[Federal Register Volume 83, Number 244 (Thursday, December 20, 2018)]
[Proposed Rules]
[Pages 65424-65464]
[FR Doc No: 2018-27052]

Vol. 83

Thursday,

No. 244

December 20, 2018

Part III

Environmental Protection Agency

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40 CFR Part 60

Review of Standards of Performance for Greenhouse Gas Emissions From
New, Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units; Proposed Rule

Federal Register / Vol. 83 , No. 244 / Thursday, December 20, 2018 /
Proposed Rules

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2013-0495; FRL-9987-85-OAR]
RIN 2060-AT56

Review of Standards of Performance for Greenhouse Gas Emissions
From New, Modified, and Reconstructed Stationary Sources: Electric
Utility Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: The Environmental Protection Agency (EPA) is proposing
amendments to the rulemaking titled ``Standards of Performance for
Greenhouse Gas Emissions from New, Modified, and Reconstructed
Stationary Sources: Electric Utility Generating Units (EGUs),'' which
the EPA promulgated by notice dated October 23, 2015 (i.e., the 2015
Rule). Specifically, the EPA proposes to amend its previous
determination that the best system of emission reduction (BSER) for
newly constructed coal-fired steam generating units (i.e., EGUs) is
partial carbon capture and storage (CCS). Instead, the EPA proposes to
find that the BSER for this source category is the most efficient
demonstrated steam cycle (e.g., supercritical steam conditions for
large units and subcritical steam conditions for small units) in
combination with the best operating practices. The EPA proposes to
revise the standard of performance for newly constructed steam
generating units as separate standards of performance for large and
small steam generating units that reflect the Agency's amended BSER
determination. In addition, the EPA proposes to revise the standard of
performance for reconstructed steam generating units to be separate
standards of performance for reconstructed large and small steam
generating units, consistent with the proposed revised standards for
newly constructed steam generating units. The EPA also proposes
separate standards of performance for newly constructed and
reconstructed coal refuse-fired EGUs. In addition, the EPA proposes to
revise the maximally stringent standards for large modifications of
steam generating units to be consistent with the standards for
reconstructed large and small steam generating units. The EPA is not
proposing to amend and is not reopening the standards of performance
for newly constructed or reconstructed stationary combustion turbines.
The EPA is also proposing to make other miscellaneous technical changes
in the regulatory requirements.

DATES: Comments. Comments must be received on or before February 19,
2019.
    Public Hearing. The 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 notice.

ADDRESSES: Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2013-0495, 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 the EPA treats submitted comments.
Regulations.gov is our preferred method of receiving comments. However,
other submission methods are accepted:
     Email<EMAIL_ADDRESS>Include Docket ID No. EPA-
HQ-OAR-2013-0495 in the subject line of the message.
     Fax:<PHONE_NUMBER>. Attention Docket ID No. EPA-HQ-OAR-
2013-0495.
     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-2013-0495, 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. Christian Fellner, 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_ADDRESS>    For information about the applicability of the new source
performance standards (NSPS) to a particular entity, contact Sara
Ayres, U.S. Environmental Protection Agency, Region 5, 77 West Jackson
Boulevard (Mail Code E-19J), Chicago, Illinois 60604-3507; telephone
number<PHONE_NUMBER>; and email address<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:
    Docket. The EPA has established a docket for this rulemaking under
Docket ID No. EPA-HQ-OAR-2013-0495. 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-
2013-0495. The 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.
    The 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. The EPA
will generally not consider comments or comment contents located
outside of the primary submission (i.e., on the Web, cloud, or other
file sharing system). 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 the EPA will not know your identity
or contact information unless you provide it in the body of your
comment. If you send an email comment directly to the EPA without going
through https://www.regulations.gov, your email address will be
automatically captured and included as part of the comment that is
placed in the public docket and made available on the internet. If you
submit an electronic comment, the EPA recommends that you include your
name and other contact information in the body of your comment and with
any digital storage media you submit. If the EPA cannot read your
comment due to technical difficulties and cannot contact you for
clarification, the EPA may not be able to consider your comment.
Electronic files should not include special characters or any form of
encryption and be free of any defects or viruses. For additional
information about the EPA's public docket, visit the EPA Docket Center
homepage at https://www.epa.gov/dockets.
    The EPA is soliciting comment on numerous aspects of the proposed
rule. The EPA has indexed each comment solicitation with an alpha-
numeric identifier (e.g., ``C-1,'' ``C-2,'' ''C-3,'' . . .) to provide
a consistent framework for effective and efficient provision of
comments. Accordingly, the EPA asks that commenters include the
corresponding identifier when providing comments relevant to that
comment solicitation. The EPA asks 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. The EPA emphasizes
that the Agency is not limiting comment to these identified areas and
encourage provision of any other comments relevant to this proposal.\1\
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    \1\ In this proposal, in some instances, the EPA identifies an
issue that the Agency has previously addressed, and states that the
Agency is not re-opening that issue in this proposal. The EPA will
not consider such an issue as relevant to this proposal.
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    Submitting CBI. Do not submit information containing CBI to the EPA
through https://www.regulations.gov or email. Clearly mark the
information that you claim to be CBI. For CBI information on any
digital storage media that you mail to the 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-2013-0495.
    Preamble Acronyms and Abbreviations. The EPA uses multiple acronyms
and terms in this preamble. While this list may not be exhaustive, to
ease the reading of this preamble and for reference purposes, the EPA
defines the following terms and acronyms here:

AEO Annual Energy Outlook
BACT best available control technology
BSER best system of emission reduction
Btu/kWh British thermal units per kilowatt-hour
Btu/lb British thermal units per pound
[deg]C degrees Celsius
CAA Clean Air Act
CAAA Clean Air Act Amendments
CAMD Clean Air Markets Division
CBI confidential business information
CBO Congressional Budget Office
CCS carbon capture and storage (or sequestration)
CEMS continuous emissions monitoring system
CFB circulating fluidized bed
CFR Code of Federal Regulations
CH4 methane
CHP combined heat and power
CO carbon monoxide
CO2 carbon dioxide
CSP concentrated solar power
DC District of Columbia
D.C. Circuit United States Court of Appeals for the District of
Columbia Circuit
DOE Department of Energy
ECMPS emissions collection and monitoring plan system
EGU electric utility generating unit
EIA U.S. Energy Information Administration
EOR enhanced oil recovery
EPA Environmental Protection Agency
[deg]F degrees Fahrenheit
FB fluidized bed
FGD flue gas desulfurization
FLGRTM fuel lean gas reburning
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GJ/h gigajoules per hour
GPM gallons per minute
GS geologic sequestration
GW gigawatts
H2 hydrogen gas
HAP hazardous air pollutant(s)
HFC hydrofluorocarbon
Hg mercury
HRSG heat recovery steam generator
ICR information collection request
IGCC integrated gasification combined cycle
IRPs Integrated Resource Plans
km kilometers
lb CO2/MMBtu pounds of CO2 per million British
thermal units
lb CO2/MWh pounds of CO2 per megawatt-hour
lb CO2/MWh-gross pounds of CO2 per megawatt-
hour on a gross output basis
lb CO2/MWh-net pounds of CO2 per megawatt-hour
on a net output basis
LCOE levelized cost of electricity
M million
MMBtu/h million British thermal units per hour
MPa megapascals
MW megawatts
MWh megawatt-hours
MWnet megawatts-net
N2 molecular nitrogen
N2O nitrous oxide
NAAQS national ambient air quality standards
NAICS North American Industry Classification System
NETL National Energy Technology Laboratory
NGCC natural gas combined cycle
NGR natural gas reburning
NOX nitrogen oxides
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
O&M operation and maintenance
OAQPS Office of Air Quality Planning and Standards
OFA overfire air
OMB Office of Management and Budget
PC pulverized coal
PFC perfluorocarbon
PM particulate matter
PRA Paperwork Reduction Act
PSD Prevention of Significant Deterioration
psi pounds per square inch
psig pounds per square inch gauge
QA quality assurance
RCRA Resource Conservation and Recovery Act
RFA Regulatory Flexibility Act
SBA Small Business Administration
SCCFB supercritical circulating fluidized bed
SCE&G South Carolina Electric and Gas
SCPC supercritical pulverized coal
SCR selective catalytic reduction
SF6 sulfur hexafluoride
SO2 sulfur dioxide
SSM startup, shutdown, and malfunction
T&S transmission and storage
TSD technical support document
UAMPS Utah Associated Municipal Power Systems
[micro]g/m\3\ micrograms per cubic meter
UMRA Unfunded Mandates Reform Act of 1995

U.S. United States
U.S.C. United States Code
VCS voluntary consensus standard

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

I. General Information
    A. Executive Summary
    B. Types of Sources
    C. The 2015 Rulemaking, Reconsideration, and Litigation
    D. The Purpose of This Regulatory Action
    E. Does this action apply to me?
    F. Where can I get a copy of this document and other related
information?
II. Proposed Requirements for New, Reconstructed, and Modified
Sources
    A. Applicability Requirements
    B. Emission Standards
III. Legal Authority
    A. Statutory Background
    B. Authority To Revise Existing Regulations
    C. Authority To Regulate CO2 From Fossil Fuel-Fired
EGUs
IV. Rationale for Proposed Applicability Criteria
V. Rationale for Proposed Emission Standards for New and
Reconstructed Fossil Fuel-Fired Steam Generating Units
    A. Review of the 2015 BSER Analysis
    B. Identification of the Revised BSER
    C. Reconstructed EGUs
    D. Coal Refuse Subcategory
    E. Determination of the Level of the Standard
    F. Format of the Output-Based Standard
VI. Rationale for Proposed Emission Standards for Modified Fossil
Fuel-Fired Steam Generating Units
    A. Identification of the BSER
    B. Determination of the Level of the Standard
VII. Interactions With Other EPA Programs and Rules
VIII. Summary of Cost, Environmental, and Economic 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 benefits of the proposed standards?
IX. Request for Comments
    A. Subcategorization by Fuel Type
    B. Low Duty Cycle Subcategory
    C. Commercial Demonstration Permit
    D. Applicability to Industrial EGUs
    E. Non-Sequestration of Captured Carbon
    F. Additional Amendments
    G. Non-Base Load Combustion Turbines
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

1. Proposed Revisions to the 2015 Rulemaking
    The EPA is revisiting several portions of the Standards of
Performance for Greenhouse Gas Emissions from New, Modified, and
Reconstructed Stationary Sources: Electric Utility Generating Units
(EGUs), which was promulgated on October 23, 2015 (80 FR 64510). First,
for newly constructed fossil fuel-fired electric utility steam
generating units that are either utility boilers or integrated
gasification combined cycle (IGCC) units, the EPA proposes to revise
the BSER to be the most efficient demonstrated steam cycle (i.e.,
supercritical steam conditions for large EGUs and best available
subcritical steam conditions for small EGUs) \2\ in combination with
the best operating practices, instead of partial CCS. The primary
reason for this proposed revision is the high costs and limited
geographic availability of CCS. Based on the proposed revisions to the
BSER, the EPA is proposing to establish revised (i.e., higher) emission
rates as the standards of performance for large and small EGUs (See
Table 1). Further, for EGUs that undertake a reconstruction, because
the standards for reconstructed EGUs are also based on best available
efficiency technology, the EPA is proposing to revise those standards
to consist of higher emission rates for large and small EGUs to be
consistent with the standards for newly constructed EGUs (See Table 1).
The EPA also proposes separate standards of performance for newly
constructed and reconstructed coal refuse-fired EGUs (See Table 1). In
addition, while the EPA is not proposing to revise the BSER identified
in the 2015 Rule (which is based on the individual EGU's best
demonstrated performance) for fossil fuel-fired electric utility steam
generating units that undertake large modifications \3\ (i.e.,
modifications that result in an increase in hourly emissions of more
than 10 percent), the EPA proposes to revise the maximally stringent
standards \4\ (that is, the level that is the most stringent that the
standard can be) to be consistent with the proposed revised standards
for new and reconstructed EGUs (See Table 1). Additionally, the EPA
proposes minor amendments to the applicability criteria for combined
heat and power (CHP) and non-fossil EGUs to reflect the original
intended coverage. Finally, with respect to EGUs that undertake small
modifications (i.e., modifications that result in an increase in hourly
emissions of 10 percent or less) for which standards were not included
in the 2015 Rule, the EPA is soliciting comment on standards of
performance based on a unit's historical performance and how to best
account for emissions variability due to changes in the mode of
operation (Comment C-1). Table 1 shows the proposed emission standards
for newly constructed and reconstructed EGUs, as well as modified EGUs.
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    \2\ A subcritical EGU operates at pressures where water first
boils and is then converted to superheated steam. A supercritical
steam generator EGU operates at pressures in excess of the critical
pressure of water and heats water to produce superheated steam
without boiling. While often referred to as a supercritical boiler,
no boiling actually occurs in the device and the term ``boiler''
should technically not be used for a supercritical pressure steam
generator. Note: the term ``EGU'' is intended to refer to the
affected facility (also referred to as the affected ``source'' or
``unit'').
    \3\ Under 40 CFR 60.14(h), a modification of an existing
electric utility steam generating unit is defined as a physical
change or change in the method of operation of the unit that
increases the maximum hourly emissions of any regulated pollutant
above the maximum hourly emissions achievable at that unit during
the 5 years prior to the change.
    \4\ The maximally stringent standard for modified EGUs is the
numeric standard for reconstructed EGUs, even if the emission rate
based on best annual performance is lower than that numeric
standard.

