Federal Register, Volume 89 Issue 91 (Thursday, May 9, 2024)
[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 [www.gpo.gov]
[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 https://www.regulations.gov 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 https://www.regulations.gov.
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:
[email protected].
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
CO2 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 CO2e 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
NOX nitrogen oxides
NSPS new source performance standards
NSR New Source Review
PM particulate matter
PM2.5 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\ https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions.
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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\ https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions.
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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 (CO2) 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. https://www.eia.gov/electricity/annual/html/epa_03_01_a.html.
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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
CO2. 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\ https://www.congress.gov/bill/117th-congress/house-bill/3684.
\7\ https://www.congress.gov/bill/117th-congress/house-bill/4346.
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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 CO2/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 CO2/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 CO2/
MMBtu for oil-fired sources and a presumptive standard of 130 lb
CO2/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 (CO2 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). https://www.epa.gov/power-sector/electric-reliability-mou.
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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 CO2 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 (NOX), sulfur dioxide (SO2), and fine
particulate matter (PM2.5), 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 PM2.5 concentration will
decline substantially relative to today's levels. Relative to these low
baseline levels, ozone and PM2.5 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 PM2.5 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 PM2.5
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 NOX, 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, https://www.epa.gov/tribal/tribes-approved-treatment-state-tas, 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 https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power. 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--CO2,
methane (CH4), nitrous oxide (N2O), HFCs,
perfluorocarbons (PFCs), and sulfur hexafluoride (SF6)--
``may reasonably be anticipated to endanger the public health and
welfare of current and future generations'' (74 FR 66523, December 15,
2009). 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.19 20 21 22 23 24 25 26 27 28 29 30 31
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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.
https://dio.org/10.17226/21852.
\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. https://doi.org/10.17226/24651.
\27\ National Academies of Sciences, Engineering, and Medicine.
2019. Climate Change and Ecosystems. Washington, DC: The National
Academies Press. https://doi.org/10.17226/25504.
\28\ Blunden, J. and T. Boyer, Eds., 2022: ``State of the
Climate in 2021.'' Bull. Amer. Meteor. Soc., 103 (8), Si-S465,
https://doi.org/10.1175/2022BAMSStateoftheClimate.1.
\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. https://doi.org/10.7930/NCA5.2023.CH1.
\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, CO2,
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
CO2 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\ https://gml.noaa.gov/webdata/ccgg/trends/co2/co2_annmean_mlo.txt.
\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 https://www.ncei.noaa.gov/bams-state-of-climate.
\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 CO2 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 CO2 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 CO2 concentration data from
https://gml.noaa.gov/webdata/ccgg/trends/co2/co2_annmean_mlo.txt,
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. https://www.nifc.gov/fireInfo/fireInfo_stats_totalFires.html.
\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. https://doi.org/10.7930/NCA5.2023.CH1.
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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, https://doi.org/10.5194/esd-14-1015-2023. (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, https://www.epa.gov/cira/fredi.
Documentation has been subject to both a public review comment
period and an independent expert peer review, following EPA peer-
review guidelines.
\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 CO2
stimulate plant growth (which can be positive in the case of beneficial
species, but negative in terms of weeds and invasive species, and can
also lead to a reduction in plant micronutrients \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. https://health2016.globalchange.gov/low/ClimateHealth2016_07_Food_small.pdf.
\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 https://www.nerc.com/AboutNERC/keyplayers/PublishingImages/NERC%20Interconnections.pdf.
\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
(H2), which can be combusted in a combined cycle system to
generate power. The heat created by these technologies produces high-
pressure steam that is released to rotate turbines, which, in turn,
spin an electric generator.
Stationary combustion turbine EGUs (most commonly natural gas-
fired) use one of two configurations: combined cycle or simple cycle
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 CO2,
CH4, N2O, HFCs, PFCs, and SF6. Of
these, CO2 is the most abundant, accounting for 80 percent
of all GHGs present in the atmosphere. This abundance of CO2
is largely due to the combustion of fossil fuels by the transportation,
electricity, and industrial sectors.\65\
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\65\ U.S. Environmental Protection Agency (EPA). Overview of
greenhouse gas emissions. July 2021. https://www.epa.gov/ghgemissions/overview-greenhouse-gases#carbon-dioxide.
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The amount of CO2 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 CO2 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 CO2 emitted
per million British thermal units of energy produced when combusted,
natural gas is the lowest compared to other fossil fuels at 117 lb
CO2/MMBtu.66 67 The average for coal is 216 lb
CO2/MMBtu, but varies between 206 to 229 lb CO2/
MMBtu by type (e.g., anthracite, lignite, subbituminous, and
bituminous).\68\ The value for petroleum products such as diesel fuel
and heating oil is 161 lb CO2/MMBtu.
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\66\ Natural gas is primarily CH4, which has a higher
hydrogen to carbon atomic ratio, relative to other fuels, and thus,
produces the least CO2 per unit of heat released. In
addition to a lower CO2 emission rate on a lb/MMBtu
basis, natural gas is generally converted to electricity more
efficiently than coal. According to EIA, the 2020 emissions rate for
coal and natural gas were 2.23 lb CO2/kWh and 0.91 lb
CO2/kWh, respectively. www.eia.gov/tools/faqs/faq.php?id=74&t=11.
\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. https://www.eia.gov/environment/emissions/co2_vol_mass.php.
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The EPA prepares the official U.S. Inventory of Greenhouse Gas
Emissions and Sinks \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 CO2 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
CO2 equivalent (MMT CO2e).\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 CO2e followed by the power sector (25.0 percent)
with 1,584 MMT CO2e. In fact, GHG emissions from the power
sector were higher than the GHG emissions from all other industrial
sectors combined (1,487 MMT CO2e). Specifically, the power
sector's emissions were far more than petroleum and natural gas systems
\72\ at 301 MMT CO2e; chemicals (71 MMT CO2e);
minerals (64 MMT CO2e); coal mining (53 MMT
CO2e); and metals (48 MMT CO2e). The agriculture
(636 MMT CO2e), commercial (439 MMT CO2e), and
residential (366 MMT CO2e) sectors combined to emit 1,441
MMT CO2e.
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\69\ U.S. Environmental Protection Agency (EPA). Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2021. https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-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. https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks.
\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
CO2. 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 CO2e, with the top emitter
(James H. Miller power plant in Alabama) reporting approximately 22 MMT
of CO2e with each of its four EGUs emitting between 5 MMT
and 6 MMT CO2e 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
CO2e (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 CO2e (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). https://ghgdata.epa.gov/ghgp/main.do#.
\74\ U.S. Energy Information Administration (EIA). Preliminary
Monthly Electric Generator Inventory, Form EIA-860M, November 2023.
https://www.eia.gov/electricity/data/eia860m/.
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Overall, CO2 emissions from the power sector have
declined by 36 percent since 2005 (when the power sector reached annual
emissions of 2,400 MMT CO2, its historical peak to
date).\75\ The reduction in CO2 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, CO2 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 CO2
emissions from coal-fired EGUs were below 1,000 MMT. In 2020, emissions
of CO2 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, CO2 emissions from natural
gas-fired generation have almost doubled since 2005, increasing from
319 MMT to 613 MMT in 2021, and CO2 emissions from petroleum
products (i.e., distillate fuel oil, petroleum coke, and residual fuel
oil) declined from 98 MMT in 2005 to 18 MMT in 2021.
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\75\ U.S. Environmental Protection Agency (EPA). Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2020. https://cfpub.epa.gov/ghgdata/inventoryexplorer/#electricitygeneration/entiresector/allgas/category/all.
\76\ U.S. Energy Information Administration (EIA). Monthly
Energy Review, table 11.6. September 2022. https://www.eia.gov/totalenergy/data/monthly/pdf/sec11.pdf.
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[[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 CO2 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 CO2
emissions from sources covered by the CPP had fallen to 1,540 MMT by
the end of 2021, a nearly 36 percent reduction below 2005 levels. The
power sector achieved a deeper level of reductions than forecast under
the CPP and approximately a decade ahead of time. By the end of 2015,
several months after the CPP was finalized, those sources already had
achieved CO2 emission levels of 1,900 MMT, or approximately
21 percent below 2005 levels. However, progress in emission reductions
is not uniform across all states and 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
CO2 in the U.S., and, despite the emission reductions since
2005, current CO2 levels continue to endanger human health
and welfare. Further, as sources in other sectors of the economy turn
to electrification to decarbonize, future CO2 reductions
from fossil fuel-fired EGUs have the potential to take on added
significance and increased benefits.
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\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 CO2 from fossil fuel-
fired EGUs. CCS has three major components: CO2 capture,
transportation, and sequestration/storage. Solvent-based CO2
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 CO2 pipelines have been constructed
and securely operated in the U.S. for decades.\79\ And tens of millions
of tons of CO2 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 CO2 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
CO2.'' 81 82
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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. https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
\80\ GHGRP US EPA. https://www.epa.gov/ghgreporting/supply-underground-injection-and-geologic-sequestration-carbon-dioxide.
\81\ American Petroleum Institute (API). (2024). Carbon Capture
and Storage: A Low-Carbon Solution to Economy-Wide Greenhouse Gas
Emissions Reductions. https://www.api.org/news-policy-and-issues/carbon-capture-storage.
\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 https://www.congress.gov/117/meeting/house/114185/witnesses/HHRG-117-GO00-Wstate-WatkinsG-20211028.pdf and https://corporate.exxonmobil.com/news/news-releases/2022/0225_exxonmobil-to-expand-carbon-capture-and-storage-at-labarge-wyoming-facility.
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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
CO2.'' 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. https://www.reuters.com/article/idUSTRE55O6TS/.
\84\ Alstom Power. (June 14, 2011). Alstom Power study
demonstrates carbon capture and storage (CCS) is efficient and cost
competitive. https://www.alstom.com/press-releases-news/2011/6/press-releases-3-26.
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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. https://www.indianamichiganpower.com/company/news/view?releaseID=1206.
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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. https://liftoff.energy.gov/wp-content/uploads/2024/02/20230424-Liftoff-Carbon-Management-vPUB_update4.pdf.
\87\ Congressional Budget Office (CBO). (December 13, 2023).
Carbon Capture and Storage in the United States. https://www.cbo.gov/publication/59345.
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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 CO2
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 CO2
sequestration under IRC section 45Q.
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\88\ Global CCS Institute. (March 2021). Technology Readiness
and Costs of CCS. https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-and-Costs-for-CCS-2021-1.pdf.
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With this combination of polices, and the advances related to
CO2 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. https://www.thedickinsonpress.com/business/gov-doug-burgum-calls-for-north-dakota-to-be-carbon-neutral-by-2030.
\90\ Tanaka, H. et al. Advanced KM CDR Process using New
Solvent. 14th International Conference on Greenhouse Gas Control
Technologies, GHGT-14. https://www.cfaenm.org/wp-content/uploads/2019/03/GHGT14_manuscript_20180913Clean-version.pdf.
\91\ Minot Daily News. (April 8, 2024). 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/.
\92\ Rainbow Energy Center. (ND). Carbon Capture. https://rainbowenergycenter.com/what-we-do/carbon-capture/.
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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 CO2 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. https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2023_IRP_Update.pdf.
\94\ Rocky Mountain Power. (April 1, 2024). Rocky Mountain Power
and 8 Rivers to collaborate on proposed Wyoming carbon capture
project. Press release. https://www.rockymountainpower.net/about/newsroom/news-releases/rmp-proposed-wyoming-carbon-capture-project.html.
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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 CO2 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 CO2 sequestration will be required.
Therefore, unlike more traditional amine-based approaches, instead of
the captured CO2 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.
https://www.cpv.com/our-projects/cpv-shay-energy-center/.
\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. https://apnews.com/article/west-virginia-power-plant-coal-hydrogen-7b46798c8e3b093a8591f25f66340e8f.
\97\ omnigenglobal.com.
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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. https://www.eia.gov/coal/annual/pdf/acr.pdf.
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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.
https://netl.doe.gov/node/12284.
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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
CO2 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. https://d1io3yog0oux5.cloudfront.net/_cde4aad258e20f5aec49abd8654499f8/netpower/db/3583/33195/pdf/Q4_2023+Earnings+Presentation_3.11.24.pdf.
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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 CO2 emission rates from the start
of 2015 through the end of 2020, 29 coal-fired steam generating units
co-fired with natural gas at rates at or above 60 percent of capacity
on an hourly basis.\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.
https://www.eia.gov/electricity/data/eia923/.
\102\ U.S. Environmental Protection Agency (EPA). ``Power Sector
Emissions Data.'' Washington, DC: Office of Atmospheric Protection,
Clean Air Markets Division. https://campd.epa.gov.
\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. https://www.eia.gov/todayinenergy/detail.php?id=44636.
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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
CO2 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 CO2 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 CO2 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 CO2 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. https://www.eia.gov/todayinenergy/detail.php?id=55439.
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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,107 108 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. https://www.eia.gov/todayinenergy/detail.php?id=25392.
\106\ U.S. Energy Information Administration (EIA). Electric
Power Monthly, March 2024. https://www.eia.gov/electricity/monthly/current_month/march2024.pdf.
\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. https://www.energy.gov/sites/default/files/2022-08/8.18%20InflationReductionAct_Factsheet_Final.pdf.
\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. https://www.energy.gov/sites/default/files/2023-08/DOE%20OP%20Economy%20Wide%20Report_0.pdf.
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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. https://www.eia.gov/totalenergy/data/annual/.
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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. https://www.eia.gov/todayinenergy/detail.php?id=61424.
\112\ U.S. Energy Information Administration (EIA). Today in
Energy. Natural gas and renewables make up most of 2018 electric
capacity additions. https://www.eia.gov/todayinenergy/detail.php?id=36092.
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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. https://www.eia.gov/todayinenergy/detail.php?id=25392.
\114\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form EIA-860M, Inventory of Operating
Generators and Inventory of Retired Generators, March 2022. https://www.eia.gov/electricity/data/eia860m/.
\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. https://www.eia.gov/todayinenergy/detail.php?id=44636.
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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. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
\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. https://www.eia.gov/todayinenergy/detail.php?id=42155.
\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. https://www.eia.gov/electricity/data/eia860m/.
\123\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v6. October 2022. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
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The reduction in coal-fired generation by electric utilities is
also evident in data for annual U.S. coal production, which reflects
reductions in international demand as well. In 2008, annual coal
production peaked at nearly 1,172 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. https://www.eia.gov/coal/annual/pdf/acr.pdf.
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Notwithstanding these trends, in 2022, coal-fired energy sources
were still responsible for 50 percent of CO2 emissions from
the electric power sector.\125\
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\125\ U.S. Energy Information Administration (EIA). U.S.
CO2 emissions from energy consumption by source and
sector, 2022. https://www.eia.gov/totalenergy/data/monthly/pdf/flow/CO2_emissions_2022.pdf.
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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. https://www.eia.gov/electricity/data/eia860m/.
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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. https://www.eia.gov/energyexplained/natural-gas/prices.php.
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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 CO2 pipelines
designed with excess capacity, enabling integrated carbon capture and
geologic storage. The IIJA also allocated $21.5 billion to fund new
programs to support the development, demonstration, and deployment of
clean energy technologies, such as $8 billion for the development of
regional clean hydrogen hubs 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\ https://www.congress.gov/bill/117th-congress/house-bill/3684/text.
\130\ https://www.whitehouse.gov/wp-content/uploads/2022/05/BUILDING-A-BETTER-AMERICA-V2.pdf.
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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\ https://www.congress.gov/bill/117th-congress/house-bill/5376/text.
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The IRA's provisions also demonstrate an intent to support
development and deployment of low-GHG emitting technologies in the
power sector through a broad array of additional tax credits, loan
guarantees, and public investment programs. 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 CO2, including from
industrial sources, coal-fired steam generating units, and natural gas-
fired stationary combustion turbines. The increase in credit values,
found in section 13104 (which revises IRC section 45Q), is 70 percent,
equaling $85/metric ton for CO2 captured and securely stored
in geologic formations and $60/metric ton for CO2 captured
and utilized or securely stored incidentally in conjunction with
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
CO2 capture design capacity of not less than 75 percent of
the baseline CO2 production of the unit and that
construction must begin before January 1, 2033. Tax credits under 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.
https://www.globalccsinstitute.com/wp-content/uploads/2019/05/LCFS-and-CCS-Protocol_digital_version-2.pdf.
\134\ EPA. (2024). Current Class VI Projects under Review at
EPA. https://www.epa.gov/uic/current-class-vi-projects-under-review-epa.
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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 H2 for less than 0.45 kilograms of
CO2-equivalent emitted per kilogram of low-GHG hydrogen
produced (kg CO2e/kg H2) down to $0.6/kg
H2 for 2.5 to 4.0 kg CO2e/kg H2
(assuming wage and apprenticeship requirements are met). Projects with
production related GHG emissions greater than 4.0 kg CO2e/kg
H2 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. https://home.treasury.gov/news/press-releases/jy1383.
\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). https://rmi.org/the-energy-infrastructure-reinvestment-program-federal-financing-for-an-equitable-clean-economy/.
\137\ U.S. Department of Agriculture (USDA). Empowering Rural
America New ERA Program. https://www.rd.usda.gov/programs-services/electric-programs/empowering-rural-america-new-era-program.
\138\ Rocky Mountain Institute (RMI). (October 4, 2023). USDA
$9.7B Rural Community Clean Energy Program Receives 150+ Letters of
Interest. Press release. https://rmi.org/press-release/usda-9-7b-rural-community-clean-energy-program-receives-150-letters-of-interest/.
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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 CO2 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 CO2 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. https://www.epa.gov/system/files/documents/2023-09/Electricity_Emissions_Impacts_Inflation_Reduction_Act_Report_EPA-FINAL.pdf.
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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 CO2 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.
https://sepapower.org/utility-transformation-challenge/utility-carbon-reduction-tracker/.
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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 2030.144 145 146 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). https://www.edf.org/sites/default/files/2023-11/EDF-State-Emissions-Gap-December-2023.pdf.
\145\ United Nations Framework Convention on Climate Change.
What is the Paris Agreement? https://unfccc.int/process-and-meetings/the-paris-agreement.
\146\ U.S. Department of State and U.S. Executive Office of the
President. November 2021. The Long-Term Strategy of the United
States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050.
https://www.whitehouse.gov/wp-content/uploads/2021/10/us-long-term-strategy.pdf.
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Several states have enacted binding economy-wide emission reduction
targets that will require significant decarbonization from state power
sectors, including California, Colorado, Maine, Maryland,
Massachusetts, New Jersey, New York, Rhode Island, Vermont, and
Washington.\147\ These commitments are statutory emission reduction
targets accompanied by mandatory agency directives to develop
comprehensive implementing regulations to achieve the necessary
reductions. Some of these states, along with other neighboring states,
also participate in the Regional Greenhouse Gas Initiative (RGGI), a
carbon market limiting pollution from power plants throughout New
England.\148\ The pollution limit combined with carbon price and
allowance market has led member states to reduce power sector
CO2 emissions by nearly 50 percent since the start of the
program in 2009. This is 10 percent more than all non-RGGI states.\149\
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\147\ 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). https://www.edf.org/sites/default/files/2023-11/EDF-State-Emissions-Gap-December-2023.pdf.
\148\ A full list of states currently participating in RGGI
include Connecticut, Delaware, Maine, Maryland, Massachusetts, New
Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, and
Vermont.
\149\ Note that these figures do not include Virginia and
Pennsylvania, which were not members of RGGI for the full duration
of 2009-2023. Acadia Center: Regional Greenhouse Gas Initiative;
Findings and Recommendations for the Third Program Review. https://acadiacenter.wpenginepowered.com/wp-content/uploads/2023/04/AC_RGGI_2023_Layout_R6.pdf.
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Other states dependent on coal-fired power generation or coal
production also have significant, albeit non-
[[Page 39821]]
binding, commitments that signal broad public support for policy with
emissions-based metrics and public affirmation that climate change is
fundamentally linked to fossil-intensive energy sources. These states
include Illinois, Michigan, Minnesota, New Mexico, North Carolina,
Pennsylvania, and Virginia. States like Wyoming, the top coal producing
state in the U.S., have promulgated sector-specific regulations
requiring their public service commissions to implement low-carbon
energy standards for public utilities.150 151 Specific
standards are further detailed in the sections that follow and in the
final TSD, Power Sector Trends.
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\150\ State of Wyoming. (Adopted March 24, 2020). House Bill 200
Reliable and dispatchable low-carbon energy standards. https://www.wyoleg.gov/Legislation/2020/HB0200.
\151\ State of Wyoming. (Adopted March 15, 2024). Senate Bill 42
Low-carbon reliable energy standards-amendments. https://www.wyoleg.gov/Legislation/2024/SF0042.
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Technologies like CCS provide a means to achieve significant
emission reduction targets. For example, to achieve GHG emission
reduction goals legislatively enacted in 2016, California Senate Bill
100, passed in 2018, requires the state to procure 60 percent of all
electricity from renewable sources by 2030 and plan for 100 percent
from carbon-free sources by 2045.\152\ Achieving California's
established goal of carbon-free electricity by 2045 requires emissions
to be balanced by carbon sequestration, capture, or other technologies.
Therefore, California Senate Bill 905, passed in 2022, requires the
California Air Resources Board (CARB) to establish programs for
permitting CCS projects while preventing the use of captured
CO2 for EOR within the state.\153\ As mentioned previously,
as the top coal producing state, Wyoming has been exceptionally
persistent on the implementation of CCS by incentivizing the national
testing of CCS at Basin Electric's coal-fired Dry Fork Station \154\
and by requiring the consideration of CCS as an alternative to coal
plant retirement.\155\ At least five other states, including Montana
and North Dakota, also have tax incentives and regulations for
CCS.\156\ In the case of Montana, the acquisition of an equity interest
or lease of coal-fired EGUs is prohibited unless it captures and stores
at least 50 percent of its CO2 emissions.\157\ These state
policies have coincided with the planning and development of large CCS
projects.
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\152\ Berkeley Law. California Climate Policy Dashboard. https://www.law.berkeley.edu/research/clee/research/climate/climate-policy-dashboard.
\153\ Berkeley Law. California Climate Policy Dashboard. https://www.law.berkeley.edu/research/clee/research/climate/climate-policy-dashboard.
\154\ Basin Electric Power Cooperative. (May 2023). Press
Release: Carbon Capture Technology Developers Break Ground at
Wyoming Integrated Test Center Located at Basin Electric's Dry Fork
Station. https://www.basinelectric.com/News-Center/news-briefs/Carbon-capture-technology-developers-break-ground-at-Wyoming-Integrated-Test-Center-located-at-Basin-Electrics-Dry-Fork-Station.
\155\ State of Wyoming. (Adopted March 15, 2024). Senate Bill 42
Low-carbon reliable energy standards-amendments. https://www.wyoleg.gov/Legislation/2024/SF0042.
\156\ Sabin Center for Climate Change Law. 2019. Legal Pathways
to Deep Decarbonization. Interactive Tracker for State Action on
Carbon Capture. https://cdrlaw.org/ccus-tracker/.
\157\ Sabin Center for Climate Change Law. 2019. Legal Pathways
to Deep Decarbonization. Model Laws. Montana prohibition on
acquiring coal plants without CCS. https://lpdd.org/resources/montana-prohibition-on-acquiring-coal-plants-without-ccs/.
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Other states have broad decarbonization laws that will drive
significant decrease in power sector GHG emissions. In New York, The
Climate Leadership and Community Protection Act, passed in 2019, sets
several climate targets. The most important goals include an 85 percent
reduction in GHG emissions by 2050, 100 percent zero-emission
electricity by 2040, and 70 percent renewable energy by 2030. Other
targets include 9,000 MW of offshore wind by 2035, 3,000 MW of energy
storage by 2030, and 6,000 MW of solar by 2025.\158\ Washington State's
Climate Commitment Act sets a target of reducing GHG emissions by 95
percent by 2050. The state is required to reduce emissions to 1990
levels by 2020, 45 percent below 1990 levels by 2030, 70 percent below
1990 levels by 2040, and 95 percent below 1990 levels by 2050. This
also includes achieving net-zero emissions by 2050.\159\ Illinois'
Climate and Equitable Jobs Act, enacted in September 2021, requires all
private coal-fired or oil-fired power plants to reach zero carbon
emissions by 2030, municipal coal-fired plants to reach zero carbon
emissions by 2045, and natural gas-fired plants to reach zero carbon
emissions by 2045.\160\ In October 2021, North Carolina passed House
Bill 951 that required the North Carolina Utilities Commission to
``take all reasonable steps to achieve a seventy percent (70 percent)
reduction in emissions of carbon dioxide (CO2) emitted in
the state from electric generating facilities owned or operated by
electric public utilities from 2005 levels by the year 2030 and carbon
neutrality by the year 2050.'' \161\
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\158\ New York State. Climate Act: Progress to our Goals.
https://climate.ny.gov/Our-Impact/Our-Progress.
\159\ Department of Ecology Washington State. Greenhouse Gases.
https://ecology.wa.gov/Air-Climate/Climate-change/Tracking-greenhouse-gases.
\160\ State of Illinois General Assembly. Public Act 102-0662:
Climate and Equitable Jobs Act. 2021. https://www.ilga.gov/legislation/publicacts/102/PDF/102-0662.pdf.
\161\ General Assembly of North Carolina, House Bill 951 (2021).
https://www.ncleg.gov/Sessions/2021/Bills/House/PDF/H951v5.pdf.
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The ambition and scope of these state power sector polices will
impact the electric generation fleet for decades. Seven states with
100-percent power sector decarbonization polices include a total of 20
coal-fired EGUs with slightly less than 10 GW total capacity and
without announced retirement dates before 2039.\162\ Virginia, which
has three coal-steam units with no announced retirement dates and one
with a 2045 retirement date, enacted the Clean Economy Act in 2020 to
impose a 100 percent RPS requirement by 2050. The combined capacity of
all four of these units in Virginia totals nearly 1.5 GW. North
Carolina, which has one coal-fired unit without an announced retirement
date and one with a planned 2048 retirement, as previously mentioned,
enacted a state law in 2021 requiring the state's utilities commission
to achieve carbon neutrality by 2050. The combined capacity of both
units totals approximately 1.4 GW of capacity. Nebraska, where three
public utility boards serving a large portion of the state have adopted
net-zero electricity emission goals by 2040 or 2050, includes six coal-
fired units with a combined capacity of 2.9 GW. The remaining eight
units are in states with long-term decarbonization goals (Illinois,
Louisiana, Maryland, and Wisconsin). All four of these states have set
100 percent clean energy goals by 2050.
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\162\ These estimates are based on an analysis of the EPA's
NEEDS database, which contains information about EGUs across the
country. The analysis includes a basic screen for units within the
NEEDS database that are likely subject to the final 111(d) EGU rule,
namely coal-steam units with capacity greater than 25 MW, and then
removes units with an announced retirement dates prior to 2039,
units with announced plans to convert from coal- to gas-fired units,
and units likely to fall outside of the rule's applicability via the
cogeneration exemption.
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Twenty-nine states and the District of Columbia have enforceable
RPS \163\ that require a percentage of electricity that utilities sell
to come from eligible renewable sources like wind and solar rather than
from fossil fuel-based sources like coal and natural gas. Furthermore,
20 states have adopted a CES that includes some form of clean
[[Page 39822]]
energy requirement or goal with a 100 percent or net-zero target.\164\
A CES shifts generating fleets away from fossil fuel resources by
requiring a percentage of retail electricity to come from sources that
are defined as clean. Unlike an RPS, which defines eligible generation
in terms of the renewable attributes of its energy source, CES
eligibility is based on the GHG emission attributes of the generation
itself, typically with a zero or net-zero carbon emissions requirement.
Additional discussion of state actions and legislation to reduce GHG
emissions from the power sector is provided in the final TSD, Power
Sector Trends.
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\163\ DSIRE, Renewable Portfolio Standards and Clean Energy
Standards (2023). https://ncsolarcen-prod.s3.amazonaws.com/wp-content/uploads/2023/12/RPS-CES-Dec2023-1.pdf; LBNL, U.S. State
Renewables Portfolio & Clean Electricity Standards: 2023 Status
Update. https://emp.lbl.gov/publications/us-state-renewables-portfolio-clean.
\164\ This count is adapted from Lawrence Berkeley National
Laboratory's (LBNL) U.S. State Renewables Portfolio & Clean
Electricity Standards: 2023 Status Update, which identifies 15
states with 100 percent CES. The LBNL count includes Virginia, which
the EPA omits because it considers Virginia a 100 percent RPS.
Further, the LBNL count excludes Louisiana, Michigan, New Jersey,
and Wisconsin because their clean energy goals are set by executive
order. The EPA instead includes Louisiana, New Jersey, and Wisconsin
but characterizes them as goals rather than requirements. Michigan,
which enacted a CES by statute after the LBNL report's publication,
is also included in the EPA count. Finally, the EPA count includes
Maryland, whose December 2023 Climate Pollution Reduction Plan sets
a goal of 100 percent clean energy by 2035, and Delaware, which
enacted a statutory goal to reach net-zero GHG emissions by 2050.
See LBNL, U.S. State Renewables Portfolio & Clean Electricity
Standards: 2023 Status Update, https://emp.lbl.gov/publications/us-state-renewables-portfolio-clean; Maryland's Climate Pollution
Reduction Plan, https://mde.maryland.gov/programs/air/ClimateChange/Maryland%20Climate%20Reduction%20Plan/Maryland%27s%20Climate%20Pollution%20Reduction%20Plan%20-%20Final%20-%20Dec%2028%202023.pdf; and HB 99, An Act to Amend
Titles 7 and 29 of the Delaware Code Relating to Climate Change,
https://legis.delaware.gov/json/BillDetail/GenerateHtmlDocumentEngrossment?engrossmentId=25785&docTypeId=6.
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F. Future Projections of Power Sector Trends
Projections for the U.S. power sector--based on the landscape of
market forces in addition to the known actions of Congress, utilities,
and states--have indicated that the ongoing transition will continue
for specific fuel types and EGUs. The EPA's Power Sector Platform 2023
using IPM reference case (i.e., the EPA's projections of the power
sector, which includes representation of the IRA absent further
regulation), provides projections out to 2050 on future outcomes of the
electric power sector. For more information on the details of this
modeling, see the model documentation.\165\
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\165\ U.S. Environmental Protection Agency.Power Sector Platform
2023 using IPM. April 2024. https://www.epa.gov/power-sector-modeling.
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Since the passage of the IRA in August 2022, the EPA has engaged
with many external partners, including other governmental entities,
academia, non-governmental organizations (NGOs), and industry, to
understand the impacts that the IRA will have on power sector GHG
emissions. In addition to engaging in several workgroups, the EPA has
contributed to two separate journal articles that include multi-model
comparisons of IRA impacts across several state-of-the-art models of
the U.S. energy system and electricity sector 166 167 and
participated in public events exploring modeling assumptions for the
IRA.\168\ The EPA plans to continue collaborating with stakeholders,
conducting external engagements, and using information gathered to
refine modeling of the IRA.
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\166\ Bistline, et al. (2023). ``Emissions and Energy System
Impacts of the Inflation Reduction Act of 2022.'' https://www.science.org/stoken/author-tokens/ST-1277/full.
\167\ Bistline, et al. (2023). ``Power Sector Impacts of the
Inflation Reduction Act of 2022.''https://iopscience.iop.org/article/10.1088/1748-9326/ad0d3b.
\168\ Resource for the Future (2023). ``Future Generation:
Exploring the New Baseline for Electricity in the Presence of the
Inflation Reduction Act.'' https://www.rff.org/events/rff-live/future-generation-exploring-the-new-baseline-for-electricity-in-the-presence-of-the-inflation-reduction-act/.
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While much of the discussion below focuses on the EPA's Power
Sector Platform 2023 using IPM reference case, many other analyses show
similar trends,\169\ and these trends are consistent with utility IRPs
and public GHG reduction commitments, as well as state actions, both of
which were described in the previous sections.
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\169\ A wide variety of modeling teams have assessed baselines
with IRA. The baseline estimated here is generally in line with
these other estimates. Bistline, et al. (2023). ``Power Sector
Impacts of the Inflation Reduction Act of 2022.'' https://iopscience.iop.org/article/10.1088/1748-9326/ad0d3b.
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1. Future Projections for Coal-Fired Generation
As described in the EPA's baseline modeling, coal-fired steam
generating unit capacity is projected to fall from 181 GW in 2023 \170\
to 52 GW in 2035, of which 11 GW includes retrofit CCS. Generation from
coal-fired steam generating units is projected to also fall from 898
thousand GWh in 2021 \171\ to 236 thousand GWh by 2035. This change in
generation reflects the anticipated continued decline in projected
coal-fired steam generating unit capacity as well as a steady decline
in annual operation of those EGUs that remain online, with capacity
factors falling from approximately 48 percent in 2022 to 45 percent in
2035 at facilities that do not install CCS. By 2050, coal-fired steam
generating unit capacity is projected to diminish further, with only 28
GW, or less than 16 percent of 2023 capacity (and approximately 9
percent of the 2010 capacity), still in operation across the
continental U.S.
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\170\ U.S. Energy Information Administration (EIA), Preliminary
Monthly Electric Generator Inventory, December 2023. https://www.eia.gov/electricity/data/eia860m/
\171\ U.S. Energy Information Administration (EIA), Electric
Power Annual, table 3.1.A. November 2022. https://www.eia.gov/electricity/annual/.
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These projections are driven by the eroding economic opportunities
for coal-fired steam generating units to operate, the continued aging
of the fleet of coal-fired steam generating units, and the continued
availability and expansion of low-cost alternatives, like natural gas,
renewable technologies, and energy storage. The projected retirements
continue the trend of coal plant retirements in recent decades that is
described in section IV.D.3. of this preamble (and further in the Power
Sector Trends technical support document). The decline in coal
generation capacity has generally resulted from a more competitive
economic environment and increasing coal plant age. Most notably,
declines in natural gas prices associated with the rise of hydraulic
fracturing and horizontal drilling lowered the cost of natural gas-
fired generation.\172\ Lower gas generation costs reduced coal plant
capacity factors and revenues. Rapid declines in the costs of
renewables and battery storage have put further price pressure on coal
plants, given the zero marginal cost operation of solar and
wind.173 174 175 In addition, most operational coal plants
today were built before 2000, and many are reaching or have surpassed
their expected useful lives.\176\ Retiring coal plants tend to be
[[Page 39823]]
old.\177\ As plants age, their efficiency tends to decline and
operations and maintenance costs increase. Older coal plant operational
parameters are less aligned with current electric grid needs. Coal
plants historically were used as base load power sources and can be
slow (or expensive) to increase or decrease generation output
throughout a typical day. That has put greater economic pressure on
older coal plants, which are forced to either incur the costs of
adjusting their generation or operate during less profitable hours when
loads are lower or renewable generation is more plentiful.\178\ All of
these factors have contributed to retirements over the past 15 years,
and similar underlying factors are projected to continue the trend of
coal retirements in the coming years.
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\172\ International Energy Agency (IEA). Energy Policies of IEA
Countries: United States 2019 Review. https://iea.blob.core.windows.net/assets/7c65c270-ba15-466a-b50d-1c5cd19e359c/United_States_2019_Review.pdf.
\173\ U.S. Energy Information Administration (EIA). (April 13,
2023). U.S. Electric Capacity Mix shifts from Fossil Fuels to
Renewables in AEO2023. https://www.eia.gov/todayinenergy/detail.php?id=56160.
\174\ Solomon, M., et al. (January 2023). Coal Cost Crossover
3.0: Local Renewables Plus Storage Create New Opportunities for
Customer Savings and Community Reinvestment. Energy Innovation.
https://energyinnovation.org/wp-content/uploads/2023/01/Coal-Cost-Crossover-3.0.pdf.
\175\ Barbose, G., et al. (September 2023). Tracking the Sun:
Pricing and Design Trends for Distributed Photovoltaic Systems in
the United States, 2023 Edition. Lawrence Berkeley National
Laboratory. https://emp.lbl.gov/sites/default/files/5_tracking_the_sun_2023_report.pdf.
\176\ U.S. Energy Information Administration (EIA). (August
2022). Electric Generators Inventory, Form-860M, Inventory of
Operating Generators and Inventory of Retired Generators. https://www.eia.gov/electricity/data/eia860m/.
\177\ Mills, A., et al. (November 2017). Power Plant
Retirements: Trends and Possible Drivers. Lawrence Berkeley National
Laboratory. https://live-etabiblio.pantheonsite.io/sites/default/files/lbnl_retirements_data_synthesis_final.pdf.
\178\ National Association of Regulatory Utility Commissioners.
(January 2020). Recent Changes to U.S. Coal Plant Operations and
Current Compensation Practices. https://pubs.naruc.org/pub/7B762FE1-A71B-E947-04FB-D2154DE77D45.
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In 2020, there was a total of 1,439 million metric tons of
CO2 emissions from the power sector with coal-fired sources
contributing to more than half of those emissions. In the EPA's Power
Sector Platform 2023 using IPM reference case, power sector related
CO2 emission are projected to fall to 724 million metric
tons by 2035, of which 23 percent is projected to come from coal-fired
sources in 2035.
2. Future Projections for Natural Gas-Fired Generation
As described in the EPA's Power Sector Platform 2023 using IPM
reference case, natural gas-fired capacity is expected to continue to
build out during the next decade with 34 GW of new capacity projected
to come online by 2035 and 261 GW of new capacity by 2050. By 2035, the
new natural gas capacity is comprised of 14 GW of simple cycle turbines
and 20 GW of combined cycle turbines. By 2050, most of the incremental
new capacity is projected to come just from simple cycle turbines. This
also represents a higher rate of new simple cycle turbine builds
compared to the reference periods (i.e., 2000-2006 and 2007-2021)
discussed previously in this section.
It should be noted that despite this increase in capacity, both
overall generation and emissions from the natural gas-fired capacity
are projected to decline. Generation from natural gas units is
projected to fall from 1,579 thousand GWh in 2021 \179\ to 1,344
thousand GWh by 2035. Power sector related CO2 emissions
from natural gas-fired EGUs were 615 million metric tons in 2021.\180\
By 2035, emission levels are projected to reach 521 million metric
tons, 96 percent of which comes from NGCC sources.
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\179\ U.S. Energy Information Administration (EIA), Electric
Power Annual, table 3.1.A. November 2022. https://www.eia.gov/electricity/annual/.
\180\ U.S. Environmental Protection Agency, Inventory of U.S.
Greenhouse Gas Emission Sources and Sinks. February 2023. https://www.epa.gov/system/files/documents/2023-02/US-GHG-Inventory-2023-Main-Text.pdf.
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The decline in generation and emissions is driven by a projected
decline in NGCC capacity factors. In model projections, NGCC units have
a capacity factor early in the projection period of 59 percent, but by
2035, capacity factor projections fall to 48 percent as many of these
units switch from base load operation to more intermediate load
operation to support the integration of variable renewable energy
resources. Natural gas-fired simple cycle turbine capacity factors also
fall, although since they are used primarily as a peaking resource and
their capacity factors are already below 10 percent annually, their
impact on generation and emissions changes are less notable.
Some of the reasons for this anticipated continued growth in
natural gas-fired capacity, coupled with a decline in generation and
emissions, include the anticipated growth in peak load, retirement of
older fossil generators, and growth in renewable energy coupled with
the greater flexibility offered by combustion turbines. Simple cycle
turbines operate at lower efficiencies than NGCC units but offer fast
startup times to meet peaking load demands. In addition, combustion
turbines, along with energy storage technologies and demand response
strategies, support the expansion of renewable electricity by meeting
demand during peak periods and providing flexibility around the
variability of renewable generation and electricity demand. In the
longer term, as renewables and battery storage grow, they are
anticipated to outcompete the need for some natural gas-fired
generation and the overall utilization of natural gas-fired capacity is
expected to decline. For additional discussion and analysis of
projections of future coal- and natural gas-fired generation, see the
final TSD, Power Sector Trends in the docket for this rulemaking.
As explained in greater detail later in this preamble and in the
accompanying RIA, future generation projections for natural gas-fired
combustion turbines differ from those highlighted in recent historical
trends. The largest source of new generation is from renewable energy,
and projections show that total natural gas-fired combined cycle
capacity is likely to decline after 2030 in response to increased
generation from renewables, deployment of energy storage, and other
technologies. Approximately 95 percent of capacity additions in 2024
are expected to be from non-emitting generation resources including
solar, battery storage, wind, and nuclear.\181\ The IRA is likely to
influence this trend, which is also expected to impact the operation of
certain combustion turbines. For example, as the electric output from
additional variable renewable generating sources fluctuates daily and
seasonally, flexible low and intermediate load combustion turbines will
be needed to support these variable sources and provide reliability to
the grid. This requires the ability to start and stop quickly and
change load more frequently. Today's system includes 212 GW of
intermediate and low load combustion turbines. These operational
changes, alongside other tools like demand response, energy storage,
and expanded transmission, will maintain reliability of the grid.
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\181\ U.S. Energy Information Administration (EIA). Today in
Energy. Solar and battery storage to make up 81 percent of new U.S.
electric-generating capacity in 2024. February 2024. https://www.eia.gov/todayinenergy/detail.php?id=61424.
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V. Statutory Background and Regulatory History for CAA Section 111
A. Statutory Authority To Regulate GHGs From EGUs Under CAA Section 111
The EPA's authority for and obligation to issue these final rules
is CAA section 111, which establishes mechanisms for controlling
emissions of air pollutants from new and existing stationary sources.
CAA section 111(b)(1)(A) requires the EPA Administrator to promulgate a
list of categories of stationary sources that the Administrator, in his
or her judgment, finds ``causes, or contributes significantly to, air
pollution which may reasonably be anticipated to endanger public health
or welfare.'' The EPA has the authority to define the scope of the
source categories, determine the pollutants for which standards should
be developed, and distinguish among classes, types, and sizes within
categories in establishing the standards.
[[Page 39824]]
1. Regulation of Emissions From New Sources
Once the EPA lists a source category, the EPA must, under CAA
section 111(b)(1)(B), establish ``standards of performance'' for ``new
sources'' in the source category. These standards are referred to as
new source performance standards, or NSPS. The NSPS are national
requirements that apply directly to the sources subject to them.
Under CAA section 111(a)(1), a ``standard of performance'' is
defined, in the singular, as ``a standard for emissions of air
pollutants'' that is determined in a specified manner, as noted in this
section, below.
Under CAA section 111(a)(2), a ``new source'' is defined, in the
singular, as ``any stationary source, the construction or modification
of which is commenced after the publication of regulations (or, if
earlier, proposed regulations) prescribing a standard of performance
under this section, which will be applicable to such source.'' Under
CAA section 111(a)(3), a ``stationary source'' is defined as ``any
building, structure, facility, or installation which emits or may emit
any air pollutant.'' Under CAA section 111(a)(4), ``modification''
means any physical change in, or change in the method of operation of,
a stationary source which increases the amount of any air pollutant
emitted by such source or which results in the emission of any air
pollutant not previously emitted. While this provision treats modified
sources as new sources, EPA regulations also treat a source that
undergoes ``reconstruction'' as a new source. Under the provisions in
40 CFR 60.15, ``reconstruction'' means the replacement of components of
an existing facility such that: (1) The fixed capital cost of the new
components exceeds 50 percent of the fixed capital cost that would be
required to construct a comparable entirely new facility; and (2) it is
technologically and economically feasible to meet the applicable
standards. Pursuant to CAA section 111(b)(1)(B), the standards of
performance or revisions thereof shall become effective upon
promulgation.
In setting or revising a performance standard, CAA section
111(a)(1) provides that performance standards are to reflect ``the
degree of emission limitation achievable through the application of the
best system of emission reduction which (taking into account the cost
of achieving such reduction and any non-air quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.'' The term ``standard of
performance'' in CAA 111(a)(1) makes clear that the EPA is to determine
both the ``best system of emission reduction . . . adequately
demonstrated'' (BSER) for the regulated sources in the source category
and the ``degree of emission limitation achievable through the
application of the [BSER].'' West Virginia v. EPA, 597 U.S. 697, 709
(2022). To determine the BSER, the EPA first identifies the ``system[s]
of emission reduction'' that are ``adequately demonstrated,'' and then
determines the ``best'' of those systems, ``taking into account''
factors including ``cost,'' ``nonair quality health and environmental
impact,'' and ``energy requirements.'' The EPA then derives from that
system an ``achievable'' ``degree of emission limitation.'' The EPA
must then, under CAA section 111(b)(1)(B), promulgate ``standard[s] for
emissions''--the NSPS--that reflect that level of stringency.
2. Regulation of Emissions From Existing Sources
When the EPA establishes a standard for emissions of an air
pollutant from new sources within a category, it must also, under CAA
section 111(d), regulate emissions of that pollutant from existing
sources within the same category, unless the pollutant is regulated
under the National Ambient Air Quality Standards (NAAQS) program, under
CAA sections 108-110, or the National Emission Standards for Hazardous
Air Pollutants (NESHAP) program, under CAA section 112. See CAA section
111(d)(1)(A)(i) and (ii); West Virginia, 597 U.S. at 710.
CAA section 111(d) establishes a framework of ``cooperative
federalism for the regulation of existing sources.'' American Lung
Ass'n, 985 F.3d at 931. CAA sections 111(d)(1)(A)-(B) require ``[t]he
Administrator . . . to prescribe regulations'' that require ``[e]ach
state . . . to submit to [EPA] a plan . . . which establishes standards
of performance for any existing stationary source for'' the air
pollutant at issue, and which ``provides for the implementation and
enforcement of such standards of performance.'' CAA section 111(a)(6)
defines an ``existing source'' as ``any stationary source other than a
new source.''
To meet these requirements, the EPA promulgates ``emission
guidelines'' that identify the BSER and the degree of emission
limitation achievable through the application of the BSER. Each state
must then establish standards of performance for its sources that
reflect that level of stringency. However, the states need not compel
regulated sources to adopt the particular components of the BSER
itself. The EPA's emission guidelines must also permit a state, ``in
applying a standard of performance to any particular source,'' to
``take into consideration, among other factors, the remaining useful
life of the existing source to which such standard applies.'' 42 U.S.C.
7411(d)(1). Once a state receives the EPA's approval of its plan, the
provisions in the plan become federally enforceable against the source,
in the same manner as the provisions of an approved State
Implementation Plan (SIP) under the Act. CAA section 111(d)(2)(B). If a
state elects not to submit a plan or submits a plan that the EPA does
not find ``satisfactory,'' the EPA must promulgate a plan that
establishes Federal standards of performance for the state's existing
sources. CAA section 111(d)(2)(A).
3. EPA Review of Requirements
CAA section 111(b)(1)(B) requires the EPA to ``at least every 8
years, review and, if appropriate, revise'' new source performance
standards. However, the Administrator need not review any such standard
if the ``Administrator determines that such review is not appropriate
in light of readily available information on the efficacy'' of the
standard. Id. When conducting a review of an NSPS, the EPA has the
discretion and authority to add emission limits for pollutants or
emission sources not currently regulated for that source category. CAA
section 111 does not by its terms require the EPA to review emission
guidelines for existing sources, but the EPA retains the authority to
do so. See 81 FR 59277 (August 29, 2016) (explaining legal authority to
review emission guidelines for municipal solid waste landfills).
B. History of EPA Regulation of Greenhouse Gases From Electricity
Generating Units Under CAA Section 111 and Caselaw
The EPA has listed more than 60 stationary source categories under
CAA section 111(b)(1)(A). See 40 CFR part 60, subparts Cb-OOOO. In
1971, the EPA listed fossil fuel-fired EGUs (which includes natural
gas, petroleum, and coal) that use steam-generating boilers in a
category under CAA section 111(b)(1)(A). See 36 FR 5931 (March 31,
1971) (listing ``fossil fuel-fired steam generators of more than 250
million Btu per hour heat input''). In 1977, the EPA listed fossil
fuel-fired combustion turbines, which can be used in EGUs, in a
category under CAA section 111(b)(1)(A). See 42 FR 53657 (October 3,
1977) (listing ``stationary gas turbines'').
[[Page 39825]]
Beginning in 2007, several decisions by the U.S. Supreme Court and
the D.C. Circuit have made clear that under CAA section 111, the EPA
has authority to regulate GHG emissions from listed source categories.
The U.S. Supreme Court ruled in Massachusetts v. EPA that GHGs \182\
meet the definition of ``air pollutant'' in the CAA,\183\ and
subsequently premised its decision in AEP v. Connecticut \184\--that
the CAA displaced any Federal common law right to compel reductions in
CO2 emissions from fossil fuel-fired power plants--on its
view that CAA section 111 applies to GHG emissions. The D.C. Circuit
confirmed in American Lung Ass'n v. EPA, 985 F.3d 914, 977 (D.C. Cir.
2021), discussed in section V.B.5, that the EPA is authorized to
promulgate requirements under CAA section 111 for GHG from the fossil
fuel-fired EGU source category notwithstanding that the source category
is regulated under CAA section 112. As discussed in section V.B.6, the
U.S. Supreme Court did not accept certiorari on the question whether
the EPA could regulate GHGs from fossil-fuel fired EGUs under CAA
section 111(d) when other pollutants from fossil-fuel fired EGUs are
regulated under CAA section 112 in West Virginia v. EPA, 597 U.S. 697
(2022), and so the D.C. Circuit's holding on this issue remains good
law.
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\182\ The EPA's 2009 endangerment finding defines the air
pollution which may endanger public health and welfare as the well-
mixed aggregate group of the following gases: CO2,
methane (CH4), nitrous oxide (N2O), sulfur
hexafluoride (SF6), hydrofluorocarbons (HFCs), and
perfluorocarbons (PFCs).
\183\ 549 U.S. 497, 520 (2007).
\184\ 131 S. Ct. 2527, 2537-38 (2011).
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In 2015, the EPA promulgated two rules that addressed
CO2 emissions from fossil fuel-fired EGUs. The first
promulgated standards of performance for new fossil fuel-fired EGUs.
``Standards of Performance for Greenhouse Gas Emissions From New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units; Final Rule,'' (80 FR 64510; October 23, 2015) (2015
NSPS). The second promulgated emission guidelines for existing sources.
``Carbon Pollution Emission Guidelines for Existing Stationary Sources:
Electric Utility Generating Units; Final Rule,'' (80 FR 64662; October
23, 2015) (Clean Power Plan, or CPP).
1. 2015 NSPS
In 2015, the EPA promulgated an NSPS to limit emissions of GHGs,
manifested as CO2, from newly constructed, modified, and
reconstructed fossil fuel-fired electric utility steam generating
units, i.e., utility boilers and IGCC EGUs, and newly constructed and
reconstructed stationary combustion turbine EGUs. These final standards
are codified in 40 CFR part 60, subpart TTTT. In promulgating the NSPS
for newly constructed fossil fuel-fired steam generating units, the EPA
determined the BSER to be a new, highly efficient, supercritical
pulverized coal (SCPC) EGU that implements post-combustion partial CCS
technology. The EPA concluded that CCS was adequately demonstrated
(including being technically feasible) and widely available and could
be implemented at reasonable cost. The EPA identified natural gas co-
firing and IGCC technology (either with natural gas co-firing or
implementing partial CCS) as alternative methods of compliance.
The 2015 NSPS included standards of performance for steam
generating units that undergo a ``reconstruction'' as well as units
that implement ``large modifications,'' (i.e., modifications resulting
in an increase in hourly CO2 emissions of more than 10
percent). The 2015 NSPS did not establish standards of performance for
steam generating units that undertake ``small modifications'' (i.e.,
modifications resulting in an increase in hourly CO2
emissions of less than or equal to 10 percent), due to the limited
information available to inform the analysis of a BSER and
corresponding standard of performance.
The 2015 NSPS also finalized standards of performance for newly
constructed and reconstructed stationary combustion turbine EGUs. For
newly constructed and reconstructed base load natural gas-fired
stationary combustion turbines, the EPA finalized a standard based on
efficient NGCC technology as the BSER. For newly constructed and
reconstructed non-base load natural gas-fired stationary combustion
turbines and for both base load and non-base load multi-fuel-fired
stationary combustion turbines, the EPA finalized a heat input-based
standard based on the use of lower-emitting fuels (referred to as clean
fuels in the 2015 NSPS). The EPA did not promulgate final standards of
performance for modified stationary combustion turbines due to lack of
information. The 2015 NSPS remains in effect today.
The EPA received six petitions for reconsideration of the 2015
NSPS. On May 6, 2016 (81 FR 27442), the EPA denied five of the
petitions on the basis that they did not satisfy the statutory
conditions for reconsideration under CAA section 307(d)(7)(B) and
deferred action on one petition that raised the issue of the treatment
of biomass. Apart from these petitions, the EPA proposed to revise the
2015 NSPS in 2018, as discussed in section V.B.2.
Multiple parties also filed petitions for judicial review of the
2015 NSPS in the D.C. Circuit. These cases have been briefed and, on
the EPA's motion, are being held in abeyance pending EPA action
concerning the 2018 proposal to revise the 2015 NSPS.
In the 2015 NSPS, the EPA noted that it was authorized to regulate
GHGs from the fossil fuel-fired EGU source categories because it had
listed those source categories under CAA section 111(b)(1)(A). The EPA
added that CAA section 111 did not require it to make a determination
that GHGs from EGUs contribute significantly to dangerous air pollution
(a pollutant-specific significant contribution finding), but in the
alternative, the EPA did make that finding. It explained that
``[greenhouse gas] air pollution may reasonably be anticipated to
endanger public health or welfare,'' 80 FR 64530 (October 23, 2015) and
emphasized that power plants are ``by far the largest emitters'' of
greenhouse gases among stationary sources in the U.S. Id. at 64522. In
American Lung Ass'n v. EPA, 985 F.3d 977 (D.C. Cir. 2021), the court
held that even if the EPA were required to determine that
CO2 from fossil fuel-fired EGUs contributes significantly to
dangerous air pollution--and the court emphasized that it was not
deciding that the EPA was required to make such a pollutant-specific
determination--the determination in the alternative that the EPA made
in the 2015 NSPS was not arbitrary and capricious and, accordingly, the
EPA had a sufficient basis to regulate greenhouse gases from EGUs under
CAA section 111(d) in the ACE Rule. This aspect of the decision remains
good law. The EPA is not reopening and did not solicit comment on any
of those determinations in the 2015 NSPS concerning its rational basis
to regulate GHG emissions from EGUs or its alternative finding that GHG
emissions from EGUs contribute significantly to dangerous air
pollution.
2. 2018 NSPS Proposal To Revise the 2015 NSPS
In 2018, the EPA proposed to revise the NSPS for new, modified, and
reconstructed fossil fuel-fired steam generating units and IGCC units,
in the Review of Standards of Performance for Greenhouse Gas Emissions
From New, Modified, and Reconstructed Stationary Sources: Electric
Utility Generating Units; Proposed Rule (83 FR 65424;
[[Page 39826]]
December 20, 2018) (2018 NSPS Proposal). The EPA proposed to revise the
NSPS for newly constructed units, based on a revised BSER of a highly
efficient SCPC, without partial CCS. The EPA also proposed to revise
the NSPS for modified and reconstructed units. As discussed in IX.A, in
the present action, the EPA is withdrawing this proposed rule.\185\
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\185\ In the 2018 NSPS Proposal, the EPA solicited comment on
whether it is required to make a determination that GHGs from a
source category contribute significantly to dangerous air pollution
as a predicate to promulgating a NSPS for GHG emissions from that
source category for the first time. 83 FR 65432 (December 20, 2018).
The EPA subsequently issued a final rule that provided that it would
not regulate GHGs under CAA section 111 from a source category
unless the GHGs from the category exceed 3 percent of total U.S. GHG
emissions, on grounds that GHGs emitted in a lesser amount do not
contribute significantly to dangerous air pollution. 86 FR 2652
(January 13, 2021). Shortly afterwards, the D.C. Circuit granted an
unopposed motion by the EPA for voluntary vacatur and remand of the
final rule. California v. EPA, No. 21-1035, doc. 1893155 (D.C. Cir.
April 5, 2021).
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3. Clean Power Plan
With the promulgation of the 2015 NSPS, the EPA also incurred a
statutory obligation under CAA section 111(d) to issue emission
guidelines for GHG emissions from existing fossil fuel-fired steam
generating EGUs and stationary combustion turbine EGUs, which the EPA
initially fulfilled with the promulgation of the CPP. See 80 FR 64662
(October 23, 2015). The EPA first determined that the BSER included
three types of measures: (1) improving heat rate (i.e., the amount of
fuel that must be burned to generate a unit of electricity) at coal-
fired steam plants; (2) substituting increased generation from lower-
emitting NGCC plants for generation from higher-emitting steam plants
(which are primarily coal-fired); and (3) substituting increased
generation from new renewable energy sources for generation from fossil
fuel-fired steam plants and combustion turbines. See 80 FR 64667
(October 23, 2015). The latter two measures are known as ``generation
shifting'' because they involve shifting electricity generation from
higher-emitting sources to lower-emitting ones. See 80 FR 64728-29
(October 23, 2015).
The EPA based this BSER determination on a technical record that
evaluated generation shifting, including its cost-effectiveness,
against the relevant statutory criteria for BSER and on a legal
interpretation that the term ``system'' in CAA section 111(a)(1) is
sufficiently broad to encompass shifting of generation from higher-
emitting to lower-emitting sources. See 80 FR 64720 (October 23, 2015).
The EPA then determined the ``degree of emission limitation achievable
through the application of the [BSER],'' CAA section 111(a)(1),
expressed as emission performance rates. See 80 FR 64667 (October 23,
2015). The EPA explained that a state would ``have to ensure, through
its plan, that the emission standards it establishes for its sources
individually, in the aggregate, or in combination with other measures
undertaken by the state, represent the equivalent of'' those
performance rates (80 FR 64667; October 23, 2015). Neither states nor
sources were required to apply the specific measures identified in the
BSER (80 FR 64667; October 23, 2015), and states could include trading
or averaging programs in their state plans for compliance. See 80 FR
64840 (October 23, 2015).
Numerous states and private parties petitioned for review of the
CPP before the D.C. Circuit. On February 9, 2016, the U.S. Supreme
Court stayed the rule pending review, West Virginia v. EPA, 577 U.S.
1126 (2016). The D.C. Circuit held the litigation in abeyance, and
ultimately dismissed it at the petitioners' request. American Lung
Ass'n, 985 F.3d at 937.
4. The CPP Repeal and ACE Rule
In 2019, the EPA repealed the CPP and replaced it with the ACE
Rule. In contrast to its interpretation of CAA section 111 in the CPP,
in the ACE Rule the EPA determined that the statutory ``text and
reasonable inferences from it'' make ``clear'' that a ``system'' of
emission reduction under CAA section 111(a)(1) ``is limited to measures
that can be applied to and at the level of the individual source,'' (84
FR 32529; July 8, 2019); that is, the system must be limited to control
measures that could be applied at and to each source to reduce
emissions at each source. See 84 FR 32523-24 (July 8, 2019).
Specifically, the ACE Rule argued that the requirements in CAA sections
111(d)(1), (a)(3), and (a)(6), that each state establish a standard of
performance ``for'' ``any existing source,'' defined, in general, as
any ``building . . . [or] facility,'' and the requirement in CAA
section 111(a)(1) that the degree of emission limitation must be
``achievable'' through the ``application'' of the BSER, by their terms,
impose this limitation. The EPA concluded that generation shifting is
not such a control measure. See 84 FR 32546 (July 8, 2019). Based on
its view that the CPP was a ``major rule,'' the EPA further determined
that, absent ``a clear statement from Congress,'' the term `` `system
of emission reduction' '' should not be read to encompass ``generation-
shifting measures.'' See 84 FR 32529 (July 8, 2019). The EPA
acknowledged, however, that ``[m]arket-based forces ha[d] already led
to significant generation shifting in the power sector,'' (84 FR 32532;
July 8, 2019), and that there was ``likely to be no difference between
a world where the CPP is implemented and one where it is not.'' See 84
FR 32561 (July 8, 2019); the Regulatory Impact Analysis for the Repeal
of the Clean Power Plan, and the Emission Guidelines for Greenhouse Gas
Emissions from Existing Electric Utility Generating Units, 2-1 to 2-
5.\186\
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\186\ https://www.epa.gov/sites/default/files/2019-06/documents/utilities_ria_final_cpp_repeal_and_ace_2019-06.pdf.
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In addition, the EPA promulgated in the ACE Rule a new set of
emission guidelines for existing coal-fired steam-generating EGUs. See
84 FR 32532 (July 8, 2019). In light of ``the legal interpretation
adopted in the repeal of the CPP,'' (84 FR 32532; July 8, 2019)--which
``limit[ed] `standards of performance' to systems that can be applied
at and to a stationary source,'' (84 FR 32534; July 8, 2019)--the EPA
found the BSER to be heat rate improvements alone. See 84 FR 32535
(July 8, 2019). The EPA listed various technologies that could improve
heat rate (84 FR 32536; July 8, 2019), and identified the ``degree of
emission limitation achievable'' by ``providing ranges of expected
[emission] reductions associated with each of the technologies.'' See
84 FR 32537-38 (July 8, 2019).
5. D.C. Circuit Decision in American Lung Association v. EPA Concerning
the CPP Repeal and ACE Rule
Numerous states and private parties petitioned for review of the
CPP Repeal and ACE Rule. In 2021, the D.C. Circuit vacated the ACE
Rule, including the CPP Repeal. American Lung Ass'n v. EPA, 985 F.3d
914 (D.C. Cir. 2021). The court held, among other things, that CAA
section 111(d) does not limit the EPA, in determining the BSER, to
measures applied at and to an individual source. The court noted that
``the sole ground on which the EPA defends its abandonment of the [CPP]
in favor of the ACE Rule is that the text of [CAA section 111] is clear
and unambiguous in constraining the EPA to use only improvements at and
to existing sources in its [BSER].'' 985 F.3d at 944. The court found
``nothing in the text, structure, history, or purpose of [CAA section
111] that compels the reading the EPA adopted.'' 985 F.3d at 957. The
court likewise rejected the
[[Page 39827]]
view that the CPP's use of generation-shifting implicated a ``major
question'' requiring unambiguous authorization by Congress. 985 F.3d at
958-68.
The D.C. Circuit concluded that, because the EPA had relied on an
``erroneous legal premise,'' both the CPP Repeal Rule and the ACE Rule
should be vacated. 985 F.3d at 995. The court did not decide, however,
``whether the approach of the ACE Rule is a permissible reading of the
statute as a matter of agency discretion,'' 985 F.3d at 944, and
instead ``remanded to the EPA so that the Agency may `consider the
question afresh,' '' 985 F.3d at 995 (citations omitted).
The court also rejected the arguments that the EPA cannot regulate
CO2 emissions from coal-fired power plants under CAA section
111(d) at all because it had already regulated mercury emissions from
coal-fired power plants under CAA section 112. 985 F.3d at 988. In
addition, the court held that that the 2015 NSPS included a valid
determination that greenhouse gases from the EGU source category
contributed significantly to dangerous air pollution, which provided a
sufficient basis for a CAA section 111(d) rule regulating greenhouse
gases from existing fossil fuel-fired EGUs. Id. at 977.
Because the D.C. Circuit vacated the ACE Rule on the grounds noted
above, it did not address the other challenges to the ACE Rule,
including the arguments by Petitioners that the heat rate improvement
BSER was inadequate because of the limited number of reductions it
achieved and because the ACE Rule failed to include an appropriately
specific degree of emission limitation.
Upon a motion from the EPA, the D.C. Circuit agreed to stay its
mandate with respect to vacatur of the CPP Repeal, American Lung Assn
v. EPA, No. 19-1140, Order (February 22, 2021), so that the CPP
remained repealed. Therefore, following the D.C. Circuit's decision, no
EPA rule under CAA section 111 to reduce GHGs from existing fossil
fuel-fired EGUs remained in place.
6. U.S. Supreme Court Decision in West Virginia v. EPA Concerning the
CPP
The Supreme Court granted petitions for certiorari from the D.C.
Circuit's American Lung Association decision, limited to the question
of whether CAA section 111 authorized the EPA to determine that
``generation shifting'' was the best system of emission reduction for
fossil-fuel fired EGUs. The Supreme Court did not grant certiorari on
the question of whether the EPA was authorized to regulate GHG
emissions from fossil-fuel fired power plants under CAA section 111,
when fossil-fuel fired power plants are regulated for other pollutants
under CAA section 112. In 2022, the U.S. Supreme Court reversed the
D.C. Circuit's vacatur of the ACE Rule's embedded repeal of the CPP.
West Virginia v. EPA, 597 U.S. 697 (2022). The Supreme Court stated
that CAA section 111 authorizes the EPA to determine the BSER and the
degree of emission limitation that state plans must achieve. Id. at
2601-02. The Supreme Court concluded, however, that the CPP's BSER of
``generation-shifting'' raised a ``major question,'' and was not
clearly authorized by section 111. The Court characterized the
generation-shifting BSER as ``restructuring the Nation's overall mix of
electricity generation,'' and stated that the EPA's claim that CAA
section 111 authorized it to promulgate generation shifting as the BSER
was ``not only unprecedented; it also effected a fundamental revision
of the statute, changing it from one sort of scheme of regulation into
an entirely different kind.'' Id. at 2612 (internal quotation marks,
brackets, and citation omitted). The Court explained that the EPA, in
prior rules under CAA section 111, had set emissions limits based on
``measures that would reduce pollution by causing the regulated source
to operate more cleanly.'' Id. at 2610. The Court noted with approval
those ``more traditional air pollution control measures,'' and gave as
examples ``fuel-switching'' and ``add-on controls,'' which, the Court
observed, the EPA had considered in the CPP. Id. at 2611 (internal
quotations marks and citation omitted). In contrast, the Court
continued, generation shifting was ``unprecedented'' because ``[r]ather
than focus on improving the performance of individual sources, it would
improve the overall power system by lowering the carbon intensity of
power generation. And it would do that by forcing a shift throughout
the power grid from one type of energy source to another.'' Id. at
2611-12 (internal quotation marks, emphasis, and citation omitted).
The Court recognized that a rule based on traditional measures
``may end up causing an incidental loss of coal's market share,'' but
emphasized that the CPP was ``obvious[ly] differen[t]'' because, with
its generation-shifting BSER, it ``simply announc[ed] what the market
share of coal, natural gas, wind, and solar must be, and then
require[ed] plants to reduce operations or subsidize their competitors
to get there.'' Id. at 2613 n.4. The Court also emphasized ``the
magnitude and consequence'' of the CPP. Id. at 2616. It noted ``the
magnitude of this unprecedented power over American industry,'' id. at
2612 (internal quotation marks and citation omitted), and added that
the EPA's adoption of generation shifting ``represent[ed] a
transformative expansion in its regulatory authority.'' Id. at 2610
(internal quotation marks and citation omitted). The Court also viewed
the CPP as promulgating ``a program that . . . Congress had considered
and rejected multiple times.'' Id. at 2614 (internal quotation marks
and citation omitted). For these and related reasons, the Court viewed
the CPP as raising a major question, and therefore, requiring ``clear
congressional authorization'' as a basis. Id. (internal quotation marks
and citation omitted).
The Court declined to address the D.C. Circuit's conclusion that
the text of CAA section 111 did not limit the type of ``system'' the
EPA could consider as the BSER to measures applied at and to an
individual source. See id. at 2615. Nor did the Court address the scope
of the states' compliance flexibilities.
7. D.C. Circuit Order Reinstating the ACE Rule
On October 27, 2022, the D.C. Circuit responded to the U.S. Supreme
Court's reversal by recalling its mandate for the vacatur of the ACE
Rule. American Lung Ass'n v. EPA, No. 19-1140, Order (October 27,
2022). Accordingly, at that time, the ACE Rule came back into effect.
The court also revised its judgment to deny petitions for review
challenging the CPP Repeal Rule, consistent with the judgment in West
Virginia, so that the CPP remains repealed. The court took further
action denying several of the petitions for review unaffected by the
Supreme Court's decision in West Virginia, which means that certain
parts of its 2021 decision in American Lung Association remain in
effect. These parts include the holding that the EPA's prior regulation
of mercury emissions from coal-fired electric power plants under CAA
section 112 does not preclude the Agency from regulating CO2
from coal-fired electric power plants under CAA section 111, and the
holding, discussed above, that the 2015 NSPS included a valid
significant contribution determination and therefore provided a
sufficient basis for a CAA section 111(d) rule regulating greenhouse
gases from existing fossil fuel-fired EGUs. The court's holding to
invalidate amendments to the implementing regulations applicable to
emission guidelines under CAA section 111(d) that extended the
preexisting schedules
[[Page 39828]]
for state and Federal actions and sources' compliance, also remains in
force. Based on the EPA's stated intention to replace the ACE Rule, the
court stayed further proceedings with respect to the ACE Rule,
including the various challenges that its BSER was flawed because it
did not achieve sufficient emission reductions and failed to specify an
appropriately specific degree of emission limitation.
C. Detailed Discussion of CAA Section 111 Requirements
This section discusses in more detail the key requirements of CAA
section 111 for both new and existing sources that are relevant for
these rulemakings.
1. Approach to the Source Category and Subcategorizing
CAA section 111 requires the EPA first to list stationary source
categories that cause or contribute to air pollution which may
reasonably be anticipated to endanger public health or welfare and then
to regulate new sources within each such source category. CAA section
111(b)(2) grants the EPA discretion whether to ``distinguish among
classes, types, and sizes within categories of new sources for the
purpose of establishing [new source] standards,'' which we refer to as
``subcategorizing.'' Whether and how to subcategorize is a decision for
which the EPA is entitled to a ``high degree of deference'' because it
entails ``scientific judgment.'' Lignite Energy Council v. EPA, 198
F.3d 930, 933 (D.C. Cir. 1999).
Although CAA section 111(d)(1) does not explicitly address
subcategorization, since its first regulations implementing the CAA,
the EPA has interpreted it to authorize the Agency to exercise
discretion as to whether and, if so, how to subcategorize, for the
following reasons. CAA section 111(d)(1) grants the EPA authority to
``prescribe regulations which shall establish a procedure . . . under
which each State shall submit to the Administrator a plan [with
standards of performance for existing sources.]'' The EPA promulgates
emission guidelines under this provision directing the states to
regulate existing sources. The Supreme Court has recognized that, under
CAA section 111(d), the ``Agency, not the States, decides the amount of
pollution reduction that must ultimately be achieved. It does so by
again determining, as when setting the new source rules, `the best
system of emission reduction . . . that has been adequately
demonstrated for [existing covered] facilities.' West Virginia, 597
U.S. at 710 (citations omitted).
The EPA's authority to determine the BSER includes the authority to
create subcategories that tailor the BSER for differently situated sets
of sources. Again, for new sources, CAA section 111(b)(2) confers
authority for the EPA to ``distinguish among classes, types, and sizes
within categories.'' Though CAA section 111(d) does not speak
specifically to the creation of subcategories for a category of
existing sources, the authority to identify the ``best'' system of
emission reduction for existing sources includes the discretion to
differentiate between differently situated sources in the category, and
group those sources into subcategories in appropriate circumstances.
The size, type, class, and other characteristics can make different
emission controls more appropriate for different sources. A system of
emission reduction that is ``best'' for some sources may not be
``best'' for others with different characteristics. For more than four
decades, the EPA has interpreted CAA section 111(d) to confer authority
on the Agency to create subcategories. The EPA's implementing
regulations under CAA section 111(d), promulgated in 1975, 40 FR 53340
(November 17, 1975), provide that the Administrator will specify
different emission guidelines or compliance times or both ``for
different sizes, types, and classes of designated facilities when
[based on] costs of control, physical limitations, geographical
location, or [based on] similar factors.'' \187\ This regulation
governs the EPA's general authority to subcategorize under CAA section
111(d), and the EPA is not reopening that issue here. At the time of
promulgation, the EPA explained that subcategorization allows the EPA
to take into account ``differences in sizes and types of facilities and
similar considerations, including differences in control costs that may
be involved for sources located in different parts of the country'' so
that the ``EPA's emission guidelines will in effect be tailored to what
is reasonably achievable by particular classes of existing sources. . .
.'' Id. at 53343. The EPA's authority to ``distinguish among classes,
types, and sizes within categories,'' as provided under CAA section
111(b)(2), generally allows the Agency to place types of sources into
subcategories. This is consistent with the commonly understood meaning
of the term ``type'' in CAA section 111(b)(2): ``a particular kind,
class, or group,'' or ``qualities common to a number of individuals
that distinguish them as an identifiable class.'' See https://www.merriam-webster.com/dictionary/type.
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\187\ 40 CFR 60.22(b)(5), 60.22a(b)(5). Because the definition
of subcategories depends on characteristics relevant to the BSER,
and because those characteristics can differ as between new and
existing sources, the EPA may establish different subcategories as
between new and existing sources.
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The EPA has developed subcategories in many rulemakings under CAA
section 111 since the 1970s. These rulemakings have included
subcategories on the basis of the size of the sources, see 40 CFR
60.40b(b)(1)-(2) (subcategorizing certain coal-fired steam generating
units on the basis of heat input capacity); the types of fuel
combusted, see Sierra Club, v. EPA, 657 F.2d 298, 318-19 (D.C. Cir.
1981) (upholding a rulemaking that established different NSPS ``for
utility plants that burn coal of varying sulfur content''), 2015 NSPS,
80 FR 64510, 64602 (table 15) (October 23, 2015) (subdividing new
combustion turbines on the basis of type of fuel combusted); the types
of equipment used to produce products, see 81 FR 35824 (June 3, 2016)
(promulgating separate NSPS for many types of oil and gas sources, such
as centrifugal compressors, pneumatic controllers, and well sites);
types of manufacturing processes used to produce product, see 42 FR
12022 (March 1, 1977) (announcing availability of final guideline
document for control of atmospheric fluoride emissions from existing
phosphate fertilizer plants) and ``Final Guideline Document: Control of
Fluoride Emissions From Existing Phosphate Fertilizer Plants,'' EPA-
450/2-77-005 1-7 to 1-9, including table 1-2 (applying different
control requirements for different manufacturing operations for
phosphate fertilizer); levels of utilization of the sources, see 2015
NSPS, 80 FR 64510, 64602 (table 15) (October 23, 2015) (dividing new
natural gas-fired combustion turbines into the subcategories of base
load and non-base load); the activity level of the sources, see 81 FR
59276, 59278-79 (August 29, 2016) (dividing municipal solid waste
landfills into the subcategories of active and closed landfills); and
geographic location of the sources, see 71 FR 38482 (July 6, 2006)
(SO2 NSPS for stationary combustion turbines subcategorizing
turbines on the basis of whether they are located in, for example, a
continental area, a non-continental area, the part of Alaska north of
the Arctic Circle, and the rest of Alaska). Thus, the EPA has
subcategorized many times in rulemaking under CAA sections 111(b) and
111(d) and based on a wide variety of physical, locational, and
operational characteristics.
Regardless of whether the EPA subcategorizes within a source
category
[[Page 39829]]
for purposes of determining the BSER and the degree of emission
limitation achievable, a state retains certain flexibility in assigning
standards of performance to its affected EGUs. The statutory framework
for CAA section 111(d) emission guidelines, and the flexibilities
available to states within that framework, are discussed below.
2. Key Elements of Determining a Standard of Performance
Congress first included the definition of ``standard of
performance'' when enacting CAA section 111 in the 1970 Clean Air Act
Amendments (CAAA), amended it in the 1977 CAAA, and then amended it
again in the 1990 CAAA to largely restore the definition as it read in
the 1970 CAAA. The current text of CAA section 111(a)(1) reads: ``The
term `standard of performance' means a standard for emission of air
pollutants which reflects the degree of emission limitation achievable
through the application of the best system of emission reduction which
(taking into account the cost of achieving such reduction and any non-
air quality health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated.'' The
D.C. Circuit has reviewed CAA section 111 rulemakings on numerous
occasions since 1973,\188\ and has developed a body of caselaw that
interprets the term ``standard of performance,'' as discussed
throughout this preamble.
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\188\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C.
Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C.
Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981);
Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999);
Portland Cement Ass'n v. EPA, 665 F.3d 177 (D.C. Cir. 2011);
American Lung Ass'n v. EPA, 985 F.3d 914 (D.C. Cir. 2021), rev'd in
part, West Virginia v. EPA, 597 U.S. 697 (2022). See also Delaware
v. EPA, No. 13-1093 (D.C. Cir. May 1, 2015).
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The basis for standards of performance, whether promulgated by the
EPA under CAA section 111(b) or established by the states under CAA
section 111(d), is that the EPA determines the ``degree of emission
limitation'' that is ``achievable'' by the sources by application of a
``system of emission reduction'' that the EPA determines is
``adequately demonstrated,'' ``taking into account'' the factors of
``cost . . . and any nonair quality health and environmental impact and
energy requirements,'' and that the EPA determines to be the ``best.''
The D.C. Circuit has stated that in determining the ``best'' system,
the EPA must also take into account ``the amount of air pollution''
\189\ reduced and the role of ``technological innovation.'' \190\ The
D.C. Circuit has also stated that to determine the ``best'' system, the
EPA may weigh the various factors identified in the statute and caselaw
against each other, and has emphasized that the EPA has discretion in
weighing the factors.191 192
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\189\ See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir.
1981).
\190\ See Sierra Club v. Costle, 657 F.2d at 347.
\191\ See Lignite Energy Council, 198 F.3d at 933.
\192\ CAA section 111(a)(1), by its terms states that the
factors enumerated in the parenthetical are part of the ``adequately
demonstrated'' determination. In addition, the D.C. Circuit's
caselaw makes clear that the EPA may consider these same factors
when it determines which adequately demonstrated system of emission
reduction is the ``best.'' See Sierra Club v. Costle, 657 F.2d at
330 (recognizing that CAA section 111 gives the EPA authority ``when
determining the best technological system to weigh cost, energy, and
environmental impacts'').
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The EPA's overall approach to determining the BSER and degree of
emission limitation achievable, which incorporates the various
elements, is as follows: The EPA identifies ``system[s] of emission
reduction'' that have been ``adequately demonstrated'' for a particular
source category and determines the ``best'' of these systems after
evaluating the amount of emission reductions, costs, any non-air health
and environmental impacts, and energy requirements. As discussed below,
for each of numerous subcategories, the EPA followed this approach to
determine the BSER on the basis that the identified costs are
reasonable and that the BSER is rational in light of the statutory
factors, including the amount of emission reductions, that the EPA
examined in its BSER analysis, consistent with governing precedent.
After determining the BSER, the EPA determines an achievable
emission limit based on application of the BSER.\193\ For a CAA section
111(b) rule, the EPA determines the standard of performance that
reflects the achievable emission limit. For a CAA section 111(d) rule,
the states have the obligation of establishing standards of performance
for the affected sources that reflect the degree of emission limitation
that the EPA has determined. As discussed below, the EPA is finalizing
these determinations in association with each of the BSER
determinations.
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\193\ See, e.g., Oil and Natural Gas Sector: New Source
Performance Standards and National Emission Standards for Hazardous
Air pollutants Reviews (77 FR 49494; August 16, 2012) (describing
the three-step analysis in setting a standard of performance).
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The remainder of this subsection discusses each element in our
general analytical approach.
a. System of Emission Reduction
The CAA does not define the phrase ``system of emission
reduction.'' In West Virginia v. EPA, the Supreme Court recognized that
historically, the EPA had looked to ``measures that improve the
pollution performance of individual sources and followed a
``technology-based approach'' in identifying systems of emission
reduction. In particular, the Court identified ``the sort of `systems
of emission reduction' [the EPA] had always before selected,'' which
included `` `efficiency improvements, fuel-switching,' and `add-on
controls'.'' 597 U.S. at 727 (quoting the Clean Power Plan).\194\
Section 111 itself recognizes that such systems may include off-site
activities that may reduce a source's pollution contribution,
identifying ``precombustion cleaning or treatment of fuels'' as a
``system'' of ``emission reduction.'' 42 U.S.C. 7411(a)(7)(B). A
``system of emission reduction'' thus, at a minimum, includes measures
that an individual source applies that improve the emissions
performance of that source. Measures are fairly characterized as
improving the pollution performance of a source where they reduce the
individual source's overall contribution to pollution.
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\194\ As noted in section V.B.4 of this preamble, the ACE Rule
adopted the interpretation that CAA section 111(a)(1), by its plain
language, limits ``system of emission reduction'' to those control
measures that could be applied at and to each source to reduce
emissions at each source. 84 FR 32523-24 (July 8, 2019). The EPA has
subsequently rejected that interpretation as too narrow. See
Adoption and Submittal of State Plans for Designated Facilities:
Implementing Regulations Under Clean Air Act Section 111(d), 88 FR
80535 (November 17, 2023).
