaluating RULOF demonstrations. The EPA 
encourages states to consult with their EPA Regional Offices as early 
as possible if they believe it may become necessary for an affected EGU 
to switch subcategories. The EPA requests comment on whether to set a 
deadline for states to provide plan revisions within a certain 
timeframe of knowing that an affected EGU needs to switch subcategories 
and on what timeframe would be appropriate.
    The EPA is proposing that states invoking RULOF because an affected 
EGU cannot comply with its newly applicable presumptive standard of 
performance by the final compliance deadline first evaluate whether the 
affected EGU is able to comply with that standard by a different, 
later-in-time deadline. If a State can demonstrate that an affected EGU 
cannot reasonably comply with the applicable presumptive standard of 
performance under any reasonable compliance deadline, it may

[[Page 33405]]

then evaluate different systems of emission reduction according to the 
proposed RULOF mechanism described in section XII.D.2 of this preamble.
4. Dual-Path Standards of Performance for Affected EGUs
    Under the structure of these emission guidelines as proposed, 
states would assign affected coal-fired steam generating units to 
subcategories in their State plans and an affected EGU would not be 
able to change its applicable subcategory without a State plan 
revision. This is because, due to the nature of the BSERs for coal-
fired steam generating units, an affected EGU that switches between 
subcategories may not be able to meet compliance obligations for a new 
and different subcategory without considerable lag time and thus the 
switch would result in noncompliance and a loss of emission reductions. 
Similarly, states would be required to assign their affected combustion 
turbine EGUs to either the CCS or hydrogen co-fired subcategory in 
their State plans, at which point a unit could not switch between 
subcategories without a plan revision. Therefore, as a general matter, 
states must assign each affected EGU to a subcategory and have in place 
all the legal instruments necessary to implement the requirements for 
that subcategory by the time of State plan submission.
    However, the EPA acknowledges that there may be circumstances in 
which the owner or operator of a coal-fired steam generating unit has 
not yet finalized its future operating plans and wishes to retain the 
option to choose between two different subcategories ahead of the 
proposed January 1, 2030, compliance date. Similarly, the owner or 
operator of a combustion turbine EGU may wish to retain the ability to 
choose between the CCS and hydrogen co-fired subcategories, 
particularly because the relatively long period between State plan 
submission and compliance means that a unit's circumstances could 
change materially in that time. The EPA is therefore soliciting comment 
on the following dual-path approach that may result in an additional 
flexibility for owners or operators of affected coal-fired steam 
generating units and affected combustion turbine EGUs that want 
additional time to commit to a particular subcategory without the need 
for a State plan revision.
    The EPA is soliciting comment on an approach that allows coal-fired 
steam generating units and combustion turbine EGUs to have two 
different standards of performance submitted to the EPA in a State plan 
based on potential inclusion in two different subcategories. A State 
plan would be required to have all the associated components for each 
subcategory. For example, for an affected coal-fired steam generating 
unit that wants the option to be part of either the long-term or 
imminent-term subcategory, the State plan would include an enforceable 
standard of performance based on implementation of CCS and associated 
requirements, including increments of progress; as well as an 
enforceable requirement to permanently cease operations before January 
1, 2033, and a standard of performance based on routine operation and 
maintenance. The affected EGU would be required to meet all compliance 
obligations for both subcategories, including increments of progress 
and/or milestones for commitments to cease operations, leading up to 
the compliance date of January 1, 2030. The State and the owner or 
operator of the affected EGU would be required to choose a subcategory 
for the affected EGU ahead of that date. Specifically, the EPA is 
proposing that the State must notify the EPA of its final applicable 
subcategory and standard of performance at least 6 months prior to the 
compliance date. For affected coal-fired steam generating units, the 
State would be required to notify the EPA of the applicable standard by 
July 1, 2029. For affected combustion turbine EGUs, the State would be 
required to notify the EPA of the applicable standard by the earliest 
compliance date, or July 1, 2031. If the State has not notified the EPA 
by the required date (July 1, 2029, or July 1, 2031) of the final 
applicable subcategory for the affected EGU, the EPA is proposing that 
a coal-fired steam generating unit would automatically be subject to 
the requirements of the subcategory that corresponds to the longer 
remaining life of the EGU, while a combustion turbine EGU would 
automatically be subject to the requirements of the CCS subcategory. 
Additionally, if the affected EGU misses an enforceable increment of 
progress, milestone (as described in section XII.D.3 of this preamble), 
or any other requirement for one of the two subcategories, the EGU will 
automatically be subject to the requirements of the other subcategory. 
If the EGU misses submissions for increments of progress and/or 
milestones for both subcategories, the EGU will automatically be 
subject to the requirements of the subcategory that corresponds to the 
longer remaining life of the EGU (for coal-fired steam generating 
units) or the CCS subcategory (for combustion turbine EGUs) and will 
additionally be found to be out of compliance for the increment of 
progress or milestone that it has missed.
    The EPA is soliciting comment on this approach to provide 
flexibility to states and affected coal-fired steam generating units 
and affected combustion turbine EGUs. In some instances, owners or 
operators of affected EGUs may wish to have additional time to evaluate 
future operating plans; this proposed dual-path approach should provide 
owners or operators additional time to commit to a subcategory. 
However, with this additional time comes additional burden on owners 
and operators to demonstrate compliance with each of the requirements 
associated with two different subcategories that would be included in a 
State plan. As an example, a coal-fired steam generating unit intends 
to cease operations between 2038 and 2041. The State plan is submitted 
and contains two different enforceable dates to permanently cease 
operations, e.g., December 31, 2038, with a standard of performance 
based on natural gas co-firing and December 31, 2041, with a standard 
of performance based on CCS, as well as an enforceable commitment by 
the State to choose one path or the other by July 1, 2029. The affected 
EGU would then be required to comply with the increments of progress 
for both the long-term (CCS) and medium-term (co-firing) subcategories, 
until the point at which the State decides which of the two paths in 
its plan it will require for the unit.
    The EPA solicits comment on whether this proposed dual-path 
flexibility would have utility and on whether it could be implemented 
in a manner that ensures that states and affected coal-fired steam 
generating units and affected combustion turbine EGUs would be able to 
comply with applicable requirements in a timely manner. Additionally, 
the EPA solicits comment on whether notification deadlines of July 1, 
2029, for coal-fired steam generating units, and July 1, 2031, for 
combustion turbine EGUs are the appropriate dates for a final decision 
between two potential standards of performance and why.
5. EPA Action on State Plans
    Pursuant to proposed subpart Ba, the EPA would use a 60-day 
timeline for the Administrator's determination of completeness of a 
State plan submission \681\ and a 12-month timeline

[[Page 33406]]

for action on State plans.\682\ The EPA is not proposing to supersede 
these timelines; therefore, review of and action on State plan 
submissions will be governed by the requirements of revised subpart Ba. 
First, the EPA would review the components of the State plan to 
determine whether the plan meets the completeness criteria of 40 CFR 
60.27a(g). The EPA must determine whether a State plan submission has 
met the completeness criteria within 60 days of its receipt of that 
submission. If the EPA has failed to make a completeness determination 
for a State plan submission within 60 days of receipt, the submission 
shall be deemed, by operation of law, complete as of that date.
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    \681\ The timeframes and requirements for state plan submissions 
described in this section also apply to state plan revisions. See 
generally 40 CFR 60.27a.
    \682\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.27a).
---------------------------------------------------------------------------

    Proposed subpart Ba would require the EPA to take action on a State 
plan submission within 12 months of that submission's being deemed 
complete. The EPA will review the components of State plan submissions 
against the applicable requirements of subpart Ba and these emission 
guidelines, consistent with the underlying requirement that State plans 
must be ``satisfactory'' per CAA section 111(d). If the EPA finalizes 
the revisions to subpart Ba as proposed, the Administrator would have 
the option to fully approve, fully disapprove, partially approve, 
partially disapprove, and conditionally approve a State plan 
submission.\683\ Any components of a State plan submission that the EPA 
approves become federally enforceable.
---------------------------------------------------------------------------

    \683\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.27a(b)).
---------------------------------------------------------------------------

    The EPA requests comment on the use of the timeframes provided in 
subpart Ba, as the EPA has proposed to revise it, for EPA actions on 
State plan submissions and for the promulgation of Federal plans for 
these particular emission guidelines.
6. Federal Plan Applicability and Promulgation Timing
    The provisions of subpart Ba, including any revisions the EPA 
finalizes pursuant to its December 2022 proposal, will apply to the 
EPA's promulgation of any Federal plans under these emission 
guidelines. The EPA's obligation to promulgate a Federal plan is 
triggered in three situations: where a State does not submit a plan by 
the plan submission deadline; where the EPA determines that a State 
plan submission does not meet the completeness criteria and the time 
period for State plan submission has elapsed; and where the EPA fully 
or partially disapproves a State's plan.\684\ Where a State has failed 
to submit a plan by the submission deadline, the proposed revisions to 
subpart Ba would give the EPA 12 months from the State plan submission 
due date to promulgate a Federal plan; otherwise, the 12-month period 
starts from the date the State plan submission is deemed incomplete, 
whether in whole or in part, or from the date of the EPA's disapproval. 
The EPA may approve a State plan submission that corrects the relevant 
deficiency within the 12-month period, before it promulgates a Federal 
plan, in which case its obligation to promulgate a Federal plan is 
relieved.\685\ As provided by 40 CFR 60.27a(e), a Federal plan will 
prescribe standards of performance for affected EGUs of the same 
stringency as required by these emission guidelines and will require 
compliance with such standards as expeditiously as practicable but no 
later than the final compliance date under these guidelines. However, 
upon application by the owner or operator of an affected EGU, the EPA 
in its discretion may provide for a less stringent standard of 
performance or longer compliance schedule than provided by these 
emission guidelines, in which case the EPA would follow the same 
process and criteria in the regulations that apply to states' provision 
of RULOF standards.\686\ Under the proposed revisions to subpart Ba, 
the EPA would also be required to conduct meaningful engagement with 
pertinent stakeholders prior to promulgating a Federal plan.\687\
---------------------------------------------------------------------------

    \684\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.27a(c)).
    \685\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.27a(d)).
    \686\ 40 CFR 60.27a(e)(2).
    \687\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.27a(f)).
---------------------------------------------------------------------------

    As described in section XII.F.2 of this preamble, the EPA is 
proposing to allow states 24 months for a State plan submission after 
the promulgation of the final emission guidelines. Therefore, the EPA 
would be obligated to promulgate a Federal plan within 36 months of the 
final emission guidelines for all states that fail to submit plans. 
Note that this will be the earliest obligation for the EPA to 
promulgate Federal plans for states and that different triggers (e.g., 
a disapproved State plan) will result in later obligations to 
promulgate Federal plans contingent on when the obligation is 
triggered.
    Under the Tribal Authority Rule (TAR) adopted by the EPA, Tribes 
may seek authority to implement a plan under CAA section 111(d) in a 
manner similar to that of 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 that of a State for purposes of developing a Tribal 
Implementation Plan (TIP) implementing the emission guidelines. If a 
Tribe obtains approval and submits a TIP, the EPA will generally use 
similar criteria and follow similar procedures as those described for 
State plans when evaluating the TIP submission and will approve the TIP 
if appropriate. The EPA is committed to working with eligible Tribes to 
help them seek authorization and develop plans if they choose. Tribes 
that choose to develop plans will generally have the same flexibilities 
available to states in this process. 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 areas of 
Indian country where designated facilities are located. 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 
an applicable TIP applicable to those facilities.