                      Table 1--Summary of BSER and Proposed Standards for Affected Sources
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          Affected source                        BSER                           Emissions standard
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New and Reconstructed Steam          Most efficient generating    1. 1,900 lb CO2/MWh-gross for sources with
 Generating Units and IGCC Units.     technology in combination    heat input >2,000 MMBtu/h.
                                      with best operating         2. 2,000 lb CO2/MWh-gross for sources with
                                      practices.                   heat input <=2,000 MMBtu/h OR
                                                                  3. 2,200 lb CO2/MWh-gross for coal refuse-
                                                                   fired sources.
Modified Steam Generating Units and  Best demonstrated            A unit-specific emission limit determined by
 IGCC Units.                          performance.                 the unit's best historical annual CO2
                                                                   emission rate (from 2002 to the date of the
                                                                   modification); the emission limit will be no
                                                                   more stringent than:
                                                                     1. 1,900 lb CO2/MWh-gross for sources with
                                                                      heat input >2,000 MMBtu/h.
                                                                     2. 2,000 lb CO2/MWh-gross for sources with
                                                                      heat input <=2,000 MMBtu/h OR
                                                                     3. 2,200 lb CO2/MWh-gross for coal refuse-
                                                                      fired sources.
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    The EPA is not proposing to amend and is not reopening the
standards of performance for newly constructed or reconstructed
stationary combustion turbines. The EPA is also proposing to make other
miscellaneous technical changes to the regulations.
2. Costs and Benefits
    When the EPA promulgated the 2015 Rule, it took note of both
utility announcements and U.S. Energy Information Administration (EIA)
modeling and, based on that information, concluded that ``even in the
absence of this rule, (i) existing and anticipated economic conditions
are such that few, if any, fossil-fuel-fired steam-generating EGUs will
be built in the foreseeable future,'' and that ``(ii) utilities and
project developers are expected to choose new generation technologies
(primarily NGCC) that would meet the final standards'' and also
``renewable generating sources that are not affected by these final
standards.'' See 80 FR 64515. The EPA, therefore, projected that the
2015 Rule would ``result in negligible CO2 emission changes,
quantified benefits, and costs by 2022 as a result of the performance
standards for newly constructed EGUs.'' Id. The Agency went on to say
that it had been ``notified of few power sector NSPS modifications or
reconstructions.'' Based on that additional information, the EPA said
it ``expects that few EGUs will trigger either the modification or the
reconstruction provisions'' of the 2015 Rule. Id. at 64516.
    The EPA believes that the projections it made in conjunction with
its promulgation of the 2015 Rule remain generally correct, in that, as
explained in the economic impact analysis for this proposed rule, in
the period of analysis, recent EPA and EIA analyses project there to
be, at most, few new, reconstructed, or modified sources that will
trigger the provisions the EPA is proposing. Consequently, the EPA has
conducted an illustrative analysis of the costs for a representative
new unit. Based on this analysis, which is presented in the economic
impact analysis, the EPA projects this proposed rule will not result in
any significant carbon dioxide (CO2) emission changes or
costs. This analysis reflects the best data available to the EPA at the
time the modeling was conducted. As with any modeling of future
projections, many of the inputs are uncertain. In this context, notable
uncertainties, in the future, include the cost of fuels, the cost to
operate existing power plants, the cost to construct and operate new
power plants, infrastructure, demand, and policies affecting the
electric power sector. The modeling conducted for this economic impact
analysis is based on estimates of these variables, which were derived
from the data currently available to the EPA. However, future
realizations could deviate from these expectations as a result of
changes in wholesale electricity markets, federal policy intervention,
including mechanisms to incorporate value for onsite fuel storage, or
substantial shifts in energy prices. The results presented in this
economic impact analysis are not a prediction of what will happen, but
rather a projection describing how this proposed regulatory action may
affect electricity sector outcomes in the absence of unexpected shocks.
The results of this economic impact analysis should be viewed in that
context.

B. Types of Sources

    Fossil fuel-fired EGUs take two forms that are relevant for present
purposes: Those that are steam generating units and those that use
gasification technology.\5\ Fossil fuel-fired steam generating units
can burn natural gas, oil, or coal. However, coal is the dominant fuel
for electric utility steam generating units. Coal-fired steam
generating units are primarily either pulverized coal (PC) or fluidized
bed (FB) steam generating units.\6\ At a PC steam generating unit, the
coal is crushed (pulverized) into a powder to increase its surface
area. The coal powder is then blown into a steam generating unit and
burned. In a fossil fuel-fired steam generating unit using FB
combustion, the solid fuel is burned in a layer of heated particles
suspended in flowing air. Power can also be generated from coal or
other fuels using gasification technology. An IGCC unit gasifies coal
or petroleum coke to form a synthetic gas (or syngas) composed of
carbon monoxide (CO) and hydrogen (H2), which can be
combusted in a combined cycle system to generate power.
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    \5\ Fossil fuel-fired EGUs also include combustion turbines, but
the EPA is not proposing any changes to standards for those types of
sources in this rulemaking.
    \6\ Fossil fuel-fired utility steam generating units (i.e.,
boilers) are most often operated using coal as the primary fuel.
However, some utility boilers use natural gas and/or fuel oil as the
primary fuel.
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    Natural gas-fired EGUs typically use one of two technologies:
Natural gas combined cycle (NGCC) or simple cycle combustion turbines.
NGCC units first generate power from a combustion turbine engine (the
combustion cycle).\7\ The unused heat from the combustion turbine
engine is then routed to a heat recovery steam generator (HRSG) that
generates steam, which is then used to produce power using a steam
turbine (the steam cycle). Combining these generation cycles increases
the overall efficiency of the system. Simple cycle combustion turbines
only use a combustion turbine engine to produce

electricity (i.e., there is no heat recovery or steam cycle).
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    \7\ Note that natural gas can also be used as a fuel in a steam
generating EGU (boiler) and many existing coal- and oil-fired
utility boilers have repowered as natural gas-fired units. However,
a natural gas-fired utility boiler is not currently an economically
or technologically viable choice for construction of a new steam
generating unit EGU (80 FR 64515).
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C. The 2015 Rulemaking, Reconsideration, and Litigation

    On April 13, 2012, the EPA first proposed a NSPS for greenhouse gas
(GHG) emissions from fossil fuel-fired EGUs (77 FR 22392). That
proposal identified as the BSER for a coal-fired power plant building a
natural gas-fired power plant (Id. at 22394). On January 8, 2014, the
EPA rescinded that proposal and replaced it with a supplemental
proposal that identified partial CCS as the BSER for coal-fired power
plants \8\ (79 FR 1430). On October 23, 2015, the EPA finalized the
Standards of Performance for Greenhouse Gas Emissions from New,
Modified, and Reconstructed Stationary Sources: Electric Generating
Units (80 FR 64510). In that action, the EPA issued final standards of
performance to limit emissions of GHG pollution manifested as
CO2 \9\ from newly constructed, modified, and reconstructed
fossil fuel-fired electric utility steam generating units (i.e.,
utility boilers and IGCC EGUs) and newly constructed and reconstructed
stationary combustion turbine EGUs. These final standards are codified
in 40 CFR part 60, subpart TTTT.
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    \8\ The applicability includes all fossil fuel-fired steam
generating units (e.g., natural gas and oil-fired EGUs), but the
BSER determination focused on coal-fired EGUs.
    \9\ Greenhouse gas pollution is the aggregate group of the
following gases: CO2, methane (CH4), nitrous
oxide (N2O), sulfur hexafluoride (SF6),
hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs).
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    The 2015 standards of performance for newly constructed fossil
fuel-fired steam generating units \10\ were based on the performance of
a new, highly efficient, supercritical pulverized coal (SCPC) EGU,
implementing post-combustion partial CCS technology, which the EPA
determined to be the BSER under Clean Air Act (CAA) section 111(b) for
these sources. The EPA concluded that CCS was adequately demonstrated
(including being technically feasible) and widely available, and could
be implemented at reasonable cost. The EPA did not determine natural
gas co-firing or IGCC technology (either with natural gas co-firing or
implementing partial CCS) to be BSER. However, the Agency did identify
them as alternative methods of compliance.
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    \10\ The EPA also refers to fossil fuel-fired steam generating
units as ``steam generating units'' or as ``utility boilers and IGCC
units.'' These are units whose emission of criteria pollutants are
covered under 40 CFR part 60, subpart Da. Criteria pollutants are
those for which the EPA issues health criteria pursuant to CAA
section 108, issues national ambient air quality standards (NAAQS)
pursuant to CAA section 109, promulgates area designations of
attainment, nonattainment, or unclassifiable pursuant to CAA section
107, and reviews and approves or disapproves state implementation
plan (SIP) submissions and issues federal implementation plans
(FIPs) pursuant to CAA section 110. GHG are not criteria pollutants.
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    The EPA also issued final standards for steam generating units that
implement ``large modifications,'' (i.e., modifications resulting in an
increase in hourly CO2 emissions of more than 10 percent).
The standards of performance for modified steam generating units that
make large modifications are based on each affected unit's own best
historical performance as the BSER. The EPA did not issue final
standards for steam generating units that implement ``small
modifications'' (i.e., modifications resulting in an increase in hourly
CO2 emissions of less than or equal to 10 percent).
    For steam generating units that undergo a ``reconstruction'' (i.e.,
the replacement of components of an existing EGU to an extent that
both: (1) The fixed capital cost of the new components exceeds 50
percent of the fixed capital cost that would be required to construct a
comparable entirely new EGU, and (2) it is technologically and
economically feasible to meet the applicable standards),\11\ the EPA
finalized standards based on the performance of the most efficient
generating technology for these types of units as the BSER (i.e.,
reconstructing the boiler as necessary to use steam with higher
temperature and pressure, even if the boiler was not originally
designed to do so).\12\ The 2015 emission standard for large EGUs
(greater than approximately 200 megawatts (MW)) was based on the
performance of a well-operated PC EGU using supercritical steam
conditions. The emission standard for small EGUs (less than
approximately 200 MW) was based on the performance of a well-operated
PC using the best available subcritical steam conditions. The
difference in the standards for larger and smaller EGUs was based on
the commercial availability of higher pressure/temperature steam
turbines (e.g., supercritical steam turbines) for large EGUs. While it
is technically possible to design smaller supercritical steam turbines,
due to the lack of commercial availability, the EPA was not able to
access sufficient information regarding the cost of developing a
specially designed steam turbine to determine that this was appropriate
for inclusion as BSER.
---------------------------------------------------------------------------

