Rule2024-09233
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
Primary source
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Published
May 9, 2024
Effective
July 8, 2024
Issuing agencies
Environmental Protection Agency
Abstract
The Environmental Protection Agency (EPA) is finalizing multiple actions under section 111 of the Clean Air Act (CAA) addressing greenhouse gas (GHG) emissions from fossil fuel-fired electric generating units (EGUs). First, the EPA is finalizing the repeal of the Affordable Clean Energy (ACE) Rule. Second, the EPA is finalizing 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. Third, the EPA is finalizing revisions to the New Source Performance Standards (NSPS) for GHG emissions from new and reconstructed fossil fuel-fired stationary combustion turbine EGUs. Fourth, the EPA is finalizing revisions to the NSPS 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. The EPA is not finalizing emission guidelines for GHG emissions from existing fossil fuel-fired stationary combustion turbines at this time; instead, the EPA intends to take further action on the proposed emission guidelines at a later date.
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[Federal Register Volume 89, Number 91 (Thursday, May 9, 2024)]
[Rules and Regulations]
[Pages 39798-40064]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2024-09233]
[[Page 39797]]
Vol. 89
Thursday,
No. 91
May 9, 2024
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; Final Rule
Federal Register / Vol. 89 , No. 91 / Thursday, May 9, 2024 / Rules
and Regulations
[[Page 39798]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2023-0072; FRL-8536-01-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: Final rule.
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SUMMARY: The Environmental Protection Agency (EPA) is finalizing
multiple actions under section 111 of the Clean Air Act (CAA)
addressing greenhouse gas (GHG) emissions from fossil fuel-fired
electric generating units (EGUs). First, the EPA is finalizing the
repeal of the Affordable Clean Energy (ACE) Rule. Second, the EPA is
finalizing 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. Third, the EPA is finalizing
revisions to the New Source Performance Standards (NSPS) for GHG
emissions from new and reconstructed fossil fuel-fired stationary
combustion turbine EGUs. Fourth, the EPA is finalizing revisions to the
NSPS 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. The EPA is not finalizing emission guidelines for
GHG emissions from existing fossil fuel-fired stationary combustion
turbines at this time; instead, the EPA intends to take further action
on the proposed emission guidelines at a later date.
DATES: This final rule is effective on July 8, 2024. The incorporation
by reference of certain publications listed in the rules is approved by
the Director of the Federal Register as of July 8, 2024. The
incorporation by reference of certain other materials listed in the
rule was approved by the Director of the Federal Register as of October
23, 2015.
ADDRESSES: The EPA has established a docket for these actions under
Docket ID No. EPA-HQ-OAR-2023-0072. All documents in the docket are
listed on the <a href="https://www.regulations.gov">https://www.regulations.gov</a> website. Although listed,
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 form. Publicly available docket materials are available
electronically through <a href="https://www.regulations.gov">https://www.regulations.gov</a>.
FOR FURTHER INFORMATION CONTACT: Lisa Thompson (she/her), Sector
Policies and Programs Division (D243-02), Office of Air Quality
Planning and Standards, U.S. Environmental Protection Agency, 109 T.W.
Alexander Drive, P.O. Box 12055, Research Triangle Park, North Carolina
27711; telephone number: (919) 541-5158; and email address:
<a href="/cdn-cgi/l/email-protection#f4809c9b9984879b9ada989d8795b4918495da939b82"><span class="__cf_email__" data-cfemail="64100c0b0914170b0a4a080d1705240114054a030b12">[email protected]</span></a>.
SUPPLEMENTARY INFORMATION:
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
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
CO<INF>2</INF> carbon dioxide
DER distributed energy resources
DOE Department of Energy
EEA energy emergency alert
EGU electric generating unit
EIA Energy Information Administration
EJ environmental justice
E.O. Executive Order
EPA Environmental Protection Agency
FEED front-end engineering and design
FGD flue gas desulfurization
FR Federal Register
GHG greenhouse gas
GW gigawatt
GWh gigawatt-hour
HAP hazardous air pollutant
HRSG heat recovery steam generator
IIJA Infrastructure Investment and Jobs Act
IRC Internal Revenue Code
kg kilogram
kWh kilowatt-hour
LCOE levelized cost of electricity
LNG liquefied natural gas
MATS Mercury and Air Toxics Standards
MMBtu/h million British thermal units per hour
MMT CO<INF>2</INF>e million metric tons of carbon dioxide equivalent
MW megawatt
MWh megawatt-hour
NAAQS National Ambient Air Quality Standards
NESHAP National Emission Standards for Hazardous Air Pollutants
NGCC natural gas combined cycle
NO<INF>X</INF> nitrogen oxides
NSPS new source performance standards
NSR New Source Review
PM particulate matter
PM<INF>2.5</INF> fine particulate matter
RIA regulatory impact analysis
TSD technical support document
U.S. United States
Organization of this document. The information in this preamble is
organized as follows:
I. Executive Summary
A. Climate Change and Fossil Fuel-Fired EGUs
B. Recent Developments in Emissions Controls and the Electric
Power Sector
C. Summary of the Principal Provisions of These Regulatory
Actions
D. Grid Reliability Considerations
E. Environmental Justice Considerations
F. Energy Workers and Communities
G. Key Changes From Proposal
II. General Information
A. Action Applicability
B. Where To Get a Copy of This Document and Other Related
Information
III. Climate Change Impacts
IV. Recent Developments in Emissions Controls and the Electric Power
Sector
A. Background
B. GHG Emissions From Fossil Fuel-Fired EGUs
C. Recent Developments in Emissions Control
D. The Electric Power Sector: Trends and Current Structure
E. The Legislative, Market, and State Law Context
F. Future 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
[[Page 39799]]
VI. 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. Withdrawal of Proposed NSR Revisions
VII. Regulatory Approach for Existing Fossil Fuel-Fired Steam
Generating Units
A. Overview
B. Applicability Requirements and Fossil Fuel-Type Definitions
for Subcategories of Steam Generating Units
C. Rationale for the BSER for Coal-Fired Steam Generating Units
D. Rationale for the BSER for Natural Gas-Fired and Oil-Fired
Steam Generating Units
E. Additional Comments Received on the Emission Guidelines for
Existing Steam Generating Units and Responses
F. Regulatory Requirement To Review Emission Guidelines for
Coal-Fired Units
VIII. Requirements for New and Reconstructed Stationary Combustion
Turbine EGUs and Rationale for 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. Standards of Performance
H. Reconstructed Stationary Combustion Turbines
I. Modified Stationary Combustion Turbines
J. Startup, Shutdown, and Malfunction
K. Testing and Monitoring Requirements
L. Recordkeeping and Reporting Requirements
M. Compliance Dates
N. Compliance Date Extension
IX. Requirements for New, Modified, and Reconstructed Fossil Fuel-
Fired Steam Generating Units
A. 2018 NSPS Proposal Withdrawal
B. Additional Amendments
C. Eight-Year Review of NSPS for Fossil Fuel-Fired Steam
Generating Units
D. Projects Under Development
X. State Plans for Emission Guidelines for Existing Fossil Fuel-
Fired EGUs
A. Overview
B. Requirement for State Plans To Maintain Stringency of the
EPA's BSER Determination
C. Establishing Standards of Performance
D. Compliance Flexibilities
E. State Plan Components and Submission
XI. Implications for Other CAA Programs
A. New Source Review Program
B. Title V Program
XII. Summary of Cost, Environmental, and Economic Impacts
A. Air Quality Impacts
B. Compliance Cost Impacts
C. Economic and Energy Impacts
D. Benefits
E. Net Benefits
F. Environmental Justice Analytical Considerations and
Stakeholder Outreach and Engagement
G. Grid Reliability Considerations and Reliability-Related
Mechanisms
XIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 14094: Modernizing 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 and Executive Order 14096: Revitalizing Our Nation's
Commitment to Environmental Justice for All
K. Congressional Review Act (CRA)
XIV. Statutory Authority
I. 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.\2\
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 2021.\3\ At the same time, a range of cost-effective
technologies and approaches to reduce GHG emissions from these sources
is available to the power sector--including carbon capture and
sequestration/storage (CCS), co-firing with less GHG-intensive fuels,
and more efficient generation. Congress has also acted to provide
funding and other incentives to encourage the deployment of various
technologies, including CCS, to achieve reductions in GHG emissions
from the power sector.
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\1\ 74 FR 66496 (December 15, 2009).
\2\ The 5th National Climate Assessment (NCA5) states that the
effects of human-caused climate change are already far-reaching and
worsening across every region of the United States and that climate
change affects all aspects of the energy system-supply, delivery,
and demand-through the increased frequency, intensity, and duration
of extreme events and through changing climate trends.
\3\ <a href="https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions">https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions</a>.
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In this notice, the EPA is finalizing several actions under section
111 of the Clean Air Act (CAA) to reduce the significant quantity of
GHG emissions from fossil fuel-fired EGUs by establishing emission
guidelines and new source performance standards (NSPS) that are based
on available and cost-effective technologies that directly reduce GHG
emissions from these sources. Consistent with the statutory command of
CAA section 111, the final 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 first finalizing the repeal of the
Affordable Clean Energy (ACE) Rule. Second, the EPA is finalizing
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. Third, the EPA is finalizing revisions to the
NSPS for GHG emissions from new and reconstructed fossil fuel-fired
stationary combustion turbine EGUs. Fourth, the EPA is finalizing
revisions to the NSPS 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. The EPA is not finalizing emission
guidelines for GHG emissions from existing fossil fuel-fired combustion
turbines at this time and plans to expeditiously issue an additional
proposal that more comprehensively addresses GHG emissions from this
portion of the fleet. The EPA acknowledges that the share of GHG
emissions from existing fossil fuel-fired combustion turbines has been
growing and is projected to continue to do so, particularly as
emissions from other portions of the fleet decline, and that it is
vital to regulate the GHG emissions from these sources consistent with
CAA section 111.
These final actions ensure that the new and existing fossil fuel-
fired EGUs that are subject to these rules 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 standards and emission guidelines will
significantly decrease GHG emissions from fossil fuel-fired EGUs and
the associated harms to human health and
[[Page 39800]]
welfare. Further, the EPA has designed these 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 Fossil Fuel-Fired EGUs
These final actions reduce the emissions of GHGs from new and
existing fossil fuel-fired EGUs. 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 threaten human
health and welfare.
Fossil fuel-fired EGUs that are uncontrolled for GHGs are one of
the biggest domestic sources of GHG emissions. At the same time, there
are technologies available (including technologies that can be applied
to fossil fuel-fired power plants) to significantly reduce emissions of
GHGs from the power sector. Low- and zero-GHG electricity are also key
enabling technologies to significantly reduce GHG emissions in almost
every other sector of the economy.
In 2021, the power sector was the largest stationary source of GHGs
in the United States, emitting 25 percent of overall domestic
emissions.\4\ In 2021, existing fossil fuel-fired steam generating
units accounted for 65 percent of the GHG emissions from the sector,
but only accounted for 23 percent of the total electricity generation.
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\4\ <a href="https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions">https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions</a>.
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Because of its outsized contributions to overall emissions,
reducing emissions from the power sector is essential to addressing the
challenge of climate change--and sources in the power sector also have
many available options for reducing their climate-destabilizing
emissions. Particularly relevant to these actions are several key
technologies (CCS and co-firing of lower-GHG fuels) that allow fossil
fuel-fired steam generating EGUs and stationary combustion turbines 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, reducing GHG emissions from
these affected sources can also help reduce power sector pollution that
might otherwise result from the electrification of other sectors of the
economy.
B. Recent Developments in Emissions Controls and the Electric Power
Sector
Several recent developments concerning emissions controls are
relevant for the EPA's determination of the BSER for existing coal-
fired steam generating EGUs and new natural gas-fired stationary
combustion turbines. These include lower costs and continued
improvements in CCS technology, alongside Federal tax incentives that
allow companies to largely offset the cost of CCS. Well-established
trends in the sector further inform where using such technologies is
cost effective and feasible, and form part of the basis for the EPA's
determination of the BSER.
In recent years, the cost of CCS has declined in part because of
process improvements learned from earlier deployments and other
advances in the technology. In addition, the Inflation Reduction Act
(IRA), enacted in 2022, extended and significantly increased the tax
credit for carbon dioxide (CO<INF>2</INF>) sequestration under Internal
Revenue Code (IRC) section 45Q. The provision of tax credits in the
IRA, combined with the funding included in the Infrastructure
Investment and Jobs Act (IIJA), enacted in 2021, incentivize and
facilitate the deployment of CCS and other GHG emission control
technologies. As explained later in this preamble, these developments
support the EPA's conclusion that CCS is the BSER for certain
subcategories of new and existing EGUs because it is an adequately
demonstrated and available control technology that significantly
reduces emissions of dangerous pollution and because the costs of its
installation and operation are reasonable. Some companies have already
made plans to install CCS on their units independent of the EPA's
regulations.
Well documented trends in the power sector also influence the EPA's
determination of the BSER. In particular, CCS entails significant
capital expenditures and is only cost-reasonable for units that will
operate enough to defray those capital costs. At the same time, many
utilities and power generating companies have recently announced plans
to accelerate changing the mix of their generating assets. The IIJA and
IRA, state legislation, technology advancements, market forces,
consumer demand, and the advanced age of much of the existing fossil
fuel-fired generating fleet are collectively leading to, in most cases,
decreased use of the fossil fuel-fired units that are the subjects of
these final actions. From 2010 through 2022, fossil fuel-fired
generation declined from approximately 72 percent of total net
generation to approximately 60 percent, with generation from coal-fired
sources dropping from 49 percent to 20 percent of net generation during
this period.\5\ These trends are expected to continue and are relevant
to determining where capital-intensive technologies, like CCS, may be
feasibly and cost-reasonably deployed to reduce emissions.
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\5\ U.S. Energy Information Administration (EIA). Electric Power
Annual. 2010 and 2022. <a href="https://www.eia.gov/electricity/annual/html/epa_03_01_a.html">https://www.eia.gov/electricity/annual/html/epa_03_01_a.html</a>.
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Congress has taken other recent actions to drive the reduction of
GHG emissions from the power sector. As noted earlier, Congress enacted
IRC section 45Q in section 115 of the Energy Improvement and Extension
Act of 2008 to provide a tax credit for the sequestration of
CO<INF>2</INF>. Congress significantly amended IRC section 45Q in the
Bipartisan Budget Act of 2018, and more recently in the IRA, to make
this tax incentive more generous and effective in spurring long-term
deployment of CCS. In addition, the IIJA provided more than $65 billion
for infrastructure investments and upgrades for transmission capacity,
pipelines, and low-carbon fuels.\6\ Further, 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 could provide additional low-cost
options for power companies to reduce overall GHG emissions.\7\ As
discussed in greater detail in section IV.E.1 of this preamble, the
IRA, the IIJA, and CHIPS contain numerous other provisions encouraging
companies to reduce their GHGs.
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\6\ <a href="https://www.congress.gov/bill/117th-congress/house-bill/3684">https://www.congress.gov/bill/117th-congress/house-bill/3684</a>.
\7\ <a href="https://www.congress.gov/bill/117th-congress/house-bill/4346">https://www.congress.gov/bill/117th-congress/house-bill/4346</a>.
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C. Summary of the Principal Provisions of These Regulatory Actions
These final actions include the repeal of the ACE Rule, BSER
determinations and emission guidelines for existing fossil fuel-fired
steam generating units, and BSER determinations and accompanying
standards of performance for GHG emissions from new and reconstructed
fossil fuel-fired stationary combustion turbines and modified fossil
fuel-fired steam generating units.
[[Page 39801]]
The EPA is taking these actions consistent with its authority under
CAA section 111. Under CAA section 111, once the EPA has identified a
source category that contributes significantly to dangerous air
pollution, 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.\8\ The EPA may determine that different sets of
sources have different characteristics relevant for determining the
BSER and may subcategorize sources accordingly.
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\8\ CAA section 111(a)(1).
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Once it identifies the BSER, the EPA must determine the ``degree of
emission limitation'' achievable by application of the BSER. For new
sources, the EPA establishes 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 in 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
CAA section 111 for more than 60 source categories, which has
established a robust set of regulatory precedents that has informed the
development of these final actions. 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 CAA
section 111. As the Supreme Court has recognized, the EPA has typically
(and does so in these actions) determined the BSER to be ``measures
that improve the pollution performance of individual sources,'' such as
add-on controls and clean fuels. West Virginia v. EPA, 597 U.S. 697,
734 (2022). For present purposes, several of a BSER's key features
include that it must reduce emissions, be based on ``adequately
demonstrated'' technology, and have a reasonable cost of control. The
case law interpreting section 111 has also recognized that the BSER can
be forward-looking in nature and take into account anticipated
improvements in control technologies. For example, 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. Further,
the most relevant costs under CAA section 111 are the costs to the
regulated facility. The actions that the EPA is finalizing are
consistent with the requirements of CAA section 111 and its regulatory
history and caselaw, which is discussed in further detail in section V
of this preamble.