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In West Virginia, the Supreme Court did not define the term
``system of emissions reduction,'' and so did not rule on whether
``system of emission reduction'' is limited to those measures that the
EPA has historically relied upon. It did go on to apply the major
questions doctrine to hold that the term ``system'' does not provide
the requisite clear authorization to support the Clean Power Plan's
BSER, which the Court described as ``carbon emissions caps based on a
generation shifting approach.'' Id. at 2614. While the Court did not
define the outer bounds of the meaning of ``system,'' systems of
emissions reduction like fuel switching, add-on controls, and
efficiency improvements fall comfortably within the scope of prior
practice as recognized by the Supreme Court.
b. ``Adequately Demonstrated''
Under CAA section 111(a)(1), an essential, although not sufficient,
condition for a ``system of emission
[[Page 39830]]
reduction'' to serve as the basis for an ``achievable'' emission
standard is that the Administrator must determine that the system is
``adequately demonstrated.'' The concepts of adequate demonstration and
achievability are closely related: as the D.C. Circuit has stated,
``[i]t is the system which must be adequately demonstrated and the
standard which must be achievable,'' \195\ through application of the
system. An achievable standard means a standard based on the EPA's
record-based finding that sufficient evidence exists to reasonably
determine that the affected sources in the source category can adopt a
specific system of emission reduction to achieve the specified degree
of emission limitation. As discussed below, consistent with Congress's
use of the word ``demonstrated,'' the caselaw has approved the EPA's
``adequately demonstrated'' determinations concerning systems utilized
at test sources or other individual sources operating at commercial
scale. The case law also authorizes the EPA to set an emissions
standard at levels more stringent than has regularly been achieved,
based on the understanding that sources will be able to adopt specific
technological improvements to the system in question that will enable
them to achieve the lower standard. Importantly, and contrary to some
comments received on the proposed rule, CAA section 111(a)(1) does not
require that a system of emission reduction exist in widespread
commercial use in order to satisfy the ``adequately demonstrated''
requirement.\196\ Instead, CAA section 111(a)(1) authorizes the EPA to
establish standards which encourage the deployment of more effective
systems of emission reduction that have been adequately demonstrated
but that are not yet in widespread use. This aligns with Congress's
purpose in enacting the CAA, in particular its recognition that
polluting sources were not widely adopting emission control technology
on a voluntary basis and that Federal regulation was necessary to spur
the development and deployment of those technologies.\197\
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\195\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (1973)
(emphasis omitted).
\196\ See, e.g., Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427
(D.C. Cir. 1973) (in which the D.C. Circuit upheld a CAA section 111
standard based on a system which had been extensively used in Europe
but at the time of promulgation was only in use in the United States
at one plant).
\197\ In introducing the respective bills which ultimately
became the 1970 Clean Air Act upon Conference Committee review, both
the House and Senate emphasized the urgency of the matter at hand,
the intended power of the new legislation, and in particular its
technology-forcing nature. The first page of the House report
declared that ``[t]he purpose of the legislation reported
unanimously by [Committee was] to speed up, expand, and intensify
the war against air pollution in the United States . . .'' H.R. Rep.
No. 17255 at 1 (1970). It was clear, stated the House report, that
until that point ``the strategies which [the United States had]
pursued in the war against air pollution [had] been inadequate in
several important respects, and the methods employed in implementing
those strategies often [had] been slow and less effective than they
might have been.'' Id. The Senate report agreed, stating that their
bill would ``provide a much more intensive and comprehensive attack
on air pollution,'' 1 S. 4358 at 4 (1970), including, crucially, by
increased federal involvement. See id.
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i. Plain Text, Statutory Context, and Legislative History of the
``Adequately Demonstrated'' Provision in CAA Section 111(a)(1)
Analysis of the plain text, statutory context, and legislative
history of CAA section 111(a)(1) establishes two primary themes. First,
Congress assigned the task of determining the appropriate BSER to the
Administrator, based on a reasonable review of available evidence.
Second, Congress authorized the EPA to set a standard, based on the
evidence, that encourages broader adoption of an emissions-reducing
technological approach that may not yet be in widespread use.
The plain text of CAA section 111(a)(1), and in particular the
phrase ``the Administrator determines'' and the term ``adequately,''
confer discretion to the EPA in identifying the appropriate system.
Rather than providing specific criteria for determining what
constitutes appropriate evidence, Congress directed the Administrator
to ``determine[ ]'' that the demonstration is ``adequate[ ].'' Courts
have typically deferred to the EPA's scientific and technological
judgments in making such determinations.\198\ Further, use of the term
``adequate'' in provisions throughout the CAA highlights EPA
flexibility and discretion in setting standards and in analyzing data
that forms the basis for standard setting.
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\198\ The D.C. Circuit stated in Nat'l Asphalt Pavement Ass'n v.
Train, 539 F.2d 775, 786 (D.C. Cir. 1976) ``The standard of review
of actions of the Administrator in setting standards of performance
is an appropriately deferential one, and we are to affirm the action
of the Administrator unless it is ``arbitrary, capricious, an abuse
of discretion, or otherwise not in accordance with law,'' 5 U.S.C.
706(2)(A) (1970). Since this is one of those ``highly technical
areas, where our understanding of the import of the evidence is
attenuated, our readiness to review evidentiary support for
decisions must be correspondingly restrained.'' Ethyl Corporation v.
EPA, 96 S. Ct. 2663 (1976). ``Our `expertise' is not in setting
standards for emission control, but in determining if the standards
as set are the result of reasoned decision-making.'' Essex Chem.
Corp. v. Ruckelshaus, 486 F.2d 427, 434 (D.C. Cir. 1973)) (cleaned
up).''
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In setting NAAQS under CAA section 109, for example, the EPA is
directed to determine, according to ``the judgment of the
Administrator,'' an ``adequate margin of safety.'' \199\ The D.C.
Circuit has held that the use of the term ``adequate'' confers
significant deference to the Administrator's scientific and
technological judgment. In Mississippi v. EPA,\200\ for example, the
D.C. Circuit in 2013 upheld the EPA's choice to set the NAAQS for ozone
below 0.08 ppm, and noted that any disagreements with the EPA's
interpretations of the scientific evidence that underlay this decision
``must come from those who are qualified to evaluate the science, not
[the court].'' \201\ This Mississippi v. EPA precedent aligns with the
general standard for judicial review of the EPA's understanding of the
evidence under CAA section 307(d)(9)(A) (``arbitrary, capricious, an
abuse of discretion, or otherwise not in accordance with law'').
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\199\ 42 U.S.C. 7409(b)(1).
\200\ 744 F.3d 1334 (D.C. Cir. 2013).
\201\ Id.
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The plain language of the phrase ``has been adequately
demonstrated,'' in context, and in light of the legislative history,
further strongly indicates that the system in question need not be in
widespread use at the time the EPA's rule is published. To the
contrary, CAA section 111(a)(1) authorizes technology forcing, in the
sense that the EPA is authorized to promote a system which is not yet
in widespread use; provided the technology is in existence and the EPA
has adequate evidence to extrapolate.\202\
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\202\ While not relevant here, because CCS is already in
existence, the text, case law, and legislative history make a
compelling case that EPA is authorized to go farther than this, and
may make a projection regarding the way in which a particular system
will develop to allow for greater emissions reductions in the
future. See 80 FR 64556-58 (discussion of ``adequately
demonstrated'' in 2015 NSPS).
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Some commenters argued that use of the phrase ``has been'' in ``has
been adequately demonstrated'' means that the system must be in
widespread commercial use at the time of rule promulgation. We
disagree. Considering the plain text, the use of the past tense, ``has
been adequately demonstrated'' indicates a requirement that the
technology currently be demonstrated. However, ``demonstrated'' in
common usage at the time of enactment meant to ``explain or make clear
by using examples, experiments, etc.'' \203\ As a general matter, and
as this definition indicates, the term ``to demonstrate'' suggests the
need for a test or study--as in, for example, a ``demonstration
[[Page 39831]]
project'' or ``demonstration plant''--that is, examples of
technological feasibility.
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\203\ Webster's New World Dictionary: Second College Edition
(David B. Guralnik, ed., 1972).
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The statutory context is also useful in establishing that where
Congress wanted to specify the availability of the control system, it
did so. The only other use of the exact term ``adequately
demonstrated'' occurs in CAA section 119, which establishes that, in
order for the EPA to require a particular ``means of emission
limitation'' for smelters, the Agency must establish that such means
``has been adequately demonstrated to be reasonably available. . . .''
\204\ The lack of the phrase ``reasonably available'' in CAA section
111(a)(1) is notable, and suggests that a system may be ``adequately
demonstrated'' under CAA section 111 even if it is not ``reasonably
available'' for every single source.\205\
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\204\ The statutory text at CAA section 119 continues, ``as
determined by the Administrator, taking into account the cost of
compliance, nonair quality health and environmental impact, and
energy consideration.'' 42 U.S.C. 7419(b)(3).
\205\ It should also be noted that the section 119 language was
added as part of the 1977 Clean Air Act amendments, while the
section 111 language was established in 1970. Thus, Congress was
aware of section 111's more permissive language when it added the
``reasonably available'' language to section 119.
---------------------------------------------------------------------------
The term ``demonstration'' also appears in CAA section 103 in an
instructive context. CAA section 103, which establishes a ``national
research and development program for the prevention and control of air
pollution'' directs that as part of this program, the EPA shall
``conduct, and promote the coordination and acceleration of, research,
investigations, experiments, demonstrations, surveys, and studies
relating to'' the issue of air pollution.\206\ According to the canon
of noscitur a sociis, associated words in a list bear on one another's
meaning.\207\ In CAA section 103, the word ``demonstrations'' appears
alongside ``research,'' ``investigations,'' ``experiments,'' and
``studies''--all words suggesting the development of new and emerging
technology. This supports interpreting CAA section 111(a)(1) to
authorize the EPA to determine a system of emission reduction to be
``adequately demonstrated'' based on demonstration projects, testing,
examples, or comparable evidence.
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\206\ 42 U.S.C. 7403(a)(1).
\207\ As the Supreme Court recently explained in Dubin v. United
States, even words that might be indeterminate alone may be more
easily interpreted in ``company,'' because per noscitur a sociis ``a
word is known by the company it keeps.'' 599 U.S. 110, 244 (2023).
---------------------------------------------------------------------------
Finally, the legislative history of the CAA in general, and section
111 in particular, strongly supports the point that BSER technology
need not be in widespread use at the time of rule enactment. The final
language of CAA section 111(a)(1), requiring that systems of emission
reduction be ``adequately demonstrated,'' was the result of compromise
in the Conference Committee between the House and Senate bill language.
The House bill would have required that the EPA give ``appropriate
consideration to technological and economic feasibility'' when
establishing standards.\208\ The Senate bill would have required that
standards ``reflect the greatest degree of emission control which the
Secretary determines to be achievable through application of the latest
available control technology, processes, operating methods, or other
alternatives.'' \209\ Although the exact language of neither the House
nor Senate bill was adopted in the final bill, both reports made clear
their intent that CAA section 111 would be significantly technology-
forcing. In particular, the Senate Report referred to ``available
control technology''--a phrase that, as just noted, the Senate bill
included--but clarified that the technology need not ``be in actual,
routine use somewhere.'' \210\ The House Report explained that EPA
regulations would ``prevent and control such emissions to the fullest
extent compatible with the available technology and economic
feasibility as determined by [the EPA],'' and ``[i]n order to be
considered `available' the technology may not be one which constitutes
a purely theoretical or experimental means of preventing or controlling
air pollution.'' \211\ This last statement implies that the House
Report anticipated that the EPA's determination may be technology
forcing. Nothing in the legislative history suggests that Congress
intended that the technology already be in widespread commercial use.
---------------------------------------------------------------------------
\208\ H.R. Rep. No. 17255 at 921 (1970) (quoting CAA Sec.
112(a), as proposed).
\209\ S. Rept. 4358 at 91 (quoting CAA Sec. 113(b)(2), as
proposed).
\210\ S. Rep. 4358 at 15-16 (1970). The Senate Report went on to
say that the EPA should ``examine the degree of emission control
that has been or can be achieved through the application of
technology which is available or normally can be made available . .
. at a cost and at a time which [the Agency] determines to be
reasonable.'' Id. Again, this language rebuts any suggestion that a
BSER technology must be in widespread use at the time of rule
enactment--Congress assumed only that the technology would be
``available'' or even that it ``[could] be made available,'' not
that it would be already broadly used.
\211\ H.R. Rep. No. 17255 at 900.
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ii. Caselaw
In a series of cases reviewing standards for new sources, the D.C.
Circuit has held that an adequately demonstrated standard of
performance may reflect the EPA's reasonable projection of what that
particular system may be expected to achieve going forward,
extrapolating from available data from pilot projects or individual
commercial-scale sources. A standard may be considered achievable even
if the system upon which the standard is based has not regularly
achieved the standard in testing. See, e.g., Essex Chem. Corp. v.
Ruckelshaus \212\ (upholding a standard of 4.0 lbs per ton based on a
system whose average control rate was 4.6 lbs per ton, and which had
achieved 4.0 lbs per ton on only three occasions and ```nearly equaled'
[the standard] on the average of nineteen different readings.'') \213\
The Ruckelshaus court concluded that the EPA's extrapolation from
available data was ``the result of the exercise of reasoned discretion
by the Administrator'' and therefore ``[could not] be upset by [the]
court.'' \214\ The court also emphasized that in order to be considered
achievable, the standard set by the EPA need not be regularly or even
specifically achieved at the time of rule promulgation. Instead,
according to the court, ``[a]n achievable standard is one which is
within the realm of the adequately demonstrated system's efficiency and
which, while not at a level that is purely theoretical or experimental,
need not necessarily be routinely achieved within the industry prior to
its adoption.'' \215\
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\212\ 486 F.2d 427 (D.C. Cir. 1973).
\213\ Id. at 437.
\214\ Id. at 437.
\215\ Id. at 433-34 (D.C. Cir. 1973). See also Sierra Club v.
Costle, 657 F.2d 298 (D.C. Cir. 1981), which supports the point that
EPA may extrapolate from testing results, rather than relying on
consistent performance, to identify an appropriate system and
standard based on that system. In that case, EPA analyzed scrubber
performance by considering performance during short-term testing
periods. See id. at 377.
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Case law also establishes that the EPA may set a standard more
stringent than has regularly been achieved based on its identification
of specific available technological improvements to the system. See
Sierra Club v. Costle \216\ (upholding a 90 percent standard for
SO2 emissions from coal-fired steam generators despite the
fact that not all plants had previously achieved this standard, based
on the EPA's expectations for improved performance with specific
technological fixes and the use of ``coal washing'' going
forward).\217\ Further, the EPA may extrapolate based on testing at a
particular kind of source to conclude that the technology at issue will
also be effective at a different,
[[Page 39832]]
related, source. See Lignite Energy Council v. EPA \218\ (holding it
permissible to base a standard for industrial boilers on application of
SCR based on extrapolated information about the application of SCR on
utility boilers).\219\ The Lignite court clarified that ``where data
are unavailable, EPA may not base its determination that a technology
is adequately demonstrated or that a standard is achievable on mere
speculation or conjecture,'' but the ``EPA may compensate for a
shortage of data through the use of other qualitative methods,
including the reasonable extrapolation of a technology's performance in
other industries.'' \220\
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\216\ 657 F.2d 298 (D.C. Cir. 1981).
\217\ Id. at 365, 370-73; 365.
\218\ 198 F.3d 930 (D.C. Cir. 1999).
\219\ See id. at 933-34.
\220\ Id. at 934 (emphasis added).
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As a general matter, the case law is clear that at the time of Rule
promulgation, the system which the EPA establishes as BSER need not be
in widespread use. See, e.g., Ruckelshaus \221\ (upholding a standard
based on a relatively new system which was in use at only one United
States plant at the time of rule promulgation. Although the system was
in use more extensively in Europe at the time of rule promulgation, the
EPA based its analysis on test results from the lone U.S. plant only.)
\222\ This makes good sense, because, as discussed above, CAA section
111(a)(1) authorizes a technology-forcing standard that encourages
broader adoption of an emissions-reducing technological approach that
is not yet broadly used. It follows that at the time of promulgation,
not every source will be prepared to adopt the BSER at once. Instead,
as discussed next, the EPA's responsibility is to determine that the
technology can be adopted in a reasonable period of time, and to base
its requirements on this understanding.
---------------------------------------------------------------------------
\221\ 486 F.2d 375 (D.C. Cir. 1973). See also Sierra Club v.
Costle, 657 F.2d 298 (D.C. Cir. 1981), which supports the point that
EPA may extrapolate from testing results, rather than relying on
consistent performance, to identify an appropriate system and
standard based on that system. In that case, EPA analyzed scrubber
performance by considering performance during short-term testing
periods. See id. at 377.
\222\ 486 F.2d at 435-36.
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iii. Compliance Timeframe
The preceding subsections have shown various circumstances under
which the EPA may determine that a system of emission reduction is
``adequately demonstrated.'' In order to establish that a system is
appropriate for the source category as a whole, the EPA must also
demonstrate that the industry can deploy the technology at scale in the
compliance timeframe. The D.C. Circuit has stated that the EPA may
determine a ``system of emission reduction'' to be ``adequately
demonstrated'' if the EPA reasonably projects that it may be more
broadly deployed with adequate lead time. This view is well-grounded in
the purposes of CAA section 111(a)(1), discussed above, which aim to
control dangerous air pollution by allowing for standards which
encourage more widespread adoption of a technology demonstrated at
individual plants.
As a practical matter, CAA section 111's allowance for lead time
recognizes that existing pollution control systems may be complex and
may require a predictable amount of time for sources across the source
category to be able to design, acquire, install, test, and begin to
operate them.\223\ Time may also be required to allow for the
development of skilled labor, and materials like steel, concrete, and
speciality parts. Accordingly, in setting 111 standards for both new
and existing sources, the EPA has typically allowed for some amount of
time before sources must demonstrate compliance with the standards. For
instance, in the 2015 NSPS for residential wood heaters, the EPA
established a ``stepped compliance approach'' which phased in
requirements over 5 years to ``allow manufacturers lead time to
develop, test, field evaluate and certify current technologies'' across
their model lines.\224\ The EPA also allowed for a series of phase-ins
of various requirements in the 2023 oil and gas NSPS.\225\ For example:
the EPA finalized a compliance deadline for process controllers
allowing for 1 year from the effective date of the final rule, to allow
for delays in equipment availability; \226\ the EPA established a 1-
year lead time period for pumps, also in response to possible equipment
and labor shortages; \227\ and the EPA built in 24 months between
publication in the Federal Register and the commencement of a
requirement to end routine flaring and route associated gas to a sales
line.\228\
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\223\ As discussed above, although the EPA is not relying on
this point for purposes of these rules, it should be noted that the
EPA may determine a system of emission reduction to be adequately
demonstrated based on some amount of projection, even if some
aspects of the system are still in development. Thus, the
authorization for lead time accommodates the development of
projected technology.
\224\ See Standards of Performance for New Residential Wood
Heaters, New Residential Hydronic Heaters and Forced-Air Furnaces,
80 FR 13672, 13676 (March 16, 2015).
\225\ See Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. 89 FR 16943 (March 8, 2024).
\226\ See id. at 16929.
\227\ See id. at 16937.
\228\ See id. at 16886.
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Finally, the EPA's longstanding regulations for new source
performance standards under CAA section 111 specifically authorize a
minimum period for lead time. Pursuant to 40 CFR 60.11, compliance with
CAA section 111 standards is generally determined in accordance with
performance tests conducted under 40 CFR 60.8. Both of these regulatory
provisions were adopted in 1971. Under 40 CFR 60.8, source performance
is generally measured via performance tests, which must typically be
carried out ``within 60 days after achieving the maximum production
rate at which the affected facility will be operated, but not later
than 180 days after initial startup of such facility, or at such other
times specified by this part, and at such other times as may be
required by the Administrator under section 114 of the Act. . . .''
\229\ The fact that this provision has been in place for over 50 years
indicates that the EPA has long recognized the need for lead time for
at least one component of control development.\230\
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\229\ 40 CFR 60.8.
\230\ For further discussion of lead time in the context of this
rulemaking, see section VIII.F.
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c. Costs
Under CAA section 111(a)(1), in determining whether a particular
emission control is the ``best system of emission reduction . . .
adequately demonstrated,'' the EPA is required to take into account
``the cost of achieving [the emission] reduction.'' Although the CAA
does not describe how the EPA is to account for costs to affected
sources, the D.C. Circuit has formulated the cost standard in various
ways, including stating that the EPA may not adopt a standard the cost
of which would be ``excessive'' or ``unreasonable.'' 231 232
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\231\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
See 79 FR 1430, 1464 (January 8, 2014); Lignite Energy Council, 198
F.3d at 933 (costs may not be ``exorbitant''); Portland Cement Ass'n
v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975) (costs may not be
``greater than the industry could bear and survive'').
\232\ These cost formulations are consistent with the
legislative history of CAA section 111. The 1977 House Committee
Report noted:
In the [1970] Congress [sic: Congress's] view, it was only right
that the costs of applying best practicable control technology be
considered by the owner of a large new source of pollution as a
normal and proper expense of doing business.
1977 House Committee Report at 184. Similarly, the 1970 Senate
Committee Report stated:
The implicit consideration of economic factors in determining
whether technology is ``available'' should not affect the usefulness
of this section. The overriding purpose of this section would be to
prevent new air pollution problems, and toward that end, maximum
feasible control of new sources at the time of their construction is
seen by the committee as the most effective and, in the long run,
the least expensive approach.
S. Comm. Rep. No. 91-1196 at 16.
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[[Page 39833]]
The EPA has discretion in its consideration of cost under section
111(a), both in determining the appropriate level of costs and in
balancing costs with other BSER factors.\233\ To determine the BSER,
the EPA must weigh the relevant factors, including the cost of controls
and the amount of emission reductions, as well as other factors.\234\
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\233\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
\234\ Id. (EPA's conclusion that the high cost of control was
acceptable was ``a judgment call with which we are not inclined to
quarrel'').
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The D.C. Circuit has repeatedly upheld the EPA's consideration of
cost in reviewing standards of performance. In several cases, the court
upheld standards that entailed significant costs, consistent with
Congress's view that ``the costs of applying best practicable control
technology be considered by the owner of a large new source of
pollution as a normal and proper expense of doing business.'' \235\ See
Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir.
1973); \236\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 387-88
(D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298, 313 (D.C. Cir.
1981) (upholding NSPS imposing controls on SO2 emissions
from coal-fired power plants when the ``cost of the new controls . . .
is substantial. The EPA estimates that utilities will have to spend
tens of billions of dollars by 1995 on pollution control under the new
NSPS.'').
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\235\ 1977 House Committee Report at 184.
\236\ The costs for these standards were described in the
rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5769 (March
21, 1972).
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In its CAA section 111 rulemakings, the EPA has frequently used a
cost-effectiveness metric, which determines the cost in dollars for
each ton or other quantity of the regulated air pollutant removed
through the system of emission reduction. See, e.g., 81 FR 35824 (June
3, 2016) (NSPS for GHG and VOC emissions for the oil and natural gas
source category); 71 FR 9866, 9870 (February 27, 2006) (NSPS for
NOX, SO2, and PM emissions from fossil fuel-fired
electric utility steam generating units); 61 FR 9905, 9910 (March 12,
1996) (NSPS and emission guidelines for nonmethane organic compounds
and landfill gas from new and existing municipal solid waste
landfills); 50 FR 40158 (October 1, 1985) (NSPS for SO2
emissions from sweetening and sulfur recovery units in natural gas
processing plants). This metric allows the EPA to compare the amount a
regulation would require sources to pay to reduce a particular
pollutant across regulations and industries. In rules for the electric
power sector, the EPA has also looked at a metric that determines the
dollar increase in the cost of a MWh of electricity generated by the
affected sources due to the emission controls, which shows the cost of
controls relative to the output of electricity. See section
VII.C.1.a.ii of this preamble, which discusses $/MWh costs of the Good
Neighbor Plan for the 2015 Ozone NAAQS (88 FR 36654; June 5, 2023) and
the Cross-State Air Pollution Rule (CSAPR) (76 FR 48208; August 8,
2011). This metric facilitates comparing costs across regulations and
pollutants. In these final actions, as explained herein, the EPA looks
at both of these metrics, in addition to other cost evaluations, to
assess the cost reasonableness of the final requirements. The EPA's
consideration of cost reasonableness in this way meets the statutory
requirement that the EPA take into account ``the cost of achieving [the
emission] reduction'' under section 111(a)(1).
d. Non-Air Quality Health and Environmental Impact and Energy
Requirements
Under CAA section 111(a)(1), the EPA is required to take into
account ``any nonair quality health and environmental impact and energy
requirements'' in determining the BSER. Non-air quality health and
environmental impacts may include the impacts of the disposal of
byproducts of the air pollution controls, or requirements of the air
pollution control equipment for water. Portland Cement Ass'n v.
Ruckelshaus, 465 F.2d 375, 387-88 (D.C. Cir. 1973), cert. denied, 417
U.S. 921 (1974). Energy requirements may include the impact, if any, of
the air pollution controls on the source's own energy needs.
e. Sector or Nationwide Component of Factors in Determining the BSER
Another component of the D.C. Circuit's interpretations of CAA
section 111 is that the EPA may consider the various factors it is
required to consider on a national or regional level and over time, and
not only on a plant-specific level at the time of the rulemaking.\237\
The D.C. Circuit based this interpretation--which it made in the 1981
Sierra Club v. Costle case regarding the NSPS for new power plants--on
a review of the legislative history, stating,
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\237\ See 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club
v. Costle, 657 F.2d at 351).
[T]he Reports from both Houses on the Senate and House bills
illustrate very clearly that Congress itself was using a long-term
lens with a broad focus on future costs, environmental and energy
effects of different technological systems when it discussed section
111.\238\
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\238\ Sierra Club v. Costle, 657 F.2d at 331 (citations omitted)
(citing legislative history).
The court has upheld EPA rules that the EPA ``justified . . . in
terms of the policies of the Act,'' including balancing long-term
national and regional impacts. For example, the court upheld a standard
of performance for SO2 emissions from new coal-fired power
---------------------------------------------------------------------------
plants on grounds that it--
reflects a balance in environmental, economic, and energy
consideration by being sufficiently stringent to bring about
substantial reductions in SO2 emissions (3 million tons
in 1995) yet does so at reasonable costs without significant energy
penalties. . . .\239\
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\239\ Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 FR
33583-84; June 11, 1979).
The EPA interprets this caselaw to authorize it to assess the
impacts of the controls it is considering as the BSER, including their
costs and implications for the energy system, on a sector-wide,
regional, or national basis, as appropriate. For example, the EPA may
assess whether controls it is considering would create risks to the
reliability of the electricity system in a particular area or
nationwide and, if they would, to reject those controls as the BSER.
f. ``Best''
In determining which adequately demonstrated system of emission
reduction is the ``best,'' the EPA has broad discretion. In AEP v.
Connecticut, 564 U.S. 410, 427 (2011), the Supreme Court explained that
under CAA section 111, ``[t]he appropriate amount of regulation in any
particular greenhouse gas-producing sector cannot be prescribed in a
vacuum: . . . informed assessment of competing interests is required.
Along with the environmental benefit potentially achievable, our
Nation's energy needs and the possibility of economic disruption must
weigh in the balance. The Clean Air Act entrusts such complex balancing
to the EPA in the first instance, in combination with state regulators.
Each ``standard of performance'' the EPA sets must ``tak[e] into
account the cost of achieving [emissions] reduction and any nonair
quality health and environmental impact and energy requirements.''
(paragraphing revised; citations omitted)).
[[Page 39834]]
Likewise, in Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981),
the court explained that ``section 111(a) explicitly instructs the EPA
to balance multiple concerns when promulgating a NSPS,'' \240\ and
emphasized that ``[t]he text gives the EPA broad discretion to weigh
different factors in setting the standard,'' including the amount of
emission reductions, the cost of the controls, and the non-air quality
environmental impacts and energy requirements.\241\ And in Lignite
Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999), the court
reiterated:
---------------------------------------------------------------------------
\240\ Sierra Club v. Costle, 657 F.2d at 319.
\241\ Sierra Club v. Costle, 657 F.2d at 321; see also New York
v. Reilly, 969 F.2d at 1150 (because Congress did not assign the
specific weight the Administrator should assign to the statutory
elements, ``the Administrator is free to exercise [her] discretion''
in promulgating an NSPS).
Because section 111 does not set forth the weight that should be
assigned to each of these factors, we have granted the agency a
great degree of discretion in balancing them . . . . EPA's choice
[of the `best system'] will be sustained unless the environmental or
economic costs of using the technology are exorbitant . . . . EPA
[has] considerable discretion under section 111.\242\
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\242\ Lignite Energy Council, 198 F.3d at 933 (paragraphing
revised for convenience). See New York v. Reilly, 969 F.2d 1147,
1150 (D.C. Cir. 1992) (``Because Congress did not assign the
specific weight the Administrator should accord each of these
factors, the Administrator is free to exercise his discretion in
this area.''); see also NRDC v. EPA, 25 F.3d 1063, 1071 (D.C. Cir.
1994) (The EPA did not err in its final balancing because ``neither
RCRA nor EPA's regulations purports to assign any particular weight
to the factors listed in subsection (a)(3). That being the case, the
Administrator was free to emphasize or deemphasize particular
factors, constrained only by the requirements of reasoned agency
decisionmaking.'').
Importantly, the courts recognize that the EPA must consider
several factors and that determining what is ``best'' depends on how
much weight to give the factors. In promulgating certain standards of
performance, the EPA may give greater weight to particular factors than
it does in promulgating other standards of performance. Thus, the
determination of what is ``best'' is complex and necessarily requires
an exercise of judgment. By analogy, the question of who is the
``best'' sprinter in the 100-meter dash primarily depends on only one
criterion--speed--and therefore is relatively straightforward, whereas
the question of who is the ``best'' baseball player depends on a more
complex weighing of multiple criteria and therefore requires a greater
exercise of judgment.
The term ``best'' also authorizes the EPA to consider factors in
addition to the ones enumerated in CAA section 111(a)(1), that further
the purpose of the statute. In Portland Cement Ass'n v. Ruckelshaus,
486 F.2d 375 (D.C. Cir. 1973), the D.C. Circuit held that under CAA
section 111(a)(1) as it read prior to the enactment of the 1977 CAA
Amendments that added a requirement that the EPA take account of non-
air quality environmental impacts, the EPA must consider ``counter-
productive environmental effects'' in Determining the BSER. Id. at 385.
The court elaborated: ``The standard of the `best system' is
comprehensive, and we cannot imagine that Congress intended that `best'
could apply to a system which did more damage to water than it
prevented to air.'' Id., n.42. In Sierra Club v. Costle, 657 F.2d at
326, 346-47, the court added that the EPA must consider the amount of
emission reductions and technology advancement in determining BSER, as
discussed in section V.C.2.g of this preamble.
The court's view that ``best'' includes additional factors that
further the purpose of CAA section 111 is a reasonable interpretation
of that term in its statutory context. The purpose of CAA section 111
is to reduce emissions of air pollutants that endanger public health or
welfare. CAA section 111(b)(1)(A). The court reasonably surmised that
the EPA's determination of whether a system of emission reduction that
reduced certain air pollutants is ``best'' should be informed by
impacts that the system may have on other pollutants that affect public
or welfare. Portland Cement Ass'n, 486 F.2d at 385. The Supreme Court
confirmed the D.C. Circuit's approach in Michigan v. EPA, 576 U.S. 743
(2015), explaining that administrative agencies must engage in
``reasoned decisionmaking'' that, in the case of pollution control,
cannot be based on technologies that ``do even more damage to human
health'' than the emissions they eliminate. Id. at 751-52. After
Portland Cement Ass'n, Congress revised CAA section 111(a)(1) to make
explicit that in determining whether a system of emission reduction is
the ``best,'' the EPA should account for non-air quality health and
environmental impacts. By the same token, the EPA takes the position
that in determining whether a system of emission reduction is the
``best,'' the EPA may account for the impacts of the system on air
pollutants other than the ones that are the subject of the CAA section
111 regulation.\243\ We discuss immediately below other factors that
the D.C. Circuit has held the EPA should account for in determining
what system is the ``best.''
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\243\ See generally Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review--
Supplemental Notice of Proposed Rulemaking, 87 FR 74765 (December 6,
2022) (proposing the BSER for reducing methane and VOC emissions
from natural gas-driven controllers in the oil and natural gas
sector on the basis of, among other things, impacts on emissions of
criteria pollutants). In this preamble, for convenience, the EPA
generally discusses the effects of controls on non-GHG air
pollutants along with the effects of controls on non-air quality
health and environmental impacts.
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g. Amount of Emissions Reductions
Consideration of the amount of emissions from the category of
sources or the amount of emission reductions achieved as factors the
EPA must consider in determining the ``best system of emission
reduction'' is implicit in the plain language of CAA section
111(a)(1)--the EPA must choose the best system of emission reduction.
Indeed, consistent with this plain language and the purpose of CAA
section 111, the EPA must consider the quantity of emissions at issue.
See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) (``we can
think of no sensible interpretation of the statutory words ``best . . .
system'' which would not incorporate the amount of air pollution as a
relevant factor to be weighed when determining the optimal standard for
controlling . . . emissions'').\244\ The fact that the purpose of a
``system of emission reduction'' is to reduce emissions, and that the
term itself explicitly incorporates the concept of reducing emissions,
supports the court's view that in determining whether a ``system of
emission reduction'' is the ``best,'' the EPA must consider the amount
of emission reductions that the system would yield. Even if the EPA
were not required to consider the amount of emission reductions, the
EPA has the discretion to do so, on grounds that either the term
``system of emission reduction'' or the term ``best'' may reasonably be
read to allow that discretion.
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\244\ Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was
governed by the 1977 CAAA version of the definition of ``standard of
performance,'' which revised the phrase ``best system of emission
reduction'' to read, ``best technological system of continuous
emission reduction.'' As noted above, the 1990 CAAA deleted
``technological'' and ``continuous'' and thereby returned the phrase
to how it read under the 1970 CAAA. The court's interpretation of
the 1977 CAAA phrase in Sierra Club v. Costle to require
consideration of the amount of air emissions focused on the term
``best,'' and the terms ``technological'' and ``continuous'' were
irrelevant to its analysis. It thus remains valid for the 1990 CAAA
phrase ``best system of emission reduction.''
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h. Expanded Use and Development of Technology
The D.C. Circuit has long held that Congress intended for CAA
section 111
[[Page 39835]]
to create incentives for new technology and therefore that the EPA is
required to consider technological innovation as one of the factors in
determining the ``best system of emission reduction.'' See Sierra Club
v. Costle, 657 F.2d at 346-47. The court has grounded its reading in
the statutory text of CAA 111(a)(1), defining the term ``standard of
performance.'' \245\ In addition, the court's interpretation finds
support in the legislative history.\246\ The legislative history
identifies three different ways that Congress designed CAA section 111
to authorize standards of performance that promote technological
improvement: (1) The development of technology that may be treated as
the ``best system of emission reduction . . . adequately
demonstrated;'' under CAA section 111(a)(1); \247\ (2) the expanded use
of the best demonstrated technology; \248\ and (3) the development of
emerging technology.\249\ Even if the EPA were not required to consider
technological innovation as part of its determination of the BSER, it
would be reasonable for the EPA to consider it because technological
innovation may be considered an element of the term ``best,''
particularly in light of Congress's emphasis on technological
innovation.
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\245\ Sierra Club v. Costle, 657 F.2d at 346 (``Our
interpretation of section 111(a) is that the mandated balancing of
cost, energy, and non-air quality health and environmental factors
embraces consideration of technological innovation as part of that
balance. The statutory factors which EPA must weigh are broadly
defined and include within their ambit subfactors such as
technological innovation.'').
\246\ See S. Rep. No. 91-1196 at 16 (1970) (``Standards of
performance should provide an incentive for industries to work
toward constant improvement in techniques for preventing and
controlling emissions from stationary sources''); S. Rep. No. 95-127
at 17 (1977) (cited in Sierra Club v. Costle, 657 F.2d at 346 n.174)
(``The section 111 Standards of Performance . . . sought to assure
the use of available technology and to stimulate the development of
new technology'').
\247\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (the best system of emission reduction must ``look[
] toward what may fairly be projected for the regulated future,
rather than the state of the art at present'').
\248\ 1970 Senate Committee Report No. 91-1196 at 15 (``The
maximum use of available means of preventing and controlling air
pollution is essential to the elimination of new pollution
problems'').
\249\ Sierra Club v. Costle, 657 F.2d at 351 (upholding a
standard of performance designed to promote the use of an emerging
technology).
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i. Achievability of the Degree of Emission Limitation
For new sources, CAA section 111(b)(1)(B) and (a)(1) provides that
the EPA must establish ``standards of performance,'' which are
standards for emissions that reflect the degree of emission limitation
that is ``achievable'' through the application of the BSER. A standard
of performance is ``achievable'' if a technology can reasonably be
projected to be available to an individual source at the time it is
constructed that will allow it to meet the standard.\250\ Moreover,
according to the court, ``[a]n achievable standard is one which is
within the realm of the adequately demonstrated system's efficiency and
which, while not at a level that is purely theoretical or experimental,
need not necessarily be routinely achieved within the industry prior to
its adoption.'' \251\ To be achievable, a standard ``must be capable of
being met under most adverse conditions which can reasonably be
expected to recur and which are not or cannot be taken into account in
determining the `costs' of compliance.'' \252\ To show a standard is
achievable, the EPA must ``(1) identify variable conditions that might
contribute to the amount of expected emissions, and (2) establish that
the test data relied on by the agency are representative of potential
industry-wide performance, given the range of variables that affect the
achievability of the standard.'' \253\
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\250\ Sierra Club v. Costle, 657 F.2d 298, 364, n.276 (D.C. Cir.
1981).
\251\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34
(D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974).
\252\ Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433, n.46 (D.C.
Cir. 1980).
\253\ Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981)
(citing Nat'l Lime Ass'n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). In
considering the representativeness of the source tested, the EPA may
consider such variables as the `` `feedstock, operation, size and
age' of the source.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433
(D.C. Cir. 1980). Moreover, it may be sufficient to ``generalize
from a sample of one when one is the only available sample, or when
that one is shown to be representative of the regulated industry
along relevant parameters.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416,
434, n.52 (D.C. Cir. 1980).
---------------------------------------------------------------------------
Although the courts have established these standards for
achievability in cases concerning CAA section 111(b) new source
standards of performance, generally comparable standards for
achievability should apply under CAA section 111(d), although the BSER
may differ in some cases as between new and existing sources due to,
for example, higher costs of retrofit. 40 FR 53340 (November 17, 1975).
For existing sources, CAA section 111(d)(1) requires the EPA to
establish requirements for state plans that, in turn, must include
``standards of performance.'' As the Supreme Court has recognized, this
provision requires the EPA to promulgate emission guidelines that
determine the BSER for a source category and then identify the degree
of emission limitation achievable by application of the BSER. See West
Virginia v. EPA, 597 U.S. at 710.\254\
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\254\ 40 CFR 60.21(e), 60.21a(e).
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The EPA has promulgated emission guidelines on the basis that the
existing sources can achieve the degree of emission limitation
described therein, even though under the RULOF provision of CAA section
111(d)(1), the state retains discretion to apply standards of
performance to individual sources that are less stringent, which
indicates that Congress recognized that the EPA may promulgate emission
guidelines that are consistent with CAA section 111(d) even though
certain individual sources may not be able to achieve the degree of
emission limitation identified therein by applying the controls that
the EPA determined to be the BSER. Note further that this requirement
that the emission limitation be ``achievable'' based on the ``best
system of emission reduction . . . adequately demonstrated'' indicates
that the technology or other measures that the EPA identifies as the
BSER must be technically feasible.
3. EPA Promulgation of Emission Guidelines for States To Establish
Standards of Performance
CAA section 111(d)(1) directs the EPA to promulgate regulations
establishing a procedure similar to that provided by CAA section 110
under which states submit state plans that establish ``standards of
performance'' for emissions of certain air pollutants from sources
which, if they were new sources, would be regulated under CAA section
111(b), and that provide for the implementation and enforcement of such
standards of performance. The term ``standard of performance'' is
defined under CAA section 111(a)(1), quoted above. Thus, CAA sections
111(a)(1) and (d)(1) collectively require the EPA to determine the
degree of emission limitation achievable through application of the
BSER to existing sources and to establish regulations under which
states establish standards of performance reflecting that degree of
emission limitation. The EPA addresses both responsibilities through
its emission guidelines, as well as through its general implementing
regulations for CAA section 111(d). Consistent with the statutory
requirements, the general implementing regulations require that the
EPA's emission guidelines reflect--
the degree of emission limitation achievable through the application
of the best system of emission reduction which (taking into account
the cost of such reduction and any non-air quality health and
environmental
[[Page 39836]]
impact and energy requirements) the Administrator has determined has
been adequately demonstrated from designated facilities.\255\
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\255\ 40 CFR 60.21a(e).
Following the EPA's promulgation of emission guidelines, each state
must establish standards of performance for its existing sources, which
the EPA's regulations call ``designated facilities.'' \256\ Such
standards of performance must reflect the degree of emission limitation
achievable through application of the best system of emission reduction
as determined by the EPA, which the Agency may express as a presumptive
standard of performance in the applicable emission guidelines.
---------------------------------------------------------------------------
\256\ 40 CFR 60.21a(b), 60.24a(b).
---------------------------------------------------------------------------
While the standards of performance that states establish in their
plans must generally be no less stringent than the degree of emission
limitation determined by the EPA,\257\ CAA section 111(d)(1) also
requires that the EPA's regulations ``permit the State in applying a
standard of performance to any particular source . . . to take into
consideration, among other factors, the remaining useful life of the
existing source to which such standard applies.'' Consistent with this
statutory direction, the EPA's general implementing regulations for CAA
section 111(d) provide a framework for states' consideration of
remaining useful life and other factors (referred to as ``RULOF'') when
applying a standard of performance to a particular source. In November
2023, the EPA finalized clarifications to its regulations governing
states' consideration of RULOF to apply less stringent standards of
performance to particular existing sources. As amended, these
regulations provide that states may apply a standard of performance to
a particular designated facility that is less stringent than, or has a
longer compliance schedule than, otherwise required by the applicable
emission guideline taking into consideration that facility's remaining
useful life and other factors. To apply a less stringent standard of
performance or longer compliance schedule, the state must demonstrate
with respect to each facility (or class of such facilities), that the
facility cannot reasonably achieve the degree of emission limitation
determined by the EPA based on unreasonable cost of control resulting
from plant age, location, or basic process design; physical
impossibility or technical infeasibility of installing necessary
control equipment; or other circumstances specific to the facility. In
doing so, the state must demonstrate that there are fundamental
differences between the information specific to a facility (or class of
such facilities) and the information the EPA considered in determining
the degree of emission limitation achievable through application of the
BSER or the compliance schedule that make achieving such degree of
emission reduction or meeting such compliance schedule unreasonable for
that facility.
---------------------------------------------------------------------------
\257\ As the Supreme Court explained in West Virginia v. EPA,
``Although the States set the actual rules governing existing power
plants, EPA itself still retains the primary regulatory role in
Section 111(d).'' 597 U.S. at 710. The Court elaborated that ``[t]he
Agency, not the States, decides the amount of pollution reduction
that must ultimately be achieved. It does so by again determining,
as when setting the new source rules, `the best system of emission
reduction . . . that has been adequately demonstrated for [existing
covered] facilities.' 40 CFR 60.22(b)(5) (2021); see also 80 FR
64664, and n.1. The States then submit plans containing the
emissions restrictions that they intend to adopt and enforce in
order not to exceed the permissible level of pollution established
by EPA. See Sec. Sec. 60.23, 60.24; 42 U.S.C. 7411(d)(1).'' Id.
---------------------------------------------------------------------------
In addition, under CAA section 116, states may establish standard
of performances that are more stringent than the presumptive standards
of performance contained in the EPA's emission guidelines.\258\ The
state must include the standards of performance in their state plans
and submit the plans to the EPA for review according to the procedures
established in the Agency's general implementing regulations for CAA
section 111(d).\259\ Under CAA section 111(d)(2)(A), the EPA approves
state plans that are determined to be ``satisfactory.'' CAA section
111(d)(2)(A) also gives the Agency ``the same authority'' as under CAA
section 110(c) to promulgate a Federal plan in cases where a state
fails to submit a satisfactory state plan.
---------------------------------------------------------------------------
\258\ 40 CFR 60.24a(i).
\259\ See generally 40 CFR 60.23a-60.28a.
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VI. ACE Rule Repeal
The EPA is finalizing repeal of the ACE Rule. The EPA proposed to
repeal the ACE Rule and did not receive significant comments objecting
to the proposal. The EPA is finalizing the proposal largely as
proposed. A general summary of the ACE Rule, including its regulatory
and judicial history, is included in section V.B.4 of this preamble.
The EPA repeals the ACE Rule on three grounds that each independently
justify the rule's repeal.
First, as a policy matter, the EPA concludes that the suite of heat
rate improvements (HRI) the ACE Rule selected as the BSER is not an
appropriate BSER for existing coal-fired EGUs. In the EPA's technical
judgment, the suite of HRI set forth in the ACE Rule provide negligible
CO2 reductions at best and, in many cases, may increase
CO2 emissions because of the ``rebound effect,'' as
explained in section VII.D.4.a.iii of this preamble. These concerns,
along with the EPA's experience in implementing the ACE Rule, cast
doubt that the ACE Rule would achieve emission reductions and increase
the likelihood that the ACE Rule could make CO2 pollution
worse. As a result, the EPA has determined it is appropriate to repeal
the rule, and to reevaluate whether other technologies constitute the
BSER.
Second, even assuming the ACE Rule's rejection of CCS and natural
gas co-firing was supported at the time, the ACE Rule's rationale for
rejecting CCS and natural gas co-firing as the BSER no longer applies
because of new factual developments. Since the ACE Rule was
promulgated, changes in the power industry, developments in the costs
of controls, and new federal subsidies have made other controls more
broadly available and less expensive. Considering these developments,
the EPA has determined that co-firing with natural gas and CCS are the
BSER for certain subcategories of sources as described in section VII.C
of this preamble, and that the HRI technologies adopted by the ACE Rule
are not the BSER. Thus, repeal of the ACE Rule is proper on this ground
as well.
Third, the EPA concludes that the ACE Rule conflicted with CAA
section 111 and the EPA's implementing regulations because it did not
specifically identify the BSER or the ``degree of emission limitation
achievable though application of the [BSER].'' Instead, the ACE Rule
described only a broad range of values as the ``degree of emission
limitation achievable.'' In doing so, the rule did not provide the
states with adequate guidance on the degree of emission limitation that
must be reflected in the standards of performance so that a state plan
would be approvable by the EPA. The ACE Rule is repealed for this
reason also.
A. Summary of Selected Features of the ACE Rule
The ACE Rule determined that the BSER for coal-fired EGUs was a
``list of `candidate technologies,' '' consisting of seven types of the
``most impactful HRI technologies, equipment upgrades, and best
operating and maintenance practices,'' (84 FR 32536; July 8, 2019),
including, among others, ``Boiler Feed Pumps'' and ``Redesign/Replace
Economizer.'' Id. at 32537 (table 1). The rule provided a range of
improvements
[[Page 39837]]
in heat rate that each of the seven ``candidate technologies'' could
achieve if applied to coal-fired EGUs of different capacities. For six
of the technologies, the expected level of improvement in heat rate
ranged from 0.1-0.4 percent to 1.0-2.9 percent, and for the seventh
technology, ``Improved Operating and Maintenance (O&M) Practices,'' the
range was ``0 to >2%.'' Id. The ACE Rule explained that states must
review each of their designated facilities, on either a source-by-
source or group-of-sources basis, and ``evaluate the applicability of
each of the candidate technologies.'' Id. at 32550. States were to use
the list of HRI technologies ``as guidance but will be expected to
conduct unit-specific evaluations of HRI potential, technical
feasibility, and applicability for each of the BSER candidate
technologies.'' Id. at 32538.
The ACE Rule emphasized that states had ``inherent flexibility'' in
evaluating candidate technologies with ``a wide range of potential
outcomes.'' Id. at 32542. The ACE Rule provided that states could
conclude that it was not appropriate to apply some technologies. Id. at
32550. Moreover, if a state decided to apply a particular technology to
a particular source, the state could determine the level of heat rate
improvement from the technology could be anywhere within the range that
the EPA had identified for that technology, or even outside that range.
Id. at 32551. The ACE Rule stated that after the state evaluated the
technologies and calculated the amount of HRI in this way, it should
determine the standard of performance 0that the source could achieve,
Id. at 32550, and then adjust that standard further based on the
application of source-specific factors such as remaining useful life.
Id. at 32551.
The ACE Rule then identified the process by which states had to
take these actions. States must ``evaluat[e] each'' of the seven
candidate technologies and provide a summary, which ``include[s] an
evaluation of the . . . degree of emission limitation achievable
through application of the technologies.'' Id. at 32580. Then, the
state must provide a variety of information about each power plant,
including, the plant's ``annual generation,'' ``CO2
emissions,'' ``[f]uel use, fuel price, and carbon content,''
``operation and maintenance costs,'' ``[h]eat rates,'' ``[e]lectric
generating capacity,'' and the ``timeline for implementation,'' among
other information. Id. at 32581. The EPA explained that the purpose of
this data was to allow the Agency to ``adequately and appropriately
review the plan to determine whether it is satisfactory.'' Id. at
32558.
The ACE Rule projected a very low level of overall emission
reduction if states generally applied the set of candidate technologies
to their sources. The rule was projected to achieve a less-than-1-
percent reduction in power-sector CO2 emissions by
2030.\260\ Further, the EPA also projected that it would increase
CO2 emissions from power plants in 15 states and the
District of Columbia because of the ``rebound effect'' as coal-fired
sources implemented HRI measures and became more efficient. This
phenomenon is explained in more detail in section VII.D.4.a.iii of this
document.\261\
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\260\ ACE Rule RIA 3-11, table 3-3.
\261\ The rebound effect becomes evident by comparing the
results of the ACE Rule IPM runs for the 2018 reference case, EPA,
IPM State-Level Emissions: EPAv6 November 2018 Reference Case,
Document ID No. EPA-HQ-OAR-2017-0355-26720, and for the
``Illustrative ACE Scenario. IPM State-Level Emissions: Illustrative
ACE Scenario, Document ID No. EPA-HQ-OAR-2017-0355-26724.
---------------------------------------------------------------------------
The ACE Rule considered several other control measures as the BSER,
including co-firing with natural gas and CCS, but rejected them. The
ACE Rule rejected co-firing with natural gas primarily on grounds that
it was too costly in general. 84 FR 32545 (July 8, 2019). The rule also
concluded that generating electricity by co-firing natural gas in a
utility boiler would be an inefficient use of the gas when compared to
combusting it in a combustion turbine. Id. The ACE Rule rejected CCS on
grounds that it was too costly. Id. at 32548. The rule identified the
high capital and operating costs of CCS and noted the fact that the IRC
section 45Q tax credit, as it then applied, would provide only limited
benefit to sources. Id. at 32548-49.
B. Developments Undermining ACE Rule's Projected Emission Reductions
The EPA's first basis for repealing the ACE Rule is that it is
unlikely that--if implemented--the rule would reduce emissions, and
implementation could increase CO2 emissions instead. Thus,
the EPA concludes that as a matter of policy it is appropriate to
repeal the rule and evaluate anew whether other technologies qualify as
the BSER.
Two factors, taken together, undermine the ACE Rule's projected
emission reductions and create the risk that implementation of the ACE
Rule could increase--rather than reduce--CO2 emissions from
coal-fired EGUs. First, HRI technologies achieve only limited GHG
emission reductions. The ACE Rule projected that if states generally
applied the set of candidate technologies to their sources, the rule
would achieve a less-than-1-percent reduction in power-sector
CO2 emissions by 2030.\262\ The EPA now doubts that even
these minimal reductions would be achieved. The ACE Rule's projected
benefits were premised in part on a 2009 technical report by Sargent &
Lundy that evaluated the effects of HRI technologies. In 2023, Sargent
& Lundy issued an updated report which details that the HRI selected as
the BSER in the ACE Rule would bring fewer emissions reductions than
estimated in 2009. The 2023 report concludes that, with few exceptions,
HRI technologies are less effective at reducing CO2
emissions than assumed in 2009. Further reinforcing the conclusion that
HRIs would bring few reductions, the 2023 report also concluded that
most sources had already optimized application of HRIs, and so there
are fewer opportunities to reduce emissions than previously
anticipated.\263\
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\262\ ACE Rule RIA 3-11, table 3-3.
\263\ Sargent and Lundy. Heat Rate Improvement Method Costs and
Limitations Memo. Available in Docket ID No. EPA-HQ-OAR-2023-0072.
---------------------------------------------------------------------------
Second, for a subset of sources, HRI are likely to cause a
``rebound effect'' leading to an increase in GHG emissions for those
sources. The rebound effect is explained in detail in section
VII.D.4.a.iii of this preamble. The ACE Rule's analysis projected that
the rule would increase CO2 emissions from power plants in
15 states and the District of Columbia. The EPA's modeling projections
assumed that, consistent with the rule, some sources would impose a
small degree of efficiency improvements. The modeling showed that, as a
consequence of these improvements, the rule would increase absolute
emissions at some coal-fired sources as these sources became more
efficient and displaced lower emitting sources like natural gas-fired
EGUs.\264\
---------------------------------------------------------------------------
\264\ See EPA, IPM State-Level Emissions: EPAv6 November 2018
Reference Case, Document ID No. EPA-HQ-OAR-2017-0355-26720
(providing ACE reference case); IPM State-Level Emissions:
Illustrative ACE Scenario, Document ID No. EPA-HQ-OAR-2017-0355-
26724 (providing illustrative scenario).
---------------------------------------------------------------------------
Even though the ACE Rule was projected to increase emissions in
many states, these states were nevertheless obligated under the rule to
assemble detailed state plans that evaluated available technologies and
the performance of each existing coal-fired power plant, as described
in section IX.A of this preamble. For example, the state was required
to analyze the plant's ``annual generation,'' ``CO2
emissions,'' ``[f]uel use, fuel price, and carbon content,''
``operation and maintenance
[[Page 39838]]
costs,'' ``[h]eat rates,'' ``[e]lectric generating capacity,'' and the
``timeline for implementation,'' among other information. 84 FR 32581
(July 8, 2019). The risk of an increase in emissions raises doubts that
the HRI for coal-fired sources satisfies the statutory criteria to
constitute the BSER for this category of sources. The core element of
the BSER analysis is whether the emission reduction technology selected
reduces emissions. See Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427,
441 (D.C. Cir. 1973) (noting ``counter productive environmental
effects'' raises questions as to whether the BSER selected was in fact
the ``best''). Moreover, this evaluation and the imposition of
standards of performance was mandated even though the state plan would
lead to an increase rather than decrease CO2 emissions.
Imposing such an obligation on states under these circumstances was
arbitrary.
The EPA's experience in implementing the ACE Rule reinforces these
concerns. After the ACE Rule was promulgated, one state drafted a state
plan that set forth a standard of performance that allowed the affected
source to increase its emission rate. The draft partial plan would have
applied to one source, the Longview Power, LLC facility, and would have
established a standard of performance, based on the state's
consideration of the ``candidate technologies,'' that was higher (i.e.,
less stringent) than the source's historical emission rate. Thus, the
draft plan would not have achieved any emission reductions from the
source, and instead would have allowed the source to increase its
emissions, if it had been finalized.\265\
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\265\ West Virginia CAA Sec. 111(d) Partial Plan for Greenhouse
Gas Emissions from Existing Electric Utility Generating Units
(EGUs), https://dep.wv.gov/daq/publicnoticeandcomment/Documents/Proposed%20WV%20ACE%20State%20Partial%20Plan.pdf.
---------------------------------------------------------------------------
Because there is doubt that the minimal reductions projected by the
ACE Rule would be achieved, and because the rebound effect could lead
to an increase in emissions for many sources in many states, the EPA
concludes that it is appropriate to repeal the ACE Rule and reevaluate
the BSER for this category of sources.
C. Developments Showing That Other Technologies Are the BSER for This
Source Category
Since the promulgation of the ACE Rule in 2019, the factual
underpinnings of the rule have changed in several ways and lead the EPA
to determine that HRI are not the BSER for coal-fired power plants.
This reevaluation is consistent with FCC v. Fox Television Stations,
Inc., 556 U.S. 502 (2009). There, the Supreme Court explained that an
agency issuing a new policy ``need not demonstrate to a court's
satisfaction that the reasons for the new policy are better than the
reasons for the old one.'' Instead, ``it suffices that the new policy
is permissible under the statute, that there are good reasons for it,
and that the agency believes it to be better, which the conscious
change of course adequately indicates.'' Id. at 514-16 (emphasis in
original; citation omitted).
Along with changes in the anticipated reductions from HRI, it makes
sense for the EPA to reexamine the BSER because the costs of two
control measures, co-firing with natural gas and CCS, have fallen for
sources with longer-term operating horizons. As noted, the ACE Rule
rejected natural gas co-firing as the BSER on grounds that it was too
costly and would lead to inefficient use of natural gas. But as
discussed in section VII.C.2.b of this preamble, the costs of natural
gas co-firing are presently reasonable, and the EPA concludes that the
costs of co-firing 40 percent by volume natural gas are cost-effective
for existing coal-fired EGUs that intend to operate after January 1,
2032, and cease operation before January 1, 2039. In addition, changed
circumstances--including that natural gas is available in greater
amounts, that many coal-fired EGUs have begun co-firing with natural
gas or converted wholly to natural-gas, and that there are fewer coal-
fired EGUs in operation--mitigate the concerns the ACE Rule identified
about inefficient use of natural gas.
Similarly, the ACE Rule rejected CCS as the BSER on grounds that it
was too costly. But the costs of CCS have substantially declined, as
discussed in section VII.C.1.a.ii of the preamble, partly because of
developments in the technology that have lowered capital costs, and
partly because the IRA extended and increased the IRS section 45Q tax
credit so that it defrays a higher portion of the costs of CCS.
Accordingly, for coal-fired EGUs that will continue to operate past
2039, the EPA concludes that the costs of CCS are reasonable, as
described in section VII.C.1.a.ii of the preamble.
The emission reductions from these two technologies are
substantial. For long-term coal-fired steam generating units, the BSER
of 90 percent capture CCS results in substantial CO2
emissions reductions amounting to emission rates that are 88.4 percent
lower on a lb/MWh-gross basis and 87.1 percent lower on a lb/MWh-net
basis compared to units without capture, as described in section
VII.C.2.b.iv of this preamble. For medium term units, the BSER of 40
percent natural gas co-firing achieves CO2 stack emissions
reductions of 16 percent, as described in section VII.C.2.b.iv of this
preamble. Given the availability of more effective, cost-reasonable
technology, the EPA concludes that HRIs are not the BSER for all coal-
fired EGUs.
The EPA is thus finalizing a new policy for coal-fired power
plants. This rule applies to those sources that intend to operate past
January 1, 2032. For sources that intend to cease operations after
January 1, 2032, but before January 1, 2039, the EPA concludes that the
BSER is co-firing 40 percent by volume natural gas. The EPA concludes
this control measure is appropriate because it achieves substantial
reductions at reasonable cost. In addition, the EPA believes that
because a large supply of natural gas is available, devoting part of
this supply for fuel for a coal-fired steam generating unit in place of
a percentage of the coal burned at the unit is an appropriate use of
natural gas and will not adversely impact the energy system, as
described in section VII.C.2.b.iii(B) of this preamble. For sources
that intend to operate past January 1, 2039, the EPA concludes that the
BSER is CCS with 90 percent capture of CO2. The EPA believes
that this control measure is appropriate because it achieves
substantial reductions at reasonable cost, as described in section
VII.C.1 of this preamble.
The EPA is not concluding that HRI is the BSER for any coal-fired
EGUs. As discussed in section VII.D.4.a, the EPA does not consider HRIs
an appropriate BSER for coal-fired EGUs because these technologies
would achieve few, if any, emissions reductions and may increase
emissions due to the rebound effect. Most importantly, changed
circumstances show that co-firing natural gas and CCS are available at
reasonable cost, and will achieve more GHG emissions reductions.
Accordingly, the EPA believes that HRI do not qualify as the BSER for
any coal-fired EGUs, and that other approaches meet the statutory
standard. On this basis, the EPA repeals the ACE Rule.
D. Insufficiently Precise Degree of Emission Limitation Achievable From
Application of the BSER
The third independent reason why the EPA is repealing the ACE Rule
is that the rule did not identify with sufficient specificity the BSER
or the degree of emission limitation achievable through the application
of the BSER. Thus, states lacked adequate guidance on the BSER they
should consider and
[[Page 39839]]
level of emission reduction that the standards of performance must
achieve. The ACE Rule determined the BSER to be a suite of HRI
``candidate technologies,'' but did not identify with specificity the
degree of emission limitation states should apply in developing
standards of performance for their sources. As a result, the ACE Rule
conflicted with CAA section 111 and the implementing regulations, and
thus failed to provide states adequate guidance so that they could
ensure that their state plans were satisfactory and approvable by the
EPA.
CAA section 111 and the EPA's longstanding implementing regulations
establish a clear process for the EPA and states to regulate emissions
of certain air pollutants from existing sources. ``The statute directs
the EPA to (1) `determine[ ],' taking into account various factors, the
`best system of emission reduction which . . . has been adequately
demonstrated,' (2) ascertain the `degree of emission limitation
achievable through the application' of that system, and (3) impose an
emissions limit on new stationary sources that `reflects' that
amount.'' West Virginia v. EPA, 597 U.S. at 709 (quoting 42 U.S.C.
7411(d)). Further, ``[a]lthough the States set the actual rules
governing existing power plants, EPA itself still retains the primary
regulatory role in Section 111(d) . . . [and] decides the amount of
pollution reduction that must ultimately be achieved.'' Id. at 2602.
Once the EPA makes these determinations, the state must establish
``standards of performance'' for its sources that are based on the
degree of emission limitation that the EPA determines in the emission
guidelines. CAA section 111(a)(1) makes this clear through its
definition of ``standard of performance'' as ``a standard for emissions
of air pollutants which reflects the degree of emission limitation
achievable through the application of the [BSER].'' After the EPA
determines the BSER, 40 CFR 60.22(b)(5), and the degree of emission
limitation achievable from application of the BSER, ``the States then
submit plans containing the emissions restrictions that they intend to
adopt and enforce in order not to exceed the permissible level of
pollution established by EPA.'' 597 U.S. at 710 (citing 40 CFR 60.23,
60.24; 42 U.S.C. 7411(d)(1)).
The EPA then reviews the plan and approves it if the standards of
performance are ``satisfactory,'' under CAA section 111(d)(2)(A). The
EPA's longstanding implementing regulations make clear that the EPA's
basis for determining whether the plan is ``satisfactory'' includes
that the plan must contain ``emission standards . . . no less stringent
than the corresponding emission guideline(s).'' 40 CFR 60.24(c), 40 CFR
60.24a(c). In addition, under CAA section 111(d)(1), in ``applying a
standard of performance to any particular source'' a state may
consider, ``among other factors, the remaining useful life of the
existing source to which such standard applies.'' This is also known as
the RULOF provision and is discussed in section X.C.2 of this preamble.
In the ACE Rule, the EPA recognized that the CAA required it to
determine the BSER and identify the degree of emission limitation
achievable through application of the BSER. 84 FR 32537 (July 8, 2019).
But the rule did not make those determinations. Rather, the ACE Rule
described the BSER as a list of ``candidate technologies.'' And the
rule described the degree of emission limitation achievable by
application of the BSER as ranges of reductions from the HRI
technologies. The rule thus shifted the responsibility for determining
the BSER and degree of emission limitation achievable from the EPA to
the states. Accordingly, the ACE Rule did not meet the CAA section 111
requirement that the EPA determine the BSER or the degree of emission
limitation from application of the BSER.
As described above, the ACE Rule identified the HRI in the form of
a list of seven ``candidate technologies,'' accompanied by a wide range
of percentage improvements to heat rate that these technologies could
provide. Indeed, for one of them, improved ``O&M'' practices (that is,
operation and management practices), the range was ``0 to >2%,'' which
is effectively unbounded. 84 FR 32537 (table 1) (July 8, 2019). The ACE
Rule was clear that this list was simply the starting point for a state
to calculate the standards of performance for its sources. That is, the
seven sets of technologies were ``candidate[s]'' that the state could
apply to determine the standard of performance for a source, and if the
state did choose to apply one or more of them, the state could do so in
a manner that yielded any percentage of heat rate improvement within
the range that the EPA identified, or even outside that range. Thus, as
a practical matter, the ACE Rule did not determine the BSER or any
degree of emission limitation from application of the BSER, and so
states had no guidance on how to craft approvable state plans. In this
way, the ACE Rule did not adhere to the applicable statutory
obligations. See 84 FR 32537-38 (July 8, 2019).
The only constraints that the ACE Rule imposed on the states were
procedural ones, and those did not give the EPA any benchmark to
determine whether a plan could be approved or give the states any
certainty on whether their plan would be approved. As noted above, when
a state submitted its plan, it needed to show that it evaluated each
candidate technology for each source or group of sources, explain how
it determined the degree of emission limitation achievable, and include
data about the sources. But because the ACE Rule did not identify a
BSER or include a degree of emission limitation that the standards must
reflect, the states lacked specific guidance on how to craft adequate
standards of performance, and the EPA had no benchmark against which to
evaluate whether a state's submission was ``satisfactory'' under CAA
section 111(d)(2)(A). Thus, the EPA's review of state plans would be
essentially a standardless exercise, notwithstanding the Agency's
longstanding view that it was ``essential'' that ``EPA review . . .
[state] plans for their substantive adequacy.'' 40 FR 53342-43
(November 17, 1975). In 1975, the EPA explained that it was not
appropriate to limit its review based ``solely on procedural criteria''
because otherwise ``states could set extremely lenient standards . . .
so long as EPA's procedural requirements were met.'' Id. at 53343.
Finally, the ACE Rule's approach to determining the BSER and degree
of emission limitation departed from prior emission guidelines under
CAA section 111(d), in which the EPA included a numeric degree of
emission limitation. See, e.g., 42 FR 55796, 55797 (October 18, 1977)
(limiting emission rate of acid mist from sulfuric acid plants to 0.25
grams per kilogram of acid); 44 FR 29829 (May 22, 1979) (limiting
concentrations of total reduced sulfur from most of the subcategories
of kraft pulp mills, such as digester systems and lime kilns, to 5, 20,
or 25 ppm over 12-hour averages); 61 FR 9919 (March 12, 1996) (limiting
concentration of non-methane organic compounds from solid waste
landfills to 20 parts per million by volume or a 98 percent reduction).
The ACE Rule did not grapple with this change in position as required
by FCC v. Fox Television Stations, Inc., 556 U.S. 502 (2009), or
explain why it was appropriate to provide a boundless degree of
emission limitation achievable in this context.
The EPA is finalizing the repeal the ACE Rule on this ground as
well. The ACE Rule's failure to determine the BSER and the associated
degree of emission limitation achievable from
[[Page 39840]]
application of the BSER deviated from CAA section 111 and the
implementing regulations. Without these determinations, the ACE Rule
lacked any benchmark that would guide the states in developing their
state plans, and by which the EPA could determine whether those state
plans were satisfactory.
For each of these three, independent reasons, repeal of the ACE
Rule is proper.
E. Withdrawal of Proposed NSR Revisions
In addition to repealing the ACE Rule, the Agency is withdrawing
the proposed revisions to the NSR applicability provisions that were
included the ACE Rule proposal (83 FR 44756, 44773-83; August 31,
2018). These proposed revisions would have included an hourly emissions
rate test to determine NSR applicability for a modified EGU, with the
expressed purpose of alleviating permitting burdens for sources
undertaking HRI projects pursuant to the ACE Rule emission guidelines.
The ACE Rule final action did not include the NSR revisions, and the
EPA indicated in that preamble that it intended to take final action on
the NSR proposal in a separate action at a later date. However, the EPA
did not take a final action on the NSR revisions, and the EPA has
decided to no longer pursue them and to withdraw the proposed
revisions.
Withdrawal of the proposal to establish an hourly emissions test
for NSR applicability for EGUs is appropriate because of the repeal of
the ACE rule and the EPA's conclusion that HRI is not the BSER for
coal-fired EGUs. The EPA's basis for proposing the NSR revisions was to
ease permitting burdens for state agencies and sources that may result
from implementing the ACE Rule. There was concern that, for sources
that modified their EGU to improve the heat rate, if a source were to
be dispatched more frequently because of improved efficiency (the
``rebound effect''), the source could experience an increase in
absolute emissions for one or more pollutants and potentially trigger
major NSR requirements. The hourly emissions rate test was proposed to
relieve such sources that were undertaking HRI projects to comply with
their state plans from the burdens of NSR permitting, particularly in
cases in which a source has an increase in annual emissions of a
pollutant. However, given that this final rule BSER is not based on
HRIs for coal-fired EGUs, the NSR revisions proposed as part of the ACE
Rule would no longer serve the purpose that the EPA expressed in that
proposal preamble.
Furthermore, in the event that any sources are increasing their
absolute emissions after modifying an EGU, applicability of the NSR
program is beneficial as a backstop that provides review of those
situations to determine if additional controls or other emission
limitations are necessary on a case-by-case basis to protect air
quality. In addition, given that considerable time has passed since
these EGU-specific NSR applicability revisions were proposed in 2018,
should the EPA decide to pursue them at a later time, it is prudent for
the Agency to propose them again at that time, accompanied with the
EPA's updated context and justification to support re-proposing the NSR
revisions, rather than relying on the proposal from 2018. Therefore,
the EPA is withdrawing these proposed NSR revisions.
VII. Regulatory Approach for Existing Fossil Fuel-Fired Steam
Generating Units
Existing fossil fuel-fired steam generation units are the largest
stationary source of CO2 emissions, emitting 909 MMT
CO2e in 2021. Recent developments in control technologies
offer opportunities to reduce CO2 emissions from these
sources. The EPA's regulatory approach for these units is to require
emissions reduction consistent with these technologies, where their use
is cost-reasonable.
A. Overview
In this section of the preamble, the EPA identifies the BSER and
degree of emission limitation achievable for the regulation of GHG
emissions from existing fossil fuel-fired steam generating units. As
detailed in section V of this preamble, to meet the requirements of CAA
section 111(d), the EPA promulgates ``emission guidelines'' that
identify the BSER and the degree of emission limitation achievable
through the application of the BSER, and states then establish
standards of performance for affected sources that reflect that level
of stringency. To determine the BSER for a source category, the EPA
identifies systems of emission reduction (e.g., control technologies)
that have been adequately demonstrated and evaluates the potential
emissions reduction, costs, any non-air health and environmental
impacts, and energy requirements. As described in section V.C.1 of this
preamble, the EPA has broad authority to create subcategories under CAA
section 111(d). Therefore, where the sources in a category differ from
each other by some characteristic that is relevant for the suitability
of the emission controls, the EPA may create separate subcategories and
make separate BSER determinations for those subcategories.
The EPA considered the characteristics of fossil fuel-fired steam
generating units that may impact the suitability of different control
measures. First, the EPA observed that the type and amounts of fossil
fuels--coal, oil, and natural gas--fired in the steam generating unit
affect the performance and emissions reductions achievable by different
control technologies, in part due to the differences in the carbon
content of those fuels. The EPA recognized that many sources fire
multiple types of fossil fuel. Therefore, the EPA is finalizing
subcategories of coal-fired, oil-fired, and natural gas-fired steam
generating units. The EPA is basing these subcategories, in part, on
the amount of fuel combusted by the steam generating unit.
The EPA then considered the BSER that may be suitable for each of
those subcategories of fuel type. For coal-fired steam generating
units, of the available control technologies, the EPA is determining
that CCS with 90 percent capture of CO2 meets the
requirements for BSER, including being adequately demonstrated and
achieving significant emission reductions at reasonable cost for units
operating in the long-term, as detailed in section VII.C.1.a of this
preamble. Application of this BSER results in a degree of emission
limitation equivalent to an 88.4 percent reduction in emission rate (lb
CO2/MWh-gross). The compliance date for these sources is
January 1, 2032.
Typically, the EPA assumes that sources subject to controls operate
in the long-term.\266\ See, for example, the 2015 NSPS (80 FR 64509;
October 23, 2015) or the 2011 CSAPR (76 FR 48208; August 8, 2011).
Under that assumption, fleet average costs for CCS are comparable to
the cost metrics the EPA has previously considered to be reasonable.
However, the EPA observes that about half of the capacity (87 GW out of
181 GW) of existing coal-fired steam generating units have announced
plans to permanently cease operation prior to 2039, as detailed in
section IV.D.3.b of this preamble, affecting the period available for
those sources to amortize the capital costs of CCS.
[[Page 39841]]
Accordingly, the EPA evaluated the costs of CCS for different
amortization periods. For an amortization period of more than 7 years--
such that sources operate after January 1, 2039--annualized fleet
average costs are comparable to or less than the metrics of costs for
controls that the EPA has previously found to be reasonable. However,
the group of sources ceasing operation prior to January 1, 2039, have
less time available to amortize the capital costs of CCS, resulting in
higher annualized costs.
---------------------------------------------------------------------------
\266\ Typically, the EPA assumes that the capital costs can be
amortized over a period of 15 years. As discussed in section
VII.C.1.a.ii of this preamble, in the case of CCS, the IRC section
45Q tax credit, which defrays a significant portion of the costs of
CCS, is available for the first 12 years of operation. Accordingly,
EPA generally assumed a 12-year amortization period in determining
CCS costs.
---------------------------------------------------------------------------
Because the costs of CCS depend on the available amortization
period, the EPA is creating a subcategory for sources demonstrating
that they plan to permanently cease operation prior to January 1, 2039.
Instead, for this subcategory of sources, the EPA is determining that
natural gas co-firing at 40 percent of annual heat input meets the
requirements of BSER. Application of the natural gas co-firing BSER
results in a degree of emission limitation equivalent to a 16 percent
reduction in emission rate (lb CO2/MWh-gross). Co-firing at
40 percent entails significantly less control equipment and
infrastructure than CCS, and as a result, the EPA has determined that
affected sources are able to implement it more quickly than CCS, by
January 1, 2030. Importantly, co-firing at 40 percent also entails
significantly less capital cost than CCS, and as a result, the costs of
co-firing are comparable to or less than the metrics for cost
reasonableness with an amortization period that is significantly
shorter than the period for CCS. The EPA has determined that the costs
of co-firing meet the metrics for cost reasonableness for the majority
of the capacity that permanently cease operation more than 2 years
after the January 1, 2030, implementation date, or after January 1,
2032 (and up to December 31, 2038), and that therefore have an
amortization period of more than 2 years (and up to 9 years).
The EPA is also determining that sources demonstrating that they
plan to permanently cease operation before January 1, 2032, are not
subject to the 40 percent co-firing requirement. This is because their
amortization period would be so short--2 years or less--that the costs
of co-firing would, in general, be less comparable to the cost metrics
for reasonableness for that group of sources. Accordingly, the EPA is
defining the medium-term subcategory to include those sources
demonstrating that they plan to permanently cease operating after
December 31, 2031, and before January 1, 2039.
Considering the limited emission reductions available in light of
the cost reasonableness of controls with short amortization periods,
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.
For natural gas- and oil-fired steam generating units, the EPA is
finalizing subcategories based on capacity factor. Because natural gas-
and oil-fired steam generating units with similar annual capacity
factors perform similarly to one another, the EPA is finalizing a BSER
of routine methods of operation and maintenance and a degree of
emission limitation of no increase in emission rate for intermediate
and base load subcategories. For low load natural gas- and oil-fired
steam generating units, the EPA is finalizing a BSER of uniform fuels
and respective degrees of emission limitation defined on a heat input
basis (130 lb CO2/MMBtu and 170 lb CO2/MMBtu).
Furthermore, the EPA is finalizing presumptive standards for natural
gas- and oil-fired steam generating units as follows: base load sources
(those with annual capacity factors greater than 45 percent) have a
presumptive standard of 1,400 lb CO2/MWh-gross, intermediate
load sources (those with annual capacity factors greater than 8 percent
and or less than or equal to 45 percent) have a presumptive standard of
1,600 lb CO2/MWh-gross. For low load oil-fired sources, the
EPA is finalizing a presumptive standard of 170 lb CO2/
MMBtu, while for low load natural gas-fired sources the EPA is
finalizing a presumptive standard of 130 lb CO2/MMBtu. A
compliance date of January 1, 2030, applies for all natural gas- and
oil-fired steam generating units.
The final subcategories and BSER are summarized in table 1 of this
document.
Table 1--Summary of Final BSER, Subcategories, and Degrees of Emission Limitation for Affected EGUs
----------------------------------------------------------------------------------------------------------------
Presumptively
Subcategory Degree of emission approvable
Affected EGUs definition BSER limitation standard of
performance *
----------------------------------------------------------------------------------------------------------------
Long-term existing coal-fired Coal-fired steam CCS with 90 88.4 percent 88.4 percent
steam generating units. generating units percent capture reduction in reduction in
that are not of CO2. emission rate (lb annual emission
medium-term units. CO2/MWh-gross). rate (lb CO2/MWh-
gross) from the
unit-specific
baseline.
Medium-term existing coal-fired Coal-fired steam Natural gas co- A 16 percent A 16 percent
steam generating units. generating units firing at 40 reduction in reduction in
that have percent of the emission rate (lb annual emission
demonstrated that heat input to the CO2/MWh-gross). rate (lb CO2/MWh-
they plan to unit. gross) from the
permanently cease unit-specific
operations after baseline.
December 31,
2031, and before
January 1, 2039.
Base load existing oil-fired Oil-fired steam Routine methods of No increase in An annual emission
steam generating units. generating units operation and emission rate (lb rate limit of
with an annual maintenance. CO2/MWh-gross). 1,400 lb CO2/MWh-
capacity factor gross.
greater than or
equal to 45
percent.
Intermediate load existing oil- Oil-fired steam Routine methods of No increase in An annual emission
fired steam generating units. generating units operation and emission rate (lb rate limit of
with an annual maintenance. CO2/MWh-gross). 1,600 lb CO2/MWh-
capacity factor gross.
greater than or
equal to 8
percent and less
than 45 percent.
Low load existing oil-fired Oil-fired steam lower-emitting 170 lb CO2/MMBtu.. 170 lb CO2/MMBtu.
steam generating units. generating units fuels.
with an annual
capacity factor
less than 8
percent.
Base load existing natural gas- Natural gas-fired Routine methods of No increase in An annual emission
fired steam generating units. steam generating operation and emission rate (lb rate limit of
units with an maintenance. CO2/MWh-gross). 1,400 lb CO2/MWh-
annual capacity gross.
factor greater
than or equal to
45 percent.
Intermediate load existing Natural gas-fired Routine methods of No increase in An annual emission
natural gas-fired steam steam generating operation and emission rate (lb rate limit of
generating units. units with an maintenance. CO2/MWh-gross). 1,600 lb CO2/MWh-
annual capacity gross.
factor greater
than or equal to
8 percent and
less than 45
percent.
[[Page 39842]]
Low load existing natural gas- Oil-fired steam lower-emitting 130 lb CO2/MMBtu.. 130 lb CO2/MMBtu.
fired steam generating units. generating units fuels.
with an annual
capacity factor
less than 8
percent.
----------------------------------------------------------------------------------------------------------------
* 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. Inclusion in this table is for completeness.
B. Applicability Requirements and Fossil Fuel-Type Definitions for
Subcategories of Steam Generating Units
In this section of the preamble, the EPA describes the rationale
for the final applicability requirements for existing fossil fuel-fired
steam generating units. The EPA also describes the rationale for the
fuel type definitions and associated subcategories.
1. Applicability Requirements
For the emission guidelines, the EPA is finalizing that a
designated facility \267\ is any fossil fuel-fired electric utility
steam generating unit (i.e., utility boiler or IGCC unit) that: (1) was
in operation or had commenced construction on or before January 8,
2014; \268\ (2) serves a generator capable of selling greater than 25
MW to a utility power distribution system; and (3) has a base load
rating greater than 260 GJ/h (250 million British thermal units per
hour (MMBtu/h)) heat input of fossil fuel (either alone or in
combination with any other fuel). Consistent with the implementing
regulations, the term ``designated facility'' is used throughout this
preamble to refer to the sources affected by these emission
guidelines.\269\ For the emission guidelines, consistent with prior CAA
section 111 rulemakings concerning EGUs, the term ``designated
facility'' refers to a single EGU that is affected by these emission
guidelines. The rationale for the final applicability requirements is
the same as that for 40 CFR part 60, subpart TTTT (80 FR 64543-44;
October 23, 2015). The EPA includes that discussion by reference here.
---------------------------------------------------------------------------
\267\ The term ``designated facility'' means ``any existing
facility . . . which emits a designated pollutant and which would be
subject to a standard of performance for that pollutant if the
existing facility were an affected facility.'' See 40 CFR 60.21a(b).
\268\ Under CAA section 111, the determination of whether a
source is a new source or an existing source (and thus potentially a
designated facility) is based on the date that the EPA proposes to
establish standards of performance for new sources.
\269\ The EPA recognizes, however, that the word ``facility'' is
often understood colloquially to refer to a single power plant,
which may have one or more EGUs co-located within the plant's
boundaries.
---------------------------------------------------------------------------
Section 111(a)(6) of the CAA defines an ``existing source'' as
``any stationary source other than a new source.'' Therefore, the
emission guidelines do not apply to any steam generating units that are
new after January 8, 2014, or reconstructed after June 18, 2014, the
applicability dates of 40 CFR part 60, subpart TTTT. Moreover, because
the EPA is now finalizing revised standards of performance for coal-
fired steam generating units that undertake a modification, a modified
coal-fired steam generating unit would be considered ``new,'' and
therefore not subject to these emission guidelines, if the modification
occurs after the date the proposal was published in the Federal
Register (May 23, 2023). Any coal-fired steam generating unit that has
modified prior to that date would be considered an existing source that
is subject to these emission guidelines.
