Document ID: EPA-HQ-OAR-2013-0495-11936
Agency: epa
Document Type: Proposed Rule
Title: Review of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units
Posted Date: 2018-12-20T05:00Z

[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

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40 CFR Part 60

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

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

[[Page 65424]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

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

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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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

DATES: Comments. Comments must be received on or before February 19, 
2019.
    Public Hearing. The EPA is planning to hold at least one public 
hearing in response to this proposed action. Information about the 
hearing, including location, date, and time, along with instructions on 
how to register to speak at the hearing, will be published in a second 
Federal Register notice.

ADDRESSES: Comments. Submit your comments, identified by Docket ID No. 
EPA-HQ-OAR-2013-0495, at https://www.regulations.gov. Follow the online 
instructions for submitting comments. Once submitted, comments cannot 
be edited or removed from Regulations.gov. See SUPPLEMENTARY 
INFORMATION for detail about how the EPA treats submitted comments. 
Regulations.gov is our preferred method of receiving comments. However, 
other submission methods are accepted:
     Email: a-and-r-docket@epa.gov. 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: fellner.christian@epa.gov.
    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: ayres.sara@epa.gov.

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\
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    \1\ In this proposal, in some instances, the EPA identifies an 
issue that the Agency has previously addressed, and states that the 
Agency is not re-opening that issue in this proposal. The EPA will 
not consider such an issue as relevant to this proposal.
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    Submitting CBI. Do not submit information containing CBI to the EPA 
through https://www.regulations.gov or email. Clearly mark the 
information that you claim to be CBI. For CBI information on any 
digital storage media that you mail to the EPA, mark the outside of the 
digital storage media as CBI and then identify electronically within 
the digital storage media the specific information that is claimed as 
CBI. In addition to one complete version of the comments that includes 
information claimed as CBI, you must submit a copy of the comments that 
does not contain the information claimed as CBI directly to the public 
docket through the procedures outlined in Instructions above. If you 
submit any digital storage media that does not contain CBI, mark the 
outside of the digital storage media clearly that it does not contain 
CBI. Information not marked as CBI will be included in the public 
docket and the EPA's electronic public docket without prior notice. 
Information marked as CBI will not be disclosed except in accordance 
with procedures set forth in 40 Code of Federal Regulations (CFR) part 
2. Send or deliver information identified as CBI only to the following 
address: OAQPS Document Control Officer (C404-02), OAQPS, U.S. 
Environmental Protection Agency, Research Triangle Park, North Carolina 
27711, Attention Docket ID No. EPA-HQ-OAR-2013-0495.
    Preamble Acronyms and Abbreviations. The EPA uses multiple acronyms 
and terms in this preamble. While this list may not be exhaustive, to 
ease the reading of this preamble and for reference purposes, the EPA 
defines the following terms and acronyms here:

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

[[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.
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    \2\ A subcritical EGU operates at pressures where water first 
boils and is then converted to superheated steam. A supercritical 
steam generator EGU operates at pressures in excess of the critical 
pressure of water and heats water to produce superheated steam 
without boiling. While often referred to as a supercritical boiler, 
no boiling actually occurs in the device and the term ``boiler'' 
should technically not be used for a supercritical pressure steam 
generator. Note: the term ``EGU'' is intended to refer to the 
affected facility (also referred to as the affected ``source'' or 
``unit'').
    \3\ Under 40 CFR 60.14(h), a modification of an existing 
electric utility steam generating unit is defined as a physical 
change or change in the method of operation of the unit that 
increases the maximum hourly emissions of any regulated pollutant 
above the maximum hourly emissions achievable at that unit during 
the 5 years prior to the change.
    \4\ The maximally stringent standard for modified EGUs is the 
numeric standard for reconstructed EGUs, even if the emission rate 
based on best annual performance is lower than that numeric 
standard.

[[Page 65427]]

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

B. Types of Sources

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

[[Page 65428]]

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

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

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

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

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

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

[[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\
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    \32\ The standard that EPA develops, reflecting the performance 
of the BSER, commonly takes the form of a numeric emission limit, 
expressed as a numeric performance level that can either be 
normalized to a rate of output or input (e.g., tons of pollution per 
amount of product produced--a so-called rate-based standard), or 
expressed as a numeric limit on mass of pollutant that may be 
emitted (e.g., 100 micrograms per cubic meter ([micro]g/m\3\)--or 
parts per billion). Generally, the EPA does not prescribe a 
particular technological system that must be used to comply with a 
standard CAA section 111(b)(5) and (h). Rather, sources generally 
may select any measure or combination of measures that will achieve 
the emissions level of the standard of performance. CAA section 
111(b)(5). In establishing standards of performance, EPA has 
significant discretion to create subcategories based on source type, 
class, or size. CAA section 111(b)(2); see also Lignite Energy 
Council v. EPA, 198 F. 3d 930, 933 (D.C. Cir. 1999).
    \33\ See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 
1981).
    \34\ See id. at 347.
---------------------------------------------------------------------------

    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\
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    \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.''

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[[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\
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    \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.
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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.
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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.
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    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