    \11\ 40 CFR 60.15.
    \12\ Steam with higher temperature and pressure has more thermal
energy that can be more efficiently converted to electrical energy.
---------------------------------------------------------------------------

    The EPA has historically been notified of only a limited number of
NSPS modifications involving fossil fuel-fired steam generating units.
See Standards of Performance for Greenhouse Gas Emissions for New
Stationary Sources: Electric Utility Generating Units--Proposed Rule,
77 FR 22392, 22400 (April 13, 2012). Given the limited information, the
Agency concluded during the 2015 rulemaking that it lacked sufficient
information to establish standards of performance for all types of
modifications at steam generating units. Instead, the EPA determined
that it was appropriate to establish standards of performance only for
affected modified steam generating units that undergo modifications
resulting in an hourly increase in CO2 emissions (mass per
hour) of more than 10 percent (``large'' modifications) as compared to
the source's highest hourly emission during the previous 5 years. The
Agency determined that it had adequate information regarding the types
of large, capital-intensive projects \13\ that could result in large
increases in hourly CO2 emissions. Additionally, the Agency
determined that it had adequate information regarding the types of
measures available to control emissions from sources that undergo such
modifications, and on the costs and effectiveness of such control
measures. The EPA determined that the BSER for steam generating units
that trigger the large modification provision is each affected unit's
own best historic annual CO2 emission rate (from 2002 to the
date of the modification).
---------------------------------------------------------------------------

    \13\ Major facility upgrades involving the refurbishment or
replacement of steam turbines or other equipment upgrades that could
significantly increase an EGU's capacity to burn more fossil fuel,
thereby resulting in a large emissions increase.
---------------------------------------------------------------------------

    With respect to affected steam generating units that undergo
modifications that result in smaller increases in CO2
emissions (specifically, steam generating units that conduct
modifications resulting in an increase in hourly CO2
emissions (mass per hour) of 10 percent or less (``small''
modifications) compared to the source's highest hourly emission during
the previous 5 years), the EPA concluded it did not have sufficient
information and did not finalize any standard of performance or other
requirements. The EPA continues to review whether it has sufficient
information to establish appropriate standards for small modifications
and is soliciting comment on options for determining appropriate
standards in this action (Comment C-2).

    The 2015 Rule also finalized standards of performance for newly
constructed and reconstructed stationary combustion turbine EGUs. For
newly constructed and reconstructed base load natural gas-fired
stationary combustion turbines, the EPA finalized a standard based on
efficient NGCC technology as the BSER. For newly constructed and
reconstructed non-base load natural gas-fired and multi-fuel-fired
(both base load and non-base load) stationary combustion turbines, the
EPA finalized a heat input-based clean fuels standard. The EPA did not
promulgate final standards of performance for modified stationary
combustion turbines due to lack of information.
    The EPA received six petitions for reconsideration of the 2015
final CAA section 111(b) GHG NSPS rule. The EPA denied five of the
petitions on the basis they did not satisfy one or both of the
statutory conditions for reconsideration under CAA section
307(d)(7)(B), and deferred action on a petition that raised the issue
of the treatment of biomass on May 6, 2016 (81 FR 27442). Multiple
parties also filed petitions for judicial review of the 2015 Rule.
These petitions were consolidated into a single case and the
petitioners filed opening written briefs in October 2016. The EPA and
supporting intervenors filed opening written briefs in December 2016.
Next, petitioners submitted written reply briefs in January 2017. On
April 28, 2017, the United States Court of Appeals for the District of
Columbia granted the EPA's motion to hold the cases in abeyance while
the Agency reviews the 2015 Rule and considers whether to propose
revisions to it.

D. The Purpose of This Regulatory Action

    Executive Order 13783 (Promoting Energy Independence and Economic
Growth) directs all executive departments and agencies, including the
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.'' \14\ Moreover, the Executive Order directs the EPA to undertake
this process of review with regard to the New Source Rule issued under
CAA section 111(b).
---------------------------------------------------------------------------

    \14\ Id., Section 1(c).
---------------------------------------------------------------------------

    In a document signed the same day as Executive Order 13783 and
published in the Federal Register at 82 FR 16330 (April 4, 2017), the
EPA announced that, consistent with the Executive Order, it was
initiating its review of the Standards of Performance for Greenhouse
Gas Emissions from New, Modified, and Reconstructed Stationary Sources:
Electric Generating Units, and providing notice of forthcoming proposed
rulemakings consistent with the Executive Order. As explained below,
that review has led the EPA to propose to revise the BSER
determinations for new, reconstructed, and modified coal-fired EGUs,
including reconsideration issues previously denied by the Agency.

E. Does this action apply to me?

    Table 2 of this preamble lists the regulated industrial source
categories that are the subject of this proposal. Table 2 is not
intended to be exhaustive, but rather provides a guide for readers
regarding the entities that this proposed action is likely to affect.
The proposed standards, once promulgated, will be directly applicable
to the affected sources. To determine whether your facility, company,
business, organization, etc., would be regulated by this proposed
action, you should examine the applicability criteria in 40 CFR 60.1.
If you have questions regarding the applicability of this action to a
particular entity, consult either the air permitting authority for the
entity or your EPA Regional representative as listed in 40 CFR 60.4
(General Provisions).

 Table 2--Industrial Source Categories Affected by This Proposed Action
------------------------------------------------------------------------
                                 NAICS code 1 2   Examples of regulated
            Category                                     entities
------------------------------------------------------------------------
Industry.......................          221112  Fossil fuel electric
                                                  power generating
                                                  units.
Federal government.............      \3\ 221112  Fossil fuel electric
                                                  power generating units
                                                  owned by the federal
                                                  government.
State/local government.........      \3\ 221112  Fossil fuel electric
                                                  power generating units
                                                  owned by
                                                  municipalities.
Tribal government..............          921150  Fossil fuel electric
                                                  power generating units
                                                  in Indian Country.
------------------------------------------------------------------------
\1\ North American Industry Classification System.
\2\ Includes NAICS codes for source categories that own and operate
  electric power generating units (including boilers and stationary
  combined cycle combustion turbines).
\3\ Federal, state, or local government-owned and operated
  establishments are classified according to the activity in which they
  are engaged.

F. 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
Administrator, the EPA will post a copy of this proposed action at
https://www.epa.gov/stationary-sources-air-pollution/proposal-nsps-ghg-emissions-new-modified-and-reconstructed-egus. Following publication in
the Federal Register, the EPA will post the Federal Register version of
the proposal and key technical documents at this same website.
    A version of the regulatory language that incorporates the proposed
changes in this action in track changes (i.e., redline) is available in
the docket for this action (Docket ID No. EPA-HQ-OAR-2013-0495).

II. Proposed Requirements for New, Reconstructed, and Modified Sources

A. Applicability Requirements

    The EPA identified the applicability requirements for the 40 CFR
part 60, subpart TTTT standards in the 2015 rulemaking, and the Agency
is not proposing to revise or reopening those requirements, except as
noted below. Those requirements are as follows: In general, the EPA
refers to fossil fuel-fired electric generating units that would be
subject to a CAA section 111 emission standard as ``affected'' EGUs or
units. An EGU is any fossil fuel-fired electric utility steam
generating unit (i.e., a utility boiler or IGCC unit) or combustion
turbine (in either simple cycle or combined cycle configuration). To be
considered an affected EGU under 40 CFR part 60, subpart TTTT, the unit
must meet the following applicability criteria: The unit must both: (i)
Be

capable of combusting more than 250 million British thermal units per
hour (MMBtu/h) (260 gigajoules per hourA (GJ/h)) of heat input of
fossil fuel (either alone or in combination with any other fuel); \15\
and (ii) serve a generator capable of supplying more than 25 MW net to
a utility distribution system (i.e., for sale to the grid).\16\
However, 40 CFR part 60, subpart TTTT includes applicability exemptions
for certain EGUs, including: (1) Non-fossil fuel units subject to a
federally enforceable permit that limits the use of fossil fuels to 10
percent or less of their heat input capacity on an annual basis; (2)
CHP units that are subject to a federally enforceable permit limiting
annual net electric sales to no more than either the unit's design
efficiency multiplied by its potential electric output, or 219,000
megawatt-hours (MWh), whichever is greater; (3) stationary combustion
turbines that are not physically capable of combusting natural gas
(e.g., those that are not connected to a natural gas pipeline); (4)
utility boilers and IGCC units that have always been subject to a
federally enforceable permit limiting annual net electric sales to one-
third or less of their potential electric output (e.g., limiting hours
of operation to less than 2,920 hours annually) or limiting annual
electric sales to 219,000 MWh or less; (5) municipal waste combustors
that are subject to 40 CFR part 60, subpart Eb; (6) commercial or
industrial solid waste incineration units subject to 40 CFR part 60,
subpart CCCC; and (7) certain projects under development, as discussed
below.
---------------------------------------------------------------------------

    \15\ The EPA refers to the capability to combust 250 MMBtu/h of
fossil fuel as the ``base load rating criterion.'' Note that 250
MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
    \16\ The EPA refers to the capability to supply 25 MW net to the
grid as the ``total electric sales criterion.''
---------------------------------------------------------------------------

    The CAA defines a new or modified source for purposes of a given
regulation as any stationary source that commences construction or
modification after the publication of the proposed regulation. Thus,
any standards of performance the Agency finalizes as part of this
rulemaking will apply to EGUs that commence construction,
reconstruction, or modification after the date of this proposal. (EGUs
that commenced construction after the date of the proposal for the 2015
Rule and before the date of this proposal will remain subject to the
standards of performance promulgated in that Rule.) A modification is
any physical change in, or change in the method of operation of an
existing source that increases the amount of any air pollutant emitted
to which a standard applies.\17\ The NSPS General Provisions (40 CFR
part 60 subpart A) provide that an existing source is considered a new
source if it undertakes a reconstruction.\18\
---------------------------------------------------------------------------

    \17\ 40 CFR 60.2.
    \18\ 40 CFR 60.15(a).
---------------------------------------------------------------------------

    The EPA is proposing several changes to the applicability
requirements. First, the EPA is proposing to change the exemption from
applicability for EGUs (item 1 on the list above) on the grounds that
they are considered non-fossil-fuel EGUs by revising the definition of
non-fossil fuel EGUs from EGUs capable of ``combusting 50 percent or
more non-fossil fuel'' to EGUs capable of ``deriving 50 percent or more
of the heat input from non-fossil fuel at the base load rating.''
(emphasis added). This amendment is consistent with the original intent
to cover only fossil fuel EGUs and would assure that solar thermal EGUs
with natural gas backup burners, which are similar to other types of
non-fossil fuel units in that most of their energy is derived from non-
fossil fuel sources, are not subject to the requirements of 40 CFR part
60, subpart TTTT. The definition of base load rating would also be
amended to include the heat input from non-combustion sources (e.g.,
solar thermal). Next, the design efficiency of an EGU is used to
determine the electric sales applicability threshold. 40 CFR part 60,
subpart TTTT currently allows the use of three methods for determining
the design efficiency.\19\ To reduce compliance burden, the EPA is
proposing to allow alternative methods as approved by the Administrator
on a case-by-case basis.\20\ The EPA is also proposing to change the
applicability of paragraph 60.8(b) in Table 3 of subpart TTTT from no
to yes. This amendment would allow the Administrator to approve
alternatives to the test methods specified in subpart TTTT. Finally, to
avoid potential double counting of electric sales, the EPA is proposing
that for CHP units determining net electric sales, purchased power of
the host facility would be determined based on the percentage of
thermal power provided to the host facility by the specific CHP
facility. If any of these amendments are not finalized, EGUs that would
be exempted by the proposed amendments would remain subject to 40 CFR
part 60, subpart TTTT.
---------------------------------------------------------------------------