XIII. Implications for Other EPA Programs

A. Implications for New Source Review (NSR) Program

    CAA section 110(a)(2)(C) requires that a SIP include a New Source 
Review (NSR) program that provides for the ``regulation of the 
modification and construction of any stationary source . . . as 
necessary to assure that [the NAAQS] are achieved.'' Within the NSR 
program, the ``major NSR'' preconstruction permitting program applies 
to new construction and modifications of existing sources that emit 
``regulated NSR pollutants'' at or above certain established 
thresholds. New sources and modifications that emit regulated NSR 
pollutants under the established thresholds may be subject to ``minor 
NSR'' program requirements or may be excluded from NSR requirements 
altogether. The NSR program for a State or local permitting authority 
with an approved SIP is implemented through 40 CFR 51.160 to 51.166, 
while the NSR program applying in areas for which the EPA or a 
delegated State, local or Tribal agency is the permitting authority is 
implemented through 40 CFR part 49 and 40 CFR 52.21.
    NSR applicability is pollutant-specific and, for the major NSR 
program, the

[[Page 33407]]

permitting requirements that apply to a source depend on the air 
quality designation at the location of the source for each of its 
emitted pollutants at the time the permit is issued. Major NSR permits 
for sources located in an area that is designated as attainment or 
unclassifiable for the NAAQS for its pollutants are referred to as 
Prevention of Significant Deterioration (PSD) permits. In addition, PSD 
permits can include requirements for specific pollutants for which 
there are no NAAQS.\688\ Sources subject to PSD must, among other 
requirements, comply with emission limitations that reflect the Best 
Available Control Technology (BACT) for ``each pollutant subject to 
regulation'' as specified by CAA sections 165(a)(4) and 169(3). Major 
NSR permits for sources located in nonattainment areas and that emit at 
or above the specified major NSR threshold for the pollutant for which 
the area is designated as nonattainment are referred to as 
Nonattainment NSR (NNSR) permits. Sources subject to NNSR must, among 
other requirements, meet the Lowest Achievable Emissions Rate (LAER) 
pursuant to CAA sections 171(3) and 173(a)(2) for any pollutant subject 
to NNSR. For sources subject to minor NSR, the CAA and EPA rules do not 
set forth prescriptive control technology requirements for minor NSR 
programs so these permits can be less stringent than major NSR permits. 
Due to the pollutant-specific applicability of the NSR program, it is 
conceivable that a source seeking to newly construct or modify may have 
to obtain multiple types of NSR permits (i.e., NNSR, PSD, or minor NSR) 
depending on the air quality designation at the location of the source 
and the types and amounts of pollutants it emits.
---------------------------------------------------------------------------

    \688\ For the PSD program, ``regulated NSR pollutant'' includes 
any pollutant for which a NAAQS has been promulgated (``criteria 
pollutants'') and any other air pollutant that meets the 
requirements of 40 CFR 52.21(b)(50). Some of these non-criteria 
pollutants include fluorides, sulfuric acid mist, hydrogen sulfide, 
total reduced sulfur, and reduced sulfur compounds.
---------------------------------------------------------------------------

    A new stationary source is subject to major NSR requirements if its 
potential to emit (PTE) a regulated NSR pollutant exceeds statutory 
emission thresholds, upon which the NSR regulations define it as a 
``major stationary source.'' \689\ For PSD permitting, once a new 
stationary source is determined to be subject to major NSR for one 
regulated NSR pollutant (with the exception of GHG),\690\ the source 
can be subject to major NSR requirements for any other regulated NSR 
pollutant if the PTE of that pollutant is at least the ``significant'' 
emissions rate (``SER''), as defined in 40 CFR 52.21(b)(23). In the 
case of GHG,\691\ the EPA has not promulgated a GHG SER but applies a 
BACT applicability threshold of 75,000 TPY CO2e.\692\
---------------------------------------------------------------------------

    \689\ For PSD, the statute uses the term ``major emitting 
facility'' and defines it as a stationary source that emits, or has 
a PTE, at least 100 tons per year (TPY) if the source is in one of 
28 listed source categories, or at least 250 TPY if the source is 
not a listed source category. CAA section 169(1). For NNSR, the 
emissions threshold for a major stationary source is 100 TPY, and 
lower thresholds apply for certain pollutants based on the severity 
of the nonattainment classification.
    \690\ As a result of the Supreme Court's decision in UARG v. 
EPA, the D.C. Circuit issued an amended judgment in Coalition for 
Responsible Regulation, Inc. v. EPA, Nos. 09-1322, 10-073, 10-1092 
and 10-1167 (D.C. Cir. April 10, 2015), which, among other things, 
vacated the PSD and title V regulations under review in that case to 
the extent that they require a stationary source to obtain a PSD or 
title V permit solely because the construction of the source, or a 
modification at the source, emits or has the potential to emit GHGs 
at or above the applicable major NSR thresholds.
    \691\ Consistent with the 2009 Endangerment Findings, the PSD 
program treats GHG as a single air pollutant defined as the 
aggregate group of six gases: CO2, N2O, 
CH4, HFCs, PFCs, and SF6. 40 CFR 
52.21(b)(49)(i).
    \692\ See Janet G. McCabe and Cynthia Giles, Next Steps and 
Preliminary Views on the Application of Clean Air Act Permitting 
Programs to Greenhouse Gases Following the Supreme Court's Decision 
in Utility Air Regulatory Group v. Environmental Protection Agency 
(July 24, 2014), https://www.epa.gov/sites/default/files/2015-12/documents/20140724memo.pdf.
---------------------------------------------------------------------------

    For an existing source, it can be subject to major NSR requirements 
if it is a major stationary source and its emissions increase resulting 
from a modification (i.e., physical change or change in the method of 
operation) are equal to or greater than the SER for a regulated NSR 
pollutant, upon which the NSR regulations define it as a ``major 
modification.'' \693\ As with new sources, the one exception to this 
applicability approach is GHG, which currently applies a BACT 
applicability threshold in lieu of a SER and can only be subject to 
major NSR if another pollutant is also subject to major NSR for the 
modification. Generally, an existing major stationary source triggering 
major NSR requirements for a regulated NSR pollutant would have both a 
significant emissions increase from the modification and a significant 
net emissions increase at the stationary source, and the calculation of 
the significant emissions increase differs depending on whether the 
modification is to an existing emissions unit, or the addition of a new 
emissions unit, or if it involves multiple types of emission 
units.\694\ An existing major stationary source would trigger PSD 
permitting requirements for GHGs if it undertakes a modification and: 
(1) The modification is otherwise subject to PSD for a pollutant other 
than GHG; and (2) the modification results in a GHG emissions increase 
and a GHG net emissions increase that is equal to or greater than 
75,000 TPY CO2e and greater than zero on a mass basis.
---------------------------------------------------------------------------

    \693\ Per 40 CFR 52.21(b)(1)(i)(c), a minor source that 
undergoes a physical change that would itself be considered major, 
is subject to major source requirements.
    \694\ 40 CFR 52.21(a)(2)(iv); 40 CFR 52.21(b)(2)(i); 40 CFR 
52.21(b)(3).
---------------------------------------------------------------------------

    Since GHG is not a criteria pollutant, it is regulated under the 
CAA's PSD program, but not under the NNSR or minor NSR programs. For 
new sources and modifications that are subject to PSD, the permitting 
authority must establish emission limitations based on BACT for each 
pollutant that is subject to PSD at the major stationary source or at 
each emissions unit involved in the major modification. BACT is 
assessed on a case-by-case basis, and the permitting authority, in its 
analysis of BACT for each pollutant, evaluates the emission reductions 
that each available emissions-reducing technology or technique would 
achieve, as well as the energy, environmental, economic, and other 
costs associated with each technology or technique. The CAA also 
specifies that BACT cannot be less stringent than any applicable 
standard of performance under the NSPS.\695\ Permitting authorities may 
determine BACT by applying the EPA's five-step ``top down'' 
approach.\696\ The ultimate determination of BACT is made by the 
permitting authority after a public notice and comment period of at 
least 30-days on the draft permit and supporting information.\697\
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    \695\ 42 U.S.C. 7479(3) (``In no event shall application of 
`best available control technology' result in emissions of any 
pollutants which will exceed the emissions allowed by any applicable 
standard established pursuant to [CAA Section 111 or 112].'').
    \696\ U.S. EPA, NSR Workshop Manual (Draft October 1990), 
https://www.epa.gov/sites/default/files/2015-07/documents/1990wman.pdf; U.S. EPA, PSD and Title V Permitting Guidance for 
Greenhouse Gases (March 2011), https://www.epa.gov/sites/default/files/2015-07/documents/ghgguid.pdf.
    \697\ 40 CFR 124.10.
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1. NSR Implications of a CAA Section 111(b) Standard
    As noted above, BACT cannot be set at a level that is less 
stringent than the standard of performance established by an applicable 
NSPS, and the EPA refers to this minimum control level as the ``BACT 
floor.'' While a proposed NSPS does not establish the BACT floor for 
affected facilities seeking a PSD permit, once an NSPS is promulgated, 
it then serves as the BACT floor for any new major stationary source or 
major modification that meets the

[[Page 33408]]

applicability of the NSPS and commences construction after the date of 
the proposed NSPS in the Federal Register.\698\ In the context of 
combustion turbines that would be subject to this NSPS at 40 CFR part 
60, subpart TTTTa, for any new major stationary source or major 
modification that commences construction or reconstruction of a 
stationary combustion turbine EGU after the date of publication of this 
proposed NSPS, the PSD permit should reflect a BACT determination that 
is at least as stringent as the promulgated NSPS for each of the 
source's affected EGUs.
---------------------------------------------------------------------------

    \698\ U.S. EPA, PSD and Title V Permitting Guidance for 
Greenhouse Gases (March 2011), p. 25.
---------------------------------------------------------------------------

    However, the fact that a minimum control requirement is established 
by an applicable NSPS does not mean that a permitting authority cannot 
select a more stringent control level for the PSD permit or consider 
technologies for BACT beyond those that were considered in developing 
the NSPS. As explained above, BACT is a case-by-case review that 
considers a number of factors, and the review should reflect advances 
in control technology, reductions in the costs or other impacts of 
using particular control strategies, or other relevant information that 
may have become available after development of an applicable NSPS.
2. NSR Implications of a CAA Section 111(d) Standard
    With respect to the proposed action for emission guidelines, should 
it be promulgated, states will be called upon to develop a plan that 
establish standards of performance for each affected EGU that meets the 
requirements in the emission guidelines. In doing so, a State agency 
may develop a plan that results in an affected source undertaking a 
physical or operational change. Under the NSR program, undertaking a 
physical or operational change may require the source to obtain a 
preconstruction permit for the proposed change, with the type of NSR 
permit (i.e., NNSR, PSD, or minor NSR) depending on the amount of the 
emissions increase resulting from the change and the air quality 
designation at the location of the source for its emitted pollutants. 
More specifically, any time an existing source adds equipment or 
otherwise makes physical or operational changes to its facility, 
regardless of whether it has done so to comply with a national or State 
level requirement, the source may be required to obtain a NSR permit 
prior to making the changes unless the permitting authority determines 
that the action is exempt from permitting.\699\
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    \699\ The EPA sought to exempt environmentally beneficially 
pollution control projects from NSR requirements in a 2002 rule that 
codified longstanding EPA policy, but this rule was struck down in 
court. New York v. EPA, 413 F.3d 3, 40-42 (D.C. Cir. 2005) (New York 
I).
---------------------------------------------------------------------------

    Thus, there may be circumstances in which an affected source that 
is implementing a BSER requirement from a State plan is required to 
obtain a major NSR permit for one or more of its pollutants. One 
scenario in which this may occur is if an affected source experiences 
greater unit availability and reliability as a result of implementing 
its BSER requirement (e.g., an efficiency based BSER) that, in turn, 
lowers the operating costs of its EGU. Since EGUs that operate at lower 
costs are generally preferred in the dispatch by the system operator 
over units with higher operational costs, the BSER implementation could 
result in improving the source's relative economics that would, in 
turn, increase its utilization of its EGU(s). With an increase in 
utilization resulting from the source implementing the BSER, the annual 
emissions from the EGU could increase, and if the emissions increase 
equals or exceeds the relevant SER for one or more of its pollutants, 
the source may be required to obtain a major NSR permit for the 
modification.
    However, while it may be possible for an affected source to trigger 
major NSR requirements from actions it takes to implement a BSER 
requirement, we expect this situation to not occur often. As previously 
discussed in this preamble, states will have considerable flexibility 
in adopting varied compliance measures as they develop their plans to 
meet the standards of performance of the emission guidelines. One of 
these flexibilities is the ability for states to establish the 
standards of performance in their plans in such a way so that their 
affected sources, in complying with those standards, in fact would not 
have emission increases that trigger major NSR requirements. To achieve 
this, the State would need to conduct an analysis consistent with the 
NSR regulatory requirements that supports its determination that as 
long as affected sources comply with the standards of performance, 
their emissions would not increase in a way that trigger major NSR 
requirements. For example, a State could, as part of its State plan, 
develop enforceable conditions for a source expected to trigger major 
NSR that would effectively limit the unit's ability to increase its 
emissions in amounts that would trigger major NSR (effectively 
establishing a synthetic minor limitation).\700\
---------------------------------------------------------------------------

