[Federal Register Volume 83, Number 170 (Friday, August 31, 2018)]
[Proposed Rules]
[Pages 44746-44813]
[FR Doc No: 2018-18755]

Vol. 83

Friday,

No. 170

August 31, 2018

Part III

Environmental Protection Agency

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40 CFR Parts 51, 52, and 60

Emission Guidelines for Greenhouse Gas Emissions From Existing Electric
Utility Generating Units; Revisions to Emission Guideline Implementing
Regulations; Revisions to New Source Review Program; Proposed Rule

Federal Register / Vol. 83 , No. 170 / Friday, August 31, 2018 /
Proposed Rules

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 51, 52, and 60

[EPA-HQ-OAR-2017-0355; FRL-9982-89-OAR]
RIN 2060-AT67

Emission Guidelines for Greenhouse Gas Emissions From Existing
Electric Utility Generating Units; Revisions to Emission Guideline
Implementing Regulations; Revisions to New Source Review Program

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: The Environmental Protection Agency (EPA) is proposing three
distinct actions, including Emission Guidelines for Greenhouse Gas
Emissions from Existing Electric Utility Generating Units (EGUs).
First, EPA is proposing to replace the Clean Power Plan (CPP) with
revised emissions guidelines (the Affordable Clean Energy (ACE) rule)
that inform the development, submittal, and implementation of state
plans to reduce greenhouse gas (GHG) emission from certain EGUs. In the
proposed emissions guidelines, consistent with the interpretation
described in the proposed repeal of the CPP, the Agency is proposing to
determine that heat rate improvement (HRI) measures are the best system
of emission reduction (BSER) for existing coal-fired EGUs. Second, EPA
is proposing new regulations that provide direction to both EPA and the
states on the implementation of emission guidelines. The new proposed
implementing regulations would apply to this action and any future
emission guideline issued under section 111(d) of the Clean Air Act
(CAA). Third, the Agency is proposing revisions to the New Source
Review (NSR) program that will help prevent NSR from being a barrier to
the implementation of efficiency projects at EGUs.

DATES:
    Comments. Comments must be received on or before October 30, 2018.
Under the Paperwork Reduction Act (PRA), comments on the information
collection provisions are best assured of consideration if the Office
of Management and Budget (OMB) receives a copy of your comments on or
before October 1, 2018.
    Public hearing: EPA is planning to hold at least one public hearing
in response to this proposed action. Information about the hearing,
including location, date, and time, along with instructions on how to
register to speak at the hearing, will be published in a second Federal
Register document.

ADDRESSES: Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2017-0355, at https://www.regulations.gov. Follow the online
instructions for submitting comments. Once submitted, comments cannot
be edited or removed from Regulations.gov. See SUPPLEMENTARY
INFORMATION for detail about how EPA treats submitted comments.
Regulations.gov is our preferred method of receiving comments.\1\
However, other submission methods are accepted:
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    \1\ Comments submitted on the proposed repeal will be considered
in the promulgation of this rulemaking so there is no need to
resubmit comments that have already been timely submitted.
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     Email: [email protected]. Include Docket ID No. EPA-
HQ-OAR-2017-0355 in the subject line of the message.
     Fax:<PHONE_NUMBER>. Attention Docket ID No. EPA-HQ-OAR-
2017-0355.
     Mail: To ship or send mail via the United States Postal
Service, use the following address: U.S. Environmental Protection
Agency, EPA Docket Center, Docket ID No. EPA-HQ-OAR-2017-0355, Mail
Code 28221T, 1200 Pennsylvania Avenue NW, Washington, DC 20460.
     Hand/Courier Delivery: Use the following Docket Center
address if you are using express mail, commercial delivery, hand
delivery, or courier: EPA Docket Center, EPA WJC West Building, Room
3334, 1301 Constitution Avenue NW, Washington, DC 20004. Delivery
verification signatures will be available only during regular business
hours.

FOR FURTHER INFORMATION CONTACT: For questions about this proposed
action, contact Mr. Nicholas Swanson, Sector Policies and Programs
Division (Mail Code D205-01), Office of Air Quality Planning and
Standards, U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina 27711; telephone number:<PHONE_NUMBER>; fax
number:<PHONE_NUMBER>; and email address: [email protected].

SUPPLEMENTARY INFORMATION:
    Docket. EPA has established a docket for this rulemaking under
Docket ID No. EPA-HQ-OAR-2017-0355. All documents in the docket are
listed in Regulations.gov. 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. Publicly
available docket materials are available either electronically in
Regulations.gov or in hard copy at the EPA Docket Center, Room 3334,
EPA WJC West Building, 1301 Constitution Avenue NW, Washington, DC. The
Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The telephone number for the Public
Reading Room is<PHONE_NUMBER>, and the telephone number for the EPA
Docket Center is<PHONE_NUMBER>.
    Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2017-0355. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
https://www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be CBI or
other information whose disclosure is restricted by statute. Do not
submit information that you consider to be CBI or otherwise protected
through https://www.regulations.gov or email. This type of information
should be submitted by mail as discussed below.
    EPA may publish any comment received to its public docket.
Multimedia submissions (audio, video, etc.) must be accompanied by a
written comment. The written comment is considered the official comment
and should include discussion of all points you wish to make. EPA will
generally not consider comments or comment contents located outside of
the primary submission (i.e., on the Web, cloud, or other file sharing
system). For additional submission methods, the full EPA public comment
policy, information about CBI or multimedia submissions, and general
guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.
    The https://www.regulations.gov website allows you to submit your
comments anonymously, which means EPA will not know your identity or
contact information unless you provide it in the body of your comment.
If you send an email comment directly to EPA without going through
https://www.regulations.gov, your email address will be automatically
captured and included as part of the comment that is placed in the
public docket and made available on the internet. If you submit an
electronic comment, EPA recommends that you include your name and other
contact information in the body of your comment and with any

digital storage media you submit. If EPA cannot read your comment due
to technical difficulties and cannot contact you for clarification, EPA
may not be able to consider your comment. Electronic files should not
include special characters or any form of encryption and be free of any
defects or viruses. For additional information about EPA's public
docket, visit the EPA Docket Center homepage at https://www.epa.gov/dockets.
    Throughout this proposal, EPA is soliciting comment on numerous
aspects of the proposed rule. EPA has indexed each comment solicitation
with an alpha-numeric identifier (e.g., ``C-1'', ``C-2'', ``C-3'', . .
.). EPA included similar identifiers in the advance notice of proposed
rulemaking (ANPRM) and asked commenters to identify the main topic area
that corresponded with their comment. In this proposal, we are
modifying this approach to include a unique identifier for each
individual comment solicitation to provide a consistent framework for
effective and efficient provision of comments.
    Accordingly, we ask that commenters include the corresponding
identifier when providing comments relevant to that comment
solicitation. We ask that commenters include the identifier in either a
heading, or within the text of each comment (e.g., ``In response to
solicitation of comment C-1, . . .'') to make clear which comment
solicitation is being addressed. We emphasize that we are not limiting
comment to these identified areas and encourage provision of any other
comments relevant to this proposal.
    Submitting CBI. Do not submit information containing CBI to EPA
through https://www.regulations.gov or email. Clearly mark the part or
all of the information that you claim to be CBI. For CBI information on
any digital storage media that you mail to EPA, mark the outside of the
digital storage media as CBI and then identify electronically within
the digital storage media the specific information that is claimed as
CBI. In addition to one complete version of the comments that includes
information claimed as CBI, you must submit a copy of the comments that
does not contain the information claimed as CBI directly to the public
docket through the procedures outlined in Instructions above. If you
submit any digital storage media that does not contain CBI, mark the
outside of the digital storage media clearly that it does not contain
CBI. Information not marked as CBI will be included in the public
docket and the EPA's electronic public docket without prior notice.
Information marked as CBI will not be disclosed except in accordance
with procedures set forth in 40 Code of Federal Regulations (CFR) part
2. Send or deliver information identified as CBI only to the following
address: OAQPS Document Control Officer (C404-02), OAQPS, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina
27711, Attention Docket ID No. EPA-HQ-OAR-2017-0355.
    Preamble acronyms and abbreviations. We use 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, EPA defines
the following terms and acronyms here:

ACE Affordable Clean Energy Rule
AEO Annual Energy Outlook
ANPRM Advance Notice of Proposed Rulemaking
BACT Best Available Control Technology
BSER Best System of Emission Reduction
Btu British Thermal Unit
CAA Clean Air Act
CBI Confidential Business Information
CCS Carbon Capture and Storage (or Sequestration)
CFR Code of Federal Regulation
CO2 Carbon Dioxide
CPP Clean Power Plan
EGU Electric Utility Generating Unit
EIA Energy Information Administration
EPA Environmental Protection Agency
FIP Federal Implementation Plan
FR Federal Register
GHG Greenhouse Gas
HRI Heat Rate Improvement
IGCC Integrated Gasification Combined Cycle
kW Kilowatt
kWh Kilowatt-hour
MW Megawatt
MWh Megawatt-hour
NAAQS National Ambient Air Quality Standards
NGCC Natural Gas Combined Cycle
NOX Nitrogen Oxides
NSPS New Source Performance Standards
NSR New Source Review
OMB Office of Management and Budget
PM2.5 Fine Particulate Matter
PRA Paperwork Reduction Act
PSD Prevention of Significant Deterioration
RIA Regulatory Impact Analysis
RTC Response to Comments
SIP State Implementation Plan
SO2 Sulfur Dioxide
UMRA Unfunded Mandates Reform Act of 1995
U.S. United States
VFD Variable Frequency Drive

    Organization of this document. The information in this preamble is
organized as follows:

I. General Information
    A. Executive Summary
    B. Where can I get a copy of this document and other related
information?
II. Background
    A. Regulatory and Judicial History of GHG Requirements for EGUs
    B. Executive Order 13783 and EPA's Review of the CPP
    C. Industry Trends
III. Legal Authority
    A. Authority to Revisit Existing Regulations
    B. Authority to Regulate EGUs
    C. Legal Authority for Determination of the BSER
IV. Affected Sources
V. Determination of the BSER
    A. Identification of the BSER
    B. HRIs for Steam-Generating EGUs
    C. HRI for Natural Gas-fired Stationary Combustion Turbines
    D. Other Considered Systems of GHG Emission Reductions
VI. State Plan Development
    A. Establishing Standards of Performance
    B. Flexibilities for States and Sources
    C. Submission of State Plans
VII. Proposed New Implementing Regulations for Section 111(d)
Emission Guidelines
    A. Changes to the Definition of ``Emission Guideline''
    B. Updates to Timing Requirements
    C. Compliance Deadlines
    D. Completeness Criteria
    E. Standard of Performance
    F. Variance
VIII. New Source Review Permitting of HRIs
    A. What is New Source Review?
    B. Interaction of NSR and the ACE Rule
    C. ANPRM Solicitation and Comments Received
    D. Proposing NSR Changes for Improved ACE Implementation
IX. Impacts
    A. What are the air impacts?
    B. What are the energy impacts?
    C. What are the compliance costs?
    D. What are the economic and employment impacts?
    E. What are the forgone benefits of the proposed action?
X. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Executive Order 13771: Reducing Regulation and Controlling
Regulatory Costs
    C. Paperwork Reduction Act (PRA)
    D. Regulatory Flexibility Act (RFA)
    E. Unfunded Mandates Reform Act (UMRA)
    F. Executive Order 13132: Federalism
    G. Executive Order 13175: Consultation and Coordination with
Indian Tribal Governments
    H. Executive Order 13045: Protection of Children from
Environmental Health Risks and Safety Risks
    I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
    J. National Technology Transfer and Advancement Act (NTTAA)
    K. Executive Order 12898: Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations
XI. Statutory Authority

