[Federal Register Volume 83, Number 170 (Friday, August 31, 2018)]
[Proposed Rules]
[Pages 44746-44813]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-18755]
[[Page 44745]]
Vol. 83
Friday,
No. 170
August 31, 2018
Part III
Environmental Protection Agency
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40 CFR Parts 51, 52, and 60
Emission Guidelines for Greenhouse Gas Emissions From Existing Electric
Utility Generating Units; Revisions to Emission Guideline Implementing
Regulations; Revisions to New Source Review Program; Proposed Rule
Federal Register / Vol. 83 , No. 170 / Friday, August 31, 2018 /
Proposed Rules
[[Page 44746]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51, 52, and 60
[EPA-HQ-OAR-2017-0355; FRL-9982-89-OAR]
RIN 2060-AT67
Emission Guidelines for Greenhouse Gas Emissions From Existing
Electric Utility Generating Units; Revisions to Emission Guideline
Implementing Regulations; Revisions to New Source Review Program
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: The Environmental Protection Agency (EPA) is proposing three
distinct actions, including Emission Guidelines for Greenhouse Gas
Emissions from Existing Electric Utility Generating Units (EGUs).
First, EPA is proposing to replace the Clean Power Plan (CPP) with
revised emissions guidelines (the Affordable Clean Energy (ACE) rule)
that inform the development, submittal, and implementation of state
plans to reduce greenhouse gas (GHG) emission from certain EGUs. In the
proposed emissions guidelines, consistent with the interpretation
described in the proposed repeal of the CPP, the Agency is proposing to
determine that heat rate improvement (HRI) measures are the best system
of emission reduction (BSER) for existing coal-fired EGUs. Second, EPA
is proposing new regulations that provide direction to both EPA and the
states on the implementation of emission guidelines. The new proposed
implementing regulations would apply to this action and any future
emission guideline issued under section 111(d) of the Clean Air Act
(CAA). Third, the Agency is proposing revisions to the New Source
Review (NSR) program that will help prevent NSR from being a barrier to
the implementation of efficiency projects at EGUs.
DATES:
Comments. Comments must be received on or before October 30, 2018.
Under the Paperwork Reduction Act (PRA), comments on the information
collection provisions are best assured of consideration if the Office
of Management and Budget (OMB) receives a copy of your comments on or
before October 1, 2018.
Public hearing: EPA is planning to hold at least one public hearing
in response to this proposed action. Information about the hearing,
including location, date, and time, along with instructions on how to
register to speak at the hearing, will be published in a second Federal
Register document.
ADDRESSES: Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2017-0355, at https://www.regulations.gov. Follow the online
instructions for submitting comments. Once submitted, comments cannot
be edited or removed from Regulations.gov. See SUPPLEMENTARY
INFORMATION for detail about how EPA treats submitted comments.
Regulations.gov is our preferred method of receiving comments.\1\
However, other submission methods are accepted:
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\1\ Comments submitted on the proposed repeal will be considered
in the promulgation of this rulemaking so there is no need to
resubmit comments that have already been timely submitted.
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Email: [email protected]. Include Docket ID No. EPA-
HQ-OAR-2017-0355 in the subject line of the message.
Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2017-0355.
Mail: To ship or send mail via the United States Postal
Service, use the following address: U.S. Environmental Protection
Agency, EPA Docket Center, Docket ID No. EPA-HQ-OAR-2017-0355, Mail
Code 28221T, 1200 Pennsylvania Avenue NW, Washington, DC 20460.
Hand/Courier Delivery: Use the following Docket Center
address if you are using express mail, commercial delivery, hand
delivery, or courier: EPA Docket Center, EPA WJC West Building, Room
3334, 1301 Constitution Avenue NW, Washington, DC 20004. Delivery
verification signatures will be available only during regular business
hours.
FOR FURTHER INFORMATION CONTACT: For questions about this proposed
action, contact Mr. Nicholas Swanson, Sector Policies and Programs
Division (Mail Code D205-01), Office of Air Quality Planning and
Standards, U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina 27711; telephone number: (919) 541-4080; fax
number: (919) 541-4991; and email address: [email protected].
SUPPLEMENTARY INFORMATION:
Docket. EPA has established a docket for this rulemaking under
Docket ID No. EPA-HQ-OAR-2017-0355. All documents in the docket are
listed in Regulations.gov. Although listed, some information is not
publicly available, e.g., confidential business information (CBI) or
other information whose disclosure is restricted by statute. Certain
other material, such as copyrighted material, is not placed on the
internet and will be publicly available only in hard copy. Publicly
available docket materials are available either electronically in
Regulations.gov or in hard copy at the EPA Docket Center, Room 3334,
EPA WJC West Building, 1301 Constitution Avenue NW, Washington, DC. The
Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The telephone number for the Public
Reading Room is (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-
2017-0355. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
https://www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be CBI or
other information whose disclosure is restricted by statute. Do not
submit information that you consider to be CBI or otherwise protected
through https://www.regulations.gov or email. This type of information
should be submitted by mail as discussed below.
EPA may publish any comment received to its public docket.
Multimedia submissions (audio, video, etc.) must be accompanied by a
written comment. The written comment is considered the official comment
and should include discussion of all points you wish to make. EPA will
generally not consider comments or comment contents located outside of
the primary submission (i.e., on the Web, cloud, or other file sharing
system). For additional submission methods, the full EPA public comment
policy, information about CBI or multimedia submissions, and general
guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.
The https://www.regulations.gov website allows you to submit your
comments anonymously, which means EPA will not know your identity or
contact information unless you provide it in the body of your comment.
If you send an email comment directly to EPA without going through
https://www.regulations.gov, your email address will be automatically
captured and included as part of the comment that is placed in the
public docket and made available on the internet. If you submit an
electronic comment, EPA recommends that you include your name and other
contact information in the body of your comment and with any
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digital storage media you submit. If EPA cannot read your comment due
to technical difficulties and cannot contact you for clarification, EPA
may not be able to consider your comment. Electronic files should not
include special characters or any form of encryption and be free of any
defects or viruses. For additional information about EPA's public
docket, visit the EPA Docket Center homepage at https://www.epa.gov/dockets.
Throughout this proposal, EPA is soliciting comment on numerous
aspects of the proposed rule. EPA has indexed each comment solicitation
with an alpha-numeric identifier (e.g., ``C-1'', ``C-2'', ``C-3'', . .
.). EPA included similar identifiers in the advance notice of proposed
rulemaking (ANPRM) and asked commenters to identify the main topic area
that corresponded with their comment. In this proposal, we are
modifying this approach to include a unique identifier for each
individual comment solicitation to provide a consistent framework for
effective and efficient provision of comments.
Accordingly, we ask that commenters include the corresponding
identifier when providing comments relevant to that comment
solicitation. We ask that commenters include the identifier in either a
heading, or within the text of each comment (e.g., ``In response to
solicitation of comment C-1, . . .'') to make clear which comment
solicitation is being addressed. We emphasize that we are not limiting
comment to these identified areas and encourage provision of any other
comments relevant to this proposal.
Submitting CBI. Do not submit information containing CBI to EPA
through https://www.regulations.gov or email. Clearly mark the part or
all of the information that you claim to be CBI. For CBI information on
any digital storage media that you mail to EPA, mark the outside of the
digital storage media as CBI and then identify electronically within
the digital storage media the specific information that is claimed as
CBI. In addition to one complete version of the comments that includes
information claimed as CBI, you must submit a copy of the comments that
does not contain the information claimed as CBI directly to the public
docket through the procedures outlined in Instructions above. If you
submit any digital storage media that does not contain CBI, mark the
outside of the digital storage media clearly that it does not contain
CBI. Information not marked as CBI will be included in the public
docket and the EPA's electronic public docket without prior notice.
Information marked as CBI will not be disclosed except in accordance
with procedures set forth in 40 Code of Federal Regulations (CFR) part
2. Send or deliver information identified as CBI only to the following
address: OAQPS Document Control Officer (C404-02), OAQPS, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina
27711, Attention Docket ID No. EPA-HQ-OAR-2017-0355.
Preamble acronyms and abbreviations. We use multiple acronyms and
terms in this preamble. While this list may not be exhaustive, to ease
the reading of this preamble and for reference purposes, EPA defines
the following terms and acronyms here:
ACE Affordable Clean Energy Rule
AEO Annual Energy Outlook
ANPRM Advance Notice of Proposed Rulemaking
BACT Best Available Control Technology
BSER Best System of Emission Reduction
Btu British Thermal Unit
CAA Clean Air Act
CBI Confidential Business Information
CCS Carbon Capture and Storage (or Sequestration)
CFR Code of Federal Regulation
CO2 Carbon Dioxide
CPP Clean Power Plan
EGU Electric Utility Generating Unit
EIA Energy Information Administration
EPA Environmental Protection Agency
FIP Federal Implementation Plan
FR Federal Register
GHG Greenhouse Gas
HRI Heat Rate Improvement
IGCC Integrated Gasification Combined Cycle
kW Kilowatt
kWh Kilowatt-hour
MW Megawatt
MWh Megawatt-hour
NAAQS National Ambient Air Quality Standards
NGCC Natural Gas Combined Cycle
NOX Nitrogen Oxides
NSPS New Source Performance Standards
NSR New Source Review
OMB Office of Management and Budget
PM2.5 Fine Particulate Matter
PRA Paperwork Reduction Act
PSD Prevention of Significant Deterioration
RIA Regulatory Impact Analysis
RTC Response to Comments
SIP State Implementation Plan
SO2 Sulfur Dioxide
UMRA Unfunded Mandates Reform Act of 1995
U.S. United States
VFD Variable Frequency Drive
Organization of this document. The information in this preamble is
organized as follows:
I. General Information
A. Executive Summary
B. Where can I get a copy of this document and other related
information?
II. Background
A. Regulatory and Judicial History of GHG Requirements for EGUs
B. Executive Order 13783 and EPA's Review of the CPP
C. Industry Trends
III. Legal Authority
A. Authority to Revisit Existing Regulations
B. Authority to Regulate EGUs
C. Legal Authority for Determination of the BSER
IV. Affected Sources
V. Determination of the BSER
A. Identification of the BSER
B. HRIs for Steam-Generating EGUs
C. HRI for Natural Gas-fired Stationary Combustion Turbines
D. Other Considered Systems of GHG Emission Reductions
VI. State Plan Development
A. Establishing Standards of Performance
B. Flexibilities for States and Sources
C. Submission of State Plans
VII. Proposed New Implementing Regulations for Section 111(d)
Emission Guidelines
A. Changes to the Definition of ``Emission Guideline''
B. Updates to Timing Requirements
C. Compliance Deadlines
D. Completeness Criteria
E. Standard of Performance
F. Variance
VIII. New Source Review Permitting of HRIs
A. What is New Source Review?
B. Interaction of NSR and the ACE Rule
C. ANPRM Solicitation and Comments Received
D. Proposing NSR Changes for Improved ACE Implementation
IX. Impacts
A. What are the air impacts?
B. What are the energy impacts?
C. What are the compliance costs?
D. What are the economic and employment impacts?
E. What are the forgone benefits of the proposed action?
X. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Executive Order 13771: Reducing Regulation and Controlling
Regulatory Costs
C. Paperwork Reduction Act (PRA)
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act (UMRA)
F. Executive Order 13132: Federalism
G. Executive Order 13175: Consultation and Coordination with
Indian Tribal Governments
H. Executive Order 13045: Protection of Children from
Environmental Health Risks and Safety Risks
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
J. National Technology Transfer and Advancement Act (NTTAA)
K. Executive Order 12898: Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations
XI. Statutory Authority
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I. General Information
A. Executive Summary
EPA is proposing the Affordable Clean Energy (ACE) rule as a
replacement to the CPP (promulgated on October 23, 2015, 80 FR 64662),
which sets GHG emission guidelines for existing EGUs. This proposal
relies in part on the legal analysis presented in the CPP repeal that
was proposed on October 16, 2017, 82 FR 48035. In the proposed repeal,
EPA asserted that the BSER in the CPP exceeded EPA's authority because
it established the BSER using measures that applied to the power sector
as whole, rather than measures that apply at and to, and can be carried
out at the level of, individual facilities. This proposed action aligns
with EPA's statutory authority and obligation because, as EPA has done
in the dozens of NSPSs issued to date, the BSER is to be determined by
evaluating technologies or systems of emission reduction that are
applicable to, at, and on the premises of the facility for an affected
source. This proposal will ensure that coal-fired power plants (the
most carbon dioxide (CO2) intensive portion of the
electricity generating fleet) address their contribution to climate
change by reducing their CO2 intensity (i.e., the amount of
CO2 they emit per unit of electricity generated).
Accordingly, the proposed ACE rule consists of three discrete
sections. First, EPA is proposing to determine the BSER for existing
EGUs based on HRI measures that can be applied at an affected source.
EPA also proposes a corresponding emission guideline clarifying the
roles of EPA and the states under CAA section 111(d). EPA's primary
role in implementing CAA section 111(d) is to provide emission
guidelines that inform the development, submittal, and implementation
of state plans, and to subsequently determine whether submitted state
plans are approvable. Per the CAA, once EPA publishes a final emission
guideline, states have the primary role of developing standards of
performance consistent with application of the BSER. Congress also
expressly required that EPA allow states to consider source-specific
factors--including, among other factors, the remaining useful life of
the affected source--in applying a standard of performance. In this
way, the state and federal roles complement each other as EPA has the
authority and responsibility to determine a nationally applicable BSER
while the states have the authority and responsibility to establish and
apply existing source standards of performance, in consideration of
source-specific factors.
Second, EPA is proposing new implementing regulations that apply to
this action and any future emission guidelines promulgated under CAA
section 111(d). The purpose of proposing new implementing regulations
is to harmonize our 40 CFR part 60 subpart B regulations with the
statute by making it clear that states have broad discretion in
establishing and applying emissions standards consistent with the BSER.
The discussion for the proposed revisions is found in Section VII
below.
Third, EPA is proposing to give the owners/operators of EGUs more
latitude to make the efficiency improvements that are consistent with
EPA's proposed BSER without triggering onerous and costly NSR permit
requirements. This change will allow states, in establishing standards
of performance, to consider HRIs that would otherwise not be cost-
effective due to the burdens incurred from triggering NSR. The
discussion of this issue is included in Section VII.
As with other regulations of this nature, this notice concludes
with a summary of the impacts of this proposal and is supported by a
Regulatory Impact Analysis (RIA) that can be found in the docket for
this action. As reported in the RIA, EPA evaluated three illustrative
policy scenarios modeling HRI at coal-fired EGUs. EPA estimates that
there are cost savings under two of the three illustrative scenarios,
with average annual compliance costs ranging from a cost savings of
about $0.5 billion to a cost of about $0.3 billion. As noted
previously, this action is preceded by a proposed repeal of the CPP.\2\
That proposal included a detailed legal analysis demonstrating that
``building blocks'' two and three of the CPP exceeded EPA's authority.
That analysis is incorporated into this proposal. Because two of the
three ``building blocks'' used to establish the CPP emission guidelines
were legally flawed (and because ``building block'' one was not
designed in such a manner that it could or was intended to stand on its
own without the other building blocks), EPA proposed that the CPP
emission guidelines be withdrawn. With the ACE rule, EPA proposes to
possibly replace the CPP with a rule that corrects the fundamental
legal flaws in the CPP to more appropriately balance federal and state
responsibilities under CAA section 111(d), and revise the NSR program
as it applies to affected EGUs to better accommodate energy efficiency
projects.
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\2\ The accompanying RIA focuses on presenting the difference
between the CPP and the concepts in ACE, but also includes a
scenario with no CPP, providing sufficient information to understand
the impact of a full repeal of the CPP, a two-step approach in which
the CPP is repealed and then an alternative BSER is put in place or
a case in which the Agency revises the BSER promulgated in the CPP.
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This proposed action has been informed by comments submitted in
response to the ANPRM, published December 28, 2017, see 82 FR 61507.
EPA notes that it does not intend to respond to the comments received
on the ANPRM. If commenters believe that any of their previously
submitted comments are still applicable, they should resubmit those
comments to this rulemaking to ensure they are considered.
B. Where can I get a copy of this document and other related
information?
In addition to being available in the docket, an electronic copy of
this action is available on the internet. Following signature by the
EPA Administrator, EPA will post a copy of this proposed action at
https://www.epa.gov/stationary-sources-air-pollution/electric-utility-generating-units-emission-guidelines-greenhouse. Following publication
in the Federal Register, EPA will post the Federal Register version of
the proposal and key technical documents at this same website.
II. Background
A. Regulatory and Judicial History of GHG Requirements for EGUs
When passing and amending the CAA, Congress sought to address and
remedy the dangers posed by air pollution to human beings and the
environment. While the text of the CAA does not reflect an explicit
intent on the part of Congress to address the potential effects of
elevated atmospheric GHG concentrations, the Supreme Court in
Massachusetts v. EPA, 549 U.S. 497 (2007), concluded that Congress had
drafted the CAA broadly enough so that GHGs constituted air pollutants
within the meaning of the CAA. EPA subsequently determined that
emissions of GHGs from new motor vehicles cause or contribute to air
pollution that may reasonably be anticipated to endanger public health
or welfare. See 74 FR 66496 (December 15, 2009). This determination
required EPA to regulate GHG emissions from motor vehicles.
In 2009, and again in 2016, the EPA Administrator issued findings
under sections 202(a) and 231(a)(2)(A) of the Clean Air Act,
respectively, that the current, elevated concentrations of six well-
mixed GHGs in the atmosphere may reasonably be anticipated to endanger
public health and welfare of current and future generations in the
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United States.\3\ In 2015, after determining that GHGs from EGUs
merited regulation under CAA section 111, EPA promulgated standards of
performance for new, modified, and reconstructed EGUs under section
111(b). 80 FR 64510. Consequentially, this led to EPA's obligation to
develop a 111(d) rule for existing EGUs, as described in Section III.
EPA believes that the BSER in ACE is consistent both with our legal
authorities under 111(d) and with what is technically feasible and
appropriate for coal-fired power plants. Therefore, EPA believes that
the emission reductions required from state plans are the appropriate
amount for a 111(d) rule.
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\3\ ``Finding that Greenhouse Gas Emissions From Aircraft Cause
or Contribute to Air Pollution That May Reasonably Be Anticipated to
Endanger Public Health and Welfare,'' 81 FR 54422 (August 15, 2016).
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While the market in the power sector is driving GHG emissions down,
the EPA, by proposing this emission guideline, is reinforcing the
market in many respects and also ensuring that available emission
reductions that are not market driven are achieved. Many regulations
are promulgated to correct market failures, which otherwise lead to a
suboptimal allocation of resources within the free market. Air quality
and pollution control regulations address ``negative externalities''
whereby the market does not internalize the full opportunity cost of
production borne by society as public goods such as air quality are
unpriced.
While recognizing that optimal social level of pollution may not be
zero, GHG emissions impose costs on society, such as negative health
and welfare impacts, that are not reflected in the market price of the
goods produced through the polluting process. For this regulatory
action the good produced is electricity. If a fossil fuel-fired
electricity producer pollutes the atmosphere when it generates
electricity, this cost will be borne not by the polluting firm but by
society as a whole, thus the producer is imposing a negative
externality, or a social cost of emissions. The equilibrium market
price of electricity may fail to incorporate the full opportunity cost
to society of generating electricity. Consequently, absent a regulation
on emissions, the EGUs will not internalize the social cost of
emissions and social costs will be higher as a result. This regulation
will work towards addressing this market failure by causing affected
EGUs to begin to internalize the negative externality associated with
CO2 emissions.
Further discussion of GHG impacts, as well as the benefits of this
proposal, can be found in the RIA for this action. As detailed in
Chapter 3 of the RIA, EPA evaluated three illustrative policy scenarios
representing ACE. These scenarios are projected to result in a decrease
of annual CO2 emissions of about 7 million to 30 million
short tons relative to a future without a CAA section 111(d) regulation
affecting the power sector.
Along with the 111(b) standard, EPA issued, under CAA section
111(d), its ``Clean Power Plan,'' consisting of GHG emission guidelines
for existing EGUs, which states would use to develop emission standards
as mentioned above. 80 FR 64662 (October 23, 2015). In February 2016,
the U.S. Supreme Court stayed implementation of the CPP pending
judicial review. West Virginia v. EPA, No. 15A773 (S.Ct. Feb. 9, 2016).
In March 2017, President Trump issued Executive Order 13873, which
among other things, directed EPA to reconsider the CPP. After
considering the statutory text, context, legislative history and
purpose, and in consideration of EPA's historical practice under CAA
section 111 as reflected in its other existing CAA section 111
regulations and of certain policy concerns, EPA proposed to repeal the
CPP. See 82 FR 48035. In a separate but related action, EPA published
an ANPRM to solicit comment on what EPA should include in a potential
new existing source regulation under CAA section 111(d), including
soliciting comment on aspects of the respective roles of the states and
EPA in that process, on the BSER in context of the statutory
interpretation contained in the proposed repeal of the CPP, on what
systems of emission reduction might be available and appropriate, and
the potential flexibility that could be afforded under the NSR program
to improve the implementation of a potential new existing source
regulation for EGUs under CAA section 111(d). 82 FR 61507 (December 28,
2017). EPA received more than 270,000 comments on the ANPRM, which have
informed this proposed rulemaking.
In ACE, EPA is proposing to determine that the BSER for GHG
emissions from existing coal-fired EGUs is heat rate improvements that
can be applied at the source, consistent with the legal interpretation
expressed in the proposed repeal. The Agency is also, in this action,
clarifying the respective roles of the states and EPA under CAA section
111(d), including by proposing revisions to the regulations, in 40 CFR
part 60 subpart B, implementing that section. Section 111(d)(1) of the
CAA states that EPA's ``Administrator shall prescribe regulations which
shall establish a procedure . . . under which each State shall submit
to the Administrator a plan which (A) establishes standards of
performance for any existing source for any air pollutant . . . to
which a standard of performance under this section would apply if such
existing source were a new source, and (B) provides for the
implementation and enforcement of such standards of performance.'' See
42 U.S.C. 7411(d). CAA section 111(d)(1) also requires the
Administrator to ``permit the State in applying a standard of
performance to any particular source under a plan submitted under this
paragraph to take into consideration, among other factors, the
remaining useful life of the existing source to which such standard
applies.'' Id.
As the plain language of the statute provides, EPA's authorized
role under CAA section 111(d)(1) is to develop a procedure for states
to establish standards of performance for existing sources. Indeed, the
Supreme Court has acknowledged the role and authority of states under
section 111(d): This provision allows ``each State to take the first
cut at determining how best to achieve EPA emissions standards within
its domain.'' Am. Elec. Power Co. v. Connecticut, 131 S. Ct. 2527, 2539
(2011). The Court addressed the statutory framework as implemented
through regulation, under which EPA promulgates emission guidelines and
the states establish performance standards: ``For existing sources, EPA
issues emissions guidelines; in compliance with those guidelines and
subject to federal oversight, the States then issue performance
standards for stationary sources within their jurisdiction, [42 U.S.C.]
Sec. 7411(d)(1).'' Id. at 2537-38.
As contemplated by CAA section 111(d)(1), states possess the
authority and discretion to establish appropriate standards of
performance for existing sources. CAA section 111(a)(1) defines
``standard of performance'' as ``a standard of emissions of air
pollutants which reflects'' what is colloquially referred to as the
``Best System of Emission Reduction'' or ``BSER''--i.e., ``the degree
of emission limitation achievable through the application of the best
system of emission reduction which (taking into account the cost of
achieving such reduction and any nonair quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.'' 42 U.S.C. 7411(a)(1)
(emphasis added).
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In order to effectuate the Agency's role under CAA section
111(d)(1), EPA promulgated implementing regulations in 1975 to provide
a framework for subsequent EPA rules and state plans under section
111(d). See 40 CFR part 60, subpart B (hereafter referred to as the
``implementing regulations''). The implementing regulations reflect
EPA's principal task under CAA section 111(d)(1), which is to develop a
procedure for states to establish standards of performance for existing
sources through state plans. EPA is proposing to promulgate an updated
version of the implementing regulations as part of ACE (see Section
VII). Per the new proposed implementing regulations, EPA effectuates
its role by publishing, an ``emission guideline'' \4\ that, among other
things, contains EPA's determination of the BSER for the category of
existing sources being regulated. See 40 CFR 60.22a(b) [``Guideline
documents published under this section will provide information for the
development of State plans, such as: . . . (4) An emission guideline
that reflects the application of the best system of emission reduction
(considering the cost of such reduction) that has been adequately
demonstrated.''] In undertaking this task, EPA ``will specify different
emissions guidelines . . . for different sizes, types and classes of .
. . facilities when costs of control, physical limitations, geographic
location, or similar factors make subcategorization appropriate.'' 40
CFR 60.22(b)(5).
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\4\ See Section VII.A. for proposed changes to the definition of
``emission guideline'' as part of EPA's proposed new implementing
regulations.
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In short, under EPA's new proposed regulations implementing CAA
section 111(d), which tracks with the existing implementing regulations
in this regard, the guideline document serves to ``provide information
for the development of state plans.'' 40 CFR 60.22a(b), with the
``emission guideline,'' reflecting BSER as determined by EPA, being the
principal piece of information states rely on to develop their plans
that establish standards of performance for existing sources.
Because the CAA cannot necessarily be applied to GHGs in the same
manner as other pollutants, Utility Air Regulatory Group, 134 S. Ct.
2427, 2455 (2014) (Alito, J., concurring in part and dissenting in
part), it is fortuitous that CAA section 111(d) recognizes that states
possess considerable flexibility in developing their plans in response
to the emissions guideline(s) established by EPA. Specifically, the Act
requires that EPA permit states to consider, ``among other factors, the
remaining useful life'' of an existing source in applying a standard of
performance to such sources. CAA section 111(d)(1).
Additionally, while CAA section 111(d)(1) clearly authorizes states
to develop state plans that establish performance standards and
provides states with certain discretion in determining appropriate
standards, CAA section 111(d)(2) provides EPA specifically a role with
respect to such state plans. This provision authorizes EPA to prescribe
a plan for a state ``in cases where the State fails to submit a
satisfactory plan.'' CAA section 111(d)(2)(A). EPA therefore is charged
with determining whether state plans developed and submitted under
section 111(d)(1) are ``satisfactory,'' and the proposed new
implementing regulations at 40 CFR 60.27a accordingly provides timing
and procedural requirements for EPA to make such a determination. Just
as guideline documents may provide information for states in developing
plans that establish standards of performance, they may also provide
information for EPA to consider when reviewing and taking action on a
submitted state plan, as the new proposed implementing regulations at
40 CFR 60.27a(c) references the ability of EPA to find a state plan as
``unsatisfactory because the requirements of (the implementing
regulations) have not been met.'' \5\
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\5\ See also 40 FR 53343 (``If there is to be substantive
review, there must be criteria for the review, and EPA believes it
is desirable (if not legally required) that the criteria be made
known in advance to the States, to industry, and to the general
public. The emission guidelines, each of which will be subjected to
public comment before final adoption, will serve this function.'').
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B. Executive Order 13783 and EPA's Review of the CPP
On March 28, 2017, President Trump issued Executive Order 13783,
which affirms the ``national interest to promote clean and safe
development of our Nation's vast energy resources, while at the same
time avoiding regulatory burdens that unnecessarily encumber energy
production, constrain economic growth, and prevent job creation.'' See
Executive Order 13783, Section 1(a). The Executive Order directs all
executive departments and agencies, including EPA, to ``immediately
review existing regulations that potentially burden the development or
use of domestically produced energy resources and appropriately
suspend, revise, or rescind those that unduly burden the development of
domestic energy resources beyond the degree necessary to protect the
public interest or otherwise comply with the law.'' Id. Section 1(c).
The Executive Order further affirms that it is ``the policy of the
United States that necessary and appropriate environmental regulations
comply with the law.'' Id. Section 1(e). Moreover, the Executive Order
specifically directs EPA to review and initiate reconsideration
proceedings to ``suspend, revise, or rescind'' the CPP, ``as
appropriate and consistent with law.'' Id. Section 4(a)-(c).
In a document signed the same day as Executive Order 13783, and
published in the Federal Register at 82 FR 16329 (April 4, 2017), EPA
announced that, consistent with the Executive Order, it was initiating
its review of the CPP and providing notice of forthcoming proposed
rulemakings consistent with the Executive Order.\6\ In the course of
EPA's review of the CPP, the Agency also reevaluated its interpretation
of CAA section 111, and, on that basis, the Agency proposed to repeal
the CPP. See 82 FR 48035.
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\6\ EPA also withdrew the proposed federal plan and model
trading rules, proposed amendments to certain regulations under 40
CFR part 60, subpart B, implementing CAA section 111(d), and
proposed rule regarding the Clean Energy Incentive Plan. 82 FR 16144
(April 3, 2017).
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This action proposes a BSER for GHGs from existing EGUs in line
with the interpretation presented in the proposed CPP repeal. See 82 FR
48038-42. Comments submitted on the proposed repeal will be considered
in the promulgation of this rulemaking so there is no need to resubmit
comments that have already been timely submitted.
C. Industry Trends
Carbon dioxide emissions in the power sector have steadily declined
in recent years due to a variety of power industry trends, which are
expected to continue. The reduction in power sector CO2
emissions is the result of industry trends away from coal-fired
generation and toward low- and zero-emitting generation sources. These
trends have been driven by market factors, reduced electricity demand,
and policy and regulatory efforts. These trends have resulted in a
notable change to the country's overall generation mix, as more natural
gas and renewable energy is used to generate electricity relative to
coal-fired electricity. The price of natural gas is expected to remain
low for the foreseeable future as improvements in drilling technologies
and techniques continue to reduce the cost of extraction. In addition,
the existing fleet of coal-fired EGUs is aging and there are very few
new coal-fired generation
[[Page 44751]]
projects under development. With a continued (but reduced) tax credit
and declining capital costs, solar capacity will continue to grow
through 2050 while tax credits that phase out for plants entering
service through 2024 provide incentives for new wind capacity in the
near-term. Some power plant generators have announced that they expect
to continue to change their generation mix away from coal-fired
generation toward natural-gas fired generation, renewables and more
deployment of energy efficiency measures. All of these trends, in
total, are expected to result in declining power sector CO2
emissions.
In the near-term, according to the U.S. Energy Information
Administration's (EIA) 2018 Annual Energy Outlook, ``the cumulative
effect of increased coal plant retirements, lower natural gas prices
and lower electricity demand in the AEO2018 Reference case is a
reduction in the projected [CO2] emissions from electric
generators, even without the [CPP]. In 2020, electric power sector
CO2 emissions are projected to be 1.72 billion metric tons,
which is 120 million metric tons (7 percent) lower than the projected
level of CO2 emissions in the AEO2017 Reference case without
the CPP.'' \7\ In other words, these declining emission trends have
continued to develop even in the absence of implementation of the CPP.
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\7\ U.S. EIA, Annual Energy Outlook 2018 with projections to
2050 (February 6, 2018), at 102, available at https://www.eia.gov/outlooks/aeo/pdf/AEO2018.pdf.
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In consideration of these ongoing and projected power sector trends
and a resulting decline in power sector CO2 emissions, EPA
is soliciting comment on whether and how to consider such trends in
developing CO2 emission guidelines for the power sector. A
comparison of EIA projections to EPA analysis for the original proposed
CPP demonstrates that the rapid changes in the power sector are leading
to CO2 emission reductions at a faster rate than projected
even a few years ago when the CPP was promulgated (Comment C-1). EPA
also notes that CO2 emissions are projected to increase over
time in some EIA AEO side cases, and, given the uncertainties
associated with long-term emission projections, solicits comments on
the applicability of those alternative results.
Because of the rapid pace of these power sector changes, it is
difficult for sector analysts to fully account for these changing
trends in near-term and long-term sector-wide projections. This means
that regulatory decisions made today could be based on information that
may very well be outdated within the next several years. If that is the
case, work put in by federal and state regulatory agencies--as well as
by the affected sources themselves--to address section 111(d)
requirements could quickly be overtaken by external market forces which
could make those efforts redundant or, even worse, put them in conflict
with industry trends that are already reducing CO2
emissions.
III. Legal Authority
A. Authority To Revisit Existing Regulations
EPA's ability to revisit existing regulations is well-grounded in
the law. Specifically, EPA has inherent authority to reconsider, repeal
or revise past decisions to the extent permitted by law so long as the
Agency provides a reasoned explanation. The CAA complements EPA's
inherent authority to reconsider prior rulemakings by providing the
Agency with broad authority to prescribe regulations as necessary. 42
U.S.C. 7601(a); see also Emission Guidelines and Compliance Times for
Municipal Solid Waste Landfills, 81 FR 59276, 59277-78 (August 29,
2016). The authority to reconsider prior decisions exists in part
because EPA's interpretations of statutes it administers ``[are not]
instantly carved in stone,'' but must be evaluated ``on a continuing
basis.'' Chevron U.S.A. Inc. v. NRDC, Inc., 467 U.S. 837, 863-64
(1984). This is true when, as is the case here, review is undertaken
``in response to . . . a change in administrations.'' National Cable &
Telecommunications Ass'n v. Brand X Internet Services, 545 U.S. 967,
981 (2005). Indeed, ``[a]gencies obviously have broad discretion to
reconsider a regulation at any time.'' Clean Air Council v. Pruitt, 862
F.3d 1, 8-9 (D.C. Cir. 2017).
B. Authority To Regulate EGUs
In the CPP, EPA stated that EPA's then-concurrent promulgation of
standards of performance regulating CO2 emissions from new,
modified, and reconstructed EGUs triggered the need to regulate
existing sources under CAA section 111(d). 80 FR 64715. In ACE, we are
not re-opening any issues related to this conclusion, but for the
convenience of stakeholders and the public, we will summarize our
explanation here.
We explained in the CPP that CAA section 111(d)(1) requires EPA to
promulgate regulations under which states must submit state plans
regulating ``any existing source'' of certain pollutants ``to which a
standard of performance would apply if such existing source were a new
source.'' Id. Under CAA section 111(a)(2) and 40 CFR 60.15(a), a ``new
source'' is defined as any stationary source, the construction,
modification, or reconstruction of which is commenced after the
publication of proposed regulations prescribing a standard of
performance under CAA section 111(b) applicable to such source. We
noted that, at that time, we were concurrently finalizing a rulemaking
under CAA section 111(b) for CO2 emissions from affected
EGUs, which provided the requisite predicate for applicability of CAA
section 111(d). Id.
EPA explained in the 111(b) rule (80 FR 64529) that ``CAA section
111(b)(1)(A) requires the Administrator to establish a list of source
categories to be regulated under section 111. A category of sources is
to be included on the list `if in [the Administrator's] judgment it
causes, or contributes significantly to, air pollution which may
reasonably be anticipated to endanger public health and welfare.' ''
This determination is commonly referred to as an ``endangerment
finding'' and that phrase encompasses both the ``causes or contributes
significantly'' component and the ``endanger public health and
welfare'' component of the determination. Then, for the source
categories listed under section 111(b)(1)(A), the Administrator
promulgates, under section 111(b)(1)(B), ``standards of performance for
new sources within such category.'' EPA further explained that, because
EGUs had previously been listed, it was unnecessary to make an
additional finding. The Agency also noted that, under section
111(b)(1)(A), findings are category specific and not pollutant
specific, so a new finding is not needed with regard to a new
pollutant. The Agency further asserted that, even if it were required
to make a finding, given the large amount of CO2 emitted
from this source category (the largest single stationary source
category of emissions of CO2 by far) that EGUs would easily
meet that standard. The Agency further noted that, given the large
amount of emissions from the source category, it was not necessary in
that rule ``for the EPA to decide whether it must identify a specific
threshold for the amount of emissions from a source category that
constitutes a significant contribution.'' 80 FR 64531.
That CAA section 111(b) rulemaking remains on the books, although
EPA is currently considering revising it. Accordingly, it continues to
provide the requisite predicate for applicability of CAA section
111(d). Any comments on the issues discussed in this subsection would
be more appropriately addressed
[[Page 44752]]
to the docket on EPA's intended forthcoming proposal with regard to the
new source rule.
C. Legal Authority for Determination of the BSER
As discussed above, EPA's authorized role under CAA section 111(d)
is to establish a procedure under which states submit plans
establishing standards of performance for existing sources, reflecting
the application of the best system of emission reduction that EPA has
determined is adequately demonstrated for the source category. In the
CPP, EPA determined that the BSER for CO2 emissions from
existing fossil fuel-fired power plants was the combination of emission
rate improvements and limitations on overall emissions by affected
power plants that can be accomplished through a combination of three
sets of measures, which the EPA called ``building blocks'':
1. Improving heat rate at affected coal-fired steam generating
units;
2. Substituting increased generation from lower-emitting existing
natural gas combined cycle units for decreased generation from higher-
emitting affected steam generating units; and
3. Substituting increased generation from new zero-emitting
renewable energy generating capacity for decreased generation from
affected fossil fuel-fired generating units.
While building block 1 constituted measures that could be applied
directly to a source--that is, integrated into its design or
operation--building blocks 2 and 3 employed generation-shifting
measures that departed from this traditional, source-specific approach
to regulation.
As explained in the proposed repeal, after reconsidering the
statutory text, context and legislative history, and in consideration
of EPA's historical practice under CAA section 111 as reflected in its
other existing section 111 regulations, the Agency proposes to return
to a reading of section 111(a)(1) (and its constituent term, ``best
system of emission reduction'') as being limited to emission reduction
measures that can be applied to or at an individual stationary source.
That is, such measures must be based on a physical or operational
change to a building, structure, facility or installation at that
source rather than measures the source's owner or operator can
implement at another location. For a more detailed discussion of EPA's
proposed interpretation, see 82 FR 48039-42.
In proposing ACE, EPA offers additional legal rationale to support
its determination that heat-rate improvements constitute the BSER. EPA
solicits comment on these additional legal interpretations (Comment C-
2).
First, as explained in the CPP preamble, reduced utilization ``does
not fit within our historical and current interpretation of the BSER.''
See 80 FR 64780; see also id. at 64762 (``EPA has generally taken the
approach of basing regulatory requirements on controls and measures
designed to reduce air pollutants from the production process without
limiting the aggregate amount of production.'') Whereas some emission
reduction measures (such as a scrubber) may have an incidental impact
on a source's production levels, reduced utilization is directly
correlated with a source's output. Moreover, predicating a CAA section
111 standard on a source's non-performance would inappropriately inject
the Agency into an owner/operator's production decisions. In returning
to our historical understanding of and practice under section 111, we
reiterate that reduced utilization is not a valid system of emission
reduction for purposes of establishing a standard of performance. EPA
believes our proposed interpretation that the BSER be limited to
measures that can be applied at or to a source does not command a
different result.
Second, as explained in the proposed repeal notice, interpretative
constraints that may apply to interpreting CAA section 111(a)(1) (i.e.,
determining what types of measures that may be considered as the BSER)
for purposes of setting a new source performance standard under section
111(b) reasonably may be applied to interpreting the BSER for purposes
of setting existing source standards under section 111(d) as well (and,
given that ``standard of performance'' is given a unitary definition
for purposes of the entire statutory section, applying the same
interpretative constraints may in fact be required). For example, we
proposed that ``the BSER should be interpreted as a source-specific
measure, in light of the fact that [Best Available Control Technology,
or BACT] standards, for which the BSER is expressly linked by statutory
text, are unambiguously intended to be source-specific.'' \8\ See 82 FR
48042.
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\8\ See 40 CFR 52.21(b)(12); see also 42 U.S.C. 7479(3).
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Under the CAA and applicable regulations, certain preconstruction
permits must contain emissions limitations based on application of BACT
for certain regulated pollutants. EPA recommends that permitting
authorities follow a five-step ``top-down'' BACT analysis, which calls
for all available control technologies for a given pollutant to be
identified and ranked in descending order of control effectiveness.\9\
The options are then assessed in consideration of technical, energy,
environmental and economic factors until an option is selected as BACT.
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\9\ The five steps are: (1) Identify all available control
technologies; (2) eliminate technically infeasible options; (3) rank
remaining control technologies; (4) evaluate most effective controls
and document results; and (5) select the BACT.
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In reviewing our BACT guidance, we have identified additional
interpretive constraints that may be applied to CAA section 111.
Specifically, in EPA's PSD and Title V Permitting Guidance for
Greenhouse Gases, we explained that a BACT analysis ``need not
necessarily include inherently lower polluting processes that would
fundamentally redefine the nature of the source proposed by the permit
applicant.'' Id. at 26 (emphasis added). Furthermore, we explained that
``BACT should generally not be applied to regulate the applicant's
purpose or objective for the proposed facility.'' Id. Indeed, ``EPA has
recognized that the initial list of control options for a BACT analysis
does not need to include `clean fuel' options that would fundamentally
redefine the source. Such options include those that would require a
permit applicant to switch to a primary fuel type (i.e., coal, natural
gas or biomass) other than the type of fuel that an applicant proposes
to use for its primary combustion process.'' Id. at 27. EPA has even
noted that ``applicants proposing to construct a coal-fired electric
generator, have not been required by EPA as part of a BACT analysis to
consider building a natural gas-fired electric turbine although the
turbine may be inherently less polluting per unit product (in this case
electricity).'' \10\ Although in the CPP we believed that EPA's
``redefining the source'' policy was not relevant for purposes of
section 111(d), see CPP RTC Chapter 1A, 170-72, we now believe that
such a policy is relevant in light of the relationship between BACT and
BSER. In the response to comments accompanying the CPP, EPA rejected
the relevance to BSER under section 111 of the Agency's general policy
against ``redefining the source'' in the context of PSD/BACT. EPA now
believes that it was incorrect in its response, and that it is worth
examining this point in some detail because it encapsulates several key
aspects of the CPP's interpretation
[[Page 44753]]
of section 111 in general and section 111(d) in particular that EPA now
proposes to conclude in ACE are not appropriate interpretations of the
statute.
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\10\ New Source Review Workshop Manual, at B.13 (Draft) (October
1990), available at https://www.epa.gov/sites/production/files/2015-07/documents/1990wman.pdf.
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In its response to comments, EPA largely based its rejection of the
relevance of PSD to BSER on what it saw as the salient distinctions
between the sources subject to, and mode of operation of, the two
statutory programs. In this regard, EPA spoke of the ``distinct context
of the PSD program, which involves the case-by-case review of the
construction of an individual stationary source. . . . BACT is not
applicable to unmodified existing sources nor is it applied on a source
category basis. The CAA's PSD program is administered primarily by
state and local permitting authorities as [an] individualized
preconstruction requirement under CAA section 165. Under section
111(d), the Administrator identifies a list of adequately demonstrated
control options in use by the industry, selects the best of those
control options after considering cost and other factors, then selects
an achievable limit for the category through the application of the
BSER across the industry. . . .'' (Emphases added.)
Here, EPA's response disregarded the fact that under CAA section
111(d), the statute explicitly tasks states--not the Administrator--
with ``establishing standards of performance'' for existing sources,
and that the statute expressly requires EPA to allow the state to take
into account source-specific factors when doing so. A ``standard of
performance'' is defined at section 111(a)(1) as ``a standard for
emissions of air pollutants which reflects the degree of emission
limitation achievable through the application of the'' BSER. (Emphasis
added.) Therefore, it is the state, not EPA, that is tasked in the
first instance with ``select[ing] an achievable limit'' for existing
sources--and section 111(d)'s emphasis on source-specific factors at
the very least renders questionable EPA's unqualified assertion that
BSER for existing sources ``is applied on a source category basis.'' In
the instant proposal, EPA proposes to give full meaning to these
textual and structural features of the existing-source program under
section 111(d) that render it in important respects distinct from the
new-source program under section 111(b) and similar to the source-by-
source PSD program: Section 111(d), unlike section 111(b), is
implemented in the first instance by the states, and it is expressly
linked to source-specific factors. These similarities counsel against
EPA's prior rejection of the relevance of the general policy under PSD
against ``redefining the source.''
Furthermore, speaking of the generation-shifting measures that
constituted the second and third ``building blocks'' of the CPP, EPA
asserted that ``those measures are part of the business purposes and
objectives within the power sector. Accordingly, the BSER, which
incorporates building blocks 2 and 3, cannot be said to force a
fundamental redefinition of the business of generating electric
power.'' (Emphases added.) The emphasized phrases reveal the influence
of EPA's statutory interpretation underlying the CPP: That EPA can
regulate under CAA section 111 at the level of an entire industrial
sector, and that the business that it is regulating is ``generating
electric power'' writ large--rather than a recognition in line with the
statute's text and structure, and EPA's practice prior to the CPP, of
regulating the performance of individual sources through measures
carried out at and by the individual source.
EPA rested on its discretionary prerogative: ``EPA's policies under
CAA section 165 regarding the construction of individual sources are
not controlling for purposes of establishing category-wide standards
for existing sources under CAA section 111(d). Even if the PSD
`redefining the source' policies were applicable in this context, it
would be within the Administrator's discretion to consider requiring a
fundamental redesign of a newly constructed or modified source[ ].
EPA's case-by-case application of CAA section 165 in the PSD program
does not limit the Administrator's discretion in establishing an
emission guideline for an entire category of existing sources under CAA
section 111(d).'' (Emphases added.) EPA has explained, both in the
proposed repeal and the instant proposal, why it is proposing to
conclude that the statute does not, in fact, delegate discretion to the
Administrator to ``establish . . . for an entire category of existing
sources'' standards that can only be accomplished by ``a fundamental
redesign'' of that category, of the generation mix, and of the division
of jurisdiction over electricity generation within the federal
government and between the federal government and the states. But to
the extent that the Agency, due to the fact that Congress did not
expressly forbid such an approach, does possess that discretion, today
it proposes not to exercise it.
