[Federal Register Volume 84, Number 130 (Monday, July 8, 2019)]
[Rules and Regulations]
[Pages 32520-32584]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2019-13507]
[[Page 32519]]
Vol. 84
Monday,
No. 130
July 8, 2019
Part II
Environmental Protection Agency
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40 CFR Part 60
Repeal of the Clean Power Plan; Emission Guidelines for Greenhouse Gas
Emissions From Existing Electric Utility Generating Units; Revisions to
Emission Guidelines Implementing Regulations; Final Rule
Federal Register / Vol. 84 , No. 130 / Monday, July 8, 2019 / Rules
and Regulations
[[Page 32520]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2017-0355: FRL-9995-70-OAR]
RIN 2060-AT67
Repeal of the Clean Power Plan; Emission Guidelines for
Greenhouse Gas Emissions From Existing Electric Utility Generating
Units; Revisions to Emission Guidelines Implementing Regulations
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: The U.S. Environmental Protection Agency (EPA) is finalizing
three separate and distinct rulemakings. First, the EPA is repealing
the Clean Power Plan (CPP) because the Agency has determined that the
CPP exceeded the EPA's statutory authority under the Clean Air Act
(CAA). Second, the EPA is finalizing the Affordable Clean Energy rule
(ACE), consisting of Emission Guidelines for Greenhouse Gas (GHG)
Emissions from Existing Electric Utility Generating Units (EGUs) under
CAA section 111(d), that will inform states on the development,
submittal, and implementation of state plans to establish performance
standards for GHG emissions from certain fossil fuel-fired EGUs. In
ACE, the Agency is finalizing its determination that heat rate
improvement (HRI) is the best system of emission reduction (BSER) for
reducing GHG--specifically carbon dioxide (CO2)--emissions
from existing coal-fired EGUs. Third, the EPA is finalizing new
regulations for the EPA and state implementation of ACE and any future
emission guidelines issued under CAA section 111(d).
DATES: Effective September 6, 2019.
ADDRESSES: The EPA has established a docket for these actions under
Docket ID No. EPA-HQ-OAR-2017-0355. All documents in the docket are
listed on the https://www.regulations.gov/ website. 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 form. Publicly available docket materials are available
electronically through https://www.regulations.gov/ or in hard copy at
the EPA Docket Center, WJC West Building, Room 3334, 1301 Constitution
Ave. NW, Washington, DC. The EPA's Public Reading Room hours of
operation are 8:30 a.m. to 4:30 p.m. Eastern Standard Time (EST),
Monday through Friday. 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.
FOR FURTHER INFORMATION CONTACT: For questions about these final
actions, 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:
Preamble acronyms and abbreviations. The EPA uses multiple acronyms
and terms in this preamble. While this list may not be exhaustive, to
ease the reading of this preamble and for reference purposes, the EPA
defines the following terms and acronyms:
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
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
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
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 eelated
information?
C. Judicial Review and Administrative Reconsideration
II. Repeal of the Clean Power Plan
A. Background for the Repeal of the Clean Power Plan
B. Basis for Repealing the Clean Power Plan
C. Independence of Repeal of the Clean Power Plan
III. The Affordable Clean Energy Rule
A. The Affordable Clean Energy Rule Background
B. Legal Authority To Regulate EGUs
C. Designated Facilities for the Affordable Clean Energy Rule
D. Regulated Pollutant
E. Determination of the Best System of Emission Reduction
F. State Plan Development
G. Impacts of the Affordable Clean Energy Rule
IV. Changes to the Implementing Regulations for CAA Section 111(d)
Emission Guidelines
A. Regulatory Background
B. Provisions for Superseding Implementing Regulations
C. Changes to the Definition of ``Emission Guidelines''
D. Updates to Timing Requirements
E. Compliance Deadlines
F. Completeness Criteria
G. Standard of Performance
H. Remaining Useful Life and Other Factors Provision
V. 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
L. Congressional Review Act (CRA)
VI. Statutory Authority
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I. General Information
A. Executive Summary
With this document, the EPA is, after review and consideration of
public comments, finalizing three separate and distinct rulemakings.
First, the EPA is finalizing the repeal of the CPP which was proposed
at 82 FR 48035 (Oct. 16, 2017) (``Proposed Repeal''). Second, the EPA
is promulgating ACE, which consists of emission guidelines for states
to develop and submit to the EPA plans that establish standards of
performance for CO2 emissions from certain existing coal-
fired EGUs within their jurisdictions. Third, the EPA is finalizing
implementing regulations that provide direction to both the EPA and
states on the implementation of ACE and any future emission guidelines
issued under CAA section 111(d). This document does not include any
final action concerning the New Source Review (NSR) reforms the EPA
proposed in conjunction with the ACE proposal; the EPA intends to take
final action on the proposed NSR reforms in a separate final action at
a later date.
First, the EPA is repealing the CPP. In proposing to repeal the
CPP, the Agency proposed a change in the legal interpretation of CAA
section 111, on which the CPP was based, to an interpretation of the
CAA that ``is consistent with the CAA's text, context, structure,
purpose, and legislative history, as well as with the Agency's
historical understanding and exercise of its statutory authority.'' \1\
After further review of the EPA's statutory authority under CAA section
111 and in consideration of public comments, the Agency is finalizing
the repeal of the CPP. The discussion of the repeal action, along with
the EPA's explanation that it intends the repeal of the CPP to be
independent from the other final actions in this document, can be found
in section II below.
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\1\ Proposed Repeal, 82 FR 48036.
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Second, the EPA is finalizing ACE, which consists of emission
guidelines to inform states in the development, submittal, and
implementation of state plans that establish standards of performance
for CO2 from certain existing coal-fired EGUs within their
jurisdictions. In these emission guidelines, the EPA has determined
that the BSER for existing EGUs is based on HRI measures that can be
applied to a designated facility. ACE also clarifies the roles of the
EPA and the states under CAA section 111(d). With the promulgation of
this action, it is the states' responsibility to use the information
and direction herein to develop standards of performance that reflect
the application of the BSER. Per the CAA, states may also consider
source-specific factors--including, among other factors, the remaining
useful life of an existing source--in applying a standard of
performance to that source. In this way, the state and federal roles
complement each other as the EPA has the authority and responsibility
to determine BSER at the national level, while the states have the
authority and responsibility to establish and apply standards of
performance for their existing sources, taking into consideration
source-specific factors where appropriate. A full discussion of ACE can
be found in section III of this preamble.
Third, the EPA is finalizing new implementing regulations that
apply to ACE and any future emission guidelines promulgated under CAA
section 111(d). The purpose of the new implementing regulations is to
harmonize aspects of our existing regulations with the statute, in a
new 40 CFR part 60, subpart Ba, by making it clear that states have
broad discretion in establishing and applying emissions standards
consistent with the BSER. The new implementing regulations also provide
changes to the timing requirements for the EPA and states to take
action to more closely align with the CAA section 110 state
implementation plan (SIP) and federal implementation plan (FIP)
deadlines. The discussion of the final revisions to the implementing
regulations is found in section IV below.
The implementing regulations (and ACE which is promulgated
consistent with those regulations) make clear that the EPA, states, and
sources all have distinct roles, responsibilities, and flexibilities
under CAA section 111(d). Specifically, the EPA identifies the BSER;
states establish standards of performance for existing sources within
their jurisdiction consistent with that BSER and also with the
flexibility to consider source-specific factors, including remaining
useful life; and sources then meet those standards using the
technologies or techniques they believe is most appropriate. As this
preamble explains, in the case of ACE, the EPA has identified the BSER
as a set of heat rate improvement measures. States will establish
standards of performance for existing sources based on application of
those heat rate improvement measures (considering source-specific
factors, including remaining useful life). Each regulated source then
must meet those standards using the measures they believe is
appropriate (e.g., via the heat rate improvement measures identified by
the EPA as the BSER, other heat rate improvement measures, or other
approaches such as CCS or natural gas co-firing).
These three rules have been informed by more than 1.5 million
public comments on the Proposed Repeal and 500,000 public comments on
the proposals for ACE and the new implementing regulations. Per CAA
section 307(d)(6)(B), the EPA is providing a response to the
significant comments received for each of these actions in the docket.
After careful consideration of the comments, the EPA is finalizing
these three rules, with revisions to what it proposed where
appropriate, to provide states guidance on how to address
CO2 emissions from coal-fired power plants in a way that is
consistent with the EPA's authority under the CAA.
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 document is available on the internet. Following signature by the
EPA Administrator, the EPA will post a copy of this document at https://www.epa.gov/stationary-sources-air-pollution/electric-utility-generating-units-emission-guidelines-greenhouse. Following publication
in the Federal Register, the EPA will post the Federal Register version
of these final rules and key technical documents at this same website.
C. Judicial Review and Administrative Reconsideration
Under CAA section 307(b)(1), judicial review of these final actions
is available only by filing a petition for review in the United States
Court of Appeals for the District of Columbia Circuit (D.C. Circuit) by
September 6, 2019. Under CAA section 307(b)(2), the requirements
established by these final rules may not be challenged separately in
any civil or criminal proceedings brought by the EPA to enforce the
requirements.