I. General Information

A. Executive Summary

    EPA is proposing the Affordable Clean Energy (ACE) rule as a
replacement to the CPP (promulgated on October 23, 2015, 80 FR 64662),
which sets GHG emission guidelines for existing EGUs. This proposal
relies in part on the legal analysis presented in the CPP repeal that
was proposed on October 16, 2017, 82 FR 48035. In the proposed repeal,
EPA asserted that the BSER in the CPP exceeded EPA's authority because
it established the BSER using measures that applied to the power sector
as whole, rather than measures that apply at and to, and can be carried
out at the level of, individual facilities. This proposed action aligns
with EPA's statutory authority and obligation because, as EPA has done
in the dozens of NSPSs issued to date, the BSER is to be determined by
evaluating technologies or systems of emission reduction that are
applicable to, at, and on the premises of the facility for an affected
source. This proposal will ensure that coal-fired power plants (the
most carbon dioxide (CO2) intensive portion of the
electricity generating fleet) address their contribution to climate
change by reducing their CO2 intensity (i.e., the amount of
CO2 they emit per unit of electricity generated).
    Accordingly, the proposed ACE rule consists of three discrete
sections. First, EPA is proposing to determine the BSER for existing
EGUs based on HRI measures that can be applied at an affected source.
EPA also proposes a corresponding emission guideline clarifying the
roles of EPA and the states under CAA section 111(d). EPA's primary
role in implementing CAA section 111(d) is to provide emission
guidelines that inform the development, submittal, and implementation
of state plans, and to subsequently determine whether submitted state
plans are approvable. Per the CAA, once EPA publishes a final emission
guideline, states have the primary role of developing standards of
performance consistent with application of the BSER. Congress also
expressly required that EPA allow states to consider source-specific
factors--including, among other factors, the remaining useful life of
the affected source--in applying a standard of performance. In this
way, the state and federal roles complement each other as EPA has the
authority and responsibility to determine a nationally applicable BSER
while the states have the authority and responsibility to establish and
apply existing source standards of performance, in consideration of
source-specific factors.
    Second, EPA is proposing new implementing regulations that apply to
this action and any future emission guidelines promulgated under CAA
section 111(d). The purpose of proposing new implementing regulations
is to harmonize our 40 CFR part 60 subpart B regulations with the
statute by making it clear that states have broad discretion in
establishing and applying emissions standards consistent with the BSER.
The discussion for the proposed revisions is found in Section VII
below.
    Third, EPA is proposing to give the owners/operators of EGUs more
latitude to make the efficiency improvements that are consistent with
EPA's proposed BSER without triggering onerous and costly NSR permit
requirements. This change will allow states, in establishing standards
of performance, to consider HRIs that would otherwise not be cost-
effective due to the burdens incurred from triggering NSR. The
discussion of this issue is included in Section VII.
    As with other regulations of this nature, this notice concludes
with a summary of the impacts of this proposal and is supported by a
Regulatory Impact Analysis (RIA) that can be found in the docket for
this action. As reported in the RIA, EPA evaluated three illustrative
policy scenarios modeling HRI at coal-fired EGUs. EPA estimates that
there are cost savings under two of the three illustrative scenarios,
with average annual compliance costs ranging from a cost savings of
about $0.5 billion to a cost of about $0.3 billion. As noted
previously, this action is preceded by a proposed repeal of the CPP.\2\
That proposal included a detailed legal analysis demonstrating that
``building blocks'' two and three of the CPP exceeded EPA's authority.
That analysis is incorporated into this proposal. Because two of the
three ``building blocks'' used to establish the CPP emission guidelines
were legally flawed (and because ``building block'' one was not
designed in such a manner that it could or was intended to stand on its
own without the other building blocks), EPA proposed that the CPP
emission guidelines be withdrawn. With the ACE rule, EPA proposes to
possibly replace the CPP with a rule that corrects the fundamental
legal flaws in the CPP to more appropriately balance federal and state
responsibilities under CAA section 111(d), and revise the NSR program
as it applies to affected EGUs to better accommodate energy efficiency
projects.
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    \2\ The accompanying RIA focuses on presenting the difference
between the CPP and the concepts in ACE, but also includes a
scenario with no CPP, providing sufficient information to understand
the impact of a full repeal of the CPP, a two-step approach in which
the CPP is repealed and then an alternative BSER is put in place or
a case in which the Agency revises the BSER promulgated in the CPP.
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    This proposed action has been informed by comments submitted in
response to the ANPRM, published December 28, 2017, see 82 FR 61507.
EPA notes that it does not intend to respond to the comments received
on the ANPRM. If commenters believe that any of their previously
submitted comments are still applicable, they should resubmit those
comments to this rulemaking to ensure they are considered.

B. Where can I get a copy of this document and other related
information?

    In addition to being available in the docket, an electronic copy of
this action is available on the internet. Following signature by the
EPA Administrator, EPA will post a copy of this proposed action at
https://www.epa.gov/stationary-sources-air-pollution/electric-utility-generating-units-emission-guidelines-greenhouse. Following publication
in the Federal Register, EPA will post the Federal Register version of
the proposal and key technical documents at this same website.

II. Background

A. Regulatory and Judicial History of GHG Requirements for EGUs

    When passing and amending the CAA, Congress sought to address and
remedy the dangers posed by air pollution to human beings and the
environment. While the text of the CAA does not reflect an explicit
intent on the part of Congress to address the potential effects of
elevated atmospheric GHG concentrations, the Supreme Court in
Massachusetts v. EPA, 549 U.S. 497 (2007), concluded that Congress had
drafted the CAA broadly enough so that GHGs constituted air pollutants
within the meaning of the CAA. EPA subsequently determined that
emissions of GHGs from new motor vehicles cause or contribute to air
pollution that may reasonably be anticipated to endanger public health
or welfare. See 74 FR 66496 (December 15, 2009). This determination
required EPA to regulate GHG emissions from motor vehicles.
    In 2009, and again in 2016, the EPA Administrator issued findings
under sections 202(a) and 231(a)(2)(A) of the Clean Air Act,
respectively, that the current, elevated concentrations of six well-
mixed GHGs in the atmosphere may reasonably be anticipated to endanger
public health and welfare of current and future generations in the

United States.\3\ In 2015, after determining that GHGs from EGUs
merited regulation under CAA section 111, EPA promulgated standards of
performance for new, modified, and reconstructed EGUs under section
111(b). 80 FR 64510. Consequentially, this led to EPA's obligation to
develop a 111(d) rule for existing EGUs, as described in Section III.
EPA believes that the BSER in ACE is consistent both with our legal
authorities under 111(d) and with what is technically feasible and
appropriate for coal-fired power plants. Therefore, EPA believes that
the emission reductions required from state plans are the appropriate
amount for a 111(d) rule.
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    \3\ ``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).
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    While the market in the power sector is driving GHG emissions down,
the EPA, by proposing this emission guideline, is reinforcing the
market in many respects and also ensuring that available emission
reductions that are not market driven are achieved. Many regulations
are promulgated to correct market failures, which otherwise lead to a
suboptimal allocation of resources within the free market. Air quality
and pollution control regulations address ``negative externalities''
whereby the market does not internalize the full opportunity cost of
production borne by society as public goods such as air quality are
unpriced.
    While recognizing that optimal social level of pollution may not be
zero, GHG emissions impose costs on society, such as negative health
and welfare impacts, that are not reflected in the market price of the
goods produced through the polluting process. For this regulatory
action the good produced is electricity. If a fossil fuel-fired
electricity producer pollutes the atmosphere when it generates
electricity, this cost will be borne not by the polluting firm but by
society as a whole, thus the producer is imposing a negative
externality, or a social cost of emissions. The equilibrium market
price of electricity may fail to incorporate the full opportunity cost
to society of generating electricity. Consequently, absent a regulation
on emissions, the EGUs will not internalize the social cost of
emissions and social costs will be higher as a result. This regulation
will work towards addressing this market failure by causing affected
EGUs to begin to internalize the negative externality associated with
CO2 emissions.
    Further discussion of GHG impacts, as well as the benefits of this
proposal, can be found in the RIA for this action. As detailed in
Chapter 3 of the RIA, EPA evaluated three illustrative policy scenarios
representing ACE. These scenarios are projected to result in a decrease
of annual CO2 emissions of about 7 million to 30 million
short tons relative to a future without a CAA section 111(d) regulation
affecting the power sector.
    Along with the 111(b) standard, EPA issued, under CAA section
111(d), its ``Clean Power Plan,'' consisting of GHG emission guidelines
for existing EGUs, which states would use to develop emission standards
as mentioned above. 80 FR 64662 (October 23, 2015). In February 2016,
the U.S. Supreme Court stayed implementation of the CPP pending
judicial review. West Virginia v. EPA, No. 15A773 (S.Ct. Feb. 9, 2016).
    In March 2017, President Trump issued Executive Order 13873, which
among other things, directed EPA to reconsider the CPP. After
considering the statutory text, context, legislative history and
purpose, and in consideration of EPA's historical practice under CAA
section 111 as reflected in its other existing CAA section 111
regulations and of certain policy concerns, EPA proposed to repeal the
CPP. See 82 FR 48035. In a separate but related action, EPA published
an ANPRM to solicit comment on what EPA should include in a potential
new existing source regulation under CAA section 111(d), including
soliciting comment on aspects of the respective roles of the states and
EPA in that process, on the BSER in context of the statutory
interpretation contained in the proposed repeal of the CPP, on what
systems of emission reduction might be available and appropriate, and
the potential flexibility that could be afforded under the NSR program
to improve the implementation of a potential new existing source
regulation for EGUs under CAA section 111(d). 82 FR 61507 (December 28,
2017). EPA received more than 270,000 comments on the ANPRM, which have
informed this proposed rulemaking.
    In ACE, EPA is proposing to determine that the BSER for GHG
emissions from existing coal-fired EGUs is heat rate improvements that
can be applied at the source, consistent with the legal interpretation
expressed in the proposed repeal. The Agency is also, in this action,
clarifying the respective roles of the states and EPA under CAA section
111(d), including by proposing revisions to the regulations, in 40 CFR
part 60 subpart B, implementing that section. Section 111(d)(1) of the
CAA states that EPA's ``Administrator shall prescribe regulations which
shall establish a procedure . . . under which each State shall submit
to the Administrator a plan which (A) establishes standards of
performance for any existing source for any air pollutant . . . to
which a standard of performance under this section would apply if such
existing source were a new source, and (B) provides for the
implementation and enforcement of such standards of performance.'' See
42 U.S.C. 7411(d). CAA section 111(d)(1) also requires the
Administrator to ``permit the State in applying a standard of
performance to any particular source under a plan submitted under this
paragraph to take into consideration, among other factors, the
remaining useful life of the existing source to which such standard
applies.'' Id.
    As the plain language of the statute provides, EPA's authorized
role under CAA section 111(d)(1) is to develop a procedure for states
to establish standards of performance for existing sources. Indeed, the
Supreme Court has acknowledged the role and authority of states under
section 111(d): This provision allows ``each State to take the first
cut at determining how best to achieve EPA emissions standards within
its domain.'' Am. Elec. Power Co. v. Connecticut, 131 S. Ct. 2527, 2539
(2011). The Court addressed the statutory framework as implemented
through regulation, under which EPA promulgates emission guidelines and
the states establish performance standards: ``For existing sources, EPA
issues emissions guidelines; in compliance with those guidelines and
subject to federal oversight, the States then issue performance
standards for stationary sources within their jurisdiction, [42 U.S.C.]
Sec.  7411(d)(1).'' Id. at 2537-38.
    As contemplated by CAA section 111(d)(1), states possess the
authority and discretion to establish appropriate standards of
performance for existing sources. CAA section 111(a)(1) defines
``standard of performance'' as ``a standard of emissions of air
pollutants which reflects'' what is colloquially referred to as the
``Best System of Emission Reduction'' or ``BSER''--i.e., ``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)
(emphasis added).