Third, notwithstanding the relationship between BACT and BSER, we
believe that measures ``redefining the source'' should be excluded from
consideration for purposes of CAA section 111(d). See, e.g., Sierra
Club v. EPA, 499 F.3d 653, 655 (7th Cir. 2007) (``Refining the
statutory definition . . . to exclude redesign is the kind of judgment
by an administrative agency to which a reviewing court should
defer.''). Indeed, the policy against redefining a source is even more
sensible when applied to existing sources. Under section 111(d),
regulated sources are well past the proposal stage and redefining such
sources would likely require, at a minimum, significant modification
and could even require decommissioning, redesign and new construction.
Accordingly, we propose to recognize that the BSER analysis need not
include options that would ``fundamentally redefine the source,''
irrespective of the application of that policy under PSD. For purposes
of ACE, therefore, we did not consider natural gas repowering (i.e.,
converting from a coal-fired boiler to a gas-fired turbine) or
refueling (i.e., converting from a coal-fired boiler to a natural gas-
fired boiler) as a system of emission reduction for coal-fired steam
generating units.
Fourth, the legislative history underlying CAA section 111 confirms
that Congress intended this provision to be source oriented. The Senate
Committee Report on Senate Bill 4358 explained that ``[t]he provisions
for new source performance standards [i.e., S. 4538, section 113] \11\
are designed to insure [sic] that new stationary sources are designed,
built, equipped, operated, and maintained so as to reduce emissions to
a minimum.'' S. Committee Rep. to accompany S. 4358 (Sept. 17, 1970),
1970 CAA Legis. Hist. at 415-16 (emphasis added). Similarly,
``[e]mission standards developed under [S. 4538, section 114] would be
applied to existing stationary sources. However, the Committee
recognizes that certain old facilities may use equipment and processes
which are not suited to the application of control technology.'' Id. at
1970 CAA Legis. Hist. at 419 (emphasis added) (noting further that in
such cases, the application of standards could be waived).
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\11\ Section 113 of Senate Bill 4538 would become CAA section
111; section 114 of the Senate Bill would become CAA section 111(d).
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The proposed interpretive scope of the BSER is reasonable because
it focuses the BSER on the performance of the emitting unit itself,
rather than the performance of the emitting unit and the transmission
system to which it belongs. EPA's area of expertise is control of
emissions at the source. EPA is not the expert agency with regard to
electricity management. FERC is the expert at the
[[Page 44754]]
federal level and public utility commissions are the experts at the
state and local level. Numerous factors might be considered in
determining which power plants dispatch on a given system or operate at
any given time (e.g., cost of service, voltage support, electricity
demand, availability of renewable resources, etc.). Moreover, numerous
factors are relevant in determining how much new/replacement generation
capacity is needed and what types of generating resources best satisfy
that need. EPA has no express legal authority and no particular
expertise in any of these areas. This is particularly relevant because,
as noted below, there are already significant changes taking place
within the power sector that are resulting in shifts away from coal-
fired generation to new technologies such as renewables. This shift is
creating tremendous strain on the power infrastructure even without the
added pressures of an EPA mandate to further shift away from additional
coal-fired generation. Many experts have expressed concern that these
pressures could create reliability problems. As DOE noted in a 2017
report on electricity markets and reliability, ``Ultimately, the
continued closure of traditional baseload power plants calls for a
comprehensive strategy for long-term reliability and resilience. States
and regions are accepting increased risks that could affect the future
reliability and resilience of electricity delivery for consumers in
their regions. Hydropower, nuclear, coal, and natural gas power plants
provide essential reliability services and fuel assurance critical to
system resilience. A continual comprehensive regional and national
review is needed to determine how a portfolio of domestic energy
resources can be developed to ensure grid reliability and resilience.''
\12\ Because EPA believes it is not appropriate to further challenge
the nation's electricity system while these important technical and
policy issues are being addressed. EPA believes that it is reasonable
to focus on a ``BSER'' limited to consideration of emission control
measures that can be applied at or to coal-fired units, ensuring that
regardless of how much coal-fired generation remains, that generation
is operated to minimize CO2 emissions.
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\12\ U.S. DOE, Staff Report to the Secretary on Electricity
Markets and Reliability (August 2017) at 14, available at https://www.energy.gov/sites/prod/files/2017/08/f36/Staff%20Report%20on%20Electricity%20Markets%20and%20Reliability_0.pdf
.
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Also, the proposed interpretive scope of the BSER is reasonable
considering the several important economic, policy and technology
shifts occurring in the power sector. The first change is being driven
by low natural gas prices that make lower carbon-emitting NGCC units
more competitive as compared to higher carbon-emitting coal plants.
Another important change is driven by both technology changes and by
state and national energy policy decisions that have made renewable
energy (e.g., solar and wind energy) more competitive compared to coal
and natural gas. The third notable change is driven by aging coal
plants, which considering the economic competitive pressures driven by
natural gas and renewable generation, are leading companies to conclude
that a significant number of coal plants are reaching the end of their
useful economic life or are no longer economic to operate.
These trends have driven down GHG emissions from power plants,
which were also key components to the BSER as defined in the CPP. In
fact, the analysis that EPA has done for ACE (see RIA), as well as
analysis by many others (including EIA), show that these trends have
already well outpaced the projections that went into the CPP for many
states. For this reason, establishing a BSER on assumptions for
generation by various sources that accounts for the continuation of
these trends into the future would create significant work for both
states and sources that may or may not result in emission reductions
from ACE if the actual trends once again prove to be stronger than
projected.
While some might suggest that this argues that the BSER in ACE
should still follow the same approach as the CPP, adjusting this
proposal to be even more stringent ignores the fact that the
uncertainties that have resulted in faster than projected emission
reductions are also uncertain in the opposite direction. From 2005 to
2008, gas prices experienced several unexpected peaks that were not
anticipated. If this were to happen in the future, it would make any
rule based on CPP-type assumptions significantly more expensive.
Similarly, while the recent past has shown continued advances in
renewable cost and performance, it is not certain that those trends
will be sustained. It should be noted that federal tax subsidies that
have been key to this trend are set to expire over the next several
years which may play a role in the future.
Because of these significant uncertainties that can have large
impacts on electric reliability and the cost of electricity to
consumers, EPA believes that this further supports the unreasonableness
of basing the BSER on generation-shifting measures. Regardless of the
path that the power sector takes, coal-fired power plants are likely to
be an important part of the generation mix for the foreseeable future,
therefore EPA believes it is reasonable to ensure that the remaining
coal-fired generation (which is also the most CO2 intensive
portion of the power sector) focuses on reducing that CO2
emission intensity to the extent technically feasible considering cost.
EPA believes that a BSER focused on making these plants as
efficient as possible is the best way to ensure GHG emission reductions
regardless of other factors such as technology changes for other types
of generation, changes in fuel price, changes in electricity demand or
changes in energy policy that neither environmental regulators nor
power companies have the power to control.
IV. Affected Sources
EPA is proposing that an affected EGU subject to regulation upon
finalization of ACE is any fossil fuel-fired electric utility steam
generating unit (i.e., utility boilers) that is not an integrated
gasification combined cycle (IGCC) unit (i.e., utility boilers, but not
IGCC units) that was in operation or had commenced construction as of
August 31, 2018,\13\ and that meets the following criteria.\14\ To be
an affected EGU, a fossil fuel-fired electric utility steam generating
unit must serve a generator capable of selling greater than 25 MW to a
utility power distribution system and have a base load rating greater
than 260 GJ/h (250 MMBtu/h) heat input of fossil fuel (either alone or
in combination with any other fuel).
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\13\ Under section 111(a) of the CAA, determination of affected
sources is based on the date that EPA proposes action on such
sources. January 8, 2014 is the date the proposed GHG standards of
performance for new fossil fuel-fired EGUs were published in the
Federal Register (79 FR 1430).
\14\ To be clear, this definition of an affected EGU does not,
at this time, include stationary combustion turbines for reasons
discussed later in this document.
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EPA is proposing different applicability criteria than in the CPP
to reflect EPA's determination of the BSER for only fossil fuel-fired
electric utility steam generating units. In ACE, EPA does not identify
a BSER for stationary combustion turbines and IGCC units and, thus,
such units are not affected EGUs for purposes of this action (see
discussion below in Section V.B). It should be noted, in the CPP's
identification of the BSER, no HRIs were identified as the BSER for
stationary combustion turbines and IGCC units. Nevertheless, EPA
solicits comment on systems of emission reduction that might be the
BSER for these types of
[[Page 44755]]
EGUs (Comment C-3). EPA notes that, under the CPP, certain EGUs were
not considered to be affected EGUs, and therefore were exempt from
inclusion in a state plan. Similarly, EPA is proposing for ACE, the
following EGUs would be excluded from a state's plan: (1) Those units
subject to 40 CFR 60 subpart TTTT as a result of commencing
modification or reconstruction; (2) steam generating units subject to a
federally enforceable permit limiting net-electric sales to one-third
or less of their potential electric output or 219,000 MWh or less on an
annual basis; (3) non-fossil units (i.e., units capable of combusting
at least 50 percent non-fossil fuel) that have historically limited the
use of fossil fuels to 10 percent or less of the annual capacity factor
or are subject to a federally enforceable permit limiting fossil fuel
use to 10 percent or less of the annual capacity factor; (4) units that
serve a generator along with other steam generating unit(s) where the
effective generation capacity (determined based on a prorated output of
the base load rating of each steam generating unit) is 25 MW or less;
(5) municipal waste combustor unit subject to 40 CFR part 60, subpart
Eb; or (6) commercial or industrial solid waste incineration units that
are subject to 40 CFR part 60, subpart CCCC. EPA solicits comment on
whether there should be a different definition of affected EGUs for ACE
(Comment C-4).
V. Determination of the BSER
CAA section 111(d)(1) directs EPA to promulgate regulations
establishing a CAA section 110-like procedure under which states submit
state plans that establish ``standards of performance'' for emissions
of certain air pollutants from sources which, if they were new sources,
would be subject to new source standards under section 111(b), and that
provide for the implementation and enforcement of those standards of
performance. The term ``standard of performance'' is defined in section
111(a)(1) as ``a standard for emissions of air pollutants which
reflects the degree of emission limitation achievable through the
application of the best system of emission reduction [BSER] which
(taking into account the cost of achieving such reduction and any
nonair quality health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated.''
Thus, EPA is authorized to determine the BSER for affected sources.
See also 40 CFR 60.22. In making this determination, EPA identifies all
``adequately demonstrated'' \15\ ``system[s] of emission reduction''
for a particular source category and then evaluates those systems to
determine which is the ``best'' \16\ while ``taking into account'' the
factors of ``cost . . . nonair quality health and environmental impact
and energy requirements.'' Because CAA section 111 does not set forth
the weight that should be assigned to each of these factors, courts
have granted the Agency a great degree of discretion in balancing them.
Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999)
(internal citations omitted).
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\15\ Case law under CAA section 111(b) explains that ``[a]n
adequately demonstrated system is one which has been shown to be
reasonably reliable, reasonably efficient, and which can reasonably
be expected to serve the interests of pollution control without
becoming exorbitantly costly in an economic or environmental way.''
Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 (D.C. Cir.
1973). While some of these cases suggest that ``[t]he Administrator
may make a projection based on existing technology,'' Portland
Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973), the
D.C. Circuit has also noted that ``there is inherent tension''
between considering a particular control technique as both ``an
emerging technology and an adequately demonstrated technology,''
Sierra Club v. Costle, 657 F.2d 298, 341 n.157 (D.C. Cir. 1981). See
also NRDC v. Thomas, 805 F.2d 410, n. 30 (D.C. Cir. 1986)
(suggesting that ``a standard cannot both require adequately
demonstrated technology and also be technology-forcing.'').
Nevertheless, EPA appears to ``have authority to hold the industry
to a standard of improved design and operational advances, so long
as there is substantial evidence that such improvements are
feasible.'' Sierra Club, 657 F.2d at 364.
\16\ The D.C. Circuit recognizes that EPA's evaluation of the
``best'' system must also include ``the amount of air pollution as a
relevant factor to be weighed . . . .'' Id. at 326.
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CAA section 111(d)(1) assigns responsibility to the states for
establishing standards of performance for affected existing sources--in
contrast to section 111(b), which directs EPA to set standards of
performance for affected new sources.
A. Identification of the BSER
In ACE, EPA identified several systems of emission reduction for
existing fossil-fuel fired steam generating EGUs (i.e., heat rate
improvements; carbon capture and storage; and fuel co-firing, including
with natural gas and biomass) and evaluated each of these systems to
determine which is the ``best'' while taking into account cost, nonair
quality health and environmental impact and energy requirements.
EPA proposes to identify ``heat rate improvements'' (which may also
be referred to as ``efficiency improvements'') as the BSER for existing
fossil-fuel fired steam generating EGUs. The basis for this
determination is discussed below. A discussion of other potential
CO2 reduction measures that EPA has determined are not BSER
(but which states may allow sources to use for compliance purposes) is
also provided below.
The U.S. fleet of existing coal-fired EGUs is a diverse group of
units with unique individual characteristics, spread across the
country. Coal-fired power plants are customized facilities that were
designed and built to meet local and regional electricity needs over
the past 100 years, with no two plants being identical. Geography and
elevation, unit size, coal type, pollution controls, cooling system,
firing method and utilization rate are just a few of the parameters
that can impact the overall efficiency and performance of individual
units. As a result, heat rates of existing coal-fired EGUs in the U.S.
vary substantially. The variation in heat rates among EGUs with similar
design characteristics, as well as year-to-year variation in heat rate
at individual EGUs, indicate that there is potential for HRIs that can
improve CO2 emission performance for the existing coal-fired
EGU fleet, but that this potential may vary considerably at the unit
level.
EPA does not currently have sufficient information on adequately
demonstrated systems of emission reduction--including HRI
opportunities--for existing natural gas-fired stationary combustion
turbines. As such, the Agency is currently unable to determine the BSER
for such units. In this action, EPA solicits information on adequately
demonstrated systems of GHG emission reduction for such units--
especially on the efficiency, applicability, and cost of such systems
(Comment C-5). This is discussed in greater detail below.
B. HRIs for Steam-Generating EGUs
As mentioned above, EPA proposes in ACE to identify ``heat rate
improvements'' as the BSER for existing steam generating fossil fuel-
fired EGUs. Heat rate is a measure of efficiency that is commonly used
in the power sector. The heat rate is the amount of energy input,
measured in British thermal units (Btu), required to generate one
kilowatt-hour (kWh) of electricity. The lower an EGU's heat rate, the
more efficiently it operates. As a result, an EGU with a lower heat
rate will consume less fuel per kWh generated and emit lower amounts of
CO2 and other air pollutants per kWh generated as compared
to a less efficient unit. An EGU's heat rate can be affected by a
variety of design characteristics, site-specific factors, and operating
conditions, including:
Thermodynamic cycle of the boiler;
[[Page 44756]]
Boiler and steam turbine size and design;
Cooling system type;
Auxiliary equipment, including pollution controls;
Operations and maintenance practices;
Fuel quality; and
Ambient conditions.
In the CPP, EPA quantified emission reductions achievable through
heat rate improvements on a regional basis (i.e., building block 1).
The Agency concluded that EGUs can achieve on average a 4.3 percent
improvement in the Eastern Interconnection, a 2.1 percent improvement
in the Western Interconnection and a 2.3 percent improvement in the
Texas Interconnection. See 80 FR 64789. The Agency then applied all
three of the building blocks to 2012 baseline data and quantified, in
the form of CO2 emission rates, the reductions achievable in
each interconnection in 2030 and selected the least stringent as a
national performance rate. Id. at 64811-819. EPA noted that building
block 1 measures could not by themselves constitute the BSER because of
a potential ``rebound effect.'' \17\ Id. at 64787.
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\17\ As discussed below, EPA modeled a range of potential HRIs
for ACE and the Agency's analysis indicates that system-wide
emission decreases from heat rate improvements will likely outweigh
any potential system-wide emission increases. Accordingly, EPA
proposes to conclude that the ``rebound effect'' does not preclude a
determination that HRIs constitute the BSER.
---------------------------------------------------------------------------
EPA believes that building block 1, as constructed in CPP, does not
represent an appropriate BSER, and ACE better reflects important
changes in the formulation and application of the BSER in accordance
with the CAA. For example, the percent improvement applied as the BSER
under CPP was determined at the interconnect-level, and did not take
into account remaining useful life or other source-specific factors,
which are addressed in this proposed rule.\18\ The current fleet of
existing fossil fuel-fired EGUs is quite diverse in terms of size, age,
fuel type, operation (e.g., baseload, cycling), boiler type, etc. Many
coal-fired EGUs now operate under load-following and cycling conditions
as opposed to the steady baseload operating conditions that were more
common a decade ago.
---------------------------------------------------------------------------
\18\ The Agency solicits comments, nonetheless, on whether and
how to retain building block 1 in lieu of the proposed approach.
---------------------------------------------------------------------------
There are available technologies and equipment upgrades, as well as
best operating and maintenance practices, that EGU owners or operators
may utilize to improve an EGU's heat rate. In the ANPRM, EPA solicited
information on a number of technology and equipment upgrades and good
practices (specifically including, but not limited to, those that were
listed in Tables 1 and 2 of the ANPRM, see 82 FR 61514) that have the
potential to reduce an EGU's heat rate.
Specifically, the Agency solicited information on: (1) Potential
HRIs from technologies and best operating and maintenance practices;
(2) costs of deploying the technologies and the best operating and
maintenance practices, including applicable planning, capital and
operating and maintenance costs; (3) owner and operator experiences
deploying the technologies and employing best operating and maintenance
practices; (4) barriers to or from deploying the technologies and
operating and maintenance practices; and (5) any other technologies or
operating and maintenance practices that may exist for improving heat
rate, but were not listed in the ANPRM.
EPA received useful information in the comments submitted in
response to the ANPRM. Many commenters contended that any evaluation of
the HRI potential of the coal-fired EGU fleet must be done on a unit-
by-unit basis since the opportunities for HRI are source-specific and
dependent upon the individual unit's design, configuration, and
operating and maintenance history. Many commenters emphasized the
significant influence that the operating mode (i.e., whether the unit
operates at consistent baseload conditions or in cycling or load-
following mode or as a low capacity factor unit that is subject to
frequent startups and shutdowns) has on an individual EGU's heat rate
and HRI potential. Many commenters also claimed that owners and
operators of fossil fuel-fired EGUs already routinely conduct HRI
efforts and, as a result, there are relatively few economic improvement
opportunities available.
1. Potential HRI Measures--Technologies and Equipment Upgrades
As mentioned above, numerous technologies and equipment upgrades,
as well as best operating and maintenance practices (which are
discussed in the next section), have been identified as potential
measures to improve an EGU's heat rate. In the ANPRM, EPA solicited
information on a large number of technology and equipment upgrades and
best operating and maintenance practices that have the potential to
reduce an EGU's heat rate. See Tables 1 and 2 of the ANPRM, 82 FR
61514.
In this action, EPA is proposing to determine that heat rate
improvement is the BSER for affected existing coal-fired EGUs and is
proposing a list of ``candidate technologies'' of HRI measures for
states to use in establishing standards of performance under CAA
section 111(d)(1). States can use the information that EPA provides on
the ``degree of emission limitation achievable through application of
the [BSER]'' to establish standards of performance for affected EGUs
covered by a state's plan.\19\ While a large number of HRI measures
have been identified in a variety of studies conducted by government
agencies and outside groups (see Table 3 in ANPRM, 82 FR 61515), some
of those identified technologies have limited applicability and many
provide only negligible HRI. EPA believes that it would be overly
burdensome to require States to evaluate the degree of emission
limitation achievable from the application of every single identified
HRI measure--including those with negligible benefits--at each source
(or subcategory of sources) within their borders. Therefore, EPA has
identified a list of the ``most impactful'' HRI measures that we are
proposing to serve as technologies, equipment upgrades and best
operating and maintenance practices that form the list of ``candidate
technologies'' constituting the BSER. The candidate technologies of the
BSER is listed in Table 1 below. Best operating and maintenance
practices are discussed in the next section. States are expected to
evaluate each of the BSER HRI measures in the candidate technologies in
establishing a standard of performance for any particular source. The
States, in applying a standard of performance, may take into
consideration, among other factors, the remaining useful life of the
existing source to which the standard would apply. EPA solicits
comments on whether other unlisted HRI measures should also be included
as part of the BSER and added to the candidate technologies (Comment C-
6). EPA also solicits comment on each of the candidate technologies
described further below, including whether any additional technologies
should be added to the list, and whether there is additional
information that EPA should be aware of and consider in determining the
BSER and establishing the candidate technologies for HRI measures
(Comment C-7).
---------------------------------------------------------------------------
\19\ The states, in applying the unit-specific standard, may
also take into consideration, among other factors, the remaining
useful life of the existing source to which the standard applies.
See CAA section 111(d)(1).
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The technologies and operating and maintenance practices listed and
[[Page 44757]]
described below may not be available or appropriate for all types of
EGUs; and some owners or operators will have already deployed some of
the technologies and employed some of the best operating and
maintenance practices.
Table 1--Summary of Most Impactful HRI Measures and Range of Their HRI Potential (%) by EGU Size
--------------------------------------------------------------------------------------------------------------------------------------------------------
<200 MW 200-500 MW >500 MW
HRI measure -----------------------------------------------------------------------------------------------
Min Max Min Max Min Max
--------------------------------------------------------------------------------------------------------------------------------------------------------
Neural Network/Intelligent Sootblowers.................. 0.5 1.4 0.3 1.0 0.3 0.9
Boiler Feed Pumps....................................... 0.2 0.5 0.2 0.5 0.2 0.5
Air Heater & Duct Leakage Control....................... 0.1 0.4 0.1 0.4 0.1 0.4
Variable Frequency Drives............................... 0.2 0.9 0.2 1.0 0.2 1.0
Blade Path Upgrade (Steam Turbine)...................... 0.9 2.7 1.0 2.9 1.0 2.9
Redesign/Replace Economizer............................. 0.5 0.9 0.5 1.0 0.5 1.0
-----------------------------------------------------------------------------------------------
Improved O&M Practices.................................. Can range from 0 to >2.0% depending on the unit's historical O&M practices.
--------------------------------------------------------------------------------------------------------------------------------------------------------
a. Neural Network/Intelligent Sootblower
Neural networks. Computer models, known as neural networks, can be
used to simulate the performance of the power plant at various
operating loads. Typically, the neural network system ties into the
plant's distributed control system for data input (process monitoring)
and process control. The system uses plant specific modeling and
control modules to optimize the unit's operation and minimize the
emissions. This model predictive control can be particularly effective
at improving the plants performance and minimizing emissions during
periods of rapid load changes. The neural network can be used to
optimize combustion conditions, steam temperatures, and air pollution
control equipment.
Intelligent Sootblowers. During operations at a coal-fired power
plant, particulate matter (ash or soot) builds up on heat transfer
surfaces. This build-up degrades the performance of the heat transfer
equipment and negatively affects the efficiency of the plant. Power
plant operators use steam injection ``sootblowers'' to clean the heat
transfer surfaces by removing the ash build-up. This is often done on a
routine basis or as needed based on monitored operating
characteristics. Intelligent sootblowers (ISB) are automated systems
that use process measurements to monitor the heat transfer performance
and strategically allocate steam to specific areas to remove ash
buildup.
The cost to implement an ISB system is relatively inexpensive if
the necessary hardware is already installed. The ISB software/control
system is often incorporated into the neural network software package
mentioned above. As such, the HRIs obtained via installation of neural
network and ISB systems are not necessarily cumulative.
The efficiency improvements from installation of intelligent
sootblowers are often greatest for EGUs firing subbituminous coal and
lignite due to more significant and rapid fouling at those units as
compared to EGUs firing bituminous coal.
b. Boiler Feed Pumps
A boiler feed pump (or boiler feedwater pump) is a device used to
pump feedwater into a boiler. The water may be either freshly supplied
or returning condensate produced from condensing steam produced by the
boiler. The boiler feed pumps consume a large fraction of the auxiliary
power used internally within a power plant. Boiler feed pumps can
require power in excess of 10 MW on a 500-MW power plant. Therefore,
the maintenance on these pumps should be rigorous to ensure both
reliability and high-efficiency operation Boiler feed pumps wear over
time and subsequently operate below the original design efficiency. The
most pragmatic remedy is to rebuild a boiler feed pump in an overhaul
or upgrade.
c. Air Heater and Duct Leakage Control
The air pre-heater is a device that recovers heat from the flue gas
for use in pre-heating the incoming combustion air (and potentially for
other uses such as coal drying). Properly operating air pre-heaters
play a significant role in the overall efficiency of a coal-fired EGU.
A major difficulty associated with the use of regenerative air pre-
heaters is air leakage from the combustion air side to the flue gas
side. Air leakage affects boiler efficiency due to lost heat recovery
and affects the axillary load since any leakage requires additional fan
capacity. The amount of air leaking past the seals tends to increase as
the unit ages. Improvements to seals on regenerative air pre-heaters
have enabled the reduction of air leakage.
d. Variable Frequency Drives (VFDs)
VFD on ID Fans. The increased pressure required to maintain proper
flue gas flow through add-on air pollutant control equipment may
require additional fan power, which can be achieved by an induced draft
(ID) fan upgrade/replacement or an added booster fan. Generally, older
power plant facilities were designed and built with centrifugal fans.
The most precise and energy-efficient method of flue gas flow
control is use of VFD. The VFD controls fan speed electrically by using
a static controllable rectifier (thyristor) to control frequency and
voltage and, thereby, the fan speed. The VFD enables very precise and
accurate speed control with an almost instantaneous response to control
signals. The VFD controller enables highly efficient fan performance at
almost all percentages of flow turndown.
Due to current electricity market conditions, many units no longer
operate at base-load capacity and, therefore, VFDs, also known as
variable-speed drives on fans can greatly enhance plant performance at
off-peak loads. Additionally, because utilities are phasing in their
environmental equipment upgrades, new fans are oversized and operated
at lower capacities until all additional equipment has been added.
Under these scenarios, VFDs can significantly improve the unit heat
rate. VFDs as motor controllers offer many substantial improvements to
electric motor power requirements. The drives provide benefits such as
soft starts, which reduce initial electrical load, excessive torque,
and subsequent equipment wear during startups; provide precise speed
control; and enable high-efficiency operation of motors at less than
the maximum efficiency point. During load turndown, plant auxiliary
power could
[[Page 44758]]
be reduced by 30-60 percent if all large motors in a plant were
efficiently controlled by VFD. With unit loads varying throughout the
year, the benefits of using VFDs on large-size equipment, such as FD or
ID fans, boiler feedwater and condenser circulation water pumps, can
have significant impacts. Because plants today usually use either new
booster ID fans or new ID fans, the option of investing in VFDs
generally appeals to plant operators since they are incurring long
outages to install the either new or additional air emission controls
equipment. There are circumstances in which the HRI has been estimated
to be much higher than that shown in Table 1, depending on the
operation of the unit. Cycling units realize the greatest gains
representative of the upper range of HRI, whereas units which were
designed with excess fan capacity will exhibit the lower range.
VFD on Boiler Feed Pumps. VFDs can also be used on boiler feed
water pumps as mentioned previously. Generally, if a unit with an older
steam turbine is rated below 350 MW the use of motor-driven boiler
feedwater pumps as the main drivers may be considered practical from an
efficiency standpoint. If a unit cycles frequently then operation of
the pumps with VFDs will offer the best results on heat rate
reductions, followed by fluid couplings. The use of VFDs for boiler
feed pumps is becoming more common in the industry for larger units.
And with the advancements in low pressure steam turbines, a motor-
driven feed pump can improve the thermal performance of a system up to
the 600-MW range, as compared to the performance associated with the
use of turbine drive pumps. Smaller and older units will generally not
upgrade to a VFD boiler feed pump drive due to high capital costs.
e. Blade Path Upgrade (Steam Turbine)
Upgrades or overhauls of steam turbines offer the greatest
opportunity for HRI on many units. Significant increases in performance
can be gained from turbine upgrades when plants experience problems
such as steam leakages or blade erosion. The typical turbine upgrade
depends on the history of the turbine itself and its overall
performance. The upgrade can entail myriad improvements, all of which
affect the performance and associated costs. The availability of
advanced design tools, such as computational fluid dynamics (CFD),
coupled with improved materials of construction and machining and
fabrication capabilities have significantly enhanced the efficiency of
modern turbines. These improvements in new turbines can also be
utilized to improve the efficiency of older steam turbines whose
efficiency has degraded over time. Upgrades or overhauls of steam
turbines may offer the greatest opportunity for HRI on many units.
Significant increases in performance can be gained from turbine
upgrades when plants experience problems such as steam leakages or
blade erosion. The typical turbine upgrade depends on the history of
the turbine itself and its overall performance. The upgrade can entail
myriad improvements, all of which affect the performance and associated
costs.
f. Redesign/Replace Economizer
In steam power plants, economizers are heat exchange devices used
to capture waste heat from boiler flue gas which is then used to heat
the boiler feedwater. This use of waste heat reduces the need to use
extracted energy from the system and, therefore, improves the overall
efficiency or heat rate of the unit. As with most other heat transfer
devices, the performance of the economizer will degrade with time and
use, and power plant representatives contend that economizer
replacements are often delayed or avoided due to concerns about
triggering NSR requirements. In some cases, economizer replacement
projects have been undertaken concurrently with retrofit installation
of selective catalytic reduction (SCR) systems because the entrance
temperature for the SCR unit must be controlled to a specific range.
2. Potential HRI Measures--Best Operating and Maintenance Practices
Many unit operators can achieve additional HRI by adopting best
operating and maintenance practices. The amount of achievable HRI will
vary significantly from unit to unit. In setting a standard of
performance for a specific unit or subcategory of units, states should
consider the opportunities for HRI from the following actions.
a. Adopt HRI Training for O&M Staff
EGU operators can obtain HRI by adopting ``awareness training'' to
ensure that all O&M staff are aware of best practices and how those
practices affect the unit's heat rate.
b. Perform On-Site Appraisals To Identify Areas for Improved Heat Rate
Performance
Some large utilities have internal groups that can perform on-site
evaluations of heat rate performance improvement opportunities. Outside
(i.e., third party) groups can also provide site-specific/unit-specific
evaluations to identify opportunities for HRI.
c. Improved Steam Surface Condenser--Cleaning
Effective operation of the steam surface condenser in a power plant
can significantly improve a unit's heat rate. In fact, in many cases it
can pose the most significant hindrance to a plant trying to maintain
its original design heat rate. Since the primary function of the
condenser is to condense steam flowing from the last stage of the steam
turbine to liquid form, it is most desirable from a thermodynamic
standpoint that this occurs at the lowest temperature reasonably
feasible. By lowering the condensing temperature, the backpressure on
the turbine is lowered, which improves turbine performance.
Condenser Cleaning. A condenser degrades primarily due to fouling
of the tubes and air in-leakage. Tube fouling leads to reduced heat
transfer rates, while air in-leakage directly increases the
backpressure of the condenser and degrades the quality of the water.
Condenser tube cleaning can be performed using either on-line methods
or more rigorous off-line methods. A full economic analysis should be
performed to determine which off-line cleaning method is to be used.
Such an analysis would result in an optimum offline or reduced-load
cleaning schedule that could average between two and three cleanings a
year. These analyses consider inputs such as operating data, plant
performance, loads, time of year, etc., to accurately assess cleaning
schedules for optimum economic performance.
3. Cost of HRI
a. Reasonableness of Cost
As mentioned earlier, under CAA section 111(a)(1), EPA is required
to determine ``the best system of emission reduction which (taking into
account the cost . . .) . . . has been adequately demonstrated.'' In
several cases, the D.C. Circuit has elaborated on this cost factor in
various ways, stating that EPA may not adopt a standard for which costs
would be ``exorbitant,'' \20\ ``greater than the industry could bear
and survive,'' \21\ ``excessive,'' \22\ or ``unreasonable.'' \23\ These
formulations appear to be synonymous and suggest a cost-reasonableness
standard. Therefore, in this action, EPA has evaluated
[[Page 44759]]
whether the costs of HRI are considered to be reasonable.
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\20\ Lignite Energy, 198 F.3d at 933.
\21\ Portland Cement, 513 F.2d at 508.
\22\ Sierra Club, 657 F.2d at 343.
\23\ Id.
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Any efficiency improvement made by an EGU will also reduce the
amount of fuel consumed per unit of electricity output; fuel costs can
account for as much as 70 percent of production costs of power. The
cost attributable to CO2 emission reductions, therefore, is
the net cost of achieving HRIs after any savings from reduced fuel
expenses. So, over some time period (depending upon, among other
factors, the extent of HRIs, the cost to implement such improvements,
and the unit utilization rate), the savings in fuel cost associated
with HRIs may be sufficient to cover the costs of implementing the HRI
measures. Thus, the net costs of HRIs associated with reducing
CO2 emissions from affected EGUs can be relatively low
depending upon each EGUs' individual circumstances. It should be noted
that this cost evaluation is not an attempt to determine the
affordability of the HRI in a business or economic sense (i.e., the
reasonableness of the imposed cost is not determined by whether there
is an economic payback within a predefined time period). However, the
ability of EGUs to recoup some of the costs of HRIs through fuel
savings supports a finding that cost recovery is a reasonable factor in
determining cost effectiveness.\24\
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\24\ While some EGUs may not realize the full potential of cost
recuperation from fuel savings, we expect that the net costs of
implementing heat rate improvements as an approach to reducing
CO2 emissions from fossil fuel-fired EGUs are reasonable.
---------------------------------------------------------------------------
Most often, when evaluating costs for criteria pollutants--in a
BACT analysis, for example--the emphasis is focused on the cost of
control relative to the amount of pollutant removed--a metric typically
referred to as the ``cost-effectiveness.'' There have been relatively
few BACT analyses evaluating GHG reduction technologies for coal-fired
EGUs; and, therefore not a large number of GHG cost-effectiveness
determinations to compare against as a measure of the cost
reasonableness. Nevertheless, in PSD and Title V permitting guidance
for GHG emissions, EPA noted that ``it is important in BACT reviews for
permitting authorities to consider options that improve the overall
energy efficiency of the source or modification--through technologies,
processes and practices at the emitting unit. In general, a more energy
efficient technology burns less fuel than a less energy efficient
technology on a per unit of output basis.'' \25\ EPA has also noted
that a ``number of energy efficiency technologies are available for
application to both existing and new coal-fired EGU projects that can
provide incremental step improvements to the overall thermal
efficiency.'' \26\
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\25\ See page 21, ``PSD and Title V Permitting Guidance for
Greenhouse Gases,'' EPA-457/B-11-001, March 2011; https://www.epa.gov/sites/production/files/2015-12/documents/ghgpermittingguidance.pdf.
\26\ See page 25, ``Available and Emerging Technologies for
Reducing Greenhouse Gas Emissions from Coal-fired Electric
Generating Units,'' October 2010; https://www.epa.gov/sites/production/files/2015-12/documents/electricgeneration.pdf.
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b. Cost of the HRI Candidate Technologies Measures
The estimated costs for the BSER candidate technologies are
presented below in Table 2. These are cost ranges from the 2009 S&L
Study \27\ updated to $2016. These costs correspond to ranges of HRI
(percent) presented earlier in Table 1.
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\27\ ``Coal-Fired Power Plant Heat Rate Reductions'' Sargent &
Lundy report SL-009597 (2009) https://www.epa.gov/sites/production/files/2015-08/documents/coalfired.pdf.
Table 2--Summary of Cost ($2016/kW) of HRI Measures
--------------------------------------------------------------------------------------------------------------------------------------------------------
<200 MW 200-500 MW >500 MW
HRI measure -----------------------------------------------------------------------------------------------
Min Max Min Max Min Max
--------------------------------------------------------------------------------------------------------------------------------------------------------
Neural Network/Intelligent Sootblowers.................. 4.7 4.7 2.5 2.5 1.4 1.4
Boiler Feed Pumps....................................... 1.4 2.0 1.1 1.3 0.9 1.0
Air Heater & Duct Leakage Control....................... 3.6 4.7 2.5 2.7 2.1 2.4
Variable Frequency Drives............................... 9.1 11.9 7.2 9.4 6.6 7.9
Blade Path Upgrade (Steam Turbine)...................... 11.2 66.9 8.9 44.6 6.2 31.0
Redesign/Replace Economizer............................. 13.1 18.7 10.5 12.7 10.0 11.2
-----------------------------------------------------------------------------------------------
Improved O&M Practices.................................. Minimal capital cost.
--------------------------------------------------------------------------------------------------------------------------------------------------------
In the CPP, EPA estimated the potential national average net HRI by
coal-fired EGUs to between 2.1 to 4.3 percent for each interconnection,
or about 4 percent nationally, with the improvements coming from some
combination of best operating practices and equipment upgrades. The
Agency noted in the CPP that the maximum cost of HRI from Table 2 is
expected to be less than the $100/kW value used in the CPP proposal,
especially as the EGU size increases; and, therefore, the Agency
assessed the economic effects of HRI costs that might range from $50 to
$100/kW. The technical applicability and efficacy of HRI measures and
the cost of implementing them are dependent upon site specific factors
and can vary widely from site to site. Because there is inherent
flexibility provided to the states in applying the standards of
performance, there is a wide range of potential outcomes that are
highly dependent upon how the standards are applied (and to what degree
states take into consideration other factors, including remaining
useful life).
In the RIA accompanying this proposal, the Agency evaluates three
illustrative scenarios that recognize the inherent flexibility provided
to states in applying standards of performance and provide insight on
potential outcomes. For those illustrative scenarios, EPA evaluates
costs ranging from $50/kW to $100/kW. EPA requests comment, with
analysis, on other cost ranges that may be appropriate.
4. Nonair Quality Health and Environmental Impacts, Energy
Requirements, and Other Considerations
As directed by CAA section 111(a)(1), EPA has taken into account
nonair quality health and environment requirements, and energy
requirements for each of the candidate BSER technologies listed in
Tables 1 and 2. None of the candidate technologies, if implemented at a
coal-fired EGU, would be expected to result in any deleterious effects
on any of the liquid effluents (e.g., scrubber liquor) or solid by-
products (e.g., ash, scrubber solids). All of these candidate
technologies, when
[[Page 44760]]
implemented, would have the effect of improving the efficiency of the
coal-fired EGUs to which they are applied. As such, the EGU would be
expected to use less fuel to produce the same amount of electricity as
it did prior to the efficiency (heat rate) improvement. None of
candidate technologies is expected to impose any significant additional
auxiliary energy demand.
Implementation of heat rate improvement measures also would achieve
reasonable reductions in CO2 emissions from affected sources
in light of the limited cost-effective and technically feasible
emissions control opportunities. In the same vein, because existing
sources face inherent constraints that new sources do not, existing
sources present different, and in some ways more limited, opportunities
for technological innovation or development. Nevertheless, the proposed
emissions guidelines encourage technological development by promoting
further development and market penetration of equipment upgrades and
process changes that improve plant efficiency.
5. Potential HRI at Existing Coal-Fired EGUs
Government agencies and laboratories, industry research
organizations, engineering firms, equipment suppliers, and
environmental organizations have conducted studies examining the
potential for improving heat rate in the U.S. EGU fleet or a subset of
the fleet. Table 3 below provides a list of some reports, case studies,
and analyses about HRI opportunities in the United States. EPA is
seeking comment on how these studies (and any others that the Agency
should be aware of) can inform our understanding of potential HRI
opportunities (Comment C-8).
Table 3--HRI Reports, Case Studies, and Analyses
------------------------------------------------------------------------
-------------------------------------------------------------------------
HRI report organization/publication (author, if known)--title--year
[URL]
------------------------------------------------------------------------
Government Studies:
Congressional Research Service (Campbell)--Increasing the Efficiency
of Existing Coal-fired Power Plants (R43343)--2013 [https://fas.org/sgp/crs/misc/R43343.pdf].
EIA--Analysis of Heat Rate Improvement Potential at Coal-Fired Power
Plants--2015 [https://www.eia.gov/analysis/studies/powerplants/heatrate/pdf/heatrate.pdf].
EPA--Greenhouse Gas Mitigation Measures--2015 [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-37114].
NETL--Opportunities to Improve the Efficiency of Existing Coal-fired
Power Plants--2009 [http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/OpportImproveEfficExistCFPP-ReportFinal.pdf].
NETL--Improving the Thermal Efficiency of Coal-Fired Power Plants in
the United States--2010 [http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/ThermalEfficCoalFiredPowerPlants-TechWorkshopRpt.pdf].
NETL--Improving the Efficiency of Coal-Fired Power Plants for Near
Term Greenhouse Gas Emissions Reductions (DOE/NETL-2010/1411)--2010
[http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/DOE-NETL-2010-1411-ImpEfficCFPPGHGRdctns-0410.pdf].
NETL--Options for Improving the Efficiency of Existing Coal-Fired
Power Plants (DOE/NETL-2013/1611)--2014 [https://www.netl.doe.gov/energy-analyses/temp/FY14_OptionsforImprovingtheEfficiencyofExistingCoalFiredPowerPlants_040114.pdf].
IEA (Reid)--Retrofitting Lignite Plants to Improve Efficiency and
Performance (CCC/264)--2016 [http://bookshop.iea-coal.org/reports/ccc-264/83861].
IEA (Henderson)--Upgrading and Efficiency Improvement in Coal-fired
Power Plants (CCC/221)--2013 [http://bookshop.iea-coal.org/reports/ccc-221/83186].
European Commission--Integrated Pollution Prevention and Control
Reference Document on Best Available Techniques for Large
Combustion Plants--2006 [http://eippcb.jrc.ec.europa.eu/reference/BREF/lcp_bref_0706.pdf].
Industry/Industrial Groups:
EPRI--Range of Applicability of Heat Rate Improvements--2014 [https://www.epri.com/#/pages/product/000000003002003457].
ABB Power Generation--Energy Efficient Design of Auxiliary Systems
in Fossil-Fuel Power Plants [https://library.e.abb.com/public/5e627b842a63d389c1257b2f002c7e77/Energy%20Efficiency%20for%20Power%20Plant%20Auxiliaries-V2_0.pdf].
Alstom Engineering (Sutton)--CO2 Reduction Through Energy Efficiency
in Coal-Fired Boilers--2011 [http://www.mcilvainecompany.com/Universal_Power/Subscriber/PowerDescriptionLinks/Jim%20Sutton%20-%20Alstom%20-%203-31-2011.pdf].
GE--Comments of the General Electric Company--2014 [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-22971].
National Petroleum Council--Electric Generation Efficiency--2007
[http://www.npc.org/Study_Topic_Papers/4-DTG-ElectricEfficiency.pdf].
S&L--Coal-fired Power Plant Heat Rate Reductions (SL-009597)--2009
[https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-36895 36895].
S&L--Coal Fired Power Plant Heat Rate Reduction--NRECA (SL-012541)--
2014 [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-22767 22767 Supp 33].
Storm Technologies--Applying the Fundamentals for Best Heat Rate
Performance of Pulverized Coal Fueled Boilers--2009 [http://www.stormeng.com/pdf/EPRI2009HeatRateConference%20FINAL.pdf].
Environmental Groups/Academic Studies:
Lehigh University--Reducing Heat Rates of Coal-fired Power Plants--
2009 [http://www.lehigh.edu/~inenr/leu/leu_61.pdf].
NRDC--Closing the Power Plant Carbon Pollution Loophole: Smart Ways
the Clean Air Act Can Clean Up America's Biggest Climate
Polluters (12-11-A)--2013 [https://www.nrdc.org/sites/default/files/pollution-standards-report.pdf].
Resources for the Future (Lin et al.)--Regulating Greenhouse Gases
from Coal Power Plants Under the Clean Air Act (RFF-DP-13-05)--2014
[http://www.rff.org/files/sharepoint/WorkImages/Download/RFF-DP-13-05.pdf].
Sierra Club (Buckheit & Spiegel)--Sierra Club 52 Unit Study--2014
[http://content.sierraclub.org/environmentallaw/sites/content.sierraclub.org.environmentallaw/files/Appendix%201%20-%20Rate%20v%20Load%20Summary.pdf].
Other Publications:
Power Engineering International (CoX)--Dry Sorbent Injection for SOX
Emissions Control--2017 [http://www.powerengineeringint.com/articles/print/volume-25/issue-6/features/dry-sorbent-injection-for-sox-emissions-control.html].
Power Mag (Korellis)--Coal-Fired Power Plant Heat Rate Improvement
Options, Parts 1 & 2--2014 [http://www.powermag.com/coal-fired-power-plant-heat-rate-improvement-options-part-2] [http://www.powermag.com/coal-fired-power-plant-heat-rate-improvement-options-part-1].
Power Mag (Peltier)--Steam Turbine Upgrading: Low-hanging Fruit--
2006 [http://www.powermag.com/steam-turbine-upgrading-low-hanging-fruit fruit].
------------------------------------------------------------------------
[[Page 44761]]
It has been noted that unit-level HRIs, with the resulting
reductions in variable operating costs at those improved EGUs, could
lead to increases in utilization of those EGUs as compared to other
generating options (i.e., ``rebound effect''). See generally 80 FR
64745.