    \19\ Subpart TTTT currently lists ASME PTC 22 Gas Turbines, ASME
PTC 46 Overall Plant Performance, and ISO 2314 Gas turbines--
acceptance tests as approved methods to determine the design
efficiency.
    \20\ Owners/operators of EGUs would petition the Administrator
is writing to use an alternate method to determine the design
efficiency. Administrator discretion is intentionally left broad and
could include other ASME or ISO methods as well as data to
demonstrate the design efficiency of the EGU.
---------------------------------------------------------------------------

B. Emission Standards

    In this action, the EPA proposes revisions to the 2015 Rule's
provisions for newly constructed coal-fired electric utility steam
generating units (both utility boilers and IGCC units). The EPA
proposes to revise its previous determination that the BSER for such
newly constructed EGUs is partial CCS. The EPA bases this revision on
(1) an updated analysis of what represents reasonable costs and (2) an
updated analysis of the geographic availability of CCS. In addition,
the EPA solicits comment on the technical feasibility of carbon capture
technologies. Instead, the EPA proposes to create three subcategories
of steam generating units: Large units, defined as units with heat
input greater than 2,000 MMBtu/h; small units, defined as units with
heat input less than or equal to 2,000 MMBtu/h; and units of any size
(that meet the applicability criteria) and that are fired with coal
refuse. The EPA proposes to find that for each of these subcategories,
the BSER is the most efficient demonstrated steam cycle (i.e.,
supercritical steam conditions for large units and best available
subcritical steam conditions for small and coal refuse-fired units) in
combination with the best operating practices. Unless stated otherwise,
the EPA's use of the term supercritical steam conditions, or, more
simply, supercritical, encompasses both ultra-supercritical and
advanced ultra-supercritical steam conditions. There is no
thermodynamic definition of ultra-supercritical or advanced ultra-
supercritical steam conditions; rather, they are terms used to define
subsets of supercritical steam conditions with higher temperatures and
pressures.\21\ The EPA is proposing revised standards of performance
for newly constructed steam units in the three subcategories that
reflect the Agency's proposed BSER determinations: 1,900 pounds of
CO2 per MWh of gross output (lb CO2/MWh-gross)
for large EGUs; 2,000 lb CO2/MWh-gross for small EGUs, and
2,200 lb CO2/MWh-gross for coal refuse-fired units.\22\ The
EPA is not proposing to

revise its view in the 2015 Rule that natural gas co-firing and IGCC
are alternate control technologies, but as described in section V.B of
this preamble, not the BSER. The EPA invites the public to identify any
additional information not considered by the Agency in the BSER
analysis. (Comment C-3)
---------------------------------------------------------------------------

    \21\ Supercritical, ultra-supercritical, and advanced ultra-
supercritical steam generators operate at pressures greater than 22
megapascals (MPa) (3,205 pounds per square inch (psi)), temperatures
greater than 550 degrees Celsius ([deg]C) (1,022 degrees Fahrenheit
([deg]F)), and use the same general steam generating unit design.
The primary difference is that different materials are required to
withstand the higher temperatures of ultra-supercritical and
advanced ultra-supercritical steam conditions.
    \22\ In contrast, in the 2015 Rule, the EPA did not create any
subcategories for new steam generating units.
---------------------------------------------------------------------------

    In addition, in this action, the EPA proposes to revise the 2015
Rule's standard of performance for reconstructed EGUs to be consistent
with the numeric standards for new EGUs. By the same token, with
respect to modified EGUs, the EPA proposes to revise the 2015 Rule's
maximally stringent emissions rate for large modifications to be the
same as the standards for newly constructed and reconstructed units in
the same three subcategories (e.g., while the standard would continue
to be based on looking at average historical data, the EPA is proposing
that the standard can be no lower than the new source standard). While
the EPA is proposing revisions to the maximally stringent emission
standards, the Agency is not proposing to revise or reopening the 2015
Rule's BSER determination, which was the use of the most efficient
generation available in combination with best operating practices,
based on historical emissions, or the associated standard of
performance. The EPA is soliciting comment on standards of performance
for ``small'' modifications based on a unit's best demonstrated
historical performance and the most appropriate approach to account for
emissions variability due to changes in the mode of operation and other
factors (Comment C-4).
    The EPA is not proposing to revise or reopening the 2015 Rule's
requirement that the emission standards applicable to any type of EGU
(however they may be revised in a final action on this proposal) apply
at all times, including during periods of startup, shutdown, and
malfunction (SSM). In addition, in this action, the EPA is not
proposing to revise or reopening the air pollutants covered by the 2015
Rule or any of the Rule's continuous monitoring requirements; emissions
performance testing requirements; continuous compliance requirements;
or notification, recordkeeping, and reporting requirements.
Furthermore, the EPA is not proposing to amend or reopening the 2015
Rule's BSER determination or standards of performance for new or
reconstructed stationary combustion turbines.
    Table 3 below summarizes the proposed standards of performance for
three proposed subcategories of newly constructed and reconstructed
EGUs as well as the proposed maximally stringent standards for modified
EGUs. Consistent with the 2015 rulemaking, these emission standards
would apply on a 12-operating month rolling average.

                      Table 3--Summary of BSER and Proposed Standards for Affected Sources
----------------------------------------------------------------------------------------------------------------
          Affected source                        BSER                           Emissions standard
----------------------------------------------------------------------------------------------------------------
New and Reconstructed Steam          Most efficient generating    1. 1,900 lb CO2/MWh-gross for sources with
 Generating Units and IGCC Units.     technology in combination    heat input >2,000 MMBtu/h.
                                      with best operating         2. 2,000 lb CO2/MWh-gross for sources with
                                      practices.                   heat input <=2,000 MMBtu/h OR
                                                                  3. 2,200 lb CO2/MWh-gross for coal refuse-
                                                                   fired sources.
Modified Steam Generating Units and  Best demonstrated            A unit-specific emission limit determined by
 IGCC Units.                          performance.                 the unit's best historical annual CO2
                                                                   emission rate (from 2002 to the date of the
                                                                   modification); the emission limit will be no
                                                                   more stringent than
                                                                     1. 1,900 lb CO2/MWh-gross for sources with
                                                                      heat input >2,000 MMBtu/h.
                                                                     2. 2,000 lb CO2/MWh-gross for sources with
                                                                      heat input <=2,000 MMBtu/h OR
                                                                     3. 2,200 lb CO2/MWh-gross for coal refuse-
                                                                      fired sources.
----------------------------------------------------------------------------------------------------------------

    The EPA is proposing that the amended emission standards apply to
any EGUs that commence construction, reconstruction, or modification
after December 20, 2018. The EPA is not aware of any coal fuel-fired
EGUs that have commenced construction, reconstruction, or modification
since January 8, 2014 (the applicability date of 40 CFR part 60,
subpart TTTT). Therefore, no existing units would be impacted by the
proposed revised BSER determination.

III. Legal Authority

A. Statutory Background

    This action is governed by CAA section 111, which authorizes and
directs the EPA to prescribe NSPS applicable to certain new stationary
sources (including newly constructed, modified, and reconstructed
sources).\23\ As a preliminary step to regulation, the EPA lists
categories of stationary sources that the Administrator, in his or her
judgment, finds ``cause, or contribute significantly to, air pollution
which may reasonably be anticipated to endanger public health or
welfare.'' the EPA has listed and regulated more than 60 stationary
source categories under CAA section 111.\24\
---------------------------------------------------------------------------

    \23\ CAA section 111(b)(1)(A).
    \24\ See generally 40 CFR part 60, subparts D-MMMM.
---------------------------------------------------------------------------

    The EPA's authority for this proposed rule is CAA section
111(b)(1). In both the 2015 Rule and the 2014 proposed rule, the EPA
discussed the requirements of that provision and why the Rule met them.
See 80 FR 64510, 64529-31 (2015 Rule), 79 FR 1430, 1455 (January 8,
2014) (2014 proposed rule). In summary, CAA section 111(b)(1)(A)
requires the Administrator to establish a list of source categories to
be regulated under CAA 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. Once the Administrator lists a source category under CAA
section 111(b)(1)(A), he or she then promulgates, under CAA section
111(b)(1)(B), ``standards of performance for new sources within such
category.''
    In the 2015 Rule, the EPA promulgated standards for CO2
emissions from sources in two source categories, fossil fuel-fired
electric utility steam generating units and combustion turbines. In the
2015 Rule,

the EPA explained that the Agency interprets the statute to require an
endangerment finding to be made at the time the EPA lists the source
category and to broadly concern emissions from the source category, and
not to concern emissions of any particular pollutant that may be made
subject to a revised or newly issued standard for a source category
that has already been listed. The EPA further explained that CAA
section 111(b) does not specify what pollutants the EPA should regulate
once it lists a source category, so that the EPA may exercise its
discretion to regulate particular pollutants as long as the EPA
provides a rational basis for doing so. See National Lime Ass'n v. EPA,
627 F.2d 416, 431-32 n.48 (D.C. Cir. 1980).
    In the 2015 Rule, the EPA described its rational basis for
regulating CO2 emissions from fossil fuel-fired EGUs,
including that the CO2 emissions from fossil fuel-fired EGUs
are almost three times as much as the emissions from the next 10 source
categories combined, and that the CO2 emissions from even a
single new coal-fired power plant may amount to millions of tons each
year. The EPA added that even if it were required to make an
endangerment finding for those emissions in order to regulate them, the
same facts that provided the rational basis would qualify as an
endangerment finding.\25\
---------------------------------------------------------------------------

    \25\ The EPA is proposing to retain the statutory
interpretations and record determinations described in this
paragraph. Nonetheless, the EPA is aware that various stakeholders
have in the past made arguments opposing our views on these points,
and the Agency sees value to allowing them to comment on these views
in this rulemaking. Accordingly, the Agency will consider comments
on the correctness of the EPA's interpretations and determinations
and whether there are alternative interpretations that may be
permissible, either as a general matter or specifically as applied
to GHG emissions. For example, the Agency will consider comments on
the issue of whether it is correct to interpret the ``endangerment
finding'' as a finding that is only made once for each source
category at the time that the EPA lists the source category or
whether the EPA must make a new endangerment finding each time the
Agency regulates an additional pollutant by an already-listed source
category. Further, the EPA will consider comments on the issue of
whether GHG emissions are different in salient respects from
traditional emissions such that it would be appropriate to conduct a
new ``endangerment finding'' with respect to GHG emissions from a
previously listed source category. In addition, the EPA solicits
comment on whether the Agency does have a rational basis for
regulating CO2 emissions from new coal-fired electric
utility steam generating units and whether it would have a rational
basis for declining to do so at this time, in light of, among other
things, the following: (i) Ongoing and projected power sector trends
that have reduced CO2 emissions from the power sector,
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, due to reduced coal-fired generation, as the EPA
discusses in the proposed Affordable Clean Energy rule, 83 FR 44746,
44750-51 (August 31, 2018); and (ii) as noted above, no more than a
few new coal-fired EGUs can be expected to be built, which raises
questions about whether new coal-fired EGUs contribute significantly
to atmospheric CO2 levels.
---------------------------------------------------------------------------

    A ``new source'' is ``any stationary source, the construction or
modification of which is commenced after,'' in general, final standards
applicable to that source are promulgated or, if earlier, proposed.\26\
A modification is ``any physical change . . . or change in the method
of operation . . . which increases the amount of any air pollutant
emitted by such source or which results in the emission of any air
pollutant not previously emitted'' to which the standard applies.\27\
The EPA, through regulations, has determined that certain types of
changes are exempt from consideration as a modification.\28\ The EPA
``may distinguish among classes, types and sizes within categories of
new sources for the purpose of establishing such standards.'' See CAA
section 111(b)(2).
---------------------------------------------------------------------------

