[Federal Register Volume 83, Number 244 (Thursday, December 20, 2018)]
[Proposed Rules]
[Pages 65424-65464]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-27052]
[[Page 65423]]
Vol. 83
Thursday,
No. 244
December 20, 2018
Part III
Environmental Protection Agency
-----------------------------------------------------------------------
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
[[Page 65424]]
-----------------------------------------------------------------------
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.
-----------------------------------------------------------------------
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 protected]. Include Docket ID No. EPA-
HQ-OAR-2013-0495 in the subject line of the message.
Fax: (202) 566-9744. 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: (919) 541-4003; fax
number: (919) 541-4991; and email address: [email protected].
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 (312) 353-6266; and email address: [email protected].
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 (202) 566-1744, and the telephone number for the EPA
Docket Center is (202) 566-1742.
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.
[[Page 65425]]
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
[[Page 65426]]
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.
---------------------------------------------------------------------------
\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.
[[Page 65427]]
Table 1--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 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
[[Page 65428]]
electricity (i.e., there is no heat recovery or steam cycle).
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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).
[[Page 65429]]
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
[[Page 65430]]
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
[[Page 65431]]
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,
[[Page 65432]]
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
[[Page 65433]]
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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).
---------------------------------------------------------------------------
\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.''
---------------------------------------------------------------------------
[[Page 65434]]
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-
[[Page 65435]]
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
[[Page 65436]]
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
[[Page 65437]]
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
[[Page 65438]]
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,
[[Page 65439]]
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
significant impact on the economic viability of a new coal-fired EGU.
Table 7 shows the LCOE at an 85 percent capacity factor and $11/tonne
T&S costs compared to an LCOE using the amended T&S costs (based on the
amount of CO2 captured) and using an adjusted capacity
factor (based on the variable operating costs). The revised LCOE
numbers account for both the amended approach to calculating T&S costs
and the change in capacity factor.
---------------------------------------------------------------------------
\73\ The EPA notes that unlike other environmental controls,
there is limited regulatory requirements or incentive to reduce GHG
emissions aside from the NSPS requirements. For example, local or
regional programs could require reductions in criteria pollutant
from all EGUs and/or owners/operators of EGUs can accrue regulatory
benefits in other regulatory programs due to criteria pollutant
reductions (e.g., offsets and emission credits). These programs
minimize the impact of the environmental controls on dispatch
because costs are spread more evenly to the entire EGU fleet.
\74\ This could create a perverse environmental incentive to
operate existing coal more than it otherwise would. A utility-system
dispatch model would be required to estimate the potential overall
environmental impacts.
Table 7--Predicted Cost and CO2 Emission Levels for a Range of Potential
New Generation Technologies
------------------------------------------------------------------------
Amended LCOE
Technology LCOE * ($/MWh) ** ($/MWh)
------------------------------------------------------------------------
Subcritical PC (bit).................... 81.2 82.1
Supercritical PC (bit).................. 81.7 81.7
SCPC + ~16% CCS (bit)................... 96.2 105.4
Supercritical PC (low rank)............. 85.2 85.2
Ultra-supercritical PC (low rank)....... 87.6 87.0
[[Page 65440]]
SCPC + ~ 26% CCS (low rank)............. 109.0 122.8
------------------------------------------------------------------------
* 85 percent capacity factor and $11/tonne T&S.
** Capacity factor adjusted based on variable operating costs and T&S
costs adjusted based on amount of captured CO2.
Assuming a constant 85 percent capacity factor and $11/tonne T&S
costs, the LCOE for a bituminous-fired SCPC with partial CCS is 18
percent higher than a SCPC without CCS. However, when the refined T&S
and capacity factors are accounted for, the relative increase in LCOE
for a bituminous-fired SCPC with partial CCS is 29 percent higher than
SCPC without CCS, a 63 percent increase in the relative LCOE impact of
partial CCS. These costs do not account for any of the potential
benefits of reduced criteria and GHG emissions due to the use of
partial CCS. The EPA solicits comment on if these should be factored
into the analysis, and if so, appropriate metrics to accounting for
these benefits (Comment C-8). Furthermore, the revised LCOE costs are
over 10 percent higher than the nuclear cost metric. Furthermore, even
with only the T&S adjustment, the revised LCOE are five percent higher
than the nuclear metric. The results of this analysis support the EPA's
proposal to revise the 2015 determination that partial CCS is BSER for
coal-fired EGUs. The EPA notes that these costs are for coal-fired EGUs
that are using geologic sequestration (GS) and do not account for any
specific economic incentives (e.g., the federal tax credits for carbon
capture, which are available only for new facilities that commence
construction before January 1, 2024, Internal Revenue Code Sec. Sec.
45Q(a)(3)-(4), (d)--which, in turn, is before the end of the 8-year
period in which the EPA is required to review and, if necessary, revise
the standard of performance that is the subject of this rulemaking, CAA
section 111(b)(1)(B)). If the owner/operator were in a location where
it could sell the byproduct CO2 (e.g., for enhanced oil
recovery or for use in the food industry) variable operating costs
could be reduced relative to an EGU without partial CCS and electric
sales would be expected to increase, offsetting some of the control
costs. For example, as discussed in the 2015 Rule, two coal-fired EGUs
elected to install carbon capture technology and sold the
CO2 to the food industry without any federal funding for the
capture technology (80 FR 64550). This type of utilization of
CO2 has the potential to both develop capture technologies
and increase economic options to reduce emissions. While sale of the
captured CO2 improves the overall economics of a new coal-
fired EGUs, the EPA recognizes that there are places where
opportunities to sell captured CO2 for utilization may not
be presently available. Therefore, consistent with approach adopted in
the 2015 Rule, the EPA is assuming no revenues from the sale of
captured CO2 (80 FR 64572).
(b) Consideration of Capital Cost Increases
In the 2015 rulemaking, commenters from industry recommended that
the EPA should separately consider the significant capital costs of
partial CCS. In response to these comments, the EPA evaluated the
impact of 2015 GHG standards on the capital costs of new fossil-steam
generation and compared the same to the capital costs of prior EPA
regulations. The EPA determined that the incremental capital costs of
partial CCS were reasonable because they were comparable to the
percentage capital costs increase in prior regulations and because the
utility industry has demonstrated the capacity to successfully absorb
capital costs of this magnitude in the past (80 FR 64559).
Specifically, in the 2015 final rule, the EPA concluded that an
increase of 21 to 22 percent for capital coats was reasonable (80 FR
64560).
The EPA cited several comparable rulemakings. First, the 1971 NSPS
for coal-fired EGUs increased costs by $19 million (M) for a 600 MW
plant. These costs consisted of $3.6 M for particulate matter (PM)
controls, $14.4 M for SO2 controls, and $1 M for nitrogen
oxide (NOX) controls; the capital cost of air pollution
control devices added 15.8 percent to the $120 M capital cost of a new
EGU. In that case, the baseline cost was primarily for a coal-fired EGU
with limited environmental controls. In addition, a retrospective
Congressional Budget Office (CBO) study of the 1978 EGU NSPS amendments
estimated that those amendments increased the capital costs for a new
EGU by 10 to 20 percent. There, the baseline costs and overall absolute
costs were higher than the 1971 NSPS because they included the cost of
controls required by the 1971 NSPS. Since the 1978 NSPS, additional
environmental controls have further increased the baseline costs to
construct a new coal-fired EGU. These additional costs include, but are
not limited to, NSPS amendments that established selective catalytic
reduction (SCR) as the BSER for NOX controls in place of low
NOX combustion controls and more stringent SO2
and PM standards, rulemakings that require mercury (Hg) controls, and
rulemakings that limit the use of once-through cooling. All of these
additional environmental control requirements increase the baseline
costs of constructing a new coal-fired EGU. Therefore, at the same
percentage increase in capital costs, absolute costs are much higher. A
comparable analysis would require that the additional control costs due
to previous rulemakings be accounted for in the baseline costs when
determining an appropriate percent increase in capital costs. The EPA
notes that even without accounting for the different cost basis, the
absolute increase in capital costs was higher for the 2015 Rule than
previous EGU NSPS rulemakings. It should also be noted that the
previous NSPS rulemakings generally concerned multiple pollutants and
adopted multiple requirements based on multiple control technologies,
which makes it more challenging to compare them with the current
rulemaking, which in turn concerns, as a practical matter, a single air
pollutant--CO2--and a single set of controls.
Furthermore, the fact that the utility industry was able to absorb
20 percent increases in cost due to pollution control in the past does
not necessarily mean the industry could do so today. For example, when
previous NSPS rulemakings with significant costs for new coal-fired
EGUs were completed, electricity demand was growing and few
alternatives existed for intermediate and base load generation. At that
time, a new coal-fired EGU built by a regulated utility could
anticipate operating at a high capacity factor for several decades.
[[Page 65441]]
The utility sector is markedly different today. Currently, many coal-
fired EGUs operate at variable load and it would be more difficult for
an owner/operator of a new coal-fired EGU to recoup the additional
control costs. Based on these assessments, the EPA is proposing that
the increase in capital costs due to partial CCS are not reasonable.
In addition, in the 2015 Rule, the EPA cited the Portland Cement
Ass'n ruling that upheld a 12 percent increase in capital costs as
reasonable (See 80 FR 64560, citing 486 F.2d at 387-88). As stated
previously, the EPA is proposing in this rule that the increase in
capital costs due to partial CCS are not reasonable. In any event,
Portland Cement Ass'n is not relevant because, as the EPA further noted
in the 2015 Rule, the costs of control equipment (capital and
operating) for the Portland Cement NSPS could be passed on without
substantially affecting competition with construction substitutes such
as steel, asphalt, and aluminum. Id., citing Portland Cement Ass'n v.
Ruckelshaus, 513 F.2d 506, 508 (DC Cir. 1975). However, in the 2015
Rule, the EPA did not account for the loss of sales (i.e., revenue) in
the electricity market. As described previously, at least in
deregulated markets, for coal-fired EGUs, an increase in operating
costs has an impact on dispatch order and thus product (i.e.,
electricity) sales, and therefore, the overall cost of the partial CCS
BSER determination. That is, the ability of EGUs to pass along their
capital costs to consumers depends on their ability to pass along their
operating costs to consumers. However, higher operating costs that
impact the EGU dispatch order cannot be passed on to end users as
easily (and profit margins cannot be narrowed as easily) without
affecting coal-fired generation's competitiveness with alternate forms
of electricity generation. This means that EGUs cannot pass along their
capital costs as easily as other industries.
(c) Other Measures of Reasonable Costs
The EPA has reviewed the rationale for a dozen GHG permits for EGUs
and other industrial facilities that were permitted between 2011 and
2017. Aside from industrial sources with existing, nearly pure
CO2 process streams (e.g., a natural gas processing
facility) situated near an existing CO2 pipeline (i.e., a
few hundred feet) that could implement CO2 capture at little
or no net cost, none of the GHG permits considered CCS to be a
reasonable cost control technology. Energy efficiency was considered
the appropriate control technology for the majority permit
determinations. The fact that all of the EGU permit determinations
rejected CCS as a reasonable control technology supports the conclusion
that CCS is not an appropriate BSER.
2. Whether CCS Is Adequately Demonstrated
In the 2015 Rule, the EPA found that partial CCS was ``adequately
demonstrated'' under CAA section 111(a)(1), a requirement that, as
noted above, incorporates the concept of technical feasibility.
However, upon further review, the EPA is proposing to revise its
analysis and determine that CCS is not adequately demonstrated in
certain key respects, as described in this section.
a. Availability of Geologic Sequestration (GS)
In the 2015 Rule, the EPA noted that, as a practical matter, the
issue of whether all new steam-generating EGUs can implement partial
CCS depends on the geographic scope of suitable GS sites. Therefore, as
part of that rulemaking, the EPA performed a geographic analysis \75\
in which the Agency examined areas of the country with sequestration
potential in deep saline formations, oil and gas reservoirs, unmineable
coal seams, and active, enhanced oil recovery (EOR) operations;
information on existing and probable, planned or under study
CO2 pipelines; and areas within a 100-km (62-mile) area of
locations with sequestration potential. The distance of 100 km was
consistent with the assumptions underlying the NETL cost estimates for
transporting CO2 by pipeline. Based on the geographic
analysis performed, the EPA determined that GS sites were widely
available and that a steam-generating plant with partial CCS, sited
near an area suitable for GS, could serve power demand in a large area,
notwithstanding that the area itself might not contain sequestration
sites. As part of the review for this action, the EPA has re-evaluated
these determinations. In addition, the EPA has reviewed the impact of
water availability with respect to geographic availability of CCS.
---------------------------------------------------------------------------
\75\ U.S. EPA, Technical Support Document: Geographic
Availability, July 31, 2015, available in the rulemaking docket at
https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0495-11772.
---------------------------------------------------------------------------
Since the 2015 Rule, the EPA has updated its analysis on geographic
availability. Using updated information from NETL,\76\ the Agency has
identified the geographic extent of potential GS in deep saline
formations and oil and gas reservoirs. The updated data show relatively
minimal changes in estimated storage resources, with most of the
changes occurring in Wyoming and Midwestern states (Kentucky, Michigan,
Illinois, Indiana and North Dakota) as a result of additional
characterization and assessment studies by the DOE Regional Carbon
Sequestration Partnerships.\77\ In addition, the EPA has updated its
list of counties where active EOR operations are occurring, based on
data reported to the EPA Greenhouse Gas Reporting Program (GHGRP) (See
40 CFR part 98, subpart UU, Injection of Carbon Dioxide, 2011-2017
data).\78\ The GHGRP data show four additional counties where active
EOR operations have occurred since the EPA's analysis in 2015. Finally,
the Agency has updated its information on existing CO2
pipelines based on Department of Transportation data along with the
locations of pipelines that are probable, planned or under study. In
general, these updates do not significantly change the EPA's
understanding of which areas are amenable to GS.
---------------------------------------------------------------------------
\76\ U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition,
September 2015, available at https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
\77\ For deep saline formations, the low-end estimate of storage
resource increased from 2,100 billion metric tons to 2,379 billion
metric tons, and the high-end estimate increased from 20,014 billion
metric tons to 21,633 billion metric tons. For oil and gas
reservoirs, the storage resource was previously estimated at 225
billion metric tons, and is now estimated at a low-end estimate of
186 billion metric tons and a high-end estimate of 232 billion
metric tons.
\78\ U.S. EPA, Greenhouse Gas Reporting Program, available at
https://www.epa.gov/ghgreporting. Data reported as of August 19,
2018.
---------------------------------------------------------------------------
The NETL Carbon Storage Atlas (Atlas) used for the EPA's analysis
of geographic availability provides a high-level overview of
prospective resources across the United States. This assessment
represents the fraction of pore volume of porous and permeable
sedimentary rocks available for CO2 storage and accessible
to injected CO2 via drilled and completed wellbores. The
estimates in the Atlas do not take into account economic or regulatory
constraints, only physical constraints (i.e., the accessible parts of
geologic formations via wellbores). The deployment of partial CCS is
site-specific and its application will depend on local market and
geologic conditions. Therefore, the cost of deploying partial CCS will
be highly variable on a geographic basis. While storage capacity
appears large in the Atlas, site-specific technical, regulatory, and
economic considerations will ultimately impact how much of that
resource is economically available. That is, the Atlas shows an
estimate of potential storage areas, but not economically
[[Page 65442]]
viable storage areas (i.e., areas where projects make business and
financial sense). Additionally, the various types of geologic
formations assessed in the Atlas have been characterized to varying
degrees. That is, there is more uncertainty in the assessment of
certain types of formations as compared to others. The maturity of oil
and gas exploration and production in certain parts of the United
States makes sequestration potential in these reservoirs relatively
well understood. However, there are still limitations to the
feasibility of GS in all oil and gas reservoirs identified as areas of
potential storage in the Atlas. Additionally, despite showing large
potential, saline storage has not yet been demonstrated to be
available, both from a geographical perspective as well as
economically, at all locations. For example, the major milestone saline
project from Archer Daniels Midland is underway, but only reflects the
feasibility of saline injection and storage at one location in the
United States. This project is still in its early stages and has not
yet proven that GS in saline formations can be done throughout the
United States (at scale) in wide geographic regions with highly diverse
geologic conditions. The project is sized at one million metric tons
per year and may not demonstrate the full application of saline storage
necessary for a large power project.
Regarding the third type of geologic formation assessed in the
Atlas, unmineable coal seams, the EPA has changed its assumptions since
the 2015 analysis. While the Atlas includes potential availability of
unmineable coal seams, the EPA has excluded this type of formation from
potential GS areas. As part of its 2015 analysis, the EPA expressed its
view unmineable coal seams offered the potential for geologic storage
and explained the technical process by which it thought that
CO2 could be injected underground to enhance methane
recovery (also known as enhanced coalbed methane recovery) while
adsorbing to the coal surface (80 FR 64576). NETL identified states
that it considered had the potential for storage in unmineable coal
seams. Some of these areas, including Iowa and Missouri, have little to
no EOR or saline sequestration potential and generate electricity at
coal-fired EGUs. Several successful small-scale demonstration projects
had been performed to evaluate the potential for GS in unmineable coal
seams, and research to optimize CO2 storage in coals was
ongoing. However, upon further review, the EPA now believes that the
processes and technologies associated with GS at unmineable coal seams
are still being developed and, in the years since the EPA expressed the
understanding and expectations underlying this aspect of its analysis
in the 2015 Rule, there have been no large-scale demonstrations of GS
associated with unmineable coal seams.\79\ In the 2015 rulemaking, the
EPA had found that the largest pilot project, the Allison Unit
CO2-ECBM pilot in New Mexico, stored 270,000 metric tons of
CO2 from 1995-2001 (an average of 45,000 tons per year).\80\
Recent DOE Regional Carbon Sequestration Partnership projects have
injected CO2 volumes ranging from 90 tons to 16,700
tons.\81\ While these projects demonstrated some degree of potential
for GS in unmineable coal seams, most were in the nature of pilot
programs undertaken to evaluate project designs and collect data to
better understand the mechanisms of injection and CO2
storage. Therefore, the project durations and injected amounts were
limited. The limited duration and amounts of the tests may have
affected the outcomes, as some tests began to show decreases in the
effectiveness of CO2 injection over time due to swelling of
the coals. This observation raises doubts regarding the feasibility of
larger-scale GS in unmineable coal seams at this time. For example, in
the Pump Canyon test, the effectiveness of CO2 storage was
believed to be limited due to the small amount of CO2
injected.\82\ The amount of CO2 injected in these tests was
significantly less than projects at deep saline formations or at oil
and gas reservoirs where CO2 was injected in the million-ton
range. The EPA now believes that additional research using larger scale
and longer duration tests in unmineable coal seams is needed to improve
the understanding and modeling of CO2 storage in coals.