    \700\ Certain stationary sources that emit or have the potential 
to emit a pollutant at a level that is equal to or greater than 
specified thresholds are subject to major source requirements. See, 
e.g., CAA sections 165(a)(1), 169(1), 501(2), 502(a). A synthetic 
minor limitation is a legally and practicably enforceable 
restriction that has the effect of limiting emissions below the 
relevant level and that a source voluntarily obtains to avoid major 
stationary source requirements, such as the PSD or title V 
permitting programs. See, e.g., 40 CFR 52.21(b)(4), 51.166(b)(4), 
70.2 (definition of ``potential to emit'').
---------------------------------------------------------------------------

B. Implications for Title V Program

    Title V is implemented through 40 CFR parts 70 and 71. Part 70 
defines the minimum requirements for State, local and Tribal (state) 
agencies to develop, implement and enforce a title V operating permit 
program; these programs are developed by the State and the State 
submits a program to the EPA for a review of consistency with part 70. 
There are about 117 approved part 70 programs in effect, with about 
14,000 part 70 permits currently in effect. (See Appendix A of 40 CFR 
part 70 for the approval status of each State program.) Part 71 is a 
Federal permit program run by the EPA, primarily where there is no part 
70 program in effect (e.g., in Indian country, the Federal Outer 
Continental Shelf, and for offshore Liquified Natural Gas 
terminals).\701\ There are about 100 part 71 permits currently in 
effect (most are in Indian country).
---------------------------------------------------------------------------

    \701\ In some circumstances, the EPA may delegate authority for 
part 71 permitting to another permitting agency, such as a Tribal 
agency or a state. The EPA has entered into delegation agreements 
for certain part 71 permitting activities with at least one Tribal 
agency. There are currently no States that do not have an approved 
part 70 program; thus, there is no need for the EPA to delegate part 
71 delegated authority to any state at this time.
---------------------------------------------------------------------------

    The title V regulations require each permit to include emission 
limitations and standards, including operational requirements and 
limitations that assure compliance with all applicable requirements. 
Requirements resulting from these rules that are imposed on EGUs or 
other potentially affected entities that have title V operating permits 
are applicable requirements under the title V regulations and would 
need to be incorporated into the source's title V permit in accordance 
with the schedule established in the title V regulations. For example, 
if the permit has a remaining life of three years or more, a permit 
reopening to incorporate the newly applicable requirement shall be 
completed no later than 18 months after promulgation of the applicable 
requirement. If the permit has a remaining life of less than three

[[Page 33409]]

years, the newly applicable requirement must be incorporated at permit 
renewal.
    If a State needs to include provisions related to the State plan in 
a source's title V permit before submitting the plan to the EPA, these 
limits should be labeled as ``state-only'' or ``not federally 
enforceable'' until the EPA has approved the State plan. The EPA 
solicits comment on whether, and under what circumstances, states might 
use this mechanism.

XIV. Impacts of Proposed Actions

    In accordance with E.O. 12866 and 13563, the guidelines of OMB 
Circular A-4 and the EPA's Guidelines for Preparing Economic Analyses, 
the EPA prepared an RIA for these proposed actions. This RIA presents 
the expected economic consequences of the EPA's proposed rules, 
including analysis of the benefits and costs associated with the 
projected emission reductions for three illustrative scenarios. The 
first scenario represents the proposed CAA 111(b) combustion turbine 
phase 1 and phase 2 standards and 111(d) steam generating turbine 
proposals in combination. The second and third scenarios represent 
different stringencies of the combined policies. All three illustrative 
scenarios are compared against a single baseline. For detailed 
descriptions of the three illustrative scenarios and the baseline, see 
section 1 of the RIA, which is titled ``Regulatory Impact Analysis for 
the Proposed 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.''
    The three scenarios detailed in the RIA, including the proposal 
scenario, are illustrative in nature and do not represent the plans 
that states may ultimately pursue. As there are considerable 
flexibilities afforded to states in developing their State plans, the 
EPA does not have sufficient information to assess specific compliance 
measures on a unit-by-unit basis. Nonetheless, the EPA believes that 
such illustrative analysis can provide important insights.
    In the RIA, the EPA evaluates the potential impacts of the three 
illustrative scenarios using the present value (PV) of costs, benefits, 
and net benefits, calculated for the years 2024 to 2042 from the 
perspective of 2024, using both a three percent and seven percent 
discount rate. In addition, the EPA presents the assessment of costs, 
benefits, and net benefits for specific snapshot years, consistent with 
the Agency's historic practice. These specific snapshot years are 2028, 
2030, 2035, and 2040. In addition to the core benefit-cost analysis, 
the RIA also includes analyses of anticipated economic and energy 
impacts, environmental justice impacts, and employment impacts.
    The analysis presented in this preamble section summarizes key 
results of the illustrative policy scenario. For detailed benefit-cost 
results for the three illustrative scenarios and results of the variety 
of impact analysis just mentioned, please see the RIA, which is 
available in the docket for this action. The EPA also seeks comment on 
all aspects of the analysis, including modeling assumptions.

A. Air Quality Impacts

    For the analysis of the proposed standards for new combustion 
turbines and for existing steam generating EGUs, which do not include 
the impact of the proposed standards for existing combustion turbines 
and the third phase of the proposed standards for new combustion 
turbines, total cumulative power sector CO2 emissions 
between 2028 and 2042 are projected to be 617 million metric tons lower 
under the illustrative proposal scenario than under the baseline. Table 
7 shows projected aggregate annual electricity sector emission changes 
for the illustrative proposal scenario, relative to the baseline.

 Table 7--Projected Electricity Sector Emission Impacts for the Illustrative Proposal Scenario, Relative to the
                                                    Baseline
----------------------------------------------------------------------------------------------------------------
                                                                   Ozone Season                    Direct PM2.5
                                   CO2 (million     Annual NOX     NOX (thousand    Annual SO2       (thousand
                                   metric tons)      (thousand      short tons)      (thousand      short tons)
                                                    short tons)                     short tons)
----------------------------------------------------------------------------------------------------------------
2028............................             -10              -7              -3             -12              -1
2030............................             -89             -64             -22            -107              -6
2035............................             -37             -21              -7             -41              -1
2040............................             -24             -13              -4             -30              -1
----------------------------------------------------------------------------------------------------------------
Note: Ozone season is the May through September period in this analysis.

    The emissions changes in these tables do not account for changes in 
HAP that are likely to occur as a result of this action.
    For the analysis of the proposed standards for existing combustion 
turbines and for the third phase of the proposed standards for new 
natural gas-fired EGUs, total cumulative power sector CO2 
emissions between 2028 and 2042 are estimated to be between 215-409 
million metric tons lower than under the illustrative proposal 
scenario.

Table 8--Estimated Electricity Sector Emission Impacts From Existing Gas
 Standard and Third Phase of Low-GHG Hydrogen Co-Firing Standard for New
                      Base Load Combustion Turbines
------------------------------------------------------------------------
                                                     CO2 (million metric
                                                            tons)
                                                   ---------------------
                                                       Low        High
------------------------------------------------------------------------
2028..............................................          0          0
2030..............................................          0          0
2035..............................................        -20        -37
2040..............................................        -20        -39
------------------------------------------------------------------------

B. Compliance Cost Impacts

    The power industry's compliance costs are represented in this 
analysis as the change in electric power generation costs between the 
baseline and illustrative scenarios, including the cost of monitoring, 
reporting, and recordkeeping. In simple terms, these costs are an 
estimate of the increased power industry expenditures required to 
comply with the proposed actions.
    The compliance assumptions--and, therefore, the projected 
compliance costs--set forth in this analysis are illustrative in nature 
and do not represent the plans that states may

[[Page 33410]]

ultimately pursue. The illustrative proposal scenario is designed to 
reflect, to the extent possible, the scope and nature of the proposed 
guidelines. However, there is uncertainty with regards to the precise 
measures that states will adopt to meet the requirements because there 
are flexibilities afforded to the states in developing their State 
plans.
    The impact of the IRA is to accelerate the ongoing shift towards 
lower emitting technology. In particular, tax credits for low-emitting 
technology results in growing generation share for renewable resources 
and the deployment of 11 GW of CCS retrofits on existing coal fired 
EGUs, and 10 GW of CCS retrofits on existing combined cycle EGUs by 
2035. New combined cycle builds are 22 GW by 2030, and existing coal 
capacity continues to decline, falling to 69 GW by 2030 and 35 GW by 
2040. As a result, the compliance cost of the proposed rules is lower 
than it would be absent the IRA.
    We estimate the present value (PV) of the projected compliance 
costs for the analysis of the proposed standards for new combustion 
turbines and for existing steam-generating EGUs, which do not include 
the impact of the proposed standards for existing combustion turbines 
EGUs and the third phase of the proposed standards for new combustion 
turbines over the 2024 to 2042 period, as well as estimate the 
equivalent annual value (EAV) of the flow of the compliance costs over 
this period. The EAV represents a flow of constant annual values that, 
had they occurred annually, would yield a sum equivalent to the PV. All 
dollars are in 2019 dollars. Consistent with Executive Order 12866 
guidance, we estimate the PV and EAV using 3 and 7 percent discount 
rates. The PV of the compliance costs, discounted at the 3-percent 
rate, is estimated to be about $14 billion, with an EAV of about $0.95 
billion. At the 7-percent discount rate, the PV of the compliance costs 
is estimated to be about $10 billion, with an EAV of about $0.98 
billion.
    The EPA has developed a separate estimate of the projected 
compliance costs for the proposed standards for existing combustion 
turbines and third phase of the proposed standards for new natural gas-
fired EGUs over the 2024 to 2042 period. The PV of these compliance 
costs, discounted at the 3-percent rate, is estimated to be between 
about $5.7 to 10 billion, with an EAV of between about $0.4 to 0.7 
billion. At the 7 percent discount rate, the PV of these compliance 
costs is estimated to be between about $3.5 to 6.2 billion, with an EAV 
of about $0.34 to 0.6 billion.
    Sections 3 and 8 of the RIA present detailed discussions of the 
compliance cost projections for the proposed requirements, as well as 
projections of compliance costs for less and more stringent regulatory 
options. For a detailed description of these compliance cost 
projections, please see sections 3 and 8 of the RIA. The EPA solicits 
comment on its cost estimation generally.

C. Economic and Energy Impacts

    These proposed actions have economic and energy market 
implications. The energy impact estimates presented here reflect the 
EPA's illustrative analysis of the proposed rules. States are afforded 
flexibility to implement the proposed rules, and thus the impacts could 
be different to the extent states make different choices than those 
assumed in the illustrative analysis. Table 9 presents a variety of 
energy market impact estimates for 2028, 2030, 2035, and 2040 for the 
illustrative proposal scenario, relative to the baseline. These results 
pertain to the analysis of the proposed standards for new combustion 
turbines and for existing steam generation EGUs, and do not include the 
impact of the proposed standards for existing combustion turbines and 
the third phase of the proposed standards for new combustion turbines.