1. Repeal of ACE Rule
The EPA is finalizing its proposed repeal of the existing ACE Rule
emission guidelines. First, as a policy matter, the EPA concludes that
the suite of heat rate improvements (HRI) that was identified in the
ACE Rule as the BSER is not an appropriate BSER for existing coal-fired
EGUs. Second, the ACE Rule rejected CCS and natural gas co-firing as
the BSER for reasons that no longer apply. Third, the EPA concludes
that the ACE Rule conflicted with CAA section 111 and the EPA's
implementing regulations because it did not provide sufficient
specificity as to the BSER the EPA had identified or the ``degree of
emission limitation achievable though application of the [BSER].''
Also, the EPA is withdrawing the proposed revisions to the New
Source Review (NSR) regulations that were included the ACE Rule
proposal (83 FR 44773-83; August 31, 2018).
2. Emission Guidelines for Existing Fossil Fuel-Fired Steam Generating
Units
The EPA is finalizing CCS with 90 percent capture as BSER for
existing coal-fired steam generating units. These units have a
presumptive standard \9\ of an 88.4 percent reduction in annual
emission rate, with a compliance deadline of January 1, 2032. As
explained in detail below, CCS is an adequately demonstrated technology
that achieves significant emissions reduction and is cost-reasonable,
taking into account the declining costs of the technology and a
substantial tax credit available to sources. In recognition of the
significant capital expenditures involved in deploying CCS technology
and the fact that 45 percent of regulated units already have announced
retirement dates, the EPA is finalizing a separate subcategory for
existing coal-fired steam generating units that demonstrate that they
plan to permanently cease operation before January 1, 2039. The BSER
for this subcategory is co-firing with natural gas, at a level of 40
percent of the unit's annual heat input. These units have a presumptive
standard of 16 percent reduction in annual emission rate corresponding
to this BSER, with a compliance deadline of January 1, 2030.
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\9\ Presumptive standards of performance are discussed in detail
in section X 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.
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The EPA is finalizing an applicability exemption for existing coal-
fired steam EGUs demonstrating that they plan to permanently cease
operation prior to January 1, 2032, based on the Agency's determination
that units retiring before this date generally do not have cost-
reasonable options for improving their GHG emissions performance.
Sources that demonstrate they will permanently cease operation before
this applicability deadline will not be subject to these emission
guidelines. Further, the EPA is not finalizing the proposed imminent-
term or near-term subcategories.
The EPA is finalizing the proposed structure of the subcategory
definitions for natural gas- and oil-fired steam generating units. The
EPA is also finalizing routine methods of operation and maintenance as
the BSER for intermediate load and base load natural gas- and oil-fired
steam generating units. Furthermore, the EPA is finalizing presumptive
standards for natural gas- and oil-fired steam generating units that
are slightly higher than at proposal: base load sources (those with
annual capacity factors greater than 45 percent) have a presumptive
standard of 1,400 lb CO<INF>2</INF>/MWh-gross, and intermediate load
sources (those with annual capacity factors greater than 8 percent and
less than or equal to 45 percent) have a presumptive standard of 1,600
lb CO<INF>2</INF>/MWh-gross. For low load (those with annual capacity
factors less than 8 percent), the EPA is finalizing a uniform fuels
BSER and a presumptive input-based standard of 170 lb CO<INF>2</INF>/
MMBtu for oil-fired sources and a presumptive standard of 130 lb
CO<INF>2</INF>/MMBtu for natural gas-fired sources.
3. Standards of Performance for New and Reconstructed Fossil Fuel-Fired
Combustion Turbines
The EPA is finalizing emission standards for three subcategories of
combustion turbines--base load, intermediate load, and low load. The
BSER for base load combustion turbines includes two components to be
implemented initially in two phases. The first component of the BSER
for base load combustion turbines is highly efficient generation (based
on the emission rates that the best performing
[[Page 39802]]
units are achieving) and the second component for base load combustion
turbines is utilization of CCS with 90 percent capture. Recognizing the
lead time that is necessary for new base load combustion turbines to
plan for and install the second component of the BSER (i.e., 90 percent
CCS), including the time that is needed to deploy the associated
infrastructure (CO<INF>2</INF> pipelines, storage sites, etc.), the EPA
is finalizing a second phase compliance deadline of January 1, 2032,
for this second component of the standard.
The EPA has identified highly efficient simple cycle generation as
the BSER for intermediate load combustion turbines. For low load
combustion turbines, the EPA is finalizing its proposed determination
that the BSER is the use of lower-emitting fuels.
4. New, Modified, and Reconstructed Fossil Fuel-Fired Steam Generating
Units
The EPA is finalizing revisions of the standards of performance for
coal-fired steam generating units that undertake a large modification
(i.e., a modification that increases its hourly emission rate by more
than 10 percent) to mirror the emission guidelines for existing coal-
fired steam generators. This reflects the EPA's determination that such
modified sources are capable of meeting the same presumptive standards
that the EPA is finalizing for existing steam EGUs. Further, this
revised standard for modified coal-fired steam EGUs will avoid creating
an unjustified disparity between emission control obligations for
modified and existing coal-fired steam EGUs.
The EPA did not propose, and we are not finalizing, any review or
revision of the 2015 standard for large modifications of oil- or gas-
fired steam generating units because we are not aware of any existing
oil- or gas-fired steam generating EGUs that have undertaken such
modifications or have plans to do so, and, unlike an existing coal-
fired steam generating EGUs, existing oil- or gas-fired steam units
have no incentive to undertake such a modification to avoid the
requirements we are including in this final rule for existing oil- or
gas-fired steam generating units.
As discussed in the proposal preamble, the EPA is not revising the
NSPS for newly constructed or reconstructed fossil fuel-fired steam
electric generating units (EGU) at this time because the EPA
anticipates that few, if any, such units will be constructed or
reconstructed in the foreseeable future. However, the EPA has recently
become aware that a new coal-fired power plant is under consideration
in Alaska. Accordingly, the EPA is not, at this time, finalizing its
proposal not to review the 2015 NSPS, and, instead, will continue to
consider whether to review the 2015 NSPS. As developments warrant, the
EPA will determine either to conduct a review, and propose revised
standards of performance, or not conduct a review.
Also, in this final action, the EPA is withdrawing the 2018
proposed amendments \10\ to the NSPS for GHG emissions from coal-fired
EGUs.
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\10\ See 83 FR 65424, December 20, 2018.
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5. Severability
This final action is composed of four independent rules: the repeal
of the ACE rule; GHG emission guidelines for existing fossil fuel-fired
steam generating units; NSPS for GHG emissions from new and
reconstructed fossil fuel-fired combustion turbines; and revisions to
the standards of performance for new, modified, and reconstructed
fossil fuel-fired steam generating units. The EPA could have finalized
each of these rules in separate Federal Register notices as separate
final actions. The Agency decided to include these four independent
rules in a single Federal Register notice for administrative ease
because they all relate to climate pollution from the fossil fuel-fired
electric generating units source category. Accordingly, despite
grouping these rules into one single Federal Register notice, the EPA
intends that each of these rules described in sections I.C.1 through
I.C.4 is severable from the other.
In addition, each rule is severable as a practical matter. For
example, the EPA would repeal the ACE Rule separate and apart from
finalizing new standards for these sources as explained herein.
Moreover, the BSER and associated emission guidelines for existing
fossil fuel-fired steam generating units are independent of and would
have been the same regardless of whether the EPA finalized the other
parts of this rule. In determining the BSER for existing fossil fuel-
fired steam generating units, the EPA considered only the technologies
available to reduce GHG emissions at those sources and did not take
into consideration the technologies or standards of performance for new
fossil fuel-fired combustion turbines. The same is true for the
Agency's evaluation and determination of the BSER and associated
standards of performance for new fossil fuel-fired combustion turbines.
The EPA identified the BSER and established the standards of
performance by examining the controls that were available for these
units. That analysis can stand alone and apart from the EPA's separate
analysis for existing fossil fuel-fired steam generating units. Though
the record evidence (including, for example, modeling results) often
addresses the availability, performance, and expected implementation of
the technologies at both existing fossil fuel-fired steam generating
units and new fossil fuel-fired combustion turbines in the same record
documents, the evidence for each evaluation stands on its own, and is
independently sufficient to support each of the final BSERs.
In addition, within section I.C.1, the final action to repeal the
ACE Rule is severable from the withdrawal of the NSR revisions that
were proposed in parallel with the ACE Rule proposal. Within the group
of actions for existing fossil fuel-fired steam generating units in
section I.C.2, the requirements for each subcategory of existing
sources are severable from the requirements for each other subcategory
of existing sources. For example, if a court were to invalidate the
BSER and associated emission standard for units in the medium-term
subcategory, the BSER and associated emission standard for units in the
long-term subcategory could function sensibly because the effectiveness
of the BSER for each subcategory is not dependent on the effectiveness
of the BSER for other subcategories. Within the group of actions for
new and reconstructed fossil fuel-fired combustion turbines in section
I.C.3, the following actions are severable: the requirements for each
subcategory of new and reconstructed turbines are severable from the
requirements for each other subcategory; and within the subcategory for
base load turbines, the requirements for each of the two components are
severable from the requirements for the other component. Each of these
standards can function sensibly without the others. For example, the
BSER for low load, intermediate load, and base load subcategories is
based on the technologies the EPA determined met the statutory
standards for those subcategories and are independent from each other.
And in the base load subcategory units may practically be constructed
using the most efficient technology without then installing CCS and
likewise may install CCS on a turbine system that was not constructed
with the most efficient technology. Within the group of actions for
new, modified, and reconstructed fossil fuel-fired steam generating
units in section I.C.4, the revisions of the standards of performance
for coal-fired steam
[[Page 39803]]
generators that undertake a large modification are severable from the
withdrawal of the 2018 proposal to revise the NSPS for emissions of GHG
from EGUs. Each of the actions in these final rules that the EPA has
identified as severable is functionally independent--i.e., may operate
in practice independently of the other actions.
In addition, while the EPA is finalizing this rule at the same time
as other final rules regulating different types of pollution from
EGUs--specifically the Supplemental Effluent Limitations Guidelines and
Standards for the Steam Electric Power Generating Point Source Category
(FR 2024-09815, EPA-HQ-OW-2009-0819; FRL-8794-02-OW); National Emission
Standards for Hazardous Air Pollutants: Coal and Oil-Fired Electric
Utility Steam Generating Units Review of the Residual Risk and
Technology Review (FR 2024-09148, EPA-HQ-OAR-2018-0794; FRL-6716.3-02-
OAR); Hazardous and Solid Waste Management System: Disposal of Coal
Combustion Residuals From Electric Utilities; Legacy CCR Surface
Impoundments (FR 2024-09157, EPA-HQ-OLEM-2020-0107; FRL-7814-04-OLEM)--
and has considered the interactions between and cumulative effects of
these rules, each rule is based on different statutory authority, a
different record, and is completely independent of the other rules.
D. Grid Reliability Considerations
The EPA is finalizing multiple adjustments to the proposed rules
that ensure the requirements in these final actions can be implemented
without compromising the ability of power companies, grid operators,
and state and Federal energy regulators to maintain resource adequacy
and grid reliability. In response to the May 2023 proposed rule, the
EPA received extensive comments from balancing authorities, independent
system operators and regional transmission organizations, state
regulators, power companies, and other stakeholders on the need for the
final rule to accommodate resource adequacy and grid reliability needs.
The EPA also engaged with the balancing authorities that submitted
comments to the docket, the staff and Commissioners of the Federal
Energy Regulatory Commission (FERC), the Department of Energy (DOE),
the North American Electric Reliability Corporation (NERC), and other
expert entities during the course of this rulemaking. Finally, at the
invitation of FERC, the EPA participated in FERC's Annual Reliability
Technical Conference on November 9, 2023.
These final actions respond to this input and feedback in multiple
ways, including through changes to the universe of affected sources,
longer compliance timeframes for CCS implementation, and other
compliance flexibilities, as well as articulation of the appropriate
use of RULOF to address reliability issues during state plan
development and in subsequent state plan revisions. In addition to
these adjustments, the EPA is finalizing several programmatic
mechanisms specifically designed to address reliability concerns raised
by commenters. For existing fossil fuel-fired EGUs, a short-term
reliability emergency mechanism is available for states to provide more
flexibility by using an alternative emission limitation during acute
operational emergencies when the grid might be temporarily under heavy
strain. A similar short-term reliability emergency mechanism is also
available to new sources. In addition, the EPA is creating an option
for states to provide for a compliance date extension for existing
sources of up to 1 year under certain circumstances for sources that
are installing control technologies to comply with their standards of
performance. Lastly, states may also provide, by inclusion in their
state plans, a reliability assurance mechanism of up to 1 year that
under limited circumstances would allow existing units that had planned
to cease operating by a certain date to temporarily remain available to
support reliability. Any extensions exceeding 1 year must be addressed
through a state plan revision. In order to utilize this reliability
pathway, there must be an adequate demonstration of need and
certification by a reliability authority, and approval by the
appropriate EPA Regional Administrator. The EPA plans to seek the
advice of FERC for extension requests exceeding 6 months. Similarly,
for new fossil fuel-fired combustion turbines, the EPA is creating a
mechanism whereby baseload units may request a 1-year extension of
their CCS compliance deadline under certain circumstances.
The EPA has evaluated the resource adequacy implications of these
actions in the final technical support document (TSD), Resource
Adequacy Analysis, and conducted capacity expansion modeling of the
final rules in a manner that takes into account resource adequacy
needs. The EPA finds that resource adequacy can be maintained with the
final rules. The EPA modeled a scenario that complies with the final
rules and that meets resource adequacy needs. The EPA also performed a
variety of other sensitivity analyses looking at higher electricity
demand (load growth) and impact of the EPA's additional regulatory
actions affecting the power sector. These sensitivity analyses indicate
that, in the context of higher demand and other pending power sector
rules, the industry has available pathways to comply with this rule
that respect NERC reliability considerations and constraints.
In addition, the EPA notes that significant planning and regulatory
mechanisms exist to ensure that sufficient generation resources are
available to maintain reliability. The EPA's consideration of
reliability in this rulemaking has also been informed by consultation
with the DOE under the auspices of the March 9, 2023, memorandum of
understanding (MOU) \11\ signed by the EPA Administrator and the
Secretary of Energy, as well as by consultation with FERC expert staff.
In these final actions, the EPA has included various flexibilities that
allow power companies and grid operators to plan for achieving feasible
and necessary reductions of GHGs from affected sources consistent with
the EPA's statutory charge while ensuring that the rule will not
interfere with systems operators' ability to ensure grid reliability.
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\11\ Joint Memorandum of Understanding on Interagency
Communication and Consultation on Electric Reliability (March 9,
2023). <a href="https://www.epa.gov/power-sector/electric-reliability-mou">https://www.epa.gov/power-sector/electric-reliability-mou</a>.
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A thorough description of how adjustments in the final rules
address reliability issues, the EPA's outreach to balancing
authorities, EPA's supplemental notice, as well as the introduction of
mechanisms to address short- and long-term reliability needs is
presented in section XII.F of this preamble.
E. Environmental Justice Considerations
Consistent with Executive Order (E.O.) 14096, and the EPA's
commitment to upholding environmental justice (EJ) across its policies
and programs, the EPA carefully considered the impacts of these actions
on communities with environmental justice concerns. As part of the
regulatory development process for these rulemakings, and consistent
with directives set forth in multiple Executive Orders, the EPA
conducted extensive outreach with interested parties including Tribal
nations and communities with environmental justice concerns. These
opportunities gave the EPA a chance to hear directly from the public,
including from communities potentially impacted by these final
[[Page 39804]]
actions. The EPA took this feedback into account in its development of
these final actions.\12\ The EPA's analysis of environmental justice in
these final actions is briefly summarized here and discussed in further
detail in sections XII.E and XIII.J of the preamble and section 6 of
the regulatory impact analysis (RIA).
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\12\ Specifically, the EPA has relied on, and is incorporating
as a basis for this rulemaking, analyses regarding possible adverse
environmental effects from CCS, including those highlighted by
commenters. Consideration of these effects is permissible under CAA
section 111(a)(1). Although the EPA also conducted analyses of
disproportionate impacts pursuant to E.O. 14096, see section XII.E,
the EPA did not consider or rely on these analyses as a basis for
these rules.