    In order to effectuate the Agency's role under CAA section
111(d)(1), EPA promulgated implementing regulations in 1975 to provide
a framework for subsequent EPA rules and state plans under section
111(d). See 40 CFR part 60, subpart B (hereafter referred to as the
``implementing regulations''). The implementing regulations reflect
EPA's principal task under CAA section 111(d)(1), which is to develop a
procedure for states to establish standards of performance for existing
sources through state plans. EPA is proposing to promulgate an updated
version of the implementing regulations as part of ACE (see Section
VII). Per the new proposed implementing regulations, EPA effectuates
its role by publishing, an ``emission guideline'' \4\ that, among other
things, contains EPA's determination of the BSER for the category of
existing sources being regulated. See 40 CFR 60.22a(b) [``Guideline
documents published under this section will provide information for the
development of State plans, such as: . . . (4) An emission guideline
that reflects the application of the best system of emission reduction
(considering the cost of such reduction) that has been adequately
demonstrated.''] In undertaking this task, EPA ``will specify different
emissions guidelines . . . for different sizes, types and classes of .
. . facilities when costs of control, physical limitations, geographic
location, or similar factors make subcategorization appropriate.'' 40
CFR 60.22(b)(5).
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    \4\ See Section VII.A. for proposed changes to the definition of
``emission guideline'' as part of EPA's proposed new implementing
regulations.
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    In short, under EPA's new proposed regulations implementing CAA
section 111(d), which tracks with the existing implementing regulations
in this regard, the guideline document serves to ``provide information
for the development of state plans.'' 40 CFR 60.22a(b), with the
``emission guideline,'' reflecting BSER as determined by EPA, being the
principal piece of information states rely on to develop their plans
that establish standards of performance for existing sources.
    Because the CAA cannot necessarily be applied to GHGs in the same
manner as other pollutants, Utility Air Regulatory Group, 134 S. Ct.
2427, 2455 (2014) (Alito, J., concurring in part and dissenting in
part), it is fortuitous that CAA section 111(d) recognizes that states
possess considerable flexibility in developing their plans in response
to the emissions guideline(s) established by EPA. Specifically, the Act
requires that EPA permit states to consider, ``among other factors, the
remaining useful life'' of an existing source in applying a standard of
performance to such sources. CAA section 111(d)(1).
    Additionally, while CAA section 111(d)(1) clearly authorizes states
to develop state plans that establish performance standards and
provides states with certain discretion in determining appropriate
standards, CAA section 111(d)(2) provides EPA specifically a role with
respect to such state plans. This provision authorizes EPA to prescribe
a plan for a state ``in cases where the State fails to submit a
satisfactory plan.'' CAA section 111(d)(2)(A). EPA therefore is charged
with determining whether state plans developed and submitted under
section 111(d)(1) are ``satisfactory,'' and the proposed new
implementing regulations at 40 CFR 60.27a accordingly provides timing
and procedural requirements for EPA to make such a determination. Just
as guideline documents may provide information for states in developing
plans that establish standards of performance, they may also provide
information for EPA to consider when reviewing and taking action on a
submitted state plan, as the new proposed implementing regulations at
40 CFR 60.27a(c) references the ability of EPA to find a state plan as
``unsatisfactory because the requirements of (the implementing
regulations) have not been met.'' \5\
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    \5\ See also 40 FR 53343 (``If there is to be substantive
review, there must be criteria for the review, and EPA believes it
is desirable (if not legally required) that the criteria be made
known in advance to the States, to industry, and to the general
public. The emission guidelines, each of which will be subjected to
public comment before final adoption, will serve this function.'').
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B. Executive Order 13783 and EPA's Review of the CPP

    On March 28, 2017, President Trump issued Executive Order 13783,
which affirms the ``national interest to promote clean and safe
development of our Nation's vast energy resources, while at the same
time avoiding regulatory burdens that unnecessarily encumber energy
production, constrain economic growth, and prevent job creation.'' See
Executive Order 13783, Section 1(a). The Executive Order directs all
executive departments and agencies, including EPA, to ``immediately
review existing regulations that potentially burden the development or
use of domestically produced energy resources and appropriately
suspend, revise, or rescind those that unduly burden the development of
domestic energy resources beyond the degree necessary to protect the
public interest or otherwise comply with the law.'' Id. Section 1(c).
The Executive Order further affirms that it is ``the policy of the
United States that necessary and appropriate environmental regulations
comply with the law.'' Id. Section 1(e). Moreover, the Executive Order
specifically directs EPA to review and initiate reconsideration
proceedings to ``suspend, revise, or rescind'' the CPP, ``as
appropriate and consistent with law.'' Id. Section 4(a)-(c).
    In a document signed the same day as Executive Order 13783, and
published in the Federal Register at 82 FR 16329 (April 4, 2017), EPA
announced that, consistent with the Executive Order, it was initiating
its review of the CPP and providing notice of forthcoming proposed
rulemakings consistent with the Executive Order.\6\ In the course of
EPA's review of the CPP, the Agency also reevaluated its interpretation
of CAA section 111, and, on that basis, the Agency proposed to repeal
the CPP. See 82 FR 48035.
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    \6\ EPA also withdrew the proposed federal plan and model
trading rules, proposed amendments to certain regulations under 40
CFR part 60, subpart B, implementing CAA section 111(d), and
proposed rule regarding the Clean Energy Incentive Plan. 82 FR 16144
(April 3, 2017).
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    This action proposes a BSER for GHGs from existing EGUs in line
with the interpretation presented in the proposed CPP repeal. See 82 FR
48038-42. Comments submitted on the proposed repeal will be considered
in the promulgation of this rulemaking so there is no need to resubmit
comments that have already been timely submitted.

C. Industry Trends

    Carbon dioxide emissions in the power sector have steadily declined
in recent years due to a variety of power industry trends, which are
expected to continue. The reduction in power sector CO2
emissions is the result of industry trends away from coal-fired
generation and toward low- and zero-emitting generation sources. These
trends have been driven by market factors, reduced electricity demand,
and policy and regulatory efforts. These trends have resulted in a
notable change to the country's overall generation mix, as more natural
gas and renewable energy is used to generate electricity relative to
coal-fired electricity. The price of natural gas is expected to remain
low for the foreseeable future as improvements in drilling technologies
and techniques continue to reduce the cost of extraction. In addition,
the existing fleet of coal-fired EGUs is aging and there are very few
new coal-fired generation

projects under development. With a continued (but reduced) tax credit
and declining capital costs, solar capacity will continue to grow
through 2050 while tax credits that phase out for plants entering
service through 2024 provide incentives for new wind capacity in the
near-term. Some power plant generators have announced that they expect
to continue to change their generation mix away from coal-fired
generation toward natural-gas fired generation, renewables and more
deployment of energy efficiency measures. All of these trends, in
total, are expected to result in declining power sector CO2
emissions.
    In the near-term, according to the U.S. Energy Information
Administration's (EIA) 2018 Annual Energy Outlook, ``the cumulative
effect of increased coal plant retirements, lower natural gas prices
and lower electricity demand in the AEO2018 Reference case is a
reduction in the projected [CO2] emissions from electric
generators, even without the [CPP]. In 2020, electric power sector
CO2 emissions are projected to be 1.72 billion metric tons,
which is 120 million metric tons (7 percent) lower than the projected
level of CO2 emissions in the AEO2017 Reference case without
the CPP.'' \7\ In other words, these declining emission trends have
continued to develop even in the absence of implementation of the CPP.
---------------------------------------------------------------------------

    \7\ U.S. EIA, Annual Energy Outlook 2018 with projections to
2050 (February 6, 2018), at 102, available at https://www.eia.gov/outlooks/aeo/pdf/AEO2018.pdf.
---------------------------------------------------------------------------

    In consideration of these ongoing and projected power sector trends
and a resulting decline in power sector CO2 emissions, EPA
is soliciting comment on whether and how to consider such trends in
developing CO2 emission guidelines for the power sector. A
comparison of EIA projections to EPA analysis for the original proposed
CPP demonstrates that the rapid changes in the power sector are leading
to CO2 emission reductions at a faster rate than projected
even a few years ago when the CPP was promulgated (Comment C-1). EPA
also notes that CO2 emissions are projected to increase over
time in some EIA AEO side cases, and, given the uncertainties
associated with long-term emission projections, solicits comments on
the applicability of those alternative results.
    Because of the rapid pace of these power sector changes, it is
difficult for sector analysts to fully account for these changing
trends in near-term and long-term sector-wide projections. This means
that regulatory decisions made today could be based on information that
may very well be outdated within the next several years. If that is the
case, work put in by federal and state regulatory agencies--as well as
by the affected sources themselves--to address section 111(d)
requirements could quickly be overtaken by external market forces which
could make those efforts redundant or, even worse, put them in conflict
with industry trends that are already reducing CO2
emissions.

III. Legal Authority

A. Authority To Revisit Existing Regulations

    EPA's ability to revisit existing regulations is well-grounded in
the law. Specifically, EPA has inherent authority to reconsider, repeal
or revise past decisions to the extent permitted by law so long as the
Agency provides a reasoned explanation. The CAA complements EPA's
inherent authority to reconsider prior rulemakings by providing the
Agency with broad authority to prescribe regulations as necessary. 42
U.S.C. 7601(a); see also Emission Guidelines and Compliance Times for
Municipal Solid Waste Landfills, 81 FR 59276, 59277-78 (August 29,
2016). The authority to reconsider prior decisions exists in part
because EPA's interpretations of statutes it administers ``[are not]
instantly carved in stone,'' but must be evaluated ``on a continuing
basis.'' Chevron U.S.A. Inc. v. NRDC, Inc., 467 U.S. 837, 863-64
(1984). This is true when, as is the case here, review is undertaken
``in response to . . . a change in administrations.'' National Cable &
Telecommunications Ass'n v. Brand X Internet Services, 545 U.S. 967,
981 (2005). Indeed, ``[a]gencies obviously have broad discretion to
reconsider a regulation at any time.'' Clean Air Council v. Pruitt, 862
F.3d 1, 8-9 (D.C. Cir. 2017).

B. Authority To Regulate EGUs

    In the CPP, EPA stated that EPA's then-concurrent promulgation of
standards of performance regulating CO2 emissions from new,
modified, and reconstructed EGUs triggered the need to regulate
existing sources under CAA section 111(d). 80 FR 64715. In ACE, we are
not re-opening any issues related to this conclusion, but for the
convenience of stakeholders and the public, we will summarize our
explanation here.
    We explained in the CPP that CAA section 111(d)(1) requires EPA to
promulgate regulations under which states must submit state plans
regulating ``any existing source'' of certain pollutants ``to which a
standard of performance would apply if such existing source were a new
source.'' Id. Under CAA section 111(a)(2) and 40 CFR 60.15(a), a ``new
source'' is defined as any stationary source, the construction,
modification, or reconstruction of which is commenced after the
publication of proposed regulations prescribing a standard of
performance under CAA section 111(b) applicable to such source. We
noted that, at that time, we were concurrently finalizing a rulemaking
under CAA section 111(b) for CO2 emissions from affected
EGUs, which provided the requisite predicate for applicability of CAA
section 111(d). Id.
    EPA explained in the 111(b) rule (80 FR 64529) that ``CAA section
111(b)(1)(A) requires the Administrator to establish a list of source
categories to be regulated under section 111. A category of sources is
to be included on the list `if in [the Administrator's] judgment it
causes, or contributes significantly to, air pollution which may
reasonably be anticipated to endanger public health and welfare.' ''
This determination is commonly referred to as an ``endangerment
finding'' and that phrase encompasses both the ``causes or contributes
significantly'' component and the ``endanger public health and
welfare'' component of the determination. Then, for the source
categories listed under section 111(b)(1)(A), the Administrator
promulgates, under section 111(b)(1)(B), ``standards of performance for
new sources within such category.'' EPA further explained that, because
EGUs had previously been listed, it was unnecessary to make an
additional finding. The Agency also noted that, under section
111(b)(1)(A), findings are category specific and not pollutant
specific, so a new finding is not needed with regard to a new
pollutant. The Agency further asserted that, even if it were required
to make a finding, given the large amount of CO2 emitted
from this source category (the largest single stationary source
category of emissions of CO2 by far) that EGUs would easily
meet that standard. The Agency further noted that, given the large
amount of emissions from the source category, it was not necessary in
that rule ``for the EPA to decide whether it must identify a specific
threshold for the amount of emissions from a source category that
constitutes a significant contribution.'' 80 FR 64531.
    That CAA section 111(b) rulemaking remains on the books, although
EPA is currently considering revising it. Accordingly, it continues to
provide the requisite predicate for applicability of CAA section
111(d). Any comments on the issues discussed in this subsection would
be more appropriately addressed

to the docket on EPA's intended forthcoming proposal with regard to the
new source rule.

C. Legal Authority for Determination of the BSER

    As discussed above, EPA's authorized role under CAA section 111(d)
is to establish a procedure under which states submit plans
establishing standards of performance for existing sources, reflecting
the application of the best system of emission reduction that EPA has
determined is adequately demonstrated for the source category. In the
CPP, EPA determined that the BSER for CO2 emissions from
existing fossil fuel-fired power plants was the combination of emission
rate improvements and limitations on overall emissions by affected
power plants that can be accomplished through a combination of three
sets of measures, which the EPA called ``building blocks'':
    1. Improving heat rate at affected coal-fired steam generating
units;
    2. Substituting increased generation from lower-emitting existing
natural gas combined cycle units for decreased generation from higher-
emitting affected steam generating units; and
    3. Substituting increased generation from new zero-emitting
renewable energy generating capacity for decreased generation from
affected fossil fuel-fired generating units.