 Table 9--Summary of Certain Energy Market Impacts for the Illustrative
               Proposal Scenario, Relative to the Baseline
                            [Percent change]
------------------------------------------------------------------------
                               2028 (%)   2030 (%)   2035 (%)   2040 (%)
------------------------------------------------------------------------
Retail electricity prices...         -1          2          0          0
Average price of coal                -1          0          2          2
 delivered to power sector..
Coal production for power            -2        -40        -23        -15
 sector use.................
Price of natural gas                  0          9         -2         -3
 delivered to power sector..
Price of average Henry Hub            0         10         -2         -2
 (spot).....................
Natural gas use for                   0          8         -1         -2
 electricity generation.....
------------------------------------------------------------------------

    These and other energy market impacts are discussed more 
extensively in section 3 of the RIA.
    More broadly, changes in production in a directly regulated sector 
may have effects on other markets when output from that sector--for 
this rule electricity--is used as an input in the production of other 
goods. It may also affect upstream industries that supply goods and 
services to the sector, along with labor and capital markets, as these 
suppliers alter production processes in response to changes in factor 
prices. In addition, households may change their demand for particular 
goods and services due to changes in the price of electricity and other 
final goods prices. Economy-wide models--and, more specifically, 
computable general equilibrium (CGE) models--are analytical tools that 
can be used to evaluate the broad impacts of a regulatory action. A 
CGE-based approach to cost estimation concurrently considers the effect 
of a regulation across all sectors in the economy.
    In 2015, the EPA established a Science Advisory Board (SAB) panel 
to consider the technical merits and challenges of using economy-wide 
models to evaluate costs, benefits, and economic impacts in regulatory 
analysis. In its final report, the SAB recommended that the EPA begin 
to integrate CGE modeling into applicable regulatory analysis to offer 
a more comprehensive assessment of the effects of air regulations.\702\ 
In response to the SAB's recommendations, the EPA developed a new CGE 
model called SAGE designed for use in regulatory analysis. A second SAB 
panel

[[Page 33411]]

performed a peer review of SAGE, and the review concluded in 2020.\703\
---------------------------------------------------------------------------

    \702\ U.S. EPA. 2017. SAB Advice on the Use of Economy-Wide 
Models in Evaluating the Social Costs, Benefits, and Economic 
Impacts of Air Regulations. EPA-SAB-17-012.
    \703\  U.S. EPA. 2020. Technical Review of EPA's Computable 
General Equilibrium Model, SAGE. EPA-SAB-20-010.
---------------------------------------------------------------------------

    The EPA used SAGE to evaluate potential economy-wide impacts of 
these proposed rules, and the results are contained in an appendix of 
the RIA. As presented in the RIA, annualized social costs estimated in 
SAGE are approximately 35 percent larger than the partial equilibrium 
private compliance costs (less taxes and transfers) derived from IPM. 
This is consistent with general expectations based on the empirical 
literature.\704\ However, the social cost estimate reflects the 
combined effect of the proposed rules' requirements and interactions 
with IRA subsidies for specific technologies that are expected to see 
increased use in response to the proposed rules. We are not able to 
identify their relative roles at this time. The EPA solicits comment on 
the SAGE analysis presented in the RIA appendix.
---------------------------------------------------------------------------

    \704\ See, for example, Marten, A.L., Garbaccio, R., and 
Wolverton, A. 2019. Exploring the General Equilibrium Costs of 
Sector-Specific Environmental Regulations. Journal of the 
Association of Environmental and Resource Economists, 6(6), 1065-
1104.
---------------------------------------------------------------------------

    Environmental regulation may affect groups of workers differently, 
as changes in abatement and other compliance activities cause labor and 
other resources to shift. An employment impact analysis describes the 
characteristics of groups of workers potentially affected by a 
regulation, as well as labor market conditions in affected occupations, 
industries, and geographic areas. Employment impacts of these proposed 
actions are discussed more extensively in section 5 of the RIA.

D. Benefits

    Pursuant to E.O. 12866, the RIA for these actions analyzes the 
benefits associated with the projected emission reductions under the 
proposals to inform the EPA and the public about these projected 
impacts.\705\ These proposed rules are projected to reduce emissions of 
CO2, SO2, NOX, and PM2.5 
nationwide which we estimate will provide climate benefits and public 
health benefits. The potential climate, health, welfare, and water 
quality impacts of these emission reductions are discussed in detail in 
the RIA. In the RIA, the EPA presents the projected monetized climate 
benefits due to reductions in CO2 emissions and the 
monetized health benefits attributable to changes in SO2, 
NOX, and PM2.5 emissions, based on the emissions 
estimates in illustrative scenarios described previously. We monetize 
benefits of the proposed standards and evaluate other costs in part to 
enable a comparison of costs and benefits pursuant to E.O. 12866, but 
we recognize there are substantial uncertainties and limitations in 
monetizing benefits, including benefits that have not been quantified 
or monetized.
---------------------------------------------------------------------------

    \705\ These results pertain to the analysis of the proposed 
standards for new combustion turbine EGUs and for existing steam-
generating EGUs, and do not include the impact of the proposed 
standards for existing combustion turbine EGUs and the third phase 
of the proposed standards for new natural gas-fired EGUs.
---------------------------------------------------------------------------

    We estimate the climate benefits from these proposed rules using 
estimates of the social cost of greenhouse gases (SC-GHG), specifically 
the SC-CO2. The SC-CO2 is the monetary value of 
the net harm to society associated with a marginal increase in 
CO2 emissions in a given year, or the benefit of avoiding 
that increase. In principle, SC-CO2 includes the value of 
all climate change impacts (both negative and positive), including (but 
not limited to) changes in net agricultural productivity, human health 
effects, property damage from increased flood risk natural disasters, 
disruption of energy systems, risk of conflict, environmental 
migration, and the value of ecosystem services. The SC-CO2, 
therefore, reflects the societal value of reducing emissions of the gas 
in question by one metric ton and is the theoretically appropriate 
value to use in conducting benefit-cost analyses of policies that 
affect CO2 emissions. In practice, data and modeling 
limitations naturally restrain the ability of SC-CO2 
estimates to include all the important physical, ecological, and 
economic impacts of climate change, such that the estimates are a 
partial accounting of climate change impacts and will therefore, tend 
to be underestimates of the marginal benefits of abatement. The EPA and 
other Federal agencies began regularly incorporating SC-GHG estimates 
in their benefit-cost analyses conducted under E.O. 12866 since 2008, 
following a Ninth Circuit Court of Appeals remand of a rule for failing 
to monetize the benefits of reducing CO2 emissions in a 
rulemaking process.
    We estimate the global social benefits of CO2 emission 
reductions expected from the proposed rule using the SC-GHG estimates 
presented in the February 2021 TSD: Social Cost of Carbon, Methane, and 
Nitrous Oxide Interim Estimates under E.O. 13990. These SC-GHG 
estimates are interim values developed under E.O. 13990 for use in 
benefit-cost analyses until updated estimates of the impacts of climate 
change can be developed based on the best available climate science and 
economics. We have evaluated the SC-GHG estimates in the TSD and have 
determined that these estimates are appropriate for use in estimating 
the global social benefits of CO2 emission reductions 
expected from this proposed rule. After considering the TSD, and the 
issues and studies discussed therein, the EPA finds that these 
estimates, while likely an underestimate, are the best currently 
available SC-GHG estimates. These SC-GHG estimates were developed over 
many years using a transparent process, peer-reviewed methodologies, 
the best science available at the time of that process, and with input 
from the public. As discussed in section 4 of the RIA, these interim 
SC-CO2 estimates have a number of limitations, including 
that the models used to produce them do not include all of the 
important physical, ecological, and economic impacts of climate change 
recognized in the climate-change literature and that several modeling 
input assumptions are outdated. As discussed in the February 2021 TSD, 
the Interagency Working Group on the Social Cost of Greenhouse Gases 
(IWG) finds that, taken together, the limitations suggest that these 
SC-CO2 estimates likely underestimate the damages from 
CO2 emissions. The IWG is currently working on a 
comprehensive update of the SC-GHG estimates (under E.O. 13990) taking 
into consideration recommendations from the National Academies of 
Sciences, Engineering and Medicine, recent scientific literature, 
public comments received on the February 2021 TSD and other input from 
experts and diverse stakeholder groups. The EPA is participating in the 
IWG's work. In addition, while that process continues, the EPA is 
continuously reviewing developments in the scientific literature on the 
SC-GHG, including more robust methodologies for estimating damages from 
emissions, and looking for opportunities to further improve SC-GHG 
estimation going forward. Most recently, the EPA has developed a draft 
updated SC-GHG methodology within a sensitivity analysis in the 
regulatory impact analysis of the EPA's November 2022 supplemental 
proposal for oil and gas standards that is currently undergoing 
external peer review and a public comment process. If EPA's updated SC-
GHG methodology is finalized before these rules are finalized, the EPA 
intends to present monetized climate benefits using the updated SC-GHG 
estimates in the final RIA. See section 4 of the RIA for more 
discussion of this effort.

[[Page 33412]]

    In addition to CO2, these proposed rules are expected to 
reduce emissions of NOX and SO2 and direct 
PM2.5 nationally throughout the year. Because NOX 
and SO2 are also precursors to secondary formation of 
ambient PM2.5, reducing these emissions would reduce human 
exposure to ambient PM2.5 throughout the year and would 
reduce the incidence of PM2.5-attributable health effects. 
These proposed rules are also expected to reduce ozone season 
NOX emissions nationally. In the presence of sunlight, 
NOX and volatile organic compounds (VOCs) can undergo a 
chemical reaction in the atmosphere to form ozone. Reducing 
NOX emissions in most locations reduces human exposure to 
ozone and the incidence of ozone-related health effects, though the 
degree to which ozone is reduced will depend in part on local 
concentration levels of VOCs. The RIA estimates the health benefits of 
changes in PM2.5 and ozone concentrations. The health effect 
endpoints, effect estimates, benefit unit-values, and how they were 
selected, are described in the Estimating PM2.5- and Ozone-
Attributable Health Benefits TSD, which is referenced in the RIA for 
these actions. Our approach for updating the endpoints and to identify 
suitable epidemiologic studies, baseline incidence rates, population 
demographics, and valuation estimates is summarized in section 4 of the 
RIA.
    The following PV and EAV estimates reflect projected benefits over 
the 2024 to 2042 period, discounted to 2024 in 2019 dollars, for the 
analysis of the proposed standards for new natural gas-fired EGUs and 
for existing coal-fired EGUs, which do not include the impact of the 
proposed standards for existing natural gas-fired EGUs and the third 
phase of the proposed standards for new natural gas-fired EGUs. We 
monetize benefits of the proposed standards and evaluate other costs in 
part to enable a comparison of costs and benefits pursuant to E.O. 
12866, but we recognize there are substantial uncertainties and 
limitations in monetizing benefits, including benefits that have not 
been quantified. The projected PV of monetized climate benefits is 
about $30 billion, with an EAV of about $2.1 billion using the SC-
CO2 discounted at 3 percent. The projected PV of monetized 
health benefits is about $68 billion, with an EAV of about $4.8 billion 
discounted at 3 percent. Combining the projected monetized climate and 
health benefits yields a total PV estimate of about $98 billion and EAV 
estimate of $6.9 billion.
    At a 7 percent discount rate, these proposed rules are expected to 
generate projected PV of monetized health benefits of about $44 
billion, with an EAV of about $4.3 billion discounted at 7 percent. The 
EPA notes that while OMB Circular A-4, as published in 2003, recommends 
using 3 percent and 7 percent discount rates as ``default'' values, 
Circular A-4 also recognizes that ``special ethical considerations 
arise when comparing benefits and costs across generations,'' and 
Circular A-4 acknowledges that analyses may appropriately ``discount 
future costs and consumption benefits . . . at a lower rate than for 
intragenerational analysis.'' Therefore, climate benefits remain 
discounted at 3 percent in this benefits analysis. Thus, these proposed 
rules would generate a PV of total monetized benefits of $74 billion, 
with an EAV of $6.4 billion discounted at a 7 percent rate.
    The projected PV of monetized climate benefits for the analysis of 
the impact of the proposed standards for existing combustion turbines 
and the third phase of the proposed standards for new natural gas-fired 
EGUs is between about $10 to 20 billion, with an EAV of between about 
$0.7 to 1.4 billion using the SC-CO2 discounted at 3 
percent.
    The results presented in this section provide an incomplete 
overview of the effects of the proposals. The monetized climate 
benefits estimates do not include important benefits that we are unable 
to fully monetize due to data and modeling limitations. In addition, 
important health, welfare, and water quality benefits anticipated under 
these proposed rules are not quantified. We anticipate that taking non-
monetized effects into account would show the proposals to be more 
beneficial than the tables in this section reflect. Discussion of the 
non-monetized health, climate, welfare, and water quality benefits is 
found in section 4 of the RIA.