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Several environmental justice organizations and community
representatives raised significant concerns about the potential health,
environmental, and safety impacts of CCS. The EPA takes these concerns
seriously, agrees that any impacts to historically disadvantaged and
overburdened communities are important to consider, and has carefully
considered these concerns as it finalized its determinations of the
BSERs for these rules. The Agency acknowledges that while these final
actions will result in large reductions of both GHGs and other
emissions that will have significant positive benefits, there is the
potential for localized increases in emissions, particularly if units
installing CCS operate for more hours during the year and/or for more
years than they would have otherwise. However, as discussed in section
VII.C.1.a.iii(B), a robust regulatory framework exists to reduce the
risks of localized emissions increases in a manner that is protective
of public health, safety, and the environment. The Council on
Environmental Quality's (CEQ) February 2022 Carbon Capture,
Utilization, and Sequestration Guidance and the EPA's evaluation of
BSER recognize that multiple Federal agencies have responsibility for
regulating and permitting CCS projects, along with state and tribal
governments. As the CEQ has noted, Federal agencies have ``taken
actions in the past decade to develop a robust carbon capture,
utilization, and sequestration/storage (CCUS) regulatory framework to
protect the environment and public health across multiple statutes.''
\13\ \14\ Furthermore, the EPA plans to review and update as needed its
guidance on NSR permitting, specifically with respect to BACT
determinations for GHG emissions and consideration of co-pollutant
increases from sources installing CCS. For the reasons explained in
section VII.C, the EPA is finalizing the determination 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. At the same time, the EPA recognizes the
critical importance of ensuring that the regulatory framework performs
as intended to protect communities.
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\13\ 87 FR 8808, 8809 (February 16, 2022).
\14\ This framework includes, among other things, the EPA
regulation of geologic sequestration wells under the Underground
Injection Control (UIC) program of the Safe Drinking Water Act;
required reporting and public disclosure of geologic sequestration
activity, as well as implementation of rigorous monitoring,
reporting, and verification of geologic sequestration under the
EPA's Greenhouse Gas Reporting Program (GHGRP); and safety
regulations for CO<INF>2</INF> pipelines administered by the
Pipeline and Hazardous Materials and Safety Administration (PHMSA).
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These actions are focused on establishing NSPS and emission
guidelines for GHGs that states will implement to significantly reduce
GHGs and move us a step closer to avoiding the worst impacts of climate
change, which is already having a disproportionate impact on
communities with environmental justice concerns. The EPA analyzed
several illustrative scenarios representing potential compliance
outcomes and evaluated the potential impacts that these actions may
have on emissions of GHG and other health-harming air pollutants from
fossil fuel-fired EGUs, as well as how these changes in emissions might
affect air quality and public health, particularly for communities with
EJ concerns.
The EPA's national-level analysis of emission reduction and public
health impacts, which is documented in section 6 of the RIA and
summarized in greater detail in section XII.A and XII.D of this
preamble, finds that these actions achieve nationwide reductions in EGU
emissions of multiple health-harming air pollutants including nitrogen
oxides (NO<INF>X</INF>), sulfur dioxide (SO<INF>2</INF>), and fine
particulate matter (PM<INF>2.5</INF>), resulting in public health
benefits. The EPA also evaluated how the air quality impacts associated
with these final actions are distributed, with particular focus on
communities with EJ concerns. As discussed in the RIA, our analysis
indicates that baseline ozone and PM<INF>2.5</INF> concentration will
decline substantially relative to today's levels. Relative to these low
baseline levels, ozone and PM<INF>2.5</INF> concentrations will
decrease further in virtually all areas of the country, although some
areas of the country may experience slower or faster rates of decline
in ozone and PM<INF>2.5</INF> pollution over time due to the changes in
generation and utilization resulting from these rules. Additionally,
our comparison of future air quality conditions with and without these
rules suggests that while these actions are anticipated to lead to
modest but widespread reductions in ambient levels of PM<INF>2.5</INF>
and ozone for a large majority of the nation's population, there is
potential for some geographic areas and demographic groups to
experience small increases in ozone concentrations relative to the
baseline levels which are projected to be substantially lower than
today's levels.
It is important to recognize that while these projections of
emissions changes and resulting air quality changes under various
illustrative compliance scenarios are based upon the best information
available to the EPA at this time, with regard to existing sources,
each state will ultimately be responsible for determining the future
operation of fossil fuel-fired steam generating units located within
its jurisdiction. The EPA expects that, in making these determinations,
states will consider a number of factors and weigh input from the wide
range of potentially affected stakeholders. The meaningful engagement
requirements discussed in section X.E.1.b.i of this preamble will
ensure that all interested stakeholders--including community members
adversely impacted by pollution, energy workers affected by
construction and/or other changes in operation at fossil-fuel-fired
power plants, consumers and other interested parties--will have an
opportunity to have their concerns heard as states make decisions
balancing a multitude of factors including appropriate standards of
performance, compliance strategies, and compliance flexibilities for
existing EGUs, as well as public health and environmental
considerations. The EPA believes that these provisions, together with
the protections referenced above, can reduce the risks of localized
emissions increases in a manner that is protective of public health,
safety, and the environment.
F. Energy Workers and Communities
These final actions include requirements for meaningful engagement
in development of state plans, including with energy workers and
communities. These communities, including energy workers employed at
affected EGUs, workers who may construct and install pollution control
technology, workers employed by fuel extraction and delivery,
organizations
[[Page 39805]]
representing these workers, and communities living near affected EGUs,
are impacted by power sector trends on an ongoing basis and by these
final actions, and the EPA expects that states will include these
stakeholders as part of their constructive engagement under the
requirements in this rule.
The EPA consulted with the Federal Interagency Working Group on
Coal and Power Plant Communities and Economic Revitalization (Energy
Communities IWG) in development of these rules and the meaningful
engagement requirements. The EPA notes that the Energy Communities IWG
has provided resources to help energy communities access the expanded
federal resources made available by the Bipartisan Infrastructure Law,
CHIPS and Science Act, and Inflation Reduction Act, many of which are
relevant to the development of state plans.
G. Key Changes From Proposal
The key changes from proposal in these final actions are: (1) the
reduction in number of subcategories for existing coal-fired steam
generating units, (2) the extension of the compliance date for existing
coal-fired steam generating units to meet a standard of performance
based on implementation of CCS, (3) the removal of low-GHG hydrogen co-
firing as a BSER pathway, and (4) the addition of two reliability-
related instruments. In addition, (5), the EPA is not finalizing
proposed requirements for existing fossil fuel-fired stationary
combustion turbines at this time.
The reduction in number of subcategories for existing coal-fired
steam generating units: The EPA proposed four subcategories for
existing coal-fired steam generating units, which would have
distinguished these units by operating horizon and by load level. These
included subcategories for existing coal-fired EGUs planning to cease
operations in the imminent-term (i.e., prior to January 1, 2032) and
those planning to cease operations in the near-term (i.e., prior to
January 1, 2035). While commenters were generally supportive of the
proposed subcategorization approach, some requested that the cease-
operation-by date for the imminent-term subcategory be extended and the
utilization limit for the near-term subcategory be relaxed. The EPA is
not finalizing the imminent-term and near-term subcategories of coal-
fired steam generating units. Rather, the EPA is finalizing an
applicability exemption for coal-fired steam generating units
demonstrating that they plan to permanently cease operation before
January 1, 2032. See section VII.B of this preamble for further
discussion.
The extension of the compliance date for existing coal-fired steam
generating units to meet a standard of performance based on
implementation of CCS. The EPA proposed a compliance date for
implementation of CCS for long-term coal-fired steam generating units
of January 1, 2030. The EPA received comments asserting that this
deadline did not provide adequate lead time. In consideration of those
comments, and the record as a whole, the EPA is finalizing a CCS
compliance date of January 1, 2032 for these sources.
The removal of low-GHG hydrogen co-firing as a BSER pathway and
only use of low-GHG hydrogen as a compliance option: The EPA is not
finalizing its proposed BSER pathway of low-GHG hydrogen co-firing for
new and reconstructed base load and intermediate load combustion
turbines in accordance with CAA section 111(a)(1). The EPA is also not
finalizing its proposed requirement that only low-GHG hydrogen may be
co-fired in a combustion turbine for the purpose of compliance with the
standards of performance. These decisions are based on uncertainties
identified for specific criteria used to evaluate low-GHG hydrogen co-
firing as a potential BSER, and after further analysis in response to
public comments, the EPA has determined that these uncertainties
prevent the EPA from concluding that low-GHG hydrogen co-firing is a
component of the ``best'' system of emission reduction at this time.
Under CAA section 111, the EPA establishes standards of performance but
does not mandate use of any particular technology to meet those
standards. Therefore, certain sources may elect to co-fire hydrogen for
compliance with the final standards of performance, even absent the
technology being a BSER pathway.\15\ See section VIII.F.5 of this
preamble for further discussion.
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\15\ The EPA is not placing qualifications on the type of
hydrogen a source may elect to co-fire at this time (see section
VIII.F.6.a of this preamble for further discussion). The Agency
continues to recognize that even though the combustion of hydrogen
is zero-GHG emitting, its production can entail a range of GHG
emissions, from low to high, depending on the production method.
Thus, even though the EPA is not finalizing the low-GHG hydrogen co-
firing as a BSER, as proposed, it maintains that the overall GHG
profile of a particular method of hydrogen production should be a
primary consideration for any source that decides to co-fire
hydrogen to ensure that overall GHG reductions and important climate
benefits are achieved. The EPA also notes the anticipated final rule
from the U.S. Department of the Treasury pertaining to clean
hydrogen production tax and energy credits, which in its proposed
form contains certain eligibility parameters, as well as programs
administered by the U.S. Department of Energy, such as the recent
H2Hubs selections.
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The addition of two reliability-related instruments: Commenters
expressed concerns that these rules, in combination with other factors,
may affect the reliability of the bulk power system. In response to
these comments the EPA engaged extensively with balancing authorities,
power companies, reliability experts, and regulatory authorities
responsible for reliability to inform its decisions in these final
rules. As described later in this preamble, the EPA has made
adjustments in these final rules that will support power companies,
grid operators, and states in maintaining the reliability of the
electric grid during the implementation of these final rules. In
addition, the EPA has undertaken an analysis of the reliability and
resource adequacy implications of these final rules that supports the
Agency's conclusion that these final rules can be implemented without
adverse consequences for grid reliability. Further, the EPA is
finalizing two reliability-related instruments as an additional layer
of safeguards for reliability. These instruments include a reliability
mechanism for short-term emergency issues, and a reliability assurance
mechanism, or compliance flexibility, for units that have chosen
compliance pathways with enforceable retirement dates, provided there
is a documented and verified reliability concern. In addition, the EPA
is finalizing compliance extensions for unanticipated delays with
control technology implementation. Specifically, as described in
greater detail in section XII.F of this preamble, the EPA is finalizing
the following features and changes from the proposal that will provide
even greater certainty that these final rules are sensitive to
reliability-related issues and constructed in a manner that does not
interfere with grid operators' responsibility to deliver reliable
power:
(1) longer compliance timelines for existing coal-fired steam
generating units;
(2) a mechanism to extend compliance timelines by up to 1 year in
the case of unforeseen circumstances, outside of an owner/operator's
control, that delay the ability to apply controls (e.g., supply chain
challenges or permitting delays);
(3) transparent unit-specific compliance information for EGUs that
will allow grid operators to plan for system changes with greater
certainty and precision;
(4) a short-term reliability mechanism to allow affected EGUs to
operate at
[[Page 39806]]
baseline emission rates during documented reliability emergencies; and
(5) a reliability assurance mechanism to allow states to delay
cease operation dates by up to 1 year in cases where the planned cease
operation date is forecast to disrupt system reliability.
Not finalizing proposed requirements for existing fossil fuel-fired
stationary combustion turbines at this time: The EPA proposed emission
guidelines for large (i.e., greater than 300 MW), frequently operated
(i.e., with an annual capacity factor of greater than 50 percent),
existing fossil fuel-fired stationary combustion turbines. The EPA
received a wide range of comments on the proposed guidelines. Multiple
commenters suggested that the proposed provisions would largely result
in shifting of generation away from the most efficient natural gas-
fired turbines to less efficient natural gas-fired turbines. Commenters
stated that, as emissions from coal-fired steam generating units
decreased, existing natural gas-fired EGUs were poised to become the
largest source of GHG emissions in the power sector. Commenters noted
that these units play an important role in grid reliability,
particularly as aging coal-fired EGUs retire. Commenters further noted
that the existing fossil fuel-fired stationary combustion turbines that
were not covered by the proposal (i.e., the smaller and less frequently
operating units) are often less efficient, less well controlled for
other pollutants such as NO<INF>X</INF>, and are more likely to be
located near population centers and communities with environmental
justice concerns.
The EPA agrees with commenters who observed that GHG emissions from
existing natural gas-fired stationary combustion turbines are a growing
portion of the emissions from the power sector. This is consistent with
EPA modeling that shows that by 2030 these units will represent the
largest portion of GHG emissions from the power sector. The EPA agrees
that it is vital to promulgate emission guidelines to address GHG
emissions from these sources, and that the EPA has a responsibility to
do so under section 111(d) of the Clean Air Act. The EPA also agrees
with commenters who noted that focusing only on the largest and most
frequently operating units, without also addressing emissions from
other units, as the May 2023 proposed rule provided, may not be the
most effective way to address emissions from this sector. The EPA's
modeling shows that over time as the power sector comes closer to
reaching the phase-out threshold of the clean electricity incentives in
the Inflation Reduction Act (IRA) (i.e., a 75 percent reduction in
emissions from the power sector from 2022 levels), the average capacity
factor for existing natural gas-fired stationary combustion turbines
decreases. Therefore, the EPA's proposal to focus only on the largest
units with the highest capacity factors may not be the most effective
policy design for reducing GHG emissions from these sources.
Recognizing the importance of reducing emissions from all fossil
fuel-fired EGUs, the EPA is not finalizing the proposed emission
guidelines for certain existing fossil fuel-fired stationary combustion
turbines at this time. Instead, the EPA intends to issue a new, more
comprehensive proposal to regulate GHGs from existing sources. The new
proposal will focus on achieving greater emission reductions from
existing stationary combustion turbines--which will soon be the largest
stationary sources of GHG emissions--while taking into account other
factors including the local non-GHG impacts of gas turbine generation
and the need for reliable, affordable electricity.
II. General Information
A. Action Applicability
The source category that is the subject of these actions is
composed of fossil fuel-fired electric utility generating units. 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 final actions are likely to
affect.
Final amendments to 40 CFR part 60, subpart TTTT, are directly
applicable to affected facilities that began construction after January
8, 2014, but before May 23, 2023, and affected facilities that began
reconstruction or modification after June 18, 2014, but before May 23,
2023. The NSPS codified in 40 CFR part 60, subpart TTTTa, is directly
applicable to affected facilities that begin construction,
reconstruction, or modification on or after May 23, 2023. Federal,
state, local, and tribal government entities that own and/or operate
EGUs subject to 40 CFR part 60, subpart TTTT or TTTTa, are affected by
these amendments and standards.
The emission guidelines codified in 40 CFR part 60, subpart UUUUb,
are for states to follow in developing, submitting, and implementing
state plans to establish performance standards to reduce emissions of
GHGs from designated facilities that are existing sources. 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. Under the Tribal Authority Rule (TAR), eligible
tribes may seek approval 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 the emission guidelines codified in 40 CFR part
60, subpart UUUUb. The TAR authorizes tribes to develop and implement
their own air quality programs, or portions thereof, under the CAA.
However, it does not require tribes to develop a CAA program. Tribes
may implement programs that are most relevant to their air quality
needs. 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.\16\ 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.
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\16\ See the EPA's website, <a href="https://www.epa.gov/tribal/tribes-approved-treatment-state-tas">https://www.epa.gov/tribal/tribes-approved-treatment-state-tas</a>, for information on those tribes that
have treatment as a state for specific environmental regulatory
programs, administrative functions, and grant programs.
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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
these final rulemakings is available on the internet at <a href="https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power">https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power</a>. Following signature by the EPA
Administrator, the EPA will post a copy of these final rulemakings at
this same website. Following publication in the Federal Register, the
EPA will post the Federal Register version of the final rules and key
technical documents at this same website.