Section 307(d)(7)(B) of the CAA further provides that only an
objection to a rule or procedure which was raised with reasonable
specificity during the period for public comment (including any public
hearing) may be raised during judicial review. This section also
provides a mechanism for the EPA to reconsider a rule if the person
raising an objection can demonstrate to the Administrator that it was
impracticable to raise such objection within the period for public
comment or if the grounds for such objection arose after the period for
public comment (but within the time
[[Page 32522]]
specified for judicial review) and if such objection is of central
relevance to the outcome of the rule. Any person seeking to make such a
demonstration should submit a Petition for Reconsideration to the
Office of the Administrator, U.S. EPA, Room 3000, WJC South Building,
1200 Pennsylvania Ave. NW, Washington, DC 20460, with a copy to both
the person(s) listed in the preceding FOR FURTHER INFORMATION CONTACT
section, and the Associate General Counsel for the Air and Radiation
Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200
Pennsylvania Ave. NW, Washington, DC 20460.
II. Repeal of the Clean Power Plan
A. Background for the Repeal of the Clean Power Plan
1. The Clean Power Plan
The EPA promulgated the CPP under section 111 of the CAA.\2\
Section 111(b) authorizes the EPA to issue nationally applicable new
source performance standards (NSPS) limiting air pollution from ``new
sources'' in source categories that cause or significantly contribute
to air pollution that may reasonably be anticipated to endanger public
health or welfare.\3\ In 2015, the EPA issued such a rule for GHG
emissions--in particular, CO2--from certain new fossil fuel-
fired power plants \4\ in light of the Agency's assessment ``that GHGs
endanger public health, now and in the future.'' \5\ CAA section 111(d)
provides that, under certain circumstances, when the EPA issues a CAA
section 111(b) standard, the EPA must develop procedures requiring each
state to submit a plan to the EPA that establishes performance
standards for existing sources in the same category.\6\ The EPA relied
on CAA section 111(d) to issue the CPP, which, for the first time,
required states to submit plans specifically designed to limit
CO2 emissions from certain existing fossil fuel-fired power
plants.
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\2\ 42 U.S.C. 7411.
\3\ Id. 7411(b)(1).
\4\ The CPP identified ``[f]ossil fuel-fired EGUs'' as ``by far
the largest emitters of GHGs among stationary sources in the U.S.,
primarily in the form of CO2.'' 80 FR 64510, 64522
(October 23, 2015).
\5\ Standards of Performance for Greenhouse Gas Emissions from
New, Modified, and Reconstructed Stationary Sources: Electric
Generating Units, 80 FR 64510, 64518 (October 23, 2015); see also
Endangerment and Cause or Contribute Findings for Greenhouse Gases
Under section 202(a) of the CAA, 74 FR 66496 (December 15, 2009)
(2009 Endangerment Finding). The substance of the 2009 Endangerment
Finding, which addressed GHG emissions from mobile sources, is not
at issue in this action.
\6\ 42 U.S.C. 7411(d)(1) (emphasis added).
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The CPP established emission guidelines for states to follow in
limiting CO2 emissions from those existing fossil fuel-fired
power plants. Those emission guidelines included both state-specific
``goals'' and alternative, nationally uniform CO2 emission
performance rates for two types of existing fossil fuel-fired power
plants: Electric utility steam generating units and stationary
combustion turbines.\7\
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\7\ See 80 FR 64707.
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In the CPP, the EPA determined that the BSER for CO2
emissions from existing fossil fuel-fired power plants was the
combination of: (1) Heat rate (e.g., efficiency) improvements to be
conducted at individual power plants, in combination with (2, 3) two
other sets of measures based on the shifting of generation at the
fleet-wide level from one type of energy source to another. The EPA
referred to these three sets of measures as ``building blocks'': \8\
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\8\ Id.
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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 relied on measures that could be applied
directly to individual sources, building blocks 2 and 3 employed
measures that were expressly designed to shift the balance of coal-,
gas-, and renewable-generated power across the power grid.
2. Legal Challenges to the CPP, Executive Order 13783, and the EPA's
Review of the CPP
On October 23, 2015, 27 states and a number of other parties sought
judicial review of the CPP in the U.S. Court of Appeals for the D.C.
Circuit.\9\ After some preliminary briefing, the Supreme Court stayed
implementation of the CPP, pending judicial review.\10\ The case was
then referred to an en banc panel of the D.C. Circuit, which held oral
argument on September 27, 2016.
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\9\ See West Virginia v. EPA, No. 15-1363 (and consolidated
cases) (D.C. Cir. October 23, 2015).
\10\ West Virginia v. EPA, 136 S. Ct. 1000 (2016).
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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.'' \11\
The Executive Order directs all executive departments and agencies,
including the EPA, to ``immediately review existing regulations that
potentially burden the development or use of domestically produced
energy resources and appropriately suspend, revise, or rescind those
that unduly burden the development of domestic energy resources beyond
the degree necessary to protect the public interest or otherwise comply
with the law.'' \12\ The Executive Order further affirms that it is
``the policy of the United States that necessary and appropriate
environmental regulations comply with the law.'' \13\ Moreover, the
Executive Order specifically directs the EPA to review and initiate
reconsideration proceedings to ``suspend, revise, or rescind'' the CPP
``as appropriate and consistent with law.'' \14\
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\11\ See Executive Order 13783, section 1(a).
\12\ Id. section 1(c).
\13\ Id. section 1(e).
\14\ Id. section 4(a)-(c).
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In a document signed the same day as Executive Order 13783 and
published in the Federal Register at 82 FR 16329 (April 4, 2017), the
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.
In light of Executive Order 13783, the EPA's initiation of a review
of the CPP, and notice of the EPA's forthcoming rulemakings, the EPA
asked the D.C. Circuit to hold the CPP litigation in abeyance, and, on
April 28, 2017, the court (still sitting en banc) granted motions to
hold the cases in abeyance for 60 days and directed the parties to file
briefs addressing whether the cases should be remanded to the Agency
rather than held in abeyance.\15\ Since then, the D.C. Circuit has
issued a series of orders holding the cases in abeyance. While the case
has been in abeyance, the EPA has been reviewing the CPP and providing
status reports to the court describing the progress of its rulemaking.
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\15\ Order, Document No. 1673071 (per curiam).
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In the course of the 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.\16\
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\16\ See Proposed Repeal, 82 FR 48035 (October 16, 2017).
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3. Public Comment and Hearings on the Proposed Repeal
Publication of the Proposed Repeal in the Federal Register opened
comment on the proposal for an initial 60-day
[[Page 32523]]
public comment period. The EPA held public hearings on November 28 and
29, 2017, in Charleston, West Virginia, and then extended the public
comment period until January 16, 2018. In response to requests for
additional opportunities for oral testimony, the EPA held three
listening sessions in Kansas City, Missouri; San Francisco, California;
and Gillette, Wyoming. The EPA also reopened the public comment period
until April 26, 2018, giving stakeholders 192 days to review and
comment on the proposal. The EPA received more than 1.5 million
comments on the Proposed Repeal.
B. Basis for Repealing the Clean Power Plan
1. Authority To Revisit Existing Regulations
The EPA's ability to revisit existing regulations is well-grounded
in the law. Specifically, the EPA has inherent authority to reconsider,
repeal, or revise past decisions to the extent permitted by law so long
as the Agency provides a reasoned explanation. The authority to
reconsider prior decisions exists in part because the EPA's
interpretations of statutes it administers ``[are not] instantly carved
in stone,'' but must be evaluated ``on a continuing basis.'' \17\ This
is true when, as is the case here, review is undertaken ``in response
to . . . a change in administrations.'' \18\ Indeed, ``[a]gencies
obviously have broad discretion to reconsider a regulation at any
time.'' \19\
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\17\ Chevron U.S.A. Inc. v. NRDC, Inc., 467 U.S. 837, 863-64
(1984).
\18\ National Cable & Telecommunications Ass'n v. Brand X
internet Services, 545 U.S. 967, 981 (2005).
\19\ Clean Air Council v. Pruitt, 862 F.3d 1, 8-9 (D.C. Cir.
2017).
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2. Legal Basis for Repeal of the Clean Power Plan
The CPP departed from the EPA's traditional understanding of its
authority under section 111 of the CAA and promulgated a rule in excess
of its statutory authority. Because the CPP significantly exceeded the
Agency's authority, it must be repealed.\20\ Fundamentally, the CPP
read the statutory term ``best system of emission reduction'' so
broadly as to encompass measures the EPA had never before envisioned in
promulgating performance standards under CAA section 111. In contrast
to its traditional regulations that set performance standards based on
the application of equipment and practices at the level of an
individual facility, the EPA in the CPP set standards that could only
be achieved by a shift in the energy generation mix at the grid level,
requiring a shift from one type of fossil-fuel-fired generation to
another, and from fossil-fuel-fired generation as a whole towards
renewable sources of energy. The text of the CAA is inconsistent with
that interpretation, and the context, structure, and legislative
history confirm that the statutory interpretation underlying the CPP
was not a permissible construction of the Act.
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\20\ As noted above, the EPA received more than 1.5 million
comments on the Proposed Repeal. The Agency's consideration of and
responses to significant comments are reflected in section II.B.2 of
this preamble.
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a. CAA Requirements and Background
In 1970, Congress enacted section 111(b) of the CAA, authorizing
the EPA to promulgate ``standards of performance'' for new stationary
sources in certain source categories.\21\ Congress also directed the
EPA, under CAA section 111(d), to ``prescribe regulations which shall
establish a procedure'' \22\ for states to establish standards \23\ for
existing sources of certain air pollutants to which a standard of
performance would apply if such existing source were a new source.\24\
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\21\ CAA Amendments of 1970, Public Law 91-604, 84 Stat. at
1683-84 (Dec. 31, 1970); see also 42 U.S.C. 7411(b).