In addition, the EPA is finalizing in the applicability
requirements of the emission guidelines many of the same exemptions as
discussed for 40 CFR part 60, subpart TTTT, in section VIII.E.1 of this
preamble. EGUs that may be excluded from the requirement to establish
standards under a state plan are: (1) units that are subject to 40 CFR
part 60, subpart TTTT, as a result of commencing a qualifying
modification or reconstruction; (2) steam generating units subject to a
federally enforceable permit limiting net-electric sales to one-third
or less of their potential electric output or 219,000 MWh or less on an
annual basis and annual net-electric sales have never exceeded one-
third or less of their potential electric output or 219,000 MWh; (3)
non-fossil fuel units (i.e., units that are capable of deriving at
least 50 percent of heat input from non-fossil fuel at the base load
rating) that are subject to a federally enforceable permit limiting
fossil fuel use to 10 percent or less of the annual capacity factor;
(4) combined heat and power (CHP) units that are subject to a federally
enforceable permit limiting annual net-electric sales to no more than
either 219,000 MWh or the product of the design efficiency and the
potential electric output, whichever is greater; (5) units that serve a
generator along with other affected EGU(s), where the effective
generation capacity (determined based on a prorated output of the base
load rating of EGU) is 25 MW or less; (6) municipal waste combustor
units subject to 40 CFR part 60, subpart Eb; (7) commercial or
industrial solid waste incineration units that are subject to 40 CFR
part 60, subpart CCCC; (8) EGUs that derive greater than 50 percent of
the heat input from an industrial process that does not produce any
electrical or mechanical output or useful thermal output that is used
outside the affected EGU; or (9) coal-fired steam generating units that
have elected to permanently cease operation prior to January 1, 2032.
The exemptions listed above at (4), (5), (6), and (7) are among the
current exemptions at 40 CFR 60.5509(b), as discussed in section
VIII.E.1 of this preamble. The exemptions listed above at (2), (3), and
(8) are exemptions the EPA is finalizing revisions for 40 CFR part 60,
subpart TTTT, and the rationale for the exemptions is in section
VIII.E.1 of this preamble. For consistency with the applicability
requirements in 40 CFR part 60, subpart TTTT, and 40 CFR part 60,
subpart TTTTa, the Agency is finalizing these same exemptions for the
applicability of the emission guidelines.
2. Coal-Fired Units Permanently Ceasing Operation Before January 1,
2032
The EPA is not addressing existing coal-fired steam generating
units demonstrating that they plan to permanently cease operating
before January 1, 2032, in these emission guidelines. Sources ceasing
operation before that date have far less emission reduction potential
than sources that will be operating longer, because there are unlikely
to be appreciable, cost-reasonable emission reductions available on
average for the group of sources operating in that timeframe. This is
because controls that entail capital expenditures are unlikely to be
[[Page 39843]]
of reasonable cost for these sources due to the relatively short period
over which they could amortize the capital costs of controls.
In particular, in developing the emission guidelines, the EPA
evaluated two systems of emission reduction that achieve substantial
emission reductions for coal-fired steam generating units: CCS with 90
percent capture; and natural gas co-firing at 40 percent of heat input.
For CCS, the EPA has determined that controls can be installed and
fully operational by the compliance date of January 1, 2032, as
detailed in section VII.C.1.a.i(E) of this preamble. CCS would
therefore, in most cases, be unavailable to coal-fired steam generating
units planning to cease operation prior to that date. Furthermore, the
EPA evaluated the costs of CCS for different amortization periods. For
an amortization period of more than 7 years--such that sources operate
after January 1, 2039--annualized fleet average costs are comparable to
or less than the costs of controls the EPA has previously determined to
be reasonable ($18.50/MWh of generation and $98/ton of CO2
reduced), as detailed in section VII.C.1.a.ii of this preamble.
However, the costs for shorter amortization periods are higher. For
sources ceasing operation by January 1, 2032, it would be unlikely that
the annualized costs of CCS would be reasonable even were CCS installed
at an earlier date (e.g., by January 1, 2030) due to the shorter
amortization period available.
Because the costs of CCS would be higher for shorter amortization
periods, the EPA is finalizing a separate subcategory for sources
demonstrating that they plan to permanently cease operating by January
1, 2039, with a BSER of 40 percent natural gas co-firing, as detailed
in section VII.C.2.b.ii of this preamble. For natural gas co-firing,
the EPA is finalizing a compliance date of January 1, 2030, as detailed
in section VII.C.2.b.i(C) of this preamble. Therefore, the EPA assumes
sources subject to a natural gas co-firing BSER can amortize costs for
a period of up to 9 years. The EPA has determined that the costs of
natural gas co-firing at 40 percent meet the metrics for cost
reasonableness for the majority of the capacity that operate more than
2 years after the January 1, 2030, implementation date, i.e., that
operate after January 1, 2032 (and up to December 31, 2038), and that
therefore have an amortization period of more than 2 years (and up to 9
years).
However, for sources ceasing operation prior to January 1, 2032,
the EPA believes that establishing a best system of emission reduction
corresponding to a substantial level of natural gas co-firing would
broadly entail costs of control that are above those that the EPA is
generally considering reasonable. Sources permanently ceasing operation
before January 1, 2032 would have less than 2 years to amortize the
capital costs, as detailed in section VII.C.2.a of this preamble.
Compared to the metrics for cost reasonableness that EPA has previously
deemed reasonable ($18.50/MWh of generation and $98/ton of
CO2 reduced), very few sources can co-fire 40 percent
natural gas at costs comparable to these metrics with an amortization
period of only one year; only 1 percent of units have costs that are
below both $18.50/MWh of generation and $98/ton of CO2
reduced. The number of sources that can co-fire lower amounts of
natural gas at costs comparable to these metrics is likewise limited--
only approximately 34 percent of units can co-fire with 20 percent
natural gas at costs lower than both cost metrics. Furthermore, the
period that these sources would operate with co-firing for would be
short, so that the emission reductions from that group of sources would
be limited.
By contrast, assuming a two-year amortization period, many more
units can co-fire with meaningful amounts of natural gas at a cost that
is consistent with the metrics EPA has previously used: 18 percent of
units can co-fire with 40 percent natural gas at costs less than $98/
ton and $18.50/MWh, and 50 percent of units can co-fire with 20 percent
natural gas at costs lower than both metrics. Because a substantial
number of sources can implement 40-percent co-firing with natural gas
with an amortization period of two years or longer with reasonable
costs, and even more can co-fire with lesser amounts with reasonable
costs with amortization periods longer than two years,\270\ the EPA
determined that a technology-based BSER was available for coal-fired
units operating past January 1, 2032.
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\270\ As described in detail in section X.C.2 of this preamble,
the EPA recognizes that particular affected EGUs may have
characteristics that make it unreasonable to achieve the degree of
emission limitation corresponding to 40 percent co-firing with
natural gas. For example, a state may be able to demonstrate a
fundamental difference between the costs the EPA considered in these
emission guidelines and the costs to an affected EGU that plans to
cease operation in late 2032. If such costs make it unreasonable for
a particular unit to meet the degree of emission limitation
corresponding to 40 percent co-firing with natural gas, the state
may apply a less stringent standard of performance to that unit.
Consistent with the requirements for calculating a less stringent
standard of performance at 40 CFR 60.24a(f), under these emission
guidelines states would consider whether it is reasonable for units
that cannot cost-reasonably co-fire natural gas at 40 percent to co-
fire at levels lower than 40 percent. It is thus appropriate that
coal-fired EGUs that can reasonably co-fire any amount of natural
gas be subject to these emission guidelines.
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Sources that retire before that date, however, are differently
situated as described above. In light of the small number of sources
that are planning to retire before January 1, 2032 that could cost-
effectively co-fire with natural gas, coupled with the small amount of
emissions reductions that can be achieved from co-firing in such a
short time span, the EPA is choosing not to establish a BSER for these
sources.\271\
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\271\ For the reasons described at length in section VI.B, the
EPA does not believe that heat rate improvement measures or HRI are
appropriate for sources retiring before January 1, 2032 because HRI
applied to coal-fired sources achieve few emission reductions, and
can lead to the ``rebound effect'' where CO2 emissions
from the source increase rather than decrease as a consequence of
imposing the technologies.
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Because, at this time, the EPA has determined that CCS and natural
gas co-firing are not available at reasonable cost for sources ceasing
operation before January 1, 2032, the EPA is not finalizing a BSER for
such sources. Not finalizing a BSER for these sources is consistent
with the Agency's discretion to take incremental steps to address
CO2 from sources in the category, and to direct the EPA's
limited resources at regulation of those sources that can achieve the
most emission reductions. The EPA is therefore providing that existing
coal-fired steam generating EGUs that have elected to cease operating
before January 1, 2032, are not regulated by these emission guidelines.
This exemption applies to a source until the earlier of December 31,
2031, or the date it demonstrates in the state plan that it plans to
cease operation. If a source continues to operate past this date, it is
no longer exempt from these emission guidelines. See section X.E.1 of
this preamble for discussion of how state plans should address sources
subject to exemption (9).\272\
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\272\ The EPA notes that this applicability exemption does not
conflict with states' ability to consider the remaining useful lives
of ``particular'' sources that are subject to these emission
guidelines. 42 U.S.C. 7411(d)(1). As the EPA's implementing
regulations specify, the provision for states' consideration of
RULOF is intended address the specific conditions of particular
sources, whereas the EPA is responsible for determining generally
how to regulate a source category under an emission guideline.
Moreover, RULOF applies only to when a state is applying a standard
of performance to an affected source--and the state would not apply
a standard of performance to exempted sources.
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3. Sources Outside of the Contiguous U.S.
The EPA proposed the same emission guidelines for fossil fuel-fired
steam
[[Page 39844]]
generating units in non-continental areas (i.e., Hawaii, the U.S.
Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico,
and the Northern Mariana Islands) and non-contiguous areas (non-
continental areas and Alaska) as the EPA proposed for comparable units
in the contiguous 48 states. The EPA notes that the modeling that
supports the final emission guidelines focus on sources in the
contiguous U.S. Further, the EPA notes that few, if any, coal-fired
steam generating units operate outside of the contiguous 48 states and
meet the applicability criteria. Finally, the EPA notes that the
proposed BSER and degree of emissions limitation for non-continental
oil-fired steam generating units would have achieved few emission
reductions. Therefore, the EPA is not finalizing emission guidelines
for existing steam generating units in states and territories
(including Alaska, Hawaii, Guam, Puerto Rico, and the U.S. Virgin
Islands) that are outside of the contiguous U.S. at this time.
4. IGCC Units
The EPA notes that existing IGCC units were included in the
proposed applicability requirements and that, in section VII.B of this
preamble, the EPA is finalizing inclusion of those units in the
subcategory of coal-fired steam generating units. IGCC units gasify
coal or solid fossil fuel (e.g., pet coke) to produce syngas (a mixture
of carbon monoxide and hydrogen), and either burn the syngas directly
in a combined cycle unit or use a catalyst for water-gas shift (WGS) to
produce a pre-combustion gas stream with a higher concentration of
CO2 and hydrogen, which can be burned in a hydrogen turbine
combined cycle unit. As described in section VII.C of this preamble,
the final BSER for coal-fired steam generating units includes co-firing
natural gas and CCS. The few IGCC units that now operate in the U.S.
either burn natural gas exclusively--and as such operate as natural gas
combined cycle units--or in amounts near to the 40 percent level of the
natural gas co-firing BSER. Additionally, IGCC units may be suitable
for pre-combustion CO2 capture. Because the CO2
concentration in the pre-combustion gas, after WGS, is high relative to
coal-combustion flue gas, pre-combustion CO2 capture for
IGCC units can be performed using either an amine-based (or other
solvent-based) capture process or a physical absorption capture
process. Alternatively, post-combustion CO2 capture can be
applied to the source. The one existing IGCC unit that still uses coal
was recently awarded funding from DOE for a front-end engineering
design (FEED) study for CCS targeting a capture efficiency of more than
95 percent.\273\ For these reasons, the EPA is not distinguishing IGCC
units from other coal-fired steam generating EGUs, so that the BSER of
co-firing for medium-term coal-fired units and CCS for long-term coal-
fired units apply to IGCC units.\274\
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\273\ Duke Edwardsport DOE FEED Study Fact Sheet. https://www.energy.gov/sites/default/files/2024-01/OCED_CCFEEDs_AwardeeFactSheet_Duke_1.5.2024.pdf.
\274\ For additional details on pre-combustion CO2
capture, please see the final TSD, GHG Mitigation Measures for Steam
Generating Units.
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5. Fossil Fuel-Type Definitions for Subcategories of Steam Generating
Units
In this action, the EPA is finalizing definitions for subcategories
of existing fossil fuel-fired steam generating units based on the type
and amount of fossil fuel used in the unit. The EPA is finalizing
separate subcategories based on fuel type because the carbon content of
the fuel combusted affects the output emission rate (i.e., lb
CO2/MWh). Fuels with a higher carbon content produce a
greater amount of CO2 emissions per unit of fuel combusted
(on a heat input basis, MMBtu) and per unit of electricity generated
(i.e., MWh).
The EPA proposed fossil fuel type subcategory definitions based on
the definitions in 40 CFR part 63, subpart UUUUU, and the fossil fuel
definitions in 40 CFR part 60, subpart TTTT. Those proposed definitions
were determined by the relative heat input contribution of the
different fuels combusted in a unit during the 3 years prior to the
proposed compliance date of January 1, 2030. Further, to be considered
an oil-fired or natural gas-fired unit for purposes of this emission
guideline, a source would no longer retain the capability to fire coal
after December 31, 2029.
The EPA proposed a 3-year lookback period, so that the proposed
fuel-type subcategorization would have been based, in part, on the fuel
type fired between January 1, 2027, and January 1, 2030. However, the
intent of the proposed fuel type subcategorization was to base the fuel
type definition on the state of the source on January 1, 2030.
Therefore, the EPA is finalizing the following fuel type subcategory
definitions:
A coal-fired steam generating unit is an electric utility
steam generating unit or IGCC unit that meets the definition of
``fossil fuel-fired'' and that burns coal for more than 10.0 percent of
the average annual heat input during any continuous 3-calendar-year
period after December 31, 2029, or for more than 15.0 percent of the
annual heat input during any one calendar year after December 31, 2029,
or that retains the capability to fire coal after December 31, 2029.
An oil-fired steam generating unit is an electric utility
steam generating unit meeting the definition of ``fossil fuel-fired''
that is not a coal-fired steam generating unit, that no longer retains
the capability to fire coal after December 31, 2029, and that burns oil
for more than 10.0 percent of the average annual heat input during any
continuous 3-calendar-year period after December 31, 2029, or for more
than 15.0 percent of the annual heat input during any one calendar year
after December 31, 2029.
A natural gas-fired steam generating unit is an electric
utility steam generating unit meeting the definition of ``fossil fuel-
fired,'' that is not a coal-fired or oil-fired steam generating unit,
that no longer retains the capability to fire coal after December 31,
2029, and that burns natural gas for more than 10.0 percent of the
average annual heat input during any continuous 3-calendar-year period
after December 31, 2029, or for more than 15.0 percent of the annual
heat input during any one calendar year after December 31, 2029.
The EPA received some comments on the fuel type definitions. Those
comments and responses are as follows.
Comment: Some industry stakeholders suggested changes to the
proposed definitions for fossil fuel type. Specifically, some
commenters requested that the reference to the initial compliance date
be removed and that the fuel type determination should instead be
rolling and continually update after the initial compliance date. Those
commenters suggested this would, for example, allow sources in the
coal-fired subcategory that begin natural gas co-firing in 2030 to
convert to the natural-gas fired subcategory prior to the proposed date
of January 1, 2040, instead of ceasing operation.
Other industry commenters suggested that to be a natural gas-fired
steam generating unit, a source could either meet the heat input
requirements during the 3 years prior to the compliance date or
(emphasis added) no longer retain the capability to fire coal after
December 31, 2029. Those commenters noted that, as proposed, a source
that had planned to convert to 100 percent natural gas-firing would
essentially have to do so prior to January 1, 2027, to meet the
proposed heat input-based definition, in addition to removing the
capability to fire coal by the compliance date.
[[Page 39845]]
Response: Although full natural gas conversions are not a measure
that the EPA considered as a potential BSER, the emission guidelines do
not prohibit such conversions should a state elect to require or
accommodate them. As noted above, the EPA recognizes that many steam
EGUs that formerly utilized coal as a primary fuel have fully or
partially converted to natural gas, and that additional steam EGUs may
elect to do so during the implementation period for these emission
guidelines. However, these emission guidelines place reasonable
constraints on the timing of such a conversion in situations where a
source seeks to be regulated as a natural gas-fired steam EGU rather
than as a coal-fired steam EGU. The EPA believes that such constraints
are necessary in order to avoid creating a perverse incentive for EGUs
to defer conversions in a way that could undermine the emission
reduction purpose of the rule. Therefore, the EPA disagrees with those
commenters that suggest the EPA should, in general, allow EGUs to be
regulated as natural gas-fired steam EGUs when they undertake such
conversions past January 1, 2030.
However, the EPA acknowledges that the proposed subcategorization
would have essentially required a unit to convert to natural gas by
January 1, 2027 in order to be regulated as a natural gas-fired steam
EGU. The EPA is finalizing fuel type subcategorization based on the
state of the source on the compliance date of January 1, 2030, and
during any period thereafter, as detailed in section VII.B of this
preamble. Should a source not be able to fully convert to natural gas
by this date, it would be treated as a coal-fired steam generating EGU;
however, the state may be able to use the RULOF provisions, as
discussed in section X.C.2 of this preamble, to particularize a
standard of performance for the unit. Note that if a state relies on
operating conditions within the control of the source as the basis of
providing a less stringent standard of performance or longer compliance
schedule, it must include those operating conditions as an enforceable
requirement in the state plan. 40 CFR 60.24a(g).
C. Rationale for the BSER for Coal-Fired Steam Generating Units
This section of the preamble describes the rationale for the final
BSERs for existing coal-fired steam generating units based on the
criteria described in section V.C of this preamble.
At proposal, the EPA evaluated two primary control technologies as
potentially representing the BSER for existing coal-fired steam
generating units: CCS and natural gas co-firing. For sources operating
in the long-term, the EPA proposed CCS with 90 percent capture as BSER.
For sources operating in the medium-term (i.e., those demonstrating
that they plan to permanently cease operation by January 1, 2040), the
EPA proposed 40 percent natural gas co-firing as BSER. For imminent-
term and near-term sources ceasing operation earlier, the EPA proposed
BSERs of routine methods of operation and maintenance.
The EPA is finalizing CCS with 90 percent capture as BSER for coal-
fired steam generating units because CCS can achieve a substantial
amount of emission reductions and satisfies the other BSER criteria.
CCS has been adequately demonstrated and results in by far the largest
emissions reductions of the available control technologies. As noted
below, the EPA has also determined that the compliance date for CCS is
January 1, 2032. CCS, however, entails significant up-front capital
expenditures that are amortized over a period of years. The EPA
evaluated the cost for different amortization periods, and the EPA has
concluded that CCS is cost-reasonable for units that operate past
January 1, 2039. As noted in section IV.D.3.b of this preamble, about
half (87 GW out of 181 GW) of all coal-fired capacity currently in
existence has announced plans to permanently cease operations by
January 1, 2039, and additional sources are likely to do so because
they will be older than the age at which sources generally have
permanently ceased operations since 2000. The EPA has determined that
the remaining sources that may operate after January 1, 2039, can, on
average, install CCS at a cost that is consistent with the EPA's
metrics for cost reasonableness, accounting for an amortization period
for the capital costs of more than 7 years, as detailed in section
VII.C.1.a.ii of this preamble. If a particular source has costs of CCS
that are fundamentally different from those amounts, the state may
consider it to be a candidate for a different control requirement under
the RULOF provision, as detailed in section X.C.2 of this preamble. For
the group of sources that permanently cease operation before January 1,
2039, the EPA has concluded that CCS would in general be of higher
cost, and therefore is finalizing a subcategory for these units, termed
medium-term units, and finalizing 40 percent natural gas co-firing on a
heat input basis as the BSER.
These final subcategories and BSERs are largely consistent with the
proposal, which included a long-term subcategory for sources that did
not plan to permanently cease operations by January 1, 2040, with 90
percent capture CCS as the BSER; and a medium-term subcategory for
sources that permanently cease operations by that date and were not in
any of the other proposed subcategories, discussed next, with 40
percent co-firing as the BSER. For both subcategories, the compliance
date was January 1, 2030. The EPA also proposed an imminent-term
subcategory, for sources that planned to permanently cease operations
by January 1, 2032; and a near-term subcategory, for sources that
planned to permanently case operations by January 1, 2035, and that
limited their annual capacity utilization to 20 percent. The EPA
proposed a BSER of routine methods of operation and maintenance for
these two subcategories.
The EPA is not finalizing these imminent-term and near-term
subcategories. In addition, after considering the comments, the EPA
acknowledges that some additional time from what was proposed may be
beneficial for the planning and installation of CCS. Therefore, the EPA
is finalizing a January 1, 2032, compliance date for long-term existing
coal-fired steam generating units. As noted above, the EPA's analysis
of the costs of CCS also indicates that CCS is cost-reasonable with a
minimum amortization period of seven years; as a result, the final
emission guidelines would apply a CCS-based standard only to those
units that plan to operate for at least seven years after the
compliance deadline (i.e., units that plan to remain in operation after
January 1, 2039). For medium-term sources subject to a natural gas co-
firing BSER, the EPA is finalizing a January 1, 2030, compliance date
because the EPA has concluded that this provides a reasonable amount of
time to begin co-firing, a technology that entails substantially less
up-front infrastructure and, relatedly, capital expenditure than CCS.
1. Long-Term Coal-Fired Steam Generating Units
The EPA is finalizing CCS with 90 percent capture of CO2
at the stack as BSER for long-term coal-fired steam generating units.
Coal-fired steam generating units are the largest stationary source of
CO2 in the United States. Coal-fired steam generating units
have higher emission rates than other generating technologies, about
twice the emission rate of a natural gas combined cycle unit.
Typically, even newer, more efficient coal-fired steam generating units
emit over 1,800 lb CO2/MWh-gross, while many existing coal-
fired steam generating units have emission rates of 2,200 lb
CO2/MWh-gross or higher. As noted in section IV.B of this
[[Page 39846]]
preamble, coal-fired sources emitted 909 MMT CO2e in 2021,
59 percent of the GHG emissions from the power sector and 14 percent of
the total U.S. GHG emissions--contributing more to U.S. GHG emissions
than any other sector, aside from transportation road sources.\275\
Furthermore, considering the sources in the long-term subcategory will
operate longer than sources with shorter operating horizons, long-term
coal-fired units have the potential to emit more total CO2.
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\275\ U.S. Environmental Protection Agency (EPA). Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2021. U.S. Greenhouse
Gas Emissions by Inventory Sector, 2021. https://cfpub.epa.gov/ghgdata/inventoryexplorer/index.html#iallsectors/allsectors/allgas/inventsect/current.
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CCS is a control technology that can be applied at the stack of a
steam generating unit, achieves substantial reductions in emissions and
can capture and permanently sequester more than 90 percent of
CO2 emitted by coal-fired steam generating units. The
technology is adequately demonstrated, given that it has been operated
at scale and is widely applicable to these sources, and there are vast
sequestration opportunities across the continental U.S. Additionally,
the costs for CCS are reasonable, in light of recent technology cost
declines and policies including the tax credit under IRC section 45Q.
Moreover, the non-air quality health and environmental impacts of CCS
can be mitigated and the energy requirements of CCS are not
unreasonably adverse. The EPA's weighing of these factors together
provides the basis for finalizing CCS as BSER for these sources. In
addition, this BSER determination aligns with the caselaw, discussed in
section V.C.2.h of the preamble, stating that CAA section 111
encourages continued advancement in pollution control technology.
At proposal, the EPA also evaluated natural gas co-firing at 40
percent of heat input as a potential BSER for long-term coal-fired
steam generating units. While the unit level emission rate reductions
of 16 percent achieved by 40 percent natural gas co-firing are
appreciable, those reductions are substantially less than CCS with 90
percent capture of CO2. Therefore, because CCS achieves more
reductions at the unit level and is cost-reasonable, the EPA is not
finalizing natural gas co-firing as the BSER for these units. Further,
the EPA is not finalizing partial-CCS at lower capture rates (e.g., 30
percent) because it achieves substantially fewer unit-level reductions
at greater cost, and because CCS at 90 percent is achievable. Notably,
the IRC section 45Q tax credit may not be available to defray the costs
of partial CCS and the emission reductions would be limited. And the
EPA is not finalizing HRI as the BSER for these units because of the
limited reductions and potential rebound effect.
a. Rationale for CCS as the BSER for Long-Term Coal-Fired Steam
Generating Units
In this section of the preamble, the EPA explains the rationale for
CCS as the BSER for existing long-term coal-fired steam generating
units. This section discusses the aspects of CCS that are relevant for
existing coal-fired steam generating units and, in particular, long-
term units. As noted in section VIII.F.4.c.iv of this preamble, much of
this discussion is also relevant for the EPA's determination that CCS
is the BSER for new base load combustion turbines.
In general, CCS has three major components: CO2 capture,
transportation, and sequestration/storage. Detailed descriptions of
these components are provided in section VII.C.1.a.i of this preamble.
As an overview, post-combustion capture processes remove CO2
from the exhaust gas of a combustion system, such as a utility boiler
or combustion turbine. This technology is referred to as ``post-
combustion capture'' because CO2 is a product of the
combustion of the primary fuel and the capture takes place after the
combustion of that fuel. The exhaust gases from most combustion
processes are at atmospheric pressure, contain somewhat dilute
concentrations of CO2, and are moved through the flue gas
duct system by fans. To separate the CO2 contained in the
flue gas, most current post-combustion capture systems utilize liquid
solvents--commonly amine-based solvents--in CO2 scrubber
systems using chemical absorption (or chemisorption).\276\ In a
chemisorption-based separation process, the flue gas is processed
through the CO2 scrubber and the CO2 is absorbed
by the liquid solvent. The CO2-rich solvent is then
regenerated by heating the solvent to release the captured
CO2.
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\276\ Other technologies may be used to capture CO2,
as described in the final TSDs, GHG Mitigation Measures for Steam
Generating Units and the GHG Mitigation Measures--Carbon Capture and
Storage for Combustion Turbines, available in the rulemaking docket.
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The high purity CO2 is then compressed and transported,
generally through pipelines, to a site for geologic sequestration
(i.e., the long-term containment of CO2 in subsurface
geologic formations). Pipelines are subject to Federal safety
regulations administered by PHMSA. Furthermore, sequestration sites are
widely available across the nation, and the EPA has developed a
comprehensive regulatory structure to oversee geologic sequestration
projects and assure their safety and effectiveness.\277\
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\277\ 80 FR 64549 (October 23, 2015).
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i. Adequately Demonstrated
In this section of the preamble, the EPA explains the rationale for
finalizing its determination that 90 percent capture applied to long-
term coal-fired steam generating units is adequately demonstrated. In
this section, the EPA first describes how simultaneous operation of all
components of CCS functioning in concert with one another has been
demonstrated, including a commercial scale application on a coal-fired
steam generating unit. The demonstration of the individual components
of CO2 capture, transport, and sequestration further support
that CCS is adequately demonstrated. The EPA describes how
demonstrations of CO2 capture support that 90 percent
capture rates are adequately demonstrated. The EPA further describes
how transport and geologic sequestration are adequately demonstrated,
including the feasibility of transport infrastructure and the broad
availability of geologic sequestration reservoirs in the U.S.
(A) Simultaneous Demonstration of CO2 Capture, Transport,
and Sequestration
The EPA proposed that CCS was adequately demonstrated for
applications on combustion turbines and existing coal-fired steam
generating units.
On reviewing the available information, all components of CCS--
CO2 capture, CO2 transport, and CO2
sequestration--have been demonstrated concurrently, with each component
operating simultaneously and in concert with the other components.
(1) Industrial Applications of CCS
Solvent-based CO2 capture was patented nearly 100 years
ago in the 1930s \278\ and has been used in a variety of industrial
applications for decades. For example, since 1978, an amine-based
system has been used to capture approximately 270,000 metric tons of
CO2 per year from the flue gas of the bituminous coal-fired
steam generating units at the 63 MW Argus Cogeneration Plant at Searles
Valley Minerals (Trona,
[[Page 39847]]
California).\279\ Furthermore, thousands of miles of CO2
pipelines have been constructed and securely operated in the U.S. for
decades.\280\ And tens of millions of tons of CO2 have been
permanently stored deep underground either for geologic sequestration
or in association with EOR.\281\ There are currently at least 15
operating CCS projects in the U.S., and another 121 that are under
construction or in advanced stages of development.\282\ This broad
application of CCS demonstrates that the components of CCS have been
successfully operated simultaneously. The Shute Creek Facility has a
capture capacity of 7 million metric tons per year and has been in
operation since 1986.\283\ The facility uses a solvent-based process to
remove CO2 from natural gas, and the captured CO2
is stored in association with EOR. Another example of CCS in industrial
applications is the Great Plains Synfuels Plant has a capture capacity
of 3 million metric tons per year and has been in operation since
2000.284 285 The Great Plains Synfuels Plant (Beulah, North
Dakota) uses a solvent-based process to remove CO2 from
lignite-derived syngas, the CO2 is transported by the Souris
Valley pipeline, and stored underground in association with EOR in the
Weyburn and Midale Oil Units in Saskatchewan, Canada. Over 39 million
metric tons of CO2 has been captured since 2000.
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\278\ 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.
\279\ Dooley, J.J., et al. (2009). ``An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009.'' U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.
\280\ U.S. Department of Transportation, Pipeline and Hazardous
Material Safety Administration, ``Hazardous Annual Liquid Data.''
2022. https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
\281\ GHGRP US EPA. https://www.epa.gov/ghgreporting/supply-underground-injection-and-geologic-sequestration-carbon-dioxide.
\282\ Carbon Capture and Storage in the United States. CBO.
December 13, 2023. https://www.cbo.gov/publication/59345.
\283\ Id.
\284\ https://netl.doe.gov/research/Coal/energy-systems/gasification/gasifipedia/great-plains.
\285\ https://co2re.co/FacilityData.
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(2) Various CO2 capture methods are used in industrial
applications and are tailored to the flue gas conditions of a
particular industry (see the TSD GHG Mitigation Measures for Steam
Generating Units for details). Of those capture technologies, amine
solvent-based capture has been demonstrated for removal of
CO2 from the post-combustion flue gas of fossil fuel-fired
EGUs. The Quest CO2 capture facility in Alberta, Canada,
uses amine-based CO2 capture retrofitted to three existing
steam methane reformers at the Scotford Upgrader facility (operated by
Shell Canada Energy) to capture and sequester approximately 80 percent
of the CO2 in the produced syngas.\286\ Amine-solvents are
also applied for post-combustion capture from fossil fuel fired EGUs.
The Quest facility has been operating since 2015 and captures
approximately 1 million metric tons of CO2 per year.
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\286\ Quest Carbon Capture and Storage Project Annual Summary
Report, Alberta Department of Energy: 2021. https://open.alberta.ca/publications/quest-carbon-capture-and-storage-project-annual-report-2021.
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Applications of CCS at Coal-Fired Steam Generating Units
For electricity generation applications, this includes operation of
CCS at Boundary Dam Unit 3 in Saskatchewan, Canada. CCS at Boundary Dam
Unit 3 includes capture of the CO2 from the flue-gas of the
fossil fuel-fired EGU, compression of the CO2 onsite and
transport via pipeline offsite, and storage of the captured
CO2 underground. Storage of the CO2 captured at
Boundary Dam primarily occurs via EOR. Moreover, CO2
captured from Boundary Dam Unit 3 is also stored in a deep saline
aquifer at the Aquistore Deep Saline CO2 Storage Project,
which has permanently stored over 550,000 tons of CO2 to
date.\287\ Other demonstrations of CCS include the 240 MWe Petra Nova
CCS project at the subbituminous coal-fired W.A. Parish plant in Texas,
which, because it was EPAct05-assisted, we cite as useful in section
VII.C.1.a.i(B)(2) of this preamble, but not essential, corroboration.
See section VII.C.1.a.i(H)(1) for a detailed description of how the EPA
considers information from EPAct05-assisted projects.
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\287\ Aquistore Project. https://ptrc.ca/media/whats-new/aquistore-co2-storage-project-reached-+500000-tonnes-stored.
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Commenters stated that that all constituent components of CCS--
carbon capture, transportation, and sequestration--have not been
adequately demonstrated in integrated, simultaneous operation. We
disagree with this comment. The record described in the preceding shows
that all components have been demonstrated simultaneously. Even if the
record only included demonstration of the individual components of CCS,
the EPA would still determine that CCS is adequately demonstrated as it
would be reasonable on a technical basis that the individual components
are capable of functioning together--they have been engineered and
designed to do so, and the record for the demonstration of the
individual components is based on decades of direct data and
experience.
(B) CO2 Capture Technology at Coal-Fired Steam Generating
Units
The EPA is finalizing the determination that the CO2
capture component of CCS has been adequately demonstrated at a capture
efficiency of 90 percent, is technically feasible, and is achievable
over long periods (e.g., a year) for the reasons summarized here and
detailed in the following subsections of this preamble. This
determination is based, in part, on the demonstration of the technology
at existing coal-fired steam generating units, including the
commercial-scale installation at Boundary Dam Unit 3. The application
of CCS at Boundary Dam follows decades of development of CO2
capture for coal-fired steam generating units, as well as numerous
smaller-scale demonstrations that have successfully implemented this
technology. Review of the available information has also identified
specific, currently available, minor technological improvements that
can be applied today to better the performance of new capture plant
retrofits, and which can assure that the capture plants achieve 90
percent capture. The EPA's determination that 90 percent capture of
CO2 is adequately demonstrated is further corroborated by
EPAct05-assisted projects, including the Petra Nova project.
Moreover, several CCS retrofit projects on coal-fired steam
generating units are in progress that apply the lessons from the prior
projects and use solvents that achieve higher capture rates. Technology
providers that supply those solvents and the associated process
technologies have made statements concluding that the technology is
commercially proven and available today and have further stated that
those solvents achieve capture rates of 95 percent or greater.
Technology providers have decades of experience and have done the work
to responsibly scale up the technology over that time across a range of
flue gas compositions. Taking all of those factors into consideration,
and accounting for the operation and flue gas conditions of the
affected sources, solvent-based capture will consistently achieve
capture rates of 90 percent or greater for the fleet of long-term coal-
fired steam generating units.
Various technologies may be used to capture CO2, the
details of which are described generally in section IV.C.1 of this
preamble and in more detail in the final TSD, GHG Mitigation Measures
for Steam Generating Units, which is
[[Page 39848]]
available in the rulemaking docket.\288\ For post-combustion capture,
these technologies include solvent-based methods (e.g., amines, chilled
ammonia), solid sorbent-based methods, membrane filtration, pressure-
swing adsorption, and cryogenic methods.\289\ Lastly, oxy-combustion
uses a purified oxygen stream from an air separation unit (often
diluted with recycled CO2 to control the flame temperature)
to combust the fuel and produce a higher concentration of
CO2 in the flue gas, as opposed to combustion with oxygen in
air which contains 80 percent nitrogen. The CO2 can then be
separated by the aforementioned CO2 capture methods. Of the
available capture technologies, solvent-based processes have been the
most widely demonstrated at commercial scale for post-combustion
capture and are applicable to use with either combustion turbines or
steam generating units.
---------------------------------------------------------------------------
\288\ Technologies to capture CO2 are also discussed
in the final TSD, GHG Mitigation Measures--Carbon Capture and
Storage for Combustion Turbines.
\289\ For pre-combustion capture (as is applicable to an IGCC
unit), syngas produced by gasification passes through a water-gas
shift catalyst to produce a gas stream with a higher concentration
of hydrogen and CO2. The higher CO2
concentration relative to conventional combustion flue gas reduces
the demands (power, heating, and cooling) of the subsequent
CO2 capture process (e.g., solid sorbent-based or
solvent-based capture); the treated hydrogen can then be combusted
in the unit.
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The EPA's identification of CCS with 90 percent capture as the BSER
is premised, in part, on an amine solvent-based CO2 system.
Amine solvents used for carbon capture are typically proprietary,
although non-proprietary solvents (e.g., monoethanolamine, MEA) may be
used. Carbon capture occurs by reactive absorption of the
CO2 from the flue gas into the amine solution in an
absorption column. The amine reacts with the CO2 but will
also react with impurities in the flue gas, including SO2.
PM will also affect the capture system. Adequate removal of
SO2 and PM prior to the CO2 capture system is
therefore necessary. After pretreatment of the flue gas with
conventional SO2 and PM controls, the flue gas goes through
a quencher to cool the flue gas and remove further impurities before
the CO2 absorption column. After absorption, the
CO2-rich amine solution passes to the solvent regeneration
column, while the treated gas passes through a water and/or acid wash
column to limit emission of amines or other byproducts. In the solvent
regeneration column, the solution is heated (using steam) to release
the absorbed CO2. The released CO2 is then
compressed and transported offsite, usually by pipeline. The amine
solution from the regenerating column is then cooled, a portion of the
lean solvent is treated in a solvent reclaiming process to mitigate
degradation of the solvent, and the lean solvent streams are recombined
and sent back to the absorption column.
(1) Capture Demonstrations at Coal-Fired Steam Generating Units
(a) SaskPower's Boundary Dam Unit 3
SaskPower's Boundary Dam Unit 3, a 110 MW lignite-fired unit in
Saskatchewan, Canada, was designed to achieve CO2 capture
rates of 90 percent using an amine-based post-combustion capture system
retrofitted to the existing steam generating unit. The capture plant,
which began operation in 2014, is the first full-scale CO2
capture system retrofit on an existing coal-fired power plant. It uses
the amine-based Shell CANSOLV[supreg] process, which includes an amine-
based SO2 scrubbing process and a separate amine-based
CO2 capture process, with integrated heat and power from the
steam generating unit.\290\
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\290\ Giannaris, S., et al. Proceedings of the 15th
International Conference on Greenhouse Gas Control Technologies
(March 15-18, 2021). SaskPower's Boundary Dam Unit 3 Carbon Capture
Facility--The Journey to Achieving Reliability. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191.
---------------------------------------------------------------------------
After undergoing maintenance and design improvements in September
and October of 2015 to address technical and mechanical challenges
faced in its first year of operation, Boundary Dam Unit 3 completed a
72-hour test of its design capture rate (3,240 metric tons/day), and
captured 9,695 metric tons of CO2 or 99.7 percent of the
design capacity (approximately 89.7 percent capture) with a peak rate
of 3,341 metric tons/day.\291\ However, the capture plant has not
consistently operated at this total capture efficiency. In general, the
capture plant ran less than 100 percent of the flue gas through the
capture equipment and the coal-fired steam generating unit also
operates when the capture plant is offline for maintenance. As a
result, although the capture plant has consistently achieved 90 percent
capture rates of the CO2 in the processed slipstream, the
amount of CO2 captured was less than 90 percent of the total
amount of CO2 in the flue gas of the steam generating unit.
Some of the reasons for this operation were due to the economic
incentives and regulatory requirements of the project, while other
reasons were due to technical challenges. The EPA has reviewed the
record of CO2 capture at Boundary Dam Unit 3. While Boundary
Dam is in Canada and therefore not subject to this action, these
technical challenges have been sufficiently overcome or are actively
mitigated so that Boundary Dam has more recently been capable of
achieving capture rates of 83 percent when the capture plant is
online.\292\ Furthermore, the improvements already employed and
identified at Boundary Dam can be readily applied during the initial
construction of a new CO2 capture plant today.
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\291\ SaskPower Annual Report (2015-16). https://
www.saskpower.com/about-us/Our-Company/~/
link.aspx?_id=29E795C8C20D48398EAB5E3273C256AD&_z=z.
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The CO2 captured at Boundary Dam is mostly used for EOR
and CO2 is also stored geologically in a deep saline
reservoir at the Aquistore site.\293\ The amount of flue gas captured
is based in part on economic reasons (i.e., to meet related contract
requirements). The incentives for CO2 capture at Boundary
Dam beyond revenue from EOR have been limited to date, and there have
been limited regulatory requirements for CO2 capture at the
facility. As a result, a portion (about 25 percent on average) of the
flue gas bypasses the capture plant and is emitted untreated. However,
because of increasing requirements to capture CO2 in Canada,
Boundary Dam Unit 3 has more recently pursued further process
optimization.
---------------------------------------------------------------------------
\293\ Aquistore. https://ptrc.ca/aquistore.
---------------------------------------------------------------------------
Total capture efficiencies at the plant have also been affected by
technical issues, particularly with the SO2 removal system
that is upstream of the CO2 capture system. Operation of the
SO2 removal system affects downstream CO2 capture
and the amount of flue gas that can be processed. Specifically, fly ash
(PM) in the flue gas at Boundary Dam Unit 3 contributed to fouling of
SO2 system components, particularly in the SO2
reboiler and the demisters of the SO2 absorber column.
Buildup of scale in the SO2 reboiler limited heat transfer
and regeneration of the SO2 scrubbing amine, and high
pressure drop affected the flowrate of the SO2 lean-solvent
back to the SO2 absorber. Likewise, fouling of the demisters
in the SO2 absorber column caused high pressure drop and
restricted the flow of flue gas through the system, limiting the amount
of flue gas that could be processed by the downstream CO2
capture system. To address these technical issues, additional wash
systems were added, including ``demister wash systems, a pre-scrubber
flue gas inlet curtain spray wash system, flue gas cooler throat
sprays, and a booster fan wash system.'' \294\
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\294\ Id.
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[[Page 39849]]
Such issues will definitively not occur in a different type of
SO2 removal system (e.g., wet lime scrubber flue gas
desulfurization, wet-FGD). SO2 scrubbers have been
successfully operated for decades across a large number of U.S. coal-
fired sources. Of the coal-fired sources with planned operation after
2039, 60 percent have wet FGD and 23 percent have a dry FGD. In section
VII.C.1.a.ii of this preamble, the EPA accounts for the cost of adding
a wet-FGD for those sources that do not have an FGD.
To further mitigate fouling due to fly ash, the PM controls
(electrostatic precipitators) at Boundary Dam Unit 3 were upgraded in
2015/2016 by adding switch integrated rectifiers. Of the coal-fired
sources with planned operation after 2039, 31 percent have baghouses
and 67 percent have electrostatic precipitators. Sources with baghouses
have greater or more consistent degrees of emission control, and wet
FGD also provides additional PM control.
Fouling at Boundary Dam Unit 3 also affected the heat exchangers in
both the SO2 removal system and the CO2 capture
system. Additional redundancies and isolations to those key components
were added in 2017 to allow for online maintenance. Damage to the
capture plant's CO2 compressor resulted in an unplanned
outage in 2021, and the issue was corrected.\295\ The facility reported
98.3 percent capture system availability in the third quarter of
2023.\296\
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\295\ S&P Global Market Intelligence (January 6, 2022). Only
still-operating carbon capture project battled technical issues in
2021. https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/only-still-operating-carbon-capture-project-battled-technical-issues-in-2021-68302671.
\296\ SaskPower (October 18, 2022). BD3 Status Update: Q3 2023.
https://www.saskpower.com/about-us/Our-Company/Blog/2023/BD3-Status-Update-Q3-2023.
---------------------------------------------------------------------------
Regular maintenance further mitigates fouling in the SO2
and CO2 absorbers, and other challenges (e.g., foaming,
biological fouling) typical of gas-liquid absorbers can be mitigated by
standard procedures. According to the 2022 paper co-authored by the
International CCS Knowledge Centre and SaskPower, ``[a] number of
initiatives are ongoing or planned with the goal of eliminating flue
gas bypass as follows: Since 2016, online cleaning of demisters has
been effective at controlling demister pressure; Chemical cleans and
replacement of fouled packing in the absorber towers to reduce pressure
losses; Optimization of antifoam injection and other aspects of amine
health, to minimize foaming potential; [and] Optimization of Liquid-to-
Gas (L/G) ratio in the absorber and other process parameters,'' as well
as other optimization procedures.\297\ While foaming is mitigated by an
antifoam injection regimen, the EPA further notes that the extent of
foaming that could occur may be specific to the chemistry of the
solvent and the source's flue gas conditions--foaming was not reported
for MHI's KS-1 solvent when treating bituminous coal post-combustion
flue gas at Petra Nova. Lastly, while biological fouling in the
CO2 absorber wash water and the SO2 absorber
caustic polisher has been observed, ``the current mitigation plan is to
perform chemical shocking to remove this particular buildup.'' \298\
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\297\ Jacobs, B., et al. Proceedings of the 16th International
Conference on Greenhouse Gas Control Technologies (October 2022).
Reducing the CO2 Emission Intensity of Boundary Dam Unit 3 Through
Optimization of Operating Parameters of the Power Plant and Carbon
Capture Facilities. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4286430.
\298\ Pradoo, P., et al. Proceedings of the 16th International
Conference on Greenhouse Gas Control Technologies (October 2022).
Improving the Operating Availability of the Boundary Dam Unit 3
Carbon Capture Facility. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4286503.
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Based on the experiences of Boundary Dam Unit 3, key improvements
can be implemented in future CCS deployments during initial design and
construction. Improvements to PM and SO2 controls can be
made prior to operation of the CO2 capture system. Where fly
ash is present in the flue gas, wash systems can be installed to limit
associated fouling. Additional redundancies and isolations of key heat-
exchangers can be made to allow for in-line cleaning during operation.
Redundancy of key equipment (e.g., utilizing two CO2
compressor trains instead of one) will further improve operational
availability. A feasibility study for the Shand power plant, which is
also operated by SaskPower, includes many such design improvements, at
an overall cost that was less than the cost for Boundary Dam.\299\
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\299\ International CCS Knowledge Centre. The Shand CCS
Feasibility Study Public Report. https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
---------------------------------------------------------------------------
(b) Other Coal-Fired Demonstrations
Several other projects have successfully demonstrated the capture
component of CCS at electricity generating plants and other industrial
facilities, some of which were previously noted in the discussion in
the 2015 NSPS.\300\ Since 1978, an amine-based system has been used to
capture approximately 270,000 metric tons of CO2 per year
from the flue gas of the bituminous coal-fired steam generating units
at the 63 MW Argus Cogeneration Plant (Trona, California).\301\ Amine-
based carbon capture has further been demonstrated at AES's Warrior Run
(Cumberland, Maryland) and Shady Point (Panama, Oklahoma) coal-fired
power plants, with the captured CO2 being sold for use in
the food processing industry.\302\ At the 180 MW bituminous coal-fired
Warrior Run plant, approximately 10 percent of the plant's
CO2 emissions (about 110,000 metric tons of CO2
per year) has been captured since 2000 and sold to the food and
beverage industry. AES's 320 MW Shady Point plant fires subbituminous
and bituminous coal, and captured CO2 from an approximate 5
percent slipstream (about 66,000 metric tons of CO2 per
year) from 2001 through around 2019.\303\ These facilities, which have
operated for multiple years, clearly show the technical feasibility of
post-combustion carbon capture.
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\300\ 80 FR 64548-54 (October 23, 2015).
\301\ Dooley, J.J., et al. (2009). ``An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009.'' U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.
\302\ Dooley, J.J., et al. (2009). ``An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009.'' U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.
\303\ Shady Point Plant (River Valley) was sold to Oklahoma Gas
and Electric in 2019. https://www.oklahoman.com/story/business/columns/2019/05/23/oklahoma-gas-and-electric-acquires-aes-shady-point-after-federal-approval/60454346007/.
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(2) EPAct05-Assisted CO2 Capture Projects at Coal-Fired
Steam Generating Units \304\
---------------------------------------------------------------------------
\304\ In the 2015 NSPS, the EPA provided a legal interpretation
of the constraints on how the EPA could rely on EPAct05-assisted
projects in determining whether technology is adequately
demonstrated for the purposes of CAA section 111. Under that legal
interpretation, ``these provisions [in the EPAct05] . . . preclude
the EPA from relying solely on the experience of facilities that
received [EPAct05] assistance, but [do] not . . . preclude the EPA
from relying on the experience of such facilities in conjunction
with other information.'' As part of the rulemaking action here, the
EPA incorporates the legal interpretation and discussion of these
EPAct05 provisions with respect the appropriateness of considering
facilities that received EPAct05 assistance in determining whether
CCS is adequately demonstrated, as found in the 2015 NSPS, 80 FR
64509, 64541-43 (October 23, 2015), and the supporting response to
comments, EPA-HQ-OAR-2013-0495-11861 at pgs.113-134.
---------------------------------------------------------------------------
(a) Petra Nova
Petra Nova is a 240 MW-equivalent capture facility that is the
first at-scale application of carbon capture at a coal-fired power
plant in the U.S. The system is located at the subbituminous coal-
[[Page 39850]]
fired W.A. Parish Generating Station in Thompsons, Texas, and began
operation in 2017, successfully capturing and sequestering
CO2 for several years. The system was put into reserve
shutdown (i.e., idled) in May 2020, citing the poor economics of
utilizing captured CO2 for EOR at that time. On September
13, 2023, JX Nippon announced that the carbon capture facility at Petra
Nova had been restarted.\305\ A final report from the National Energy
Technology Laboratory (NETL) details the success of the project and
what was learned from this first-of-a-kind demonstration at scale.\306\
The project used Mitsubishi Heavy Industry's proprietary KM-CDR
Process[supreg], a process that is similar to an amine-based solvent
process but that uses a proprietary solvent. During its operation, the
project successfully captured 92.4 percent of the CO2 from
the slip stream of flue gas processed with 99.08 percent of the
captured CO2 sequestered by EOR.
---------------------------------------------------------------------------
\305\ JX Nippon Oil & Gas Exploration Corporation. Restart of
the large-scale Petra Nova Carbon Capture Facility in the U.S.
(September 2023). https://www.nex.jx-group.co.jp/english/newsrelease/upload_files/20230913EN.pdf.
\306\ W.A. Parish Post-Combustion CO2 Capture and
Sequestration Demonstration Project, Final Scientific/Technical
Report (March 2020). https://www.osti.gov/servlets/purl/1608572.
---------------------------------------------------------------------------
The amount of flue gas treated at Petra Nova was consistent with a
240 MW size coal-fired steam EGU. The properties of the flue gas--
composition, temperature, pressure, density, flowrate, etc.--are the
same as would occur for a similarly sized coal-firing unit. Therefore,
Petra Nova corroborates that the capture equipment--including the
CO2 absorption column, solvent regeneration column, balance
of plant equipment, and the solvent itself--work at commercial scale
and can achieve capture rates of 90 percent.
The Petra Nova project did experience periodic outages that were
unrelated to the CO2 capture facility and do not implicate
the basis for the EPA's BSER determination.\307\ These include outages
at either the coal-fired steam generating unit (W.A. Parish Unit 8) or
the auxiliary combined cycle facility, extreme weather events
(Hurricane Harvey), and the operation of the EOR site and downstream
oil recovery and processing. Outages at the coal-fired steam generating
unit itself do not compromise the reliability of the CO2
capture plant or the plant's ability to achieve a standard of
performance based on CCS, as there would be no CO2 to
capture. Outages at the auxiliary combined cycle facility are also not
relevant to the EPA's BSER determination, because the final BSER is not
premised on the CO2 capture plant using an auxiliary
combined cycle plant for steam and power. Rather, the final BSER
assumes the steam and power come directly from the associated steam
generating unit. Extreme weather events can affect the operation of any
facility. Furthermore, the BSER is not premised on EOR, and it is not
dependent on downstream oil recovery or processing. Outages
attributable to the CO2 capture facility were 41 days in
2017, 34 days in 2018, and 29 days in 2019--outages decreased year-on-
year and were on average less than 10 percent of the year. Planned and
unplanned outages are normal for industrial processes, including steam
generating units.
---------------------------------------------------------------------------
\307\ Id.
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Petra Nova experienced some technical challenges that were
addressed during its first 3 years of operation.\308\ One of these
issues was leaks from heat exchangers due to the properties of the
gasket materials--replacement of the gaskets addressed the issue.
Another issue was vibration of the flue gas blower due to build-up of
slurry and solids carryover. W.A. Parish Unit 8 uses a wet limestone
FGD scrubber to remove SO2, and the flue gas connection to
the capture plant is located at the bottom of the duct running from the
wet-FGD to the original stack. A diversion wall and collection drains
were installed to mitigate solids and slurry carryover. Regular
maintenance is required to clean affected components and reduce the
amount of slurry carryover to the quencher. Solids and slurry carryover
also resulted in calcium scale buildup on the flue gas blower. Although
calcium concentrations were observed to increase in the solvent,
impacts of calcium on the quencher and capture plant chemistry were not
observed. Some scaling may have been occurring in the cooling section
of the quencher and would have been addressed during a planned outage
in 2020. Another issue encountered was scaling related to the
CO2 compressor intercoolers, compressor dehydration system,
and an associated heat exchanger. The issue was determined to be due to
a material incompatibility of the CO2 compressor
intercooler, and the components were replaced during a 2018 planned
outage. To mitigate the scaling prior to the replacement of those
components, the compressor drain was also rerouted to the reclaimer and
a backup filtering system was also installed and used, both of which
proved to be effective. Some decrease in performance was also observed
in heat exchangers. The presence of cooling tower fill (a solid medium
used to increase surface area in cooling towers) in the cooling water
system exchangers may have impacted performance. It is also possible
that there could have been some fouling in heat exchangers. Fill was
planned to be removed and fouling checked for during regular
maintenance. Petra Nova did not observe fouling of the CO2
absorber packing or high pressure drops across the CO2
absorber bed, and Petra Nova also did not report any foaming of the
solvent. Even with the challenges that were faced, Petra Nova was never
restricted in reaching its maximum capture rate of 5,200 tons of
CO2 per day, a scale that was substantially greater than
Boundary Dam Unit 3 (approximately 3,600 tons of CO2 per
day).
---------------------------------------------------------------------------
\308\ Id.
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(b) Plant Barry
Plant Barry, a bituminous coal-fired steam generating unit in
Mobile, Alabama, began using the KM-CDR Process[supreg] in 2011 for a
fully integrated 25 MWe CCS project with a capture rate of 90
percent.\309\ The CCS project at Plant Barry captured approximately
165,000 tons of CO2 annually, which was then transported via
pipeline and sequestered underground in geologic formations.\310\
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\309\ U.S. Department of Energy (DOE). National Energy
Technology Laboratory (NETL). https://www.netl.doe.gov/node/1741.
\310\ 80 FR 64552 (October 23, 2015).
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(c) Project Tundra
Project Tundra is a carbon capture project in North Dakota at the
Milton R. Young Station lignite coal-fired power plant. Project Tundra
will capture up to 4 million metric tons of CO2 per year for
permanent geologic storage. One planned storage site is collocated with
the power plant and is already fully permitted, while permitting for a
second nearby storage site is in progress.\311\ An air permit for the
capture facility has also been issued by North Dakota Department of
Environmental Quality. The project is designed to capture
CO2 at a rate of about 95 percent of the treated flue
gas.\312\ The capture plant will treat the flue gas from the 455 MW
Unit 2 and additional flue gas from the 250 MW Unit 1, and will treat
an equivalent capacity of 530 MW.\313\ The project began a final FEED
study in February 2023 with planned completion
[[Page 39851]]
in April 2024,\314\ and, prior to selection by DOE for funding award
negotiation, the project was scheduled to begin construction in
2024.\315\ The project will use MHI's KS-21 solvent and the Advanced
KM-CDR process. The MHI solvent KS-1 and an advanced MHI solvent
(likely KS-21) were previously tested on the lignite post-combustion
flue gas from the Milton R. Young Station.\316\ To provide additional
conditioning of the flue gas, the project is utilizing a wet
electrostatic precipitator (WESP). A draft Environmental Assessment
summarizing the project and potential environmental impacts was
released by DOE.\317\ Finally, Project Tundra was selected for award
negotiation for funding from DOE.\318\
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\311\ Project Tundra--Progress, Minnkota Power Cooperative,
2023. https://www.projecttundrand.com.
\312\ See Document ID No. EPA-HQ-OAR-2023-0072-0632.
\313\ Id.
\314\ ``An Overview of Minnkota's Carbon Capture Initiative--
Project Tundra,'' 2023 LEC Annual Meeting, October 5, 2023.
\315\ Project Tundra--Progress, Minnkota Power Cooperative,
2023. https://www.projecttundrand.com.
\316\ Laum, Jason. Subtask 2.4--Overcoming Barriers to the
Implementation of Postcombustion Carbon Capture. https://www.osti.gov/biblio/1580659.
\317\ DOE-EA-2197 Draft Environmental Assessment, August 17,
2023. https://www.energy.gov/nepa/listings/doeea-2197-documents-available-download.
\318\ Carbon Capture Demonstration Projects Selections for Award
Negotiations. https://www.energy.gov/oced/carbon-capture-demonstration-projects-selections-award-negotiations.
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That this project has funding through the Bipartisan Infrastructure
Law, and that this funding is facilitated through DOE's Office of Clean
Energy Demonstration's (OCED) Carbon Capture Demonstration Projects
Program, does not detract from the adequate demonstration of CCS.
Rather, the goal of that program is, ``to accelerate the implementation
of integrated carbon capture and storage technologies and catalyze
significant follow-on investments from the private sector to mitigate
carbon emissions sources in industries across America.'' \319\ For the
commercial scale projects, the stated requirement of the funding
opportunity announcement (FOA) is not that projects demonstrate CCS in
general, but that they ``demonstrate significant improvements in the
efficiency, effectiveness, cost, operational and environmental
performance of existing carbon capture technologies.'' \320\ This
implies that the basic technology already exists and is already
demonstrated. The FOA further notes that the technologies used by the
projects receiving funding should be proven such that, ``the
technologies funded can be readily replicated and deployed into
commercial practice.'' \321\ The EPA also notes that this and other on-
going projects were announced well in advance of the FOA. Considering
these factors, Project Tundra and other similarly funded projects are
supportive of the determination that CCS is adequately demonstrated.
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\319\ DOE. https://www.energy.gov/oced/carbon-capture-demonstration-projects-program-front-end-engineering-design-feed-studies.
\320\ DE-FOA-0002962. https://oced-exchange.energy.gov/FileContent.aspx?FileID=86c47d5d-835c-4343-86e8-2ba27d9dc119.
\321\ Id.
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(d) Project Diamond Vault
Project Diamond Vault will capture up to 95 percent of
CO2 emissions from the 600 MW Madison Unit 3 at Brame Energy
Center in Lena, Louisiana. Madison Unit 3 fires approximately 70
percent petroleum coke and 30 percent bituminous (Illinois Basin) coal
in a circulating fluidized bed. The FEED study for the project is
targeted for completion on September 9, 2024.322 323
Construction is planned to begin by the end of 2025 with commercial
operation starting in 2028.\324\ From the utility: ``Government
Inflation Reduction Act (IRA) funding through 45Q tax credits makes the
project financially viable. With these government tax credits, the
company does not expect a rate increase as a result of this project.''
\325\
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\322\ Diamond Vault Carbon Capture FEED Study. https://netl.doe.gov/sites/default/files/netl-file/23CM_PSCC31_Bordelon.pdf.
\323\ Note that while the FEED study is EPAct05-assisted, the
capture plant is not.
\324\ Project Diamond Vault Overview. https://www.cleco.com/docs/default-source/diamond-vault/project_diamond_vault_overview.pdf.
\325\ Id.
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(e) Other Projects
Other projects have completed or are in the process of completing
feasibility work or FEED studies, or are taking other steps towards
installing CCS on coal-fired steam generating units. These projects are
summarized in the final TSD, GHG Mitigation Measures for Steam
Generating Units, available in the docket. In general, these projects
target capture rates of 90 percent or above and provide evidence that
sources are actively pursuing the installation of CCS.
(3) CO2 Capture Technology Vendor Statements
CO2 capture technology providers have issued statements
supportive of the application of systems and solvents for
CO2 capture at fossil fuel-fired EGUs. These statements
speak to the decades of experience that technology providers have and
as noted below, vendors attest, and offer guarantees that 90 percent
capture rates are achievable. Generally, while there are many
CO2 capture methods available, solvent-based CO2
capture from post-combustion flue gas is particularly applicable to
fossil fuel-fired EGUs. Solvent-based CO2 capture systems
are commercially available from technology providers including Shell,
Mitsubishi Heavy Industries (MHI), Linde/BASF, Fluor and ION Clean
Energy.
Technology providers have made statements asserting extensive
experience in CO2 capture and the commercial availability of
CO2 capture technologies. Solvent-based CO2
capture was first patented in the 1930s.\326\ Since then, commercial
solvent-based capture systems have been developed that are focused on
applications to post-combustion flue gas. Several technology providers
have over 30 years of experience applying solvent-based CO2
capture to the post-combustion flue gas of fossil fuel-fired EGUs. In
general, technology providers describe the technologies for
CO2 capture from post-combustion flue gas as ``proven'' or
``commercially available'' or ``commercially proven'' or ``available
now'' and describe their experience with CO2 capture from
post-combustion flue gas as ``extensive.'' CO2 capture rates
of 90 percent or higher from post-combustion flue gas have been proven
by CO2 capture technology providers using several
commercially available solvents. Many of the available solvent
technologies have over 50,000 hours of operation, equivalent to over 5
years of operation.
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\326\ 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.
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Shell has decades of experience in CO2 capture systems.
Shell notes that ``[c]apturing and safely storing carbon is an option
that's available now.'' \327\ Shell has developed the CANSOLV[supreg]
CO2 capture system for CO2 capture from post-
combustion flue gas, a regenerable amine that the company claims has
multiple advantages including ``low parasitic energy consumption, fast
kinetics and extremely low volatility.'' \328\ Shell further notes,
``Moreover, the technology has been designed for
[[Page 39852]]
reliability through its highly flexible turn-up and turndown
capacity.'' \329\ The company has stated that ``Over 90% of the
CO2 in exhaust gases can be effectively and economically
removed through the implementation of Shell's carbon capture
technology.'' \330\ Shell also notes, ``Systems can be guaranteed for
bulk CO2 removal of over 90%.'' \331\
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\327\ Shell Global--Carbon Capture and Storage. https://www.shell.com/energy-and-innovation/carbon-capture-and-storage.html.
\328\ Shell Global--CANSOLV[supreg] CO2 Capture
System. https://www.shell.com/business-customers/catalysts-technologies/licensed-technologies/emissions-standards/tail-gas-treatment-unit/cansolv-co2.html.
\329\ Shell Catalysts & Technologies--Shell CANSOLV[supreg]
CO2 Capture System. https://catalysts.shell.com/en/Cansolv-co2-fact-sheet.
\330\ Id.
\331\ Id.
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MHI in collaboration with Kansai Electric Power Co., Inc. began
developing a solvent-based capture process (the KM CDR
ProcessTM) using the KS-1TM solvent in 1990.\332\
MHI describes the extensive experience of commercial application of the
solvent, ``KS-1TM--a solvent whose high reliability has been
confirmed by a track record of deliveries to 15 commercial plants
worldwide.'' \333\ Notable applications of KS-1TM and the
KM-CDR ProcessTM include applications at Plant Barry and
Petra Nova. Previously, MHI has achieved capture rates of greater than
90 percent over long periods and at full scale at the Petra Nova
project where the KS-1TM solvent was used.\334\ MHI has
further improved on the original process and solvent by making
available the Advanced KM CDR ProcessTM using the KS-
21TM solvent. From MHI, ``Commercialization of KS-
21TM solvent was completed following demonstration testing
in 2021 at the Technology Centre Mongstad in Norway, one of the world's
largest carbon capture demonstration facilities.'' \335\ MHI has
achieved CO2 capture rates of 95 to 98 percent using both
the KS-1TM and KS-21TM solvent at the Technology
Centre Mongstad (TCM).\336\ Higher capture rates under modified
conditions were also measured, ``In addition, in testing conducted
under modified operating conditions, the KS-21TM solvent
delivered an industry-leading carbon capture rate was 99.8% and
demonstrated the successful recovery of CO2 from flue gas of
lower concentration than the CO2 contained in the
atmosphere.'' \337\
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\332\ Mitsubishi Heavy Industries--CO2 Capture
Technology--CO2 Capture Process. https://www.mhi.com/products/engineering/co2plants_process.html.
\333\ Id.
\334\ Note: Petra Nova is an EPAct05-assisted project. W.A.
Parish Post-Combustion CO2 Capture and Sequestration
Demonstration Project, Final Scientific/Technical Report (March
2020). https://www.osti.gov/servlets/purl/1608572.
\335\ Id.
\336\ Mitsubishi Heavy Industries, ``Mitsubishi Heavy Industries
Engineering Successfully Completes Testing of New KS-21TM
Solvent for CO2 Capture,'' https://www.mhi.com/news/211019.html.
\337\ Id.
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Linde engineering in partnership with BASF has made available
BASF's OASE[supreg] blue amine solvent technology for post-combustion
CO2 capture. Linde notes their experience: ``We have
longstanding experience in the design and construction of chemical wash
processes, providing the necessary amine-based solvent systems and the
CO2 compression, drying and purification system.'' \338\
Linde also notes that ``[t]he BASF OASE[supreg] process is used
successfully in more than 400 plants worldwide to scrub natural,
synthesis and other industrial gases.'' \339\ The OASE[supreg] blue
technology has been successfully piloted at RWE Power, Niederaussem,
Germany (from 2009 through 2017; 55,000 operating hours) and the
National Center for Carbon Capture in Wilsonville, Alabama (January
2015 through January 2016; 3,200 operating hours). Based on the
demonstrated performance, Linde concludes that ``PCC plants combining
Linde's engineering skills and BASF's OASE[supreg] blue solvent
technology are now commercially available for a wide range of
applications.'' \340\ Linde and BASF have demonstrated capture rates
over 90 percent and operating availability \341\ rates of more than 97
percent during 55,000 hours of operation.
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\338\ Linde Engineering--Post Combustion Capture. https://www.linde-engineering.com/en/process-plants/co2-plants/carbon-capture/post-combustion-capture/index.html.
\339\ Linde and BASF--Carbon capture storage and utilisation.
https://www.linde-engineering.com/en/images/Carbon-capture-storage-utilisation-Linde-BASF_tcm19-462558.pdf.
\340\ Id.
\341\ Operating availability is the percent of time that the
CO2 capture equipment is available relative to its
planned operation.
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Fluor provides a solvent technology (Econamine FG Plus) and EPC
services for CO2 capture. Fluor describes their technology
as ``proven,'' noting that, ``Proven technology. Fluor Econamine FG
Plus technology is a propriety carbon capture solution with more than
30 licensed plants and more than 30 years of operation.'' \342\ Fluor
further notes, ``The technology builds on Fluor's more than 400
CO2 removal units in natural gas and synthesis gas
processing.'' \343\ Fluor further states, ``Fluor is a global leader in
CO2 capture [. . .] with long-term commercial operating
experience in CO2 recovery from flue gas.'' On the status of
Econamine FG Plus, Fluor notes that the ``[the] Technology [is]
commercially proven on natural gas, coal, and fuel oil flue gases,''
and further note that ``[o]perating experience includes using steam
reformers, gas turbines, gas engines, and coal/natural gas boilers.''
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\342\ Fluor--Comprehensive Solutions for Carbon Capture. https://www.fluor.com/client-markets/energy/production/carbon-capture.
\343\ Fluor--Econamine FG Plus\SM\. https://www.fluor.com/sitecollectiondocuments/qr/econamine-fg-plus-brochure.pdf.
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ION Clean Energy is a company focused on post-combustion carbon
capture founded in 2008. ION's ICE-21 solvent has been used at NCCC and
TCM Norway.\344\ ION has achieved capture rates of 98 percent using the
ICE-31 solvent.
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\344\ ION Clean Energy--Company. https://www.ioncleanenergy.com/company.
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(4) CCS User Statements on CCS
A number of the companies who have either completed large scale
pilot projects or who are currently developing full scale projects have
also indicated that CCS technology is currently a viable technology for
large coal-fired power plants. In 2011, announcing a decision not to
move forward with the first full scale commercial CCS installation of a
carbon capture system on a coal plant, AEP did not cite any technology
concerns, but rather indicated that ``it is impossible to gain
regulatory approval to recover our share of the costs for validating
and deploying the technology without federal requirements to reduce
greenhouse gas emissions already in place.'' \345\ Enchant Energy, a
company developing CCS for coal-fired power plants explained that its
FEED study for the San Juan Generating Station, ``shows that the
technical and business case for adding carbon capture to existing coal-
fired power plants is strong.'' \346\ Rainbow Energy, who is developing
a carbon capture project at the Coal Creek Power Station in North
Dakota explains, ``CCUS technology has been proven and is an economical
option for a facility like Coal Creek Station. We see CCUS as the best
option to manage CO2 emissions at our facility.'' \347\
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\345\ https://www.aep.com/news/releases/read/1206/AEP-Places-Carbon-Capture-Commercialization-On-Hold-Citing-Uncertain-Status-Of-Climate-Policy-Weak-Economy.
\346\ Enchant Energy. What is Carbon Capture and Sequestration
(CCS)? https://enchantenergy.com/carbon-capture-technology/.
\347\ Rainbow Energy Center. Carbon Capture. https://rainbowenergycenter.com/what-we-do/carbon-capture/.
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(5) State CCS Requirements
Several states encourage or even require sources to install CCS.
These state requirements further indicate that CCS is well-established
and effective. These state laws include the Illinois 2021 Climate and
Equitable Jobs Act, which requires privately owned coal-
[[Page 39853]]
fired units to reduce emissions to zero by 2030 and requires publicly
owned coal-fired units to reduce emissions to zero by 2045.\348\
Illinois has also imposed CCS-based CO2 emission standards
on new coal-fired power plants since 2009 when the state adopted its
Clean Coal Portfolio Standard law.\349\ The statute required an initial
capture rate of 50 percent when enacted but steadily increased the
capture rate requirement to 90 percent in 2017, where it remains.
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\348\ State of Illinois General Assembly. Public Act 102-0662:
Climate and Equitable Jobs Act. 2021. https://www.ilga.gov/legislation/publicacts/102/PDF/102-0662.pdf.
\349\ State of Illinois General Assembly. Public Act 095-1027:
Clean Coal Portfolio Standard Law. https://www.ilga.gov/legislation/publicacts/95/PDF/095-1027.pdf.
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Michigan in 2023 established a 100 percent clean energy requirement
by 2040 with a nearer term 80 percent clean energy by 2035
requirement.\350\ The statute encourages the application of CCS by
defining ``clean energy'' to include generation resources that achieve
90 percent carbon capture.
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\350\ State of Michigan Legislature. Public Act 235 of 2023.
Clean and Renewable Energy and Energy Waste Reduction Act. https://legislature.mi.gov/documents/2023-2024/publicact/pdf/2023-PA-0235.pdf.
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California identifies carbon capture and sequestration as a
necessary tool to reduce GHG emissions within its 2022 scoping plan
update \351\ and, that same year, enacted a statutory requirement
through Assembly Bill 1279 \352\ requiring the state to plan and
implement policies that enable carbon capture and storage technologies.
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\351\ California Air Resources Board, 2022 Scoping Plan for
Achieving Carbon Neutrality. https://ww2.arb.ca.gov/sites/default/files/2023-04/2022-sp.pdf.
\352\ State of California Legislature. Assembly Bill 1279
(2022). The California Climate Crisis Act. https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill_id=202120220AB1279.
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Several states in different parts of the country have adopted
strategic and planning frameworks that also encourage CCS. Louisiana,
which in 2020 set an economy-wide net-zero goal by 2050, has explored
policies that encourage CCS deployment in the power sector. The state's
2022 Climate Action Plan proposes a Renewable and Clean Portfolio
Standard requiring 100 percent renewable or clean energy by 2035.\353\
That proposal defines power plants achieving 90 percent carbon capture
as a qualifying clean energy resource that can be used to meet the
standard.
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\353\ Louisiana Climate Initiatives Task Force. Louisiana
Climate Action Plan (February 1, 2022). https://gov.louisiana.gov/assets/docs/CCI-Task-force/CAP/ClimateActionPlanFinal.pdf.
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Pennsylvania's 2021 Climate Action Plan notes that the state is
well positioned to install CCS to transition the state's electric fleet
to a zero-carbon economy.\354\ The state also established an
interagency workgroup in 2019 to identify ways to speed the deployment
of CCS.
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\354\ Pennsylvania Dept. of Environmental Protection.
Pennsylvania Climate Action Plan (2021). https://www.dep.pa.gov/Citizens/climate/Pages/PA-Climate-Action-Plan.aspx.
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The Governor of North Dakota announced in 2021 an economy-wide
carbon neutral goal by 2030.\355\ The announcement singled out the
Project Tundra Initiative, which is working to apply CCS technology to
the state's Milton R. Young Power Station.
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\355\ https://www.governor.nd.gov/news/updated-waudio-burgum-addresses-williston-basin-petroleum-conference-issues-carbon-neutral.
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The Governor of Wyoming has broadly promoted a Decarbonizing the
West initiative that includes the study of CCS technologies to reduce
carbon emissions from the region.\356\ A 2024 Wyoming law also requires
utilities in the state to install CCS technologies on a portion of
their existing coal-fired power plants by 2033.\357\
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\356\ https://westgov.org/initiatives/overview/decarbonizing-the-west.
\357\ State of Wyoming Legislature. SF0042. Low-carbon Reliable
Energy Standards-amendments. https://www.wyoleg.gov/Legislation/2024/SF0042.
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(6) Variable Load and Startups and Shutdowns
In this section of the preamble, the EPA considers the effects of
variable load and startups and shutdowns on the achievability of 90
percent capture. First, the coal-fired steam generating unit can itself
turndown \358\ to only about 40 percent of its maximum design capacity.
Due to this, coal-fired EGUs have relatively high duty cycles \359\--
that is, they do not cycle as frequently as other sources and typically
have high average loads when operating. In 2021, coal-fired steam
generating units had an average duty cycle of 70 percent, and more than
75 percent of units had duty cycles greater than 60 percent.\360\ Prior
demonstrations of CO2 capture plants on coal-fired steam
generating units have had turndown limits of approximately 60 percent
of throughput for Boundary Dam Unit 3 \361\ and about 70 percent
throughput for Petra Nova.\362\ Based on the technology currently
available, turndown to throughputs of 50 percent \363\ are achievable
for a single capture train.\364\ Considering that coal units can
typically only turndown to 40 percent, a 50 percent turndown ratio for
the CO2 capture plant is likely sufficient for most sources,
although utilizing two CO2 capture trains would allow for
turndown to as low as 25 percent of throughput. When operating at less
than maximum throughputs, the CO2 capture facility actually
achieves higher capture efficiencies, as evidenced by the data
collected at Boundary Dam Unit 3.\365\ Data from the Shand Feasibility
Report suggests that, for a solvent and design achieving 90 percent
capture at 100 percent of net load, 97.5 percent capture is achievable
at 62.5 percent of net load.\366\ Considering these factors,
CO2 capture is, in general, able to meet the variable load
of coal-fired steam generating units without any adverse impact on the
CO2 capture rate. In fact, operation at lower loads may lead
to
[[Page 39854]]
higher achievable capture rates over long periods of time.
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\358\ Here, ``turndown'' is the ability of a facility to turn
down some process value, such as flowrate, throughput or capacity.
Typically, this is expressed as a ratio relative to operation at its
maximum instantaneous capability. Because processes are designed to
operate within specific ranges, turndown is typically limited by
some lower threshold.
\359\ Here, ``duty cycle'' is the ratio of the gross amount of
electricity generated relative to the amount that could be
potentially generated if the unit operated at its nameplate capacity
during every hour of operation. Duty cycle is thereby an indication
of the amount of cycling or load following a unit experiences
(higher duty cycles indicate less cycling, i.e., more time at
nameplate capacity when operating). Duty cycle is different from
capacity factor, as the latter also quantifies the amount that the
unit spends offline.
\360\ U.S. Environmental Protection Agency (EPA). ``Power Sector
Emissions Data.'' Washington, DC: Office of Atmospheric Protection,
Clean Air Markets Division. Available from EPA's Air Markets Program
Data website: https://campd.epa.gov.
\361\ Jacobs, B., et al. Proceedings of the 16th International
Conference on Greenhouse Gas Control Technologies (March 15-18,
2021). Reducing the CO2 Emission Intensity of Boundary Dam Unit 3
Through Optimization of Operating Parameters of the Power Plant and
Carbon Capture Facilities. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4286430.
\362\ W.A. Parish Post-Combustion CO2 Capture and
Sequestration Demonstration Project, Final Scientific/Technical
Report (March 2020). https://www.osti.gov/servlets/purl/1608572.
\363\ International CCS Knowledge Centre. The Shand CCS
Feasibility Study Public Report. https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
\364\ Here, a ``train'' in this context is a series of connected
sequential process equipment. For carbon capture, a process train
can include the quencher, absorber, stripper, and compressor. Rather
than doubling the size of a single train of process equipment, a
source could use two equivalent sized trains.
\365\ Jacobs, B., et al. Proceedings of the 16th International
Conference on Greenhouse Gas Control Technologies (March 15-18,
2021). Reducing the CO2 Emission Intensity of Boundary Dam Unit 3
Through Optimization of Operating Parameters of the Power Plant and
Carbon Capture Facilities. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4286430.
\366\ International CCS Knowledge Centre. The Shand CCS
Feasibility Study Public Report. https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
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Coal-fired steam generating units also typically have few startups
and shutdowns per year, and CO2 emissions during those
periods are low. Although capacity factor has declined in recent years,
as noted in section IV.D.3 of the preamble, the number of startups per
year has been relatively stable. In 2011, coal-fired sources had about
10 startups on average. In 2021, coal-fired steam generating units had
only 12 startups on average, see the final TSD, GHG Mitigation Measures
for Steam Generating Units, available in the docket. Prior to
generation of electricity, coal-fired steam generating units use
natural gas or distillate oil--which have a lower carbon content than
coal--because of their ignition stability and low ignition temperature.
Heat input rates during startup are relatively low, to slowly raise the
temperature of the boiler. Existing natural gas- or oil-fired ignitors
designed for startup purposes are generally sized for up to 15 percent
of the maximum heat-input. Considering the low heat input rate, use of
fuel with a lower carbon content, and the relatively few startups per
year, the contribution of startup to total GHG emissions is relatively
low. Shutdowns are relatively short events, so that the contribution to
total emissions are also low. The emissions during startup and shutdown
are therefore small relative to emissions during normal operation, so
that any impact is averaged out over the course of a year.
Furthermore, the IRC section 45Q tax credit provides incentive for
units to operate more. Sources operating at higher capacity factors are
likely to have fewer startups and shutdowns and spend less time at low
loads, so that their average load would be higher. This would further
minimize the insubstantial contribution of startups and shutdowns to
total emissions. Additionally, as noted in the preceding sections of
the preamble, new solvents achieve capture rates of 95 percent at full
load, and ongoing projects are targeting capture rates of 95 percent.
Considering all of these factors, startup and shutdown, in general, do
not affect the achievability of 90 percent capture over long periods
(i.e., a year).
(7) Coal Rank
CO2 capture at coal-fired steam generating units
achieves 90 percent capture, for the reasons detailed in sections
VII.C.1.a.i(B)(1) through (6) of this preamble. Moreover, 90 percent
capture is achievable for all coal types because amine solvents have
been used to remove CO2 from a variety of flue gas
compositions including a broad range of different coal ranks,
differences in CO2 concentration are slight and the capture
process can be designed to the appropriate scale, amine solvents have
been used to capture CO2 from flue gas with much lower
CO2 concentrations, and differences in flue gas impurities
due to different coal compositions can be managed or mitigated by
controls.
As detailed in the preceding sections, CO2 capture has
been operated on flue gas from the combustion of a broad range of coal
ranks including lignite, bituminous, subbituminous, and anthracite
coals. Post-combustion CO2 capture from the flue gas of an
EGU firing lignite has been demonstrated at the Boundary Dam Unit 3 EGU
(Saskatchewan, Canada). Most lignites have a higher ash and moisture
content than other coal types and, in that respect, the flue gas can be
more challenging to manage for CO2 capture. Amine
CO2 capture has also been used to treat lignite post-
combustion flue gas in pilot studies at the Milton R. Young station
(North Dakota).\367\ CO2 capture solvents have been used to
treat subbituminous post-combustion flue gas from W.A. Parish
Generating Station (Texas),\368\ and the bituminous post-combustion
flue gas from Plant Barry (Mobile, Alabama),\369\ Warrior Run
(Maryland),\370\ and Argus Cogeneration Plant (California).\371\ Amine
solvents have also been used to remove CO2 from the flue gas
of the bituminous- and subbituminous-fired Shady Point plant.\372\
CO2 capture solvents have been used to treat anthracite
post-combustion flue gas at the Wilhelmshaven power plant
(Germany).\373\ There are also ongoing projects that will apply CCS to
the flue gas of coal-fired steam generating units. The EPA considers
these ongoing projects to be indicative of the confidence that industry
stakeholders have in CCS. These include Project Tundra at the lignite-
fired Milton R. Young station (North Dakota),\374\ Project Diamond
Vault at the petroleum coke- and subbituminous-fired Brame Energy
Center Madison Unit 3 (Louisiana) \375\ and two units at the Jim
Bridger Plant (Wyoming).\376\
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\367\ Laum, Jason. Subtask 2.4--Overcoming Barriers to the
Implementation of Postcombustion Carbon Capture. https://www.osti.gov/biblio/1580659.