While building block 1 constituted measures that could be applied
directly to a source--that is, integrated into its design or
operation--building blocks 2 and 3 employed generation-shifting
measures that departed from this traditional, source-specific approach
to regulation.
    As explained in the proposed repeal, after reconsidering the
statutory text, context and legislative history, and in consideration
of EPA's historical practice under CAA section 111 as reflected in its
other existing section 111 regulations, the Agency proposes to return
to a reading of section 111(a)(1) (and its constituent term, ``best
system of emission reduction'') as being limited to emission reduction
measures that can be applied to or at an individual stationary source.
That is, such measures must be based on a physical or operational
change to a building, structure, facility or installation at that
source rather than measures the source's owner or operator can
implement at another location. For a more detailed discussion of EPA's
proposed interpretation, see 82 FR 48039-42.
    In proposing ACE, EPA offers additional legal rationale to support
its determination that heat-rate improvements constitute the BSER. EPA
solicits comment on these additional legal interpretations (Comment C-
2).
    First, as explained in the CPP preamble, reduced utilization ``does
not fit within our historical and current interpretation of the BSER.''
See 80 FR 64780; see also id. at 64762 (``EPA has generally taken the
approach of basing regulatory requirements on controls and measures
designed to reduce air pollutants from the production process without
limiting the aggregate amount of production.'') Whereas some emission
reduction measures (such as a scrubber) may have an incidental impact
on a source's production levels, reduced utilization is directly
correlated with a source's output. Moreover, predicating a CAA section
111 standard on a source's non-performance would inappropriately inject
the Agency into an owner/operator's production decisions. In returning
to our historical understanding of and practice under section 111, we
reiterate that reduced utilization is not a valid system of emission
reduction for purposes of establishing a standard of performance. EPA
believes our proposed interpretation that the BSER be limited to
measures that can be applied at or to a source does not command a
different result.
    Second, as explained in the proposed repeal notice, interpretative
constraints that may apply to interpreting CAA section 111(a)(1) (i.e.,
determining what types of measures that may be considered as the BSER)
for purposes of setting a new source performance standard under section
111(b) reasonably may be applied to interpreting the BSER for purposes
of setting existing source standards under section 111(d) as well (and,
given that ``standard of performance'' is given a unitary definition
for purposes of the entire statutory section, applying the same
interpretative constraints may in fact be required). For example, we
proposed that ``the BSER should be interpreted as a source-specific
measure, in light of the fact that [Best Available Control Technology,
or BACT] standards, for which the BSER is expressly linked by statutory
text, are unambiguously intended to be source-specific.'' \8\ See 82 FR
48042.
---------------------------------------------------------------------------

    \8\ See 40 CFR 52.21(b)(12); see also 42 U.S.C. 7479(3).
---------------------------------------------------------------------------

    Under the CAA and applicable regulations, certain preconstruction
permits must contain emissions limitations based on application of BACT
for certain regulated pollutants. EPA recommends that permitting
authorities follow a five-step ``top-down'' BACT analysis, which calls
for all available control technologies for a given pollutant to be
identified and ranked in descending order of control effectiveness.\9\
The options are then assessed in consideration of technical, energy,
environmental and economic factors until an option is selected as BACT.
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    \9\ The five steps are: (1) Identify all available control
technologies; (2) eliminate technically infeasible options; (3) rank
remaining control technologies; (4) evaluate most effective controls
and document results; and (5) select the BACT.
---------------------------------------------------------------------------

    In reviewing our BACT guidance, we have identified additional
interpretive constraints that may be applied to CAA section 111.
Specifically, in EPA's PSD and Title V Permitting Guidance for
Greenhouse Gases, we explained that a BACT analysis ``need not
necessarily include inherently lower polluting processes that would
fundamentally redefine the nature of the source proposed by the permit
applicant.'' Id. at 26 (emphasis added). Furthermore, we explained that
``BACT should generally not be applied to regulate the applicant's
purpose or objective for the proposed facility.'' Id. Indeed, ``EPA has
recognized that the initial list of control options for a BACT analysis
does not need to include `clean fuel' options that would fundamentally
redefine the source. Such options include those that would require a
permit applicant to switch to a primary fuel type (i.e., coal, natural
gas or biomass) other than the type of fuel that an applicant proposes
to use for its primary combustion process.'' Id. at 27. EPA has even
noted that ``applicants proposing to construct a coal-fired electric
generator, have not been required by EPA as part of a BACT analysis to
consider building a natural gas-fired electric turbine although the
turbine may be inherently less polluting per unit product (in this case
electricity).'' \10\ Although in the CPP we believed that EPA's
``redefining the source'' policy was not relevant for purposes of
section 111(d), see CPP RTC Chapter 1A, 170-72, we now believe that
such a policy is relevant in light of the relationship between BACT and
BSER. In the response to comments accompanying the CPP, EPA rejected
the relevance to BSER under section 111 of the Agency's general policy
against ``redefining the source'' in the context of PSD/BACT. EPA now
believes that it was incorrect in its response, and that it is worth
examining this point in some detail because it encapsulates several key
aspects of the CPP's interpretation

of section 111 in general and section 111(d) in particular that EPA now
proposes to conclude in ACE are not appropriate interpretations of the
statute.
---------------------------------------------------------------------------

    \10\ New Source Review Workshop Manual, at B.13 (Draft) (October
1990), available at https://www.epa.gov/sites/production/files/2015-07/documents/1990wman.pdf.
---------------------------------------------------------------------------

    In its response to comments, EPA largely based its rejection of the
relevance of PSD to BSER on what it saw as the salient distinctions
between the sources subject to, and mode of operation of, the two
statutory programs. In this regard, EPA spoke of the ``distinct context
of the PSD program, which involves the case-by-case review of the
construction of an individual stationary source. . . . BACT is not
applicable to unmodified existing sources nor is it applied on a source
category basis. The CAA's PSD program is administered primarily by
state and local permitting authorities as [an] individualized
preconstruction requirement under CAA section 165. Under section
111(d), the Administrator identifies a list of adequately demonstrated
control options in use by the industry, selects the best of those
control options after considering cost and other factors, then selects
an achievable limit for the category through the application of the
BSER across the industry. . . .'' (Emphases added.)
    Here, EPA's response disregarded the fact that under CAA section
111(d), the statute explicitly tasks states--not the Administrator--
with ``establishing standards of performance'' for existing sources,
and that the statute expressly requires EPA to allow the state to take
into account source-specific factors when doing so. A ``standard of
performance'' is defined at section 111(a)(1) as ``a standard for
emissions of air pollutants which reflects the degree of emission
limitation achievable through the application of the'' BSER. (Emphasis
added.) Therefore, it is the state, not EPA, that is tasked in the
first instance with ``select[ing] an achievable limit'' for existing
sources--and section 111(d)'s emphasis on source-specific factors at
the very least renders questionable EPA's unqualified assertion that
BSER for existing sources ``is applied on a source category basis.'' In
the instant proposal, EPA proposes to give full meaning to these
textual and structural features of the existing-source program under
section 111(d) that render it in important respects distinct from the
new-source program under section 111(b) and similar to the source-by-
source PSD program: Section 111(d), unlike section 111(b), is
implemented in the first instance by the states, and it is expressly
linked to source-specific factors. These similarities counsel against
EPA's prior rejection of the relevance of the general policy under PSD
against ``redefining the source.''
    Furthermore, speaking of the generation-shifting measures that
constituted the second and third ``building blocks'' of the CPP, EPA
asserted that ``those measures are part of the business purposes and
objectives within the power sector. Accordingly, the BSER, which
incorporates building blocks 2 and 3, cannot be said to force a
fundamental redefinition of the business of generating electric
power.'' (Emphases added.) The emphasized phrases reveal the influence
of EPA's statutory interpretation underlying the CPP: That EPA can
regulate under CAA section 111 at the level of an entire industrial
sector, and that the business that it is regulating is ``generating
electric power'' writ large--rather than a recognition in line with the
statute's text and structure, and EPA's practice prior to the CPP, of
regulating the performance of individual sources through measures
carried out at and by the individual source.
    EPA rested on its discretionary prerogative: ``EPA's policies under
CAA section 165 regarding the construction of individual sources are
not controlling for purposes of establishing category-wide standards
for existing sources under CAA section 111(d). Even if the PSD
`redefining the source' policies were applicable in this context, it
would be within the Administrator's discretion to consider requiring a
fundamental redesign of a newly constructed or modified source[ ].
EPA's case-by-case application of CAA section 165 in the PSD program
does not limit the Administrator's discretion in establishing an
emission guideline for an entire category of existing sources under CAA
section 111(d).'' (Emphases added.) EPA has explained, both in the
proposed repeal and the instant proposal, why it is proposing to
conclude that the statute does not, in fact, delegate discretion to the
Administrator to ``establish . . . for an entire category of existing
sources'' standards that can only be accomplished by ``a fundamental
redesign'' of that category, of the generation mix, and of the division
of jurisdiction over electricity generation within the federal
government and between the federal government and the states. But to
the extent that the Agency, due to the fact that Congress did not
expressly forbid such an approach, does possess that discretion, today
it proposes not to exercise it.
    Third, notwithstanding the relationship between BACT and BSER, we
believe that measures ``redefining the source'' should be excluded from
consideration for purposes of CAA section 111(d). See, e.g., Sierra
Club v. EPA, 499 F.3d 653, 655 (7th Cir. 2007) (``Refining the
statutory definition . . . to exclude redesign is the kind of judgment
by an administrative agency to which a reviewing court should
defer.''). Indeed, the policy against redefining a source is even more
sensible when applied to existing sources. Under section 111(d),
regulated sources are well past the proposal stage and redefining such
sources would likely require, at a minimum, significant modification
and could even require decommissioning, redesign and new construction.
Accordingly, we propose to recognize that the BSER analysis need not
include options that would ``fundamentally redefine the source,''
irrespective of the application of that policy under PSD. For purposes
of ACE, therefore, we did not consider natural gas repowering (i.e.,
converting from a coal-fired boiler to a gas-fired turbine) or
refueling (i.e., converting from a coal-fired boiler to a natural gas-
fired boiler) as a system of emission reduction for coal-fired steam
generating units.
    Fourth, the legislative history underlying CAA section 111 confirms
that Congress intended this provision to be source oriented. The Senate
Committee Report on Senate Bill 4358 explained that ``[t]he provisions
for new source performance standards [i.e., S. 4538, section 113] \11\
are designed to insure [sic] that new stationary sources are designed,
built, equipped, operated, and maintained so as to reduce emissions to
a minimum.'' S. Committee Rep. to accompany S. 4358 (Sept. 17, 1970),
1970 CAA Legis. Hist. at 415-16 (emphasis added). Similarly,
``[e]mission standards developed under [S. 4538, section 114] would be
applied to existing stationary sources. However, the Committee
recognizes that certain old facilities may use equipment and processes
which are not suited to the application of control technology.'' Id. at
1970 CAA Legis. Hist. at 419 (emphasis added) (noting further that in
such cases, the application of standards could be waived).
---------------------------------------------------------------------------

    \11\ Section 113 of Senate Bill 4538 would become CAA section
111; section 114 of the Senate Bill would become CAA section 111(d).
---------------------------------------------------------------------------

    The proposed interpretive scope of the BSER is reasonable because
it focuses the BSER on the performance of the emitting unit itself,
rather than the performance of the emitting unit and the transmission
system to which it belongs. EPA's area of expertise is control of
emissions at the source. EPA is not the expert agency with regard to
electricity management. FERC is the expert at the

federal level and public utility commissions are the experts at the
state and local level. Numerous factors might be considered in
determining which power plants dispatch on a given system or operate at
any given time (e.g., cost of service, voltage support, electricity
demand, availability of renewable resources, etc.). Moreover, numerous
factors are relevant in determining how much new/replacement generation
capacity is needed and what types of generating resources best satisfy
that need. EPA has no express legal authority and no particular
expertise in any of these areas. This is particularly relevant because,
as noted below, there are already significant changes taking place
within the power sector that are resulting in shifts away from coal-
fired generation to new technologies such as renewables. This shift is
creating tremendous strain on the power infrastructure even without the
added pressures of an EPA mandate to further shift away from additional
coal-fired generation. Many experts have expressed concern that these
pressures could create reliability problems. As DOE noted in a 2017
report on electricity markets and reliability, ``Ultimately, the
continued closure of traditional baseload power plants calls for a
comprehensive strategy for long-term reliability and resilience. States
and regions are accepting increased risks that could affect the future
reliability and resilience of electricity delivery for consumers in
their regions. Hydropower, nuclear, coal, and natural gas power plants
provide essential reliability services and fuel assurance critical to
system resilience. A continual comprehensive regional and national
review is needed to determine how a portfolio of domestic energy
resources can be developed to ensure grid reliability and resilience.''
\12\ Because EPA believes it is not appropriate to further challenge
the nation's electricity system while these important technical and
policy issues are being addressed. EPA believes that it is reasonable
to focus on a ``BSER'' limited to consideration of emission control
measures that can be applied at or to coal-fired units, ensuring that
regardless of how much coal-fired generation remains, that generation
is operated to minimize CO2 emissions.
---------------------------------------------------------------------------