\22\ See section IV (addressing changes to the implementing
regulations).
\23\ As originally enacted, CAA section 111 required states to
establish ``emission standards'' for existing sources, but Congress
replaced that term with ``standard of performance'' as part of the
CAA Amendments of 1977. See Public Law 95-95, 91 Stat. at 699 (Aug.
7, 1977) (``Section 111(d)(1) . . . is amended by striking out
`emissions standards' in each place it appears and inserting in lieu
thereof `standards of performance' '').
\24\ CAA Amendments of 1970, 84 Stat. at 1684; see also 42
U.S.C. 7411(d).
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Since 1990, new- and existing-source CAA section 111 rulemakings
have been governed by the same statutory definitions.\25\ The CAA
defines the term ``standard of performance'' in two sections. CAA
section 111(a)(1) defines it, for purposes of section 111 (which
contains the new- and existing-source performance standard authority
in, respectively, CAA section 111(b) and 111(d)), as:
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\25\ See infra n.51.
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.\26\
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\26\ 42 U.S.C. 7411(a)(1).
And CAA section 302(l) defines ``standard of performance'' as ``a
requirement of continuous emission reduction, including any requirement
relating to the operation or maintenance of a source to assure
continuous reduction.'' \27\
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\27\ 42 U.S.C. 7602(l).
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EPA's role under CAA section 111(d) is narrow. Indeed, CAA section
111(d) tasks states with ``establish[ing] standards of performance for
any existing source'' and ``provid[ing] for the implementation and
enforcement of such standards of performance.'' It requires further
that the regulations the EPA is directed to adopt must permit the state
``to take into consideration, among other factors, the remaining useful
life of the existing source to which such standard [of performance]
applies.'' \28\ After all, Congress found that ``air pollution
prevention . . . and air pollution control at its source is the primary
responsibility of States and local governments.'' \29\
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\28\ 42 U.S.C. 7411(d)(1).
\29\ 42 U.S.C. 7401(a)(3).
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In contrast to CAA section 111(b) (where the EPA may directly
establish performance standards for emissions from new sources), the
EPA implements CAA section 111(d) by issuing regulations that it calls
``emission guidelines'' \30\ These guidelines provide states with
information to assist them in developing state plans establishing
standards of performance for existing designated facilities within
their jurisdiction that are submitted to the EPA for review. Such
information includes the EPA's determination of the ``best system of
emission reduction,'' which is commonly referred to as the BSER.
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\30\ See American Elec. Power Co. v. Connecticut, 564 U.S. 410,
424 (2011). See generally Section IV, infra (discussing the
promulgation of revised implementing regulations governing the EPA's
issuance of emission guidelines); 40 CFR part 60, subpart B.
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b. The Plain Meaning of CAA Sections 111(a)(1) and (d)
CAA section 111(d) provides that ``each State shall submit to the
Administrator a plan which (A) establishes standards of performance for
any existing source for [certain air pollutants] . . . and (B) provides
for the implementation and enforcement of such standards of
performance.'' \31\ Given how Congress has defined the phrase
``standard of performance'' for purposes of CAA section 111, the plain
meaning of CAA section 111(d), therefore is that states shall submit a
plan which ``establishes [a standard for
[[Page 32524]]
emissions of air pollutants which reflects the degree of emission
limitation achievable through the application of the [BSER] . . .] for
any existing source.''
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\31\ 42 U.S.C. 7411(d)(1) (emphasis added).
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While CAA section 111(a)(1) provides that the EPA determines the
BSER upon which existing-source performance standards are based,
Congress expressly limited the universe of systems of emission
reduction from which the EPA may choose the BSER to those systems whose
``application'' to an ``existing source'' will yield an ``achievable''
``degree of emission limitation.'' \32\ ``[W]here . . . the statute's
language is plain,'' courts explain, our `` `sole function . . . is to
enforce it according to its terms.' '' \33\
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\32\ Id.
\33\ Air Line Pilots Ass'n v. Chao, 167 F.3d 602, 791 (D.C. Cir.
2018) (quoting United States v. Ron Pair Enterprises, 489 U.S. 235,
241 (1989)).
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The EPA begins with the meaning of ``application,'' as it appears
in CAA section 111(a)(1). In the absence of a statutory definition, the
term must be construed in accordance with its ordinary or natural
meaning.\34\ Here the ordinary meaning of ``application'' refers to the
``act of applying'' or the ``act of putting to use.'' \35\ Accordingly,
a standard of performance must reflect the degree of emission
limitation that can be achieved by putting the BSER into use.
Furthermore, the ordinary and natural use of the term ``application,''
which is derived from the verb ``to apply,'' requires both a direct
object and an indirect object. In other words, someone must apply
something to something else (e.g., the application of general rules to
particular cases). In the case of CAA section 111, the direct object is
the BSER. CAA section 111(d) also provides that the indirect object is
the ``existing source''--``each State shall submit to the Administrator
a plan which (A) establishes standards of performance for any existing
source'' (emphasis added). The Act further defines an ``existing
source'' as ``any stationary source other than a new source,'' \36\ and
in turn defines a ``stationary source'' as ``any building, structure,
facility, or installation which emits or may emit any air pollutant.''
\37\ Consequently, CAA section 111 unambiguously limits the BSER to
those systems that can be put into operation at a building, structure,
facility, or installation. Such systems include, for example, add-on
controls (e.g., scrubbers) and inherently lower-emitting processes/
practices/designs.
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\34\ See Leocal v. Ashcroft, 543 U.S. 1, 10 (2004).
\35\ Merriam-Webster's Collegiate Dictionary (11th ed. 2003)
(``1: an act of applying: a (1) : an act of putting to use <~ of new
techniques> (2) : a use to which something is put ''). Definitions are also provided from when CAA section
111(a)(1) was last amended, see The Oxford English Dictionary (2d
ed. 1989) (``The action of applying; the thing applied. 1. a. The
action of putting a thing to another, of bringing into material or
effective contact''), and first enacted, see American Heritage
Dictionary of the English Language (2d ed. 1969) (``1. The act of
applying or putting something on. 2. Anything that is applied, such
as a cosmetic or curative agent. 3. The act of putting something to
a special use or purpose.'').
\36\ 42 U.S.C. 7411(a)(6).
\37\ 42 U.S.C. 7411(a)(3).
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Conversely, the plain language of CAA section 111 does not
authorize the EPA to select as the BSER a system that is premised on
application to the source category as a whole or to entities entirely
outside the regulated source category. First, Congress specified that
``standards of performance'' are established ``for new sources within
such category '' \38\ and ``for any existing source.'' \39\ CAA section
111, therefore, does not allow for the establishment of standards for
the source category or for entities not within the source category.
Instead, CAA section 111 standards must be established for individual
sources. Second, because CAA section 111 standards reflect an
``achievable'' ``degree of emission limitation'' through application of
the BSER, an owner or operator must be able to achieve an applicable
standard by applying the BSER to the designated facility. Accordingly,
the BSER--like standards of performance--cannot be premised on a system
of emission reduction that is implementable only through the combined
activities of sources or non-sources. Thus, the EPA is precluded from
basing BSER on strategies like generation shifting and corresponding
emissions offsets because these types of systems cannot be put into use
at the regulated building, structure, facility, or installation.\40\
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\38\ 42 U.S.C. 7411(b)(1)(B) (requiring the Administrator to
establish performance standards ``for new sources within such
category'' rather than for the category itself as a whole) (emphasis
added)
\39\ 42 U.S.C. 7411(d)(1)(A).
\40\ The CPP's BSER was in part designed to consist of
generation-shifting. See, e.g., 80 FR 64,776 (final rule)
(describing `building blocks' 2 and 3 as ``processes of shifting
dispatch from steam generators to existing NGCC units and from both
steam generators and NGCC units to renewable generators.'').
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c. Statutory Structure and Purpose Confirm That a ``System of Emission
Reduction'' Must Be Applied to an Individual Source and That CAA
Section 111 is Intended to Best Design, Build, Equip, Operate, and
Maintain Sources so as To Reduce Emissions
While the plain meaning of CAA section 111 provides that the BSER
must be applied to a building, structure, facility, or installation,
Congress' intent is also manifest in the statutory structure and
purpose. ``Statutory construction,'' the Supreme Court instructs, ``is
a holistic endeavor.'' \41\ The interpretation of a phrase ``is often
clarified by the remainder of the statutory scheme--because the same
terminology is used elsewhere in a context that makes its meaning
clear, or because only one of the permissible meanings produces a
substantive effect that is compatible with the rest of the law.'' \42\
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\41\ Czyzewski v. Jevic Holding Corp., 137 S. Ct. 973, 985
(2017) (citing United Savings Ass'n v. Timbers of Inwood Forest
Associates, 484 U.S. 365, 371 (1988)).
\42\ Utility Air Regulatory Group v. EPA, 573 U.S. 302, 321
(2014).