E. Environmental Justice Analytical Considerations and Stakeholder 
Outreach and Engagement

    Consistent with the EPA's commitment to integrating environmental 
justice (EJ) in the Agency's actions, and following the directives set 
forth in multiple Executive Orders, the Agency has analyzed the impacts 
of these proposed rules on communities with potential environmental 
justice concerns and engaged with stakeholders representing these 
communities to seek input and feedback. The EPA evaluates, to the 
extent practicable, whether proposed GHG reductions are accompanied by 
changes in other health-harming pollutants that may place further 
burdens on these communities.\706\
---------------------------------------------------------------------------

    \706\ These results pertain to the analysis of the proposed 
standards for new combustion turbine EGUs and for existing steam-
generating EGUs, and do not include the impact of the proposed 
standards for existing combustion turbine EGUs and the third phase 
of the proposed standards for new natural gas-fired EGUs.
---------------------------------------------------------------------------

    Executive Order 12898 is discussed in section XV.J of this preamble 
and analytical results are available in section 6 of the RIA.
1. Introduction
    Executive Order 12898 directs the EPA to identify the populations 
of concern who are most likely to experience unequal burdens from 
environmental harms; specifically, minority populations, low-income 
populations, and indigenous peoples. Additionally, Executive Order 
13985 is intended to advance racial equity and support underserved 
communities through Federal government actions. The EPA defines 
environmental justice as the fair treatment and meaningful involvement 
of all people regardless of race, color, national origin, or income, 
with respect to the development, implementation, and enforcement of 
environmental laws, regulations, and policies. The EPA further defines 
the term fair treatment to mean that ``no group of people should bear a 
disproportionate burden of environmental harms and risks, including 
those resulting from the negative environmental consequences of 
industrial, governmental, and commercial operations or programs and 
policies''.\707\ In recognizing that minority and low-income 
populations often bear an unequal burden of environmental harms and 
risks, the EPA continues to consider ways of protecting them from 
adverse public health and environmental effects of air pollution.
---------------------------------------------------------------------------

    \707\ Plan EJ 2014. Washington, DC: U.S. EPA, Office of 
Environmental Justice. https://www.epa.gov/environmentaljustice/plan-ej-2014.
---------------------------------------------------------------------------

2. Analytical Considerations
    EJ concerns for each rulemaking are unique and should be considered 
on a case-by-case basis, and the EPA's EJ Technical Guidance states 
that ``[t]he analysis of potential EJ concerns for regulatory actions 
should address three questions:
    1. Are there potential EJ concerns associated with environmental 
stressors affected by the regulatory action for population groups of 
concern in the baseline?
    2. Are there potential EJ concerns associated with environmental 
stressors affected by the regulatory action for population groups of 
concern for the

[[Page 33413]]

regulatory option(s) under consideration?
    3. For the regulatory option(s) under consideration, are potential 
EJ concerns created or mitigated compared to the baseline?''
    To address these questions, the EPA developed an analytical 
approach that considers the purpose and specifics of the rulemaking, as 
well as the nature of known and potential exposures and impacts. For 
the rules, the EPA quantitatively evaluates the proximity of existing 
affected facilities to potentially vulnerable and/or overburdened 
populations for consideration of local pollutants impacted by these 
rules but not modeled here (RIA section 6.4), as well as the 
distribution of ozone and PM2.5 concentrations in the 
baseline and changes due to the proposed rulemakings across different 
demographic groups on the basis of race, ethnicity, poverty status, 
employment status, health insurance status, age, sex, educational 
attainment, and degree of linguistic isolation (RIA section 6.5). The 
EPA also qualitatively discusses potential EJ climate impacts (RIA 
section 6.3). Each of these analyses was performed to answer separate 
questions and is associated with unique limitations and uncertainties.
    Baseline demographic proximity analyses provide information as to 
whether there may be potential EJ concerns associated with 
environmental stressors emitted from sources affected by the regulatory 
actions for certain population groups of concern. The baseline 
demographic proximity analyses examined the demographics of populations 
living within 5 km and 10 km of the following three sets of sources: 
(1) all 140 coal plants with units potentially subject to the proposed 
rules, (2) three coal plants retiring by January 1, 2032 with units 
potentially subject to the proposed rules, and (3) 19 coal plants 
retiring between January 1, 2032 to January 1, 2040 with units 
potentially subject to the proposed rules. The proximity analysis of 
the full population of potentially affected units greater than 25 MW 
indicated that the demographic percentages of the population within 10 
km and 50 km of the facilities are relatively similar to the national 
averages. The proximity analysis of the 19 units that will retire from 
1/1/32 to 1/1/40 (a subset of the total 140 units) found that the 
percent of the population within 10 km that is African American is 
higher than the national average. The proximity analysis for the 3 
units that will retire by 1/1/32 (a subset of the total 140 units) 
found that for both the 10 km and 50 km populations the percent of the 
population that is Native American for one facility is significantly 
above the national average, the percent of the population that is 
Hispanic/Latino for another facility is significantly above the 
national average, and all three facilities were well above the national 
average for both the percent below the poverty level and the percent 
below two times the poverty level.
    Because the pollution impacts that are the focus of these rules may 
occur downwind from affected facilities, ozone and PM2.5 
exposure analyses that evaluate demographic variables are better able 
to evaluate any potentially disproportionate pollution impacts of these 
rulemakings. The baseline PM2.5 and ozone exposure analyses 
respond to question 1 from EPA's EJ Technical Guidance document more 
directly than the proximity analyses, as they evaluate a form of the 
environmental stressor primarily affected by the regulatory actions 
(RIA section 6.5). Baseline ozone and PM2.5 exposure 
analyses show that certain populations, such as Hispanics, Asians, 
those linguistically isolated, and those less educated may experience 
disproportionately higher ozone and PM2.5 exposures as 
compared to the national average. Black populations may also experience 
disproportionately higher PM2.5 concentrations than the 
reference group, and American Indian populations and children may also 
experience disproportionately higher ozone concentrations than the 
reference group. Therefore, there likely are potential EJ concerns 
associated with environmental stressors affected by the regulatory 
actions for population groups of concern in the baseline (question 1).
    Finally, the EPA evaluates how post-policy regulatory alternatives 
of these proposed rulemakings are expected to differentially impact 
demographic populations, informing questions 2 and 3 from EPA's EJ 
Technical Guidance with regard to ozone and PM2.5 exposure 
changes. We infer that baseline disparities in the ozone and 
PM2.5 concentration burdens are likely to remain after 
implementation of the regulatory action or alternatives under 
consideration. This is due to the small magnitude of the concentration 
changes associated with these rulemakings across population demographic 
groups, relative to the magnitude of the baseline disparities (question 
2). This EJ assessment also suggests that these actions are unlikely to 
mitigate or exacerbate PM2.5 exposures disparities across 
populations of EJ concern analyzed. Regarding ozone exposures, while 
most policy options and future years analyzed will not likely mitigate 
or exacerbate ozone exposure disparities for the population groups 
evaluated, ozone exposure disparities may be exacerbated for some 
population groups analyzed in 2030 under all regulatory options. 
However, the extent to which disparities may be exacerbated is likely 
modest, due to the small magnitude of the ozone concentration changes 
(question 3). Importantly, the actions described in these proposals are 
expected to lower PM2.5 and ozone in many areas, and thus 
mitigate some pre-existing health risks of air pollution across all 
populations evaluated.
3. Outreach and Engagement
    In outreach with potentially vulnerable communities, residents have 
voiced two primary concerns. First, there is the concern that their 
communities have experienced historically disproportionate burdens from 
the environmental impacts of energy production, and second, that as the 
sector evolves to use new technologies such as CCS and hydrogen, they 
may continue to face disproportionate burdens.
    With regard to CCS, the EPA is proposing that CCS is a component of 
the BSER for new base load stationary combustion turbine EGUs, existing 
coal-fired steam generating units that intend to operate after 2040, 
and large and frequently operated existing stationary combustion 
turbine EGUs. The EPA recognizes and has given careful consideration to 
the various concerns that potentially vulnerable communities have 
raised with regard to the use of CCS in determining that CCS is BSER 
for these sources. In the following section, the EPA discusses various 
measures undertaken in this rulemaking and elsewhere to address 
community concerns on this matter.
    One concern the EPA has heard from stakeholders is that adding CCS 
to EGUs can extend the life of an existing coal-fired steam generating 
unit, subjecting local residents who have already been negatively 
impacted by the operation of the coal-fired steam generating unit to 
additional harmful pollution. There are several important factors the 
EPA considered in evaluating the emission impact of an upgraded EGU 
when determining BSER for these units that intend to operate in the 
long term. First, CCS is the most effective add-on pollution control 
available for mitigation of GHG emissions from affected sources. 
Second, most CCS technologies work much more effectively when the EGU 
is emitting the lowest levels of SO2 possible; therefore it 
is likely that as part of a CCS installation, companies will improve 
their EGUs' SO2 control. Third, a CCS

[[Page 33414]]

retrofit may trigger requirements under the major NSR program because 
of the potential for an emissions increase of one or more pollutants 
due to the additional energy production by the EGU to power the 
CO2 capture system. If the source is undergoing major NSR 
permitting, the permitting authority would provide an opportunity for 
the public to comment on the draft permit, which is another avenue for 
affected residents to submit input regarding additional controls that 
may be needed to meet best available control technology requirements 
for non-GHG pollutants such as NOX.\708\
---------------------------------------------------------------------------

    \708\ The EPA discusses the interactions between CCS and non-GHG 
pollutants for existing coal-fired steam generating units in section 
X.D.1.a.iii(B) of this preamble.
---------------------------------------------------------------------------

    Communities have also expressed concerns about CO2 
pipeline safety and geologic sequestration. As discussed in section 
VII.F.3.b.iii of the preamble, supercritical CO2 pipeline 
safety is regulated by PHMSA. These regulations protect against 
environmental release during transport and PHMSA has announced steps to 
further strengthen its safety oversight of supercritical CO2 
pipelines, including initiating a new rulemaking to update standards 
for supercritical CO2 pipelines and solicited research 
proposals to strengthen CO2 pipeline safety.\709\ Geologic 
sequestration of CO2 is regulated by the EPA through the UIC 
Program under the Safe Drinking Water Act, and through the GHGRP under 
the Clean Air Act. UIC Class VI regulations include strong protections 
for communities to prevent contamination of underground sources of 
drinking water. These regulatory protections include a variety of 
measures, including proper site characterization and strict 
construction, operating, and monitoring requirements to ensure well and 
formation integrity, proper plugging of wells, and long-term project 
management and post-injection site care to ensure leakage 
prevention.\710\ GHGRP requirements complement and build on UIC 
regulations through air-side monitoring and reporting requirements that 
provide the EPA and communities with a transparent means of evaluating 
the effectiveness of geologic sequestration. These programs work in 
combination to provide security and transparency.
---------------------------------------------------------------------------

    \709\ PHMSA, ``PHMSA Announces New Safety Measures to Protect 
Americans From Carbon Dioxide Pipeline Failures After Satartia, MS 
Leak.'' 2022. https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americans-carbon-dioxide-pipeline-failures.
    \710\ See generally Administrator Michael S. Regan, Underground 
Injection Control Class VI Letter to Governors (December 9, 2022), 
https://www.epa.gov/system/files/documents/2022-12/AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
---------------------------------------------------------------------------

    The final concern the EPA has heard from stakeholders is about a 
lack of opportunity for impacted communities to voice opinions about 
projects like this that affect them. Recognizing the important stake 
that local residents have in decisions regarding EGUs in their 
communities, the EPA expects that states will address facility-specific 
concerns about how to responsibly deploy CCS and any other potential 
control strategies in the course of meaningful engagement under the 
proposed emission guidelines for existing steam generating units and 
existing combustion turbines, as discussed in section XII.F.1.b of the 
preamble. State plans should specifically ensure that community members 
have an opportunity to share their input if they reside near a fossil 
fuel-fired steam generating unit that plans to install CCS to meet the 
requirements of these proposed rules regarding how to responsibly 
deploy this technology.
    With regard to the decision to construct a new combustion turbine, 
most of the safeguards outlined above for CCS retrofits apply. While 
meaningful engagement applies under emission guidelines to existing 
sources, there exists an opportunity for community engagement for new 
sources as part of the major NSR permitting process, in the event that 
the source triggers major NSR requirements. While new combustion 
turbines that co-fire with hydrogen may trigger major NSR, there are 
cases in which they are less likely to trigger major NSR, such as: (1) 
If the new combustion turbine is proposed at an existing facility and 
the facility is able to reduce its emissions more than the emissions 
increase from the combustion turbine (e.g., if the combustion turbine 
replaces an existing coal-fired EGU and the facility has emission 
reduction credits from the shutdown unit), or (2) if the emissions from 
the new combustion turbine are low enough to not trigger major NSR.
    The EPA further notes that hydrogen production presents a unique 
set of potential issues for vulnerable communities. During the February 
27th National Tribal Energy Roundtable Webinar, one of the primary 
concerns articulated was the potential for fossil-derived hydrogen to 
essentially extend the life of petrochemical industries already 
creating localized pollution loading. Since hydrogen is non-toxic, and 
it does not produce carbon dioxide when burned, the inclusion of 
hydrogen in combustion turbine operations will lower overall health 
risks compared with hydrocarbons. Perceived community risks with 
hydrogen related to storage and transportation include its 
combustibility and propensity to leak due to extremely low molecular 
weight. Despite concerns about hydrogen, its low molecular weight 
ensures that it dissipates and disperses quickly when released 
outdoors, reducing unintended combustion risks compared with other 
fuels.\711\ Adequate ventilation and leak detection are available to 
ensure safety and are important elements in the design of hydrogen 
systems. Concerns around hydrogen leaks can be mitigated with hydrogen 
monitoring systems combined with adequate ventilation and leak 
detection equipment, including special flame detectors.\712\ Further, 
building and operational codes and standards developed specifically for 
hydrogen's properties can minimize risks around hydrogen usage in a 
community.\713\
---------------------------------------------------------------------------