As part of the cost-benefit analysis in the RIA for this proposed
action, EPA modeled a range of potential HRIs (percent improvement, as
described in the RIA). The results of the modeling, for the years of
analysis for this rule, predict that there will be no cumulative
increases in system-wide emissions relative to a scenario where no
action is taken. While the RIA shows that, under certain assumptions,
sources that adopt HRI may increase generation, due to their improved
efficiency and relatively improved economic competitiveness, they also
generally reduce emissions (as a group) because they can generate
higher levels of electricity with a lower overall emission rate. Hence,
EPA analysis indicates that the system-wide emission decreases due to
reduced heat rate are likely to be larger than any system-wide
increases due to increased operation. EPA solicits comment on this
conclusion (Comment C-9).
C. HRI for Natural Gas-Fired Stationary Combustion Turbines
EPA has also considered opportunities for emission reductions at
natural gas-fired stationary combustion turbines as a part of the
BSER--at both simple cycle turbines and combined cycle turbines--and
previously determined that the available emission reductions would
likely be expensive or would likely provide only small overall
reductions relative to those that were predicted through application of
other systems of emission reduction identified in the CPP building
blocks. In the development of the CAA section 111(b) standards of
performance for new, modified, and reconstructed EGUs, several
commenters provided information on options that may be available to
improve the efficiency of existing natural gas-fired stationary
combustion turbines. See 80 FR 64620. Commenters--including turbine
manufacturers--described specific technology upgrades for the
compressor, combustor, and gas turbine components that operators of
existing combustion turbines may deploy. The commenters noted that
these state-of-the-art gas path upgrades, software upgrades, and
combustor upgrades have the potential to reduce GHG emissions by a
significant amount. In addition, one turbine manufacturer stated that
existing combustion turbines can achieve the largest efficiency
improvements by upgrading existing compressors with more advanced
compressor technologies, potentially improving the combustion turbine's
efficiency by an additional margin. See 80 FR 64620.
In addition to upgrades to the combustion turbine, the operator of
a NGCC unit may have the opportunity to improve the efficiency of the
heat recovery steam generator and steam cycle using retrofit
technologies that may reduce the GHG emissions by 1.5 to 3 percent.
These include: (1) Steam path upgrades that can minimize aerodynamic
and steam leakage losses; (2) replacement of the existing high-pressure
turbine stages with state-of-the-art stages capable of extracting more
energy from the same steam supply; and (3) replacement of low-pressure
turbine stages with larger diameter components that extract additional
energy and that reduce velocities, wear, and corrosion.
In the ANPRM, EPA requested comment on the broad availability and
applicability of any HRIs for natural gas combustion turbine EGUs. EPA
also solicited comment on the Agency's previous determination in the
CPP that the available GHG emission reduction opportunities would
likely provide only small overall GHG reductions as compared to those
from HRIs at existing coal-fired EGUs. See 80 FR 64756.
Several commenters suggested that there are significant
opportunities for emission reductions via HRIs at natural gas combined
cycle EGUs while many other commenters contended that any such emission
reductions would be minimal and too expensive. Still, other commenters
noted that operational changes--such as lower capacity factor or
fluctuations in load (cycling)--affect the heat rate and make it
difficult to accurately gauge the availability of HRI opportunities for
NGCC EGUs.
However, while numerous comments suggested that there are available
HRI opportunities at existing NGCC EGUs, no commenters provided
specific information on the availability, applicability, or cost of HRI
opportunities for NGCC units--nor did any commenters provide any
information on the magnitude of expected heat rate reductions.
To assess potential HRI of existing NGCC EGUs, EPA looked at 11
years of historical gross heat rate data from 2007 to 2017 for existing
NGCC EGUs that reported both heat input and gross electricity output to
the Agency in 2017. The Agency used the 2007 to 2016 data to calculate
a ``benchmark'' heat rate for each unit. EPA evaluated the HRI
potential using an approach that is similar to the method used to
determine a unit-specific standard that was finalized for modified
coal-fired EGUs. The Agency evaluated the HRI potential by comparing
the 2017 national annual heat rate with the best annual heat rate in
the years from 2007 to 2016 year. The HRI potential was calculated
nationally and at each regional interconnection: East, West, and Texas.
Nationally the HRI evaluation suggested an average HRI potential of 3.4
percent.
EPA also conducted a literature search and found some papers
suggesting potential for improvement in the heat rate. The literature
suggested that most HRIs would be accompanied by commensurate capacity
increases.\28\ EPA takes comment on the estimates in this paper and is
seeking any other information commenters have about the performance and
cost of potential HRIs for turbines (Comment C-10). We also take
comment on whether if EPA determined that HRIs in that range were
available for similar costs, it would be appropriate for EPA to
reconsider its determination that there are no HRIs that represent the
BSER (Comment C-11).
---------------------------------------------------------------------------
\28\ Phillips, J.; Levine, P.; ``Gas Turbine Performance Upgrade
Options'', FERN Engineering Paper, available at http://www.fernengineering.com/pdf/gt_upgrade_options.pdf.
---------------------------------------------------------------------------
D. Other Considered Systems of GHG Emission Reductions
EPA also considered other systems of GHG emission reductions that
may be applied to affected EGUs but is not proposing that they should
be part of the BSER for the reasons discussed below. EPA acknowledges
that there may be other methods and technologies suitable for adoption
at some specific sources, but states and sources are best suited to
determine if those alternative measures and technologies are
appropriate and/or allowable compliance measures.
1. Carbon Capture and Storage (CCS) \29\
EPA has previously determined that CCS (or partial CCS) should not
be a part of the BSER for existing fossil fuel-fired EGUs because it
was significantly more expensive than alternative options for reducing
emissions and may not be a viable option for many individual
facilities. See 80 FR 64756. Even assuming that CAA section 111(d) may
be used to project technological
[[Page 44762]]
advances, EPA must balance innovative technologies against their
economic, energy, nonair health and environmental impacts. EPA
continues to believe that neither CCS nor partial CCS are technologies
that can be considered the BSER for existing fossil fuel-fired EGUs.
However, if there is any new information regarding the availability,
applicability, costs, or technical feasibility of CCS technologies,
commenters are encouraged to provide that information to EPA (Comment
C-12).
---------------------------------------------------------------------------
\29\ CCS is sometimes referred to as Carbon Capture and
Sequestration. It is also sometimes referred to as CCUS or Carbon
Capture Utilization and Storage (or Sequestration), where the
captured CO2 is utilized in some useful way and/or
permanently stored (for example, in conjunction with enhanced oil
recovery). In this document, we consider these terms to be
interchangeable and for convenience will exclusively use the term
CCS.
---------------------------------------------------------------------------
Similarly, EPA considered whether CCS or partial CCS should be the
BSER for natural gas-fired stationary combustion turbines and have
determined that, currently, the technology is exorbitantly expensive,
has not been adequately demonstrated, and would not be available for a
large number of existing sources. Similar technologies--such as use of
the novel Allam Cycle \30\--are, while seemingly promising, still in
the early demonstration phase.
---------------------------------------------------------------------------
\30\ https://www.netpower.com/.
---------------------------------------------------------------------------
2. Fuel Co-Firing
EPA has previously determined that co-firing of alternative fuels
(biomass or natural gas) in coal-fired utility boilers is not part of
BSER for existing fossil fuel-fired sources due to cost and feasibility
considerations. See 80 FR 64756. Although some fuel co-firing methods
are technically feasible for some affected sources, there are factors
and considerations that prevent its inclusion as BSER. In general, fuel
use opportunities are dependent upon many regional considerations and
characteristics (e.g., access to biomass, or natural gas pipeline
infrastructure limitations), that prevent its adoption as BSER on a
national level (whereas nearly all sources can or have implemented some
form of heat rate improvement measures). Another important factor is
cost, and broader application of fuel co-firing methods has been shown
to be costly. While this proposal does not include fuel co-firing
methods as BSER, EPA proposes that they be allowed as compliance
options that states may consider (see Section VI). EPA solicits
comment, nevertheless, on whether co-firing methods should be included
among the list of BSER candidate technologies for states to evaluate
when establishing a standard of performance for each affected source in
their jurisdiction.
a. Natural Gas Co-Firing
Coal-fired power plants typically use natural gas or other clean
fuel (such as low sulfur fuel oil) for start-up operations and, if
needed, to maintain the unit in ``warm stand-by.'' Some plants co-fire
natural gas simultaneously with coal--either directly as a combustion
fuel or in configuration referred to as natural gas reburn, which is
used for NOx control. During periods of natural gas co-firing, an EGU's
CO2 emission rate is reduced as natural gas is a less carbon
intensive fuel than coal. For example, at 10 percent natural gas co-
firing, the net emissions rate (lb/MWh-net) of a typical unit would
decrease by approximately 4 percent. On the other hand, co-firing can
negatively impact a unit's efficiency due to the high hydrogen content
of natural gas and the resulting production of water as a combustion
by-product. And depending on the design of the boiler and extent of
modifications, some boilers may be forced to de-rate (a reduction in
generating capacity) in order to maintain steam temperatures at or
within design limits, or for other technical reasons.
In evaluating BSER technology options, CAA section 111(a)(1)
directs EPA to take into account nonair quality health and
environmental impacts, and energy requirements. EPA is unaware of any
significant nonair quality health or environmental impacts associated
with natural gas co-firing. However, in taking energy requirements into
account, EPA notes that co-firing natural gas in coal-fired utility
boilers is not the best, most efficient use of natural gas and, as
noted above, can lead to inefficient operation of utility boilers. NGCC
stationary combustion turbine units are much more efficient at using
natural gas as a fuel for the production of electricity and it would
not be an environmentally positive outcome for utilities and owner/
operators to redirect natural gas from the more efficient NGCC EGUs to
the less efficient coal-fired EGUs in order to satisfy an emission
standard at the coal-fired unit.
Moreover, unlike coal, natural gas cannot be stored in quantities
sufficient for sustained utilization on site. Accordingly, delivery of
natural gas via pipeline is essential for using natural gas at coal-
fired EGUs. Many existing coal-fired plants, however, do not have
access to natural gas transportation infrastructure and gaining access
would be either infeasible (due to technical or timing considerations)
or unreasonably costly.\31\ For plants that currently co-fire natural
gas and have access to an existing natural gas pipeline, many may be
capacity constrained (i.e., they are not able to greatly increase
purchase volumes with the existing infrastructure). Accordingly,
although natural gas fuel prices are currently low and some sources
currently co-fire natural gas, on balance, there are notable challenges
and concerns with instituting natural gas co-firing on a wide variety
of units across the country. Therefore, EPA is not proposing that
natural gas co-firing should be part of the BSER.
---------------------------------------------------------------------------
\31\ In addition to new pipeline infrastructure, conversion to
natural gas co-firing in a coal-fired boiler typically involves
installation of new gas burners and supply piping, modifications to
combustion air ducts and control dampers, and possibly modifications
to the boiler's steam superheater, reheater, and economizer heating
surfaces that transfer heat from the hot flue gas exiting the boiler
furnace. The conversion may also involve modification and possible
deactivation of some downstream air pollution emission control
equipment.
---------------------------------------------------------------------------
b. Co-Firing Biomass
The infrastructure, proximity and cost aspects of co-firing biomass
at existing coal EGUs are similar in nature and concept to those of
natural gas. While there are some existing coal-fired EGUs that
currently co-fire with biomass fuel, those are in relatively close
proximity to cost-effective biomass supplies; and, there are regional
supply and demand dynamics at play. As with the other emission
reduction measures discussed in this section, EPA expects that use of
some types of biomass may be economically attractive for certain
individual sources. However, on a broader scale, biomass co-firing is
more expensive and/or less achievable than the measures determined to
be part of the BSER. As such, EPA is not proposing that the use of
biomass fuels is part of the BSER because too few individual sources
will be able to employ that measure in a cost-reasonable manner.
VI. State Plan Development
A. Establishing Standards of Performance
1. Application of the BSER
As discussed in Section III above, EPA has the authority to
determine the BSER as part of regulations it promulgates pursuant to
CAA section 111(d)(1) (providing that states shall submit plans to EPA
establishing ``standards of performance'' for existing sources); see
also CAA section 111(a)(1) (defining ``standard of performance'' with
reference to the ``best system of emission reduction which . . . the
Administrator determines has been adequately demonstrated''). For such
regulations, EPA has traditionally promulgated emission guidelines
governing the process for states to
[[Page 44763]]
submit plans which establish standards of performance which reflect the
degree of emission limitation achievable through application of the
BSER to each affected source within the state, in addition to the
implementing regulations EPA initially promulgated in 1975 to set the
general framework under which it would administer section 111(d). The
implementing regulations that are also being proposed in this action
(see Section VII below for a discussion on the proposed new
implementing regulations) contain certain requirements for EPA in
promulgating an emission guideline under section 111(d). One
requirement of the new proposed implementing regulations (consistent
with the previous implementing regulations and section 111(d) of the
CAA) is that an EPA-promulgated emission guideline provide information
on the degree of emission reduction which is achievable with each
system, together with information on the costs, and nonair health and
environmental effects, and energy requirements of applying each system
to designated facilities.\32\ This means that EPA will provide, in
addition to the BSER, information on the degree of emission reduction
that is achievable when the BSER is applied. In the case of this
proposed rulemaking and as described above in Section V, EPA is
proposing that the BSER is HRI made at the unit level. To meet the
requirements of the new proposed implementing regulations, EPA is
proposing candidate technologies for HRI measures corresponding to a
range of reductions and costs as information regarding the degree of
emission reduction achievable through application of the BSER. Because
affected EGUs in each state are different and the application of
different HRI measures may take into account source-specific factors,
EPA is providing expected ranges of HRIs. These ranges are shown in
Table 1.
---------------------------------------------------------------------------
\32\ This is consistent with the statutory definition of
``standard of performance'' at CAA section 111(a)(1) (emphases
added): ``a standard for emissions of air pollutants which reflects
the degree of emission limitation achievable through the application
of the best system of emission reduction which (taking into account
the cost of achieving such reduction and any nonair quality health
and environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.''
---------------------------------------------------------------------------
EPA expects that states can use the information that EPA provides
on the degree of emission limitation in developing standards of
performance for affected EGUs as part of establishing a standard of
performance for inclusion in a state's plan pursuant to the
requirements of section 111(d)(1). In this case, the ranges of HRIs are
provided as guidance for states to use in evaluating the efficacy of
implementing each measure identified as part of the BSER candidate
technologies at each affected EGU. While the HRI potential range is
provided as guidance for the states, the actual HRI performance for
each of the candidate technologies will be unit-specific and will
depend upon a range of unit-specific factors. The states will use the
information provided by EPA as guidance, but will be expected to
conduct unit-specific evaluations of HRI potential, technical
feasibility, and applicability for each of the BSER candidate
technologies. Once a state evaluates the HRIs identified as part of the
BSER in establishing a standard of performance for a particular
affected EGU, it is within the state's discretion to take certain
factors concerning that source, such as remaining useful life, into
consideration when determining how the standard of performance should
be applied. The next section describes how states may derive a standard
of performance reflecting the degree of emission limitation achievable
through application of the BSER.
Additionally, the new proposed implementing regulations require
that an emission guideline identify information such as a timeline for
compliance with standards of performance that reflect the application
of the BSER. See proposed 40 CFR 60.22a. However, given the source-
specific nature of this proposed emission guideline and reasonably
anticipated variation between standards established for sources within
a state, EPA believes it more appropriate that a state establish
tailored compliance deadlines for its sources based on the standard
ultimately determined for each source. Accordingly, the EPA proposes to
supersede this aspect of proposed 40 CFR 60.22a, as allowed under the
applicability provision under proposed 60.20a, and allow for states to
include appropriate compliance deadlines for sources based on the
standards of performance determined as part of the state plan process.
EPA is proposing, consistent with the new proposed implementing
regulations (subpart Ba), that states will include custom compliance
schedules for affected EGUs as part of their state plan. This is
another area that states have latitude for taking into account unit
specific factors. It should be noted however, that per the proposed new
implementing regulations, if a state chooses to include a compliance
schedule for a source that extends more than twenty-four months from
the submittal of the state plan, the plan must also include legally
enforceable increments of progress for that source (See proposed 40 CFR
60.24a(d)(1)). The EPA solicits comment on whether states should
determine source-specific compliance schedules under this emission
guideline, or if a uniform compliance schedule is appropriate, and if
so, what length of time is appropriate. (Comment C-13).
2. Determination of a Unit's Standard of Performance
As described in other parts of this section, while EPA's role is to
determine the BSER, section 111(d)(1) squarely places the
responsibility of establishing a standard of performance for an
existing source on the state as part of developing a state plan. EPA is
proposing that once EPA determines the BSER, states are expected to
evaluate each of the BSER HRI measures that EPA has determined
represent BSER in establishing a standard of performance for each
source within their jurisdiction. The states, in applying the standards
of performance, may take into consideration, among other factors, the
remaining useful life of the existing source to which the standard
would apply (see Section VI.B.1 for further discussion on remaining
useful life and other factors). The proposed BSER is a list of
candidate technologies that are HRI measures, which states should
evaluate, and potentially apply to existing sources as appropriate
based upon the specific characteristics of those units. In general, EPA
envisions that, under the proposed program, the states would set
standards based on considerations most appropriate to individual
sources or groups of sources (e.g., subcategories). These may include
consideration of historical emission rates, effect of potential HRIs
(informed by the information in EPA's candidate technologies described
earlier in Section V), or changes in operation of the units, among
other factors the state believes are relevant. As such, states have
considerable flexibility in determining emission standards for units,
as contemplated by the express statutory text.
Several commenters on the ANPRM suggested that EPA should develop a
default methodology for determining appropriate standards of
performance that are consistent with the BSER. More specifically,
commenters suggested that EPA should use a methodology that is similar
to the one finalized for major modifications at coal-fired EGUs under
the section 111(b) program--i.e., based on the use of historical heat
rate or emissions data for the individual
[[Page 44764]]
source. Commenters also suggested that any approach covering all
existing units should use at least ten years' worth of historical data
and should be based on rolling averages for multiple year periods
(e.g., the fourth highest three-year average during the historical
look-back period). Other commenters suggested that the approach used
for major modifications was too stringent to apply to all units. EPA
understands that if the Agency were to provide a specific and
presumptively-approvable methodology for establishing standards of
performance, that approach would provide states with certainty in how
to develop plans. EPA is not proposing a specific methodology or
formula for establishing standards of performance for existing sources
in this action. EPA believes that such a presumptive standard could be
viewed as limiting a state's ability to deviate from the prescribed
methodology and that the approach could ultimately be more limiting
than helpful. While EPA is not proposing a presumptive formulaic
approach in this action, the Agency is soliciting comment on approaches
based on the use of historical heat rate or emissions data for the
individual source (Comment C-14). The circumstances and considerations
for establishing standards of performance under CAA 111(b) for affected
sources that have undergone a modification (i.e., any physical change
in or change in the method of operation that increases the hourly
emissions of GHG) are not the same as the circumstances and
considerations for states should take into account in establishing
standards of performance under these proposed emission guidelines, but
there are certainly parallels and similarities.
As mentioned earlier, states may take into consideration other
factors, including remaining useful life, when applying unit-specific
standards of performance. Consideration of these factors may result in
the application of the standard of performance in a less stringent
manner than would otherwise be suggested by strict implementation of
the BSER technologies. This topic is discussed in detail in Section
VI.B.
As previously described, this proposal seeks to clarify the
Agency's and states' roles under section 111(d). The statute is clear
that EPA determines the BSER, and states submit plans that establish
standards of performance for existing sources that, under the
definition of ``standard of performance in CAA section 111(a)(1),
reflect the degree of emission limitation achievable though the
application of the BSER. Consistent with the statute, EPA's proposed
implementing regulations at 40 CFR 60.22a(b)(2) specify that an
emission guideline must include information on the degree of emission
reduction which is achievable, but does not require that EPA must
provide a standard of performance that presumptively reflects such
degree of emission reduction which is achievable through application of
the BSER, as that is appropriately the states' role. EPA is proposing
to clarify that the implementing regulations do not require EPA to
provide a presumptive numerical standard as part of its emission
guidelines and that the ranges of expected emission reductions that can
be achieved in EPA's BSER determination adequately provide sufficient
information to the states on the degree of emission limitation that
will result from application of the BSER to existing sources to
appropriately inform the states' exercise of their authority to develop
plans under 111(d).
Given that section 111(d)(1) requires states to submit plans that
establish standards of performance for affected sources, EPA believes
it is consistent with the spirit of cooperative federalism to provide
information sufficient to assist states in the development of state
plans, which in turn will provide both states and sources with
regulatory certainty via a plan that is approvable under section
111(d)(2) and applicable regulations. As mentioned above, EPA is
proposing to provide information regarding ranges of expected
reductions associated with the various HRIs identified as the BSER,
which will assist states in establishing appropriate standards of
performance for affected EGUs. EPA proposes to determine providing such
information is consistent with both the implementing regulations at 40
CFR 60.22(b) and CAA section 111(d) regarding the roles of states and
EPA determining the degree of emission limitation achievable through
application of the BSER.
As described below in Section VI.B, under the statute, the proposed
new implementing regulations, and these proposed emission guidelines,
states have considerable flexibility in developing their plans and
establishing and applying standards of performance to existing sources.
One of the areas of flexibility described is in the standard setting
process for EGUs. As part of this flexibility, EPA is proposing that
states should have broad flexibility on whether and how the state
chooses to group, sort, or subcategorize affected EGUs within the state
to establish standards of performance. In evaluating affected EGUs, if
a state finds that there is an overlap in circumstances around a group
of EGUs, it might make sense to implement a uniform methodology for
setting a standard of performance across that group. Another area of
flexibility is explicitly provided in the statutory text of 111(d)(1)
itself. The statute requires that EPA's regulations implementing
section 111(d) shall permit the State in applying a standard of
performance to any particular source under a plan submitted under this
paragraph to take into consideration, among other factors, the
remaining useful life of the existing source to which such standard
applies.
3. Forms of Standards of Performance
As described further in Section VII.C of this preamble, EPA is
proposing a new implementing regulation for section 111(d) which
includes a proposed definition of ``standard of performance that aligns
with the statutory definition of the term under CAA section 111(a)(1).
EPA is further proposing, as part of the new implementing regulations,
that a specific emission guideline may contain provisions that
supersede the applicability of the implementing regulations. In the
context of these emission guidelines, EPA is proposing that an
allowable emission rate (i.e., rate-based standard in, for example, lb
CO2/MWh-gross) be the form of standard of performance that
states would include in their state plans for affected EGUs. Primarily,
an allowable emission rate most closely aligns to EPA's BSER
determination for these emission guidelines. When HRIs are made at an
EGU, by definition, the CO2 emission rate will decrease as
described above in Section V.B. There is a natural correspondence
between the BSER and an allowable emission rate as the standard of
performance in this action. Secondly, EPA is proposing that state plans
include only the one form of standard of performance (i.e., proposing
only an allowable emission rate) to create continuity across states,
prevent ambiguity, and to ensure as much simplicity as possible.
However, EPA solicits comment on whether other forms of standards of
performance should be allowed in state plans and whether a different
form of standard should be the primary form that is authorized for
state plans under a final emission guideline in response to this
proposal (Comment C-15).
EPA is proposing an allowable emission rate of CO2 as
the form of the standard of performance because it creates the most
straightforward system for states to determine standards and ensure
compliance. This also creates a more streamlined evaluation for EPA to
consider in state plan evaluation as there are fewer variables to
consider (e.g., projections of utilization which
[[Page 44765]]
would be required if the standard of performance took a mass-based
form).
4. Gross Versus Net Emission Standards
EPA also requests comment on the merits of differentiating between
gross and net heat rate (Comment C-16). This may be particularly
important when considering the effects of part load operations (i.e.,
net heat rate would include inefficiencies of the air quality control
system at a part load whereas gross heat rate would not). This will
also be important in recognizing the improved efficiency obtained from
upgrades to equipment that reduce the auxiliary power demand.
B. Flexibilities for States and Sources
Once EPA determines the BSER, section 111(d)(1) of the CAA requires
that ``each State shall submit to the Administrator a plan which (A)
establishes standards of performance for any existing source [. . .],
and (B) provides for the implementation and enforcement of such
standards of performance.'' Section 111(d)(1) further requires EPA to
``permit the State in applying a standard of performance to any
particular source under a plan [. . .] to take into consideration,
among other factors, the remaining useful life of the existing source
to which such standard applies.''
In light of the cooperative-federalist structure of section 111(d)
and its express language requiring that EPA allow states to take into
account source-specific factors when establishing standards of
performance for existing sources, EPA believes it is appropriate in
this proposal to provide considerable flexibility for states to set
standards of performance for units and also allow states to have
considerable latitude for implementing measures and standards for
affected EGUs. A detailed discussion of the flexibility that states
have in developing standards of performance is provided below in
Section VI.B.1. States also have flexibility in the measures and
processes that they put in place for affected EGUs to meet their
compliance obligations. One of the examples of this is discussed in
Section VI.B.2 on averaging and trading. As previously discussed, the
BSER's candidate technologies affords states considerable flexibility
to determine how to apply standards of performance to affected sources.
Several commenters noted in the ANPRM that flexibility for States and
affected sources should be part of any replacement rule, with States
being able to choose from a wide variety of possible methods for
developing a standard of performance, along with options for how to
implement the standard through their state plans. Other commenters
suggested that any flexible compliance opportunities provided should be
directly linked to the determination of the BSER, such that increased
compliance flexibility in the state's establishment of a standard of
performance for an existing source can only be included to the extent
that the flexibility is included as part of the BSER.
Another important and distinctly different element of flexibility
in this proposal is the availability of compliance options for affected
sources in meeting their standards of performance. To the extent that a
state develops a standard of performance for an affected source within
its jurisdiction, the state is free to give the source flexibility to
meet that standard of performance using either BSER technologies or
some other non-BSER technology or strategy. In other words, an affected
source may have broad discretion in meeting its standard of performance
within the requirements of a state's plan. For example, there are
technologies, methods, and/or fuels that can be adopted at the affected
source to allow the source to comply with its standard of performance
that were not determined to be the BSER, but which may be applicable
and prudent for specific units to use to meet their compliance
obligations. Examples of non-BSER technologies and fuels include HRI
technologies that were not included as candidate technologies, CCS, and
fuel co-firing (natural gas or certain biomass). In keeping with past
programs that regulated affected sources using a standard of
performance, EPA takes no position regarding whether there may be other
methods or approaches to meeting such a standard, since there are
likely various approaches to meeting the standard of performance that
EPA is either unable to include as part of the BSER, or is unable to
predict. EPA proposes that affected sources may use both BSER and non-
BSER measures to achieve compliance with their state plan obligations.
To demonstrate that measures taken to meet compliance obligations
for a source actually reduce its emission rate, EPA proposes that the
measures should meet two criteria: (1) They are implemented at the
source itself, and (2) they are measurable at the source of emissions
using data, emissions monitoring equipment or other methods to
demonstrate compliance, such that they can be easily monitored,
reported and verified at a unit. There may be other technologies or
compliance measures that meet these general criteria. EPA solicits
comment on whether these two criteria are appropriate or not and why,
and whether there may be compliance flexibilities that might meet the
two proposed criteria (Comment C-17). This proposed rule is intended to
generally allow compliance flexibility in state plans where
appropriate, to the extent they contribute to meeting any particular
standard of performance, consistent with the criteria. EPA is further
soliciting comment on whether there are certain non-BSER measures that
should be disallowed for compliance, and if so, under what criteria or
rationale should measures be disallowed for compliance (Comment C-18).
Section 111(d)(1)(B) additionally requires state plans to include
measures that provide for the implementation and enforcement of
standards of performance. EPA believes states can meet these
requirements by including measures as described in Section VI.C of this
proposal regarding state plan components, such as monitoring,
reporting, and recordkeeping requirements. EPA solicits comments on
what other implementation and enforcement measures may be necessary for
states to meet the requirements of section 111(d)(1)(B) (Comment C-19).
Additionally, as part of ensuring that regulatory obligations
appropriately meet statutory requirements such as enforceability, EPA
has historically and consistently required that obligations placed on
sources be quantifiable, non-duplicative, permanent, verifiable, and
enforceable. EPA is similarly proposing that standards of performance
places on affected EGUs as part of a state plan be quantifiable, non-
duplicative, permanent, verifiable, and enforceable.
The Agency specifically recognizes that some entities may be
interested in using biomass as a compliance option for meeting the
state determined emission standard.\33\ As with the other non-BSER
measures discussed in this section, EPA expects that use of biomass may
be economically attractive for certain individual sources even though
on a broader scale it may be more expensive or less achievable than the
measures determined to be part of the BSER (and therefore EPA is not
proposing to determine that it should be included within the BSER,
which is properly limited to measures likely to be cost-reasonable for
a greater proportion
[[Page 44766]]
of existing sources than we believe biomass to be at this time).
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\33\ EPA believes that biomass co-firing can meet the two
criteria above because the biomass can be burned at the source and
there are different methods that can be used to monitor or calculate
the amount of biogenic CO2 emissions associated with
biomass use at a unit.
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Certain kinds of biomass, including that from managed forests, have
the potential to offer a wide range of economic and environmental
benefits, including carbon benefits. However, these benefits can
typically only be realized if biomass feedstocks are sourced
responsibly, which can include ensuring that forest biomass is not
sourced from lands converted to non-forest uses. States that intend to
propose the use of forest-derived biomass for compliance by affected
units may refer to EPA's April 2018 statement on its intended treatment
of biogenic CO2 emissions from stationary sources that use
forest biomass for energy production.34 35 As discussed in
the recent statement, EPA's policy is to treat biogenic CO2
emissions resulting from the combustion of biomass from managed forests
at stationary sources for energy production as carbon neutral.36 EPA
will continue to evaluate the applicability of this policy of treating
forest-biomass derived biogenic CO2 as carbon neutral based
on relevant information, including data from interagency partners on
updated trends in forest carbon stocks.
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\34\ https://www.epa.gov/sites/production/files/2018-04/documents/biomass_policy_statement_2018_04_23.pdf.
\35\ This policy statement aligns with provisions in the
Consolidated Appropriations Act, 2018, which calls for EPA, the
Department of Energy and the Department of Agriculture to establish
policies that, consistent with their missions, jointly ``reflect the
carbon-neutrality of forest bioenergy and recognize biomass as a
renewable energy source, provided the use of forest biomass for
energy production does not cause conversion of forests to non-forest
use.'' https://www.congress.gov/115/bills/hr1625/BILLS-115hr1625enr.pdf.
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EPA solicits comments on the inclusion of forest-derived biomass as
a compliance option for affected units to meet state plan standards
under this rule (Comment C-20). The Agency also solicits comment on the
inclusion of non-forest biomass (e.g., agricultural, waste stream-
derived) for energy production as a compliance option, and what value
to attribute to the biogenic CO2 emissions associated with
non-forest biomass feedstocks (Comment C-21). EPA recognizes that CCS
technology (described above in this section) could be applied in
conjunction with biomass use.
1. State Discretion To Consider Remaining Useful Life and Other Factors
in Setting Standards of Performance
Section 111(d)(1) requires that EPA's regulations must permit
states to take into account, among other factors, an affected source's
remaining useful life when establishing an appropriate standard of
performance. In other words, Congress explicitly envisioned under
section 111(d)(1) that states could implement standards of performance
that vary from EPA's emission guidelines under appropriate
circumstances.
Congress explicitly mentions consideration of remaining useful life
in 111(d). Ultimately remaining useful life impacts cost. When EPA
develops a BSER, EPA typically considers factors such as cost relative
to assumptions about a typical unit. If the remaining useful life of a
particular unit is less, that will generally increase the cost of
control because the time to amortize capital costs is less. When
congress mentions other factors, EPA believes that these are generally
other factors that may substantially increase costs relative to a more
typical unit.
As such, EPA is proposing, as part of the proposed implementing
regulations, to permit states to take into account remaining useful
life, among other factors, in establishing a standard of performance
for a particular affected source, consistent with section 111(d)(1)(B).
EPA solicits comments on the manner in which states should be permitted
to exercise their statutory authority to take into account remaining
useful life and on what ``other factors'' might appropriately be
besides remaining useful life (Comment C-22). As described in Section
VII.F., EPA further proposes as part of the new implementing
regulations that the following factors give meaning to section
111(d)(1)(B):
Unreasonable cost of control resulting from plant age,
location, or basic process design;
Physical impossibility of installing necessary control
equipment; or
Other factors specific to the facility (or class of facilities)
that make application of a less stringent standard or final compliance
time significantly more reasonable. Given that there are unique
attributes and aspects of each affected source, there are important
factors that influence decisions to invest in technologies to meet a
potential performance standard. These include timing considerations
like expected life of the source, payback period for investments, the
timing of regulatory requirements, and other unit-specific criteria.
The state may find that there are space or other physical barriers to
implementing certain HRIs at specific units. Or the state may find that
some heat rate improvement options are either not applicable or have
already been implemented at certain units. EPA understands that many of
these ``other factors'' that can affect the application of the BSER
candidate technologies distill down to a consideration of cost.
Applying a specific candidate technology at an affected EGU can be a
unit-by-unit determination that weighs the value of both the cost of
installation and the CO2 reductions. Accordingly, EPA
proposes that these factors are the types that are specific to the
facility (or class of facilities) that make a variance from the
emission guideline significantly more reasonable, as allowed under
proposed 40 CFR 60.24a(e)(3). EPA, therefore, proposes to allow states
to take these factors into account in establishing a standard of
performance for state plans in response to this emission guideline. EPA
further solicits comments on what are other factors that states should
be allowed to consider in establishing a standard of performance, per
the proposed variance provision (Comment C-23).
As previously described, EPA proposes that states that utilize the
proposed variance provision in the new implementing regulations to
establish a less stringent standard of performance for an affected EGU
and/or a compliance schedule that is longer than that contemplated in
EPA's final emission guideline must demonstrate as part of their state
plan submission that such application of the provision meets the
criteria described in the factors in Section VII.D. EPA also recognizes
that for some sources, the criteria may result in determining that no
measures in the candidate technologies are applicable. Two examples of
this might be a unit with a very short remaining useful life or a unit
that has already implemented all of the candidate technologies of the
BSER. In cases such as these, a state should still establish a standard
of performance. In the case of a unit with a short remaining useful
life, EPA takes comment on what such a standard might look like
(Comment C-24). For instance, a state could set a standard using both
an emission rate and a compliance deadline to address this instance.
The emission standard would only be applicable if a source did not shut
down by the compliance deadline. In the case of an affected EGU that
has already implemented all of the candidate technologies, EPA would
expect that a state set a standard of performance that would reflect an
emission rate that is at least as stringent as ``business as usual''
for that source without allowing for any backsliding on performance.
EPA requests comment on these proposed treatments of a source that
either has a short remaining useful
[[Page 44767]]
life or has already implemented all of the HRIs identified as the BSER.
EPA is also generally soliciting comment on whether there are
considerations in allowing states to utilize this proposed variance
provision in the new implementing regulations in response to the final
emission guideline, including the potential interaction of the
compliance flexibilities proposed in this proposal with utilization of
the provision (Comment C-25). For example, could states authorize
trading as a compliance mechanism for affected EGUs and additionally
invoke this provision, or would utilizing both trading and this
provision in establishing standards in a state plan potentially result
in such standards going beyond what section 111(d) permits (i.e., would
allowing for both trading and a variance with respect to the same
standard result in a standard that is impermissibly less stringent than
what application of the BSER in conjunction with invocation of this
provision would result in)? EPA welcomes comments on the legality and
appropriateness of utilizing this provision generally, and in the
context of specific compliance flexibilities that states may employ in
developing their plans (Comment C-26).
Another consideration for states in determining a standard of
performance with consideration to unique aspects at an affected EGU is
the interaction between BSER and NSR. EPA is aware that the prospect of
triggering NSR, and its associated permitting requirements, may have
discouraged sources from implementing some heat rate improvements
previously. In Section VIII of this preamble, EPA discusses proposed
changes to alleviate NSR burdens for EGUs undertaking heat rate
improvements. The proposed action on NSR would ultimately impact the
level of reductions reflected in the standard of performance that a
state establishes for its sources. In considering each of the candidate
technologies, EPA believes it is appropriate for states to consider the
potential that the application of HRI may trigger NSR for some sources,
and associated NSR requirements could ultimately impact the cost of HRI
and the way the state applies standards to an affected EGU. EPA
solicits comment on any factors that may play a role in a state setting
a standard of performance with consideration to NSR (Comment C-27).
2. Averaging and Trading
EPA solicits comment on the question of whether CAA section 111(d)
authorizes states to include averaging and trading between existing
sources in the plans they submit to meet the requirements of a final
emission guideline (Comment C-28). Section 111(d)(1) provides that
states shall submit a plan which (A) establishes standards of
performance for any existing source of certain air pollutants to which
a 111(b) standard would apply if they were new sources, and (B)
provides for the implementation and enforcement of such standards of
performance. EPA's regulations under section 111(d) must permit the
state, in applying a standard of performance to any particular existing
source under a state plan, to consider, among other factors, the
remaining useful life of that source.
To be clear, this section discusses averaging in the context of
averaging across a facility and across multiple existing sources. For a
discussion on EPA allowing individual EGU emissions averaging over a
period of time, see Section VI.C.
EPA is proposing to allow states to incorporate, as a part of their
plan, emissions averaging among EGUs across a single facility. The
Agency's determination of the BSER is predicated on measures that can
be implemented at the facility level and averaging across a facility is
consistent with the proposed BSER. EPA is proposing that averaging at a
facility only be applicable to affected EGUs (i.e. coal-fired steam
EGUs) for several reasons. First, if averaging could include non-
affected EGUs, this might not result in real reductions, but simply
result in averaging with lower-emitting emitting fossil-fuel-fired EGUs
such as NGCC units that would have been operating anyway. Further, even
if it did result in generation shifting to lower emitting units it is
contrary to the intention of the rule which is to focus on reducing the
rate at coal-fired EGUs when they run, not to reduce the amount they
run. Second, EPA is currently considering whether NGCC units should
become affected EGUs. How NGCC units fit into an averaging program will
be determined if a determination is made that they are affected EGUs in
this program. Third, EPA is proposing that facility-wide averaging only
apply to affected EGUs because it would mirror the BSER determination
for this rule. The EPA solicits comment on whether this type of
facility-wide averaging of affected EGUs is appropriate and whether
there should be other types of considerations involved (Comment C-29).
EPA is also taking comment on the possibility of averaging affected
EGUs with non-affected EGUs within a facility in the limited case when
they represent incremental new non-emitting capacity (Comment C-30).
This would be consistent with a compliance option such as integrated
solar.
Notwithstanding EPA's discussion above, EPA believes that there are
both legal and practical concerns may weigh against the inclusion of
averaging and trading between existing sources in state plans at any
level more broad than averaging between sources across a particular
facility. First, EPA is concerned that averaging and trading across
affected sources (or between affected sources and non-affected sources,
e.g., wind turbines) would be inconsistent with our proposed
interpretation of the BSER as limited to measures that apply at and to
an individual source. Because state plans must establish standards of
performance--which by definition ``reflect . . . the application of the
[BSER],'' CAA section 111(a)(1)--implementation and enforcement of such
standards should correspond with the approach used to set the standard
in the first place. Applying a different analytical approach to
standard-setting may result in asymmetrical regulation (for example, a
state's implementation measures might result in a more stringent
standard than could otherwise be derived from application of the
BSER).\37\
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\37\ While CAA section 116 allows for states to adopt more
stringent state laws, and provides that the CAA does not preempt
such state laws, it does not provide that those more stringent
standards are federalized.
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Second, EPA believes that if section 111(d) authorized states to
include trading and averaging between sources in their plans, the
express provision under 111(d)(1) authorizing states to consider
existing sources' remaining useful life and other factors when
establishing and applying standards of performance could be viewed as
superfluous. Once a state takes into consideration a source's remaining
useful life and other factors (e.g., unreasonable cost of control
resulting from plant age, location, or basic process design; physical
impossibility of installing necessary control equipment; whether the
source has already undertaken some of the measures encompassed in the
BSER; or other factors), then additional compliance flexibilities may
not be required or otherwise appropriate. Indeed, averaging and trading
by themselves would appear to eliminate the need to take into
consideration a source's remaining useful life: If a source cannot meet
a performance standard (or if it is impractical or inadvisable to
require that source to do so), but if the state, in its plan, is
authorized to permit that
[[Page 44768]]
source to average or otherwise obtain credits for its performance with
other sources' performance, there may have been no need for Congress to
specifically require EPA to permit states to conduct a remaining-
useful-life analysis. Moreover, the source-focused language in
111(d)(1) both generally weighs in favor of EPA's proposed
interpretation of the BSER as limited to source-specific measures, and
specifically weighs against interpreting section 111(d) to authorize
state plans to include averaging and trading.
Third, multiple practical concerns regarding emissions averaging
and trading between sources inform EPA's concerns regarding inclusion
of those mechanisms in state plans under section 111(d) and its
solicitation of comment on this issue. These concerns include the
relative complexity of development and implementation of a state plan
that includes averaging or trading, as well as the difficulty in
ensuring robust compliance with standards of performance by means of
averaging or trading. Trading programs necessitate developing adequate
means of evaluation, monitoring, and verification (EM&V) to ensure that
standards of performance are actually complied with, and these
programmatic aspects increase the burden on states in developing a
satisfactory state plan, and on sources in demonstrating compliance.
Additionally, either a mass-based or rate-based trading program
potentially brings into question of whether the state has established
standards of performance that appropriately reflect the BSER. Under a
trading program, a single source could potentially shut down or reduce
utilization to such an extent that its reduced or eliminated operation
generates adequate compliance instruments for a state's remaining
sources to meet their standards of performance without implementing any
additional measures at any other source. This compliance strategy might
undermine EPA's BSER, which EPA is proposing to determine as a menu of
heat rate improvements. It would also undermine the purpose of section
111 in a broader sense. The section is directed toward the improvement
of performance of new sources, and, through section 111(d)'s specific
procedures, of existing sources. It is not, under EPA's proposed
interpretation of section 111 (and contrary to the interpretation
underlying the CPP), directed toward the aggregate emissions of an
industrial sector as a whole, at either the state or national level.
Adopting an interpretation of section 111(d) that could lead to relying
on the shutdown or reduced operation of one or a small handful of
sources in order to cap or limit the source category's aggregate
emissions, while not resulting in the improved performance of any other
source, may be contrary to the structure and purpose of section 111 as
a whole and section 111(d) specifically.
However, EPA recognizes that there are significant benefits of
averaging and trading across affected sources and is interested in
whether emissions averaging could be a way to provide flexibility while
still focusing on a core tenet of the BSER for this rule: Reducing
emissions per MWH of coal-fired generation. Since averaging
traditionally focuses only on the emission rate during hours of
operation, it focuses on encouraging lowering emissions per MW
generated and not on encouraging generation shifting away from the
affected source category. The EPA welcomes comment on whether there is
a way to allow trading between affected EGUs across affected sources
while not encouraging generation shifting (Comment C-31).
EPA is soliciting comment on whether section 111(d) should be read
not to authorize states to include trading and averaging between
sources, EPA is also interested in affording flexibility to states and
sources in meeting their respective obligations and solicits public
comment on whether this proposed interpretation and conclusion is
compatible with that goal. EPA is primarily interested in comments
pertaining to whether averaging could and should be allowed for
trading, and to what degree (i.e., averaging across a state, or
trading) (Comment C-32). If a commenter believes that averaging across
multiple affected sources should be allowed as part of a state's plan,
EPA requests comment on how the averaging system should conceptually
work (Comment C-33). EPA requests comment on how allowing averaging
across multiple affected sources would or would not undermine the BSER
determination (Comment C-34). If a commenter believes that trading
should be allowed as part of a state's plan, EPA requests comment on
what type of EM&V criteria should be included for the compliance
instruments (Comment C-35). If a commenter believes that trading should
be allowed as part of a state's plan, EPA requests comment on whether
sources should be allowed to bank compliance instruments (Comment C-
36). If a commenter believes that averaging across multiple affected
sources should be allowed as part of a state's plan, EPA requests
comment on what mechanisms states would need to employ to ensure
compliance is maintained and tracked for purposes of providing for the
implementation and enforcement of the standards of performance (Comment
C-37). If a commenter believes that averaging across multiple affected
sources should be allowed as part of a state's plan, EPA requests
comment on which and/or if technology should be limited in the
averaging program (Comment C-38). If a commenter believes that
averaging across multiple affected sources should be allowed as part of
a state's plan, EPA requests comment on whether affected EGUs across
state lines could be able to average and what measures state plans
should include to provide for the implementation and enforcement of
such multi-state averaging (Comment C-39). EPA further requests comment
on the issues of statutory interpretation laid forth above, whether
they are appropriate interpretations of section 111(d) specifically and
section 111 generally, in terms of the provision's text, structure, and
purpose (Comment C-40). EPA additionally solicits comment on whether
such averaging, trading, or ``bubbling'' compliance flexibilities as
are available under other sections of title I of the CAA suggest that
such flexibilities should be afforded under state plans under section
111(d) (Comment C-41).