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(1) The Statutory Structure Limits a ``System of Emission Reduction''
to ``Systems'' That Have a Potential for Application to an Individual
Source
The conclusion that CAA section 111 standards are limited as
described above is confirmed by considering the section's place in the
overall statutory scheme. Congress tied CAA section 111 to the Best
Available Control Technology (``BACT'') provisions in CAA section
165.\43\ Section 165 provides that ``[a]ny major stationary source or
major modification subject to [preconstruction requirements] must
conduct an analysis to ensure the application of [BACT].'' \44\ A
permitting authority must ``conduct a BACT analysis on a case-by-case
basis . . . and must evaluate the amount of emission reductions that
each available emissions-reducing technology or technique would
achieve, as well as the energy, environmental, economic and other costs
. . . .'' \45\ The EPA has long recommended that permitting agencies
conduct this analysis through a top-down assessment of the best
available and feasible control technologies for the emissions subject
to BACT.\46\ ``Based on
[[Page 32525]]
this [technology] assessment, the permitting authority must [then]
establish a numeric emission limitation that reflects the maximum
degree of reduction achievable. . . .'' \47\
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\43\ 42 U.S.C. 7479(3) (``In no event shall application of `best
available control technology' result in emissions of any pollutants
which will exceed the emissions allowed by any applicable standard
established pursuant to section 7411 or 7412 of this title.'').
\44\ U.S. EPA, DRAFT New Source Review Workshop Manual:
Prevention of Significant Deterioration and Nonattainment Area
Permitting, B. 1 (October 1990) (``NSR Manual''), available at
https://www.epa.gov/sites/production/files/2015-07/documents/1990wman.pdf. Though the EPA never finalized this draft, it
continues to follow the analytical approach to the BACT analysis
contained within the NSR Manual. See also U.S. EPA, PSD and Title V
Permitting Guidance for Greenhouse Gases (March 2011) (``GHG
Permitting Guidance''), available at https://www.epa.gov/sites/production/files/2015-07/documents/ghgguid.pdf.
\45\ GHG Permitting Guidance at 17 (emphasis added).
\46\ See id. at 17-44.
\47\ Id. at 17, 44-46.
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In no event, Congress specified, can application of BACT result in
greater emissions than allowed by ``any applicable standard established
pursuant to section [1]11 or [1]12 . . . .'' \48\ To ensure such an
exceedance does not occur, NSPS serve as the base upon which BACT
determinations are made and are commonly viewed as the BACT ``floor.''
\49\ However, because Congress refers to ``any applicable standard
established pursuant to section [1]11,'' without reference to either
subsection (b) or (d), any applicable existing source standard would
also function as a BACT ``floor.'' \50\
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\48\ 42 U.S.C. 7479(3).
\49\ GHG Permitting Guidance, 25 n.64 (``While this guidance is
being issued at a time when no NSPS have been established for GHGs,
permitting authorities must consider any applicable NSPS as a
controlling floor in determining BACT once any such standards are
final.'').
\50\ Accordingly, certain commenters incorrectly argue that the
scope of CAA section 169 is irrelevant to regulating existing
sources under CAA section 111(d) because only CAA section 111(b)
standards (i.e., NSPS), not CAA section 111(d) existing-source
standards, apply to sources subject to BACT. However, both CAA
section 111(b) and (d) rely on the same definition of ``standard of
performance'' in CAA section 111(a), and the term's statutory
history (that is, its evolution through repeated acts of Congress
from 1970 to 1990) supports the conclusion that Congress intended
for the term to have the same meaning under both programs. Between
the 1970 and 1977 CAA Amendments, ``standards of performance''
applied only to the regulation of new sources under CAA section
111(b); existing sources, on the other hand, were required to meet
``emission standards,'' which was an undefined term. See Public Law
91-604, 84 Stat. at 1683-84. Between the 1977 and 1990 CAA
Amendments, CAA section 111(a)(1) provided three context-specific
definitions: One definition applied to all new stationary sources
regulated under CAA section 111(b) (basing standards on the best
technological system of continuous emission reduction (``TSCER''));
the second applied only to new fossil-fuel-fired sources regulated
under CAA section 111(b) (basing standards on the TSCER and
requiring a percent reduction in emissions); and a third applied to
existing sources regulated under CAA section 111(d) (basing
standards on the best system of continuous emission reduction). See
Public Law 95-95, 91 Stat. at 699-700. In 1990, however, Congress
replaced the three separate definitions with a singular definition
of ``standard of performance'' under CAA section 111(a)(1), to apply
throughout CAA section 111, based on application of the BSER. See
Public Law 101-549, 104 Stat. at 2631. The legislative history of
CAA section 111 demonstrates that Congress knew full well how to
require either that the regulations applying to new and existing
sources would be different in definition and scope (as in both the
1970 and 1977 versions of the Act) or that they would be the same
and demonstrates that in 1990 they plainly chose the latter course.
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The EPA has consistently taken the position that BACT encompasses
``all `available' control options . . . that have the potential for
practical application to the emissions unit and the regulated pollutant
under evaluation.'' \51\ This is so because BACT reflects a level of
control that the permitting agency ``determines is achievable for such
facility through application of production processes and available
methods, systems, and techniques, including fuel cleaning, clean fuels,
or treatment or innovative fuel combustion techniques for control.''
\52\ Put simply, both the statutory text and the EPA's long-standing
interpretation provide that BACT is limited to control options that can
be applied to the source itself and does not include control options
that go beyond the source.
---------------------------------------------------------------------------
\51\ GHG Permitting Guidance, 24 (emphasis added).
\52\ 42 U.S.C. 7479(3) (emphasis added).
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Because CAA section 111 operates as a floor to BACT, section 111
cannot be interpreted to offer a broader set of tools than are
available under section 165. Also, because BACT is limited to control
options that are applied to an individual source, so too with section
111. The explicit statutory link of CAA section 111 standards to BACT,
the statutory definition of the latter, the Agency's consistent
position that BACT must apply to and be achievable for a particular
facility, and the text of CAA section 111(b) and 111(d), confirm the
conclusion that the text of 111(a)(1) can only be read to mean that
standards of performance (and the BSER on which they are predicated)
are likewise measures applied to individual facilities.
(2) The Purpose of CAA Section 111 is To Design, Build, Equip, Operate,
and Maintain Individual Sources so as To Reduce Emissions
Congress intended that CAA section 111 would set minimum
requirements \53\ on individual sources to be designed, built,
equipped, operated, and maintained to reduce emissions. This purpose is
evidenced in the history of CAA section 111(a)(1)'s text and
corroborated by legislative history. CAA section 111 was originally
enacted as part of the 1970 CAA Amendments. In that enactment, state
plans under CAA section 111(d) were to establish ``emission standards''
rather than ``standards of performance.'' The EPA's CAA section 111(d)
implementing regulations, issued in 1975, provided that, in the case of
existing sources, the EPA would issue ``emissions guidelines,'' that
these guidelines would ``reflect the degree of emission reduction
achievable through the application of the [BSER] which (taking into
account the cost of such reduction) the Administrator has determined
has been adequately demonstrated for designated facilities,'' and that
state plans establishing standards of performance for existing sources
would be developed in light of these guidelines.\54\ Then in 1977,
Congress replaced the term ``emission standard'' under CAA section
111(d) with the phrase ``standard of performance''--a phrase defined
for all of CAA section 111 in section 111(a)(1). Thus, the history
behind CAA section 111(a)(1) is relevant to understanding EPA's
authority for both sections 111(b) and (d).
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\53\ In a 1978 BACT guidance document, the EPA explained that
performance standards reflect emission limits ``which can reasonably
be met by all new or modified sources in an industrial category,
even though some individual sources are capable of lower emissions.
Additionally, because of resource limitations in the EPA, revision
of new source standards must lag somewhat behind the evolution of
new or improved technology. Accordingly, new or modified facilities
in some source categories may be capable of achieving lower emission
levels that [sic] NSPS without substantial economic impacts. The
case-by-case BACT approach provides a mechanism for determining and
applying the best technology in each individual situation. Hence,
NSPS and NESHAP are Federal guidelines for BACT determinations and
establish minimum acceptable control requirements for a BACT
determination.'' U.S. EPA, Guidelines for Determining Best Available
Control Technology, 3 (December 1978).
Further, while some commenters suggest that the BSER must
reflect the ``greatest degree of emission control,'' citing to
section 113 of Senate bill 4358 (S. 4358, at 6, 1970 Legis. Hist. at
554-55), Congress imposed no such requirement. See Sierra Club, 657
F.2d at 330 (``we believe it is clear that this language is far
different from the words Congress would have chosen to mandate that
the EPA set standards at the maximum degree of pollution control
technologically achievable.'').
\54\ 40 FR 53346.
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The 1970 enactment of CAA section 111 represents a choice between
two alternative approaches to direct federal regulation of stationary
sources. Under the House bill, the Administrator would have been
authorized to establish ``emission standards'' for new sources of
pollutants that may contribute substantially to endangerment of the
public health or welfare. These standards would have ``require[d] that
new sources of such emissions be designed and equipped to maximize
emission control insofar as technologically and economically
feasible.'' \55\ The House bill did not contain any analogous
provisions for existing sources. Nevertheless, the House bill
contemplated that under CAA section 111, individual sources would be
designed to emit less.
---------------------------------------------------------------------------
\55\ H.R. Conf. Rep. No. 91-1783, 46 (December 17, 1970)
(emphasis added).