    \12\ U.S. DOE, Staff Report to the Secretary on Electricity
Markets and Reliability (August 2017) at 14, available at https://www.energy.gov/sites/prod/files/2017/08/f36/Staff%20Report%20on%20Electricity%20Markets%20and%20Reliability_0.pdf
.
---------------------------------------------------------------------------

    Also, the proposed interpretive scope of the BSER is reasonable
considering the several important economic, policy and technology
shifts occurring in the power sector. The first change is being driven
by low natural gas prices that make lower carbon-emitting NGCC units
more competitive as compared to higher carbon-emitting coal plants.
Another important change is driven by both technology changes and by
state and national energy policy decisions that have made renewable
energy (e.g., solar and wind energy) more competitive compared to coal
and natural gas. The third notable change is driven by aging coal
plants, which considering the economic competitive pressures driven by
natural gas and renewable generation, are leading companies to conclude
that a significant number of coal plants are reaching the end of their
useful economic life or are no longer economic to operate.
    These trends have driven down GHG emissions from power plants,
which were also key components to the BSER as defined in the CPP. In
fact, the analysis that EPA has done for ACE (see RIA), as well as
analysis by many others (including EIA), show that these trends have
already well outpaced the projections that went into the CPP for many
states. For this reason, establishing a BSER on assumptions for
generation by various sources that accounts for the continuation of
these trends into the future would create significant work for both
states and sources that may or may not result in emission reductions
from ACE if the actual trends once again prove to be stronger than
projected.
    While some might suggest that this argues that the BSER in ACE
should still follow the same approach as the CPP, adjusting this
proposal to be even more stringent ignores the fact that the
uncertainties that have resulted in faster than projected emission
reductions are also uncertain in the opposite direction. From 2005 to
2008, gas prices experienced several unexpected peaks that were not
anticipated. If this were to happen in the future, it would make any
rule based on CPP-type assumptions significantly more expensive.
Similarly, while the recent past has shown continued advances in
renewable cost and performance, it is not certain that those trends
will be sustained. It should be noted that federal tax subsidies that
have been key to this trend are set to expire over the next several
years which may play a role in the future.
    Because of these significant uncertainties that can have large
impacts on electric reliability and the cost of electricity to
consumers, EPA believes that this further supports the unreasonableness
of basing the BSER on generation-shifting measures. Regardless of the
path that the power sector takes, coal-fired power plants are likely to
be an important part of the generation mix for the foreseeable future,
therefore EPA believes it is reasonable to ensure that the remaining
coal-fired generation (which is also the most CO2 intensive
portion of the power sector) focuses on reducing that CO2
emission intensity to the extent technically feasible considering cost.
    EPA believes that a BSER focused on making these plants as
efficient as possible is the best way to ensure GHG emission reductions
regardless of other factors such as technology changes for other types
of generation, changes in fuel price, changes in electricity demand or
changes in energy policy that neither environmental regulators nor
power companies have the power to control.

IV. Affected Sources

    EPA is proposing that an affected EGU subject to regulation upon
finalization of ACE is any fossil fuel-fired electric utility steam
generating unit (i.e., utility boilers) that is not an integrated
gasification combined cycle (IGCC) unit (i.e., utility boilers, but not
IGCC units) that was in operation or had commenced construction as of
August 31, 2018,\13\ and that meets the following criteria.\14\ To be
an affected EGU, a fossil fuel-fired electric utility steam generating
unit must serve a generator capable of selling greater than 25 MW to a
utility power distribution system and have a base load rating greater
than 260 GJ/h (250 MMBtu/h) heat input of fossil fuel (either alone or
in combination with any other fuel).
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    \13\ Under section 111(a) of the CAA, determination of affected
sources is based on the date that EPA proposes action on such
sources. January 8, 2014 is the date the proposed GHG standards of
performance for new fossil fuel-fired EGUs were published in the
Federal Register (79 FR 1430).
    \14\ To be clear, this definition of an affected EGU does not,
at this time, include stationary combustion turbines for reasons
discussed later in this document.
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    EPA is proposing different applicability criteria than in the CPP
to reflect EPA's determination of the BSER for only fossil fuel-fired
electric utility steam generating units. In ACE, EPA does not identify
a BSER for stationary combustion turbines and IGCC units and, thus,
such units are not affected EGUs for purposes of this action (see
discussion below in Section V.B). It should be noted, in the CPP's
identification of the BSER, no HRIs were identified as the BSER for
stationary combustion turbines and IGCC units. Nevertheless, EPA
solicits comment on systems of emission reduction that might be the
BSER for these types of

EGUs (Comment C-3). EPA notes that, under the CPP, certain EGUs were
not considered to be affected EGUs, and therefore were exempt from
inclusion in a state plan. Similarly, EPA is proposing for ACE, the
following EGUs would be excluded from a state's plan: (1) Those units
subject to 40 CFR 60 subpart TTTT as a result of commencing
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; (3) non-fossil units (i.e., units capable of combusting
at least 50 percent non-fossil fuel) that have historically limited the
use of fossil fuels to 10 percent or less of the annual capacity factor
or are subject to a federally enforceable permit limiting fossil fuel
use to 10 percent or less of the annual capacity factor; (4) units that
serve a generator along with other steam generating unit(s) where the
effective generation capacity (determined based on a prorated output of
the base load rating of each steam generating unit) is 25 MW or less;
(5) municipal waste combustor unit subject to 40 CFR part 60, subpart
Eb; or (6) commercial or industrial solid waste incineration units that
are subject to 40 CFR part 60, subpart CCCC. EPA solicits comment on
whether there should be a different definition of affected EGUs for ACE
(Comment C-4).

V. Determination of the BSER

    CAA section 111(d)(1) directs EPA to promulgate regulations
establishing a CAA section 110-like procedure under which states submit
state plans that establish ``standards of performance'' for emissions
of certain air pollutants from sources which, if they were new sources,
would be subject to new source standards under section 111(b), and that
provide for the implementation and enforcement of those standards of
performance. The term ``standard of performance'' is defined in section
111(a)(1) as ``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 [BSER] 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.''
    Thus, EPA is authorized to determine the BSER for affected sources.
See also 40 CFR 60.22. In making this determination, EPA identifies all
``adequately demonstrated'' \15\ ``system[s] of emission reduction''
for a particular source category and then evaluates those systems to
determine which is the ``best'' \16\ while ``taking into account'' the
factors of ``cost . . . nonair quality health and environmental impact
and energy requirements.'' Because CAA section 111 does not set forth
the weight that should be assigned to each of these factors, courts
have granted the Agency a great degree of discretion in balancing them.
Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999)
(internal citations omitted).
---------------------------------------------------------------------------

    \15\ Case law under CAA section 111(b) explains that ``[a]n
adequately demonstrated system is one which has been shown to be
reasonably reliable, reasonably efficient, and which can reasonably
be expected to serve the interests of pollution control without
becoming exorbitantly costly in an economic or environmental way.''
Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 (D.C. Cir.
1973). While some of these cases suggest that ``[t]he Administrator
may make a projection based on existing technology,'' Portland
Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973), the
D.C. Circuit has also noted that ``there is inherent tension''
between considering a particular control technique as both ``an
emerging technology and an adequately demonstrated technology,''
Sierra Club v. Costle, 657 F.2d 298, 341 n.157 (D.C. Cir. 1981). See
also NRDC v. Thomas, 805 F.2d 410, n. 30 (D.C. Cir. 1986)
(suggesting that ``a standard cannot both require adequately
demonstrated technology and also be technology-forcing.'').
Nevertheless, EPA appears to ``have authority to hold the industry
to a standard of improved design and operational advances, so long
as there is substantial evidence that such improvements are
feasible.'' Sierra Club, 657 F.2d at 364.
    \16\ The D.C. Circuit recognizes that EPA's evaluation of the
``best'' system must also include ``the amount of air pollution as a
relevant factor to be weighed . . . .'' Id. at 326.
---------------------------------------------------------------------------

    CAA section 111(d)(1) assigns responsibility to the states for
establishing standards of performance for affected existing sources--in
contrast to section 111(b), which directs EPA to set standards of
performance for affected new sources.

A. Identification of the BSER

    In ACE, EPA identified several systems of emission reduction for
existing fossil-fuel fired steam generating EGUs (i.e., heat rate
improvements; carbon capture and storage; and fuel co-firing, including
with natural gas and biomass) and evaluated each of these systems to
determine which is the ``best'' while taking into account cost, nonair
quality health and environmental impact and energy requirements.
    EPA proposes to identify ``heat rate improvements'' (which may also
be referred to as ``efficiency improvements'') as the BSER for existing
fossil-fuel fired steam generating EGUs. The basis for this
determination is discussed below. A discussion of other potential
CO2 reduction measures that EPA has determined are not BSER
(but which states may allow sources to use for compliance purposes) is
also provided below.
    The U.S. fleet of existing coal-fired EGUs is a diverse group of
units with unique individual characteristics, spread across the
country. Coal-fired power plants are customized facilities that were
designed and built to meet local and regional electricity needs over
the past 100 years, with no two plants being identical. Geography and
elevation, unit size, coal type, pollution controls, cooling system,
firing method and utilization rate are just a few of the parameters
that can impact the overall efficiency and performance of individual
units. As a result, heat rates of existing coal-fired EGUs in the U.S.
vary substantially. The variation in heat rates among EGUs with similar
design characteristics, as well as year-to-year variation in heat rate
at individual EGUs, indicate that there is potential for HRIs that can
improve CO2 emission performance for the existing coal-fired
EGU fleet, but that this potential may vary considerably at the unit
level.
    EPA does not currently have sufficient information on adequately
demonstrated systems of emission reduction--including HRI
opportunities--for existing natural gas-fired stationary combustion
turbines. As such, the Agency is currently unable to determine the BSER
for such units. In this action, EPA solicits information on adequately
demonstrated systems of GHG emission reduction for such units--
especially on the efficiency, applicability, and cost of such systems
(Comment C-5). This is discussed in greater detail below.