Unmineable coal seams have not been shown to be a suitable GS
technology option for purposes of this action; however, such formations
could have potential applicability in the future. Therefore, unmineable
coal seams have been excluded from potential GS areas in the analysis
underlying this proposal. The elimination of unmineable coal seams
reduces the geographic availability of sequestration areas by
approximately 4 percent.\83\
---------------------------------------------------------------------------
\79\ See, e.g., M. Godec et al., ``CO2-ECBM: A Review
of its Status and Global Potential,'' Energy Procedia 63: 5858-5869
(2014), available at https://doi.org/10.1016/j.egypro.2014.11.619;
IEAGHG, Potential Implications on Gas Production from Shales and
Coals for Geological Storage of CO2, Report Number 2013/10,
September 2013, available at http://www.ieaghg.org/docs/General_Docs/Reports/2013-10.pdf.
\80\ Id.
\81\ J. Litynski et al., ``Using CO2 for enhanced
coalbed methane recovery and storage, CBM Review, June 2014,
available at https://www.netl.doe.gov/File%20Library/Research/Carbon-Storage/Project-Portfolio/CBM-June-2014.pdf.
\82\ M. Godec et al., ``CO2-ECBM: A Review of its
Status and Global Potential,'' Energy Procedia 63: 5858-5869 (2014),
available at https://doi.org/10.1016/j.egypro.2014.11.619; IEAGHG,
Potential Implications on Gas Production from Shales and Coals for
Geological Storage of CO2, Report Number 2013/10 (September 2013),
available at http://www.ieaghg.org/docs/General_Docs/Reports/2013-10.pdf.
\83\ Based on an analysis of the information provided in U.S.
DOE NETL, Carbon Storage Atlas, Fifth Edition, September 2015,
available at https://www.netl.doe.gov/research/coal/carbon-storage/atlasv and areas within 100 km (62 miles) of these locations. The
geographic area decreased by 411,156 square km (158,748 square
miles).
---------------------------------------------------------------------------
For these reasons, GS may not be as widely geographically available
as assumed in the 2015 analysis. Further work being conducted by DOE to
devise and develop technologies that can improve wellbore integrity,
increase reservoir storage efficiency, quantitatively assess and
mitigate risks, and confirm permanent storage of CO2 through
reliable, cost-effective, multilevel monitoring programs in storage
complexes in diverse geologic settings would help determine actual
availability of GS in all types of formations. Additionally, work on
the DOE Carbon Storage Assurance Facility Enterprise (CarbonSAFE)
initiative, an effort to develop an integrated CCS storage complex
constructed and permitted for operation in the 2025 timeframe, will
increase understanding of the feasibility of GS across the United
States and further characterize the availability of GS.
b. Water Availability
Currently available amine-based solvent capture systems require
water for process makeup and cooling. As part of the 2015 rulemaking,
multiple commenters expressed concerns that the EPA's determination
that partial CCS was BSER was inappropriate because of increased water
consumption impacts and geographical (or other) water availability/
scarcity issues limiting or eliminating CCS implementation. The EPA
acknowledged that, similar to other air pollution controls, such as a
wet flue gas desulfurization scrubber, post-combustion amine-based
capture systems result in increased water consumption. However, the EPA
evaluated the issue and found the water use to be manageable (80 FR
64593). The Agency stated that the studies \84\
[[Page 65443]]
referenced by commenters that indicated significant increases in water
use from CCS cooling and process operations compared to coal-fired EGUs
without CCS were for cases where full CCS (90 percent or greater
capture) is implemented, and were therefore of limited relevance to its
determination that partial CCS was BSER.
---------------------------------------------------------------------------
\84\ See comments of UARG at p. 84 (Docket entry: EPA-HQ-OAR-
2013-0495-9666) citing Haibo Zhai, et al., ``Water Use at Pulverized
Coal Power Plants with Post-Combustion Carbon Capture and Storage,''
Environ. Sci. Technol., 45:2479-85 (2011); U.S. DOE NETL, Water
Requirements for Existing and Emerging Thermoelectric Plant
Technologies at 13 DOE/NETL-402/080108, August 2008, April 2009
revision.
---------------------------------------------------------------------------
In the 2015 Rule, the EPA examined water use predicted from the
updated DOE/NETL studies to determine the magnitude of increased water
usage for a new SCPC EGU implementing partial CCS to meet the final
standard of 1,400 lb CO2/MWh-gross. The EPA in 2015
determined that the results showed that a new SCPC unit that implements
16 percent partial CCS to meet the final standard would see an increase
in water consumption (the difference between the predicted water
withdraw and discharge) of about 6.4 percent compared to an SCPC with
no CCS and the same net power output. Further, the EPA expressed the
view that there would be additional opportunities to minimize the water
usage at such a facility. For example, the SaskPower Boundary Dam Unit
#3 post-combustion capture project captures water from the flue gas and
recycles the water, resulting in decreased withdrawal of fresh water.
In addition, while the Agency did not find IGCC to be the BSER, the
predicted water consumption for the new IGCC unit was nearly 20 percent
less than that predicted for the new SCPC unit without CCS (and almost
25 percent less than the SCPC unit meeting the final standard). The EPA
also predicted that water consumption at a new NGCC unit would be less
than half that for a new SCPC EGU with the same net output.
In the 2015 Rule, the EPA's water use increase comparison, which
was summarized in Table 13 of the 2015 final rule preamble (80 FR
64592), was evaluated based on a bituminous-fired EGU with a wet
scrubber and a cooling tower. While this is one common configuration
for an EGU boiler and associated air pollution control device, this
does not account for other boiler configurations and other air
pollution control devices. Certain regions of the country with an arid
climate and/or scarce water availability often use boiler and pollution
control devices that minimize water use. While the absolute amount of
water required for CO2 capture equipment is relatively
constant on a gallon per ton of captured CO2 basis across
various boiler types, the percentage increase in water requirements is
not. A more appropriate percentage increase comparison for arid western
markets and other locations in water-scarce environments is a
subbituminous-fired PC unit with spray drying or a fluidized bed unit
and a cooling tower. To estimate the increased water consumption for
low rank coal-fired EGUs, the EPA used the NETL partial capture report
for bituminous coal-fired EGUs to determine the increased water
requirements per amount of CO2 captured. The EPA then
applied the increased water use relationship to the 2011 baseline
report that included model plants burning low rank coal.
As shown in Table 8, the percent increase in water use for EGUs
burning low rank coals is four times as large as for bituminous-fired
EGUs. The EPA is proposing that this increase in water requirements is
so great that it could be prohibitively expensive for developers to
secure sufficient quantities of water in arid regions of the
country.85 86
---------------------------------------------------------------------------
\85\ Part of the rationale that the water requirements are too
great is that the water requirements for partial CCS are roughly
double that of the water requirements for a spray dryer used for
SO2 control.
\86\ In the 2015 final rule, the EPA referenced SaskPower
Boundary Dam's lignite-fired Unit #3 post-combustion capture project
that recovers water from the flue gas and recycles it, resulting in
decreased need for withdrawal of fresh water from the adjacent
reservoir. However, specific data on how much water was captured/
saved was not cited. In retrospect, the EPA now believes that it
should have considered that for new lignite-fired power plants
owners/operators would likely dry the lignite prior to combustion.
Drying lignite both decreases the capital cost of a new boiler
island and increases boiler efficiency. However, it results in less
water in the flue gas, limiting the amount that can be captured/
recycled. The same might be the case for new subbituminous coal-
fired EGUs--they would likely dry the coal prior to combustion so
less water would be available in the flue gas for recovery and
reuse.
\87\ In the 2015 rulemaking, the raw water consumption for a
SCPC with no CCS (bit) was reported as 4,095 gallons per minute
(gpm) instead of 4,045 gpm. This resulted in a reported increase in
water use of 6.4 percent instead of 7.7 percent.
Table 8--Predicted Water Consumption
------------------------------------------------------------------------
Raw water Increase in
consumption water use
Technology (gpm/MWnet) compared to no
\1\ CCS (%) \87\
------------------------------------------------------------------------
SCPC - no CCS (bit)..................... 7.4 ..............
SCPC + ~16% CCS (bit)................... 7.9 7.7
SCPC - no CCS (low rank))............... 3.8 ..............
SCPC + ~ 26% CCS (low rank)............. 4.9 28
------------------------------------------------------------------------
\1\ MWnet = megawatts-net.
\2\ SCCFB = supercritical circulating fluidized bed.
In addition to the configurations cited in the NETL report, other
boiler configurations use even less water. For example, Black Hills
Power Corporation's 110-MW Wygen III is a pulverized coal power plant
near Gillette, Wyoming. The plant, which came online in 2010, fires
Powder River Basin coal and has an air pollution control system
comprised of selective catalytic reduction, dry flue gas
desulfurization (FGD), and a fabric filter baghouse. This type of
``dry'' plant was built with minimal water requirements due to dry
cooling and dry lime FGD for acid gas control. As described elsewhere
in the preamble, this type of boiler design is one of the
configurations likely to be considered for future coal-fired EGUs.
However, carbon capture technologies are limited to using conventional
wet cooling technologies. The EPA is unaware of any demonstration,
pilot, or large-scale projects using dry cooling technologies with
carbon capture technologies. Therefore, requiring CCS on a plant of
this design would substantially increase the plant's water-use
requirements.
All CCS systems that are currently available require substantial
amounts of water to operate. These water requirements would limit the
geographic availability of potential future EGU construction to areas
of the country with sufficient water resources.
[[Page 65444]]
To establish water availability, the EPA has, for this proposal,
reviewed annual average rainfall totals as an estimation of water
availability. This approach indicates that the Western U.S. (i.e.,
areas west of a line running from central Texas to North Dakota),
excluding the Pacific Northwest, has lower amounts of water available
for EGUs. In addition, a comparison of areas of the country with lower
rainfall amounts shows considerable overlap with areas of the country
with sequestration sites. This suggests that many sequestration sites
might not have sufficient water resources to operate CO2
capture equipment. Therefore, this, in combination with the EPA's
proposed determination that its earlier understanding of the scope of
geologic sequestration site availability was an overestimation (by some
4 percent), has led the EPA to propose a revision to its 2015 findings
and a new determination that the overall geographic availability of CCS
is too limited to be considered as BSER.
In the 2015 Rule, EPA also stated that a new IGCC unit required
nearly 20 percent less water than a new bituminous coal-fired SCPC unit
without CCS (and almost 25 percent less than the SCPC unit meeting the
final standard). The DOE/NETL reports indicate that IGCC designs are
available that use less water than comparative PC units for low rank
coals as well. However, in an April 2017 independent engineering report
on the Kemper IGCC Project,\88\ one of the concerns noted was the
underestimation of the amount of water needed for the process water
system. The report noted that the initially planned 5 million gallons
of storage was insufficient, that a new 1.7-million-gallon temporary
tank was to be installed and that additional permanent water storage
tank capacity should be considered. Based on this, the EPA is
soliciting comment on whether IGCC reduces the amount of water use by
coal-fired EGUs (Comment C-9).
---------------------------------------------------------------------------
\88\ This project received federal assistance under the Energy
Policy Act of 2005 (EPAct05). See 2015 rule, 80 FR at 64526, n.74.
The EPA is not proposing to revise or re-open the interpretation of
EPAct05 that the EPA included in the 2015 rule. Id. at 64541-64542.
Thus, because the EPA is considering information about the Kemper
project in conjunction with other information that is not from
facilities affected by EPAct05, EPAct05 does not preclude the EPA
from considering such Kemper information.
---------------------------------------------------------------------------
c. Review of Technical Feasibility of Carbon Capture Equipment
In the 2015 Rule, the EPA determined that CO2 capture
technology was technically feasible based on EGUs that had previously
and were currently using post-combustion carbon capture technology
(especially Boundary Dam), commercial vendors that offered carbon
capture technology and other performance guarantees, a review of the
literature, and industry and technology developers' pronouncements of
the feasibility and availability of CCS technologies. Since the 2015
rulemaking, the Petra Nova CCS project, located at NRG's W.A. Parish
power generating station near Houston, Texas, has begun operations, and
is reported to be the world's largest post-combustion carbon capture
system.\89\
---------------------------------------------------------------------------
\89\ As with the Kemper project discussed above, this project
received federal assistance under EPAct05. See 2015 rule, 80 FR at
64526, n.74. As with the Kemper project, because EPA is considering
information about the Petra Nova project in conjunction with other
information that is not from facilities affected by EPAct05, EPAct05
does not preclude EPA from considering the Petra Nova information.
---------------------------------------------------------------------------
While the carbon capture technology at the Boundary Dam project is
currently operating, that project experienced multiple issues with the
performance of the capture technology during its first year of
operation (2014-15). During that time, the capture equipment was
operating with lower reliability than designed, and, as a result,
SaskPower renegotiated its CO2 supply contract with Cenovus
to avoid paying penalties for not supplying the agreed amount of
CO2 for the company's EOR projects. These problems included
the amine chemistry and the CO2 compression system. While
the Petra Nova project is currently operating, it has not demonstrated
the integration of the thermal load of the capture technology into the
EGU steam generating unit (i.e., boiler) steam cycle. Rather, the
parasitic electrical and steam load are supplied by a new 75 MW co-
located natural gas-fired CHP facility. The EPA solicits comment on
whether Boundary Dam's first-year operational problems cast doubt on
the technical feasibility of fully integrated CCS (Comment C-10). For
example, would an EGU with a fully integrated steam cycle that draws
steam from the steam turbine to regenerate the amine be able to operate
during periods when the carbon capture system is not operating?
The EPA notes that while both these projects are currently
operating, both received significant government support to mitigate the
financial risks associated with the CCS technology. Because no
independent commercial CCS projects are in operation, the EPA solicits
comment on whether the fact that Boundary Dam and Petra Nova were
dependent on government support casts doubt on the technical
feasibility of CCS, e.g., whether it raises concerns as to the extent
to which developers are willing to accept the risks associated with the
operation and long-term reliability of CCS technology (Comment C-11).
While the EPA did not find that a new IGCC EGU is part of the final
BSER, the Agency did note that IGCC without CCS is a viable alternative
compliance option. However, both the Edwardsport and Kemper IGCC
facilities had significant cost overruns. In fact, the Kemper IGCC's
technology challenges, escalating costs, and project management issues
resulted in the company suspending startup and operations activities
involving the lignite gasification portion of the energy facility,
leaving only the natural gas combined cycle plant in operation.\90\ The
EPA solicits comment on the extent to which the issues with these IGCC
EGUs cast doubt on the economic viability of IGCC as an option for new
generation (Comment C-12).
---------------------------------------------------------------------------
\90\ URS Corp., IM Monthly Report--Mississippi Public Service
Commission: Kemper IGCC Project, April 2017, available at http://www.psc.state.ms.us/executive/pdfs/2017/Kemper/Monthly%20Report%20April%202017%20Executive%20Summary.pdf.
---------------------------------------------------------------------------
B. Identification of the Revised BSER
The EPA evaluated six different control technology configurations
as potentially representing the BSER for new and reconstructed coal-
fired EGUs: (1) The use of partial CCS, (2) conversion to (or co-firing
with) natural gas, (3) the use of CHP, (4) the use of a hybrid power
plant, (5) the use of IGCC technology, and (6) efficient generation.
This section discusses each of these alternatives, including the
technical systems that the EPA considered for the BSER, evaluations of
each system, and the reasons for determining that the most efficient
generating technology meets the criteria to qualify as the BSER. The
discussion includes the rationale for selecting the proposed standards
of performance based on those BSER.
As noted above, the EPA determines the best demonstrated system
based on the following key considerations, among others:
The system of emission reduction must be technically
feasible.
The costs of the system must be reasonable. The EPA may
consider the costs on the source level, the industrywide level, and, at
least in the case of the power sector, on the national level in terms
of the overall costs of electricity and the impact on the national
economy over time.
[[Page 65445]]
The EPA must also consider energy impacts, and, as with
costs, may consider them on the level of the source, the region, and on
the nationwide structure of the power sector over time.
According to the D.C. Circuit caselaw, the EPA must
consider the amount of emissions reductions that the system would
generate, and that CAA section 111 is designed to promote the
development and implementation of technology. Moreover, the EPA has
discretion to weigh these various considerations, may determine that
some merit greater weight than others, and may vary the weighting
depending on the source category.
1. Partial CCS
As described previously, under the revised analysis set forth in
this proposal, the EPA proposes that the cost of partial CCS is not
reasonable. In addition, when the availability of water and geologic
sequestration sites are considered together, the EPA finds that partial
CCS is not widely geographically available. In addition, the EPA is
soliciting comment on whether there is sufficient information about the
long-term reliability of carbon capture technology and sequestration
capture technology to assess the technical feasibility of CCS (Comment
C-13). Therefore, the EPA proposes to rescind our finding that partial
CCS satisfies the BSER criteria and proposes to find that it does not.
2. Conversion to or Co-Firing With Natural Gas
While co-firing with natural gas in a utility steam generating unit
a technically feasible option to reduce CO2 emission rates,
it is an inefficient way to generate electricity compared to use of an
NGCC. For cases where the natural gas could be co-fired without any
capital investment (e.g., sufficient natural gas is available at the
site) or impact on the performance or operation of the affected EGU,
the costs of CO2 reduction would be between approximately
$40 to $70 per ton of CO2 avoided (that is, $40/ton for
bituminous coal and $70/ton for subbituminous coal), depending on the
coal rank burned in the boiler. This calculation only accounts for the
relative costs and CO2 emission rates of the fuel and does
not account for potential adverse or positive impacts on the operation
of the boiler. While natural gas prices have fallen significantly over
the past decade, long term price projections forecast that natural gas
will still be significantly more expensive than coal on a $/MMBtu
basis. The higher fuel costs from co-firing would increase both the
LCOE and variable operating costs of the unit. As described earlier,
due to economic dispatch, the unit would be expected to have lower
electricity sales, and therefore generate less revenue and less
marginal and overall profit. Further, if an owner/operator is required
to burn natural gas for compliance purposes, it would likely have to
enter into firm service contracts as opposed to interruptible service
contracts for natural gas, which would increase its costs for natural
gas. Potential positive aspects include a reduction in pre-post
combustion control criteria pollutant and HAP emission rates. Due to
these lower pre-post combustion emission rates, post-combustion control
requirements are reduced and savings could be realized due to both
lower capital and O&M post combustion control costs and/or the cost of
emission allowances under certain pollution control programs. Most
pollutants, and especially NOX, would be reduced in
proportion to the amount of natural gas burned.
Natural gas reburning (NGR) is a combustion technology in which a
portion of the main fuel heat input is diverted to locations above the
burners, creating a secondary combustion zone called the reburn zone.
In NGR, natural gas is injected to produce a slightly fuel rich reburn
zone. Overfire air (OFA) is added above the reburn zone to complete
burnout. NGR requires 15 to 20 percent of furnace heat input from
natural gas and OFA and has been demonstrated to reduce NOX
emissions by 39 to 67 percent on several existing coal-fired boilers in
applications ranging in size from 33 to 600 MW in the U.S. and up to
800 MW internationally. With NGR at 15 and 20 percent of the heat input
to a coal-fired boiler, the CO2 emission rate would be
reduced by 6 to 10 percent.