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Under the Senate approach, the Administrator would have established
[[Page 32526]]
``standards of performance'' for new sources based ``on the greatest
emission control possible through application of [the] latest available
control technology.'' \56\ This would have ensured ``that new
stationary sources are designed, built, equipped, operated, and
maintained so as to reduce emission[s] to a minimum.'' \57\
Accordingly, such standards would have reflected ``the degree of
emission control which can be achieved through process changes,
operation changes, direct emission control, or other methods.'' \58\ A
separate provision governing emissions of ``selected agents''
authorized the Administrator to develop ``emission standards'' for both
new and existing sources.\59\ However, the Senate ``recognize[d] that
certain old facilities may use equipment and processes which are not
suited to the application of control technology. The [Administrator]
would be authorized therefore to waive the application of standards . .
. .'' \60\
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\56\ Id. (describing the approach under the Senate amendment).
\57\ S. Rep. No. 91-1196, 15-16 (September 17, 1970) (emphasis
added).
\58\ Id. at 17.
\59\ Id. at 18-19.
\60\ Id. at 19.
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The conference substitute settled on the language largely reflected
in the current wording of CAA section 111(a)(1); the differences
between the 1970 enactment and the current version are not relevant to
this discussion. As explained above, both the Senate and House bills
contemplated only control measures that would lead to better design,
construction, operation, and maintenance of an individual source \61\
and, in the case of existing sources under the Senate bill, the waiver
of standards if certain sources could not apply new control
technologies. Accordingly, recognizing that a ``system of emission
reduction'' is limited to control technologies or techniques that can
be integrated into an individual source's design or operation (i.e.,
add-on controls and lower-emitting processes/practices/designs) is the
only interpretation compatible with the fundamental principle,
reflected in the original competing drafts of the provision, that
sources should be designed, built, equipped, operated, and maintained
to reduce emissions.\62\
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\61\ References to ``other alternatives,'' ``other means,'' or
``other methods'' in the Senate bill and accompanying report are not
evidence that Congress intended to confer boundless discretion. In
fact, these terms must be interpreted in light of the other
specifically listed control techniques. For example, the Senate
bill's reference to ``control technology,'' ``processes,'' and
``operating methods'' are properly read to denote measures that can
be applied to individual sources--and ``other alternatives'' must be
interpreted ejusdem generis: in the same fashion.
\62\ To be sure, the Agency does not contend that a ``system of
emission reduction'' is limited to technological improvements.
Indeed, the CAA Amendments of 1990 make clear that CAA section 111
is not to be limited to ``technological systems.'' See supra n. 51
(discussing amendments to CAA section 111(a)(1)). But that does not
mean CAA section 111 therefore authorizes basing BSER on generation
shifting ``measures,'' such as substitute generation from lower- or
non-polluting power plants, which cannot be applied to individual
sources like add-on controls or inherently lower-emitting processes/
practices/designs.
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d. The CPP Unlawfully Exceeds the Scope of CAA Section 111(a)(1) and
Must Be Repealed
Before the CPP, the EPA had issued only six CAA section 111(d)
rulemakings, in the form of a ``guideline document'' with corresponding
``emission guidelines.'' \63\ Conversely, the EPA has issued around
seventy CAA section 111(b) rulemakings, including several for new
fossil-fuel-fired steam-generating units.\64\ Every one of those
rulemakings applied technologies, techniques, processes, practices, or
design modifications directly to individual sources.
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\63\ (See 1) Phosphate Fertilizer Plants, Final Guideline
Document Availability, 42 FR 12022 (March. 1, 1977) [Final Guideline
Document: Control of Fluoride Emissions from Existing Phosphate
Fertilizer Plants, March 1977, Doc. No. EPA-450/2-77-005]; 2)
Emission Guideline for Sulfuric Acid Mist, 42 FR 55796 (October 18,
1977); 3) Kraft Pulp Mills; Final Guideline Document; Availability,
44 FR 29828 (May 22, 1979) [Kraft Pulping, ``Control of Emissions
from Existing Mills,'' March 1979, Doc. No. EPA-450/2-78-003b]; 4)
Primary Aluminum Plants; Availability of Final Guideline Document,
45 FR 26294 (Apr. 17, 1980) [Primary Aluminum: Guidelines for
Control of Fluoride Emissions from Existing Primary Aluminum Plants,
December 1979, Doc. No. EPA-450/2-78-049b]; 5) Standards of
Performance for New Stationary Sources and Guidelines for Control of
Existing Sources: Municipal Solid Waste Landfills, 61 FR 9905 (March
12, 1996); and 6) Standards of Performance for New and Existing
Stationary Sources: Electric Utility Steam Generating Units, 70 FR
28606 (May 18, 2005) (hereafter, the Clean Air Mercury Rule or CAMR)
(vacated in New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2007)
(reviewing an action that sought to shift regulation of certain
emissions from power plants from the CAA section 112 hazardous air
pollutants regime to the section 111 standards regime and holding
that the EPA failed to comply with the delisting requirements of
section 112(c)(9) and thus vacating the corresponding section 111
standards for electric utility steam generating units). This list of
six CAA section 111(d) rulemakings does not include any guideline
documents mandated by and carried out in compliance with CAA section
129 (governing solid waste incinerator units).
\64\ See generally 40 CFR part 60, subparts D-TTTT. In fact,
steam-generating units were among the first sources regulated under
section 111(b). See 36 FR 24876 (December 23, 1971) (promulgating
standards for steam generators, portland cement plants,
incinerators, nitric acid plants, and sulfuric acid plants).
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In the CPP, the EPA determined that the BSER for reducing
CO2 emissions from existing fossil fuel-fired power plants
was the combination of three ``building blocks'':
1. Improving heat rate at individual 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.
This was the first time the EPA interpreted the BSER to authorize
measures wholly outside a particular source.\65\ The EPA reached this
determination by interpreting the statutory term ``application'' as if
it instead read ``implementation'' (without pointing to any legal basis
for equating those terms), and interpreting the phrase ``system of
emission reduction'' broadly as ``a set of measures that work together
to reduce emissions and that are implementable by the sources
themselves.'' \66\ ``As a practical matter,'' the Agency continued,
``the `source' includes the `owner or operator' of any building,
structure, facility, or installation for which a standard of
performance is applicable.'' \67\ The EPA then concluded that the
breadth of a dictionary definition of the word ``system'' established
the bounds of its statutory authority, finding that the phrase ``
`system of emission reduction' . . . means a set of measures that
source owners or operators can implement to
[[Page 32527]]
achieve an emission limitation applicable to their existing source.''
\68\
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\65\ CAMR, which relied in part on a cap-and-trade mechanism,
was still ultimately ``based on control technology available in the
relevant timeframe,'' an approach fundamentally different than the
CPP's second and third ``building blocks,'' which were not based on
systems that could be applied to or at individual sources. Indeed,
the rule explained that the BSER refers to ``the combination of the
cap-and-trade mechanism and the technology needed to achieve the
chosen cap level.'' 70 FR 28620 (emphasis added). Accordingly, the
Agency concluded that it would be ``reasonable to establish a cap on
[the basis of using a particular technology] and require compliance
with that cap at a later point in time when the necessary technology
becomes widely available.'' Id. To the extent that CAMR's BSER
(i.e., the combined control technology and cap-and-trade program) is
premised on application to the source category (as opposed to an
individual source), however, CAMR would be unlawful. Trading as a
compliance mechanism under CAA section 111 is discussed in section
III.F.2.a of this preamble.
\66\ 80 FR 64762 (citing the Oxford Dictionary of English (3rd
ed.) (2010), among others). The EPA reached this interpretation in
part on the assumption that ``the terms `implement' and `apply' are
used interchangeably.'' See Legal Memorandum Accompanying Clean
Power Plan for Certain Issues at 84 n.175.
\67\ 80 FR 64762.
\68\ Id. The EPA acknowledged, nonetheless, that ``regulatory
requirements'' in the CPP would be based ``on measures the affected
EGUs can implement to assure that electricity is generated with
lower emissions'' and that ``do not require reductions in the total
amount of electricity produced.'' Id. at 64778. But the EPA did not
exclude such ``measures'' (i.e., reduced utilization and demand-side
energy efficiency) as being outside the scope of the dictionary
definition of ``system.'' Indeed, the EPA believed they would play
an important compliance role under the CPP. See id. at 64753-657
(discussing reduced utilization and demand-side energy efficiency
measures under rate-based and mass-based state plans). See also n.
83, infra.
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In reviewing the CPP, the EPA concludes that the interpretation
relied upon in the CPP ignored or misinterpreted critical statutory
elements and rules of statutory construction. After reconsidering the
relevant statutory text, structure, and purpose, the Agency now
recognizes that Congress ``spoke to the precise question'' of the scope
of CAA section 111(a)(1) and clearly precluded the unsupportable
reading of that provision asserted in the CPP. Accordingly, this action
repeals the CPP.\69\
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\69\ One commenter asserted that, rather than repeal the CPP,
the EPA should retain building block 1. As explained in the Proposed
Repeal, however, while heat rate improvement measures may be
considered in a CAA section 111 standard, ``building block 1, as
analyzed, cannot stand on its own. 80 FR 64758 n. 444; see also id.
at 64658 (discussing severability of the building blocks).'' 82 FR
48039 n.5. Accordingly, today's action repeals the whole of the CPP
and does not retain building block 1 as the BSER. In any case, as
discussed in the ACE proposal, ``building block 1, as constructed in
[the] 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.'' 83 FR 44756 (discussing the EPA's
change in approach to analyzing heat rate improvement measures). See
section III for the EPA's evaluation of heat rate improvement
measures under ACE.