B. HRIs for Steam-Generating EGUs

    As mentioned above, EPA proposes in ACE to identify ``heat rate
improvements'' as the BSER for existing steam generating fossil fuel-
fired EGUs. 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 British thermal units (Btu), required to generate one
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 per kWh generated and emit lower amounts of
CO2 and other air pollutants per kWh generated as compared
to a less efficient unit. An EGU's heat rate can be affected by a
variety of design characteristics, site-specific factors, and operating
conditions, including:
     Thermodynamic cycle of the boiler;

     Boiler and steam turbine size and design;
     Cooling system type;
     Auxiliary equipment, including pollution controls;
     Operations and maintenance practices;
     Fuel quality; and
     Ambient conditions.
    In the CPP, EPA quantified emission reductions achievable through
heat rate improvements on a regional basis (i.e., building block 1).
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. 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 selected the least stringent as a
national performance rate. Id. at 64811-819. EPA noted that building
block 1 measures could not by themselves constitute the BSER because of
a potential ``rebound effect.'' \17\ Id. at 64787.
---------------------------------------------------------------------------

    \17\ As discussed below, EPA modeled a range of potential HRIs
for ACE and the Agency's analysis indicates that system-wide
emission decreases from heat rate improvements will likely outweigh
any potential system-wide emission increases. Accordingly, EPA
proposes to conclude that the ``rebound effect'' does not preclude a
determination that HRIs constitute the BSER.
---------------------------------------------------------------------------

    EPA believes that building block 1, as constructed in CPP, does not
represent an appropriate BSER, and ACE better reflects important
changes in the formulation and application of the BSER in accordance
with the CAA. For example, the percent improvement applied as the BSER
under CPP was determined at the interconnect-level, and did not take
into account remaining useful life or other source-specific factors,
which are addressed in this proposed rule.\18\ The current fleet of
existing fossil fuel-fired EGUs is quite diverse in terms of size, age,
fuel type, operation (e.g., baseload, cycling), boiler type, etc. Many
coal-fired EGUs now operate under load-following and cycling conditions
as opposed to the steady baseload operating conditions that were more
common a decade ago.
---------------------------------------------------------------------------

    \18\ The Agency solicits comments, nonetheless, on whether and
how to retain building block 1 in lieu of the proposed approach.
---------------------------------------------------------------------------

    There are available technologies and equipment upgrades, as well as
best operating and maintenance practices, that EGU owners or operators
may utilize to improve an EGU's heat rate. In the ANPRM, EPA solicited
information on a number of technology and equipment upgrades and good
practices (specifically including, but not limited to, those that were
listed in Tables 1 and 2 of the ANPRM, see 82 FR 61514) that have the
potential to reduce an EGU's heat rate.
    Specifically, the Agency solicited information on: (1) Potential
HRIs from technologies and best operating and maintenance practices;
(2) costs of deploying the technologies and the best operating and
maintenance practices, including applicable planning, capital and
operating and maintenance costs; (3) owner and operator experiences
deploying the technologies and employing best operating and maintenance
practices; (4) barriers to or from deploying the technologies and
operating and maintenance practices; and (5) any other technologies or
operating and maintenance practices that may exist for improving heat
rate, but were not listed in the ANPRM.
    EPA received useful information in the comments submitted in
response to the ANPRM. Many commenters contended that any evaluation of
the HRI potential of the coal-fired EGU fleet must be done on a unit-
by-unit basis since the opportunities for HRI are source-specific and
dependent upon the individual unit's design, configuration, and
operating and maintenance history. Many commenters emphasized the
significant influence that the operating mode (i.e., whether the unit
operates at consistent baseload conditions or in cycling or load-
following mode or as a low capacity factor unit that is subject to
frequent startups and shutdowns) has on an individual EGU's heat rate
and HRI potential. Many commenters also claimed that owners and
operators of fossil fuel-fired EGUs already routinely conduct HRI
efforts and, as a result, there are relatively few economic improvement
opportunities available.
1. Potential HRI Measures--Technologies and Equipment Upgrades
    As mentioned above, numerous technologies and equipment upgrades,
as well as best operating and maintenance practices (which are
discussed in the next section), have been identified as potential
measures to improve an EGU's heat rate. In the ANPRM, EPA solicited
information on a large number of technology and equipment upgrades and
best operating and maintenance practices that have the potential to
reduce an EGU's heat rate. See Tables 1 and 2 of the ANPRM, 82 FR
61514.
    In this action, EPA is proposing to determine that heat rate
improvement is the BSER for affected existing coal-fired EGUs and is
proposing a list of ``candidate technologies'' of HRI measures for
states to use in establishing standards of performance under CAA
section 111(d)(1). States can use the information that EPA provides on
the ``degree of emission limitation achievable through application of
the [BSER]'' to establish standards of performance for affected EGUs
covered by a state's plan.\19\ While a large number of HRI measures
have been identified in a variety of studies conducted by government
agencies and outside groups (see Table 3 in ANPRM, 82 FR 61515), some
of those identified technologies have limited applicability and many
provide only negligible HRI. EPA believes that it would be overly
burdensome to require States to evaluate the degree of emission
limitation achievable from the application of every single identified
HRI measure--including those with negligible benefits--at each source
(or subcategory of sources) within their borders. Therefore, EPA has
identified a list of the ``most impactful'' HRI measures that we are
proposing to serve as technologies, equipment upgrades and best
operating and maintenance practices that form the list of ``candidate
technologies'' constituting the BSER. The candidate technologies of the
BSER is listed in Table 1 below. Best operating and maintenance
practices are discussed in the next section. States are expected to
evaluate each of the BSER HRI measures in the candidate technologies in
establishing a standard of performance for any particular source. The
States, in applying a standard of performance, may take into
consideration, among other factors, the remaining useful life of the
existing source to which the standard would apply. EPA solicits
comments on whether other unlisted HRI measures should also be included
as part of the BSER and added to the candidate technologies (Comment C-
6). EPA also solicits comment on each of the candidate technologies
described further below, including whether any additional technologies
should be added to the list, and whether there is additional
information that EPA should be aware of and consider in determining the
BSER and establishing the candidate technologies for HRI measures
(Comment C-7).
---------------------------------------------------------------------------

    \19\ The states, in applying the unit-specific standard, may
also take into consideration, among other factors, the remaining
useful life of the existing source to which the standard applies.
See CAA section 111(d)(1).
---------------------------------------------------------------------------

    The technologies and operating and maintenance practices listed and

described below may not be available or appropriate for all types of
EGUs; and some owners or operators will have already deployed some of
the technologies and employed some of the best operating and
maintenance practices.

                            Table 1--Summary of Most Impactful HRI Measures and Range of Their HRI Potential (%) by EGU Size
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      <200 MW                       200-500 MW                        >500 MW
                       HRI measure                       -----------------------------------------------------------------------------------------------
                                                                Min             Max             Min             Max             Min             Max
--------------------------------------------------------------------------------------------------------------------------------------------------------
Neural Network/Intelligent Sootblowers..................             0.5             1.4             0.3             1.0             0.3             0.9
Boiler Feed Pumps.......................................             0.2             0.5             0.2             0.5             0.2             0.5
Air Heater & Duct Leakage Control.......................             0.1             0.4             0.1             0.4             0.1             0.4
Variable Frequency Drives...............................             0.2             0.9             0.2             1.0             0.2             1.0
Blade Path Upgrade (Steam Turbine)......................             0.9             2.7             1.0             2.9             1.0             2.9
Redesign/Replace Economizer.............................             0.5             0.9             0.5             1.0             0.5             1.0
                                                         -----------------------------------------------------------------------------------------------
Improved O&M Practices..................................            Can range from 0 to >2.0% depending on the unit's historical O&M practices.
--------------------------------------------------------------------------------------------------------------------------------------------------------

a. Neural Network/Intelligent Sootblower
    Neural networks. Computer models, known as neural networks, can be
used to simulate the performance of the power plant at various
operating loads. Typically, the neural network system ties into the
plant's distributed control system for data input (process monitoring)
and process control. The system uses plant specific modeling and
control modules to optimize the unit's operation and minimize the
emissions. This model predictive control can be particularly effective
at improving the plants performance and minimizing emissions during
periods of rapid load changes. The neural network can be used to
optimize combustion conditions, steam temperatures, and air pollution
control equipment.
    Intelligent Sootblowers. During operations at a coal-fired power
plant, particulate matter (ash or soot) builds up on heat transfer
surfaces. This build-up degrades the performance of the heat transfer
equipment and negatively affects the efficiency of the plant. Power
plant operators use steam injection ``sootblowers'' to clean the heat
transfer surfaces by removing the ash build-up. This is often done on a
routine basis or as needed based on monitored operating
characteristics. Intelligent sootblowers (ISB) are automated systems
that use process measurements to monitor the heat transfer performance
and strategically allocate steam to specific areas to remove ash
buildup.
    The cost to implement an ISB system is relatively inexpensive if
the necessary hardware is already installed. The ISB software/control
system is often incorporated into the neural network software package
mentioned above. As such, the HRIs obtained via installation of neural
network and ISB systems are not necessarily cumulative.
    The efficiency improvements from installation of intelligent
sootblowers are often greatest for EGUs firing subbituminous coal and
lignite due to more significant and rapid fouling at those units as
compared to EGUs firing bituminous coal.
b. Boiler Feed Pumps
    A boiler feed pump (or boiler feedwater pump) is a device used to
pump feedwater into a boiler. The water may be either freshly supplied
or returning condensate produced from condensing steam produced by the
boiler. The boiler feed pumps consume a large fraction of the auxiliary
power used internally within a power plant. Boiler feed pumps can
require power in excess of 10 MW on a 500-MW power plant. Therefore,
the maintenance on these pumps should be rigorous to ensure both
reliability and high-efficiency operation Boiler feed pumps wear over
time and subsequently operate below the original design efficiency. The
most pragmatic remedy is to rebuild a boiler feed pump in an overhaul
or upgrade.
c. Air Heater and Duct Leakage Control
    The air pre-heater is a device that recovers heat from the flue gas
for use in pre-heating the incoming combustion air (and potentially for
other uses such as coal drying). Properly operating air pre-heaters
play a significant role in the overall efficiency of a coal-fired EGU.
A major difficulty associated with the use of regenerative air pre-
heaters is air leakage from the combustion air side to the flue gas
side. Air leakage affects boiler efficiency due to lost heat recovery
and affects the axillary load since any leakage requires additional fan
capacity. The amount of air leaking past the seals tends to increase as
the unit ages. Improvements to seals on regenerative air pre-heaters
have enabled the reduction of air leakage.
d. Variable Frequency Drives (VFDs)
    VFD on ID Fans. The increased pressure required to maintain proper
flue gas flow through add-on air pollutant control equipment may
require additional fan power, which can be achieved by an induced draft
(ID) fan upgrade/replacement or an added booster fan. Generally, older
power plant facilities were designed and built with centrifugal fans.
    The most precise and energy-efficient method of flue gas flow
control is use of VFD. The VFD controls fan speed electrically by using
a static controllable rectifier (thyristor) to control frequency and
voltage and, thereby, the fan speed. The VFD enables very precise and
accurate speed control with an almost instantaneous response to control
signals. The VFD controller enables highly efficient fan performance at
almost all percentages of flow turndown.
    Due to current electricity market conditions, many units no longer
operate at base-load capacity and, therefore, VFDs, also known as
variable-speed drives on fans can greatly enhance plant performance at
off-peak loads. Additionally, because utilities are phasing in their
environmental equipment upgrades, new fans are oversized and operated
at lower capacities until all additional equipment has been added.
Under these scenarios, VFDs can significantly improve the unit heat
rate. VFDs as motor controllers offer many substantial improvements to
electric motor power requirements. The drives provide benefits such as
soft starts, which reduce initial electrical load, excessive torque,
and subsequent equipment wear during startups; provide precise speed
control; and enable high-efficiency operation of motors at less than
the maximum efficiency point. During load turndown, plant auxiliary
power could