    \26\ CAA section 111(a)(2).
    \27\ CAA section 111(a)(4). See also 40 CFR 60.14 (concerning
what constitutes a modification, how to determine the emission rate,
how to determine an emission increase, and exempting specific
actions that are not, by themselves, considered modifications).
    \28\ 40 CFR 60.2, 60.14(e).
---------------------------------------------------------------------------

    The NSPS General Provisions (40 CFR part 60, subpart A) provides
that an existing source is considered to be a new source if it
undertakes a ``reconstruction,'' which is the replacement of components
of an existing EGU to an extent that both (1) the fixed capital cost of
the new components exceeds 50 percent of the fixed capital cost that
would be required to construct a comparable entirely new EGU, and (2)
it is technologically and economically feasible to meet the applicable
standards.\29\
---------------------------------------------------------------------------

    \29\ 40 CFR 60.15.
---------------------------------------------------------------------------

    Congress first enacted the definition of ``standard of
performance'' as part of CAA section 111 in the 1970 Clean Air Act
Amendments (CAAA), amended it in the 1977 CAAA, and amended it again in
the 1990 CAAA to largely restore the original definition as it read in
the 1970 CAAA. It is in the legislative history for the 1970 and 1977
CAAAs that Congress primarily addressed the definition as it read in
those two versions of the statute, and that legislative history
provides guidance in interpreting this provision.\30\ In addition, the
U.S. Court of Appeals for the D.C. Circuit has reviewed rulemakings
under CAA section 111 on numerous occasions during the past 40 years,
issuing decisions dated from 1973 to 2011,\31\ through which the Court
has developed a body of case law that interprets the term ``standard of
performance.''
---------------------------------------------------------------------------

    \30\ In the 1970 CAAA, Congress defined ``standard of
performance,'' under CAA 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 which (taking into account the cost of achieving
such reduction) the Administrator determines has been adequately
demonstrated.
    In the 1977 CAAA, Congress revised the definition to distinguish
among different types of sources, and to require that for fossil
fuel-fired sources, the standard: (i) Be based on, in lieu of the
``best system of emission reduction . . . adequately demonstrated,''
the ``best technological system of continuous emission reduction . .
. adequately demonstrated'' (emphasis added); and (ii) require a
specific percentage reduction in emissions. In addition, in the 1977
CAAA, Congress expanded the parenthetical requirement that the
Administrator consider the cost of achieving the reduction to also
require the Administrator to consider ``any non-air quality health
and environment impact and energy requirements.''
    In the 1990 CAAA, Congress again revised the definition, this
time repealing the requirements that the standard of performance be
based on the best technological system and achieve a percentage
reduction in emissions, and replacing those provisions with the
terms used in the 1970 CAAA version of CAA section 111(a)(1) that
the standard of performance be based on the ``best system of
emission reduction . . . adequately demonstrated.'' This 1990 CAAA
version is the current definition. Even so, because parts of the
definition as it read under the 1977 CAAA were retained in the 1990
CAAA, see CAA section 111(a)(1), the explanation in the 1977 CAAA
legislative history, and the interpretation in the case law, of
those parts of the definition in the case law remain relevant to the
definition as it reads currently.
    \31\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C.
Cir. 1973); Essex Chemical Corp.; Portland Cement Ass'n v. EPA, 665
F.3d 177 (D.C. Cir. 2011). See also Delaware v. EPA, No. 13-1093
LEXIS CITE (D.C. Cir. May 1, 2015).
---------------------------------------------------------------------------

    Section 111(b) of the CAA authorizes the EPA to set ``standards of
performance'' for new, reconstructed, and modified stationary sources
from listed source categories to minimize emissions of air pollutants
to the environment. Under CAA section 111(a)(1), the EPA must set these
standards at the level that reflects the ``best system of emission
reduction . . . adequately demonstrated'' taking into account technical
feasibility, costs, and non-air quality health and environmental
impacts and energy requirements.\32\ The text and legislative

history of CAA section 111, the EPA's regulatory interpretations of
that provision, and relevant court decisions, identify factors for the
EPA to consider in making a BSER determination. They include, among
others, whether the system of emission reduction is technically
feasible, whether the costs of the system are reasonable, the amount of
emissions reductions the system would generate,\33\ and whether the
standard would effectively promote further deployment or development of
advanced technology.\34\
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    \32\ The standard that EPA develops, reflecting the performance
of the BSER, commonly takes the form of a numeric emission limit,
expressed as a numeric performance level that can either be
normalized to a rate of output or input (e.g., tons of pollution per
amount of product produced--a so-called rate-based standard), or
expressed as a numeric limit on mass of pollutant that may be
emitted (e.g., 100 micrograms per cubic meter ([micro]g/m\3\)--or
parts per billion). Generally, the EPA does not prescribe a
particular technological system that must be used to comply with a
standard CAA section 111(b)(5) and (h). Rather, sources generally
may select any measure or combination of measures that will achieve
the emissions level of the standard of performance. CAA section
111(b)(5). In establishing standards of performance, EPA has
significant discretion to create subcategories based on source type,
class, or size. CAA section 111(b)(2); see also Lignite Energy
Council v. EPA, 198 F. 3d 930, 933 (D.C. Cir. 1999).
    \33\ See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir.
1981).
    \34\ See id. at 347.
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    The overall approach to determining the BSER, which incorporates
the various elements, is as follows: First, the EPA identifies the
``system[s] of emission reduction'' that have been ``adequately
demonstrated'' for a particular source category. Second, the EPA
determines the ``best'' of these systems after evaluating the extent of
emission reductions, costs, any non-air health and environmental
impacts, and energy requirements. Third, the EPA selects an achievable
standard for emissions--here, the emission rate--based on the
performance of the BSER. The remainder of this subsection discusses the
various elements in that analytical approach.
1. ``System[s] of Emission Reduction . . . Adequately Demonstrated''
    The EPA's first step is to identify ``system[s] of emission
reduction . . . adequately demonstrated.'' An ``adequately
demonstrated'' system, according to the D.C. Circuit, 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.'' \35\ It does not mean that the system ``must be in
actual routine use somewhere.'' \36\ Rather, the Court has said,
``[t]he Administrator may make a projection based on existing
technology, though that projection is subject to the restraints of
reasonableness and cannot be based on `crystal ball' inquiry.'' \37\
The EPA has previously explained that the requirement that the standard
for emissions be ``achievable'' based on the ``best system of emission
reduction . . . adequately demonstrated'' indicates that one of the
requirements for the technology or other measures that the EPA
identifies as the BSER is that the measure must be technically feasible
(81 FR 64538).
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    \35\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C.
Cir. 1973), cert. denied, 416 U.S. 969 (1974).
    \36\ Portland Cement Ass'n, 486 F.2d at 391 (citations omitted)
(discussing the Senate and House bills and reports from which the
language in CAA section 111 grew).
    \37\ Id. (citations omitted).
---------------------------------------------------------------------------

2. ``Best''
    In determining which adequately demonstrated system of emission
reduction is the ``best,'' the EPA considers the following factors:
a. Costs
    Under CAA section 111(a)(1), the EPA is required to take into
account ``the cost of achieving'' the required emission reductions. In
several cases, the D.C. Circuit has elaborated on this cost factor and
formulated the cost standard in various ways, stating that the EPA may
not adopt a standard the cost of which would be ``exorbitant,'' \38\
``greater than the industry could bear and survive,'' \39\
``excessive,'' \40\ or ``unreasonable.'' \41\ As the EPA has explained
in a prior rulemaking, for convenience, the EPA uses ``reasonableness''
to describe costs well within the bounds established by this
jurisprudence.
---------------------------------------------------------------------------

    \38\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir.
1999).
    \39\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir.
1975).
    \40\ Sierra Club v. Costle, 657 F.2d at 343 (D.C. Cir. 1981).
    \41\ Id.
---------------------------------------------------------------------------

    The D.C. Circuit has indicated that the EPA has substantial
discretion in its consideration of cost under CAA section 111(a). In
several cases, the Court upheld standards that entailed significant
costs, consistent with Congress's view that ``the costs of applying
best practicable control technology be considered by the owner of a
large new source of pollution as a normal and proper expense of doing
business.'' \42\ See Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427,
440 (D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974); \43\ Portland
Cement Association v. Ruckelshaus, 486 F.2d 375, 387-88 (D.C. Cir.
1973); Sierra Club v. Costle, 657 F.2d 298, 313 (D.C. Cir. 1981)
(upholding standard imposing controls on sulfur dioxide
(SO2) emissions from coal-fired power plants when the ''cost
of the new controls . . . is substantial'').\44\ Moreover, section
111(a) does not provide specific direction regarding what metric or
metrics to use in considering costs, again affording the EPA
considerable discretion in choosing a means of cost consideration.\45\
---------------------------------------------------------------------------

    \42\ 1977 House Committee Report at 184.
    \43\ The costs for these standards were described in the
rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 5769
(March 21, 1972).
    \44\ Indeed, in upholding the EPA's consideration of costs under
the provisions of the Clean Water Act authorizing technology-based
standards based on performance of a best technology taking costs
into account, courts have also noted the substantial discretion
delegated to the EPA to weigh cost considerations with other
factors. Chemical Mfr's Ass'n v. EPA, 870 F.2d 177, 251 (5th Cir.
1989); Ass'n of Iron and Steel Inst. v. EPA, 526 F.2d 1027, 1054 (3d
Cir. 1975); Ass'n of Pacific Fisheries v. EPA, 615 F.2d 794, 808
(9th Cir. 1980).
    \45\ See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, 200 (D.C.
Cir. 2001) (where CAA section 213 does not mandate a specific method
of cost analysis, the EPA may make a reasoned choice as to how to
analyze costs).
---------------------------------------------------------------------------

b. Non-Air Quality Health and Environmental Impacts
    Under CAA section 111(a)(1), the EPA is required to take into
account ``any non-air quality health and environmental impact'' in
determining the BSER. As the D.C. Circuit has explained, this
requirement makes explicit that a system cannot be ``best'' if it does
more harm than good due to cross-media environmental impacts.\46\
---------------------------------------------------------------------------

    \46\ Portland Cement, 486 F. 2d at 384; Sierra Club, 657 F.2d at
331; see also Essex Chemical Corp., 486 F.2d at 439 (remanding
standard to consider solid waste disposal implications of the BSER
determination).
---------------------------------------------------------------------------

c. Energy Considerations
    Under CAA section 111(a)(1), the EPA is required to take into
account ``energy requirements.'' As discussed below, the EPA may
consider energy requirements on both a source-specific basis and a
sector-wide, region-wide or nationwide basis. Considered on a source-
specific basis, ``energy requirements'' entail, for example, the
impact, if any, of the system of emission reduction on the source's own
energy needs.
d. Amount of Emissions Reductions
    As the EPA has previously explained, although the definition of
``standard of performance'' does not by its terms identify the amount
of emissions from the category of sources or the amount of emission
reductions achieved as factors the EPA must consider in determining the
``best system of emission reduction,'' the D.C. Circuit has stated that
the EPA must in fact do so. See 81 FR at 64529; See Sierra Club v.
Costle, 657 F.2d at 326.\47\
---------------------------------------------------------------------------

    \47\ Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was
governed by the 1977 CAAA version of the definition of ``standard of
performance,'' which revised the phrase ``best system'' to read,
``best technological system.'' As noted above, the 1990 CAAA deleted
``technological,'' and thereby returned the phrase to how it read
under the 1970 CAAA. The court's interpretation of this phrase in
Sierra Club to require consideration of the amount of air emissions
reductions remains valid for the phrase ``best system.''