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(1) The CPP Is Impermissibly Based on ``Implementation'' Rather Than
``Application'' of the BSER
CAA section 111(a)(1) provides that standards of performance
reflect an emission limitation achievable ``through the application of
the [BSER] . . . .'' In the Legal Memorandum accompanying the CPP, the
Agency stated in a footnote that ``the terms `implement' and `apply'
are used interchangeably.'' \70\ Thus, the Agency decided, ``the system
must be limited to measures that can be implemented--``appl[ied]''--by
the sources themselves . . . .'' \71\ But Congress does not in fact use
these terms interchangeably in the Act, and in CAA section 111(a)(1),
as in other source-focused standard-setting provisions in the Act, used
a term (``application'') meaningfully different than the one CPP read
into that section (``implementation'')--and the term that Congress
actually used is one that reflects the CAA's other source-focused
standard-setting provisions.\72\
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\70\ Legal Memorandum Accompanying Clean Power Plan for Certain
Issues at 84 n.175.
\71\ 80 FR 64720.
\72\ See, e.g., 42 U.S.C. 7412(d)(2) (describing MACT as
``through application of measures, processes, methods, systems or
techniques including, but not limited to, measures which--(A) reduce
the volume of, or eliminate emissions of, such pollutants through
process changes, substitution of materials or other modifications,
(B) enclose systems or processes to eliminate emissions, (C)
collect, capture or treat such pollutants when released from a
process, stack, storage or fugitive emissions point, (D) are design,
equipment, work practice, or operational standards . . . , or (E)
are a combination of the above;''); id. at 7479(3) (describing BACT
as ``achievable for such facility through application of production
processes and available methods, systems, and techniques, including
fuel cleaning, clean fuels, or treatment or innovative fuel
combustion techniques for control'').
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The Act is replete with provisions calling for the
``implementation'' of ``a system,'' \73\ ``control measures,'' \74\
``emission reduction measures,'' \75\ and even ``steps, by owners or
operators of stationary sources,'' \76\ but CAA section 111(a)(1) is
not among them. Congress defines ``implementing'' under CAA section
105(a)(1)(A) as ``any activity related to the planning, developing,
establishing, carrying-out, improving, or maintaining of such programs
[for the prevention and control of air pollution or implementation of
national primary and secondary ambient air quality standards].'' \77\
But again, ``applying'' is not included in this list defining
``implementing.'' In the case of the Act's standard-setting provisions,
on the other hand, BACT and maximum achievable control technology
(MACT) requirements--like CAA section 111--are based on ``application
of'' control measures to individual sources.
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\73\ 42 U.S.C. 7412(r)(7)(H)(vii) (``the Administrator . . .
shall develop and implement a system for providing off-site
consequence analysis information'').
\74\ Id. 7511a(b)(2) (``Such plan provisions shall provide for
the implementation of all reasonably available control measures'').
\75\ Id. 7412(i)(5)(C) (``prior to implementation of emissions
reduction measures'').
\76\ Id. 7410(a)(2)(F) (emphasis added) (``require, as may be
prescribed by the Administrator--(i) the installation, maintenance,
and replacement of equipment, and the implementation of other
necessary steps, by owners or operators of stationary sources'').
\77\ 42 U.S.C. 7405(a)(1)(A).
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Functionally, the two terms send different signals.
``Implementation'' requires a subject and direct object (I implement
the plan), whereas ``application'' requires a subject, direct object,
and indirect object (I apply the protocol to the subject). That is, an
owner or operator can implement a system (without anything more and
without any particular object of the system being implied), but an
owner/operator must apply a system to another object (i.e., the
source). CAA section 111 illustrates this distinction. Congress
provided, in CAA section 111(d)(1), that state plans must provide ``for
the implementation and enforcement of such standards of performance,''
but that EPA's regulations must also permit a state ``in applying a
standard of performance to any particular source'' to take into
consideration, among other factors, the remaining useful life of the
existing source to which such standard applies. Thus, whereas state
plans more broadly ``implement'' the CAA section 111(d) program, states
``appl[y]'' standards to individual sources. Congress could have
defined a standard of performance as reflecting the ``implementation of
the BSER by the owner or operator of a stationary source,'' but
Congress did not. Simply put, equating the terms ``implement'' and
``apply'' conflicts with the plain language of CAA section 111(a)(1)
and their use throughout the Act; this conflict is compounded by the
conflation of the source with its owner, different concepts that are
separately defined, see CAA section 111(a)(3), (5).
Now take generation shifting, the basis for the second and third
``building blocks'' of the CPP's BSER. The CPP recognized that an owner
or operator of a regulated source can ``shift'' power-producing
operations to a different facility, such as a nuclear power plant,
through bilateral contracts for capacity or by reducing utilization.
But just because generation shifting is ``implementable'' by an owner
or operator (i.e., just because an owner or operator of a given source
can subsidize generation elsewhere that will reduce demand for
generation from that) does not mean that generation shifting can be
``applied'' to the source.\78\ And indeed, the CPP shifted generation
from one regulated source category to another and from both those
regulated source categories together to other forms of electricity
generation outside any regulated source category. Because the CPP is
premised on ``implementation of the BSER by a source's owner or
operator'' and not ``application of the [BSER]'' to an individual
source, the rule contravenes the plain language of CAA section
111(a)(1) and must be repealed.
---------------------------------------------------------------------------
\78\ A contract, for example, is neither a ``system'' nor
``applied to'' a source.
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[[Page 32528]]
(2) Dictionary Definitions Cannot Confer an ``Infinitude'' of
Possibilities
Although the word ``system'' is not defined in the CAA, ``[t]he
meaning--or ambiguity--of certain words or phrases may only become
evident when placed in context.'' \79\ Thus, the issue is not whether
the dictionary provides a broad definition of the word ``system,'' but
what are the permissible bounds of the legal meaning of the word
``system.'' The precise question in this case is whether the word
``system'' as used in CAA section 111 encompasses any ``set of
measures'' \80\ to reduce emissions, or whether it is limited to lower-
emitting processes, practices, designs, and add-on controls that are
applied at the level of the individual facility.
---------------------------------------------------------------------------
\79\ King v. Burwell, 135 S. Ct. 2480, 2489 (2015) (quoting FDA
v. Brown & Williamson Corp., 529 U.S. 120, 132 (2000)).
\80\ 80 FR 64762.
---------------------------------------------------------------------------
``System,'' as used in CAA section 111, cannot be read to encompass
any ``set of measures'' that would--through some chain of causation--
lead to a reduction in emissions. As an initial matter, Congress did
not use the phrase ``set of measures'' in CAA section 111. On its own,
this phrase could create unbounded discretion in the Agency. Moreover,
even when the term ``measures'' is used elsewhere in the Act, it is
intended to be limited. For example, CAA section 112 emission standards
are derived ``through application of measures, processes, methods,
systems or techniques.'' ``Measures,'' are further defined to include
measures which:
Reduce the volume of, or eliminate emissions of, such
pollutants through process changes, substitution of materials or other
modifications,
enclose systems or processes to eliminate emissions,
collect, capture or treat such pollutants when released
from a process, stack, storage or fugitive emissions point,
are design, equipment, work practice, or operational
standards (including requirements for operator training or
certification) as provided in subsection (h) of CAA section 111, or
are a combination of the above.\81\
---------------------------------------------------------------------------
\81\ 42 U.S.C. 7412(d)(2).
---------------------------------------------------------------------------
``Measures,'' as Congress provides, are limited to control measures
that can be integrated into an individual source's design or operation.
``Measures'' do not include shifting production away from the regulated
source. The CPP read ``system'' in CAA section 111(a)(1) to mean any
``set of measures,'' relying on the dictionary, and then determined
that there was no limitation on those ``set of measures'' so long as
they were measures that could be implemented through obligations placed
on the owner or operator of a source.\82\ At both steps, the CPP relied
on an absence of an express textual commandment forbidding these open-
ended interpretations. That methodology is untenable.
---------------------------------------------------------------------------
\82\ The CPP identified purported limitations to the underlying
legal interpretation (e.g., ``system'' does not extend to measures
that directly target consumer behavior), see 80 FR 64776-779, but
those purported limitations still led to an interpretation that far
exceeded the bounds of the authority actually conferred by Congress
on the EPA.
---------------------------------------------------------------------------
Construing ``system'' to offer such an ``infinitude'' \83\ of
possibilities would have significant implications. The fact is, fossil
fuel-fired EGUs operate within an interconnected ``system.'' Thus, any
action that would affect electricity rates will have generation-
shifting and potentially emission-reduction consequences. By the very
nature of the interconnected grid, EPA's authority to determine the
BSER under CAA section 111 is, under the Agency's prior interpretation,
stretched to every aspect of the entire power sector. This cannot have
been the intent of the Congress that enacted CAA section 111.
---------------------------------------------------------------------------
\83\ See Cal. Indep. Sys. Operator Corp. v. FERC, 372 F.3d 395,
401 (D.C. Cir. 2004) (``Cal ISO'').