C. Judicial Review and Administrative Review
Under CAA section 307(b)(1), judicial review of these final actions
is available only by filing a petition for review in
[[Page 39807]]
the United States Court of Appeals for the District of Columbia Circuit
by July 8, 2024. These final actions are ``standard[s] of performance
or requirement[s] under section 111,'' and, in addition, are
``nationally applicable regulations promulgated, or final action taken,
by the Administrator under [the CAA],'' CAA section 307(b)(1). Under
CAA section 307(b)(2), the requirements established by this final rule
may not be challenged separately in any civil or criminal proceedings
brought by the EPA to enforce the requirements.
Section 307(d)(7)(B) of the CAA further provides that ``[o]nly an
objection to a rule or procedure which was raised with reasonable
specificity during the period for public comment (including any public
hearing) may be raised during judicial review.'' This section also
provides a mechanism for the EPA to convene a proceeding for
reconsideration, ``[i]f the person raising an objection can demonstrate
to the EPA that it was impracticable to raise such objection within
[the period for public comment] or if the grounds for such objection
arose after the period for public comment, (but within the time
specified for judicial review) and if such objection is of central
relevance to the outcome of the rule.'' Any person seeking to make such
a demonstration to us should submit a Petition for Reconsideration to
the Office of the Administrator, U.S. Environmental Protection Agency,
Room 3000, WJC West Building, 1200 Pennsylvania Ave. NW, Washington, DC
20460, with a copy to both the person(s) listed in the preceding FOR
FURTHER INFORMATION CONTACT section, and the Associate General Counsel
for the Air and Radiation Law Office, Office of General Counsel (Mail
Code 2344A), U.S. Environmental Protection Agency, 1200 Pennsylvania
Ave. NW, Washington, DC 20460.
III. Climate Change Impacts
Elevated concentrations of GHGs have been warming the planet,
leading to changes in the Earth's climate that are occurring at a pace
and in a way that threatens human health, society, and the natural
environment. While the EPA is not making any new scientific or factual
findings with regard to the well-documented impact of GHG emissions on
public health and welfare in support of these rules, the EPA is
providing in this section a brief scientific background on climate
change to offer additional context for these rulemakings and to help
the public understand the environmental impacts of GHGs.
Extensive 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 Greenhouse Gases
Under Section 202(a) of the CAA'' (74 FR 66496, December 15, 2009)
(``2009 Endangerment Finding''). In the 2009 Endangerment Finding, the
Administrator found under section 202(a) of the CAA that elevated
atmospheric concentrations of six key well-mixed GHGs--CO<INF>2</INF>,
methane (CH<INF>4</INF>), nitrous oxide (N<INF>2</INF>O), HFCs,
perfluorocarbons (PFCs), and sulfur hexafluoride (SF<INF>6</INF>)--
``may reasonably be anticipated to endanger the public health and
welfare of current and future generations'' (74 FR 66523, December 15,
2009). The 2009 Endangerment Finding, 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 Finding further explained that compared with 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).
The 2009 Endangerment Finding also documented, together with the
extensive scientific and technical evidence in the supporting record,
that climate change touches nearly every aspect of public welfare \17\
in the U.S., including the following: changes in water supply and
quality due to changes in 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; 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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\17\ 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 issued a similar finding for GHG
emissions from aircraft under section 231(a)(2)(A) of the CAA.\18\ In
the 2016 Endangerment Finding, the Administrator found that the body of
scientific evidence amassed in the record for the 2009 Endangerment
Finding 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 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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\18\ Finding That Greenhouse Gas Emissions From Aircraft Cause
or Contribute to Air Pollution That May Reasonably Be Anticipated To
Endanger Public Health and Welfare. 81 FR 54422, August 15, 2016
(``2016 Endangerment Finding'').
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Since the 2016 Endangerment Finding, the climate has continued to
change, with new observational records being set for several climate
indicators such as global average surface temperatures, GHG
concentrations, and sea level rise. Additionally, major scientific
assessments continue to be released that further advance our
understanding of the climate system and the impacts that GHGs have on
public health and welfare for both current and future generations.
These updated observations and projections document the rapid rate of
current and future
[[Page 39808]]
climate change both globally and in the
U.S.<SUP>19 20 21 22 23 24 25 26 27 28 29 30 31</SUP>
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\19\ 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.
\20\ 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.
\21\ 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.
\22\ 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. P[ouml]rtner,
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.)].
\23\ 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. P[ouml]rtner, 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.)].
\24\ 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.
Alegri[iacute]a, M. Nicolai, A. Okem, J. Petzold, B. Rama, N.M.
Weyer (eds.)].
\25\ National Academies of Sciences, Engineering, and Medicine.
2016. Attribution of Extreme Weather Events in the Context of
Climate Change. Washington, DC: The National Academies Press.
<a href="https://dio.org/10.17226/21852">https://dio.org/10.17226/21852</a>.
\26\ National Academies of Sciences, Engineering, and Medicine.
2017. Valuing Climate Damages: Updating Estimation of the Social
Cost of Carbon Dioxide. Washington, DC: The National Academies
Press. <a href="https://doi.org/10.17226/24651">https://doi.org/10.17226/24651</a>.
\27\ National Academies of Sciences, Engineering, and Medicine.
2019. Climate Change and Ecosystems. Washington, DC: The National
Academies Press. <a href="https://doi.org/10.17226/25504">https://doi.org/10.17226/25504</a>.
\28\ Blunden, J. and T. Boyer, Eds., 2022: ``State of the
Climate in 2021.'' Bull. Amer. Meteor. Soc., 103 (8), Si-S465,
<a href="https://doi.org/10.1175/2022BAMSStateoftheClimate">https://doi.org/10.1175/2022BAMSStateoftheClimate</a>.1.
\29\ U.S. Environmental Protection Agency. 2021. Climate Change
and Social Vulnerability in the United States: A Focus on Six
Impacts. EPA 430-R-21-003.
\30\ Jay, A.K., A.R. Crimmins, C.W. Avery, T.A. Dahl, R.S.
Dodder, B.D. Hamlington, A. Lustig, K. Marvel, P.A. M[eacute]ndez-
Lazaro, M.S. Osler, A. Terando, E.S. Weeks, and A. Zycherman, 2023:
Ch. 1. Overview: Understanding risks, impacts, and responses. In:
Fifth National Climate Assessment. Crimmins, A.R., C.W. Avery, D.R.
Easterling, K.E. Kunkel, B.C. Stewart, and T.K. Maycock, Eds. U.S.
Global Change Research Program, Washington, DC, USA. <a href="https://doi.org/10.7930/NCA5.2023.CH1">https://doi.org/10.7930/NCA5.2023.CH1</a>.
\31\ IPCC, 2023: Summary for Policymakers. In: Climate Change
2023: Synthesis Report. Contribution of Working Groups I, II and III
to the Sixth Assessment Report of the Intergovernmental Panel on
Climate Change [Core Writing Team, H. Lee and J. Romero (eds.)].
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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 because of
both historical 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,
atmospheric concentrations of one of these GHGs, CO<INF>2</INF>,
measured at Mauna Loa in Hawaii and at other sites around the world
reached 419 parts per million (ppm) in 2022 (nearly 50 percent higher
than preindustrial levels) \32\ and have continued to rise at a rapid
rate. Global average temperature has increased by about 1.1 [deg]C (2.0
[deg]F) in the 2011-2020 decade relative to 1850-1900.\33\ The years
2015-2021 were the warmest 7 years in the 1880-2021 record,
contributing to the warmest decade on record with a decadal temperature
of 0.82 [deg]C (1.48 [deg]F) above the 20th century.\34\ \35\ The
Intergovernmental Panel on Climate Change (IPCC) determined (with
medium confidence) that this past decade was warmer than any multi-
century period in at least the past 100,000 years.\36\ 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.\37\ The
rate of sea level rise over the 20th century was higher than in any
other century in at least the last 2,800 years.\38\ Higher
CO<INF>2</INF> concentrations have led to acidification of the surface
ocean in recent decades to an extent unusual in the past 65 million
years, with negative impacts on marine organisms that use calcium
carbonate to build shells or skeletons.\39\ 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.\40\ 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 \41\ in many
regions.\42\
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\32\ <a href="https://gml.noaa.gov/webdata/ccgg/trends/co2/co2_annmean_mlo.txt">https://gml.noaa.gov/webdata/ccgg/trends/co2/co2_annmean_mlo.txt</a>.
\33\ 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. 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, NY, USA, pp. 3-32, doi:10.1017/9781009157896.001.
\34\ NOAA National Centers for Environmental Information, State
of the Climate 2021 retrieved on August 3, 2023, from <a href="https://www.ncei.noaa.gov/bams-state-of-climate">https://www.ncei.noaa.gov/bams-state-of-climate</a>.
\35\ Blunden, J. and T. Boyer, Eds., 2022: ``State of the
Climate in 2021.'' Bull. Amer. Meteor. Soc., 103 (8), Si-S465,
https://doi.org/10.1175/2022BAMSStateoftheClimate1.
\36\ IPCC, 2021.
\37\ IPCC, 2021.
\38\ 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.
\39\ IPCC, 2018.
\40\ IPCC, 2021.
\41\ These are drought measures based on soil moisture.
\42\ 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 2022 CO<INF>2</INF> concentration of 419 ppm
is already higher than at any time in the last 2 million years.\43\ If
concentrations exceed 450 ppm, they would likely be higher than any
time in the past 23 million years: \44\ at the current rate of increase
of more than 2 ppm per year, this would occur in about 15 years. While
GHGs are not the only factor that controls climate, it is illustrative
that 3 million years ago (the last time CO<INF>2</INF> concentrations
were above 400 ppm) 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. If the Greenland
and Antarctic ice sheets were
[[Page 39809]]
to melt substantially, sea levels would rise dramatically.
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\43\ Annual Mauna Loa CO<INF>2</INF> concentration data from
<a href="https://gml.noaa.gov/webdata/ccgg/trends/co2/co2_annmean_mlo.txt">https://gml.noaa.gov/webdata/ccgg/trends/co2/co2_annmean_mlo.txt</a>,
accessed September 9, 2023.
\44\ IPCC, 2013.
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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.\45\ 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.\46\ 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.
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\45\ USGCRP, 2018.
\46\ IPCC, 2018.
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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 at least every five years, and 62
million more people to frequent exceptional heatwaves at least every
five years (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''). It would increase the frequency of sea-
ice-free Arctic summers from once in 100 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
would thaw over several centuries. Risks to food security would
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
would 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).\47\ 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 will 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, the movement speed has decreased, and elevated sea levels
have increased coastal flooding, all of which make these tropical
cyclones more damaging.\48\
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\47\ IPCC, 2018.
\48\ 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.\49\ 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.\50\ 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, requiring the installation of costly pump
stations, flooding streets, and increasing storm surge damages. Tens of
billions of dollars of U.S. real estate could be below sea level by
2050 under some scenarios. Increased frequency and duration of drought
will reduce agricultural productivity in some regions, accelerate
depletion of water supplies for irrigation, and expand the distribution
and incidence of pests and diseases for crops and livestock. The NCA4
also recognized that climate change can increase risks to national
security, both through direct impacts on military infrastructure and 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.\51\ The NCA5 further reinforces the science showing that
climate change will have many impacts on the U.S., as described above
in the preamble. Particularly relevant for these rules, the NCA5 states
that climate change affects all aspects of the energy system-supply,
delivery, and demand-through the increased frequency, intensity, and
duration of extreme events and through changing climate trends.'' \52\
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\49\ USGCRP, 2018.
\50\ NIFC (National Interagency Fire Center). 2021. Total
wildland fires and acres (1983-2020). Accessed August 2021. <a href="https://www.nifc.gov/fireInfo/fireInfo_stats_totalFires.html">https://www.nifc.gov/fireInfo/fireInfo_stats_totalFires.html</a>.
\51\ USGCRP, 2018.
\52\ Jay, A.K., A.R. Crimmins, C.W. Avery, T.A. Dahl, R.S.
Dodder, B.D. Hamlington, A. Lustig, K. Marvel, P.A. M[eacute]ndez-
Lazaro, M.S. Osler, A. Terando, E.S. Weeks, and A. Zycherman, 2023:
Ch. 1. Overview: Understanding risks, impacts, and responses. In:
Fifth National Climate Assessment. Crimmins, A.R., C.W. Avery, D.R.
Easterling, K.E. Kunkel, B.C. Stewart, and T.K. Maycock, Eds. U.S.
Global Change Research Program, Washington, DC, USA. <a href="https://doi.org/10.7930/NCA5.2023.CH1">https://doi.org/10.7930/NCA5.2023.CH1</a>.
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EPA modeling efforts can further illustrate how these impacts from
climate change may be experienced across the U.S. EPA's Framework for
Evaluating Damages and Impacts (FrEDI) \53\ uses information from over
30 peer-reviewed climate change impact studies to project the physical
and economic impacts of climate change to the U.S. resulting from
future temperature changes. These impacts are projected for specific
regions within the U.S. and for more than 20 impact categories, which
span a large number of sectors of the U.S. economy.\54\ Using
[[Page 39810]]
this framework, the EPA estimates that global emission projections,
with no additional mitigation, will result in significant climate-
related damages to the U.S.\55\ These damages to the U.S. would mainly
be from increases in lives lost due to increases in temperatures, as
well as impacts to human health from increases in climate-driven
changes in air quality, dust and wildfire smoke exposure, and incidence
of suicide. Additional major climate-related damages would occur to
U.S. infrastructure such as roads and rail, as well as transportation
impacts and coastal flooding from sea level rise, increases in property
damage from tropical cyclones, and reductions in labor hours worked in
outdoor settings and buildings without air conditioning. These impacts
are also projected to vary from region to region with the Southeast,
for example, projected to see some of the largest damages from sea
level rise, the West Coast projected to experience damages from
wildfire smoke more than other parts of the country, and the Northern
Plains states projected to see a higher proportion of damages to rail
and road infrastructure. While information on the distribution of
climate impacts helps to better understand the ways in which climate
change may impact the U.S., recent analyses are still only a partial
assessment of climate impacts relevant to U.S. interests and in
addition do 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 occurring
abroad have spillover effects in different regions of the U.S.
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\53\ (1) Hartin, C., et al. (2023). Advancing the estimation of
future climate impacts within the United States. Earth Syst. Dynam.,
14, 1015-1037, <a href="https://doi.org/10.5194/esd-14-1015-2023">https://doi.org/10.5194/esd-14-1015-2023</a>. (2)
Supplementary Material for the Regulatory Impact Analysis for the
Final Rulemaking, Standards of Performance for New, Reconstructed,
and Modified Sources and Emissions Guidelines for Existing Sources:
Oil and Natural Gas Sector Climate Review, ``Report on the Social
Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific
Advances,'' Docket ID No. EPA-HQ-OAR-2021-0317, November 2023, (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.
\54\ EPA (2021). Technical Documentation on the Framework for
Evaluating Damages and Impacts (FrEDI). U.S. Environmental
Protection Agency, EPA 430-R-21-004, <a href="https://www.epa.gov/cira/fredi">https://www.epa.gov/cira/fredi</a>.
Documentation has been subject to both a public review comment
period and an independent expert peer review, following EPA peer-
review guidelines.
\55\ Compared to a world with no additional warming after the
model baseline (1986-2005).
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Some GHGs also have impacts beyond those mediated through climate
change. For example, elevated concentrations of CO<INF>2</INF>
stimulate plant growth (which can be positive in the case of beneficial
species, but negative in terms of weeds and invasive species, and can
also lead to a reduction in plant micronutrients \56\) and cause ocean
acidification. Nitrous oxide depletes the levels of protective
stratospheric ozone.\57\ Methane reacts to form tropospheric ozone.
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\56\ Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse, J.F.
Garofalo, A.S. Khan, I. Loladze, A.A. P[eacute]rez de Le[oacute]n,
A. Showler, J. Thurston, and I. Walls, 2016: Ch. 7: Food Safety,
Nutrition, and Distribution. The Impacts of Climate Change on Human
Health in the United States: A Scientific Assessment. U.S. Global
Change Research Program, Washington, DC, 189-216. <a href="https://health2016.globalchange.gov/low/ClimateHealth2016_07_Food_small.pdf">https://health2016.globalchange.gov/low/ClimateHealth2016_07_Food_small.pdf</a>.
\57\ WMO (World Meteorological Organization), Scientific
Assessment of Ozone Depletion: 2018, Global Ozone Research and
Monitoring Project--Report No. 58, 588 pp., Geneva, Switzerland,
2018.