Fuel lean gas reburning (FLGR\TM\), also known as controlled gas
injection, is a process in which natural gas is injected above the main
combustion zone at a lower temperature zone than in NGR. FLGR\TM\ is
different from NGR because the gas is injected in a manner that
optimizes the furnace's stoichiometry on a localized basis. By doing
this, the process avoids creating a fuel-rich zone and maintains
overall fuel-lean conditions. The FLGR\TM\ technology achieves
NOX control using less than 10 percent natural gas heat
input without the requirement for OFA. FLGR\TM\ has a capital cost of
approximately $8/kW \91\ and been demonstrated to reduce NOX
emissions by 33 to 45 percent. At a 10 percent heat input reburn rate,
the CO2 emission rate of a coal-fired EGU would be reduced
by 4 to 5 percent. Based strictly on the difference in fuel prices, co-
firing 10 percent natural gas would only increase the LCOE of a coal-
fired EGU by approximately 2 or 3 percent. However, variable operating
costs would increase between approximately 7 to 9 percent, impacting
dispatch and energy revenue for the EGU.
---------------------------------------------------------------------------
\91\ Breen, Fuel Lean Gas Reburn (FLGR) Solutions, available at
http://breenes.com/wp-content/uploads/2017/07/FLGR_ljv4singles.pdf.
---------------------------------------------------------------------------
In addition, while many recently constructed coal-fired power
plants routinely use natural gas or other fuels such as low sulfur fuel
oil for start-up operations and, if needed, to maintain the EGU in
``warm stand-by,'' some areas of the U.S. have natural gas pipeline
infrastructure limitations. These areas either currently lack access to
natural gas transportation infrastructure or face capacity constraints
in their existing natural gas pipelines (i.e., they are not able to
greatly increase purchase volumes with the existing
infrastructure).\92\ For new coal-fired EGUs wishing to locate in these
areas, it could be either infeasible or extremely costly to co-fire
natural gas. The EPA solicits comment on the cost to add natural gas
capability to areas of the county without sufficient infrastructure to
support a new natural gas-fired EGU (Comment C-14).
---------------------------------------------------------------------------
\92\ Maps of natural gas pipelines and underground storage
facilities are available from EIA, https://www.eia.gov/naturalgas/archive/analysis_publications/ngpipeline/index.html. Information on
pending projects are available from EIA and the Federal Energy
Regulatory Commission (FERC), https://www.eia.gov/naturalgas/pipelines/EIA-NaturalGasPipelineProjects.xlsx and https://www.ferc.gov/industries/gas/indus-act/pipelines/pending-projects.asp
---------------------------------------------------------------------------
While co-firing natural gas might be a viable option for specific
coal-fired EGUs, the EPA is not proposing natural gas co-firing as part
of the BSER for multiple reason. First, as discussed previously, a
significant benefit of a new coal-fired power plant is the fuel
diversity value that it brings. Requiring the EGU to burn natural gas
defeats the purpose of constructing the EGU in the first place.
Further, not all areas of the country have cost-effective access to
natural gas. Co-firing natural gas is an inefficient use of the
nation's natural gas resources, which is relevant under the ``energy
requirements'' criterion for BSER. Combined cycle EGUs are more
efficient at using natural gas to generate electricity and it would not
be environmentally beneficial for utilities to combust natural gas in
less steam generating units to satisfy a facility specific emissions
standard. Finally, at this time, the EPA does not have
[[Page 65446]]
sufficient information to analyze the overall impact of co-firing
natural gas, particularly impacts on dispatch.
3. Combined Heat and Power (CHP)
CHP, also known as cogeneration, is the simultaneous production of
electricity and/or mechanical energy and useful thermal output from a
single fuel. CHP requires less fuel to produce a given energy output,
and because less fuel is burned to produce each unit of energy output,
CHP reduces air pollution and GHG emissions. CHP has lower emission
rates and can be more economic than separate electric and thermal
generation. However, a critical requirement for a CHP facility is that
it primarily generates thermal output and generates electricity as a
byproduct and must therefore be physically close to a thermal host that
can consistently accept the useful thermal output. For coal-fired EGUs,
it can be particularly difficult to locate a thermal host with
sufficiently large thermal demands such that the useful thermal output
would impact the emissions rate. The refining, chemical manufacturing,
pulp and paper, food processing, and district energy industries tend to
have large thermal demands. However, the thermal demand at these
facilities is generally only sufficient to support a smaller coal-fired
power plant, approximately a maximum of 100 MW. This would limit the
geographically available locations where new coal-fired generation
could be constructed in addition to limiting size. Furthermore, even if
a sufficiently large thermal host were in close proximity, the owner/
operator of the EGU would be required to rely on the continued
operation of the thermal host for the life of the EGU. If the thermal
host were to shut down, the EGU would be unable to comply with the
emissions standard. This reality would likely result in difficulty in
securing funding for the construction of the EGU and could also lead
the thermal host to demand discount pricing for the delivered useful
thermal output. For these reasons, the EPA proposes it is not
practicable to find that CHP is BSER.
4. Hybrid Power Plant
Hybrid power plants combine two or more forms of energy input into
a single facility with an integrated mix of complementary generation
methods. While there are multiple types of hybrid power plants, the
most relevant type for this proposal is the integration of solar energy
(e.g., concentrating solar thermal) with a fossil fuel-fired EGU. Both
coal-fired and NGCC EGUs have operated using the integration of
concentrating solar thermal energy for use in boiler feed water
heating, preheating makeup water, and/or producing steam for use in the
steam turbine or to power the boiler feed pumps.
One of the benefits of integrating solar thermal with a fossil
fuel-fired EGU is the lower capital and O&M costs of the solar thermal
technology. This is due to the ability to use equipment (e.g., HRSG,
steam turbine, condenser, etc.) already included at the fossil fuel-
fired EGU. Another advantage is the improved electrical generation
efficiency of the non-emitting generation. For example, solar thermal
often produces steam at relatively low temperatures and pressures, and
the conversion of the thermal energy in the steam to electricity is
relatively low. In a hybrid power plant, the lower quality steam is
heated to higher temperatures and pressures in the boiler (or HSRG)
prior to expansion in the steam turbine, where it produces electricity.
Upgrading the relatively low-grade steam produced by the solar thermal
facility in the boiler improves the relative conversion efficiencies of
the solar thermal to electricity process. The primary incremental costs
of the non-emitting generation in a hybrid power plant is the costs of
the mirrors, additional piping, and a steam turbine that is 10 to 20
percent larger than that in a comparable fossil only EGU to accommodate
the additional steam load during sunny hours. A drawback of integrating
solar thermal is that the larger steam turbine will operate at part
loads and reduced efficiency when no steam is provided from the solar
thermal panels during periods when the sun is not shining (i.e., the
night and cloudy weather). This limits the amount of solar thermal that
can be integrated into the steam cycle at a fossil fuel-fired EGU.
In the 2018 Annual Energy Outlook \93\ (AEO 2018), the levelized
cost of concentrated solar power (CSP) without transmission costs or
tax credits is $161/MWh. Integrating solar thermal into a fossil fuel
EGU reduces the capital cost and O&M expenses of the CSP portion by 25
and 67 percent compared to a stand-alone CSP EGU respectively.\94\ This
results in an effective LCOE for the integrated CSP of $104/MWh.
Assuming the integrated CSP is sized to provide 10 percent of the
maximum steam turbine output and the relative capacity factors of the
coal-fired boiler and the CSP (those capacity factors are 85 and 25
percent, respectively) the overall annual generation due to the
concentrating solar thermal would be 3 percent of the hybrid EGU
output. This would result in a three percent reduction in the overall
CO2 emissions and a one percent increase in the LCOE,
without accounting for any reduction in the steam turbine efficiency.
However, these costs do not account for potential reductions in the
steam turbine efficiency due to being oversized relative to a non-
hybrid EGU. Without this information, the EPA does not have sufficient
information to evaluate costs and overall impact, and therefore cannot
propose this technology as the BSER.
---------------------------------------------------------------------------
\93\ EIA, Annual Energy Outlook 2018, February 6, 2018,
available at https://www.eia.gov/outlooks/aeo/.
\94\ B. Alqahtani and D. Pati[ntilde]o-Echeverri, Duke
University, Nicholas School of the Environment, ``Integrated Solar
Combined Cycle Power Plants: Paving the Way for Thermal Solar,''
Applied Energy 169:927-936 (2016).
---------------------------------------------------------------------------
In addition, solar thermal facilities require locations with
abundant sunshine and significant land area in order to collect the
thermal energy. Existing concentrated solar power projects in the U.S.
are primarily located in California, Arizona, and Nevada with smaller
projects in Florida, Hawaii, Utah, and Colorado. Not all areas of the
U.S. have both sufficient space and the abundant sunshine to
successfully operate a hybrid power plant. The EPA proposes that due to
the limited geographic availability of concentrated solar thermal
projects, the Agency cannot propose this technology as BSER.
---------------------------------------------------------------------------
\95\ The Gerstein power plant, unit K, in Germany integrates a
natural gas-fired combustion turbine that discharges the exhaust
directly into the coal-fired boiler. This essentially creates a
combined cycle EGU with a coal-fired heat recovery steam generator.
---------------------------------------------------------------------------
An alternate, but similar, approach for coal-fired EGUs to
integrate lower-emitting generation would be to use natural gas-fired
combustion turbines, fuel cells, or other combustion technology. These
alternatives can reheat or preheat boiler feed water (minimizing the
steam that is otherwise extracted from the steam turbine), preheat
makeup water and combustion air, produce steam for use in the steam
turbine or to power the boiler feed pumps, or use the exhaust directly
in the boiler to generate steam. In theory, this could lower generation
costs as well the GHG emissions rate for a coal-fired EGU. The EPA is
aware of only one coal-fired EGU currently integrating lower-emitting
combustion technology,\95\ does not have sufficient information to
evaluate costs, and therefore cannot propose this technology as the
BSER.
[[Page 65447]]
5. IGCC
The EPA also considered whether IGCC technology represents the BSER
for new power plants using coal or other solid fossil fuels. While
gasification is available and used in other industrial sectors (e.g.,
petroleum refining) there are relatively few IGCC EGUs. According to
the NETL baseline fossil reports, IGCC units are projected to have a
lower gross-output based emission rates compared to SCPC. However, the
design net emission rates and absolute amount of emissions to the
atmosphere tend to be materially similar so there are limited, if any,
net GHG benefits. Furthermore, the emissions data for the IGCC
facilities in the EPA database does not include the output from the
steam turbine. As a result, it is not possible to verify the gross
emissions rate or estimate the net emissions rate. Therefore, the EPA
does not currently have sufficient information based on actual
operating data to evaluate whether IGCC meets the BSER requirements. In
addition, the NETL baseline fossil fuel reports indicate that IGCC LCOE
costs are 20 percent higher, and the incremental generating costs are 4
percent higher, than a comparable SCPC. However, the two most recent
IGCC EGUs constructed in the U.S. (Edwardsport and Kemper) both
experienced significant cost overruns. In fact, the technical
complexity and costs of the Kemper project were so great that the
gasification project was abandoned and the facility is currently
operating as a natural gas-fired combined cycle facility. Based on
consideration of these factors, the EPA is not proposing IGCC as the
BSER.
6. Energy Efficient Power Generation
This section describes the technology that the EPA proposes for the
BSER: the most efficient generation technology available, which is the
use supercritical \96\ steam conditions (i.e., a SCPC or supercritical
circulating fluidized bed (CFB) boiler) for large EGUs, and the use of
the best available subcritical steam conditions for small EGUs in
combination with the best operating practices and dry cooling. The use
of higher steam temperatures and pressures (e.g., supercritical steam
conditions) increases the efficiency of converting the thermal energy
in the steam to electrical energy. Best operating practices, include,
but are not limited to, installing and maintaining equipment (e.g.,
economizers, feedwater heaters, etc.) in such a way to maximize overall
efficiency and to operate the steam generating unit to maximize overall
efficiency (e.g., minimize excess air, optimize soot blowing, etc.).
The cooling (i.e., condensing) system also has a significant impact on
efficiency. Once through cooling systems use an open system where
cooling water is extracted directly from a water body and returned to
the same water body at a high temperature. This type of cooling result
in the most efficient operation. However, once through system have
greater environmental impacts and new EGUs use either cooling towers or
dry cooling systems. Cooling towers are closed systems where the water
extracted for cooling is evaporated in the cooling tower. Cooling
towers reduce water impacts compared to once through systems, but still
require substantial amounts of water to operate. Dry cooling systems
use air heat exchangers to provide cooling and minimize water impacts.
However, these systems are also the least efficient.
---------------------------------------------------------------------------
\96\ Subcritical coal-fired boilers are designed and operated
with a steam cycle below the critical point of water (22 MPa (3,205
psi)). EGUs using supercritical steam conditions operate at
pressures greater than 22 MPa and temperatures greater than 550
[deg]C (1,022 [deg]F). Increasing the steam pressure and temperature
increases the amount of energy within the steam, so that more energy
can be extracted by the steam turbine, which in turn leads to
increased efficiency and lower emissions.
---------------------------------------------------------------------------
a. Reasonable Costs
Advanced generation technologies enhance operational efficiency
compared to lower efficiency designs. Such technologies are technically
feasible and present little incremental capital cost compared to other
types of technologies that may be considered for new and reconstructed
sources. In addition, due to the lower variable operating costs, more
efficient designs would be expected to dispatch more often and sell
more electricity, thereby offsetting increases in capital costs. It
should be noted that this cost evaluation is not an attempt to
determine the affordability of advanced generation in a business or
economic sense (i.e., the reasonableness of the imposed cost is not
determined by whether there is an economic payback within a predefined
time period). Table 9 lists the capital costs, variable operating
costs, design emission rates, and LCOE for various boiler designs.
Table 9--Cost and Emission Rates of Coal-Fired EGUs (2016 $) \97\
----------------------------------------------------------------------------------------------------------------
Design
Total as spent Variable emissions rate
Technology \98\ capital ($/kW) operating (lb CO2/ MWh- LCOE ($/MWh)
costs ($/MWh) net)
----------------------------------------------------------------------------------------------------------------
Subcritical PC (bit)............................ 2,850 32.3 1,780 81.2
Supercritical PC (bit).......................... 2,940 31.3 1,710 81.7
IGCC (bit)...................................... 3,590 32.0 1,730 97.9
Supercritical PC (low rank)..................... 3,340 28.0 1,890 85.2
Ultra-supercritical PC (low rank)............... 3,520 27.4 1,840 87.6
----------------------------------------------------------------------------------------------------------------
b. Non-Air Quality Health and Environmental Impacts and Energy
Requirements
---------------------------------------------------------------------------
\97\ The primary sources of information are the NETL baseline
fossil reports. The EPA converted the dollar year to 2016 values and
estimated low rank subcritical and bituminous ultra-supercritical
based on the ratios in the relevant baseline fossil reports.
Consistent with the NETL partial CCS approach, costs are ``next-of-
a-kind'' rather than first of a kind (80 FR at 64,570/3). First of a
kind costs are higher than ``next-of-a-kind'' costs but are expected
to decrease (as is normally the case) with the completion of
additional projects and DOE/NETL research.
\98\ The NETL design values are 16.5 MPa (2,400 pounds per
square inch gauge (psig)) () and 566 [deg]C (1,050 [deg]F) for
subcritical EGUs, 24 MPa (3,500 psig) and 593 [deg]C (1,100 [deg]F)
for supercritical EGUs, and 28 MPa (4,000 psig) and 650 [deg]C
(1,200 [deg]F) for ultra-supercritical EGUs.
---------------------------------------------------------------------------
Highly efficient generation reduces all environmental and energy
impacts compared to less efficient generation. Even when operating at
the same input-based emissions rate, the more efficient a unit is, the
less fuel is required to produce the same level of output, so overall
emissions are reduced for all pollutants. Supercritical steam
conditions, compared to subcritical, reduce all pollutants between
approximately 3 to 5 percent. More
[[Page 65448]]
efficient EGUs also have lower auxiliary (i.e., parasitic) loads so
that impacts on energy requirements are also reduced.
c. Extent of Reductions in CO2 Emissions
In the 2015 Rule, the EPA found that highly efficient generation
did not represent BSER in part because it would not result in
meaningful emission reductions and did not promote the development of
control technology. That conclusion was based on the assumption that
any new coal-fired EGU built in the U.S. would use highly efficient
generation even in the absence of 40 CFR part 60, subpart TTTT.
Close to 90 percent of the large coal-fired EGUs that have
commenced operation since 2010 in the U.S. use either supercritical
steam conditions or IGCC technology. The remainder of the capacity uses
subcritical steam conditions. However, according to data submitted to
the EPA's Clean Air Markets Division (CAMD), the average 2017 reported
emissions rate of all large coal-fired boilers that commenced operation
since 2010 was 1,938 lb CO2/MWh-gross. This is two percent
higher than the proposed standard. The sole small coal-fired EGU
reporting emissions that commenced operation since 2010 in the U.S.
uses subcritical steam conditions and had a reported annual emissions
rate of 2,200 lb CO2/MWh-gross, nine percent higher than the
proposed standard. Therefore, if a new coal-fired EGU were to be
constructed, the EPA estimates that the proposed BSER standards would
result in reductions in emissions of approximately two percent for
large EGUs and nine percent for small EGUs when compared to the
expected emissions for new EGUs absent an NSPS establishing standards
for GHG emissions. Fuel costs makeup a significant portion of the
variable operating costs of a coal-fired EGUs and owners/operators of
EGUs currently have a financial incentive to maximize efficiency and
minimize CO2 emissions. While achievable, the proposed
emission rates would require owners/operators of a new coal-fired EGU
to both construct a highly efficient EGU and operate and maintain it to
minimize CO2 emissions.
d. Technical Feasibility
The use of supercritical steam conditions has been demonstrated by
multiple facilities since the 1970s. Between 2013 and 2017, 327
gigawatts (GW) of coal-fired EGUs entered operation globally in 15
countries. The new capacity is split roughly equally between
subcritical, supercritical, and ultra-supercritical steam conditions.
Subcritical units tend to be smaller (i.e., less than 300 MW) and
supercritical units tend to be approximately 500 MW. Ultra-
supercritical EGUs tend to be larger (e.g., 800 MW) and have been built
in China, Germany, South Korea, Netherlands, Malaysia, and Japan.
Materials capable of withstanding ultra-supercritical steam conditions
of 30 MPa (4,350 psi) and 620 [deg]C (1,120 [deg]F) have been
demonstrated internationally at coal-fired boilers.\99\ In addition,
vendors are offering designs capable of withstanding advanced ultra-
supercritical steam conditions of 33 MPa and 670 [deg]C.\100\
Furthermore, using supercritical steam also allows the use of a second
reheat cycle, which further increases efficiency.
---------------------------------------------------------------------------
\99\ Isogo unit 2 (located in Japan) has a reheat temperature of
620 [deg]C and Avedore 2 (located in Denmark) operates at 30 MPa.
\100\ https://www.ge.com/power/steam/steamh.