---------------------------------------------------------------------------
The D.C. Circuit has previously disapproved of a federal agency's
expansive reading of its authority in analogous circumstances. In Cal
ISO, the D.C. Circuit vacated the Federal Energy Regulatory
Commission's (``FERC'') attempt to reform a utility's governing
structure on the theory that FERC's statutory authority over
``practice[s] . . . affecting [a] rate'' gave FERC ``authority to
regulate anything done by or connected with a regulated utility, as any
act or aspect of such an entity's corporate existence could affect, in
some sense, the rates.'' \84\
---------------------------------------------------------------------------
\84\ Id.
---------------------------------------------------------------------------
Upholding FERC's interpretation of ``practice'' to include
replacing the governing board of California's Independent System
Operator Corporation, the Court warned, could authorize FERC to
``dictate the choice of CEO, COO, and the method of contracting for
services, labor, office space, or whatever one might imagine . . . .''
\85\ But where ``the text and reasonable inferences from it give a
clear answer . . . that . . . is `the end of the matter.' '' \86\ There
is no need, therefore, to consider ``such parade of horribles.'' \87\
---------------------------------------------------------------------------
\85\ Id. at 403.
\86\ Id. at 401 (citing Brown v. Gardiner, 513 U.S. 115, 120
(1994)) (emphasis in original).
\87\ Id. at 403.
---------------------------------------------------------------------------
The Court explained that, ``no matter how important the principle
of ISO independence is to the Commission, `[the FERC Order] is merely a
regulation,' and cannot be the basis to override the limitations of
`statutes enacted by both houses of Congress and signed into law by the
president.'' \88\ The court reasoned that both ``the history of the
application of this and similar statutes and by the implications of
FERC's amorphous defining of the term'' firmly barred FERC's attempt to
stretch its authority.\89\ On this point, Congress's intent is
``crystal clear''--FERC had no authority to ``reform and regulate the
governing body of a public utility under the theory that corporate
governance constitutes a `practice' for ratemaking authority
purposes.'' \90\
---------------------------------------------------------------------------
\88\ Id. at 404.
\89\ Id. at 402.
\90\ Id.
---------------------------------------------------------------------------
The EPA's prior interpretation underlying the CPP is untenable for
the same reasons. The EPA began, like FERC, with an ordinary statutory
term (``system'') and then read into it maximally broad authority to
shift generation away from coal-fired and gas-fired power plants to
other electricity producers on the basis that generation shifting would
cause those regulated sources to be displaced and therefore not be a
source of emissions. But for nearly 45 years prior to the CPP, this
Agency had never understood CAA section 111 to confer upon it the
implicit power to restructure the utility industry through generation-
shifting measures. Indeed, the EPA has issued many rules under CAA
section 111 (both the limited set of existing-source rules under CAA
section 111(d) and the much larger set of new-source rules under CAA
section 111(b)). In all those rules, the EPA determined that the BSER
consisted of add-on controls or lower-emitting processes/practices/
designs that can be applied to individual sources.\91\
---------------------------------------------------------------------------
\91\ See supra n. 66 (discussing CAMR).
---------------------------------------------------------------------------
The CPP deviated from this settled understanding of CAA section
111. By embracing an expansive dictionary definition of ``system,''
\92\ the EPA ignored that the text and structure of the Act expressly
limited the scope of the term ``system'' in a way that foreclosed the
CPP's expansive definition. The Agency concluded that actions that
would cause generation to shift from higher-emitting to lower- or non-
[[Page 32529]]
emitting power generators represent a means of reducing CO2
emissions from existing fossil fuel-fired electric generating units--
and thus constituted a ``system'' within the meaning of CAA section
111. Taken to its logical end, however, any action affecting a
generator's operating costs could impact its order of dispatch and lead
to generation shifting. This could include, for example, minimum wage
requirements or production caps. It is axiomatic that ``Congress . . .
does not alter the fundamental details of a regulatory scheme in vague
terms or ancillary provisions--it does not, one might say, hide
elephants in mouseholes.'' \93\ Because Congress clearly did not
authorize CAA section 111 standards to be based on any ``set of
measures,'' the EPA need not address the potential consequences of
deviating from our historical practice under CAA section 111 when
determining whether the CPP's interpretation was a permissible reading
of the statute. Like the D.C. Circuit in Cal ISO, the EPA concludes
that the text and reasonable inferences from it give a clear answer:
``system'' does not embody any conceivable ``set of measures'' that
might lead to a reduction in emissions, but is limited to measures that
can be applied to and at the level of the individual source
---------------------------------------------------------------------------
\92\ 80 FR at 64720 (defined by the Oxford Dictionary of English
as ``a set of things or parts forming a complex whole; a set of
principles or procedures according to which something is done; an
organized scheme or method; and a group of interacting,
interrelated, or independent elements'').
\93\ Whitman v. American Trucking, 531 US 457, 466 (2001). See
also Letter from Neil Chatterjee, Chairman, Fed. Energy Reg. Comm'n,
to Andrew Wheeler, Administrator, EPA at 5 (Oct. 31, 2018) (Docket
ID# EPA-HQ-OAR-2017-0355-24053) (``The Supreme Court has explained
several times that Congress `does not alter the fundamental details
of a regulatory scheme in vague terms or ancillary provisions--it
does not, one might say, hide elephants in mouseholes.' The
challenges posed by global climate change present `question[s] of
deep `economic and political significance' that [are] central to
[the] statutory scheme[s]' administered by both the Agency and the
Commission.'') (internal citation omitted).
---------------------------------------------------------------------------
(3) Basing BSER on Generation Shifting Is Not Authorized by Congress
On the question of whether basing BSER on generation shifting is
precluded by the statute, the major question doctrine instructs that an
agency may issue a major rule only if Congress has clearly authorized
the agency to do so. As the Supreme Court has stated, ``We expect
Congress to speak clearly if it wishes to assign to an agency decisions
of vast `economic and political significance.' '' \94\ Although the
Court has not articulated a bright-line test, its cases indicate that a
number of factors are relevant in distinguishing major rules from
ordinary rules: ``the amount of money involved for regulated and
affected parties, the overall impact on the economy, the number of
people affected, and the degree of congressional and public attention
to the issue.'' \95\
---------------------------------------------------------------------------
\94\ Utility Air Regulatory Group v. EPA, 573 U.S. 302, 324
(2014) (quoting Brown & Williamson, 529 U.S. at 159).
\95\ U.S. Telecom Ass'n v. FCC, 855 F.3d 381, 422-23 (D.C. Cir.
2017) (internal citations omitted).
---------------------------------------------------------------------------
While the EPA believes that today's action is based on the only
permissible reading of the statute and would reach that conclusion even
without consideration of the major question doctrine, the EPA believes
that that doctrine should apply here and that its application confirms
the unambiguously expressed intent of CAA section 111. The CPP is a
major rule. At the time the CPP was promulgated, its generation-
shifting scheme was projected to have billions of dollars of impact on
regulated parties and the economy, would have affected every
electricity customer (i.e., all Americans), was subject to litigation
involving almost every State in the Union, and, as discussed in the
following section, would have disturbed the state-federal and intra-
federal jurisdictional scheme. Building blocks 2 and 3 are far afield
from the core activity of CAA section 111--indeed, no section 111 rule
of the scores issued has ever been based on generation shifting since
the enactment of CAA section 111 in 1970. Because the CPP is a major
rule, the interpretative question raised in CAA section 111(a)(1)
(i.e., whether a ``system of emission reduction'' can consist of
generation-shifting measures) must be supported by a clear-statement
from Congress.\96\ As explained above, however, it is not--indeed,
Congress has directly spoken to this precise question and precluded the
interpretation of CAA section 111 advanced by the EPA in the CPP.
---------------------------------------------------------------------------
\96\ The EPA acknowledges that for the reasons noted above, its
position on this major rule issue has evolved since the EPA
addressed it in the CPP, 80 FR 64,783. See FCC v. Fox Television
Stations, Inc., 556 U.S. 502 (2009).
---------------------------------------------------------------------------
Further evidence comes from the notable absence of a valid limiting
principle to basing a CAA section 111 rule on generation shifting. In
the CPP, the EPA explained that the Agency ``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.'' \97\ But by shifting
focus to the entire grid (which includes regulated sources and non-
sources), the Agency could empower itself to order the wholesale
restructuring of any industrial sector (whether or not it has authority
to even regulate all the actors within that sector--so long, in keeping
with the interpretation underlying the CPP, as it can place obligations
on the owners and operators over whom it does have authority to carry
out a ``system'' that goes beyond the EPA's actual direct reach).
Appealing to such factors as ``cost'' and ``feasibility'' \98\ as
putative constraints on EPA's authority, furthermore, does not provide
any assurance--indeed, the D.C. Circuit traditionally ``grant[s] the
[A]gency a great degree of discretion in balancing them.'' \99\ Thus,
it is not reasonable to find in this statutory scheme Congressional
intent to endow the Agency with discretion of this breadth to regulate
a fundamental sector of the economy.
---------------------------------------------------------------------------
\97\ 80 FR 64762.
\98\ See Legal Memorandum Accompanying Clean Power Plan for
Certain Issues at 117-20.
\99\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir.
1999).