C. Submission of State Plans
Section 111(d)(1) of the Clean Air Act requires that in addition to
establishing standards of performance for affected sources, such plans
must also provide for the implementation and enforcement of such
standards. As described in Section VII, EPA is proposing new
implementing regulations for section 111(d), which in part carry over a
number of the same provisions currently present in the existing
implementing regulations under 40 CFR part 60, subpart B. EPA is
proposing that these provisions apply for states to meet the
requirement that state plans include implementation and enforcement
measures. EPA requests comment on whether these provisions are
appropriate to apply for purposes of meeting obligations under a final
rule in response to this proposal, or whether other implementation or
enforcement measures should be required (Comment C-42).
Additionally, EPA is proposing that states must include appropriate
monitoring, reporting, and recordkeeping requirements to ensure that
state plans adequately provide for the implementation and enforcement
of standards of performance. Each state will have the flexibility to
design a
[[Page 44769]]
monitoring program for assessing compliance with the standards of
performance identified in the plan. Most potentially affected coal-
fired EGUs already continuously monitor CO2 emissions, heat
input, and gross electric output and report hourly data to EPA under 40
CFR part 75. Accordingly, if a state plan establishes a standard of
performance for a unit's CO2 emissions rate (e.g., lb/MWh),
EPA proposes that states may elect to use data collected by EPA under
40 CFR part 75 to meet the required monitoring, reporting, and
recordkeeping requirements under this emission guideline.
EPA also notes that states have it within their discretion to
establish averaging times for affected EGUs. Averaging the emission
rate of an affected EGU over different time periods may have different
effects on the demonstration of compliance for an EGU to the state. EPA
solicits comment on whether there should be any bounds or consideration
to the averaging times that states are allowed to consider (Comment C-
43).
EPA is further proposing to apply generally the proposed new
implementing regulations for timing, process and required components
for state plan submissions and implementation for state plans required
under for affected EGUs. The new implementing regulations are described
in detail in Section VII. In addition to application of the
implementing regulations to state plans in response to a final emission
guideline under this proposal, EPA is also proposing that state plans
be comprehensively submitted electronically through an EPA provided
platform. EPA solicits comment on whether electronic submittals are
appropriate and less burdensome to states (Comment C-44) and whether
this should be the sole means of submitting state plans (Comment C-45).
EPA believes that electronic submittals will ease the burden of state
plan submittals for both states and EPA.
In section 60.5740a of the regulatory text for this proposal, there
is description and list of what a state plan must include. EPA solicits
comment on whether this list is comprehensive to submit a state plan
(Comment C-46).
VII. Proposed New Implementing Regulations for Section 111(d) Emission
Guidelines
Distinct from EPA's proposed emission guidelines for the regulation
of GHGs for existing affected EGUs, EPA is also proposing to promulgate
new regulations to implement section 111(d) regulations. As previously
described, the current implementing regulations at 40 CFR part 60,
subpart B were promulgated in 1975 [See 40 FR 53346.]. Section
111(d)(1) of the CAA explicitly requires that EPA establish regulations
similar to those under section 110 of the CAA to establish a procedure
for states to submit plans to EPA. The implementing regulations have
not been significantly revised since their original promulgation in
1975. Notably, the implementing regulations do not reflect section
111(d) in its current form as amended by Congress in 1977, and do not
reflect section 110 in its current form as amended by Congress in 1990.
Accordingly, EPA believes that certain portions of the implementing
regulations do not appropriately align with section 111(d), contrary to
that provision's mandate that EPA's regulations be ``similar'' to the
provisions under section 110. Therefore, EPA is proposing to promulgate
new implementing regulations that are in accordance with the statute in
its current form. As previously discussed, agencies have the ability to
revisit prior decisions, and EPA believes it is appropriate to do so
here in light of the potential mismatch between certain provisions of
the implementing regulations and the statute.\38\
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\38\ The authority to reconsider prior decisions exists in part
because EPA's interpretations of statutes it administers ``[are not]
instantly carved in stone,'' but must be evaluated ``on a continuing
basis.'' Chevron U.S.A. Inc. v. NRDC, Inc., 467 U.S. 837, 863-64
(1984). 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 (DC Cir. 2017).
---------------------------------------------------------------------------
EPA is proposing to largely carry over the current implementing
regulations in 40 CFR part 60, subpart B to a new subpart that will be
applicable to EPA's emission guidelines and state plans or federal
plans associated with such emission guidelines, both those contemplated
in this proposal and for any others that may be published or
promulgated either concurrently or subsequent to final promulgation of
the new implementing regulations. For purposes of regulatory certainty,
EPA believes it is appropriate to apply these new implementing
regulations prospectively, and retain the existing implementing
regulations as applicable to section 111(d) emission guidelines and
associated state plans that were promulgated previously. Additionally,
the existing implementing regulations at 40 CFR part 60, subpart B are
applicable to regulations promulgated under CAA section 129, and
associated state plans. EPA intends to retain the applicability of the
existing implementing regulations with respect to rules and state plans
associated with section 129, and the proposed new implementing
regulations are intended to apply only to section 111(d) regulations
and associated state plans issued solely under the authority of section
111(d). EPA requests comments on this proposed applicability of both
the existing and new implementing regulations (Comment C-47).
EPA is aware that there are a number of cases where state plan
submittal and review processes are still ongoing for existing 111(d)
emission guidelines. Because EPA is proposing changes to the timing
requirements to more closely align 111(d) with both general SIP
submittal timing requirements and because of the realities of how long
these actions take, EPA is proposing to apply the changes to timing
requirements to both emission guidelines published after the new
implementing regulations are finalized, and to all ongoing emission
guidelines already published under section 111(d). EPA is soliciting
comment on the proposed timing requirements for prospective emission
guidelines under the new implementing regulations and the alignment of
ongoing emission guidelines by amending their respective regulatory
text to incorporate the new timing requirements. (Comment C-48). EPA is
proposing to apply the timing changes to all ongoing 111(d) regulations
for the same reasons that EPA is changing the timing requirements
prospectively. Based on years of experience with working with states to
develop SIPs under section 110, EPA believes that given the comparable
amount of work, effort, coordination with sources, and the time
required to develop state plans that more time is necessary for the
process. Giving states three years to develop state plans is more
appropriate than the nine months provided for under the existing
implementing regulations considering the workload. These practical
considerations regarding the time needed for state plan development are
also applicable and true for recent emission guidelines where the state
plan submittal and review process are still ongoing.
For those provisions that are being carried over from the existing
implementing regulations into the new implementing regulations, EPA
believes the placement of those provisions under a new subpart is a
ministerial action that does not require reopening the substance of
those provisions for notice and comment. EPA is not intending to
substantively change those provisions from their original promulgation,
and continues to rely on the record under
[[Page 44770]]
which they were promulgated. Therefore, EPA is not soliciting comment
on the following provisions, which remain substantively the same from
their original promulgation: 40 CFR 60.21a(a)-(d), (g)-(j)
(Definitions); 60.22a(a), 60.22a(b)(1)-(3), (b)(5), (c) (Publication of
emission guidelines); 60.23a(a)-(c), (d)(3)-(5), (e)-(h) (Adoption and
submittal of State plans; public hearings); 60.24a(a)-(d), (f)
(Standards of performance and compliance schedules); 60.25a (Emission
inventories, source surveillance, reports); 60.26a (Legal authority);
60.27a(a), (e)-(f) (Actions by the Administrator); 60.28a(b) (Plan
revisions by the State); 60.29a (Plan revisions by the Administrator).
EPA is also sensitive to potential confusion over whether these new
implementing regulations would apply to an emission guideline
previously promulgated or to state plans associated with a prior
emission guideline, so EPA is proposing that the new implementing
regulations are applicable only to emission guidelines and associated
plans developed after promulgation of this regulation, including the
emission guideline being proposed as part of this action for GHGs and
existing affected EGUs. EPA solicits comment on this proposed
applicability of the new implementing regulations (Comment C-49).
While EPA is carrying over a number of requirements from the
existing implementing regulations, EPA is proposing specific changes to
better align the regulations with the statute. These changes are
reflected in the proposed regulatory text for this action, and EPA
solicits comments on both the substance of these changes and the
proposed regulatory text (Comment C-50). These changes include:
An explicit provision allowing a specific emission
guideline to supersede the requirements of the new implementing
regulations;
Changes to the definition of ``emission guideline'';
Updated timing requirements for the submission of state
plans;
Updated timing requirements for EPA's action on state
plans;
Updated timing requirements for EPA's promulgation of a
federal plan;
Updated timing requirement for when increments of progress
must be included as part of a state plan;
Completeness criteria and a process for determining
completeness of state plan submissions similar to CAA section 110(k)(1)
and (2);
Updated definition replacing ``emission standard'' with
``standard of performance;''
Usage of the internet to satisfy certain public hearing
requirements;
No longer making a distinction between public health-based
and welfare-based pollutants in an emission guideline; and,
Updating the variance provision to be consistent with CAA
section 111(d)(1)(B).
EPA is proposing to include a provision in the new implementing
regulations that expressly allows for any emission guideline to
supersede the applicability of the implementing regulations as
appropriate. EPA cannot foresee all of the unique circumstances and
factors associated with a particular future emission guideline, and
therefore different requirements may be necessary for a particular
111(d) rulemaking that EPA cannot envision at this time. The proposed
provision is parallel to one contained in the 40 CFR part 63 General
Provisions implementing section 112 of the CAA. EPA solicits comments
on the inclusion of such provision as part of the implementing
regulations for section 111(d) (Comment C-51).
Because EPA is updating the implementing regulations and many of
the provisions from the existing implementing regulations are being
carried over, EPA wants to be clear and transparent with regard to the
changes that are being made to the implementing regulations. As such,
EPA is providing Table 4 that summarizes the changes being made. EPA
also has included in the docket for this action a red-line-strike-out
of the changes that are being proposed.
Table 4--Summary of Changes to the Implementing Regulations
------------------------------------------------------------------------
Existing implementing
New implementing regulations--subpart regulations--subpart B for all
Ba for all future 111(d) emission previously promulgated 111(d)
guidelines emission guidelines
------------------------------------------------------------------------
Explicit authority for a new 111(d) No explicit authority.
emission guideline requirement to
supersede these implementing
regulations.
Use of term ``guideline document''; Use of term ``emission
does not require EPA to provide a guideline''; arguably required
presumptive emission standard. EPA to provide a presumptive
emission standard.
Use of term ``standard of performance'' Use of term ``emission
standard''.
``Standard of performance'' allows ``Emission standard'' allows
states to include design, equipment, states to prescribe equipment
work practice, or operational specifications when EPA
standards when EPA determines it's not determines it's clearly
feasible to prescribe or enforce a impracticable to establish an
standard pf performance, consistent emission standard.
with the requirements of CAA section
111(h).
State submission timing: 3 years from State submission timing: 9
promulgation of a final emission months from promulgation of a
guideline. final emission guideline.
EPA action on state plan submission EPA action on state plan
timing: 12 months after determination submission timing: 4 months
of completeness. after submittal deadline.
Timing for EPA promulgation of a Timing for EPA promulgation of
federal plan, as appropriate: 2 years a federal plan, as
after finding of failure to submit a appropriate: 6 months after
complete plan, or disapproval of state submittal deadline.
plan.
Increments of progress are required if Increments of progress are
compliance schedule for a state plan required if compliance
is longer than 24 months after the schedule for a state plan is
plan is due. longer than 12 months after
the plan is due.
Completeness criteria and process for No previous discussion.
state plan submittals.
Usage of the internet to satisfy No previous discussion.
certain public hearing requirements.
No distinction made in treatment Different provisions for health-
between health-based and welfare-based based and welfare-based
pollutants; variance provision pollutants; state plans must
available regardless of type of be as stringent as EPA's
pollutant. emission guideline for health-
based pollutants unless
variance provision is invoked.
------------------------------------------------------------------------
[[Page 44771]]
A. Changes to the Definition of ``Emission Guideline''
The existing implementation regulations under 40 CFR 60.21(e)
contain a definition of ``emission guideline'', defining it as a
guideline which reflects the degree of emission reduction achievable
through the application of the best system of emission reduction which
(taking into account the cost of such reduction) the Administrator has
determined has been adequately demonstrated for designated facilities.
This definition additionally references that an emission guideline may
be set forth in 40 CFR part 60, subpart C or a ``final guideline
document'' published under 40 CFR 60.22(a). While the implementing
regulations do not define the term ``final guideline document,'' 40 CFR
60.22 generally contains a number of requirements pertaining to the
contents of guideline documents, which are intended to provide
information for the development of state plans. See 40 CFR 60.22(b).
The preambles for both the proposed and final existing implementing
regulations suggest that an ``emission guideline'' would be a guideline
provided by EPA that presumptively reflects the degree of emission
limitation achievable by the BSER. EPA believes it is important to at
least provide information on such degree of emission limitation in
order to guide states in their establishment of standards of
performance as required under CAA section 111(d). However, EPA does not
believe anything in CAA section 111(a)(1) or section 111(d) compels EPA
to provide a presumptive emission standard that reflects the degree of
emission limitation achievable by application of the BSER. Accordingly,
as part of the new implementing regulations, EPA proposes to re-define
``emission guideline'' as a final guideline document published under
Sec. 60.22a(a), which includes information on the degree of emission
reduction achievable through the application of the best system of
emission reduction which (taking into account the cost of such
reduction and any nonair quality health and environmental impact and
energy requirements) EPA has determined has been adequately
demonstrated for designated facilities.
B. Updates to Timing Requirements
The timing requirements in the existing implementing regulations
for state plan submissions, EPA's action on state plan submissions and
EPA's promulgation of federal plans generally track the timing
requirements for SIPs and federal implementation plans (FIPs) under the
1970 version of the Clean Air Act. Congress revised these SIP/FIP
timing requirements in section 110 as part of the 1990 Clean Air Act
amendments. EPA proposes to accordingly update the timing requirements
regarding state and federal plans under section 111(d) to be consistent
with the current timing requirements for SIPs and FIPs under section
110. The existing implementing regulations at 40 CFR 60.23(a)(1)
requires state plans to be submitted to EPA within nine months after
publication of a final emission guideline, unless otherwise specified
in an emission guideline. EPA is proposing, as part of new implementing
regulations, to provide states with three years after the notice of the
availability of the final emission guideline to adopt and submit a
state plan to EPA. Because of the amount of work, effort, and time
required for developing state plans that include unit-specific
standards, and implementation and enforcement measures for such
standards, EPA believes that extending the submission date of state
plans from nine months to three years is appropriate. Because states
have considerable flexibility in implementing section 111(d), this
timing also allows states to interact and work with the Agency in the
development of state plan and minimize the chances of unexpected issues
arising that could slow down eventual approval of state plans. EPA
solicits comment on generally providing states with three years after
the publication of the final emission guidelines, and solicits comment
on any other timeframes that may be appropriate for submission of state
plans given the flexibilities EPA intends to provide through its
emission guidelines (Comment C-52). EPA also proposes to give itself
discretion to determine in a specific emission guideline that a shorter
time period for the submission of state plans particular to that
emission guideline is appropriate. Such authority is consistent with
CAA section 110(a)(1)'s grant of authority to the Administrator to
determine that a period shorter than three years is appropriate for the
submission of particular SIPs implementing the NAAQS.
Following submission of state plans, EPA will review plan
submittals to determine whether they are ``satisfactory'' as per CAA
section 111(d)(2)(A). Given the flexibilities section 111(d) and
emission guidelines generally accord to states, and EPA's prior
experience on reviewing and acting on SIPs under section 110, EPA is
proposing to extend the period for EPA review and approval or
disapproval of plans from the four-month period provided in EPA
implementing regulations to a twelve-month period after a determination
of completeness (either affirmatively by EPA or by operation of law,
see below for EPA's proposal on completeness) as part of the new
implanting regulations. This timeline will provide adequate time for
EPA to review plans and follow notice-and-comment rulemaking procedures
to ensure an opportunity for public comment on EPA's proposed action on
a state plan. EPA solicits comment on extending the timing of EPA's
action on a state plan from 4 months of when a plan is due to 12 months
from determination that a state plan submission is complete (Comment C-
53).
EPA additionally proposes to extend the timing from six months in
the existing implementing regulations to two years, as part of new
implementing regulations, for EPA to promulgate a federal plan for
states that fail to submit an approvable state plan in response to a
final emission guideline. This two-year timeline is consistent with the
FIP deadline under section 110(c) of the CAA. EPA solicits comment on
change in timing for EPA to promulgate a federal plan from six months
to two years (Comment C-54). EPA solicits comment on extending deadline
for promulgating a final (i.e., after appropriate notice and comment)
federal plan for a state to two years after either (1) EPA finds that a
state has failed to submit a complete plan, or (2) EPA disapproves a
state plan submission (Comment C-55).
C. Compliance Deadlines
The existing implementing regulations require that any compliance
schedule for state plans extending more than 12 months from the date
required for submittal of the plan must include legally enforceable
increments of progress to achieve compliance for each designated
facility or category of facilities. 40 CFR 60.24(e)(1). However, as
described in section VII.B, the EPA is proposing certain updates to the
timing requirements for the submission of, and action on, state plans.
Consequently, it follows that the requirement for increments of
progress should also be updated in order to align with the proposed new
timelines. Given that the EPA is proposing a period of up to 18 months
for its action on state plans (i.e. 12 months from the determination
that a state plan submission is complete, which could occur up to six
months after receipt of the state plan), EPA
[[Page 44772]]
believes it is appropriate that the requirement for increments of
progress should attach to plans that contain compliance periods that
are longer than the period provided for EPA's review of such plans.
This way, sources subject to a plan have more certainty that their
regulatory compliance obligations would not change between the period
between when a state plan is due and when EPA acts on a plan.
Accordingly, EPA proposes that increments of progress will be included
for state plans that contain compliance schedules longer than 24 months
from the date when state plans are due for a particular emission
guideline. EPA solicits comments on whether this 24-month component, or
some other period of time, is appropriate as a trigger for requiring
increments of progress as part of a plan's compliance schedule.
D. Completeness Criteria
Similar to requirements regarding determinations of completeness
under section 110(k)(1), EPA is proposing completeness criteria that
provide the Agency with a means to determine whether a state plan
submission includes the minimum elements necessary for EPA to act on
the submission. EPA would determine completeness simply by comparing
the state's submission against these completeness criteria. In the case
of SIPs under CAA section 110(k)(1), EPA promulgated completeness
criteria in 1990 at Appendix V to 40 CFR part 51 (55 FR 5830; February
16, 1990). EPA proposes to adopt criteria similar to the criteria set
out at section 2.0 of Appendix V for determining the completeness of
submissions under CAA section 111(d).
EPA notes that the addition of completeness criteria in the
framework regulations does not alter any of the submission requirements
states already have under any applicable emission guideline. The
completeness criteria proposed by this action are those that would
generally apply to all plan submissions under section 111(d), but
specific emission guidelines may supplement these general criteria with
additional requirements.
The completeness criteria that EPA is proposing in this action can
be grouped into administrative materials and technical support. For
administrative materials, the completeness criteria mirror criteria for
SIP submissions because the two programs have similar administrative
processes. Under these criteria, the submittal must include the
following:
(1) A formal letter of submittal from the Governor or the
Governor's designee requesting EPA approval of the plan or revision
thereof.
(2) Evidence that the state has adopted the plan in the state code
or body of regulations. That evidence must include the date of adoption
or final issuance as well as the effective date of the plan, if
different from the adoption/issuance date.
(3) Evidence that the state has the necessary legal authority under
state law to adopt and implement the plan.
(4) A copy of the official state regulation(s) or document(s)
submitted for approval and incorporated by reference into the plan,
signed, stamped and dated by the appropriate state official indicating
that they are fully adopted and enforceable by the state. The effective
date of the regulation or document must, whenever possible, be
indicated in the document itself. The state's electronic copy must be
an exact duplicate of the hard copy. For revisions to the approved
plan, the submission must indicate the changes made to the approved
plan by redline/strikethrough.
(5) Evidence that the state followed all of the procedural
requirements of the state's laws and constitution in conducting and
completing the adoption/issuance of the plan.
(6) Evidence that public notice was given of the plan or plan
revisions with procedures consistent with the requirements of 40 CFR
60.23, including the date of publication of such notice.
(7) Certification that public hearing(s) were held in accordance
with the information provided in the public notice and the state's laws
and constitution, if applicable and consistent with the public hearing
requirements in 40 CFR 60.23.
(8) Compilation of public comments and the state's response
thereto.
The technical support required for all plans must include each of
the following:
(1) Description of the plan approach and geographic scope.
(2) Identification of each designated facility; identification of
emission standards for each designated facility; and monitoring,
recordkeeping, and reporting requirements that will determine
compliance by each designated facility.
(3) Identification of compliance schedules and/or increments of
progress.
(4) Demonstration that the state plan submission is projected to
achieve emissions performance under the applicable emission guidelines.
(5) Documentation of state recordkeeping and reporting requirements
to determine the performance of the plan as a whole.
(6) Demonstration that each emission standard is quantifiable, non-
duplicative, permanent, verifiable, and enforceable.
EPA intends that these criteria be generally applicable to all CAA
section 111(d) plans submitted on or after final new implementing
regulations are promulgated, with the proviso that specific emission
guidelines may provide otherwise.
Consistent with the requirements of CAA section 110(k)(1)(B) for
SIPs, EPA is proposing to determine whether a state plan is complete
(i.e., meets the completeness criteria) no later than 6 months after
the date, if any, by which a state is required to submit the plan. EPA
further proposes that any plan or plan revision that a State submits to
EPA, and that has not been determined by EPA by the date 6 months after
receipt of the submission to have failed to meet the minimum
completeness criteria, shall on that date be deemed by operation of law
to be a complete state plan. Then, as previously discussed, EPA is
relatedly proposing to act on a state plan submission within 12 months
after determining a plan is complete, either through an affirmative
determination or by operation of law.
When plan submissions do not contain the minimum elements, EPA is
proposing to find that a state has failed to submit a complete plan
through the same process as finding a state has made no submission at
all. Specifically, EPA would notify the state that its submission is
incomplete and therefore, that it has not submitted a required plan,
and EPA would also publish a finding of failure to submit in the
Federal Register, which triggers EPA's obligation to promulgate a
federal plan for the state. This determination that a submission is
incomplete and the state has failed to submit a plan is ministerial in
nature and requires no exercise of discretion or judgment on the
Agency's part, nor does it reflect a judgment on the eventual
approvability of the submitted portions of the plan.
E. Standard of Performance
As previously described, the implementing regulations were
promulgated in 1975 and effectuated the 1970 version of the Clean Air
Act as at it existed at that time. The 1970 version of section 111(d)
required state plans to include ``emission standards'' for existing
sources, and consequently the implementing regulations refer to this
term. However, as part of the 1977 amendments to the CAA, Congress
replaced the term ``emission standard'' in section 111(d) with
``standard of performance.'' EPA has not since
[[Page 44773]]
revised the implementing regulations to reflect this change in
terminology. For clarity's sake and to better track with statutory
requirements, EPA is proposing to include a definition of ``standards
of performance'' as part of the new implementing regulations, and to
consistently refer to this term as appropriate within those regulations
in lieu of referring to an ``emission standard.'' Additionally, the
current definition of ``emission standard'' in the implementing
regulations is incomplete and requires clean-up regardless. For
example, the definition encompasses equipment standards, which is an
alternative form of standard provided for in CAA section 111(h) under
certain circumstances. However, section 111(h) provides for other forms
of alternative standards, such as work practice standards, which are
not covered by the existing regulatory definition of ``emission
standard.'' Furthermore, the definition of ``emission standard''
encompasses allowance systems, a reference that was added as part of
EPA's Clean Air Mercury Rule. 70 FR 28605. This rule was vacated by the
D.C. Circuit, and therefore this added component to the definition of
``emission standard'' had no legal effect because of the court's
vacatur. Consistent with the court's opinion, EPA signaled its intent
to remove this reference as part of its Mercury Air Toxics rule. 77 FR
9304. However, in the final regulatory text of that rulemaking, EPA did
not take action removing this reference, and it remains as a vestigial
artifact.
For these reasons, EPA is proposing to replace the existing
definition of ``emission standard'' with a definition of ``standard of
performance'' that tracks with the definition provided for under CAA
section 111(a)(1). This means a standard of performance for existing
sources would be defined as a standard for emissions or air pollutants
which reflects the degree of emission limitation achievable through the
application by the state of the best system of emission reduction which
(taking into account the cost of achieving such reduction and any
nonair quality health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated. EPA is
further proposing to incorporate into a definition of standard of
performance CAA section 111(h)'s allowance for design, equipment, work
practice, or operational standards as alternative standards of
performance under the statutorily prescribed circumstances. Currently,
the existing implanting regulations allow for state plans to prescribe
equipment specifications when emission rates are ``clearly
impracticable'' as determined by EPA. CAA section 111(h)(1) by contrast
allows for alternative standards such as equipment standards to be
promulgated when standards of performance are ``not feasible to
prescribe or enforce,'' as those terms are defined under CAA section
111(h)(2). Given the potential discrepancy between the conditions under
which alternative standards may be established based on the different
terminology used by the statute and existing implementing regulations,
EPA proposes to use the ``not feasible to prescribe or enforce''
language as the condition for the new implementing regulations under
which alternative standards may be established.
EPA solicits comment on all of these means of tracking and
incorporating the section 111(a)(1) and 111(h) for purposes of a
regulatory definition of ``standard of performance,'' and requests
comment on any other considerations for such definition (Comment C-56).
F. Variance
EPA believes that the existing implementing regulations'
distinction between public health-based and welfare-based pollutants is
not a distinction unambiguously required under section 111(d) or any
other applicable provision of the statute. EPA does not believe the
nature of the pollutant in terms of its impacts on health and/or
welfare impact the manner in which it is regulated under this
provision. Particularly, 60.24(c) requires that for health-based
pollutants, a state's standards of performance must be of equivalent
stringency to EPA's emission guidelines. However, section 111(d)(1)(B)
requires that EPA's regulations must permit states to take into
account, among other factors, an affected source's remaining useful
life when establishing an appropriate standard of performance. In other
words, Congress explicitly envisioned under section 111(d)(1)(B) that
states could implement standards of performance that vary from EPA's
emission guidelines under appropriate circumstances. Notably, the
implementing regulations at 40 CFR 60.24(f) contain a variance
provision that allow for states to also apply less stringent standards
on sources under certain circumstances. However, the variance provision
attaches to the distinction between health-based and welfare-based
pollutants, and is available to the states only under EPA's discretion.
The variance provision was also promulgated prior to Congress's
addition of the requirement in section 111(d)(1)(B) that EPA permit
states to take into account remaining useful life and other factors,
and the terms of the regulatory provision and statutory provision do
not match one another, meaning that the variance provision may not
account for all of the factors envisioned under section 111(d)(1)(B).
Given all of these factors, EPA is proposing to not make a distinction
between health-based and welfare-based pollutants and attach
requirements contingent upon this distinction as part of the new
implementing regulations. EPA is also proposing a new variance
provision to permit states to take into account remaining useful life,
among other factors, in establishing a standard of performance for a
particular affected source, consistent with section 111(d)(1)(B).
Given that there are unique attributes and aspects of each affected
source, these other factors may be ones that influence decisions to
invest in technologies to meet a potential performance standard. Such
other factors may include timing considerations like expected life of
the source, payback period for investments, the timing of regulatory
requirements, and other unit-specific criteria. EPA solicits comments
on how a new variance provision can permit states to take into account
remaining useful life and other factors, and what other factors might
appropriately be (Comment C-57). EPA is also soliciting comment on
whether the factors outlined in the existing variance provision at 40
CFR 60.24(f) are appropriate to carry over to a new variance provision
if they adequately give meaning to the requirements of section
111(d)(1)(B) (Comment C-58). Those factors are:
Unreasonable cost of control resulting from plant age,
location, or basic process design;
Physical impossibility of installing necessary control
equipment; or
Other factors specific to the facility (or class of
facilities) that make application of a less stringent standard or final
compliance time significantly more reasonable.
VIII. New Source Review Permitting of HRIs
A. What is New Source Review?
The NSR program is a preconstruction permitting program that
requires stationary sources of air pollution to obtain permits prior to
beginning construction. The NSR program applies both to new
construction and to modifications of existing sources. New construction
and modifications of
[[Page 44774]]
stationary sources that emit or increase emissions of ``regulated NSR
pollutants'' \39\ at or above certain thresholds defined in either the
CAA or the NSR regulations are subject to major NSR requirements, while
smaller emitting sources and modifications may be subject to minor NSR
requirements.\40\ A pollutant is a ``regulated NSR pollutant'' if it
meets at least one of four requirements, which are, in general, any
pollutant for which EPA has promulgated a NAAQS or a NSPS, certain
ozone depleting substances, and ``[a]ny pollutant that otherwise is
subject to regulation under the Act.'' See, e.g., 40 CFR 52.21(b)(50).
For purposes of NSR, hazardous air pollutants are excluded. Id.
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\39\ 40 CFR 51.165(a)(1)(xxxvii), 40 CFR 52.21(b)(50).
\40\ The one exception to this approach is for GHG. Regardless
of the GHG emissions resulting from construction of a new source or
modification, the source will not be required to obtain a major NSR
permit unless the emissions of another regulated NSR pollutant equal
or exceed the major NSR threshold. 80 FR 50199 (August 19, 2015);
Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427 (2015).
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NSR permits for major sources emitting pollutants for which the
area is classified as attainment or unclassifiable, and for other
pollutants regulated under the CAA, are referred to as prevention of
significant deterioration (PSD) permits. NSR permits for major sources
emitting pollutants for which the area is in nonattainment are referred
to as nonattainment NSR (NNSR) permits. The pollutant(s) at issue and
the air quality designation of the area where the facility is located
or proposed to be built determine the specific permitting
requirements.\41\ Among other requirements, the CAA requires sources
subject to PSD to meet emission limits based on Best Available Control
Technology (BACT) as specified by section 165(a)(4), and the CAA
requires sources subject to NNSR to meet the Lowest Achievable
Emissions Rate (LAER) pursuant to section 173(a)(2). These technology
requirements for major NSR permits are not predetermined by a rule or
state plan, but are case-by-case determinations made by the permitting
authority.\42\ Other requirements to obtain a major NSR permit vary
depending on whether the source needs a PSD or an NNSR permit.
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\41\ PSD applies on a regulated NSR pollutant-by-regulated NSR
pollutant basis. The PSD requirements do not apply to regulated NSR
pollutants for which the area is designated as nonattainment. NNSR
could only be applicable with regard to a source's emissions of
criteria pollutants, as those are the only pollutants with respect
to which areas are designated as attainment or nonattainment.
\42\ The term `best available control technology' means an
emission limitation . . . which the permitting authority, on a case
by case basis, taking into account energy, environmental, and
economic impacts and other costs, determines is achievable for such
facility . . .'' 42 U.S.C. 7479(3); see e.g., supra Section III.C;
PSD and Title V Permitting Guidance for Greenhouse Gases (Mar.
2011), available at https://www.epa.gov/sites/production/files/2015-07/documents/ghgguid.pdf.
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The test to determine whether a source is subject to major NSR
differs for new stationary sources and for modifications to existing
stationary sources. A new source is subject to major NSR permitting
requirements if its potential to emit (PTE) any regulated NSR pollutant
equals or exceeds the statutory emission threshold. For sources in
attainment areas, the major source threshold is either 100 or 250 tons
per year, depending on the type of source.\43\ The major source
threshold for sources in nonattainment areas is generally 100 tons per
year, although lower thresholds apply to sources located in areas
classified at higher levels of nonattainment.
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\43\ The NSR major source and major modification emission
thresholds are expressed in short tons (i.e., 2000 lbs.).
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A modification at an existing major source is subject to major NSR
permitting requirements when it is a ``major modification,'' which
occurs when a source undertakes a physical change or change in method
of operation (i.e., a ``project'') \44\ that would result in both (1) a
significant emissions increase from all emission units that are part of
the project, and (2) a significant net emissions increase from the
source, which is determined by a source-wide analysis that considers
creditable emission increases and decreases occurring at the source as
a result of other projects over a 5-year contemporaneous period. See,
e.g., 40 CFR 52.21(b)(2)(i). For this analysis, the NSR regulations
define emissions rates that are ``significant'' for each NSR pollutant.
See, e.g., 40 CFR 52.21(b)(23). In calculating the emissions increase
that will result from a proposed project, existing NSR regulations
require a comparison of the ``projected actual emissions'' (PAE) to the
``baseline actual emissions'' (BAE). The PAE is currently defined as
the maximum annual rate that the modified unit is projected to emit a
pollutant in any one of the 5 years (or 10 years if the design capacity
increases) after the project, excluding any increase in emissions that
(1) is unrelated to the project, and (2) could have been accommodated
during the baseline period (commonly referred to as the ``demand growth
exclusion''). See, e.g., 40 CFR 52.21(b)(41). For electric utility
steam generating units (EUSGU), the BAE is defined as the average
annual rate of actual emissions during any 24-month period within the
last 5 years. See, e.g., 40 CFR 52.21(b)(48)(i). For non-EUSGUs, the
BAE is defined the same as for EUSGUs, except that the 24-month period
can be within the last 10 years. See, e.g., 40 CFR
52.21(b)(48)(ii).\45\
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\44\ The NSR regulations expressly exempt certain activities
from being considered a physical change or change in method of
operation, including routine maintenance, repair and replacement,
increases in hours of operation or production rate, and change in
ownership. See, e.g., 40 CFR 52.21(b)(2)(iii).
\45\ While we are discussing federal regulations, a state or
local permitting authority may have different regulations to define
NSR applicability if approved by EPA into its implementation plan.
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As noted above, new stationary sources and modifications of
stationary sources that do not require a major NSR permit may instead
require a minor NSR permit prior to construction. Minor NSR permits are
primarily issued by state and local air agencies. Minor NSR
requirements are approved into an implementation plan in order to
achieve and maintain national ambient air quality standards (NAAQS).
See CAA section 110(a)(2)(C).\46\ The Act, EPA regulations and EPA
guidance each specify minor NSR requirements, although the requirements
are not as prescriptive as those covering the major NSR program. This
reduced specificity affords agencies flexibility in designing their
minor NSR programs. Since the minor NSR program deals with smaller
sources and smaller increases in air pollution, the control
requirements that are identified for a minor NSR permit tend to be less
stringent than a BACT or LAER requirement for a major NSR permit. In
addition, the time to process a permit for a minor NSR source or a
minor modification is generally faster than for a major NSR permit, due
to having fewer requirements.
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\46\ EPA's regulations at 40 CFR 51.160-51.169 apply to state
permitting programs; however, these provisions cover both major and
minor sources. The requirements that apply to strictly minor sources
are limited to sections 51.160-51.164. In addition, in 2011 EPA
created the Indian country minor NSR permitting program, which
authorizes EPA regional offices to issue minor source permits on
tribal lands. These regulations are located at 40 CFR 49.101-49.104
and 49.151-49.164.
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B. Interaction of NSR and the ACE Rule
Since emission guidelines that are established pursuant to CAA
section 111(d) apply to units at existing sources, the way in which the
NSR programs treat modifications of existing sources is implicated by
implementation of a CAA section 111(d) program. Specifically, in
complying with the emission guidelines, a state agency may develop
[[Page 44775]]
a CAA section 111(d) plan that results in an affected source
undertaking a physical or operational change. As explained above, under
the NSR program undertaking a physical or operational change may
require that the source obtain a preconstruction permit for the
proposed change, with the type of NSR permit depending on the amount of
the emissions increase resulting from the change and the air quality at
the location of the source. Thus, a source that is adding equipment or
otherwise making changes to its facility, on either its own volition or
to comply with a national or state level requirement, will typically
need some type of NSR permit prior to making such changes to its
facility. EPA sought to exempt environmentally beneficially pollution
control projects from NSR requirements in a 2002 rule that codified
longstanding EPA policy, but this rule was struck down in court. New
York v. EPA, 413 F.3d 3, 40-42 (DC Cir. 2005) (New York I).
With respect to the proposed action, should it be promulgated,
states will be called upon to develop a section 111(d) plan that
evaluates BSER technologies for each of their EGU sources and assigns
emission reduction compliance obligations to their affected EGUs.
Assuming the promulgated action adopts the same form as this proposal,
the state may require a source with an affected EGU to achieve a HRI of
a specified percentage. As described in Section VI.B of this preamble,
a HRI project is designed to lower the heat rate of the EGU, which
correlates to the unit consuming less fuel per kWh and emitting lower
amounts of CO2 (and other air pollutants) per kWh generated
as compared to a less efficient unit. Along with this increase in
energy efficiency, the EGU which undergoes the HRI project will
typically experience greater unit availability and reliability, all of
which contribute to lower operating costs. EGUs that operate at lower
costs are generally preferred in the dispatch order by the system
operator over units that have higher operational costs,\47\ and EPA's
regulatory impact analysis (RIA) for this action (located in the
docket) shows that improving an EGU's heat rate will lead to increased
generation due to its improved efficiency and relative economics. As
the EGU increases its generation, to the extent the EGU operates beyond
its historical levels by a meaningful amount, it could result in an
increase in emissions on an annual basis, as calculated pursuant to the
current NSR regulations. Specifically, if a source is undertaking a HRI
project and its future emissions (i.e., PAE) are projected to increase
above its historical emissions (i.e., BAE) in an amount greater than
the relevant ``significant'' level, the source could be required to
obtain a major NSR permit for the modification.
---------------------------------------------------------------------------
\47\ See, e.g., Comments of Florida Municipal Elec Association
on the U.S. Environmental Protection Agency's ANPRM entitled,
``State Guidelines for Greenhouse Gas Emissions from Existing
Electric Utility Generating Units,'' 82 FR 61507 (December 28, 2017)
at 11 (EPA-HQ-OAR-2017-0545-0155); see also https://www.eia.gov/todayinenergy/detail.php?id=7590.
---------------------------------------------------------------------------
Thus, it is possible that a source undertaking a HRI project at its
EGU would project, or actually experience, an increase in operation of
its EGU and a corresponding increase in annual emissions. This would
require the source, at a minimum, to conduct an analysis to determine
whether the project by itself is projected to lead to a significant
emissions increase (at step one of the two-step analysis that
determines whether a project constitutes a ``major modification''). If
so, the source would have to conduct a netting analysis to determine
whether there is also a significant net increase when contemporaneous
increases and decreases from other projects are considered (step two of
that analysis). If both of these types of increases would be projected
to occur, this could result in the source being subject to additional
pollutant control requirements (e.g., BACT or LAER), in addition to the
substantial extra time and cost of applying for a major NSR permit
prior to undertaking the HRI project. Such could be the consequence
despite the fact that the project would lower the EGU's output-based
emissions rate for its air pollutants, and despite the fact that the
resulting effect on the dispatch order could yield an emission
reduction from a system-wide standpoint.
Similarly, over the years, some stakeholders have asserted that the
NSR rules discourage companies from exercising the discretion to
undertake energy efficiency improvement projects, which they assert
results in less environmentally protective outcomes from a system-wide
standpoint. Stakeholders have claimed that triggering major NSR
permitting requirements can increase the costs of beneficial plant
improvement projects, like HRIs, and often contribute to a company's
decision to forego the projects. For instance, a commenter on the CPP
proposal stated that ``many coal-fired plants may refrain from making
improvements based on the financial risk associated with potentially
triggering a New Source Review, which may result in the requirement to
invest in additional emissions controls . . . . [T]he [permitting]
requirements could increase costs of potential heat rate improvements
and therefore are a potential impediment which should be recognized in
the rule's calculations.'' \48\
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\48\ Electric Power Research Institute comments U.S.
Environmental Protection Agency's Proposed Rule ``Carbon Pollution
Emissions Guidelines for Existing Stationary Sources: Electric
Utility Generating Units,'' 79 FR 34830 (June 18, 2014) at 12-13
(EPA-HQ-OAR-2013-0602-21697).
---------------------------------------------------------------------------
In promulgating the CPP, EPA noted that these stakeholders
expressed concerns of the potential NSR permitting effects from a state
implementing the rule, stating ``[w]hile there may be instances in
which an NSR permit would be required, we expect those situations to be
few . . . states have considerable flexibility in selecting varied
measures as they develop their plans to meet the goals of the emission
guidelines. One of these flexibilities is the ability of the state to
establish emission standards in their CAA section 111(d) plans in such
a way so that their affected sources, in complying with those
standards, in fact would not have emissions increases that trigger NSR.
To achieve this, the state would need to conduct an analysis consistent
with the NSR regulatory requirements that supports its determination
that as long as affected sources comply with the emission standards in
their CAA section 111(d) plan, the source's emissions would not
increase in a way that trigger NSR requirements.'' 80 FR 64920 (October
23, 2015). The CPP also explained that sources can voluntarily take
enforceable limits on hours of operation, in the form of a synthetic
minor source limitation, in order to avoid triggering major NSR
requirements that would otherwise apply to the source. 80 FR 64781,
64920.
However, these concerns regarding the applicability of NSR take on
even greater significance and may not be as easily avoided in the
context of this proposed rule, which constrains the compliance options
available in the CPP to within-the-fenceline measures and may therefore
more directly result in individual sources making HRIs.
Individuals within the academic community have examined the NSR
interplay with making efficiency gains at existing coal plants. A 2014
report projected that 80 percent of non-retiring coal-fired units have
emissions rates for NOX and SO2 at levels that
exceed those typically required under NSR and concluded that the units
would have to install additional controls for NOX or sulfur
dioxide (SO2) if these HRI projects triggered the
applicability of
[[Page 44776]]
NSR.\49\ For these units then, the potential requirement to undertake a
HRI to satisfy 111(d) may result in substantial time, effort, and money
to comply with the requirements of major NSR. In addition, the
potential need to permit so many of the projects being required under a
111(d) plan could substantially increase the burden for permit agencies
in processing permit applications. To help reduce the effect this may
have on the effective and prompt implementation of a revised CAA
section 111(d) standard for EGUs, EPA is proposing revisions to the NSR
regulations in this action.
---------------------------------------------------------------------------
\49\ Sarah K. Adair, David C. Hoppock, Jonas J. Monast (from
Duke University's Nicholas Institute for Environmental Policy
Solutions and School of Law, ``New Source Review and coal plant
efficiency gains: How new and forthcoming air regulations affect
outcomes''; Elsevier, Energy Policy 70 (2014), 183-192.
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C. ANPRM Solicitation and Comments Received
Through the ANPRM, EPA took comment on the topic of how the NSR
program overlays with emission guidelines established under CAA section
111(d). EPA specifically acknowledged the concerns raised previously by
stakeholders regarding the potential for a source to make energy
efficient improvements that could trigger major NSR requirements.
Furthermore, as EPA did in the CPP, EPA described current approaches
available within the NSR program to avoid triggering NSR requirements.
These include the ability for a source to obtain a synthetic minor
source limitation, which restricts its hours of operation and its
emissions below major NSR levels, and the Plantwide Applicability Limit
(PAL), which allows a source to operate within a source-wide emissions
cap to avoid triggering NSR for changes.
The ANPRM solicited input on possible actions that EPA can take to
harmonize and streamline the NSR applicability or the NSR permitting
processes for an amended rule. EPA requested comment on ways to
minimize the impact of the NSR program on the implementation of a
performance standard for EGU sources under CAA section 111(d),
specifically asking ``[w]hat rule or policy changes or flexibilities
can EPA provide as part of the NSR program that would enable EGUs to
implement projects required under a CAA section 111(d) plan and not
trigger major NSR permitting while maintaining environmental
protections?'' 82 FR 61519 (Dec. 28, 2017).
Several ANPRM commenters reiterated concerns that were raised on
the CPP proposal regarding the NSR program--specifically that, if an
air agency, as part of its plan to comply with emission guidelines
established pursuant to CAA section 111(d), requires an affected source
to make modifications (e.g., HRI projects), it could potentially
trigger major NSR requirements. Some commenters alleged that the NSR
program unfairly treats sources that are undertaking changes to become
more energy efficient by requiring a costly and time consuming
permitting burden. As expressed by one industry representative, ``EGUs
engaging in HRI projects can face NSR pre-construction permitting
requirements consisting of, at a minimum, costly, detailed analyses and
permitting delays. In some cases, this has resulted in costly and
protracted litigation, and expensive new emission control requirements,
both of which result in substantial time delays for these projects.
These concerns remain should unit operators pursue HRI upgrades . . .
that could trigger NSR in an effort to comply with . . . revised CAA
section 111(d) GHG emissions guidelines.'' \50\ Another commenter noted
that the major NSR permitting process ``is time and resource
intensive'' and, including pre-permit application work, ``can take as
long as 3 years or longer.'' \51\ The same commenter noted that ``[the]
uncertainty of permit timing can hinder investment decisions as much as
the actual permit schedule delays.'' \52\ Some commenters indicated
that the current flexibilities offered within the NSR program are not
sufficient to avoid placing a significant permitting burden on EGUs and
permitting agencies, which could result in substantial delays during
the planned implementation stage.\53\ To avoid such outcomes, a number
of commenters suggested that EPA undertake actions to clarify or change
the NSR regulations, including, for example, revising the NSR
modification applicability to be based on pounds per kilowatt-hour (lb/
kW-h) \54\ or rejecting as BSER any project that would result in
triggering NSR.\55\
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\50\ Edison Electric Institute comments on the U.S.
Environmental Protection Agency's ANPRM entitled, ``State Guidelines
for Greenhouse Gas Emissions from Existing Electric Utility
Generating Units,'' 82 FR 61507 (December 28, 2017) at 22 (EPA-HQ-
OAR-2017-0545-0221).
\51\ General Electric Company (GE) comments on the U.S.