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Section XII.E of this preamble discusses the impacts of GHG
emissions on individuals living in socially and economically vulnerable
communities. While the EPA did not conduct modeling to specifically
quantify changes in climate impacts resulting from these rules in terms
of avoided temperature change or sea-level rise, the Agency did
quantify climate benefits by monetizing the emission reductions through
the application of the social cost of greenhouse gases (SC-GHGs), as
described in section XII.D of this preamble.
These scientific assessments, the 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
In this section, we discuss background information about the
electric power sector and controls available to limit GHG pollution
from the fossil fuel-fired power plants regulated by these final rules,
and then discuss several recent developments that are relevant for
determining the BSER for these sources. After giving some general
background, we first discuss CCS and explain that its costs have fallen
significantly. Lower costs are central for the EPA's determination that
CCS is the BSER for certain existing coal-fired steam generating units
and certain new natural gas-fired combustion turbines. Second, we
discuss natural gas co-firing for coal-fired steam generating units and
explain recent reductions in cost for this approach as well as its
widespread availability and current and potential deployment within
this subcategory. Third, we discuss highly efficient generation as a
BSER technology for new and reconstructed simple cycle and combined
cycle combustion turbine EGUs. The emission reductions achieved by
highly efficient turbines are well demonstrated in the power sector,
and along with operational and maintenance best practices, represent a
cost-effective technology that reduces fuel consumption. Finally, we
discuss key developments in the electric power sector that influence
which units can feasibly and cost-effectively deploy these
technologies.
A. Background
1. Electric Power Sector
Electricity in the U.S. is generated by a range of technologies,
and different EGUs play different roles in providing reliable and
affordable electricity. For example, certain EGUs generate base load
power, which is the portion of electricity loads that are continually
present and typically operate throughout all hours of the year.
Intermediate EGUs often provide complementary generation to balance
variable supply and demand resources. Low load ``peaking units''
provide capacity during hours of the highest daily, weekly, or seasonal
net demand, and while these resources have low levels of utilization on
an annual basis, they play important roles in providing generation to
meet short-term demand and often must be available to quickly increase
or decrease their output. Furthermore, many of these 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 \58\ in the event of unexpected changes in the availability of
other generators.
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\58\ 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 (1 kWh = 1,000 watt-
hours), megawatt-hours (1 MWh = 1,000 kWh), gigawatt-hours (1 GWh =
1 million kWh), or terawatt-hours (1 TWh = 1 billion 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
are 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.
[[Page 39811]]
Generated electricity must be transmitted over networks \59\ 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; \60\ in others, individual utilities \61\ coordinate
the operations of their generation and transmission to balance the
system across their respective service territories.
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\59\ The three network interconnections are the Western
Interconnection, comprising the western parts of the U.S. and
Canada, the Eastern Interconnection, comprising the eastern parts of
the U.S. and Canada except parts of Eastern Canada in the Quebec
Interconnection, and the Texas Interconnection, encompassing the
portion of the Texas electricity system commonly known as the
Electric Reliability Council of Texas (ERCOT). See map of all NERC
interconnections at <a href="https://www.nerc.com/AboutNERC/keyplayers/PublishingImages/NERC%20Interconnections.pdf">https://www.nerc.com/AboutNERC/keyplayers/PublishingImages/NERC%20Interconnections.pdf</a>.
\60\ For example, PJM Interconnection, LLC, New York Independent
System Operator (NYISO), Midwest Independent System Operator (MISO),
California Independent System Operator (CAISO), etc.
\61\ For example, Los Angeles Department of Power and Water,
Florida Power and Light, etc.
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2. Types of EGUs
There are many types of EGUs including fossil fuel-fired power
plants (i.e., those using coal, oil, and natural gas), nuclear power
plants, renewable generating sources (such as wind and solar) and
others. This rule focuses on the fossil fuel-fired portion of the
generating fleet that is responsible for the vast majority of GHG
emissions from the power sector. The definition of fossil fuel-fired
electric utility steam generating units includes utility boilers as
well as 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 refueled as natural gas-fired utility boilers. An
IGCC unit gasifies fuel--typically coal or petroleum coke--to form a
synthetic gas (or syngas) composed of carbon monoxide (CO) and hydrogen
(H<INF>2</INF>), which can be combusted in a combined cycle system to
generate power. The heat created by these technologies produces high-
pressure steam that is released to rotate turbines, which, in turn,
spin an electric generator.
Stationary combustion turbine EGUs (most commonly natural gas-
fired) use one of two configurations: combined cycle or simple cycle
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 load power. An EGU's capacity factor indicates a
power plant's electricity output as a percentage of its total
generation capacity. Simple cycle 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.\62\
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\62\ 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.
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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 40 percent of the overall net electricity supply
in 2022. Many projections show this share growing over time. For
example, the EPA's Power Sector Platform 2023 using IPM (i.e., the
EPA's baseline projections of the power sector) projects zero-emitting
sources reaching 76 percent of electricity generation by 2040. This
shift is driven by multiple factors. These factors include changes in
the relative economics of generating technologies, the efforts by
states to reduce GHG emissions, utility and other corporate
commitments, and customer preference. The shift is further promoted by
provisions of Federal legislation, most notably the Clean Electricity
Investment and Production tax credits included in IRC sections 48E and
45Y of the IRA, which do not begin to phase out until the later of 2032
or when power sector GHG emissions are 75 percent less than 2022
levels. (See section IV.F of this preamble and the accompanying RIA for
additional discussion of projections for the power sector.) These
projections are consistent with power company announcements. For
example, as the Edison Electric Institute (EEI) stated in pre-proposal
public comments submitted to the regulatory docket: ``Fifty EEI members
have announced forward-looking carbon reduction goals, two-thirds of
which include a net-zero by 2050 or earlier equivalent goal, and
members are routinely increasing the ambition or speed of their goals
or altogether transforming them into net-zero goals . . . . EEI's
member companies see a clear path to continued emissions reductions
over the next decade using current technologies, including nuclear
power, natural gas-based generation, energy demand efficiency, energy
storage, and deployment of new renewable energy--especially wind and
solar--as older coal-based and less-efficient natural gas-based
generating units retire.'' \63\ The Energy Strategy Coalition similarly
said in public comments that ``[a]s major electrical utilities and
power producers, our top priority is providing clean, affordable, and
reliable energy to our customers'' and are ``seeking to advance''
technologies ``such as a carbon capture and storage, which can
significantly reduce carbon dioxide
[[Page 39812]]
emissions from fossil fuel-fired EGUs.'' \64\
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\63\ 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. Public comments submitted to the
EPA's pre-proposal rulemaking, Document ID No. EPA-HQ-OAR-2022-0723-
0024.
\64\ Energy Strategy Coalition Comments on EPA's 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, Document ID No. EPA-HQ-OAR-2023-
0072-0672, August 14, 2023.
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B. GHG Emissions From Fossil Fuel-Fired EGUs
The principal GHGs that accumulate in the Earth's atmosphere above
pre-industrial levels because of human activity are CO<INF>2</INF>,
CH<INF>4</INF>, N<INF>2</INF>O, HFCs, PFCs, and SF<INF>6</INF>. Of
these, CO<INF>2</INF> is the most abundant, accounting for 80 percent
of all GHGs present in the atmosphere. This abundance of CO<INF>2</INF>
is largely due to the combustion of fossil fuels by the transportation,
electricity, and industrial sectors.\65\
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\65\ U.S. Environmental Protection Agency (EPA). Overview of
greenhouse gas emissions. July 2021. <a href="https://www.epa.gov/ghgemissions/overview-greenhouse-gases#carbon-dioxide">https://www.epa.gov/ghgemissions/overview-greenhouse-gases#carbon-dioxide</a>.
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The amount of CO<INF>2</INF> produced when a fossil fuel is burned
in an EGU is a function of the carbon content of the fuel relative to
the size and efficiency of the EGU. Different fuels emit different
amounts of CO<INF>2</INF> in relation to the energy they produce when
combusted. The heat content, or the amount of energy produced when a
fuel is burned, is mainly determined by the carbon and hydrogen content
of the fuel. For example, in terms of pounds of CO<INF>2</INF> emitted
per million British thermal units of energy produced when combusted,
natural gas is the lowest compared to other fossil fuels at 117 lb
CO<INF>2</INF>/MMBtu.<SUP>66 67</SUP> The average for coal is 216 lb
CO<INF>2</INF>/MMBtu, but varies between 206 to 229 lb CO<INF>2</INF>/
MMBtu by type (e.g., anthracite, lignite, subbituminous, and
bituminous).\68\ The value for petroleum products such as diesel fuel
and heating oil is 161 lb CO<INF>2</INF>/MMBtu.
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\66\ Natural gas is primarily CH<INF>4</INF>, which has a higher
hydrogen to carbon atomic ratio, relative to other fuels, and thus,
produces the least CO<INF>2</INF> per unit of heat released. In
addition to a lower CO<INF>2</INF> emission rate on a lb/MMBtu
basis, natural gas is generally converted to electricity more
efficiently than coal. According to EIA, the 2020 emissions rate for
coal and natural gas were 2.23 lb CO<INF>2</INF>/kWh and 0.91 lb
CO<INF>2</INF>/kWh, respectively. <a href="http://www.eia.gov/tools/faqs/faq.php?id=74&t=11">www.eia.gov/tools/faqs/faq.php?id=74&t=11</a>.
\67\ 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.
\68\ Energy Information Administration (EIA). Carbon Dioxide
Emissions Coefficients. <a href="https://www.eia.gov/environment/emissions/co2_vol_mass.php">https://www.eia.gov/environment/emissions/co2_vol_mass.php</a>.
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The EPA prepares the official U.S. Inventory of Greenhouse Gas
Emissions and Sinks \69\ (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 \70\ of GHGs, including CO<INF>2</INF> emissions
since 1990. According to the latest inventory of all sectors, in 2021,
total U.S. GHG emissions were 6,340 million metric tons of
CO<INF>2</INF> equivalent (MMT CO<INF>2</INF>e).\71\ The transportation
sector (28.5 percent), which includes approximately 300 million
vehicles, was the largest contributor to total U.S. GHG emissions with
1,804 MMT CO<INF>2</INF>e followed by the power sector (25.0 percent)
with 1,584 MMT CO<INF>2</INF>e. In fact, GHG emissions from the power
sector were higher than the GHG emissions from all other industrial
sectors combined (1,487 MMT CO<INF>2</INF>e). Specifically, the power
sector's emissions were far more than petroleum and natural gas systems
\72\ at 301 MMT CO<INF>2</INF>e; chemicals (71 MMT CO<INF>2</INF>e);
minerals (64 MMT CO<INF>2</INF>e); coal mining (53 MMT
CO<INF>2</INF>e); and metals (48 MMT CO<INF>2</INF>e). The agriculture
(636 MMT CO<INF>2</INF>e), commercial (439 MMT CO<INF>2</INF>e), and
residential (366 MMT CO<INF>2</INF>e) sectors combined to emit 1,441
MMT CO<INF>2</INF>e.
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\69\ U.S. Environmental Protection Agency (EPA). Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2021. <a href="https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks">https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks</a>-1990-2021.
\70\ Sinks are a physical unit or process that stores GHGs, such
as forests or underground or deep-sea reservoirs of carbon dioxide.
\71\ U.S. Environmental Protection Agency (EPA). Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2021. <a href="https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks">https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks</a>.
\72\ Petroleum and natural gas systems include: offshore and
onshore petroleum and natural gas production; onshore petroleum and
natural gas gathering and boosting; natural gas processing; natural
gas transmission/compression; onshore natural gas transmission
pipelines; natural gas local distribution companies; underground
natural gas storage; liquified natural gas storage; liquified
natural gas import/export equipment; and other petroleum and natural
gas systems.
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Fossil fuel-fired EGUs are by far the largest stationary source
emitters of GHGs in the nation. For example, according to the EPA's
Greenhouse Gas Reporting Program (GHGRP), of the top 100 large
facilities that reported facility-level GHGs in 2022, 85 were fossil
fuel-fired power plants while 10 were refineries and/or chemical
plants, four were metals facilities, and one was a petroleum and
natural gas systems facility.\73\ Of the 85 fossil fuel-fired power
plants, 81 were primarily coal-fired, including the top 41 emitters of
CO<INF>2</INF>. In addition, of the 81 coal-fired plants, 43 have no
retirement planned prior to 2039. The top 10 of these plants combined
to emit more than 135 MMT of CO<INF>2</INF>e, with the top emitter
(James H. Miller power plant in Alabama) reporting approximately 22 MMT
of CO<INF>2</INF>e with each of its four EGUs emitting between 5 MMT
and 6 MMT CO<INF>2</INF>e that year. The combined capacity of these 10
plants is more than 23 gigawatts (GW), and all except for the Monroe
(Michigan) plant operated at annual capacity factors of 50 percent or
higher.\74\ For comparison, the largest GHG emitter in the U.S. that is
not a fossil fuel-fired power plant is the ExxonMobil refinery and
chemical plant in Baytown, Texas, which reported 12.6 MMT
CO<INF>2</INF>e (No. 6 overall in the nation) to the GHGRP in 2022. The
largest metals facility in terms of GHG emissions was the U.S. Steel
facility in Gary, Indiana, with 10.4 MMT CO<INF>2</INF>e (No. 16
overall in the nation).
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\73\ U.S. Environmental Protection Agency (EPA). Greenhouse Gas
Reporting Program. Facility Level Information on Greenhouse Gases
Tool (FLIGHT). <a href="https://ghgdata.epa.gov/ghgp/main.do#">https://ghgdata.epa.gov/ghgp/main.do#</a>.
\74\ U.S. Energy Information Administration (EIA). Preliminary
Monthly Electric Generator Inventory, Form EIA-860M, November 2023.
<a href="https://www.eia.gov/electricity/data/eia860m/">https://www.eia.gov/electricity/data/eia860m/</a>.
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Overall, CO<INF>2</INF> emissions from the power sector have
declined by 36 percent since 2005 (when the power sector reached annual
emissions of 2,400 MMT CO<INF>2</INF>, its historical peak to
date).\75\ The reduction in CO<INF>2</INF> emissions can be attributed
to the power sector's ongoing trend away from carbon-intensive coal-
fired generation and toward more natural gas-fired and renewable
sources. In 2005, CO<INF>2</INF> emissions from coal-fired EGUs alone
measured 1,983 MMT.\76\ This total dropped to 1,351 MMT in 2015 and
reached 974 MMT in 2019, the first time since 1978 that CO<INF>2</INF>
emissions from coal-fired EGUs were below 1,000 MMT. In 2020, emissions
of CO<INF>2</INF> from coal-fired EGUs measured 788 MMT as the result
of pandemic-related closures and reduced utilization before rebounding
in 2021 to 909 MMT. By contrast, CO<INF>2</INF> emissions from natural
gas-fired generation have almost doubled since 2005, increasing from
319 MMT to 613 MMT in 2021, and CO<INF>2</INF> emissions from petroleum
products (i.e., distillate fuel oil, petroleum coke, and residual fuel
oil) declined from 98 MMT in 2005 to 18 MMT in 2021.
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\75\ U.S. Environmental Protection Agency (EPA). Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2020. <a href="https://cfpub.epa.gov/ghgdata/inventoryexplorer/#electricitygeneration/entiresector/allgas/category/all">https://cfpub.epa.gov/ghgdata/inventoryexplorer/#electricitygeneration/entiresector/allgas/category/all</a>.
\76\ U.S. Energy Information Administration (EIA). Monthly
Energy Review, table 11.6. September 2022. <a href="https://www.eia.gov/totalenergy/data/monthly/pdf/sec11.pdf">https://www.eia.gov/totalenergy/data/monthly/pdf/sec11.pdf</a>.
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[[Page 39813]]
When the EPA finalized the Clean Power Plan (CPP) in October 2015,
the Agency projected that, as a result of the CPP, the power sector
would reduce its annual CO<INF>2</INF> emissions to 1,632 MMT by 2030,
or 32 percent below 2005 levels (2,400 MMT).\77\ Instead, even in the
absence of Federal regulations for existing EGUs, annual CO<INF>2</INF>
emissions from sources covered by the CPP had fallen to 1,540 MMT by
the end of 2021, a nearly 36 percent reduction below 2005 levels. The
power sector achieved a deeper level of reductions than forecast under
the CPP and approximately a decade ahead of time. By the end of 2015,
several months after the CPP was finalized, those sources already had
achieved CO<INF>2</INF> emission levels of 1,900 MMT, or approximately
21 percent below 2005 levels. However, progress in emission reductions
is not uniform across all states and is not guaranteed to continue,
therefore Federal policies play an essential role. As discussed earlier
in this section, the power sector remains a leading emitter of
CO<INF>2</INF> in the U.S., and, despite the emission reductions since
2005, current CO<INF>2</INF> levels continue to endanger human health
and welfare. Further, as sources in other sectors of the economy turn
to electrification to decarbonize, future CO<INF>2</INF> reductions
from fossil fuel-fired EGUs have the potential to take on added
significance and increased benefits.