be reduced by 30-60 percent if all large motors in a plant were
efficiently controlled by VFD. With unit loads varying throughout the
year, the benefits of using VFDs on large-size equipment, such as FD or
ID fans, boiler feedwater and condenser circulation water pumps, can
have significant impacts. Because plants today usually use either new
booster ID fans or new ID fans, the option of investing in VFDs
generally appeals to plant operators since they are incurring long
outages to install the either new or additional air emission controls
equipment. There are circumstances in which the HRI has been estimated
to be much higher than that shown in Table 1, depending on the
operation of the unit. Cycling units realize the greatest gains
representative of the upper range of HRI, whereas units which were
designed with excess fan capacity will exhibit the lower range.
    VFD on Boiler Feed Pumps. VFDs can also be used on boiler feed
water pumps as mentioned previously. Generally, if a unit with an older
steam turbine is rated below 350 MW the use of motor-driven boiler
feedwater pumps as the main drivers may be considered practical from an
efficiency standpoint. If a unit cycles frequently then operation of
the pumps with VFDs will offer the best results on heat rate
reductions, followed by fluid couplings. The use of VFDs for boiler
feed pumps is becoming more common in the industry for larger units.
And with the advancements in low pressure steam turbines, a motor-
driven feed pump can improve the thermal performance of a system up to
the 600-MW range, as compared to the performance associated with the
use of turbine drive pumps. Smaller and older units will generally not
upgrade to a VFD boiler feed pump drive due to high capital costs.
e. Blade Path Upgrade (Steam Turbine)
    Upgrades or overhauls of steam turbines offer the greatest
opportunity for HRI on many units. Significant increases in performance
can be gained from turbine upgrades when plants experience problems
such as steam leakages or blade erosion. The typical turbine upgrade
depends on the history of the turbine itself and its overall
performance. The upgrade can entail myriad improvements, all of which
affect the performance and associated costs. The availability of
advanced design tools, such as computational fluid dynamics (CFD),
coupled with improved materials of construction and machining and
fabrication capabilities have significantly enhanced the efficiency of
modern turbines. These improvements in new turbines can also be
utilized to improve the efficiency of older steam turbines whose
efficiency has degraded over time. Upgrades or overhauls of steam
turbines may offer the greatest opportunity for HRI on many units.
Significant increases in performance can be gained from turbine
upgrades when plants experience problems such as steam leakages or
blade erosion. The typical turbine upgrade depends on the history of
the turbine itself and its overall performance. The upgrade can entail
myriad improvements, all of which affect the performance and associated
costs.
f. Redesign/Replace Economizer
    In steam power plants, economizers are heat exchange devices used
to capture waste heat from boiler flue gas which is then used to heat
the boiler feedwater. This use of waste heat reduces the need to use
extracted energy from the system and, therefore, improves the overall
efficiency or heat rate of the unit. As with most other heat transfer
devices, the performance of the economizer will degrade with time and
use, and power plant representatives contend that economizer
replacements are often delayed or avoided due to concerns about
triggering NSR requirements. In some cases, economizer replacement
projects have been undertaken concurrently with retrofit installation
of selective catalytic reduction (SCR) systems because the entrance
temperature for the SCR unit must be controlled to a specific range.
2. Potential HRI Measures--Best Operating and Maintenance Practices
    Many unit operators can achieve additional HRI by adopting best
operating and maintenance practices. The amount of achievable HRI will
vary significantly from unit to unit. In setting a standard of
performance for a specific unit or subcategory of units, states should
consider the opportunities for HRI from the following actions.
a. Adopt HRI Training for O&M Staff
    EGU operators can obtain HRI by adopting ``awareness training'' to
ensure that all O&M staff are aware of best practices and how those
practices affect the unit's heat rate.
b. Perform On-Site Appraisals To Identify Areas for Improved Heat Rate
Performance
    Some large utilities have internal groups that can perform on-site
evaluations of heat rate performance improvement opportunities. Outside
(i.e., third party) groups can also provide site-specific/unit-specific
evaluations to identify opportunities for HRI.
c. Improved Steam Surface Condenser--Cleaning
    Effective operation of the steam surface condenser in a power plant
can significantly improve a unit's heat rate. In fact, in many cases it
can pose the most significant hindrance to a plant trying to maintain
its original design heat rate. Since the primary function of the
condenser is to condense steam flowing from the last stage of the steam
turbine to liquid form, it is most desirable from a thermodynamic
standpoint that this occurs at the lowest temperature reasonably
feasible. By lowering the condensing temperature, the backpressure on
the turbine is lowered, which improves turbine performance.
    Condenser Cleaning. A condenser degrades primarily due to fouling
of the tubes and air in-leakage. Tube fouling leads to reduced heat
transfer rates, while air in-leakage directly increases the
backpressure of the condenser and degrades the quality of the water.
Condenser tube cleaning can be performed using either on-line methods
or more rigorous off-line methods. A full economic analysis should be
performed to determine which off-line cleaning method is to be used.
Such an analysis would result in an optimum offline or reduced-load
cleaning schedule that could average between two and three cleanings a
year. These analyses consider inputs such as operating data, plant
performance, loads, time of year, etc., to accurately assess cleaning
schedules for optimum economic performance.
3. Cost of HRI
a. Reasonableness of Cost
    As mentioned earlier, under CAA section 111(a)(1), EPA is required
to determine ``the best system of emission reduction which (taking into
account the cost . . .) . . . has been adequately demonstrated.'' In
several cases, the D.C. Circuit has elaborated on this cost factor in
various ways, stating that EPA may not adopt a standard for which costs
would be ``exorbitant,'' \20\ ``greater than the industry could bear
and survive,'' \21\ ``excessive,'' \22\ or ``unreasonable.'' \23\ These
formulations appear to be synonymous and suggest a cost-reasonableness
standard. Therefore, in this action, EPA has evaluated

whether the costs of HRI are considered to be reasonable.
---------------------------------------------------------------------------

    \20\ Lignite Energy, 198 F.3d at 933.
    \21\ Portland Cement, 513 F.2d at 508.
    \22\ Sierra Club, 657 F.2d at 343.
    \23\ Id.
---------------------------------------------------------------------------

    Any efficiency improvement made by an EGU will also reduce the
amount of fuel consumed per unit of electricity output; fuel costs can
account for as much as 70 percent of production costs of power. The
cost attributable to CO2 emission reductions, therefore, is
the net cost of achieving HRIs after any savings from reduced fuel
expenses. So, over some time period (depending upon, among other
factors, the extent of HRIs, the cost to implement such improvements,
and the unit utilization rate), the savings in fuel cost associated
with HRIs may be sufficient to cover the costs of implementing the HRI
measures. Thus, the net costs of HRIs associated with reducing
CO2 emissions from affected EGUs can be relatively low
depending upon each EGUs' individual circumstances. It should be noted
that this cost evaluation is not an attempt to determine the
affordability of the HRI in a business or economic sense (i.e., the
reasonableness of the imposed cost is not determined by whether there
is an economic payback within a predefined time period). However, the
ability of EGUs to recoup some of the costs of HRIs through fuel
savings supports a finding that cost recovery is a reasonable factor in
determining cost effectiveness.\24\
---------------------------------------------------------------------------

    \24\ While some EGUs may not realize the full potential of cost
recuperation from fuel savings, we expect that the net costs of
implementing heat rate improvements as an approach to reducing
CO2 emissions from fossil fuel-fired EGUs are reasonable.
---------------------------------------------------------------------------

    Most often, when evaluating costs for criteria pollutants--in a
BACT analysis, for example--the emphasis is focused on the cost of
control relative to the amount of pollutant removed--a metric typically
referred to as the ``cost-effectiveness.'' There have been relatively
few BACT analyses evaluating GHG reduction technologies for coal-fired
EGUs; and, therefore not a large number of GHG cost-effectiveness
determinations to compare against as a measure of the cost
reasonableness. Nevertheless, in PSD and Title V permitting guidance
for GHG emissions, EPA noted that ``it is important in BACT reviews for
permitting authorities to consider options that improve the overall
energy efficiency of the source or modification--through technologies,
processes and practices at the emitting unit. In general, a more energy
efficient technology burns less fuel than a less energy efficient
technology on a per unit of output basis.'' \25\ EPA has also noted
that a ``number of energy efficiency technologies are available for
application to both existing and new coal-fired EGU projects that can
provide incremental step improvements to the overall thermal
efficiency.'' \26\
---------------------------------------------------------------------------

    \25\ See page 21, ``PSD and Title V Permitting Guidance for
Greenhouse Gases,'' EPA-457/B-11-001, March 2011; https://www.epa.gov/sites/production/files/2015-12/documents/ghgpermittingguidance.pdf.
    \26\ See page 25, ``Available and Emerging Technologies for
Reducing Greenhouse Gas Emissions from Coal-fired Electric
Generating Units,'' October 2010; https://www.epa.gov/sites/production/files/2015-12/documents/electricgeneration.pdf.
---------------------------------------------------------------------------

b. Cost of the HRI Candidate Technologies Measures
    The estimated costs for the BSER candidate technologies are
presented below in Table 2. These are cost ranges from the 2009 S&L
Study \27\ updated to $2016. These costs correspond to ranges of HRI
(percent) presented earlier in Table 1.
---------------------------------------------------------------------------

    \27\ ``Coal-Fired Power Plant Heat Rate Reductions'' Sargent &
Lundy report SL-009597 (2009) https://www.epa.gov/sites/production/files/2015-08/documents/coalfired.pdf.

                                                   Table 2--Summary of Cost ($2016/kW) of HRI Measures
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      <200 MW                       200-500 MW                        >500 MW
                       HRI measure                       -----------------------------------------------------------------------------------------------
                                                                Min             Max             Min             Max             Min             Max
--------------------------------------------------------------------------------------------------------------------------------------------------------
Neural Network/Intelligent Sootblowers..................             4.7             4.7             2.5             2.5             1.4             1.4
Boiler Feed Pumps.......................................             1.4             2.0             1.1             1.3             0.9             1.0
Air Heater & Duct Leakage Control.......................             3.6             4.7             2.5             2.7             2.1             2.4
Variable Frequency Drives...............................             9.1            11.9             7.2             9.4             6.6             7.9
Blade Path Upgrade (Steam Turbine)......................            11.2            66.9             8.9            44.6             6.2            31.0
Redesign/Replace Economizer.............................            13.1            18.7            10.5            12.7            10.0            11.2
                                                         -----------------------------------------------------------------------------------------------
Improved O&M Practices..................................                                       Minimal capital cost.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    In the CPP, EPA estimated the potential national average net HRI by
coal-fired EGUs to between 2.1 to 4.3 percent for each interconnection,
or about 4 percent nationally, with the improvements coming from some
combination of best operating practices and equipment upgrades. The
Agency noted in the CPP that the maximum cost of HRI from Table 2 is
expected to be less than the $100/kW value used in the CPP proposal,
especially as the EGU size increases; and, therefore, the Agency
assessed the economic effects of HRI costs that might range from $50 to
$100/kW. The technical applicability and efficacy of HRI measures and
the cost of implementing them are dependent upon site specific factors
and can vary widely from site to site. Because there is inherent
flexibility provided to the states in applying the standards of
performance, there is a wide range of potential outcomes that are
highly dependent upon how the standards are applied (and to what degree
states take into consideration other factors, including remaining
useful life).
    In the RIA accompanying this proposal, the Agency evaluates three
illustrative scenarios that recognize the inherent flexibility provided
to states in applying standards of performance and provide insight on
potential outcomes. For those illustrative scenarios, EPA evaluates
costs ranging from $50/kW to $100/kW. EPA requests comment, with
analysis, on other cost ranges that may be appropriate.
4. Nonair Quality Health and Environmental Impacts, Energy
Requirements, and Other Considerations
    As directed by CAA section 111(a)(1), EPA has taken into account
nonair quality health and environment requirements, and energy
requirements for each of the candidate BSER technologies listed in
Tables 1 and 2. None of the candidate technologies, if implemented at a
coal-fired EGU, would be expected to result in any deleterious effects
on any of the liquid effluents (e.g., scrubber liquor) or solid by-
products (e.g., ash, scrubber solids). All of these candidate
technologies, when

implemented, would have the effect of improving the efficiency of the
coal-fired EGUs to which they are applied. As such, the EGU would be
expected to use less fuel to produce the same amount of electricity as
it did prior to the efficiency (heat rate) improvement. None of
candidate technologies is expected to impose any significant additional
auxiliary energy demand.
    Implementation of heat rate improvement measures also would achieve
reasonable reductions in CO2 emissions from affected sources
in light of the limited cost-effective and technically feasible
emissions control opportunities. In the same vein, because existing
sources face inherent constraints that new sources do not, existing
sources present different, and in some ways more limited, opportunities
for technological innovation or development. Nevertheless, the proposed
emissions guidelines encourage technological development by promoting
further development and market penetration of equipment upgrades and
process changes that improve plant efficiency.
5. Potential HRI at Existing Coal-Fired EGUs
    Government agencies and laboratories, industry research
organizations, engineering firms, equipment suppliers, and
environmental organizations have conducted studies examining the
potential for improving heat rate in the U.S. EGU fleet or a subset of
the fleet. Table 3 below provides a list of some reports, case studies,
and analyses about HRI opportunities in the United States. EPA is
seeking comment on how these studies (and any others that the Agency
should be aware of) can inform our understanding of potential HRI
opportunities (Comment C-8).