Environmental Protection Agency's ANPRM entitled, ``State Guidelines
for Greenhouse Gas Emissions from Existing Electric Utility
Generating Units,'' 82 FR 61507 (December 28, 2017) at 29-30 (EPA-
HQ-OAR-2017-0545-0271).
\52\ Id. at 30.
\53\ See, e.g., Ohio Environmental Protection Agency comments on
the U.S. Environmental Protection Agency's ANPRM entitled, ``State
Guidelines for Greenhouse Gas Emissions from Existing Electric
Utility Generating Units,'' 82 FR 61507 (December 28, 2017) at 9, 32
(EPA-HQ-OAR-2017-0545-0246).
\54\ GE comments, supra note at 33.
\55\ Indiana Municipal Power Agency comments on the U.S.
Environmental Protection Agency's ANPRM entitled, ``State Guidelines
for Greenhouse Gas Emissions from Existing Electric Utility
Generating Units,'' 82 FR 61507 (December 28, 2017) at 3 (EPA-HQ-
OAR-2017-0545-0204).
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However, other commenters disagreed. For instance, the Natural
Resources Defense Council (NRDC) suggested that changes to the NSR
program ``are unwarranted.'' \56\ They added that EPA needs to remain
in the boundary of the controlling judicial decisions in considering
what approaches could be used to reduce the number of existing sources
that will be subject to NSR permitting while crafting CAA section
111(d) plans. NRDC focused the basis of many of its concerns on the
court's opinion in New York v. EPA, 443 F.3d 880 (D.C. Cir. 2006) (New
York II), which vacated EPA's attempt to more clearly define ``routine
maintenance, repair, and replacement'' (RMRR) projects that are exempt
from major NSR by EPA's rules. NRDC also referenced the following
observation from an earlier decision by the same court that vacated the
``pollution control project exclusion'' that EPA finalized in 2002:
``Absent clear congressional delegation, however, EPA lacks authority
to create an exemption from NSR by administrative rule.'' \57\
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\56\ Natural Resources Defense Council comments on the U.S.
Environmental Protection Agency's ANPRM entitled, ``State Guidelines
for Greenhouse Gas Emissions from Existing Electric Utility
Generating Units,'' 82 FR 61507 (December 28, 2017) at 14-17 (EPA-
HQ-OAR-2017-0545-0358).
\57\ New York v. EPA, 413 F.3d 3, 41 (D.C. Cir. 2005) (New York
I) (citing Sierra Club v. EPA, 129 F.3d 137, 140 (D.C. Cir. 1997)).
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D. Proposing NSR Changes for Improved ACE Implementation
1. Overview
EPA acknowledges the NSR program may have unintended consequences
for implementation of this emission guidelines for GHG emissions from
existing EGUs. Based on the comments received on the ANPRM and EPA's
experience with the NSR program generally, EPA recognizes the potential
for triggering major NSR permitting when sources undertake HRI
projects. EPA further recognizes that the prospect of a protracted
permitting process and a possible requirement to install pollution
control equipment at the emissions unit can create a disincentive for
sources to voluntarily make energy efficiency
[[Page 44777]]
improvements. Many of these concerns with the NSR program were raised
nearly two decades ago, and formed the cornerstone of EPA's initiative
in the early 2000's to reform the NSR program.\58\
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\58\ In May 2001, President Bush's National Energy Policy
Development Group issued findings and key recommendations for a
National Energy Policy. This document included numerous
recommendations for action, including a recommendation that the EPA
Administrator, in consultation with the Secretary of Energy and
other relevant agencies, review NSR regulations, including
administrative interpretation and implementation. The recommendation
requested that EPA issue a report to the President on the impact of
the regulations on investment in new utility and refinery generation
capacity, energy efficiency, and environmental protection. The
report to the President was issued on June 13, 2002, and is
available at https://www.epa.gov/nsr/new-source-review-report-president. In the report to the President, EPA concluded ``[as]
applied to existing power plants and refineries . . . the NSR
program has impeded or resulted in the cancellation of projects
which would maintain and improve reliability, efficiency and safety
of existing energy capacity. Such discouragement results in lost
capacity, as well as lost opportunities to improve energy efficiency
and reduce air pollution.'' New Source Review Report to the
President at 3.
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But this dynamic takes on a new character in the context of a
regulation that may result in a source undertaking a HRI or another
project to meet a standard of performance as determined by the state.
When a state's 111(d) plan requires an EGU to comply with a standard of
performance, sources cannot choose to forego a project in an effort to
avoid NSR permitting as they could with improvement projects they were
otherwise considering. Despite recent actions by EPA to streamline the
NSR program, the reality remains that a source that undertakes a HRI
project may trigger major NSR under the current NSR applicability test
when required to undertake a HRI project as part of a state's 111(d)
plan. As has been noted by commenters on the ANPRM, this can require
the source to undertake significant planning and analysis with the
process to receive a preconstruction permit, sometimes taking 3 or more
years. This added time and cost to sources and the associated burden on
permitting agencies could hinder the effective and prompt
implementation of state 111(d) plans.
In this context, our approach in the CPP of encouraging agencies to
minimize the triggering of major NSR for their affected EGUs by
conducting emissions analyses as part of their CAA section 111(d) plan
development does not appear to be a sufficient solution. While EPA
supports states having the primary authority to implement the air
programs, state agencies should not be burdened with having to
determine a ``work around'' for the NSR program requirements in
developing their plans to implement the emission guidelines for
affected EGUs. The responsibility of ensuring that emission guidelines
under 111(d) are clearly articulated and easily implementable rests
squarely with EPA. Thus, EPA addressing the time delays and costs that
can result from NSR requirements could be one tool for helping ensure
the successful implementation of a national program for controlling GHG
emissions from existing EGUs.
It is important for a state that is developing a CAA section 111(d)
plan to completely understand the full costs being imposed on their
affected sources in order for the state to make informed decisions in
applying a standard of performance to each of their existing sources
(much like a state would consider, among other factors, the remaining
useful life of each source). However, EPA has historically not
considered the costs of complying with other CAA programs, like NSR,
when determining BSER for a source category under section 111. This was
in part because, for many years, EPA applied a policy of excluding
pollution control projects from NSR. But, as noted earlier in this
section, EPA's attempt to codify such a policy in the NSR regulations
was struck down by the D.C. Circuit in 2005. Since that decision, EPA
has not written a significant number of rules under section 111, and
the rules that EPA has written have not presented a need to consider
this question. However, due to the nature of the electric utility
industry and the types of candidate control measures being considered
in this proposal, it may be appropriate to consider NSR compliance
costs in this instance. Specifically, the BSER measures chosen in this
rule may result in a source undertaking a physical change that
significantly increases its annual emissions and triggers major NSR
permitting requirements such that permitting costs are unavoidable.
However, due to the case-specific analysis required to determine NSR
applicability, it would likely be difficult for a state to adequately
predict and quantify the effect of a HRI on an EGU's operational costs,
change in dispatch order, and other variables that would factor into
whether the source needs a major NSR permit or, perhaps, a minor NSR
permit. In addition, even if a state can reasonably predict an EGU's
emissions increase resulting from a HRI project such that it can expect
the source will need a major NSR permit, it would likely be difficult
to predict the expected permitting costs since the emission control and
other permitting requirements are case-by-case determinations and can
therefore vary significantly due to a number of factors, including how
well the source is already controlled, the emissions from nearby
sources and their contribution to air quality concerns, whether the
source is located in an attainment or nonattainment area, and the
potential for the air permit to trigger other requirements (e.g.,
Endangered Species Act, National Historic Preservation Act). In some
cases, a source triggering major NSR may be required to conduct
extensive modeling and install additional pollution controls for non-
GHG pollutants. Thus, the case-by-case nature of the NSR program can
lead to uncertainty for a state that is creating its 111(d) plan and
wanting to ensure that the plan fully appreciates the projected
compliance costs for its affected EGUs.
EPA is, therefore, inviting comment on whether it is appropriate to
consider the costs of NSR compliance in the BSER analysis under section
111(d), assuming that triggering NSR cannot otherwise be avoided
through actions by the source or through revisions to the NSR
regulations that are proposed by EPA in this rule or if EPA does not
finalize revisions to the NSR regulations (Comment C-59). In addition,
EPA solicits comment on how a state or local permitting agency may
estimate or project the cost for the source to comply with any NSR
requirements that may flow from a selected BSER, and on how the
potential for delays because of an influx of NSR permit applications
may be accounted for in setting an implementation schedule for 111(d)
plans (Comment C-60).
Recognizing that EPA issuing this 111(d) rule would mean that a
source may no longer be in a position to forego a HRI project due to
unwanted permitting costs, EPA has continued to look for ways to reduce
the costs of NSR requirements, while being mindful of the requirements
of the CAA and the court decisions on prior NSR reform rules that were
referenced by some commenters. In this light, EPA believes that a past
option for revising the NSR regulation that EPA has considered may
warrant further consideration to address this concern. In 2005 and
2007, EPA previously proposed adopting an hourly emissions rate test
for NSR applicability for EGUs. While this rulemaking was never
completed, EPA believes that it warrants a fresh look in a new context
here where NSR program flexibility takes on added significance as a
means to facilitate the HRI projects that are expected to be undertaken
should the proposed ACE rule be finalized. This same idea was also
raised by a few
[[Page 44778]]
commenters on the ANPRM.\59\ Thus, EPA is soliciting comment on whether
a narrower range of options for implementing an hourly emissions test
for NSR for EGUs would both help promote energy efficiency and the
effectiveness of implementing the ACE rule, while at the same time
being consistent with the NSR provisions in CAA and past judicial
decisions interpreting those provisions (Comment C-61).
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\59\ See, e.g., Arizona Public Service Company comments on the
U.S. Environmental Protection Agency's ANPRM entitled, ``State
Guidelines for Greenhouse Gas Emissions from Existing Electric
Utility Generating Units,'' 82 FR 61507 (Dec. 28, 2017) at 6 (EPA-
HQ-OAR-2017-0545-0286);Unions for Jobs & Environmental Progress
comments on the U.S. Environmental Protection Agency's ANPRM
entitled, ``State Guidelines for Greenhouse Gas Emissions from
Existing Electric Utility Generating Units,'' 82 FR 61507 (Dec. 28,
2017) at 14-17 (EPA-HQ-OAR-2017-0545-0162).
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2. The 2007 Supplemental Rule Proposal
In 2007, EPA proposed to revise the NSR provisions to include an
NSR applicability test for EGUs that is based on maximum hourly
emissions. 72 FR 26202 (May 8, 2007). The 2007 proposed action was a
``supplemental'' notice of proposed rulemaking (SNPRM), because the
2007 proposal followed an earlier action by EPA that proposed a more
limited form of the hourly emissions test for NSR applicability. 70 FR
61081 (October 20, 2005) (NPRM). These proposals followed EPA's NSR
regulatory reform efforts of 2002 and 2003, when EPA promulgated final
regulations that implemented several of the recommendations in the New
Source Review Report to the President.\60\ Those earlier regulatory
actions, however, left the NSR provisions for electric utilities
largely unchanged.
---------------------------------------------------------------------------
\60\ See supra note.
---------------------------------------------------------------------------
The 2007 SNPRM requested comment on two basic options, and various
alternatives within each of the two options, for changing the test for
determining an emissions increase from an EGU undergoing a physical or
operational change. The proposal included emissions test alternatives
based on an EGU's maximum achieved hourly emissions rate--applying
either a ``statistical approach'' or a ``one-in-5-year baseline
approach''--and an EGU's maximum achievable hourly emissions rate,
which mirrored the NSPS modification applicability test. While EPA did
not propose rule amendments in the 2005 NPRM, in 2007 EPA proposed to
amend 40 CFR part 51 to include a new provision at Sec. 51.167, which
largely mirrored the NSPS modification provisions in Sec. 60.2 and
Sec. 60.14. The 2007 SNPRM provided EPA's legal and policy basis for
incorporating an hourly emissions increase test within the NSR program
for EGUs.
For the proposed maximum achieved hourly test alternatives, an EGU
owner/operator would determine whether an emissions increase would
occur by comparing the pre-change maximum actual hourly emissions rate
to a projection of the post-change maximum actual hourly emissions
rate. In establishing the baseline, both alternatives considered the
unit's actual performance during the 5-year period immediately
preceding the physical or operational change. For the one-in-5-year
baseline approach, the emissions rate would be computed based on what
the unit actually achieved for any single hour within the 5-year period
immediately before the physical or operational change. For the
statistical approach, the owner/operative would analyze continuous
emission monitoring system (CEMS) or predictive emission monitoring
system (PEMS) data from the 5 years preceding the physical or
operational change to determine the maximum actual pollutant emissions
rate. The statistical approach would utilize actual recorded data from
periods of representative operation to calculate the maximum actual
emissions rate associated with the pre-change maximum actual operating
capacity in the past 5 years.
The purpose behind developing the statistical approach was to
address concerns from comments received on the 2005 NPRM ``that maximum
achievable emissions could differ from maximum achieved emissions for a
given EGU for any given period as a result of factors independent of
the physical or operational change, including variability of the sulfur
content in the coal being burned.'' 72 FR 26219 (May 8, 2007). In the
2007 SNPRM, EPA acknowledged that the highest hourly emissions do not
always occur at the point of highest capacity utilization, due to
fluctuations in process and control equipment operation, as well as in
fuel content and firing method. The proposed statistical procedure
would consequently ensure that the maximum achieved hourly emissions
test identified the maximum hourly pollutant emissions value.
Specifically, the statistical procedure would estimate the highest
value (99.9 percentage level) in the period represented by the data set
compiled from hourly average CEMS or PEMS measured emission rates and
corresponding heat input data. EPA asserted that this approach would
mitigate some of the uncertainty associated with trying to identify the
highest hourly emissions rate at the highest capacity utilization. EPA
asserted then that ``over a period that is representative of normal
operations, in general the maximum achievable and maximum achieved
hourly emissions test would lead to substantially equivalent results.''
72 FR 26220.
For the proposed maximum achievable hourly test alternatives, the
major NSR regulations would apply at an EGU if a physical or
operational change results in any increase above the maximum hourly
emissions achievable at that unit during the 5 years prior to the
change. Pre-change and post-change hourly emissions rates would be
determined according to the NSPS provisions in Sec. 60.14(b). Hourly
emission increases would be determined using emission factors, material
balances, continuous monitor data, or manual emission tests.
In the 2007 SNPRM, EPA argued that a maximum hourly emissions test
would simplify major NSR applicability determinations and
implementation. EPA contended that ``the achieved and achievable
[hourly emissions] tests eliminate the burden of projecting future
emissions and distinguishing between emissions increases caused by the
change from those due solely to demand growth, because any increase in
the emissions under the hourly emissions tests would logically be
attributed to the change. Both the achieved and achievable tests reduce
recordkeeping and reporting burdens on sources because compliance will
no longer rely on synthesizing emissions data into rolling average
emissions.'' 72 FR 26206 (May 8, 2007).
While the 2005 action had proposed to replace the current NSR
annual emissions increase test with an hourly test, the 2007 action
proposed the same option as well as an option to retain the annual
emissions test along with an hourly test. For the combined hourly and
annual emissions option, if a change would not increase the hourly
emissions of the EGU, major NSR would not apply; however, if hourly
emissions would increase after the change, then projected annual
emissions would be reviewed using the existing NSR applicability test.
The 2007 SNPRM expressed a preference for this combined applicability
option.
In the 2007 SNPRM, the proposed changes to the NSR emissions test
were in part justified by the substantial EGU emission reductions from
other air programs enacted since 1980 and the capped emissions
approaches used for
[[Page 44779]]
SO2 and nitrogen oxides (NOX) since the CAA
Amendment of 1990. The analyses conducted for that 2007 SNPRM concluded
that, by 2020, more EGUs would install controls than they would in
complying with a number of emission cap-based EPA rules that were in
play at the time (i.e., Clean Air Interstate Rule, Clean Air Mercury
Rule, and Clean Air Visibility Rule). The analysis maintained that the
hourly emissions test would allow units to operate more hours each
year, and the more hours a unit operates, the more it will control
emissions to remain under the emission caps. It concluded that there
would be essentially no changes in national emissions of SO2
and NOX by coal-fired power plants, and essentially no
impact on county-level emissions or local air quality.
These 2005 and 2007 proposed rules were neither finalized nor
withdrawn by EPA. The rulemaking docket for these actions is EPA-HQ-
OAR-2005-0163.
3. Legal Basis for Using Hourly Emission Rates To Identify Increases in
Emissions
The 2007 SNPRM followed EPA's NPRM from 2005 that would have
replaced the NSR program's annual emissions test with an hourly test.
The proposed regulatory approach taken in 2005 was based on the
decision in United States v. Duke Energy Corp., 411 F.3d 539 (4th Cir.
2005), in which the court held that the NSPS and NSR programs must have
a uniform emissions test. There, in the context of an NSR enforcement
case, the meaning of the CAA's definition of ``modification,'' and the
proper interpretation of the provisions of the NSR regulations (as
promulgated in 1980) that spoke to how an ``emissions increase'' was to
be determined were at issue. The Fourth Circuit held that the CAA
requires that those NSR regulations ``conform'' to their NSPS
counterpart. 411 F.3d at 548. According to the Fourth Circuit, because
Congress had relied on a cross-reference to CAA section 111(a)(4)'s
definition of ``modification'' (i.e., the original NSPS definition) to
define ``modification'' for purposes of the NSR program, this created
an ``effectively irrebuttable presumption'' that the two definitions
must be the same.'' Id. at 550.
The case then went to the Supreme Court, and the Supreme Court
disagreed. In Environmental Defense v. Duke Energy Corporation, 549
U.S. 561 (2007), the Supreme Court held that there was ``no effectively
irrebuttable presumption that the same defined term in different
provisions of the same statute must be interpreted identically. Context
counts.'' 549 U.S. at 575-76 (internal citation and quotation marks
omitted). Moving beyond the procedural question of whether the Fourth
Circuit had applied the proper tools of statutory construction, the
Court also engaged the underlying substantive question, finding that
``[n]othing in the text or the legislative history'' suggests that
Congress intended to require that the programs be tied together and
thereby ``eliminat[e] the customary agency discretion to resolve
questions about a statutory definition by looking to the surroundings
of the defined term.'' Id. at 576.
Of particular significance here, the Supreme Court also addressed
the possibility that the two regulatory programs could be read together
as set and subset, such than an NSPS-type modification was a
prerequisite to an NSR-type modification--i.e., that ``before a project
can become a `major modification' under the PSD regulations, it must
meet the definition of `modification' under the NSPS regulations.'' 549
U.S. at 581 n.8. This reading ``sounds right,'' the Court opined,'' but
then observed that, in its view, the NSPS and NSR regulations as they
were then written did not support such a reading. Id. Although the
Court had no occasion to address whether the Clean Air Act allows,
rather than directs, EPA to define ``modification'' the same way in
both the NSPS and NSR programs, EPA believes that the answer is clearly
yes. The Court does generally ``presume that the same term has the same
meaning when it occurs here and there in a single statute,'' 549 U.S.
at 575, and, as Justice Thomas pointed out in his concurrence, in the
case of the CAA's definition of ``modification,'' Congress's use of a
cross-reference ``carries more meaning than mere repetition of the same
word in a different statutory context.'' Id. at 583 (Thomas, J.,
concurring).\61\
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\61\ To this point, as Justice Thomas explains, the majority's
analysis of the relationship between the NSR and NSPS programs is
dicta, because the NSR regulations, as then written, could not be
permissibly read to mean the same as the NSPS regulations, and CAA
section 307(b) prohibits review of the NSR regulations in the
context of an enforcement action. Duke Energy, 549 U.S. at 582
(Thomas, J. concurring) (explaining that Justice Thomas joins only
Part III.B of the majority opinion).
---------------------------------------------------------------------------
In the 2007 SNPRM, EPA argued that the Supreme Court decision left
room for EPA to revise the regulations when it has a rational basis for
doing so. 72 FR 26202, 26204 (May 8, 2007); see also Environmental
Defense v. Duke Energy Corp., 549 U.S. 561, 576 (2007) (``EPA's
construction [of the definition of modification] need do no more than
fall within the limits of what is reasonable, as set by the Act's
common definition.'') EPA also argued that a maximum hourly emissions
test for NSR is an appropriate exercise of EPA's discretion citing
Chevron U.S.A., Inc. v. NRDC, Inc. 467 U.S. 37,865 (1984). Chevron
provides that when a statute is silent or ambiguous with respect to a
specific issue, the relevant inquiry for a reviewing court is whether
the Agency's interpretation of the statutory provision is permissible.
In this case, the Clean Air Act is silent on how to determine whether a
physical change or change in method of operation ``increases the amount
of any air pollutant emitted.'' 42 U.S.C. 7411(a)(4); New York I, 413
F.3d at 22 (``[T]he CAA . . . is silent on how to calculate such
`increases' in emissions.''). Accordingly, EPA has broad discretion to
propose a reasonable method by which to calculate the ``amount'' of an
emissions ``increase'' for purposes of NSR applicability.
In the 2007 action, EPA also explained how an applicability test
based on maximum achievable hourly emissions is, in fact, a test based
on actual emissions. The reason is that, as a practical matter, ``for
most, if not all EGUs, the hourly rate at which the unit is actually
able to emit is substantively equivalent to that unit's historical
maximum hourly emissions. That is, most, if not all EGUs will operate
at their maximum actual physical and operational capacity at some point
in a 5-year period. In general, the highest emissions occur during the
period of highest utilization. As a result, both the maximum achievable
and maximum achieved hourly emissions increase tests allow an EGU to
utilize all of its existing capacity, and in this aspect the hourly
rate at which the unit is actually able to emit is substantively
equivalent under both tests.'' 72 FR 26219 (May 8, 2007).
Thus, EPA considered the approaches proposed in the 2007 SNPRM to
be consistent with the D.C. Circuit precedent which held that the 2002
NSR Reform Rule's ``Clean Unit'' provision was beyond EPA's authority
because Congress intended to apply NSR to increases in actual
emissions, even though the decision deferred to EPA on the method for
calculating baseline emissions. Compare New York I, 413 F.3d at 40 with
id. at 20. In New York I, the D.C. Circuit found that the ``Clean
Unit'' provision was unlawful because it ``measures `increases' in
terms of Clean Unit status instead of actual emissions.'' 413 F.3d at
39. In defense of the provision, EPA had asserted that the CAA is
``silent'' as to whether an emissions increase ``must be measured in
terms of actual emissions, potential
[[Page 44780]]
emissions, or some other currency,'' and that EPA was therefore owed
deference to interpret what type of ``increases'' are relevant for the
modification analysis. Id. The D.C. Circuit, however, disagreed. The
court found that section 111(a)(4)'s reference to ``the amount of any
air pollutant emitted by [the] source plainly refers to actual
emissions'' and cannot encompass potential emissions. Id. at 40
(emphases in original). According to the court, ``the plain language of
the CAA indicates that Congress intended to apply NSR to changes that
increase actual emissions instead of potential or allowable
emissions.'' Id.
At the same time, the D.C. Circuit affirmed that EPA has wide
discretion to interpret the definition of ``modification'' within these
bounds. The court rejected challenges brought to the 2002 NSR Reform
Rule's then-new baseline period provision, finding that ``[i]n enacting
the NSR program, Congress did not specify how to calculate `increases'
in emissions,'' with the result that it was left to EPA ``to fill that
gap while balancing the economic and environmental goals of the
statute.'' 413 F.3d at 27. Because the CAA is ``silent on how to
calculate . . . `increases' in emissions'' for purposes of determining
``modification,'' the court said, id. at 22, EPA has discretion to give
meaning to that term by adopting a baseline period that `` `represents
a reasonable accommodation of' '' the Agency's environmental, economic,
and administrative concerns. Id. at 23 (quoting Chevron, 467 U.S. at
845). The D.C. Circuit went on to say that ``[d]ifferent
interpretations of the term `increases' may have different
environmental and economic consequences,'' and in ``administering the
NSR program and filling in the gaps left by Congress, EPA has the
authority to choose an interpretation that balances those
consequences.'' Id. at 23-24. The court added that this choice may be
informed by both EPA's ``extensive experience and expertise'' in this
technical and complex regulatory program and by the ``incumbent
administration's view of wise policy.'' Id at 24.
As for NRDC's argument in comments on the ANPRM that narrowing the
scope of projects subject to NSR requirements would be contrary to the
D.C. Circuit's New York II decision, EPA notes that what was before the
court in that case was an effort by EPA to further define what type of
projects are considered RMRR and thus excluded from the types of
``physical change[s] in, or change[s] in the method of operation of'' a
source that may trigger NSR. New York II, 443 F.3d at 883. While the
case focused on the ``physical change'' criterion of ``modification,''
the court's decision does provide some guidance on EPA's discretion to
interpret ``emissions increase.'' The court in New York II found that
the Equipment Replacement Rule, as promulgated in 2003, violated the
CAA because its bright-line RMRR test, which took into account the
value of the particular components being replaced, was inconsistent
with CAA section 111(a)'s broad applicability to ``any physical
change'' that results in increased emissions, subject to only de
minimis exclusions. Id. at 890. But in so finding, the D.C. Circuit
contrasted what it found to be the clear meaning of ``any physical
change'' with ``Congress's use of the word `increase,' '' which
``necessitated further definition regarding rate and measurement for
the term to have any contextual meaning.'' Id. at 888-889. Accordingly,
contrary to NRDC's assertions, New York II confirms the finding in New
York I that, other than requiring that they be measured in terms of
actual emissions, the CAA leaves to EPA the discretion to determine how
emission increases will be defined for the purposes of NSR
modification.
4. This Proposal
Consistent with our policy goal of encouraging efficient use of
existing energy capacity and managing the burden on states of
developing and implementing their CAA section 111(d) plans, EPA is
proposing to amend the NSR regulations to include an hourly emissions
increase test for EGUs. These proposed changes could be one tool that
states may use to help ensure the efficient and effective
implementation of their 111(d) plans.\62\
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\62\ As noted above, EPA is inviting comment regarding whether,
if we do not address NSR permitting burden with this proposal, we
should provide a mechanism for state and local permitting agencies
to consider the costs and delays associated with NSR permitting. See
Section VIII.C.1 of this preamble.
---------------------------------------------------------------------------
EPA is proposing some of the same alternatives for an hourly
emissions test that EPA proposed in 2007. The 2007 SNPRM solicited
comment on 12 alternatives, but EPA is narrowing the number of
alternatives for this revised proposal and solicitation of comment. In
this case, EPA is proposing only alternatives in which the hourly test
is paired with the current NSR annual emissions test (i.e., Option 1 in
the 2007 SNPRM) and only the alternatives that have an input-based
format (i.e., Alternatives 1, 3, and 5 in the 2007 SNPRM). Table 1
reflects the three alternatives being proposed in this action, and how
they fit within the structure of the proposed combined annual and
hourly emissions test for NSR applicability.
---------------------------------------------------------------------------
\63\ For clarity, this table lists all of the steps in the NSR
major modification applicability determination under the three
alternatives being proposed in this action. This current action does
not propose to change any of the current NSR applicability steps
besides inserting Step 2.
Table 5--Proposed Major NSR Applicability for an Existing EGU \63\
------------------------------------------------------------------------
-------------------------------------------------------------------------
Step 1: Physical Change or Change in the Method of Operation.
Step 2: Hourly Emissions Increase Test.
Alternative 1--Maximum achieved hourly emissions;
statistical approach; input basis.
Alternative 2--Maximum achieved hourly emissions; one-in-5-
year baseline; input basis.
Alternative 3--Maximum achievable hourly emissions; input
basis.
Step 3: Significant Emissions Increase Determined Using the Actual-to-
Projected-Actual Emissions Test as in the Current NSR Rules.
Step 4: Significant Net Emissions Increase as in the Current NSR Rules.
------------------------------------------------------------------------
Thus, under this proposed approach, the major NSR program would
include a four-step applicability process (with the second step
inserted as proposed, while retaining the other steps): (1) A physical
change or change in the method of operation as in the current major NSR
regulations; (2) an hourly emissions increase test (either maximum
achieved hourly emissions rate or maximum achievable hourly emissions
rate, each on an input-basis (lb/hr)); (3) a significant emissions
increase as in the current major NSR regulations; and (4) a significant
net emissions increase as in the current major NSR regulations. For a
major modification to occur, under Step 1, a physical change or change
in the method of operation must occur. If there is a physical change or
change in
[[Page 44781]]
method of operation, under Step 2, that change must result in an hourly
emissions increase at the existing EGU. If a post-change hourly
emissions increase is projected, a source must then proceed to
determine whether there is also a significant emissions increase and a
significant net emissions increase. In such cases, under Step 3, the
owner/operator would determine whether an emissions increase would
occur using the actual-to-projected-actual annual emissions test as
provided in the current regulations. There would be no conversion from
annual to hourly emissions. Finally, in Step 4, as in the current
regulations, if a significant emissions increase is projected to occur,
the source would still not be subject to major NSR unless there was a
determination that a significant net emissions increase would occur.
This proposed approach would not alter the provisions in the
current major NSR regulations pertaining to a significant emissions
increase and a significant net emissions increase. Therefore, the NSR
regulations would retain the definitions of net emissions increase,
significant, projected actual emissions, and baseline actual emissions.
See 40 CFR 51.166(b)(3), 51.166(b)(23), 51.166(b)(40),
51.166(b)(47).\64\ The regulations would also retain all provisions in
the current regulations that refer to major modifications, including,
but not limited to, those in 40 CFR 51.166(a)(7)(i) through (iii),
(b)(9), (b)(12), (b)(14)(ii), (b)(15), (b)(18), (i)(1) through (9),
(j)(1) through (4), (m)(1) through (3), (p)(1) through (7), (r)(1)
through (7), and (s)(1) through (4).\65\
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\64\ Analogous provisions are found in 40 CFR 51.165, 52.21, and
appendix S to 40 CFR part 51.
\65\ Analogous provisions are found in 40 CFR 51.165, 52.21, and
appendix S to 40 CFR part 51.
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To incorporate the four-step modification provisions, EPA is
proposing to add two new sections to the major NSR program rules. The
first, 40 CFR 51.167, would specify that State Implementation Plans may
include a new Step 2 for major NSR applicability at existing EGUs,
including those for both attainment and nonattainment areas. The
second, 40 CFR 52.25, would contain the requirements for major NSR
applicability for existing EGUs where EPA is the reviewing authority or
EPA has delegated our authority to a state or local air permitting
agency. EPA is also proposing to make the same changes where necessary
to conform the general provisions in parts 51 and 52 to the
requirements of the major NSR program, such as in the definition of
modification in 40 CFR 52.01. The new sections at Sec. 51.167 and
Sec. 52.25 will be separate and distinct from the other NSR provisions
and this will allow our rules to apply this new proposed Step 2 to EGUs
while keeping the current distinction in our NSR rules that applies
different applicability requirements for EUSGUs and non-EUSGUs that are
not EGUs.
While EPA is proposing that this NSR hourly emissions test would
apply to all EGUs, as defined in 40 CFR 51.124(q), EPA is soliciting
comment on whether to confine the applicability of the hourly test to a
smaller subset of the power sector, such as only the affected EGUs that
are making modifications to comply with their state's standards of
performance pursuant to these section 111(d) emissions guidelines
(i.e., pursuant to this document's proposed provisions at Sec.
60.5775a and Sec. 60.5780a) (Comment C-62). In addition, while the
2007 SNPRM solicited comment on whether such a test should be limited
to the geographic areas covered by several of EPA's rules at the time,
because the ACE rule would potentially affect EGUs in all of the
contiguous U.S., EPA is proposing in this action to not limit its
applicability to specific geographic areas. We are specifically
proposing that it would apply to EGUs in all areas of the United
States. Finally, although the 2007 SNPRM requested comment on whether
the proposed NSR hourly emissions test should be limited to increases
of SO2 and NOX emissions (due to the analysis
that supported the 2007 SNPRM), EPA is proposing in this action that
the NSR hourly emissions test would apply to all regulated NSR
pollutants because the candidate technologies being considered under
this proposal may affect annual emissions of not only GHGs but of all
pollutants from the power sector (and because EPA is not relying on the
previous proposal's analysis that focused on SO2 and
NOX emissions). EPA solicits comment on these approaches to
applicability for the proposed NSR hourly emission increase test.
Recognizing that existing case law dictates that the phrase
``increases the amount of any air pollutant'' in CAA section 111(a)(4)
refers to increases in actual emissions for NSR purposes, in 2007 EPA
argued that an hourly achievable test is equivalent to a measure of
actual emissions because ``for most, if not all EGUs, the hourly rate
at which the unit is actually able to emit is substantively equivalent
to that unit's historical maximum hourly emissions.'' 72 FR 26219 (May
8, 2007). EPA is taking comment on this prior assertion and whether
recent changes to the energy sector may have rendered it invalid
(Comment C-63). EPA is also asking for comment on whether if,
practically speaking, maximum achieved and maximum achievable hourly
rates are equivalent for most if not all EGUs, EPA has the flexibility
under the CAA to implement an hourly achievable emissions test for NSR
(Comment C-64).
As noted in the preceding section, EPA's proposal in 2007 to adopt
an hourly emissions increase test for NSR included an analysis
demonstrating that (1) the proposed regulations would not have an undue
adverse impact on local air quality, and (2) increases in the hours of
operation at EGUs, to the extent they may increase under a maximum
hourly rate test for NSR, would not notably increase national
SO2, NOx, PM2.5, VOC, or CO emissions from the
power sector. The analysis in 2007 concluded that the more efficiently
and the more cost-effectively an EGU operates, the more likely it is to
install controls due to other EPA air regulations. While time has
passed since the analyses in the 2007 SNPRM were conducted, the
analysis conducted for the ACE rule similarly reflects that, for
scenarios that include varying levels and costs of efficiency
improvements (reflecting, in part, the proposed changes to NSR in this
action), total national emissions of CO2 and other
pollutants will essentially stay the same or be slightly reduced when
compared with a CPP repeal. While it is possible that some individual
units may experience an increase in annual emissions due to increases
in operation, it is very difficult to project with confidence at which
of the units this would actually occur. This is partly due to the
framework of the current NSR annual emissions test, which considers a
number of source-specific variables--including operational history of
the unit, projected emissions that may be exempted due to demand
growth, other units competing for dispatch, and availability of
creditable emission decreases at the facility--that could result in the
source ultimately not being subject to major NSR. Consequently, the
analysis conducted for the ACE rule estimates the cost and benefits of
the different scenarios in a categorical sense and does not attempt to
identify the particular sources at which major NSR permitting may be
required absent the type of revisions to the NSR regulations proposed
here or incorporate a specific cost for NSR permitting within any of
the scenarios. This is due in part to limitations in the feasibility of
such analysis and in part to the structure of
[[Page 44782]]
section 111(d) and the state-plan development phase which would follow
a finalization of this proposed rule. EPA requests comment on the
concern about the potential emission increases as part of the proposed
NSR changes that some stakeholders have raised (Comment C-65).
While recognizing that fewer sources will trigger major NSR under
an hourly emissions increase, we note that even if a source undertaking
a heat rate improvement is not subject to major NSR requirements, it
will often require a minor NSR permit from its permitting agency. As
noted in Section VIII.A of this preamble, the minor NSR program applies
to new and modified sources that are not subject to major NSR
permitting. The purpose of a minor NSR program is, along with major
NSR, to ensure that sources of air emissions are properly regulated so
that the NAAQS are attained and protected. For example, under EPA's
tribal minor NSR program, the reviewing authority (i.e., EPA or a
delegated Tribe) must ensure that the NAAQS are protected through the
permitting process. The reviewing authority has the option to require
an air quality impact analysis for individual permits if they deem it
necessary based on air quality concerns.\66\ All minor NSR permits
require a public notice process and the permit may potentially require
the installation of air pollution controls based on an assessment by
the permitting authority.
---------------------------------------------------------------------------
\66\ 40 CFR 49.154(d). We note that many state (and local) minor
NSR permitting programs have similar methods for ensuring that the
NAAQS are protected.
---------------------------------------------------------------------------
Furthermore, states use measures contained in their State
Implementation Plan (SIP) to ensure that local air quality impacts are
addressed or minimized to the extent possible. A SIP may include (1)
state-adopted control measures which consist of either regulations or
source-specific requirements (e.g., orders and consent decrees); (2)
state-submitted ``non-regulatory'' components (e.g., maintenance plans
and attainment demonstrations); and (3) additional requirements
promulgated by EPA to satisfy a mandatory requirement in Section 110 or
Part D of the CAA.
Supplementing the Agency's legal and policy rationale provided in
the 2007 SNPRM, EPA is taking comment on an important factor that EPA
believes supports for moving forward with the addition of an NSR hourly
emissions test for EGUs: EPA is now proposing a rule that could result
in sources being required to perform HRIs (as determined by their state
111(d) plans) rather than sources independently deciding to do them
(Comment C-66). EPA believes this added factor of the 111(d) GHG
emission guidelines for EGUs directing sources to consider HRIs when
complying with their state plans may make the case for adopting an NSR
hourly emissions test for EGUs more compelling. EPA requests comment on
the extent to which EPA should allow the adoption of an NSR hourly
emissions test for EGUs in light of EPA's decision to issue these
proposed emission guidelines for the power sector (Comment C-67).
EPA is also taking comment on other ways to minimize or eliminate
any adverse impact that NSR may have on implementing section 111(d)
plans for EGUs (Comment C-68). Specifically, have there been court
decisions since New York I and New York II that can be read to afford
EPA more flexibility with respect to its reading of the definition of
``modification'' in the context of the NSR program?
For example, when EPA undertook the challenge of applying the PSD
program to GHGs, the Supreme Court pointed to several instances where
EPA had permissibly narrowed the scope of the general CAA definition of
``air pollutant'' based on the surrounding context of provisions within
which the term is used, including the NSR program. UARG v. EPA, 134
S.Ct. 2427, 2439-41 (2014). Based in part on this observation, the
Court rejected EPA's strict interpretation that the term ``air
pollutant'' must apply to greenhouse gases in the context of the
definition of ``major emitting facility'' in section 169(1) of the Act
in spite of the Agency's recognition that such a reading would
dramatically expand the reach of the PSD program to smaller scale
construction that Congress had never intended to cover. Id. at 2442. In
a like manner, does EPA have more flexibility with regard to its
interpretation of the definition of ``modification'' in the context of
the PSD program than the D.C. Circuit has previously recognized? Where
the D.C. Circuit's reading of the definition of ``modification'' in the
PSD context would produce results that frustrates Congressional
objectives in the CAA section 111 programs, does the reasoning of the
Supreme Court in UARG supply a basis for EPA to develop a narrower form
of a pollution control project exclusion from NSR?
The requirements of the CAA section 111 program were intended to
work in harmony with NSR and other provisions of the Act. The
complementary relationship of the programs is evident from the
statutory requirements. Both programs are intended to protect air
quality from stationary sources of pollution, and they rely on many of
the same CAA provisions and definitions--namely, the programs'
framework for existing sources are both rooted in the same definition
for ``modification.'' In addition, there are instances in which the CAA
cross links the programs such that a requirement from one program bears
an influence on the other program. For example, in accordance with CAA
section 169(3), an applicable standard of performance under NSPS
establishes the minimum level of stringency for BACT for a source
getting a PSD permit. Similarly, LAER must reflect an emission rate
that is does not exceed the allowable emission rate under any
applicable NSPS. CAA section 171(3). Thus, the NSPS program sets the
minimum performance standards for new stationary sources as part of
program to ensure air quality is protected, and NSR authorizes the
construction or modification of sources of air pollution, taking into
account the NSPS as it examines what the source needs to do to control
its emissions in order to adequately protect or improve air quality.
Thus, EPA believes the two programs are intended to complement--not
conflict with--each other. However, because changes considered under
111(d) plans could result in a source triggering NSR under the current
NSR rules and increasing the costs to the point that undertaking HRI
are less financially feasible for some sources, can EPA apply the
reasoning of UARG to read the definition of ``modification'' in this
context to afford more flexibility to exempt sources from NSR
requirements when they are compelled to make changes by an NSPS
(Comment C-69)?
5. State Adoption
As the hourly emissions test for NSR would be one tool for
implementing the ACE rule, EPA expects that some states may determine
that they do not need or desire to change the NSR applicability
requirements for EGUs. Consequently, EPA does not intend the NSR hourly
emissions test to be a mandatory element of state programs (as EPA had
proposed in 2007). EPA is proposing for this action that states would
have the discretion to decide whether to incorporate the NSR hourly
emissions test for EGUs into their rules. However, state and local
permitting authorities that are issuing permits on behalf of EPA under
a delegation agreement will be required to apply the NSR hourly
emissions test for EGUs, since they would follow the Federal NSR
program provided in 40 CFR part 52 (which would be amended to include
section
[[Page 44783]]
52.25). EPA solicits comment on allowing states this flexibility to
adopt the proposed NSR rule changes and on any other considerations
with respect to state (or local/district agency) adoption and
implementation of the proposed NSR changes (Comment C-70).
6. Severability
Although EPA proposes to finalize these NSR revisions as part of an
integrated action with the rest of this proposal, EPA views the
revisions to the definition of BSER, revisions to the implementing
regulations, and emission guideline proposed in this proposal as
appropriate policies in their own right and on their own terms. EPA
intends that the NSR revisions, if finalized, would be severable from
the other provisions on judicial review. EPA solicits comment on
whether it would be appropriate to finalize the NSR revisions as a
separate action from the remainder of the proposal (Comment C-71).
7. Submitting Comments
Please submit all comments on this NSR section docket established
for this rulemaking (Docket ID number EPA-HQ-OAR-2017-0355). To the
extent that you previously commented on the October 20, 2005 NPRM and/
or May 8, 2007 SNPRM and desire for your comments to be considered for
this proposed action, please resubmit them.
IX. Impacts
A. What are the air impacts?
In the Regulatory Impact Analysis (RIA) for this proposed
rulemaking, the Agency provides a full benefit cost analysis of four
illustrative scenarios. The four illustrative scenarios include a
scenario modeling the full repeal of the CPP (which can also be
conceptualized as the legal state of affairs as of the date of this
proposal, given the Supreme Court stay of the CPP) and three policy
scenarios modeling heat rate improvements (HRI) at coal-fired EGUs.
Throughout the RIA, these three illustrative policy scenarios are
compared against a base case, which includes the CPP. By analyzing
against the CPP, the reader can understand the combined impact of the
CPP repeal and proposed ACE rule. Inclusion of a no CPP case allows for
an understanding of the repeal alone and also allows the reader to
evaluate the impact of the policy cases against a no CPP scenario. The
RIA assumes a mass-based implementation of the CPP for existing
affected sources, and does not assume interstate trading. The three
illustrative policy scenarios represent potential outcomes of state
determinations of standards of performance, and compliance with those
standards by affected coal-fired EGUs. These policy scenarios
illustrate the analysis of the world without the CPP, the world with
this proposal, and the difference in the effects of this proposal and
those of the CPP.
The illustrative policy scenarios model different levels and costs
of HRIs applied uniformly at all affected coal-fired EGUs in the
contiguous U.S. beginning in 2025. EPA has identified the BSER to be
HRI. Each of these illustrative scenarios assumes that the affected
sources are no longer subject to the state plan requirements of the CPP
(i.e., the mass-based requirements assumed for CPP implementation in
the base case for the RIA). The cost, suitability, and potential
improvement for any of these HRI technologies is dependent on a range
of unit-specific factors such as the size, age, fuel use, and the
operating and maintenance history of the unit. As such, the HRI
potential can vary significantly from unit to unit. EPA does not have
sufficient information to assess HRI potential on a unit-by-unit basis.
To avoid the impression that EPA can sufficiently distinguish likely
standards of performance across individual affected units and their
compliance strategies, this analysis assumes different HRI levels and
costs are applied uniformly to affected coal-fired EGUs under each of
three illustrative policy scenarios:
The first illustrative scenario, 2 Percent HRI at $50/kW,
represents a policy case that reflects modest improvements in HRI
absent any revisions to NSR requirements. For many years, industry has
indicated to the Agency that many sources have not implemented certain
HRI projects because the burdensome costs of NSR cause such projects to
not be viable. Thus, absent NSR reform, HRI at affected units might be
expected to be modest. Based on numerous studies and statistical
analysis, the Agency believes that the HRI potential for coal-fired
EGUs will, on average, range from one to three percent at a cost of $30
to $60 per kilowatt (kW) of EGU generating capacity. The Agency
believes that this scenario (2 percent HRI at $50/kW) reasonably
represents that range of HRI and cost.
The second illustrative scenario, 4.5 Percent HRI at $50/kW,
represents a policy case that includes benefits from the proposed
revisions to NSR, with the HRI modeled at a low cost. As mentioned
earlier, the Agency is proposing revisions to the NSR program that will
provide owners and operators of existing EGUs greater ability to make
efficiency improvements without triggering the provisions of NSR. This
scenario is informative in that it represents the ability of all coal-
fired EGUs to obtain greater improvements in heat rate because of NSR
reform at the $50/kW cost identified earlier. EPA believes this higher
heat rate improvement potential is possible because without NSR a
greater number of units may have the opportunity to make cost effective
heat rate improvements such as steam turbine upgrades that have the
potential to offer greater heat rate improvement opportunities.