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\77\ 80 FR 63662 (October 23, 2015).
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C. Recent Developments in Emissions Control
This section of the preamble describes recent developments in GHG
emissions control in general. Details of those controls in the context
of BSER determination are provided in section VII.C.1.a for CCS on
coal-fired steam generating units, section VII.C.2.a for natural gas
co-firing on coal-fired steam generating units, section VIII.F.2.b for
efficient generation on natural gas-fired combustion turbines, and
section VIII.F.4.c.iv for CCS on natural gas-fired combustion turbines.
Further details of the control technologies are available in the final
TSDs, GHG Mitigation Measures for Steam Generating Units and GHG
Mitigation Measures--CCS for Combustion Turbines, available in the
docket for these actions.
1. CCS
One of the key GHG reduction technologies upon which the BSER
determinations are founded in these final rules is CCS--a technology
that can capture and permanently store CO<INF>2</INF> from fossil fuel-
fired EGUs. CCS has three major components: CO<INF>2</INF> capture,
transportation, and sequestration/storage. Solvent-based CO<INF>2</INF>
capture was patented nearly 100 years ago in the 1930s \78\ and has
been used in a variety of industrial applications for decades.
Thousands of miles of CO<INF>2</INF> pipelines have been constructed
and securely operated in the U.S. for decades.\79\ And tens of millions
of tons of CO<INF>2</INF> have been permanently stored deep underground
either for geologic sequestration or in association with enhanced oil
recovery (EOR).\80\ The American Petroleum Institute (API) explains
that ``CCS is a proven technology'' and that ``[t]he methods that apply
to [the] carbon sequestration process are not novel. The U.S. has more
than 40 years of CO<INF>2</INF> gas injection and storage experience.
During the last 40 years the U.S. gas and oil industry's (EOR) enhanced
oil recovery operations) have injected more than 1 billion tonnes of
CO<INF>2</INF>.'' <SUP>81 82</SUP>
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\78\ Bottoms, R.R. Process for Separating Acidic Gases (1930)
United States patent application. United States Patent US1783901A;
Allen, A.S. and Arthur, M. Method of Separating Carbon Dioxide from
a Gas Mixture (1933) United States Patent Application. United States
Patent US1934472A.
\79\ U.S. Department of Transportation, Pipeline and Hazardous
Material Safety Administration, ``Hazardous Annual Liquid Data.''
2022. <a href="https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids">https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids</a>.
\80\ GHGRP US EPA. <a href="https://www.epa.gov/ghgreporting/supply-underground-injection-and-geologic-sequestration-carbon-dioxide">https://www.epa.gov/ghgreporting/supply-underground-injection-and-geologic-sequestration-carbon-dioxide</a>.
\81\ American Petroleum Institute (API). (2024). Carbon Capture
and Storage: A Low-Carbon Solution to Economy-Wide Greenhouse Gas
Emissions Reductions. <a href="https://www.api.org/news-policy-and-issues/carbon-capture-storage">https://www.api.org/news-policy-and-issues/carbon-capture-storage</a>.
\82\ Major energy company presidents have made similar
statements. For example, in 2021, Shell Oil Company president
Gretchen H. Watkins testified to Congress that ``Carbon capture and
storage is a proven technology,'' and in 2022, Joe Blommaert, the
president of ExxonMobil Low Carbon Solutions, stated that ``Carbon
capture and storage is a readily available technology that can play
a critical role in helping society reduce greenhouse gas
emissions.'' See <a href="https://www.congress.gov/117/meeting/house/114185/witnesses/HHRG-117-GO00-Wstate-WatkinsG-20211028.pdf">https://www.congress.gov/117/meeting/house/114185/witnesses/HHRG-117-GO00-Wstate-WatkinsG-20211028.pdf</a> and <a href="https://corporate.exxonmobil.com/news/news-releases/2022/0225_exxonmobil-to-expand-carbon-capture-and-storage-at-labarge-wyoming-facility">https://corporate.exxonmobil.com/news/news-releases/2022/0225_exxonmobil-to-expand-carbon-capture-and-storage-at-labarge-wyoming-facility</a>.
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In 2009, Mike Morris, then-CEO of American Electric Power (AEP),
was interviewed by Reuters and the article noted that Morris's
``companies' work in West Virginia on [CCS] gave [Morris] more insight
than skeptics who doubt the technology.'' In that interview, Morris
explained, ``I'm convinced it will be primetime ready by 2015 and
deployable.'' \83\ In 2011, Alstom Power, the company that developed
the 30 MW pilot project upon which Morris had based his conclusions,
reiterated the claim that CCS would be commercially available in 2015.
A press release from Alstom Power stated that, based on the results of
Alstom's ``13 pilot and demonstration projects and validated by
independent experts . . . we can now be confident that CCS works and is
cost effective . . . and will be available at a commercial scale in
2015 and will allow [plants] to capture 90% of the emitted
CO<INF>2</INF>.'' The press release went on to note that ``the same
conclusion applies for a gas plant using CCS.'' \84\
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\83\ Woodall, B. (June 25, 2009). AEP sees carbon capture from
coal ready by 2015. Reuters. <a href="https://www.reuters.com/article/idUSTRE55O6TS/">https://www.reuters.com/article/idUSTRE55O6TS/</a>.
\84\ Alstom Power. (June 14, 2011). Alstom Power study
demonstrates carbon capture and storage (CCS) is efficient and cost
competitive. <a href="https://www.alstom.com/press-releases-news/2011/6/press-releases-3-26">https://www.alstom.com/press-releases-news/2011/6/press-releases-3-26</a>.
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In 2011, however, AEP determined that the economic and regulatory
environment at the time did not support further development of the
technology. After canceling a large-scale commercial project, Morris
explained, ``as a regulated utility, it is impossible to gain
regulatory approval to cover our share of the costs for validating and
deploying the technology without federal requirements to reduce
greenhouse gas emissions already in place.'' \85\
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\85\ Indiana Michigan Power. (July 14, 2011). AEP Places Carbon
Capture Commercialization on Hold, Citing Uncertain Status of
Climate Policy, Weak Economy. Press release. <a href="https://www.indianamichiganpower.com/company/news/view?releaseID=1206">https://www.indianamichiganpower.com/company/news/view?releaseID=1206</a>.
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Thirteen years later, the situation is fundamentally different.
Since 2011, the technological advances from full-scale deployments
(e.g., the Petra Nova and Boundary Dam projects discussed later in this
preamble) combined with supportive policies in multiple states and the
financial incentives included in the IRA, mean that CCS can be deployed
at scale today. In addition to applications at fossil fuel-fired EGUs,
installation of CCS is poised to dramatically increase across a range
of industries in the coming years, including ethanol production,
natural gas processing, and steam methane reformers.\86\ Many of the
CCS projects across these industries, including capture systems,
pipelines, and sequestration, are already in operation or are in
advanced stages of deployment. There are currently at least 15
operating CCS projects in the U.S., and another 121 that are under
[[Page 39814]]
construction or in advanced stages of development.\87\
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\86\ U.S. Department of Energy (DOE). (2023). Pathways to
Commercial Liftoff: Carbon Management. <a href="https://liftoff.energy.gov/wp-content/uploads/2024/02/20230424-Liftoff-Carbon-Management-vPUB_update4.pdf">https://liftoff.energy.gov/wp-content/uploads/2024/02/20230424-Liftoff-Carbon-Management-vPUB_update4.pdf</a>.
\87\ Congressional Budget Office (CBO). (December 13, 2023).
Carbon Capture and Storage in the United States. <a href="https://www.cbo.gov/publication/59345">https://www.cbo.gov/publication/59345</a>.
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Process improvements learned from earlier deployments of CCS, the
availability of better solvents, and other advances have decreased the
costs of CCS in recent years. As a result, the cost of CO<INF>2</INF>
capture, excluding any tax credits, from coal-fired power generation is
projected to fall by 50 percent by 2025 compared to 2010.\88\ The IRA
makes additional and significant reductions in the cost of implementing
CCS by extending and increasing the tax credit for CO<INF>2</INF>
sequestration under IRC section 45Q.
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\88\ Global CCS Institute. (March 2021). Technology Readiness
and Costs of CCS. <a href="https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-and-Costs-for-CCS-2021-1.pdf">https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-and-Costs-for-CCS-2021-1.pdf</a>.
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With this combination of polices, and the advances related to
CO<INF>2</INF> capture, multiple projects consistent with the emission
reduction requirements of a 90 percent capture amine based BSER are in
advanced stages of development. These projects use a wider range of
technologies, and some of them are being developed as first-of-a-kind
projects and offer significant advantages over the amine-based CCS
technology that the EPA is finalizing as BSER.
For instance, in North Dakota, Governor Doug Burgum announced a
goal of becoming carbon neutral by 2030 while retaining the core
position of its fossil fuel industries, and to do so by significant CCS
implementation. Gov. Burgum explained, ``This may seem like a moonshot
goal, but it's actually not. It's actually completely doable, even with
the technologies that we have today.'' \89\ Companies in the state are
backing up this claim with projects in multiple industries in various
stages of operation and development. In the power sector, two of the
biggest projects under development are Project Tundra and Coal Creek.
Project Tundra is a carbon capture project on Minnkota Power's 705 MW
Milton R Young Power Plant in Oliver County, North Dakota. Mitsubishi
Heavy Industries will be providing an advanced version of its carbon
capture equipment that builds upon the lessons learned from the Petra
Nova project.\90\ Rainbow Energy is developing the project at the Coal
Creek Station, located in McLean, North Dakota. Notably, Rainbow Energy
purchased the 1,150 MW Coal Creek Station with a business model of
installing CCS based on the IRC section 45Q tax credit of $50/ton that
existed at the time (the IRA has since increased the amount to $85/
ton).\91\ Rainbow Energy explains, ``CCUS technology has been proven
and is an economical option for a facility like Coal Creek Station. We
see CCUS as the best way to manage emissions at our facility.'' \92\
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\89\ Willis, A. (May 12, 2021). Gov. Doug Burgum calls for North
Dakota to be carbon neutral by 2030. The Dickinson Press. <a href="https://www.thedickinsonpress.com/business/gov-doug-burgum-calls-for-north-dakota-to-be-carbon-neutral-by-2030">https://www.thedickinsonpress.com/business/gov-doug-burgum-calls-for-north-dakota-to-be-carbon-neutral-by-2030</a>.
\90\ Tanaka, H. et al. Advanced KM CDR Process using New
Solvent. 14th International Conference on Greenhouse Gas Control
Technologies, GHGT-14. <a href="https://www.cfaenm.org/wp-content/uploads/2019/03/GHGT14_manuscript_20180913Clean-version.pdf">https://www.cfaenm.org/wp-content/uploads/2019/03/GHGT14_manuscript_20180913Clean-version.pdf</a>.
\91\ Minot Daily News. (April 8, 2024). Hoeven: ND to lead
country with carbon capture project at Coal Creek Station. <a href="https://minotdailynews.com/news/local-news/2021/07/hoeven-nd-to-lead-country-with-carbon-capture-project-at-coal-creek-station/">https://minotdailynews.com/news/local-news/2021/07/hoeven-nd-to-lead-country-with-carbon-capture-project-at-coal-creek-station/</a>.
\92\ Rainbow Energy Center. (ND). Carbon Capture. <a href="https://rainbowenergycenter.com/what-we-do/carbon-capture/">https://rainbowenergycenter.com/what-we-do/carbon-capture/</a>.
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While North Dakota has encouraged CCS on coal-fired power plants
without specific mandates, Wyoming is taking a different approach.
Senate Bill 42, enacted in 2024, requires utilities to generate a
specified percentage of their electricity using coal-fired power plants
with CCS. SB 42 updates HB 200, enacted in 2020, which required the CCS
to be installed by 2030, which SB 42 extends to 2033. To comply with
those requirements, PacificCorp has stated in its 2023 IRP that it
intends to install CCS on two coal-fired units by 2028.\93\ Rocky
Mountain Power has also announced that it will explore a new carbon
capture technology at either its David Johnston plant or its Wyodak
plant.\94\ Another CCS project is also under development at the Dry
Fork Power Plant in Wyoming. Currently, a pilot project that will
capture 150 tons of CO<INF>2</INF> per day is under construction and is
scheduled to be completed in late 2024. Work has also begun on a full-
scale front end engineering design (FEED) study.
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\93\ PacifiCorp. (April 1, 2024). 2023 Integrated Resource Plan
Update. <a href="https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2023_IRP_Update.pdf">https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2023_IRP_Update.pdf</a>.
\94\ Rocky Mountain Power. (April 1, 2024). Rocky Mountain Power
and 8 Rivers to collaborate on proposed Wyoming carbon capture
project. Press release. <a href="https://www.rockymountainpower.net/about/newsroom/news-releases/rmp-proposed-wyoming-carbon-capture-project.html">https://www.rockymountainpower.net/about/newsroom/news-releases/rmp-proposed-wyoming-carbon-capture-project.html</a>.
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Like North Dakota, West Virginia does not have a carbon capture
mandate, but there are several carbon capture projects under
development in the state. One is a new, 2,000 MW natural gas combined
cycle plant being developed by Competitive Power Ventures that will
capture 90-95 percent of the CO<INF>2</INF> using GE turbine and carbon
capture technology.\95\ A second is an Omnis Fuel Technologies project
to convert the coal-fired Pleasants Power Station to run on
hydrogen.\96\ Omnis intends to use a pyrolysis-based process to convert
coal into hydrogen and graphite. Because the graphite is a usable,
solid form of carbon, no CO<INF>2</INF> sequestration will be required.
Therefore, unlike more traditional amine-based approaches, instead of
the captured CO<INF>2</INF> being a cost, the graphite product will
provide a revenue stream.\97\ Omnis states that the Pleasants Power
Project broke ground in August 2023 and will be online by 2025.
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\95\ Competitive Power Ventures (CPV). Shay Clean Energy Center.
<a href="https://www.cpv.com/our-projects/cpv-shay-energy-center/">https://www.cpv.com/our-projects/cpv-shay-energy-center/</a>.
\96\ The Associated Press (AP). (August 30, 2023). New owner
restarts West Virginia coal-fired power plant and intends to convert
it to hydrogen use. <a href="https://apnews.com/article/west-virginia-power-plant-coal-hydrogen-7b46798c8e3b093a8591f25f66340e8f">https://apnews.com/article/west-virginia-power-plant-coal-hydrogen-7b46798c8e3b093a8591f25f66340e8f</a>.
\97\ <a href="http://omnigenglobal.com">omnigenglobal.com</a>.
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It should be noted that Wyoming, West Virginia, and North Dakota
represented the first-, second-, and seventh-largest coal producers,
respectively, in the U.S. in 2022.\98\
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\98\ U.S. Energy Information Administration (EIA). (October
2023). Annual Coal Report 2022. <a href="https://www.eia.gov/coal/annual/pdf/acr.pdf">https://www.eia.gov/coal/annual/pdf/acr.pdf</a>.
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In addition to the coal-based CCS projects mentioned above,
multiple other projects are in advanced stages of development and/or
have completed FEED studies. For instance, Linde/BASF is installing a
10 MW pilot project on the Dallman Power Plant in Illinois. Based on
results from small scale pilot studies, techno economic analysis
indicates that the Linde/BASF process can provide a significant
reduction in capital costs compared to the NETL base case for a
supercritical pulverized coal plant with carbon capture.'' \99\
Multiple other FEED studies are either completed or under development,
putting those projects on a path to being able to be built and to
commence operation well before January 1, 2032.
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\99\ National Energy Technology Laboratory (NETL). Large Pilot
Carbon Capture Project Supported by NETL Breaks Ground in Illinois.
<a href="https://netl.doe.gov/node/12284">https://netl.doe.gov/node/12284</a>.
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In addition to the Competitive Power Partners project, there are
multiple post-combustion CCS retrofit projects in various stages of
development. In particular, NET Power is in advanced stages of
development on a 300 MW project in west Texas using the Allam-Fetvedt
cycle, which is being designed to achieve greater than 97 percent
CO<INF>2</INF> capture. In addition to working on this first project,
NET Power has indicated that it has an additional project under
development and is working with
[[Page 39815]]
suppliers to support additional future projects.\100\
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\100\ Net Power. (March 11, 2024). Q4 2023 Business Update and
Results. <a href="https://d1io3yog0oux5.cloudfront.net/_cde4aad258e20f5aec49abd8654499f8/netpower/db/3583/33195/pdf/Q4_2023+Earnings+Presentation_3.11.24.pdf">https://d1io3yog0oux5.cloudfront.net/_cde4aad258e20f5aec49abd8654499f8/netpower/db/3583/33195/pdf/Q4_2023+Earnings+Presentation_3.11.24.pdf</a>.