    \711\ Department of Energy, Safe Use of Hydrogen https://www.energy.gov/eere/fuelcells/safe-use-hydrogen.
    \712\ Ibid.
    \713\ Department of Energy, Safety Codes and Standards https://www.energy.gov/eere/fuelcells/safety-codes-and-standards-basics.
---------------------------------------------------------------------------

    New combustion turbine models designed to combust hydrogen, and 
those potentially being retrofit to combust hydrogen, may be co-located 
with electrolyzers that produce the hydrogen the facility will use. In 
such instances, water scarcity could be exacerbated in some areas by 
the freshwater demands of electrolytic hydrogen production, which could 
pose a particular challenge for vulnerable communities. As such, 
electrolyzer siting will need to take water availability into account. 
Examples for sustainable siting for electrolyzers are emerging in 
Europe, which has begun to employ Sustainable Value Methodology 
designed to be sensitive to water access and availability and includes, 
``decision-making support, combining economic, environmental and social 
criteria''.\714\ We also expect advances in electrolytic technology 
over time to reduce water demand, including the potential to enabling 
sea-water usage in electrolyzers.\715\
---------------------------------------------------------------------------

    \714\ Journal of Cleaner Production, Volume 315, 15 September 
2021, 128124, ``Water Availability and Water Usage Solutions for 
Electrolysis in Hydrogen Production'' Simoes, Sophia et al., https://www.sciencedirect.com/science/article/pii/S0959652621023428.
    \715\ Sun, F., Qin, J., Wang, Z. et al. Energy-saving hydrogen 
production by chlorine-free hybrid seawater splitting coupling 
hydrazine degradation. Nat Commun 12, 4182 (2021). https://doi.org/10.1038/s41467-021-24529-3.

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[[Page 33415]]

F. Grid Reliability Considerations

    The requirements for sources and states set forth in these proposed 
actions were developed cognizant of concerns about an electric grid 
under transition, and related reliability considerations. As previously 
stated, a variety of important influences have led to notable changes 
in the generation mix and expectations of how the power sector will 
evolve. These trends have generally put existing high-emitting 
generators under greater economic pressure and will continue to do so 
even absent any EPA action pursuant to CAA section 111, and that is 
manifest in various economic projections and modeling of the electric 
power system. Recent legislation, including the IIJA, the IRA, and 
State policies have amplified these trends, with continued change 
expected for the existing fleet of EGUs. Moreover, many regions of the 
country have experienced a significant increase in the frequency and 
severity of extreme weather events--events that are notably projected 
to worsen if GHG emissions are not adequately controlled. These events 
have impacted energy infrastructure and both the demand for and supply 
of electricity. A wide range of stakeholders including power 
generators, grid operators and State and Federal regulators are 
actively engaged in ensuring the reliability of the electric power 
system is maintained and enhanced in the face of these changes.
    As explained in this preamble, these proposed actions take account 
of the rapidly evolving power sector and extensive input received from 
power companies and other stakeholders on the future of these regulated 
sources, while ensuring that new natural gas-fired combustion turbines 
and existing steam EGUs achieve significant and cost-effective 
reductions in GHG emissions through the application of adequately 
demonstrated control technologies. Preserving the ability of power 
companies and grid operators to maintain system reliability has been a 
paramount consideration in the development of these proposed actions. 
Accordingly, these proposed rules include significant design elements 
that are intended to allow the power sector continued resource and 
operational flexibility, and to facilitate long-term planning during 
this dynamic period. Among other things, these elements include 
subcategories of new natural gas-fired combustion turbines that allow 
for the stringency of standards of performance to vary by capacity 
factor; subcategories for existing steam EGUs that are based on 
operating horizons and fuel reflecting the request of industry 
stakeholders; compliance deadlines for both new and existing EGUs that 
provide ample lead time to plan; and proposed State plan flexibilities. 
In addition, this preamble discusses EPA's intention to exercise its 
enforcement discretion where needed to address any potential instances 
in which individual EGUs may need to temporarily operate for 
reliability reasons, and to set forth clear and transparent 
expectations for administrative compliance orders to ensure that 
compliance with these proposed rules can be achieved without impairing 
the ability of power companies and grid operators to maintain 
reliability. As such, these proposed rules provide the flexibility 
needed to avoid reliability concerns while still securing the pollution 
reductions consistent with section 111 of the CAA.
    To support these proposed actions, the EPA has conducted an 
analysis of resource adequacy based upon power sector modeling and 
projections of the standards on existing steam generating units, and 
the first two phases of the standards on new combustion turbines, as 
well as the results of the spreadsheet-based analysis of the standards 
on existing combustion turbines and the third phase of the standards on 
new combustion turbines, that can be found in the RIA. Any potential 
impact of these proposed actions is dependent upon a myriad of 
decisions and compliance choices source owners and operators may 
pursue. It is important to recognize that the proposed rules provide 
multiple flexibilities that preserve the ability of responsible 
authorities to maintain electric reliability. While not explicitly 
modeled using IPM, the proposed emission guidelines for existing 
natural gas-fired EGUs are estimated to have very little incremental 
impact on resource adequacy. The guidelines would affect a subset of 
the total natural gas fleet, and units that install CCS are still able 
to maintain capacity accreditation values (after accounting for 
capacity de-rates). Moreover, units that operate below 50 percent 
capacity factor annually (and are not subject to the CCS requirement) 
would still be able to operate at higher levels during times of greater 
demand, thereby maintaining their capacity accreditation values.
    The results presented in the Resource Adequacy Analysis TSD, which 
is available in the docket, show that the projected impacts of the 
proposed rules on power system operations, under conditions preserving 
resource adequacy, are modest and manageable. For the specific 
scenarios analyzed in the RIA, the implementation of the proposed rules 
can be achieved while maintaining resource adequacy even as shifts in 
existing and new capacity occur. Retirements are offset by additions, 
along with reserve transfers where/when needed, which demonstrates that 
ample compliance pathways exist for sources while preserving resource 
adequacy.
    The EPA routinely consults with the DOE and FERC on electric 
reliability and intends to continue to do so as it develops and 
implements a final rule. This ongoing engagement will be strengthened 
with routine and comprehensive communication between the agencies under 
the DOE-EPA Joint Memorandum of Understanding on Interagency 
Communication and Consultation on Electric Reliability signed on March 
8, 2023.\716\ The memorandum will provide greater interagency 
engagement on electric reliability issues at a time of significant 
dynamism in the power sector, allowing the EPA and the DOE to use their 
considerable expertise in various aspects of grid reliability to 
support the ability of Federal and State regulators, grid operators, 
regional reliability entities, and power companies to continue to 
deliver a high standard of reliable electric service. As the power 
sector continues to change and as the agencies carry out their 
respective authorities, the agencies intend to continue to engage and 
collectively monitor, share information, and consult on policy and 
program decisions to assure the continued reliability of the bulk power 
system.
---------------------------------------------------------------------------

    \716\ Joint Memorandum of Understanding on Interagency 
Communication and Consultation on Electric Reliability (March 8, 
2023). https://www.epa.gov/power-sector/electric-reliability-mou.
---------------------------------------------------------------------------

    In addition, the EPA observes that power companies, grid operators, 
and State public utility commissions have well-established procedures 
in place to preserve electric reliability in response to changes in the 
generating portfolio, and expects that those procedures will continue 
to be effective in addressing compliance decisions that power companies 
may make over the extended time period for implementation of these 
proposed rules. In response to any regulatory requirement, affected 
sources will have to take some type of action to reduce emissions, 
which will generally have costs. Some EGU owners may conclude that, all 
else being equal, retiring a particular EGU is likely to be the more 
economic option from the perspective of the unit's customers and/or 
owners because there are better opportunities for using the capital 
than investing it in new emissions controls at

[[Page 33416]]

the unit. Such a retirement decision will require the unit's owner to 
follow the processes put in place by the relevant RTO, balancing 
authority, or State regulator to protect electric system reliability. 
These processes typically include analysis of the potential impacts of 
the proposed EGU retirement on electrical system reliability, 
identification of options for mitigating any identified adverse 
impacts, and, in some cases, temporary provision of additional revenues 
to support the EGU's continued operation until longer-term mitigation 
measures can be put in place. In some rare instances where the 
reliability of the system is jeopardized due to extreme weather events 
or other unforeseen emergencies, authorities can request a temporary 
reprieve from environmental requirements and constraints (through DOE) 
in order to meet electric demand and maintain reliability. These 
proposed actions do not interfere with these already available 
provisions, but rather provides a long-term pathway for sources to 
develop and implement a proper plan to reduce emissions while 
maintaining adequate supplies of electricity.

XV. Statutory and Executive Order Reviews

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

    These actions were submitted to the Office of Management and Budget 
(OMB) for review under Section 3(f)(1) of Executive Order 12866. Any 
changes made in response to recommendations received as part of 
Executive Order 12866 review have been documented in the docket. The 
EPA prepared an analysis of the potential costs and benefits associated 
with these actions. This analysis, ``Regulatory Impact Analysis for the 
Proposed 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,'' is available in the docket.
    Table 10 presents the estimated present values (PV) and equivalent 
annualized values (EAV) of the projected climate benefits, health 
benefits, compliance costs, and net benefits of the proposed rule in 
2019 dollars discounted to 2024. This analysis covers the impacts of 
the proposed standards for new combustion turbines and for existing 
steam generating EGUs, and does not include the impact of the proposed 
standards for existing combustion turbines and the third phase of the 
proposed standards for new combustion turbines. The estimated monetized 
net benefits are the projected monetized benefits minus the projected 
monetized costs of the proposed rules.
    The projected climate benefits in table 8 are based on estimates of 
the social cost of carbon (SC-CO2) at a 3 percent discount 
rate and are discounted using a 3 percent discount rate to obtain the 
PV and EAV estimates in the table. Under E.O. 12866, the EPA is 
directed to consider the costs and benefits of its actions. 
Accordingly, in addition to the projected climate benefits of the 
proposals from anticipated reductions in CO2 emissions, the 
projected monetized health benefits include those related to public 
health associated with projected reductions in fine particulate matter 
(PM2.5) and ozone concentrations. The projected health 
benefits are associated with several point estimates and are presented 
at real discount rates of 3 and 7 percent. The power industry's 
compliance costs are represented in this analysis as the change in 
electric power generation costs between the baseline and policy 
scenarios. In simple terms, these costs are an estimate of the 
increased power industry expenditures required to implement the 
proposed requirements.
    These results present an incomplete overview of the potential 
effects of the proposals because important categories of benefits--
including benefits from reducing HAP emissions--were not monetized and 
are therefore not reflected in the benefit-cost tables. The EPA 
anticipates that taking non-monetized effects into account would show 
the proposals to have a greater net benefit than this table reflects.
---------------------------------------------------------------------------

    \717\ This analysis pertains to the proposed standards for new 
combustion turbines and for existing steam generating EGUs and does 
not include the impact of the proposed standards for existing 
combustion turbines and the third phase of the proposed standards 
for new combustion turbines.