\368\ W.A. Parish Post-Combustion CO2 Capture and
Sequestration Demonstration Project, Final Scientific/Technical
Report (March 2020). https://www.osti.gov/servlets/purl/1608572.
\369\ U.S. Department of Energy (DOE). National Energy
Technology Laboratory (NETL). https://www.netl.doe.gov/node/1741.
\370\ Dooley, J.J., et al. (2009). ``An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009.'' U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.
\371\ Id.
\372\ Id.
\373\ Reddy, et al. Energy Procedia, 37 (2013) 6216-6225.
\374\ Project Tundra--Progress, Minnkota Power Cooperative,
2023. https://www.projecttundrand.com.
\375\ Project Diamond Vault Overview. https://www.cleco.com/docs/default-source/diamond-vault/project_diamond_vault_overview.pdf.
\376\ 2023 Integrated Resource Plan Update, PacifiCorp, April 1,
2024, https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2023_IRP_Update.pdf.
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Different coal ranks have different carbon contents, affecting the
concentration of CO2 in flue gas. In general, however,
CO2 concentration of coal combustion flue gas varies only
between 13 and 15 percent. Differences in CO2 concentration
can be accounted for by appropriately designing the capture equipment,
including sizing the absorber columns. As detailed in section
VIII.F.4.c.iv of the preamble, CO2 has been captured from
the post-combustion flue gas of NGCCs, which typically have a
CO2 concentration of 4 percent.
Prior to emission controls and pre-conditioning, characteristics of
different coal ranks and boiler design result in other differences in
the flue gas composition, including in the concentration of
SO2, NOX, PM, and trace impurities. Such
impurities in the flue gas can react with the solvent or cause fouling
of downstream processes. However, in general, most existing coal-fired
steam generating units in the U.S. have controls that are necessary for
the pre-conditioning of flue gas prior to the CO2 capture
plant, including PM and SO2 controls. For those sources
without an FGD for SO2 control, the EPA included the costs
of adding an FGD in its cost analysis. Other marginal differences in
flue gas impurities can be managed by appropriately designing the
polishing column (direct contact cooler) for the individual source's
flue gas. Trace impurities can be mitigated using conventional controls
in the solvent reclaiming process (e.g., an activated carbon bed).
Considering the broad range of coal post-combustion flue gases
amine solvents have been operated with, that solvents capture
CO2 from flue gases with lower CO2
concentrations, that the capture process can be designed for different
CO2 concentrations, and that flue gas impurities that may
differ by coal rank can be managed by controls, the EPA therefore
concludes that 90 percent capture is achievable across all coal ranks,
including waste coal.
[[Page 39855]]
(8) Natural Gas-Fired Combustion Turbines
Additional information supporting the EPA's determination that 90
percent capture of CO2 from steam generating units is
adequately demonstrated is the experience from CO2 capture
from natural gas-fired combustion turbines. The EPA describes this
information in section VIII.F.4.c.iv(B)(1), including explaining how
information about CO2 capture from coal-fired steam
generating units also applies to natural gas-fired combustion turbines.
The reverse is true as well; information about CO2 capture
from natural gas-fired turbines can be applied to coal fired-units, for
much the same reasons.
(9) Summary of Evidence Supporting BSER Determination Without EPAct05-
Assisted Projects
As noted above, under the EPA's interpretation of the EPAct05
provisions, the EPA may not rely on capture projects that received
assistance under EPAct05 as the sole basis for a determination of
adequate demonstration, but the EPA may rely on those projects to
support or corroborate other information that supports such a
determination. The information described above that supports the EPA's
determination that 90 percent CO2 capture from coal-fired
steam generating units is adequately demonstrated, without
consideration of the EPAct05-assisted projects, includes (i) the
information concerning Boundary Dam, coupled with engineering analysis
concerning key improvements that can be implemented in future CCS
deployments during initial design and construction (i.e., all the
information in section VII.C.1.a.i.(B)(1)(a) and the information
concerning Boundary Dam in section VII.C.1.a.i.(B)(1)(b)); (ii) the
information concerning other coal-fired demonstrations, including the
Argus Cogeneration Plant and AES's Warrior Run (i.e., all the
information concerning those sources in section VII.C.1.a.i.(B)(1)(a));
(iii) the information concerning industrial applications of CCS (i.e.,
all the information in section VII.C.1.a.i.(A)(1); (iv) the information
concerning CO2 capture technology vendor statements (i.e.,
all the information in section VII.C.1.a.i.(B)(3)); (v) information
concerning carbon capture at natural gas-fired combustion turbines
other than EPAct05-assisted projects (i.e., all the information other
than information about EPAct05-assisted projects in section
VIII.F.4.c.iv.(B)(1)). All this information by itself is sufficient to
support the EPA's determination that 90 percent CO2 capture
from coal-fired steam generating units is adequately demonstrated.
Substantial additional information from EPAct05-assisted projects, as
described in section VII.C.1.a.i.(B), provides additional support and
confirms that 90 percent CO2 capture from coal-fired steam
generating units is adequately demonstrated.
(C) CO2 Transport
The EPA is finalizing its determination that CO2
transport by pipelines as a component of CCS is adequately
demonstrated. The EPA anticipates that in the coming years, a large-
scale interstate pipeline network may develop to transport
CO2. Indeed, PHMSA is currently engaged in a rulemaking to
update and strengthen its safety regulations for CO2
pipelines, which assumes that such a pipeline network will
develop.\377\ For purposes of determining the CCS BSER in this final
action, however, the EPA did not base its analysis of the availability
of CCS on the projected existence of a large-scale interstate pipeline
network. Instead, the EPA adopted a more conservative approach. The
BSER is premised on the construction of relatively short lateral
pipelines that extend from the source to the nearest geologic storage
reservoir. While the EPA anticipates that sources would likely avail
themselves of an existing interstate pipeline network if one were
constructed and that using an existing network would reduce costs, the
EPA's analysis focuses on steps that an individual source could take to
access CO2 storage independently.
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\377\ PHMSA submitted the associated Notice of Proposed
Rulemaking to the White House Office of Management and Budget on
February 1, 2024 for pre-publication review. The notice stated that
the proposed rulemaking would enhance safety regulations to
``accommodate an anticipated increase in the number of carbon
dioxide pipelines and volume of carbon dioxide transported.'' Office
of Management and Budget. https://www.reginfo.gov/public/do/eAgendaViewRule?pubId=202310&RIN=2137-AF60.
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EGUs that do not currently capture and transport CO2
will need to construct new CO2 pipelines to access
CO2 storage sites, or make arrangements with pipeline owners
and operators who can do so. Most coal-fired steam EGUs, however, are
located in relatively close proximity to deep saline formations that
have the potential to be used as long-term CO2 storage
sites.\378\ Of existing coal-fired steam generating capacity with
planned operation during or after 2039, more than 50 percent is located
less than 32 km (20 miles) from potential deep saline sequestration
sites, 73 percent is located within 50 km (31 miles), 80 percent is
located within 100 km (62 miles), and 91 percent is within 160 km (100
miles). While the EPA's analysis focuses on the geographic availability
of deep saline formations, unmineable coal seams and depleted oil and
gas reservoirs could also potentially serve as storage formations
depending on site-specific characteristics. Thus, for the majority of
sources, only relatively short pipelines would be needed for
transporting CO2 from the source to the sequestration site.
For the reasons described below, the EPA believes that both new and
existing EGUs are capable of constructing CO2 pipelines as
needed. New EGUs may also be planned to be co-located with a storage
site so that minimal transport of the CO2 is required. The
EPA has assurance that the necessary pipelines will be safe because the
safety of existing and new supercritical CO2 pipelines is
comprehensively regulated by PHMSA.\379\
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\378\ Individual saline formations would require site-specific
characterization to determine their suitability for geologic
sequestration and the potential capacity for storage.
\379\ PHMSA additionally initiated a rulemaking in 2022 to
develop and implement new measures to strengthen its safety
oversight of CO2 pipelines following investigation into a
CO2 pipeline failure in Satartia, Mississippi in 2020.
For more information, see: https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americans-carbon-dioxide-pipeline-failures.
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(1) CO2 Transport Demonstrations
The majority of CO2 transported in the United States is
moved through pipelines. CO2 pipelines have been in use
across the country for nearly 60 years. Operation of this pipeline
infrastructure for this period of time establishes that the design,
construction, and operational requirements for CO2 pipelines
have been adequately demonstrated.\380\ PHMSA reported that 8,666 km
(5,385 miles) of CO2 pipelines were in operation in 2022, a
14 percent increase in CO2 pipeline miles since 2011.\381\
This pipeline infrastructure continues to expand with a number of
anticipated projects underway.
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\380\ For additional information on CO2
transportation infrastructure project timelines, costs and other
details, please see EPA's final TSD, GHG Mitigation Measures for
Steam Generating Units.
\381\ U.S. Department of Transportation, Pipeline and Hazardous
Material Safety Administration, ``Hazardous Annual Liquid Data.''
2022. https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
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The U.S. CO2 pipeline network includes major trunkline
(i.e., large capacity) pipelines as well as shorter, smaller capacity
lateral pipelines connecting a CO2 source to a larger
trunkline or connecting a CO2 source to a nearby
CO2 end use. While CO2
[[Page 39856]]
pipelines are generally more economical, other methods of
CO2 transport may also be used in certain circumstances and
are detailed in the final TSD, GHG Mitigation Measures for Steam
Generating Units.
(a) Distance of CO2 Transport for Coal-Fired Power Plants
An important factor in the consideration of the feasibility of
CO2 transport from existing coal-fired steam generating
units to sequestration sites is the distance the CO2 must be
transported. As discussed in section VII.C.1.a.i(D), potential
sequestration formations include deep saline formations, unmineable
coal seams, and oil and gas reservoirs. Based on data from DOE/NETL
studies of storage resources, of existing coal-fired steam generating
capacity with planned operation during or after 2039, 80 percent is
within 100 km (62 miles) of potential deep saline sequestration sites,
and another 11 percent is within 160 km (100 miles).\382\ In other
words, 91 percent of this capacity is within 160 km (100 miles) of
potential deep saline sequestration sites. In gigawatts, of the 81 GW
of coal-fired steam generation capacity with planned operation during
or after 2039, only 16 GW is not within 100 km (62 miles) of a
potential saline sequestration site, and only 7 GW is not within 160 km
(100 mi). The vast majority of these units (on the order of 80 percent)
can reach these deep saline sequestration sites by building an
intrastate pipeline. This distance is consistent with the distances
referenced in studies that form the basis for transport cost estimates
for this final rule.\383\ While the EPA's analysis focuses on the
geographic availability of deep saline formations, unmineable coal
seams and depleted oil and gas reservoirs could also potentially serve
as storage formations depending on site-specific characteristics.
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\382\ Sequestration potential as it relates to distance from
existing resources is a key part of the EPA's regular power sector
modeling development, using data from DOE/NETL studies. For details,
please see chapter 6 of the IPM documentation. https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
\383\ The pipeline diameter was sized for this to be achieved
without the need for recompression stages along the pipeline length.
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Of the 9 percent of existing coal-fired steam generating capacity
with planned operation during or after 2039 that is not within 160 km
(100 miles) of a potential deep saline sequestration site, 5 percent is
within 241 km (150 miles) of potential saline sequestration sites, an
additional 3 percent is within 322 km (200 miles) of potential saline
sequestration sites, and another 1 percent is within 402 km (250 miles)
of potential sequestration sites. In total, assuming all existing coal-
fired steam generating capacity with planned operation during or after
2039 adopts CCS, the EPA analysis shows that approximately 8,000 km
(5,000 miles) of CO2 pipelines would be constructed by 2032.
This includes units located at any distance from sequestration. Note
that this value is not optimized for the least total pipeline length,
but rather represents the approximate total pipeline length that would
be required if each power plant constructed a lateral pipeline
connecting their power plant to the nearest potential saline
sequestration site.\384\
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\384\ Note that multiple coal-fired EGUs may be located at each
power plant.
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Additionally, the EPA's compliance modeling projects 3,300 miles of
CO2 pipeline buildout in the baseline and 4,700 miles of
pipeline buildout in the policy scenario. This is comparable to the
4,700 to 6,000 miles of CO2 pipeline buildout estimated by
other simulations examining similar scenarios of coal CCS
deployment.\385\ Over 5 years, this total projected CO2
pipeline capacity would amount to about 660 to 940 miles per year on
average.\386\ This projected pipeline mileage is comparable to other
types of pipelines that are regularly constructed in the United States
each year. For example, based on data collected by EIA, the total
annual mileage of natural gas pipelines constructed over the 2017-2021
period ranged from approximately 1,000 to 2,500 miles per year. The
projected annual average CO2 pipeline mileage is less than
each year in this historical natural gas pipeline range, and
significantly less than the upper end of this range.
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\385\ CO2 Pipeline Analysis for Existing Coal-Fired
Powerplants. Chen et. al. Los Alamos National Lab. 2024. https://permalink.lanl.gov/object/tr?what=info:lanl-repo/lareport/LA-UR-24-23321.
\386\ In the EPA's representative timeline, the CO2
pipeline is constructed in an 18-month period. In practice, all
CO2 pipeline construction projects would be spread over a
larger time period. In the Transport and Storage Timeline Summary,
ICF (2024), available in Docket ID EPA-HQ-OAR-2023-0072, permitting
is 1.5 years. Some CO2 pipeline construction would
therefore likely begin by the start of 2028, or even earlier
considering on-going projects. With the one-year compliance
extension for delays outside of the owner/operators control that
would provide extra time if there were challenges in building
pipelines, the construction on CO2 pipelines could occur
during 2032.
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The EPA also notes that the pipeline construction estimates
presented in this section are not additive with the natural gas co-
firing pipeline construction estimates presented below because
individual sources will not elect to utilize both compliance methods.
In other words, more pipeline buildout for one compliance method
necessarily means less pipeline buildout for the other method.
Therefore, there is no compliance scenario in which the total pipeline
construction is equal to the sum of the CCS and natural gas co-firing
pipeline estimates presented in this preamble.
While natural gas line construction may be easier in some
circumstances given the uniform federal regulation that governs those
such construction, the historical trends support the EPA's conclusion
that constructing less CO2 pipeline length over a several
year period is feasible.
(b) CO2 Pipeline Examples
PHMSA reported that 8,666 km (5,385 miles) of CO2
pipelines were in operation in 2022.\387\ Due to the unique nature of
each project, CO2 pipelines vary widely in length and
capacity. Examples of projects that have utilized CO2
pipelines include the following: Beaver Creek (76 km), Monell (52.6
km), Bairoil (258 km), Salt Creek (201 km), Sheep Mountain (656 km),
Slaughter (56 km), Cortez (808 km), Central Basin (231 km), Canyon Reef
Carriers (354 km), and Choctaw (294 km). These pipelines range in
capacity from 1.6 million tons per year to 27 million tons per year,
and transported CO2 for uses such as EOR.\388\
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\387\ U.S. Department of Transportation, Pipeline and Hazardous
Material Safety Administration, ``Hazardous Annual Liquid Data.''
2022. https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
\388\ Noothout, Paul. Et. Al. (2014). ``CO2 Pipeline
infrastructure--lessons learnt.'' https://www.sciencedirect.com/science/article/pii/S187661021402864.
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Most sources deploying CCS are anticipated to construct pipelines
that run from the source to the sequestration site. Similar
CO2 pipelines have been successfully constructed and
operated in the past. For example, a 109 km (68 mile) CO2
pipeline was constructed from a fertilizer plant in Coffeyville,
Kansas, to the North Burbank Unit, an EOR operation in Oklahoma.\389\
Chaparral Energy entered a long-term CO2 purchase and sale
agreement with a subsidiary of CVR Energy for the capture of
CO2 from CVR's nitrogen fertilizer plant in 2011.\390\ The
pipeline
[[Page 39857]]
was then constructed, and operations started in 2013.\391\ Furthermore,
a 132 km (82 mile) pipeline was constructed from the Terrell Gas
facility (formerly Val Verde) in Texas to supply CO2 for EOR
projects in the Permian Basin.\392\ Additionally, the Kemper Country
CCS project in Mississippi, was designed to capture CO2 from
an integrated gasification combined cycle power plant, and transport
CO2 via a 96 km (60 mile) pipeline to be used in EOR.\393\
Construction for this facility commenced in 2010 and was completed in
2014.\394\ Furthermore, the Citronelle Project in Alabama, which was
the largest demonstration of a fully integrated, pulverized coal-fired
CCS project in the United States as of 2016, utilized a dedicated 19 km
(12 mile) pipeline constructed by Denbury Resources in 2011 to
transport CO2 to a saline storage site.\395\
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\389\ Rassenfoss, Stephen. (2014). ``Carbon Dioxide: From
Industry to Oil Fields.'' ttps://jpt.spe.org/carbon-dioxide-industry-oil-fields.
\390\ GlobeNewswire. ``Chaparral Energy Agrees to a CO2 Purchase
and Sale Agreement with CVR Energy for Capture of CO2 for
Enhanced Oil Recovery.'' March 29, 2011. https://www.globenewswire.com/news-release/2011/03/29/443163/10562/en/Chaparral-Energy-Agrees-to-a-CO2-Purchase-and-Sale-Agreement-With-CVR-Energy-for-Capture-of-CO2-for-Enhanced-Oil-Recovery.html.
\391\ Chaparral Energy. ``A `CO2 Midstream' Overview:
EOR Carbon Management Workshop.'' December 10, 2013. https://www.co2conference.net/wp-content/uploads/2014/01/13-Chaparral-CO2-Midstream-Overview-2013.12.09new.pdf.
\392\ ``Val Verde Fact Sheet: Commercial EOR using Anthropogenic
Carbon Dioxide.'' https://sequestration.mit.edu/tools/projects/val_verde.html.
\393\ Kemper County IGCC Fact Sheet: Carbon Dioxide Capture and
Storage Project. https://sequestration.mit.edu/tools/projects/kemper.html.
\394\ Office of Fossil Energy and Carbon Management. Southern
Company--Kemper County, Mississippi. https://www.energy.gov/fecm/southern-company-kemper-county-mississippi.
\395\ Citronelle Project. National Energy Technology Laboratory.
(2018). https://www.netl.doe.gov/sites/default/files/2018-11/Citronelle-SECARB-Project.PDF.
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(c) EPAct05-Assisted CO2 Pipelines for CCS
Consistent with the EPA's legal interpretation that the Agency can
rely on experience from EPAct05 funded facilities in conjunction with
other information, this section provides additional examples of
CO2 pipelines with EPAct05 funding. CCS projects with
EPAct05 funding have built pipelines to connect the captured
CO2 source with sequestration sites, including Illinois
Industrial Carbon Capture and Storage in Illinois, Petra Nova in Texas,
and Red Trail Energy in North Dakota. The Petra Nova project, which
restarted operations in September 2023,\396\ transports CO2
via a 131 km (81 mile) pipeline to the injection site, while the
Illinois Industrial Carbon Capture project and Red Trail Energy
transport CO2 using pipelines under 8 km (5 miles)
long.397 398 399 Additionally, Project Tundra, a saline
sequestration project planned at the lignite-fired Milton R. Young
Station in North Dakota will transport CO2 via a 0.4 km
(0.25 mile) pipeline.\400\
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\396\ Jacobs, Trent. (2023). ``A New Day Begins for Shuttered
Petra Nova CCUS.'' https://jpt.spe.org/a-new-day-begins-for-shuttered-petra-nova-ccus.
\397\ Technical Review of Subpart RR MRV Plan for Petra Nova
West Ranch Unit. (2021). https://www.epa.gov/system/files/documents/2021-09/wru_decision.pdf.
\398\ Technical Review of Subpart RR MRV Plan for Archer Daniels
Midland Illinois Industrial Carbon Capture and Storage Project.
(2017). https://www.epa.gov/sites/default/files/2017-01/documents/adm_final_decision.pdf.
\399\ Red Trail Energy Subpart RR Monitoring, Reporting, and
Verification (MRV) Plan. (2022). https://www.epa.gov/system/files/documents/2022-04/rtemrvplan.pdf.
\400\ Technical Review of Subpart RR MRV Plan for Tundra SGS LLC
at the Milton R. Young Station. (2022). https://www.epa.gov/system/files/documents/2022-04/tsgsdecision.pdf.
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(d) Existing and Planned CO2 Trunklines
Although the BSER is premised on the construction of pipelines that
connect the CO2 source to the sequestration site, in
practice some sources may construct short laterals to existing
CO2 trunklines, which can reduce the number of miles of
pipeline that may need to be constructed. A map displaying both
existing and planned CO2 pipelines, overlayed on potential
geologic sequestration sites, is available in the final TSD, GHG
Mitigation Measures for Steam Generating Units. Pipelines connect
natural CO2 sources in south central Colorado, northeast New
Mexico, and Mississippi to oil fields in Texas, Oklahoma, New Mexico,
Utah, and Louisiana. The Cortez pipeline is the longest CO2
pipeline, and it traverses over 800 km (500) miles from southwest
Colorado to Denver City, Texas CO2 Hub, where it connects
with several other CO2 pipelines. Many existing
CO2 pipelines in the U.S. are located in the Permian Basin
region of west Texas and eastern New Mexico. CO2 pipelines
in Wyoming, Texas, and Louisiana also carry CO2 captured
from natural gas processing plants and refineries to EOR projects.
Additional pipelines have been constructed to meet the demand for
CO2 transportation. A 170 km (105 mile) CO2
pipeline owned by Denbury connecting oil fields in the Cedar Creek
Anticline (located along the Montana-North Dakota border) to
CO2 produced in Wyoming was completed in 2021, and a 30 km
(18 mile) pipeline also owned by Denbury connects to the same oil field
and was completed in 2022.401 402 These pipelines form a
network with existing pipelines in the region--including the Denbury
Greencore pipeline, which was completed in 2012 and is 232 miles long,
running from the Lost Cabin gas plant in Wyoming to Bell Creek Field in
Montana.\403\
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\401\ Denbury. Detailed Pipeline and Ownership Information.
(2022) https://www.denbury.com/wp-content/uploads/2022/11/DEN-Pipeline-Schedule.pdf.
\402\ AP News. Officials mark start of CO2 pipeline
used for oil recovery. (2022) https://apnews.com/article/business-texas-north-dakota-plano-25f1dbf9a924613a56827c1c83e4ba68.
\403\ Denbury. Detailed Pipeline and Ownership Information.
(2022) https://www.denbury.com/wp-content/uploads/2022/11/DEN-Pipeline-Schedule.pdf.
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In addition to the existing pipeline network, there are a number of
large CO2 trunklines that are planned or in progress, which
could further reduce the number of miles of pipeline that a source may
need to construct. Several major projects have recently been announced
to expand the CO2 pipeline network across the United States.
For example, the Summit Carbon Solutions Midwest Carbon Express project
has proposed to add more than 3,200 km (2,000) miles of dedicated
CO2 pipeline in Iowa, Nebraska, North Dakota, South Dakota,
and Minnesota. The Midwest Carbon Express is projected to begin
operations in 2026. Further, Wolf Carbon Solutions has recently
announced that it plans to refile permit applications for the Mt. Simon
Hub, which will expand the CO2 pipeline by 450 km (280
miles) in the Midwest. Tallgrass announced in 2022 a plan to convert an
existing 630 km (392 mile) natural gas pipeline to carry CO2
from an ADM ethanol production facility in Nebraska to a planned
commercial-scale CO2 sequestration hub in Wyoming aimed for
completion in 2024.\404\ Recently, as part of agreeing to a communities
benefits plan, a number of community groups have agreed that they will
support construction of the Tallgrass pipeline in Nebraska.\405\ While
the construction of larger networks of trunklines could facilitate CCS
for power plants, the BSER is not predicated on the buildout of a
trunkline network and the existence of future trunklines was not
assumed in the EPA's feasibility or costing analysis. The EPA's
analysis is conservative in that it does not presume the buildout of
trunkline networks. The development of more robust and interconnected
pipeline systems over the next several years would merely lower the
EPA's
[[Page 39858]]
cost projections and create additional CO2 transport options
for power plants that do CCS.
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\404\ Tallgrass. Tallgrass to Capture and Sequester
CO2 Emissions from ADM Corn Processing Complex in
Nebraska. (2022). https://tallgrass.com/newsroom/press-releases/tallgrass-to-capture-and-sequester-co2-emissions-from-adm-corn-processing-complex-in-nebraska.
\405\ https://boldnebraska.org/upcoming-meetings-understanding-the-new-tallgrass-carbon-pipeline-community-benefits-agreement/.
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Moreover, pipeline projects have received funding under the IIJA to
conduct front-end engineering and design (FEED) studies.\406\ Carbon
Solutions LLC received funding to conduct a FEED study for a
commercial-scale pipeline to transport CO2 in support of the
Wyoming Trails Carbon Hub as part of a statewide pipeline system that
would be capable of transporting up to 45 million metric tons of
CO2 per year from multiple sources. In addition, Howard
Midstream Energy Partners LLC received funding to conduct a FEED study
for a 965 km (600 mi) CO2 pipeline system on the Gulf Coast
that would be capable of moving at least 250 million metric tons of
CO2 annually and connecting carbon sources within 30 mi of
the trunkline.
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\406\ Office of Fossil Energy and Carbon Management. ``Project
Selections for FOA 2730: Carbon Dioxide Transport Engineering and
Design (Round 1).'' https://www.energy.gov/fecm/project-selections-foa-2730-carbon-dioxide-transport-engineering-and-design-round-1.
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Other programs were created by the IIJA to facilitate the buildout
of large pipelines to carry carbon dioxide from multiple sources. For
example, the Carbon Dioxide Transportation Infrastructure Finance and
Innovation Act (CIFIA) was incorporated into the IIJA and provided $2.1
billion to DOE to finance projects that build shared (i.e., common
carrier) transport infrastructure to move CO2 from points of
capture to conversion facilities and/or storage wells. The program
offers direct loans, loan guarantees, and ``future growth grants'' to
provide cash payments to specifically for eligible costs to build
additional capacity for potential future demand.\407\
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\407\ https://www.energy.gov/lpo/carbon-dioxide-transportation-infrastructure.
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(2) Permitting and Rights of Way
The permitting process for CO2 pipelines often involves
a number of private, local, state, tribal, and/or Federal agencies.
States and local governments are directly involved in siting and
permitting proposed CO2 pipeline projects. CO2
pipeline siting and permitting authorities, landowner rights, and
eminent domain laws are governed by the states and vary by state.
State laws determine pipeline siting and the process for developers
to acquire rights-of-way needed to build. Pipeline developers may
secure rights-of-way for proposed projects through voluntary agreements
with landowners; pipeline developers may also secure rights-of-way
through eminent domain authority, which typically accompanies siting
permits from state utility regulators with jurisdiction over
CO2 pipeline siting.\408\ The permitting process for
interstate pipelines may take longer than for intrastate pipelines.
Whereas multiple state regulatory agencies would be involved in the
permitting process for an interstate pipeline, only one primary state
regulatory agency would be involved in the permitting process for an
intrastate pipeline.
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\408\ Congressional Research Service.2022. Carbon Dioxide
Pipelines: Safety Issues, CRS Reports, June 3, 2022. https://crsreports.congress.gov/product/pdf/IN/IN11944.
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Most regulation of CO2 pipeline siting and development
is conducted at the state level, and under state specific regulatory
regimes. As the interest in CO2 pipelines has grown, states
have taken steps to facilitate pipeline siting and construction. State
level regulation related to CO2 sequestration and transport
is an very active area of legislation across states in all parts of the
country, with many states seeking to facilitate pipeline siting and
construction.\409\ Many states, including Kentucky, Michigan, Montana,
Arkansas, and Rhode Island, treat CO2 pipeline operators as
common carriers or public utilities.\410\ This is an important
classification in some jurisdictions where it may be required for
pipelines seeking to exercise eminent domain.\411\ Currently, 17 states
explicitly allow CO2 pipeline operators to exercise eminent
domain authority for acquisition of CO2 pipeline rights-of-
way, should developers not secure them through negotiation with
landowners.\412\ Some states have recognized the need for a streamlined
CO2 pipeline permitting process when there are multiple
layers of regulation and developed joint permit applications. Illinois,
Louisiana, New York, and Pennsylvania have created a joint permitting
form that allows applicants to file a single application for pipeline
projects covering both state and federal permitting requirements.\413\
Even in states without this streamlined process, pipeline developers
can pursue required state permits concurrently with federal permits,
NEPA review (as applicable), and the acquisition of rights-of-way.
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\409\ Great Plains Institute State Legislative Tracker 2023.
Carbon Management State Legislative Program Tracker. https://www.quorum.us/spreadsheet/external/fVOjsTvwyeWkIqVlNmoq/?mc_cid=915706f2bc&.
\410\ National Association of Regulatory Utility Commissioners
(NARUC). (2023). Onshore U.S. Carbon Pipeline Deployment: Siting,
Safety. and Regulation. https://pubs.naruc.org/pub/F1EECB6B-CD8A-6AD4-B05B-E7DA0F12672E.
\411\ Martin Lockman. Permitting CO2 Pipelines. Sabin Center for
Climate Change Law (2023). https://scholarship.law.columbia.edu/cgi/viewcontent.cgi?article=1208&context=sabin_climate_change.
\412\ The 17 states are: Arizona, Illinois, Indiana, Iowa,
Kentucky, Louisiana, Michigan, Mississippi, Missouri, Montana, New
Mexico, North Carolina, North Dakota, Pennsylvania, South Dakota,
Texas, and Wyoming. National Association of Regulatory Utility
Commissioners (NARUC). (2023). Onshore U.S. Carbon Pipeline
Deployment: Siting, Safety. and Regulation. https://pubs.naruc.org/pub/F1EECB6B-CD8A-6AD4-B05B-E7DA0F12672E.
\413\ Martin Lockman. Permitting CO2 Pipelines. Sabin Center for
Climate Change Law (Sept. 2023). https://scholarship.law.columbia.edu/cgi/viewcontent.cgi?article=1208&context=sabin_climate_change.
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Pipeline developers have been able to successfully secure the
necessary rights-of way for CO2 pipeline projects. For
example, Summit Carbon Solutions, which has proposed to add more than
3,200 km (2,000 mi) of dedicated CO2 pipeline in Iowa,
Nebraska, North Dakota, South Dakota, and Minnesota, has stated that as
of November 7, 2023, it had reached easement agreements with 2,100
landowners along the route.\414\ As of February 23, 2024, Summit Carbon
Solutions stated that it had acquired about 75 percent of the rights of
way needed in Iowa, about 80 percent in North Dakota, about 75 percent
in South Dakota, and about 89 percent in Minnesota. The company has
successfully navigated hurdles, such as rerouting the pipelines in
certain counties where necessary.415 416 The EPA notes that
this successful acquisition of right-of-way easements for thousands of
miles of pipeline across five states has taken place in just the three
years since the project launched in 2021.\417\ In addition, the
Citronelle Project, which was constructed in Alabama in 2011,
successfully acquired rights-of-way through 9 miles of forested and
commercial timber land and 3 miles of emergent shrub and forested
wetlands. The Citronelle Project was able to attain rights-of-way
through the habitat of an endangered species by mitigating potential
environmental
[[Page 39859]]
impacts.\418\ Even projects that require rights-of-way across multiple
ownership regimes including state, private, and federally owned land
have been successfully developed. The 170 km (105 mile) Cedar Creek
Anticline CO2 pipeline owned by Denbury required easements
for approximately 10 km (6.2 mi) to cross state school trust lands in
Montana, 27 km (17 mi) across Federal land and the remaining miles
across private lands.419 420 The pipeline was completed in
2021.\421\
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\414\ South Dakota Public Broadcasting. ``Summit reaches land
deals on more than half of CO2 pipeline route.'' (2022).
https://listen.sdpb.org/business-economics/2022-11-08/summit-reaches-land-deals-on-more-than-half-of-co2-pipeline-route.
\415\ Summit CEO: CO2 Pipeline's Time is Now. (2024). https://www.dtnpf.com/agriculture/web/ag/news/business-inputs/article/2024/02/23/summit-ceo-blank-says-company-toward.
\416\ Summit Carbon Solutions. Summit Carbon Solutions Signs 80
Percent of North Dakota Landowners. (2023). https://summitcarbonsolutions.com/summit-carbon-solutions-signs-80-percent-of-north-dakota-landowners/.
\417\ Summit Carbon Solutions. Summit Carbon Solutions Announces
Progress on Carbon Capture and Storage Project. (2022). https://summitcarbonsolutions.com/summit-carbon-solutions-announces-progress-on-carbon-capture-and-storage-project/.
\418\ SECARB. (2021). Final Project Report--SECARB Phase III,
September 2021. https://www.osti.gov/servlets/purl/1823250.
\419\ Great Falls Tribune. Texas company plans 110-mile
CO2 pipeline to enhance Montana oil recovery. (2018).
https://www.greatfallstribune.com/story/news/2018/10/09/texas-company-plans-co-2-pipeline-injection-free-montana-oil/1577657002/.
\420\ U.S. D.O.I B.L.M. Denbury-Green Pipeline-MT, LLC, Denbury
Onshore, LLC Cedar Creek Anticline CO2 Pipeline and EOR
Development Project Scoping Report. https://eplanning.blm.gov/public_projects/nepa/89883/137194/167548/BLM_Denbury_Projects_Scoping_Report_March2018.pdf.
\421\ AP News. Officials mark start of CO2 pipeline
used for oil recovery. (2022) https://apnews.com/article/business-texas-north-dakota-plano-25f1dbf9a924613a56827c1c83e4ba68.
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Federal actions (e.g., funding a CCS project) must generally comply
with NEPA, which often requires that an environmental assessment (EA)
or environmental impact statement (EIS) be conducted to consider
environmental impacts of the proposed action, including consideration
of reasonable alternatives.\422\ An EA determines whether or not a
Federal action has the potential to cause significant environmental
effects. Each Federal agency has adopted its own NEPA procedures for
the preparation of EAs.\423\ If the agency determines that the action
will not have significant environmental impacts, the agency will issue
a Finding of No Significant Impact (FONSI). Some projects may also be
``categorically excluded'' from a detailed environmental analysis when
the Federal action normally does not have a significant effect on the
human environment. Federal agencies prepare an EIS if a proposed
Federal action is determined to significantly affect the quality of the
human environment. The regulatory requirements for an EIS are more
detailed and rigorous than the requirements for an EA. The
determination of the level of NEPA review depends on the potential for
significant environmental impacts considering the whole project (e.g.,
crossings of sensitive habitats, cultural resources, wetlands, public
safety concerns). Consequently, whether a pipeline project is covered
by NEPA and the associated permitting timelines may vary depending on
site characteristics (e.g., pipeline length, whether a project crosses
a water of the U.S.) and funding source. Pipelines through Bureau of
Land Management (BLM) land, U.S. Forest Service (USFS) land, or other
Federal land would be subject to NEPA. To ensure that agencies conduct
NEPA reviews as efficiently and expeditiously as practicable, the
Fiscal Responsibility Act \424\ amendments to NEPA established
deadlines for the preparation of environmental assessments and
environmental impact statements. Environmental assessments must be
completed within 1 year and environmental impact statements must be
completed within 2 years \425\ A lead agency that determines it is not
able to meet the deadline may extend the deadline, in consultation with
the applicant, to establish a new deadline that provides only so much
additional time as is necessary to complete such environmental impact
statement or environmental assessment.\426\
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\422\ Council on Environmental Quality. (2024). CEQ NEPA
Regulations. https://ceq.doe.gov/laws-regulations/regulations.html.
\423\ Council of Environmental Quality. (2023). Agency NEPA
Implementing Procedures. https://ceq.doe.gov/laws-regulations/agency_implementing_procedures.html.
\424\ Public Law 118-5 (June 3, 2023).
\425\ NEPA Sec. 107(g)(1); 42 U.S.C. 4336a(g)(1).
\426\ NEPA sec. 107(g)(2); 42 U.S.C. 4336a(g)(2).
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As discussed above, it is anticipated that most EGUs would need
shorter, intrastate pipeline segments. For example, ADM's Decatur,
Illinois, pipeline, which spans 1.9 km (1.18 miles), was constructed
after Decatur was selected for the DOE Phase 1 research and development
grants in October 2009.\427\ Construction of the CO2
compression, dehydration, and pipeline facilities began in July 2011
and was completed in June 2013.\428\ The ADM project required only an
EA. Additionally, Air Products operates a large-scale system to capture
CO2 from two steam methane reformers located within the
Valero Refinery in Port Arthur, Texas. The recovered and purified
CO2 is delivered by pipeline for use in enhanced oil
recovery operations.\429\ This 12-mile pipeline required only an
EA.\430\ Conversely, the Petra Nova project in Texas required an EIS to
evaluate the potential environmental impacts associated with DOE's
proposed action of providing financial assistance for the project. This
EIS addressed potential impacts from both the associated 131 km (81
mile) pipeline and other aspects of the larger CCS system, including
the post-combustion CO2.\431\ For Petra Nova, a notice of
intent to issue an EIS was published on November 14, 2011, and the
record of decision was issued less than 2 years later, on May 23,
2013.\432\ Construction of the CO2 pipeline for Petra Nova
from the W.A. Parish Power Plant to the West Ranch Oilfield in Jackson
County, TX began in July 2014 and was completed in July 2016.\433\
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\427\ Massachusetts Institute of Technology. (2014). Decatur
Fact Sheet: Carbon Dioxide Capture and Storage Project. https://sequestration.mit.edu/tools/projects/decatur.html.
\428\ NETL. ``CO2 Capture from Biofuels Production and
Sequestration into the Mt. Simon Sandstone.'' Award #DE-FE0001547.
https://www.usaspending.gov/award/ASST_NON_DEFE0001547_8900.
\429\ Air Products. Carbon Capture. https://www.airproducts.com/company/innovation/carbon-capture.
\430\ Department of Energy. (2011). Final Environmental
Assessment for Air Products and Chemicals, Inc. Recovery Act:
Demonstration of CO2 Capture and Sequestration of Steam
Methane Reforming Process Gas Used for Large Scale Hydrogen
Production. https://netl.doe.gov/sites/default/files/environmental-assessments/20110622_APCI_PtA_CO2_FEA.pdf.
\431\ Department of Energy, Office of NEPA Policy and
Compliance. (2013). EIS-0473: Record of Decision. https://www.energy.gov/nepa/articles/eis-0473-record-decision.
\432\ Department of Energy. (2017). Petra Nova W.A. Parish
Project. https://www.energy.gov/fecm/petra-nova-wa-parish-project.
\433\ Kennedy, Greg. (2020). ``W.A. Parish Post Combustion
CO2 Capture and Sequestration Demonstration Project.''
Final Technical Report. https://www.osti.gov/biblio/1608572/.
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Compliance with section 7 of the Endangered Species Act related to
Federal agency consultation and biological assessment is also required
for projects on Federal lands. Specifically, the Endangered Species Act
requires consultation with the Department of Interior's Fish and
Wildlife Service and Department of Commerce's NOAA Fisheries, in order
to avoid or mitigate impacts to any threatened or endangered species
and their habitats.\434\ This agency consultation process and
biological assessment are generally conducted during preparation of the
NEPA documentation (EIS or EA) for the Federal project and generally
within the regulatory timeframes for environmental assessment or
environmental impact statement preparation. Consequently, the EPA does
not anticipate that compliance with the Endangered Species Act will
change the anticipated timeline for most projects.
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\434\ CEQ. (2021). ``Council on Environmental Quality Report to
Congress on Carbon Capture, Utilization, and Sequestration.''
https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
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The EPA notes that the Fixing America's Surface Transportation Act
(FAST Act) is also relevant to CCS projects and pipelines. Title 41 of
this Act (42 U.S.C. 4370m et seq.), referred to as ``FAST-41,'' created
a new
[[Page 39860]]
governance structure, set of procedures, and funding authorities to
improve the Federal environmental review and authorization process for
covered infrastructure projects.\435\ The Utilizing Significant
Emissions with Innovative Technologies (USE IT) Act, among other
actions, clarified that CCS projects and CO2 pipelines are
eligible for this more predictable and transparent review process.\436\
FAST-41 created the Federal Permitting Improvement Steering Council
(Permitting Council), composed of agency Deputy Secretary-level members
and chaired by an Executive Director appointed by the President. FAST-
41 establishes procedures that standardize interagency consultation and
coordination practices. FAST-41 codifies into law the use of the
Permitting Dashboard \437\ to track project timelines, including
qualifying actions that must be taken by the EPA and other Federal
agencies. Project sponsor participation in FAST-41 is voluntary.\438\
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\435\ Federal Permitting Improvement Steering Council. (2022).
FAST-41 Fact Sheet. https://www.permits.performance.gov/documentation/fast-41-fact-sheet.
\436\ Galford, Chris. USE IT carbon capture bill becomes law,
incentivizing development and deployment. (2020). https://dailyenergyinsider.com/news/28522-use-it-carbon-capture-bill-becomes-law-incentivizing-development-and-deployment/.
\437\ Permitting Dashboard Federal Infrastructure Projects.
https://permits.performance.gov/.
\438\ EPA. ``FAST-41 Coordination.'' (2023). https://www.epa.gov/sustainability/fast-41-coordination.
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Community engagement also plays a role in the safe operation and
construction of CO2 pipelines. These efforts can be
supported using the CCS Pipeline Route Planning Database that was
developed by NETL, a public resource designed to support pipeline
routing decisions and increase transportation safety.\439\ The database
includes state-specific regulations and restrictions, energy and social
justice factors, land use requirements, existing infrastructure, and
areas of potential risk. The database produces weighted values ranging
from zero to one, where zero represents acceptable areas for pipeline
placement and one represents areas that should be avoided.\440\ The
database will be a key input for the CCS Pipeline Route Planning Tool
under development by NETL.\441\ The purpose of the siting tool is to
aid pipeline routing decisions and facilitate avoidance of areas that
would pose permitting challenges.
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\439\ ``CCS Pipeline Route Planning Database V1--EDX.'' https://edx.netl.doe.gov/dataset/ccs-pipeline-route-planning-database-v1.
\440\ ``CCS Pipeline Route Planning Database V1--EDX.'' https://edx.netl.doe.gov/dataset/ccs-pipeline-route-planning-database-v1.
\441\ Department of Energy. ``CCS Pipeline Route Planning
Database V1--EDX.'' https://edx.netl.doe.gov/dataset/ccs-pipeline-route-planning-database-v1.
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In sum, the permitting process for CO2 pipelines often
involves private, local, state, tribal, and/or Federal agencies, and
permitting timelines may vary depending on site characteristics.
Projects that opt in to the FAST-41 process are eligible for a more
transparent and predictable review process. EGUs can generally proceed
to obtain permits and rights-of-way simultaneously, and the EPA
anticipates that, in total, the permitting process would only take
around 2.5 years for pipelines that only need an EA, with a possible
additional year if the project requires an EIS (see the final TSD, GHG
Mitigation Measures for Steam Generating Units for additional
information). This is consistent with the anticipated timelines for CCS
discussed in section VII.C.1.a.i(E). Furthermore, the EPA notes that
there is over 60 years of experience in the CO2 pipeline
industry designing, permitting, building and operating CO2
pipelines, and that this expertise can be applied to the CO2
pipelines that would be constructed to connect to sequestration sites
and units.
As discussed above in section VII.C.1.a.i.(C)(1)(a), the core of
the EPA's analysis of pipeline feasibility focuses on units located
within 100 km (62 miles) of potential deep saline sequestration
formations. The EPA notes that the majority (80 percent) of the coal-
fired steam generating capacity with planned operation during or after
2039 is located within 100 km (62 miles) of the nearest potential deep
saline sequestration site. For these sources, as explained, units would
be required only to build relatively short pipelines, and such buildout
would be feasible within the required timeframe. For the capacity that
is more than 100 km (62 miles) away from sequestration, building a
pipeline may become more complex. Almost all (98 percent) of this
capacity's closest sequestration site is located outside state
boundaries, and access to the nearest sequestration site would require
building an interstate pipeline and coordinating with multiple state
authorities for permitting purposes. Conversely, for capacity where the
distance to the nearest potential sequestration site is less than 100
km (62 miles), only about 19 percent would require the associated
pipeline to cross state boundaries. Therefore, the EPA believes that
distance to the nearest sequestration site is a useful proxy for
considerations related to the complexity of pipeline construction and
how long it will take to build a pipeline.
A unit that is located more than 100 km away from sequestration may
face complexities in pipeline construction, including additional
permitting hurdles, difficulties in obtaining the necessary rights of
way over such a distance, or other considerations, that may make it
unreasonable for that unit to meet the compliance schedule that is
generally reasonable for sources in the subcategory as a whole.
Pursuant to the RULOF provisions of 40 CFR 60.2a(e)-(h), if a state can
demonstrate that there is a fundamental difference between the
information relevant to a particular affected EGU and the information
the EPA considered in determining the compliance deadline for sources
in the long-term subcategory, and that this difference makes it
unreasonable for the EGU to meet the compliance deadline, a longer
compliance schedule may be warranted. The EPA does not believe that the
fact that a pipeline crosses state boundaries standing alone is
sufficient to show that an extended timeframe would be appropriate--
many such pipelines could be reasonably accomplished in the required
timeframe. Rather, it is the confluence of factors, including that a
pipeline crosses state boundaries, along with others that may make
RULOF appropriate.
(3) Security of CO2 Transport
As part of its analysis, the EPA also considered the safety of
CO2 pipelines. The safety of existing and new CO2
pipelines that transport CO2 in a supercritical state is
regulated by PHMSA. These regulations include standards related to
pipeline design, pipeline construction and testing, pipeline operations
and maintenance, operator reporting requirements, operator
qualifications, corrosion control and pipeline integrity management,
incident reporting and response, and public awareness and
communications. PHMSA has regulatory authority to conduct inspections
of supercritical CO2 pipeline operations and issue notices
to operators in the event of operator noncompliance with regulatory
requirements.\442\
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\442\ See generally 49 CFR 190-199.
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CO2 pipelines have been operating safely for more than
60 years. In the past 20 years, 500 million metric tons of
CO2 moved through over 5,000 miles of CO2
pipelines with zero incidents involving fatalities.\443\ PHMSA reported
a total of
[[Page 39861]]
102 CO2 pipeline incidents between 2003 and 2022, with one
injury (requiring in-patient hospitalization) and zero fatalities.\444\
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\443\ Congressional Research Service. 2022. Carbon Dioxide
Pipelines: Safety Issues, CRS Reports, June 3, 2022. https://crsreports.congress.gov/product/pdf/IN/IN11944.
\444\ NARUC. (2023). Onshore U.S. Carbon Pipeline Deployment:
Siting, Safety. and Regulation. Prepared by Public Sector
Consultants for the National Association of Regulatory Utility
Commissioners (NARUC). June 2023. https://pubs.naruc.org/pub/F1EECB6B-CD8A-6AD4-B05B-E7DA0F12672E.
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As noted previously in this preamble, a significant CO2
pipeline rupture occurred in 2020 in Satartia, Mississippi, following
heavy rains that resulted in a landslide. Although no one required in-
patient hospitalization as a result of this incident, 45 people
received treatment at local emergency rooms after the incident and 200
hundred residents were evacuated. Typically, when CO2 is
released into the open air, it vaporizes into a heavier-than-air gas
and dissipates. During the Satartia incident, however, unique
atmospheric conditions and the topographical features of the area
delayed this dissipation. As a result, residents were exposed to high
concentrations of CO2 in the air after the rupture.
Furthermore, local emergency responders were not informed by the
operator of the rupture and the nature of the unique safety risks of
the CO2 pipeline.\445\
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\445\ Failure Investigation Report--Denbury Gulf Coast Pipeline,
May 2022. https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2022-05/Failure%20Investigation%20Report%20-%20Denbury%20Gulf%20Coast%20Pipeline.pdf.
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PHMSA initiated a rulemaking in 2022 to develop and implement new
measures to strengthen its safety oversight of supercritical
CO2 pipelines following the investigation into the
CO2 pipeline failure in Satartia.\446\ PHMSA submitted the
associated Notice of Proposed Rulemaking to the White House Office of
Management and Budget on February 1, 2024 for pre-publication
review.\447\ Following the Satartia incident, PHMSA also issued a
Notice of Probable Violation, Proposed Civil Penalty, and Proposed
Compliance Order (Notice) to the operator related to probable
violations of Federal pipeline safety regulations. The Notice was
ultimately resolved through a Consent Agreement between PHMSA and the
operator that includes the assessment of civil penalties and identifies
actions for the operator to take to address the alleged violations and
risk conditions.\448\ PHMSA has further issued an updated nationwide
advisory bulletin to all pipeline operators and solicited research
proposals to strengthen CO2 pipeline safety.\449\ Given the
Federal and state regulation of CO2 pipelines and the steps
that PHMSA is taking to further improve pipeline safety, the EPA
believes CO2 can be safely transported by pipeline.
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\446\ PHMSA. (2022). ``PHMSA Announces New Safety Measures to
Protect Americans From Carbon Dioxide Pipeline Failures After
Satartia, MS Leak.'' https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americans-carbon-dioxide-pipeline-failures.
\447\ Columbia Law School. (2024). PHMSA Advances CO2 Pipeline
Safety Regulations. https://climate.law.columbia.edu/content/phmsa-advances-co2-pipeline-safety-regulations.
\448\ Department of Transportation. (2023). Consent Order,
Denbury Gulf Coast Pipelines, LLC, CPF No. 4-2022-017-NOPV https://primis.phmsa.dot.gov/comm/reports/enforce/CaseDetail_cpf_42022017NOPV.html?nocache=7208.
\449\ Ibid.
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Certain states have authority delegated from the U.S. Department of
Transportation to conduct safety inspections and enforce state and
Federal pipeline safety regulations for intrastate CO2
pipelines.450 451 452 PHMSA's state partners employ about 70
percent of all pipeline inspectors, which covers more than 80 percent
of regulated pipelines.\453\ Federal law requires certified state
authorities to adopt safety standards at least as stringent as the
Federal standards.\454\ Further, there are required steps that
CO2 pipeline operators must take to ensure pipelines are
operated safely under PHMSA standards and related state standards, such
as the use of pressure monitors to detect leaks or initiate shut-off
valves, and annual reporting on operations, structural integrity
assessments, and inspections.\455\ These CO2 pipeline
controls and PHMSA standards are designed to ensure that captured
CO2 will be securely conveyed to a sequestration site.
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\450\ New Mexico Public Regulation Commission. 2023.
Transportation Pipeline Safety. New Mexico Public Regulation
Commission, Bureau of Pipeline Safety. https://www.nm-prc.org/transportation/pipeline-safety.
\451\ Texas Railroad Commission. 2023. Oversight & Safety
Division. Texas Railroad Commission. https://www.rrc.texas.gov/about-us/organization-and-activities/rrc-divisions/oversight-safety-division.
\452\ NARUC. (2023). Onshore U.S. Carbon Pipeline Deployment:
Siting, Safety. and Regulation. Prepared by Public Sector
Consultants for the National Association of Regulatory Utility
Commissioners (NARUC). June 2023. https://pubs.naruc.org/pub/F1EECB6B-CD8A-6AD4-B05B-E7DA0F12672E.
\453\ PHMSA. (2023). ``PHMSA Issues Letters to Wolf Carbon,
Summit, and Navigator Clarifying Federal, State, and Local
Government Pipeline Authorities.'' https://www.phmsa.dot.gov/news/phmsa-issues-letters-wolf-carbon-summit-and-navigator-clarifying-federal-state-and-local.
\454\ PHMSA, ``PHMSA Issues Letters to Wolf Carbon, Summit, and
Navigator Clarifying Federal, State, and Local Government Pipeline
Authorities.'' 2023. https://www.phmsa.dot.gov/news/phmsa-issues-letters-wolf-carbon-summit-and-navigator-clarifying-federal-state-and-local.
\455\ Carbon Capture Coalition. ``PHMSA/Pipeline Safety Fact
Sheet,'' November 2023. https://carboncapturecoalition.org/wp-content/uploads/2023/11/Pipeline-Safety-Fact-Sheet.pdf.
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(4) Comments Received on CO2 Transport and Responses
The EPA received comments on CO2 transport, including
CO2 pipelines. Those comments, and the EPA's responses, are
as follows.
Comment: Some commenters identified challenges to the deployment of
a national, interstate CO2 pipeline network. In particular,
those commenters discussed the experience faced by long (e.g., over
1,000 miles) CO2 pipelines seeking permitting and right-of-
way access in Midwest states including Iowa and North Dakota.
Commenters claimed those challenges make CCS as BSER infeasible. Some
commenters argued that the existing CO2 pipeline capacity is
not adequate to meet potential demand caused by this rule and that the
ability of the network to grow and meet future potential demand is
hindered by significant public opposition.
Response: The EPA acknowledges the challenges that some large
multi-state pipeline projects have faced, but does not agree that those
experiences show that the BSER is not adequately demonstrated or that
the standards finalized in these actions are not achievable. As
detailed in the preceding subsections of the preamble, the BSER is not
premised on the buildout of a national, trunkline CO2
pipeline network. Most coal-fired steam generating units are in
relatively close proximity to geologic storage, and those shorter
pipelines would not likely be as challenging to permit and build as
demonstrated by the examples of smaller pipeline discussed above.
The EPA acknowledges that some larger trunkline CO2
pipeline projects, specifically the Heartland Greenway project, have
recently been delayed or canceled. However, many projects are still
moving forward and several major projects have recently been announced
to expand the CO2 pipeline network across the United States.
The EPA notes that there are often opportunities to reroute pipelines
to minimize permitting challenges and landowner concerns. For example,
Summit Carbon Solutions changed their planned pipeline route in North
Dakota after their initial permit was denied, leading to successful
acquisition of rights of way.\456\ Additionally, Tallgrass, which
[[Page 39862]]
is planning to convert a 630 km (392 mile) natural gas pipeline to
carry CO2, announced that they had reach a community
benefits agreement, in which certain organizations have agreed not to
oppose the pipeline project while Tallgrass has agreed to terms such as
contributing funds to first responders along the pipeline route and
providing royalty checks to landowners.\457\ See section
VII.C.1.a.i(C)(1)(d) for additional discussion of planned
CO2 pipelines. While access to larger trunkline projects
would not be required for most EGUs, at least some larger trunkline
projects are likely to be constructed, which would increase
opportunities for connecting to pipeline networks.
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\456\ Summit Carbon Solutions. Summit Carbon Solutions Signs 80
Percent of North Dakota Landowners. (2023). https://summitcarbonsolutions.com/summit-carbon-solutions-signs-80-percent-of-north-dakota-landowners/.
\457\ Hammel, Paul. (2024). Pipeline company, Nebraska
environmental group strike unique `community benefits' agreement.
https://www.desmoinesregister.com/story/tech/science/environment/2024/04/11/nebraska-environmentalist-forge-peace-pact-with-pipeline-company/73282852007/.
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Comment: Some commenters disagreed with the modeling assumption
that 100 km is a typical pipeline distance. The commenters asserted
that there is data showing the actual locations of the power plants
affected by the rule, and the required pipeline distance is not always
100 km.
Response: The EPA acknowledges that the physical locations of EGUs
and the physical locations of carbon sequestration capacity and
corresponding pipeline distance will not be 100 km in all cases. As
discussed previously in section VII.C.1.a.i(C)(1)(a), the EPA modeled
the unique approximate distance from each existing coal-fired steam
generating capacity with planned operation during or after 2039 to the
nearest potential saline sequestration site, and found that the
majority (80 percent) is within 100 km (62 miles) of potential saline
sequestration sites, and another 11 percent is within 160 km (100
miles).\458\ Furthermore, the EPA disagrees with the comments
suggesting that the use of 100 km is an inappropriate economic modeling
assumption. The 100 km assumption was not meant to encompass the
physical location of every potentially affected EGU. The 100 km
assumption is intended as an economic modeling assumption and is based
on similar assumptions applied in NETL studies used to estimate
CO2 transport costs. The EPA carefully reviewed the
assumptions on which the NETL transport cost estimates are based and
continues to find them reasonable. The NETL studies referenced in
section VII.C.1.a.ii based transport costs on a generic 100 km (62
mile) pipeline and a generic 80 km pipeline.\459\ For most EGUs, the
necessary pipeline distance is anticipated to be less than 100 km and
therefore the associated costs could also be lower than these
assumptions. Other published economic models applying different
assumptions have also reached the conclusion that CO2
transport and sequestration are adequately demonstrated.\460\
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\458\ Sequestration potential as it relates to distance from
existing resources is a key part of the EPA's regular power sector
modeling development, using data from DOE/NETL studies. For details,
please see chapter 6 of the IPM documentation. https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
\459\ The pipeline diameter was sized for this to be achieved
without the need for recompression stages along the pipeline length.
\460\ Ogland-Hand, Jonathan D. et. al. 2022. Screening for
Geologic Sequestration of CO2: A Comparison Between SCO2TPRO and the
FE/NETL CO2 Saline Storage Cost Model. International Journal of
Greenhouse Gas Control, Volume 114, February 2022, 103557. https://www.sciencedirect.com/science/article/pii/S175058362100308X.
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Comment: Commenters also stated that the permitting and
construction processes can be time-consuming.
Response: The EPA acknowledges building CO2 pipelines
requires capital expenditure and acknowledges that the timeline for
siting, engineering design, permitting, and construction of
CO2 pipelines depends on factors including the pipeline
capacity and pipeline length, whether the pipeline route is intrastate
or interstate, and the specifics of the state pipeline regulator's
regulatory requirements. In the BSER analysis, individual EGUs that are
subject to carbon capture requirements are assumed to take a point-to-
point approach to CO2 transport and sequestration. These
smaller-scale projects require less capital and may present less
complexity than larger projects. The EPA considers the timeline to
permit and install such pipelines in section VII.C.1.a.i(E) of the
preamble, and has determined that a compliance date of January 1, 2032
allows for a sufficient amount of time.
Comment: Some commenters expressed significant concerns about the
safety of CO2 pipelines following the CO2
pipeline failure in Satartia, Mississippi in 2020.
Response: For a discussion of the safety of CO2
pipelines and the Satartia pipeline failure, see section
VII.C.1.a.i(C)(3). The EPA believes that the framework of Federal and
state regulation of CO2 pipelines and the steps that PHMSA
is taking to further improve pipeline safety, is sufficient to ensure
CO2 can be safely transported by pipeline.
(D) Geologic Sequestration of CO2
The EPA is finalizing its determination that geologic sequestration
(i.e., the long-term containment of a CO2 stream in
subsurface geologic formations) is adequately demonstrated. In this
section, we provide an overview of the availability of sequestration
sites in the U.S., discuss how geologic sequestration of CO2
is well proven and broadly available throughout the U.S, explain the
effectiveness of sequestration, discuss the regulatory framework for
UIC wells, and discuss the timing of permitting for sequestration
sites. We then provide a summary of key comments received concerning
geologic sequestration and our responses to those comments.
(1) Sequestration Sites for Coal-Fired Power Plants Subject to CCS
Requirements
(a) Broad Availability of Sequestration
Sequestration is broadly available in the United States, which
makes clear that it is adequately demonstrated. By far the most widely
available and well understood type of sequestration is that in deep
saline formations. These formations are common in the U.S. These
formations are numerous and only a small subset of the existing saline
storage capacity would be required to store the CO2 from
EGUs. Many projects are in the process of completing thorough
subsurface studies of these deep saline formations to determine their
suitability for regional-scale storage. Furthermore, sequestration
formations could also include unmineable coal seams and oil and gas
reservoirs. CO2 may be stored in oil and gas reservoirs in
association with EOR and enhanced gas recovery (EGR) technologies,
collectively referred to as enhanced recovery (ER), which include the
injection of CO2 in oil and gas reservoirs to increase
production. ER is a technology that has been used for decades in states
across the U.S.\461\
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\461\ NETL. (2010). Carbon Dioxide Enhanced Oil Recovery.
https://www.netl.doe.gov/sites/default/files/netl-file/co2_eor_primer.pdf.
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Geologic sequestration is based on a demonstrated understanding of
the trapping and containment processes that retain CO2 in
the subsurface. The presence of a low permeability seal is an important
component of demonstrating secure geologic sequestration. Analyses of
the potential availability of geologic sequestration capacity in the
United States have been conducted by DOE,
[[Page 39863]]
and the U.S. Geological Survey (USGS) has also undertaken a
comprehensive assessment of geologic sequestration resources in the
United States.462 463 Geologic sequestration potential for
CO2 is widespread and available throughout the United
States. Nearly every state in the United States has or is in close
proximity to formations with geologic sequestration potential,
including areas offshore. There have been numerous efforts
demonstrating successful geologic sequestration projects in the United
States and overseas, and the United States has developed a detailed set
of regulatory requirements to ensure the security of sequestered
CO2. Moreover, the amount of storage potential can readily
accommodate the amount of CO2 for which sequestration could
be expected under this final rule.
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\462\ U.S. DOE NETL. (2015). Carbon Storage Atlas, Fifth
Edition, September 2015. https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
\463\ U.S. Geological Survey Geologic Carbon Dioxide Storage
Resources Assessment Team. (2013). National assessment of geologic
carbon dioxide storage resources--Summary: U.S. Geological Survey
Factsheet 2013-3020. http://pubs.usgs.gov/fs/2013/3020/.
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The EPA has performed a geographic availability analysis in which
the Agency examined areas of the U.S. with sequestration potential in
deep saline formations, unmineable coal seams, and oil and gas
reservoirs; information on existing and probable, planned or under
study CO2 pipelines; and areas within a 100 km (62-mile)
area of potential sequestration sites. This availability analysis is
based on resources from the DOE, the USGS, and the EPA. The distance of
100 km is consistent with the assumptions underlying the NETL cost
estimates for transporting CO2 by pipeline. The scoping
assessment by the EPA found that at least 37 states have geologic
characteristics that are amenable to deep saline sequestration, and an
additional 6 states are within 100 kilometers of potentially amenable
deep saline formations in either onshore or offshore locations. Of the
7 states that are further than 100 km (62 mi) of onshore or offshore
storage potential in deep saline formations, only New Hampshire has
coal EGUs that were assumed to be in operation after 2039, with a total
capacity of 534 MW. However, the EPA notes that as of March 27, 2024,
the last coal-fired steam EGUs in New Hampshire announced that they
would cease operation by 2028.\464\ Therefore, the EPA anticipates that
there will no existing coal-fired steam EGUs located in states that are
further than 100 km (62 mi) of potential geologic sequestration sites.
Furthermore, as described in section VII.C.1.a.i(C), new EGUs would
have the ability to consider proximity and access to geologic
sequestration sites or CO2 pipelines in the siting process.
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\464\ Vickers, Clayton. (2024). ``Last coal plants in New
England to close; renewables take their place.'' https://thehill.com/policy/energy-environment/4560375-new-hampshire-coal-plants-closing/.
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The DOE and the United States Geological Survey (USGS) have
independently conducted preliminary analyses of the availability and
potential CO2 sequestration resources in the United States.
The DOE estimates are compiled in the DOE's National Carbon
Sequestration Database and Geographic Information System (NATCARB)
using volumetric models and are published in its Carbon Utilization and
Sequestration Atlas (NETL Atlas). The DOE estimates that areas of the
United States with appropriate geology have a sequestration potential
of at least 2,400 billion to over 21,000 billion metric tons of
CO2 in deep saline formations, unmineable coal seams, and
oil and gas reservoirs. The USGS assessment estimates a mean of 3,000
billion metric tons of subsurface CO2 sequestration
potential across the United States. With respect to deep saline
formations, the DOE estimates a sequestration potential of at least
2,200 billion metric tons of CO2 in these formations in the
United States. The EPA estimates that the CO2 emissions
reductions for this rule (which is similar to the amount of
CO2 may be sequestered under this rule) are estimated in the
range of 1.3 to 1.4 billion metric tons over the 2028 to 2047
timeframe.\465\ This volume of sequestered CO2 is less than
a tenth of a percent of the storage capacity in deep saline formations
estimated to be available by DOE.
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\465\ For detailed information on the estimated emissions
reductions from this rule, see section 3 of the RIA, available in
the rulemaking docket.
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Unmineable coal seams offer another potential option for geologic
sequestration of CO2. Enhanced coalbed methane recovery is
the process of injecting and storing CO2 in unmineable coal
seams to enhance methane recovery. These operations take advantage of
the preferential chemical affinity of coal for CO2 relative
to the methane that is naturally found on the surfaces of coal. When
CO2 is injected, it is adsorbed to the coal surface and
releases methane that can then be captured and produced. This process
effectively ``locks'' the CO2 to the coal, where it remains
stored. States with the potential for sequestration in unmineable coal
seams include Iowa and Missouri, which have little to no saline
sequestration potential and have existing coal-fired EGUs. Unmineable
coal seams have a sequestration potential of at least 54 billion metric
tons of CO2, or 2 percent of total potential in the United
States, and are located in 22 states.
The potential for CO2 sequestration in unmineable coal
seams has been demonstrated in small-scale demonstration projects,
including the Allison Unit pilot project in New Mexico, which injected
a total of 270,000 tons of CO2 over a 6-year period (1995-
2001). Further, DOE Regional Carbon Sequestration Partnership projects
have injected CO2 volumes in unmineable coal seams ranging
from 90 tons to 16,700 tons, and completed site characterization,
injection, and post-injection monitoring for sites. DOE has included
unmineable coal seams in the NETL Atlas. One study estimated that in
the United States, 86.16 billion tons of CO2 could be
permanently stored in unmineable coal seams.\466\ Although the large-
scale injection of CO2 in coal seams can lead to swelling of
coal, the literature also suggests that there are available
technologies and techniques to compensate for the resulting reduction
in injectivity. Further, the reduced injectivity can be anticipated and
accommodated in sizing and characterizing prospective sequestration
sites.
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\466\ Godec, Koperna, and Gale. (2014). ``CO2-ECBM: A
Review of its Status and Global Potential'', Energy Procedia, Volume
63. https://doi.org/10.1016/j.egypro.2014.11.619.
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Depleted oil and gas reservoirs present additional potential for
geologic sequestration. The reservoir characteristics of developed
fields are well known as a result of exploration and many years of
hydrocarbon production and, in many areas, infrastructure already
exists which could be evaluated for conversion to CO2
transportation and sequestration service. Other types of geologic
formations such as organic rich shale and basalt may also have the
ability to store CO2, and DOE is continuing to evaluate
their potential sequestration capacity and efficacy.
(b) Inventory of Coal-Fired Power Plants That Are Candidates for CCS
Sequestration potential as it relates to distance from existing
coal-fired steam generating units is a key part of the EPA's regular
power sector modeling, using data from DOE/NETL studies.\467\ As
discussed in section VII.C.1.a.i(D)(1)(a), the availability
[[Page 39864]]
analysis shows that of the coal-fired steam generating capacity with
planned operation during or after 2039, more than 50 percent is less
than 32 km (20 miles) from potential deep saline sequestration sites,
73 percent is located within 50 km (31 miles), 80 percent is located
within 100 km (62 miles), and 91 percent is within 160 km (100
miles).\468\
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\467\ For details, please see Chapter 6 of the IPM
documentation. https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
\468\ Sequestration potential as it relates to distance from
existing resources is a key part of the EPA's regular power sector
modeling development, using data from DOE/NETL studies. For details,
please see chapter 6 of the IPM documentation. https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
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(2) Geologic Sequestration of CO2 Is Adequately Demonstrated
Geologic sequestration is based on a demonstrated understanding of
the processes that affect the fate of CO2 in the subsurface.
Existing project and regulatory experience, along with other
information, indicate that geologic sequestration is a viable long-term
CO2 sequestration option. As discussed in this section,
there are many examples of projects successfully injecting and
containing CO2 in the subsurface.
Research conducted through the Department of Energy's Regional
Carbon Sequestration Partnerships has demonstrated geologic
sequestration through a series of field research projects that
increased in scale over time, injecting more than 12 million tons of
CO2 with no indications of negative impacts to either human
health or the environment.\469\ Building on this experience, DOE
launched the Carbon Storage Assurance Facility Enterprise (CarbonSAFE)
Initiative in 2016 to demonstrate how knowledge from the Regional
Carbon Sequestration Partnerships can be applied to commercial-scale
safe storage. This initiative is furthering the development and
refinement of technologies and techniques critical to the
characterization of sites with the potential to sequester greater than
50 million tons of CO2.\470\ In Phase I of CarbonSAFE,
thirteen projects conducted economic feasibility analyses, collected,
analyzed, and modeled extensive regional data, evaluated multiple
storage sites and infrastructure, and evaluated business plans. Six
projects were funded for Phase II which involves storage complex
feasibility studies. These projects evaluate initial reservoir
characteristics to determine if the reservoir is suitable for geologic
sequestration sites of more than 50 million tons of CO2,
address technical and non-technical challenges that may arise, develop
a risk assessment and CO2 management strategy for the
project; and assist with the validation of existing tools. Five
projects have been funded for CarbonSAFE Phase III and are currently
performing site characterization and permitting.
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\469\ Regional Sequestration Partnership Overview. https://netl.doe.gov/carbon-management/carbon-storage/RCSP.
\470\ National Energy Technology Laboratory. CarbonSAFE
Initiative. https://netl.doe.gov/carbon-management/carbon-storage/carbonsafe.
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The EPA notes that, while only sequestration facilities with
Federal funding are currently operational in the United States,
multiple commercial sequestration facilities, other than those funded
under EPAct05, are in construction or advanced development, with some
scheduled to open for operation as early as 2025.\471\ These facilities
have proposed sequestration capacities ranging from 0.03 to 6 million
tons of CO2 per year. The Great Plains Synfuel Plant
currently captures 2 million metric tons of CO2 per year,
which is exported to Canada for use in EOR; a planned addition of
sequestration in a saline formation for this facility is expected to
increase the amount of CO2 captured and sequestered (through
both geologic sequestration and EOR) to 3.5 million metric tons of
CO2 per year.\472\ The EPA and states with approved UIC
Class VI programs (including Wyoming, North Dakota, and Louisiana) are
currently reviewing UIC Class VI geologic sequestration well permit
applications for proposed sequestration sites in fourteen
states.473 474 475 As of March 15, 2024, 44 projects with
130 injection wells are under review by the EPA.\476\
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\471\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\472\ Basin Electric Power Cooperative. (2021). ``Great Plains
Synfuels Plant Potential to Be Largest Coal-Based Carbon Capture and
Storage Project to Use Geologic Storage''. https://www.basinelectric.com/News-Center/news-releases/Great-Plains-Synfuels-Plant-potential-to-be-largest-coal-based-carbon-capture-and-storage-project-to-use-geologic-storage.
\473\ UIC regulations for Class VI wells authorize the injection
of CO2 for geologic sequestration while protecting human
health by ensuring the protection of underground sources of drinking
water. The major components to be included in UIC Class VI permits
are detailed further in section VII.C.1.a.i(D)(4).
\474\ U.S. EPA Class VI Underground Injection Control (UIC)
Class VI Wells Permitted by EPA as of January 25, 2024. https://www.epa.gov/uic/table-epas-draft-and-final-class-vi-well-permits
Last updated January 19, 2024.
\475\ U.S. EPA Current Class VI Projects under Review at EPA.
2024. https://www.epa.gov/uic/current-class-vi-projects-under-review-epa.
\476\ U.S. EPA. Current Class VI Projects under Review at EPA.
2024. https://www.epa.gov/uic/current-class-vi-projects-under-review-epa.
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Currently, there are planned geologic sequestration facilities
across the United States in various phases of development,
construction, and operation. The Wyoming Department of Environmental
Quality issued three UIC Class VI permits in December 2023 to Frontier
Carbon Solutions. The Frontier Carbon Solutions project will sequester
5 million metric tons of CO2/year.\477\ Additionally, UIC
Class VI permit applications have been submitted to the Wyoming
Department of Environmental Quality for a proposed Eastern Wyoming
Sequestration Hub project that would sequester up to 3 million metric
tons of CO2/year.\478\ The North Dakota Oil and Gas Division
has issued UIC Class VI permits to 6 sequestration projects that
collectively will sequester 18 million metric tons of CO2/
year.\479\ Since 2014, the EPA has issued two UIC Class VI permits to
Archer Daniels Midland (ADM) in Decatur, Illinois, which authorize the
injection of up to 7 million metric tons of CO2. One of the
AMD wells is in the injection phase while the other is in the post-
injection phase. In January 2024, the EPA issued two UIC Class VI
permits to Wabash Carbon Services LLC for a project that will sequester
up to 1.67 million metric tons of CO2/year over an injection
period of 12 years.\480\ In December 2023, the EPA released for public
comment four UIC Class VI draft permits for the Carbon TerraVault
projects, to be located in California.\481\ These projects propose to
sequester CO2 captured from multiple different sources in
California including a hydrogen plant, direct air capture, and pre-
combustion gas treatment. TerraVault plans to inject 1.46 million
metric tons of CO2 annually into the four proposed wells
over a 26-year injection period with a total potential capacity of 191
million metric tons.482 483 One of the proposed wells is
[[Page 39865]]
an existing UIC Class II well that would be converted to a UIC Class VI
well for the TerraVault project.\484\
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\477\ Wyoming DEQ, Water Quality. Wyoming grants its first three
Class VI permits. By Kimberly Mazza, December 14, 2023 https://deq.wyoming.gov/2023/12/wyoming-grants-its-first-three-class-vi-permits/.
\478\ Wyoming DEQ Class VI Permit Applications. Trailblazer
permit application. https://deq.wyoming.gov/water-quality/groundwater/uic/class-vi.
\479\ North Dakota Oil and Gas Division, Class VI--Geologic
Sequestration Wells. https://www.dmr.nd.gov/dmr/oilgas/ClassVI.
\480\ EPA Approves Permits to Begin Construction of Wabash
Carbon Services Underground Injection Wells in Indiana's Vermillion
and Vigo Counties. (2024) https://www.epa.gov/uic/epa-approves-permits-wabash-carbon-services-underground-injection-wells-indianas-vigo-and
\481\ U.S. EPA Current Class VI Projects under Review at EPA.
2024. https://www.epa.gov/uic/current-class-vi-projects-under-review-epa.
\482\ U.S. EPA Class VI Permit Application. ``Intent to Issue
Four (4) Class VI Geologic Carbon Sequestration Underground
Injection Control (UIC) Permits for Carbon TerraVault JV Storage
Company Sub 1, LLC. EPA-R09-OW-2023-0623.'' https://www.epa.gov/publicnotices/intent-issue-class-vi-underground-injection-control-permits-carbon-terravault-jv.
\483\ California Resources Corporation. ``Carbon TerraVault
Potential Storage Capacity.''https://www.crc.com/carbon-terravault/Vaults/default.aspx.
\484\ U.S. EPA Class VI Permit Application. ``Intent to Issue
Four (4) Class VI Geologic Carbon Sequestration Underground
Injection Control (UIC) Permits for Carbon TerraVault JV Storage
Company Sub 1, LLC. EPA-R09-OW-2023-0623.
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Geologic sequestration has been proven to be successful and safe in
projects internationally. In Norway, facilities conduct offshore
sequestration under the Norwegian continental shelf.\485\ In addition,
the Sleipner CO2 Storage facility in the North Sea, which
began operations in 1996, injects around 1 million metric tons of
CO2 per year from natural gas processing.\486\ The Snohvit
CO2 Storage facility in the Barents Sea, which began
operations in 2008, injects around 0.7 million metric tons of
CO2 per year from natural gas processing. The SaskPower
carbon capture and sequestration facility at Boundary Dam Power Station
in Saskatchewan, Canada had, as of the end of 2023, captured 5.6
million metric tons of CO2 since it began operating in
2014.\487\ Other international sequestration facilities in operation
include Glacier Gas Plant MCCS (Canada),\488\ Quest (Canada), and Qatar
LNG CCS (Qatar). The CarbFix project in Iceland injects CO2
into a geologic formation in which the CO2 reacts with
basalt rock formations to form stone. The CarbFix project has injected
approximately 100,000 metric tons of CO2 into geologic
formations since 2014.\489\
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\485\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage. https://www.ipcc.ch/report/carbon-dioxide-capture-and-storage/.
\486\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\487\ BD3 Status Update: Q3 2023. https://www.saskpower.com/
about-us/our-company/blog/2023/bd3-status-update-q3-2023.
\488\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\489\ CarbFix Operations. (2024). https://www.carbfix.com/.
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EOR, the process of injecting CO2 into oil and gas
formations to extract additional oil and gas, has been successfully
used for decades at numerous production fields throughout the United
States to increase oil and gas recovery. The oil and gas industry in
the United States has nearly 60 years of experience with EOR.\490\ This
experience provides a strong foundation for demonstrating successful
CO2 injection and monitoring technologies, which are needed
for safe and secure geologic sequestration that can be used for
deployment of CCS across geographically diverse areas. The amount of
CO2 that can be injected for an EOR project and the duration
of operations are of similar magnitude to the duration and volume of
CO2 that is expected to be captured from fossil fuel-fired
EGUs. The Farnsworth Unit, the Camrick Unit, the Shute Creek Facility,
and the Core Energy CO2-EOR facility are all examples of
operations that store anthropogenic CO2 as a part of EOR
operations.491 492 Currently, 13 states have active EOR
operations, and these states also have areas that are amenable to deep
saline sequestration in either onshore or offshore locations.\493\
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\490\ NETL. (2010). Carbon Dioxide Enhanced Oil Recovery.
https://www.netl.doe.gov/sites/default/files/netl-file/co2_eor_primer.pdf.
\491\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\492\ Greenhouse Gas Reporting Program monitoring reports for
these facilities are available at https://www.epa.gov/ghgreporting/subpart-rr-geologic-sequestration-carbon-dioxide#decisions.
\493\ U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition,
September 2015. https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
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(3) EPAct05-Assisted Geologic Sequestration Projects
Consistent with the EPA's legal interpretation that the Agency can
rely on experience from EPAct05 funded facilities in conjunction with
other information, this section provides examples of EPAct05-assisted
geologic sequestration projects. While the EPA has determined that the
sequestration component of CCS is adequately demonstrated based on the
non-EPAct05 examples discussed above, adequate demonstration of
geologic sequestration is further corroborated by planned and
operational geologic sequestration projects assisted by grants, loan
guarantees, and the IRC section 48A federal tax credit for ``clean coal
technology'' authorized by the EPAct05.\494\
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\494\ 80 FR 64541-42 (October 23, 2015).
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At present, there are 13 operational and one post-injection phase
commercial carbon sequestration facilities in the United
States.495 496 Red Trail Energy CCS Project in North Dakota
and Illinois Industrial Carbon Capture and Storage in Illinois are
dedicated saline sequestration facilities, while the other facilities,
including Petra Nova in Texas, are sequestration via
EOR.497 498 Several other facilities are under
development.\499\ The Red Trail Energy CCS facility in North Dakota
began injecting CO2 captured from ethanol production plants
in 2022.\500\ This project is expected to inject 180,000 tons of
CO2 per year.\501\ The Illinois Industrial Carbon Capture
and Storage Project began injecting CO2 from ethanol
production into the Mount Simon Sandstone in April 2017. According to
the facility's report to the EPA's Greenhouse Gas Reporting Program
(GHGRP), as of 2022, 2.9 million metric tons of CO2 had been
injected into the saline reservoir.\502\ CO2 injection for
one of the two permitted Class VI wells ceased in 2021 and this well is
now in the post-operation data collection phase.\503\
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\495\ Clean Air Task Force. (August 3, 2023). U.S. Carbon
Capture Activity and Project Map. https://www.catf.us/ccsmapus/.
\496\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\497\ Reuters. (September 14, 2023) ``Carbon capture project
back at Texas coal plant after 3-year shutdown''. https://www.reuters.com/business/energy/carbon-capture-project-back-texas-coal-plant-after-3-year-shutdown-2023-09-14/.
\498\ Clean Air Task Force. (August 3, 2023). U.S. Carbon
Capture Activity and Project Map. https://www.catf.us/ccsmapus/.
\499\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\500\ Ibid.
\501\ Ibid.
\502\ EPA Greenhouse Gas Reporting Program. Data reported as of
August 12, 2022.
\503\ University of Illinois Urbana-Champaign, Prairie Research
Institute. (2022). Data from landmark Illinois Basin carbon storage
project are now available. https://blogs.illinois.edu/view/7447/54118905.