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

e. Sector or Nationwide Component of the BSER Factors
    The D.C. Circuit has also interpreted CAA section 111 to allow (but
not require) the EPA to consider the various factors it is required to
consider on a national or regional level and over time, not only on a
plant-specific level or as of the time of the rulemaking.\48\ \49\
---------------------------------------------------------------------------

    \48\ Sierra Club, 657 F.2d at 327-28 (quoting 44 FR 33583/3-
33584/1), 331 (citations omitted) (citing legislative history). See
81 FR at 64539; 79 FR 1430, 1466 (January 8, 2014) (explaining that
although the D.C. Circuit decided Sierra Club before the Chevron
case was decided in 1984, the D.C. Circuit's decision could be
justified under either Chevron step 1 or 2. 79 FR 1430, 1466
(January 8, 2014)).
    \49\ The D.C. Circuit's authorization for EPA to consider the
factors on a national or regional level does not refer to the types
of controls or actions that may be part of the BSER, rather, it
refers to the factors EPA uses to evaluate the impacts of those
controls or actions.
---------------------------------------------------------------------------

3. Achievability of the Standard for Emissions
    The definition of ``standard of performance'' provides that the
emission limit (i.e., the ``standard for emissions'') that the EPA
promulgates must be ``achievable'' based on performance of the BSER.
See 81 FR at 64539-40 (discussing D.C. Circuit case law for
requirements for achievability).
4. Expanded Use and Development of Technology
    The D.C. Circuit has made clear that Congress intended for CAA
section 111 to create incentives for new technology, and therefore, the
EPA is required to consider technological innovation as one of the
factors in determining the ``best system of emission reduction.'' \50\
---------------------------------------------------------------------------

    \50\ Sierra Club, 657 F.2d at 346-47.
---------------------------------------------------------------------------

5. Overall Agency Discretion To Balance the Factors
    The D.C. Circuit has made clear that the EPA has broad discretion
in determining the appropriate standard of performance under the
definition in CAA section 111(a)(1), quoted above. Specifically, in
Sierra Club, the Court explained that ``section 111(a) explicitly
instructs the EPA to balance multiple concerns when promulgating a
NSPS,'' \51\ and emphasized that ``[t]he text gives the EPA broad
discretion to weigh different factors in setting the standard.'' \52\
In Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999), the
Court reiterated:
---------------------------------------------------------------------------

    \51\ Id., 657 F.2d at 319.
    \52\ Id., 657 F.2d at 321; see also New York v. Reilly, 969 F.
2d 1147, 1150 (D.C. Cir. 1992) (because Congress did not assign the
specific weight the Administrator should assign to the statutory
elements, ``the Administrator is free to exercise [her] discretion''
in promulgating an NSPS).

    Because section 111 does not set forth the weight that should be
assigned to each of these factors, we have granted the agency a
great degree of discretion in balancing them. . . . EPA's choice [of
the `best system'] will be sustained unless the environmental or
economic costs of using the technology are exorbitant. . . . EPA
[has] considerable discretion under section 111.\53\
---------------------------------------------------------------------------

    \53\ Lignite Energy Council, 198 F.3d at 933. See also NRDC v.
EPA, 25 F.3d 1063, 1071 (D.C. Cir. 1994) (EPA did not err in its
final balancing because ``neither RCRA nor the EPA's regulations
purports to assign any particular weight to the factors listed in
subsection (a)(3). That being the case, the Administrator was free
to emphasize or deemphasize particular factors, constrained only by
the requirements of reasoned agency decision making.'').
---------------------------------------------------------------------------

B. Authority To Revise Existing Regulations

    The EPA's ability to revisit existing regulations is well-grounded
in the law. Specifically, the 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. See Motor Vehicle
Manufacturers Association of the United States v. State Farm Mutual
Automobile Insurance Co., 463 US 29, 56-57 (1983) (``an agency changing
its course must supply a reasoned analysis,'' quoting Greater Boston
Television Corp. v. FCC, 143 F.2d 841, 842 (D.C. Cir.)). The CAA
complements the EPA's inherent authority to reconsider prior
rulemakings by providing the Agency with broad authority to prescribe
regulations as necessary. See 42 U.S.C. 7601(a). The authority to
reconsider prior decisions exists in part because the 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,
as is the case here, when 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).

C. Authority To Regulate CO2 From Fossil Fuel-Fired EGUs

    The EPA's authority for this proposed rule is CAA section
111(b)(1). In the 2015 Rule, the EPA discussed the requirements of that
provision and why the Rule met them (80 FR 64529-31). The EPA
summarizes that discussion here, but is not re-opening any of the
issues discussed: 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. Once the
Administrator lists a source category under section 111(b)(1)(A), the
Administrator then promulgates, under section 111(b)(1)(B), ``standards
of performance for new sources within such that category.''
    In the 2015 Rule, the EPA promulgated standards for CO2
emissions from sources in two source categories, fossil fuel-fired
electric utility steam generating units and combustion turbines. The
EPA explained that because it was not listing a new source category, it
was not required to make a new endangerment finding with regard to the
affected sources, and the EPA added that in any event, the required
endangerment finding concerned the source category, and not individual
pollutants. The EPA further explained that section 111(b) does not
specify what pollutants the EPA should regulate once it lists a source
category, so that the EPA may exercise its discretion to regulate
particular pollutants as long as the EPA provides a rational basis for
doing so. In the 2015 Rule, the EPA described its rational basis for
regulating CO2 emissions from fossil fuel-fired EGUs. The
EPA added that even if it were required to make an endangerment finding
for those emissions in order to regulate them, the same facts that
provided the rational basis would qualify as an endangerment finding.

IV. Rationale for Proposed Applicability Criteria

    The current non-fossil applicability exemption is based strictly on
the combustion of non-fossil fuels (e.g., biomass). To be considered a
non-fossil fuel-fired EGU, the EGU must be both (1) capable of
combusting over 50 percent non-fossil fuel and (2) limit the use of all
fossil fuels to an annual capacity factor of 10 percent or less. The
current language does not take heat input from non-combustion sources
(e.g., solar thermal) into account. Certain solar thermal installations
have natural gas backup burners that are over 250 MMBtu/h. As currently
written, these solar thermal installations would not be eligible to be
considered non-

fossil units since they are not capable of deriving more than 50
percent of the heat input from the combustion of non-fossil fuels.
Therefore, solar thermal installations that include backup burners
could meet the applicability criteria of 40 CFR part 60, subpart TTTT
even if the burners are limited to an annual capacity factor of 10
percent or less. Amending the applicability language to include heat
input derived from non-combustion sources would allow these facilities
to avoid applicability with 40 CFR part 60, subpart TTTT by limiting
the use of the natural gas burners to less than 10 percent of the
capacity factor of the backup burners. These EGUs would readily comply
with the emissions standard, but the reporting and recordkeeping would
increase costs for these EGUs. The proposed amended non-fossil
applicability language of changing ``combusting'' to ``deriving'' will
assure that 40 CFR part 60, subpart TTTT continues to cover the fossil
fuel-fired EGUs, properly understood, that it was intended to cover,
while minimizing unnecessary costs to EGUs fueled primarily by
renewable energy. The corresponding change in the base load rating to
include the heat input from non-combustion sources is necessary to
determine the relative heat input from fossil and non-fossil sources.
    The definition of design efficiency (i.e., the efficiency of
converting thermal energy to useful energy output) is used to determine
if an EGU meets the electric sales criteria and is relevant to both new
and existing EGUs. EGUs that sell less electricity than the electric
sales criteria are not included in the applicability of subpart TTTT.
The sales criteria is based in part of the individual EGU design
efficiency. The current definition includes several specific options
for determining the design efficiency. Since the 2015 final rule, the
EPA has become aware that owners/operators of certain existing units do
not have records of the original design efficiency. These units are
therefore not able to readily determine if they meet the applicability
criteria and are subject to the existing source 111(d) requirements.
Many of these units are CHP units and it is highly likely they do not
meet the applicability criteria. However, the current language would
require them to conduct additional testing to demonstrate this. To
minimize the compliance burden and to provide additional flexibility to
the regulated community, the proposed amendment to the definition of
design efficiency would allow the Administrator to approve alternate
test methods to determine the design efficiency. For existing CHP units
with large useful thermal outputs that would clearly not meet the
electric sales applicability criteria, this could potentially include
the use of historical operating data.
    For CHP units, the current approach for determining net electric
sales for applicability purposes allows the owner/operator to subtract
the purchased power of the thermal host facility. The intent of the
approach is to determine applicability similarly for third-party
developers and CHP units owned by the thermal host facility.\54\
However, as currently written, each third-party CHP unit would subtract
the entire electricity use of the thermal host facility when
determining its net electric sales. It is clearly not the intent of the
provision to allow multiple third-party developers that serve the same
thermal host to all subtract the purchased power of the thermal host
facility when determining net electric sales. This would result in
counting the purchased power multiple times. In addition, it is not the
intent of the provision to allow a CHP developer to provide a trivial
amount of useful thermal output to multiple thermal hosts and then
subtract all of the thermal hosts' purchased power when determining net
electric sales for applicability purposes. The proposed amendment would
set a limit to the amount of thermal host purchased power that a third-
party CHP developer can subtract for electric sales when determining
net electric sales equivalent to the percentage of useful thermal
output provided to the host facility by the specific CHP unit. This
approach would eliminate both circumvention of the intended
applicability by sales of trivial amounts of useful thermal output and
double counting of thermal host-purchased power.
---------------------------------------------------------------------------

    \54\ For contractual reasons, many developers of CHP units sell
all the generated electricity to the electricity distribution grid
even though in actuality a significant portion of the generated
electricity is used onsite. Owners/operators of both the CHP unit
and thermal host can subtract the site purchased power when
determining net electric sales. Third party developers that do not
own the thermal host can also subtract the purchased power of the
thermal host when determining net electric sales for applicability
purposes.
---------------------------------------------------------------------------

    Finally, during the 2015 rulemaking, the EPA identified the
Washington County (GA) and Holcomb (KS) EGU projects as ``projects
under development'' that would not be able to meet the standard of
performance without a complete redesign (80 FR 64542-43). As a result,
the EPA determined that it would not be appropriate to apply the
standard to those projects and excluded them. The EPA added that if it
received information suggesting that either will be built, the Agency
would propose a standard of performance specifically for the project.
It is not clear if these projects will be constructed, and, if so,
whether they would be able to meet the standard proposed in this
action. For this reason, the EPA is not proposing to amend the manner
in which the 2015 Rule addressed these projects. Thus, the proposed
standard would not apply to these projects, and if the Agency receives
information suggesting that either will be built, the EPA will propose
a standard of performance specifically for the project. However, the
EPA also requests comment on whether the projects should be covered by
the standard proposed in this action (Comment C-5)

V. Rationale for Proposed Emission Standards for New and Reconstructed
Fossil Fuel-Fired Steam Generating Units

    In the 2015 Rule, the EPA determined that partial CCS was the BSER
for newly constructed coal-fired steam generating units. The EPA
determined that partial CCS had reasonable costs (the levelized cost of
electricity (LCOE) was comparable to the costs of two then-current
projects to add nuclear capacity, and the percentage increase in
capital costs was comparable to increases that the industry had shown
it could absorb),\55\ was technically feasible in the majority of the
U.S., achieved meaningful emission reductions, and promoted technology
development. For the reasons discussed immediately below, on the basis
of updated information, the EPA proposes that partial CCS does not
qualify as the BSER; and for the reasons discussed further below, the
EPA proposes that highly efficient generation technology is the BSER.
---------------------------------------------------------------------------

    \55\ The two projects are SCE&G and Santee Cooper's V.C. Summer
Nuclear Generating Station and Georgia Power and Southern Company's
Vogtle Electric Generating Station.
---------------------------------------------------------------------------