---------------------------------------------------------------------------
As stated in the 2015 Rule, the smallest supercritical coal-fired
EGU is approximately 200 MW, and steam turbines that operate on
supercritical steam are currently not commercially available for
smaller coal-fired EGUs. Consequently, developers of a small EGU that
wished to use supercritical steam conditions would have to have a steam
turbine designed specifically for that project, substantially
increasing the cost of the project. Therefore, for smaller new and
reconstructed EGUs the maximum economically viable steam pressure and
temperature for which steam turbines are currently available are 21 MPa
(3,000 psi) and 570 [deg]C (1,060 [deg]F). Above this pressure, the
steam would be supercritical. Also, using subcritical steam conditions
limits the steam cycle to use of a single steam reheat cycle.
Therefore, it is not technically feasible for smaller EGUs to use a
second reheat cycle to improve efficiency.
e. Promotion of the Development and Implementation of Technology
As noted above, the case law makes clear that the EPA is to
consider the effect of its selection of BSER on technological
innovation or development, but that the EPA also has the authority to
weigh this against the other factors. Selecting highly efficient
generation technology as the BSER offers an opportunity to encourage
the development and implementation of improved control technology. This
technology is readily transferrable to other countries, existing EGUs,
and other industries.
According to EIA, demand in India and Southeast Asia is projected
to drive an increase in coal use over the next two decades. Coal is
often the fuel of choice because it is abundant, inexpensive, secure,
and easy to store. Clean coal technologies are critical to ensuring
that these economies develop in a more environmentally sustainable way.
According to the World Electric Power database, sixty percent of the
new coal-fired capacity in India and Southeast Asia between 2013 and
2017 uses subcritical steam conditions. Although supercritical
technology is already developed, establishing it as the basis for
control requirements in the U.S. for new and reconstructed sources
would help establish it in other nations, resulting in a reduction in
global CO2 emissions. The EPA considers that the proposed
BSER will promote the development and implementation of viable control
technologies.
f. Nationwide, Longer-Term Perspective of Impacts on the Energy Sector
Designating the most efficient generation technology as the BSER
for new and reconstructed coal-fired utility boilers and IGCC units
will not have significant impacts on nationwide electricity prices.
This is because (1) the additional costs of the use of efficient
generation will, on a nationwide basis, be small because few, if any,
new coal-fired projects are expected, and because at least some of
these can be expected to incorporate efficient generation technology in
any event; and (2) the technology does not add significant costs. For
similar reasons, designation of the most efficient generation
technology as the BSER for reconstructed new coal-fired utility boilers
and IGCC units will not have adverse effects on the structure of the
power sector, will promote fuel diversity, and will not have adverse
effects on the supply of electricity.
Based on the reasonable cost, technical feasibility, and emission
reductions the EPA proposes that efficient generation in combination
with the best operating practices is the BSER for new coal-fired EGUs.
C. Reconstructed EGUs
In the 2015 Rule, the EPA explained the background of, and
requirements for, reconstructed EGUs, evaluated various control
technology configurations to determine the BSER for reconstructed coal-
fired boiler and IGCC EGUs, and selected efficiency improvements
achieved through the use of the most efficient generation technology.
The EPA explained that this technology was technically feasible, had
sufficient emission reductions, had reasonable costs, and had some
opportunity for technological
[[Page 65449]]
innovation. The EPA is taking the same approach in this rulemaking and
is not proposing to change the BSER technology. However, since the BSER
is the same, the Agency is proposing to use the emissions analysis as
for new EGUs for reconstructed EGUs as well. For each of the
subcategories, that is, the BSER and emissions standard for
reconstructed EGUs is the same as for new EGUs.
D. Coal Refuse Subcategory
Coal refuse (also called waste coal) is a combustible material
containing a significant amount of coal mixed with rock, shale, slate,
clay and other material that is reclaimed from refuse piles remaining
at the sites of past or abandoned coal mining operations. In the April
2012 proposal, the EPA solicited comment on subcategorizing EGUs that
burn over 75 percent coal refuse on an annual basis (the EGU NSPS for
criteria pollutants contain such a subcategory). Multiple commenters
supported a subcategory, citing numerous environmental benefits of
remediating coal refuse piles. The EPA declined to adopt a subcategory
and explained that the costs faced by coal refuse facilities to install
partial CCS were similar for coal-fired EGUs burning any of the primary
coals (i.e., bituminous, subbituminous, and lignite). Further, the
final applicable requirements and standards in the rule did not
entirely preclude the development of new coal refuse-fired units
without CCS, for example, through the exclusion for industrial CHP
units. Many existing coal refuse-fired units are relatively small and
designed as CHP units. Due to the expense of transporting coal refuse
long distances, the EPA projected that any new coal refuse-fired EGU
would likely be relatively small. Moreover, sites with sufficient
thermal demand exist such that the unit could be designed as an
industrial CHP facility and the requirements of 40 CFR part 60, subpart
TTTT would not apply.
Under the 2015 partial CCS BSER determination, due to lower
efficiencies and higher uncontrolled emission rates, coal refuse-fired
EGUs would have had to install a slightly higher percentage of partial
CCS, increasing costs roughly in proportion to the percentage increase
in partial CCS. These increase in costs were determined to be
sufficiently similar and a subcategory for coal refuse-fired EGUs was
not necessary. However, as described previously the proposed BSER (and
the corresponding emissions rate) for coal-fired EGUS (including coal
refuse-fired EGUs) is efficient generation and not the use of partial
CCS. Therefore, the cost rationale for not providing a subcategory for
coal refuse-fired EGUs is not necessarily applicable. For multiple
reasons, coal refuse-fired EGUs have higher uncontrolled emission
rates. Coal refuse generally has lower energy density (British thermal
units per pound (Btu/lb) of fuel) due to its high ash content along
with a higher emissions rate on a pound of CO2 per million
British thermal unit (lb CO2/MMBtu) basis. Unlike with
``wet'' coals such as lignite, there are limited options for upgrading
the energy density of coal refuse. This lower energy density leads to
inherently lower efficiency steam generating units. Furthermore,
certain coal refuse piles have high sulfur contents. While remediating
these piles through combustion provides significant multimedia
environmental benefits, combusting these fuels presents challenging
problems. To control sulfur emissions, significant quantities of
limestone are added to the fluidized bed boilers. This not only
decreases efficiency (due to the additional fuel required to calcine
the limestone) but leads to chemically created CO2 (released
when the limestone is calcined to lime) that is released through the
stack. These factors make it difficult for coal refuse-fired EGUs to
achieve the same output-based GHG emission rates of EGUs burning
primary coals. While coal refuse-fired EGUs do not report sufficient
emissions data to the EPA's CAMD to determine their emission rates,
based on normalization of emissions data, a coal refuse-fired EGU would
emit approximately 20 percent more than a comparable bituminous-fired
EGU. Therefore, if there is not a subcategory for coal refuse-fired
EGUs, a developer of a new coal refuse-fired EGU would be required to
install controls beyond the BSER technology basis.
In the 2015 Rule, the EPA concluded that, due to their relatively
small size, new coal refuse-fired EGUs would likely be designed as CHP
units and would therefore not be subject to 40 CFR part 60, subpart
TTTT. However, the EPA has conducted a more recent analysis of the
makeup of existing coal refuse-fired EGUs, which calls this conclusion
into question. There are 18 existing coal refuse-fired EGUs that range
from 400 to 2,500 MMBtu/h heat input. Only half of these units are CHP
units, and the other half are strictly electricity production
facilities. As stated previously, coal refuse-fired EGUs tend to be
located close to existing coal refuse piles, and there is no assurance
that a suitable thermal host will locate in those areas. Without a
thermal host, the coal refuse-fired unit would not qualify as a CHP
unit, and, instead, would become subject to 40 CFR part 60, subpart
TTTT. Consequently, the EPA is proposing to revise our conclusion that
all new coal refuse-fired EGUs have the ability to avoid applicability
with 40 CFR part 60, subpart TTTT.
Considering these factors, the EPA proposed that the BSER for coal
refuse-fired EGUs is the use of the best available subcritical steam
conditions in combination with the best operating practices. One
benefit of creating a subcategory for coal refuse-fired EGUs is to not
discourage the development of these projects and to recognize the
multimedia environmental benefits of remediating coal refuse
piles.\101\ The non-air quality environmental benefits include the
remediation of acid seepage and leachate production, low soil
fertility, and reclaiming land for productive use. An additional
consideration is that existing coal refuse piles are slowly combusting
in place and the CO2 will eventually be released to the
atmosphere so net GHG emissions are lower than those measured at the
stack.
---------------------------------------------------------------------------
\101\ The criteria pollutant coal-fired EGU NSPS subcategorizes
coal refuse-fired EGUs in part due to the environmental benefits of
remediating coal refuse piles.
---------------------------------------------------------------------------
E. Determination of the Level of the Standard
Once the EPA has determined that a particular system or technology
represents BSER, the CAA authorizes the Administrator to establish NSPS
emission standards for new units that reflect the application of that
BSER. In this case, the EPA proposes to determine that BSER is
supercritical steam technology for large EGUs, and subcritical steam
technology for small EGUs and coal refuse-fired EGUs. However, the Act
prohibits the Administrator from expressly requiring sources to use any
particular technology, such as supercritical steam conditions (See CAA
section 111(b)(5), (h)). These provisions also ensure that NSPS
standards do not preclude development of future technologies that may
be even more efficient than the current supercritical systems. For new
and reconstructed coal-fired boiler and IGCC EGUs, the EPA proposes to
find that the best available steam conditions--which qualify as the
BSER--support a standard of 1,900 lb CO2/MWh-gross for large
EGUs (i.e., those with a nameplate heat input greater than 2,000 MMBtu/
h), 2,000 lb CO2/MWh-gross for small EGUs (i.e., those with
a nameplate heat input less
[[Page 65450]]
than or equal 2,000 MMBtu/h), and 2,200 lb CO2/MWh-gross for
coal refuse-fired EGUs. Compliance with these standards would be
determined on a 12-operating month rolling average basis. These levels
of the standard are based on the emissions performance that can be
achieved by a large pulverized or CFB coal-fired EGU using
supercritical steam conditions and small and coal refuse-fired EGUs
using subcritical steam conditions.
To determine what emission rates are currently achieved by existing
coal-fired EGUs, the EPA reviewed annual generation and CO2
emissions data from 2008 through 2017 for all coal-fired EGUs that
submitted continuous emissions monitoring system (CEMS) data to the
EPA's emissions collection and monitoring plan system (ECMPS). The data
was sorted by the lowest maximum annual emissions rate for each unit to
identify long term emission rates on a lb CO2/MWh-gross
basis that have been demonstrated by the existing coal fleet. Since an
NSPS is a never-to-exceed standard, the EPA is proposing that long-term
data are more appropriate than shorter term data to use in determining
an achievable standard. These long-term averages account for
degradation and variable operating conditions, and the EGUs should be
able to maintain their current emission rates, as long as the units are
properly maintained. While annual emission rates indicate a particular
standard is achievable for certain EGUs in the short term, they are not
necessarily representative of emission rates that can be maintained
over an extended period using the most efficient available steam cycle
(i.e., the BSER), the range of fuel types that are burned, or all
cooling systems.
Specifically, EGUs with the lowest annual emission rates use wet
cooling systems and do not use dry cooling systems. Both recirculating
cooling towers and once-through cooling systems require substantial
amounts of water. In fact, the power sector is one of the largest
freshwater consumers in the U.S.\102\ Water usage by the power sector
strongly depends on the generation technology. For example, combined
cycle units use much less cooling water, because significantly less
heat energy remains that is required to be removed by cooling at the
outlet of the steam turbine of a combined cycle unit compared to a
coal-fired EGU of the same capacity.
---------------------------------------------------------------------------
\102\ Water use in coal to Power Applications, available at
https://www.netl.doe.gov/research/Coal/energy-systems/gasification/gasifipedia/water-usage.
---------------------------------------------------------------------------
Dry cooling systems, however, may be necessary for a particular EGU
due to limited water availability or desirable to eliminate the adverse
environmental impacts caused by cooling tower intake structures. A
drawback of dry cooling systems is that the EGU is unable to reach as
low of a condensing temperature as with either a recirculating cooling
tower or a once-through open system and is therefore less efficient.
The EPA is aware of four existing coal-fired EGUs using a dry cooling
system. Three are located in Wyoming, and one is located in Virginia.
While the projects in Wyoming use this type of system in part or in
whole due to the arid climate, the project in Virginia demonstrates
that water use concerns are likely applicable to areas with larger
amounts of rainfall as well. To further determine the likelihood that a
developer of a new coal-fired EGU would want to use a dry cooling
system, the EPA reviewed the cooling system of combined cycle units.
More than 15 percent of operating natural gas-fired combined cycled
capacity in the U.S. uses dry cooling technology.\103\ Based on
analysis of form EIA-860 data, these dry cooling systems are located
throughout the U.S., further indicating that water use concerns are
more widespread than just arid locations with limited rainfall.
Therefore, the EPA is proposing that the NSPS for coal-fired EGUs
should account for the use of dry cooling by setting higher emission
rates that account for the lower efficiency of EGUs using dry cooling.
The EPA is soliciting comment on whether it is appropriate to
subcategorize based on geography and, if so, how that subcategorization
should be done (Comment C-15). One potential approach would be to add a
provision allowing the Administrator to approve alternate emissions
standards for coal-fired EGUs located in areas without access to
sufficient water to operate a cooling tower. Paragraph 60.4330(b) of
the combustion turbine criteria pollutant NSPS (40 CFR part 60, subpart
KKKK) includes a similar provision. That provision allows the
Administrator to approve alternate SO2 standards for a
combustion turbine without access to natural gas and located in an area
where removal of sulfur compounds would cause more environmental harm
than good.
---------------------------------------------------------------------------
\103\ ``Some U.S. electricity generating plants use dry
cooling,'' Today in Energy, EIA, 29 August 2018, https://www.eia.gov/todayinenergy/detail.php?id=36773.
---------------------------------------------------------------------------
In order to determine the 12-operating month average emissions rate
that is achievable by application of the BSER, the EPA analyzed data
reported by owners/operators of EGUs to the CAMD database to identify
the best performing (i.e., the best operated and maintained) EGUs. The
EPA normalized the emissions rate data to account for factors that the
Agency has information on and that engineering equations can be used to
account for design efficiency differences between EGUs based on the
factors. The design factors include the steam cycle (i.e., steam
temperature and pressure and the number of reheat cycles), coal type
(which impacts both boiler efficiency and emissions on a lb
CO2/MMBtu basis), cooling type (i.e., dry, recirculating
cooling tower, and open), and average ambient temperature. The EPA
identified the single best EGU based on this normalized emissions rate.
The EPA selected this single best unit to account for site specific
factors about which the Agency does not have specific information.
These factors include, but are not limited to, (1) design factors
influencing efficiency (e.g., number of feedwater heaters, economizer
efficiency, combustion and soot blowing optimization, and an exposed
structure or main building enclosure) and (2) O&M practices (e.g.,
percent excess air, operator training, and prioritizing efficiency
related repairs). The owner/operator of a new EGU would be able to
incorporate the best EGU design parameters and O&M practices. The EPA
then adjusted the emissions data for the best performing EGU by
applying engineering equations for the EGU design factors (steam cycle,
etc.) that impact the theoretical efficiency and the CO2
emissions rate. For example, if a particular unit had no steam reheat
cycle, the EPA estimated the theoretical increase in efficiency for a
similar unit with a single reheat cycle.
Factors for which owners/operators have more limited influence
include the condenser technology and ambient temperature. For example,
designers can specify ultra-supercritical steam conditions compatible
with state-of-the art metallurgy, multiple stages of feedwater heating,
and double steam reheat cycles to optimize efficiency gains
attributable to increasing the average temperature at which heat is
supplied to the cycle. However, designers have fewer options for
lowering the temperature at which heat is rejected from an affected EGU
because this low-temperature constraint is largely determined by the
available cooling reservoir and local ambient
[[Page 65451]]
conditions. Consistent with the 2015 Rule, to account for the impact of
ambient conditions, the EPA conservatively normalized the emission rate
data to 20 [deg]C, with one exception. Since coal refuse-fired EGUs are
located in more temperate regions, the EPA assumed 10 [deg]C for coal
refuse-fired EGUs. In the 2015 rulemaking, the EPA assumed that a new
large EGU would use some type of a wet cooling tower, but specifically
accounted for air cooled condensers (i.e., dry cooling) only for the
small EGU subcategory. However, as described previously, the EPA is
proposing to account for dry cooling for both large and small EGUs.
The EPA calculated 12-month CO2 emission rates by
dividing the sum of the CO2 emissions by the sum of the
gross electrical energy output over the same period. The best
performing large EGU is Weston 4, which is a supercritical
subbituminous-fired EGU located in Wisconsin, with an emissions rate of
1,780 lb CO2/MWh-gross, measured over 12-operating months
with 99-percent confidence. Based on the normalization of the Weston 4
data using various steam cycles and fuels, as well as dry cooling, the
proposed emissions rate of 1,900 lb CO2/MWh-gross is
achievable for EGUs burning subbituminous, petroleum coke, and lignite
using ultra-supercritical steam conditions and dry cooling. An EGU
burning bituminous coal and dry cooling would be able to comply using
supercritical steam conditions. Based on data submitted to ECMPS, 25
existing EGUs have maintained annual emission rates of 1,900 lb
CO2/MWh-gross over the past 10 years. While this includes a
broad range of EGU types, it does not include any lignite-fired EGUs or
coal-fired EGUs using dry cooling. The lowest emitting lignite-fired
EGU is emitting at approximately 2,000 lb CO2/MWh-gross, and
the lowest emitting coal-fired EGU using dry cooling is emitting at
approximately 2,100 lb CO2/MWh-gross. However, no lignite-
fired or coal-fired EGU using dry cooling is using ultra-supercritical
steam conditions. The EPA has concluded that additional efficiency
technologies could be incorporated into new units to allow a new EGU
burning lignite with dry cooling to comply with the proposed standard.
The best performing small EGU is Wygen III, which is a subcritical
subbituminous-fired EGU located in Wyoming, with a 12-operating month,
99-percent confidence emissions rate of 2,170 lb CO2/MWh-
gross. Wygen III has relatively low steam temperatures and pressures
\104\ and does not have a reheat cycle. Based on the normalization of
the Wygen III data to the most efficient subcritical conditions and dry
cooling,\105\ the proposed 2,000 lb CO2/MWh-gross emissions
rate is achievable for any solid fuel other than coal refuse using the
best available subcritical steam conditions and dry cooling. Based on
data submitted to ECMPS, five small bituminous-fired EGUs have
maintained a maximum annual emissions rate of 2,000 lb CO2/
MWh-gross over the reviewed 10-year period. These EGUs commenced
operation between 1957 and 1960 and range in size from 1,400 MMBtu/h to
2,000 MMBtu/h. Four of these EGUs use once-through open cooling
systems, and one uses a recirculating cooling tower for steam
condensing. These long-term averages account for degradation and
variable operating conditions and the EGUs should be able to maintain
their current emission rates as long as the units are properly
maintained. Normalization of the Wygen III data for a coal refuse-fired
EGU indicates that a standard of 2,200 lb CO2/MWh-gross is
achievable for a coal refuse-fired EGU.