            Table 3--HRI Reports, Case Studies, and Analyses
------------------------------------------------------------------------

-------------------------------------------------------------------------
   HRI report organization/publication (author, if known)--title--year
                                  [URL]
------------------------------------------------------------------------
Government Studies:
    Congressional Research Service (Campbell)--Increasing the Efficiency
     of Existing Coal-fired Power Plants (R43343)--2013 [https://fas.org/sgp/crs/misc/R43343.pdf].
    EIA--Analysis of Heat Rate Improvement Potential at Coal-Fired Power
     Plants--2015 [https://www.eia.gov/analysis/studies/powerplants/heatrate/pdf/heatrate.pdf].
    EPA--Greenhouse Gas Mitigation Measures--2015 [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-37114].
    NETL--Opportunities to Improve the Efficiency of Existing Coal-fired
     Power Plants--2009 [http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/OpportImproveEfficExistCFPP-ReportFinal.pdf].
    NETL--Improving the Thermal Efficiency of Coal-Fired Power Plants in
     the United States--2010 [http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/ThermalEfficCoalFiredPowerPlants-TechWorkshopRpt.pdf].
    NETL--Improving the Efficiency of Coal-Fired Power Plants for Near
     Term Greenhouse Gas Emissions Reductions (DOE/NETL-2010/1411)--2010
     [http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/DOE-NETL-2010-1411-ImpEfficCFPPGHGRdctns-0410.pdf].
    NETL--Options for Improving the Efficiency of Existing Coal-Fired
     Power Plants (DOE/NETL-2013/1611)--2014 [https://www.netl.doe.gov/energy-analyses/temp/FY14_OptionsforImprovingtheEfficiencyofExistingCoalFiredPowerPlants_040114.pdf].
    IEA (Reid)--Retrofitting Lignite Plants to Improve Efficiency and
     Performance (CCC/264)--2016 [http://bookshop.iea-coal.org/reports/ccc-264/83861].
    IEA (Henderson)--Upgrading and Efficiency Improvement in Coal-fired
     Power Plants (CCC/221)--2013 [http://bookshop.iea-coal.org/reports/ccc-221/83186].
    European Commission--Integrated Pollution Prevention and Control
     Reference Document on Best Available Techniques for Large
    Combustion Plants--2006 [http://eippcb.jrc.ec.europa.eu/reference/BREF/lcp_bref_0706.pdf].
Industry/Industrial Groups:
    EPRI--Range of Applicability of Heat Rate Improvements--2014 [https://www.epri.com/#/pages/product/000000003002003457].
    ABB Power Generation--Energy Efficient Design of Auxiliary Systems
     in Fossil-Fuel Power Plants [https://library.e.abb.com/public/5e627b842a63d389c1257b2f002c7e77/Energy%20Efficiency%20for%20Power%20Plant%20Auxiliaries-V2_0.pdf].
    Alstom Engineering (Sutton)--CO2 Reduction Through Energy Efficiency
     in Coal-Fired Boilers--2011 [http://www.mcilvainecompany.com/Universal_Power/Subscriber/PowerDescriptionLinks/Jim%20Sutton%20-%20Alstom%20-%203-31-2011.pdf].
    GE--Comments of the General Electric Company--2014 [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-22971].
    National Petroleum Council--Electric Generation Efficiency--2007
     [http://www.npc.org/Study_Topic_Papers/4-DTG-ElectricEfficiency.pdf].
    S&L--Coal-fired Power Plant Heat Rate Reductions (SL-009597)--2009
     [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-36895 36895].
    S&L--Coal Fired Power Plant Heat Rate Reduction--NRECA (SL-012541)--
     2014 [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-22767 22767 Supp 33].
    Storm Technologies--Applying the Fundamentals for Best Heat Rate
     Performance of Pulverized Coal Fueled Boilers--2009 [http://www.stormeng.com/pdf/EPRI2009HeatRateConference%20FINAL.pdf].
Environmental Groups/Academic Studies:
    Lehigh University--Reducing Heat Rates of Coal-fired Power Plants--
     2009 [http://www.lehigh.edu/~inenr/leu/leu_61.pdf].
    NRDC--Closing the Power Plant Carbon Pollution Loophole: Smart Ways
     the Clean Air Act Can Clean Up America's Biggest Climate
    Polluters (12-11-A)--2013 [https://www.nrdc.org/sites/default/files/pollution-standards-report.pdf].
    Resources for the Future (Lin et al.)--Regulating Greenhouse Gases
     from Coal Power Plants Under the Clean Air Act (RFF-DP-13-05)--2014
     [http://www.rff.org/files/sharepoint/WorkImages/Download/RFF-DP-13-05.pdf].
    Sierra Club (Buckheit & Spiegel)--Sierra Club 52 Unit Study--2014
     [http://content.sierraclub.org/environmentallaw/sites/content.sierraclub.org.environmentallaw/files/Appendix%201%20-%20Rate%20v%20Load%20Summary.pdf].
Other Publications:
    Power Engineering International (CoX)--Dry Sorbent Injection for SOX
     Emissions Control--2017 [http://www.powerengineeringint.com/articles/print/volume-25/issue-6/features/dry-sorbent-injection-for-sox-emissions-control.html].
    Power Mag (Korellis)--Coal-Fired Power Plant Heat Rate Improvement
     Options, Parts 1 & 2--2014 [http://www.powermag.com/coal-fired-power-plant-heat-rate-improvement-options-part-2] [http://www.powermag.com/coal-fired-power-plant-heat-rate-improvement-options-part-1].
    Power Mag (Peltier)--Steam Turbine Upgrading: Low-hanging Fruit--
     2006 [http://www.powermag.com/steam-turbine-upgrading-low-hanging-fruit fruit].
------------------------------------------------------------------------

    It has been noted that unit-level HRIs, with the resulting
reductions in variable operating costs at those improved EGUs, could
lead to increases in utilization of those EGUs as compared to other
generating options (i.e., ``rebound effect''). See generally 80 FR
64745.
    As part of the cost-benefit analysis in the RIA for this proposed
action, EPA modeled a range of potential HRIs (percent improvement, as
described in the RIA). The results of the modeling, for the years of
analysis for this rule, predict that there will be no cumulative
increases in system-wide emissions relative to a scenario where no
action is taken. While the RIA shows that, under certain assumptions,
sources that adopt HRI may increase generation, due to their improved
efficiency and relatively improved economic competitiveness, they also
generally reduce emissions (as a group) because they can generate
higher levels of electricity with a lower overall emission rate. Hence,
EPA analysis indicates that the system-wide emission decreases due to
reduced heat rate are likely to be larger than any system-wide
increases due to increased operation. EPA solicits comment on this
conclusion (Comment C-9).

C. HRI for Natural Gas-Fired Stationary Combustion Turbines

    EPA has also considered opportunities for emission reductions at
natural gas-fired stationary combustion turbines as a part of the
BSER--at both simple cycle turbines and combined cycle turbines--and
previously determined that the available emission reductions would
likely be expensive or would likely provide only small overall
reductions relative to those that were predicted through application of
other systems of emission reduction identified in the CPP building
blocks. In the development of the CAA section 111(b) standards of
performance for new, modified, and reconstructed EGUs, several
commenters provided information on options that may be available to
improve the efficiency of existing natural gas-fired stationary
combustion turbines. See 80 FR 64620. Commenters--including turbine
manufacturers--described specific technology upgrades for the
compressor, combustor, and gas turbine components that operators of
existing combustion turbines may deploy. The commenters noted that
these state-of-the-art gas path upgrades, software upgrades, and
combustor upgrades have the potential to reduce GHG emissions by a
significant amount. In addition, one turbine manufacturer stated that
existing combustion turbines can achieve the largest efficiency
improvements by upgrading existing compressors with more advanced
compressor technologies, potentially improving the combustion turbine's
efficiency by an additional margin. See 80 FR 64620.
    In addition to upgrades to the combustion turbine, the operator of
a NGCC unit may have the opportunity to improve the efficiency of the
heat recovery steam generator and steam cycle using retrofit
technologies that may reduce the GHG emissions by 1.5 to 3 percent.
These include: (1) Steam path upgrades that can minimize aerodynamic
and steam leakage losses; (2) replacement of the existing high-pressure
turbine stages with state-of-the-art stages capable of extracting more
energy from the same steam supply; and (3) replacement of low-pressure
turbine stages with larger diameter components that extract additional
energy and that reduce velocities, wear, and corrosion.
    In the ANPRM, EPA requested comment on the broad availability and
applicability of any HRIs for natural gas combustion turbine EGUs. EPA
also solicited comment on the Agency's previous determination in the
CPP that the available GHG emission reduction opportunities would
likely provide only small overall GHG reductions as compared to those
from HRIs at existing coal-fired EGUs. See 80 FR 64756.
    Several commenters suggested that there are significant
opportunities for emission reductions via HRIs at natural gas combined
cycle EGUs while many other commenters contended that any such emission
reductions would be minimal and too expensive. Still, other commenters
noted that operational changes--such as lower capacity factor or
fluctuations in load (cycling)--affect the heat rate and make it
difficult to accurately gauge the availability of HRI opportunities for
NGCC EGUs.
    However, while numerous comments suggested that there are available
HRI opportunities at existing NGCC EGUs, no commenters provided
specific information on the availability, applicability, or cost of HRI
opportunities for NGCC units--nor did any commenters provide any
information on the magnitude of expected heat rate reductions.
    To assess potential HRI of existing NGCC EGUs, EPA looked at 11
years of historical gross heat rate data from 2007 to 2017 for existing
NGCC EGUs that reported both heat input and gross electricity output to
the Agency in 2017. The Agency used the 2007 to 2016 data to calculate
a ``benchmark'' heat rate for each unit. EPA evaluated the HRI
potential using an approach that is similar to the method used to
determine a unit-specific standard that was finalized for modified
coal-fired EGUs. The Agency evaluated the HRI potential by comparing
the 2017 national annual heat rate with the best annual heat rate in
the years from 2007 to 2016 year. The HRI potential was calculated
nationally and at each regional interconnection: East, West, and Texas.
Nationally the HRI evaluation suggested an average HRI potential of 3.4
percent.
    EPA also conducted a literature search and found some papers
suggesting potential for improvement in the heat rate. The literature
suggested that most HRIs would be accompanied by commensurate capacity
increases.\28\ EPA takes comment on the estimates in this paper and is
seeking any other information commenters have about the performance and
cost of potential HRIs for turbines (Comment C-10). We also take
comment on whether if EPA determined that HRIs in that range were
available for similar costs, it would be appropriate for EPA to
reconsider its determination that there are no HRIs that represent the
BSER (Comment C-11).
---------------------------------------------------------------------------

    \28\ Phillips, J.; Levine, P.; ``Gas Turbine Performance Upgrade
Options'', FERN Engineering Paper, available at http://www.fernengineering.com/pdf/gt_upgrade_options.pdf.
---------------------------------------------------------------------------

D. Other Considered Systems of GHG Emission Reductions

    EPA also considered other systems of GHG emission reductions that
may be applied to affected EGUs but is not proposing that they should
be part of the BSER for the reasons discussed below. EPA acknowledges
that there may be other methods and technologies suitable for adoption
at some specific sources, but states and sources are best suited to
determine if those alternative measures and technologies are
appropriate and/or allowable compliance measures.
1. Carbon Capture and Storage (CCS) \29\
    EPA has previously determined that CCS (or partial CCS) should not
be a part of the BSER for existing fossil fuel-fired EGUs because it
was significantly more expensive than alternative options for reducing
emissions and may not be a viable option for many individual
facilities. See 80 FR 64756. Even assuming that CAA section 111(d) may
be used to project technological

advances, EPA must balance innovative technologies against their
economic, energy, nonair health and environmental impacts. EPA
continues to believe that neither CCS nor partial CCS are technologies
that can be considered the BSER for existing fossil fuel-fired EGUs.
However, if there is any new information regarding the availability,
applicability, costs, or technical feasibility of CCS technologies,
commenters are encouraged to provide that information to EPA (Comment
C-12).
---------------------------------------------------------------------------

    \29\ CCS is sometimes referred to as Carbon Capture and
Sequestration. It is also sometimes referred to as CCUS or Carbon
Capture Utilization and Storage (or Sequestration), where the
captured CO2 is utilized in some useful way and/or
permanently stored (for example, in conjunction with enhanced oil
recovery). In this document, we consider these terms to be
interchangeable and for convenience will exclusively use the term
CCS.
---------------------------------------------------------------------------

    Similarly, EPA considered whether CCS or partial CCS should be the
BSER for natural gas-fired stationary combustion turbines and have
determined that, currently, the technology is exorbitantly expensive,
has not been adequately demonstrated, and would not be available for a
large number of existing sources. Similar technologies--such as use of
the novel Allam Cycle \30\--are, while seemingly promising, still in
the early demonstration phase.
---------------------------------------------------------------------------

    \30\ https://www.netpower.com/.
---------------------------------------------------------------------------

2. Fuel Co-Firing
    EPA has previously determined that co-firing of alternative fuels
(biomass or natural gas) in coal-fired utility boilers is not part of
BSER for existing fossil fuel-fired sources due to cost and feasibility
considerations. See 80 FR 64756. Although some fuel co-firing methods
are technically feasible for some affected sources, there are factors
and considerations that prevent its inclusion as BSER. In general, fuel
use opportunities are dependent upon many regional considerations and
characteristics (e.g., access to biomass, or natural gas pipeline
infrastructure limitations), that prevent its adoption as BSER on a
national level (whereas nearly all sources can or have implemented some
form of heat rate improvement measures). Another important factor is
cost, and broader application of fuel co-firing methods has been shown
to be costly. While this proposal does not include fuel co-firing
methods as BSER, EPA proposes that they be allowed as compliance