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There are additional planned geologic sequestration projects under
review by the EPA and across the United States.504 505
Project Tundra, a saline sequestration project planned at the lignite-
fired Milton R. Young Station in North Dakota is projected to capture 4
million metric tons of CO2 annually.\506\ In Wyoming, Class
VI permit
[[Page 39866]]
applications have been issued by the Wyoming Department of
Environmental Quality for the proposed Eastern Wyoming Sequestration
Hub project, a saline sequestration facility proposed to be located in
Southwestern Wyoming.\507\ At full capacity, the facility would
permanently store up to 5 million metric tons of CO2
captured from industrial facilities annually in the Nugget saline
sandstone reservoir.\508\ In Texas, three NGCCs plan to add carbon
capture equipment. Deer Park NGCC plans to capture 5 million tons per
year, Quail Run NGCC plans to capture 1.5 million tons of
CO2 per year, and Baytown NGCC plans to capture up to 2
million tons of CO2 per year.509 510
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\504\ In addition, Denbury Resources injected CO2
into a depleted oil and gas reservoir at a rate greater than 1.2
million tons/year as part of a DOE Southeast Regional Carbon
Sequestration Partnership study. The Texas Bureau of Economic
Geology tested a wide range of surface and subsurface monitoring
tools and approaches to document sequestration efficiency and
sequestration permanence at the Cranfield oilfield in Mississippi.
Texas Bureau of Economic Geology, ``Cranfield Log.'' https://www.beg.utexas.edu/gccc/research/cranfield.
\505\ EPA Class VI Permit Tracker. https://www.epa.gov/system/files/documents/2024-02/class-vi-permit-tracker_2-5-24.pdf. Accessed
February 5, 2024.
\506\ Project Tundra. ``Project Tundra.'' https://www.projecttundrand.com/.
\507\ Wyoming DEQ Class VI Permit Applications. https://deq.wyoming.gov/water-quality/groundwater/uic/class-vi/.
\508\ Id.
\509\ Calpine. (2023). Calpine Carbon Capture, Bayton, Texas.
https://calpinecarboncapture.com/wp-content/uploads/2023/04/Calpine-Baytown-One-Pager-English-1.pdf.
\510\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
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(4) Security of Geologic Sequestration and Related Regulatory
Requirements
As discussed in section VII.C.1.a.i(D)(2) of this preamble, there
have been numerous instances of geologic sequestration in the U.S. and
overseas, and the U.S. has developed a detailed set of regulatory
requirements to ensure the security of sequestered CO2. This
regulatory framework includes the UIC well regulations pursuant to SDWA
authority, and the GHGRP pursuant to CAA authority.
Regulatory oversight of geologic sequestration is built upon an
understanding of the proven mechanisms by which CO2 is
retained in geologic formations. These mechanisms include (1)
Structural and stratigraphic trapping (generally trapping below a low
permeability confining layer); (2) residual CO2 trapping
(retention as an immobile phase trapped in the pore spaces of the
geologic formation); (3) solubility trapping (dissolution in the in
situ formation fluids); (4) mineral trapping (reaction with the
minerals in the geologic formation and confining layer to produce
carbonate minerals); and (5) preferential adsorption trapping
(adsorption onto organic matter in coal and shale).
(a) Overview of Legal and Regulatory Framework
For the reasons detailed below, the UIC Program, the GHGRP, and
other regulatory requirements comprise a detailed regulatory framework
for geologic sequestration in the United States. This framework is
analyzed in a 2021 report from the Council on Environmental Quality
(CEQ),\511\ and statutory and regulatory frameworks that may be
applicable for CCS are summarized in the EPA CCS Regulations
Table.512 513 This regulatory framework includes the UIC
regulations, promulgated by the EPA under the authority of the Safe
Drinking Water Act (SDWA); and the GHGRP, promulgated by the EPA under
the authority of the CAA. The requirements of the UIC and GHGRP
programs work together to ensure that sequestered CO2 will
remain securely stored underground. Furthermore, geologic sequestration
efforts on Federal lands as well as those efforts that are directly
supported with Federal funds would need to comply with the NEPA and
other Federal laws and regulations, depending on the nature of the
project.\514\ In cases where sequestration is conducted offshore, the
SDWA, the Marine Protection, Research, and Sanctuaries Act (MPRSA) or
the Outer Continental Shelf Lands Act (OCSLA) may apply. The Department
of Interior Bureau of Safety and Environmental Enforcement and Bureau
of Ocean Energy Management are developing new regulations and creating
a program for oversight of carbon sequestration activities on the outer
continental shelf.\515\ Furthermore, Title V of the Federal Land Policy
and Management Act of 1976 (FLPMA) and its implementing regulations, 43
CFR part 2800, authorize the Bureau of Land Management (BLM) to issue
rights-of-way (ROWs) to geologically sequester CO2 in
Federal pore space, including BLM ROWs for the necessary physical
infrastructure and for the use and occupancy of the pore space itself.
The BLM has published a policy defining access to pore space on BLM
lands, including clarification of Federal policy for situations where
the surface and pore space are under the control of different Federal
agencies.\516\
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\511\ CEQ. (2021). ``Council on Environmental Quality Report to
Congress on Carbon Capture, Utilization, and Sequestration.''
https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
\512\ EPA. 2023. Regulatory and Statutory Authorities Relevant
to Carbon Capture and Sequestration (CCS) Projects. https://www.epa.gov/system/files/documents/2023-10/regulatory-and-statutory-authorities-relevant-to-carbon-capture-and-sequestration-ccs-projects.pdf.
\513\ This table serves as a reference of many possible
authorities that may affect a CCS project (including site selection,
capture, transportation, and sequestration). Many of the authorities
listed in this table would apply only in specific circumstances.
\514\ CEQ. ``Council on Environmental Quality Report to Congress
on Carbon Capture, Utilization, and Sequestration.'' 2021. https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
\515\ Department of the Interior. (2023). BSEE Budget. https://www.doi.gov/ocl/bsee-budget.
\516\ National Policy for the Right-of-Way Authorizations
Necessary for Site Characterization, Capture, Transportation,
Injection, and Permanent Geologic Sequestration of Carbon Dioxide in
Connection with Carbon Sequestration Projects. BLM IM 2022-041
Instruction Memorandum, June 8, 2022. https://www.blm.gov/policy/im-2022-041.
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(b) Underground Injection Control (UIC) Program
The UIC regulations, including the Class VI program, authorize the
injection of CO2 for geologic sequestration while protecting
human health by ensuring the protection of underground sources of
drinking water (USDW). These regulations are built upon nearly a half-
century of Federal experience regulating underground injection wells,
and many additional years of state UIC program expertise. The IIJA
established a $50 million grant program to assist states and tribal
regulatory authorities in developing and implementing UIC Class VI
programs.\517\ Major components included in UIC Class VI permits are
site characterization, area of review,\518\ corrective action,\519\
well construction and operation, testing and monitoring, financial
responsibility, post-injection site care, well plugging, emergency and
remedial response, and site closure. The EPA's UIC regulations are
included in 40 CFR parts 144-147. The UIC regulations ensure that
injected CO2 does not migrate out of the authorized
injection zone, which in turn ensures that CO2 is securely
stored underground.
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\517\ EPA. Underground Injection Control Class VI Wells
Memorandum. (December 9, 2022). https://www.epa.gov/system/files/documents/2022-12/AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
\518\ Per 40 CFR 146.84(a), the area of review is the region
surrounding the geologic sequestration project where USDWs may be
endangered by the injection activity. The area of review is
delineated using computational modeling that accounts for the
physical and chemical properties of all phases of the injected
carbon dioxide stream and is based on available site
characterization, monitoring, and operational data.
\519\ UIC permitting authorities may require corrective action
for existing wells within the area of review to ensure protection of
underground sources of drinking water.
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Review of a UIC permit application by the permitting authority,
including for Class VI geologic sequestration, entails a
multidisciplinary evaluation to determine whether the application
includes the required information, is technically accurate, and
supports a determination that USDWs will not be endangered by the
proposed injection
[[Page 39867]]
activity.\520\ The EPA promulgated UIC regulations to ensure
underground injection wells are constructed, operated, and closed in a
manner that is protective of USDWs and to address potential risks to
USDWs associated with injection activities.\521\ The UIC regulations
address the major pathways by which injected fluids can migrate into
USDWs, including along the injection well bore, via improperly
completed or plugged wells in the area near the injection well, direct
injection into a USDW, faults or fractures in the confining strata, or
lateral displacement into hydraulically connected USDWs. States may
apply to the EPA to be the UIC permitting authority in the state and
receive primary enforcement authority (primacy). Where a state has not
obtained primacy, the EPA is the UIC permitting authority.
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\520\ EPA. EPA Report to Congress: Class VI Permitting. 2022.
https://www.epa.gov/system/files/documents/2022-11/EPAClassVIPermittingReporttoCongress.pdf.
\521\ See 40 CFR parts 124, 144-147.
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Recognizing that CO2 injection, for the purpose of
geologic sequestration, poses unique risks relative to other injection
activities, the EPA promulgated Federal Requirements Under the UIC
Program for Carbon Dioxide GS Wells, known as the Class VI Rule, in
December 2010.\522\ The Class VI Rule created and set requirements for
a new class of injection wells, Class VI. The Class VI Rule builds upon
the long-standing protective framework of the UIC Program, with
requirements that are tailored to address issues unique to large-scale
geologic sequestration, including large injection volumes, higher
reservoir pressures relative to other injection formations, the
relative buoyancy of CO2, the potential presence of
impurities in captured CO2, the corrosivity of
CO2 in the presence of water, and the mobility of
CO2 within subsurface geologic formations. These additional
protective requirements include more extensive geologic testing,
detailed computational modeling of the project area and periodic re-
evaluations, detailed requirements for monitoring and tracking the
CO2 plume and pressure in the injection zone, unique
financial responsibility requirements, and extended post-injection
monitoring and site care.
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\522\ EPA. (2010). Federal Requirements Under the Underground
Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic
Sequestration (GS) Wells; Final Rule, 75 FR 77230, December 10, 2010
(codified at 40 CFR part 146, subpart H).
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UIC Class VI permits are designed to ensure that geologic
sequestration does not cause the movement of injected CO2 or
formation fluids outside the authorized injection zone; if monitoring
indicates leakage of injected CO2 from the injection zone,
the leakage may trigger a response per the permittee's Class VI
Emergency and Remedial Response Plan including halting injection, and
the permitting authority may prescribe additional permit requirements
necessary to prevent such movement to ensure USDWs are protected or
take appropriate enforcement action if the permit has been
violated.\523\ Class II EOR permits are also designed to ensure the
protection of USDWs with requirements appropriate for the risks of the
enhanced recovery operation. In general, the EPA believes that the
protection of USDWs by preventing leakage of injected CO2
out of the injection zone will also ensure that CO2 is
sufficiently sequestered in the subsurface, and therefore will not leak
from the subsurface to the atmosphere.
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\523\ See 40 CFR 144.12(b) (prohibition of movement of fluid
into USDWs); 40 CFR 146.86(a)(1) (Class VI injection well
construction requirements); 40 CFR 146(a) (Class VI injection well
operation requirements); 40 CFR 146.94 (emergency and remedial
response).
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The UIC program works with injection well operators throughout the
life of the well to confirm practices do not pose a risk to USDWs. The
program conducts inspections to verify compliance with the UIC permit,
including checking for leaks.\524\ Inspections are only one way that
programs deter noncompliance. Programs also evaluate periodic
monitoring reports submitted by operators and discuss potential issues
with operators. If a well is found to be out of compliance with
applicable requirements in its permit or UIC regulations, the program
will identify specific actions that an operator must take to address
the issues. The UIC program may assist the operator in returning the
well to compliance or use administrative or judicial enforcement to
return a well to compliance.
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\524\ EPA. (2020). Underground Injection Control Program.
https://www.epa.gov/sites/default/files/2020-04/documents/uic_fact_sheet.pdf.
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UIC program requirements address potential safety concerns with
induced seismicity. More specifically, through the UIC Class VI
program, the EPA has put in place mechanisms to identify, monitor, and
reduce risks associated with induced seismicity in any areas within or
surrounding a sequestration site through permit and program
requirements such as site characterization and monitoring, and the
requirement for applicants to demonstrate that induced seismic activity
will not endanger USDWs.\525\ The National Academy of Sciences released
a report in 2012 on induced seismicity from CCS and determined that
with appropriate site selection, a monitoring program, a regulatory
system, and the appropriate use of remediation methods, the induced
seismicity risks of geologic sequestration could be mitigated.\526\
Furthermore, the Ground Water Protection Council and Interstate Oil and
Gas Compact Commission have published a ``Potential Induced Seismicity
Guide.'' This report found that the strategies for avoiding,
mitigating, and responding to potential risks of induced seismicity
should be determined based on site-specific characteristics (i.e.,
local geology). These strategies could include supplemental seismic
monitoring, altering operational parameters (such as rates and
pressures) to reduce the ground motion hazard and risk, permit
modification, partial plug back of the well, controlled restart (if
feasible), suspending or revoking injection authorization, or stopping
injection and shutting in a well.\527\ The EPA's UIC National Technical
Workgroup released technical recommendations in 2015 to address induced
seismicity concerns in Class II wells and elements of these
recommendations have been utilized in developing Class VI emergency and
remedial response plans for Class VI permits.528 529 For
example, as identified
[[Page 39868]]
by the EPA's UIC National Technical Workgroup, sufficient pressure
buildup from disposal activities, the presence of Faults of Concern
(i.e., a fault optimally oriented for movement and located in a
critically stressed region), and the existence of a pathway for
allowing the increased pressure to communicate with the fault
contribute to the risk of injection-induced seismicity. The UIC
requirements, including site characterization (e.g., ensuring the
confining zone \530\ is free of faults of concern) and operating
requirements (e.g., ensuring injection pressure in the injection zone
is below the fracture pressure), work together to address these
components and reduce the risk of injection-induced seismicity,
particularly any injection-induced seismicity that could be felt by
people at the surface.\531\ Additionally, the EPA recommends that Class
VI permits include an approach for monitoring for seismicity near the
site, including seismicity that cannot be felt at the surface, and that
injection activities be stopped or reduced in certain situations if
seismic activity is detected to ensure that no seismic activity will
endanger USDWs.\532\ This also reduces the likelihood of any future
injection-induced seismic activity that will be felt at the surface.
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\525\ See 40 CFR 146.82(a)(3)(v) (requiring the permit applicant
to submit and the permitting authority to consider information on
the seismic history including the presence and depth of seismic
sources and a determination that the seismicity would not interfere
with containment); EPA. (2018). Geologic Sequestration of Carbon
Dioxide Underground Injection Control (UIC) Program Class VI
Implementation Manual for UIC Program Directors. U.S. Environmental
Protection Agency Office of Water (4606M) EPA 816-R-18-001. https://www.epa.gov/sites/default/files/2018-01/documents/implementation_manual_508_010318.pdf.
\526\ National Research Council. (2013). Induced Seismicity
Potential in Energy Technologies. Washington, DC: The National
Academies Press. https://doi.org/10.17226/13355.
\527\ Ground Water Protection Council and Interstate Oil and Gas
Compact Commission. (2021). Potential Induced Seismicity Guide: A
Resource of Technical and Regulatory Considerations Associated with
Fluid Injection. https://www.gwpc.org/wp-content/uploads/2022/12/FINAL_Induced_Seismicity_2021_Guide_33021.pdf.
\528\ EPA. (2015). Minimizing and Managing Potential Impacts of
Injection-Induced Seismicity from Class II Disposal Wells: Practical
Approaches. https://www.epa.gov/sites/default/files/2015-08/documents/induced-seismicity-201502.pdf.
\529\ EPA. (2018). Geologic Sequestration of Carbon Dioxide:
Underground Injection Control (UIC) Program Class VI Implementation
Manual for UIC Program Directors. EPA 816-R-18-001. https://www.epa.gov/sites/default/files/2018-01/documents/implementation_manual_508_010318.pdf.
\530\ ``Confining zone'' means a geological formation, group of
formations, or part of a formation that is capable of limiting fluid
movement above an injection zone. 40 CFR 146.3.
\531\ EPA. (2015). Minimizing and Managing Potential Impacts of
Injection-Induced Seismicity from Class II Disposal Wells: Practical
Approaches. https://www.epa.gov/sites/default/files/2015-08/documents/induced-seismicity-201502.pdf.
\532\ See EPA. Emergency and Remedial Response Plan: 40 CFR
146.94(a) template. https://www.epa.gov/system/files/documents/2022-03/err_plan_template.docx. See also EPA. (2018). Geologic
Sequestration of Carbon Dioxide: Underground Injection Control (UIC)
Program Class VI Implementation Manual for UIC Program Directors.
EPA 816-R-18-001. https://www.epa.gov/sites/default/files/2018-01/documents/implementation_manual_508_010318.pdf.
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Furthermore, during site characterization, if any of the geologic
or seismic data obtained indicate a substantial likelihood of seismic
activity, the EPA may require further analyses, potential planned
operational changes, and additional monitoring.\533\ The EPA has the
authority to require seismic monitoring as a condition of the UIC
permit if appropriate, or to deny the permit if the injection-induced
seismicity risk could endanger USDWs.
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\533\ 40 CFR 146.82(a)(3)(v).
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The EPA believes that meaningful engagement with local communities
is an important step in the development of geologic sequestration
projects and has programs and public participation requirements in
place to support this process. The EPA is committed to advancing EJ for
overburdened communities in all its programs, including the UIC Class
VI program.\534\ The EPA is also committed to supporting states' and
tribes' efforts to obtain UIC Class VI primacy and strongly encourages
such states and tribes to incorporate environmental justice principles
and equity into proposed UIC Class VI programs.\535\ The EPA is taking
steps to address EJ in accordance with Presidential Executive Order
14096, Revitalizing Our Nation's Commitment to Environmental Justice
for All (88 FR 25251, April 26, 2023). In 2023, the EPA released
Environmental Justice Guidance for UIC Class VI Permitting and Primacy
that builds on the 2011 UIC Quick Reference Guide: Additional Tools for
UIC Program Directors Incorporating Environmental Justice
Considerations into the Class VI Injection Well Permitting
Process.536 537 The 2023 guidance serves as an operating
framework for identifying, analyzing, and addressing EJ concerns in the
context of implementing and overseeing UIC permitting and primacy
programs, including primacy approvals. The EPA notes that while this
guidance is focused on the UIC Class VI program, EPA Regions should
apply them to the other five injection well classes wherever possible,
including class II. The guidance includes recommended actions across
five themes to address various aspects of EJ in UIC Class VI permitting
including: (1) identify communities with potential EJ concerns, (2)
enhance public involvement, (3) conduct appropriately scoped EJ
assessments, (4) enhance transparency throughout the permitting
process, and (5) minimize adverse effects to USDWs and the communities
they may serve.\538\
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\534\ EPA. (2023). Environmental justice Guidance for UIC Class
VI Permitting and Primacy. https://www.epa.gov/system/files/documents/2023-08/Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI_August%202023.pdf
; see also EPA. Letter from the EPA Administrator Michael S. Regan
to U.S. State Governors. December 9, 2022. https://www.epa.gov/system/files/documents/2022-12/AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
\535\ EPA. (2023). Targeted UIC program grants for Class VI
Wells. https://www.epa.gov/uic/underground-injection-control-grants#ClassVI_Grants.
\536\ EPA. (2023). Environmental justice Guidance for UIC Class
VI Permitting and Primacy. https://www.epa.gov/system/files/documents/2023-08/Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI_August%202023.pdf
.
\537\ EPA. (2011). Geologic Sequestration of Carbon Dioxide--UIC
Quick Reference Guide. https://www.epa.gov/sites/default/files/2015-07/documents/epa816r11002.pdf.
\538\ EPA. (2023). Environmental justice Guidance for UIC Class
VI Permitting and Primacy. https://www.epa.gov/system/files/documents/2023-08/Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI_August%202023.pdf
.
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As a part of the UIC Class VI permit application process,
applicants and the EPA Regions should complete an EJ review using the
EPA's EJScreen Tool, an online mapping tool that integrates numerous
demographic, socioeconomic, and environmental data sets that are
overlain on an applicant's UIC Area of Review to identify whether any
disadvantaged communities are encompassed.\539\ If the results indicate
a potential EJ impact, applicants and the EPA Regions should consider
potential measures to mitigate the impacts of the UIC Class VI project
on identified vulnerable communities and enhance the public
participation process to be inclusive of all potentially affected
communities (e.g., conduct early targeted outreach to communities and
identify and mitigate any communication obstacles such as language
barriers or lack of technology resources).\540\
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\539\ EPA Report to Congress: Class VI Permitting. 2022. https://www.epa.gov/system/files/documents/2022-11/EPAClassVIPermittingReporttoCongress.pdf.
\540\ EPA Report to Congress: Class VI Permitting. 2022. https://www.epa.gov/system/files/documents/2022-11/EPAClassVIPermittingReporttoCongress.pdf.
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ER technologies are used in oil and gas reservoirs to increase
production. Injection wells used for ER are regulated through the UIC
Class II program. Injection of CO2 is one of several
techniques used in ER. Sometimes ER uses CO2 from
anthropogenic sources such as natural gas processing, ammonia and
fertilizer production, and coal gasification facilities. Through the ER
process, much of the injected CO2 is recovered from
production wells and can be separated and reinjected into the
subsurface formation, resulting in the storage of CO2
underground. The EPA's Class II regulations were designed to regulate
ER injection wells, among other injection wells associated with oil and
natural gas production. See e.g., 40 CFR 144.6(b)(2). The EPA's Class
II program is designed to prevent Class II injection activities from
endangering USDWs. The Class II programs of states and tribes must be
approved by the EPA and must meet the EPA regulatory requirements for
Class II programs, 42 U.S.C. 300h-1, or otherwise represent an
effective program to prevent endangerment of USDWs. 42 U.S.C 300h-4.
[[Page 39869]]
In promulgating the Class VI regulations, the EPA recognized that
if the business model for ER shifts to focus on maximizing
CO2 injection volumes and permanent storage, then the risk
of endangerment to USDWs is likely to increase. As an ER project shifts
away from oil and/or gas production, injection zone pressure and carbon
dioxide volumes will likely increase if carbon dioxide injection rates
increase, and the dissipation of reservoir pressure will decrease if
fluid production from the reservoir decreases. Therefore, the EPA's
regulations require the operator of a Class II well to obtain a Class
VI permit when there is an increased risk to USDWs. 40 CFR 144.19.\541\
While the EPA's regulations require the Class II well operator to
assess whether there is an increased risk to USDWs (considering factors
identified in the EPA's regulations), the permitting authority can also
make this assessment and, in the event that an operator makes changes
to Class II operations such that the increased risk to USDWs warrants
transition to Class VI and the operator does not notify the permitting
authority, the operator may be subject to SDWA enforcement and
compliance actions to protect USDWs, including cessation of injection.
The determination of whether there is an increased risk to USDWs would
be based on factors specified in 40 CFR 144.19(b), including increase
in reservoir pressure within the injection zone; increase in
CO2 injection rates; and suitability of the Class II Area of
Review (AoR) delineation.
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\541\ EPA. (2015). Key Principles in EPA's Underground Injection
Control Program Class VI Rule Related to Transition of Class II
Enhanced Oil or Gas Recovery Wells to Class VI. https://www.epa.gov/sites/default/files/2015-07/documents/class2eorclass6memo_1.pdf.
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(c) Greenhouse Gas Reporting Program (GHGRP)
The GHGRP requires reporting of greenhouse gas (GHG) data and other
relevant information from large GHG emission sources, fuel and
industrial gas suppliers, and CO2 injection sites in the
United States. Approximately 8,000 facilities are required to report
their emissions, injection, and/or supply activity annually, and the
non-confidential reported data are made available to the public around
October of each year. To complement the UIC regulations, the EPA
included in the GHGRP air-side monitoring and reporting requirements
for CO2 capture, underground injection, and geologic
sequestration. These requirements are included in 40 CFR part 98,
subpart RR and subpart VV, also referred to as ``GHGRP subpart RR'' and
``GHGRP subpart VV.''
GHGRP subpart RR applies to ``any well or group of wells that
inject a CO2 stream for long-term containment in subsurface
geologic formations'' \542\ and provides the monitoring and reporting
mechanisms to quantify CO2 storage and to identify,
quantify, and address potential leakage. The EPA designed GHGRP subpart
RR to complement the UIC monitoring and testing requirements. See e.g.,
40 CFR 146.90-91. Reporting under GHGRP subpart RR is required for, but
not limited to, all facilities that have received a UIC Class VI permit
for injection of CO2.\543\ Under existing GHGRP regulations,
facilities that conduct ER in Class II wells are not subject to
reporting data under GHGRP subpart RR unless they have chosen to submit
a proposed monitoring, reporting, and verification (MRV) plan to the
EPA and received an approved plan from the EPA. Facilities conducting
ER and who do not choose to submit a subpart RR MRV plan to the EPA
would otherwise be required to report CO2 data under subpart
UU.\544\ GHGRP subpart RR requires facilities meeting the source
category definition (40 CFR 98.440) for any well or group of wells to
report basic information on the mass of CO2 received for
injection; develop and implement an EPA-approved monitoring, reporting,
and verification (MRV) plan; report the mass of CO2
sequestered using a mass balance approach; and report annual monitoring
activities.545 546 547 548 Extensive subsurface monitoring
is required for UIC Class VI wells at 40 CFR 146.90 and is the primary
means of determining if the injected CO2 remains in the
authorized injection zone and otherwise does not endanger any USDW, and
monitoring under a GHGRP subpart RR MRV Plan complements these
requirements. The MRV plan includes five major components: a
delineation of monitoring areas based on the CO2 plume
location; an identification and evaluation of the potential surface
leakage pathways and an assessment of the likelihood, magnitude, and
timing, of surface leakage of CO2 through these pathways; a
strategy for detecting and quantifying any surface leakage of
CO2 in the event leakage occurs; an approach for
establishing the expected baselines for monitoring CO2
surface leakage; and, a summary of considerations made to calculate
site-specific variables for the mass balance equation.\549\
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\542\ See 40 CFR 98.440.
\543\ 40 CFR 98.440.
\544\ As discussed in section X.C.5.b, entities conducting CCS
to comply with this rule would be required to send the captured
CO2 to a facility that reports data under subpart RR or
subpart VV.
\545\ 40 CFR 98.446.
\546\ 40 CFR 98.448.
\547\ 40 CFR 98.446(f)(9) and (10).
\548\ 40 CFR 98.446(f)(12).
\549\ 40 CFR 98.448(a).
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In April 2024, the EPA finalized a new GHGRP subpart, ``Geologic
Sequestration of Carbon Dioxide with Enhanced Oil Recovery (EOR) Using
ISO 27916'' (or GHGRP subpart VV).\550\ GHGRP subpart VV applies to
facilities that quantify the geologic sequestration of CO2
in association with EOR operations in conformance with the ISO standard
designated as CSA/ANSI ISO 27916:2019, Carbon Dioxide Capture,
Transportation and Geological Storage--Carbon Dioxide Storage Using
Enhanced Oil Recovery. Facilities that have chosen to submit an MRV
plan and report under GHGRP subpart RR must not report data under GHGRP
subpart VV. GHGRP subpart VV is largely modeled after the requirements
in this ISO standard and focuses on quantifying storage of
CO2. Facilities subject to GHGRP subpart VV must include in
their GHGRP annual report a copy of their EOR Operations Management
Plan (EOR OMP). The EOR OMP includes a description of the EOR complex
and engineered system, establishes that the EOR complex is adequate to
provide safe, long-term containment of CO2, and includes
site-specific and other information including a geologic
characterization of the EOR complex, a description of the facilities
within the EOR project, a description of all wells and other engineered
features in the EOR project, and the operations history of the project
reservoir.\551\
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\550\ EPA. (2024). Rulemaking Notices for GHG Reporting. https://www.epa.gov/ghgreporting/rulemaking-notices-ghg-reporting.
\551\ EPA. (2024). Rulemaking Notices for GHG Reporting. https://www.epa.gov/ghgreporting/rulemaking-notices-ghg-reporting.
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Based on the understanding developed from existing projects, the
security of sequestered CO2 is expected to increase over
time after injection ceases.\552\ This is due to trapping mechanisms
that reduce CO2 mobility over time (e.g., physical
CO2 trapping by a low-permeability geologic seal or chemical
trapping by conversion or adsorption).\553\ The EPA acknowledges the
potential for some leakage of CO2 to the atmosphere at
sequestration sites, primarily while injection operations are active.
For example, small quantities of the CO2 that were sent to
the
[[Page 39870]]
sequestration site may be emitted from leaks in pipes and valves that
are traversed before the CO2 actually reaches the
sequestration formation. However, the EPA's robust UIC regulatory
protections protect against leakage out of the injection zone. Relative
to the 46.75 million metric tons of CO2 reported as
sequestered under subpart RR of the GHGRP between 2016 to 2022, only
196,060 metric tons were reported as leakage/emissions to the
atmosphere in the same time period (representing less than 0.5% of the
sequestration amount). Of these emissions, most were from equipment
leaks and vented emissions of CO2 from equipment located on
the surface rather than leakage from the subsurface.\554\ Furthermore,
any leakage of CO2 at a sequestration facility would be
required to be quantified and reported under the GHGRP subpart RR or
subpart VV, and such data are made publicly available on the EPA's
website.
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\552\ ``Report of the Interagency Task Force on Carbon Capture
and Storage.'' 2010. https://www.osti.gov/servlets/purl/985209.
\553\ See, e.g., Intergovernmental Panel on Climate Change.
(2005). Special Report on Carbon Dioxide Capture and Storage.
\554\ Based on subpart RR data retrieved from the EPA Facility
Level Information on Greenhouse Gases Tool (FLIGHT), at https://ghgdata.epa.gov/ghgp/main.do. Retrieved March 2024.
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(5) Timing of Permitting for Sequestration Sites
As previously discussed, the EPA is the Class VI permitting
authority for states, tribes, and territories that have not obtained
primacy over their Class VI programs.\555\ The EPA is committed to
reviewing UIC Class VI permits as expeditiously as possible when the
agency is the permitting authority. The EPA has the experience to
properly regulate and review permits for UIC Class VI injection wells,
and technical experts of multiple disciplines to review permit
applications submitted to the EPA.
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\555\ See 40 CFR part 145 (State UIC Program Requirements), 40
CFR part 147 (State, Tribal, and EPA-Administered Underground
Injection Control Programs).
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The EPA has seen a considerable uptick in Class VI permit
applications over the past few years. The 2018 passage of revisions and
enhancements to the IRC section 45Q tax credit that provides tax
credits for carbon oxide (including CO2) sequestration has
led to an increase in Class VI permit applications submitted to the
EPA. The 2022 IRA further expanded the IRC section 45Q tax credit and
the 2021 IIJA established a $50 million program for grants to help
states and tribes in developing and implementing a UIC Class VI primacy
program, leading to even more interest in this area.\556\ Between 2011,
when the Class VI rule went into effect, and 2020, the EPA received a
total of 8 permit applications for Class VI wells. The EPA then
received 12 Class VI permit applications in 2021, 44 in 2022, and 123
in 2023. As of March 2024, the EPA has 130 Class VI permit applications
under review (56 permit applications were transferred to Louisiana in
February 2024 when the EPA rule granting Class VI primacy to the state
became effective). The majority of those 130 permit applications (63%)
were submitted to the EPA within the past 12 months. Also, as of March
2024, the EPA has issued eight Class VI permits, including six for
projects in Illinois and two for projects in Indiana, and has released
for public comment four additional draft permits for proposed projects
in California. Two of the permits are in the pre-operation phase, one
is in the injection phase, and one is in the post-injection monitoring
phase.
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\556\ EPA. (2023). Targeted UIC program grants for Class VI
Wells https://www.epa.gov/uic/underground-injection-control-grants#ClassVI_Grants.
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In light of the recent flurry of interest in this area, the EPA is
devoting increased resources to the Class VI program, including through
increased staffing levels in order to meet the increased demand for
action on Class VI permit applications.\557\ Reviewing a Class VI
permit application entails a multidisciplinary evaluation to determine
whether the application includes the required information, is
technically accurate, and supports a risk-based determination that
underground sources of drinking water will not be endangered by the
proposed injection activity. A wide variety of technical experts--from
geologists to engineers to physical scientists--review permit
applications submitted to the EPA. The EPA has been working to develop
staff expertise and increase capacity in the UIC program, and the
agency has effectively deployed appropriated resources over the last
five years to scale UIC program staff from a few employees to the
equivalent of more than 25 full-time employees across the agency's
headquarters and regional offices. We expect that the additional
resources and staff capacity for the Class VI program will lead to
increased efficiencies in the Class VI permitting process.
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\557\ EPA. (2023). Testimony Of Mr. Bruno Pigott, Principal
Deputy Assistant Administrator for Water, U.S. Environmental
Protection Agency, Hearing On Carbon Capture And Storage. https://www.epa.gov/system/files/documents/2023-11/testimony-pigott-senr-hearing-nov-2-2023_-cleared.pdf.
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In addition to increased staffing resources, the EPA has made
considerable improvements to the Class VI permitting process to reduce
the time needed to make final permitting decisions for Class VI wells
while maintaining a robust and thorough review process that ensures
USDWs are protected. The EPA has created additional resources for
applicants including upgrading the Geologic Sequestration Data Tool
(GSDT) to guide applicants through the application process.\558\ The
EPA has also created resources for permit writers including training
series and guidance documents to build capacity for Class VI
permitting.\559\ Additionally, the EPA issued internal guidelines to
streamline and create uniformity and consistency in the Class VI
permitting process, which should help to reduce permitting timeframes.
These internal guidelines include the expectation that EPA Regions will
classify all Class VI well applications received on or after December
12, 2023, as applications for major new UIC injection wells, which
requires the Regions to develop project decision schedules for
reviewing Class VI permit applications. The guidelines also set target
timeframes for components of the permitting process, such as the number
of days EPA Regions should set for public comment periods and for
developing responses to comments and final permit decisions. The EPA
will continue to evaluate its internal UIC permitting processes to
identify potential opportunities for streamlining and other
improvements over time. Although the available data for Class VI wells
is limited, the timeframe for processing Class I wells, which follows a
similar regulatory structure, is typically less than 2 years.\560\
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\558\ EPA. (2023). Geologic Sequestration Data Tool (GSDT).
https://www.epa.gov/system/files/documents/2023-10/geologic-sequestration-data-tool_factsheet_oct2023.pdf.
\559\ EPA. (2023). Final Class VI Guidance Documents. https://www.epa.gov/uic/final-class-vi-guidance-documents.
\560\ EPA Report to Congress: Class VI Permitting. 2022. https://www.epa.gov/system/files/documents/2022-11/EPAClassVIPermittingReporttoCongress.pdf.
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The EPA notes that a Class VI permit tracker is available on its
website.\561\ This tracker shows information for the 44 projects
(representing 130 wells) that have submitted Class VI applications to
the EPA, including details such as the current permit review stage,
whether a project has been sent a Notice of Deficiency (NOD) or Request
for Additional Information (RAI), and the applicant's response time to
any NODs or RAIs. As mentioned above, most of the permits submitted to
the EPA have been submitted within the past 12
[[Page 39871]]
months. The EPA aims to review complete Class VI applications and issue
permits when appropriate within approximately 24 months. This timeframe
is dependent on several factors, including the complexity of the
project and the quality and completeness of the submitted application.
It is important for the applicant to submit a complete application and
provide any information requested by the permitting agency in a timely
manner so as not to extend the overall time for the review.
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\561\ EPA. (2024). Current Class VI Projects under Review at
EPA. https://www.epa.gov/uic/current-class-vi-projects-under-review-epa.
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States may apply to the EPA for primacy to administer the Class VI
programs within their states. The primacy application process has four
phases: (1) pre-application activities, (2) completeness review and
determination, (3) application evaluation, and (4) rulemaking and
codification. To date, three states have been granted primacy for Class
VI wells, including North Dakota, Wyoming, and most recently
Louisiana.\562\ As discussed above, North Dakota has issued 6 Class VI
permits since receiving Class VI primacy in 2018, and Wyoming issued
its first three Class VI permits in December
2023.563 564 565 The EPA finalized a rule granting Louisiana
Class VI primacy in January 2024 and the state's program became
effective in February 2024. At that time, EPA Region 6 transferred 56
Class VI permit applications for projects in Louisiana to the state for
continued review and permit issuance if appropriate. Prior to receiving
primacy, the state worked with the EPA in understanding where each
application was in the evaluation process. Currently, the EPA is
working with the states of Texas, Arizona, and West Virginia as they
are developing their UIC primacy applications.\566\ Arizona submitted a
primacy application to the EPA on February 13, 2024.\567\ Texas and
West Virginia are engaging with the EPA to complete pre-application
activities.\568\ If more states apply for and receive Class VI primacy,
the number of permits in EPA review is expected to be reduced. The EPA
has also created resources for regulators including training series and
guidance documents to build capacity for Class VI permitting within UIC
programs across the U.S. Through state primacy for Class VI programs,
state expertise and capacity can be leveraged to support effective and
efficient permit application reviews. The IIJA established a $50
million grant program to support states, Tribes, and territories in
developing and implementing UIC Class VI programs. The EPA has
allocated $1,930,000 to each state, tribe, and territory that submitted
letters of intent.\569\
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\562\ On December 28, 2023, the EPA Administrator signed a final
rule granting Louisiana's request for primacy for UIC Class VI
junction wells located within the state. See EPA. (2023).
Underground Injection Control (UIC) Primary Enforcement Authority
for the Underground Injection Control Program. U.S. Environmental
Protection Agency. https://www.epa.gov/uic/primary-enforcement-authority-underground-injection-control-program-0.
\563\ Wyoming Department of Environmental Quality. (2023).
Wyoming grants its first three Class VI permits. https://deq.wyoming.gov/2023/12/wyoming-grants-its-first-three-class-vi-permits/.
\564\ Ibid.
\565\ Arnold & Porter. (2023). EPA Provides Increased
Transparency in Class VI Permitting Process; Now Incorporated in
Update to Interactive CCUS State Tracker. https://www.arnoldporter.com/en/perspectives/blogs/environmental-edge/2023/11/ccus-state-legislative-tracker.
\566\ EPA. (2023). Underground Injection Control (UIC) Primary
Enforcement Authority for the Underground Injection Control Program.
U.S. Environmental Protection Agency. https://www.epa.gov/uic/primary-enforcement-authority-underground-injection-control-program-0.
\567\ Arizona Department of Environmental Quality. (2024).
Underground Injection Control (UIC) Program. https://azdeq.gov/UIC.
\568\ EPA. (2023). Underground Injection Control (UIC) Primary
Enforcement Authority for the Underground Injection Control Program.
U.S. Environmental Protection Agency. https://www.epa.gov/uic/primary-enforcement-authority-underground-injection-control-program-0.
\569\ EPA. (2023). Underground Injection Control (UIC) Class VI
Grant Program. https://www.epa.gov/system/files/documents/2023-11/uic-class-vi-grant-fact-sheet.pdf.
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(6) Comments Received on Geologic Sequestration and Responses
The EPA received comments on geologic sequestration. Those
comments, and the EPA's responses, are as follows.
Comment: Some commenters expressed concerns that the EPA has not
demonstrated the adequacy of carbon sequestration at a commercial
scale.
Response: The EPA disagrees that commercial carbon sequestration
capacity will be inadequate to support this rule. As detailed in
section VII.C.1.a.i(D)(1), commercial geologic sequestration capacity
is growing in the United States. Multiple commercial sequestration
facilities, other than those funded under EPAct05, are in construction
or advanced development, with some scheduled to open for operation as
early as 2025.\570\ These facilities have proposed sequestration
capacities ranging from 0.03 to 6 million tons of CO2 per
year. The EPA and states with approved UIC Class VI programs (including
Wyoming, North Dakota, and Louisiana) are currently reviewing UIC Class
VI geologic sequestration well permit applications for proposed
sequestration sites in fourteen states.571 572 573 As of
March 2024, there are 44 projects with 130 injection wells are under
review by the EPA.\574\ Furthermore, the EPA anticipates that as the
demand for commercial sequestration grows, more commercial sites will
be developed in response to financial incentives.
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\570\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\571\ UIC regulations for Class VI wells authorize the injection
of CO2 for geologic sequestration while protecting human
health by ensuring the protection of underground sources of drinking
water. The major components to be included in UIC Class VI permits
are detailed further in section VII.C.1.a.i(D)(4).
\572\ U.S. EPA Class VI Underground Injection Control (UIC)
Class VI Wells Permitted by EPA as of January 25, 2024. https://www.epa.gov/uic/table-epas-draft-and-final-class-vi-well-permits
Last updated January 19, 2024.
\573\ EPA. (2024). Current Class VI Projects under Review at
EPA. https://www.epa.gov/uic/current-class-vi-projects-under-review-epa.
\574\ Ibid.
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Comment: Some commenters expressed concern about leakage of
CO2 from sequestration sites.
Response: The EPA acknowledges the potential for some leakage of
CO2 to the atmosphere at sequestration sites (such as leaks
through valves before the CO2 reaches the injection
formation). However, as detailed in the preceding sections of preamble,
the EPA's robust UIC permitting process is adequate to protect against
CO2 escaping the authorized injection zone (and then
entering the atmosphere). As discussed in the preceding section,
leakage out of the injection zone could trigger emergency and remedial
response action including ceasing injection, possible permit
modification, and possible enforcement action. Furthermore, the GHGRP
subpart RR and subpart VV regulations prescribe accounting
methodologies for facilities to quantify and report any potential
leakage at the surface, and the EPA makes sequestration data and
related monitoring plans publicly available on its website. The
reported emissions/leakage from sequestration sites under subpart RR is
a comparatively small fraction (less than 0.5 percent) of the
associated sequestration volumes, with most of these reported emissions
attributable to leaks or vents from surface equipment.
Comment: Some commenters expressed concern over safety due to
induced seismicity.
Response: The EPA believes that the UIC program requirements
adequately address potential safety concerns with induced seismicity at
site-adjacent communities. More specifically, through the UIC Class VI
program the EPA has put in place mechanisms to identify,
[[Page 39872]]
monitor, and mitigate risks associated with induced seismicity in any
areas within or surrounding a sequestration site through permit and
program requirements, such as site characterization and monitoring, and
the requirement for applicants to demonstrate that induced seismic
activity will not endanger USDWs.\575\ See section VII.C.1.a.i(D)(4)(b)
for further discussion of mitigating induced seismicity risk. Although
the UIC Class II program does not have specific requirements regarding
seismicity, it includes discretionary authority to add additional
conditions to a UIC permit on a case-by-case basis. The EPA created a
document outlining practical approaches for UIC Directors to use to
minimize and manage injection-induced seismicity in Class II
wells.\576\ Furthermore, during site characterization, if any of the
geologic or seismic data obtained indicate a substantial likelihood of
seismic activity, further analyses, potential planned operational
changes, and additional monitoring may be required.\577\ The EPA has
the authority to require seismic monitoring as a condition of the UIC
permit if appropriate, or to deny the permit if the injection-induced
seismicity risk could endanger USDWs.
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\575\ EPA. (2018). Geologic Sequestration of Carbon Dioxide:
Underground Injection Control (UIC) Program Class VI Implementation
Manual for UIC Program Directors. EPA 816-R-18-001. https://www.epa.gov/sites/default/files/2018-01/documents/implementation_manual_508_010318.pdf.
\576\ EPA. (2015). Minimizing and Managing Potential Impacts of
Injection-Induced Seismicity from Class II Disposal Wells: Practical
Approaches. https://www.epa.gov/sites/default/files/2015-08/documents/induced-seismicity-201502.pdf.
\577\ 40 CFR 146.82(a)(3)(v).
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Comment: Some commenters have expressed concern that the EPA has
not meaningfully engaged with historically disadvantaged and
overburdened communities who may be impacted by environmental changes
due to geologic sequestration.
Response: The EPA acknowledges that meaningful engagement with
local communities is an important step in the development of geologic
sequestration projects and has programs and public participation
requirements in place to support this process. The EPA is committed to
advancing environmental justice for overburdened communities in all its
programs, including the UIC Class VI program.\578\ The EPA's
environmental justice guidance for Class VI permitting and primacy
states that many of the expectations are broadly applicable, and EPA
Regions should apply them to the other five injection well classes,
including Class II, wherever possible.\579\ See section
VII.C.1.a.i(D)(4) for a detailed discussion of environmental justice
requirements and guidance.
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\578\ EPA. (2023). Environmental justice Guidance for UIC Class
VI Permitting and Primacy. https://www.epa.gov/system/files/documents/2023-08/Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI_August%202023.pdf
; see also EPA. Letter from the EPA Administrator Michael S. Regan
to U.S. State Governors. December 9, 2022. https://www.epa.gov/system/files/documents/2022-12/AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
\579\ EPA. (2023). Environmental Justice Guidance for UIC Class
VI Permitting and Primacy. https://www.epa.gov/system/files/documents/2023-08/Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI_August%202023.pdf
.
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Comment: Commenters expressed concern that companies are not always
in compliance with reporting requirements for subpart RR when required
for other Federal programs.
Response: The EPA recognizes the need for geologic sequestration
facilities to comply with the reporting requirements of the GHGRP, and
acknowledges that there have been instances of entities claiming
geologic sequestration under non-EPA programs (e.g., to qualify for IRC
section 45Q tax credits) while not having an EPA-approved MRV plan or
reporting data under subpart RR.\580\ The EPA does not implement the
IRC section 45Q tax credit program, and it is not privy to taxpayer
information. Thus, the EPA has no role in implementing or enforcing
these tax credit claims, and it is unclear, for example, whether these
companies would have been required by GHGRP regulations to report data
under subpart RR, or if they would have been required only by the IRC
section 45Q rules to opt-in to reporting under subpart RR. The EPA
disagrees that compliance with the GHGRP would be a problem for this
rule because the rule requires any affected unit that employs CCS
technology that captures enough CO2 to meet the proposed
standard and injects the captured CO2 underground to report
under GHGRP subpart RR or GHGRP subpart VV. Unlike the IRC section 45Q
tax credit program, which is implemented by the Internal Revenue
Service (IRS), the EPA will have the information necessary to discern
whether a facility is in compliance with any applicable GHGRP
requirements. If the emitting EGU sends the captured CO2
offsite, it must transfer the CO2 to a facility that reports
in accordance with GHGRP subpart RR or GHGRP subpart VV. For more
information on the relationship to GHGRP requirements, see section
X.C.5 of this preamble.
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\580\ Letter from U.S. Treasury Inspector General for Tax
Administration (TIGTA). (2020). https://www.menendez.senate.gov/imo/media/doc/TIGTA%20IRC%2045Q%20Response%20Letter%20FINAL%2004-15-2020.pdf.
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Comment: Commenters expressed concerns that UIC regulations allow
Class II wells to be used for long-term CO2 storage if the
operator assesses that a Class VI permit is not required and asserted
that Class II regulations are less protective than Class VI
regulations.
Response: The EPA acknowledges that Class II wells for EOR may be
used to inject CO2 including CO2 captured from an
EGU. However, the EPA disagrees that the use of Class II wells for ER
will be less protective of human health than the use of Class VI wells
for geologic sequestration. Class II wells are used only to inject
fluids associated with oil and natural gas production, and Class II ER
wells are used specifically for the injection of fluids, including
CO2, for the purpose of enhanced recovery of oil or natural
gas. The EPA's UIC Class II program is designed to prevent Class II
injection activities from endangering USDWs. Any leakage out of the
designated injection zone could pose a risk to USDWs and therefore
could be subject to enforcement action or permit modification.
Therefore, the EPA believes that UIC protections for USDWs would also
ensure that the injected CO2 is contained in the subsurface
formations. The Class II programs of states and tribes must be approved
by the EPA and must meet EPA regulatory requirements for Class II
programs, 42 U.S.C. 300h-1, or otherwise represent an effective program
to prevent endangerment of USDWs. 42 U.S.C 300h-4. The EPA's
regulations require the operator of a Class II well to obtain a Class
VI permit when operations shift to geologic sequestration and there is
consequently an increased risk to USDWs. 40 CFR 144.19. UIC Class VI
regulations require that owners or operators must show that the
injection zone has sufficient volume to contain the injected carbon
dioxide stream and report any fluid migration out of the injection zone
and into or between USDWs. 40 CFR 146.83 and 40 CFR 146.91. The EPA
emphasizes that while CO2 captured from an EGU can be
injected into a Class II ER injection well, it cannot be injected into
the other two types of Class II wells, which are Class II disposal
wells and Class II wells for the storage of hydrocarbons. 40 CFR
144.6(b).
Comment: Some commenters expressed concern that because few Class
VI permits have been issued, the EPA's current level of experience in
properly regulating and reviewing permits for these wells is limited.
[[Page 39873]]
Response: The EPA disagrees that the Agency lacks experience to
properly regulate, and review permits for Class VI injection wells. We
expect that the additional resources that have been allocated for the
Class VI program will lead to increased efficiencies in the Class VI
permitting process and timeframes. For a more detailed discussion of
Class VI permitting and timeframes, see sections VII.C.1.a.i(D)(4)(b)
and VII.C.1.a.i(D)(5) of this preamble. The EPA emphasizes that
incomplete or insufficient application materials can result in
substantially delayed permitting decisions. When the EPA receives
incomplete or insufficient permit applications, the EPA communicates
the deficiencies, waits to receive additional materials from the
applicant, and then reviews any new data. This back and forth can
result in longer permitting timeframes. The EPA therefore encourages
applicants to contact their permitting authority early on so applicants
can gain a thorough understanding of the Class VI permitting process
and the permitting authority's expectations. To assist potential permit
applicants, the EPA maintains a list of UIC contacts within each EPA
Regional Office on the Agency's website.\581\ The EPA has met with more
than 100 companies and other interested parties.
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\581\ EPA. (2023). Underground Injection Control Class VI
(Geologic Sequestration) Contact Information. https://www.epa.gov/uic/underground-injection-control-class-vi-geologic-sequestration-contact-information.
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Comment: Some commenters claimed that various legal uncertainties
preclude a finding that geologic sequestration of CO2 has
been adequately demonstrated. This concern has been raised in
particular with issues of pore space ownership and the lack of long-
term liability insurance and noted uncertainties regarding long-term
liability generally.
Response: The EPA disagrees that these uncertainties are sufficient
to prohibit the development of geologic sequestration projects. An
interagency CCS task force examined sequestration-related legal issues
thoroughly and concluded that early CCS projects could proceed under
the existing legal framework with respect to issues such as property
rights and liability.\582\ The development of CCS projects may be more
complex in certain regions, due to distinct pore space ownership
regulatory regimes at the state level, except on Federal lands.\583\
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\582\ Report of the Interagency Task Force on Carbon Capture and
Storage. 2010. https://www.energy.gov/fecm/articles/ccstf-final-report.
\583\ Council on Environmental Quality Report to Congress on
Carbon Capture, Utilization, and Sequestration. 2021. https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
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As discussed in section VII.C.1.a.i.(D)(4) of this preamble, Title
V of the FLPMA and its implementing regulations, 43 CFR part 2800,
authorize the BLM to issue ROWs to geologically sequester
CO2 in Federal pore space, including BLM ROWs for the
necessary physical infrastructure and for the use and occupancy of the
pore space itself. The BLM has published a policy defining access to
pore space on BLM lands, including clarification of Federal policy for
situations where the surface and pore space are under the control of
different Federal agencies.\584\
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\584\ National Policy for the Right-of-Way Authorizations
Necessary for Site Characterization, Capture, Transportation,
Injection, and Permanent Geologic Sequestration of Carbon Dioxide in
Connection with Carbon Sequestration Projects. BLM IM 2022-041
Instruction Memorandum, June 8, 2022. https://www.blm.gov/policy/im-2022-041.
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States have established legislation and regulations defining pore
space ownership and providing clarification to prospective users of
surface pore space. For example, in North Dakota, the surface owner
also owns the pore space underlying their surface estate.\585\ North
Dakota state courts have determined that in situations where the
surface ownership and mineral ownership have been legally severed the
mineral estate is the dominant estate and has the right to use as much
of the surface estate as reasonably necessary. The North Dakota
legislature codified this interpretation in 2019.\586\ Summit Carbon
Solutions, which is developing a carbon storage hub in North Dakota to
store an estimated one billion tons of CO2, indicated that
they had secured the majority of the pore space needed through long
term leases with landowners.\587\ Wyoming defines ownership of pore
space underlying surfaces within the state.\588\ Other states have also
established laws, implementing regulations and guidance defining
ownership and access to pore space. The EPA notes that many states are
actively enacting legislation addressing pore space ownership. See
e.g., Wyoming H.B. No. 89 (2008) (Wyo. Stat. Sec. 34-1-152); Montana
S.B. No. 498 (2009) (Mont. Code Ann. 82-11-180); North Dakota S.B. No.
2139 (2009) (N.D. Cent. Code Sec. 47-31-03); Kentucky H.B. 259 (2011)
(Ky. Rev. Stat. Ann. Sec. 353.800); West Virginia H.B. 4491 (2022) (W.
Va. Code Sec. 22-11B-18); California S.B. No. 905 (2022) (Cal. Pub.
Res. Code Sec. 71462); Indiana Public Law 163 (2022) (Ind. Code Sec.
14-39-2-3); Utah H.B. 244 (2022) (Utah Code Sec. 40-6-20.5).
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\585\ ND DMR 2023. Pore Space in North Dakota. North Dakota
Department of Mineral Resources https://www.dmr.nd.gov/oilgas/ND_DMR_Pore_Space_Information.pdf.
\586\ Ibid.
\587\ Summit Carbon Solutions. (2021). Summit Carbon Solutions
Announces Significant Carbon Storage Project Milestones. (2021).
https://summitcarbonsolutions.com/summit-carbon-solutions-announces-significant-carbon-storage-project-milestones/.
\588\ Wyo. Stat Sec. 34-1-152 (2022).
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Liability during operation is usually assumed by the project
operator, so liability concerns primarily arise after the period of
operations. Research has previously shown that the environmental risk
is greatest before injection stops.\589\ In terms of long-term
liability and permittee obligations under the SDWA, the EPA's Class VI
regulations impose various requirements on permittees even after
injection ceases, including regarding injection well plugging (40 CFR
146.92), post-injection site care (PISC), and site closure (40 CFR
146.93). The default time period for post-injection site care is 50
years, during which the permittee must monitor the position of the
CO2 plume and pressure front and demonstrate that USDWs are
not being endangered. 40 CFR 146.93. The permittee must also generally
maintain financial responsibility sufficient to cover injection well
plugging, corrective action, emergency and remedial response, PISC, and
site closure until the permitting authority approves site closure. 40
CFR 146.85(a)&(b). Even after the former permittee has fulfilled all
its UIC regulatory obligations, it may still be held liable for
previous regulatory noncompliance, such as where the permittee provided
erroneous data to support approval of site closure. A former permittee
may always be subject to an order that the EPA Administrator deems
necessary to protect public health if there is fluid migration that
causes or threatens imminent and substantial endangerment to a USDW. 42
U.S.C. 300i; 40 CFR 144.12(e).
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\589\ Benson, S.M. (2007). Carbon dioxide capture and storage:
research pathways, progress and potential. Presentation given at the
Global Climate & Energy Project Annual Symposium, October 1, 2007.
https://drive.google.com/file/d/1ZvfRW92OqvBBAFs69SPHIWoYFGySMgtD/view.
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The EPA notes that many states are enacting legislation addressing
long term liability. See e.g., Montana S.B. No. 498 (2009) (Mont. Code
Ann. 82-11-183); Texas H.B. 1796 (2009) (Tex. Health & Safety Code Ann.
Sec. 382.508); North Dakota S.B. No. 2095 (2009) (N.D. Cent. Code
Sec. 38-22-17); Kansas H.B.
[[Page 39874]]
2418 (2010) (Kan. Stat. Ann. Sec. 55-1637(h)); Wyoming S.F. No. 47
(2022) (Wyo. Stat. Sec. Sec. 35-11-319); Louisiana H.B. 661 (2009) &
H.B. 571 (2023) (La. Stat. Ann. Sec. 30:1109). Because states are
actively working to address pore space and liability uncertainties, the
EPA does not believe these to be issues that would delay project
implementation beyond the timelines discussed in this preamble.
(E) Compliance Date for Long-Term Coal-Fired Steam Generating Units
The EPA proposed a January 1, 2030 compliance date for long-term
coal fired steam generating units subject to a CCS BSER. That
compliance date assumed installation of CCS was concurrent with
development of state plans. While several commenters were supportive of
the proposed compliance date, the EPA also received comments on the
proposed rule that stated that the proposed compliance date was not
achievable. Commenters referenced longer project timelines for
CO2 capture. Commenters also requested that the EPA should
account for the state plan process in determining the appropriate
compliance date.
The EPA has considered the comments and information available and
is finalizing a compliance date of January 1, 2032, for long-term coal-
fired steam generating units. The EPA is also finalizing a mechanism
for a 1-year compliance date extension in cases where a source faces
delays outside its control, as detailed in section X.C.1.d of this
preamble. The justification for the January 1, 2032 compliance date
does not require substantial work to be done during the state planning
process. Rather, the justification for the compliance date reflects the
assumption that only the initial feasibility work which is necessary to
inform the state planning process would occur during state plan
development, with the start of more substantial work beginning after
the due date for state plan submission, and a longer timeline for
installation of CCS than at proposal. In total, this allows for 6 years
and 7 months for both initial feasibility and more substantial work to
occur after issuance of this rule. This is consistent with the
approximately 6 years from start to finish for Boundary Dam Unit 3 and
Petra Nova.
The timing for installation of CCS on existing coal-fired steam
generating units is based on the baseline project schedule for the
CO2 capture plant developed by Sargent and Lundy (S&L \590\
and a review of the available information for installation of
CO2 pipelines and sequestration sites.\591\ Additional
details on the timeline are in the TSD GHG Mitigation Measures for
Steam Generating Units, available in the docket. The dates for
intermediate steps are for reference. The specific sequencing of steps
may differ slightly, and, for some sources, the duration of one step
may be shorter while another may be longer, however the total duration
is expected to be the same. The resulting timeline is therefore an
accurate representation of the time necessary to install CCS in
general.
---------------------------------------------------------------------------
\590\ CO2 Capture Project Schedule and Operations
Memo, Sargent & Lundy (2024). Available in Docket ID EPA-HQ-OAR-
2023-0072.
\591\ Transport and Storage Timeline Summary, ICF (2024).
Available in Docket ID EPA-HQ-OAR-2023-0072.
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The EPA assumes that feasibility work, amounting to less than 1
year (June 2024 through June 2025) for each component of CCS (capture,
transport, and storage) occurs during the state plan development period
(June 2024 through June 2026). This feasibility work is limited to
initial conceptual design and other preliminary tasks, and the costs of
the feasibility work in general are substantially less than other
components of the project schedule. The EPA determined that it was
appropriate to assume that this work would take place during the state
plan development period because it is necessary for evaluating the
controls that the state may determine to be appropriate for a source
and is necessary for determining the resulting standard of performance
that the state may apply to the source on the basis of those controls.
In other words, without such feasibility and design work, it would be
very difficult for a state to determine whether CCS is appropriate for
a given source or the resulting standard of performance. While the EPA
accounts for up to 1 year for feasibility for the capture plant, the
S&L baseline schedule estimates this initial design activity can be
completed in 6 months. For the capture plant, feasibility includes a
preliminary technical evaluation to review the available utilities and
siting footprint for the capture plant, as well as screening of the
available capture technologies and vendors for the project, with an
associated initial economic estimate. For sequestration, in many cases,
general geologic characterization of regional areas has already been
conducted by U.S. DOE and regional initiatives; however, the EPA
assumes an up to 1 year period for a storage complex feasibility study.
For the pipeline, the feasibility includes the initial pipeline routing
analysis, taking less than 1 year. This exercise involves using
software to review existing right-of-way and other considerations to
develop an optimized pipeline route. Inputs to that analysis have been
made publicly available by DOE in NETL's Pipeline Route Planning
Database.\592\
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\592\ NETL Develops Pipeline Route Planning Database To Guide
CO2 Transport Decisions. May 31, 2023. https://netl.doe.gov/node/12580.
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When state plans are submitted 24 months after publication of the
final rule, requirements included within those state plans should be
effective at the state level. On that basis, the EPA assumes that
sources installing CCS are fully committed, and more substantial work
(e.g., FEED study for the capture plant, permitting, land use and
right-of-way acquisition) resumes in June 2026. The EPA notes, however,
that it would be possible that a source installing CCS would choose to
continue these activities as soon as the initial feasibility work is
completed even if not yet required to do so, rather than wait for state
plan submission to occur for the reasons explained in full below.
Of the components of CCS, the CO2 capture plant is the
more technically involved and time consuming, and therefore is the
primary driver for determining the compliance date. The EPA assumes
substantial work commences only after submission due date for state
plans. The S&L baseline timeline accounts for 5.78 years (301 weeks)
for final design, permitting, and installation of the CO2
capture plant. First, the EPA describes the timeline that is consistent
with the S&L baseline for substantial work. Subsequently, the EPA
describes the rationale for slight adjustments that can be made to that
timeline based upon an examination of actual project timelines.
In the S&L baseline, substantial work on the CO2 capture
plant begins with a 1-year FEED study (June 2026 to June 2027). The
information developed in the FEED study is necessary for finalizing
commercial arrangements. In the S&L baseline, the commercial
arrangements can take up to 9 months (June 2027 to March 2028).
Commercial arrangements include finalizing funding as well as
finalizing contracts with a CO2 capture technology provider
and engineering, procurement, and construction companies. The S&L
baseline accounts for 1 year for permitting, beginning when commercial
arrangements are nearly complete (December 2027 to December 2028).
After commercial arrangements are complete, a 2-year period for
engineering and procurement begins (March 2028 to March 2030).
[[Page 39875]]
Detailed engineering starts after commercial arrangements are complete
because engineers must consider details regarding the selected
CO2 capture technology, equipment providers, and
coordination with construction. Shortly after permitting is complete, 6
months of sitework (March 2029 to September 2029) occur. Sitework is
followed by 2 years of construction (July 2029 to July 2031).
Approximately 8 months prior to the completion of construction, a
roughly 14 month (60 weeks) period for startup and commissioning begins
(January 2031 to March 2032).
In many cases, the EPA believes that sources are positioned to
install CO2 capture on a slightly faster timeline than the
baseline S&L timeline detailed in the prior paragraph, because CCS
projects have been developed in a shorter timeframe. Including these
minor adjustments, the total time for detailed engineering,
procurement, construction, startup and commissioning is 4 years, which
is consistent with completed projects (Boundary Dam Unit 3 and Petra
Nova) and project schedules developed in completed FEED studies, see
the final TSD, GHG Mitigation Measures for Steam Generating Units for
additional details. In addition, the IRC tax credits incentivize
sources to begin complying earlier to reap economic benefits earlier.
Sources that have already completed feasibility or FEED studies, or
that have FEED studies ongoing are likely to be able to have CCS fully
operational well in advance of January 1, 2032. Ongoing projects have
planned dates for commercial operation that are much earlier. For
example, Project Diamond Vault has plans to be fully operational in
2028.\593\ While the EPA assumes FEED studies start after the date for
state plan submission, in practice sources are likely to install
CO2 capture as expeditiously as practicable. Moreover, the
preceding timeline is derived from project schedules developed in the
absence of any regulatory impetus. Considering these factors, sources
have opportunities to slightly condense the duration, overlap, or
sequencing of steps so that the total duration for completing
substantial work on the capture plant is reduced by 2 months. For
example, by expediting the duration for commercial arrangements from 9
months to 7 months, reasonably assuming sources immediately begin
sitework as soon as permitting is complete, and accounting for 13
months (rather than 14) for startup and testing, the CO2
capture plant will be fully operational by January 2032. Therefore, the
EPA concludes that CO2 capture can be fully operational by
January 1, 2032. To the extent additional time is needed to take into
account the particular circumstances of a particular source, the state
may take those circumstances into account to provide a different
compliance schedule, as detailed in section X.C.2 of this preamble.
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\593\ Project Diamond Vault Overview. https://www.cleco.com/docs/default-source/diamond-vault/project_diamond_vault_overview.pdf.
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The EPA also notes that there is additional time for permitting
than described in the S&L baseline. The key permitting that affects the
timeline are air permits because of the permits' impact on the ability
to construct and operate the CCS capture equipment, in which the EPA is
the expert in. The S&L baseline assumes permitting starts after the
FEED study is complete while commercial arrangements are ongoing,
however permitting can begin earlier allowing a more extended period
for permitting. Examples of CCS permitting being completed while FEED
studies are on-going include the air permits for Project Tundra,
Baytown Energy Center, and Deer Park Energy Center. Therefore, while
the FEED study is on-going, the EPA assumes that a 2-year process for
permitting can begin.
The EPA's compliance deadline assumes that storage and pipelines
for the captured CO2 can be installed concurrently with
deployment of the capture system. Substantial work on the storage site
starts with 3 years (June 2026 to June 2029) for final site
characterization, pore-space acquisition, and permitting, including at
least 2 years for permitting of Class VI wells during that period.
Lastly, construction for sequestration takes 1 year (June 2029 to June
2030). While the EPA assumes that storage can be permitted and
constructed in 4 years, the EPA notes that there is at least an
additional 12 months of time available to complete construction of the
sequestration site without impacting progress of the other components.
The EPA assumes the substantial work on the pipeline lags the start
of substantial work on the storage site by 6 months. After the 1 year
of feasibility work prior to state plan submission, the general
timeline for the CO2 pipeline assumes up to 3 years for
final routing, permitting activities, and right-of-way acquisition
(December 2026 to December 2029). Lastly, there are 1.5 years for
pipeline construction (December 2029 to June 2031).\594\
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\594\ The summary timeline for CO2 pipelines assumes
feasibility for pipelines is 1 year, followed by 1.5 years for
permitting, with the pipeline feasibility beginning 1 year after
permitting for sequestration starts. The EPA assumes initial
pipeline feasibility occurs up-front, with a longer period for final
routing, permitting, and right-of-way acquisition.
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The EPA does not assume that CCS projects are, in general, subject
to NEPA. NEPA review is required for reasons including sources
receiving federal funding (e.g., through USDA or DOE) or projects on
federal lands. NEPA may also be triggered for a CCS project if NEPA
compliance is necessary for construction of the pipeline, such as where
necessary because of a Clean Water Act section 404 permit, or for
sequestration. Generally, if one aspect of a project is subject to
NEPA, then the other project components could be as well. In cases
where a project is subject to NEPA, an environmental assessment (EA)
that takes 1 year, can be finalized concurrently during the permitting
periods of each component of CCS (capture, pipeline, and
sequestration). However, the EPA notes that the final timeline can also
accommodate a concurrent 2-year period if an EIS were required under
NEPA across all components of the project. The EPA also notes that, in
some circumstances, NEPA review may begin prior to completion of a FEED
study. For Petra Nova, a notice of intent to issue an EIS was published
on November 14, 2011, and the record of decision was issued less than 2
years later, on May 23, 2013,\595\ while the FEED study was completed
in 2014.
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\595\ Petra Nova W.A. Parish Project. https://www.energy.gov/fecm/petra-nova-wa-parish-project.
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Based on this detailed analysis, the EPA has concluded that January
1, 2032, is an achievable compliance date for CCS on existing coal-
fired steam generating units that takes into account the state plan
development period, as well as the technical and bureaucratic steps
necessary to install and implement CCS and is consistent with other
expert estimates and real-world experience.
(F) Long-Term Coal-Fired Steam Generating Units Potentially Subject to
This Rule
In this section of the preamble, the EPA estimates the size of the
inventory of coal-fired power plants in the long-term subcategory
likely subject to CCS as the BSER. Considering that capacity, the EPA
also describes the distance to storage for those sources.
(1) Capacity of Units Potentially Subject to This Rule
First, the EPA estimates the total capacity of units that are
currently operating and that have not announced plans to retire by
2039, or to cease firing
[[Page 39876]]
coal by 2030. Starting from that first estimate, the EPA then estimates
the capacity of units that would likely be subject to the CCS
requirement, based on unit age, industry trends, and economic factors.
Currently, there are 181 GW of coal-fired steam generating
units.\596\ About half of that capacity, totaling 87 GW, have announced
plans to retire before 2039, and an additional 13 GW have announced
plans to cease firing coal by that time. The remaining amount, 81 GW,
are likely to be the most that could potentially be subject to
requirements based on CCS.
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\596\ EIA December 2023 Preliminary Monthly Electric Generator
Inventory. https://www.eia.gov/electricity/data/eia860m/.
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However, the capacity of affected coal-fired steam generating units
that would ultimately be subject to a CCS BSER is likely approximately
40 GW. This determination is supported by several lines of analysis of
the historical data on the size of the fleet over the past several
years. Historical trends in the coal-fired generation fleet are
detailed in section IV.D.3 of this preamble. As coal-fired units age,
they become less efficient and therefore the costs of their electricity
go up, rendering them even more competitively disadvantaged. Further,
older sources require additional investment to replace worn parts.
Those circumstances are likely to continue through the 2030s and beyond
and become more pronounced. These factors contribute to the historical
changes in the size of the fleet.
One way to analyze historical changes in the size of the fleet is
based on unit age. As the average age of the coal-fired fleet has
increased, many sources have ceased operation. From 2000 to 2022, the
average age of a unit that retired was 53 years. At present, the
average age of the operating fleet is 45 years. Of the 81 GW that are
presently operating and that have not announced plans to retire or
convert to gas prior to 2039, 56 GW will be 53 years or older by
2039.\597\
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\597\ 81 GW is derived capacity, plant type, and retirement
dates as represented in EPA NEEDS database. Total amount of covered
capacity in this category may ultimately be slightly less
(approximately) due to CHP-related exemptions.
---------------------------------------------------------------------------
Another line of analysis is based on the rate of change of the size
of the fleet. The final TSD, Power Sector Trends, available in the
rulemaking docket, includes analysis showing sharp and steady decline
in the total capacity of the coal-fired steam generating fleet. Over
the last 15 years (2009-2023), average annual coal retirements have
been 8 GW/year. Projecting that retirements will continue at
approximately the same pace from now until 2039 is reasonable because
the same circumstances will likely continue or accelerate further given
the incentives under the IRA. Applying this level of annual retirement
would result in 45 GW of coal capacity continuing to operate by 2039.
Alternatively, the TSD also includes a graph that shows what the fleet
would look like assuming that coal units without an announced
retirement date retire at age 53 (the average retirement age of units
over the 2000-2022 period). It shows that the amount of coal-fired
capacity that remains in operation by 2039 is 38 GW.
The EPA also notes that it is often the case that coal-fired units
announce that they plan to retire only a few years in advance of the
retirement date. For instance, of the 15 GW of coal-fired EGUs that
reported a 2022 retirement year in DOE's EIA Form 860, only 0.5 GW of
that capacity had announced its retirements plans when reporting in to
the same EIA-860 survey 5 years earlier, in 2017.\598\ Thus, although
many coal-fired units have already announced plans to retire before
2039, it is likely that many others may anticipate retiring by that
date but have not yet announced it.
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\598\ The survey Form EIA-860 collects generator-level specific
information about existing and planned generators and associated
environmental equipment at electric power plants with 1 megawatt or
greater of combined nameplate capacity. Data available at https://www.eia.gov/electricity/data/eia860/.
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Finally, the EPA observes that modeling the baseline circumstances,
absent this final rule, shows additional retirements of coal-fired
steam generating units. At the end of 2022, there were 189 GW of coal
active in the U.S. By 2039, the IPM baseline projects that there will
be 42 GW of operating coal-fired capacity (not including coal-to-gas
conversions). Between 2023-2039, 95 GW of coal capacity have announced
retirement and an additional 13 have announced they will cease firing
coal. Thus, of the 81 GW that have not announced retirement or
conversion to gas by 2039, the IPM baseline projects 39 GW will retire
by 2039 due to economic reasons.
For all these reasons, the EPA considers that it is realistic to
expect that 42 GW of coal-fired generating will be operating by 2039--
based on announced retirements, historical trends, and model
projections--and therefore constitutes the affected sources in the
long-term subcategory that would be subject to requirements based on
CCS. It should be noted that the EPA does not consider the above
analysis to predict with precision which units will remain in operation
by 2039. Rather, the two sets of sources should be considered to be
reasonably representative of the inventory of sources that are likely
to remain in operation by 2039, which is sufficient for purposes of the
BSER analysis that follows.
(2) Distance to Storage for Units Potentially Subject to This Rule
The EPA believes that it is conservative to assume that all 81 GW
of capacity with planned operation during or after 2039 would need to
construct pipelines to connect to sequestration sites. As detailed in
section VII.B.2 of this preamble, the EPA is finalizing an exemption
for coal-fired sources permanently ceasing operation by January 1,
2032. About 42 percent (34 GW) of the existing coal-fired steam
generation capacity that is currently in operation and has not
announced plans to retire prior to 2039 will be 53 years or older by
2032. As discussed in section VII.C.1.a.i(F), from 2000 to 2022, the
average age of a coal unit that retired was 53 years old. Therefore,
the EPA anticipates that approximately 34 GW of the total capacity may
permanently cease operation by 2032 despite not having yet announced
plans to do so. Furthermore, of the coal-fired steam generation
capacity that has not announced plans to cease operation before 2039
and is further than 100 km (62 miles) of a potential saline
sequestration site, 45 percent (7 GW) will be over 53 years old in
2032. Therefore, it is possible that much of the capacity that is
further than 100 km (62 miles) of a saline sequestration site and has
not announced plans to retire will permanently cease operation due to
age before 2032 and thus the rule would not apply to them. Similarly,
of the coal-fired steam generation capacity that has not announced
plans to cease operation before 2039 and is further than 160 km (100
miles) of a potential saline sequestration site, 56 percent (4 GW) will
be over 53 years old in 2032. Therefore, the EPA notes that it is
possible that the majority of capacity that is further than 160 km (100
miles) of a saline sequestration and has not announced plans to retire
site will permanently cease operation due to age before 2032 and thus
be exempt from the requirements of this rule.
The EPA also notes that a majority (56 GW) of the existing coal-
fired steam generation capacity that is currently in operation and has
not announced plans to permanently cease operation prior to 2039 will
be 53 years or older by 2039. Of the coal-fired steam generation
capacity with planned operation during
[[Page 39877]]
or after 2039 that is not located within 100 km (62 miles) of a
potential saline sequestration site, the majority (58 percent or 9 GW)
of the units will be 53 years or older in 2039.\599\ Consequently, the
EPA believes that many of these units may permanently cease operation
due to age prior to 2039 despite not at this point having announced
specific plans to do so, and thereby would likely not be subject to a
CCS BSER.
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\599\ Sequestration potential as it relates to distance from
existing resources is a key part of the EPA's regular power sector
modeling development, using data from DOE/NETL studies. For details,
please see chapter 6 of the IPM documentation available at:. https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
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(G) Resources and Workforce To Install CCS
Sufficient resources and an available workforce are required for
installation and operation of CCS. Raw materials necessary for CCS are
generally available and include common commodities such as steel and
concrete for construction of the capture plant, pipelines, and storage
wells.
Drawing on data from recently published studies, the DOE completed
an order-of-magnitude assessment of the potential requirements for
specialized equipment and commodity materials for retrofitting existing
U.S. coal-fueled EGUs with CCS.\600\ Specialized equipment analyzed
included absorbers, strippers, heat exchangers, and compressors.
Commodity materials analyzed included monoethanolamine (MEA) solvent
for carbon capture, triethylene glycol (TEG) for carbon dioxide drying,
and steel and cement for construction of certain aspects of the CCS
value chain.\601\ The DOE analyzed one scenario in which 42 GW of coal-
fueled EGUs are retrofitted with CCS and a second scenario in which 73
GW of coal-fueled EGUs are retrofitted with CCS.\602\ The analysis
determined that in both scenarios, the maximum annual commodity
requirements to construct and operate the CCS systems are likely to be
much less than their respective global production rates. The maximum
requirements are expected to be at least one order of magnitude lower
than global annual production for all of the commodities considered
except MEA, which was estimated to be approximately 14 percent of
global annual production in the 42 GW scenario and approximately 24
percent of global annual production in the 73 GW scenario.\603\ For
steel and cement, the maximum annual requirements are also expected to
be at least one order of magnitude lower than U.S. annual production
rates. Finally, the DOE analysis determined that it is unlikely that
the deployment scenarios would encounter any bottlenecks in the
supplies of specialized equipment (absorbers, strippers, heat
exchangers, and compressors) because of the large pool of potential
suppliers.
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\600\ DOE. Material Requirements for Carbon Capture and Storage
Retrofits on Existing Coal-Fueled Electric Generating Units. https://www.energy.gov/policy/articles/material-requirements-carbon-capture-and-storage-retrofits-existing-coal-fueled.
\601\ Steel requirements were assessed for carbon capture,
transport and storage, but cement requirements were only assessed
for capture and storage.
\602\ DOE analyzed the resources--including specialized
equipment, commodity materials, and, as discussed below, workforce,
necessary for 73 GW of coal capacity to install CCS because that is
the amount that has not announced plans to retire by January 1,
2040. As indicated in the final TSD, Power Sector Trends, a somewhat
larger amount--81 GW--has not announced plans to retire or cease
firing coal by January 1, 2039, and it is this latter amount that is
the maximum that, at least in theory, could be subject to the CCS
requirement. DOE's conclusions that sufficient resources are
available also hold true for the larger amount.
\603\ Although the assessment assumed that all of the CCS
deployments would utilize MEA-based carbon capture technologies,
future CCS deployments could potentially use different solvents, or
capture technologies that do not use solvents, e.g., membranes,
sorbents. A number of technology providers have solvents that are
commercially available, as detailed in section VII.C.1.a.i.(B)(3) of
this preamble. In addition, a 2022 DOE carbon capture supply chain
assessment concluded that common amines used in carbon capture have
robust and resilient supply chains that could be rapidly scaled,
with low supply chain risk associated with the main inputs for
scale-up. See U.S. Department of Energy (DOE). Supply Chain Deep
Dive Assessment: Carbon Capture, Transport & Storage. https://www.energy.gov/sites/default/files/2022-02/Carbon%20Capture%20Supply%20Chain%20Report%20-%20Final.pdf.
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The workforce necessary for installing and operating CCS is readily
available. The required workforce includes construction, engineering,
manufacturing, and other skilled labor (e.g., electrical, plumbing, and
mechanical trades). The existing workforce is well positioned to meet
the demand for installation and operation of CCS. Many of the skills
needed to build and operate carbon capture plants are similar to those
used by workers in existing industries, and this experience can be
leveraged to support the workforce needed to deploy CCS. In addition,
government programs, industry workforce investments, and IRC section
45Q prevailing wage and apprenticeship provisions provide additional
significant support to workforce development and demonstrate that the
CCS industry likely has the capacity to train and expand the available
workforce to meet future needs.\604\
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\604\ DOE. Workforce Analysis of Existing Coal Carbon Capture
Retrofits. https://www.energy.gov/policy/articles/workforce-analysis-existing-coal-carbon-capture-retrofits.
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Overall, quantitative estimates of workforce needs indicates that
the total number of jobs needed for deploying CCS on coal power plants
is significantly less than the size of the existing workforce in
adjacent occupations with transferrable skills in the electricity
generation and fuels industries. The majority of direct jobs,
approximately 90 percent, are expected to be in the construction of
facilities, which tend to be project-based. The remaining 10 percent of
jobs are expected to be tied to ongoing facility operations and
maintenance.\605\ Recent project-level estimates bear this out. The
Boundary Dam CCS facility in Canada employed 1,700 people at peak
construction.\606\ A recent workforce projection estimates average
annual jobs related to investment in carbon capture retrofits at coal
power plants could range from 1,070 to 1,600 jobs per plant. A DOE
memorandum estimates that 71,400 to 107,100 average annual jobs
resulting from CCS project investments--across construction, project
management, machinery installers, sales representatives, freight, and
engineering occupations--would likely be needed over a five-year
construction period \607\ to deploy CCS at
[[Page 39878]]
a subset of coal power plants. The memorandum further estimates that
116,200 to 174,300 average annual jobs would likely be needed if CCS
were deployed at all coal-fired EGUs that currently have no firm
commitment to retire or convert to natural gas by 2040.\608\ For
comparison, the DOE memorandum further categorizes potential workforce
needs by occupation, and estimates 11,420 to 27,890 annual jobs for
construction trade workers, while the U.S. Energy and Employment Report
estimates that electric power generation and fuels accounted for more
than 292,000 construction jobs in 2022, which is an order of magnitude
greater than the potential workforce needs for CCS deployment under
this rule. Overall energy-related construction activities across the
entire energy industry accounted for nearly 2 million jobs, or 25
percent of all construction jobs in 2022, indicating that there is a
very large pool of workers potentially available.\609\
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\605\ Ibid.
\606\ SaskPower, ``SaskPower CCS.'' https://unfccc.int/files/bodies/awg/application/pdf/01_saskatchewan_environment_micheal_monea.pdf. For corroboration, we
note similar employment numbers for two EPAct-05 assisted projects:
Petra Nova estimated it would need approximately 1,100 construction-
related jobs and up to 20 jobs for ongoing operations. National
Energy Technology Laboratory and U.S. Department of Energy. W.A.
Parish Post-Combustion CO2 Capture and Sequestration Project, Final
Environmental Impact Statement. https://www.energy.gov/sites/default/files/EIS-0473-FEIS-Summary-2013_1.pdf. Project Tundra
projects a peak labor force of 600 to 700. National Energy
Technology Laboratory and U.S. Department of Energy. Draft
Environmental Assessment for North Dakota CarbonSAFE: Project
Tundra. https://www.energy.gov/sites/default/files/2023-08/draft-ea-2197-nd-carbonsafe-chapters-2023-08.pdf.