---------------------------------------------------------------------------
\104\ 11 MPa steam pressure and 541[deg] C main steam
temperature with no reheat cycle.
\105\ The best available subcritical steam conditions are 21 MPa
steam pressure and 570[deg] C main and reheat steam temperature.
---------------------------------------------------------------------------
While the EPA is proposing these standards of performance, the
Agency is also taking comment on a range of potential emission
standards. Specifically, the EPA solicits comment on the following
emission standard ranges:
For new and reconstructed fossil fuel-fired steam
generating units and IGCC units with a heat input rating that is
greater than 2,000 MMBtu/h, a range of 1,700--1,900 lb CO2/
MWh-gross (Comment C-16);
For new and reconstructed fossil fuel-fired steam
generating units and IGCC units with a heat input rating of 2,000
MMBtu/h or less, a range of 1,800--2,000 lb CO2/MWh-gross
(Comment C-17);
For new and reconstructed coal refuse-fired steam
generating units and IGCC units, a range of 2,000-2,200 lb
CO2/MWh-gross (Comment C-18);
While some domestic coal-fired EGUs have maintained annual emission
rates of 1,700 lb CO2/MWh-gross, no existing coal-fired
units have demonstrated multi-year performance at 1,700 lb
CO2/MWh-gross. Based on normalized Weston 4 data, this
emissions rate could be met by a bituminous-fired EGU using
supercritical steam conditions, a subbituminous-fired EGU using ultra-
supercritical steam conditions, and petroleum coke and lignite-fired
EGUs using the best available ultra-supercritical steam conditions and
a cooling tower.\106\ Three existing coal-fired EGUs have maintained a
maximum annual emissions rate of 1,800 lb CO2/MWh-gross over
the reviewed 10-year period. These units include two supercritical
bituminous-fired EGUs and one supercritical subbituminous-fired EGU.
The EGUs commenced operation between 2008 and 2012 and range in size
from 5,200 MMBtu/h to 7,900 MMBtu/h. All use recirculating cooling
towers for condensing. Based on normalized Weston 4 data, an emission
rate of 1,800 lb CO2/MWh-gross is achievable for bituminous-
fired EGUs using the best available subcritical steam condition; and
subbituminous and dried lignite-fired EGUs using supercritical steam
conditions when paired with a cooling tower.\107\ An EGU burning
undried lignite or petroleum coke could comply using ultra-
supercritical steam conditions and a cooling tower.\108\ However, a key
assumption for achieving an 1,800 lb CO2/MWh-gross emissions
rate is the use of a cooling tower. With dry cooling, an 1,800 lb
CO2/MWh-gross emissions rate is only achievable for a
bituminous-fired EGU using ultra-supercritical steam conditions. Based
on normalized Weston 4 data, a 1,900 lb CO2/MWh-gross
emissions rate is achievable for bituminous-fired EGUs using the best
available subcritical steam condition; and subbituminous, dried
lignite, and petroleum coke-fired EGUs using supercritical steam
conditions when paired with dry cooling. An EGU burning undried lignite
could comply using ultra-supercritical steam conditions and dry
cooling. The EPA proposes that a standard above 1,900 lb
CO2/MWh-gross for large units would not promote the use of
the best available steam conditions.
---------------------------------------------------------------------------
\106\ Best available ultra-supercritical steam conditions are
650 [deg]C (1,400 [deg]F) and 36 MPa (5,000 psi).
\107\ 24 MPa steam pressure and 593 [deg]C main and reheat steam
temperature (supercritical steam conditions).
\108\ 30 MPa steam pressure and 600 [deg]C main and 620 [deg]C
reheat steam temperature (ultra-supercritical steam conditions).
---------------------------------------------------------------------------
For small EGUs, based on the normalization of the Wygen III
emissions data, an emissions rate of 1,800 lb CO2/MWh-gross
is achievable for bituminous-fired EGUs using the best available
subcritical steam conditions with either a cooling tower or dry
cooling. In order to achieve this emissions rate, however, EGUs burning
other solid fuels would be required to
[[Page 65452]]
use additional compliance options such as co-firing natural gas, a
hybrid power plant, integration of non-emitting generation
technologies, or combined heat and power. Based on the normalization of
the Wygen III emissions data, an emissions rate of 1,900 lb
CO2/MWh-gross could be met by any coal-fired EGU using the
best available subcritical steam conditions and a cooling tower.
However, only bituminous and subbituminous-fired EGUs could comply with
this emissions rate using dry cooling. Without additional controls
(e.g., co-firing natural gas) EGUs burning dried lignite, petroleum
coke, and undried lignite are only able to comply with an emissions
rate of 2,000 lb CO2/MWh-gross using dry cooling. The EPA proposes that
a standard above 2,000 lb CO2/MWh-gross for small units
would not appropriately promote the use of the best available
efficiency technologies.
For all reconstructed EGUs, large and small, the EPA is soliciting
comment on an emission standard consistent with the proposed standard
for new small EGUs (i.e., all reconstructed EGUs would have a standard
of 2,000 lb CO2/MWh-gross) (Comment C-19). While multiple
organizations are evaluating repowering existing subcritical EGUs with
supercritical topping cycles,\109\ the EPA is only aware of a single
EGU where this was actively considered--the Ferrybridge unit in the
United Kingdom. The addition of a supercritical topping cycle is
projected to reduce the heat rate for a large EGU by between 4 to 8
percent. While this would entail a substantial reduction in emissions,
based on existing emissions data some large EGUs would still not be
able to comply with an emissions rate of 1,900 lb CO2/MWh-
gross even with an 8 percent reduction in the emissions rate. For these
units, additional efficiency improvements would also have to be
conducted as part of the reconstruction project. The EPA is soliciting
comment on whether a single standard regardless of size for
reconstructed EGUs is appropriate and whether the existing
reconstruction exemption in the general provisions (i.e., a
reconstructed EGU will be exempt from the requirement to meet the
standard if the Administrator determines the standard is not
technically or economically achievable (40 CFR 60.15(b)(2))) is
sufficient to account for circumstances where a large reconstructed EGU
would not be able to achieve the proposed emissions standard (Comment
C-20).
---------------------------------------------------------------------------
\109\ A supercritical topping cycle adds a new supercritical
steam turbine that exhausts at the temperature, pressure, and flow
of the existing steam turbine, allowing for reuse of existing
infrastructure.
---------------------------------------------------------------------------
F. Format of the Output-Based Standard
For all newly constructed units, the proposed standards are
expressed on a gross output emission rate basis consistent with current
monitoring and reporting requirements under 40 CFR part 75.\110\ For a
non-CHP EGU, gross output is the electricity generation measured at the
generator terminals. In addition, the EPA is proposing equivalent net-
output-based standards as a compliance alternative. Net output is the
gross electrical output less the unit's total parasitic (i.e.,
auxiliary) power requirements. A parasitic load for an EGU is a load or
device powered by electricity, steam, hot water, or directly by the
gross output of the EGU that does not contribute electrical,
mechanical, or useful thermal output. In general, parasitic energy
demands include less than 7.5 percent of non-IGCC and non-CCS coal-
fired station power output and approximately 15 percent of non-CCS
IGCC-based coal-fired station power output. Net output is used to
recognize the environmental benefits of: (1) EGU designs and control
equipment that use less auxiliary power; (2) fuels that require less
emissions control equipment; and (3) higher efficiency motors, pumps,
and fans. Thus, allowing compliance through net output would enable
owners/operators of these types of units to pursue projects that reduce
auxiliary loads for compliance purposes.
---------------------------------------------------------------------------
\110\ 79 FR 1447-48.
---------------------------------------------------------------------------
Owners/operators of utility boilers have multiple technology
pathways available to comply with the actual emission standard, and the
choice of both control technologies and fuel impact the overall
auxiliary load. In the 2015 Rule, for utility boilers and IGCC units,
the EPA finalized only gross-output-based standards. The rationale for
not including an alternate net-output-based standard was that the
Agency did not have sufficient information to establish an appropriate
net-output-based standard that would not impact the identified BSER for
these types of units. Therefore, the Agency could not identify an
appropriate assumed auxiliary load to establish an equivalent net-
output-based standard.
Since the proposed BSER determination has changed, the EPA is
proposing CO2 standards for steam generating units in a
format similar to the 40 CFR part 60, subpart TTTT standards for
combustion turbines and current EGU NSPS format for criteria
pollutants. Thus, the proposed standards establish a gross-output-based
standard. This allows owners/operators of new EGU to comply with the
CO2 emissions standard under Part 60 using the same data
currently collected under Part 75.\111\ However, in the 2015 Rule, many
permitting authorities commented that the environmental benefits of
using net-output-based standards can outweigh any additional
complexities for particular units.\112\ The EPA expects permitting
authorities to continue to move toward net-output-based standards and
have concluded that it is appropriate to support the expanded use of
net-output-based standards. Therefore, the EPA is proposing to allow
owners/operators of sources to elect between gross-output-based and
net-output-based standards.
---------------------------------------------------------------------------
\111\ Additionally, having an NSPS standard that is measured
using the same monitoring equipment as required under the operating
permit minimizes compliance burden. If a combustion turbine were
subject to both a gross and net emission limit, more expensive
higher accuracy monitoring could be required for both measurements.
\112\ In the 2015 rulemaking, the EPA solicited comment on a
range of options for the form of the final standards. Many
commenters supported gross-output-based standards, maintaining that
a net-output standard penalizes the operation of air pollution
control equipment and EGUs located in hot and/or dry areas of the
country. Commenters further disagreed that a net-output standard
provides any significant incentive to minimize auxiliary loads.
Other commenters, however, maintained that the final rule should
strictly require compliance on a net output-basis. They believed
that this is the only way for the standards to minimize the carbon
footprint of the electricity delivered to consumers. In general,
both sets of commenters believed it appropriate to include net-
output-based standards as an option in the final rule.
---------------------------------------------------------------------------
The EPA is proposing to use the current 40 CFR part 60, subpart
TTTT procedures for requesting the use of the alternate net-output-
based standard (40 CFR 60.5520(c)). Specifically, the owner/operator
would be required to petition the Administrator in writing to comply
with the alternate applicable net-output-based standard. If the
Administrator grants the petition, this election would be binding and
would be the unit's sole means of demonstrating compliance. Owners/
operators complying with the net-output-based standard must similarly
petition the Administrator to switch back to complying with the gross-
output-based standard. This flexibility is particularly important for
IGCC co-production (i.e., to produce useful by-products and chemicals
along with electricity) facilities. The implementing authority (e.g.,
delegated state permitting authority) will best be able to identify the
appropriate format for facilities of this type.
The EPA is not proposing to revise or reopening the 2015 Rule's (1)
approach
[[Page 65453]]
for determining the emissions rate for CHP units with useful thermal
output that meet the applicability criteria or (2) expression of the
standards in the form of limits on only emissions of CO2,
and not the other constituent gases of the air pollutant GHGs.\113\
---------------------------------------------------------------------------
\113\ As noted above, in the 2009 Endangerment Finding, EPA
defined the relevant ``air pollution'' as the atmospheric mix of six
long-lived and directly-emitted greenhouse gases: carbon dioxide
(CO2), methane (CH4), nitrous oxide
(N2O), hydrofluorocarbons (HFCs), perfluorocarbons
(PFCs), and sulfur hexafluoride (SF6). 74 FR 66497.
---------------------------------------------------------------------------
VI. Rationale for Proposed Emission Standards for Modified Fossil Fuel-
Fired Steam Generating Units
In CAA section 111(a)(4), a ``modification'' is defined as ``any
physical change in, or change in the method of operation of, a
stationary source which increases the amount of any air pollutant
emitted by such source or which results in the emission of any air
pollutant'' not previously emitted. The EPA, through regulations, has
determined that certain types of changes are exempt from consideration
as a modification.\114\ As discussed in the 2015 rulemaking, the EPA
has historically been notified of only a limited number of NSPS
modifications \115\ involving fossil steam generating units and
therefore predicted that few of these units would trigger the
modification provisions and be subject to the final standards. Given
the limited information that the Agency has about past modifications,
the EPA concluded 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 for larger modifications, such as
major facility upgrades involving, for example, the refurbishing or
replacement of steam turbines and other equipment upgrades that could
result in substantial increases in a unit's hourly CO2
emissions rate. The Agency determined that it had adequate information
regarding (1) the types of modifications that could result in large
increases in hourly CO2 emissions, (2) the types of measures
available to control emissions from sources that undergo such
modifications, and (3) the costs and effectiveness of such control
measures, upon which to establish standards of performance for
modifications with large emissions increases. The EPA concluded that
the BSER for steam generating units that conduct modifications
resulting in an hourly increase in CO2 emissions (mass per
hour) of more than 10 percent (``large'' modifications) was each
affected unit's own best potential performance as determined by that
unit's historical performance. The EPA deferred establishing standards
for modified sources that conduct modifications resulting in an hourly
increase in CO2 emissions (mass per hour) of less than or
equal to 10 percent (``small'' modifications). Therefore, sources that
conduct small modifications did not fall within the definition of ``new
source'' in section 111(a)(2) and continued to be an ``existing
source'' as defined in section 111(a)(6).
---------------------------------------------------------------------------
\114\ 40 CFR 60.2, 60.14(e).
\115\ NSPS modifications resulting in increases in hourly
emissions of criteria pollutants.
---------------------------------------------------------------------------
In this proposal, the EPA is soliciting comment on a BSER and
standard of performance for fossil fuel-fired steam generating EGUs
that conduct small modifications. The BSER and associated standard of
performance for which the EPA solicits comment are similar to the BSER
and standard for fossil fuel-fired steam generating EGUs that conduct
large modifications. To explain this solicitation of comment, it is
convenient to refer to the 2015 Rule's discussion of the BSER and
standard for large modifications (80 FR 64597-64600). However, the EPA
is not proposing to revise or reopening the BSER or final standard for
fossil fuel-fired steam generating EGUs that conduct large
modifications (except that, as noted above, the EPA is proposing to
revise the maximum stringency of the standard). The EPA is also not
proposing standards of performance for fossil fuel-fired stationary
combustion turbines that conduct modifications.
A. Identification of the BSER
The 2015 Rule provided that a steam generating EGU that undertook a
large modification was required to meet a unit-specific CO2
emission limit determined by that unit's best demonstrated historical
performance (i.e., the best annual performance during the years from
2002 to the time of the modification).\116\ The EPA determined that
this standard based on each unit's own best historical performance
could be met through a combination of best operating practices and
equipment upgrades and that these steps could be implemented cost
effectively at the time when a source was undertaking a large
modification. To account for facilities that had already implemented
best practices and equipment upgrades, the final rule also specified
that modified facilities did not have to meet an emission standard more
stringent than the corresponding standard for reconstructed steam
generating units.
---------------------------------------------------------------------------
\116\ For the 2002 reporting year, EPA introduced new automated
checks in the software that integrated automated quality assurance
(QA) checks on the hourly data. Thus, EPA believes that the data
from 2002 and forward are of higher quality.
---------------------------------------------------------------------------
In this action, the EPA is soliciting comment on a similar, but not
identical, BSER and standard of performance for fossil fuel-fired steam
generating EGUs that undertake small modifications (Comment C-21). The
EPA believes that there are potentially different circumstances
surrounding a small versus large modification. It seems highly unlikely
that an owner or operator could inadvertently make a physical change
in, or change in the method of operation of, a fossil fuel-fired steam-
generating EGU that would result in an increase of hourly
CO2 emissions of more than 10 percent. As stated in the
final 2015 Rule, such an increase in CO2 emissions would
likely come as a result of a significant capital investment in, or a
significant change in the method of operation of, the affected EGU.
However, it is conceivable that an owner or operator could make a
small physical change in, or change in the method of operation of, a
fossil fuel-fired steam-generating EGU that results in an increase of
hourly CO2 emissions of less than 10 percent. If there is an
applicable standard of performance for such ``small'' modifications,
then the EGU could trigger the modification provisions and become a
unit subject to federally-enforced CAA section 111(b) emission
standards and, if the source had previously become subject to a CAA
section 111(d) state program, it would no longer be subject to that
program. The EPA solicits comment on the types of changes in operation
or physical changes to a unit that could result in small increases in
hourly CO2 emissions (Comment C-22).
In this action, the Agency is seeking comment on the need for a
standard for a small modification and, if needed, on the BSER and
appropriate standard of performance (Comment C-23). As with the 2015
Rule's BSER for fossil fuel-fired EGUs conducting large modifications,
the EPA solicits comment on identifying the BSER for such units
conducting small modifications as also heat rate or efficiency
improvements.
1. Reasonable Costs
Any efficiency improvement made by EGUs for the purpose of reducing
CO2 emissions will also reduce the amount of fuel that EGUs
consume to produce the same electricity output. The cost attributable
to CO2 emission reductions, therefore, is the net cost of
achieving
[[Page 65454]]
heat rate improvements after any savings from reduced fuel expenses.
The EPA estimates that, on average, the savings in fuel cost associated
with heat rate improvements would be sufficient to cover much of the
associated costs, and thus that the net costs of heat rate improvements
associated with reducing CO2 emissions from affected EGUs
are relatively low.
The EPA recognizes that our cost analysis just described will
characterize the costs for some EGUs more accurately than others
because of differences in EGUs' individual circumstances. The EPA
further recognize that reduced generation from coal-fired EGUs will
tend to reduce the fuel savings associated with heat rate improvements,
thereby raising the effective cost of achieving the CO2
emission reductions from the heat rate improvements. Nevertheless, the
EPA still expect that most of the investment required to capture the
technical potential for CO2 emission reductions from heat
rate improvements would be offset by fuel savings, and that the net
costs of implementing heat rate improvements as an approach to reducing
CO2 emissions from modified fossil fuel-fired EGUs are
reasonable.
2. Reductions in CO2 Emissions
This approach would achieve reasonable reductions in CO2
emissions from the affected modified units as those units will be
required to meet an emission standard that is consistent with more
efficient operation. In light of the limited opportunities for emission
reductions from retrofits, these reductions are adequate.
3. Technical Feasibility
A standard that is based on a site-specific, previously achieved
emissions rate is technically feasible because there are a large number
of available technologies and equipment upgrades, as well as best
operating and maintenance practices, that EGU owners or operators may
use to improve an EGU's efficiency.
4. Promotion of the Development and Implementation of Technology
As noted previously, the case law makes clear that the EPA is to
consider the effect of its selection of the BSER on technological
innovation or development, but that the EPA also has the authority to
balance this factor against the various other factors (See Sierra Club,
657 F.2d at 346-47). With regard to the selection of emissions
controls, modified sources face inherent constraints that newly
constructed greenfield and reconstructed sources do not. As a result,
modified sources present different, and in some ways more limited,
opportunities for technological innovation or development. In this
case, the standards promote technological development by promoting
further development and market penetration of equipment upgrades and
process changes that improve plant efficiency.