A. Review of the 2015 BSER Analysis

1. Review of Reasonable Cost Criteria
    In the 2015 Rule, as part of the partial CCS BSER determination,
the EPA evaluated the costs for new base load electricity generating
options to determine what was a ``reasonable'' cost. Specifically, the
EPA determined that the LCOE for a new non-natural gas fossil fuel-
fired power plant would be ``reasonable'' if it was consistent with the
LCOE associated with the construction of a new nuclear power plant. The
EPA argued that the

increased costs (relative to a newly constructed natural gas combined
cycle EGU) were reasonable because utilities had indicated to the EPA
that they valued the fuel diversity provided by coal-fired EGUs (80 FR
64510). The EPA also determined that an increase in the capital cost of
slightly more than 20 percent was reasonable when compared to previous
CAA rulemakings affecting the power sector (80 FR 64560). Since 2015,
additional facts have come to light that have led the EPA to reassess
these determinations and therefore to reassess the reasonableness of
the cost of partial CCS.
    Projections in 2015 from the EPA, EIA, and utility planners
consistently showed NGCC as the lowest cost option for new intermediate
and base load generation. Consistent with the 2015 Rule, current
utility forecast models continue to project that few, if any, new coal-
fired power plants will be built in the U.S. in the subsequent
decade.\56\ However, these models do not necessarily account for
certain source-specific considerations that power plant developers use
to determine what type of generation technology to construct. The EPA
explained in the 2015 Rule that it was possible that circumstances
would arise under which a developer would find it advantageous to build
a new coal-fired EGU, for example, for purposes of fuel diversification
(80 FR 64513), and the EPA has not received information since the 2015
Rule that would cause it to rule out that possibility. In the event a
new coal-fired EGU is constructed in the U.S., in the absence of the
requirements of 40 CFR part 60, subpart TTTT, as finalized in 2015, the
EPA believes that the majority of large coal-fired EGUs would adopt the
use of supercritical steam conditions and the majority of small coal-
fired EGUs would use the best available subcritical steam conditions.
This is consistent with the analysis included in the 2015 final rule.
---------------------------------------------------------------------------

    \56\ Power sector modeling does not predict the construction of
any new coal-fired EGUs. Therefore, based on modeled impacts, any
GHG requirements for new coal-fired EGUs would have no significant
costs or benefits.
---------------------------------------------------------------------------

    In addition, as part of the 2015 rulemaking the EPA received public
comments stating that there is value in maintaining the ability to
develop non-natural gas-fired base load generation that is not captured
in economic dispatch models (80 FR 64559). These values can include,
but are not limited to: Historically stable fuel prices; fuel security
(i.e., the ability to store significant quantities of fuel onsite), and
site-specific jobs and economic development considerations (e.g., local
mining and power plant jobs, maintaining an active rail line,
maintaining the property tax base, and, in the case of coal refuse,
remediation of existing environmental concerns). The EPA also noted
that a number of integrated resource plans (IRPs) \57\ recognize
significant value in these fuel diversity considerations (80 FR 64526,
64563). Several utilities included nuclear and coal-fired options in
their resource plans expressly to preserve fuel diversity within their
portfolios.\58\ These utility sector plans justified ``prudent'' costs
(that were significantly higher than the projected least cost option)
to maintain fuel diversity. Based on these factors, in the 2015
rulemaking, the EPA developed metrics for determining reasonable costs,
i.e., a cost level for performance standards at which new coal-fired
EGUs can still be part of the future fuel diversity mix. These cost
indicators were (1) the LCOE of other options for new non-natural gas-
fired base load generation (e.g., nuclear) and (2) the percentage
increase in capital cost.
---------------------------------------------------------------------------

    \57\ An Integrated Resource Plan (IRP) is a publicly available
long-term resource plan outlining a utility's resource needs,
considering both supply and demand side resources, to meet future
energy demands reliably and cost effectively.
    \58\ U.S. EPA, Technical Support Document: Review of Electric
Utility Integrated Resource Plans, July 31, 2015, available in the
rulemaking docket at https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0495-11775.
---------------------------------------------------------------------------

a. Levelized Cost of Electricity (LCOE) Comparison
(1) Background
    As part of the 2015 rulemaking, the EPA assumed that developers
valued fuel diversity and were therefore willing to pay a premium for
non-natural gas-fired dispatchable base load generation. The EPA
concluded that the LCOE of new nuclear (and biomass) generation was one
appropriate indicator of the value of maintaining the option to develop
new non-natural gas-fired base load generation. For this metric, the
EPA used cost data from EIA \59\ and U.S. Department of Energy National
Energy Technology Laboratory (DOE/NETL) \60\ to project the cost at
which a new coal-fired EGU with partial CCS would have substantially
similar levelized cost compared to new nuclear capacity. Table 4
includes the summary table of the EPA's cost projections from the
preamble to the 2015 final rule (See 80 FR 64562, Table 8). The data in
Table 4 reflect the EPA's 2015 determination that the cost of full
carbon capture was not reasonable.\61\ However, the EPA further
determined that the cost of the specified partial CCS level in Table 4
was reasonable because they were comparable to the costs of new nuclear
capacity. The increase in the LCOE from a supercritical pulverized coal
unit due to partial CCS ranged from approximately 20 to 30 percent.
---------------------------------------------------------------------------

    \59\ EIA, Levelized Cost and Levelized Avoided Cost of New
Generation Resources in the Annual Energy Outlook 2015. June 2015.
Available at https://www.eia.gov/outlooks/archive/aeo15/pdf/electricity_generation.pdf.
    \60\ U.S. DOE NETL, Cost and Performance Baseline for Fossil
Energy Plants Supplement: Sensitivity to CO2 Capture Rate
in Coal-Fired Plants, DOE/NETL-2015/1720, June 22, 2015, available
at https://www.netl.doe.gov/energy-analyses/temp/SupplementSensitivitytoCO2CaptureRateinCoalFiredPowerPlants_062215.pdf.
    \61\ A further indication of the unfavorable economics of full
capture CCS may be found in the recent cancellation by the Canadian
firm, SaskPower of its planned CCS retrofits at additional units at
the Boundary Dam facility, in Saskatchewan, Canada, due to high
costs. See C. Marshall, ``Landmark project puts coal expansion on
ice,'' Greenwire, July 10, 2016 (subscription required).

Table 4--Predicted Cost and CO2 Emission Levels for a Range of Potential
             New Generation Technologies From the 2015 Rule
------------------------------------------------------------------------
                               Emissions (lb CO2/
         Technology                MWh-gross)           LCOE* ($/MWh)
------------------------------------------------------------------------
SCPC--no CCS (bit)..........                 1,620                 76-95
SCPC--no CCS (low rank).....                 1,740                 75-94
SCPC + ~16% CCS (bit).......                 1,400                92-117
SCPC + ~ 25% CCS (low rank).                 1,400                95-121
Nuclear (EIA)...............                     0                87-115
Nuclear (Lazard)............                     0                92-132
Biomass (EIA)...............  ....................                94-113

Biomass (Lazard)............  ....................                87-116
IGCC........................                 1,430                94-120
NGCC........................                 1,000              ** 52-86
------------------------------------------------------------------------
* The emissions and LCOE (2011 $) for the SCPC cases, IGCC, and NGCC are
  based on the NETL ``Sensitivity to CO2 Capture Rate'' report. The
  nuclear and biomass LCOE (2011 $) are based on data from EIA and
  Lazard. The LCOE ranges include an uncertainty of -15%/+30% on capital
  costs for SCPC and IGCC cases and an uncertainty of -10%/+30% on
  capital costs for nuclear and biomass cases. LCOE estimates displayed
  in this table for SCPC units with partial CCS as well as for IGCC
  units use a higher financing cost rate in comparison to the SCPC unit
  without capture.
** This range represents a natural gas price from $5/MMBtu to $10/MMBtu.

(2) Comparison With Biomass-Fired Power Plants
    While the EPA included biomass in the 2015 rulemaking LCOE
analysis, the EPA noted that new nuclear power, which, besides natural
gas combustion turbines, is the principal other option often considered
for providing new base load power (79 FR 1477). Biomass-fired EGUs are
smaller in scale \62\ and not as closely analogous to coal-fired
generation as is nuclear power. EIA projects that average net
additional biomass generation capacity amounts to less than 100 MW
annually. The largest domestic biomass-fired EGU is less than 200 MW
and the largest international biomass-fired EGUs are less than 300 MW.
Similar to coal refuse-fired EGUs, biomass-fired EGUs are limited
geographically because they tend to be located in areas with large
quantities of biomass that can be cost effectively delivered to the
plant. Based on these considerations, the EPA does not consider biomass
to be an appropriate comparison for coal-fired generation.
---------------------------------------------------------------------------

    \62\ Biomass-fired EGUs tend to have challenges in securing and
transporting large amounts of biomass.
---------------------------------------------------------------------------

(3) Comparison With Nuclear-Fueled Power Plants
(a) Levelized Cost of Electricity (LCOE)
    In the 2015 analysis, the EPA assumed nuclear generation and coal-
fired generation were similarly attractive for purposes of fuel
diversity. As part of this review, the EPA is reevaluating whether that
assumption is valid. Specifically, the EPA is requesting comment on
whether nuclear capacity is more attractive than coal as an option for
providing fuel diversity (Comment C-6). Nuclear projects have no
emissions of criteria pollutants, hazardous air pollutants (HAPs),\63\
or GHGs. Particularly in light of potential future costs associated
with GHG emissions, nuclear projects provide a significant price
stability guarantee. In addition, the incremental generating costs for
nuclear projects are lower than those for coal-fired EGUs, thus,
nuclear EGUs would be expected to dispatch more frequently and provide
more actual non-natural gas generation per amount of installed
capacity.\64\ Therefore, to the extent that nuclear projects are more
attractive than coal-fired EGUs for providing fuel diversity,
developers could be willing to pay more of a premium for nuclear
projects than for coal-fired EGUs.
---------------------------------------------------------------------------

    \63\ HAP are toxic air pollutants regulated under CAA section
112.
    \64\ EIA used a 90 percent capacity factor for nuclear when
calculating the LCOE in the 2015 Rule. According to EIA, the average
nuclear EGU capacity factors was 92 percent in 2017.
---------------------------------------------------------------------------

    On the other hand, more recent information, since the 2015 Rule,
indicates that the LCOE of a new nuclear EGU is in fact higher than
what developers may be willing to accept. In 2015, multiple new
advanced Generation III+ nuclear units were under construction in the
U.S.65 66 including, at that time, two new units each at the
Summer and Vogtle nuclear power plants in South Carolina and Georgia,
respectively. However, since the 2015 Rule, both the Summer and Vogtle
projects have experienced significant delays and cost overruns. South
Carolina Electric and Gas (SCE&G), majority owner of Summer, has now
abandoned completion of both reactors and has raised rates at least
nine times to cover the increasing costs of the reactors.\67\ While
over budget and behind schedule, construction of both the Vogtle units
continues. They are scheduled to be completed in 2021 and 2022.
Furthermore, there appear to be no new nuclear projects under
construction or that have received regulatory approval at this time.
According to EIA, which reports data on recently constructed EGUs and
planned EGU additions, including EGUs under construction, EGUs that
have received regulatory approvals but that have not commenced
construction, and planned projects that have not received regulatory
approvals, the only planned nuclear project is the Utah Associated
Municipal Power Systems (UAMPS) Carbon Free Power Project. This project
proposes to use small modular nuclear reactors developed with funding
from the DOE. However, this project has not yet received all of the
required regulatory approvals to proceed. The EPA solicits comment on
the extent to which new nuclear energy projects can serve as a
comparison point, for purposes of fuel diversity, for new coal-fired
EGUs (Comment C-7).
---------------------------------------------------------------------------

    \65\ EIA, Form EIA-860 Detailed Data, 2014, available at https://www.eia.gov/electricity/data/eia860/,3_1_Generator_Y2014.xls,
``Proposed'' sheet.
    \66\ As of the promulgation of the 2015 Rule, 4,400 MW of new
nuclear capacity was under construction with 2019-20 commercial
operating dates.
    \67\ G. Blade, ``Santee Cooper, SCANA abandon Summer nuclear
plant construction,'' Utility Dive, July 31, 2017, available at
https://www.utilitydive.com/news/santee-cooper-scana-abandon-summer-nuclear-plant-construction/448262/.
---------------------------------------------------------------------------