\607\ For the purposes of evaluating the actual workforce and
resources necessary for installation of CCS, the five-year
assumption in the DOE memo is reasonable. The representative
timeline for CCS includes an about 3-year period for construction
activities (including site work, construction, and startup and
testing) across the components of CCS (capture, pipeline, and
sequestration), beginning at the end of 2028. Many sources are well
positioned to install CCS, having already completed feasibility
work, FEED studies, and/or permitting, and could thereby reasonably
start construction activities (still 3-years in duration) by the
beginning of 2028 or earlier and, as a practical matter, would
likely do so notwithstanding the requirements of this rule given the
strong economic incentives provided by the tax credit. The
representative timeline also makes conservative assumptions about
the pre-construction activities for pipelines and sequestration, and
for many sources construction of those components could occur
earlier. Finally, to provide greater regulatory certainty and
incentivize the installation of controls, the EPA is finalizing a
limited one-year compliance date extension mechanism for certain
circumstances as detailed in section X.C.1.d of the preamble, and it
would also be reasonable to assume that, in practice, some sources
use that mechanism. Considering these factors, evaluating workforce
and resource requirements over a five-year period is reasonable.
\608\ DOE. Workforce Analysis of Existing Coal Carbon Capture
Retrofits. https://www.energy.gov/policy/articles/workforce-analysis-existing-coal-carbon-capture-retrofits.
\609\ U.S. Department of Energy. United States Energy &
Employment Report 2023. https://www.energy.gov/sites/default/files/2023-06/2023%20USEER%20REPORT-v2.pdf.
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As noted in section VII.C.1.a.i(F), the EPA determined that the
population of sources without announced plans to cease operation or
discontinue coal-firing by 2039, and that is therefore potentially
subject to a CCS BSER, is not more than 81 GW, as indicated in the
final TSD, Power Sector Trends. The DOE CCS Commodity Materials and
Workforce Memos evaluated material resource and workforce needs for a
similar capacity (about 73 GW), and determined that the resources and
workforce available are more than sufficient, in most cases by an order
of magnitude. Considering these factors, and the similar scale of the
population of sources considered, the EPA therefore concludes that the
workforce and resources available are more than sufficient to meet the
demands of coal-fired steam generating units potentially subject to a
CCS BSER.
(H) Determination That CCS Is ``Adequately Demonstrated''
As discussed in detail in section V.C.2.b, pursuant to the text,
context, legislative history, and judicial precedent interpreting CAA
section 111(a)(1), a technology is ``adequately demonstrated'' if there
is sufficient evidence that the EPA may reasonably conclude that a
source that applies the technology will be able to achieve the
associated standard of performance under the reasonably expected
operating circumstances. Specifically, an adequately demonstrated
standard of performance may reflect the EPA's reasonable expectation of
what that particular system will achieve, based on analysis of
available data from individual commercial scale sources, and, if
necessary, identifying specific available technological improvements
that are expected to improve performance.\610\ The law is clear in
establishing that at the time a section 111 rule is promulgated, the
system that the EPA establishes as BSER need not be in widespread use.
Instead, the EPA's responsibility is to determine that the demonstrated
technology can be implemented at the necessary scale in a reasonable
period of time, and to base its requirements on this understanding.
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\610\ A line of cases establishes that the EPA may extrapolate
based on its findings and project technological improvements in a
variety of ways. First, the EPA may reasonably extrapolate from
testing results to predict a lower emissions rate than has been
regularly achieved in testing. See Essex Chem. Corp. v. Ruckelshaus,
486 F.2d 427, 433 (D.C. Cir. 1973). Second, the EPA may forecast
technological improvements allowing a lower emissions rate or
effective control at larger plants than those previously subject to
testing, provided the agency has adequate knowledge about the needed
changes to make a reasonable prediction. See Sierra Club v. Costle
657 F.2d 298 (1981). Third, the EPA may extrapolate based on testing
at a particular kind of source to conclude that the technology at
issue will also be effective at a different, related, source. See
Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999).
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In this case, the EPA acknowledged in the proposed rule, and
reaffirms now, that sources will require some amount of time to install
CCS. Installing CCS requires the building of capture facilities and
pipelines to transport captured CO2 to sequestration sites,
and the development of sequestration sites. This is true for both
existing coal plants, which will need to retrofit CCS, and new gas
plants, which must incorporate CCS into their construction planning. As
the EPA explained at proposal, D.C. Circuit caselaw supports this
approach.\611\ Moreover, the EPA has determined that there will be
sufficient resources for all coal-fired power plants that are
reasonably expected to be operating as of January 1, 2039, to install
CCS. Nothing in the comments alters the EPA's view of the relevant
legal requirements related to the EPA's determination of time necessary
to allow for adoption of the system.
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\611\ There, EPA cited Portland Cement v. Ruckelshaus, for the
proposition that ``D.C. Circuit caselaw supports the proposition
that CAA section 111 authorizes the EPA to determine that controls
qualify as the BSER--including meeting the `adequately demonstrated'
criterion--even if the controls require some amount of `lead time,'
which the court has defined as `the time in which the technology
will have to be available.' '' See 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, 88
FR 33240, 33289 (May 23, 2023) (quoting Portland Cement Ass'n v.
Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973)).
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With all of the above in mind, the preceding sections show that CCS
technology with 90 percent capture is clearly adequately demonstrated
for coal-fired steam generating units, that the 90 percent standard is
achievable,\612\ and that it is reasonable for the EPA to determine
that CCS can be deployed at the necessary scale in the compliance
timeframe.
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\612\ The concepts of ``adequately demonstrated'' and
``achievable'' are closely related. As the D.C. Circuit explained in
Essex Chem. Corp. v. Ruckelshaus, ``[i]t is the system which must be
adequately demonstrated and the standard which must be achievable.''
486 F.2d 427, 433 (1973).
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(1) EPAct05
In the proposal, the EPA noted that in the 2015 NSPS, the EPA had
considered coal-fired industrial projects that had installed at least
some components of CCS technology. In doing so, the EPA recognized that
some of those projects had received assistance in the form of grants,
loan guarantees, and Federal tax credits for investment in ``clean coal
technology,'' under provisions of the Energy Policy Act of 2005
(``EPAct05''). See 80 FR 64541-42 (October 23, 2015). (The EPA refers
to projects that received assistance under that legislation as
``EPAct05-assisted projects.'') The EPA further recognized that the
EPAct05 included provisions that constrained how the EPA could rely on
EPAct05-assisted projects in determining whether technology is
adequately demonstrated for the purposes of CAA section 111.\613\
[[Page 39879]]
In the 2015 NSPS, the EPA went on to provide a legal interpretation of
those constraints. Under that legal interpretation, ``these provisions
[in the EPAct05] . . . preclude the EPA from relying solely on the
experience of facilities that received [EPAct05] assistance, but [do]
not . . . preclude the EPA from relying on the experience of such
facilities in conjunction with other information.'' \614\ Id. at 64541-
42. In this action, the EPA is adhering to the interpretation of these
provisions that it announced in the 2015 NSPS.
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\613\ The relevant EPAct05 provisions include the following:
Section 402(i) of the EPAct05, codified at 42 U.S.C. 15962(a),
provides as follows: ``No technology, or level of emission
reduction, solely by reason of the use of the technology, or the
achievement of the emission reduction, by 1 or more facilities
receiving assistance under this Act, shall be considered to be
adequately demonstrated [ ] for purposes of section 111 of the Clean
Air Act. . . .'' IRC section 48A(g), as added by EPAct05 1307(b),
provides as follows: ``No use of technology (or level of emission
reduction solely by reason of the use of the technology), and no
achievement of any emission reduction by the demonstration of any
technology or performance level, by or at one or more facilities
with respect to which a credit is allowed under this section, shall
be considered to indicate that the technology or performance level
is adequately demonstrated [ ] for purposes of section 111 of the
Clean Air Act. . . .'' Section 421(a) states: ``No technology, or
level of emission reduction, shall be treated as adequately
demonstrated for purpose [sic] of section 7411 of this title, . . .
solely by reason of the use of such technology, or the achievement
of such emission reduction, by one or more facilities receiving
assistance under section 13572(a)(1) of this title.''
\614\ In the 2015 NSPS, the EPA adopted several other legal
interpretations of these EPAct05 provisions as well. See 80 FR 64541
(October 23, 2015).
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Some commenters criticized the legal interpretation that the EPA
advanced in the 2015 NSPS, and others supported the interpretation. The
EPA has responded to these comments in the Response to Comments
Document, available in the docket for this rulemaking.
ii. Costs
The EPA has analyzed the costs of CCS for existing coal-fired long-
term steam generating units, including costs for CO2
capture, transport, and sequestration. The EPA has determined costs of
CCS for these sources are reasonable. The EPA also evaluated costs
assuming shorter amortization periods. As elsewhere in this section of
the preamble, costs are presented in 2019 dollars. In sum, the costs of
CCS are reasonable under a variety of metrics. The costs of CCS are
reasonable as compared to the costs of other controls that the EPA has
required for these sources. And the costs of CCS are reasonable when
looking to the dollars per ton of CO2 reduced. The
reasonableness of CCS as an emission control is further reinforced by
the fact that some sources are projected to install CCS even in the
absence of any EPA rule addressing CO2 emissions--11 GW of
coal-fired EGUs install CCS in the modeling base case.
Specifically, the EPA assessed the average cost of CCS for the
fleet of coal-fired steam generating units with no announced retirement
or gas conversion prior to 2039. In evaluating costs, the EPA accounts
for the IRC section 45Q tax credit of $85/metric ton (assumes
prevailing wage and apprenticeship requirements are met), a detailed
discussion of which is provided in section VII.C.1.a.ii(C) of this
preamble. The EPA also accounts for increases in utilization that will
occur for units that apply CCS due to the incentives provided by the
IRC section 45Q tax credit. In other words, because the IRC section 45Q
tax credit provides a significant economic benefit, sources that apply
CCS will have a strong economic incentive to increase utilization and
run at higher capacity factors than occurred historically. This
assumption is confirmed by the modeling, which projects that sources
that install CCS run at a high capacity factor--generally, about 80
percent or even higher. The EPA notes that the NETL Baseline study
assumes 85 percent as the default capacity factor assumption for coal
CCS retrofits, noting that coal plants in market conditions supporting
baseload operation have demonstrated the ability to operate at annual
capacity factors of 85 percent or higher.\615\ This assumption is also
supported by observations of wind generators who receive the IRC
section 45 production tax credit who continue to operate even during
periods of negative power prices.\616\ Therefore, the EPA assessed the
costs for CCS retrofitted to existing coal-fired steam generating units
assuming an 80 percent annual capacity factor. Assuming an 80 percent
capacity factor and 12-year amortization period,\617\ the average costs
of CCS for the fleet are -$5/ton of CO2 reduced or -$4/MWh
of generation. Assuming at least a 12-year amortization period is
reasonable because any unit that installs CCS and seeks to maximize its
profitability will be incentivized to recoup the full value of the 12-
year tax credit.
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\615\ See Exhibit 2-18. https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_101422.pdf.
\616\ If those generators were not receiving the tax credit,
they otherwise would cease producing power during those periods and
result in a lower overall capacity factor. As noted by EIA, ``Wind
plants can offer negative prices because of the revenue stream that
results from the federal production tax credit, which generates tax
benefits whenever the wind plant is producing electricity, and
payments from state renewable portfolio or financial incentive
programs. These alternative revenue streams make it possible for
wind generators to offer their wind power into the wholesale
electricity market at prices lower than other generators, and even
at negative prices.'' https://www.eia.gov/todayinenergy/detail.php?id=16831.
\617\ A 12-year amortization period is consistent with the
period of time during which the IRC section 45Q tax credit can be
claimed.
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Therefore for long-term coal-fired steam generating units--ones
that operate after January 1, 2039--the costs of CCS are similar or
better than the representative costs of controls detailed in section
VII.C.1.a.ii(D) of this preamble (i.e., costs for SCRs and FGDs on EGUs
of $10.60 to $18.50/MWh and the costs in the 2016 NSPS regulating GHGs
for the Crude Oil and Natural Gas source category of $98/ton of
CO2e reduced (80 FR 56627; September 18, 2015)).
The EPA also evaluated the costs for shorter amortization periods,
considering the $/MWh and $/ton metrics, as well as other cost
indicators, as described in section VII.C.1.a.ii.(D). Specifically,
with an initial compliance date of January 1, 2032, sources operating
through the end of 2039 have at least 8 years to amortize costs. For an
80 percent capacity factor and an 8-year amortization period, the
average costs of CCS for the fleet are $19/ton of CO2
reduced or $18/MWh of generation; these costs are comparable to those
costs that the EPA has previously determined to be reasonable. Sources
operating through the end of 2040, 2041, and beyond (i.e., sources with
9, 10, or more years to amortize the costs of CCS) have even more
favorable average costs per MWh and per ton of CO2 reduced.
Sources ceasing operation by January 1, 2039, have 7 years to amortize
costs. For an 80 percent capacity factor and a 7-year amortization
period, the fleet average costs are $29/ton of CO2 reduced
or $28/MWh of generation; these average costs are less comparable on a
$/MWh of generation basis to those costs the EPA has previously
determined to be reasonable, but substantially lower than costs the EPA
has previously determined to be reasonable on a $/ton of CO2
reduced basis. The EPA further notes that the costs presented are
average costs for the fleet. For a substantial amount of capacity,
costs assuming a 7-year amortization period are comparable to those
costs the EPA has previously determined to be reasonable on both a $/
MWh basis (i.e., less than $18.50/MWh) and a $/ton basis (i.e. less
than $98/ton CO2e),\618\ and the EPA concludes that a substantial
amount of capacity can install CCS at reasonable cost with a 7-year
amortization
[[Page 39880]]
period.\619\ Considering that a significant number of sources can cost
reasonably install CCS even assuming a 7-year amortization period, the
EPA concludes that sources operating in 2039 should be subject to a CCS
BSER,\620\ and for this reason, is finalizing the date of January 1,
2039 as the dividing line between the medium-term and long-term
subcategories. Moreover, the EPA underscores that given the strong
economic incentives of the IRC section 45Q tax credit, sources that
install CCS will have strong economic incentives to operate at high
capacity for the full 12 years that the tax credit is available.
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\618\ See the final TSD, GHG Mitigation Measures for Steam
Generating Units for additional details.
\619\ As indicated in section 4.7.5 of the final TSD, Greenhouse
Gas Mitigation Measures for Steam Generating Units, 24 percent of
all coal-fired steam generating units in the long-term subcategory
would have CCS costs below both $18.50/MWh and $98/ton of
CO2 with a 7-year amortization period (Table 11), and
that amount increases to 40 percent for those coal-fired units that,
in light of their age and efficiency, are most likely to operate in
the long term (and thus be subject to the CCS-based standards of
performance) (Table 12). In addition, of the 9 units in the NEEDS
data base that have announced plans to retire in 2039, and that
therefore would have a 7-year amortization period if they installed
CCS by January 1, 2032, 6 would have costs below both $18.50/MWh and
$98/ton of CO2.
\620\ The EPA determines the BSER based on considering
information on the statutory factors, including cost, on a source
category or subcategory basis. However, there may be particular
sources for which, based on source-specific considerations, the cost
of CCS is fundamentally different from the costs the EPA considered
in making its BSER determination. If such a fundamental difference
makes it unreasonable for a particular source to achieve the degree
of emission limitation associated with implementing CCS with 90
percent capture, a state may provide a less stringent standard of
performance (and/or longer compliance schedule, if applicable) for
that source pursuant to the RULOF provisions. See section X.C.2 of
this preamble for further discussion.
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As discussed in the RTC section 2.16, the EPA has also examined the
reasonableness of the costs of this rule in additional ways:
considering the total annual costs of the rule as compared to past CAA
rules for the electricity sector and as compared to the industry's
annual revenues and annual capital expenditures, and considering the
effects of this rule on electricity prices. Taking all of these into
consideration, in addition to the cost metrics just discussed, the EPA
concludes that, in general, the costs of CCS are reasonable for sources
operating after January 1, 2039.
(A) Capture Costs
The EPA developed an independent engineering cost assessment for
CCS retrofits, with support from Sargent and Lundy.\621\ The EPA cost
analysis assumes installation of one CO2 capture plant for
each coal-fired EGU, and that sources without SO2 controls
(FGD) or NOX controls (specifically, selective catalytic
reduction--SCR; or selective non-catalytic reduction--SNCR) add a wet
FGD and/or SCR.\622\
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\621\ Detailed cost information, assessment of technology
options, and demonstration of cost reasonableness can be found in
the final TSD, GHG Mitigation Measures for Steam Generating Units.
\622\ Whether an FGD and SCR or controls with lower costs are
necessary for flue gas pretreatment prior to the CO2
capture process will in practice depend on the flue gas conditions
of the source.
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(B) CO2 Transport and Sequestration Costs
To calculate the costs of CCS for coal-fired steam generating units
for purposes of determining BSER as well as for EPA modeling, the EPA
relied on transportation and storage costs consistent with the cost of
transporting and storing CO2 from each power plant to the
nearest saline reservoir.\623\ For a power plant composed of multiple
coal-fired EGUs, the EPA's cost analysis assumes installation and
operation of a single, common CO2 pipeline.
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\623\ For additional details on CO2 transport and
storage costs, see the final TSD, GHG Mitigation Measures for Steam
Generating Units.
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The EPA notes that NETL has also developed costs for transport and
storage. NETL's ``Quality Guidelines for Energy System Studies; Carbon
Dioxide Transport and Sequestration Costs in NETL Studies'' provides an
estimation of transport costs based on the CO2 Transport
Cost Model.\624\ The CO2 Transport Cost Model estimates
costs for a single point-to-point pipeline. Estimated costs reflect
pipeline capital costs, related capital expenditures, and operations
and maintenance costs.\625\
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\624\ Grant, T., et al. (2019). ``Quality Guidelines for Energy
System Studies; Carbon Dioxide Transport and Storage Costs in NETL
Studies.'' National Energy Technology Laboratory. https://www.netl.doe.gov/energy-analysis/details?id=3743.
\625\ Grant, T., et al. ``Quality Guidelines for Energy System
Studies; Carbon Dioxide Transport and Storage Costs in NETL
Studies.'' National Energy Technology Laboratory. 2019. https://www.netl.doe.gov/energy-analysis/details?id=3743.
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NETL's Quality Guidelines also provide an estimate of sequestration
costs. These costs reflect the cost of site screening and evaluation,
permitting and construction costs, the cost of injection wells, the
cost of injection equipment, operation and maintenance costs, pore
volume acquisition expense, and long-term liability protection.
Permitting and construction costs also reflect the regulatory
requirements of the UIC Class VI program and GHGRP subpart RR for
geologic sequestration of CO2 in deep saline formations.
NETL calculates these sequestration costs on the basis of generic plant
locations in the Midwest, Texas, North Dakota, and Montana, as
described in the NETL energy system studies that utilize the coal found
in Illinois, East Texas, Williston, and Powder River basins.\626\
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\626\ National Energy Technology Laboratory (NETL). (2017).
``FE/NETL CO2 Saline Storage Cost Model (2017),'' U.S.
Department of Energy, DOE/NETL-2018-1871. https://netl.doe.gov/energy-analysis/details?id=2403.
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There are two primary cost drivers for a CO2
sequestration project: the rate of injection of the CO2 into
the reservoir and the areal extent of the CO2 plume in the
reservoir. The rate of injection depends, in part, on the thickness of
the reservoir and its permeability. Thick, permeable reservoirs provide
for better injection and fewer injection wells. The areal extent of the
CO2 plume depends on the sequestration capacity of the
reservoir. Thick, porous reservoirs with a good sequestration
coefficient will present a small areal extent for the CO2
plume and have a smaller monitoring footprint, resulting in lower
monitoring costs. NETL's Quality Guidelines model costs for a given
cumulative sequestration potential.\627\
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\627\ Details on CO2 transportation and sequestration
costs can be found in the final TSD, GHG Mitigation Measures for
Steam Generating Units.
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In addition, provisions in the IIJA and IRA are expected to
significantly increase the CO2 pipeline infrastructure and
development of sequestration sites, which, in turn, are expected to
result in further cost reductions for the application of CCS at new
combined cycle EGUs. The IIJA establishes a new Carbon Dioxide
Transportation Infrastructure Finance and Innovation program to provide
direct loans, loan guarantees, and grants to CO2
infrastructure projects, such as pipelines, rail transport, ships and
barges.\628\ The IIJA also establishes a new Regional Direct Air
Capture Hubs program that includes funds to support four large-scale,
regional direct air capture hubs and more broadly support projects that
could be developed into a regional or inter-regional network to
facilitate sequestration or utilization.\629\ DOE is additionally
implementing IIJA section 40305 (Carbon Storage Validation and Testing)
through its CarbonSAFE initiative, which aims to further develop
geographically widespread, commercial-scale, safe sequestration.\630\
The IRA increases and
[[Page 39881]]
extends the IRC section 45Q tax credit, discussed next.
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\628\ Department of Energy. ``Biden-Harris Administration
Announces $2 Billion from Bipartisan Infrastructure Law to Finance
Carbon Dioxide Transportation Infrastructure.'' (2022). https://www.energy.gov/articles/biden-harris-administration-announces-2-billion-bipartisan-infrastructure-law-finance.
\629\ Department of Energy. ``Regional Direct Air Capture
Hubs.'' (2022). https://www.energy.gov/oced/regional-direct-air-capture-hubs.
\630\ For more information, see the NETL announcement. https://www.netl.doe.gov/node/12405.
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(C) IRC Section 45Q Tax Credit
In determining the cost of CCS, the EPA is taking into account the
tax credit provided under IRC section 45Q, as revised by the IRA. The
tax credit is available at $85/metric ton ($77/ton) and offsets a
significant portion of the capture, transport, and sequestration costs
noted above.
Several other aspects of the tax credit should be noted. A tax
credit offsets tax liability dollar for dollar up to the amount of the
taxpayer's tax liability. Any credits in excess of the taxpayer's
liability are eligible to be carried back (3 years in the case of IRC
section 45Q) and then carried forward up to 20 years.\631\As noted
above, the IRA also enabled additional methods to monetize tax credits
in the event the taxpayer does not have sufficient tax liability, such
as through credit transfer.
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\631\ IRC section 39.
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The EPA has determined that it is likely that EGUs installing CCS
will meet the 45Q prevailing wage and apprenticeship requirements.
First, the requirements provide a significant economic incentive,
increasing the value of the 45Q credit by five times over the base
value of the credit available if the prevailing wage and apprenticeship
requirements are not met. This provides a significant incentive to meet
the requirements. Second, the increased cost of meeting the
requirements is likely significantly less than the increase in credit
value. A recent EPRI assessment found meeting the requirements for
other types of power generation projects resulted in significant
savings across projects,\632\ and other studies indicate prevailing
wage laws and requirements for construction projects in general do not
significantly affect overall construction costs.\633\ The EPA expects a
similar dynamic for 45Q projects. Third, the use of registered
apprenticeship programs for training new employees is generally well-
established in the electric power generation sector, and apprenticeship
programs are widely available to generate additional trained workers in
this field.\634\ The overall U.S. apprentice market has more than
doubled between 2014 and 2023, growing at an average annual rate of
more than 7 percent.\635\ Additional programs support the skilled
construction trade workforce required for CCS implementation and
maintenance.\636\
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\632\ https://www.epri.com/research/products/000000003002027328.
\633\ https://journals.sagepub.com/doi/abs/10.1177/0160449X18766398.
\634\ DOE. Workforce Analysis of Existing Coal Carbon Capture
Retrofits. https://www.energy.gov/policy/articles/workforce-analysis-existing-coal-carbon-capture-retrofits.
\635\ https://www.apprenticeship.gov/data-and-statistics.
\636\ https://www.apprenticeship.gov/partner-finder.
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As discussed in section V.C.2.c of this preamble, CAA section
111(a)(1) is clear that the cost that the Administrator must take into
account in determining the BSER is the cost of the controls to the
source. It is reasonable to take the tax credit into account because it
reduces the cost of the controls to the source, which has a significant
effect on the actual cost of installing and operating CCS. In addition,
all sources that install CCS to meet the requirements of these final
actions are eligible for the tax credit. The legislative history of the
IRA makes clear that Congress was well aware that the EPA may
promulgate rulemaking under CAA section 111 based on CCS and the
utility of the tax credit in reducing the costs of CCUS (i.e., CCS).
Rep. Frank Pallone, the chair of the House Energy & Commerce Committee,
included a statement in the Congressional Record when the House adopted
the IRA in which he explained: ``The tax credit[ ] for CCUS . . .
included in this Act may also figure into CAA Section 111 GHG
regulations for new and existing industrial sources[.] . . . Congress
anticipates that EPA may consider CCUS . . . as [a] candidate[ ] for
BSER for electric generating plants . . . . Further, Congress
anticipates that EPA may consider the impact of the CCUS . . . tax
credit[ ] in lowering the costs of [that] measure[ ].'' 168 Cong. Rec.
E879 (August 26, 2022) (statement of Rep. Frank Pallone).
In the 2015 NSPS, in which the EPA determined partial CCS to be the
BSER for GHGs from new coal-fired steam generating EGUs, the EPA
recognized that the IRC section 45Q tax credit or other tax incentives
could factor into the cost of the controls to the sources.
Specifically, the EPA calculated the cost of partial CCS on the basis
of cost calculations from NETL, which included ``a range of assumptions
including the projected capital costs, the cost of financing the
project, the fixed and variable O&M costs, the projected fuel costs,
and incorporation of any incentives such as tax credits or favorable
financing that may be available to the project developer.'' 80 FR 64570
(October 23, 2015).\637\
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\637\ In fact, because of limits on the availability of the IRC
section 45Q tax credit at the time of the 2015 NSPS, the EPA did not
factor it into the cost calculation for partial CCS. 80 FR 64558-64
(October 23, 2015).
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Similarly, in the 2015 NSPS, the EPA also recognized that revenues
from utilizing captured CO2 for EOR would reduce the cost of
CCS to the sources, although the EPA did not account for potential EOR
revenues for purposes of determining the BSER. Id. At 64563-64. In
other rules, the EPA has considered revenues from sale of the by-
products of emission controls to affect the costs of the emission
controls. For example, in the 2016 Oil and Gas Methane Rule, the EPA
determined that certain control requirements would reduce natural gas
leaks and therefore result in the collection of recovered natural gas
that could be sold; and the EPA further determined that revenues from
the sale of the recovered natural gas reduces the cost of controls. See
81 FR 35824 (June 3, 2016). The EPA made the same determination in the
2024 Oil and Gas Methane Rule. See 89 FR 16820, 16865 (May 7, 2024). In
a 2011 action concerning a regional haze SIP, the EPA recognized that a
NOX control would alter the chemical composition of fly ash
that the source had previously sold, so that it could no longer be
sold; and as a result, the EPA further determined that the cost of the
NOX control should include the foregone revenues from the
fly ash sales. 76 FR 58570, 58603 (September 21, 2011). In the 2016
emission guidelines for landfill gas from municipal solid waste
landfills, the EPA reduced the costs of controls by accounting for
revenue from the sale of electricity produced from the landfill gas
collected through the controls. 81 FR 59276, 19679 (August 29, 2016).
The amount of the IRC section 45Q tax credit that the EPA is taking
into account is $85/metric ton for CO2 that is captured and
geologically stored. This amount is available to the affected source as
long as it meets the prevailing wage and apprenticeship requirements of
IRC section 45Q(h)(3)-(4). The legislative history to the IRA
specifically stated that when the EPA considers CCS as the BSER for GHG
emissions from industrial sources in CAA section 111 rulemaking, the
EPA should determine the cost of CCS by assuming that the sources would
meet those prevailing wage and apprenticeship requirements. 168 Cong.
Rec. E879 (August 26, 2022) (statement of Rep. Frank Pallone). If
prevailing wage and apprenticeship requirements are not met, the value
of the IRC section 45Q tax credit falls to $17/metric ton. The
substantially higher credit available provides a considerable incentive
to meeting the prevailing wage and apprenticeship requirements.
[[Page 39882]]
Therefore, the EPA assumes that investors maximize the value of the IRC
section 45Q tax credit at $85/metric ton by meeting those requirements.
(D) Comparison to Other Costs of Controls and Other Measures of Cost
Reasonableness
In assessing cost reasonableness for the BSER determination for
this rule, the EPA looks at a range of cost information. As discussed
in Chapter 2 of the RTC, the EPA considered the total annual costs of
the rule as compared to past CAA rules for the electricity sector and
as compared to the industry's annual revenues and annual capital
expenditures, and considered the effects of this rule on electricity
prices.
For each of the BSER determinations, the EPA also considers cost
metrics that it has historically considered in assessing costs to
compare the costs of GHG control measures to control costs that the EPA
has previously determined to be reasonable. This includes comparison to
the costs of controls at EGUs for other air pollutants, such as
SO2 and NOX, and costs of controls for GHGs in
other industries. Based on these costs, the EPA has developed two
metrics for assessing the cost reasonableness of controls: the increase
in cost of electricity due to controls, measured in $/MWh, and the
control costs of removing a ton of pollutant, measured in $/ton
CO2e. The costs presented in this section of the preamble
are in 2019 dollars.\638\
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\638\ The EPA used the NETL Baseline Report costs directly for
the combustion turbine model plant BSER analysis. Even though these
costs are in 2018 dollars, the adjustment to 2019 dollars (1.018
using the U.S. GDP Implicit Price Deflator) is well within the
uncertainty range of the report and the minor adjustment would not
impact the EPA's BSER determination.
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In different rulemakings, the EPA has required many coal-fired
steam generating units to install and operate flue gas desulfurization
(FGD) equipment--that is, wet or dry scrubbers--to reduce their
SO2 emissions or SCR to reduce their NOX
emissions. The EPA compares these control costs across technologies--
steam generating units and combustion turbines--because these costs are
indicative of what is reasonable for the power sector in general. The
facts that the EPA required these controls in prior rules, and that
many EGUs subsequently installed and operated these controls, provide
evidence that these costs are reasonable, and as a result, the cost of
these controls provides a benchmark to assess the reasonableness of the
costs of the controls in this preamble. In the 2011 CSAPR (76 FR 48208;
August 8, 2011), the EPA estimated the annualized costs to install and
operate wet FGD retrofits on existing coal-fired steam generating
units. Using those same cost equations and assumptions (i.e., a 63
percent annual capacity factor--the average value in 2011) for
retrofitting wet FGD on a representative 700 to 300 MW coal-fired steam
generating unit results in annualized costs of $14.80 to $18.50/MWh of
generation, respectively.\639\ In the Good Neighbor Plan for the 2015
Ozone NAAQS (2023 GNP), 88 FR 36654 (June 5, 2023), the EPA estimated
the annualized costs to install and operate SCR retrofits on existing
coal-fired steam generating units. Using those same cost equations and
assumptions (including a 56 percent annual capacity factor--a
representative value in that rulemaking) to retrofit SCR on a
representative 700 to 300 MW coal-fired steam generating unit results
in annualized costs of $10.60 to $11.80/MWh of generation,
respectively.\640\
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\639\ For additional details, see https://www.epa.gov/power-sector-modeling/documentation-integrated-planning-model-ipm-base-case-v410.
\640\ For additional details, see https://www.epa.gov/system/files/documents/2023-01/Updated%20Summer%202021%20Reference%20Case%20Incremental%20Documentation%20for%20the%202015%20Ozone%20NAAQS%20Actions_0.pdf.
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The EPA also compares costs to the costs for GHG controls in
rulemakings for other industries. In the 2016 NSPS regulating GHGs for
the Crude Oil and Natural Gas source category, the EPA found the costs
of reducing methane emissions of $2,447/ton to be reasonable (80 FR
56627; September 18, 2015).\641\ Converted to a ton of CO2e
reduced basis, those costs are expressed as $98/ton of CO2e
reduced.\642\
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\641\ The EPA finalized the 2016 NSPS GHGs for the Crude Oil and
Natural Gas source category at 81 FR 35824 (June 3, 2016). The EPA
included cost information in the proposed rulemaking, at 80 FR 56627
(September 18, 2015).
\642\ Based on the 100-year global warming potential for methane
of 25 used in the GHGRP (40 CFR 98 Subpart A, table A-1).
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The EPA does not consider either of these metrics, $18.50/MWh and
$98/ton of CO2e, to be bright line standards that
distinguish between levels of control costs that are reasonable and
levels that are unreasonable. But they do usefully indicate that
control costs that are generally consistent with those levels of
control costs should be considered reasonable. The EPA has required
controls with comparable costs in prior rules for the electric power
industry and the industry has successfully complied with those rules by
installing and operating the applicable controls. In the case of the $/
ton metric, the EPA has required other industries--specifically, the
oil and gas industry--to reduce their climate pollution at this level
of cost-effectiveness. In this rulemaking, the costs of the controls
that the EPA identifies as the BSER generally match up well against
both of these $/MWh and $/ton metrics for the affected subcategories of
sources. And looking broadly at the range of cost information and these
cost metrics, the EPA concludes that the costs of these rules are
reasonable.
(E) Comparison to Costs for CCS in Prior Rulemakings
In the CPP and ACE Rule, the EPA determined that CCS did not
qualify as the BSER due to cost considerations. Two key developments
have led the EPA to reevaluate this conclusion: the costs of CCS
technology have fallen and the extension and increase in the IRC
section 45Q tax credit, as included in the IRA, in effect provide a
significant stream of revenue for sequestered CO2 emissions.
The CPP and ACE Rule relied on a 2015 NETL report estimating the cost
of CCS. NETL has issued updated reports to incorporate the latest
information available, most recently in 2022, which show significant
cost reductions. The 2015 report estimated incremental levelized cost
of CCS at a new pulverized coal facility relative to a new facility
without CCS at $74/MWh (2022$),\643\ while the 2022 report estimated
incremental levelized cost at $44/MWh (2022$).\644\ Additionally, the
IRA increased the IRC section 45Q tax credit from $50/metric ton to
$85/metric ton (and, in the case of EOR or certain industrial uses,
from $35/metric ton to $60/metric ton), assuming prevailing wage and
apprenticeship conditions are met. The IRA also enhanced the realized
value of the tax credit through the elective pay (informally known as
direct pay) and transferability monetization options described in
section IV.E.1. The combination of lower costs and higher tax credits
significantly improves the cost reasonableness of CCS for purposes
[[Page 39883]]
of determining whether it qualifies as the BSER.
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\643\ Cost And Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 3
(July 2015). Note: The EPA adjusted reported costs to reflect $2022.
https://www.netl.doe.gov/projects/files/CostandPerformanceBaselineforFossilEnergyPlantsVolume1aBitCoalPCandNaturalGastoElectRev3_070615.pdf.
\644\ Cost And Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 4A
(October 2022). Note: The EPA adjusted reported costs to reflect
$2022. https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_101422.pdf.
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iii. Non-Air Quality Health and Environmental Impact and Energy
Requirements
The EPA considered non-GHG emissions impacts, the water use
impacts, the transport and sequestration of captured CO2,
and energy requirements resulting from CCS for steam generating units.
As discussed below, where the EPA has found potential for localized
adverse consequences related to non-air quality health and
environmental impacts or energy requirements, the EPA also finds that
protections are in place to mitigate those risks. Because the non-air
quality health and environmental impacts are closely related to the
energy requirements, we discuss the latter first.
(A) Energy Requirements
For a steam generating unit with 90 percent amine-based
CO2 capture, parasitic/auxiliary energy demand increases and
the net power output decreases. In particular, the solvent regeneration
process requires heat in the form of steam and CO2
compression requires a large amount of electricity. Heat and power for
the CO2 capture equipment can be provided either by using
the steam and electricity produced by the steam generating unit or by
an auxiliary cogeneration unit. However, any auxiliary source of heat
and power is part of the ``designated facility,'' along with the steam
generating unit. The standards of performance apply to the designated
facility. Thus, any CO2 emissions from the connected
auxiliary equipment need to be captured or they will increase the
facility's emission rate.
Using integrated heat and power can reduce the capacity (i.e., the
amount of electricity that a unit can distribute to the grid) of an
approximately 474 MW-net (501 MW-gross) coal-fired steam generating
unit without CCS to approximately 425 MW-net with CCS and contributes
to a reduction in net efficiency of 23 percent.\645\ For retrofits of
CCS on existing sources, the ductwork for flue gas and piping for heat
integration to overcome potential spatial constraints are a component
of efficiency reduction. The EPA notes that slightly greater efficiency
reductions than in the 2016 NETL retrofit report are assumed for the
BSER cost analyses, as detailed in the final TSD, GHG Mitigation
Measures for Steam Generating Units, available in the docket. Despite
decreases in efficiency, IRC section 45Q tax credit provides an
incentive for increased generation with full operation of CCS because
the amount of revenue from the tax credit is based on the amount of
captured and sequestered CO2 emissions and not the amount of
electricity generated. In this final action, the Agency considers the
energy penalty to not be unreasonable and to be relatively minor
compared to the benefits in GHG reduction of CCS.
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\645\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon
Capture Retrofits.'' May 31, 2016. https://www.netl.doe.gov/energy-analysis/details?id=d335ce79-84ee-4a0b-a27b-c1a64edbb866.
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(B) Non-GHG Emissions
As a part of considering the non-air quality health and
environmental impacts of CCS, the EPA considered the potential non-GHG
emission impacts of CO2 capture. The EPA recognizes that
amine-based CO2 capture can, under some circumstances,
result in the increase in emission of certain co-pollutants at a coal-
fired steam generating unit. However, there are protections in place
that can mitigate these impacts. For example, as discussed below, CCS
retrofit projects with co-pollutant increases may be subject to
preconstruction permitting under the New Source Review (NSR) program,
which could require the source to adopt emission limitations based on
applicable NSR requirements. Sources obtaining major NSR permits would
be required to either apply Lowest Achievable Emission Rate (LAER) and
fully offset any anticipated increases in criteria pollutant emissions
(for their nonattainment pollutants) or apply Best Available Control
Technology (BACT) and demonstrate that its emissions of criteria
pollutants will not cause or contribute to a violation of applicable
National Ambient Air Quality Standards (for their attainment
pollutants).\646\ The EPA expects facility owners, states, permitting
authorities, and other responsible parties will use these protections
to address co-pollutant impacts in situations where individual units
use CCS to comply with these emission guidelines.
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\646\ Section XI.A of this preamble provides additional
information on the NSR program and how it relates to the NSPS and
emission guidelines.
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The EPA also expects that the meaningful engagement requirements
discussed in section X.E.1.b.i of this preamble will ensure that all
interested stakeholders, including community members who might be
adversely impacted by non-GHG pollutants, will have an opportunity to
raise this concern with states and permitting authorities.
Additionally, state permitting authorities are, in general, required to
provide notice and an opportunity for public comment on construction
projects that require NSR permits. This provides additional
opportunities for affected stakeholders to engage in that process, and
it is the EPA's expectation that the responsible authorities will
consider these concerns and take full advantage of existing
protections. Moreover, the EPA through its regional offices is
committed to thoroughly review draft NSR permits associated with
CO2 capture projects and provide comments as necessary to
state permitting authorities to address any concerns or questions with
regard to the draft permit's consideration and treatment of non-GHG
pollutants.
In the following discussion, the EPA describes the potential
emissions of non-GHG pollutants resulting from installation and
operation of CO2 capture plants, the protections in place
such as the controls and processes for mitigating those emissions, as
well as regulations and permitting that may require review and
implementation of those controls. The EPA first discusses these issues
in relation to criteria air pollutants and precursor pollutants
(SO2, NOX, and PM), and subsequently provides
details regarding hazardous air pollutants (HAPs) and volatile organic
compounds (VOCs).
Operation of an amine-based CO2 capture plant on a coal-
fired steam generating unit can impact the emission of criteria
pollutants from the facility, including SO2 and PM, as well
as precursor pollutants, like NOX. Sources installing CCS
may operate more due to the incentives provided by the IRC section 45Q
tax credit, and increased utilization would--all else being equal--
result in increases in SO2, PM, and NOX. However,
certain impacts are mitigated by the flue gas conditioning required by
the CO2 capture process and by other control equipment that
the units already have or may need to install to meet other CAA
requirements. Substantial flue gas conditioning, particularly to remove
SO2 and PM, is critical to limiting solvent degradation and
maintaining reliable operation of the capture plant. To achieve the
necessary limits on SO2 levels in the flue gas for the
capture process, steam generating units will need to add an FGD
scrubber, if they do not already have one, and will usually need an
additional polishing column (i.e., quencher), thereby further reducing
the emission of SO2. A wet FGD column and a polishing column
will also reduce the emission rate of PM. Additional improvements in PM
removal may also be necessary to reduce the fouling of
[[Page 39884]]
other components (e.g., heat exchangers) of the capture process,
including upgrades to existing PM controls or, where appropriate, the
inclusion of various wash stages to limit fly ash carry-over to the
CO2 removal system. Although PM emissions from the steam
generating unit may be reduced, PM emissions may occur from cooling
towers for those sources using wet cooling for the capture process. For
some sources, a WESP may be necessary to limit the amount of aerosols
in the flue gas prior to the CO2 capture process. Reducing
the amount of aerosols to the CO2 absorber will also reduce
emissions of the solvent out of the top of the absorber. Controls to
limit emission of aerosols installed at the outlet of the absorber
could be considered, but could lead to higher pressure drops. Thus,
emission increases of SO2 and PM would be reduced through
flue gas conditioning and other system requirements of the
CO2 capture process, and NSR permitting would serve as an
added backstop to review remaining SO2 and PM increases for
mitigation.
NOX emissions can cause solvent degradation and
nitrosamine formation, depending on the chemical structure of the
solvent. Limits on NOX levels of the flue gas required to
avoid solvent degradation and nitrosamine formation in the
CO2 scrubber vary. For most units, the requisite limits on
NOX levels to assure that the CO2 capture process
functions properly may be met by the existing NOX combustion
controls. Other units may need to install SCR to achieve the required
NOx level. Most existing coal-fired steam generating units either
already have SCR or will be covered by final Federal Implementation
Plan (FIP) requirements regulating interstate transport of
NOX (as ozone precursors) from EGUs. See 88 FR 36654 (June
5, 2023).\647\ For units not otherwise required to have SCR, an
increase in utilization from a CO2 capture retrofit could
result in increased NOX emissions at the source that,
depending on the quantity of the emissions increase, may trigger major
NSR permitting requirements. Under this scenario, the permitting
authority may determine that the NSR permit requires the installation
of SCR for those units, based on applying the control technology
requirements of major NSR. Alternatively, a state could, as part of its
state plan, develop enforceable conditions for a source expected to
trigger major NSR that would effectively limit the unit's ability to
increase its emissions in amounts that would trigger major NSR. Under
this scenario, with no major NSR requirements applying due to the limit
on the emissions increase, the permitting authority may conclude for
the minor NSR permit that installation of SCR is not required for the
units and the source is to minimize its NOX emission
increases using other techniques. Finally, a source with some lesser
increase in NOX emissions may not trigger major NSR to begin
with and, as with the previous scenario, the permitting authority would
determine the NOX control requirements pursuant to its minor
NSR program requirements.
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\647\ As of September 21, 2023, the Good Neighbor Plan ``Group
3'' ozone-season NOX control program for power plants is
being implemented in the following states: Illinois, Indiana,
Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania,
Virginia, and Wisconsin. Pursuant to court orders staying the
Agency's FIP Disapproval action as to the following states, the EPA
is not currently implementing the Good Neighbor Plan ``Group 3''
ozone-season NOX control program for power plants in the
following states: Alabama, Arkansas, Kentucky, Louisiana, Minnesota,
Mississippi, Missouri, Nevada, Oklahoma, Texas, Utah, and West
Virginia.
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Recognizing that potential emission increases of SO2,
PM, and NOX from operating a CO2 capture process
are an area of concern for stakeholders, 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. In its analysis to
support this final action, the EPA accounted for controlling these co-
pollutant increases by assuming that coal-fired units that install CCS
would be required to install SCR and/or FGD if they do not already have
those controls installed. The costs of these controls are included in
the total program compliance cost estimates through IPM modeling, as
well as in the BSER cost calculations.
An amine-based CO2 capture plant can also impact
emissions of HAP and VOC (as an ozone precursor) from the coal-fired
steam generating unit. Degradation of the solvent can produce HAP, and
organic HAP and amine solvent emissions from the absorber would
contribute to VOC emissions out of the top of the CO2
absorber. A conventional multistage water or acid wash and mist
eliminator (demister) at the exit of the CO2 scrubber is
effective at removal of gaseous amine and amine degradation products
(e.g., nitrosamine) emissions.648 649 The DOE's Carbon
Management Pathway report notes that monitoring and emission controls
for such degradation products are currently part of standard operating
procedures for amine-based CO2 capture systems.\650\
Depending on the solvent properties, different amounts of aldehydes
including acetaldehyde and formaldehyde may form through oxidative
processes, contributing to total HAP and VOC emissions. While a water
wash or acid wash can be effective at limiting emission of amines, a
separate system of controls would be required to reduce aldehyde
emissions; however, the low temperature and likely high water vapor
content of the gas emitted out of absorber may limit the applicability
of catalytic or thermal oxidation. Other controls (e.g.,
electrochemical, ultraviolet) common to water treatment could be
considered to reduce the loading of copollutants in the water wash
section, although their efficacy is still in development and it is
possible that partial treatment could result in the formation of
additional degradation products. Apart from these potential controls,
any increase in VOC emissions from a CCS retrofit project would be
mitigated through NSR permitting. As such VOC increases are not
expected to be large enough to trigger major NSR requirements, they
would likely be reviewed and addressed under a state's minor NSR
program.
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\648\ Sharma, S., Azzi, M., ``A critical review of existing
strategies for emission control in the monoethanolamine-based carbon
capture process and some recommendations for improved strategies,''
Fuel, 121, 178 (2014).
\649\ Mertens, J., et al., ``Understanding ethanolamine (MEA)
and ammonia emissions from amine-based post combustion carbon
capture: Lessons learned from field tests,'' Int'l J. of GHG
Control, 13, 72 (2013).
\650\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Carbon Management. https://liftoff.energy.gov/wp-content/uploads/2023/04/20230424-Liftoff-Carbon-Management-vPUB_update.pdf.
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There is one nitrosamine that is a listed HAP regulated under CAA
section 112. Carbon capture systems that are themselves a major source
of HAP should evaluate the applicability of CAA section 112(g) and
conduct a case-by-case MACT analysis if required, to establish MACT for
any listed HAP, including listed nitrosamines, formaldehyde, and
acetaldehyde. Because of the differences in the formation and
effectiveness of controls, such a case-by-case MACT analysis should
evaluate the performance of controls for nitrosamines and aldehydes
separately, as formaldehyde or acetaldehyde may not be a suitable
surrogate for amine and nitrosamine emissions. However, measurement of
nitrosamine emissions may be challenging when the concentration is low
(e.g., less than 1 part per billion, dry basis).
HAP emissions from the CO2 capture plant will depend on
the flue gas
[[Page 39885]]
conditions, solvent, size of the source, and process design. The air
permit application for Project Tundra \651\ includes potential-to-emit
(PTE) values for CAA section 112 listed HAP specific to the 530 MW-
equivalent CO2 capture plant, including emissions of 1.75
tons per year (TPY) of formaldehyde (CASRN 50-00-0), 32.9 TPY of
acetaldehyde (CASRN 75-07-0), 0.54 TPY of acetamide (CASRN 60-35-5),
0.018 TPY of ethylenimine (CASRN 151-56-4), 0.044 TPY of N-
nitrosodimethylamine (CASRN 62-75-9), and 0.018 TPY of N-
nitrosomorpholine (CASRN 59-89-2). Additional PTE other species that
are not CAA section 112 listed HAP were also included, including 0.022
TPY of N-nitrosodiethylamine (CASRN 55-18-5). PTE values for other
CO2 capture plants may differ. To comply with North Dakota
Department of Environmental Quality (ND-DEQ) Air Toxics Policy, an air
toxics assessment was included in the permit application. According to
that assessment, the total maximum individual carcinogenic risk was
1.02E-6 (approximately 1-in-1 million, below the ND-DEQ threshold of
1E-5) primarily driven by N-nitrosodiethylamine and N-
nitrosodimethylamine. The hazard index value was 0.022 (below the ND-
DEQ threshold of 1), with formaldehyde being the primary driver.
Results of air toxics risk assessments for other facilities would
depend on the emissions from the facility, controls in place, stack
height and flue gas conditions, local ambient conditions, and the
relative location of the exposed population.
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\651\ DCC East PTC Application. https://ceris.deq.nd.gov/ext/nsite/map/results/detail/-8992368000928857057/documents.
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Emissions of amines and nitrosamines at Project Tundra are
controlled by the water wash section of the absorber column. According
to the permit to construct issued by ND-DEQ, limits for formaldehyde
and acetaldehyde will be established based on testing after initial
operation of the CO2 capture plant. The permit does not
include a mechanism for establishing limits for nitrosamine emissions,
as they may be below the limit of detection (less than 1 part per
billion, dry basis).
The EPA received several comments related to the potential for non-
GHG emissions associated with CCS. Those comments and the EPA's
responses are as follows.
Comment: Some commenters noted that there is a potential for
increases in co-pollutants when operating amine-based CO2
capture systems. One commenter requested that the EPA proactively
regulate potential nitrosamine emissions.
Response: The EPA carefully considered these concerns as it
finalized its determination of the BSERs for these rules. The EPA takes
these concerns seriously, agrees that any impacts to local and downwind
communities are important to consider and has done so as part of its
analysis discussed at section XII.E. While the EPA acknowledges that,
in some circumstances, there is potential for some non-GHG emissions to
increase, there are several protections in place to help mitigate these
impacts. The EPA believes that these protections, along with the
meaningful engagement of potentially affected communities, can
facilitate a responsible deployment of this technology that mitigates
the risk of any adverse impacts.
There is one nitrosamine that is a listed HAP under CAA section 112
(N-Nitrosodimethylamine; CASRN 62-75-9). Other nitrosamines would have
to be listed before the EPA could establish regulations limiting their
emission. Furthermore, carbon capture systems are themselves not a
listed source category of HAP, and the listing of a source category
under CAA section 112 would first require some number of the sources to
exist for the EPA to develop MACT standards. However, if a new
CO2 capture facility were to be permitted as a separate
entity (rather than as part of the EGU) then it may be subject to case-
by-case MACT under section 112(g), as detailed in the preceding section
of this preamble.
Comment: Commenters noted that a source could attempt to permit
CO2 facilities as separate entities to avoid triggering NSR
for the EGU.
Response: For the CO2 capture plant to be permitted as a
separate entity, the source would have to demonstrate to the state
permitting authority that the EGU and CO2 capture plant are
not a single stationary source under the NSR program. In determining
what constitutes a stationary source, the EPA's NSR regulations set
forth criteria that are to be used when determining the scope of a
``stationary source.'' \652\ These criteria require the aggregation of
different pollutant-emitting activities if they (1) belong to the same
industrial grouping as defined by SIC codes, (2) are located on
contiguous or adjacent properties, and (3) are under common
control.\653\ In the case of an EGU and CO2 capture plant
that are collocated, to permit them as separate sources they should not
be under common control or not be defined by the same industrial
grouping.
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\652\ 40 CFR 51.165(a)(1)(i) and (ii); 40 CFR 51.166(b)(5) and
(6).
\653\ The EPA has issued guidance to clarify these regulatory
criteria of stationary source determination. See https://www.epa.gov/nsr/single-source-determination.
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The EPA would anticipate that, in most cases, the operation of the
EGU and the CO2 capture plant will intrinsically affect one
another--typically steam, electricity, and the flue gas of the EGU will
be provided to the CO2 capture plant. Conditions of the flue
gas will affect the operation of the CO2 capture plant,
including its emissions, and the steam and electrical load will affect
the operation of the EGU. Moreover, the emissions from the EGU will be
routed through the CO2 capture system and emitted out of the
top of the CO2 absorber. Even if the EGU and CO2
capture plant are owned by separate entities, the CO2
capture plant is likely to be on or directly adjacent to land owned by
the owners of the EGU and contractual obligations are likely to exist
between the two owners. While each of these individual factors may not
ultimately determine the outcome of whether two nominally-separate
facilities should be treated as a single stationary source for
permitting purposes, the EPA expects that in most cases an EGU and its
collocated CO2 capture plant would meet each of the
aforementioned NSR regulatory criteria necessary to make such a
determination. Thus, the EPA generally would not expect an EGU and its
CO2 capture plant to be permitted as separate stationary
sources.
(C) Water Use
Water consumption at the plant increases when applying carbon
capture, due to solvent water makeup and cooling demand. Water
consumption can increase by 36 percent on a gross basis.\654\ A
separate cooling water system dedicated to a CO2 capture
plant may be necessary. However, the amount of water consumption
depends on the design of the cooling system. For example, the cooling
system cited in the CCS feasibility study for SaskPower's Shand Power
station would rely entirely on water condensed from the flue gas and
thus would not require any increase in external water consumption--all
while achieving higher capture rates at lower cost than Boundary Dam
Unit 3.\655\ Regions with limited water supply
[[Page 39886]]
may therefore rely on dry or hybrid cooling systems. Therefore, the EPA
considers the water use requirements to be manageable and does not
expect this consideration to preclude coal-fired power plants generally
from being able to install and operate CCS.
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\654\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon
Capture Retrofits.'' May 31, 2016. https://www.netl.doe.gov/energy-analysis/details?id=e818549c-a565-4cbc-94db-442a1c2a70a9.
\655\ International CCS Knowledge Centre. The Shand CCS
Feasibility Study Public Report. https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
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(D) CO2 Capture Plant Siting
With respect to siting considerations, CO2 capture
systems have a sizeable physical footprint and a consequent land-use
requirement. One commenter cited their analysis showing that, for a
subset of coal-fired sources greater than 300 MW, 98 percent (154 GW of
the existing fleet) have adjacent land available within 1 mile of the
facility, and 83 percent have adjacent land available within 100 meters
of the facility. Furthermore, the cited analysis did not include land
available onsite, and it is therefore possible there is even greater
land availability for siting capture equipment. Qualitatively, some
commenters claimed there is limited land available for siting
CO2 capture plants adjacent to coal-fired steam generating
units. However, those commenters provided no data or analysis to
support their assertion. The EPA has reviewed the analysis provided by
the first commenter, and the approach, methods, and assumptions are
logical. Further, the EPA has reviewed the available information,
including the location of coal-fired steam generating units and visual
inspection of the associated maps and plots. Although in some cases
longer duct runs may be required, this would not preclude coal-fired
power plants generally from being able to install and operate CCS.
Therefore, the EPA has concluded that siting and land-use requirements
for CO2 capture are not unreasonable.
(E) Transport and Geologic Sequestration
As noted in section VII.C.1.a.i(C) of this preamble, PHMSA
oversight of supercritical CO2 pipeline safety protects
against environmental release during transport. The vast majority of
CO2 pipelines have been operating safely for more than 60
years. PHMSA reported a total of 102 CO2 pipeline incidents
between 2003 and 2022, with one injury (requiring in-patient
hospitalization) and zero fatalities.\656\ In the past 20 years, 500
million metric tons of CO2 moved through over 5,000 miles of
CO2 pipelines with zero incidents involving fatalities.\657\
PHMSA initiated a rulemaking in 2022 to develop and implement new
measures to strengthen its safety oversight of supercritical
CO2 pipelines. Furthermore, UIC Class VI and Class II
regulations under the SDWA, in tandem with GHGRP subpart RR and subpart
VV requirements, ensure the protection of USDWs and the security of
geologic sequestration. The EPA believes these protections constitute
an effective framework for addressing potential health and
environmental concerns related to CO2 transportation and
sequestration, and the EPA has taken this regulatory framework into
consideration in determining that CCS represents the BSER for long-term
steam EGUs.
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\656\ NARUC. (2023). Onshore U.S. Carbon Pipeline Deployment:
Siting, Safety. and Regulation. Prepared by Public Sector
Consultants for the National Association of Regulatory Utility
Commissioners (NARUC). June 2023. https://pubs.naruc.org/pub/F1EECB6B-CD8A-6AD4-B05B-E7DA0F12672E.
\657\ Congressional Research Service. 2022. Carbon Dioxide
Pipelines: Safety Issues, CRS Reports, June 3, 2022. https://crsreports.congress.gov/product/pdf/IN/IN11944.
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(F) Impacts on the Energy Sector
Additionally, the EPA considered the impacts on the power sector,
on a nationwide and long-term basis, of determining CCS to be the BSER
for long-term coal-fired steam generating units. In this final action,
the EPA considers that designating CCS as the BSER for these units
would have limited and non-adverse impacts on the long-term structure
of the power sector or on the reliability of the power sector. Absent
the requirements defined in this action, the EPA projects that 11 GW of
coal-fired steam generating units would apply CCS by 2035 and an
additional 30 GW of coal-fired steam generating units, without
controls, would remain in operation in 2040. Designating CCS to be the
BSER for existing long-term coal-fired steam generating units may
result in more of the coal-fired steam generating unit capacity
applying CCS. The time available before the compliance deadline of
January 1, 2032, provides for adequate resource planning, including
accounting for the downtime necessary to install the CO2
capture equipment at long-term coal-fired steam generating units. For
the 12-year duration that eligible EGUs earn the IRC section 45Q tax
credit, long-term coal-fired steam generating units are anticipated to
run at or near base load conditions in order to maximize the amount of
tax credit earned through IRC section 45Q. Total generation from coal-
fired steam generating units in the medium-term subcategory would
gradually decrease over an extended period of time through 2039,
subject to the commitments those units have chosen to adopt.
Additionally, for the long-term units applying CCS, the EPA has
determined that the increase in the annualized cost of generation is
reasonable. Therefore, the EPA concludes that these elements of BSER
can be implemented while maintaining a reliable electric grid. A
broader discussion of reliability impacts of these final rules is
available in section XII.F of this preamble.
iv. Extent of Reductions in CO2 Emissions
CCS is an extremely effective technology for reducing
CO2 emissions. As of 2021, coal-fired power plants are the
largest stationary source of GHG emissions by sector. Furthermore,
emission rates (lb CO2/MWh-gross) from coal-fired sources
are almost twice those of natural gas-fired combined cycle units, and
sources operating in the long-term have the more substantial emissions
potential. CCS can be applied to coal-fired steam generating units at
the source to reduce the mass of CO2 emissions by 90 percent
or more. Increased steam and power demand have a small impact on the
reduction in emission rate (i.e., lb CO2/MWh-gross) that
occurs with 90 percent capture. According to the 2016 NETL Retrofit
report, 90 percent capture will result in emission rates that are 88.4
percent lower on a lb/MWh-gross basis and 87.1 percent lower on a lb/
MWh-net basis compared to units without capture.\658\ After capture,
CO2 can be transported and securely sequestered.\659\
Although steam generating units with CO2 capture will have
an incentive to operate at higher utilization because the cost to
install the CCS system is largely fixed and the IRC section 45Q tax
credit increases based on the amount of CO2 captured and
sequestered, any increase in utilization will be far outweighed by the
substantial reductions in emission rate.
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\658\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon
Capture Retrofits.'' May 31, 2016. https://www.netl.doe.gov/energy-analysis/details?id=e818549c-a565-4cbc-94db-442a1c2a70a9.
\659\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage.
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v. Promotion of the Development and Implementation of Technology
The EPA considered the potential impact on technology advancement
of designating CCS as the BSER for long-term coal-fired steam
generating units, and in this final rule, the EPA considers
[[Page 39887]]
that designating CCS as the BSER will provide for meaningful
advancement of CCS technology. As indicated above, the EPA's IPM
modeling indicates that 11 GW of coal-fired power plants install CCS
and generate 76 terawatt-hours (TWh) per year in the base case, and
that another 8 GW of plants install CCS and generate another 57 TWh per
year in the policy case. In this manner, this rule advances CCS
technology more widely throughout the coal-fired power sector. As
discussed in section VIII.F.4.c.iv(G) of this preamble, this rule
advances CCS technology for new combined cycle base load combustion
turbines, as well. It is also likely that this rule supports advances
in the technology in other industries.
vi. Comparison With 2015 NSPS For Newly Constructed Coal-Fired EGUs
In the 2015 NSPS, the EPA determined that the BSER for newly
constructed coal-fired EGUs was based on CCS with 16 to 23 percent
capture, based on the type of coal combusted, and consequently, the EPA
promulgated standards of performance of 1,400 lb CO2/MWh-g.
80 FR 64512 (table 1), 64513 (October 23, 2015). The EPA made those
determinations based on the costs of CCS at the time of that
rulemaking. In general, those costs were significantly higher than at
present, due to recent technology cost declines as well as related
policies, including the IRC section 45Q tax credit for CCS, which were
not available at that time for purposes of consideration during the
development of the NSPS. Id. at 64562 (table 8). Based on of these
higher costs, the EPA determined that 16-23 percent capture qualified
as the BSER, rather than a significantly higher percentage of capture.
Given the substantial differences in the cost of CCS during the time of
the 2015 NSPS and the present time, the capture percentage of the 2015
NSPS necessarily differed from the capture percentage in this final
action, and, by the same token, the associated degree of emission
limitation and resulting standards of performance necessarily differ as
well. If the EPA had strong evidence to indicate that new coal-fired
EGUs would be built, it would propose to revise the 2015 NSPS to align
the BSER and emissions standards to reflect the new information
regarding the costs of CCS. Because there is no evidence to suggest
that there are any firm plans to build new coal-fired EGUs in the
future, however, it is not at present a good use of the EPA's limited
resources to propose to update the new source standard to align with
the existing source standard finalized today. While the EPA is not
revising the new source standard for new coal-fired EGUs in this
action, the EPA is retaining the ability to propose review in the
future.
vii. Requirement That Source Must Transfer CO2 to an Entity
That Reports Under the Greenhouse Gas Reporting Program
The final rule requires that EGUs that capture CO2 in
order to meet the applicable emission standard report in accordance
with the GHGRP requirements of 40 CFR part 98, including subpart PP.
GHGRP subpart RR and subpart VV requirements provide the monitoring and
reporting mechanisms to quantify CO2 storage and to
identify, quantify, and address potential leakage. Under existing GHGRP
regulations, sequestration wells permitted as Class VI under the UIC
program are required to report under subpart RR. Facilities with UIC
Class II wells that inject CO2 to enhance the recovery of
oil or natural gas can opt-in to reporting under subpart RR by
submitting and receiving approval for a monitoring, reporting, and
verification (MRV) plan. Subpart VV applies to facilities that conduct
enhanced recovery using ISO 27916 to quantify geologic storage unless
they have opted to report under subpart RR. For this rule, if injection
occurs on site, the EGU must report data accordingly under 40 CFR part
98 subpart RR or subpart VV. If the CO2 is injected off
site, the EGU must transfer the captured CO2 to a facility
that reports in accordance with the requirements of 40 CFR part 98,
subpart RR or subpart VV. They may also transfer the captured
CO2 to a facility that has received an innovative technology
waiver from the EPA.
b. Options Not Determined To Be the BSER for Long-Term Coal-Fired Steam
Generating Units
In this section, we explain why CCS at 90 percent capture best
balances the BSER factors and therefore why the EPA has determined it
to be the best of the possible options for the BSER.
i. Partial Capture CCS
Partial capture for CCS was not determined to be BSER because the
emission reductions are lower and the costs would, in general, be
higher. As discussed in section IV.B of this preamble, individual coal-
fired power plants are by far the highest-emitting plants in the
nation, and the coal-fired power plant sector is higher-emitting than
any other stationary source sector. CCS at 90 percent capture removes
very high absolute amounts of emissions. Partial capture CCS would fail
to capture large quantities of emissions. With respect to costs,
designs for 90 percent capture in general take greater advantage of
economies of scale. Eligibility for the IRC section 45Q tax credit for
existing EGUs requires design capture rates equivalent to 75 percent of
a baseline emission rate by mass. Even assuming partial capture rates
meet that definition, lower capture rates would receive fewer returns
from the IRC section 45Q tax credit (since these are tied to the amount
of carbon sequestered, and all else being equal lower capture rates
would result in lower amounts of sequestered carbon) and costs would
thereby be higher.
ii. Natural Gas Co-Firing
(A) Reasons Why Not Selected as BSER
As discussed in section VII.C.2, the EPA is determining 40 percent
natural gas co-firing to qualify as the BSER for the medium-term
subcategory of coal-fired steam generating units. This subcategory
consists of units that will permanently cease operation by January 1,
2039. In making this BSER determination, the EPA analyzed the ability
of all existing coal-fired units--not only medium-term units--to
install and operate 40 percent co-firing. As a result, all of the
determinations concerning the criteria for BSER that the EPA made for
40 percent co-firing apply to all existing coal-fired units, including
the units in the long-term subcategory. For example, 40 percent co-
firing is adequately demonstrated for the long-term subcategory, and
has reasonable energy requirements and reasonable non-air quality
environmental impacts. It would also be of reasonable cost for the
long-term subcategory. Although the capital expenditure for natural gas
co-firing is lower than CCS, the variable costs are higher. As a
result, the total costs of natural gas co-firing, in general, are
higher on a $/ton basis and not substantially lower on a $/MWh basis,
than for CCS. Were co-firing the BSER for long-term units, the cost
that industry would bear might then be considered similar to the cost
for CCS. In addition, the GHG Mitigation Measures TSD shows that all
coal-fired units would be able to achieve the requisite infrastructure
build-out and obtain sufficient quantities of natural gas to comply
with standards of performance based on 40 percent co-firing by January
1, 2030.
The EPA is not selecting 40 percent natural gas co-firing as the
BSER for the long-term subcategory, however, because it requires
substantially less emission reductions at the unit-level than 90
percent capture CCS. Natural gas co-firing at 40 percent of the heat
[[Page 39888]]
input to the steam generating unit achieves 16 percent reductions in
emission rate at the stack, while CCS achieves an 88.4 percent
reduction in emission rate. As discussed in section IV.B of this
preamble, individual coal-fired power plants are by far the highest-
emitting plants in the nation, and the coal-fired power plant sector is
higher-emitting than any other stationary source sector. Because the
unit-level emission reductions achievable by CCS are substantially
greater, and because CCS is of reasonable cost and matches up well
against the other BSER criteria, the EPA did not determine natural gas
co-firing to be BSER for the long-term subcategory although, under
other circumstances, it could be. Determining BSER requires the EPA to
select the ``best'' of the systems of emission reduction that are
adequately demonstrated, as described in section V.C.2; in this case,
there are two systems of emission reduction that match up well against
the BSER criteria, but based on weighing the criteria together, and in
light of the substantially greater unit-level emission reductions from
CCS, the EPA has determined that CCS is a better system of emission
reduction than co-firing for the long-term subcategory.
The EPA notes that if a state demonstrates that a long-term coal-
fired steam generating unit cannot install and operate CCS and cannot
otherwise reasonably achieve the degree of emission limitation that the
EPA has determined based on CCS, following the process the EPA has
specified in its applicable regulations for consideration of RULOF, the
state would evaluate natural gas co-firing as a potential basis for
establishing a less stringent standard of performance, as detailed in
section X.C.2 of this document.
iii. Heat Rate Improvements
Heat rate improvements were not considered to be BSER for long-term
steam generating units because the achievable reductions are very low
and may result in a rebound effect whereby total emissions from the
source increase, as detailed in section VII.D.4.a of this preamble.
Comment: One commenter requested that HRI be considered as BSER in
addition to CCS, so that long-term sources would be required to achieve
reductions in emission rate consistent with performing HRI and adding
CCS with 90 percent capture to the source.
Response: As described in section VII.D.4.a, the reductions from
HRI are very low and many sources have already made HRI, so that
additional reductions are not available. It is possible that a source
installing CO2 capture will make efficiency improvements as
a matter of best practices. For example, Boundary Dam Unit 3 made
upgrades to the existing steam generating unit when CCS was installed,
including installing a new steam turbine.\660\ However, the reductions
from efficiency improvements would not be additive to the reductions
from CCS because of the impact of the CO2 capture plant on
the efficiency of source due to the required steam and electricity load
of the capture plant.
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\660\ IEAGHG Report 2015-06. Integrated Carbon Capture and
Storage Project at SaskPower's Boundary Dam Power Station. August
2015. https://ieaghg.org/publications/technical-reports/reports-list/9-technical-reports/935-2015-06-integrated-ccs-project-at-saskpower-s-boundary-dam-power-station.
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c. Conclusion
Coal-fired EGUs remain the largest stationary source of dangerous
CO2 emissions. The EPA is finalizing CCS at a capture rate
of 90 percent as the BSER for long-term coal-fired steam generating
units because this system satisfies the criteria for BSER as summarized
here. CCS at a capture rate of 90 percent as the BSER for long-term
coal-fired steam generating units is adequately demonstrated, as
indicated by the facts that it has been operated at scale, is widely
applicable to these sources, and that there are vast sequestration
opportunities across the continental U.S. Additionally, accounting for
recent technology cost declines as well as policies including the tax
credit under IRC section 45Q, the costs for CCS are reasonable.
Moreover, any adverse non-air quality health and environmental impacts
and energy requirements of CCS, including impacts on the power sector
on a nationwide basis, are limited and can be effectively avoided or
mitigated. In contrast, co-firing 40 percent natural gas would achieve
far fewer emission reductions without improving the cost reasonableness
of the control strategy.
These considerations provide the basis for finalizing CCS as the
best of the systems of emission reduction for long-term coal-fired
power plants. In addition, determining CCS as the BSER promotes
advancements in control technology for CO2, which is a
relevant consideration when establishing BSER under section 111 of the
CAA.
i. Adequately Demonstrated
CCS with 90 percent capture is adequately demonstrated based on the
information in section VII.C.1.a.i of this preamble. Solvent-based
CO2 capture was patented nearly 100 years ago in the 1930s
\661\ and has been used in a variety of industrial applications for
decades. Thousands of miles of CO2 pipelines have been
constructed and securely operated in the U.S. for decades.\662\ And
tens of millions of tons of CO2 have been permanently stored
deep underground either for geologic sequestration or in association
with EOR.\663\ There are currently at least 15 operating CCS projects
in the U.S., and another 121 that are under construction or in advanced
stages of development.\664\ This broad application of CCS demonstrates
the successful operation of all three components of CCS, operating both
independently and simultaneously. Various CO2 capture
methods are used in industrial applications and are tailored to the
flue gas conditions of a particular industry (see the final TSD, GHG
Mitigation Measures for Steam Generating Units for details). Of those
capture technologies, amine solvent-based capture has been demonstrated
for removal of CO2 from the post-combustion flue gas of
fossil fuel-fired EGUs.
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\661\ 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.
\662\ U.S. Department of Transportation, Pipeline and Hazardous
Material Safety Administration, ``Hazardous Annual Liquid Data.''
2022. https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
\663\ US EPA. GHGRP. https://www.epa.gov/ghgreporting/supply-underground-injection-and-geologic-sequestration-carbon-dioxide.
\664\ Carbon Capture and Storage in the United States. CBO.
December 13, 2023. https://www.cbo.gov/publication/59345.
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Since 1978, an amine-based system has been used to capture
approximately 270,000 metric tons of CO2 per year from the
flue gas of the bituminous coal-fired steam generating units at the 63
MW Argus Cogeneration Plant (Trona, California).\665\ Amine solvent
capture has been further demonstrated at coal-fired power plants
including AES's Warrior Run and Shady Point. And since 2014, CCS has
been applied at the commercial scale at Boundary Dam Unit 3, a 110 MW
lignite coal-fired steam generating unit in Saskatchewan, Canada.
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\665\ Dooley, J.J., et al. (2009). ``An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009.'' U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.
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Impending increases in Canadian regulatory CO2 emission
requirements have prompted optimization of Boundary Dam Unit 3 so that
the facility now captures 83 percent of its total CO2
emissions. Moreover, from the flue gas
[[Page 39889]]
treated, Boundary Dam Unit 3 consistently captured 90 percent or more
of the CO2 over a 3-year period. The adequate demonstration
of CCS is further corroborated by the EPAct05-assisted 240MW-equivalent
Petra Nova CCS project at the coal-fired W.A. Parish Unit 8, which
achieved over 90 percent capture from the treated flue gas during a 3-
year period. Additionally, the technical improvements put in practice
at Boundary Dam Unit 3 and Petra Nova can be put in place on new
capture facilities during initial construction. This includes
redundancies and isolations for key equipment, and spray systems to
limit fly ash carryover. Projects that have announced plans to install
CO2 capture directly include these improvements in their
design and employ new solvents achieving higher capture rates that are
commercially available from technology providers. As a result, these
projects target capture efficiencies of at least 95 percent, well above
the BSER finalized here.
Precedent, building upon the statutory text and context, has
established that the EPA may make a finding of adequate demonstration
by drawing upon existing data from individual commercial-scale sources,
including testing at these sources,\666\ and that the agency may make
projections based on existing data to establish a more stringent
standard than has been regularly shown,\667\ in particular in cases
when the agency can specifically identify technological improvements
that can be expected to achieve the standard in question.\668\ Further,
the EPA may extrapolate based on testing at a particular kind of source
to conclude that the technology at issue will also be effective at a
different, related, source.\669\ Following this legal standard, the
available data regarding performance and testing at Boundary Dam, a
commercial-scale plant, is enough, by itself, to support the EPA's
adequate demonstration finding for a 90 percent standard. In addition
to this, however, in the 9 years since Boundary Dam began operating,
operators and the EPA have developed a clear understanding of specific
technological improvements which, if implemented, the EPA can
reasonably expect to lead to a 90 percent capture rate on a regular and
ongoing basis. The D.C. Circuit has established that this information
is more than enough to establish that a 90 percent standard is
achievable.\670\ And per Lignite Energy Council, the findings from
Boundary Dam can be extrapolated to other, similarly operating power
plants, including natural gas plants.\671\
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\666\ See Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427 (D.C.
Cir. 1973); Nat'l Asphalt Pavement Ass'n v. Train, 539 F.2d 775
(D.C. Cir. 1976).
\667\ See id.
\668\ See Sierra Club v. Costle, 657 F.2d 298 (1981).
\669\ Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir.
1999).
\670\ See, e.g., Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427
(D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (1981).
\671\ 198 F.3d 930 (D.C. Cir. 1999).
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Transport of CO2 and geological storage of
CO2 have also been adequately demonstrated, as detailed in
VII.C.1.a.i(B)(7) and VII.C.1.a.i(D)(2). CO2 has been
transported through pipelines for over 60 years, and in the past 20
years, 500 million metric tons of CO2 moved through over
5,000 miles of CO2 pipelines. CO2 pipeline
controls and PHMSA standards ensure that captured CO2 will
be securely conveyed to a sequestration site. Due to the proximity of
sources to storage, it would be feasible for most sources to build
smaller and shorter source-to-sink laterals, rather than rely on a
trunkline network buildout. In addition to pipelines, CO2
can also be transported via vessel, highway, or rail. Geological
storage is proven and broadly available, and of the coal-fired steam
generating units with planned operation during or after 2030, 77
percent are within 40 miles of the boundary of a saline reservoir.
The EPA also considered the timelines, materials, and workforce
necessary for installing CCS, and determined they are sufficient.
ii. Cost
Process improvements have resulted in a decrease in the projected
costs to install CCS on existing coal-fired steam generating units.
Additionally, the IRC section 45Q tax credit provides $85 per metric
ton ($77 per ton) of CO2. It is reasonable to account for
the IRC section 45Q tax credit because the costs that should be
accounted for are the costs to the source. For the fleet of coal-fired
steam generating units with planned operation during or after 2033, and
assuming a 12-year amortization period and 80 percent annual capacity
factor and including source specific transport and storage costs, the
average total costs of CCS are -$5/ton of CO2 reduced and -
$4/MWh. And even for shorter amortization periods, the $/MWh costs are
comparable to or less than the costs for other controls ($10.60-$18.50/
MWh) for a substantial number of sources. Notably, the EPA's IPM model
projects that even without this final rule--that is, in the base case,
without any CAA section 111 requirements--some units would deploy CCS.
Similarly, the IPM model projects that even if this rule determined 40
percent co-firing to be the BSER for long-term coal, instead of CCS,
some additional units would deploy CCS. Therefore, the costs of CCS
with 90 percent capture are reasonable.
iii. Non-Air Quality Health and Environmental Impacts and Energy
Requirements
The CO2 capture plant requires substantial pre-treatment
of the flue gas to remove SO2 and fly ash (PM) while other
controls and process designs are necessary to minimize solvent
degradation and solvent loss. Although CCS has the potential to result
in some increases in non-GHG emissions, a robust regulatory framework,
generally implemented at the state level, is in place to mitigate other
non-GHG emissions from the CO2 capture plant. For transport,
pipeline safety is regulated by PHMSA, while UIC Class VI regulations
under the SDWA, in tandem with GHGRP subpart RR requirements, ensure
the protection of USDWs and the security of geologic sequestration.
Therefore, the potential non-air quality health and environmental
impacts do not militate against designating CCS as the BSER for long-
term steam EGUs. The EPA also considered energy requirements. While the
CO2 capture plant requires steam and electricity to operate,
the incentives provided by the IRC section 45Q tax credit will likely
result in increased total generation from the source. Therefore, the
energy requirements are not unreasonable, and there would be limited,
non-adverse impacts on the broader energy sector.
2. Medium-Term Coal-Fired Steam Generating Units
The EPA is finalizing its conclusion that 40 percent natural gas
co-firing on a heat input basis is the BSER for medium-term coal-fired
steam generating units. Co-firing 40 percent natural gas, on an annual
average heat input basis, results in a 16 percent reduction in
CO2 emission rate. The technology has been adequately
demonstrated, can be implemented at reasonable cost, does not have
significant adverse non-air quality health and environmental impacts or
energy requirements, including impacts on the energy sector, and
achieves meaningful reductions in CO2 emissions. Co-firing
also advances useful control technology, which provides additional,
although not essential, support for treating it as the BSER.
[[Page 39890]]
a. Rationale for the Medium-Term Coal-Fired Steam Generating Unit
Subcategory
For the development of the emission guidelines, the EPA first
considered CCS as the BSER for existing coal-fired steam generating
units. CCS generally achieves significant emission reductions at
reasonable cost. Typically, in setting the BSER, the EPA assumes that
regulated units will continue to operate indefinitely. However, that
assumption is not appropriate for all coal-fired steam generating
units. 62 percent of existing coal-fired steam generating units greater
than 25 MW have already announced that they will retire or convert from
coal to gas by 2039.\672\ CCS is capital cost-intensive, entailing a
certain period to amortize the capital costs. Therefore, the EPA
evaluated the costs of CCS for different amortization periods, as
detailed in section VII.C.1.a.ii of the preamble, and determined that
CCS was cost reasonable, on average, for sources operating more than 7
years after the compliance date of January 1, 2032. Accordingly, units
that cease operating before January 1, 2039, will generally have less
time to amortize the capital costs, and the costs for those sources
would be higher and thereby less comparable to those the EPA has
previously determined to be reasonable. Considering this, and the other
factors evaluated in determining BSER, the EPA is not finalizing CCS as
BSER for units demonstrating that they plan to permanently cease
operation prior to January 1, 2039.
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\672\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v7. December 2023. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
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Instead, the EPA is subcategorizing these units into the medium-
term subcategory and finalizing a BSER based on 40 percent natural gas
co-firing on a heat input basis for these units. Co-firing natural gas
at 40 percent has significantly lower capital costs than CCS and can be
implemented by January 1, 2030. For sources that expect to continue in
operation until January 1, 2039, and that therefore have a 9-year
amortization period, the costs of 40 percent co-firing are $73/ton of
CO2 reduced or $13/MWh of generation, which supports their
reasonableness because they are comparable to or less than the costs
detailed in section VII.C.1.a.ii(D) of this preamble for other controls
on EGUs ($10.60 to $18.50/MWh) and for GHGs for the Crude Oil and
Natural Gas source category in the 2016 NSPS of $98/ton of
CO2e reduced (80 FR 56627; September 18, 2015). Co-firing is
also cost-reasonable for sources permanently ceasing operations sooner,
and that therefore have a shorter amortization period. As discussed in
section VII.B.2 of this preamble, with a two-year amortization period,
many units can co-fire with meaningful amounts of natural gas at
reasonable cost. Of course, even more can co-fire at reasonable costs
with amortization periods longer than two years. For example, the EPA
has determined that 33 percent of sources with an amortization period
of at least three years have costs for 40 percent co-firing below both
of the $/ton and $/MWh metrics, and 68 percent of those sources have
costs for 20 percent co-firing below both of those metrics. Therefore,
recognizing that operating horizon affects the cost reasonableness of
controls, the EPA is finalizing a separate subcategory for coal-fired
steam generating units operating in the medium-term--those
demonstrating that they plan to permanently cease operation after
December 31, 2031, and before January 1, 2039--with 40 percent natural
gas co-firing as the BSER.
i. Legal Basis for Establishing the Medium-Term Subcategory
As noted in section V.C.1 of this preamble, the EPA has broad
authority under CAA section 111(d) to identify subcategories. As also
noted in section V.C.1, the EPA's authority to ``distinguish among
classes, types, and sizes within categories,'' as provided under CAA
section 111(b)(2) and as we interpret CAA section 111(d) to provide as
well, generally allows the Agency to place types of sources into
subcategories when they have characteristics that are relevant to the
controls that the EPA may determine to be the BSER for those sources.