B. Determination of the Level of the Standard
An existing source that undergoes a modification should be able to
at least match its best emission rate since 2002 because with the
modification, it is expanding its capacity and therefore appears to be
interested in upgrading and appears to believe that it will continue to
operate for the long term. The EPA believes that any source that meets
those conditions should be able to make whatever additional investment
is necessary to assure that it meets its most efficient emission rate
since 2002. Improving its efficiency in that manner should be
consistent with its long-term operational goals. On the other hand, an
existing source that is not undertaking that type of upgrade is
differently situated. For example, it may not expect to operate over
the long-term and it may have limited funds available for upgrades.
Thus, it should be subject to the 111(d) rule's requirements, which
assume that it can apply the EPA-identified heat rate improvement
measures, but allow the state to determine whether all of those
measures are appropriate, and further allow the state to grant a
variance.
In the 2015 Rule, the final standard of performance for a steam
generating unit implementing a large modification was a unit-specific
emission limit based on that unit's own best one-year historical
performance. The EPA determined that such a standard was achievable for
a unit implementing a large (likely capital intensive and pre-planned)
modification because the necessary upgrades could be implemented at the
same time as the large modification. However, a unit that undertakes a
small change may trigger the modification requirement, even without a
large capital expenditure or coinciding with a pre-planned outage. The
EPA solicits comment on the appropriate standard of performance for
such EGUs (Comment C-24). In particular, the EPA solicits comment on
whether the 2015 unit-specific emission limit is also appropriate for
an EGU that conducts a small modification (Comment C-25).
To assess the potential heat rate improvement for existing coal-
fired EGUs, the EPA looked at 11 years of historical gross heat rate
data from 2007 to 2017 for 574 coal-fired EGUs that reported both heat
input and gross electricity output to the Agency in 2017. The Agency
used the 2007 to 2017 data to calculate several ``benchmark'' heat
rates for each unit. This included calculating the 1-year average heat
rate, the 2-year rolling average heat rate, and the 3-year rolling
average heat rate. Within each of these groups, the EPA then selected
the best (lowest) heat rate and fourth best heat rate. In all, the
Agency calculated heat rate improvement potential using six different
``benchmarks'' (1-year best, 1-year fourth best, 2-year best, 2-year
fourth best, 3-year best, and 3-year fourth best.). Within each
category, each unit's ``benchmark'' heat rate has been used to
calculate a gross electricity output weighted average across the unit
population. The difference between the gross electricity output
weighted average for a ``benchmark'' category and the 2017 gross
electricity output weighted average (baseline) indicates the heat rate
improvement potential. The heat rate improvement potential has been
calculated nationally and at each regional interconnection: East, West,
and Texas. Table 10 below shows the results expressed as a percent
difference between the 2017 baseline heat rate and each ``benchmark.''
Nationally the range in heat rate improvement varies between 2 and 6.6
percent depending on which ``benchmark'' is used.
Table 10--Potential Heat Rate Improvement Using Different Benchmarks
[Nationally and by regional interconnection]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Fourth best Fourth best
Best one-year Fourth best Best two-year two-year Best three- three-year
Interconnect 2017 Heat rate average one-year rolling rolling year average rolling
(Btu/kWh \1\) (percent) average average average (percent) average
(percent) (percent) (percent) (percent)
--------------------------------------------------------------------------------------------------------------------------------------------------------
National................................ 9,849 6.6 2.9 5.4 2.4 4.6 2.0
[[Page 65455]]
East.................................... 9,780 6.6 2.8 5.4 2.3 4.6 1.9
West.................................... 10,045 6.1 2.4 4.8 2.1 3.9 1.8
Texas................................... 10,097 7.0 3.6 6.0 3.1 5.3 2.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Btu/kWh = British thermal units per kilowatt-hour.
The EPA solicits comment on which, if any, of these formulations
should be used to determine the unit-specific standard of performance
for a fossil fuel-fired steam generating unit that implements small
modifications (Comment C-26). For example, should the EPA finalize a
standard of performance that requires a steam generating unit that
implements a small modification to meet an emission limit consistent
with its best 1-year average emission or an emission limit consistent
with its fourth best 2-year rolling average or some other emission
limit? The EPA solicits comment on this approach and on any other
methods to determine an appropriate unit-specific standard that takes
into consideration the inherent differences in small modifications
versus large modifications (Comment C-27).
VII. Interactions With Other EPA Programs and Rules
Nothing in this rulemaking changes the EPA's regulations or
processes for determining whether a source is subject to permitting
under the Prevention of Significant Deterioration (PSD) program or
title V for its GHG emissions, nor does it require any additional
revisions to State Implementation Plans for PSD applicability purposes
or State title V Programs.
With respect to PSD, the CAA specifies that the best available
control technology (BACT) cannot be less stringent than any applicable
standard of performance under section 111. Id. Thus, in determining GHG
BACT for a new EGU, if the EGU meets the applicability criteria of 40
CFR part 60, subpart TTTT, permitting authorities currently must
consider the emission levels established under 40 CFR part 60, subpart
TTTT as a controlling floor in the BACT review. If the EPA finalizes
these proposed changes to 40 CFR part 60, subpart TTTT, permitting
authorities will need to consider the amended 40 CFR part 60, subpart
TTTT when determining the minimum level of GHG control that represents
BACT for an affected EGU.
With respect to the title V operating permits program, this rule
does not affect whether sources are subject to the requirement to
obtain a title V operating permit. The 2015 rule included revisions to
the fee requirements of the 40 CFR part 70 and part 71 operating permit
rules under title V of the CAA to avoid inadvertent consequences for
fees that would be triggered by the promulgation of the first CAA
section 111 standard to regulate GHGs. In order to avoid excess fees
from GHG emissions, the EPA revised the definition of regulated
pollutant (for presumptive fee calculation) in 40 CFR 70.2 and
regulated pollutant (for fee calculation) in 40 CFR 71.2 to exempt GHG
emissions. This regulatory amendment had the effect of excluding GHG
emissions from being subject to the statutory ($/ton) fee rate set for
the presumptive minimum calculation requirement of part 70 and the fee
calculation requirements of part 71. See 80 FR at 64632-64638; Updated
Guidance on EPA Review of Fee Schedules for Operating Permit Programs
Under Title V, Peter Tsirigotis, Director of the Office of Air Quality
Planning and Standards, U.S. EPA, at 14-16 (Mar. 27, 2018). The EPA is
not proposing to revise or reopening these provisions of the 2015 Rule,
and nothing in this proposed rulemaking would require any additional
changes to the title V regulations.
VIII. Summary of Cost, Environmental, and Economic Impacts
As discussed in the economic impact analysis accompanying this
action, substantial new construction of coal-fired steam units is not
anticipated under existing prevailing and anticipated future
conditions. Therefore, the economic impact analysis concludes that this
final rule will result in no or negligible costs overall on owners and
operators of newly constructed EGUs during the 8-year NSPS review cycle
(See CAA section 111(b)(1)(B)). 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.
With regard to modified and reconstructed fossil fuel-fired steam
generating units, this action proposes amended standards for
reconstructed sources and the maximally stringent standard for modified
sources. Historically, few EGUs have notified the EPA that they have
modified under the modification provision of section 111(b), and
similarly only one EGU, over the history of the NSPS program,\117\ has
notified the EPA that it has reconstructed. Moreover, approximately
half of existing coal refuse-fired facilities are potentially exempt
from this standard as CHP units. Based on this information, the EPA
anticipates that few, if any, EGUs will take actions during the period
of analysis that would be considered NSPS modifications or
reconstruction and, as a result, be
[[Page 65456]]
subject to the standards of performance proposed in this action.
---------------------------------------------------------------------------
\117\ That is, from 1975, when EPA promulgated the regulations
establishing the requirements for reconstructions, 40 FR 58420 (Dec.
16, 1975) (promulgating 40 CFR 60.15).
---------------------------------------------------------------------------
A. What are the air impacts?
The EPA does not anticipate that this proposed rule will result in
significant CO2 emission changes by 2026. As explained
immediately above, the EPA does not anticipate the construction of new
coal-fired steam generating units and expects few, if any, coal-fired
EGUs to trigger the proposed NSPS modification or reconstruction
standard for these sources.
B. What are the energy impacts?
This proposed rule is not anticipated to have an effect on the
supply, distribution, or use of energy. As previously stated, the EPA
projects few, at most, new reconstructed or modified EGUs.
C. What are the compliance costs?
The EPA does not believe this proposed rule will have compliance
costs associated with it, because, the EPA projects there to be, at
most, few new, modified, or reconstructed fossil fuel-fired steam
generating units that will trigger the provisions the EPA is proposing.
The economic impact analysis includes an illustrative analysis of the
potential project-level costs of this proposed action relative to the
2015 Rule's standards.
D. What are the economic and employment impacts?
The EPA does not anticipate that this proposed rule will result in
economic or employment impacts because, the EPA projects there to be,
at most, few new, modified, or reconstructed coal-fired steam
generating units EGUs that will trigger the provisions the EPA is
proposing. Likewise, the EPA believes this rule will not have any
impacts on the price of electricity, employment or labor markets, or
the U.S. economy.
E. What are the benefits of the proposed standards?
As previously stated, the EPA does not anticipate emission changes
resulting from the rule as the EPA projects there to be, at most, few
new, modified, or reconstructed coal-fired steam generating units that
will trigger the provisions the EPA is proposing. Therefore, there are
no direct climate or human health benefits associated with this
rulemaking.
IX. Request for Comments
The EPA requests comments on all aspects of the proposed
rulemaking, including the economic impact analysis (Comment C-28). All
significant comments received will be considered in the development and
selection of the final rule. The EPA is specifically soliciting
comments on alternate compliance options (Comment C-29).
A. Subcategorization by Fuel Type
Except for coal refuse, the EPA is not proposing subcategorization
by fuel type, but the Agency is soliciting comments on that approach
(Comment C-30). The EPA is not proposing to subcategorize by fuel type
for multiple reasons. Subcategorizing by fuel type could have the
perverse impact of both increasing emissions and decreasing compliance
options. Due to averaging, if the subcategorization is based on the
fuel with the highest percentage heat input, owner/operators could have
an incentive to burn sufficient amounts of higher emitting fuels in
order to qualify for the higher emissions standard. For example, a
facility that blends subbituminous and lignite would have a regulatory
incentive to burn higher amounts of lignite than subbituminous coal
(even though coal is lower emitting) in order to have a less stringent
NSPS emissions rate. If the standard is determined based on the actual
percentage of each fuel burned, that would limit the ability of owners/
operators of coal-fired EGUs to use natural gas or other lower emitting
fuels as compliance options because the emissions standard would become
more stringent with increasing percentages of natural gas use. Both of
these subcategorization by fuel type approaches fail to recognize the
environmental benefit of lower emitting (e.g., cleaner) fuels or
integrated non-emitting (i.e., renewable) electric generation. The
proposed fuel neutral standard is consistent with the emissions
standards in the criteria pollutant NSPS and is achievable for all coal
types. This approach both incentivizes the use of lower emitting fuels
and allows the use of natural gas and/or integrated renewable
generation as compliance options.
B. Low Duty Cycle Subcategory
Due to the low variable operating costs of highly efficient coal-
fired EGUs, any affected coal-fired EGU would likely operate at high
capacity factors. This is confirmed by review of the hourly operating
data from highly efficient coal-fired EGUs. As existing coal-fired
generation EGUs retire and additional energy storage technologies enter
the market, the EPA expects the remaining coal-fired EGUs to continue
to operate at high loads. However, during periods of low electric
demand, coal-fired EGUs may reduce load to approximately 45 percent as
an alternate to shutting down completely. While efficiency is reduced
at this load, it is high enough to maintain power generation, continue
operation of the pollution control equipment, and allow the unit to
ramp up relatively quickly as demand increases. Based on this, the EPA
is soliciting comment on establishing separate emissions standards for
steam generating units operating at partial load (Comment C-31).
Based on the data reviewed, maximum coal-fired EGU efficiency tends
to be achieved when the EGU operates at between 80 to 90 percent load.
Efficiency is relatively stable down to about 65 percent load \118\ and
up to 100 percent load. EGUs operating above or below those load levels
experience noticeable reductions in efficiency. Due to maintenance
concerns, EGUs would not operate above 100 percent of the rated load
for extended periods of time. Also, brief periods of lower efficiencies
will not have an appreciable impact on a 12-operating month rolling
average emissions rate, so the Agency is not proposing to establish a
subcategory for operation above 100 percent load. However, coal-fired
EGUs operating at low loads (below approximately 65 percent) lose
efficiency and could have difficulty in complying with an emissions
standard that reflects the efficiencies achieved at higher operating
loads unless they co-fire natural gas. Therefore, the EPA is soliciting
comment on whether it would be appropriate to establish a subcategory
for steam generating units during 12-month rolling average periods when
the unit is not operated at high capacity factors (Comment C-32).
Specifically, the Agency is considering a subcategory for units that
operate at less than a 65 percent duty cycle on a rolling average basis
during any 12-operating month period. Duty cycle is defined as the
average operating load. It is different from capacity factor in that
periods of no operation are not considered when calculating the duty
cycle. The EPA is considering using duty cycle instead of capacity
factor for several reasons. First, a standard based on capacity factor
is more difficult to establish since it is a less precise measurement.
A unit operating at a 65 percent capacity factor could either be
operated at a constant 65 percent load or at 100 percent load 65
percent of the time and not operate for 35 percent of the time. For
identical
[[Page 65457]]
units, these operating profiles could result in substantially different
emission rates. A duty cycle subcategorization approach assures that
units are not deemed to be in the low load subcategory because of
periods of non-operation. Specifically, the EPA is considering that
during periods when these units are operated as non-base load units
(12-operating month average duty cycle is less than 65 percent) an
alternate emission standard would apply. The emission standards the EPA
is soliciting comment on during non-base load operation for the
subcategorized sources are 2,100 lb CO2/MWh-gross for
sources with a nameplate heat input rating of greater than 2,000 MMBtu/
h, 2,200 lb CO2/MWh-gross for sources with a heat input
rating of less than or equal to 2,000 MMBtu/h, and 2,400 lb
CO2/MWh-gross for coal refuse-fired steam generating units
(Comment C-33).\119\
---------------------------------------------------------------------------
\118\ Sliding pressure steam generating units are able to
maintain efficiency at part-load operation better then constant
pressure steam generating units.
\119\ Based on review of hourly emissions data, part load
emission rates are approximately 10 percent higher than the minimum
full load emissions rate. To maintain the minimum full load
emissions rate, a unit would have to co-fire approximately 20
percent natural gas when operating at part load.
---------------------------------------------------------------------------
The EPA is also soliciting comment on establishing a part load heat
input-based standard (similar to the part load standard for combustion
turbines) as an alternate or in place of the low duty cycle output-
based standard (Comment C-34). The advantage of a heat input-based
standard is that it is a constant value based on the fuel burned and is
independent of efficiency and provides a clear compliance option
regardless of the level of degradation of efficiency that results from
operation at low loads. However, this approach does not directly
recognize the environmental benefit of efficient operation at part
load. To incorporate recognition of the environmental benefit of energy
efficiency into the heat input-based standard, the EPA proposes to
conclude that it is not appropriate to base a heat input standard on
the emissions rate of bituminous coal (the lowest emitting coal on a
heat input basis). While compliance would be straight forward for
bituminous-fired EGUs and would only require a small amount of co-
firing for units burning other coals, basing a heat input standard on
the emissions rate of bituminous coal would not recognize the
environmental benefit of efficient part load operation. This could have
the perverse environmental impact of increasing emissions. Owners and
operators of EGUs that are expected to dispatch at part loads would
have limited regulatory incentive to assure that the unit is operated
efficiently. In fact, there would be a regulatory incentive to operate
the unit at lower duty cycles specifically to qualify for the part load
standard.
Based on this, the EPA solicits comment on whether only a more
stringent heat input-based standard would be appropriate (Comment C-
35). The alternate heat input-based standard the EPA is considering
would be based on the heat input-based emissions rate of 200 lb
CO2/MMBtu. This approach has the advantage of allowing for a
clear path for continuous compliance, while at the same time
recognizing the environmental benefit of efficient operation across all
load levels. Due to the price of natural gas relative to coal, owner/
operators of EGUs would have a financial incentive to operate their
units as efficiently as possible so they could comply with the full
load standard with as low an average duty cycle as possible (i.e.,
below 65 percent) without co-firing natural gas and/or fuel oil. Less
efficient EGUs operating below a 65 percent duty cycle, and well
maintained efficient EGUs operating at substantially lower duty cycles
or idle conditions, could co-fire approximately 15 percent natural gas
to demonstrate compliance. The EPA is soliciting comment on whether
this is a reasonable requirement (Comment C-36). Specifically, as
traditionally coal-fired EGUs shift from base load use towards being
reserved for capacity requirements (e.g., peaking units) natural gas
often becomes the primary fuel due to the ability to reduce expenses
from operation of post-combustion emissions control equipment.
The EPA is also soliciting comment on several related issues.
First, the Agency soliciting comment on the cutoff point for the low
duty cycle standard (Comment C-37). The EPA is currently considering a
range of between 50 to 70 percent average duty cycle. In addition, the
EPA is soliciting comment on whether the low duty cycle subcategory
should be based on percent of potential electric sales instead of a
heat input-based capacity factor (Comment C-38). While this approach is
similar to a heat input-based capacity factor approach, it would use
the same calculational procedure as for combustion turbines. The
primary difference is that EGUs that generate power for use on site
(e.g., combined heat and power units) would not be subject to the
output-based standard as frequently. Finally, the EPA is soliciting
comment on whether IGCC units should also have a low duty cycle
subcategory or if a single standard should apply at all load levels
(Comment C-39). IGCC units are particularly well suited to burn natural
gas efficiently and co-firing would allow compliance at all load
levels.
C. Commercial Demonstration Permit
The steam generating unit criteria pollutant NSPS (subpart Da)
includes a provision to assure that NSPS requirements do not discourage
the development and implementation of innovative and emerging
technologies. Specifically, the commercial demonstration permit (40 CFR
60.47Da) provides a procedure for owner/operators of new coal-fired
EGUs proposing to demonstrate an emerging technology to apply to the
Administrator for a slightly less stringent standard than would
otherwise be required. The commercial demonstration permit section of
the EGU criteria pollutant NSPS was included in the original 1979
rulemaking (44 FR 33580) and was later updated in the 2012 amendments
(77 FR 9304) to assure that the NSPS recognizes the environmental
benefit of the development of new and emerging technologies. The
rationale for this provision includes that the innovative technology
waiver under section 111(j) of the CAA does not by itself offer
adequate support for certain capital-intensive technologies, as it does
not provide sufficient time for amortization (44 FR 33580). The
authority to issue these permits is predicated on the D.C. Circuit
Court's opinion in Essex Chemical Corp. v. Ruckelshaus, 486 F. 2d 42
(D.C. Cir. 1973); NSPS should be set to avoid unreasonable costs or
other impacts. Similar provisions for emerging technologies are
included in the industrial-commercial-institutional steam generating
unit criteria pollutant NSPS (52 FR 47839).
Standards requiring a high level of performance, such as the
proposed standards for GHG emissions, might discourage the continued
development of some new technologies. The EPA recognizes that owners/
operators in the utility sector may not accept the risk of using new
and innovative technologies as the emission reduction efficiencies of
such technologies have not been fully demonstrated. As such, owners/
operators may prefer conventional, demonstrated technologies.