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In developing these final rules, the EPA reviewed the current state
and cost of CCS technology for use with both steam generating units and
stationary combustion turbines. This review is reflected in the
respective BSER discussions later in this preamble and is further
detailed in the accompanying RIA and final TSDs, GHG Mitigation
Measures for Steam Generating Units and GHG Mitigation Measures--Carbon
Capture and Storage for Combustion Turbines. These documents are
included in the rulemaking docket.
2. 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.'' 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 involves the
installation of new gas burners and related boiler modifications and
may involve the construction of a natural gas supply pipeline if one
does not already exist. In recent years, the cost of natural gas co-
firing has declined because the expected difference between coal and
gas prices has decreased and analysis supports lower capital costs for
modifying existing boilers to co-fire with natural gas, as discussed in
section VII.C.2.a of this preamble.
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 use of natural gas as a primary fuel or for startup.\101\
Based on hourly reported CO<INF>2</INF> 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.\102\ 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 it
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, many coal-fired
steam generating EGUs have also opted to switch entirely to providing
generation from the firing of natural gas. Since 2011, more than 80
coal-fired utility boilers have been converted to natural gas-fired
utility boilers.\103\
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\101\ U.S. Energy Information Administration (EIA). Form 923.
<a href="https://www.eia.gov/electricity/data/eia923/">https://www.eia.gov/electricity/data/eia923/</a>.
\102\ U.S. Environmental Protection Agency (EPA). ``Power Sector
Emissions Data.'' Washington, DC: Office of Atmospheric Protection,
Clean Air Markets Division. <a href="https://campd.epa.gov">https://campd.epa.gov</a>.
\103\ U.S. Energy Information Administration (EIA). (5 August
2020). Today in Energy. More than 100 coal-fired plants have been
replaced or converted to natural gas since 2011. <a href="https://www.eia.gov/todayinenergy/detail.php?id=44636">https://www.eia.gov/todayinenergy/detail.php?id=44636</a>.
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In developing these final actions, 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 final TSD, GHG
Mitigation Measures for Steam Generating Units. Both documents are
included in the rulemaking docket.
3. Efficient Generation
Highly efficient generation is the BSER technology upon which the
first phase standards of performance are based for certain new and
reconstructed stationary combustion turbine EGUs. This technology is
available for both simple cycle and combined cycle combustion turbines
and has been demonstrated--along with best operating and maintenance
practices--to reduce emissions. Generally, as the thermal efficiency of
a combustion turbine increases, less fuel is burned per gross MWh of
electricity produced and there is a corresponding decrease in
CO<INF>2</INF> and other air emissions.
For simple cycle turbines, manufacturers continue to improve the
efficiency by increasing firing temperature, increasing pressure
ratios, using intercooling on the air compressor, and adopting other
measures. Best operating practices for simple cycle 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, a highly
efficient combustion turbine engine is matched with a high-efficiency
HRSG. 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.
As discussed in section VIII.F.2.b of this preamble, efficient
generation technologies have been in use at facilities in the power
sector for decades and the levels of efficiency that the EPA is
finalizing in this rule have been achieved by many recently constructed
turbines. The efficiency improvements are incremental in nature and do
not change how the combustion turbine is operated or maintained and
present little incremental capital or compliance costs compared to
other types of technologies that may be considered for new and
reconstructed sources. In addition, more efficient designs have lower
fuel costs, which offset at least a portion of the increase in capital
costs. For additional discussion of this BSER technology, see the final
TSD, Efficient Generation in Combustion Turbines in the docket for this
rulemaking.
Efficiency improvements are also available for fossil fuel-fired
steam generating units, and as discussed further in section VII.D.4.a,
the more efficiently an EGU operates the less fuel it consumes, thereby
emitting lower amounts of CO<INF>2</INF> and other air pollutants per
MWh generated. Efficiency improvements for steam generating EGUs
include a variety of technology upgrades and operating practices that
may achieve CO<INF>2</INF> emission rate reductions of 0.1 to 5 percent
for individual EGUs. These reductions are small relative to the
reductions that are achievable from natural gas co-firing and from CCS.
Also, as efficiency increases, some facilities could increase their
utilization and therefore increase their CO<INF>2</INF> emissions (as
well as emissions of other air pollutants). This phenomenon is known as
the ``rebound effect.'' Because of this potential for perverse GHG
emission outcomes resulting from deployment of efficiency measures at
certain steam generating units, coupled with the relatively minor
overall GHG emission reductions that would be expected, the EPA is not
finalizing efficiency improvements as the BSER for any subcategory of
existing coal-fired steam generating units. Specific details of
efficiency measures are described in the final TSD, GHG Mitigation
Measures for Steam Generating Units, and an updated 2023 Sargent and
Lundy HRI report (Heat Rate Improvement Method Costs and Limitations
Memo), available in the docket.
[[Page 39816]]
D. The Electric Power Sector: Trends and Current Structure
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--especially coal-fired power plants--with more efficient
and lower-cost alternatives.
These developments have significant implications for the types of
controls that the EPA determined to qualify as the BSER for different
types of fossil fuel-fired EGUs. For example, power plant owners and
operators retired an average annual coal-fired EGU capacity of 10 GW
from 2015 to 2023, and coal-fired EGUs comprised 58 percent of all
retired capacity in 2023.\104\ While use of CCS promises significant
emissions reduction from fossil fuel-fired sources, it requires
substantial up-front capital expenditure. Therefore, it is not a
feasible or cost-reasonable emission reduction technology for units
that intend to cease operation before they would be able to amortize
its costs. Industry stakeholders requested that the EPA structure these
rules to avoid imposing costly control obligations on coal-fired power
plants that have announced plans to voluntarily cease operations, and
the EPA has determined the BSER in accordance with its understanding of
which coal-fired units will be able to feasibly and cost-effectively
deploy the BSER technologies. 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 finalizing as the BSER for these turbines.
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\104\ U.S. Energy Information Administration (EIA). (7 February
2023). Today in Energy. Coal and natural gas plants will account for
98 percent of U.S. capacity retirements in 2023. <a href="https://www.eia.gov/todayinenergy/detail.php?id=55439">https://www.eia.gov/todayinenergy/detail.php?id=55439</a>.
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2. Broad Trends Within the Power Sector
For more than a decade, the power sector has been experiencing
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;
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, as discussed
in section IV.D.3.b of this preamble and in the final TSD, Power Sector
Trends, the existing fleet of coal-fired EGUs continues to age and
become more costly to maintain and operate. At the same time, natural
gas prices have held relatively low due to increased supply, and
renewable costs have fallen rapidly with technological improvement and
growing scale. Natural gas surpassed coal in monthly net electricity
generation for the first time in April 2015, and since that time
natural gas has maintained its position as the primary fuel for base
load electricity generation, for peaking applications, and for
balancing renewable generation.\105\ In 2023, generation from natural
gas was more than 2.5 times as much as generation from coal.\106\
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, CCS and
associated infrastructure, advanced geothermal systems, and advanced
distributed energy resources (DER) as well as more traditional wind,
solar, and battery energy storage resources. The IRA provides numerous
tax and other incentives to directly spur deployment of clean energy
technologies. Particularly relevant to these final actions, the
incentives in the IRA,<SUP>107 108</SUP> which are discussed in detail
later in this section of the preamble, support the expansion of
technologies, such as CCS, that reduce GHG emissions from fossil-fired
EGUs.
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\105\ U.S. Energy Information Administration (EIA). Monthly
Energy Review and Short-Term Energy Outlook, March 2016. <a href="https://www.eia.gov/todayinenergy/detail.php?id=25392">https://www.eia.gov/todayinenergy/detail.php?id=25392</a>.
\106\ U.S. Energy Information Administration (EIA). Electric
Power Monthly, March 2024. <a href="https://www.eia.gov/electricity/monthly/current_month/march2024.pdf">https://www.eia.gov/electricity/monthly/current_month/march2024.pdf</a>.
\107\ U.S. Department of Energy (DOE). August 2022. The
Inflation Reduction Act Drives Significant Emissions Reductions and
Positions America to Reach Our Climate Goals. <a href="https://www.energy.gov/sites/default/files/2022-08/8.18%20InflationReductionAct_Factsheet_Final.pdf">https://www.energy.gov/sites/default/files/2022-08/8.18%20InflationReductionAct_Factsheet_Final.pdf</a>.
\108\ U.S. Department of Energy (DOE). August 2023. Investing in
American Energy. Significant Impacts of the Inflation Reduction Act
and Bipartisan Infrastructure Law on the U.S. Energy Economy and
Emissions Reductions. <a href="https://www.energy.gov/sites/default/files/2023-08/DOE%20OP%20Economy%20Wide%20Report_0.pdf">https://www.energy.gov/sites/default/files/2023-08/DOE%20OP%20Economy%20Wide%20Report_0.pdf</a>.
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The ongoing transition of the power sector is illustrated by a
comparison of data between 2007 and 2022. In 2007, the year of peak
coal generation, approximately 72 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 2022, fossil fuel net generation was approximately 60
percent, less than the share in 2007 despite electricity demand
remaining relatively flat over this same period. Moreover, the share of
generation supplied by coal-fired EGUs fell from 49 percent in 2007 to
19 percent in 2022 while the share supplied by natural gas-fired EGUs
rose from 22 to 39 percent during the same period. In absolute terms,
coal-fired generation declined by 59 percent while natural gas-fired
generation increased by 88 percent. This reflects both the increase in
natural gas capacity as well as an increase in the utilization of new
and existing natural gas-fired EGUs. The combination of wind and solar
generation also grew from 1 percent of the electric power sector mix in
2007 to 15 percent in 2022.\109\
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\109\ U.S. Energy Information Administration (EIA). Annual
Energy Review, table 8.2b Electricity net generation: electric power
sector. <a href="https://www.eia.gov/totalenergy/data/annual/">https://www.eia.gov/totalenergy/data/annual/</a>.
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Additional analysis of the utility power sector, including
projections of future power sector behavior and the impacts of these
final rules, is discussed in more detail in section XII of this
preamble, in the accompanying RIA, and in the final TSD, Power Sector
Trends. The latter two documents are available in the rulemaking
docket. Consistent with analyses done by other energy modelers, the
information
[[Page 39817]]
provided in the RIA and TSD demonstrates that the sector trend of
moving away from coal-fired generation is likely to continue, the share
from natural gas-fired generation is projected to decline eventually,
and the share of generation from non-emitting technologies is likely to
continue increasing. For instance, according to the Energy Information
Administration (EIA), the net change in solar capacity has been larger
than the net change in capacity for any other source of electricity for
every year since 2020. In 2024, EIA projects that the actual increase
in generation from solar will exceed every other source of generating
capacity. This is in part because of the large amounts of new solar
coming online in 2024 but is also due to the large amount of energy
storage coming online, which will help reduce renewable
curtailments.\110\ EIA also projects that in 2024, the U.S. will see
its largest year for installation of both solar and battery storage.
Specifically, EIA projects that 36.4 GW of solar will be added, nearly
doubling last year's record of 18.4 GW. Similarly, EIA projects 14.3 GW
of new energy storage. This would more than double last year's record
installation of 6.4 GW and nearly double the existing total capacity of
15.5 GW. This compares to only 2.5 GW of new natural gas turbine
capacity.\111\ The only year since 2013 when renewable generation did
not make up the majority of new generation capacity in the U.S. was
2018.\112\
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\110\ U.S. Energy Information Administration (EIA). Short Term
Energy Outlook, December 2023.
\111\ U.S. Energy Information Administration (EIA). (February
15, 2024). Today in Energy. Solar and Battery Storage to make up 81%
of new U.S. Electric-generating capacity in 2024. <a href="https://www.eia.gov/todayinenergy/detail.php?id=61424">https://www.eia.gov/todayinenergy/detail.php?id=61424</a>.
\112\ U.S. Energy Information Administration (EIA). Today in
Energy. Natural gas and renewables make up most of 2018 electric
capacity additions. <a href="https://www.eia.gov/todayinenergy/detail.php?id=36092">https://www.eia.gov/todayinenergy/detail.php?id=36092</a>.
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3. Coal-Fired Generation: Historical Trends and Current Structure
a. Historical 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.\113\
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.\114\
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 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.\115\ With no
new coal-fired steam generating units larger than 25 MW commencing
construction in the past decade--and with the EPA unaware of any plans
being approved 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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\113\ U.S. Energy Information Administration (EIA). Today in
Energy. Natural gas expected to surpass coal in mix of fuel used for
U.S. power generation in 2016. March 2016. <a href="https://www.eia.gov/todayinenergy/detail.php?id=25392">https://www.eia.gov/todayinenergy/detail.php?id=25392</a>.
\114\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form EIA-860M, Inventory of Operating
Generators and Inventory of Retired Generators, March 2022. <a href="https://www.eia.gov/electricity/data/eia860m/">https://www.eia.gov/electricity/data/eia860m/</a>.
\115\ U.S. Energy Information Administration (EIA). Today in
Energy. More than 100 coal-fired plants have been replaced or
converted to natural gas since 2011. August 2020. <a href="https://www.eia.gov/todayinenergy/detail.php?id=44636">https://www.eia.gov/todayinenergy/detail.php?id=44636</a>.
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Since 2007, the power sector's total installed net summer capacity
\116\ has increased by 167 GW (17 percent) while coal-fired steam
generating unit capacity has declined by 123 GW.\117\ This reduction in
coal-fired steam generating unit capacity was offset by a net increase
in total installed wind capacity of 125 GW, net natural gas capacity of
110 GW, and a net increase in utility-scale solar capacity of 71 GW
during the same period. Additionally, significant amounts (40 GW) of
DER solar were also added. At least half of these changes were in the
most recent 7 years of this period. From 2015 to 2022, coal capacity
was reduced by 90 GW and this reduction in capacity was offset by a net
increase of 69 GW of wind capacity, 63 GW of natural gas capacity, and
59 GW of utility-scale solar capacity. Additionally, a net summer
capacity of 30 GW of DER solar were added from 2015 to 2022.
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\116\ 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).
\117\ U.S. Energy Information Administration (EIA). Electric
Power Annuals 2010 (Tables 1.1.A and 1.1.B) and 2022 (Tables 4.2.A
and 4.2.B).
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b. Current Structure of Coal-Fired Generation
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.\118\ Moreover, average annual capacity factors for
coal-fired steam generating units have declined from 74 to 50 percent
since 2007.\119\ These declining capacity factors indicate that a
larger share of units are operating in non-base load fashion largely
because they are no longer cost-competitive in many hours of the year.
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\118\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v7. December 2023. <a href="https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs">https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs</a>.
\119\ 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,\120\ 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 2022 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.\121\ To
further illustrate this trend, the existing coal-fired steam generating
units older than 40 years represent 71 percent (129 GW) \122\ of the
total remaining capacity. In fact, more than half (100 GW) of the coal-
fired steam generating units still operating have already announced
retirement dates prior to 2039 or conversion to gas-fired units by the
[[Page 39818]]
same year.\123\ As discussed later in this section, projections
anticipate that this trend will continue.
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\120\ U.S. Energy Information Administration (EIA). U.S. coal
plant retirements linked to plants with higher operating costs.
December 2019. <a href="https://www.eia.gov/todayinenergy/detail.php?id=42155">https://www.eia.gov/todayinenergy/detail.php?id=42155</a>.
\121\ 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.
\122\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form-860M, Inventory of Operating Generators
and Inventory of Retired Generators. August 2022. <a href="https://www.eia.gov/electricity/data/eia860m/">https://www.eia.gov/electricity/data/eia860m/</a>.
\123\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v6. October 2022. <a href="https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs">https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs</a>.
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The reduction in coal-fired generation by electric utilities is
also evident in data for annual U.S. coal production, which reflects
reductions in international demand as well. In 2008, annual coal
production peaked at nearly 1,172 million short tons (MMst) followed by
sharp declines in 2015 and 2020.\124\ In 2015, less than 900 MMst were
produced, and in 2020, the total dropped to 535 MMst, the lowest output
since 1965. Following the pandemic, in 2022, annual coal production had
increased to 594 MMst. For additional analysis of the coal-fired steam
generation fleet, see the final TSD, Power Sector Trends included in
the docket for this rulemaking.