The third illustrative scenario, 4.5 Percent HRI at $100/kW,
represents a policy case that includes the benefits from the proposed
revisions to NSR, with the HRI modeled at a higher cost. This scenario
is informative in that it represents the ability of a typical coal-
fired EGU to obtain greater improvements in heat rate because of NSR
reform but at a much higher cost ($100/kW) than the $50/kW cost
identified earlier. Particularly for lower capacity units or those with
limited remaining useful life, this could ultimately translate into HRI
projects with costs beyond what most states might determine to be
reasonable.
Combined, the 4.5 percent HRI at $50/kW scenario and the 4.5
percent HRI at $100/kW scenario represent a range of potential costs
for the proposed policy option that couples HRI with NSR reform.
Modeling this at $50/kW and $100/kW provides a sensitivity analysis on
the cost of the proposed policy including NSR reform. The $50/kW cost
represents an optimistic bounding where NSR reform unleashes
significant new opportunity for low-cost heat rate improvements. The
$100/kW cost scenario, while informative, represents a high-end bound
that could overstate potential because, particularly for lower capacity
factor units and those with limited remaining useful life, these would
represent project costs that states would likely find to be
unreasonable.
The Agency understands that there may be interest in comparing the
three illustrative policy scenarios against an alternative baseline
that does not include the CPP. For those interested in comparing the
potential impacts of the policy scenarios in a world without the CPP,
results from the three illustrative policy scenarios may be compared
against an alternative baseline results from the illustrative No CPP
scenario. The presentation of an alternative baseline is consistent
with Circular A-4, which states, ``When more than one
[[Page 44784]]
baseline is reasonable and the choice of baseline will significantly
affect estimated benefits and costs, you should consider measuring
benefits and costs against alternative baselines'' \67\ In addition,
the full suite of model outputs and additional comparisons tables are
available in the rulemaking docket.
---------------------------------------------------------------------------
\67\ Office of Management and Budget (OMB), 2003, Circular A-4,
https://www.whitehouse.gov/sites/whitehouse.gov/files/omb/circulars/A4/a-4.pdf.
---------------------------------------------------------------------------
EPA evaluates the potential regulatory impacts of the illustrative
No CPP scenario and the three illustrative policy scenarios using the
present value (PV) of costs, benefits, and net benefits, calculated for
the years 2023-2037 from the perspective of 2016, using both a three
percent and seven percent beginning-of-period discount rate. In
addition, the Agency presents the assessment of costs, benefits, and
net benefits for specific snapshot years, consistent with historic
practice. In the RIA, the regulatory impacts are evaluated for the
specific years of 2025, 2030, and 2035.
Emissions are projected to be higher under the three illustrative
policy scenarios and the illustrative No CPP scenario than under the
base case, as the base case includes the CPP. Table 6 shows projected
emission increases relative to the base case for CO2,
SO2 and NOX from the electricity sector. Table 7
shows the same emissions change information, except relative to the No
CPP alternative baseline.
Table 6--Projected CO2, SO2, and NOX Electricity Sector Emission Increases, Relative to the Base Case (CPP)
(2025-2035)
----------------------------------------------------------------------------------------------------------------
CO2 (million SO2 (thousand NOX (thousand
short tons) short tons) short tons)
----------------------------------------------------------------------------------------------------------------
No CPP
----------------------------------------------------------------------------------------------------------------
2025............................................................ 50 36 32
2030............................................................ 74 60 47
2035............................................................ 66 44 43
----------------------------------------------------------------------------------------------------------------
2% HRI at $50/kW
----------------------------------------------------------------------------------------------------------------
2025............................................................ 37 35 24
2030............................................................ 61 53 39
2035............................................................ 55 34 39
----------------------------------------------------------------------------------------------------------------
4.5% HRI at $50/kW
----------------------------------------------------------------------------------------------------------------
2025............................................................ 32 40 21
2030............................................................ 60 53 39
2035............................................................ 59 43 43
----------------------------------------------------------------------------------------------------------------
4.5% HRI at $100/kW
----------------------------------------------------------------------------------------------------------------
2025............................................................ 20 32 14
2030............................................................ 47 45 32
2035............................................................ 44 29 33
----------------------------------------------------------------------------------------------------------------
Table 7--Projected CO2, SO2, and NOX Electricity Sector Emission Changes, Relative to the No CPP Alternative
Baseline
[2025-2035]
----------------------------------------------------------------------------------------------------------------
CO2 (million SO2 (thousand NOX (thousand
short tons) short tons) short tons)
----------------------------------------------------------------------------------------------------------------
Base Case (CPP)
----------------------------------------------------------------------------------------------------------------
2025............................................................ -50 -36 -32
2030............................................................ -74 -60 -47
2035............................................................ -66 -44 -43
----------------------------------------------------------------------------------------------------------------
2% HRI at $50/kW
----------------------------------------------------------------------------------------------------------------
2025............................................................ -13 0 -8
2030............................................................ -13 -7 -8
2035............................................................ -11 -11 -5
----------------------------------------------------------------------------------------------------------------
4.5% HRI at $50/kW
----------------------------------------------------------------------------------------------------------------
2025............................................................ -18 4 -11
2030............................................................ -14 -7 -8
2035............................................................ -7 -1 -1
----------------------------------------------------------------------------------------------------------------
[[Page 44785]]
4.5% HRI at $100/kW
----------------------------------------------------------------------------------------------------------------
2025............................................................ -30 -3 -18
2030............................................................ -27 -15 -15
2035............................................................ -22 -16 -11
----------------------------------------------------------------------------------------------------------------
The emissions changes in these tables do not account for changes in
hazardous air pollutants (HAPs) that may occur as a result of this
rule. For projected impacts on mercury emissions, please see Chapter 3
of the RIA for this proposed rulemaking.
B. What are the energy impacts?
The proposed actions have energy market implications. Overall, the
analysis to support this proposed rule indicates that there are
important power sector impacts that are worth noting, although they are
relatively small compared to other EPA air regulatory actions for EGUs.
The estimated impacts reflect EPA's illustrative analysis of the
proposed rule, which applies various levels of heat rate improvements
to affected sources in order to ascertain how they might respond, in
order to capture the potential systemwide economic and energy impacts
of the requirements. States are afforded considerable flexibility in
this proposed rule, and thus the impacts could be different, to the
extent states make different choices.
Table 8 presents a variety of energy market impacts for 2025, 2030,
and 2035 for the four illustrative scenarios, relative to the base
case, which includes the CPP.
Table 8--Summary of Certain Energy Market Impacts, Relative to Base Case (CPP)
[Percent change]
----------------------------------------------------------------------------------------------------------------
2025 (%) 2030 (%) 2035 (%)
----------------------------------------------------------------------------------------------------------------
No CPP
----------------------------------------------------------------------------------------------------------------
Retail electricity prices....................................... -0.5 -0.4 -0.1
Average price of coal delivered to the power sector............. -0.1 -0.2 -0.4
Coal production for power sector use............................ 6.1 9.2 9.5
Price of natural gas delivered to power sector.................. -1.1 -0.3 0.1
Price of average Henry Hub (spot)............................... -1.4 -0.8 -0.2
Natural gas use for electricity generation...................... -1.5 -1.5 -0.9
----------------------------------------------------------------------------------------------------------------
2% HRI at $50/kW
----------------------------------------------------------------------------------------------------------------
Retail electricity prices....................................... -0.3 -0.2 -0.1
Average price of coal delivered to the power sector............. 0.2 -0.1 -0.4
Coal production for power sector use............................ 5.5 8.0 8.4
Price of natural gas delivered to power sector.................. -1.1 -0.9 -0.4
Price of average Henry Hub (spot)............................... -1.4 -1.3 -0.6
Natural gas use for electricity generation...................... -2.5 -1.7 -1.1
----------------------------------------------------------------------------------------------------------------
4.5% HRI at $50/kW
----------------------------------------------------------------------------------------------------------------
Retail electricity prices....................................... -0.5 -0.4 -0.2
Average price of coal delivered to the power sector............. 0.7 0.6 0.3
Coal production for power sector use............................ 5.8 8.6 9.5
Price of natural gas delivered to power sector.................. -1.4 -1.1 -0.7
Price of average Henry Hub (spot)............................... -1.7 -1.6 -1.0
Natural gas use for electricity generation...................... -3.4 -2.5 -1.9
----------------------------------------------------------------------------------------------------------------
4.5% HRI at $100/kW
----------------------------------------------------------------------------------------------------------------
Retail electricity prices....................................... -0.2 0.0 0.0
Average price of coal delivered to the power sector............. 0.5 0.3 -0.1
Coal production for power sector use............................ 4.5 7.1 7.4
Price of natural gas delivered to power sector.................. -1.3 -1.1 -0.7
Price of average Henry Hub (spot)............................... -1.6 -1.6 -1.0
Natural gas use for electricity generation...................... -3.4 -2.3 -1.6
----------------------------------------------------------------------------------------------------------------
[[Page 44786]]
Energy market impacts are discussed more extensively in the RIA
found in the rulemaking docket.
C. What are the compliance costs?
The power industry's ``compliance costs'' are represented in this
analysis as the change in electric power generation costs between the
base case and illustrative scenarios, including the cost of monitoring,
reporting, and recordkeeping (MR&R). In simple terms, these costs are
an estimate of the increased power industry expenditures required to
implement the HRI required by the proposed rule, minus the sectoral
cost of complying with the CPP assumed in the base case.
The compliance assumptions--and, therefore, the projected
compliance costs--set forth in this analysis are illustrative in nature
and do not represent the plans that states may ultimately pursue. The
illustrative compliance scenarios are designed to reflect, to the
extent possible, the scope and nature of the proposed guidelines.
However, there is considerable uncertainty with regards to the precise
measure that states will adopt to meet the proposed requirements,
because there are considerable flexibilities afforded to the states in
developing their state plans.
Table 9 presents the annualized compliance costs of the three
illustrative policy scenarios and the illustrative No CPP scenario. In
this table, and throughout the RIA for this proposed rulemaking,
negative costs indicate avoided costs relative to the base case (which
includes the CPP), and positive costs indicate an increase in projected
compliance costs, relative to the base case. As shown in Table 9, the
Agency estimates that there are avoided costs under three out of the
four illustrative scenarios. Table 7 shows the same compliance cost
information, except relative to the No CPP alternative baseline.
Table 9--Compliance Costs, Relative to Base Case (CPP)
[Billions of 2016$]
----------------------------------------------------------------------------------------------------------------
2% HRI at $50/ 4.5% HRI at 4.5% HRI at
CPP repeal kW $50/kW $100/kW
----------------------------------------------------------------------------------------------------------------
2025............................................ (0.7) 0.0 (0.6) 0.5
2030............................................ (0.7) (0.2) (1.0) 0.2
2035............................................ (0.4) 0.1 (0.6) 0.5
----------------------------------------------------------------------------------------------------------------
Notes: Negative costs indicate that, on net, the illustrative scenario avoids costs relative to the base case
with the CPP. Compliance costs equal the projected change in total power sector generating costs, plus the
costs of monitoring, reporting, and recordkeeping.
Table 10--Compliance Costs, Relative to the No CPP Alternative Baseline
[Billions of 2016$]
----------------------------------------------------------------------------------------------------------------
2% HRI at $50/ 4.5% HRI at 4.5% HRI at
kW $50/kW $100/kW
----------------------------------------------------------------------------------------------------------------
2025............................................................ 0.7 0.1 1.3
2030............................................................ 0.5 (0.2) 0.9
2035............................................................ 0.5 (0.2) 0.8
----------------------------------------------------------------------------------------------------------------
Notes: Negative costs indicate that, on net, the illustrative scenario reduces costs relative to the No CPP
alternative baseline. Compliance costs equal the projected change in total power sector generating costs, plus
the costs of monitoring, reporting, and recordkeeping.
Due to a number of changes in the electricity sector since the CPP
was finalized, as documented in the October 2017 RIA conducted for the
proposed CPP repeal and Chapter 3 of the RIA for this action, the
sector has become less carbon intensive over the past several years,
and the trend is projected to continue. These changes and trends are
reflected in the modeling used for this analysis. As such, achieving
the emissions levels required under CPP requires less effort and
expense, relative to a scenario without the CPP, and the estimated
compliance costs are significantly lower than what was estimated in the
final CPP RIA. More detailed cost estimates are available in the RIA
included in the rulemaking docket.
D. What are the economic and employment impacts?
Environmental regulation may affect groups of workers differently,
as changes in abatement and other compliance activities cause labor and
other resources to shift. An employment impact analysis describes the
characteristics of groups of workers potentially affected by a
regulation, as well as labor market conditions in affected occupations,
industries, and geographic areas. Market and employment impacts of this
proposed action are discussed more extensively in Chapter 5 of the RIA
for this proposed rulemaking.
E. What are the benefits of the proposed action?
EPA reports the impact on climate benefits from changes in
CO2 and the impact on health benefits attributable to
changes in SO2, NOX and PM2.5
emissions. EPA refers to the climate benefits as ``targeted pollutant
benefits'' as they reflect the direct benefits of reducing
CO2, and to the ancillary health benefits as ``co-benefits''
as they are not benefits from reducing the targeted pollutant. To
estimate the climate benefits associated with changes in CO2
emissions, EPA applies a measure of the domestic social cost of carbon
(SC-CO2). The SC-CO2 is a metric that estimates
the monetary value of impacts associated with marginal changes in
CO2 emissions in a given year. The SC-CO2
estimates used in the RIA for this proposed rulemaking focus on the
direct impacts of climate change that are anticipated to occur within
U.S. borders.
The estimated health co-benefits are the monetized value of the
forgone human health benefits among populations exposed to changes in
PM2.5 and ozone. This rule is expected to alter the
emissions of SO2 and NOX emissions, which will in
turn affect the level of PM2.5 and ozone in the atmosphere.
Using photochemical modeling, EPA predicted the change in the annual
average PM2.5 and summer
[[Page 44787]]
season ozone across the U.S. for the years 2025, 2030 and 2035. EPA
next quantified the human health impacts and economic value of these
changes in air quality using the environmental Benefits Mapping and
Analysis Program--Community Edition. EPA quantified effects using
concentration-response parameters detailed in the RIA and that are
consistent with those employed by the Agency in the PM NAAQS and Ozone
NAAQS RIAs (U.S. EPA, 2012; 2015). In these tables, negative values
represent forgone benefits and positive benefits represent realized
benefits.
[GRAPHIC] [TIFF OMITTED] TP31AU18.001
[[Page 44788]]
[GRAPHIC] [TIFF OMITTED] TP31AU18.002
[[Page 44789]]
[GRAPHIC] [TIFF OMITTED] TP31AU18.003
Table 14 reports the combined domestic climate benefits and
ancillary health co-benefits attributable to changes in SO2
and NOX emissions estimated for 3 percent and 7 percent
discount rates in the years 2025, 2030 and 2035, in 2016 dollars. This
table reports the air pollution effects calculated using
PM2.5 log-linear no threshold concentration-response
functions that quantify risk associated with the full range of
PM2.5 exposures experienced by the population (U.S. EPA,
2009; U.S. EPA, 2011; NRC, 2002).
In this table, negative benefits indicate forgone benefits,
relative to the base case, which includes the CPP. As all benefit
estimates in this table are negative values, this indicates that the
Agency estimates there to be forgone climate benefits and forgone
ancillary health co-benefits under all four illustrative scenarios in
the years and discount rates analyzed relative to the base case.
[[Page 44790]]
Table 14--Monetized Benefits, Relative to Base Case (CPP)
[billions of 2016$]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Values calculated using 3% discount rate Values calculated using 7% discount rate
-------------------------------------------------------------------------------------------------------------------------------------------------------------
Domestic Domestic
climate Ancillary health co-benefits Total benefits climate Ancillary health co-benefits Total benefits
benefits benefits
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
No CPP
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2025.............................. (0.3) (2.8) to (6.6)................ (3.2) to (7.0)................ (0.1) (2.6) to (6.1)............... (2.7) to (6.1)
2030.............................. (0.5) (4.9) to (11.4)............... (5.4) to (11.9)............... (0.1) (4.5) to (10.5).............. (4.6) to (10.6)
2035.............................. (0.5) (3.8) to (8.8)................ (4.3) to (9.3)................ (0.1) (3.5) to (8.1)............... (3.6) to (8.2)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2% HRI at $50/kW
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2025.............................. (0.2) (2.6) to (5.9)................ (2.8) to (6.2)................ (0.0) (2.4) to (5.4)............... (2.4) to (5.5)
2030.............................. (0.4) (4.5) to (10.6)............... (4.9) to (11.0)............... (0.1) (4.1) to (9.8)............... (4.2) to (9.9)
2035.............................. (0.4) (3.0) to (7.0)................ (3.4) to (7.4)................ (0.1) (2.7) to (6.5)............... (2.8) to (6.6)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
4.5% HRI at $50/kW
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2025.............................. (0.2) (2.7) to (6.2)................ (2.9) to (6.4)................ (0.0) (2.5) to (5.7)............... (2.5) to (5.7)
2030.............................. (0.4) (4.2) to (9.8)................ (4.6) to (10.2)............... (0.1) (3.9) to (9.0)............... (3.9) to (9.1)
2035.............................. (0.5) (4.0) to (9.3)................ (4.4) to (9.8)................ (0.1) (3.7) to (8.6)............... (3.7) to (8.7)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
4.5% HRI at $100/kW
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2025.............................. (0.1) (2.1) to (4.9)................ (2.3) to (5.0)................ (0.0) (2.0) to (4.4)............... (2.0) to (4.4)
2030.............................. (0.3) (3.6) to (8.2)................ (3.9) to (8.6)................ (0.1) (3.3) to (7.6)............... (3.3) to (7.6)
2035.............................. (0.3) (2.6) to (6.0)................ (2.9) to (6.3)................ (0.1) (2.4) to (5.5)............... (2.4) to (5.6)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: Negative benefit values indicate forgone benefits relative to the base case, which includes the CPP. All estimates are rounded to one decimal point, so figures may not sum due to
independent rounding. Climate benefits reflect the value of domestic impacts from CO2 emissions changes. The ancillary health co-benefits reflect the sum of the PM2.5 and ozone benefits from
changes in electricity sector SO2, NOX, and PM2.5 emissions and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Smith et al. (2009) to Lepeule et
al. (2012) with Jerrett et al. (2009)) using a log-linear no threshold model.
In general, EPA is more confident in the size of the risks
estimated from simulated PM2.5 concentrations that coincide
with the bulk of the observed PM concentrations in the epidemiological
studies that are used to estimate the benefits. Likewise, EPA is less
confident in the risk EPA estimates from simulated PM2.5
concentrations that fall below the bulk of the observed data in these
studies.\68\ Furthermore, when setting the 2012 PM NAAQS, the
Administrator also acknowledged greater uncertainty in specifying the
``magnitude and significance'' of PM-related health risks at PM
concentrations below the NAAQS. As noted in the preamble to the 2012 PM
NAAQS final rule, ``EPA concludes that it is not appropriate to place
as much confidence in the magnitude and significance of the
associations over the lower percentiles of the distribution in each
study as at and around the long-term mean concentration.'' (78 FR 3154,
January 15, 2013). In general, we are more confident in the size of the
risks we estimate from simulated PM2.5 concentrations that
coincide with the bulk of the observed PM concentrations in the
epidemiological studies that are used to estimate the benefits.
Likewise, we are less confident in the risk we estimate from simulated
PM2.5 concentrations that fall below the bulk of the
observed data in these studies.
---------------------------------------------------------------------------
\68\ The Federal Register notice for the 2012 PM NAAQS indicates
that ``[i]n considering this additional population level
information, the Administrator recognizes that, in general, the
confidence in the magnitude and significance of an association
identified in a study is strongest at and around the long-term mean
concentration for the air quality distribution, as this represents
the part of the distribution in which the data in any given study
are generally most concentrated. She also recognizes that the degree
of confidence decreases as one moves towards the lower part of the
distribution.''
---------------------------------------------------------------------------
To give readers insight to the distribution of estimated forgone
benefits displayed in Table 14, EPA also reports the PM benefits
according to alternative concentration cut-points and concentration-
response parameters. The percentage of estimated PM2.5-
related deaths occurring below the lowest measured levels (LML) of the
two long-term epidemiological studies EPA uses to estimate risk varies
between 16 percent (Krewski et al. 2009) and 79 percent (Lepeule et al.
2012). The percentage of estimated premature deaths occurring above the
LML and below the NAAQS ranges between 84 percent (Krewski et al. 2009)
and 21 percent (Lepeule et al. 2012). Less than 1% of the estimated
premature deaths occur above the annual mean PM2.5 NAAQS of
12 [micro]g/m\3\.
Monetized co-benefits estimates shown here do not include several
important benefit categories, such as direct exposure to
SO2, NOX and hazardous air pollutants including
mercury and hydrogen chloride. Although EPA does not have sufficient
information or modeling available to provide monetized estimates of
changes in exposure to these pollutants for this rule, EPA includes a
qualitative assessment of these unquantified benefits in the RIA. For
more information on the benefits analysis, please refer to the RIA for
this rule, which is available in the rulemaking docket.
X. Statutory and Executive Order Reviews
Additional information about these Statutory 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 proposed action is an economically significant action that was
[[Page 44791]]
submitted to the OMB for review. Any changes made in response to OMB
recommendations have been documented in the docket. EPA prepared an
analysis of the compliance cost, benefit, and net benefit impacts
associated with this action in the analysis years of 2025, 2030, and
2035. This analysis, which is contained in the Regulatory Impact
Analysis (RIA) for this proposed rulemaking, is consistent with
Executive Order 12866 and is available in the rulemaking docket.
In the RIA for this proposed rulemaking, the Agency presents full
benefit cost analysis of four illustrative scenarios. The four
illustrative scenarios include a scenario modeling the full repeal of
the CPP and three policy scenarios modeling heat rate improvements
(HRI) at coal-fired EGUs. Throughout the RIA, these three illustrative
policy scenarios are compared against a base case, which includes the
CPP. By analyzing against the CPP, the reader can understand the
combined impact of a CPP repeal and proposed ACE rule. Inclusion of a
No CPP case allows for an understanding of the repeal alone and also
allows the reader to evaluate the impact of the policy cases against a
No CPP scenario. The RIA assumes a mass-based implementation of the CPP
for existing affected sources, and does not assume interstate trading.
The three illustrative policy scenarios represent potential outcomes of
state determinations of standards of performance, and compliance with
those standards by affected coal-fired EGUs.
The Agency understands that there may be interest in comparing the
three illustrative policy scenarios against a scenario that does not
include the CPP. For those interested in comparing the potential
impacts of policy scenarios in a world without the CPP, results from
the three illustrative policy scenarios may be compared against results
from the illustrative No CPP scenario. We provide information here on
compliance costs, emissions impacts and present value net benefits
compared to the No CPP alternative baseline. In addition, the Executive
Summary and Chapter 3 of the RIA compares the three illustrative policy
scenarios to the scenario of a full CPP repeal. Also, the full suite of
model outputs is available in the rulemaking docket.
The three illustrative policy scenarios model different levels and
costs of HRIs applied uniformly at all affected coal-fired EGUs in the
contiguous U.S. beginning in 2025. EPA has identified the BSER to be
HRI. Each of these illustrative scenarios assumes that the affected
sources are no longer subject to the state plan requirements of the CPP
(i.e., the mass-based requirements assumed for CPP implementation in
the base case for the RIA). The cost, suitability, and potential
improvement for any of these HRI technologies is dependent on a range
of unit-specific factors such as the size, age, fuel use, and the
operating and maintenance history of the unit. As such, the HRI
potential can vary significantly from unit to unit. EPA does not have
sufficient information to assess HRI potential on a unit-by-unit basis.
To avoid the impression that EPA can sufficiently distinguish
likely standards of performance across individual affected units and
their compliance strategies, this analysis assumes different HRI levels
and costs are applied uniformly to affected coal-fired EGUs under each
of three illustrative policy scenarios.
The first illustrative scenario, 2 Percent HRI at $50/kW,
represents a policy case that reflects modest improvements in HRI
absent any revisions to NSR requirements. For many years, industry has
indicated to the Agency that many sources have not implemented certain
HRI projects because the burdensome costs of NSR cause such projects to
not be viable. Thus, absent NSR reform, HRI at affected units might be
expected to be modest. Based on numerous studies and statistical
analysis, the Agency believes that the HRI potential for coal-fired
EGUs will, on average, range from one to three percent at a cost of $30
to $60 per kilowatt (kW) of EGU generating capacity. The Agency
believes that this scenario (2 percent HRI at $50/kW) reasonably
represents that range of HRI and cost.
The second illustrative scenario, 4.5 Percent HRI at $50/kW,
represents a policy case that includes benefits from the proposed
revisions to NSR, with the HRI modeled at a low cost. As mentioned
earlier, the Agency is proposing revisions to the NSR program that will
provide owners and operators of existing EGUs greater ability to make
efficiency improvements without triggering provisions of NSR. This
scenario is informative in that it represents the ability of all coal-
fired EGUs to obtain greater improvements in heat rate because of NSR
reform at the $50/kW cost identified earlier. EPA believes this higher
heat rate improvement potential is possible because without NSR a
greater number of units may have the opportunity to make cost effective
heat rate improvements such as turbine upgrades that have the potential
to offer greater heat rate improvement opportunities.
The third illustrative scenario, 4.5 Percent HRI at $100/kW,
represents a policy case that includes the benefits from the proposed
revisions to NSR, with the HRI modeled at a higher cost. This scenario
is informative in that it represents the ability of a typical coal-
fired EGUs to obtain greater improvements in heat rate because of NSR
reform but at a much higher cost ($100/kW) than the $50/kW cost
identified earlier. Particularly for lower capacity units or those with
limited remaining useful life, this could ultimately translate into HRI
projects with costs beyond what most states might determine to be
reasonable.
Combined, the 4.5 percent HRI at $50/kW scenario and the 4.5
percent HRI at $100/kW scenario represent a range of potential costs
for the proposed policy option that couples HRI with NSR reform.
Modeling this at $50/kW and $100/kW provides a sensitivity analysis on
the cost of the proposed policy including NSR reform. The $50/kW cost
represents an optimistic bounding where NSR reform unleashes
significant new opportunity for low-cost heat rate improvements. The
$100/kW cost scenario, while informative, represents a high-end bound
that could overstate potential because, particularly for lower capacity
factor units and those with limited remaining useful life, these would
represent project costs that states would likely find to be
unreasonable.
We evaluate the potential regulatory impacts of the illustrative No
CPP scenario and the three illustrative policy scenarios using the
present value (PV) of costs, benefits, and net benefits, calculated for
the years 2023-2037 from the perspective of 2016, using both a three
percent and seven percent beginning-of-period discount rate. In
addition, the Agency presents the assessment of costs, benefits, and
net benefits for specific snapshot years, consistent with historic
practice. In the RIA, the regulatory impacts are evaluated for the
specific years of 2025, 2030, and 2035.
The power industry's ``compliance costs'' are represented in this
analysis as the change in electric power generation costs between the
base case and illustrative scenarios, including the cost of monitoring,
reporting, and recordkeeping (MR&R). In simple terms, these costs are
an estimate of the increased power industry expenditures required to
implement the HRI required by the proposed rule, minus the sectoral
cost of complying with the CPP assumed in the base case.
The compliance assumptions--and, therefore, the projected
compliance costs--set forth in this analysis are
[[Page 44792]]
illustrative in nature and do not represent the plans that states may
ultimately pursue. The illustrative compliance scenarios are designed
to reflect, to the extent possible, the scope and nature of the
proposed guidelines. However, there is considerable uncertainty with
regards to the precise measure that states will adopt to meet the
proposed requirements, because there are considerable flexibilities
afforded to the states in developing their state plans.
EPA reports the impact on climate benefits from changes in
CO2 and the impact on health benefits attributable to
changes in SO2, NOX and PM2.5
emissions. We refer to the climate benefits as ``targeted pollutant
benefits'' as they reflect the direct benefits of reducing
CO2, and to the ancillary health benefits as ``co-benefits''
as they are not benefits from reducing the targeted pollutant. To
estimate the climate benefits associated with changes in CO2
emissions, we apply a measure of the domestic social cost of carbon
(SC-CO2). The SC-CO2 is a metric that estimates
the monetary value of impacts associated with marginal changes in
CO2 emissions in a given year. The SC-CO2
estimates used in the RIA for this proposed rulemaking focus on the
direct impacts of climate change that are anticipated to occur within
U.S. borders.
The health co-benefits estimates represent the monetized value of
the forgone human health benefits among populations exposed to changes
in PM2.5 and ozone. This rule is expected to alter the
emissions of SO2, NOX, and PM2.5
emissions, which will in turn affect the level of PM2.5 and
ozone in the atmosphere. Using photochemical modeling, we predicted the
change in the annual average PM2.5 and summer season ozone
across the U.S. for the years 2025, 2030 and 2035. We next quantified
the human health impacts and economic value of these changes in air
quality using the environmental Benefits Mapping and Analysis Program--
Community Edition. We quantified effects using concentration-response
parameters detailed in the RIA and that are consistent with those
employed by the Agency in the PM NAAQS and Ozone NAAQS RIAs (U.S. EPA,
2012; 2015).
In general, we are more confident in the size of the risks we
estimate from simulated PM2.5 concentrations that coincide
with the bulk of the observed PM concentrations in the epidemiological
studies that are used to estimate the benefits. Likewise, we are less
confident in the risk we estimate from simulated PM2.5
concentrations that fall below the bulk of the observed data in these
studies.\69\
---------------------------------------------------------------------------
\69\ The Federal Register notice for the 2012 PM NAAQS indicates
that ``[i]n considering this additional population level
information, the Administrator recognizes that, in general, the
confidence in the magnitude and significance of an association
identified in a study is strongest at and around the long-term mean
concentration for the air quality distribution, as this represents
the part of the distribution in which the data in any given study
are generally most concentrated. She also recognizes that the degree
of confidence decreases as one moves towards the lower part of the
distribution.''
---------------------------------------------------------------------------
Furthermore, when setting the 2012 PM NAAQS, the Administrator also
acknowledged greater uncertainty in specifying the ``magnitude and
significance'' of PM-related health risks at PM concentrations below
the NAAQS. As noted in the preamble to the 2012 PM NAAQS final rule,
``EPA concludes that it is not appropriate to place as much confidence
in the magnitude and significance of the associations over the lower
percentiles of the distribution in each study as at and around the
long-term mean concentration.'' (78 FR 3154, 15 January 2013). In
general, we are more confident in the size of the risks we estimate
from simulated PM2.5 concentrations that coincide with the
bulk of the observed PM concentrations in the epidemiological studies
that are used to estimate the benefits. Likewise, we are less confident
in the risk we estimate from simulated PM2.5 concentrations
that fall below the bulk of the observed data in these studies.
To give readers insight to the distribution of estimated forgone
benefits displayed in Table 14, EPA also reports the PM benefits
according to alternative concentration cut-points and concentration-
response parameters. To give readers insight to the uncertainty in the
estimated forgone PM2.5 mortality benefits occurring at
lower ambient levels, we also report the PM benefits according to
alternative concentration cut-points and concentration-response
parameters. The percentage of estimated PM2.5-related deaths
occurring below the lowest measured levels (LML) of the two long-term
epidemiological studies we use to estimate risk varies between 16
percent (Krewski et al. 2009) and 79 percent (Lepeule et al. 2012). The
percentage of estimated premature deaths occurring above the LML and
below the NAAQS ranges between 84 percent (Krewski et al. 2009) and 21
percent (Lepeule et al. 2012). Less than 1% of the estimated premature
deaths occur above the annual mean PM2.5 NAAQS of 12
[micro]g/m\3\.
Monetized co-benefits estimates shown here do not include several
important benefit categories, such as direct exposure to
SO2, NOX and hazardous air pollutants including
mercury and hydrogen chloride. Although we do not have sufficient
information or modeling available to provide monetized estimates of
changes in exposure to these pollutants for this rule, we include a
qualitative assessment of these unquantified benefits in the RIA. For
more information on the benefits analysis, please refer to the RIA for
this rule, which is available in the rulemaking docket.
In the decision-making process it is useful to consider the change
in benefits due to the targeted pollutant relative to the costs.
Therefore, in Chapter 6 of the RIA for this proposed rulemaking we
present a comparison of the benefits from the targeted pollutant--
CO2--with the compliance costs. Excluded from this
comparison are the benefits from changes in PM2.5 and ozone
concentrations from changes in SO2, NOX and
PM2.5 emissions that are projected to accompany changes in
CO2 emissions.
Table 15 presents the present value (PV) and equivalent annualized
value (EAV) of the estimated costs, benefits, and net benefits
associated with the targeted pollutant, CO2, for the
timeframe of 2023-2037, relative to the base case, which includes the
CPP. The EAV represents an even-flow of figures over the timeframe of
2023-2037 that would yield an equivalent present value. The EAV is
identical for each year of the analysis, in contrast to the year-
specific estimates presented earlier for the snapshot years of 2025,
2030, and 2035.
In Table 15, and all net benefit tables, negative costs indicate
avoided costs, negative benefits indicate forgone benefits, and
negative net benefits indicate forgone net benefits.
[[Page 44793]]
Table 15--Present Value and Equivalent Annualized Value of Compliance Costs, Climate Benefits, and Net Benefits
Associated With Targeted Pollutant (CO2), Relative to Base Case (CPP), 3 and 7 Percent Discount Rates, 2023-2037
[Billions of 2016$]
----------------------------------------------------------------------------------------------------------------
Costs Domestic climate benefits Net benefits associated
------------------------------------------------------ with the targeted
pollutant (CO2)
3% 7% 3% 7% -------------------------
3% 7%
----------------------------------------------------------------------------------------------------------------
Present Value
----------------------------------------------------------------------------------------------------------------
No CPP.......................... (5.2) (3.1) (3.9) (0.4) 1.2 2.7
2% HRI at $50/kW................ (0.4) (0.3) (3.2) (0.3) (2.8) (0.1)
4.5% HRI at $50/kW.............. (6.4) (3.7) (3.2) (0.3) 3.2 3.4
4.5% HRI at $100/kW............. 3.0 1.7 (2.4) (0.2) (5.4) (2.0)
----------------------------------------------------------------------------------------------------------------
Equivalent Annualized Value
----------------------------------------------------------------------------------------------------------------
No CPP.......................... (0.4) (0.3) (0.3) (0.0) 0.1 0.3
2% HRI at $50/kW................ (0.0) (0.0) (0.3) (0.0) (0.2) (0.0)
4.5% HRI at $50/kW.............. (0.5) (0.4) (0.3) (0.0) 0.3 0.4
4.5% HRI at $100/kW............. 0.3 0.2 (0.2) (0.0) (0.5) (0.2)
----------------------------------------------------------------------------------------------------------------
Notes: Negative costs indicate avoided costs, negative benefits indicate forgone benefits, and negative net
benefits indicate forgone net benefits. All estimates are rounded to one decimal point, so figures may not sum
due to independent rounding. Climate benefits reflect the value of domestic impacts from CO2 emissions
changes. This table does not include estimates of ancillary health co-benefits from changes in electricity
sector SO2 and NOX emissions.
Table 16 presents the costs, benefits, and net benefits associated with
the targeted pollutant for specific years, rather than as a PV or EAV
as found in Table 18.
Table 16--Compliance Costs, Climate Benefits, and Net Benefits Associated With Targeted Pollutant (CO2),
Relative to Base Case (CPP), 3 and 7 Percent Discount Rates, 2025, 2030, and 2035
[Billions of 2016$]
----------------------------------------------------------------------------------------------------------------
Costs Domestic climate benefits Net benefits associated
------------------------------------------------------ with the targeted
pollutant (CO2)
3% 7% 3% 7% -------------------------
3% 7%
----------------------------------------------------------------------------------------------------------------
No CPP
----------------------------------------------------------------------------------------------------------------
2025............................ (0.7) (0.7) (0.3) (0.1) 0.4 0.7
2030............................ (0.7) (0.7) (0.5) (0.1) 0.2 0.6
2035............................ (0.4) (0.4) (0.5) (0.1) (0.1) 0.3
----------------------------------------------------------------------------------------------------------------
2% HRI at $50/kW
----------------------------------------------------------------------------------------------------------------
2025............................ 0.0 0.0 (0.2) (0.0) (0.3) (0.1)
2030............................ (0.2) (0.2) (0.4) (0.1) (0.2) 0.2
2035............................ 0.1 0.1 (0.4) (0.1) (0.6) (0.2)
----------------------------------------------------------------------------------------------------------------
4.5% HRI at $50/kW
----------------------------------------------------------------------------------------------------------------
2025............................ (0.6) (0.6) (0.2) (0.0) 0.4 0.6
2030............................ (1.0) (1.0) (0.4) (0.1) 0.5 0.9
2035............................ (0.6) (0.6) (0.5) (0.1) 0.2 0.5
----------------------------------------------------------------------------------------------------------------
4.5% HRI at $100/kW
----------------------------------------------------------------------------------------------------------------
2025............................ 0.5 0.5 (0.1) (0.0) (0.7) (0.5)
2030............................ 0.2 0.2 (0.3) (0.1) (0.5) (0.2)
2035............................ 0.5 0.5 (0.3) (0.1) (0.8) (0.5)
----------------------------------------------------------------------------------------------------------------
Notes: Negative costs indicate avoided costs, negative benefits indicate forgone benefits, and negative net
benefits indicate forgone net benefits. All estimates are rounded to one decimal point, so figures may not sum
due to independent rounding. Climate benefits reflect the value of domestic impacts from CO2 emissions
changes. This table does not include estimates of ancillary health co-benefits from changes in electricity
sector SO2 and NOX emissions.
[[Page 44794]]
Table 17 presents the present value (PV) and equivalent annualized
value (EAV) of the estimated costs, benefits, and net benefits
associated with the targeted pollutant, CO2, for the timeframe of 2023-
2037, relative to the No CPP alternative baseline.
Table 17--Present Value and Equivalent Annualized Value of Compliance Costs, Climate Benefits, and Net Benefits
Associated With Targeted Pollutant (CO2), Relative to the No CPP Alternative Baseline, 3 and 7 Percent Discount
Rates, 2023-2037
[Billions of 2016$]
----------------------------------------------------------------------------------------------------------------
Costs Domestic climate benefits Net benefits associated
------------------------------------------------------ with the targeted
pollutant (CO2)
3% 7% 3% 7% -------------------------
3% 7%
----------------------------------------------------------------------------------------------------------------
Present Value
----------------------------------------------------------------------------------------------------------------
2% HRI at $50/kW................ 4.8 2.8 0.8 0.1 (4.1) (2.8)
4.5% HRI at $50/kW.............. (1.2) (0.6) 0.7 0.1 2.0 0.7
4.5% HRI at $100/kW............. 8.2 4.8 1.6 0.2 (6.6) (4.7)
----------------------------------------------------------------------------------------------------------------
Equivalent Annualized Value
----------------------------------------------------------------------------------------------------------------
2% HRI at $50/kW................ 0.4 0.3 0.1 0.0 (0.3) (0.3)
4.5% HRI at $50/kW.............. (0.1) (0.1) 0.1 0.0 0.2 0.1
4.5% HRI at $100/kW............. 0.7 0.5 0.1 0.0 (0.6) (0.5)
----------------------------------------------------------------------------------------------------------------
Notes: Negative costs indicate avoided costs, negative benefits indicate forgone benefits, and negative net
benefits indicate forgone net benefits. All estimates are rounded to one decimal point, so figures may not sum
due to independent rounding. Climate benefits reflect the value of domestic impacts from CO2 emissions
changes. This table does not include estimates of ancillary health co-benefits from changes in electricity
sector SO2 and NOX emissions.
Table 18 and Table 19 provide the estimated costs, benefits, and net
benefits, inclusive of the ancillary health-co benefits and relative to
the base case (CPP). Table 18 presents the PV and EAV estimates, and
Table 19 presents the estimates for the specific years of 2025, 2030,
and 2035.
Table 18--Present Value and Equivalent Annualized Value of Compliance Costs, Total Benefits, and Net Benefits, Relative to Base Case (CPP), 3 and 7 Percent Discount Rates, 2023-2037
[Billions of 2016$]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Costs Benefits Net benefits
------------------------------------------------------------------------------------------------------------------------------------------------------------
3% 7% 3% 7% 3% 7%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Present Value
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
No CPP............................. (5.2) (3.1) (37.2) to (81.5)............... (17.9) to (41.3)............... (32.0) to (76.3).............. (14.8) to (38.2)
2% HRI at $50/kW................... (0.4) (0.3) (32.7) to (72.4)............... (15.9) to (36.9)............... (32.3) to (72.0).............. (15.7) to (36.7)
4.5% HRI at $50/kW................. (6.4) (3.7) (34.3) to (75.2)............... (16.6) to (39.4)............... (27.9) to (68.8).............. (12.8) to (35.6)
4.5% HRI at $100/kW................ 3.0 1.7 (27.2) to (60.2)............... (13.9) to (31.9)............... (30.2) to (63.2).............. (15.6) to (33.7)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Equivalent Annualized Value
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
No CPP............................. (0.4) (0.3) (3.1) to (6.8)................. (2.0) to (4.5)................. (2.7) to (6.4)................ (1.6) to (4.2)
2% HRI at $50/kW................... (0.0) (0.0) (2.7) to (6.1)................. (1.7) to (4.1)................. (2.7) to (6.0)................ (1.7) to (4.0)
4.5% HRI at $50/kW................. (0.5) (0.4) (2.9) to (6.3)................. (1.8) to (4.3)................. (2.3) to (5.8)................ (1.4) to (3.9)
4.5% HRI at $100/kW................ 0.3 0.2 (2.3) to (5.0)................. (1.5) to (3.5)................. (2.5) to (5.3)................ (1.7) to (3.7)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: Negative costs indicate avoided costs, negative benefits indicate forgone benefits, and negative net benefits indicate forgone net benefits. All estimates are rounded to one decimal
point, so figures may not sum due to independent rounding. Total benefits include both climate benefits and ancillary health co-benefits. Climate benefits reflect the value of domestic
impacts from CO2 emissions changes. The ancillary health co-benefits reflect the sum of the PM2.5 and ozone benefits from changes in electricity sector SO2, NOX and PM2.5 emissions and
reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Smith et al. (2009) to Lepeule et al. (2012) with Jerrett et al. (2009)). PM premature mortality
benefits estimated using a log-linear no-threshold model.
[[Page 44795]]
Table 19--Compliance Costs, Total Benefits, and Net Benefits, Relative to Base Case (CPP), 3 and 7 Percent Discount Rates, 2025, 2030, and 2035
[Billions of 2016$]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Costs Benefits Net benefits
------------------------------------------------------------------------------------------------------------------------------------------------------------
3% 7% 3% 7% 3% 7%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
No CPP
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2025............................... (0.7) (0.7) (3.2) to (7.0)................. (2.7) to (6.1)................. (2.4) to (6.2)................ (1.9) to (5.4)
2030............................... (0.7) (0.7) (5.4) to (11.9)................ (4.6) to (10.6)................ (4.7) to (11.2)............... (3.8) to (9.8)
2035............................... (0.4) (0.4) (4.3) to (9.3)................. (3.6) to (8.2)................. (3.9) to (8.9)................ (3.2) to (7.8)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2% HRI at $50/kW
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2025............................... 0.0 0.0 (2.8) to (6.2)................. (2.4) to (5.5)................. (2.8) to (6.2)................ (2.4) to (5.5)
2030............................... (0.2) (0.2) (4.9) to (11.0)................ (4.2) to (9.9)................. (4.7) to (10.8)............... (3.9) to (9.7)
2035............................... 0.1 0.1 (3.4) to (7.4)................. (2.8) to (6.6)................. (3.5) to (7.6)................ (3.0) to (6.7)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
4.5% HRI at $50/kW
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2025............................... (0.6) (0.6) (2.9) to (6.4)................. (2.5) to (5.7)................. (2.3) to (5.8)................ (1.9) to (5.1)
2030............................... (1.0) (1.0) (4.6) to (10.2)................ (3.9) to (9.1)................. (3.7) to (9.2)................ (3.0) to (8.1)
2035............................... (0.6) (0.6) (4.4) to (9.8)................. (3.7) to (8.7)................. (3.8) to (9.2)................ (3.1) to (8.1)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
4.5% HRI at $100/kW
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2025............................... 0.5 0.5 (2.3) to (5.0)................. (2.0) to (4.4)................. (2.8) to (5.5)................ (2.5) to (5.0)
2030............................... 0.2 0.2 (3.9) to (8.6)................. (3.3) to (7.6)................. (4.1) to (8.7)................ (3.5) to (7.8)
2035............................... 0.5 0.5 (2.9) to (6.3)................. (2.4) to (5.6)................. (3.4) to (6.8)................ (2.9) to (6.0)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: Negative costs indicate avoided costs, negative benefits indicate forgone benefits, and negative net benefits indicate forgone net benefits. All estimates are rounded to one decimal
point, so figures may not sum due to independent rounding. Total benefits include both climate benefits and ancillary health co-benefits. Climate benefits reflect the value of domestic
impacts from CO2 emissions changes. The ancillary health co-benefits reflect the sum of the PM2.5 and ozone benefits from changes in electricity sector SO2, NOX and PM2.5 emissions and
reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Smith et al. (2009) to Lepeule et al. (2012) with Zanobetti & Schwartz. (2008)). PM premature
mortality benefits estimated using a log-linear no-threshold model.
Table 20 provides the estimated costs, benefits, and net benefits,
inclusive of the ancillary health-co benefits and relative to the No
CPP alternative baseline.