Therefore, it is desirable that standards of performance accommodate
and foster the continued development of emerging technologies. Special
provisions may be needed to encourage the continued development and use
of technologies that show promise in achieving levels of performance
comparable or superior to those achieved by the use of fully
demonstrated conventional technologies, but at reduced cost or with
[[Page 65458]]
other offsetting environmental or energy benefits. Establishing less
stringent percent reduction requirements for emerging technologies may
substantially reduce financial risk and increases the likelihood that
owners and operators of new coal-fired EGUs will install and operate
emerging technologies. The experience gained in utilizing emerging
technologies will, in turn, foster their continued development. Unlike
most other air pollutants, GHG pollution has limited direct health
impacts and can persist in the atmosphere for decades or millennia,
depending on the specific GHG. This special characteristic makes
transfer of control technologies and long-term technology innovation
particularly important factors when considering appropriate control
options for GHG emissions.
To mitigate the potential negative impact on emerging technologies,
the EPA is soliciting comment on whether it should include a commercial
demonstration permit provision in 40 CFR part 60, subpart TTTT (Comment
C-40). The EPA believes that this provision would encourage the
development of new technologies and compensate for problems that may
arise when applying them to commercial-scale units. The technologies
the EPA is currently considering include pressurized fluidized bed
technology, alternate power cycle working fluid (e.g., supercritical
CO2), additional energy recovery using integrated thermo-
electric materials, a supercritical CO2 Brayton cycle, an
integrated organic rankine cycle, integrated hybrid photovoltaic-solar
thermal, integrated novel energy storage technologies, and novel carbon
capture technologies. Specifically, the Administrator (in consultation
with DOE) would issue commercial demonstration permits for the first
1,000 MW of full-scale demonstration units of each emerging technology.
Owners/operators of the units that are granted a commercial
demonstration permit would be exempt from the otherwise applicable
standards of subpart TTTT and would instead be subject to less
stringent emission standards. To encourage the continued development of
emerging technologies, standards should be set low enough to be
reasonably attainable, but stringent enough to ensure a minimum level
of CO2 emissions to protect human health and the
environment. Although there is some uncertainty on setting a precise
standard, the standards the EPA is considering would be 100 lb
CO2/MWh higher than the proposed standards for new and
reconstructed units using conventional technologies. The proposed
commercial demonstration permit standards would provide flexibility for
innovative and emerging technologies and ensure the NSPS does not
preclude the development of these technologies while at the same time
maintaining the emission standards for traditional control
technologies. The EPA is also soliciting comment on whether other
innovative emerging technologies should be included (Comment C-41).
Specifically, the Agency is interested in commenters' views with regard
to other innovative boiler designs, new materials that would allow for
the use of advanced ultra-supercritical steam conditions, supercritical
topping cycles, and alternate cooling technologies.
The EPA selected these particular technologies for the following
reasons. Pressurized fluidized bed technology combines a pressurized
circulating fluidized bed boiler with a combustion turbine. This
combination essentially creates a coal-fired combined cycle power plant
and has the potential to improve the efficiency and reduce the
environmental impact (on both a criteria pollutant and GHG emissions
basis) of using coal to generate electricity. However, it is still a
relatively developing technology and has only been deployed on a
limited basis worldwide. Traditional coal-fired power plants use water
as the working fluid in a rankine cycle. Water is heated to create
steam that is then expanded through a steam turbine to generate
electricity. The use of alternate working fluids, such as supercritical
CO2, has the potential to increase the efficiency of
converting thermal energy to electricity. However, these systems have
not yet been fully demonstrated.
Coal-fired power plants generate significant quantities of
relatively low-temperature heat (i.e., waste heat) that cannot be used
by the traditional rankine cycle. This heat is currently sent to the
power plant cooling system (e.g., cooling tower). If this energy could
be recovered to produce additional electricity, it could significantly
reduce the environmental impact of power generation. Thermoelectric
materials are materials that generate electricity due to temperature
differences across the material. Organic rankine cycle use working
fluids with boiler points lower than that of water and can generate
electricity from lower temperature sources of heat. Both of these
technologies have the potential to recover useful energy from the waste
heat from power plants, but neither has been fully demonstrated.
Hybrid power plants combined multiple forms of power generation in
a single integrated system. The integration of solar thermal with
traditional fossil fuel-fired power plants has been demonstrated at
multiple facilities. A promising technology that could expand the
opportunities for additional hybrid fossil fuel-fired EGUs is the
integration of hybrid photovoltaic-solar thermal. Hybrid photovoltaic-
solar thermal first concentrates the solar energy onto photovoltaic
cells that convert a portion of that energy directly into electricity.
As a result of the concentrated solar energy, the photovoltaic cells
are heated, and additional useful thermal output energy is recovered
from the ``hot'' photovoltaic cells. This approach is potentially more
efficient than either standalone photovoltaic or solar thermal EGUs.
The recovered thermal energy from hybrid photovoltaic-solar thermal is
relatively low and has limited potential for direct integration into
the thermal cycle. However, it could potentially be integrated into
coal-fired power plants for boiler feedwater heating or the generation
of low pressure steam. However, the integration of hybrid photovoltaic-
solar thermal power has not been demonstrated on a fossil fuel-fired
EGU, so the efficiency gains cannot be estimated. A developer of a new
coal-fired EGU would therefore be unable to rely on this technology to
guarantee compliance with the NSPS until the technology is further
developed.
At the utility level, energy storage devices have historically
provided improved power quality (i.e., frequency and voltage) and help
to manage the amount of power required to supply (i.e., generation) and
load (i.e., customers demand) during periods of peak power demand. With
the advent of increasing amounts of variable generation energy storage
technology can help integrate renewable energy efficiently into the
electric grid. Since renewable generation generally provides
electricity based on local conditions (e.g., when the wind is blowing
or the sun is shining) and is not dispatched by grid operators to
satisfy demand, large amounts of renewable generation can result in
excess power generation (i.e., grid oversupply) that results in
dispatchable generators operating in a non-optimal manner and
decreasing operating efficiency. Low-cost energy storage technologies
with high electricity-in to electricity-out round-trip efficiency \120\
could help to balance load and generation allowing for the integration
of additional renewable
[[Page 65459]]
generation while maintaining a dependable power supply and allowing for
the operation of dispatchable power plants at peak operating
efficiencies. A high round trip efficiency is necessary to assure that
the losses in the energy storage technology are less than the increase
in emissions that would result from operating the dispatchable fossil
fuel-fired EGUs under conditions that result in lower operating
efficiencies.
---------------------------------------------------------------------------
\120\ Round-trip efficiency is the ratio of the energy recovered
from the energy storage device and the energy put into the device.
---------------------------------------------------------------------------
Utility scale energy storage systems are classified into
mechanical, electrochemical, chemical, electrical, and thermal energy
storage systems. While some of these technologies are well demonstrated
(e.g., pumped storage), other novel technologies are still in
development. A developer installing a novel energy storage device to
allow the EGU to operate at closer to maximum efficiency would not be
able to guarantee the cycle efficiency or reliability of the energy
storage technology and would therefore not be able to rely on the
integration for compliance purposes. Demonstrating innovative energy
storage technologies could help address barriers reducing costs and
accelerating market acceptance.
An owner or operator of a new or reconstructed coal-fired EGU who
wished to demonstrate a novel carbon capture technology could face
multiple difficulties in demonstrating continuous compliance. First,
novel carbon capture technologies by nature prevent quantitative
assessment of their continuous performance. If the capture system were
taken down for repair or modification, the entire facility might have
to be taken off line to assure continuous compliance. In addition, due
to the additional auxiliary load and increased stack emissions per MWh
of electricity generated, the captured CO2 would need to be
sequestered for the unit to demonstrate continuous compliance.
Sequestering relatively small amounts of CO2 could be
technically challenging and cost prohibitive, therefore limiting the
development of more cost-effective capture technologies. Without the
commercial demonstration permit provision, it would be difficult for an
owner/operator of a coal-fired EGU to support a CCS demonstration
project while still maintaining compliance with the NSPS emissions
standard.
Allowing the Administrator to approve commercial demonstration
permits would limit regulatory impediments to improvements in GHG
reduction technologies. If the Administrator finds (in consultation
with DOE) that a given emerging technology (taking into consideration
all areas of environmental impact, including air, water, solid waste,
toxics, and land use) offers superior overall environmental
performance, permission to operate in compliance with alternative
standards could then be granted by the Administrator. A mere
modification of an existing demonstrated technology will not be viewed
as emerging technologies and will not be approved for a commercial
demonstration permit. The EPA is requesting comment on additional
technologies that should be considered, as well as the maximum
magnitude of the demonstration permits (Comment C-42). In particular,
the Agency is considering including DOE demonstration projects as
emerging technologies and potential candidates for the commercial
demonstration permit. This would assure that the NSPS would continue to
accommodate alternate technologies as they become available.
D. Applicability to Industrial EGUs
In simple terms, the current applicability provisions require that
an EGU be capable of combusting over 250 MMBtu/h of fossil fuel and be
capable of selling 25 MW to a utility distribution system in order to
be subject to 40 CFR part 60, subpart TTTT. These applicability
provisions exclude industrial EGUs. However, since the affected EGU
includes ``integrated equipment that provides electricity or useful
thermal output,'' certain large processes might be included as part of
the EGU and meet the applicability criteria. For example, the high-
temperature exhaust from an industrial process (e.g., calcining kilns,
dryer, or metals processing) that consumes fossil fuel could be sent to
a heat recovery steam generator. If the industrial process is over 250
MMBtu/h heat input and the electric sales exceed the applicability
criteria, then the unit could be subject to 40 CFR part 60, subpart
TTTT. This is potentially problematic for multiple reasons. First, it
is difficult to determine the useful output of the EGU since part of
the useful output is included in the industrial process. In addition,
the fossil fuel that is combusted might have a relatively high
CO2 emissions rate on a lb/MMBtu basis, making it
problematic to meet the emissions standard. Finally, the compliance
costs associated with 40 CFR part 60, subpart TTTT could discourage the
development of environmentally beneficial projects.
To avoid these outcomes, the EPA is soliciting comment on
amendments to the applicability provisions (Comment C-43). One option
the Agency considering is amending the provisions to include an
industrial unit exemption (Comment C-44). This exemption would apply to
any EGU where greater than 50 percent of the heat input is derived from
an industrial process that does not produce any electrical or
mechanical output or useful thermal output that is used outside the
affected EGU. In addition, the EPA soliciting comment on excluding
fuels that are combusted to comply with another EPA regulation (e.g.,
control of HAP emissions) from being considered a fossil fuel (Comment
C-45).
The current approach owner/operators of CHP units use to calculate
net-electric sales and net energy output includes that ``at least 20.0
percent of the total gross or net energy output consists of electric or
direct mechanical output.'' It is unlikely that a CHP with a relatively
low electric output (i.e., less than 20 percent) would meet the
applicability criteria. However, if a CHP unit with less than 20
percent of the total output consisting of electricity were to meet the
applicability criteria, the net-electric sales and net energy output
would be calculated the same as for a traditional non-CHP EGU. Even so,
it is not clear that these CHP units would have less environmental
benefit per unit of electricity produced than more traditional CHP
units. The EPA is therefore soliciting comment on eliminating the
restriction that CHP produce at least 20 percent electrical or
mechanical output to qualify for the CHP specific method for
calculating net-electric sales and net energy output (Comment C-46).
The current electric sales applicability exemption for non-CHP
steam generating units includes the provision that steam generating
units have ``always been subject to a federally enforceable permit
limiting annual net electric sales to one-third or less of their
potential electric output (e.g., limiting hours of operation to less
than 2,920 hours annually) or limiting annual electric sales to 219,000
MWh or less'' (emphasis added). The justification for this restriction
includes that the 40 CFR part 60 subpart Da applicability language
includes ``constructed for the purpose of . . .'' and the Agency
concluded that the intent was defined by permit conditions (80 FR
64544). This applicability criterion is important for determining
applicability with both the new source section 111(b) requirements and
if existing steam generating units are subject to the existing source
section 111(d) requirements. For steam generating units that commenced
construction after September 18, 1978, the applicability date of 40 CFR
part 60 subpart Da,
[[Page 65460]]
applicability would be relatively clear by what criteria pollutant NSPS
is applicable to the facility. However, for steam generating units that
commenced construction prior to September 18, 1978 or where the owner/
operator determined that criteria pollutant NSPS applicability was not
critical to the project (e.g., emission controls were sufficient to
comply with either the EGU or industrial boiler criteria pollutant
NSPS) owners/operators might not have requested an electric sales
permit restriction be included in the operating permit. Under the
current applicability language, some onsite steam generating unit
electric generators could be covered by the existing source section
111(d) requirements even if they have never sold electricity to the
grid. The EPA is soliciting comment on amending the electric sales
exemption to read have ``have never sold more than one-third of their
potential electric output or 219,000 MWh, whichever is greater, and are
always been subject to a federally enforceable permit limiting annual
net electric sales to one-third or less of their potential electric
output (e.g., limiting hours of operation to less than 2,920 hours
annually) or limiting annual electric sales to 219,000 MWh or less''
(emphasis added) (Comment C-47). EGUs that reduce current generation
would continue to be covered as long as they sold more than \1/3\ of
their potential electric output at some time in the past.
E. Non-Sequestration of Captured Carbon
While carbon capture technology is not included in the proposed
BSER, the EPA recognizes that there are potential site-specific
situations where a developer elects to install carbon capture
technology. For example, a developer might wish to evaluate a
particular capture technology or to sell the captured CO2.
However, 40 CFR part 60, subpart TTTT as currently written requires
that captured CO2 be geologically sequestered or stored in a
different manner that is as effective as geologic sequestration.
Captured CO2 that is sold to the food industry would not
currently qualify for emission reduction because it results in near
term releases rather than in permanent sequestration. However, a
different situation can be envisioned in which the captured
CO2 could be considered to offset CO2 generated
specifically for the food industry and from a life cycle perspective it
would be as effective as sequestration at reducing emissions.
Therefore, to accommodate non geologic sequestration and to support the
effective utilization and management of CO2, the EPA is
soliciting comment on amending the second sentence of paragraph
60.555(g) to read ``To receive a waiver, the applicant must demonstrate
to the Administrator that its technology will store captured
CO2 as effectively as geologic sequestration or the CO2 will
be used as an input to an industrial process where the life cycle
emissions are reducing emissions as effective as geologic
sequestration, and that the proposed technology will not cause or
contribute to an unreasonable risk to public health, welfare, or
safety.'' (emphasis added) (Comment C-48)
F. Additional Amendments
The EPA is soliciting comment on multiple less significant
amendments. These amendments either would be either strictly editorial
and would not change any of the requirements of subpart TTTT or are
intended to add additional compliance flexibility. For additional
information on these amendments, see the regulatory text track changes
technical support document. First, the EPA is considering editorial
amendments to define acronyms the first time they are used in the
regulatory text (Comment C-49). Second, the EPA is considering adding
International System of Units (SI) equivalent for owners/operators of
stationary combustion turbines complying with a heat input-based
standard (Comment C-50). Third, the EPA is considering fixing errors in
the current subpart TTTT regulatory text referring to part 63 instead
of part 60 (Comment C-51). Fourth, as a practical matter owners/
operators of stationary combustion turbines subject to the heat input-
based emissions standard need to maintain records of electric sales to
demonstrate that they are not subject to the output-based emissions
standard. Therefore, the EPA is soliciting comment on adding specific
requirement that owner/operators maintain records of electric sales to
demonstrate they did not sell electricity above the threshold that
would trigger the output-based standard (Comment C-52). Next, the EPA
is soliciting comment on if the ANSI, ASME, and ASTM test methods
should be updated to include more recent versions of the test methods
(Comment C-53). Finally, the EPA is soliciting comment on adding
additional compliance flexibilities for EGUs either serving a common
electric generator or using a common stack (Comment C-54).
Specifically, for EGUs serving a common electric generator should the
Administrator be able to approve alternate methods for determining
energy output? For EGUs using a common stack, the EPA is soliciting
comment on if specific procedures should be added for apportioning the
emissions and/or if the Administrator should be able to approve site
specific alternate procedures.
G. Non-Base Load Combustion Turbines
As noted in the General Information section above, in the 2015
Rule, the EPA set separate standards for base load and non-base load
stationary combustion turbines. The electric sales threshold between
the two subcategories is based on the design efficiency of the
combustion turbine. Stationary combustion turbines qualify as non-base
load, and thus for a less stringent standard of performance, if they
have net electric sales equal to or below their design efficiency (not
to exceed 50 percent) multiplied by their potential electric output, 80
FR at 64,601 (e.g., a 40 percent efficient combustion turbine can sell
up to 40 percent of its potential electrical output), but if their
sales exceed that level, they are treated as base load and subject to a
more stringent standard of performance. For additional discussion on
this approach, see the 2015 Rule (80 FR 64609 to 64612).
Recently, stakeholders have expressed concerns about this approach
for distinguishing between base load and non-base load turbines. They
posit a scenario under which increased utilization of wind and solar
resources, combined with low natural gas prices, would result in
certain types of simple cycle turbines being deemed attractive to
operate for a longer period of time than had been contemplated at the
time the 2015 Rule was being developed. Specifically, stakeholders have
observed that in some regional electricity markets with large amounts
of wind generation, some of the most efficient new simple cycle
turbines--aeroderivative turbines--could be called on to operate at
capacity factors greater than their design efficiency; however, if they
were to be operated at those higher capacity factors, they would become
subject to the more stringent standard of performance for base load
turbines, which they would not be able to meet. As a result, according
to these stakeholders, the owners or operators of the aeroderivative
turbines would have to curtail their generation and less efficient
turbines would be called on to run, which would result in higher
emissions.
Although, as noted above, the EPA is not re-opening the standards
promulgated in the 2015 Rule for combustion turbines, the EPA is
soliciting comment on the concerns identified by stakeholders to
determine the extent of the potential issue
[[Page 65461]]
identified above and, if necessary, potential remedies. Specifically,
the EPA is soliciting information, including seeking supporting data
and documentation, on whether there have been, or are anticipated to
be, circumstances (e.g., high utilization of wind or solar resources or
low natural gas prices) in which simple cycle stationary combustion
aeroderivative turbines (i.e., those that are subject to standards of
performance in 40 CFR part 60 subpart TTTT) have been or may be called
upon to operate in excess of the non-base load threshold described in
the 2015 Rule (Comment C-55). The EPA is also requesting information on
whether, and the extent to which, these aeroderivative turbines are
different in design and operation than frame simple cycle turbines and
NGCC units, including fast start NGCC units (Comment C-56). The EPA is
also requesting information on the environmental consequences, if any,
of the aeroderivative combustion turbines having to forego continued
operation in such circumstances (e.g., is a more efficient turbine
being displaced by a higher emitting turbine or utility boiler?)