    In the 2015 Rule, the partial CCS costs were based largely on the
report, ``Cost and Performance Baseline for Fossil Energy Plants
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired
Power Plants,'' June 22, 2015 (DOE/NETL-2015/1720). The EPA used the
reported costs without any significant adjustments. In this rulemaking,
the EPA is proposing to make refinements to the CO2
transmission and storage (T&S) costs and EGU capacity factors. That is,
as described below, the EPA is proposing to adjust the T&S costs based
on the amount of CO2 captured and adjust the capacity factor
based on the increase in variable operating costs due to the impact of
partial CCS. Accounting for these factors revises the LCOE with partial
CCS upwards. The EPA also proposes in the alternative to use the NETL
costs without any significant adjustments, similar to the approach used
in the 2015 Rule. The EPA is not aware of any more recent, detailed, or
transparent costing analysis specific to coal-fired EGUs with or
without carbon capture technology. The EPA invites the

public to identify any additional costing information.
    First, the CO2 T&S costs in the NETL baseline reports
are not included in the reported capital cost or operation and
maintenance (O&M) costs but are treated separately and added to the
LCOE. Specifically, the combined transport and storage costs for
geologic storage (not accounting for any revenues from the sale of
CO2) equaled $11 per metric ton of captured CO2.
This cost represents annual transportation through a 100-kilometer (km)
(62 mile) CO2 pipeline and storage in a deep saline
formation in the Midwest of 3.2 million tons of CO2.\68\ The
EPA used this value in all the partial capture cases as well. In this
rule, to account for economies of scale, the EPA is proposing to adjust
the T&S costs based on the amount of CO2 captured. To
estimate the T&S costs, the EPA is using the FE/NETL CO2
Transport Cost Model and the FE/NETL CO2 Saline Storage Cost
Model with the same general assumptions described in ``Performance
Baseline for Fossil Energy Plants, Volume 1a: Bituminous Coal (PC) and
Natural Gas to Electricity, Revision 3,'' July 6, 2015 (DOE/NETL-2015/
1723) and adjusting the metric megatons of CO2 transported
and stored.\69\ Table 5 shows the resulting total estimated T&S costs
for various amounts of captured CO2.
---------------------------------------------------------------------------

    \68\ Use of the T&S costs for the Illinois Basin (i.e., Midwest)
are consistent with the NETL costing approach. According to NETL,
T&S costs would be similar for the East Texas Basin. However, T&S
costs for the Williston Basin are estimated to be 40 percent higher,
and T&S costs for the Power River Basin are approximately double.
    \69\ For additional detail on CO2 T&S costing see
section 2.7.3 CO2 Transport and Storage in volume 1a,
revision 3 of the NETL baseline reports and the T&S technical
support document that is available in the docket.

 Table 5--CO2 Transport and Storage Costs for Various Amounts of Capture
------------------------------------------------------------------------
                                                          Total T&S cost
                    Megatonne (Mt)/yr                     (2016 $/tonne)
------------------------------------------------------------------------
4.2.....................................................             9.6
3.2.....................................................              11
2.6.....................................................              12
2.0.....................................................              13
1.4.....................................................              16
0.62....................................................              29
------------------------------------------------------------------------

    The EPA is using the best fit trendline to estimate the T&S costs
for various amounts of CO2 capture. The trendline predicts
that costs would increase substantially at lower levels of capture. As
stated previously, the EPA also proposes in the alternative to use an
$11 metric ton T&S costs consistent with the NETL costing approach and
the 2015 Rule.
    Second, as part of the 2015 rulemaking, for the LCOE calculations,
consistent with the NETL calculations, as noted above, the EPA assumed
a constant capacity factor \70\ (i.e., electric sales) regardless of
the amount of CCS installed on the representative (i.e., model) coal-
fired EGU. This simplified approach captured the fixed and operating
costs of CCS but did not account for the impact of economic dispatch
(e.g., it did not include analysis of the interaction of the affected
EGU with the grid or other EGUs on an hourly basis) and loss of
potential revenue due to lower electric sales.
---------------------------------------------------------------------------

    \70\ EPA used an 85 percent capacity factor, consistent with the
NETL LCOE calculations.
---------------------------------------------------------------------------

    However, electricity is a unique commodity in that it cannot (at
present) be stored at a large scale at a reasonable cost. Therefore,
electric grid operators need to make plans and take actions to match
supply and demand in real time. Multiple factors influence which EGUs
supply power to the grid to satisfy system load (e.g., transmission and
operational constraints) at any given point, and in which order. In the
simplest terms, economic dispatch is used to satisfy the grid load at
minimal costs. In the economic dispatch model, EGUs with the lowest
marginal (i.e., operating) costs are dispatched first. Those EGUs
increase output until all the load is satisfied or until the EGUs
cannot supply additional power. If needed, EGUs with higher operating
costs are then dispatched to satisfy demand. The process continues by
dispatching more expensive units until the grid load is satisfied. The
marginal cost of the final generator needed to meet load sets the
system marginal cost. Owners and operators of generators are paid based
on the system marginal cost. Therefore, net revenue is the difference
between the variable operating costs and the system marginal cost.
    Importantly, economic dispatch only accounts for the costs directly
associated with power plant operations and does not consider any fixed
costs. This is important because historically units with high fixed
costs (e.g., coal-fired and nuclear EGUs) have low operating costs,
dispatch often, and typically run as base load units. For example,
nuclear units tend to have operating costs on the order of $15 to $20
per MWh and capacity factors of greater than 90 percent. These units
would be able to recover their high fixed costs by spreading them out
over many MWh of electric sales. Units with low fixed costs but high
operating costs (e.g., simple cycle combustion turbines) have
historically tended to dispatch last and provide peaking power. With
natural gas prices of $4 per MMBtu, the operating costs of simple cycle
units are approximately $40 per MWh and capacity factors are less than
10 percent in most cases. Therefore, an increase in operating costs of
$20 per MWh can change an EGU from a high capacity factor base load
unit to a peaking unit with limited operation. Emission control
equipment can impact both the fixed costs and operating costs of an
EGU. Another important aspect of economic dispatch, which may be unique
to the electricity generation sector, is that the end user (i.e.,
consumer) has historically had limited, if any, choice in what
technology is used to generate electricity. Therefore, electric
generators compete strictly on the basis of their variable costs, with
no ability to differentiate their product.
    In deregulated markets, a new coal-fired EGU must compete directly
against all other forms of generation, including existing coal-fired
EGUs and natural gas-fired combined cycle units. A developer of a new
coal-fired EGU could anticipate revenues from capacity payments,
various ancillary services, and to the extent the new unit is
dispatched, energy payments. In a deregulated market, each of these
revenue streams is priced through competitive market-based structures.
As described earlier, revenue from energy payments will largely be
determined based on variable operating costs. Any requirements that
impact variable operating costs could impact the ability of the owner/
operator of a new coal-fired EGU to obtain adequate revenues to cover
the generation investment and recover costs.
    In the 2015 Rule, commenters indicated that competitive electricity
markets only allow for the entry of competitively-priced power.
Therefore, a new coal plant with partial CCS that was compliant with an
NSPS requirement based on the use of CCS might not be competitive
compared to older coal plants with no CCS requirements (even if the
older plants are less thermally efficient). The EPA responded that,
given current and projected market conditions, any new coal-fired EGU
would likely only be built in a location where it would be expected to
operate at a high capacity factor (e.g., as a base load unit). However,
at least in deregulated markets, economic dispatch is still a factor
for base load units and can change annual capacity factors by multiple
percentage points. Moreover,

an increasing number of coal-fired power plants are changing from base
load to variable load. Accordingly, the EPA is proposing to include the
impact of economic dispatch in determining the costs of a potential new
coal-fired EGU. Inclusion of these costs is a more refined
representation of the impact of the BSER determination. As stated
previously, the EPA is proposing in the alternative that the Agency not
account for economic dispatch and instead use the same capacity factors
regardless of variable operating costs, for the same reasons as the EPA
stated in the 2015 Rule.\71\
---------------------------------------------------------------------------

    \71\ One approach developers could take to reduce the impact on
the capacity factor could be to construct a smaller EGU. While this
would not impact capacity factors strictly based on simplified
economic dispatch (i.e., at the same variable operating costs the
unit would still dispatch after units with lower variable operating
costs) multiple factors impact dispatch and a smaller unit might
provide local grid support that would allow it to operate at higher
capacity factors.
---------------------------------------------------------------------------

    To estimate the impacts at a national level of the increase in
variable operating costs due to partial CCS, the EPA analyzed the
dispatch of coal-fired EGUs relative to variable operating costs.\72\
Based on a review of the variable operating costs and capacity factors
in the Annual Energy Outlook 2018 and fuel prices reported under EIA
form 923, the EPA determined that capacity factors for coal-fired EGUs
decrease approximately 1.5 percent for each $1/MWh increase in
operating costs. Table 6 shows the operating costs of various
generating technologies. The capacity factors for coal-fired EGUs have
been adjusted based on a baseline of the relevant coal rank
supercritical EGU having a capacity factor of 85 percent.
---------------------------------------------------------------------------

    \72\ Fuel costs comprise approximately two-thirds to three-
fourths of the variable operating costs for a coal-fired EGU.

                               Table 6--Proposed T&S Costs and Capacity Factors *
----------------------------------------------------------------------------------------------------------------
                                                                                Variable
                   Technology                      Captured CO2    T&S costs ($/     operating      Amended CF
                                                       (Mt)           tonne)       costs ($/MWh)     (percent)
----------------------------------------------------------------------------------------------------------------
Subcritical PC (bit)............................  ..............  ..............            32.3            83.5
Supercritical PC (bit)..........................  ..............  ..............            31.3            85.0
SCPC + ~16% CCS (bit)...........................         520,000              30            36.9            76.6
Supercritical PC (low rank).....................  ..............  ..............            28.0            85.0
Ultra-supercritical PC (low rank)...............  ..............  ..............            27.4            85.8
SCPC + ~ 26% CCS (low rank).....................       1,000,000              20            36.3            72.5
Combined Cycle CT (NG)..........................  ..............  ..............            33.1  ..............
Simple Cycle CT (NG)............................  ..............  ..............            50.7  ..............
----------------------------------------------------------------------------------------------------------------
* Variable operating costs calculated using $2.61/MMBtu for bituminous coal, $2.09/MMBtu for low rank coal, and
  $4.73/MMBtu for natural gas. Captured CO2 based on an 85 percent capacity factor. Costs are in 2016 $.
  Variable operating costs is also referred to as incremental generating costs. Simple cycle CT variable
  operating costs were estimated by adjusting the combined cycle efficiency to 33 percent.

    The variable operating costs shown in Table 6 demonstrate part of
the reason why the U.S. generation mix is changing so dramatically with
the decrease in the price of natural gas. Fuel costs comprise
approximately two thirds to three quarters, depending on the coal type,
of the variable operating costs for coal-fired EGUs. In comparison,
fuel costs comprise over 90 percent of the variable operating costs for
combined cycle EGUs. Therefore, declining natural gas prices can have a
dramatic impact on the competitiveness of natural gas-fired EGUs
relative to coal-fired EGUs. While the variable operating costs in
Table 6 are based on long term projections for the price of natural
gas, spot process can be significantly lower. When natural gas is
available at $4/MMBtu or less, the variable operating costs of combined
cycle units can drop below those of certain coal-fired EGUs and
displace those units in the dispatch order. The data further show that
due to the relatively high operating costs of CCS compared to other
environmental controls,\73\ a BSER based on partial CCS increases the
variable operating costs of new coal plants to significantly greater
than existing coal-fired EGUs without GHG controls. Therefore, in an
economic dispatch system, a new coal-fired EGU with partial CCS would
dispatch after the majority of existing coal-fired EGUs.\74\ In markets
with significant quantities of coal-fired generation, this could have a