Table 20--Present Value and Equivalent Annualized Value of Compliance Costs, Total Benefits, and Net Benefits, Relative to the No CPP Alternative Baseline, 3 and 7 Percent Discount Rates, 2023-
2037
[Billions of 2016$]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Costs Benefits Net benefits
------------------------------------------------------------------------------------------------------------------------------------------------------------
3% 7% 3% 7% 3% 7%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Present Value
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2% HRI at $50/kW................... 4.8 2.8 4.5 to 9.2..................... 2.0 to 4.3..................... (0.3) to 4.3.................. (0.9) to 1.5
4.5% HRI at $50/kW................. (1.2) (0.6) 2.9 to 6.3..................... 1.4 to 1.9..................... 4.1 to 7.5.................... 2.0 to 2.6
4.5% HRI at $100/kW................ 8.2 4.8 10.0 to 21.3................... 4.1 to 9.4..................... 1.8 to 13.2................... (0.8) to 4.5
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Equivalent Annualized Value
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2% HRI at $50/kW................... 0.4 0.3 0.4 to 0.8..................... 0.2 to 0.5..................... (0.0) to 0.4.................. (0.1) to 0.2
4.5% HRI at $50/kW................. (0.1) (0.1) 0.2 to 0.5..................... 0.1 to 0.2..................... 0.3 to 0.6.................... 0.2 to 0.3
4.5% HRI at $100/kW................ 0.7 0.5 0.8 to 1.8..................... 0.4 to 1.0..................... 0.1 to 1.1.................... (0.1) to 0.5
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: Negative costs indicate avoided costs, negative benefits indicate forgone benefits, and negative net benefits indicate forgone net benefits. All estimates are rounded to one decimal
point, so figures may not sum due to independent rounding. Total benefits include both climate benefits and ancillary health co-benefits. Climate benefits reflect the value of domestic
impacts from CO2 emissions changes. The ancillary health co-benefits reflect the sum of the PM2.5 and ozone benefits from changes in electricity sector SO2, NOX and PM2.5 emissions and
reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Smith et al. (2009) to Lepeule et al. (2012) with Jerrett et al. (2009)). PM premature mortality
benefits estimated using a log-linear no-threshold model.
Throughout the RIA for this proposed rulemaking, EPA examines a
number of sources of uncertainty, both quantitatively and
qualitatively, on benefits and costs. Some of these elements are
evaluated using probabilistic techniques. For other elements, where the
underlying likelihoods of certain outcomes are unknown, we use scenario
analysis to evaluate their potential effect on the benefits and costs
of this proposed
[[Page 44796]]
rulemaking. We summarize key elements of our analysis of uncertainty
here:
The extent to which all coal-fired EGUs will improve heat
rates under this proposal, on average;
The cost to improve heat rates at all affected coal-fired
EGUs nationally;
Uncertainty in monetizing climate-related benefits; and,
Uncertainty in the estimated health impacts attributable
to changes in particulate matter.
In the RIA for this proposed rulemaking, EPA also summarize other
potential sources of benefits and costs that may result from this
proposed rule that have not been quantified or monetized.
B. Executive Order 13771: Reducing Regulation and Controlling
Regulatory Costs
This action is expected to be an Executive Order 13771 deregulatory
action. Details on the estimated cost savings of this proposed rule can
be found in the rule's RIA.
C. Paperwork Reduction Act (PRA)
The information collection activities in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the PRA. The Information Collection Request (ICR) document
that EPA prepared has been assigned EPA ICR number 2503.03. You can
find a copy of the ICR in the docket for this rule, and it is briefly
summarized here.
The information collection requirements are based on the
recordkeeping and reporting burden associated with developing,
implementing, and enforcing a state plan to limit CO2
emissions from existing sources in the power sector. These
recordkeeping and reporting requirements are specifically authorized by
CAA section 114 (42 U.S.C. 7414). All information submitted to EPA
pursuant to the recordkeeping and reporting requirements for which a
claim of confidentiality is made is safeguarded according to Agency
policies set forth in 40 CFR part 2, subpart Ba.
Respondents/affected entities: 48.
Respondent's obligation to respond: EPA expects state plan
submissions from the 43 contiguous states and negative declarations
from Vermont, California, Maine, Idaho, and Rhode Island.
Frequency of response: Yearly.
Total estimated burden: 192,640 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $21,500 annualized capital or operation &
maintenance costs.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9.
Submit your comments on the Agency's need for this information, the
accuracy of the provided burden estimates and any suggested methods for
minimizing respondent burden to EPA using the docket identified at the
beginning of this rule (Comment C-72). You may also send your ICR-
related comments to OMB's Office of Information and Regulatory Affairs
via email to [email protected], Attention: Desk Officer for
EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after receipt, OMB must receive comments no
later than October 1, 2018. EPA will respond to any ICR-related
comments in the final rule.
D. Regulatory Flexibility Act (RFA)
After considering the economic impacts of this proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. The proposed
rule will not impose any requirements on small entities. Specifically,
emission guidelines established under CAA section 111(d) do not impose
any requirements on regulated entities and, thus, will not have a
significant economic impact upon a substantial number of small
entities. After emission guidelines are promulgated, states establish
emission standards on existing sources, and it is those state
requirements that could potentially impact small entities. Our analysis
in the accompanying RIA is consistent with the analysis of the
analogous situation arising when EPA establishes NAAQS, which do not
impose any requirements on regulated entities. As with the description
in the RIA, any impact of a NAAQS on small entities would only arise
when states take subsequent action to maintain and/or achieve the NAAQS
through their state implementation plans. See American Trucking Assoc.
v. EPA, 175 F.3d 1029, 1043-45 (D.C. Cir. 1999) (NAAQS do not have
significant impacts upon small entities because NAAQS themselves impose
no regulations upon small entities).
Nevertheless, EPA is aware that there is substantial interest in
the proposed rule among small entities (municipal and rural electric
cooperatives) and we invite comments on all aspects of the proposal and
its impacts, including potential impacts on small entities (Comment C-
73).
E. Unfunded Mandates Reform Act (UMRA)
This action does not contain a federal mandate that may result in
expenditures of $100 million or more for state, local and tribal
governments, in the aggregate or the private sector in any one year.
Specifically, the emission guidelines proposed under CAA section 111(d)
do not impose any direct compliance requirements on regulated entities,
apart from the requirement for states to develop state plans. The
burden for states to develop state plans in the three-year period
following promulgation of the rule was estimated and is listed in
Section IX.C above, but this burden is estimated to be below $100
million in any one year. Thus, this proposed rule is not subject to the
requirements of section 203 or section 205 of the Unfunded Mandates
Reform Act (UMRA).
This proposed rule is also not subject to the requirements of
section 203 of UMRA because, as described in 2 U.S.C. 1531-38, it
contains no regulatory requirements that might significantly or
uniquely affect small governments. This action imposes no enforceable
duty on any state, local, or tribal governments or the private sector.
F. Executive Order 13132: Federalism
Under Executive Order 13132, EPA may not issue an action that has
federalism implications, that imposes substantial direct compliance
costs and that is not required by statute unless the federal government
provides the funds necessary to pay the direct compliance costs
incurred by state and local governments, or EPA consults with state and
local officials early in the process of developing the proposed action.
EPA has concluded that this action may have federalism implications
because it might impose substantial direct compliance costs on state or
local governments, and the federal government will not provide the
funds necessary to pay those costs. The development of state plans will
entail many hours of staff time to develop and coordinate programs for
compliance with the proposed rule, as well as time to work with state
legislatures as appropriate, and develop a plan submittal.
In the spirit of Executive Order 13132, and consistent with EPA's
policy to promote communications between EPA and state and local
governments, EPA specifically solicits comment on this
[[Page 44797]]
proposed action from state and local officials (Comment C-74).
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 not impose substantial direct
compliance costs on tribal governments that have affected EGUs located
in their area of Indian country. Tribes are not required to develop
plans to implement the guidelines under CAA section 111(d) for affected
EGUs. EPA notes that this proposal does not directly impose specific
requirements on EGU sources, including those located in Indian country,
but before developing any standards for sources on tribal land, EPA
would consult with leaders from affected tribes. This proposed action
also will not have substantial direct effects on the relationship
between the federal government and Indian tribes or on the distribution
of power and responsibilities between the federal government and Indian
tribes, as specified in Executive Order 13175. Thus, Executive Order
13175 does not apply to the action.
Consistent with EPA Policy on Consultation and Coordination with
Indian Tribes, EPA will engage in consultation with tribal officials
during the development of this action.
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This proposed action is subject to Executive Order 13045 because it
is an economically significant regulatory action as defined by
Executive Order 12866. The CPP, as discussed in the RIA,\70\ was
anticipated to reduce emissions of PM2.5 and ozone, and some
of the benefits of reducing these pollutants would have accrued to
children. While the proposed ACE rule does not project to achieve
reductions at the level of the CPP, EPA believes that this proposal
will achieve CO2 emission reductions resulting from
implementation of these proposed guidelines, as well as ozone and
PM2.5 emission reductions as a co-benefit, and will further
improve children's health as discussed in the RIA.
---------------------------------------------------------------------------
\70\ See Chapter 5, ``Economic and Employment Impacts'', of the
RIA.
---------------------------------------------------------------------------
Moreover, this proposed action does not affect the level of public
health and environmental protection already being provided by existing
NAAQS, including ozone and PM2.5, and other mechanisms in
the CAA. This proposed action does not affect applicable local, state,
or federal permitting or air quality management programs that will
continue to address areas with degraded air quality and maintain the
air quality in areas meeting current standards. Areas that need to
reduce criteria air pollution to meet the NAAQS will still need to rely
on control strategies to reduce emissions.
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This proposed action, which is a significant regulatory energy
action under Executive Order 12866, is likely to have a significant
effect on the supply, distribution, or use of energy. Specifically, EPA
estimated in the RIA that the proposed rule could result in up to a 3
percent reduction in natural gas use in the power sector (or more than
a 25 MM MCF reduction in production on an annual basis).
The energy impacts EPA estimates from the proposed rule may be
under- or over-estimates of the true energy impacts associated with
this action. For example, some states are likely to pursue emissions
reduction strategies independent of EPA action.
J. National Technology Transfer and Advancement Act (NTTAA)
This proposed rulemaking does not involve technical standards. EPA
welcomes comments on this aspect of the proposed rulemaking and
specifically invites the public to identify potentially-applicable
voluntary consensus standards and to explain why such standards should
be used in this action (Comment C-75).
K. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
EPA believes that this proposed action is unlikely to have
disproportionately high and adverse human health or environmental
effects on minority populations, low-income populations and/or
indigenous peoples as specified in Executive Order 12898 (59 FR 7629,
February 16, 1994). The CPP, as discussed in the RIA,\71\ was
anticipated to reduce emissions of PM2.5 and ozone, and some
of the benefits of reducing these pollutants would have accrued to
minority populations, low-income populations and/or indigenous peoples.
While this proposal does not project to achieve reductions at the level
of the CPP, EPA believes that this proposal will achieve CO2
emission reductions resulting from implementation of these proposed
guidelines, as well as ozone and PM2.5 emission reductions
as a co-benefit, and will further improve children's health as
discussed in the RIA.
---------------------------------------------------------------------------
\71\ See Chapter 5, ``Economic and Employment Impacts,'' of the
RIA.
---------------------------------------------------------------------------
Moreover, this proposed action does not affect the level of public
health and environmental protection already being provided by existing
NAAQS, including ozone and PM2.5, and other mechanisms in
the CAA. This proposed action does not affect applicable local, state,
or federal permitting or air quality management programs that will
continue to address areas with degraded air quality and maintain the
air quality in areas meeting current standards. Areas that need to
reduce criteria air pollution to meet the NAAQS will still need to rely
on control strategies to reduce emissions.
XI. Statutory Authority
The statutory authority for this action is provided by sections
111, 301, and 307(d)(1)(V) of the CAA, as amended (42 U.S.C. 7411,
7601, 7607(d)(1)(V)). This action is also subject to section 307(d) of
the CAA (42 U.S.C. 7607(d)).
List of Subjects
40 CFR Part 51
Environmental protection, Intergovernmental relations, Reporting
and recordkeeping requirements.
40 CFR Part 52
Environmental protection, Air pollution control, Incorporation by
reference, Intergovernmental relations, Reporting and recordkeeping
requirements.
40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Incorporation by reference, Intergovernmental relations, Reporting and
recordkeeping requirements.
Dated: August 20, 2018.
Andrew R. Wheeler,
Acting Administrator.
For the reasons stated in the preamble, EPA proposes to amend 40
CFR parts 51, 52, and 60 as set forth below:
PART 51--REQUIREMENTS FOR PREPARATION, ADOPTION, AND SUBMITTAL OF
IMPLEMENTATION PLANS
0
1. The authority citation for part 51 continues to read as follows:
[[Page 44798]]
Authority: 23 U.S.C. 101; 42 U.S.C. 7401-7671q.
Subpart I--Review of New Sources and Modifications
0
2. Add Sec. 51.167 to read as follows:
Sec. 51.167 Preliminary major NSR applicability test for electric
generating units (EGUs).
(a) What is the purpose of this section? State Implementation Plans
(SIP) may incorporate the requirements in paragraphs (b) through (h) of
this section for determining whether a change to an electric generating
unit (EGU), as defined in Sec. 51.124(q), is a modification for
purposes of major NSR applicability. Deviations from these provisions
will be approved only if the State demonstrates that the submitted
provisions are at least as stringent in all respects as the
corresponding provisions in paragraphs (b) through (h) of this section.
(b) Am I subject to this section? You must meet the requirements of
this section if your State incorporates these provisions in its SIP,
and you own or operate an EGU that is located at a major stationary
source, and you plan to make a change to the EGU.
(c) What happens if a change to my EGU is determined to be a
modification according to the procedures of this section? If the change
to your EGU is a modification according to the procedures of this
section, you must determine whether the change is a major modification
according to the procedures of the major NSR program that applies in
the area in which your EGU is located. That is, you must evaluate your
modification according to the requirements set out in the applicable
regulations approved pursuant to Sec. 51.165 or Sec. 51.166 depending
on the regulated NSR pollutants emitted and the attainment status of
the area in which your EGU is located for those pollutants. Section
51.165 sets out the requirements for State nonattainment major NSR
programs, while Sec. 51.166 sets out the requirements for State PSD
programs.
(d) What is the process for determining if a change to an EGU is a
modification? The two-step process set out in paragraphs (d)(1) and (2)
of this section is used to determine (before beginning actual
construction) whether a change to an EGU located at a major stationary
source is a modification. Regardless of any preconstruction
projections, a modification has occurred if a change satisfies both
steps in the process.
(1) Step 1. Is the change a physical change in, or change in the
method of operation of, the EGU? (See paragraph (e) of this section for
a list of actions that are not physical or operational changes.) If so,
go on to Step 2 (paragraph (d)(2) of this section).
(2) Step 2. Will the physical or operational change to the EGU
increase the amount of any regulated NSR pollutant emitted into the
atmosphere by the source (as determined according to paragraph (f) of
this section) or result in the emissions of any regulated NSR
pollutant(s) into the atmosphere that the source did not previously
emit? If so, the change is a modification.
(e) What types of actions are not physical changes or changes in
the method of operation? (Step 1) For purposes of this section, a
physical change or change in the method of operation shall not include:
(1) Routine maintenance, repair, and replacement;
(2) Use of an alternative fuel or raw material by reason of an
order under sections 2(a) and (b) of the Energy Supply and
Environmental Coordination Act of 1974 (or any superseding legislation)
or by reason of a natural gas curtailment plan pursuant to the Federal
Power Act;
(3) Use of an alternative fuel by reason of an order or rule under
section 125 of the Act;
(4) Use of an alternative fuel at a steam generating unit to the
extent that the fuel is generated from municipal solid waste;
(5) Use of an alternative fuel or raw material by a stationary
source which the source is approved to use under any permit issued
under 40 CFR 52.21 or under regulations approved pursuant to Sec.
51.165 or Sec. 51.166, or which:
(i) For purposes of evaluating attainment pollutants, the source
was capable of accommodating before January 6, 1975, unless such change
would be prohibited under any federally enforceable permit condition
which was established after January 6, 1975 pursuant to 40 CFR 52.21 or
under regulations approved pursuant to subpart I of this part; or
(ii) For purposes of evaluating nonattainment pollutants, the
source was capable of accommodating before December 21, 1976, unless
such change would be prohibited under any federally enforceable permit
condition which was established after December 21, 1976 pursuant to 40
CFR 52.21 or under regulations approved pursuant to subpart I of this
part;
(6) An increase in the hours of operation or in the production
rate, unless such change is prohibited under any federally enforceable
permit condition which was established after January 6, 1975 (for
purposes of evaluating attainment pollutants) or after December 21,
1976 (for purposes of evaluating nonattainment pollutants) pursuant to
40 CFR 52.21 or regulations approved pursuant to subpart I of this
part;
(7) Any change in ownership at a stationary source;
(8) The installation, operation, cessation, or removal of a
temporary clean coal technology demonstration project, provided that
the project complies with:
(i) The State Implementation Plan for the State in which the
project is located; and
(ii) Other requirements necessary to attain and maintain the
national ambient air quality standard during the project and after it
is terminated;
(9) For purposes of evaluating attainment pollutants, the
installation or operation of a permanent clean coal technology
demonstration project that constitutes repowering, provided that the
project does not result in an increase in the potential to emit of any
regulated pollutant emitted by the unit. This exemption shall apply on
a pollutant-by-pollutant basis; or
(10) For purposes of evaluating attainment pollutants, the
reactivation of a very clean coal-fired EGU.
(f) How do I determine if there is an emissions increase? (Step 2)
You must determine if the physical or operational change to your EGU
increases the amount of any regulated NSR pollutant emitted to the
atmosphere using the method in paragraph (f)(1) of this section,
subject to the limitations in paragraph (f)(2) of this section. If the
physical or operational change to your EGU increases the amount of any
regulated NSR pollutant emitted into the atmosphere or results in the
emission of any regulated NSR pollutant(s) into the atmosphere that
your EGU did not previously emit, the change is a modification as
defined in paragraph (h)(2) of this section.
Alternative 1 for paragraph (f)(1):
(1) Emissions increase test. For each regulated NSR pollutant for
which you have hourly average CEMS or PEMS emissions data with
corresponding fuel heat input data, compare the pre-change maximum
actual hourly emissions rate in pounds per hour (lb/hr) to a projection
of the post-change maximum actual hourly emissions rate in lb/hr,
subject to the provisions in paragraphs (f)(1)(i) through (iii) of this
section.
(i) Pre-change emissions. Determine the pre-change maximum actual
hourly emissions rate as follows:
(A) Select a period of 365 consecutive days within the 5-year
period
[[Page 44799]]
immediately preceding when you begin actual construction of the
physical or operational change. Compile a data set (for example, in a
spreadsheet) with the hourly average CEMS or PEMS (as applicable)
measured emissions rates and corresponding heat input data for all of
the hours of operation for that 365-day period for the pollutant of
interest.
(B) Delete any unacceptable hourly data from this 365-day period in
accordance with the data limitations in paragraph (f)(2) of this
section.
(C) Extract the hourly data for the 10 percent of the remaining
data set corresponding to the highest heat input rates for the selected
period. This step may be facilitated by sorting the data set for the
remaining operating hours from the lowest to the highest heat input
rates.
(D) Calculate the average emissions rate from the extracted (i.e.,
highest 10 percent heat input rates) data set, using Equation 1:
[GRAPHIC] [TIFF OMITTED] TP31AU18.004
Where:
x = average emissions rate, lb/hr;
n = number of emissions rate values; and
xi = ith emissions rate value, lb/hr.
(E) Calculate the standard deviation of the data set using Equation
2:
[GRAPHIC] [TIFF OMITTED] TP31AU18.005
Where:
s = standard deviation of the data set.
(F) Calculate the Upper Tolerance Limit of the data set using
Equation 3:
[GRAPHIC] [TIFF OMITTED] TP31AU18.006
Where:
UTL = Upper Tolerance Limit of the data set;
Z1-p = 3.090, Z score for the 99.9 percentage of
interval; and
Z1-q = 2.326, Z score for the 99 percent confidence
level.
(G) Use the UTL calculated in paragraph (f)(1)(i)(F) of this
section as the pre-change maximum actual hourly emissions rate.
(ii) Post-change emissions--preconstruction projections. For each
regulated NSR pollutant, you must project the maximum emissions rate
that your EGU will actually achieve in any 1 hour in the 5 years
following the date the EGU resumes regular operation after the physical
or operational change. An emissions increase results from the physical
or operational change if this projected maximum actual hourly emissions
rate exceeds the pre-change maximum actual hourly emissions rate.
(iii) Post-change emissions-actually achieved. Regardless of any
preconstruction projections, an emissions increase has occurred if the
hourly emissions rate actually achieved in the 5 years after the change
exceeds the pre-change maximum actual hourly emissions rate.
Alternative 2 for paragraph (f)(1):
(1) Emissions increase test. For each regulated NSR pollutant,
compare the pre-change maximum actual hourly emissions rate in pounds
per hour (lb/hr) to a projection of the post-change maximum actual
hourly emissions rate in lb/hr, subject to the provisions in paragraphs
(f)(1)(i) through (iv) of this section.
(i) Pre-change emissions--general procedures. The pre-change
maximum actual hourly emissions rate for the pollutant is the highest
emissions rate (lb/hr) actually achieved by the EGU for 1 hour at any
time during the 5-year period immediately preceding when you begin
actual construction of the physical or operational change.
(ii) Pre-change emissions--data sources. You must determine the
highest pre-change hourly emissions rate for each regulated NSR
pollutant using the best data available to you. Use the highest
available source of data in the following hierarchy, unless your
reviewing authority has determined that a data source lower in the
hierarchy will provide better data for your EGU:
(A) Continuous emissions monitoring system (CEMS).
[[Page 44800]]
(B) Approved predictive emissions monitoring system (PEMS).
(C) Emission tests/emission factor specific to the EGU to be
changed.
(D) Material balance calculations.
(E) Published emission factor.
(iii) Post-change emissions--preconstruction projections. For each
regulated NSR pollutant, you must project the maximum emissions rate
that your EGU will actually achieve in any 1 hour in the 5 years
following the date the EGU resumes regular operation after the physical
or operational change. An emissions increase results from the physical
or operational change if this projected maximum actual hourly emissions
rate exceeds the pre-change maximum actual hourly emissions rate.
(iv) Post-change emissions--actually achieved. Regardless of any
preconstruction projections, an emissions increase has occurred if the
hourly emissions rate actually achieved in the 5 years after the change
exceeds the pre-change maximum actual hourly emissions rate.
Alternative 3 for paragraph (f)(1):
(1) Emissions increase test. For each regulated NSR pollutant,
compare the maximum achievable hourly emissions rate before the
physical or operational change to the maximum achievable hourly
emissions rate after the change. Determine these maximum achievable
hourly emissions rates according to Sec. [thinsp]60.14(b) of this
chapter. No physical change, or change in the method of operation, at
an existing EGU shall be treated as a modification for the purposes of
this section provided that such change does not increase the maximum
hourly emissions of any regulated NSR pollutant above the maximum
hourly emissions achievable at that unit during the 5 years prior to
the change.
(2) Data limitations for maximum emissions rates. For purposes of
determining pre-change and post-change maximum emissions rates under
paragraph (f)(1) of this section, the following limitations apply to
the types of data that you may use:
(i) Data limitations for Alternatives 1-2. (A) You must not use
emissions rate data associated with startups, shutdowns, or
malfunctions of your EGU, as defined by applicable regulation(s) or
permit term(s), or malfunctions of an associated air pollution control
device. A malfunction means any sudden, infrequent, and not reasonably
preventable failure of the EGU or the air pollution control equipment
to operate in a normal or usual manner.
(B) You must not use continuous emissions monitoring system (CEMS)
or predictive emissions monitoring system (PEMS) data recorded during
monitoring system out-of-control periods. Out-of-control periods
include those during which the monitoring system fails to meet quality
assurance criteria (for example, periods of system breakdown, repair,
calibration checks, or zero and span adjustments) established by
regulation, by permit, or in an approved quality assurance plan.
(C) You must not use emissions rate data from periods of
noncompliance when your EGU was operating above an emission limitation
that was legally enforceable at the time the data were collected.
(D) You must not use data from any period for which the information
is inadequate for determining emissions rates, including information
related to the limitations in paragraphs (f)(2)(i)(A) through (C) of
this section.
(ii) Data limitations for Alternative 3. (A) You must not use
emissions rate data associated with startups, shutdowns, or
malfunctions of your EGU, as defined by applicable regulation(s) or
permit term(s), or malfunctions of an associated air pollution control
device. A malfunction means any sudden, infrequent, and not reasonably
preventable failure of the EGU or the air pollution control equipment
to operate in a normal or usual manner.
(B) You must not use continuous emissions monitoring system (CEMS)
or predictive emissions monitoring system (PEMS) data recorded during
monitoring system out-of-control periods. Out-of-control periods
include those during which the monitoring system fails to meet quality
assurance criteria (for example, periods of system breakdown, repair,
calibration checks, or zero and span adjustments) established by
regulation, by permit, or in an approved quality assurance plan.
(C) You must not use data from any period for which the information
is inadequate for determining emissions rates, including information
related to the limitations in paragraphs (f)(2)(ii)(A) and (B) of this
section.
(g) What are my requirements for recordkeeping? You must maintain a
file of all information related to determinations that you make under
this section of whether a change to an EGU is a modification, subject
to the following provisions:
(1) The file must include, but is not limited to, the following
information recorded in permanent form suitable for inspection:
(i) Continuous monitoring system, monitoring device, and
performance testing measurements;
(ii) All continuous monitoring system performance evaluations;
(iii) All continuous monitoring system or monitoring device
calibration checks;
(iv) All adjustments and maintenance performed on these systems or
devices; and
(v) All other information relevant to any determination made under
this section of whether a change to an EGU is a modification.
(2) You must retain the file until the later of:
(i) The date 5 years following the date the EGU resumes regular
operation after the physical or operational change; and
(ii) The date 5 years following the date of such measurements,
maintenance, reports, and records.
(h) What definitions apply under this section? The definitions of
terms in Sec. 51.124(q) apply. Terms used in this section have the
meaning accorded them under Sec. 51.165(a)(1) or Sec. 51.166(b), as
appropriate. Terms not defined here or in Sec. 51.165(a)(1) or Sec.
51.166(b) (as appropriate) have the meaning accorded them under the
applicable requirements of the Clean Air Act.
PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS
0
3. The authority citation for part 52 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart A--General Provisions
0
4. Add Sec. 52.25 to read as follows:
Sec. 52.25 Preliminary major NSR applicability test for electric
generating units (EGUs).
(a) What is the purpose of this section? The provisions of this
section are applicable to any State implementation plan which has been
disapproved with respect to prevention of significant deterioration of
air quality in any portion of any State where the existing air quality
is better than the national ambient air quality standards. Specific
disapprovals are listed where applicable, in subparts B through DDD and
FFF of this part. The provisions of this section have been incorporated
by reference into the applicable implementation plans for various
States, as provided in subparts B through DDD and FFF of this part.
Where this section is so incorporated, the provisions shall also be
applicable to all lands owned by the Federal Government and Indian
Reservations located in such State. No disapproval with respect to a
State's failure to prevent significant deterioration of air quality
shall invalidate or otherwise affect the
[[Page 44801]]
obligations of States, emission sources, or other persons with respect
to all portions of plans approved or promulgated under this part.
(b) Am I subject to this section? You must meet the requirements of
this section if you own or operate an EGU that is located at a major
stationary source, and you plan to make a change to the EGU.
(c) What happens if a change to my EGU is determined to be a
modification according to the procedures of this section? If the change
to your electric generating unit (EGU), as defined in Sec. 51.124(q)
of this chapter, is a modification according to the procedures of this
section, you must determine whether the change is a major modification
according to the procedures of the major NSR program that applies in
the area in which your EGU is located. That is, you must evaluate your
modification according to the requirements set out in the applicable
regulations approved pursuant to Sec. 52.21.
(d) What is the process for determining if a change to an EGU is a
modification? The two-step process set out in paragraphs (d)(1) and (2)
of this section is used to determine (before beginning actual
construction) whether a change to an EGU located at a major stationary
source is a modification. Regardless of any preconstruction
projections, a modification has occurred if a change satisfies both
steps in the process.
(1) Step 1. Is the change a physical change in, or change in the
method of operation of, the EGU? (See paragraph (e) of this section for
a list of actions that are not physical or operational changes.) If so,
go on to Step 2 (paragraph (d)(2) of this section).
(2) Step 2. Will the physical or operational change to the EGU
increase the amount of any regulated NSR pollutant emitted into the
atmosphere by the source (as determined according to paragraph (f) of
this section) or result in the emissions of any regulated NSR
pollutant(s) into the atmosphere that the source did not previously
emit? If so, the change is a modification.
(e) What types of actions are not physical changes or changes in
the method of operation? (Step 1) For purposes of this section, a
physical change or change in the method of operation shall not include:
(1) Routine maintenance, repair, and replacement;
(2) Use of an alternative fuel or raw material by reason of an
order under sections 2(a) and (b) of the Energy Supply and
Environmental Coordination Act of 1974 (or any superseding legislation)
or by reason of a natural gas curtailment plan pursuant to the Federal
Power Act;
(3) Use of an alternative fuel by reason of an order or rule under
section 125 of the Act;
(4) Use of an alternative fuel at a steam generating unit to the
extent that the fuel is generated from municipal solid waste;
(5) Use of an alternative fuel or raw material by a stationary
source which the source is approved to use under any permit issued
under 40 CFR 52.21 or under regulations approved pursuant to Sec.
51.166 of this chapter, or which the source was capable of
accommodating before January 6, 1975, unless such change would be
prohibited under any federally enforceable permit condition which was
established after January 6, 1975 pursuant to 40 CFR 52.21 or under
regulations approved pursuant to 40 CFR part 51, subpart I; or
(6) An increase in the hours of operation or in the production
rate, unless such change is prohibited under any federally enforceable
permit condition which was established after January 6, 1975 pursuant
to 40 CFR 52.21 or regulations approved pursuant to 40 CFR part 51,
subpart I;
(7) Any change in ownership at a stationary source;
(8) The installation, operation, cessation, or removal of a
temporary clean coal technology demonstration project, provided that
the project complies with:
(i) The State Implementation Plan for the State in which the
project is located; and
(ii) Other requirements necessary to attain and maintain the
national ambient air quality standard during the project and after it
is terminated;
(9) For purposes of evaluating attainment pollutants, the
installation or operation of a permanent clean coal technology
demonstration project that constitutes repowering, provided that the
project does not result in an increase in the potential to emit of any
regulated pollutant emitted by the unit. This exemption shall apply on
a pollutant-by-pollutant basis; or
(10) For purposes of evaluating attainment pollutants, the
reactivation of a very clean coal-fired EGU.
(f) How do I determine if there is an emissions increase? (Step 2)
You must determine if the physical or operational change to your EGU
increases the amount of any regulated NSR pollutant emitted to the
atmosphere using the method in paragraph (f)(1) of this section,
subject to the limitations in paragraph (f)(2) of this section. If the
physical or operational change to your EGU increases the amount of any
regulated NSR pollutant emitted into the atmosphere or results in the
emission of any regulated NSR pollutant(s) into the atmosphere that
your EGU did not previously emit, the change is a modification as
defined in paragraph (h)(2) of this section.
Alternative 1 for paragraph (f)(1):
(1) Emissions increase test. For each regulated NSR pollutant for
which you have hourly average CEMS or PEMS emissions data with
corresponding fuel heat input data, compare the pre-change maximum
actual hourly emissions rate in pounds per hour (lb/hr) to a projection
of the post-change maximum actual hourly emissions rate in lb/hr,
subject to the provisions in paragraphs (f)(1)(i) through (iii) of this
section.
(i) Pre-change emissions. Determine the pre-change maximum actual
hourly emissions rate as follows:
(A) Select a period of 365 consecutive days within the 5-year
period immediately preceding when you begin actual construction of the
physical or operational change. Compile a data set (for example, in a
spreadsheet) with the hourly average CEMS or PEMS (as applicable)
measured emissions rates and corresponding heat input data for all of
the hours of operation for that 365-day period for the pollutant of
interest.
(B) Delete any unacceptable hourly data from this 365-day period in
accordance with the data limitations in paragraph (f)(2) of this
section.
(C) Extract the hourly data for the 10 percent of the remaining
data set corresponding to the highest heat input rates for the selected
period. This step may be facilitated by sorting the data set for the
remaining operating hours from the lowest to the highest heat input
rates.
(D) Calculate the average emissions rate from the extracted (i.e.,
highest 10 percent heat input rates) data set, using Equation 1:
[[Page 44802]]
[GRAPHIC] [TIFF OMITTED] TP31AU18.007
Where:
x = average emissions rate, lb/hr;
n = number of emissions rate values; and
xi = ith emissions rate value, lb/hr.
(E) Calculate the standard deviation of the data set using Equation
2:
[GRAPHIC] [TIFF OMITTED] TP31AU18.008
Where:
s = standard deviation of the data set.
(F) Calculate the Upper Tolerance Limit of the data set using
Equation 3:
[GRAPHIC] [TIFF OMITTED] TP31AU18.009
Where:
UTL = Upper Tolerance Limit of the data set;
Z1-p = 3.090, Z score for the 99.9 percentage of
interval; and
Z1-q = 2.326, Z score for the 99 percent confidence
level.
(G) Use the UTL calculated in paragraph (f)(1)(i)(F) of this
section as the pre-change maximum actual hourly emissions rate.
(ii) Post-change emissions--preconstruction projections. For each
regulated NSR pollutant, you must project the maximum emissions rate
that your EGU will actually achieve in any 1 hour in the 5 years
following the date the EGU resumes regular operation after the physical
or operational change. An emissions increase results from the physical
or operational change if this projected maximum actual hourly emissions
rate exceeds the pre-change maximum actual hourly emissions rate.
(iii) Post-change emissions--actually achieved. Regardless of any
preconstruction projections, an emissions increase has occurred if the
hourly emissions rate actually achieved in the 5 years after the change
exceeds the pre-change maximum actual hourly emissions rate.
Alternative 2 for paragraph (f)(1):
(1) Emissions increase test. For each regulated NSR pollutant,
compare the pre-change maximum actual hourly emissions rate in pounds
per hour (lb/hr) to a projection of the post-change maximum actual
hourly emissions rate in lb/hr, subject to the provisions in paragraphs
(f)(1)(i) through (iv) of this section.
(i) Pre-change emissions--general procedures. The pre-change
maximum actual hourly emissions rate for the pollutant is the highest
emissions rate (lb/hr) actually achieved by the EGU for 1 hour at any
time during the 5-year period immediately preceding when you begin
actual construction of the physical or operational change.
(ii) Pre-change emissions--data sources. You must determine the
highest pre-change hourly emissions rate for each regulated NSR
pollutant using the best data available to you. Use the highest
available source of data in the following hierarchy, unless your
reviewing authority has determined that a data source lower in the
hierarchy will provide better data for your EGU:
(A) Continuous emissions monitoring system (CEMS).
(B) Approved predictive emissions monitoring system (PEMS).
(C) Emission tests/emission factor specific to the EGU to be
changed.
(D) Material balance calculations.
(E) Published emission factor.
(iii) Post-change emissions--preconstruction projections. For each
regulated NSR pollutant, you must project the maximum emissions rate
that your EGU will actually achieve in any 1 hour in the 5 years
following the date the EGU resumes regular operation after the physical
or operational change. An emissions increase results from the physical
or operational change if this projected maximum actual hourly emissions
rate exceeds the pre-change maximum actual hourly emissions rate.
(iv) Post-change emissions--actually achieved. Regardless of any
preconstruction projections, an emissions increase has occurred if the
hourly emissions rate actually achieved in the 5 years after the change
exceeds the pre-change maximum actual hourly emissions rate.
Alternative 3 for paragraph (f)(1):
(1) Emissions increase test. For each regulated NSR pollutant,
compare the maximum achievable hourly emissions rate before the
physical or operational change to the maximum achievable hourly
emissions rate after the change. Determine these maximum achievable
[[Page 44803]]
hourly emissions rates according to Sec. [thinsp]60.14(b) of this
chapter. No physical change, or change in the method of operation, at
an existing EGU shall be treated as a modification for the purposes of
this section provided that such change does not increase the maximum
hourly emissions of any regulated NSR pollutant above the maximum
hourly emissions achievable at that unit during the 5 years prior to
the change.
(2) Data limitations for maximum emissions rates. For purposes of
determining pre-change and post-change maximum emissions rates under
paragraph (f)(1) of this section, the following limitations apply to
the types of data that you may use:
(i) Data limitations for Alternatives 1-2. (A) You must not use
emissions rate data associated with startups, shutdowns, or
malfunctions of your EGU, as defined by applicable regulation(s) or
permit term(s), or malfunctions of an associated air pollution control
device. A malfunction means any sudden, infrequent, and not reasonably
preventable failure of the EGU or the air pollution control equipment
to operate in a normal or usual manner.
(B) You must not use continuous emissions monitoring system (CEMS)
or predictive emissions monitoring system (PEMS) data recorded during
monitoring system out-of-control periods. Out-of-control periods
include those during which the monitoring system fails to meet quality
assurance criteria (for example, periods of system breakdown, repair,
calibration checks, or zero and span adjustments) established by
regulation, by permit, or in an approved quality assurance plan.
(C) You must not use emissions rate data from periods of
noncompliance when your EGU was operating above an emission limitation
that was legally enforceable at the time the data were collected.
(D) You must not use data from any period for which the information
is inadequate for determining emissions rates, including information
related to the limitations in paragraphs (f)(2)(i)(A) through (C) of
this section.
(ii) Data limitations for Alternative 3. (A) You must not use
emissions rate data associated with startups, shutdowns, or
malfunctions of your EGU, as defined by applicable regulation(s) or
permit term(s), or malfunctions of an associated air pollution control
device. A malfunction means any sudden, infrequent, and not reasonably
preventable failure of the EGU or the air pollution control equipment
to operate in a normal or usual manner.
(B) You must not use continuous emissions monitoring system (CEMS)
or predictive emissions monitoring system (PEMS) data recorded during
monitoring system out-of-control periods. Out-of-control periods
include those during which the monitoring system fails to meet quality
assurance criteria (for example, periods of system breakdown, repair,
calibration checks, or zero and span adjustments) established by
regulation, by permit, or in an approved quality assurance plan.
(C) You must not use data from any period for which the information
is inadequate for determining emissions rates, including information
related to the limitations in paragraphs (f)(2)(ii)(A) and (B) of this
section.
(g) What are my requirements for recordkeeping? You must maintain a
file of all information related to determinations that you make under
this section of whether a change to an EGU is a modification, subject
to the following provisions:
(1) The file must include, but is not limited to, the following
information recorded in permanent form suitable for inspection:
(i) Continuous monitoring system, monitoring device, and
performance testing measurements;
(ii) All continuous monitoring system performance evaluations;
(iii) All continuous monitoring system or monitoring device
calibration checks;
(iv) All adjustments and maintenance performed on these systems or
devices; and
(v) All other information relevant to any determination made under
this section of whether a change to an EGU is a modification.
(2) You must retain the file until the later of:
(i) The date 5 years following the date the EGU resumes regular
operation after the physical or operational change; and
(ii) The date 5 years following the date of such measurements,
maintenance, reports, and records.
(h) What definitions apply under this section? The definitions of
terms in Sec. 51.124(q) of this chapter apply. Terms used in this
section have the meaning accorded them under Sec. 52.21. Terms not
defined here or in Sec. 52.21 have the meaning accorded them under the
applicable requirements of the Clean Air Act.
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
0
5. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
0
6. Add subpart Ba to read as follows:
Subpart Ba--Adoption and Submittal of State Plans for Designated
Facilities
Sec.
60.20a Applicability.
60.21a Definitions.
60.22a Publication of emission guidelines.
60.23a Adoption and submittal of State plans; public hearings.
60.24a Standards of performance and compliance schedules.
60.25a Emission inventories, source surveillance, reports.
60.26a Legal authority.
60.27a Actions by the Administrator.
60.28a Plan revisions by the State.
60.29a Plan revisions by the Administrator.
Subpart Ba--Adoption and Submittal of State Plans for Designated
Facilities
Sec. 60.20a Applicability.
(a) The provisions of this subpart apply to States upon publication
of a final emission guideline under Sec. 60.22a(a), if such final
guideline is published after [date of publication of final rule in the
Federal Register].
(1) Each emission guideline promulgated under this part is subject
to the requirements of this subpart, except that each emission
guideline may include specific provisions in addition to or that
supersede requirements of this subpart. Each emission guideline must
identify explicitly any provision of this subpart that is superseded.
(2) Terms used throughout this part are defined in Sec. 60.21a or
in the Clean Air Act (Act) as amended in 1990, except that emission
guidelines promulgated as individual subparts of this part may include
specific definitions in addition to or that supersede definitions in
Sec. 60.21a.
(b) No standard of performance or other requirement established
under this part shall be interpreted, construed, or applied to diminish
or replace the requirements of a more stringent emission limitation or
other applicable requirement established by the Administrator pursuant
to other authority of the Act (section 112, Part C or D, or any other
authority of the Act), or a standard issued under State authority. The
Administrator may specify in a specific standard under this part that
facilities subject to other provisions under the Act need only comply
with the provisions of that standard.
Sec. 60.21a Definitions.
Terms used but not defined in this subpart shall have the meaning
given them in the Act and in subpart A:
(a) Designated pollutant means any air pollutant, the emissions of
which are
[[Page 44804]]
subject to a standard of performance for new stationary sources, but
for which air quality criteria have not been issued and that is not
included on a list published under section 108(a) or section 112(b) of
the Act.
(b) Designated facility means any existing facility (see Sec.
60.2a(aa)) which emits a designated pollutant and which would be
subject to a standard of performance for that pollutant if the existing
facility were an affected facility (see Sec. 60.2a(e)).
(c) Plan means a plan under section 111(d) of the Act which
establishes standards of performance for designated pollutants from
designated facilities and provides for the implementation and
enforcement of such standards of performance.
(d) Applicable plan means the plan, or most recent revision
thereof, which has been approved under Sec. 60.27a(b) or promulgated
under Sec. 60.27a(d).
(e) Emission guideline means a final guideline document published
under Sec. 60.22a(a), which includes information on the degree of
emission reduction achievable through the application of the best
system of emission reduction which (taking into account the cost of
such reduction and any nonair quality health and environmental impact
and energy requirements) the Administrator has determined has been
adequately demonstrated for designated facilities.
(f) Standard of performance means a standard for emissions of air
pollutants which reflects the degree of emission limitation achievable
through the application of the best system of emission reduction which
(taking into account the cost of achieving such reduction and any
nonair quality health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated,
including, but not limited to,a legally enforceable regulation setting
forth an allowable rate or limit of emissions into the atmosphere, or
prescribing a design, equipment, work practice, or operational
standard, or combination thereof.
(g) Compliance schedule means a legally enforceable schedule
specifying a date or dates by which a source or category of sources
must comply with specific standards of performance contained in a plan
or with any increments of progress to achieve such compliance.
(h) Increments of progress means steps to achieve compliance which
must be taken by an owner or operator of a designated facility,
including:
(1) Submittal of a final control plan for the designated facility
to the appropriate air pollution control agency;
(2) Awarding of contracts for emission control systems or for
process modifications, or issuance of orders for the purchase of
component parts to accomplish emission control or process modification;
(3) Initiation of on-site construction or installation of emission
control equipment or process change;
(4) Completion of on-site construction or installation of emission
control equipment or process change; and
(5) Final compliance.
(i) Region means an air quality control region designated under
section 107 of the Act and described in part 81 of this chapter.
(j) Local agency means any local governmental agency.
Sec. 60.22a Publication of emission guidelines.
(a) Concurrently upon or after proposal of standards of performance
for the control of a designated pollutant from affected facilities, the
Administrator will publish a draft emission guideline containing
information pertinent to control of the designated pollutant from
designated facilities. Notice of the availability of the draft emission
guideline will be published in the Federal Register and public comments
on its contents will be invited. After consideration of public
comments, a final emission guideline will be published and notice of
its availability will be published in the Federal Register.
(b) Emission guidelines published under this section will provide
information for the development of State plans, such as:
(1) A description of systems of emission reduction which, in the
judgment of the Administrator, have been adequately demonstrated.
(2) Information on the degree of emission reduction which is
achievable with each system, together with information on the costs,
nonair quality health environmental effects, and energy requirements of
applying each system to designated facilities.
(3) Incremental periods of time normally expected to be necessary
for the design, installation, and startup of identified control
systems.
(4) An emission guideline that reflects the application of the best
system of emission reduction (considering the cost of such achieving
reduction and any nonair quality health and environmental impact and
energy requirements) that has been adequately demonstrated for
designated facilities, and the time within which compliance with
standards of performance can be achieved. The Administrator may specify
different emission guidelines or compliance times or both for different
sizes, types, and classes of designated facilities when costs of
control, physical limitations, geographical location, or similar
factors make subcategorization appropriate.
(5) Such other available information as the Administrator
determines may contribute to the formulation of State plans.
Sec. 60.23a Adoption and submittal of State plans; public hearings.
(a)(1) Unless otherwise specified in the applicable subpart, within
three years after notice of the availability of a final emission
guideline is published under Sec. 60.22a(a), each State shall adopt
and submit to the Administrator, in accordance with Sec. 60.4, a plan
for the control of the designated pollutant to which the emission
guideline applies.