(Comment C-57). The EPA is also soliciting comment on remedies that the
Agency should consider, if necessary, to address this potential
concern. For example, should the EPA consider creating a separate
subcategory and standard of performance for simple cycle aeroderivative
turbines? Should the EPA consider changing the formula used to
calculate allowable operating hours for non-baseload combustion
turbines? Should the Agency consider creating a process by which owners
or operators could petition the EPA to increase the allowable operating
hours for non-baseload combustion turbines on a case-by-case basis if
they could demonstrate that, given the composition of the regional grid
they belong to, the increase would result in better overall
environmental outcome? (Comment C-58). The EPA will evaluate all
comments and any new information and, if warranted, will initiate a
subsequent rulemaking to address any issues raised from this
solicitation of comment.
X. Statutory and Executive Order Reviews
Additional information about these statutes and Executive Orders
can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is a significant regulatory action that was submitted
to the Office of Management and Budget (OMB) for review. Any changes
made in response to OMB recommendations have been documented in the
docket. The EPA prepared an economic impact analysis of the potential
costs and benefits associated with this action. This analysis is
contained in the Economic Impact Analysis for the Review of Standards
of Performance for Greenhouse Gas Emissions from New, Modified, and
Reconstructed Stationary Sources: Electric Utility Generating Units.
The economic impact analysis includes an illustrative analysis of the
potential difference in project-level costs of constructing a coal-
fired EGU under this proposed standard relative to the 2015 standard.
B. Executive Order 13771: Reducing Regulation and Controlling
Regulatory Costs
This action is expected to be an Executive Order 13771 regulatory
action. There are no quantified cost estimates for this proposed rule
because the EPA does not anticipate this action to result in costs or
cost savings. For more information on this conclusion please see the
Economic Impact Analysis for the Review of Standards of Performance for
Greenhouse Gas Emissions from New, Modified, and Reconstructed
Stationary Sources: Electric Utility Generating Units.
C. Paperwork Reduction Act (PRA)
This action does not impose any new information collection burden
under the provisions of the PRA. The information required by the rule
is already collected and reported by other regulatory programs. OMB has
previously approved the information collection activities contained in
the existing 40 CFR part 75 and 98 regulations and has assigned OMB
control numbers 2060-0626 and 2060-0629, respectively.
D. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. In
making this determination, the impact of concern is any significant
adverse economic impact on small entities. An agency mat certify that a
rule will not have a significant economic impact on a substantial
number of small entities if the rule relieves regulatory burden, has no
net burden, or otherwise has a positive economic effect on the small
entities subject to the rule. The EPA does not project any new,
modified, or reconstructed coal-fired electric utility steam generating
units. As such, this proposed rule would not impose significant
requirements on those sources, including any that are owned by small
entities. The EPA has, therefore, concluded that this action will have
no net regulatory burden for all directly regulated small entities.
E. Unfunded Mandates Reform Act (UMRA)
This action does not contain an unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments. This action is not
expected to impact state, local, or tribal governments.
F. Executive Order 13132: Federalism
This action does not have federalism implications. It would not
have substantial direct effects on the states, on the relationship
between the national government and the states, or on the distribution
of power and responsibilities among the various levels of government.
G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175. It would neither impose substantial direct
compliance costs on tribal governments, nor preempt Tribal law. The EPA
is aware of three coal-fired EGUs located in Indian Country, but is not
aware of any EGUs owned or operated by tribal entities. The EPA notes
that this action would only affect existing sources such as the three
coal-fired EGUs located in Indian Country, if those EGUs were to take
actions constituting modifications or reconstructions as defined under
the EPA's NSPS regulations. However, as previously stated, the EPA does
not project any new, reconstructed, or modified EGUs. Thus, Executive
Order 13175 does not apply to this action.
The EPA will hold meetings with tribal environmental staff during
the public comment period to inform them of the content of this
proposal and will offer further consultation with tribal elected
officials where it is appropriate. The EPA specifically solicits
additional comment from tribal officials on this proposed rule.
[[Page 65462]]
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern health or safety risks that the EPA has
reason to believe may disproportionately affect children, per the
definition of ``covered regulatory action'' in section 2-202 of the
Executive Order. This action is not subject to Executive Order 13045
because it does not concern an environmental health or safety risk.
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution, or use of energy. This proposed action is not anticipated
to have impacts on emissions, costs, or energy supply decisions for the
affected electric utility industry.
J. National Technology Transfer and Advancement Act (NTTAA)
This action involves technical standards. Therefore, the EPA
conducted a search to identify potentially applicable voluntary
consensus standards (VCS). However, the Agency identified no such
standards. Therefore, the EPA has decided to continue to use technical
standard Method 19 of 40 CFR part 60, appendix A. The EPA invites the
public to identify potentially applicable VCS and to explain why such
standards should be used in this action (Comment C-59).
K. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
The EPA believes that this action does not have disproportionately
high and adverse human health or environmental effects on minority
populations, low-income populations, and/or indigenous peoples, as
specific in Executive Order 12898 (59 FR 7629, February 16, 1994),
because it does not affect the level of protection provided to human
health or the environment. As previously stated, the EPA does not
project any fossil fuel-fired electric utility steam generating units
would be affected by this action.
XI. Statutory Authority
The statutory authority for this action is provided by sections
111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411,
7601, 7602, 7607(d)(1)(C)). This action is also subject to section
307(d) of the CAA (42 U.S.C. 7607(d)).
List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.
Dated: December 6, 2018.
Andrew R. Wheeler,
Acting Administrator.
For the reasons set out in the preamble, title 40, chapter I, part
60 of the Code of Federal Regulations is proposed to be amended as
follows:
PART 60--Standards of Performance for New Stationary Sources
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart TTTT--[Amended]
0
2. Section 60.5509 is amended by revising paragraph (b)(2) to read as
follows:
Sec. 60.5509 Am I subject to this subpart?
* * * * *
(b) * * *
(2) Your EGU is capable of deriving 50 percent or more of the heat
input from non-fossil fuel at the base load rating and is also subject
to a federally enforceable permit condition limiting the annual
capacity factor for all fossil fuels combined of 10 percent (0.10) or
less.
* * * * *
0
3. Section 60.5520 is amended by revising paragraphs (a) and (c) to
read as follows:
Sec. 60.5520 What CO2 emissions standard must I meet?
(a) For each affected EGU subject to this subpart, you must not
discharge from the affected EGU any gases that contain CO2
in excess of the applicable CO2 emission standard specified
in Table 1, 2, or 3 of this subpart, consistent with paragraphs (b),
(c), and (d) of this section, as applicable.
* * * * *
(c) As an alternate to meeting the requirements in paragraph (b) of
this section, an owner or operator of an EGU may petition the
Administrator in writing to comply with the alternate applicable net
energy output standard. If the Administrator grants the petition,
beginning on the date the Administrator grants the petition, the
affected EGU must comply with the applicable net energy output-based
standard included in this subpart. Your operating permit must include
monitoring, recordkeeping, and reporting methodologies based on the
applicable net energy output standard. For the remainder of this
subpart, where the term ``gross or net energy output'' is used, the
term that applies to you is ``net energy output.'' Owners or operators
complying with the net output-based standard must petition the
Administrator to switch back to complying with the gross energy output-
based standard.
* * * * *
0
4. Section 60.5525 is amended by revising the introductory text, the
introductory text of paragraph (c), and paragraphs (c)(1)(i) and (ii),
(c)(2), and (c)(3) to read as follows:
Sec. 60.5525 What are my general requirements for complying with this
subpart?
Combustion turbines qualifying under Sec. 60.5520(d)(1) are not
subject to any requirements in this section other than the requirement
to maintain fuel purchase records for permitted fuel(s). For all other
affected sources, compliance with the applicable CO2
emission standard of this subpart shall be determined on a 12-
operating-month rolling average basis. See Table 1, 2, or 3 of this
subpart for the applicable CO2 emission standards.
* * * * *
(c) Within 30 days after the end of the initial compliance period
(i.e., no more than 30 days after the first 12-operating-month
compliance period), you must make an initial compliance determination
for your affected EGU(s) with respect to the applicable emissions
standard in Table 1, 2, or 3 of this subpart, in accordance with the
requirements in this subpart. The first operating month included in the
initial 12-operating-month compliance period shall be determined as
follows:
(1) * * *
(i) Section 60.5555(c)(3)(i), for units subject to the Acid Rain
Program; or
(ii) Section 60.5555(c)(3)(ii)(A), for units that are not in the
Acid Rain Program.
(2) For an affected EGU that has commenced commercial operation (as
defined in Sec. 72.2 of this chapter) prior to October 23, 2015:
(i) If the date on which emissions reporting is required to begin
under Sec. 75.64(a) of this chapter has passed prior to October 23,
2015, emissions reporting shall begin according to Sec.
60.5555(c)(3)(i) (for Acid Rain program units), or according to Sec.
60.5555(c)(3)(ii)(B) (for units that are not subject to the Acid Rain
Program). The first month of the initial
[[Page 65463]]
compliance period shall be the first operating month (as defined in
Sec. 60.5580) after the calendar month in which the rule becomes
effective; or
(ii) If the date on which emissions reporting is required to begin
under Sec. 75.64(a) of this chapter occurs on or after October 23,
2015, then the first month of the initial compliance period shall be
the first operating month (as defined in Sec. 60.5580) after the
calendar month in which emissions reporting is required to begin under
Sec. 60.5555(c)(3)(ii)(A).
(3) For a modified or reconstructed EGU that becomes subject to
this subpart, the first month of the initial compliance period shall be
the first operating month (as defined in Sec. 60.5580) after the
calendar month in which emissions reporting is required to begin under
Sec. 60.5555(c)(3)(iii).
0
5. Section 60.5535 is amended by revising paragraphs (f) and (g) to
read as follows:
Sec. 60.5535 How do I monitor and collect data to demonstrate
compliance?
* * * * *
(f) In accordance with Sec. Sec. 60.13(g) and 60.5520, if two or
more affected EGUs that implement the continuous emission monitoring
provisions in paragraph (b) of this section share a common exhaust gas
stack and are subject to the same emissions standard in Table 1, 2, or
3 of this subpart, you may monitor the hourly CO2 mass
emissions at the common stack in lieu of monitoring each EGU
separately. If you choose this option, the hourly gross or net energy
output (electric, thermal, and/or mechanical, as applicable) must be
the sum of the hourly loads for the individual affected EGUs and you
must express the operating time as ``stack operating hours'' (as
defined in Sec. 72.2 of this chapter). If you attain compliance with
the applicable emissions standard in Sec. 60.5520 at the common stack,
each affected EGU sharing the stack is in compliance.
(g) In accordance with Sec. Sec. 60.13(g) and 60.5520 if the
exhaust gases from an affected EGU that implements the continuous
emission monitoring provisions in paragraph (b) of this section are
emitted to the atmosphere through multiple stacks (or if the exhaust
gases are routed to a common stack through multiple ducts and you elect
to monitor in the ducts), you must monitor the hourly CO2
mass emissions and the ``stack operating time'' (as defined in Sec.
72.2 of this chapter) at each stack or duct separately. In this case,
you must determine compliance with the applicable emissions standard in
Table 1, 2, or 3 of this subpart by summing the CO2 mass
emissions measured at the individual stacks or ducts and dividing by
the total gross or net energy output for the affected EGU.
0
6. Section 60.5540 is amended by revising the introductory text of
paragraph (a) and paragraph (b) to read as follows:
Sec. 60.5540 How do I demonstrate compliance with my CO2 emissions
standard and determine excess emissions?
(a) In accordance with Sec. 60.5520, if you are subject to an
output-based emission standard or you burn non-uniform fuels as
specified in Sec. 60.5520(d)(2), you must demonstrate compliance with
the applicable CO2 emission standard in Table 1, 2, or 3 of
this subpart as required in this section. For the initial and each
subsequent 12-operating-month rolling average compliance period, you
must follow the procedures in paragraphs (a)(1) through (7) of this
section to calculate the CO2 mass emissions rate for your
affected EGU(s) in units of the applicable emissions standard (i.e.,
either kg/MWh or lb/MMBtu). You must use the hourly CO2 mass
emissions calculated under Sec. 60.5535(b) or (c), as applicable, and
either the generating load data from Sec. 60.5535(d)(1) for output-
based calculations or the heat input data from Sec. 60.5535(d)(2) for
heat-input-based calculations. Combustion turbines firing non-uniform
fuels that contain CO2 prior to combustion (e.g., blast
furnace gas or landfill gas) may sample the fuel stream to determine
the quantity of CO2 present in the fuel prior to combustion
and exclude this portion of the CO2 mass emissions from
compliance determinations.
* * * * *
(b) In accordance with Sec. 60.5520, to demonstrate compliance
with the applicable CO2 emission standard, for the initial
and each subsequent 12-operating-month compliance period, the
CO2 mass emissions rate for your affected EGU must be
determined according to the procedures specified in paragraph (a)(1)
through (7) of this section and must be less than or equal to the
applicable CO2 emissions standard in Table 1, 2, or 3 of
this part, or the emissions standard calculated in accordance with
Sec. 60.5525(a)(2).
0
7. Section 60.5555 is amended by revising paragraph (a)(2)(v) to read
as follows:
Sec. 60.5555 What reports must I submit and when?
(a) * * *
(2) * * *
(v) Consistent with Sec. 60.5520, the CO2 emissions
standard (as identified in Table 1, 2, or 3 of this part) with which
your affected EGU must comply; and
* * * * *
0
8. Section 60.5560 is amended by revising paragraph (f) to read as
follows:
Sec. 60.5560 What records must I maintain?
* * * * *
(f) You must keep records of the calculations you performed to
assess compliance with each applicable CO2 mass emissions
standard in Table 1, 2, or 3 of this subpart.
* * * * *
0
9. Section 60.5580 is amended by revising the definitions for ``Base
load rating'' and ``Design efficiency,'' revising paragraph (2) of the
definition for ``Net-electric sales,'' and revising the definition for
``Violation'' to read as follows:
Sec. 60.5580 What definitions apply to this subpart?
* * * * *
Base load rating means the maximum amount of heat input (fuel) that
an EGU can combust on a steady state basis plus the maximum amount of
heat input derived from non-combustion source (e.g., solar thermal), as
determined by the physical design and characteristics of the EGU at ISO
conditions. For a stationary combustion turbine, base load rating
includes the heat input from duct burners.
* * * * *
Design efficiency means the rated overall net efficiency (e.g.,
electric plus useful thermal output) on a lower heating value basis at
the base load rating, at ISO conditions, and at the maximum useful
thermal output (e.g., CHP unit with condensing steam turbines would
determine the design efficiency at the maximum level of extraction and/
or bypass). Design efficiency shall be determined using one of the
following methods: ASME PTC 22 Gas Turbines (incorporated by reference,
see Sec. 60.17), ASME PTC 46 Overall Plant Performance (incorporated
by reference, see Sec. 60.17), ISO 2314 Gas turbines--acceptance tests
(incorporated by reference, see Sec. 60.17), or an alternative
approved by the Administrator.
* * * * *
Net-electric sales means: * * *
(2) For combined heat and power facilities where at least 20.0
percent of the total gross energy output consists of electric or direct
mechanical output and at least 20.0 percent of the total gross energy
output consists of useful thermal output on an annual basis, the gross
electric sales to the utility power distribution system minus the
[[Page 65464]]
applicable percentage of purchased power of the thermal host facility
or facilities. The applicable percentage of purchase power for CHP
facilities is determined based on the percentage of the total thermal
load of the host facility supplied to the host facility by the CHP
facility. For example, if a CHP facility serves 50 percent of a thermal
hosts thermal demand, the owner/operator of the CHP facility would
subtract 50 percent of the thermal hosts electric purchased power when
determining net-electric sales.
* * * * *
Violation means a specified averaging period over which the
CO2 emissions rate is higher than the applicable emissions
standard located in Table 1, 2, or 3 of this subpart.
0
10. Re-designate Table 3 of Subpart TTTT of Part 60 as Table 4 of
Subpart TTTT of Part 60.
0
11. Revise the heading of Table 1 of Subpart TTTT of Part 60 to read as
follows:
Table 1 of Subpart TTTT of Part 60--CO2 Emission Standards for Affected
Steam Generating Units and Integrated Gasification Combined Cycle
Facilities That Commenced Construction After January 8, 2014, but
Before December 21, 2018, and Reconstruction or Modification After June
18, 2014, but Before December 21, 2018
[Note: Numerical values of 1,000 or greater have a minimum of 3
significant figures and numerical values of less than 1,000 have a
minimum of 2 significant figures]
* * * * *
0
12. Add new Table 3 of Subpart TTTT of Part 60 to read as follows:
Table 3 of Subpart TTTT of Part 60--CO2 Emission Standards for Affected
Steam Generating Units and Integrated Gasification Combined Cycle
Facilities That Commenced Construction, Reconstruction, or Modification
After December 21, 2018 (Net Energy Output-Based Standards Applicable
as Approved by the Administrator)
[Note: Numerical values of 1,000 or greater have a minimum of 3
significant figures and numerical values of less than 1,000 have a
minimum of 2 significant figures]
------------------------------------------------------------------------
Affected EGU CO2 emission standard
------------------------------------------------------------------------
Newly constructed and reconstructed 910 kg CO2/MWh (2,000 lb CO2/
steam generating unit or IGCC that has MWh) of gross energy output;
base load rating of 2,100 GJ/h (2,000 or 980 kg CO2/MWh (2,160 lb
MMBtu/h) or less. CO2/MWh) of net energy output.
Newly constructed and reconstructed 870 kg CO2/MWh (1,900 lb CO2/
steam generating unit or IGCC that has MWh) of gross energy output;
base load rating greater than 2,100 GJ/ or 940 kg CO2/MWh (2,070 lb
h (2,000 MMBtu/h). CO2/MWh) of net energy output.
Newly constructed and reconstructed 1,000 kg CO2/MWh (2,200 lb CO2/
steam generating unit or IGCC units MWh) of gross energy output;
that burn 75 percent or more (by heat or 1,080 kg CO2/MWh (2,380 lb
input) coal refuse on a 12-operating CO2/MWh) of net energy output.
month rolling average basis.
Modified steam generating unit or IGCC. A unit-specific emission limit
determined by 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. 910 kg CO2/MWh (2,000 lb CO2/
MWh) of gross energy output;
or 980 kg CO2/MWh (2,160 lb
CO2/MWh) of net energy output
for units with a base load
rating of 2,100 GJ/h (2,000
MMBtu/h) or less; or
2. 870 kg CO2/MWh (1,900 lb CO2/
MWh) of gross energy output;
or 940 kg CO2/MWh (2,070 lb
CO2/MWh) of net energy output
for units with a base load
rating of greater than 2,100
GJ/h (2,000 MMBtu/h); or
3. 1,000 kg CO2/MWh (2,200 lb
CO2/MWh) of gross energy
output; or 1,080 kg CO2/MWh
(2,380 lb CO2/MWh) of net
energy output for units that
burn 75 percent or more (by
heat input) coal refuse on a
12-operating month rolling
average basis.
------------------------------------------------------------------------
[FR Doc. 2018-27052 Filed 12-19-18; 8:45 am]
BILLING CODE 6560-50-P