    Table 10--Projected Monetized Benefits, Compliance Costs, and Net
         Benefits of the Proposed Rules, 2024 Through 2042 \717\
                [Billions 2019$, discounted to 2024] \a\
------------------------------------------------------------------------
                                            3% Discount     7% Discount
                                               rate            rate
------------------------------------------------------------------------
Present Value:
    Climate Benefits \c\................             $30             $30
    Health Benefits \d\.................              68              44
    Compliance Costs....................              14              10
    Net Benefits \e\....................              85              64
Equivalent Annualized Value \b\:
    Climate Benefits \c\................             2.1             2.1
    Health Benefits \d\.................             4.8             4.3
    Compliance Costs....................            0.95            0.98
    Net Benefits \e\....................             5.9             5.4
------------------------------------------------------------------------
\a\ Values have been rounded to two significant figures. Rows may not
  appear to sum correctly due to rounding.
\b\ The annualized present value of costs and benefits are calculated
  over the 20-year period from 2024 to 2042.
\c\ Climate benefits are based on changes (reductions) in CO2 emissions.
  Climate benefits in this table are based on estimates of the SC-CO2 at
  a 3 percent discount rate and are discounted using a 3 percent
  discount rate to obtain the PV and EAV estimates in the table. The EPA
  does not have a single central SC-CO2 point estimate. We emphasize the
  importance and value of considering the benefits calculated using all
  four SC-CO2 estimates (model average at 2.5 percent, 3 percent, and 5
  percent discount rates; 95th percentile at 3 percent discount rate).
  As discussed in section 4 of the RIA, consideration of climate
  benefits calculated using discount rates below 3 percent, including 2
  percent and lower, is also warranted when discounting
  intergenerational impacts.

[[Page 33417]]

 
\d\ The EPA notes that while OMB Circular A-4, as published in 2003,
  recommends using 3 percent and 7 percent discount rates as ``default''
  values, Circular A-4 also recognizes that ``special ethical
  considerations arise when comparing benefits and costs across
  generations,'' and Circular A-4 acknowledges that analyses may
  appropriately ``discount future costs and consumption benefits . . .
  at a lower rate than for intragenerational analysis.'' Therefore,
  climate benefits remain discounted at 3 percent in this benefits
  analysis.
\e\ The projected monetized health benefits include those related to
  public health associated with reductions in PM2.5 and ozone
  concentrations. The projected health benefits are associated with
  several point estimates and are presented at real discount rates of 3
  and 7 percent.
\f\ Several categories of benefits remain unmonetized and are thus not
  reflected in the table. Non-monetized benefits include important
  climate, health, welfare, and water quality benefits and are described
  in RIA Table 4-6.

    As shown in table 10, the proposed rules are projected to reduce 
greenhouse gas emissions in the form of CO2, producing a 
projected PV of monetized climate benefits of about $30 billion, with 
an EAV of about $2.1 billion using the SC-CO2 discounted at 
3 percent. The proposed rules are also projected to reduce 
PM2.5 and ozone concentrations, producing a projected PV of 
monetized health benefits of about $68 billion, with an EAV of about 
$4.8 billion discounted at 3 percent.
    The PV of the projected compliance costs are $14 billion, with an 
EAV of about $0.95 billion discounted at 3 percent. Combining the 
projected benefits with the projected compliance costs yields a net 
benefit PV estimate of about $85 billion and EAV of about $5.9 billion 
at a 3 percent discount rate.
    At a 7 percent discount rate, the proposed rules are expected to 
generate projected PV of monetized health benefits of about $44 
billion, with an EAV of about $4.3 billion. Climate benefits remain 
discounted at 3 percent in this net benefits analysis. Thus, the 
proposed rules would generate a PV of monetized benefits of about $74 
billion, with an EAV of about $6.4 billion discounted at a 7 percent 
rate. The PV of the projected compliance costs are about $10 billion, 
with an EAV of $0.98 billion discounted at 7 percent. Combining the 
projected benefits with the projected compliance costs yields a net 
benefit PV estimate of about $64 billion and an EAV of about $5.4 
billion discounted at 7 percent.
    The EPA has developed a separate analysis of the proposed standards 
for existing combustion turbines and third phase of the proposed 
standards for new natural gas-fired EGUs over the 2024 to 2042 period. 
This analysis includes estimated compliance costs and climate benefits, 
and is located in Section 8 of the RIA. The PV of the compliance costs, 
discounted at the 3-percent rate, is estimated to be between about $5.7 
to 10 billion, with an EAV of between about $0.40 to 0.70 billion. At 
the 7 percent discount rate, the PV of the compliance costs is 
estimated to be between about $ 3.5 to 6.2 billion, with an EAV of 
about $ 0.34 to 0.60 billion. The PV of the climate benefits, 
discounted at the 3-percent rate, is estimated to be between about $10 
to 20 billion, with an EAV of between about $0.70 to 1.4 billion.
    As discussed in section XIV of this preamble, the monetized 
benefits estimates provide an incomplete overview of the beneficial 
impacts of the proposals. In particular, the monetized climate benefits 
are incomplete and an underestimate as explained in section 4.2 of the 
RIA. In addition, important health, welfare, and water quality benefits 
anticipated under these proposed rules are not quantified or monetized. 
The EPA anticipates that taking non-monetized effects into account 
would show the proposals to have greater benefits than the estimates in 
the preamble and RIA reflect. Simultaneously, the estimates of 
compliance costs used in the net benefits analysis may provide an 
incomplete characterization of the true costs of the rule. The balance 
of unquantified benefits and costs is ambiguous but is unlikely to 
change the result that the benefits of the proposals exceed the costs 
by billions of dollars annually.
    We also note that the RIA follows the EPA's historic practice of 
using a technology-rich partial equilibrium model of the electricity 
and related fuel sectors to estimate the incremental costs of producing 
electricity under the requirements of proposed and final major EPA 
power sector rules. In Appendix B of the RIA for these actions, the EPA 
has also included an economy-wide analysis that considers additional 
facets of the economic response to the proposed rules, including the 
full resource requirements of the expected compliance pathways, some of 
which are paid for through subsidies in the partial equilibrium 
analysis. The social cost estimates in the economy-wide analysis and 
discussed in Appendix B of the RIA are still far below the projected 
benefits of the proposed rules.

B. Paperwork Reduction Act (PRA)

1. 40 CFR Part 60, Subpart TTTT
    This action does not impose any new information collection burden 
under the PRA. OMB has previously approved the information collection 
activities contained in the existing regulations and has assigned OMB 
control number 2060-0685.
2. 40 CFR Part 60, Subpart TTTTa
    The information collection activities in this proposed rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the PRA. The Information Collection Request (ICR) document 
that the EPA prepared has been assigned EPA ICR number 2771.01. You can 
find a copy of the ICR in the docket for this rule, and it is briefly 
summarized here.
    Respondents/affected entities: Owners and operators of fossil-fuel 
fired EGUs.
    Respondent's obligation to respond: Mandatory.
    Estimated number of respondents: 2.
    Frequency of response: Annual.
    Total estimated burden: 110 hours (per year). Burden is defined at 
5 CFR 1320.3(b).
    Total estimated cost: $14,000 (per year), includes $0 annualized 
capital or operation & maintenance costs.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    Submit your comments on the Agency's need for this information, the 
accuracy of the provided burden estimates and any suggested methods for 
minimizing respondent burden to the EPA using the docket identified at 
the beginning of this rule. The EPA will respond to any ICR-related 
comments in the final rule. You may also send your ICR-related comments 
to OMB's Office of Information and Regulatory Affairs using the 
interface at www.reginfo.gov/public/do/PRAMain. Find this particular 
information collection by selecting ``Currently under Review--Open for 
Public Comments'' or by using the search function. OMB must receive 
comments no later than July 24, 2023.
3. 40 CFR Part 60, Subpart UUUUb
    The information collection activities in this proposed rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the PRA. The Information Collection Request (ICR) document 
that the EPA prepared has been assigned EPA ICR number 2770.01. You can 
find a copy of the ICR in the docket for this rule, and it is briefly 
summarized here.

[[Page 33418]]

    This rule imposes specific requirements on State governments with 
existing fossil fuel-fired steam generating units. The information 
collection requirements are based on the recordkeeping and reporting 
burden associated with developing, implementing, and enforcing a plan 
to limit GHG emissions from existing EGUs. These recordkeeping and 
reporting requirements are specifically authorized by CAA section 114 
(42 U.S.C. 7414). All information submitted to the EPA pursuant to the 
recordkeeping and reporting requirements for which a claim of 
confidentiality is made is safeguarded according to Agency policies set 
forth in 40 CFR part 2, subpart B.
    The annual burden for this collection of information for the states 
(averaged over the first 3 years following promulgation) is estimated 
to be 104,000 hours at a total annual labor cost of $13.1 million. The 
annual burden for the Federal government associated with the State 
collection of information (averaged over the first 3 years following 
promulgation) is estimated to be 27,347 hours at a total annual labor 
cost of $1.8 million. Burden is defined at 5 CFR 1320.3(b).
    Respondents/affected entities: States with one or more designated 
facilities covered under subpart UUUUb.
    Respondent's obligation to respond: Mandatory.
    Estimated number of respondents: 50.
    Frequency of response: Once.
    Total estimated burden: 104,000 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total estimated cost: $13,163,689, includes $36,750 annualized 
capital or operation & maintenance costs.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    Submit your comments on the Agency's need for this information, the 
accuracy of the provided burden estimates and any suggested methods for 
minimizing respondent burden to the EPA using the docket identified at 
the beginning of this rule. The EPA will respond to any ICR-related 
comments in the final rule. You may also send your ICR-related comments 
to OMB's Office of Information and Regulatory Affairs using the 
interface at www.reginfo.gov/public/do/PRAMain. Find this particular 
information collection by selecting ``Currently under Review--Open for 
Public Comments'' or by using the search function. OMB must receive 
comments no later than July 24, 2023.
4. 40 CFR Part 60, Subpart UUUUa
    This proposed rule does not impose an information collection burden 
under the PRA.

C. Regulatory Flexibility Act (RFA)

    I certify that these actions will not have a significant economic 
impact on a substantial number of small entities under the RFA. The 
small entities subject to the requirements of the NSPS are private 
companies, investor-owned utilities, cooperatives, municipalities, and 
sub-divisions, that would seek to build and operate stationary 
combustion turbines in the future. The Agency has determined that seven 
small entities may be so impacted, and may experience an impact of 0 
percent to 0.9 percent of revenues in 2035. Details of this analysis 
are presented in section 5.3 of the RIA.
    The EPA started the Small Business Advocacy Review (SBAR) panel 
process prior to determining if the NSPS would have a significant 
economic impact on a substantial number of small entities under the 
RFA. The EPA conducted an initial outreach meeting with small entity 
representatives on December 14, 2022. The EPA sought input from 
representatives of small entities while developing the proposed NSPS 
which enabled the EPA to hear directly from these representatives about 
the regulation of GHG emissions from EGUs. The purpose of the meeting 
was to provide general background on the NSPS rulemaking, answer 
questions, and solicit input. Fifteen various small entities that 
potentially would be affected by the NSPS attended the meeting. The 
representatives included small entity municipalities, cooperatives, and 
industry professional organizations. When the EPA determined the NSPS 
would not have a significant economic impact on a substantial number of 
small entities under the RFA, the EPA did not proceed with convening 
the SBAR panel.
    Emission guidelines will not impose any requirements on small 
entities. Specifically, emission guidelines established under CAA 
section 111(d) do not impose any requirements on regulated entities 
and, thus, will not have a significant economic impact upon a 
substantial number of small entities. After emission guidelines are 
promulgated, states establish standards on existing sources, and it is 
those State requirements that could potentially impact small entities.
    The analysis in the accompanying RIA is consistent with the 
analysis of the analogous situation arising when the EPA establishes 
NAAQS, which do not impose any requirements on regulated entities. As 
here, any impact of a NAAQS on small entities would only arise when 
states take subsequent action to maintain and/or achieve the NAAQS 
through their State implementation plans. See American Trucking Assoc. 
v. EPA, 175 F.3d 1029, 1043-45 (D.C. Cir. 1999) (NAAQS do not have 
significant impacts upon small entities because NAAQS themselves impose 
no regulations upon small entities).
    The EPA is aware that there is substantial interest in the proposed 
rules among small entities and invites comments on all aspects of the 
proposals and their impacts, including potential impacts on small 
entities.