One element of the BSER is cost reasonableness. See CAA section
111(d)(1) (requiring the EPA, in setting the BSER, to ``tak[e] into
account the cost of achieving such reduction''). As noted in section V,
the EPA's longstanding regulations under CAA section 111(d) explicitly
recognize that subcategorizing may be appropriate for sources based on
the ``costs of control.'' \673\ Subcategorizing on the basis of
operating horizon is consistent with a key characteristic of the coal-
fired power industry that is relevant for determining the cost
reasonableness of control requirements: A large percentage of the
sources in the industry have already announced, and more are expected
to announce, dates for ceasing operation, and the fact that many coal-
fired steam generating units intend to cease operation in the near term
affects what controls are ``best'' for different subcategories.\674\ At
the outset, installation of emission control technology takes time,
sometimes several years. Whether the costs of control are reasonable
depends in part on the period of time over which the affected sources
can amortize those costs. Sources that have shorter operating horizons
will have less time to amortize capital costs. Thus, the annualized
cost of controls may thereby be less comparable to the costs the EPA
has previously determined to be reasonable.\675\
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\673\ 40 CFR 60.22(b)(5), 60.22a(b)(5).
\674\ The EPA recognizes that section 111(d) provides that in
applying standards of performance, a state may take into account,
among other factors, the remaining useful life of a facility. The
EPA believes that provision is intended to address exceptional
circumstances at particular facilities, while the EPA has the
responsibility to determine how to address the source category as a
whole. See 88 FR 80480, 80511 (November 17, 2023) (``Under CAA 111,
EPA must provide BSER and degree of emission limitation
determinations that are, to the extent reasonably practicable,
applicable to all designated facilities in the source category. In
many cases, this requires the EPA to create subcategories of
designated facilities, each of which has a BSER and degree of
emission limitation tailored to its circumstances. . . . However, as
Congress recognized, this may not be possible in every instance
because, for example, it is not be feasible [sic] for the Agency to
know and consider the idiosyncrasies of every designated facility or
because the circumstances of individual facilities change after the
EPA determined the BSER.'') (internal citations omitted). That a
state may take into account the remaining useful life of an
individual source, however, does not bar the EPA from considering
operating horizon as a factor in determining whether
subcategorization is appropriate. As discussed, the authority to
subcategorize is encompassed within the EPA's authority to identify
the BSER. Here, where many units share similar characteristics and
have announced intended shorter operating horizons, it is
permissible for the EPA to take operating horizon into account in
determining the BSER for this subcategory of sources. States may
continue to take RULOF factors into account for particular units
where the information relevant to those units is fundamentally
different than the information the EPA took into account in
determining the degree of emission limitation achievable through
application of the BSER. Should a court conclude that the EPA does
not have the authority to create a subcategory based on the date at
which units intend to cease operation, then the EPA believes it
would be reasonable for states to consider co-firing as an
alternative to CCS as an option for these units through the states'
authority to consider, among other factors, remaining useful life.
\675\ Steam Electric Reconsideration Rule, 85 FR 64650, 64679
(October 13, 2020) (distinguishes between EGUs retiring before 2028
and EGUs remaining in operation after that time).
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In addition, subcategorizing by length of period of continued
operation is similar to two other bases for subcategorization on which
the EPA has relied in prior rules, each of which implicates the cost
reasonableness of controls: The first is load level, noted in section
V.C.1. of this preamble. For
[[Page 39891]]
example, in the 2015 NSPS, the EPA divided new natural gas-fired
combustion turbines into the subcategories of base load and non-base
load. 80 FR 64602 (table 15) (October 23, 2015). The EPA did so because
the control technologies that were ``best''--including consideration of
feasibility and cost reasonableness--depended on how much the unit
operated. The load level, which relates to the amount of product
produced on a yearly or other basis, bears similarity to a limit on a
period of continued operation, which concerns the amount of time
remaining to produce the product. In both cases, certain technologies
may not be cost-reasonable because of the capacity to produce product--
i.e., the costs are spread over less product produced.
Subcategorization on this basis is also supported by how utilities
manage their assets over the long term, and was widely supported by
industry commenters.
The second basis for subcategorization on which EPA has previously
relied is fuel type, as also noted in section V.C.1 of this preamble.
The 2015 NSPS provides an example of this type of subcategorization as
well. There, the EPA divided new combustion turbines into subcategories
on the basis of type of fuel combusted. Id. Subcategorizing on the
basis of the type of fuel combusted may be appropriate when different
controls have different costs, depending on the type of fuel, so that
the cost reasonableness of the control depends on the type of fuel. In
that way, it is similar to subcategorizing by operating horizon because
in both cases, the subcategory is based upon the cost reasonableness of
controls. Subcategorizing by operating horizon is also tantamount to
the length of time over which the source will continue to combust the
fuel. Subcategorizing on this basis may be appropriate when different
controls for a particular fuel have different costs, depending on the
length of time when the fuel will continue to be combusted, so that the
cost reasonableness of controls depends on that timeframe. Some prior
EPA rules for coal-fired sources have made explicit the link between
length of time for continued operation and type of fuel combusted by
codifying federally enforceable retirement dates as the dates by which
the source must ``cease burning coal.'' \676\
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\676\ See 79 FR 5031, 5192 (January 30, 2014) (explaining that
``[t]he construction permit issued by Wyoming requires Naughton Unit
3 to cease burning coal by December 31, 2017, and to be retrofitted
to natural gas as its fuel source by June 30, 2018'' (emphasis
added)).
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As noted above, creating a subcategory on the basis of operating
horizon does not preclude a state from considering RULOF in applying a
standard of performance to a particular source. The EPA's authority to
set BSER for a source category (including subcategories) and a state's
authority to invoke RULOF for individual sources within a category or
subcategory are distinct. The EPA's statutory obligation is to
determine a generally applicable BSER for a source category, and where
that source category encompasses different classes, types, or sizes of
sources, to set generally applicable BSERs for subcategories accounting
for those differences. By contrast, states' authority to invoke RULOF
is premised on the state's ability to take into account information
relevant to individual units that is fundamentally different than the
information the EPA took into account in determining BSER generally. As
noted, the EPA may subcategorize on the basis of cost of controls, and
operating horizon may factor into the cost of controls. Moreover,
through section 111(d)(1), Congress also required the EPA to develop
regulations that permit states to consider ``among other factors, the
remaining useful life'' of a particular existing source. The EPA has
interpreted these other factors to include costs or technical
feasibility specific to a particular source, even though these are
factors the EPA itself considers in setting the BSER. In other words,
the factors the EPA may consider in setting the BSER and the factors
the states may consider in applying standards of performance are not
distinct. As noted above, the EPA is finalizing these subcategories in
response to requests by power sector representatives that this rule
accommodate the fact that there is a class of sources that plan to
voluntarily cease operations in the near term. Although the EPA has
designed the subcategories to accommodate those requests, a particular
source may still present source-specific considerations--whether
related to its remaining useful life or other factors--that the state
may consider relevant for the application of that particular source's
standard of performance, and that the state should address as described
in section X.C.2 of this preamble.
ii. Comments Received on Existing Coal-Fired Subcategories
Comment: The EPA received several comments on the proposed
subcategories for coal-fired steam generating units. Many commenters,
including industry commenters, supported these subcategories. Some
commenters opposed these proposed subcategories. They argued that the
subcategories were designed to force coal-fired power plants to retire.
Response: We disagree with comments suggesting that the
subcategories for existing coal-fired steam EGUs that the EPA has
finalized in this rule were designed to force retirements. The
subcategories were not designed for that purpose, and the commenters do
not explain their allegations to the contrary. The subcategories were
designed, at industry's request,\677\ to ensure that subcategories of
units that can feasibly and cost-reasonably employ emissions reduction
technologies--and only those subcategories of units that can do so--are
required to reduce their emissions commensurate with those
technologies. As explained above, in determining the BSER, the EPA
generally assumes that a source will operate indefinitely, and
calculates expected control costs on that basis. Under that assumption,
the BSER for existing fossil-fuel fired EGUs is CCS. Nevertheless, the
EPA recognizes that many fossil-fuel fired EGUs have already announced
plans to cease operation. In recognition of this unique, distinguishing
factor, the EPA determined whether a different BSER would be
appropriate for fossil fuel-fired EGUs that do not intend to operate
over the long term, and concluded, for the reasons stated above, that
natural gas co-firing was appropriate for these sources that intended
to cease operation before 2039. This subcategory is not intended to
force retirements, and the EPA is not directing any state or any unit
as to the choice of when to cease operation. Rather, the EPA has
created this subcategory to accommodate these sources' intended
operation plans. In fact, a number of industry commenters specifically
requested and supported subcategories based on retirement dates in
recognition of the reality that many operators are choosing to retire
these units and that whether or not a control technology is feasible
and cost-reasonable depends upon how long a unit intends to operate.
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\677\ As described in the proposal, during the early engagement
process, industry stakeholders requested that the EPA ``[p]rovide
approaches that allow for the retirement of units as opposed to
investments in new control technologies, which could prolong the
lives of higher-emitting EGUs; this will achieve maximum and durable
environmental benefits.'' Industry stakeholders also suggested that
the EPA recognize that some units may remain operational for a
several-year period but will do so at limited capacity (in part to
assure reliability), and then voluntarily cease operations entirely.
88 FR 33245 (May 23, 2023).
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Specifically, as noted in section VII.B of this preamble, in this
final action, the
[[Page 39892]]
medium-term subcategory includes a date for permanently ceasing
operation, which applies to coal-fired plants demonstrating that they
plan to permanently cease operating after December 31, 2031, and before
January 1, 2039. The EPA is retaining this subcategory because 55
percent of existing coal-fired steam generating units greater than 25
MW have already announced that they will retire or convert from coal to
gas by January 1, 2039.\678\ Accordingly, the costs of CCS--the high
capital costs of which require a lengthy amortization period from its
January 1, 2032, implementation date--are higher than the traditional
metric for cost reasonableness for these sources. As discussed in
section VII.C.2 of this preamble, the BSER for these sources is co-
firing 40 percent natural gas. This is because co-firing, which has an
implementation date of January 1, 2030, has lower capital costs and is
therefore cost-reasonable for sources continuing to operate on or after
January 1, 2032. It is further noted that this subcategory is elective.
Furthermore, states also have the authority to establish a less
stringent standard through RULOF in the state plan process, as detailed
in section X.C.2 of this preamble.
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\678\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v7. December 2023. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
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In sum, these emission guidelines do not require any coal-fired
steam EGU to retire, nor are they intended to induce retirements.
Rather, these emission guidelines simply set forth presumptive
standards that are cost-reasonable and achievable for each subcategory
of existing coal-fired steam EGUs. See section VII.E.1 of this preamble
(responding to comments that this rule violates the major questions
doctrine).
Comment: The EPA broadly solicited comment on the dates and values
defining the proposed subcategories for coal-fired steam generating
units. Regarding the proposed dates for the subcategories, one industry
stakeholder commented that the ``EPA's proposed retirement dates for
applicability of the various subcategories are appropriate and broadly
consistent with system reliability needs.'' \679\ More specifically,
industry commenters requested that the cease-operation-by date for the
imminent-term subcategory be changed from January 1, 2032, to January
1, 2033. Industry commenters also stated that the 20 percent
utilization limit in the definition of the near-term subcategory was
overly restrictive and inconsistent with the emissions stringency of
either the proposed medium term or imminent term subcategory--
commenters requested greater flexibility for the near-term subcategory.
Other comments from NGOs and other groups suggested various other
changes to the subcategory definitions. One commenter requested moving
the cease-operation-by date for the medium-term subcategory up to
January 1, 2038, while eliminating the imminent-term subcategory and
extending the near-term subcategory to January 1, 2038.
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\679\ See Document ID No. EPA-HQ-OAR-2023-0072-0772.
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Response: The EPA is not finalizing the proposed imminent-term or
near-term subcategories. The EPA is finalizing an applicability
exemption for sources demonstrating that they plan to permanently cease
operation prior to January 1, 2032, as detailed in section VII.B of
this preamble. The EPA is finalizing the cease operating by date of
January 1, 2039, for medium-term coal-fired steam generating units.
These dates are all based on costs of co-firing and CCS, driven by
their amortization periods, as discussed in the preceding sections of
this preamble.
b. Rationale for Natural Gas Co-Firing as the BSER for Medium-Term
Coal-Fired Steam Generating Units
In this section of the preamble, the EPA describes its rationale
for natural gas co-firing as the final BSER for medium-term coal-fired
steam generating units.
For a coal-fired steam generating unit, the substitution of natural
gas for some of the coal, so that the unit fires a combination of coal
and natural gas, is known as ``natural gas co-firing.'' The EPA is
finalizing natural gas co-firing at a level of 40 percent of annual
heat input as BSER for medium-term coal-fired steam generating units.
i. Adequately Demonstrated
The EPA is finalizing its determination that natural gas co-firing
at the level of 40 percent of annual heat input is adequately
demonstrated for coal-fired steam generating units. Many existing coal-
fired steam generating units already use some amount of natural gas,
and several have co-fired at relatively high levels at or above 40
percent of heat input in recent years.
(A) Boiler Modifications
Existing coal-fired steam generating units can be modified to co-
fire natural gas in any desired proportion with coal, up to 100 percent
natural gas. Generally, the modification of existing boilers to enable
or increase natural gas firing typically involves the installation of
new gas burners and related boiler modifications, including, for
example, new fuel supply lines and modifications to existing air ducts.
The introduction of natural gas as a fuel can reduce boiler efficiency
slightly, due in large part to the relatively high hydrogen content of
natural gas. However, since the reduction in coal can result in reduced
auxiliary power demand, the overall impact on net heat rate can range
from a 2 percent increase to a 2 percent decrease.
It is common practice for steam generating units to have the
capability to burn multiple fuels onsite, and of the 565 coal-fired
steam generating units operating at the end of 2021, 249 of them
reported consuming natural gas as a fuel or startup source. Coal-fired
steam generating units often use natural gas or oil as a startup fuel,
to warm the units up before running them at full capacity with coal.
While startup fuels are generally used at low levels (up to roughly 1
percent of capacity on an annual average basis), some coal-fired steam
generating units have co-fired natural gas at considerably higher
shares. Based on hourly reported CO2 emission rates from the
start of 2015 through the end of 2020, 29 coal-fired steam generating
units co-fired with natural gas at rates at or above 60 percent of
capacity on an hourly basis.\680\ The capability of those units on an
hourly basis is indicative of the extent of boiler burner modifications
and sizing and capacity of natural gas pipelines to those units, and
implies that those units are technically capable of co-firing at least
60 percent natural gas on a heat input basis on average over the course
of an extended period (e.g., a year). Additionally, during that same
2015 through 2020 period, 29 coal-fired steam generating units co-fired
natural gas at over 40 percent on an annual heat input basis. Because
of the number of units that have demonstrated co-firing above 40
percent of heat input, the EPA is finalizing that co-firing at 40
percent is adequately demonstrated. A more detailed discussion of the
record of natural gas co-firing, including current trends, at coal-
fired steam generating units is included in the final TSD, GHG
Mitigation Measures for Steam Generating Units.
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\680\ U.S. Environmental Protection Agency (EPA). ``Power Sector
Emissions Data.'' Washington, DC: Office of Atmospheric Protection,
Clean Air Markets Division. Available from EPA's Air Markets Program
Data website: https://campd.epa.gov.
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(B) Natural Gas Pipeline Development
In addition to any potential boiler modifications, the supply of
natural gas is necessary to enable co-firing at existing coal-fired
steam boilers. As
[[Page 39893]]
discussed in the previous section, many plants already have at least
some access to natural gas. In order to increase natural gas access
beyond current levels, plants may find it necessary to construct
natural gas supply pipelines.
The U.S. natural gas pipeline network consists of approximately 3
million miles of pipelines that connect natural gas production with
consumers of natural gas. To increase natural gas consumption at a
coal-fired boiler without sufficient existing natural gas access, it is
necessary to connect the facility to the natural gas pipeline
transmission network via the construction of a lateral pipeline. The
cost of doing so is a function of the total necessary pipeline capacity
(which is characterized by the length, size, and number of laterals)
and the location of the plant relative to the existing pipeline
transmission network. The EPA estimated the costs associated with
developing new lateral pipeline capacity sufficient to meet 60 percent
of the net summer capacity at each coal-fired steam generating unit
that could be included in this subcategory. As discussed in the final
TSD, GHG Mitigation Measures for Steam Generating Units, the EPA
estimates that this lateral capacity would be sufficient to enable each
unit to achieve 40 percent natural gas co-firing on an annual average
basis.
The EPA considered the availability of the upstream natural gas
pipeline capacity to satisfy the assumed co-firing demand implied by
these new laterals. This analysis included pipeline development at all
EGUs that could be included in this subcategory, including those
without announced plans to cease operating before January 1, 2039. The
EPA's assessment reviewed the reasonableness of each assumed new
lateral by determining whether the peak gas capacity of that lateral
could be satisfied without modification of the transmission pipeline
systems to which it is assumed to be connected. This analysis found
that most, if not all, existing pipeline systems are currently able to
meet the peak needs implied by these new laterals in aggregate,
assuming that each existing coal-fired unit in the analysis co-fired
with natural gas at a level implied by these new laterals, or 60
percent of net summer generating capacity. While this is a reasonable
assumption for the analysis to support this mitigation measure in the
BSER context, it is also a conservative assumption that overstates the
amount of natural gas co-firing expected under the final rule.\681\
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\681\ In practice, not all sources would necessarily be subject
to a natural gas co-firing BSER in compliance. E.g., some portion of
that population of sources could install CCS, so the resulting
amount of natural gas co-firing would be less.
---------------------------------------------------------------------------
Most of these individual laterals are less than 15 miles in length.
The maximum aggregate amount of pipeline capacity, if all coal-fired
steam capacity that could be included in the medium-term subcategory
(i.e., all capacity that has not announced that it plans to retire by
2032) implemented the final BSER by co-firing 40 percent natural gas,
would be comparable to pipeline capacity constructed recently. The EPA
estimates that this maximum total capacity would be nearly 14.7 billion
cubic feet per day, which would require about 3,500 miles of pipeline
costing roughly $11.5 billion. Over 2 years,\682\ this maximum total
incremental pipeline capacity would amount to less than 1,800 miles per
year, with a total annual capacity of roughly 7.35 billion cubic feet
per day. This represents an estimated annual investment of
approximately $5.75 billion per year in capital expenditures, on
average. By comparison, based on data collected by EIA, the total
annual mileage of natural gas pipelines constructed over the 2017-2021
period ranged from approximately 1,000 to 2,500 miles per year, with a
total annual capacity of 10 to 25 billion cubic feet per day. This
represents an estimated annual investment of up to nearly $15 billion.
The upper end of these historical annual values is much higher than the
maximum annual values that could be expected under this final BSER
measure--which, as noted above, represent a conservative estimate that
significantly overstates the amount of co-firing that the EPA projects
would occur under this final rule.
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\682\ The average time for permitting for a natural gas pipeline
lateral is 1.5 years, and many sources could be permitted faster
(about 1 year) so that it is reasonable to assume that many sources
could begin construction by June 2027. The average time for
construction of an individual pipeline is about 1 year or less.
Considering this, the EPA assumes construction of all of the natural
gas pipeline laterals in the analysis occurs over a 2-year period
(June 2027 through June 2029), and notes that in practice some of
these projects could be constructed outside of this period.
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These conservatively high estimates of pipeline requirements also
compare favorably to industry projections of future pipeline capacity
additions. Based on a review of a 2018 industry report, titled ``North
America Midstream Infrastructure through 2035: Significant Development
Continues,'' investment in midstream infrastructure development is
expected to range between $10 to $20 billion per year through 2035.
Approximately $5 to $10 billion annually is expected to be invested in
natural gas pipelines through 2035. This report also projects that an
average of over 1,400 miles of new natural gas pipeline will be built
through 2035, which is similar to the approximately 1,670 miles that
were built on average from 2013 to 2017. These values are consistent
with the average annual expenditure of $5.75 billion on less than 1,800
miles per year of new pipeline construction that would be necessary for
the entire operational fleet of existing coal-fired steam generating
units to co-fire with natural gas. The actual pipeline investment for
this subcategory would be substantially lower.
(C) Compliance Date for Medium-Term Coal-Fired Steam Generating Units
The EPA is finalizing a compliance date for medium-term coal-fired
steam generating units of January 1, 2030.
As in the timeline for CCS for the long term coal-fired steam
generating units described in section VII.C.1.a.i(E), the EPA assumes
here that feasibility work occurs during the state plan development
period, and that all subsequent work occurs after the state plan is
submitted and thereby effective at the state level. The EPA assumes 12
months of feasibility work for the natural gas pipeline lateral and 6
months of feasibility work for boiler modifications (both to occur over
June 2024 to June 2025). As with the feasibility analysis for CCS, the
feasibility analysis for co-firing will inform the state plan and
therefore it is reasonable to assume units will perform it during the
state planning window. Feasibility for the pipeline includes a right-
of-way and routing analysis. Feasibility for the boiler modifications
includes conceptual studies and design basis.
The timeline for the natural gas pipeline permitting and
construction is based on a review of recently completed permitting
approvals and construction.\683\ The average time to complete
permitting and approval is less than 1.5 years, and the average time to
complete actual construction is less than 1 year. Of the 31 reviewed
pipeline projects, the vast majority (27 projects) took less than a
total of 3 years for permitting and construction, and none took more
than 3.5 years. Therefore, it is reasonable to assume that permitting
and construction would take no more than 3 years for most sources (June
2026 to June 2029), noting that permitting
[[Page 39894]]
and construction for many sources would be faster.
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\683\ Documentation for the Lateral Cost Estimation (2024), ICF
International. Available in Docket ID EPA-HQ-OAR-2023-0072.
---------------------------------------------------------------------------
The timeline for boiler modifications based on the baseline
duration co-firing conversion project schedule developed by Sargent and
Lundy.\684\ The EPA assumes that, with the exception of the feasibility
studies discussed above, work on the boiler modifications begins after
the state plan submission due date. The EPA also assumes permitting for
the boiler modifications is required and takes 12 months (June 2026 to
June 2027). In the schedule developed by Sargent and Lundy, commercial
arrangements for the boiler modification take about 6 months (June 2026
to December 2026). Detailed engineering and procurement takes about 7
months (December 2026 to July 2027), and begins after commercial
arrangements are complete. Site work takes 3 months (July 2027 to
October 2027), followed by 4 months of construction (October 2027 to
February 2028). Lastly, startup and testing takes about 2 months (June
2029 to August 2029), noting that the EPA assumes this occurs after the
natural gas pipeline lateral is constructed. Considering the preceding
information, the EPA has determined January 1, 2030 is the compliance
date for medium-term coal-fired steam generating units.
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\684\ Natural Gas Co-Firing Memo, Sargent & Lundy (2023).
Available in Docket ID EPA-HQ-OAR-2023-0072.
---------------------------------------------------------------------------
ii. Costs
The capital costs associated with the addition of new gas burners
and other necessary boiler modifications depend on the extent to which
the current boiler is already able to co-fire with some natural gas and
on the amount of gas co-firing desired. The EPA estimates that, on
average, the total capital cost associated with modifying existing
boilers to operate at up to 100 percent of heat input using natural gas
is approximately $52/kW. These costs could be higher or lower,
depending on the equipment that is already installed and the expected
impact on heat rate or steam temperature.
While fixed O&M (FOM) costs can potentially decrease as a result of
decreasing the amount of coal consumed, it is common for plants to
maintain operation of one coal pulverizer at all times, which is
necessary for maintaining several coal burners in continuous service.
In this case, coal handling equipment would be required to operate
continuously and therefore natural gas co-firing would have limited
effect on reducing the coal-related FOM costs. Although, as noted,
coal-related FOM costs have the potential to decrease, the EPA does not
anticipate a significant increase in impact on FOM costs related to co-
firing with natural gas.
In addition to capital and FOM cost impacts, any additional natural
gas co-firing would result in incremental costs related to the
differential in fuel cost, taking into consideration the difference in
delivered coal and gas prices, as well as any potential impact on the
overall net heat rate. The EPA's reference case projects that in 2030,
the average delivered price of coal will be $1.56/MMBtu and the average
delivered price of natural gas will be $2.95/MMBtu. Thus, assuming the
same level of generation and no impact on heat rate, the additional
fuel cost would be $1.39/MMBtu on average in 2030. The total additional
fuel cost could increase or decrease depending on the potential impact
on net heat rate. An increase in net heat rate, for example, would
result in more fuel required to produce a given amount of generation
and thus additional cost. In the final TSD, GHG Mitigation Measures for
Steam Generating Units, the EPA's cost estimates assume a 1 percent
average increase in net heat rate.
Finally, for plants without sufficient access to natural gas, it is
also necessary to construct new natural gas pipelines (``laterals'').
Pipeline costs are typically expressed in terms of dollars per inch of
pipeline diameter per mile of pipeline distance (i.e., dollars per
inch-mile), reflecting the fact that costs increase with larger
diameters and longer pipelines. On average, the cost for lateral
development within the contiguous U.S. is approximately $280,000 per
inch-mile (2019$), which can vary based on site-specific factors. The
total pipeline cost for each coal-fired steam generating unit is a
function of this cost, as well as a function of the necessary pipeline
capacity and the location of the plant relative to the existing
pipeline transmission network. The pipeline capacity required depends
on the amount of co-firing desired as well as on the desired level of
generation--a higher degree of co-firing while operating at full load
would require more pipeline capacity than a lower degree of co-firing
while operating at partial load. It is reasonable to assume that most
plant owners would develop sufficient pipeline capacity to deliver the
maximum amount of desired gas use in any moment, enabling higher levels
of co-firing during periods of lower fuel price differentials. Once the
necessary pipeline capacity is determined, the total lateral cost can
be estimated by considering the location of each plant relative to the
existing natural gas transmission pipelines as well as the available
excess capacity of each of those existing pipelines.
The EPA determined the costs of 40 percent co-firing based on the
fleet of coal-fired steam generating units that existed in 2021 and
that do not have known plans to cease operations or convert to gas by
2032, and assuming that each of those units continues to operate at the
same level as it operated over 2017-2021. The EPA assessed those costs
against the cost reasonableness metrics, as described in section
VII.C.1.a.ii(D) of this preamble (i.e., emission control costs on EGUs
of $10.60 to $18.50/MWh and the costs in the 2016 NSPS regulating GHGs
for the Crude Oil and Natural Gas source category of $98/ton of
CO2e reduced (80 FR 56627; September 18, 2015)). On average,
the EPA estimates that the weighted average cost of co-firing with 40
percent natural gas as the BSER on an annual average basis is
approximately $73/ton CO2 reduced, or $13/MWh. The costs
here reflect an amortization period of 9 years. These estimates support
a conclusion that co-firing is cost-reasonable for sources that
continue to operate up until the January 1, 2039, threshold date for
the subcategory. The EPA also evaluated the fleet average costs of
natural gas co-firing for shorter amortization periods and has
determined that the costs are consistent with the cost reasonableness
metrics for the majority of sources that will operate past January 1,
2032, and therefore have an amortization period of at least 2 years and
up to 9 years. These estimates and all underlying assumptions are
explained in detail in the final TSD, GHG Mitigation Measures for Steam
Generating Units. Based on this cost analysis, alongside the EPA's
overall assessment of the costs of this rule, the EPA is finalizing
that the costs of natural gas co-firing are reasonable for the medium-
term coal-fired steam generating unit subcategory. If a particular
source has costs of 40 percent co-firing that are fundamentally
different from the cost reasonability metrics, the state may consider
this fact under the RULOF provisions, as detailed in section X.C.2 of
this preamble. The EPA previously estimated the cost of natural gas co-
firing in the Clean Power Plan (CPP). 80 FR 64662 (October 23, 2015).
The cost-estimates for co-firing presented in this section are lower
than in the CPP, for several reasons. Since then, the expected
difference between coal and gas prices has decreased significantly,
from over $3/MMBtu to less than $1.50/MMBtu in this final rule.
Additionally,
[[Page 39895]]
a recent analysis performed by Sargent and Lundy for the EPA supports a
considerably lower capital cost for modifying existing boilers to co-
fire with natural gas. The EPA also recently conducted a highly
detailed facility-level analysis of natural gas pipeline costs, the
median value of which is slightly lower than the value used by the EPA
previously to approximate the cost of co-firing at a representative
unit.
iii. Non-Air Quality Health and Environmental Impact and Energy
Requirements
Natural gas co-firing for steam generating units is not expected to
have any significant adverse consequences related to non-air quality
health and environmental impacts or energy requirements.
(A) Non-GHG Emissions
Non-GHG emissions are reduced when steam generating units co-fire
with natural gas because less coal is combusted. SO2,
PM2.5, acid gas, mercury and other hazardous air pollutant
emissions that result from coal combustion are reduced proportionally
to the amount of natural gas consumed, i.e., under this final rule, by
40 percent. Natural gas combustion does produce NOX
emissions, but in lesser amounts than from coal-firing. However, the
magnitude of this reduction is dependent on the combustion system
modifications that are implemented to facilitate natural gas co-firing.
Sufficient regulations also exist related to natural gas pipelines
and transport that assure natural gas can be safely transported with
minimal risk of environmental release. PHMSA develops and enforces
regulations for the safe, reliable, and environmentally sound operation
of the nation's 2.6 million mile pipeline transportation system.
Recently, PHMSA finalized a rule that will improve the safety and
strengthen the environmental protection of more than 300,000 miles of
onshore gas transmission pipelines.\685\ PHMSA also recently
promulgated a separate rule covering natural gas transmission,\686\ as
well as a rule that significantly expanded the scope of safety and
reporting requirements for more than 400,000 miles of previously
unregulated gas gathering lines.\687\ FERC is responsible for the
regulation of the siting, construction, and/or abandonment of
interstate natural gas pipelines, gas storage facilities, and Liquified
Natural Gas (LNG) terminals.
---------------------------------------------------------------------------
\685\ Pipeline Safety: Safety of Gas Transmission Pipelines:
Repair Criteria, Integrity Management Improvements, Cathodic
Protection, Management of Change, and Other Related Amendments (87
FR 52224; August 24, 2022).
\686\ Pipeline Safety: Safety of Gas Transmission Pipelines:
MAOP Reconfirmation, Expansion of Assessment Requirements, and Other
Related Amendments (84 FR 52180; October 1, 2019).
\687\ Pipeline Safety: Safety of Gas Gathering Pipelines:
Extension of Reporting Requirements, Regulation of Large, High-
Pressure Lines, and Other Related Amendments (86 FR 63266; November
15, 2021).
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(B) Energy Requirements
The introduction of natural gas co-firing will cause steam boilers
to be slightly less efficient due to the high hydrogen content of
natural gas. Co-firing at levels between 20 percent and 100 percent can
be expected to decrease boiler efficiency between 1 percent and 5
percent. However, despite the decrease in boiler efficiency, the
overall net output efficiency of a steam generating unit that switches
from coal- to natural gas-firing may change only slightly, in either a
positive or negative direction. Since co-firing reduces coal
consumption, the auxiliary power demand related to coal handling and
emissions controls typically decreases as well. While a site-specific
analysis would be required to determine the overall net impact of these
countervailing factors, generally the effect of co-firing on net unit
heat rate can vary within approximately plus or minus 2 percent.
The EPA previously determined in the ACE Rule (84 FR 32545; July 8,
2019) that ``co-firing natural gas in coal-fired utility boilers is not
the best or most efficient use of natural gas and [. . .] can lead to
less efficient operation of utility boilers.'' That determination was
informed by the more limited supply of natural gas, and the larger
amount of coal-fired EGU capacity and generation, in 2019. Since that
determination, the expected supply of natural gas has expanded
considerably, and the capacity and generation of the existing coal-
fired fleet has decreased, reducing the total mass of natural gas that
might be required for sources to implement this measure.
Furthermore, regarding the efficient operation of boilers, the ACE
determination was based on the observation that ``co-firing can
negatively impact a unit's heat rate (efficiency) due to the high
hydrogen content of natural gas and the resulting production of water
as a combustion by-product.'' That finding does not consider the fact
that the effect of co-firing on net unit heat rate can vary within
approximately plus or minus 2 percent, and therefore the net impact on
overall utility boiler efficiency for each steam generating unit is
uncertain.
For all of these reasons, the EPA is finalizing that natural gas
co-firing at medium-term coal-fired steam generating units does not
result in any significant adverse consequences related to energy
requirements.
Additionally, the EPA considered longer term impacts on the energy
sector, and the EPA is finalizing these impacts are reasonable.
Designating natural gas co-firing as the BSER for medium-term coal-
fired steam generating units would not have significant adverse impacts
on the structure of the energy sector. Steam generating units that
currently are coal-fired would be able to remain primarily coal-fired.
The replacement of some coal with natural gas as fuel in these sources
would not have significant adverse effects on the price of natural gas
or the price of electricity.
iv. Extent of Reductions in CO2 Emissions
One of the primary benefits of natural gas co-firing is emission
reduction. CO2 emissions are reduced by approximately 4
percent for every additional 10 percent of co-firing. When moving from
100 percent coal to 60 percent coal and 40 percent natural gas,
CO2 stack emissions are reduced by approximately 16 percent.
Non-CO2 emissions are reduced as well, as noted earlier in
this preamble.
v. Technology Advancement
Natural gas co-firing is already well-established and widely used
by coal-fired steam boiler generating units. As a result, this final
rule is not likely to lead to technological advances or cost reductions
in the components of natural gas co-firing, including modifications to
boilers and pipeline construction. However, greater use of natural gas
co-firing may lead to improvements in the efficiency of conducting
natural gas co-firing and operating the associated equipment.
c. Options Not Determined To Be the BSER for Medium-Term Coal-Fired
Steam Generating Units
i. CCS
As discussed earlier in this preamble, the compliance date for CCS
is January 1, 2032. Accordingly, sources in the medium-term
subcategory--which have elected to commit to permanently cease
operations prior to 2039--would have less than 7 years to amortize the
capital costs of CCS. As a result, for these sources, the overall costs
of CCS would exceed the metrics for cost reasonableness that the EPA is
using in
[[Page 39896]]
this rulemaking, which are detailed in section VII.C.1.a.ii(D). For
this reason, the EPA is not finalizing CCS as the BSER for the medium-
term subcategory.
ii. Heat Rate Improvements
Heat rate improvements were not considered to be BSER for medium-
term steam generating units because the achievable reductions are low
and may result in rebound effect whereby total emissions from the
source increase, as detailed in section VII.D.4.a.
d. Conclusion
The EPA is finalizing that natural gas co-firing at 40 percent of
heat input is the BSER for medium-term coal-fired steam generating
units because natural gas co-firing is adequately demonstrated, as
indicated by the facts that it has been operated at scale and is widely
applicable to sources. Additionally, the costs for natural gas co-
firing are reasonable. Moreover, natural gas co-firing can be expected
to reduce emissions of several other air pollutants in addition to
GHGs. Any adverse non-air quality health and environmental impacts and
energy requirements of natural gas co-firing are limited. In contrast,
CCS, although achieving greater emission reductions, would be of higher
cost, in general, for the subcategory of medium-term units, and HRI
would achieve few reductions and, in fact, may increase emissions.
3. Degree of Emission Limitation for Final Standards
Under CAA section 111(d), once the EPA determines the BSER, it must
determine the ``degree of emission limitation'' achievable by the
application of the BSER. States then determine standards of performance
and include them in the state plans, based on the specified degree of
emission limitation. Final presumptive standards of performance are
detailed in section X.C.1.b of this preamble. There is substantial
variation in emission rates among coal-fired steam generating units--
the range is, approximately, from 1,700 lb CO2/MWh-gross to
2,500 lb CO2/MWh-gross--which makes it challenging to
determine a single, uniform emission limit. Accordingly, the EPA is
finalizing the degrees of emission limitation by a percentage change in
emission rate, as follows.
a. Long-Term Coal-Fired Steam Generating Units
As discussed earlier in this preamble, the EPA is finalizing the
BSER for long-term coal-fired steam generating units as ``full-
capture'' CCS, defined as 90 percent capture of the CO2 in
the flue gas. The degree of emission limitation achievable by applying
this BSER can be determined on a rate basis. A capture rate of 90
percent results in reductions in the emission rate of 88.4 percent on a
lb CO2/MWh-gross basis, and this reduction in emission rate
can be observed over an extended period (e.g., an annual calendar-year
basis). Therefore, the EPA is finalizing that the degree of emission
limitation for long-term units is an 88.4 percent reduction in emission
rate on a lb CO2/MWh-gross basis over an extended period
(e.g., an annual calendar-year basis).
b. Medium-Term Coal-Fired Steam Generating Units
As discussed earlier in this preamble, the BSER for medium-term
coal-fired steam generating units is 40 percent natural gas co-firing.
The application of 40 percent natural gas co-firing results in
reductions in the emission rate of 16 percent. Therefore, the degree of
emission limitation for these units is a 16 percent reduction in
emission rate on a lb CO2/MWh-gross basis over an extended
period (e.g., an annual calendar-year basis).
D. Rationale for the BSER for Natural Gas-Fired And Oil-Fired Steam
Generating Units
This section of the preamble describes the rationale for the final
BSERs for existing natural gas- and oil-fired steam generating units
based on the criteria described in section V.C of this preamble.
1. Subcategorization of Natural Gas- and Oil-Fired Steam Generating
Units
The EPA is finalizing subcategories based on load level (i.e.,
annual capacity factor), specifically, units that are base load,
intermediate load, and low load. The EPA is finalizing routine methods
of operation and maintenance as BSER for intermediate and base load
units. Applying that BSER would not achieve emission reductions but
would prevent increases in emission rates. The EPA is finalizing
presumptive standards of performance that differ between intermediate
and base load units due to their differences in operation, as detailed
in section X.C.1.b.iii of this preamble. The EPA proposed a separate
subcategory for non-continental oil-fired steam generating units, which
operate differently from continental units; however, the EPA is not
finalizing emission guidelines for sources outside of the contiguous
U.S., as described in section VII.B. At proposal, the EPA solicited
comment on a BSER of ``uniform fuels'' for low load natural gas- and
oil-fired steam generating units, and the EPA is finalizing this
approach for those sources.
Natural gas- and oil-fired steam generating units combust natural
gas or distillate fuel oil or residual fuel oil in a boiler to produce
steam for a turbine that drives a generator to create electricity. In
non-continental areas, existing natural gas- and oil-fired steam
generating units may provide base load power, but in the continental
U.S., most existing units operate in a load-following manner. There are
approximately 200 natural gas-fired steam generating units and fewer
than 30 oil-fired steam generating units in operation in the
continental U.S. Fuel costs and inefficiency relative to other
technologies (e.g., combustion turbines) result in operation at lower
annual capacity factors for most units. Based on data reported to EIA
and the EPA \688\ for the contiguous U.S., for natural gas-fired steam
generating units in 2019, the average annual capacity factor was less
than 15 percent and 90 percent of units had annual capacity factors
less than 35 percent. For oil-fired steam generating units in 2019, no
units had annual capacity factors above 8 percent. Additionally, their
load-following method of operation results in frequent cycling and a
greater proportion of time spent at low hourly capacities, when
generation is less efficient. Furthermore, because startup times for
most boilers are usually long, natural gas steam generating units may
operate in standby mode between periods of peak demand. Operating in
standby mode requires combusting fuel to keep the boiler warm, and this
further reduces the efficiency of natural gas combustion.
---------------------------------------------------------------------------
\688\ Clean Air Markets Program Data at https://campd.epa.gov.
---------------------------------------------------------------------------
Unlike coal-fired steam generating units, the CO2
emission rates of oil- and natural gas-fired steam generating units
that have similar annual capacity factors do not vary considerably
between units. This is partly due to the more uniform qualities (e.g.,
carbon content) of the fuel used. However, the emission rates for units
that have different annual capacity factors do vary considerably, as
detailed in the final TSD, Natural Gas- and Oil-fired Steam Generating
Units. Low annual capacity factor units cycle frequently, have a
greater proportion of CO2 emissions that may be attributed
to startup, and have a greater proportion of generation at inefficient
hourly capacities. Intermediate annual capacity factor units operate
more often at higher hourly capacities, where CO2 emission
rates are lower. High annual capacity factor units operate still more
at base load conditions, where units are more
[[Page 39897]]
efficient and CO2 emission rates are lower.
Based on these performance differences between these load levels,
the EPA, in general, proposed subcategories based on dividing natural
gas- and oil-fired steam generating units into three groups each--low
load, intermediate load, and base load.
The EPA is finalizing subcategories for oil-fired and natural gas-
fired steam generating units, based on load levels. The EPA proposed
the following load levels: ``low'' load, defined by annual capacity
factors less than 8 percent; ``intermediate'' load, defined by annual
capacity factors greater than or equal to 8 percent and less than 45
percent; and ``base'' load, defined by annual capacity factors greater
than or equal to 45 percent.
The EPA is finalizing January 1, 2030, as the compliance date for
natural gas- and oil-fired steam generating units and this date is
consistent with the dates in the fuel type definitions.
The EPA received comments that were generally supportive of the
proposed subcategory definitions,\689\ and the EPA is finalizing the
subcategory definitions as proposed.
---------------------------------------------------------------------------
\689\ See, for example, Document ID No. EPA-HQ-OAR-2023-0072-
0583.
---------------------------------------------------------------------------
2. Options Considered for BSER
The EPA has considered various methods for controlling
CO2 emissions from natural gas- and oil-fired steam
generating units to determine whether they meet the criteria for BSER.
Co-firing natural gas cannot be the BSER for these units because
natural gas- and oil-fired steam generating units already fire large
proportions of natural gas. Most natural gas-fired steam generating
units fire more than 90 percent natural gas on a heat input basis, and
any oil-fired steam generating units that would potentially operate
above an annual capacity factor of around 15 percent typically combust
natural gas as a large proportion of their fuel as well. Nor is CCS a
candidate for BSER. The utilization of most gas-fired units, and likely
all oil-fired units, is relatively low, and as a result, the amount of
CO2 available to be captured is low. However, the capture
equipment would still need to be sized for the nameplate capacity of
the unit. Therefore, the capital and operating costs of CCS would be
high relative to the amount of CO2 available to be captured.
Additionally, again due to lower utilization, the amount of IRC section
45Q tax credits that owner/operators could claim would be low. Because
of the relatively high costs and the relatively low cumulative emission
reduction potential for these natural gas- and oil-fired steam
generating units, the EPA is not determining CCS as the BSER for them.
The EPA has reviewed other possible controls but is not finalizing
any of them as the BSER for natural gas- and oil-fired units either.
Co-firing hydrogen in a boiler is technically possible, but there is
limited availability of hydrogen now and in the near future and it
should be prioritized for more efficient units. Additionally, for
natural gas-fired steam generating units, setting a future standard
based on hydrogen would likely have limited GHG reduction benefits
given the low utilization of natural gas- and oil-fired steam
generating units. Lastly, HRI for these types of units would face many
of the same issues as for coal-fired steam generating units; in
particular, HRI could result in a rebound effect that would increase
emissions.
However, the EPA recognizes that natural gas- and oil-fired steam
generating units could possibly, over time, operate more, in response
to other changes in the power sector. Additionally, some coal-fired
steam generating units have converted to 100 percent natural gas-fired,
and it is possible that more may do so in the future. The EPA also
received several comments from industry stating plans to do so.
Moreover, in part because the fleet continues to age, the plants may
operate with degrading emission rates. In light of these possibilities,
identifying the BSER and degrees of emission limitation for these
sources would be useful to provide clarity and prevent backsliding in
GHG performance. Therefore, the EPA is finalizing BSER for intermediate
and base load natural gas- and oil-fired steam generating units to be
routine methods of operation and maintenance, such that the sources
could maintain the emission rates (on a lb/MWh-gross basis) currently
maintained by the majority of the fleet across discrete ranges of
annual capacity factor. The EPA is finalizing this BSER for
intermediate load and base load natural gas- and oil-fired steam
generating units, regardless of the operating horizon of the unit.
A BSER based on routine methods of operation and maintenance is
adequately demonstrated because units already operate with those
practices. There are no or negligible additional costs because there is
no additional technology that units are required to apply and there is
no change in operation or maintenance that units must perform.
Similarly, there are no adverse non-air quality health and
environmental impacts or adverse impacts on energy requirements. Nor do
they have adverse impacts on the energy sector from a nationwide or
long-term perspective. The EPA's modeling, which supports this final
rule, indicates that by 2040, a number of natural gas-fired steam
generating units will have remained in operation since 2030, although
at reduced annual capacity factors. There are no CO2
reductions that may be achieved at the unit level, but applying routine
methods of operation and maintenance as the BSER prevents increases in
emission rates. Routine methods of operation and maintenance do not
advance useful control technology, but this point is not significant
enough to offset their benefits.
At proposal, the EPA also took comment on a potential BSER of
uniform fuels for low load natural gas- and oil-fired steam generating
units. As noted earlier in this preamble, non-coal fossil fuels
combusted in utility boilers typically include natural gas, distillate
fuel oil (i.e., fuel oil No. 1 and No. 2), and residual fuel oil (i.e.,
fuel oil No. 5 and No. 6). The EPA previously established heat-input
based fuel composition as BSER in the 2015 NSPS (termed ``clean fuels''
in that rulemaking) for new non-base load natural gas- and multi-fuel-
fired stationary combustion turbines (80 FR 64615-17; October 23,
2015), and the EPA is similarly finalizing lower-emitting fuels as BSER
for new low load combustion turbines as described in section VIII.F of
this preamble. For low load natural gas- and oil-fired steam generating
units, the high variability in emission rates associated with the
variability of load at the lower-load levels limits the benefits of a
BSER based on routine maintenance and operation. That is because the
high variability in emission rates would make it challenging to
determine an emission rate (i.e., on a lb CO2/MWh-gross
basis) that could serve as the presumptive standard of performance that
would reflect application of a BSER of routine operation and
maintenance. On the other hand, for those units, a BSER of ``uniform
fuels'' and an associated presumptive standard of performance based on
a heat input basis, as described in section X.C.1.b.iii of this
preamble, is reasonable. Therefore, the EPA is finalizing a BSER of
uniform fuels for low load natural gas- and oil-fired steam generating
units, with presumptive standards depending on fuel type detailed in
section X.C.1.b.iii.
[[Page 39898]]
3. Degree of Emission Limitation
As discussed above, because the BSER for base load and intermediate
load natural gas- and oil-fired steam generating units is routine
operation and maintenance, which the units are, by definition, already
employing, the degree of emission limitation by application of this
BSER is no increase in emission rate on a lb CO2/MWh-gross
basis over an extended period of time (e.g., a year).
For low load natural gas- and oil-fired steam generating units, the
EPA is finalizing a BSER of uniform fuels, with a degree of emission
limitation on a heat input basis consistent with a fixed 130 lb
CO2/MMBtu for natural gas-fired steam generating units and
170 lb CO2/MMBtu for oil-fired steam generating units. The
degree of emission limitation for natural gas- and oil-fired steam
generating units is higher than the corresponding values under 40 CFR
part 60, subpart TTTT, because steam generating units may fire fuels
with slightly higher carbon contents.
4. Other Emission Reduction Measures Not Considered BSER
a. Heat Rate Improvements
Heat rate is a measure of efficiency that is commonly used in the
power sector. The heat rate is the amount of energy input, measured in
Btu, required to generate 1 kilowatt-hour (kWh) of electricity. The
lower an EGU's heat rate, the more efficiently it operates. As a
result, an EGU with a lower heat rate will consume less fuel and emit
lower amounts of CO2 and other air pollutants per kWh
generated as compared to a less efficient unit. HRI measures include a
variety of technology upgrades and operating practices that may achieve
CO2 emission rate reductions of 0.1 to 5 percent for
individual EGUs. The EPA considered HRI to be part of the BSER in the
CPP and to be the BSER in the ACE Rule. However, the reductions that
may be achieved by HRI are small relative to the reductions from
natural gas co-firing and CCS. Also, some facilities that apply HRI
would, as a result of their increased efficiency, increase their
utilization and therefore increase their CO2 emissions (as
well as emissions of other air pollutants), a phenomenon that the EPA
has termed the ``rebound effect.'' Therefore, the EPA is not finalizing
HRI as a part of BSER.
i. CO2 Reductions From HRI in Prior Rulemakings
In the CPP, the EPA quantified emission reductions achievable
through heat rate improvements on a regional basis by an analysis of
historical emission rate data, taking into consideration operating load
and ambient temperature. The Agency concluded that EGUs can achieve on
average a 4.3 percent improvement in the Eastern Interconnection, a 2.1
percent improvement in the Western Interconnection, and a 2.3 percent
improvement in the Texas Interconnection. See 80 FR 64789 (October 23,
2015). The Agency then applied all three of the building blocks to 2012
baseline data and quantified, in the form of CO2 emission
rates, the reductions achievable in Each interconnection in 2030, and
then selected the least stringent as a national performance rate. Id.
at 64811-19. The EPA noted that building block 1 measures could not by
themselves constitute the BSER because the quantity of emission
reductions achieved would be too small and because of the potential for
an increase in emissions due to increased utilization (i.e., the
``rebound effect'').
ii. Updated CO2 Reductions From HRI
The HRI measures include improvements to the boiler island (e.g.,
neural network system, intelligent sootblower system), improvements to
the steam turbine (e.g., turbine overhaul and upgrade), and other
equipment upgrades (e.g., variable frequency drives). Some regular
practices that may recover degradation in heat rate to recent levels--
but that do not result in upgrades in heat rate over recent design
levels and are therefore not HRI measures--include practices such as
in-kind replacements and regular surface cleaning (e.g., descaling,
fouling removal). Specific details of the HRI measures are described in
the 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. Most HRI
upgrade measures achieve reductions in heat rate of less than 1
percent. In general, the 2023 Sargent and Lundy HRI report, which
updates the 2009 Sargent and Lundy HRI report, shows that HRI achieve
less reductions than indicated in the 2009 report, and shows that
several HRI either have limited applicability or have already been
applied at many units. Steam path overhaul and upgrade may achieve
reductions up to 5.15 percent, with the average being around 1.5
percent. Different combinations of HRI measures do not necessarily
result in cumulative reductions in emission rate (e.g., intelligent
sootblowing systems combined with neural network systems). Some of the
HRI measures (e.g., variable frequency drives) only impact heat rate on
a net generation basis by reducing the parasitic load on the unit and
would thereby not be observable for emission rates measured on a gross
basis. Assuming many of the HRI measures could be applied to the same
unit, adding together the upper range of some of the HRI percentages
could yield an emission rate reduction of around 5 percent. However,
the reductions that the fleet could achieve on average are likely much
smaller. As noted, the 2023 Sargent and Lundy HRI report notes that, in
many cases, units have already applied HRI upgrades or that those
upgrades would not be applicable to all units. The unit level
reductions in emission rate from HRI are small relative to CCS or
natural gas co-firing. In the CPP and ACE Rule, the EPA viewed CCS and
natural gas co-firing as too costly to qualify as the BSER; those costs
have fallen since those rules and, as a result, CCS and natural gas co-
firing do qualify as the BSER for the long-term and medium-term
subcategories, respectively.
iii. Potential for Rebound in CO2 Emissions
Reductions achieved on a rate basis from HRI may not result in
overall emission reductions and could instead cause a ``rebound
effect'' from increased utilization. A rebound effect would occur
where, because of an improvement in its heat rate, a steam generating
unit experiences a reduction in variable operating costs that makes the
unit more competitive relative to other EGUs and consequently raises
the unit's output. The increase in the unit's CO2 emissions
associated with the increase in output would offset the reduction in
the unit's CO2 emissions caused by the decrease in its heat
rate and rate of CO2 emissions per unit of output. The
extent of the offset would depend on the extent to which the unit's
generation increased. The CPP did not consider HRI to be BSER on its
own, in part because of the potential for a rebound effect. Analysis
for the ACE Rule, where HRI was the entire BSER, observed a rebound
effect for certain sources in some cases.\690\ In this action, where
different subcategories of units are to be subject to different BSER
measures, steam generating units in a hypothetical subcategory with HRI
as BSER could experience a rebound effect. Because of this potential
for perverse GHG emission outcomes resulting from deployment of HRI at
certain steam generating units, coupled with the
[[Page 39899]]
relatively minor overall GHG emission reductions that would be expected
from this measure, the EPA is not finalizing HRI as the BSER for any
subcategory of existing coal-fired steam generating units.
---------------------------------------------------------------------------
\690\ 84 FR 32520 (July 8, 2019).
---------------------------------------------------------------------------
E. Additional Comments Received on the Emission Guidelines for Existing
Steam Generating Units and Responses
1. Consistency With West Virginia v. EPA and the Major Questions
Doctrine
Comment: Some commenters argued that the EPA's determination that
CCS is the BSER for existing coal-fired power plants is invalid under
West Virginia v. EPA, 597 U.S. 697 (2022), and the major questions
doctrine (MQD). Commenters state that for various reasons, coal-fired
power plants will not install CCS and instead will be forced to retire
their units. They point to the EPA's IPM modeling which, they say,
shows that many coal-fired power plants retire rather than install CCS.
They add that, in this way, the rule effectively results in the EPA's
requiring generation-shifting from coal-fired generation to renewable
and other generation, and thus is like the Clean Power Plan (CPP). For
those reasons, they state that the rule raises a major question, and
further that CAA section 111(d) does not contain a clear authorization
for this type of rule.
Response: The EPA discussed West Virginia and its articulation of
the MQD in section V.B.6 of this preamble.
The EPA disagrees with these comments. This rule is fully
consistent with the Supreme Court's interpretation of the EPA's
authority in West Virginia. The EPA's determination that CCS--a
traditional, add-on emissions control--is the BSER is consistent with
the plain text of section 111. As explained in detail in section
VII.C.1.a, for long-term coal-fired steam generating units, CCS meets
all of the BSER factors: it is adequately demonstrated, of reasonable
cost, and achieves substantial emissions reductions. That some coal-
fired power plants will choose not to install emission controls and
will instead retire does not raise major questions concerns.
In West Virginia, the U.S. Supreme Court held that ``generation-
shifting'' as the BSER for coal- and gas-fired units ``effected a
fundamental revision of the statute, changing it from one sort of
scheme of regulation into an entirely different kind.'' 597 U.S. at 728
(internal quotation marks, brackets, and citation omitted). The Court
explained that prior CAA section 111 rules were premised on ``more
traditional air pollution control measures'' that ``focus on improving
the performance of individual sources.'' Id. at 727 (citing ``fuel-
switching'' and ``add-on controls''). The Court said that generation-
shifting as the BSER was ``unprecedented'' because it was designed to
``improve the overall power system by lowering the carbon intensity of
power generation . . . by forcing a shift throughout the power grid
from one type of energy source to another.'' Id. at 727-28 (internal
quotation marks, emphasis, and citation omitted). The Court cited
statements by the then-Administrator describing the CPP as ``not about
pollution control so much as it was an investment opportunity for
States, especially investments in renewables and clean energy.'' Id. at
728. The Court further concluded that the EPA's view of its authority
was virtually unbounded because the ``EPA decides, for instance, how
much of a switch from coal to natural gas is practically feasible by
2020, 2025, and 2030 before the grid collapses, and how high energy
prices can go as a result before they become unreasonably exorbitant.''
Id. at 729.
Here, the EPA's determination that CCS is the BSER does not affect
a fundamental revision of the statute, nor is it unbounded. CCS is not
directed at improvement of the overall power system. Rather, CCS is a
traditional ``add-on [pollution] control[ ]'' akin to measures that the
EPA identified as BSER in prior CAA section 111 rules. See id. at 727.
It ``focus[es] on improving the performance of individual sources''--it
reduces CO2 pollution from each individual source--because
each affected source is able to apply it to its own facility to reduce
its own emissions. Id. at 727. Further, the EPA determined that CCS
qualifies as the BSER by applying the criteria specified in CAA section
111(a)(1)--including adequate demonstration, costs of control, and
emissions reductions. See section VII.C.1.a of this preamble. Thus, CCS
as the BSER does not ``chang[e]'' the statute ``from one sort of scheme
of regulation into an entirely different kind.'' Id. at 728 (internal
quotation marks, brackets, and citation omitted).
Commenters contend that notwithstanding these distinctions, the
choice of CCS as the BSER has the effect of shifting generation because
modeling projections for the rule show that coal-fired generation will
become less competitive, and gas-fired and renewable-generated
electricity will be more competitive and dispatched more frequently.
That some coal-fired sources may retire rather than reduce their
CO2 pollution does not mean that the rule ``represents a
transformative expansion [of EPA's] regulatory authority''. Id. at 724.
To be sure, this rule's determination that CCS is the BSER imposes
compliance costs on coal-fired power plants. That sources will incur
costs to control their emissions of dangerous pollution is an
unremarkable consequence of regulation, which, as the Supreme Court
recognized, ``may end up causing an incidental loss of coal's market
share.'' Id. at 731 n.4.\691\ Indeed, ensuring that sources internalize
the full costs of mitigating their impacts on human health and the
environment is a central purpose of traditional environmental
regulation.
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\691\ As discussed in section VII.C.1.a.ii.(D), the costs of CCS
are reasonable based on the EPA's $/MWh and $/ton metrics. As
discussed in RTC section 2.16, the total annual costs of this rule
are a small fraction of the revenues and capital costs of the
electric power industry.
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In particular, for the power sector, grid operators constantly
shift generation as they dispatch electricity from sources based upon
their costs. The EPA's IPM modeling, which is based on the costs of the
various types of electricity generation, projects these impacts. Viewed
as a whole, these projected impacts show that, collectively, coal-fired
power plants will likely produce less electricity, and other sources
(like gas-fired units and renewable sources) will likely produce more
electricity, but this pattern does not constitute a transformative
expansion of statutory authority (EPA's Power Sector Platform 2023
using IPM; final TSD, Power Sector Trends.)
These projected impacts are best understood by comparing the IPM
model's ``base case,'' i.e., the projected electricity generation
without any rule in place, to the model's ``policy case,'' i.e., the
projected electricity generation expected to result from this rule. The
base case projects that many coal-fired units will retire over the next
20 years (EPA's Power Sector Platform 2023 using IPM; final TSD, Power
Sector Trends). Those projected retirements track trends over the past
two decades where coal-fired units have retired in high numbers because
gas-fired units and renewable sources have become increasingly able to
generate lower-cost electricity. As more gas-fired and renewable
generation sources deploy in the future, and as coal-fired units
continue to age--which results in decreased efficiency and increased
costs--the coal-fired units will become increasingly marginal and
continue to retire (EPA's Power Sector Platform 2023 using IPM; final
TSD, Power Sector Trends.) That is true in the absence of this rule.
The EPA's modeling results also project that even if the EPA had
[[Page 39900]]
determined BSER for long-term sources to be 40 percent co-firing, which
requires significantly less capital investment, and not 90 percent
capture CCS, a comparable number of sources would retire instead of
installing controls. These results confirm that the primary cause for
the projected retirements is the marginal profitability of the sources.
Importantly, the base-case projections also show that some coal-
fired units install CCS and run at high capacity factors, in fact,
higher than they would have had they not installed CCS. This is because
the IRC section 45Q tax credit significantly reduces the variable cost
of operation for qualifying sources. This incentivizes sources to
increase generation to maximize the tons of CO2 the CCS
equipment captures, and thereby increase the amount of the tax credit
they receive. In the ``policy case,'' beginning when the CCS
requirement applies in the 2035 model year,\692\ some additional coal-
fired units will likely install CCS, and also run at high capacity
factors, again, significantly higher than they would have without CCS.
Other units may retire rather than install emission controls (EPA's
Power Sector Platform 2023 using IPM; final TSD, Power Sector Trends).
On balance, the coal-fired units that install CCS collectively generate
nearly the same amount of electricity in the 2040 model year as do the
group of coal-fired units in the base case.
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\692\ Under the rule, sources are required to meet their CCS-
based standard of performance by January 1, 2032. IPM groups
calendar years into 5-year periods, e.g., the 2035 model year and
the 2040 model year. January 1, 2032, falls into the 2035 model
year.
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The policy case also shows that in the 2045 model year, by which
time the 12-year period for sources to claim the IRC section 45Q tax
credit will have expired, most sources that install CCS retire due to
the costs of meeting the CCS-based standards without the benefit of the
tax credit. However, in fact, these projected outcomes are far from
certain as the modeling results generally do not account for numerous
potential changes that may occur over the next 20 or more years, any of
which may enable these units to continue to operate economically for a
longer period. Examples of potential changes include reductions in the
operational costs of CCS through technological improvements, or the
development of additional potential revenue streams for captured
CO2 as the market for beneficial uses of CO2
continues to develop, among other possible changed economic
circumstances (including the possible extension of the tax credits). In
light of these potential significant developments, the EPA is
committing to review and, if appropriate, revise the requirements of
this rule by January 1, 2041, as described in section VII.F.
In any event, the modeling projections showing that many sources
retire instead of installing controls are in line with the trends for
these units in the absence of the rule--as the coal-fired fleet ages
and lower-cost alternatives become increasingly available, more
operators will retire coal-fired units with or without this rule. In
2045, the average age of coal-fired units that have not yet announced
retirement dates or coal-to-gas conversion by 2039 will be 61 years
old. And, on average, between 2000 and 2022, even in the absence of
this rule, coal-fired units generally retired at 53 years old. Thus,
taken as a whole, this rule does not dramatically reduce the expected
operating horizon of most coal-fired units. Indeed, for units that
install CCS, the generous IRC section 45Q tax credit increases the
competitiveness of these units, and it allows them to generate more
electricity with greater profit than the sources would otherwise
generate if they did not install CCS.
The projected effects of the rule do not show the BSER--here, CCS--
is akin to generation shifting, or otherwise represents an expansion of
EPA authority with vast political or economic significance. As
described above at VII.C.1.a.ii, CCS is an affordable emissions control
technology. It is also very effective, reducing CO2
emissions from coal-fired units by 90 percent, as described in section
VII.C.1.a.i. Indeed, as noted, the IRA tax credits make CCS so
affordable that coal-fired units that install CCS run at higher
capacity factors than they would otherwise.
Considered as a whole, and in context with historical retirement
trends, the projected impacts of this rule on coal-fired generating
units do not raise MQD concerns. The projected impacts are merely
incidental to the CCS control itself--the unremarkable consequence of
marginally increasing the cost of doing business in a competitive
market. Nor is the rule ``transformative.'' The rule does not
``announce what the market share of coal, natural gas, wind, and solar
must be, and then requiring plants to reduce operations or subsidize
their competitors to get there.'' 597 U.S. at 731 n.4. As noted above,
coal-fired units that install CCS are projected to generate substantial
amounts of electricity. The retirements that are projected to occur are
broadly consistent with market trends over the past two decades, which
show that coal-fired electricity production is generally less economic
and less competitive than other forms of electricity production. That
is, the retirements that the model predicts under this rule, and the
structure of the industry that results, diverge little from the prior
rate of retirements of coal-fired units over the past two decades. They
also diverge little from the rate of retirements from sources that have
already announced that they will retire, or from the additional
retirements that IPM projects will occur in the base case (EPA's Power
Sector Platform 2023 using IPM; final TSD, Power Sector Trends).
As discussed above, because much of the coal-fired fleet is
operating on the edge of viability, many sources would retire instead
of installing any meaningful CO2 emissions control--whether
CCS, natural gas co-firing, or otherwise. Under commenters' view that
such retirements create a major question, any form of meaningful
regulation of these sources would create a major question and effect a
fundamental revision of the statute. That cannot possibly be so.
Section 111(d)(1) plainly mandates regulation of these units, which are
the biggest stationary source of dangerous CO2 emissions.
The legislative history for the CAA further makes clear that
Congress intended the EPA to promulgate regulations even where
emissions controls had economic costs. At the time of the 1970 CAA
Amendments, Congress recognized that the threats of air pollution to
public health and welfare had grown urgent and severe. Sen. Edmund
Muskie (D-ME), manager of the bill and chair of the Public Works
Subcommittee on Air and Water Pollution, which drafted the bill,
regularly referred to the air pollution problem as a ``crisis.'' As
Sen. Muskie recognized, ``Air pollution control will be cheap only in
relation to the costs of lack of control.'' \693\ The Senate Committee
Report for the 1970 CAA Amendments specifically discussed the precursor
provision to section 111(d) and noted, ``there should be no gaps in
control activities pertaining to stationary source emissions that pose
any significant danger to public health or welfare.'' \694\
Accordingly, some of the
[[Page 39901]]
EPA's prior CAA section 111 rulemakings have imposed stringent
requirements, at significant cost, in order to achieve significant
emission reductions.\695\
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\693\ Sen. Muskie, Sept. 21, 1970, LH 226.
\694\ S. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA
Legis. Hist. at 420 (discussing section 114 of the Senate Committee
bill, which was the basis for CAA section 111(d)). Note that in the
1977 CAA Amendments, the House Committee Report made a similar
statement. H.R. Rep. No. 95-294, at 42 (May 12, 1977), 1977 CAA
Legis. Hist. at 2509 (discussing a provision in the House Committee
bill that became CAA section 122, requiring EPA to study and then
take action to regulate radioactive air pollutants and three other
air pollutants).
\695\ See Sierra Club v. Costle, 657 F.2d 298, 313 (D.C. Cir.
1981) (upholding NSPS imposing controls on SO2 emissions
from coal-fired power plants when the ``cost of the new controls . .
. is substantial. EPA estimates that utilities will have to spend
tens of billions of dollars by 1995 on pollution control under the
new NSPS.'').
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Congress's enactment of the IRA and IIJA further shows its view
that reducing air pollution--specifically, in those laws, GHG emissions
to address climate change--is a high priority. As discussed in section
IV.E.1, that law provided funds for DOE grant and loan programs to
support CCS, and extended and increased the IRC section 45Q tax credit
for carbon capture. It also adopted the Low Emission Electricity
Program (LEEP), which allocates funds to the EPA for the express
purpose of using CAA regulatory authority to reduce GHG emissions from
domestic electricity generation through use of its existing CAA
authorities. CAA section 135, added by IRA section 60107. The EPA is
promulgating the present rulemaking with those funds. The congressional
sponsor of the LEEP made clear that it authorized the type of
rulemaking that the EPA is promulgating today: he stated that the EPA
may promulgate rulemaking under CAA section 111, based on CCS, to
address CO2 emissions from fossil fuel-fired power plants,
which may be ``impactful'' by having the ``incidental effect'' of
leading some ``companies . . . to choose to retire such plants. . . .''
\696\
---------------------------------------------------------------------------
\696\ 168 Cong. Rec. E868 (August 23, 2022) (statement of Rep.
Frank Pallone, Jr.); id. E879 (August 26, 2022) (statement of Rep.
Frank Pallone, Jr.).
---------------------------------------------------------------------------
For these reasons, the rule here is consistent with the Supreme
Court's decision in West Virginia. The selection of CCS as the BSER for
existing coal-fired units is a traditional, add-on control intended to
reduce the emissions performance of individual sources. That some
sources may retire instead of controlling their emissions does not
otherwise show that the rule runs afoul of the MQD. The modeling
projections for this rule show that the anticipated retirements are
largely consistent with historical trends, and due to many coal-fired
units' advanced age and lack of competitiveness with lower cost methods
of electricity generation.
2. Redefining the Source
Comment: Some commenters contended that the proposed 40 percent
natural gas co-firing performance standard violates legal precedent
that bars the EPA from setting technology-based performance standards
that would have the effect of ``redefining the source.'' They stated
that this prohibition against the redefinition of the source bars the
EPA from adopting the proposed performance standard for medium-term
coal-fired EGUs, which requires such units to operate in a manner for
which the unit was never designed to do, namely operate as a hybrid
coal/natural gas co-firing generating unit and combusting 40 percent of
its fuel input as natural gas (instead of coal) on an annual basis.
Commenters argued that co-firing would constitute forcing one type
of source to become an entirely different kind of source, and that the
Supreme Court precluded such a requirement in West Virginia v. EPA when
it stated in footnote 3 of that case that the EPA has ``never ordered
anything remotely like'' a rule that would ``simply require coal plants
to become natural gas plants'' and the Court ``doubt[ed that EPA]
could.'' \697\
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\697\ West Virginia v. EPA, 597 U.S, 697, 728 n.3 (2022).
---------------------------------------------------------------------------
Response: The EPA disagrees with these comments.
Standards based on co-firing, as contemplated in this rule, are
based on a ``traditional pollution control measure,'' in particular,
``fuel switching,'' as the Supreme Court recognized in West
Virginia.\698\ Rules based on switching to a cleaner fuel are
authorized under the CAA, an authorization directly acknowledged by
Congress. Specifically, as part of the 1977 CAA Amendments, Congress
required that the EPA base its standards regulating certain new
sources, including power plants, on ``technological'' controls, rather
than simply the ``best system.'' \699\ Congress understood this to mean
that new sources would be required to implement add-on controls, rather
than merely relying on fuel switching, and noted that one of the
purposes of this amendment was to allow new sources to burn high sulfur
coal while still decreasing emissions, and thus to increase the
availability of low sulfur coal for existing sources, which were not
subject to the ``technological'' control requirement.\700\ In 1990,
however, Congress removed the ``technological'' language, allowing the
EPA to set fuel-switching based standards for both new and existing
power plants.\701\
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\698\ See 597 U.S. at 727.
\699\ In 1977, Congress clarified that for purposes of CAA
section 111(a)(1)(A), concerning standards of performance for new
and modified ``fossil fuel-fired stationary sources'' a standard or
performance ``shall reflect the degree of emission limitation and
the percentage reduction achievable through application of the best
technological system of continuous emission reduction which (taking
into consideration the cost of achieving such emission reduction,
any nonair quality health and environmental impact and energy
requirements) the Administrator determines has been adequately
demonstrated.'' Clean Air Act 1977 Revisions (emphasis added).
\700\ See H. Rep. No. 94-1175, 94th Cong., 2d Sess. (May 15,
1976) Part A, at 159 (listing the various purposes of the amendment
to Section 111 adding the term `technological': ``Fourth, by using
best control technology on large new fuel-burning stationary
sources, these sources could burn higher sulfur fuel than if no
technological means of reducing emissions were used. This means an
expansion of the energy resources that could be burned in compliance
with environmental requirements. Fifth, since large new fuel-burning
sources would not rely on naturally low sulfur coal or oil to
achieve compliance with new source performance standards, the low
sulfur coal or oil that would have been burned in these major new
sources could instead be used in older and smaller sources.'')
\701\ In 1990, Congress removed this reference to a
``technological system'', and the current text reads simply: ``The
term ``standard of performance'' means a standard for emissions of
air pollutants which reflects the degree of emission limitation
achievable through the application of the best system of emission
reduction which (taking into account the cost of achieving such
reduction and any nonair quality health and environmental impact and
energy requirements) the Administrator determines has been
adequately demonstrated.'' 42 U.S.C. 7411(a)(1).
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The EPA has a tradition of promulgating rules based on fuel
switching. For example, the 2006 NSPS for stationary compression
ignition internal combustion engines required the use of ultra-low
sulfur diesel.\702\ Similarly, in the 2015 NSPS for EGUs,\703\ the EPA
determined that the BSER for peaking plants was to burn primarily
natural gas, with distillate oil used only as a backup fuel.\704\ Nor
is this approach unique to CAA section 111; in the 2016 rule setting
section 112 standards for hazardous air pollutant emissions from area
sources, for example, the EPA finalized an alternative particulate
matter (PM) standard that specified that certain oil-fired boilers
would meet the applicable
[[Page 39902]]
standard if they combusted only ultra-low-sulfur liquid fuel.\705\
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\702\ Standards of Performance for Stationary Compression
Ignition Internal Combustion Engines, 71 FR 39154 (July 11, 2006).
In the preamble to the final rule, the EPA noted that for engines
which had not previously used this new ultra-low sulfur fuel,
additives would likely need to be added to the fuel to maintain
appropriate lubricity. See id. at 39158.
\703\ Standards of Performance for Greenhouse Gas Emissions From
New, Modified, and Reconstructed Stationary Sources: Electric
Utility Generating Units, 80 FR 64510, (October 23, 2015).
\704\ See id. at 64621.
\705\ See National Emission Standards for Hazardous Air
Pollutants for Area Sources: Industrial, Commercial, and
Institutional Boilers, 81 FR 63112-01 (September 14, 2016).
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Moreover, the West Virginia Court's statements in footnote 3 are
irrelevant to the question of the validity of a 40 percent co-firing
standard. There, the Court was referring to a complete transformation
of the coal-fired unit to a 100 percent gas fired unit--a change that
would require entirely repowering the unit. By contrast, increasing co-
firing at existing coal-fired units to 40 percent would require only
minor changes to the units' boilers. In fact, many coal-fired units are
already capable of co-firing some amount of gas without any changes at
all, and several have fired at 40 percent and above in recent years. Of
the 565 coal-fired EGUs operating at the end of 2021, 249 of them
reported consuming natural gas as a fuel or startup source, 162
reported more than one month of consumption of natural gas at their
boiler, and 29 co-fired at over 40 percent on an annual heat input
basis in at least one year while also operating with annual capacity
factors greater than 10 percent. For more on this, see section IV.C.2
of this preamble; see also the final TSD, GHG Mitigation Measures for
Steam Generating Units.
F. Commitment To Review and, If Appropriate, Revise Emission Guidelines
for Coal-Fired Units
The EPA recognizes that the IRC 45Q tax credit is a key component
to the cost of CCS, as discussed in section VII.C.1.a.ii(C) of this
preamble. The EPA further recognizes that for any affected source, the
tax credit is currently available for a 12-year period and not
subsequently. The tax credit is generally sufficient to defray the
capital costs of CCS and much, if not all, of the operating costs
during that 12-year period. Following the 12-year period, affected
sources that continue to operate the CCS equipment would have higher
costs of generation, due to the CCS operating costs, including
parasitic load. Under certain circumstances, these higher costs could
push the affected sources lower on the dispatch curve, and thereby lead
to reductions in the amount of their generation, i.e., if affected
sources are not able to replace the revenue from the tax credit with
revenue from other sources, or if the price of electricity does not
reflect any additional costs needed to minimize GHG emissions.
However, the costs of CCS and the overall economic viability of
operating CO2 capture at power plants are improving and can
be expected to continue to improve in years to come. CO2
that is captured from fossil-fuel fired sources is currently
beneficially used, including, for example, for enhanced oil recovery
and in the food and beverage industry. There is much research into
developing beneficial uses for many other industries, including
construction, chemical manufacturing, graphite manufacturing. The
demand for CO2 is expected to grow considerably over the
next several decades. As a result, in the decades to come, affected
sources may well be able to replace at least some of the revenues from
the tax credit with revenues from the sale of CO2. We
discuss these potential developments in chapter 2 of the Response to
Comments document, available in the rulemaking docket.
In addition, numerous states have imposed requirements to
decarbonize generation within their borders. Many utilities have also
announced plans to decarbonize their fleet, including building small
modular (advanced nuclear) reactors. Given the relatively high capital
and fixed costs of small modular reactors, plans for their construction
represent an expectation of higher future energy prices. This suggests
that, in the decades to come, at least in certain areas of the country,
affected sources may be able to maintain a place in the dispatch curve
that allows them to continue to generate while they continue to operate
CCS, even in the absence of additional revenues for CO2. We
discuss these potential developments in the final TSD, Power Sector
Trends, available in the rulemaking docket.
These developments, which may occur by the 2040s--the expiration of
the 12-year period for the IRC 45Q tax credit, the potential
development of the CO2 utilization market, and potential
market supports for low-GHG generation--may significantly affect the
costs to coal-fired steam EGUs of operating their CCS controls. As a
result, the EPA will closely monitor these developments. Our efforts
will include consulting with other agencies with expertise and
information, including DOE, which currently has a program, the Carbon
Conversion Program, in the Office of Carbon Management, that funds
research into CO2 utilization. We regularly consult with
stakeholders, including industry stakeholders, and will continue to do
so.
In light of these potential significant developments and their
impacts, potentially positive or negative, on the economics of
continued generation by affected sources that have installed CCS, the
EPA is committing to review and, if appropriate, revise this rule by
January 1, 2041. This commitment is included in the regulations that
the EPA is promulgating with this rule. The EPA will conduct this
review based on what we learn from monitoring these developments, as
noted above. Completing this review and any appropriate revisions by
that date will allow time for the states to revise, if necessary,
standards applicable to affected sources, and for the EPA to act on
those state revisions, by the early to mid-2040s. That is when the 12-
year period for the 45Q tax credit is expected to expire for affected
sources that comply with the CCS requirement by January 1, 2032, and
when other significant developments noted above may be well underway.
VIII. Requirements for New and Reconstructed Stationary Combustion
Turbine EGUs and Rationale for Requirements
A. Overview
This section discusses the requirements for stationary combustion
turbine EGUs that commence construction or reconstruction after May 23,
2023. The requirements are codified in 40 CFR part 60, subpart TTTTa.
The EPA explains in section VIII.B of this document the two basic
turbine technologies that are used in the power sector and are covered
by 40 CFR part 60, subpart TTTTa. Those are simple cycle combustion
turbines and combined cycle combustion turbines. The EPA also explains
how these technologies are used in the three subcategories: low load
turbines, intermediate load turbines, and base load turbines. Section
VIII.C provides an overview of how stationary combustion turbines have
been previously regulated. Section VIII.D discusses the EPA's decision
to revisit the standards for new and reconstructed turbines as part of
the statutorily required 8-year review of the NSPS. Section VIII.E
discusses changes that the EPA is finalizing in both applicability and
subcategories in the new 40 CFR part 60, subpart TTTTa, as compared to
those codified previously in 40 CFR part 60, subpart TTTT. Most
notably, for new and reconstructed natural gas-fired combustion
turbines, the EPA is finalizing BSER determinations and standards of
performance for the three subcategories mentioned above--low load,
intermediate load, and base load.
Sections VIII.F and VIII.G of this document discuss the EPA's
[[Page 39903]]
determination of the BSER for each of the three subcategories of
combustion turbines and the applicable standards of performance,
respectively. For low load combustion turbines, the EPA is finalizing a
determination that the use of lower-emitting fuels is the appropriate
BSER. For intermediate load combustion turbines, the EPA is finalizing
a determination that highly efficient simple cycle generation is the
appropriate BSER. For base load combustion turbines, the EPA is
finalizing a determination that the BSER includes two components that
correspond initially to a two-phase standard of performance. The first
component of the BSER, with an immediate compliance date (phase 1), is
highly efficient generation based on the performance of a highly
efficient combined cycle turbine and the second component of the BSER,
with a compliance date of January 1, 2032 (phase 2), is based on the
use of CCS with a 90 percent capture rate, along with continued use of
highly efficient generation. For base load turbines, the standards of
performance corresponding to both components of the BSER would apply to
all new and reconstructed sources that commence construction or
reconstruction after May 23, 2023. The EPA occasionally refers to these
standards of performance as the phase 1 or phase 2 standards.
B. Combustion Turbine Technology
For purposes of 40 CFR part 60, subparts TTTT and TTTTa, stationary
combustion turbines include both simple cycle and combined cycle EGUs.
Simple cycle turbines operate in the Brayton thermodynamic cycle and
include three primary components: a multi-stage compressor, a
combustion chamber (i.e., combustor), and a turbine. The compressor is
used to supply large volumes of high-pressure air to the combustion
chamber. The combustion chamber converts fuel to heat and expands the
now heated, compressed air through the turbine to create shaft work.
The shaft work drives an electric generator to produce electricity.
Combustion turbines that recover the energy in the high-temperature
exhaust--instead of venting it directly to the atmosphere--are combined
cycle EGUs and can obtain additional useful electric output. A combined
cycle EGU includes an HRSG operating in the Rankine thermodynamic
cycle. The HRSG receives the high-temperature exhaust and converts the
heat to mechanical energy by producing steam that is then fed into a
steam turbine that, in turn, drives an electric generator. As the
thermal efficiency of a stationary combustion turbine EGU is increased,
less fuel is burned to produce the same amount of electricity, with a
corresponding decrease in fuel costs and lower emissions of
CO2 and, generally, of other air pollutants. The greater the
output of electric energy for a given amount of fuel energy input, the
higher the efficiency of the electric generation process.
Combustion turbines serve various roles in the power sector. Some
combustion turbines operate at low annual capacity factors and are
available to provide temporary power during periods of high load
demand. These turbines are often referred to as ``peaking units.'' Some
combustion turbines operate at intermediate annual capacity factors and
are often referred to as cycling or load-following units. Other
combustion turbines operate at high annual capacity factors to serve
base load demand and are often referred to as base load units. In this
rulemaking, the EPA refers to these types of combustion turbines as low
load, intermediate load, and base load, respectively.
Low load combustion turbines provide reserve capacity, support grid
reliability, and generally provide power during periods of peak
electric demand. As such, the units may operate at or near their full
capacity, but only for short periods, as needed. Because these units
only operate occasionally, capital expenses are a major factor in the
overall cost of electricity, and often, the lowest capital cost (and
generally less efficient) simple cycle EGUs are intended for use only
during periods of peak electric demand. Due to their low efficiency,
these units require more fuel per MWh of electricity produced and their
operating costs tend to be higher. Because of the higher operating
costs, they are generally some of the last units in the dispatch order.