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\124\ U.S. Energy Information Administration (EIA). (October
2023). Annual Coal Report 2022. <a href="https://www.eia.gov/coal/annual/pdf/acr.pdf">https://www.eia.gov/coal/annual/pdf/acr.pdf</a>.
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Notwithstanding these trends, in 2022, coal-fired energy sources
were still responsible for 50 percent of CO<INF>2</INF> emissions from
the electric power sector.\125\
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\125\ U.S. Energy Information Administration (EIA). U.S.
CO<INF>2</INF> emissions from energy consumption by source and
sector, 2022. <a href="https://www.eia.gov/totalenergy/data/monthly/pdf/flow/CO2_emissions_2022.pdf">https://www.eia.gov/totalenergy/data/monthly/pdf/flow/CO2_emissions_2022.pdf</a>.
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4. Natural Gas-Fired Generation: Historical Trends and Current
Structure
a. Historical Trends in Natural Gas-Fired Generation
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
variable 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 (about 35 GW per year). Of this total,
approximately 147 GW (70 percent) were combined cycle capacity and 65
GW were simple cycle capacity.\126\ From 2007 to 2022, more than 132 GW
of capacity were constructed and approximately 77 percent of that total
were combined cycle EGUs. This figure represents an average of almost
8.8 GW of new combustion turbine generation capacity per year. In 2022,
the net summer capacity of combustion turbine EGUs totaled 419 GW, with
289 GW being combined cycle generation and 130 GW being simple cycle
generation.
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\126\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form EIA-860M, Inventory of Operating
Generators and Inventory of Retired Generators, July 2022. <a href="https://www.eia.gov/electricity/data/eia860m/">https://www.eia.gov/electricity/data/eia860m/</a>.
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This trend away from electricity generation using coal-fired EGUs
to natural gas-fired turbine EGUs is also reflected in comparisons of
annual capacity factors, sizes, and ages of affected EGUs. For example,
the average annual capacity factors for natural gas-fired units
increased from 28 to 38 percent between 2010 and 2022. 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.\127\
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\127\ National Electric Energy Data System (NEEDS) v.6.
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b. Current Structure of 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.
Over 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. As the production of natural gas has
increased, the annual average price has declined during the same
period, leading to more natural gas-fired combustion turbines.\128\
Natural gas net generation increased 181 percent in the past two
decades, from 601 thousand gigawatt-hours (GWh) in 2000 to 1,687
thousand GWh in 2022. For additional analysis of natural gas-fired
generation, see the final TSD, Power Sector Trends included in the
docket for this rulemaking.
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\128\ U.S. Energy Information Administration (EIA). Natural Gas
Annual, September 2021. <a href="https://www.eia.gov/energyexplained/natural-gas/prices.php">https://www.eia.gov/energyexplained/natural-gas/prices.php</a>.
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E. The Legislative, Market, and State Law Context
1. Recent Legislation Impacting the Power Sector
On November 15, 2021, President Biden signed the IIJA \129\ (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
\130\ that will impact the utility power sector include more than $20
billion to build and upgrade the nation's electric grid, up to $6
billion in financial support for existing nuclear reactors that are at
risk of closing, and more than $700 million for upgrades to the
existing hydroelectric fleet. The IIJA established the Carbon Dioxide
Transportation Infrastructure Finance and Innovation Program to provide
flexible Federal loans and grants for building CO<INF>2</INF> pipelines
designed with excess capacity, enabling integrated carbon capture and
geologic storage. The IIJA also allocated $21.5 billion to fund new
programs to support the development, demonstration, and deployment of
clean energy technologies, such as $8 billion for the development of
regional clean hydrogen hubs and $7 billion for the development of
carbon management technologies, including regional direct air capture
hubs, carbon capture large-scale pilot projects for development of
transformational technologies, and carbon capture commercial-scale
demonstration projects to improve efficiency and effectiveness. Other
clean energy technologies with IIJA and IRA funding include industrial
demonstrations, geologic sequestration, grid-scale energy storage, and
advanced nuclear reactors.
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\129\ <a href="https://www.congress.gov/bill/117th-congress/house-bill/3684/text">https://www.congress.gov/bill/117th-congress/house-bill/3684/text</a>.
\130\ <a href="https://www.whitehouse.gov/wp-content/uploads/2022/05/BUILDING-A-BETTER-AMERICA-V2.pdf">https://www.whitehouse.gov/wp-content/uploads/2022/05/BUILDING-A-BETTER-AMERICA-V2.pdf</a>.
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The IRA, which President Biden signed on August 16, 2022,\131\ has
the potential for even greater impacts on the electric power sector.
Energy Security and Climate Change programs in the
[[Page 39819]]
IRA covering grant funding and tax incentives provide significant
investments in low and 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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\131\ <a href="https://www.congress.gov/bill/117th-congress/house-bill/5376/text">https://www.congress.gov/bill/117th-congress/house-bill/5376/text</a>.
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The IRA's provisions also demonstrate an intent to support
development and deployment of low-GHG emitting technologies in the
power sector through a broad array of additional tax credits, loan
guarantees, and public investment programs. Particularly relevant for
these final actions, these provisions are aimed at reducing emissions
of GHGs from new and existing generating assets, with tax credits for
CCUS and clean hydrogen production, providing a pathway for the use of
coal and natural gas as part of a low-GHG electricity grid.
To assist states and utilities in their decarbonizing efforts, and
most germane to these final actions, the IRA increased the tax credit
incentives for capturing and storing CO<INF>2</INF>, including from
industrial sources, coal-fired steam generating units, and natural gas-
fired stationary combustion turbines. The increase in credit values,
found in section 13104 (which revises IRC section 45Q), is 70 percent,
equaling $85/metric ton for CO<INF>2</INF> captured and securely stored
in geologic formations and $60/metric ton for CO<INF>2</INF> captured
and utilized or securely stored incidentally in conjunction with
EOR.\132\ The CCUS incentives include 12 years of credits that can be
claimed at the higher credit value beginning in 2023 for qualifying
projects. These incentives will significantly cut costs and are
expected to accelerate the adoption of CCS in the utility power and
other industrial sectors. Specifically for the power sector, the IRA
requires that a qualifying carbon capture facility have a
CO<INF>2</INF> capture design capacity of not less than 75 percent of
the baseline CO<INF>2</INF> production of the unit and that
construction must begin before January 1, 2033. Tax credits under IRC
section 45Q can be combined with some 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.\133\ The magnitude of this
incentive is driving investment and announcements, evidenced by the
increased number of permit applications for geologic
sequestration.\134\
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\132\ 26 U.S.C. 45Q. Note, qualified facilities must meet
prevailing wage and apprenticeship requirements to be eligible for
the full value of the tax credit.
\133\ Global CCS Institute. (2019). The LCFS and CCS Protocol:
An Overview for Policymakers and Project Developers. Policy report.
<a href="https://www.globalccsinstitute.com/wp-content/uploads/2019/05/LCFS-and-CCS-Protocol_digital_version-2.pdf">https://www.globalccsinstitute.com/wp-content/uploads/2019/05/LCFS-and-CCS-Protocol_digital_version-2.pdf</a>.
\134\ EPA. (2024). Current Class VI Projects under Review at
EPA. <a href="https://www.epa.gov/uic/current-class-vi-projects-under-review-epa">https://www.epa.gov/uic/current-class-vi-projects-under-review-epa</a>.
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The new provisions in section 13204 (IRC section 45V) codify
production tax credits for `clean hydrogen' as defined in the
provision. The value of the credits earned by a project is tiered (four
different tiers) and depends on the estimated GHG emissions of the
hydrogen production process as defined in the statute. The credits
range from $3/kg H<INF>2</INF> for less than 0.45 kilograms of
CO<INF>2</INF>-equivalent emitted per kilogram of low-GHG hydrogen
produced (kg CO<INF>2</INF>e/kg H<INF>2</INF>) down to $0.6/kg
H<INF>2</INF> for 2.5 to 4.0 kg CO<INF>2</INF>e/kg H<INF>2</INF>
(assuming wage and apprenticeship requirements are met). Projects with
production related GHG emissions greater than 4.0 kg CO<INF>2</INF>e/kg
H<INF>2</INF> are not eligible. Future costs for clean hydrogen
produced using renewable energy are anticipated to through 2030 due to
these tax incentives and concurrent scaling up of manufacturing and
deployment of clean hydrogen production facilities.
Both IRC section 45Q and IRC section 45V are eligible for
additional provisions that increase the value and usability of the
credits. Certain tax-exempt entities, such as electric co-operatives,
may elect direct payment 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 IRC section 45Q or 45V credits for 5 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.
In addition to provisions such as 45Q that allow for the use of
fossil-generating assets in a low-GHG future, the IRA also includes
significant incentives to deploy clean energy generation. For instance,
the IRA provides an additional 10 percent in production tax credit
(PTC) and investment tax credit (ITC) bonuses for clean energy projects
located in energy communities with historic employment and tax bases
related to fossil fuels.\135\ The IRA's Energy Infrastructure
Reinvestment Program also provides $250 billion for the DOE to finance
loan guarantees that can be used to reduce both the cost of retiring
existing fossil assets and of replacement generation for those assets,
including updating operating energy infrastructure with emissions
control technologies.\136\ As a further example, the Empowering Rural
America (New ERA) Program provides rural electric cooperatives with
funds that can be used for a variety of purposes, including ``funding
for renewable and zero emissions energy systems that eliminate aging,
obsolete or expensive infrastructure'' or that allow rural cooperatives
to ``change [their] purchased-power mixes to support cleaner
portfolios, manage stranded assets and boost [the] transition to clean
energy.'' \137\ The $9.7 billion New ERA program represents the single
largest investment in rural energy systems since the Rural
Electrification Act of 1936.\138\
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\135\ U.S. Department of the Treasury. (April 4, 2023). Treasury
Releases Guidance to Drive Investment to Coal Communities. Press
release. <a href="https://home.treasury.gov/news/press-releases/jy1383">https://home.treasury.gov/news/press-releases/jy1383</a>.
\136\ Fong, C., Posner, D., Varadarajan, U. (February 16, 2024).
The Energy Infrastructure Reinvestment Program: Federal financing
for an equitable, clean economy. Case studies from Missouri and
Iowa. Rocky Mountain Institute (RMI). <a href="https://rmi.org/the-energy-infrastructure-reinvestment-program-federal-financing-for-an-equitable-clean-economy/">https://rmi.org/the-energy-infrastructure-reinvestment-program-federal-financing-for-an-equitable-clean-economy/</a>.
\137\ U.S. Department of Agriculture (USDA). Empowering Rural
America New ERA Program. <a href="https://www.rd.usda.gov/programs-services/electric-programs/empowering-rural-america-new-era-program">https://www.rd.usda.gov/programs-services/electric-programs/empowering-rural-america-new-era-program</a>.
\138\ Rocky Mountain Institute (RMI). (October 4, 2023). USDA
$9.7B Rural Community Clean Energy Program Receives 150+ Letters of
Interest. Press release. <a href="https://rmi.org/press-release/usda-9-7b-rural-community-clean-energy-program-receives-150-letters-of-interest/">https://rmi.org/press-release/usda-9-7b-rural-community-clean-energy-program-receives-150-letters-of-interest/</a>.
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On September 12, 2023, the EPA released a report assessing the
impact of the IRA on the power sector. Modeling results showed that
economy-wide CO<INF>2</INF> emissions are lower under the IRA. The
[[Page 39820]]
results from the EPA's analysis of an array of multi-sector and
electric sector modeling efforts show that a wide range of emissions
reductions are possible. The IRA spurs CO<INF>2</INF> emissions
reductions from the electric power sector of 49 to 83 percent below
2005 levels in 2030. This finding reflects diversity in how the models
represent the IRA, the assumptions the models use, and fundamental
differences in model structures.\139\
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\139\ U.S. Environmental Protection Agency (EPA). (September
2023). Electricity Sector Emissions Impacts of the Inflation
Reduction Act. <a href="https://www.epa.gov/system/files/documents/2023-09/Electricity_Emissions_Impacts_Inflation_Reduction_Act_Report_EPA-FINAL.pdf">https://www.epa.gov/system/files/documents/2023-09/Electricity_Emissions_Impacts_Inflation_Reduction_Act_Report_EPA-FINAL.pdf</a>.
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In determining the CAA section 111 emission limitations that are
included in these final actions, the EPA did not consider many of the
technologies that receive investment under recent Federal legislation.
The EPA's determination of the BSER focused on ``measures that improve
the pollution performance of individual sources,'' \140\ not generation
technologies that entities could employ as alternatives to fossil fuel-
fired EGUs. However, these overarching incentives and policies are
important context for this rulemaking and influence where control
technologies can be feasibly and cost-reasonably deployed, as well as
how owners and operators of EGUs may respond to the requirements of
these final actions.
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\140\ West Virginia v. EPA, 597 U.S. at 734.
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2. Commitments by Utilities To Reduce GHG Emissions
Integrated resource plans (IRPs) are filed by public utilities and
demonstrate how utilities plan to meet future forecasted energy demand
while ensuring reliable and cost-effective service. In developing these
rules, the EPA reviewed filed IRPs of companies that have publicly
committed to reducing their GHGs. These IRPs demonstrate a range of
strategies that public utilities are planning to adopt to reduce their
GHGs, independent of these final actions. These strategies include
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, and
reducing GHGs from their natural gas-fired assets through a combination
of CCS and reduced utilization. To affirm these findings, according to
EIA, as of 2022 there are no new coal-fired EGUs in development. This
section highlights recent actions and announced plans of many utilities
across the industry to reduce GHGs from their fleets. Indeed, 50 power
producers that are members of the Edison Electric Institute (EEI) have
announced CO<INF>2</INF> reduction goals, two-thirds of which include
net-zero carbon emissions by 2050.\141\ The members of the Energy
Strategies Coalition, a group of companies that operate and manage
electricity generation facilities, as well as electricity and natural
gas transmission and distribution systems, likewise are focused on
investments to reduce carbon dioxide emissions from the electricity
sector.\142\ This trend is not unique. Smaller utilities, rural
electric cooperatives, and municipal entities are also contributing to
these changes.
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\141\ See Comments of Edison Electric Institute to EPA's Pre-
Proposal Docket on Greenhouse Gas Regulations for Fossil Fuel-fired
Power Plants, Document ID No. EPA-HQ-OAR-2022-0723-0024, 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.'').
\142\ Energy Strategy Coalition Comments on EPA's 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, Document ID No. EPA-HQ-OAR-2023-
0072-0672, August 14, 2023.
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Many electric utilities have publicly announced near- and long-term
emission reduction commitments independent of these final actions. The
Smart Electric Power Alliance demonstrates that the geographic
footprint of commitments for 100 percent renewable, net-zero, or other
carbon emission reductions by 2050 made by utilities, their parent
companies, or in response to a state clean energy requirement, covers
portions of 47 states and includes 80 percent of U.S. customer
accounts.\143\ According to this same source, 341 utilities in 26
states have similar commitments by 2040. Additional detail about
emission reduction commitments from major utilities is provided in
section 2.2 of the RIA and in the final TSD, Power Sector Trends.
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\143\ Smart Electric Power Alliance Utility Carbon Tracker.
<a href="https://sepapower.org/utility-transformation-challenge/utility-carbon-reduction-tracker/">https://sepapower.org/utility-transformation-challenge/utility-carbon-reduction-tracker/</a>.
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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. As of mid-2023, 25 states had made
commitments to reduce economy-wide GHG emissions consistent with the
goals of the Paris Agreement, including reducing GHG emissions by 50 to
52 percent by 2030.<SUP>144 145 146</SUP> These actions include
legislation to decarbonize state power systems as well as commitments
that require utilities to expand renewable and clean energy production
through the adoption of renewable portfolio standards (RPS) and clean
energy standards (CES).
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\144\ Cao, L., Brindle., T., Schneer, K., and DeGolia, A.
(December 2023). Turning Climate Commitments into Results:
Evaluating Updated 2023 Projections vs. State Climate Targets.
Environmental Defense Fund (EDF). <a href="https://www.edf.org/sites/default/files/2023-11/EDF-State-Emissions-Gap-December-2023.pdf">https://www.edf.org/sites/default/files/2023-11/EDF-State-Emissions-Gap-December-2023.pdf</a>.
\145\ United Nations Framework Convention on Climate Change.
What is the Paris Agreement? <a href="https://unfccc.int/process-and-meetings/the-paris-agreement">https://unfccc.int/process-and-meetings/the-pari
[…truncated; see source link]Indexed from Federal Register on May 9, 2024.
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