D. Unfunded Mandates Reform Act of 1995 (UMRA)

    The proposed NSPS contain a Federal mandate under UMRA, 2 U.S.C. 
1531-1538, that may result in expenditures of $100 million or more for 
the private sector in any one year. The proposed NSPS do not contain an 
unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 
1531-1538 for State, local, and Tribal governments, in the aggregate. 
Accordingly, the EPA prepared, under section 202 of UMRA, a written 
statement of the benefit-cost analysis, which is in section XIV of this 
preamble and in the RIA.
    The proposed repeal of the ACE Rule and emission guidelines do not 
contain an unfunded mandate of $100 million or more as described in 
UMRA, 2 U.S.C. 1531-1538, and do not significantly or uniquely affect 
small governments. The proposed emission guidelines do not impose any 
direct compliance requirements on regulated entities, apart from the 
requirement for states to develop plans to implement the guidelines 
under CAA section 111(d) for designated EGUs. The burden for states to 
develop CAA section 111(d) plans in the 24-month period following 
promulgation of the emission guidelines was estimated and is listed in 
section XV.B, but this burden is estimated to be below $100 million in 
any one year. As explained in section XII.F.6, the proposed emission 
guidelines do not impose specific requirements on Tribal governments 
that have designated EGUs located in their area of Indian country.
    The proposed actions are not subject to the requirements of section 
203 of UMRA because they contain no regulatory requirements that might 
significantly or uniquely affect small governments.
    In light of the interest in these rules among governmental 
entities, the EPA

[[Page 33419]]

initiated consultation with governmental entities. The EPA invited the 
following 10 national organizations representing State and local 
elected officials to a virtual meeting on September 22, 2022: (1) 
National Governors Association, (2) National Conference of State 
Legislatures, (3) Council of State Governments, (4) National League of 
Cities, (5) U.S. Conference of Mayors, (6) National Association of 
Counties, (7) International City/County Management Association, (8) 
National Association of Towns and Townships, (9) County Executives of 
America, and (10) Environmental Council of States. These 10 
organizations representing elected State and local officials have been 
identified by the EPA as the ``Big 10'' organizations appropriate to 
contact for purpose of consultation with elected officials. Also, the 
EPA invited air and utility professional groups who may have State and 
local government members, including the Association of Air Pollution 
Control Agencies, National Association of Clean Air Agencies, and 
American Public Power Association, Large Public Power Council, National 
Rural Electric Cooperative Association, and National Association of 
Regulatory Utility Commissioners to participate in the meeting. The 
purpose of the consultation was to provide general background on these 
rulemakings, answer questions, and solicit input from State and local 
governments. Subsequent to the September 22, 2022, meeting, the EPA 
received letters from five organizations. These letters were submitted 
to the pre-proposal non-rulemaking docket. See Docket ID No. EPA-HQ-
OAR-2022-0723-0013, EPA-HQ-OAR-2022-0723-0016, EPA-HQ-OAR-2022-0723-
0017, EPA-HQ-OAR-2022-0723-0020, and EPA-HQ-OAR-2022-0723-0021. For 
summary of the UMRA consultation see the memorandum in the docket 
titled, Federalism Pre-Proposal Consultation Summary.

E. Executive Order 13132: Federalism

    The proposed NSPS and the proposed repeal of the ACE Rule do not 
have federalism implications. These actions will not have substantial 
direct effects on the states, on the relationship between the national 
government and the states, or on the distribution of power and 
responsibilities among the various levels of government.
    The EPA has concluded that the proposed emission guidelines may 
have federalism implications, because they may impose substantial 
direct compliance costs on State or local governments, and the Federal 
Government will not provide the funds necessary to pay these costs.
    Any potential federalism implications arise from the provisions of 
CAA section 111(d)(1), which direct the EPA to ``prescribe regulations 
. . . under which each State shall submit to the [EPA] a [state] plan . 
. .'' establishing standards of performance for sources in the State. 
As discussed in the Supporting Statement found in the docket for this 
rulemaking, the development of State plans will entail many hours of 
staff time to develop and coordinate programs for compliance with the 
proposed emission guidelines, as well as time to work with State 
legislatures as appropriate, and develop a plan submittal.
    Although the direct compliance costs may not be substantial, the 
EPA nonetheless elected to consult with representatives of State and 
local governments in the process of developing these actions to permit 
them to have meaningful and timely input into their development. The 
EPA's consultation regarded planned actions for the NSPS and emission 
guidelines. The EPA invited the following 10 national organizations 
representing State and local elected officials to a virtual meeting on 
September 22, 2022: (1) National Governors Association, (2) National 
Conference of State Legislatures, (3) Council of State Governments, (4) 
National League of Cities, (5) U.S. Conference of Mayors, (6) National 
Association of Counties, (7) International City/County Management 
Association, (8) National Association of Towns and Townships, (9) 
County Executives of America, and (10) Environmental Council of States. 
These 10 organizations representing elected State and local officials 
have been identified by the EPA as the ``Big 10'' organizations 
appropriate to contact for purpose of consultation with elected 
officials. Also, the EPA invited air and utility professional groups 
who may have State and local government members, including the 
Association of Air Pollution Control Agencies, National Association of 
Clean Air Agencies, and American Public Power Association, Large Public 
Power Council, National Rural Electric Cooperative Association, and 
National Association of Regulatory Utility Commissioners to participate 
in the meeting. The purpose of the consultation was to provide general 
background on these rulemakings, answer questions, and solicit input 
from State and local governments. Subsequent to the September 22, 2022, 
meeting, the EPA received letters from five organizations. These 
letters were submitted to the pre-proposal non-rulemaking docket. See 
Docket ID No. EPA-HQ-OAR-2022-0723-0013, EPA-HQ-OAR-2022-0723-0016, 
EPA-HQ-OAR-2022-0723-0017, EPA-HQ-OAR-2022-0723-0020, and EPA-HQ-OAR-
2022-0723-0021. For a summary of the Federalism consultation see the 
memorandum in the docket titled Federalism Pre-Proposal Consultation 
Summary. A detailed Federalism Summary Impact Statement (FSIS) 
describing the most pressing issues raised in pre-proposal and post-
proposal comments will be forthcoming with the final emission 
guidelines, as required by section 6(b) of Executive Order 13132. In 
the spirit of E.O. 13132, and consistent with EPA policy to promote 
communications between State and local governments, the EPA 
specifically solicits comment on these proposed actions from State and 
local officials.

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

    These actions do not have Tribal implications, as specified in 
Executive Order 13175. The proposed NSPS would impose requirements on 
owners and operators of new or reconstructed stationary combustion 
turbines and emission guidelines would not impose direct requirements 
on Tribal governments. Tribes are not required to develop plans to 
implement the emission guidelines developed under CAA section 111(d) 
for designated EGUs. The EPA is aware of six fossil fuel-fired steam 
generating units located in Indian country but is not aware of any 
fossil fuel-fired steam generating units owned or operated by Tribal 
entities. The EPA notes that the proposed emission guidelines do not 
directly impose specific requirements on EGU sources, including those 
located in Indian country, but before developing any standards for 
sources on Tribal land, the EPA would consult with leaders from 
affected Tribes. Thus, Executive Order 13175 does not apply to these 
actions.
    Because the EPA is aware of Tribal interest in these proposed rules 
and consistent with the EPA Policy on Consultation and Coordination 
with Indian Tribes, the EPA offered government-to-government 
consultation with Tribes and conducted stakeholder engagement.
    The EPA will hold additional meetings with Tribal environmental 
staff to inform them of the content of these proposed rules as well as 
offer government-to-government consultation with Tribes. The EPA 
specifically

[[Page 33420]]

solicits additional comment on these proposed rules from Tribal 
officials.

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

    Executive Order 13045 (62 FR 19885, April 23, 1997) directs Federal 
agencies to include an evaluation of the health and safety effects of 
the planned regulation on children in Federal health and safety 
standards and explain why the regulation is preferable to potentially 
effective and reasonably feasible alternatives. This action is not 
subject to Executive Order 13045 because the EPA does not believe the 
environmental health risks or safety risks addressed by this action 
present a disproportionate risk to children. The EPA evaluated the 
health benefits of the CO2, ozone and PM2.5 
emissions reductions and the results of this evaluation are contained 
in the RIA and are available in the docket. The EPA believes that the 
PM2.5-related, ozone-related, and CO2-related 
benefits projected under these proposed rules will improve children's 
health. Additionally, the PM2.5 and ozone EJ exposure 
analyses in section 6 of the RIA suggests that nationally, children 
(ages 0-17) will experience at least as great a reduction in 
PM2.5 and ozone exposures as adults (ages 18-64) in 2028, 
2030, 2035 and 2040 under all regulatory alternatives of these 
rulemakings.

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

    These actions, which are significant regulatory actions under 
Executive Order 12866, are likely to have a significant adverse effect 
on the supply, distribution or use of energy. The EPA has prepared a 
Statement of Energy Effects for these action as follows. This analysis 
pertains to the proposed standards for new combustion turbines and for 
existing steam generating EGUs, and does not include the impact of the 
proposed standards for existing combustion turbines and the third phase 
of the proposed standards for new combustion turbines. The EPA 
estimates a 0.2 percent increase in retail electricity prices on 
average, across the contiguous U.S. in 2035, and a 28 percent reduction 
in coal-fired electricity generation in 2035 as a result of these 
actions. The EPA projects that utility power sector delivered natural 
gas prices will decrease 2.4 percent in 2035. For more information on 
the estimated energy effects, please refer sections 5.1 and 8.3.3 of 
the RIA, which is in the public docket.

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

    These proposed actions involve technical standards. Therefore, the 
EPA conducted searches for the 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 
through the Enhanced National Standards Systems Network (NSSN) Database 
managed by the American National Standards Institute (ANSI). Searches 
were conducted for EPA Method 19 of 40 CFR part 60, appendix A. No 
applicable voluntary consensus standards were identified for EPA Method 
19. For additional information, please see the March 23, 2023, 
memorandum titled, Voluntary Consensus Standard Results for 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.
    The EPA welcomes comments on this aspect of the proposed 
rulemakings and, specifically, invites the public to identify 
potentially applicable VCS and to explain why such standards should be 
used in these regulations.

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

    Executive Order 12898 (59 FR 7629; February 16, 1994) directs 
Federal agencies, to the greatest extent practicable and permitted by 
law, to make environmental justice part of their mission by identifying 
and addressing, as appropriate, disproportionately high and adverse 
human health or environmental effects of their programs, policies, and 
activities on minority populations (people of color and/or Indigenous 
peoples) and low-income populations.
    For new sources constructed after the date of publication of this 
proposed action under CAA section 111(b), the EPA believes that it is 
not practicable to assess whether the human health or environmental 
conditions that exist prior to this action result in disproportionate 
and adverse effects on people of color, low-income populations and/or 
Indigenous peoples, because the location and number of new sources is 
unknown.
    For existing sources of this proposed action under CAA section 
111(d), the EPA believes that the human health or environmental 
conditions that exist prior to this action result in or have the 
potential to result in disproportionate and adverse human health or 
environmental effects on people of color, low-income populations, and/
or Indigenous peoples. The EPA believes that this proposed action is 
not likely to change disproportionate and adverse PM2.5 
exposure impacts on people of color, low-income populations, Indigenous 
peoples, and/or other potential populations of concern evaluated in the 
future analytical years. The EPA also believes that this proposed 
action is not likely to change disproportionate and adverse ozone 
exposure impacts on people of color, low-income populations, Indigenous 
peoples, and/or other potential populations of concern evaluated in 
2028, 2035, and 2040. However, in the analytical year of 2030, this 
action is likely to slightly increase existing national level 
disproportionate and adverse ozone exposure impacts on Asian 
populations, Hispanic populations, and those linguistically isolated.
    The EPA believes that it is not practicable to assess whether the 
GHG impacts associated with this action are likely to result in a 
change in disproportionate and adverse effects on people of color, low-
income populations and/or Indigenous peoples. However, the EPA believes 
that the projected total cumulative power sector reduction of 617 
million metric tons of CO2 emissions between 2028 and 2042 
will have a beneficial effect on populations at risk of climate change 
effects/impacts. Research indicates that some communities of color, 
specifically populations defined jointly by ethnic/racial 
characteristics and geographic location, may be uniquely vulnerable to 
climate change health impacts in the U.S. See sections VII, X, and XIV 
of this preamble for further information regarding GHG controls and 
emission reductions.

Michael S. Regan,
Administrator.
[FR Doc. 2023-10141 Filed 5-22-23; 8:45 am]
 BILLING CODE 6560-50-P