Important characteristics for low load combustion turbines include
their low capital costs, their ability to start quickly and to rapidly
ramp up to full load, and their ability to operate at partial loads
while maintaining acceptable emission rates and efficiencies. The
ability to start quickly and rapidly attain full load is important to
maximize revenue during periods of peak electric prices and to meet
sudden shifts in demand. In contrast, under steady-state conditions,
more efficient combined cycle EGUs are dispatched ahead of low load
turbines and often operate at higher annual capacity factors.
Highly efficient simple cycle turbines and flexible fast-start
combined cycle turbines both offer different advantages and
disadvantages when operating at intermediate loads. One of the roles of
these intermediate or load following EGUs is to provide dispatchable
backup power to support variable renewable generating sources (e.g.,
solar and wind). A developer's decision as to whether to build a simple
cycle turbine or a combined cycle turbine to serve intermediate load
demand is based on several factors related to the intended operation of
the unit. These factors would include how frequently the unit is
expected to cycle between starts and stops, the predominant load level
at which the unit is expected to operate, and whether this level of
operation is expected to remain consistent or is expected to vary over
the lifetime of the unit. In areas of the U.S. with vertically
integrated electricity markets, utilities determine dispatch orders
based generally on economic merit of individual units. Meanwhile, in
areas of the U.S. inside organized wholesale electricity markets,
owner/operators of individual combustion turbines control whether and
how units will operate over time, but they do not necessarily control
the precise timing of dispatch for units in any given day or hour. Such
short-term dispatch decisions are often made by regional grid operators
that determine, on a moment-to-moment basis, which available individual
units should operate to balance supply and demand and other
requirements in an optimal manner, based on operating costs, price
bids, and/or operational characteristics. However, operating permits
for simple cycle turbines often contain restrictions on the annual
hours of operation that owners/operators incorporate into longer-term
operating plans and short-term dispatch decisions.
Intermediate load combustion turbines vary their generation,
especially during transition periods between low and high electric
demand. Both high-efficiency simple cycle turbines and flexible fast-
start combined cycle turbines can fill this cycling role. While the
ability to start quickly and quickly ramp up is important, efficiency
is also an important characteristic. These combustion turbines
generally have higher capital costs than low load combustion turbines
but are generally less expensive to operate.
Base load combustion turbines are designed to operate for extended
periods at high loads with infrequent starts and stops. Quick-start
capability and low capital costs are less important than low operating
costs. High-efficiency combined cycle turbines typically fill the role
of base load combustion turbines.
The increase in generation from variable renewable energy sources
during the past decade has impacted the
[[Page 39904]]
way in which dispatchable generating resources operate.\706\ For
example, the electric output from wind and solar generating sources
fluctuates daily and seasonally due to increases and decreases in the
wind speed or solar intensity. Due to this variable nature of wind and
solar, dispatchable EGUs, including combustion turbines as well as
other technologies like energy storage, are used to ensure the
reliability of the electric grid. This requires dispatchable power
plants to have the ability to quickly start and stop and to rapidly and
frequently change load--much more often than was previously needed.
These are important characteristics of the combustion turbines that
provide firm backup capacity. Combustion turbines are much more
flexible than coal-fired utility boilers in this regard and have played
an important role during the past decade in ensuring that electric
supply and demand are balanced.
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\706\ Dispatchable generating sources are those that can be
turned on and off and adjusted to provide power to the electric grid
based on the demand for electricity. Variable (sometimes referred to
as intermittent) generating sources are those that supply
electricity based on external factors that are not controlled by the
owner/operator of the source (e.g., wind and solar sources).
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As discussed in section IV.F.2 of this preamble, in the final TSD,
Power Sector Trends, and in the accompanying RIA, the EPA's Power
Sector Platform 2023 using IPM projects that natural gas-fired
combustion turbines will continue to play an important role in meeting
electricity demand. However, that role is projected to evolve as
additional renewable and non-renewable low-GHG generation and energy
storage technologies are added to the grid. Energy storage technologies
can store energy during periods when generation from renewable
resources is high relative to demand and can provide electricity to the
grid during other periods. Energy storage technologies are projected to
reduce the need for base load fossil fuel-fired firm dispatchable power
plants, and the capacity factors of combined cycle EGUs are forecast to
decline by 2040.
C. Overview of Regulation of Stationary Combustion Turbines for GHGs
As explained earlier in this preamble, the EPA originally regulated
new and reconstructed stationary combustion turbine EGUs for emissions
of GHGs in 2015 under 40 CFR part 60, subpart TTTT. In 40 CFR part 60,
subpart TTTT, the EPA created three subcategories: two for natural gas-
fired combustion turbines and one for multi-fuel-fired combustion
turbines. For natural gas-fired turbines, the EPA created a subcategory
for base load turbines and a separate subcategory for non-base load
turbines. Base load turbines were defined as combustion turbines with
electric sales greater than a site-specific electric sales threshold
based on the design efficiency of the combustion turbine. Non-base load
turbines were defined as combustion turbines with a capacity factor
less than or equal to the site-specific electric sales threshold. For
base load turbines, the EPA set a standard of 1,000 lb CO2/
MWh-gross based on efficient combined cycle turbine technology. For
non-base load and multi-fuel-fired turbines, the EPA set a standard
based on the use of lower-emitting fuels that varied from 120 lb
CO2/MMBtu to 160 lb CO2/MMBtu, depending upon
whether the turbine burned primarily natural gas or other lower-
emitting fuels.
D. Eight-Year Review of NSPS
CAA section 111(b)(1)(B) requires the Administrator to ``at least
every 8 years, review and, if appropriate, revise [the NSPS] . . . .''
The provision further provides that ``the Administrator need not review
any such standard if the Administrator determines that such review is
not appropriate in light of readily available information on the
efficacy of such [NSPS].''
The EPA promulgated the NSPS for GHG emissions for stationary
combustion turbines in 2015. Announcements and modeling projections
show that project developers are building new fossil fuel-fired
combustion turbines and have plans to continue building additional
capacity. Because the emissions from this added capacity have the
potential to be large and these units are likely to have long operating
lives (25 years or more), it is important to limit emissions from these
new units. Accordingly, in this final rule, the EPA is updating the
NSPS for newly constructed and reconstructed fossil fuel-fired
stationary combustion turbines.
E. Applicability Requirements and Subcategorization
This section describes the amendments to the specific applicability
criteria for non-fossil fuel-fired EGUs, industrial EGUs, CHP EGUs, and
combustion turbine EGUs not connected to a natural gas pipeline. The
EPA is also making certain changes to the applicability requirements
for stationary combustion turbines affected by this final rule as
compared to those for sources affected by the 2015 NSPS. The amendments
are described below and include the elimination of the multi-fuel-fired
subcategory, further binning non-base load combustion turbines into low
load and intermediate load subcategories and establishing a capacity
factor threshold for base load combustion turbines.
1. Applicability Requirements
In general, the EPA refers to fossil fuel-fired EGUs that would be
subject to a CAA section 111 NSPS as ``affected'' EGUs or units. An EGU
is any fossil fuel-fired electric utility steam generating unit (i.e.,
a utility boiler or IGCC unit) or stationary combustion turbine (in
either simple cycle or combined cycle configuration). To be considered
an affected EGU under the 2015 NSPS at 40 CFR part 60, subpart TTTT,
the unit must meet the following applicability criteria: The unit must:
(1) be capable of combusting more than 250 MMBtu/h (260 gigajoules per
hour (GJ/h)) of heat input of fossil fuel (either alone or in
combination with any other fuel); and (2) serve a generator capable of
supplying more than 25 MW net to a utility distribution system (i.e.,
for sale to the grid).\707\ However, 40 CFR part 60, subpart TTTT,
includes applicability exemptions for certain EGUs, including: (1) non-
fossil fuel-fired units subject to a federally enforceable permit that
limits the use of fossil fuels to 10 percent or less of their heat
input capacity on an annual basis; (2) CHP units that are subject to a
federally enforceable permit limiting annual net electric sales to no
more than either the unit's design efficiency multiplied by its
potential electric output, or 219,000 MWh, whichever is greater; (3)
stationary combustion turbines that are not physically capable of
combusting natural gas (e.g., those that are not connected to a natural
gas pipeline); (4) utility boilers and IGCC units that have always been
subject to a federally enforceable permit limiting annual net electric
sales to one-third or less of their potential electric output (e.g.,
limiting hours of operation to less than 2,920 hours annually) or
limiting annual electric sales to 219,000 MWh or less; (5) municipal
waste combustors that are subject to 40 CFR part 60, subpart Eb; (6)
commercial or industrial solid waste incineration units subject to 40
CFR part 60, subpart CCCC; and (7) certain projects under development,
as discussed in the preamble for the 2015 final NSPS.
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\707\ The EPA refers to the capability to combust 250 MMBtu/h of
fossil fuel as the ``base load rating criterion.'' Note that 250
MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
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[[Page 39905]]
a. Revisions to 40 CFR Part 60, Subpart TTTT
The EPA is amending 40 CFR 60.5508 and 60.5509 to reflect that
stationary combustion turbines that commenced construction after
January 8, 2014, or reconstruction after June 18, 2014, and before May
24, 2023, and that meet the relevant applicability criteria are subject
to 40 CFR part 60, subpart TTTT. For steam generating EGUs and IGCC
units, 40 CFR part 60, subpart TTTT, remains applicable for units
constructed after January 8, 2014, or reconstructed after June 18,
2014. The EPA is finalizing 40 CFR part 60, subpart TTTTa, to be
applicable to stationary combustion turbines that commence construction
or reconstruction after May 23, 2023, and that meet the relevant
applicability criteria.
b. Revisions to 40 CFR Part 60, Subpart TTTT, That Are Also Included in
40 CFR Part 60, Subpart TTTTa
The EPA is finalizing that 40 CFR part 60, subpart TTTT, and 40 CFR
part 60, subpart TTTTa, use similar regulatory text except where
specifically stated. This section describes amendments included in both
subparts.
i. Applicability to Non-Fossil Fuel-Fired EGUs
The current non-fossil applicability exemption in 40 CFR part 60,
subpart TTTT, is based strictly on the combustion of non-fossil fuels
(e.g., biomass). To be considered a non-fossil fuel-fired EGU, the EGU
must be both: (1) Capable of combusting more than 50 percent non-fossil
fuel and (2) subject to a federally enforceable permit condition
limiting the annual heat input capacity for all fossil fuels combined
of 10 percent or less. The current language does not take heat input
from non-combustion sources (e.g., solar thermal) into account. Certain
solar thermal installations have natural gas backup burners larger than
250 MMBtu/h. As currently treated in 40 CFR part 60, subpart TTTT,
these solar thermal installations are not eligible to be considered
non-fossil units because they are not capable of deriving more than 50
percent of their heat input from the combustion of non-fossil fuels.
Therefore, solar thermal installations that include backup burners
could meet the applicability criteria of 40 CFR part 60, subpart TTTT,
even if the burners are limited to an annual capacity factor of 10
percent or less. These EGUs would readily comply with the standard of
performance, but the reporting and recordkeeping would increase costs
for these EGUs.
The EPA proposed and is finalizing several amendments to align the
applicability criteria with the original intent to cover only fossil
fuel-fired EGUs. These amendments ensure that solar thermal EGUs with
natural gas backup burners, like other types of non-fossil fuel-fired
units that derive most of their energy from non-fossil fuel sources,
are not subject to the requirements of 40 CFR part 60, subpart TTTT or
TTTTa. Amending the applicability language to include heat input
derived from non-combustion sources allows these facilities to avoid
the requirements of 40 CFR part 60, subpart TTTT or TTTTa, by limiting
the use of the natural gas burners to less than 10 percent of the
capacity factor of the backup burners. Specifically, the EPA is
amending the definition of non-fossil fuel-fired EGUs from EGUs capable
of ``combusting 50 percent or more non-fossil fuel'' to EGUs capable of
``deriving 50 percent or more of the heat input from non-fossil fuel at
the base load rating'' (emphasis added). The definition of base load
rating is also being amended to include the heat input from non-
combustion sources (e.g., solar thermal).
Revising ``combusting'' to ``deriving'' in the amended non-fossil
fuel applicability language ensures that 40 CFR part 60, subparts TTTT
and TTTTa, cover the fossil fuel-fired EGUs that the original rule was
intended to cover, while minimizing unnecessary costs to EGUs fueled
primarily by steam generated without combustion (e.g., thermal energy
supplied through the use of solar thermal collectors). The
corresponding change in the base load rating to include the heat input
from non-combustion sources is necessary to determine the relative heat
input from fossil fuel and non-fossil fuel sources.
ii. Industrial EGUs
(A) Applicability to Industrial EGUs
In simple terms, the current applicability provisions in 40 CFR
part 60, subpart TTTT, require that an EGU be capable of combusting
more than 250 MMBtu/h of fossil fuel and be capable of selling 25 MW to
a utility distribution system to be subject to 40 CFR part 60, subpart
TTTT. These applicability provisions exclude industrial EGUs. However,
the definition of an EGU also includes ``integrated equipment that
provides electricity or useful thermal output.'' This language
facilitates the integration of non-emitting generation and avoids
energy inputs from non-affected facilities being used in the emission
calculation without also considering the emissions of those facilities
(e.g., an auxiliary boiler providing steam to a primary boiler). This
language could result in certain large processes being included as part
of the EGU and meeting the applicability criteria. For example, the
high-temperature exhaust from an industrial process (e.g., calcining
kilns, dryer, metals processing, or carbon black production facilities)
that consumes fossil fuel could be sent to a HRSG to produce
electricity. If the industrial process uses more than 250 MMBtu/h heat
input and the electric sales exceed the applicability criteria, then
the unit could be subject to 40 CFR part 60, subpart TTTT or TTTTa.
This is potentially problematic for multiple reasons. First, it is
difficult to determine the useful output of the EGU (i.e., HRSG) since
part of the useful output is included in the industrial process. In
addition, the fossil fuel that is combusted could have a relatively
high CO2 emissions rate on a lb/MMBtu basis, making it
potentially problematic to meet the standard of performance using
efficient generation. This could result in the owner/operator reducing
the electric output of the industrial facility to avoid the
applicability criteria. Finally, the compliance costs associated with
40 CFR part 60, subpart TTTT or TTTTa, could discourage the development
of environmentally beneficial projects.
To avoid these outcomes, the EPA is, as proposed, amending the
applicability provision that exempts EGUs where greater than 50 percent
of the heat input is derived from an industrial process that does not
produce any electrical or mechanical output or useful thermal output
that is used outside the affected EGU.\708\ Reducing the output or not
developing industrial electric generating projects where the majority
of the heat input is derived from the industrial process itself would
not necessarily result in reductions in GHG emissions from the
industrial facility. However, the electricity that would have been
produced from the industrial project could still be needed. Therefore,
projects of this type provide significant environmental benefit by
providing additional useful output with little if any additional
environmental impact. Including these types of projects would result in
regulatory burden without any associated environmental benefit and
could discourage project development,
[[Page 39906]]
leading to potential overall increases in GHG emissions.
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\708\ Auxiliary equipment such as boilers or combustion turbines
that provide heat or electricity to the primary EGU (including to
any control equipment) would still be considered integrated
equipment and included as part of the affected facility.
---------------------------------------------------------------------------
(B) Industrial EGUs Electric Sales Threshold Permit Requirement
The current electric sales applicability exemption in 40 CFR part
60, subpart TTTT, for non-CHP steam generating units includes the
provision that EGUs have ``always been subject to a federally
enforceable permit limiting annual net electric sales to one-third or
less of their potential electric output (e.g., limiting hours of
operation to less than 2,920 hours annually) or limiting annual
electric sales to 219,000 MWh or less'' (emphasis added). The
justification for this restriction includes that the 40 CFR part 60,
subpart Da, applicability language includes ``constructed for the
purpose of . . .'' and the Agency concluded that the intent was defined
by permit conditions (80 FR 64544; October 23, 2015). This
applicability criterion is important both for determining applicability
with the new source CAA section 111(b) requirements and for determining
whether existing steam generating units are subject to the existing
source CAA section 111(d) requirements. For steam generating units that
commenced construction after September 18, 1978, the applicability of
40 CFR part 60, subpart Da, would be relatively clear as to what
criteria pollutant NSPS is applicable to the facility. However, for
steam generating units that commenced construction prior to September
18, 1978, or where the owner/operator determined that criteria
pollutant NSPS applicability was not critical to the project (e.g.,
emission controls were sufficient to comply with either the EGU or
industrial boiler criteria pollutant NSPS), owners/operators might not
have requested that an electric sales permit restriction be included in
the operating permit. Under the current applicability language, some
onsite EGUs could be covered by the existing source CAA section 111(d)
requirements even if they have never sold electricity to the grid. To
avoid covering these industrial EGUs, the EPA proposed and is
finalizing amendments to the electric sales exemption in 40 CFR part
60, subparts TTTT and TTTTa, to read, ``annual net electric sales have
never exceeded one-third of its potential electric output or 219,000
MWh, whichever is greater, and is [the ``always been'' would be
deleted] subject to a federally enforceable permit limiting annual net
electric sales to one-third or less of their potential electric output
(e.g., limiting hours of operation to less than 2,920 hours annually)
or limiting annual electric sales to 219,000 MWh or less'' (emphasis
added). EGUs that reduce current generation will continue to be covered
as long as they sold more than one-third of their potential electric
output at some time in the past. The revisions make it possible for an
owner/operator of an existing industrial EGU to provide evidence to the
Administrator that the facility has never sold electricity in excess of
the electricity sales threshold and to modify their permit to limit
sales in the future. Without the amendment, owners/operators of any
non-CHP industrial EGU capable of selling 25 MW would be subject to the
existing source CAA section 111(d) requirements even if they have never
sold any electricity. Therefore, the EPA is eliminating the requirement
that existing industrial EGUs must have always been subject to a permit
restriction limiting net electric sales.
iii. Determination of the Design Efficiency
The design efficiency (i.e., the efficiency of converting thermal
energy to useful energy output) of a combustion turbine is used to
determine the electric sales applicability threshold. In 40 CFR part
60, subpart TTTT, the sales criteria are based in part on the
individual EGU design efficiency. Three methods for determining the
design efficiency are currently provided in 40 CFR part 60, subpart
TTTT.\709\ Since the 2015 NSPS was finalized, the EPA has become aware
that owners/operators of certain existing EGUs do not have records of
the original design efficiency. These units would not be able to
readily determine whether they meet the applicability criteria (and
would therefore be subject to CAA section 111(d) requirements for
existing sources) in the same way that 111(b) sources would be able to
determine if the facility meets the applicability criteria. Many of
these EGUs are CHP units that are unlikely to meet the 111(b)
applicability criteria and would therefore not be subject to any future
111(d) requirements. However, the language in the 2015 NSPS would
require them to conduct additional testing to demonstrate this. The
requirement would result in burden to the regulated community without
any environmental benefit. The electricity generating market has
changed, in some cases dramatically, during the lifetime of existing
EGUs, especially concerning ownership. As a result of acquisitions and
mergers, original EGU design efficiency documentation, as well as
performance guarantee results that affirmed the design efficiency, may
no longer exist. Moreover, such documentation and results may not be
relevant for current EGU efficiencies, as changes to original EGU
configurations, upon which the original design efficiencies were based,
render those original design efficiencies moot, meaning that there
would be little reason to maintain former design efficiency
documentation since it would not comport with the efficiency associated
with current EGU configurations. As the three specified methods would
rely on documentation from the original EGU configuration performance
guarantee testing, and results from that documentation may no longer
exist or be relevant, it is appropriate to allow other means to
demonstrate EGU design efficiency. To reduce potential future
compliance burden, the EPA proposed and is finalizing in 40 CFR part
60, subparts TTTT and TTTTa, to allow alternative methods as approved
by the Administrator on a case-by-case basis. Owners/operators of EGUs
can petition the Administrator in writing to use an alternate method to
determine the design efficiency. The Administrator's discretion is
intentionally left broad and can extend to other American Society of
Mechanical Engineers (ASME) or International Organization for
Standardization (ISO) methods as well as to operating data to
demonstrate the design efficiency of the EGU. The EPA also proposed and
is finalizing a change to the applicability of paragraph 60.8(b) in
table 3 of 40 CFR part 60, subpart TTTT, from ``no'' to ``yes'' and
that the applicability of paragraph 60.8(b) in table 3 of 40 CFR part
60, subpart TTTTa, is ``yes.'' This allows the Administrator to approve
alternatives to the test methods specified in 40 CFR part 60, subparts
TTTT and TTTTa.
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\709\ 40 CFR part 60, subpart TTTT, currently lists ``ASME PTC
22 Gas Turbines,'' ``ASME PTC 46 Overall Plant Performance,'' and
``ISO 2314 Gas turbines--acceptance tests'' as approved methods to
determine the design efficiency.
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c. Applicability for 40 CFR Part 60, Subpart TTTTa
This section describes applicability criteria that are only
incorporated into 40 CFR part 60, subpart TTTTa, and that differ from
the requirements in 40 CFR part 60, subpart TTTT.
Section 111 of the CAA defines a new or modified source for
purposes of a given NSPS as any stationary source that commences
construction or modification after the publication of the proposed
regulation. Thus, the standards of performance apply to EGUs that
commence construction or reconstruction after the date of proposal of
this rule--May 23, 2023. EGUs that commenced construction after the
date
[[Page 39907]]
of the proposal for the 2015 NSPS and by May 23, 2023, will remain
subject to the standards of performance promulgated in the 2015 NSPS. A
modification is any physical change in, or change in the method of
operation of, an existing source that increases the amount of any air
pollutant emitted to which a standard applies.\710\ The NSPS general
provisions (40 CFR part 60, subpart A) provide that an existing source
is considered a new source if it undertakes a reconstruction.\711\
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\710\ 40 CFR 60.2.
\711\ 40 CFR 60.15(a).
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The EPA is finalizing the same applicability requirements in 40 CFR
part 60, subpart TTTTa, as the applicability requirements in 40 CFR
part 60, subpart TTTT. The stationary combustion turbine must meet the
following applicability criteria: The stationary combustion turbine
must: (1) be capable of combusting more than 250 MMBtu/h (260
gigajoules per hour (GJ/h)) of heat input of fossil fuel (either alone
or in combination with any other fuel); and (2) serve a generator
capable of supplying more than 25 MW net to a utility distribution
system (i.e., for sale to the grid).\712\ In addition, the EPA proposed
and is finalizing in 40 CFR part 60, subpart TTTTa, to include
applicability exemptions for stationary combustion turbines that are:
(1) capable of deriving 50 percent or more of the heat input from non-
fossil fuel at the base load rating and subject to a federally
enforceable permit condition limiting the annual capacity factor for
all fossil fuels combined of 10 percent (0.10) or less; (2) combined
heat and power units subject to a federally enforceable permit
condition limiting annual net electric sales to no more than 219,000
MWh or the product of the design efficiency and the potential electric
output, whichever is greater; (3) serving a generator along with other
steam generating unit(s), IGCC, or stationary combustion turbine(s)
where the effective generation capacity is 25 MW or less; (4) municipal
waste combustors that are subject to 40 CFR part 60, subpart Eb; (5)
commercial or industrial solid waste incineration units subject to 40
CFR part 60, subpart CCCC; and (6) deriving greater than 50 percent of
heat input from an industrial process that does not produce any
electrical or mechanical output that is used outside the affected
stationary combustion turbine.
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\712\ The EPA refers to the capability to combust 250 MMBtu/h of
fossil fuel as the ``base load rating criterion.'' Note that 250
MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
---------------------------------------------------------------------------
The EPA proposed the same requirements to combustion turbines in
non-continental areas (i.e., Hawaii, the Virgin Islands, Guam, American
Samoa, the Commonwealth of Puerto Rico, and the Northern Mariana
Islands) and non-contiguous areas (non-continental areas and Alaska) as
the EPA did for comparable units in the contiguous 48 states.\713\
However, the Agency solicited comment on whether owners/operators of
new and reconstructed combustion turbines in non-continental and non-
contiguous areas should be subject to different requirements.
Commenters generally commented that due to the difference in non-
contiguous areas relative to the lower 48 states, the proposed
requirements should not apply to owners/operators of new or
reconstructed combustion turbines in non-contiguous areas. The Agency
has considered these comments and is finalizing that only the initial
BSER component will be applicable to owners/operators of combustion
turbines located in non-contiguous areas. Therefore, owners/operators
of base load combustions turbines would not be subject to the CCS-based
numerical standards in 2032 and would continue to comply with the
efficiency-based numeric standard. Based on information reported in the
2022 EIA Form EIA-860, there are no planned new combustion turbines in
either Alaska or Hawaii. In addition, since 2015 no new combustion
turbines have commenced operation in Hawaii. Two new combustion turbine
facilities totaling 190 MW have commenced operation in Alaska since
2015. One facility is a combined cycle CHP facility and the other is at
an industrial facility and neither facility would likely meet the
applicability of 40 CFR part 60, subpart TTTTa. Therefore, not
finalizing phase-2 BSER for non-continental and non-contiguous areas
will have limited, if any, impacts on emissions or costs. The EPA notes
that the Agency has the authority to amend this decision in future
rulemakings.
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\713\ 40 CFR part 60, subpart TTTT, also includes coverage for
owners/operators of combustion turbines in non-contiguous areas.
However, owners/operators of combustion turbines not capable of
combusting natural gas (e.g., not connected to a natural gas
pipeline) are not subject to the rule. This exemption covers many
combustion turbines in non-contiguous areas.
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i. Applicability to CHP Units
For 40 CFR part 60, subpart TTTT, owners/operators of CHP units
calculate net electric sales and net energy output using an approach
that includes ``at least 20.0 percent of the total gross or net energy
output consists of electric or direct mechanical output.'' It is
unlikely that a CHP unit with a relatively low electric output (i.e.,
less than 20.0 percent) would meet the applicability criteria. However,
if a CHP unit with less than 20.0 percent of the total output
consisting of electricity were to meet the applicability criteria, the
net electric sales and net energy output would be calculated the same
as for a traditional non-CHP EGU. Even so, it is not clear that these
CHP units would have less environmental benefit per unit of electricity
produced than would more traditional CHP units. For 40 CFR part 60,
subpart TTTTa, the EPA proposed and is finalizing to eliminate the
restriction that CHP units produce at least 20.0 percent electrical or
mechanical output to qualify for the CHP-specific method for
calculating net electric sales and net energy output.
In the 2015 NSPS, the EPA did not issue standards of performance
for certain types of sources--including industrial CHP units and CHPs
that are subject to a federally enforceable permit limiting annual net
electric sales to no more than the unit's design efficiency multiplied
by its potential electric output, or 219,000 MWh or less, whichever is
greater. For CHP units, the approach in 40 CFR part 60, subpart TTTT,
for determining net electric sales for applicability purposes allows
the owner/operator to subtract the purchased power of the thermal host
facility. The intent of the approach is to determine applicability
similarly for third-party developers and CHP units owned by the thermal
host facility.\714\ However, as written in 40 CFR part 60, subpart
TTTT, each third-party CHP unit would subtract the entire electricity
use of the thermal host facility when determining its net electric
sales. It is clearly not the intent of the provision to allow multiple
third-party developers that serve the same thermal host to all subtract
the purchased power of the thermal host facility when determining net
electric sales. This would result in counting the purchased power
multiple times. In addition, it is not the intent of the provision to
allow a CHP developer to provide a trivial amount of useful thermal
output to multiple thermal hosts and then subtract all the thermal
hosts' purchased power when determining net electric sales for
applicability purposes. The EPA
[[Page 39908]]
proposed and is finalizing in 40 CFR part 60, subpart TTTTa, to limit
to the amount of thermal host purchased power that a third-party CHP
developer can subtract for electric sales when determining net electric
sales equivalent to the percentage of useful thermal output provided to
the host facility by the specific CHP unit. This approach eliminates
both circumvention of the intended applicability by sales of trivial
amounts of useful thermal output and double counting of thermal host-
purchased power.
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\714\ For contractual reasons, many developers of CHP units sell
the majority of the generated electricity to the electricity
distribution grid. Owners/operators of both the CHP unit and thermal
host can subtract the site purchased power when determining net
electric sales. Third-party developers that do not own the thermal
host can also subtract the purchased power of the thermal host when
determining net electric sales for applicability purposes.
---------------------------------------------------------------------------
Finally, to avoid potential double counting of electric sales, the
EPA proposed and is finalizing that for CHP units determining net
electric sales, purchased power of the host facility be determined
based on the percentage of thermal power provided to the host facility
by the specific CHP facility.
ii. Non-Natural Gas Stationary Combustion Turbines
There is currently an exemption in 40 CFR part 60, subpart TTTT,
for stationary combustion turbines that are not physically capable of
combusting natural gas (e.g., those that are not connected to a natural
gas pipeline). While combustion turbines not connected to a natural gas
pipeline meet the general applicability of 40 CFR part 60, subpart
TTTT, these units are not subject to any of the requirements. The EPA
is not including in 40 CFR part 60, subpart TTTTa, the exemption for
stationary combustion turbines that are not physically capable of
combusting natural gas. As described in the standards of performance
section, owners/operators of combustion turbines burning fuels with a
higher heat input emission rate than natural gas would adjust the
natural gas-fired emissions rate by the ratio of the heat input-based
emission rates. The overall result is that new stationary combustion
turbines combusting fuels with higher GHG emissions rates than natural
gas on a lb CO2/MMBtu basis must maintain the same
efficiency compared to a natural gas-fired combustion turbine and
comply with a standard of performance based on the identified BSER.
2. Subcategorization
In this final rule, the EPA is continuing to include both simple
and combined cycle turbines in the definition of a stationary
combustion turbine, and like in prior rules for this source category,
the Agency is finalizing three subcategories--low load, intermediate
load, and base load combustion turbines. These subcategories are
determined based on electric sales (i.e., utilization) relative to the
combustion turbines' potential electric output to an electric
distribution network on both a 12-operating month and 3-year rolling
average basis. The applicable subcategory is determined each operating
month and a stationary combustion turbine can switch subcategories if
the owner/operator changes the way the facility is operated.
Subcategorization based on percent electric sales is a proxy for how a
combustion turbine operates and for determining the BSER and
corresponding emission standards. For example, low load combustion
turbines tend to spend a relatively high percentage of operating hours
starting and stopping. However, within each subcategory not all
combustion turbines operate the same. Some low load combustion turbines
operate with less starting and stopping, but in general, combustion
turbines tend to operate with fewer starts and stops (i.e., more
steady-state hours of operation) with increasing percentages of
electric sales. The BSER for each subcategory is based on
representative operation of the combustion turbines in that subcategory
and on what is achievable for the subcategory as a whole.
Subcategorization by electric sales is similar, but not identical,
to subcategorizing by heat input-based capacity factors or annual hours
of operation limits.\715\ The EPA has determined that, for NSPS
purposes, electric sales is appropriate because it reflects operational
limitations inherent in the design of certain units, and also that--
given these differences--certain emission reduction technologies are
more suitable for some units than for others.\716\ This
subcategorization approach is also consistent with industry practice.
For example, operating permits for simple cycle turbines often include
annual operating hour limitations of 1,500 to 4,000 hours annually.
When average hourly capacity factors (i.e., duty cycles) are accounted
for, these hourly restrictions are similar to annual capacity factor
restrictions of approximately 15 percent and 40 percent, respectively.
The owners or operators of these combustion turbines never intend for
them to provide base load power. In contrast, operating permits do not
typically restrict the number of hours of annual operation for combined
cycle turbines, reflecting that these types of combustion turbines are
intended to have the ability to provide base load power.
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\715\ Percent electric sales thresholds, capacity factor
thresholds, and annual hours of operation limitations all categorize
combustion turbines based on utilization.
\716\ While utilization and electric sales are often similar,
the EPA uses electric sales because the focus of the applicability
is facilities that sell electricity to the grid and not industrial
facilities where the electricity is generated primarily for use
onsite.
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The EPA evaluated the operation of the three general combustion
turbine technologies--combined cycle turbines, frame-type simple cycle
turbines, and aeroderivative simple cycle turbines--when determining
the subcategorization approach in this rulemaking.\717\ The EPA found
that, at the same capacity factor, aeroderivative simple cycle turbines
have more starts (including fewer operating hours per start) than
either frame simple cycle turbines or combined cycle turbines. The
maximum number of starts for aeroderivative simple cycle turbines
occurs at capacity factors of approximately 30 percent and the maximum
number of starts for frame simple cycle turbines and combined cycle
turbines both occur at capacity factors of approximately 25 percent. In
terms of the median hours of operation per start, the hours per starts
increases exponentially with capacity factor for each type of
combustion turbine. The rate of increase is greatest for combined cycle
turbines with the run times per start increasing significantly at
capacity factors of 40 and greater. This threshold roughly matches the
subcategorization threshold for intermediate load and base load
turbines in this final rule. As is discussed later in section VIII.F.3
and VIII.F.4, technology options including those related to efficiency
and to post combustion capture are impacted by the way units operate
and can be more effective for units with fewer stops and starts.
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\717\ The EPA used manufacturers' designations for frame and
aeroderivative combustion turbines.
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a. Legal Basis for Subcategorization
As noted in section V.C.1 of this preamble, CAA section 111(b)(2)
provides that the EPA ``may distinguish among classes, types, and sizes
within categories of new sources for the purpose of establishing . . .
standards [of performance].'' The D.C. Circuit has held that the EPA
has broad discretion in determining whether and how to subcategorize
under CAA section 111(b)(2). Lignite Energy Council, 198 F.3d at 933.
As also noted in section V.C.1 of this preamble, in prior CAA section
111 rules, the EPA has subcategorized on numerous bases, including,
among other things, fuel type and load, i.e., utilization. In
particular, as noted in section V.C.1 of this preamble, the EPA
subcategorized on the basis of utilization--for base load
[[Page 39909]]
and non-base load subcategories--in the 2015 NSPS for GHG emissions
from combustion turbines, Standards of Performance for Greenhouse Gas
Emissions From New, Modified, and Reconstructed Stationary Sources:
Electric Utility Generating Units, 80 FR 64509 (October 23, 2015), and
also in the NESHAP for Reciprocating Internal Combustion Engines; NSPS
for Stationary Internal Combustion Engines, 79 FR 48072-01 (August 15,
2014).
Subcategorizing combustion turbines based on utilization is
appropriate because it recognizes the way differently designed
combustion turbines actually operate. Project developers do not
construct combined cycle combustion turbine system to start and stop
often to serve peak demand. Similarly, project developers do not
construct and install simple cycle combustion turbines to operate at
higher capacity factors to provide base load demand. And intermediate
load demand may be served by higher efficiency simple cycle turbine
systems or by ``quick start'' combined cycle units. Thus, there are
distinguishing features (i.e., different classes, types, and sizes) of
turbines that are predominantly used in each of the utilization-based
subcategories. Further, the amount of utilization and the mode of
operation are relevant for the systems of emission reduction that the
EPA may evaluate to be the BSER and therefore for the resulting
standards of performance. See section VII.C.2.a.i for more discussion
of the legal basis to subcategorize based upon characteristics relevant
to the controls the EPA may determine to be the BSER.
As noted in sections VIII.E.2.b and VIII.F of this preamble,
combustion turbines that operate at low load have highly variable
operation and therefore highly variable emission rates. This
variability made it challenging for the EPA to specify a BSER based on
efficient design and operation and limits the BSER for purposes of this
rulemaking to lower-emitting fuels. The EPA notes that the
subcategorization threshold and the standard of performance are
related. For example, the Agency could have finalized a lower electric
sales threshold for the low load subcategory (e.g., 15 percent) and
evaluated the emission rates at the lower capacity factors. In future
rulemaking the Agency could further evaluate the costs and emissions
impacts of reducing the threshold for combustion turbines subject to a
BSER based on the use of lower emitting fuels.
Intermediate load combustion turbines (i.e., those that operate at
loads that are somewhat higher than the low load peaking units) are
most often designed to be simple cycle units rather than combined cycle
units. This is because combustion turbines operating in the
intermediate load range also start and stop and vary their load
frequently (though not as often as low load peaking units). Because of
the more frequent starts and stops, simple cycle combustion turbines
are more economical for project developers when compared to combined
cycle combustion turbines. Utilization of CCS technology is not
practicable for those simple cycle units due to the lack of a HRSG.
Therefore, the EPA has determined that efficient design and operation
is the BSER for intermediate load combustion turbines.
While use of CCS is practicable for combined cycle combustion
turbines, it is most appropriate for those units that operate at
relatively higher loads (i.e., as base load units) that do not
frequently start, stop, and change load. Moreover, with current
technology, CCS works better on units running at base load levels.
b. Electric Sales Subcategorization (Low, Intermediate, and Base Load
Combustion Turbines)
As noted earlier, in the 2015 NSPS, the EPA established separate
standards of performance for new and reconstructed natural gas-fired
base load and non-base load stationary combustion turbines. The
electric sales threshold distinguishing the two subcategories is based
on the design efficiency of individual combustion turbines. A
combustion turbine qualifies as a non-base load turbine--and is thus
subject to a less stringent standard of performance--if it has net
electric sales equal to or less than the design efficiency of the
turbine (not to exceed 50 percent) multiplied by the potential electric
output (80 FR 64601; October 23, 2015). If the net electric sales
exceed that level on both a 12-operating month and 3-calendar year
basis, then the combustion turbine is in the base load subcategory and
is subject to a more stringent standard of performance. Subcategory
applicability can change on a month-to-month basis since applicability
is determined each operating month. For additional discussion on this
approach, see the 2015 NSPS (80 FR 64609-12; October 23, 2015). The
2015 NSPS non-base load subcategory is broad and includes combustion
turbines that assure grid reliability by providing electricity during
periods of peak electric demand. These peaking turbines tend to have
low annual capacity factors and sell a small amount of their potential
electric output. The non-base load subcategory in the 2015 NSPS also
includes combustion turbines that operate at intermediate annual
capacity factors and are not considered base load EGUs. These
intermediate load EGUs provide a variety of services, including
providing dispatchable power to support variable generation from
renewable sources of electricity. The need for this service has been
expanding as the amount of electricity from wind and solar continues to
grow. In the 2015 NSPS, the EPA determined the BSER for the non-base
load subcategory to be the use of lower-emitting fuels (e.g., natural
gas and Nos. 1 and 2 fuel oils). In 2015, the EPA explained that
efficient generation did not qualify as the BSER due in part to the
challenge of determining an achievable output-based CO2
emissions rate for all combustion turbines in this subcategory.
In this action, the EPA proposed and is finalizing the
subcategories in 40 CFR part 60, subpart TTTTa, that will be applicable
to sources that commence construction or reconstruction after May 23,
2023. First, the Agency proposed and is finalizing the definition of
design efficiency so that the heat input calculation of an EGU is based
on the higher heating value (HHV) of the fuel instead of the lower
heating value (LHV), as explained immediately below. This has the
effect of lowering the calculated potential electric output and the
electric sales threshold. In addition, the EPA proposed and is
finalizing division of the non-base load subcategory into separate
intermediate and low load subcategories.
i. Higher Heating Value as the Basis for Calculation of the Design
Efficiency
The heat rate is the amount of energy used by an EGU to generate 1
kWh of electricity and is often provided in units of Btu/kWh. As the
thermal efficiency of a combustion turbine EGU is increased, less fuel
is burned per kWh generated and there is a corresponding decrease in
emissions of CO2 and other air pollutants. The electric
energy output as a fraction of the fuel energy input expressed as a
percentage is a common practice for reporting the unit's efficiency.
The greater the output of electric energy for a given amount of fuel
energy input, the higher the efficiency of the electric generation
process. Lower heat rates are associated with more efficient power
generating plants.
Efficiency can be calculated using the HHV or the LHV of the fuel.
The HHV is the heating value directly determined by calorimetric
measurement of the fuel in the laboratory. The LHV is calculated using
a formula to account for the
[[Page 39910]]
moisture in the combustion gas (i.e., subtracting the energy required
to vaporize the water in the flue gas) and is a lower value than the
HHV. Consequently, the HHV efficiency for a given EGU is always lower
than the corresponding LHV efficiency because the reported heat input
for the HHV is larger. For U.S. pipeline natural gas, the HHV heating
value is approximately 10 percent higher than the corresponding LHV
heating value and varies slightly based on the actual constituent
composition of the natural gas.\718\ The EPA default is to reference
all technologies on a HHV basis,\719\ and the Agency is basing the heat
input calculation of an EGU on HHV for purposes of the definition of
design efficiency. However, it should be recognized that manufacturers
of combustion turbines typically use the LHV to express the efficiency
of combustion turbines.\720\
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\718\ The HHV of natural gas is 1.108 times the LHV of natural
gas. Therefore, the HHV efficiency is equal to the LHV efficiency
divided by 1.108. For example, an EGU with a LHV efficiency of 59.4
percent is equal to a HHV efficiency of 53.6 percent. The HHV/LHV
ratio is dependent on the composition of the natural gas (i.e., the
percentage of each chemical species (e.g., methane, ethane,
propane)) within the pipeline and will slightly move the ratio.
\719\ Natural gas is also sold on a HHV basis.
\720\ European plants tend to report thermal efficiency based on
the LHV of the fuel rather than the HHV for both combustion turbines
and steam generating EGUs. In the U.S., boiler efficiency is
typically reported on a HHV basis.
---------------------------------------------------------------------------
Similarly, the electric energy output for an EGU can be expressed
as either of two measured values. One value relates to the amount of
total electric power generated by the EGU, or gross output. However, a
portion of this electricity must be used by the EGU facility to operate
the unit, including compressors, pumps, fans, electric motors, and
pollution control equipment. This within-facility electrical demand,
often referred to as the parasitic load or auxiliary load, reduces the
amount of power that can be delivered to the transmission grid for
distribution and sale to customers. Consequently, electric energy
output may also be expressed in terms of net output, which reflects the
EGU gross output minus its parasitic load.\721\
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\721\ It is important to note that net output values reflect the
net output delivered to the electric grid and not the net output
delivered to the end user. Electricity is lost as it is transmitted
from the point of generation to the end user and these ``line
losses'' increase the farther the power is transmitted. 40 CFR part
60, subpart TTTT, provides a way to account for the environmental
benefit of reduced line losses by crediting CHP EGUs, which are
typically located close to large electric load centers. See 40 CFR
60.5540(a)(5)(i) and the definitions of gross energy output and net
energy output in 40 CFR 60.5580.
---------------------------------------------------------------------------
When using efficiency to compare the effectiveness of different
combustion turbine EGU configurations and the applicable GHG emissions
control technologies, it is important to ensure that all efficiencies
are calculated using the same type of heating value (i.e., HHV or LHV)
and the same basis of electric energy output (i.e., MWh-gross or MWh-
net). Most emissions data are available on a gross output basis and the
EPA is finalizing output-based standards based on gross output.
However, to recognize the superior environmental benefit of minimizing
auxiliary/parasitic loads, the Agency is including optional equivalent
standards on a net output basis. To convert from gross to net output-
based standards, the EPA used a 2 percent auxiliary load for simple and
combined cycle turbines and a 7 percent auxiliary load for combined
cycle EGUs using 90 percent CCS.\722\
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\722\ The 7 percent auxiliary load for combined cycle turbines
with 90 percent CCS is specific to electric output. Additional
auxiliary load includes thermal energy that is diverted to the CCS
system instead of being used to generate additional electricity.
This additional auxiliary thermal energy is accounted for when
converting the phase 1 emissions standard to the phase 2 standard.
---------------------------------------------------------------------------
ii. Lowering the Threshold Between the Base Load and Non-Base Load
Subcategories
The subpart TTTT distinction between a base load and non-base load
combustion turbine is determined by the unit's actual electric sales
relative to its potential electric sales, assuming the EGU is operated
continuously (i.e., percent electric sales). Specifically, stationary
combustion turbines are categorized as non-base load and are
subsequently subject to a less stringent standard of performance if
they have net electric sales equal to or less than their design
efficiency (not to exceed 50 percent) multiplied by their potential
electric output (80 FR 64601; October 23, 2015). Because the electric
sales threshold is based in part on the design efficiency of the EGU,
more efficient combustion turbine EGUs can sell a higher percentage of
their potential electric output while remaining in the non-base load
subcategory. This approach recognizes both the environmental benefit of
combustion turbines with higher design efficiencies and provides
flexibility to the regulated community. In the 2015 NSPS, it was
unclear how often high-efficiency simple cycle EGUs would be called
upon to support increased generation from variable renewable generating
resources. Therefore, the Agency determined it was appropriate to
provide maximum flexibility to the regulated community. To do this, the
Agency based the numeric value of the design efficiency, which is used
to calculate the electric sales threshold, on the LHV efficiency. This
had the impact of allowing combustion turbines to sell a greater share
of their potential electric output while remaining in the non-base load
subcategory.
The EPA proposed and is finalizing that the design efficiency in 40
CFR part 60, subpart TTTTa be based on the HHV efficiency instead of
LHV efficiency and to not include the 50 percent maximum and 33 percent
minimum restrictions. When determining the potential electric output
used in calculating the electric sales threshold in 40 CFR part 60,
subpart TTTT, design efficiencies of greater than 50 percent are
reduced to 50 percent and design efficiencies of less than 33 percent
are increased to 33 percent for determining electric sales threshold
subcategorization criteria. The 50 percent criterion was established to
limit non-base load EGUs from selling greater than 55 percent of their
potential electric sales.\723\ The 33 percent criterion was included to
be consistent with applicability thresholds in the electric utility
criteria pollutant NSPS (40 CFR part 60, subpart Da).
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\723\ While the design efficiency is capped at 50 percent on a
LHV basis, the base load rating (maximum heat input of the
combustion turbine) is on a HHV basis. This mixture of LHV and HHV
results in the electric sales threshold being 11 percent higher than
the design efficiency. The design efficiency of all new combined
cycle EGUs exceed 50 percent on a LHV basis.
---------------------------------------------------------------------------
Neither of those criteria are appropriate for 40 CFR part 60,
subpart TTTTa, and the EPA proposed and is finalizing a decision that
they are not incorporated when determining the electric sales
threshold. Instead, as discussed later in the section, the EPA is
finalizing a fixed percent electric sales thresholds and the design
efficiency does not impact the subcategorization thresholds. However,
the design efficiency is still used when determining the potential
electric sales and any restriction on using the actual design
efficiency of the combustion turbine would have the impact of changing
the threshold. If this restriction were maintained, it would reduce the
regulatory incentive for manufacturers to invest in programs to develop
higher efficiency combustion turbines.
The EPA also proposed and is finalizing a decision to eliminate the
33 percent minimum design efficiency in the calculation of the
potential electric output. The EPA is unaware of any new combustion
turbines with design efficiencies meeting the general
[[Page 39911]]
applicability criteria of less than 33 percent; and this will likely
have no cost or emissions impact.
The EPA solicited comment on whether the intermediate/base load
electric sales threshold should be reduced further to a range that
would lower the base load electric sales threshold for simple cycle
turbines to between 29 to 35 percent (depending on the design
efficiency) and to between 40 to 49 percent for combined cycle turbines
(depending on the design efficiency). The specific approach the EPA
solicited comment on was reducing the design efficiency by 6 percent
(e.g., multiplying by 0.94) when determining the electric sales
threshold. Some commenters supported lowering the proposed electric
sales threshold while others supported maintaining the proposed
standards.
After considering comments, in 40 CFR part 60, subpart TTTTa, the
EPA has determined it is appropriate to eliminate the sliding scale
electric sales threshold based on the design efficiency and instead
base the subcategorization thresholds on fixed electric sales (also
referred to sometimes here as capacity factor). In 40 CFR part 60
subpart TTTTa, the EPA is finalizing that the fixed electric sales
threshold between intermediate load combustion turbines and base load
combustion turbines is 40 percent. The 40 percent electric sales
(capacity factor) threshold reflects the maximum capacity factor for
intermediate load simple cycle turbines and the minimum prorated
efficiency approach for base load combined cycle turbines that the EPA
solicited comment on in proposal.\724\
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\724\ The EPA solicited comment on basing the electric sales
threshold on a value calculated using 0.94 times the design
efficiency.
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The base load electric sales threshold is appropriate for new
combustion turbines because, as will be discussed later, the first
component of BSER for base load turbines is based on highly efficient
combined cycle generation. Combined cycle units are significantly more
efficient than simple cycle turbines; and therefore, in general, the
EPA should be focusing its determination of the BSER for base load
units on that more efficient technology. The electric sales thresholds
and the emission standards are related because, at lower capacity
factors, combustion turbines tend to have more variable operation
(e.g., more starts and stops and operation at part load conditions)
that reduces the efficiency of the combustion turbine. This is
particularly the case for combined cycle turbines because while the
turbine engine can come to full load relatively quickly, the HRSG and
steam turbine cannot, and combined cycle turbines responding to highly
variable load will have efficiencies similar to simple cycle
turbines.\725\ This has implications for the appropriate control
technologies and corresponding emission reduction potential. The EPA
determined the final standard of performance based on review of
emissions data for recently installed combined cycle combustion
turbines with 12-operating month capacity factors of 40 percent or
greater. The EPA considered a capacity factor threshold lower than 40
percent. However, expanding the subcategory to include combustion
turbines with a 12-operating month electric sales of less than 40
percent would require the EPA to consider the emissions performance of
combined cycle turbines operating at lower capacity factors and, while
it would expand the number of sources in the base load subcategory, it
would also result in a higher (i.e., less stringent) numerical emission
standard for the sources in the category.
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\725\ This discussion assumes that the combined cycle turbine
incorporates a bypass stack that allows the combustion turbine
engine to operate independent of the HRSG/steam turbine. Without a
bypass stack the combustion turbine engine could not come to full
load as quickly.
---------------------------------------------------------------------------
Direct comparison of the costs of combined cycle turbines relative
to simple cycle turbines can be challenging because model plant costs
are often for combustion turbines of different sizes and do not account
for variable operation. For example, combined cycle turbine model
plants are generally for an EGU that is several hundred megawatts while
simple cycle turbine model plants are generally less than a hundred
megawatts. Direct comparison of the LCOE from these model plants is not
relevant because the facilities are not comparable. Consider a facility
with a block of 10 simple cycle turbines that are each 50 MW (so the
overall facility capacity is 500 MW). Each simple cycle turbine
operates as an individual unit and provides a different value to the
electric grid as compared to a single 500 MW combined cycle turbine.
While the minimum load of the combined cycle facility might be 200 MW,
the block of 10 simple cycle turbines can provide from approximately 20
MW to 500 MW to the electric grid.
A more accurate cost comparison accounts for economies of scale and
estimates the cost of a combined cycle turbine with the same net output
as a simple cycle turbine. Comparing the modeled LCOE of these
combustion turbines provides a meaningful comparison, at least for base
load combustion turbines. Without accounting for economies of scale and
variable operation, combined cycle turbines can appear to be more cost
effective than simple cycle turbines under almost all conditions. In
addition, without accounting for economies of scale, large frame simple
cycle turbines can appear to be more cost effective than higher
efficiency aeroderivative simple cycle turbines, even if operated at a
100 percent capacity factor. These cost models are not intended to make
direct comparisons, and the EPA appropriately accounted for economies
of scale when estimating the cost of the BSER. Since base load
combustion turbines tend to operate under steady state conditions with
few starts and stops, startup and shutdown costs and the efficiency
impact of operating at variable loads are not important for determining
the compliance costs of base load combustion turbines.
Based on an adjusted model plant comparison, combined cycle EGUs
have a lower LCOE at capacity factors above approximately 40 percent
compared to simple cycle EGUs operating at the same capacity factors.
This supports the final base load fixed electric sales threshold of 40
percent for simple cycle turbines because it would be cost-effective
for owners/operators of simple cycle turbines to add heat recovery if
they elected to operate at higher capacity factors as a base load unit.
Furthermore, based on an analysis of monthly emission rates, recently
constructed combined cycle EGUs maintain consistent emission rates at
capacity factors of less than 55 percent (which is the base load
electric sales threshold in subpart TTTT) relative to operation at
higher capacity factors. Therefore, the base load subcategory operating
range can be expanded in 40 CFR part 60, subpart TTTTa, without
impacting the stringency of the numeric standard. However, at capacity
factors of less than approximately 40 percent, emission rates of
combined cycle EGUs increase relative to their operation at higher
capacity factors. It takes much longer for a HRSG to begin producing
steam that can be used to generate additional electricity than it takes
a combustion engine to reach full power. Under operating conditions
with a significant number of starts and stops, typical of some
intermediate and especially low load combustion turbines, there may not
be enough time for the HRSG to generate steam that can be used for
additional electrical generation. To maximize overall efficiency,
combined cycle EGUs often use combustion turbine engines that are less
efficient than the most
[[Page 39912]]
efficient simple cycle turbine engines. Under operating conditions with
frequent starts and stops where the HRSG does not have sufficient time
to begin generating additional electricity, a combined cycle EGU may be
no more efficient than a highly efficient simple cycle EGU. These
distinctions in operation are thus meaningful for determining which
emissions control technologies are most appropriate for types of units.
Once a combustion turbine unit exceeds approximately 40 percent annual
capacity factor, it is economical to add a HRSG which results in the
unit becoming both more efficient and less likely to cycle its
operation. Such units are, therefore, better suited for more stringent
emission control technologies including CCS.
After the 2015 NSPS was finalized, some stakeholders expressed
concerns about the approach for distinguishing between base load and
non-base load turbines. They posited a scenario in which increased
utilization of wind and solar resources, combined with low natural gas
prices, would create the need for certain types of simple cycle
turbines to operate for longer time periods than had been contemplated
when the 2015 NSPS was being developed. Specifically, stakeholders have
claimed that in some regional electricity markets with large amounts of
variable renewable generation, some of the most efficient new simple
cycle turbines--aeroderivative turbines--could be called upon to
operate at capacity factors greater than their design efficiency.
However, if those new simple cycle turbines were to operate at those
higher capacity factors, they would become subject to the more
stringent standard of performance for base load turbines. As a result,
according to these stakeholders, the new aeroderivative turbines would
have to curtail their generation and instead, less-efficient existing
turbines would be called upon to run by the regional grid operators,
which would result in overall higher emissions. The EPA evaluated the
operation of simple cycle turbines in areas of the country with
relatively large amounts of variable renewable generation and did not
find a strong correlation between the percentage of generation from the
renewable sources and the 12-operating month capacity factors of simple
cycle turbines. In addition, most of the simple cycle turbines that
commenced operation between 2010 and 2016 (the most recent simple cycle
turbines not subject to 40 CFR part 60, subpart TTTT) have operated
well below the base load electric sales threshold in 40 CFR part 60,
subpart TTTT. Therefore, the Agency does not believe that the concerns
expressed by stakeholders necessitates any revisions to the regulatory
scheme. In fact, as noted above, the EPA is finalizing that the
electric sales threshold can be lowered without impairing the
availability of simple cycle turbines where needed, including to
support the integration of variable generation. The EPA believes that
the final threshold is not overly restrictive since a simple cycle
turbine could operate on average for more than 9 hours a day in the
intermediate load subcategory.
iii. Low and Intermediate Load Subcategories
This section discusses the EPA's rationale for subcategorizing non-
base load combustion turbines into two subcategories--low load and
intermediate load.
(A) Low Load Subcategory
The EPA proposed and is finalizing in 40 CFR part 60, subpart
TTTTa, a low load subcategory to includes combustion turbines that
operate only during periods of peak electric demand (i.e., peaking
units), which will be separate from the intermediate load subcategory.
Low load combustion turbines also provide ramping capability and other
ancillary services to support grid reliability. The EPA evaluated the
operation of recently constructed simple cycle turbines to understand
how they operate and to determine at what electric sales level or
capacity factor their emissions rate is relatively steady. (Note that
for purposes of this discussion, the terms ``electric sales'' and
``capacity factor'' are used interchangeably.) Low load combustion
turbines generally only operate for short periods of time and
potentially at relatively low duty cycles.\726\ This type of operation
reduces the efficiency and increases the emissions rate, regardless of
the design efficiency of the combustion turbine or how it is
maintained. For this reason, it is difficult to establish a reasonable
output-based standard of performance for low load combustion turbines.
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\726\ The duty cycle is the average operating capacity factor.
For example, if an EGU operates at 75 percent of the fully rated
capacity, the duty cycle would be 75 percent regardless of how often
the EGU actually operates. The capacity factor is a measure of how
much an EGU is operated relative to how much it could potentially
have been operated.
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To determine the electric sales threshold--that is, to distinguish
between the intermediate load and low load subcategories--the EPA
evaluated capacity factor electric sales thresholds of 10 percent, 15
percent, 20 percent, and 25 percent. The EPA proposed to find and is
finalizing a conclusion that the 10 percent threshold is problematic
for two reasons. First, simple cycle turbines operating at that level
or lower have highly variable emission rates, and therefore it is
difficult for the EPA to establish a meaningful output-based standard
of performance. In addition, only one-third of simple cycle turbines
that have commenced operation since 2015 have maintained 12-operating
month capacity factors of less than 10 percent. Therefore, setting the
threshold at this level would bring most new simple cycle turbines into
the intermediate load subcategory, which would subject them to a more
stringent emission rate that is only achievable for simple cycle
turbines operating at higher capacity factors. This could create a
situation where simple cycle turbines might not be able to comply with
the intermediate load standard of performance while operating at the
low end of the intermediate load capacity factor subcategorization
criteria.
Based on the EPA's review of hourly emissions data, at a capacity
factor above 15 percent, GHG emission rates for many simple cycle
turbines begin to stabilize. At higher capacity factors, more time is
typically spent at steady state operation rather than ramping up and
down; and emission rates tend to be lower while in steady-state
operation. Of recently constructed simple cycle turbines, half have
maintained 12-operating month capacity factors of 15 percent or less,
two-thirds have maintained capacity factors of 20 percent or less; and
approximately 80 percent have maintained maximum capacity factors of 25
percent or less. The emission rates clearly stabilize for most simple
cycle turbines operating at capacity factors of greater than 20
percent. Based on this information, the EPA proposed the low load
electric sales threshold--again, the dividing line to distinguish
between the intermediate and low load subcategories--to be 20 percent
and solicited comment on a range of 15 to 25 percent. The EPA also
solicited comment on whether the low load electric sales threshold
should be determined by a site-specific threshold based on three-
fourths of the design efficiency of the combustion turbine.\727\Under
this approach, simple
[[Page 39913]]
cycle turbines selling less than 18 to 22 percent of their potential
electric output (depending on the design efficiency) would still have
been considered low load combustion turbines. This ``sliding scale''
electric sales threshold approach is like the approach the EPA used in
the 2015 NSPS to recognize the environmental benefit of installing the
most efficient combustion turbines for low load applications. Using
this approach, combined cycle EGUs would have been able to sell between
26 to 31 percent of their potential electric output while still being
considered low load combustion turbines. Some commenters supported a
lower electric sales threshold while others supported a higher
threshold. Based on these comments, the EPA is finalizing the proposed
low load electric sales threshold of 20 percent of the potential
electric sales. The fixed 20 percent capacity factor threshold
represents a level of utilization at which most simple cycle combustion
turbines perform at a consistent level of efficiency and GHG emission
performance, enabling the EPA to establish a standard of performance
that reflects a BSER of efficient operation. The 20 percent capacity
factor threshold is also more environmentally protective than the
higher thresholds the EPA considered, since owners and operators of
combustion turbines operating above a 20 percent capacity factor would
be subject to an output-based emissions standard instead of a heat
input-based emissions standard based on the use of lower-emitting
fuels. This ensures that owners/operators of intermediate load combined
cycle turbines properly maintain and operate their combustion turbines.
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\727\ The calculation used to determine the electric sales
threshold includes both the design efficiency and the base load
rating. Since the base load rating stays the same when adjusting the
numeric value of the design efficiency for applicability purposes,
adjustments to the design efficiency has twice the impact.
Specifically, using three-fourths of the design efficiency reduces
the electric sales threshold by half.
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(B) Intermediate Load Subcategory
The proposed sliding scale subcategorization approach essentially
included two subcategories within the proposed intermediate load
subcategory. As proposed, simple cycle turbines would be classified as
intermediate load combustion turbines when operated between capacity
factors of 20 percent and approximately 40 percent while combined cycle
turbines would be classified as intermediate load combustion turbines
when operated between capacity factors of 20 percent to approximately
55 percent. Owners/operators of combined cycle turbines operating at
the high end of the intermediate load subcategory would only be subject
to an emissions standard based on a BSER of high-efficiency simple
cycle turbine technology. The proposed approach provided a regulatory
incentive for owners/operators to purchase the most efficient
technologies in exchange for additional compliance flexibility. The use
of a prorated efficiency the EPA solicited comment on would have
lowered the simple cycle and combined cycle turbine thresholds to
approximately 35 percent and 50 percent, respectively.
In this final rule, the BSER for the intermediate load subcategory
is consistent with the proposal--high-efficiency simple cycle turbine
technology. While not specifically identified in the proposal, the BSER
for the base load subcategory is also consistent with the proposal--the
use of combined cycle technology.\728\
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\728\ Under the proposed subcategorization approach, for a
combustion turbine to be subcategorized as an intermediate load
combustion turbine while operating at capacity factors of greater
than 40 percent required the use of a HRSG (e.g., combined cycle
turbine technology).
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The 12-operating month electric sales (i.e., capacity factor)
thresholds for the stationary combustion turbine subcategories in this
final rule are summarized below in Table 2.
Table 2--Sales Thresholds for Subcategories of Combustion Turbine EGUs
------------------------------------------------------------------------
12-Operating month
electric sales
Subcategory threshold (percent
of potential
electric sales)
------------------------------------------------------------------------
Low Load........................................... <=20
Intermediate Load.................................. >20 and <=40
Base Load.......................................... >40
------------------------------------------------------------------------
iv. Integrated Onsite Generation and Energy Storage
Integrated equipment is currently included as part of the affected
facility, and the EPA proposed and is finalizing amended regulatory
text to clarify that the output from integrated renewables is included
as output when determining the NSPS emissions rate. The EPA also
proposed that the output from the integrated renewable generation is
not included when determining the net electric sales for applicability
purposes (i.e., generation from integrated renewables would not be
considered when determining if a combustion turbine is subcategorized
as a low, intermediate, or base load combustion turbine). In the
alternative, the EPA solicited comment on whether instead of exempting
the generation from the integrated renewables from counting toward
electric sales, the potential output from the integrated renewables
would be included when determining the design efficiency of the
facility. Since the design efficiency is used when determining the
electric sales threshold this would increase the allowable electric
sales for subcategorization purposes. Including the integrated
renewables when determining the design efficiency of the affected
facility has the impact of increasing the operational flexibility of
owners/operators of combustion turbines. Commenters generally supported
maintaining that integrated renewables are part of the affected
facility and including the output of the renewables when determining
the emissions rate of the affected facility.\729\ Therefore, the Agency
is finalizing a decision that the rated output of integrated renewables
be included when determining the design efficiency of the affected
facility, which is used to determine the potential electric output of
the affected facility, and that the output of the integrated renewables
be included in determining the emissions rate of the affected facility.
However, since the design efficiency is not a factor in determining the
subcategory thresholds in 40 CFR part 60, subpart TTTTa, the output of
the integrated renewables will not be included for determining the
applicable subcategory. If the output from the integrated renewable
generation were included for subcategorization purposes, this could
discourage the use of integrated renewables (or curtailments) because
affected facilities could move to a subcategory with a more stringent
emissions standard that could cause the owner/operator to be out of
compliance. The impact of this approach is that the electric sales
threshold of the combustion turbine island itself, not including the
integrated renewables, for an owner/operator of a combustion turbine
that includes integrated renewables that increase the potential
electric output by 1 percent would be 1 or 2 percent higher for the
stationary combustion turbine island not considering the integrated
renewables, depending on the design efficiency of the combustion
turbine itself, than an identical combustion turbine without integrated
renewables. In addition, when the output from the integrated renewables
is considered, the output from the integrated renewables
[[Page 39914]]
lowers the emissions rate of the affected facility by approximately 1
percent.
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\729\ The EPA did not propose to include, and is not finalizing
including, integrated renewables as part of the BSER. Commenters
opposed a BSER that would include integrated renewables as part of
the BSER. Commenters noted that this could result in renewables
being installed in suboptimal locations which could result in lower
overall GHG reductions.
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For integrated energy storage technologies, the EPA solicited
comment on and is finalizing a decision to include the rated output of
the energy storage when determining the design efficiency of the
affected facility. Similar to integrated renewables, this increases the
flexibility of owner/operators to sell larger amounts of electricity
while remaining in the low, variable, and intermediate load
subcategories. While energy storage technologies have high capital
costs, operating costs are low and would dispatch prior to the
combustion turbine the technology is integrated with. Therefore, simple
cycle turbines with integrated energy storage would likely operate at
lower capacity factors than an identical simple cycle turbine at the
same location. However, while the energy storage might be charged with
renewables that would otherwise be curtailed, there is no guarantee
that low emitting generation would be used to charge the energy
storage. Therefore, the output from the energy storage is not
considered in either determining the NSPS emissions rate or as net
electric sales for subcategorization applicability purposes. In future
rulemaking the Agency could further evaluate the impact of integrated
energy storage on the operation of simple cycle turbines to determine
if the number of starts and stops are reduced and increases the
efficiency of simple cycle turbines relative to simple cycle turbines
without integrated energy storage. If this is the case, it could be
appropriate to lower the threshold for combustion turbines subject to a
lower emitting fuels BSER because emission rates would be stable at
lower capacity factors.
v. Definition of System Emergency
In 2015, the EPA included a provision that electricity sold during
hours of operation when a unit is called upon due to a system emergency
is not counted toward the percentage electric sales subcategorization
threshold in 40 CFR part 60, subpart TTTT.\730\ The Agency concluded
that this exclusion is necessary to provide flexibility, maintain
system reliability, and minimize overall costs to the sector.\731\ The
intent is that the local grid operator will determine the EGUs
essential to maintaining grid reliability. Subsequent to the 2015 NSPS,
members of the regulated community informed the EPA that additional
clarification of a system emergency is needed to determine and document
generation during system emergencies. The EPA proposed to include the
system emergency approach in 40 CFR part 60, subpart TTTTa, and
solicited comment on amending the definition of system emergency to
clarify in implementation in 40 CFR part 60, subparts TTTT and TTTTa.
Commenters generally agreed with the proposal to allow owners/operators
of EGUs called upon during a system emergency to operate without
impacting the EGUs' subcategorization (i.e., electric sales during
system emergencies would not be considered when determining net
electric sales), and that the Agency should clarify how system
emergencies are determined and documented.
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\730\ In 40 CFR part 60, subpart TTTT, electricity sold by units
that are not called upon to operate due to a system emergency (e.g.,
units already operating when the system emergency is declared) is
counted toward the percentage electric sales threshold.
\731\ See 80 FR 64612; October 23, 2015.
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In terms of the definition of the system emergency provision,
commenters stated that ``abnormal'' be deleted from the definition, and
instead of referencing ``the Regional Transmission Organizations (RTO),
Independent System Operators (ISO) or control area Administrator,'' the
definition should reference ``the balancing authority or reliability
coordinator.'' This change would align the regulation's definition with
the terms used by NERC. Some commenters also stated that the EPA should
specify that electric sales during periods the grid operator declares
energy emergency alerts (EEA) levels 1 through 3 be included in the
definition of system emergency.\732\ In addition, some commenters
stated that the definition should be expanded to include the concept of
energy emergencies. Specifically, the definition should also exempt
generation during periods when a load-serving entity or balancing
authority has exhausted all other resource options and can no longer
meet its expected load obligations. Finally, commenters stated that the
definition should apply to all EGUs, regardless of if they are already
operating when the system emergency is declared. This would avoid
regulatory incentive to come offline prior to a potential system
emergency to be eligible for the electric sales exemption and would
treat all EGUs similarly during system emergencies (i.e., not penalize
EGUs that are already operating to maintain grid reliability and
avoiding the need to declare grid emergencies).
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\732\ Commenters noted that grid operators have slightly
different terms for grid emergencies, but example descriptions
include: EEA 1, all available generation online and non-firm
wholesale sales curtailed; EEA 2, load management procedures in
effect, all available generation units online, demand-response
programs in effect; and EEA 3, firm load interruption is imminent or
in progress.
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The Agency is including the system emergency concept in 40 CFR part
60, subpart TTTTa, along with a definition that clarifies how to
determine generation during periods of system emergencies. The EPA
agrees with commenters that the definition of system emergency should
be clarified and that it should not be limited to EGUs not operating
when the system emergency is declared. Based on information provided by
entities with reliability expertise, the EPA has determined that a
system emergency should be defined to include EEA levels 2 and 3. These
EEA levels generally correspond to time-limited, well-defined, and
relatively infrequent situations in which the system is experiencing an
energy deficiency. During EEA level 2 and 3 events, all available
generation is online and demand-response or other load management
procedures are in effect, or firm load interruption is imminent or in
progress. The EPA believes it is appropriate to exclude hours of
operation during such events in order to ensure that EGUs are not
impeded from maintaining or increasing their output as needed to
respond to a declared energy emergency. Because these events tend to be
short, infrequent, and well-defined, the EPA also believes any
incremental GHG emissions associated with operations during these
periods would be relatively limited.
The EPA has determined not to include EEA level 1 in the definition
of a ``system emergency.'' The EPA's understanding is that EEA level 1
events often include situations in which an energy deficiency does not
yet exist, and in which balancing authorities are preparing to pursue
various options for either bringing additional resources online or
managing load. The EPA also understands that EEA level 1 events tend to
be more frequently declared, and longer in duration, than level 2 or 3
events. Based on this information, the EPA believes that including EEA
level 1 events in the definition of a ``system emergency'' would carry
a greater risk of increasing overall GHG emissions without making a
meaningful contribution to supporting reliability. This approach
balances the need to have operational flexibility when the grid may be
strained to help ensure that all available generating sources are
available for grid reliability, while balancing with important
considerations about potential GHG emission tradeoffs. The EPA is also
amending the definition in 40 CFR part 60, subpart TTTT, to be
[[Page 39915]]
consistent with the definition in 40 CFR part 60, subpart TTTTa.
Commenters also added that operation during system emergencies
should be subject to alternate standards of performance (e.g., owners/
operators are not required to use the CCS system during system
emergencies to increase power output). The EPA agrees with commenters
that since system emergencies are defined and historically rare events,
an alternate standard of performance should apply during these periods.
Carbon capture systems require significant amounts of energy to
operate. Allowing owners/operators of EGUs equipped with CCS systems to
temporarily reduce the capture rate or cease capture will increase the
electricity available to end users during system emergencies. In place
of the applicable output-based emissions standard, the owner/operator
of an intermediate or base load combustion turbine would be subject to
a BSER based on the combustion of lower-emitting fuels during system
emergencies.\733\ The emissions and output would not be included when
calculating the 12-operating month emissions rate. The EPA considered
an alternate emissions standard based on efficient generation but
rejected that for multiple reasons. First, since system emergencies are
limited in nature the emissions calculation would include a limited
number of hours and would not necessarily be representative of an
achievable longer-term emissions rate. In addition, EGUs that are
designed to operate with CCS will not necessarily operate as
efficiently without the CCS system operating compared to a similar EGU
without a CCS system. Therefore, the Agency is not able to determine a
reasonable efficiency-based alternate emissions standard for periods of
system emergencies. Due to both the costs and time associated with
starting and stopping the CCS system, the Agency has determined it is
unlikely that an owner/operator of an affected facility would use it
where it is not needed. System emergencies have historically been
relatively brief and any hours of operation outside of the system
emergencies are included when determining the output-based emissions
standard. During short-duration system emergencies, the costs
associated with stopping and starting the CCS system could outweigh the
increased revenue from the additional electric sales. In addition, the
time associated with starting and stopping a CCS system would likely
result in an EGU operating without the CCS system in operation during
periods of non-system emergencies. This would require the owner/
operator to overcontrol during other periods of operation to maintain
emissions below the applicable standard of performance. Therefore, it
is likely an owner/operator would unnecessarily adjust the operation of
the CCS system during EEA levels 2 and 3.
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\733\ For owners/operators of combustion turbines the lower
emitting fuels requirement is defined to include fuels with an
emissions rate of 160 lb CO2/MMBtu or less. For owners/
operators of steam generating units or IGCC facilities the EPA is
requiring the use of the maximum amount of non-coal fuels available
to the affected facility.
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In addition to these measures, DOE has authority pursuant to
section 202(c) of the Federal Power Act to, on its own motion or by
request, order, among other things, the temporary generation of
electricity from particular sources in certain emergency conditions,
including during events that would result in a shortage of electric
energy, when the Secretary of Energy determines that doing so will meet
the emergency and serve the public interest. An affected source
operating pursuant to such an order is deemed not to be operating in
violation of its environmental requirements. Such orders may be issued
for 90 days and may be extended in 90-day increments after consultation
with the EPA. DOE has historically issued section 202(c) orders at the
request of electric generators and grid operators such as RTOs in order
to enable the supply of additional generation in times of expected
emergency-related generation shortfalls.
c. Multi-Fuel-Fired Combustion Turbines
In 40 CFR part 60, subpart TTTT, multi-fuel-fired combustion
turbines are subcategorized as EGUs that combust 10 percent or more of
fuels not meeting the definition of natural gas on a 12-operating month
rolling average basis. The BSER for this subcategory is the use of
lower-emitting fuels with a corresponding heat input-based standard of
performance of 120 to 160 lb CO2/MMBtu, depending on the
fuel, for newly constructed and reconstructed multi-fuel-fired
stationary combustion turbines.\734\ Lower-emitting fuels for these
units include natural gas, ethylene, propane, naphtha, jet fuel
kerosene, Nos. 1 and 2 fuel oils, biodiesel, and landfill gas. The
definition of natural gas in 40 CFR part 60, subpart TTTT, includes
fuel that maintains a gaseous state at ISO conditions, is composed of
70 percent by volume or more methane, and has a heating value of
between 35 and 41 megajoules (MJ) per dry standard cubic meter (dscm)
(950 and 1,100 Btu per dry standard cubic foot). Natural gas typically
contains 95 percent methane and has a heating value of 1,050 Btu/
lb.\735\ A potential issue with the multi-fuel subcategory is that
owners/operators of simple cycle turbines can elect to burn 10 percent
non-natural gas fuels, such as Nos. 1 or 2 fuel oil, and thereby remain
in that subcategory, regardless of their electric sales. As a result,
they would remain subject to the less stringent standard that applies
to multi-fuel-fired sources, the lower-emitting fuels standard. This
could allow less efficient combustion turbine designs to operate as
base load units without having to improve efficiency and could allow
EGUs to avoid the need for efficient design or best operating and
maintenance practices. These potential circumventions would result in
higher GHG emissions.
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\734\ Combustion turbines co-firing natural gas with other fuels
must determine fuel-based site-specific standards at the end of each
operating month. The site-specific standards depend on the amount of
co-fired natural gas. 80 FR 64616 (October 23, 2015).
\735\ Note that according to 40 CFR part 60, subpart TTTT,
combustion turbines co-firing 25 percent hydrogen by volume could be
subcategorized as multi-fuel-fired EGUs because the percent methane
by volume could fall below 70 percent, the heating value could fall
below 35 MJ/Sm\3\, and 10 percent of the heat input could be coming
from a fuel not meeting the definition of natural gas.
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To avoid these outcomes, the EPA proposed and is finalizing a
decision not to include the multi-fuel subcategory for low,
intermediate, and base load combustion turbines in 40 CFR part 60,
subpart TTTTa. This means that new multi-fuel-fired turbines that
commence construction or reconstruction after May 23, 2023, will fall
within a particular subcategory depending on their level of electric
sales. The EPA also proposed and is finalizing a decision that the
performance standards for each subcategory be adjusted appropriately
for multi-fuel-fired turbines to reflect the application of the BSER
for the subcategories to turbines burning fuels with higher GHG
emission rates than natural gas. To be consistent with the definition
of lower-emitting fuels in the 2015 NSPS, the maximum allowable heat
input-based emissions rate is 160 lb CO2/MMBtu. For example,
a standard of performance based on efficient generation would be 33
percent higher for a fuel oil-fired combustion turbine compared to a
natural gas-fired combustion turbine. This assures that the BSER, in
this case efficient generation, is applied, while at the same time
accounting for the use of multiple fuels.
[[Page 39916]]
d. Rural Areas and Small Utility Distribution Systems
As part of the original proposal and during the Small Business
Advocacy Review (SBAR) outreach the EPA solicited comment on creating a
subcategory for rural electric cooperatives and small utility
distribution systems (serving 50,000 customers or less). Commenters
expressed concerns that a BSER based on either co-firing hydrogen or
CCS may present an additional hardship on economically disadvantaged
communities and on small entities, and that the EPA should evaluate
potential increased energy costs, transmission upgrade costs, and
infrastructure encroachment which may directly affect the
disproportionately impacted communities. As described in section
VIII.F, the BSER for new stationary combustion turbines does not
include hydrogen co-firing and CCS qualifies as the BSER for base load
combustion turbines on a nationwide basis. Therefore, the EPA has
determined that a subcategory for rural cooperatives and/or small
utility distribution systems is not appropriate.
F. Determination of the Best System of Emission Reduction (BSER) for
New and Reconstructed Stationary Combustion Turbines
In this section, the EPA describes the technologies it proposed as
the BSER for each of the subcategories of new and reconstructed
combustion turbines that commence construction after May 23, 2023, as
well as topics for which the Agency solicited comment. In the following
section, the EPA describes the technologies it is determining are the
final BSER for each of the three subcategories of affected combustion
turbines and explains its basis for selecting those controls, and not
others, as the final BSER. The controls that the EPA evaluated included
combusting non-hydrogen lower-emitting fuels (e.g., natural gas and
distillate oil), using highly efficient generation, using CCS, and co-
firing with low-GHG hydrogen.
For the low load subcategory, the EPA proposed the use of lower-
emitting fuels as the BSER. This was consistent with the BSER and
performance standards established in the 2015 NSPS for the non-base
load subcategory as discussed earlier in section VIII.C.
For the intermediate load subcategory, the EPA proposed an approach
under which the BSER was made up of two components: (1) highly
efficient generation; and (2) co-firing 30 percent (by volume) low-GHG
hydrogen. Each component of the BSER represented a different set of
controls, and those controls formed the basis of corresponding
standards of performance that applied in two phases. Specifically, the
EPA proposed that affected facilities (i.e., facilities that commence
construction or reconstruction after May 23, 2023) could apply the
first component of the BSER (i.e., highly efficient generation) upon
initial startup to meet the first phase of the standard of performance.
Then, by 2032, the EPA proposed that affected facilities could apply
the second component of the BSER (i.e., co-firing 30 percent (by
volume) low-GHG hydrogen) to meet a second and more stringent standard
of performance. The EPA also solicited comment on whether the
intermediate load subcategory should apply a third component of the
BSER: co-firing 96 percent (by volume) low-GHG hydrogen by 2038. In
addition, the EPA solicited comment on whether the low load subcategory
should also apply the second component of BSER, co-firing 30 percent
(by volume) low-GHG hydrogen, by 2032. The Agency proposed that these
latter components of the BSER would continue to include the application
of highly efficient generation.
For the base load subcategory, the EPA also proposed a multi-
component BSER and multi-phase standard of performance. The EPA
proposed that each new base load combustion turbine would be required
to meet a phase-1 standard of performance based on the application of
the first component of the BSER--highly efficient generation--upon
initial startup of the affected source. For the second component of the
BSER, the EPA proposed two potential technology pathways for base load
combustion turbines with corresponding standards of performance. One
proposed technology pathway was 90 percent CCS, which base load
combustion turbines would install and begin to operate by 2035 to meet
the phase-2 standard of performance. A second proposed technology
pathway was co-firing low-GHG hydrogen, which base load combustion
turbines would implement in two steps: (1) By co-firing 30 percent (by
volume) low-GHG hydrogen to meet the phase-2 standard of performance by
2032, and (2) by co-firing 96 percent (by volume) low-GHG hydrogen to
meet a phase 3 standard of performance by 2038. Throughout, the Agency
proposed base load turbines, like intermediate load turbines, would
remain subject to the first component of the BSER based on highly
efficient generation.
The proposed approach reflected the EPA's view that the BSER
components for the intermediate load and base load subcategories could
achieve deeper reductions in GHG emissions by implementing CCS and co-
firing low-GHG hydrogen. This proposed approach also recognized that
building the infrastructure required to support widespread use of CCS
and low-GHG hydrogen technologies in the power sector will take place
on a multi-year time scale. Accordingly, new and reconstructed
facilities would be aware of their need to ramp toward more stringent
phases of the standards, which would reflect application of the more
stringent controls in the BSER. This would occur either by co-firing a
lower percentage (by volume) of low-GHG hydrogen by 2032 and a higher
percentage (by volume) of low-GHG hydrogen by 2038, or with
installation and use of CCS by 2035. The EPA also solicited comment on
the potential for an earlier compliance date for the second phase.
For the base load subcategory, the EPA proposed two potential BSER
pathways because the Agency believed there was more than one viable
technology for these combustion turbines to significantly reduce their
CO2 emissions. The Agency also found value in receiving
comments on, and potentially finalizing, both BSER pathways to enable
project developers to elect how they would reduce their CO2
emissions on timeframes that make sense for each BSER pathway.\736\ The
EPA solicited comment on whether the co-firing of low-GHG hydrogen
should be considered a compliance pathway for sources to meet a single
standard of performance based on the application of C