(2) At any time, each State may adopt and submit to the
Administrator any plan revision necessary to meet the requirements of
this subpart or an applicable subpart of this part.
(b) If no designated facility is located within a State, the State
shall submit a letter of certification to that effect to the
Administrator within the time specified in paragraph (a) of this
section. Such certification shall exempt the State from the
requirements of this subpart for that designated pollutant.
(c) The State shall, prior to the adoption of any plan or revision
thereof, conduct one or more public hearings within the State on such
plan or plan revision.
(d) Any hearing required by paragraph (c) of this section shall be
held only after reasonable notice. Notice shall be given at least 30
days prior to the date of such hearing and shall include:
(1) Notification to the public by prominently advertising the date,
time, and place of such hearing in each region affected. This
requirement may be satisfied by advertisement on the internet;
(2) Availability, at the time of public announcement, of each
proposed plan or revision thereof for public inspection in at least one
location in each region to which it will apply. This requirement may be
satisfied by posting each proposed plan or revision on the internet;
(3) Notification to the Administrator;
(4) Notification to each local air pollution control agency in each
region to which the plan or revision will apply; and
[[Page 44805]]
(5) In the case of an interstate region, notification to any other
State included in the region.
(e) The State may cancel the public hearing through a method it
identifies if no request for a public hearing is received during the 30
day notification period under subsection (d) and the original notice
announcing the 30 day notification period states that if no request for
a public hearing is received the hearing will be cancelled; identifies
the method and time for announcing that the hearing has been cancelled;
and provides a contact phone number for the public to call to find out
if the hearing has been cancelled.
(f) The State shall prepare and retain, for a minimum of 2 years, a
record of each hearing for inspection by any interested party. The
record shall contain, as a minimum, a list of witnesses together with
the text of each presentation.
(g) The State shall submit with the plan or revision:
(1) Certification that each hearing required by paragraph (c) of
this section was held in accordance with the notice required by
paragraph (d) of this section; and
(2) A list of witnesses and their organizational affiliations, if
any, appearing at the hearing and a brief written summary of each
presentation or written submission.
(h) Upon written application by a State agency (through the
appropriate Regional Office), the Administrator may approve State
procedures designed to insure public participation in the matters for
which hearings are required and public notification of the opportunity
to participate if, in the judgment of the Administrator, the
procedures, although different from the requirements of this subpart,
in fact provide for adequate notice to and participation of the public.
The Administrator may impose such conditions on his approval as he
deems necessary. Procedures approved under this section shall be deemed
to satisfy the requirements of this subpart regarding procedures for
public hearings.
Sec. 60.24a Standards of performance and compliance schedules.
(a) Each plan shall include standards of performance and compliance
schedules.
(b) Standards of performance shall either be based on allowable
rate or limit of emissions, except when it is not feasible to prescribe
or enforce a standard of performance. The EPA shall identify such cases
in the emission guidelines issued under Sec. 60.22a. Where standards
of performance prescribing design, equipment, work practice, or
operational standard, or combination thereof are established, the plan
shall, to the degree possible, set forth the emission reductions
achievable by implementation of such standards, and may permit
compliance by the use of equipment determined by the State to be
equivalent to that prescribed.
(1) Test methods and procedures for determining compliance with the
standards of performance shall be specified in the plan. Methods other
than those specified in appendix A to this part or an applicable
subpart of this part may be specified in the plan if shown to be
equivalent or alternative methods as defined in Sec. 60.2(t) and (u).
(2) Standards of performance shall apply to all designated
facilities within the State. A plan may contain standards of
performance adopted by local jurisdictions provided that the standards
are enforceable by the State.
(c) Except as provided in paragraph (e) of this section, standards
of performance shall be no less stringent than the corresponding
emission guideline(s) specified in subpart C of this part, and final
compliance shall be required as expeditiously as practicable, but no
later than the compliance times specified in an applicable subpart of
this part.
(d)(1) Any compliance schedule extending more than 24 months from
the date required for submittal of the plan must include legally
enforceable increments of progress to achieve compliance for each
designated facility or category of facilities. Unless otherwise
specified in the applicable subpart, increments of progress must
include, where practicable, each increment of progress specified in
Sec. 60.21a(h) and must include such additional increments of progress
as may be necessary to permit close and effective supervision of
progress toward final compliance.
(2) A plan may provide that compliance schedules for individual
sources or categories of sources will be formulated after plan
submittal. Any such schedule shall be the subject of a public hearing
held according to Sec. 60.23a and shall be submitted to the
Administrator within 60 days after the date of adoption of the schedule
but in no case later than the date prescribed for submittal of the
first semiannual report required by Sec. 60.25a(e).
(e) In applying a standard of performance to a particular source,
the State may take into consideration factors, such as the remaining
useful life of such source, provided that the State demonstrates with
respect to each such facility (or class of such facilities):
(1) Unreasonable cost of control resulting from plant age,
location, or basic process design;
(2) Physical impossibility of installing necessary control
equipment; or
(3) Other factors specific to the facility (or class of facilities)
that make application of a less stringent standard or final compliance
time significantly more reasonable.
(f) Nothing in this subpart shall be construed to preclude any
State or political subdivision thereof from adopting or enforcing:
(1) Standards of performance more stringent than emission
guidelines specified in subpart C of this part or in applicable
emission guidelines; or
(2) Compliance schedules requiring final compliance at earlier
times than those specified in subpart C or in applicable emission
guidelines.
Sec. 60.25a Emission inventories, source surveillance, reports.
(a) Each plan shall include an inventory of all designated
facilities, including emission data for the designated pollutants and
information related to emissions as specified in appendix D to this
part. Such data shall be summarized in the plan, and emission rates of
designated pollutants from designated facilities shall be correlated
with applicable standards of performance. As used in this subpart,
``correlated'' means presented in such a manner as to show the
relationship between measured or estimated amounts of emissions and the
amounts of such emissions allowable under applicable standards of
performance.
(b) Each plan shall provide for monitoring the status of compliance
with applicable standards of performance. Each plan shall, as a
minimum, provide for:
(1) Legally enforceable procedures for requiring owners or
operators of designated facilities to maintain records and periodically
report to the State information on the nature and amount of emissions
from such facilities, and/or such other information as may be necessary
to enable the State to determine whether such facilities are in
compliance with applicable portions of the plan. Submission of
electronic documents shall comply with the requirements of 40 CFR part
3--(Electronic reporting).
(2) Periodic inspection and, when applicable, testing of designated
facilities.
(c) Each plan shall provide that information obtained by the State
under paragraph (b) of this section shall be
[[Page 44806]]
correlated with applicable standards of performance (see Sec.
60.25a(a)) and made available to the general public.
(d) The provisions referred to in paragraphs (b) and (c) of this
section shall be specifically identified. Copies of such provisions
shall be submitted with the plan unless:
(1) They have been approved as portions of a preceding plan
submitted under this subpart or as portions of an implementation plan
submitted under section 110 of the Act, and
(2) The State demonstrates:
(i) That the provisions are applicable to the designated
pollutant(s) for which the plan is submitted, and
(ii) That the requirements of Sec. 60.26a are met.
(e) The State shall submit reports on progress in plan enforcement
to the Administrator on an annual (calendar year) basis, commencing
with the first full report period after approval of a plan or after
promulgation of a plan by the Administrator. Information required under
this paragraph must be included in the annual report required by Sec.
51.321 of this chapter.
(f) Each progress report shall include:
(1) Enforcement actions initiated against designated facilities
during the reporting period, under any standard of performance or
compliance schedule of the plan.
(2) Identification of the achievement of any increment of progress
required by the applicable plan during the reporting period.
(3) Identification of designated facilities that have ceased
operation during the reporting period.
(4) Submission of emission inventory data as described in paragraph
(a) of this section for designated facilities that were not in
operation at the time of plan development but began operation during
the reporting period.
(5) Submission of additional data as necessary to update the
information submitted under paragraph (a) of this section or in
previous progress reports.
(6) Submission of copies of technical reports on all performance
testing on designated facilities conducted under paragraph (b)(2) of
this section, complete with concurrently recorded process data.
Sec. 60.26a Legal authority.
(a) Each plan shall show that the State has legal authority to
carry out the plan, including authority to:
(1) Adopt standards of performance and compliance schedules
applicable to designated facilities.
(2) Enforce applicable laws, regulations, standards, and compliance
schedules, and seek injunctive relief.
(3) Obtain information necessary to determine whether designated
facilities are in compliance with applicable laws, regulations,
standards, and compliance schedules, including authority to require
recordkeeping and to make inspections and conduct tests of designated
facilities.
(4) Require owners or operators of designated facilities to
install, maintain, and use emission monitoring devices and to make
periodic reports to the State on the nature and amounts of emissions
from such facilities; also authority for the State to make such data
available to the public as reported and as correlated with applicable
standards of performance.
(b) The provisions of law or regulations which the State determines
provide the authorities required by this section shall be specifically
identified. Copies of such laws or regulations shall be submitted with
the plan unless:
(1) They have been approved as portions of a preceding plan
submitted under this subpart or as portions of an implementation plan
submitted under section 110 of the Act, and
(2) The State demonstrates that the laws or regulations are
applicable to the designated pollutant(s) for which the plan is
submitted.
(c) The plan shall show that the legal authorities specified in
this section are available to the State at the time of submission of
the plan. Legal authority adequate to meet the requirements of
paragraphs (a)(3) and (4) of this section may be delegated to the State
under section 114 of the Act.
(d) A State governmental agency other than the State air pollution
control agency may be assigned responsibility for carrying out a
portion of a plan if the plan demonstrates to the Administrator's
satisfaction that the State governmental agency has the legal authority
necessary to carry out that portion of the plan.
(e) The State may authorize a local agency to carry out a plan, or
portion thereof, within the local agency's jurisdiction if the plan
demonstrates to the Administrator's satisfaction that the local agency
has the legal authority necessary to implement the plan or portion
thereof, and that the authorization does not relieve the State of
responsibility under the Act for carrying out the plan or portion
thereof.
Sec. 60.27a Actions by the Administrator.
(a) The Administrator may, whenever he determines necessary,
shorten the period for submission of any plan or plan revision or
portion thereof.
(b) After determination that a plan or plan revision is complete
per the requirements of paragraph (g) of this section, the
Administrator will take action on the plan or revision. The
Administrator will, within twelve months of finding that a plan or plan
revision is complete, approve or disapprove such plan or revision or
each portion thereof.
(c) The Administrator will propose to promulgate, through notice
and comment rulemaking, a federal plan, or portion thereof, for a State
if:
(1) The Administrator finds that a State fails to submit a required
complete plan or complete plan revision within the time prescribed; or
(2) The Administrator disapproves the required State plan or plan
revision or any portion thereof, as unsatisfactory because the
applicable requirements of this subpart or an applicable subpart under
this part have not been met.
(d) The Administrator will, at any time within two years after the
finding of failure to submit a complete plan or disapproval described
under paragraph (c) of this section, promulgate a final federal plan
unless, prior to such promulgation, the State has adopted and submitted
a plan or plan revision which the Administrator determines to be
approvable.
(e)(1) Except as provided in paragraph (e)(2) of this section, a
federal plan promulgated by the Administrator under this section will
prescribe standards of performance of the same stringency as the
corresponding emission guideline(s) specified in the final emission
guideline published under Sec. 60.22a(a) and will require compliance
with such standards as expeditiously as practicable but no later than
the times specified in the emission guideline.
(2) Upon application by the owner or operator of a designated
facility to which regulations proposed and promulgated under this
section will apply, the Administrator may provide for the application
of less stringent standards of performance or longer compliance
schedules than those otherwise required by this section in accordance
with the criteria specified in Sec. 60.24a(f).
(f) Prior to promulgation of a federal plan under paragraph (d) of
this section, the Administrator will provide the opportunity for at
least one public hearing in either:
(1) Each State that failed to hold a public hearing as required by
Sec. 60.23a(c); or
(2) Washington, DC or an alternate location specified in the
Federal Register.
(g) Each plan or plan revision that is submitted to the
Administrator shall be
[[Page 44807]]
reviewed for completeness as described in paragraphs (g)(1) through
(g)(3) of this section.
(1) General. Within 60 days of the Administrator's receipt of a
state submission, but no later than 6 months after the date, if any, by
which a State is required to submit the plan or revision, the
Administrator shall determine whether the minimum criteria for
completeness have been met. Any plan or plan revision that a State
submits to the EPA, and that has not been determined by the EPA by the
date 6 months after receipt of the submission to have failed to meet
the minimum criteria, shall on that date be deemed by operation of law
to meet such minimum criteria. Where the Administrator determines that
a plan submission does not meet the minimum criteria of this paragraph,
the State will be treated as not having made the submission and the
requirements of this section regarding promulgation of a federal plan
shall apply.
(2) Administrative criteria. In order to be deemed complete, a
State plan must contain each of the following administrative criteria:
(i) A formal letter of submittal from the Governor or her designee
requesting EPA approval of the plan or revision thereof;
(ii) Evidence that the State has adopted the plan in the state code
or body of regulations. That evidence must include the date of adoption
or final issuance as well as the effective date of the plan, if
different from the adoption/issuance date;
(iii) Evidence that the State has the necessary legal authority
under state law to adopt and implement the plan;
(iv) A copy of the actual regulation, or document submitted for
approval and incorporation by reference into the plan. The submittal
must be a copy of the official state regulation or document signed,
stamped and dated by the appropriate state official indicating that it
is fully enforceable by the State. The effective date of the regulation
or document must, whenever possible, be indicated in the document
itself. The State's electronic copy must be an exact duplicate of the
hard copy. For revisions to the approved plan, the submittal must
indicate the changes made (for example, by redline/strikethrough) to
the approved plan;
(v) Evidence that the State followed all of the procedural
requirements of the state's laws and constitution in conducting and
completing the adoption and issuance of the plan;
(vi) Evidence that public notice was given of the proposed change
with procedures consistent with the requirements of Sec. 60.23,
including the date of publication of such notice;
(vii) Certification that public hearing(s) were held in accordance
with the information provided in the public notice and the State's laws
and constitution, if applicable and consistent with the public hearing
requirements in Sec. 60.23;
(viii) Compilation of public comments and the State's response
thereto; and
(ix) Such other criteria for completeness as may be specified by
the Administrator under the applicable emission guidelines.
(3) Technical criteria. In order to be deemed complete, a State
plan must contain each of the following technical criteria:
(i) Description of the plan approach and geographic scope;
(ii) Identification of each affected source, identification of
emission standards for the affected sources, and monitoring,
recordkeeping and reporting requirements that will determine compliance
by each affected source;
(iii) Identification of compliance schedules and/or increments of
progress;
(iv) Demonstration that the State plan submittal is projected to
achieve emissions performance under the applicable emission guidelines;
(v) Documentation of state recordkeeping and reporting requirements
to determine the performance of the plan as a whole; and
(vi) Demonstration that each emission standard is quantifiable,
non-duplicative, permanent, verifiable, and enforceable.
Sec. 60.28a Plan revisions by the State.
(a) Plan revisions shall be submitted to the Administrator within
12 months, or shorter if required by the Administrator, after notice of
the availability of a final revised emission guideline is published
under Sec. 60.22a, in accordance with the procedures and requirements
applicable to development and submission of the original plan.
(b) A revision of a plan, or any portion thereof, shall not be
considered part of an applicable plan until approved by the
Administrator in accordance with this subpart.
Sec. 60.29a Plan revisions by the Administrator.
After notice and opportunity for public hearing in each affected
State, the Administrator may revise any provision of an applicable
federal plan if:
(a) The provision was promulgated by the Administrator, and
(b) The plan, as revised, will be consistent with the Act and with
the requirements of this subpart.
0
7. Add subpart UUUUa to read as follows:
Subpart--UUUUa Emission Guidelines for Greenhouse Gas Emissions and
Compliance Times for Electric Utility Generating Units
Introduction
Sec.
60.5700a What is the purpose of this subpart?
60.5705a Which pollutants are regulated by this subpart?
60.5710a Am I affected by this subpart?
60.5715a What is the review and approval process for my plan?
60.5720a What if I do not submit a plan or my plan is not
approvable?
60.5725a In lieu of a State plan submittal, are there other
acceptable option(s) for a State to meet its CAA section 111(d)
obligations?
60.5730a Is there an approval process for a negative declaration
letter?
State Plan Requirements
60.5735a What must I include in my federally enforceable State plan?
60.5740a What must I include in my plan submittal?
60.5745a What are the timing requirements for submitting my plan?
60.5750a What schedules, performance periods, and compliance periods
must I include in my plan?
60.5755a What standards of performance must I include in my plan?
60.5760a What is the procedure for revising my plan?
60.5765a What must I do to meet my plan obligations?
Applicablity of Plans to Affected EGUs
60.5770a Does this subpart directly affect EGU owners or operators
in my State?
60.5775a What affected EGUs must I address in my State plan?
60.5780a What EGUs are excluded from being affected EGUs?
60.5785a What applicable monitoring, recordkeeping, and reporting
requirements do I need to include in my plan for affected EGUs?
Recordkeeping and Reporting Requirements
60.5790a What are my recordkeeping requirements?
60.5795a What are my reporting and notification requirements?
60.5800a How do I submit information required by these Emission
Guidelines to the EPA?
Definitions
60.5805a What definitions apply to this subpart?
[[Page 44808]]
Subpart--UUUUa Emission Guidelines for Greenhouse Gas Emissions and
Compliance Times for Electric Utility Generating Units
Introduction
Sec. 60.5700a What is the purpose of this subpart?
This subpart establishes emission guidelines and approval criteria
for State plans that establish standards of performance limiting
greenhouse gas (GHG) emissions from an affected steam generating unit.
An affected steam generating unit for the purposes of this subpart, is
referred to as an affected EGU. These emission guidelines are developed
in accordance with section 111(d) of the Clean Air Act and subpart Ba
of this part. To the extent any requirement of this subpart is
inconsistent with the requirements of subparts A or subpart Ba of this
part, the requirements of this subpart will apply.
Sec. 60.5705a Which pollutants are regulated by this subpart?
(a) The pollutants regulated by this subpart are greenhouse gases.
The emission guidelines for greenhouse gases established in this
subpart are heat rate improvements which target achieving lower carbon
dioxide (CO2) emission rates at affected EGUs.
(b) PSD and Title V thresholds for greenhouse gases are set out in
this paragraph (b).
(1) For the purposes of Sec. 51.166(b)(49)(ii), with respect to
GHG emissions from facilities, the ``pollutant that is subject to the
standard promulgated under section 111 of the Act'' shall be considered
to be the pollutant that otherwise is subject to regulation under the
Act as defined in Sec. 51.166(b)(48) and in any State Implementation
Plan (SIP) approved by the EPA that is interpreted to incorporate, or
specifically incorporates, Sec. 51.166(b)(48) of this chapter.
(2) For the purposes of Sec. 52.21(b)(50)(ii), with respect to GHG
emissions from facilities regulated in the plan, the ``pollutant that
is subject to the standard promulgated under section 111 of the Act''
shall be considered to be the pollutant that otherwise is subject to
regulation under the Act as defined in Sec. 52.21(b)(49) of this
chapter.
(3) For the purposes of Sec. 70.2 of this chapter, with respect to
greenhouse gas emissions from facilities regulated in the plan, the
``pollutant that is subject to any standard promulgated under section
111 of the Act'' shall be considered to be the pollutant that otherwise
is ``subject to regulation'' as defined in Sec. 70.2 of this chapter.
(4) For the purposes of Sec. 71.2, with respect to greenhouse gas
emissions from facilities regulated in the plan, the ``pollutant that
is subject to any standard promulgated under section 111 of the Act''
shall be considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in Sec. 71.2 of this chapter.
Sec. 60.5710a Am I affected by this subpart?
If you are the Governor of a State in the contiguous United States
with one or more affected EGUs that commenced construction on or before
August 31, 2018, you are subject to this action and you must submit a
State plan to the U.S. Environmental Protection Agency (EPA) that
implements the emission guidelines contained in this subpart. If you
are the Governor of a State in the United States with no affected EGUs
for which construction commenced on or before August 31, 2018, in your
State, you must submit a negative declaration letter in place of the
State plan.
Sec. 60.5715a What is the review and approval process for my plan?
The EPA will review your plan according to Sec. 60.27a to approve
or disapprove such plan or revision or each portion thereof.
Sec. 60.5720a What if I do not submit a plan or my plan is not
approvable?
(a) If you do not submit an approvable plan the EPA will develop a
Federal plan for your State according to Sec. 60.27a. The Federal plan
will implement the emission guidelines contained in this subpart.
Owners and operators of affected EGUs not covered by an approved plan
must comply with a Federal plan implemented by the EPA for the State.
(b) After a Federal plan has been implemented in your State, it
will be withdrawn when your State submits, and the EPA approves, a
plan.
Sec. 60.5725a In lieu of a State plan submittal, are there other
acceptable option(s) for a State to meet its CAA section 111(d)
obligations?
A State may meet its CAA section 111(d) obligations only by
submitting a State plan submittal or a negative declaration letter (if
applicable).
Sec. 60.5730a Is there an approval process for a negative
declaration letter?
The EPA has no formal review process for negative declaration
letters. Once your negative declaration letter has been received, the
EPA will place a copy in the public docket and publish a notice in the
Federal Register. If, at a later date, an affected EGU for which
construction commenced on or before August 31, 2018 is found in your
State, you will be found to have failed to submit a final plan as
required, and a Federal plan implementing the emission guidelines
contained in this subpart, when promulgated by the EPA, will apply to
that affected EGU until you submit, and the EPA approves, a final State
plan.
State Plan Requirements
Sec. 60.5735a What must I include in my federally enforceable State
plan?
(a) You must include the components described in paragraphs (a)(1)
through (4) of this section in your plan submittal. The final plan must
meet the requirements of, and include the information required under,
Sec. 60.5740a.
(1) Identification of affected EGUs. Consistent with Sec.
60.25a(a), you must identify the affected EGUs covered by your plan and
all affected EGUs in your State that meet the applicability criteria in
Sec. 60.5775a. In addition, you must include an inventory of
CO2 emissions from the affected EGUs during the most recent
calendar year for which data is available prior to the submission of
the plan.
(2) Standards of performance. You must provide a standard of
performance for each affected EGU according to Sec. 60.5755a and
compliance periods for each standard of performance according to Sec.
60.5750a. In establishing a standard of performance, the state must
evaluate all of the heat rate improvements described in Sec. 60.5740a.
(3) Identification of applicable monitoring, reporting, and
recordkeeping requirements for each affected EGU. You must include in
your plan all applicable monitoring, reporting and recordkeeping
requirements for each affected EGU and the requirements must be
consistent with or no less stringent than the requirements specified in
Sec. 60.5785a.
(4) State reporting. Your plan must include a description of the
process, contents, and schedule for State reporting to the EPA about
plan implementation and progress, including information required under
Sec. 60.5795a.
(b) You must follow the requirements of subpart Ba of this part and
demonstrate that they were met in your State plan.
Sec. 60.5740a What must I include in my plan submittal?
(a) In addition to the components of the plan listed in Sec.
60.5735a, a state plan submittal to the EPA must include the
information in paragraphs (a)(1) through (8) of this section. This
information must be submitted to the EPA as part of your plan submittal
but
[[Page 44809]]
will not be codified as part of the federally enforceable plan upon
approval by EPA.
(1) You must include a summary of how you determined each standard
of performance for each affected EGU according to Sec. 60.5755a(a).
You must include in the summary an evaluation of the applicability of
each of the following heat rate improvements to each affected EGU:
(i) Neural network/intelligent sootblowers
(ii) Boiler feed pumps
(iii) Air heater and duct leakage control
(iv) Variable frequency drives
(v) Blade path upgrades for steam turbines
(vi) Redesign or replacement of economizer
(vii) Improved operating and maintenance practices
(2) In applying a standard of performance, if you consider
remaining useful life and other factors for an affected EGU as provided
in Sec. 60.24a(e), you must include a summary of the application of
the relevant factors in deriving a standard of performance.
(3) You must include a demonstration that each affected EGU's
standard of performance is quantifiable, non-duplicative, permanent,
verifiable, and enforceable according to Sec. 60.5755a.
(4) Your plan demonstration, if applicable, must include the
information listed in paragraphs (a)(4)(i) through (v) of this section
as applicable.
(i) A summary of each affected EGU's anticipated future operation
characteristics, including:
(A) Annual generation;
(B) CO2 emissions;
(C) Fuel use, fuel prices (when applicable), fuel carbon content;
(D) Fixed and variable operations and maintenance costs (when
applicable);
(E) Heat rates; and
(F) Electric generation capacity and capacity factors.
(ii) A timeline for implementation of EGU-specific actions (if
applicable).
(iii) All wholesale electricity prices.
(iv) A time period of analysis, which must extend through at least
2035.
(v) A demonstration that each standard of performance included in
your plan meets the requirements of Sec. 60.5755a.
(5) Your plan submittal must include a timeline with all the
programmatic milestone steps the State intends to take between the time
of the State plan submittal and [date three years after the notice of
availability of a final emission guideline is published in the Federal
Register] to ensure the plan is effective as of [date plan takes
effect].
(6) Your plan submittal must adequately demonstrate that your State
has the legal authority (e.g., through regulations or legislation) and
funding to implement and enforce each component of the State plan
submittal, including federally enforceable standards of performance for
affected EGUs.
(7) Your plan submittal must include certification that a hearing
required under Sec. 60.23a(c)on the State plan was held, a list of
witnesses and their organizational affiliations, if any, appearing at
the hearing, and a brief written summary of each presentation or
written submission, pursuant to the requirements of Sec. 60.27a(f).
(8) Your plan submittal must include supporting material for your
plan including:
(i) Materials demonstrating the State's legal authority to
implement and enforce each component of its plan, including standards
of performance, pursuant to the requirements of Sec. 60.27a(f) and
Sec. 60.5740a(a)(6);
(ii) Materials supporting calculations for affected EGU's standards
of performance according to Sec. 60.5755a; and
(iii) Any other materials necessary to support evaluation of the
plan by the EPA.
(b) You must submit your final plan to the EPA electronically
according to Sec. 60.5800a.
Sec. 60.5745a What are the timing requirements for submitting my
plan?
You must submit a plan with the information required under Sec.
60.5740a by [date three years after the notice of availability of a
final emission guideline is published in the Federal Register].
Sec. 60.5750a What schedules, performance periods, and compliance
periods must I include in my plan?
The standards of performance for affected EGUs regulated under the
plan must include compliance periods. Any compliance period extending
more than 24 months from the date required for submittal of the plan
must include legally enforceable increments of progress to achieve
compliance for each designated facility or category of facilities.
Sec. 60.5755a What standards of performance must I include in my
plan?
(a) You must set a standard of performance for each affected EGU
within the state.
(1) The standard of performance must be an emission performance
rate relating mass of CO2 emitted per unit of energy (e.g.
pounds of CO2 emitted per MWh).
(2) In establishing any standard of performance, you must consider
the applicability of each of the heat rate improvements included in
Sec. 60.5740a(1) to the affected EGU.
(i) In applying a standard of performance to any affected EGU, you
may consider the source-specific factors included in Sec. 60.24(e).
(ii) If you consider source-specific factors to apply a standard of
performance, you must include a demonstration in your plan submission
for how you considered such factors.
(b) Standards of performance for affected EGUs included under your
plan must be demonstrated to be quantifiable, verifiable, non-
duplicative, permanent, and enforceable with respect to each affected
EGU. The plan submittal must include the methods by which each standard
of performance meets each of the requirements in paragraphs (c) through
(f) of this section.
(c) An affected EGU's standard of performance is quantifiable if it
can be reliably measured in a manner that can be replicated.
(d) An affected EGU's standard of performance is verifiable if
adequate monitoring, recordkeeping and reporting requirements are in
place to enable the State and the Administrator to independently
evaluate, measure, and verify compliance with the standard of
performance.
(e) An affected EGU's standard of performance is permanent if the
standard of performance must be met for each compliance period, unless
it is replaced by another standard of performance in an approved plan
revision.
(f) An affected EGU's standard of performance is enforceable if:
(1) A technically accurate limitation or requirement and the time
period for the limitation or requirement are specified;
(2) Compliance requirements are clearly defined;
(3) The affected EGU responsible for compliance and liable for
violations can be identified;
(4) Each compliance activity or measure is enforceable as a
practical matter; and
(5) The Administrator, the State, and third parties maintain the
ability to enforce against violations (including if an affected EGU
does not meet its standard of performance based on its emissions) and
secure appropriate corrective actions, in the case of the Administrator
pursuant to CAA sections 113(a)-(h), in the case of a State, pursuant
to its plan, State law or CAA section 304, as applicable, and in the
[[Page 44810]]
case of third parties, pursuant to CAA section 304.
Sec. 60.5760a What is the procedure for revising my plan?
EPA-approved plans can be revised only with approval by the
Administrator. The Administrator will approve a plan revision if it is
satisfactory with respect to the applicable requirements of this
subpart and any applicable requirements of subpart Ba of this part,
including the requirements in Sec. 60.5740a. If one (or more) of the
elements of the plan set in Sec. 60.5735a require revision, a request
must be submitted to the Administrator indicating the proposed
revisions to the plan to ensure the CO2 emission performance
are met.
Sec. 60.5765a What must I do to meet my plan obligations?
To meet your plan obligations, you must demonstrate that your
affected EGUs are complying with their standards of performance as
specified in Sec. 60.5755a.
Applicability of Plans to Affected EGUs
Sec. 60.5770a Does this subpart directly affect EGU owners or
operators in my State?
(a) This subpart does not directly affect EGU owners or operators
in your State. However, affected EGU owners or operators must comply
with the plan that a State develops to implement the emission
guidelines contained in this subpart.
(b) If a State does not submit a plan to implement and enforce the
emission guidelines contained in this subpart by [date three years
after the notice of availability of a final emission guideline is
published in the Federal Register], or the date that EPA disapproves a
final plan, the EPA will implement and enforce a Federal plan, as
provided in Sec. 60.27a(c), applicable to each affected EGU within the
State that commenced construction on or before January 8, 2014.
Sec. 60.5775a What affected EGUs must I address in my State plan?
(a) The EGUs that must be addressed by your plan are any affected
EGU that commenced construction on or before August 31, 2018.
(b) An affected EGU is a steam generating unit that meets the
relevant applicability conditions specified in paragraph (b)(1) through
(2), as applicable, of this section except as provided in Sec.
60.5780a.
(1) Serves a generator connected to a utility power distribution
system with a nameplate capacity greater than 25 MW-net (i.e., capable
of selling greater than 25 MW of electricity);
(2) Has a base load rating (i.e., design heat input capacity)
greater than 260 GJ/hr (250 MMBtu/hr) heat input of fossil fuel (either
alone or in combination with any other fuel).
Sec. 60.5780a What EGUs are excluded from being affected EGUs?
(a) An EGU that is excluded from being an affected EGU is:
(1) An EGU that is subject to subpart TTTT of this part as a result
of commencing construction, reconstruction or modification after the
subpart TTTT applicability date;
(2) A steam generating unit that is, and always has been, subject
to a federally enforceable permit limiting annual net-electric sales to
one-third or less of its potential electric output, or 219,000 MWh or
less;
(3) A stationary combustion turbine that meets the definition of
either a combined cycle or combined heat and power combustion turbine;
(4) An IGCC unit;
(5) A non-fossil unit (i.e., a unit that is capable of combusting
50 percent or more non-fossil fuel) that has always limited the use of
fossil fuels to 10 percent or less of the annual capacity factor or is
subject to a federally enforceable permit limiting fossil fuel use to
10 percent or less of the annual capacity factor;
(6) An EGU that is a combined heat and power unit that has always
limited, or is subject to a federally enforceable permit limiting,
annual net-electric sales to a utility distribution system to no more
than the greater of either 219,000 MWh or the product of the design
efficiency and the potential electric output;
(7) An EGU that serves a generator along with other steam
generating unit(s), IGCC(s), or stationary combustion turbine(s) where
the effective generation capacity (determined based on a prorated
output of the base load rating of each steam generating unit, IGCC, or
stationary combustion turbine) is 25 MW or less;
(8) An EGU that is a municipal waste combustor unit that is subject
to subpart Eb of this part; or
(9) An EGU that is a commercial or industrial solid waste
incineration unit that is subject to subpart CCCC of this part.
(b) [Reserved]
Sec. 60.5785a What applicable monitoring, recordkeeping, and
reporting requirements do I need to include in my plan for affected
EGUs?
(a) Your plan must include monitoring, recordkeeping, and reporting
requirements for affected EGUs. To satisfy this requirement, you have
the option of either:
(1) Specifying that sources must report emission and electricity
generation data according to part 75 of this chapter; or
(2) Describing an alternative monitoring, recordkeeping, and
reporting program that includes specifications for the following
program elements:
(i) Monitoring plans that specify the monitoring methods, systems,
and formulas that will be used to measure CO2 emissions;
(ii) Monitoring methods to continuously and accurately measure all
CO2 emissions, CO2 emission rates, and other data
necessary to determine compliance or assure data quality;
(iii) Quality assurance test requirements to ensure monitoring
systems provide reliable and accurate data for assessing and verifying
compliance;
(iv) Recordkeeping requirements;
(v) Electronic reporting procedures and systems; and
(vi) Data validation procedures for ensuring data are complete and
calculated consistent with program rules, including procedures for
determining substitute data in instances where required data would
otherwise be incomplete.
(b) [Reserved]
Recordkeeping and Reporting Requirements
Sec. 60.5790a What are my recordkeeping requirements?
(a) You must keep records of all information relied upon in support
of any demonstration of plan components, plan requirements, supporting
documentation, and the status of meeting the plan requirements defined
in the plan for each interim step and the interim period. After [date
plan takes effect], States must keep records of all information relied
upon in support of any continued demonstration that the final
CO2 emission performance rates or CO2 emissions
goals are being achieved.
(b) You must keep records of all data submitted by the owner or
operator of each affected EGU that is used to determine compliance with
each affected EGU emissions standard or requirements in an approved
State plan, consistent with the affected EGU requirements listed in
Sec. 60.5785a.
(c) If your State has a requirement for all hourly CO2
emissions and net generation information to be used to calculate
compliance with an annual emissions standard for affected EGUs,
[[Page 44811]]
any information that is submitted by the owners or operators of
affected EGUs to the EPA electronically pursuant to requirements in
Part 75 meets the recordkeeping requirement of this section and you are
not required to keep records of information that would be in duplicate
of paragraph (b) of this section.
(d) You must keep records at a minimum for 5 years from the date
the record is used to determine compliance with a standard of
performance or plan requirement. Each record must be in a form suitable
and readily available for expeditious review.
Sec. 60.5795a What are my reporting and notification requirements?
You must submit an annual report as required under Sec. 60.25a(e)
and (f).
Sec. 60.5800a How do I submit information required by these Emission
Guidelines to the EPA?
(a) You must submit to the EPA the information required by the
emission guidelines in this subpart following the procedures in
paragraphs (b) through (e) of this section.
(b) All negative declarations, State plan submittals, supporting
materials that are part of a State plan submittal, any plan revisions,
and all State reports required to be submitted to the EPA by the State
plan must be reported through EPA's State Plan Electronic Collection
System (SPeCS). SPeCS is a web accessible electronic system accessed at
the EPA's Central Data Exchange (CDX) (http://www.epa.gov/cdx/). States
who claim that a State plan submittal or supporting documentation
includes confidential business information (CBI) must submit that
information on a compact disc, flash drive, or other commonly used
electronic storage media to the EPA. The electronic media must be
clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office,
Attention: State and Local Programs Group, MD C539-01, 4930 Old Page
Rd., Durham, NC 27703.
(c) Only a submittal by the Governor or the Governor's designee by
an electronic submission through SPeCS shall be considered an official
submittal to the EPA under this subpart. If the Governor wishes to
designate another responsible official the authority to submit a State
plan, the EPA must be notified via letter from the Governor prior to
the [date three years after the notice of availability of a final
emission guideline is published in the Federal Register], deadline for
plan submittal so that the official will have the ability to submit a
plan in the SPeCS. If the Governor has previously delegated authority
to make CAA submittals on the Governor's behalf, a State may submit
documentation of the delegation in lieu of a letter from the Governor.
The letter or documentation must identify the designee to whom
authority is being designated and must include the name and contact
information for the designee and also identify the State plan preparers
who will need access to SPeCS. A State may also submit the names of the
State plan preparers via a separate letter prior to the designation
letter from the Governor in order to expedite the State plan
administrative process. Required contact information for the designee
and preparers includes the person's title, organization, and email
address.
(d) The submission of the information by the authorized official
must be in a non-editable format. In addition to the non-editable
version all plan components designated as federally enforceable must
also be submitted in an editable version.
(e) You must provide the EPA with non-editable and editable copies
of any submitted revision to existing approved federally enforceable
plan components. The editable copy of any such submitted plan revision
must indicate the changes made at the State level, if any, to the
existing approved federally enforceable plan components, using a
mechanism such as redline/strikethrough. These changes are not part of
the State plan until formal approval by EPA.
Definitions
Sec. 60.5805a What definitions apply to this subpart?
As used in this subpart, all terms not defined herein will have the
meaning given them in the Clean Air Act and in subparts TTTT, A
(General Provisions) and subpart Ba of this part.
Affected electric generating unit or Affected EGU means a steam
generating unit that meets the relevant applicability conditions in
section Sec. 60.5775a, except as provided in Sec. 60.5780a.
Air heater means a device that recovers heat from the flue gas for
use in pre-heating the incoming combustion air and potentially for
other uses such as coal drying.
Annual capacity factor means the ratio between the actual heat
input to an EGU during a calendar year and the potential heat input to
the EGU had it been operated for 8,760 hours during a calendar year at
the base load rating.
Base load rating means the maximum amount of heat input (fuel) that
an EGU can combust on a steady-state basis, as determined by the
physical design and characteristics of the EGU at ISO conditions.
Boiler feed pump (or boiler feedwater pump) means a device used to
pump feedwater into a steam boiler at an EGU. The water may be either
freshly supplied or returning condensate produced from condensing steam
produced by the boiler.
CO2 emission rate means for an affected EGU, the reported
CO2 emission rate of an affected EGU used by an affected EGU
to demonstrate compliance with its CO2 standard of
performance.
Combined heat and power unit or CHP unit, (also known as
``cogeneration'') means an electric generating unit that uses a steam-
generating unit or stationary combustion turbine to simultaneously
produce both electric (or mechanical) and useful thermal output from
the same primary energy source.
Compliance period means a discrete time period for an affected EGU
to comply with a standard of performance.
Economizer means a heat exchange device used to capture waste heat
from boiler flue gas which is then used to heat the boiler feedwater.
Fossil fuel means natural gas, petroleum, coal, and any form of
solid fuel, liquid fuel, or gaseous fuel derived from such material to
create useful heat.
Integrated gasification combined cycle facility or IGCC means a
combined cycle facility that is designed to burn fuels containing 50
percent (by heat input) or more solid-derived fuel not meeting the
definition of natural gas plus any integrated equipment that provides
electricity or useful thermal output to either the affected facility or
auxiliary equipment. The Administrator may waive the 50 percent solid-
derived fuel requirement during periods of the gasification system
construction, startup and commissioning, shutdown, or repair. No solid
fuel is directly burned in the unit during operation.
Intelligent sootblower means an automated system that use process
measurements to monitor the heat transfer performance and strategically
allocate steam to specific areas to remove ash buildup at a steam
generating unit.
ISO conditions means 288 Kelvin (15 [deg]C), 60 percent relative
humidity and 101.3 kilopascals pressure.
Nameplate capacity means, starting from the initial installation,
the maximum electrical generating output that a generator, prime mover,
or other electric power production equipment under specific conditions
designated by the manufacturer is capable of producing (in MWe, rounded
to the
[[Page 44812]]
nearest tenth) on a steady-state basis and during continuous operation
(when not restricted by seasonal or other deratings) as of such
installation as specified by the manufacturer of the equipment, or
starting from the completion of any subsequent physical change
resulting in an increase in the maximum electrical generating output
that the equipment is capable of producing on a steady-state basis and
during continuous operation (when not restricted by seasonal or other
deratings), such increased maximum amount (in MWe, rounded to the
nearest tenth) as of such completion as specified by the person
conducting the physical change.
Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous State under ISO conditions. In
addition, natural gas contains 20.0 grains or less of total sulfur per
100 standard cubic feet. Finally, natural gas does not include the
following gaseous fuels: landfill gas, digester gas, refinery gas, sour
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas,
or any gaseous fuel produced in a process which might result in highly
variable sulfur content or heating value.
Net electric output means the amount of gross generation the
generator(s) produce (including, but not limited to, output from steam
turbine(s), combustion turbine(s), and gas expander(s)), as measured at
the generator terminals, less the electricity used to operate the plant
(i.e., auxiliary loads); such uses include fuel handling equipment,
pumps, fans, pollution control equipment, other electricity needs, and
transformer losses as measured at the transmission side of the step up
transformer (e.g., the point of sale).
Net energy output means:
(1) The net electric or mechanical output from the affected
facility, plus 100 percent of the useful thermal output measured
relative to SATP conditions that is not used to generate additional
electric or mechanical output or to enhance the performance of the unit
(e.g., steam delivered to an industrial process for a heating
application).
(2) For combined heat and power facilities where at least 20.0
percent of the total gross or net energy output consists of electric or
direct mechanical output and at least 20.0 percent of the total gross
or net energy output consists of useful thermal output on a 12-
operating month rolling average basis, the net electric or mechanical
output from the affected EGU divided by 0.95, plus 100 percent of the
useful thermal output; (e.g., steam delivered to an industrial process
for a heating application).
Neural network means a computer model that can be used to optimize
combustion conditions, steam temperatures, and air pollution at steam
generating unit.
Programmatic milestone means the implementation of measures
necessary for plan progress, including specific dates associated with
such implementation. Prior to [date plan takes effect], programmatic
milestones are applicable to all state plan approaches and measures.
Standard ambient temperature and pressure (SATP) conditions means
298.15 Kelvin (25 [deg]C, 77 [deg]F)) and 100.0 kilopascals (14.504
psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is
50 Btu/lb.
State agent means an entity acting on behalf of the State, with the
legal authority of the State.
Stationary combustion turbine means all equipment, including but
not limited to the turbine engine, the fuel, air, lubrication and
exhaust gas systems, control systems (except emissions control
equipment), heat recovery system, fuel compressor, heater, and/or pump,
post-combustion emissions control technology, and any ancillary
components and sub-components comprising any simple cycle stationary
combustion turbine, any combined cycle combustion turbine, and any
combined heat and power combustion turbine based system plus any
integrated equipment that provides electricity or useful thermal output
to the combustion turbine engine, heat recovery system or auxiliary
equipment. Stationary means that the combustion turbine is not self-
propelled or intended to be propelled while performing its function. It
may, however, be mounted on a vehicle for portability. If a stationary
combustion turbine burns any solid fuel directly it is considered a
steam generating unit.
Steam generating unit means any furnace, boiler, or other device
used for combusting fuel and producing steam (nuclear steam generators
are not included) plus any integrated equipment that provides
electricity or useful thermal output to the affected facility or
auxiliary equipment.
Useful thermal output means the thermal energy made available for
use in any heating application (e.g., steam delivered to an industrial
process for a heating application, including thermal cooling
applications) that is not used for electric generation, mechanical
output at the affected EGU, to directly enhance the performance of the
affected EGU (e.g., economizer output is not useful thermal output, but
thermal energy used to reduce fuel moisture is considered useful
thermal output), or to supply energy to a pollution control device at
the affected EGU. Useful thermal output for affected EGU(s) with no
condensate return (or other thermal energy input to the affected
EGU(s)) or where measuring the energy in the condensate (or other
thermal energy input to the affected EGU(s)) would not meaningfully
impact the emission rate calculation is measured against the energy in
the thermal output at SATP conditions. Affected EGU(s) with meaningful
energy in the condensate return (or other thermal energy input to the
affected EGU) must measure the energy in the condensate and subtract
that energy relative to SATP conditions from the measured thermal
output.
Valid data means quality-assured data generated by continuous
monitoring systems that are installed, operated, and maintained
according to part 75 of this chapter. For CEMS, the initial
certification requirements in Sec. 75.20 of this chapter and appendix
A to part 75 of this chapter must be met before quality-assured data
are reported under this subpart; for on-going quality assurance, the
daily, quarterly, and semiannual/annual test requirements in sections
2.1, 2.2, and 2.3 of appendix B to part 75 of this chapter must be met
and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of
appendix B to part 75 of this chapter apply. For fuel flow meters, the
initial certification requirements in section 2.1.5 of appendix D to
part 75 of this chapter must be met before quality-assured data are
reported under this subpart (except for qualifying commercial billing
meters under section 2.1.4.2 of appendix D), and for on-going quality
assurance, the provisions in section 2.1.6 of appendix D to part 75 of
this chapter apply (except for qualifying commercial billing meters).
[[Page 44813]]
Variable frequency drive means an adjustable-speed drive used on
induced draft fans and boiler feed pumps to control motor speed and
torque by varying motor input frequency and voltage.
Waste-to-Energy means a process or unit (e.g., solid waste
incineration unit) that recovers energy from the conversion or
combustion of waste stream materials, such as municipal solid waste, to
generate electricity and /or heat.
[FR Doc. 2018-18755 Filed 8-30-18; 8:45 am]
BILLING CODE 6560-50-P