---------------------------------------------------------------------------
As a final point, the CPP not only advanced a broad reading of CAA
section 111(a)(1), the rule applied that interpretation to ``the source
category as a whole'' \100\ to cause a reduction in coal-fired
generation.\101\ To do so, the CPP relied on ``emission reduction
approaches that focus on the machine as a whole--that is, the overall
source category--by shifting generation from dirtier to cleaner sources
in addition to emission reduction approaches that focus on improving
the emission rates of individual sources.'' \102\ Consequently, it was
designed as ``an emission guideline for an entire category of existing
sources . . . .'' \103\ However, by acting as a guideline for an entire
category, the CPP ignored the statutory directive to establish
standards for sources and overextended federal authority into matters
traditionally reserved for states: ``administration of integrated
resource planning and . . . utility generation and resource
portfolios.'' \104\
---------------------------------------------------------------------------
\100\ 80 FR 64727.
\101\ Id. at 64665.
\102\ 80 FR 64725-726; see also id. at 64726 (noting
``consideration of emission reduction measures at the source-
category level'').
\103\ CPP RTC Chapter 1A, 170-72.
\104\ New York v. FERC, 535 US 1, 24 (2002).
---------------------------------------------------------------------------
(4) Basing BSER on Generation Shifting Encroaches on FERC and State
Authorities
The Federal Power Act (FPA) establishes the dichotomy between
federal and state regulation in the electricity sector by drawing ``a
bright line easily ascertained, between state and federal
jurisdiction.'' \105\ The Supreme Court recently observed that, under
the FPA, FERC has ``exclusive jurisdiction over wholesale sales of
electricity in the interstate market'' and
[[Page 32530]]
establishing the associated just and reasonable rates and charges.\106\
However, ``the law places beyond FERC and leaves to the States alone,
the regulation of `any other sale'--most notably, any retail sale--of
electricity.'' \107\ Therefore, under the FPA, Congress limited the
jurisdiction of FERC ``to those matters which are not subject to
regulation by the States,'' including ``over facilities used for the
generation of electric energy.'' \108\ Indeed, ``the States retain
their traditional responsibility in the field of regulating electrical
utilities for determining questions of need, reliability, cost, and
other related state concerns.'' \109\ ``Such responsibilities include
``authority over the need for additional generating capacity [and] the
type of generating facilities to be licensed.'' \110\ Thus, the FPA
``not only establishes an affirmative grant of authority to the federal
government to regulate wholesale sales and transmission of electricity
in interstate commerce, but also draws a line where that exclusive
authority ends and the state's exclusive authority to regulate other
matters . . . begins.'' \111\
---------------------------------------------------------------------------
\105\ Fed. Power Comm'n v. S. Cal. Edison Co., 376 U.S. 205, 215
(1964).
\106\ Hughes v. Talen Energy Marketing, LLC, 136 S.Ct. 1288,
1291-92 (2016) (citing 16 U.S.C. 824(b)(1), 824d(a) and 824e(a)).
\107\ Id. at 1292 (quoting FERC v. Electric Power Supply Assn.,
136 S.Ct. 760, 766 (2016) (EPSA) (quoting 824(b)). The States'
reserved authority includes control over in-state ``facilities used
for the generation of electric energy.'' 824(b)(1); see Pacific Gas
& Elec. Co. v. State Energy Resources Conservation and Development
Comm'n, 461 U.S. 190, 205 (1983) (``Need for new power facilities,
their economic feasibility, and rates and services, are areas that
have been characteristically governed by the States.'').
\108\ 16 U.S.C. 824(a), 824(b)(1); see also id. 824o(i)(2)
(``This section does not authorize . . . [FERC] to order the
construction of additional generation or transmission capacity'').
There are other jurisdictional limitations under the FPA. For
example, publicly-owned and many cooperatively owned utilities are
subject to only some elements of the FPA. Id. 824(f), 824(b)(2). And
entities not operating in interstate commerce, i.e., entities in
Alaska, Hawaii, and the Electric Reliability Council of Texas
portion of Texas, are also subject to only limited FERC
jurisdiction.
\109\ Pacific Gas & Elec. Co. v. State Energy Resources
Conservation and Development Comm'n, 461 U.S. 190, 205 (1983).
\110\ Id. at 212.
\111\ Dennis, Jeffrey S., et al., Federal/State Jurisdictional
Split: Implications for Emerging Electricity Technologies, 3
(December 2016), available at https://www.energy.gov/sites/prod/files/2017/01/f34/Federal%20State%20Jurisdictional%20Split-Implications%20for%20Emerging%20Electricity%20Technologies.pdf; see
also 16 U.S.C. 824o(i)(2) (``This section does not authorize . . .
[FERC] to order the construction of additional generation or
transmission capacity'').
---------------------------------------------------------------------------
Courts have observed that regulation of other areas may
incidentally affect areas within these exclusive domains, but there is
no room for direct regulation by States in areas of FERC domain or
vice-versa, and such regulation that would achieve indirectly what
could not be done directly is also prohibited.\112\ Just as ``FERC has
no authority to direct or encourage generation'' \113\ absent clear
authority from Congress, neither does (indeed, a fortiori so much the
less does) the EPA.\114\ The EPA has no more ability to ``do indirectly
what it could not do directly'' than FERC would with respect to matters
that the FPA left to the states. Historically, any traditional
environmental regulation of the power sector may have incidentally
affected these domains without indirectly or directly regulating within
them. For example, an on-site control, such as a scrubber, may affect
rate determinations as it is factored into potentially recovered costs.
The CPP, however, included a BSER that was based largely on measures
and subjects exclusively left to FERC and the states, rather than
inflicting only permissible, incidental effects on those domains.
---------------------------------------------------------------------------
\112\ Hughes, 136 S. Ct. at 1297-98. See also EPSA, 753 F.3d at
221, 224 (``the Federal Power Act unambiguously restricts FERC from
regulating the retail market'' and quoting Altamont Gas Transmission
Co. v. FERC, 92 F.3d 1239, 1248 (D.C. Cir. 1996)) (noting that
``FERC cannot `do indirectly what it could not do directly' '').
\113\ CRS, The Federal Power Act (FPA) and Electricity Markets,
9 (March 10, 2017), available at https://www.everycrsreport.com/files/20170310_R44783_dd3f5c7c0c852b78f3ea62166ac5ebdbd1586e12.pdf.
\114\ See 80 FR 64745 (explaining that ``the BSER also reflects
other CO2 reduction strategies that encourage increases
in generation from lower- or zero-carbon EGUs'') (emphasis added);
cf. 42 U.S.C. 7651(b) (providing that one purpose of Title IV (but
not the CAA overall) is to encourage the ``use of renewable and
clean alternative technologies'').
---------------------------------------------------------------------------
The CPP identified as part of the BSER generation-shifting
measures. Increased renewable generation capacity, building block 3,
falls within a state's authority to determine its generation mix and to
direct the planning and resource decisions of utilities under its
jurisdiction.\115\ Additionally, increased utilization of natural gas
combined cycle (NGCC) plants, building block 2, falls within that state
authority and within FERC's authority to determine just and reasonable
rates by requiring a conclusion that the associated costs of increased
utilization rates are reasonable, and, further ignores these areas of
exclusive regulation by neglecting to consider changes to regional
transmission organization (RTO) and ISO dispatch procedures necessary
to achieve the increased utilization rates. By including generation-
shifting measures within the states' and FERC's purview in the BSER,
rather than relying on traditional controls within the EPA's purview,
the EPA established a rule predicated largely upon actions in the power
sector outside of the scope of the Agency's authority to compel. Some
generation shifting may be an incidental effect of implementing a
properly established BSER (e.g., due to higher operation costs), but
basing the BSER itself on generation shifting improperly encroaches on
FERC and state authorities.
---------------------------------------------------------------------------
\115\ See S.Cal. Edison Co., 71 FERC 61,269 (June 2, 1995); see
also Pacific Gas & Elec. Co. v. State Energy Resources Conservation
and Development Comm'n, 461 U.S. 190, 205, 212 (1983).
---------------------------------------------------------------------------
Further, the actual effect of the CPP as anticipated by the EPA was
that the states would impose standards of performance based on the
EPA's BSER, and sources would largely rely on generation-shifting
measures to comply with those standards. In its analysis of potential
energy impacts associated with the rule, the CPP modeling ``presume[d]
policies that lead to generation shifts and growing use of demand-side
[energy efficiency] and renewable electricity generation out to 2029.''
\116\ In this manner, the CPP could directly shape the generation mix
of a complying state. It is clear from the FPA that Congress intended
the states to have that authority, not the relevant federal agency,
FERC. Given that even FERC would not have such authority, the only
reasonable inference is that Congress did not intend to give the EPA
that authority via CAA section 111.\117\ Federal law ``may not be
interpreted to reach into areas of state sovereignty unless the
language of the federal law compels the intrusion,'' \118\ and, as
discussed above, basing BSER on generation shifting is not authorized
by Congress here. Such an interpretation is also consistent with the
cooperative-federalism framework of the CAA.\119\ While the EPA has
previously asserted that the CPP only provides emissions guidelines,
leaving the states with the flexibility to create their own compliance
measures,\120\ the guidelines are based on actions outside of the EPA's
authority to directly or indirectly compel and the practical effect of
[[Page 32531]]
implementing the guidelines is that many of those actions likely must
be taken.
---------------------------------------------------------------------------
\116\ 80 FR 64927.
\117\ See Solid Waste Agency of Northern Cook County v. U.S.
Army Corps of Engineers, 531 U.S. 159, 172 (2001) (citing Edward J.
DeBartolo Corp. v. Florida Gulf Coast Building & Constr. Trades
Council, 485 U.S. 568, 575 (1988)).
\118\ Am. Bar Ass'n v. FTC, 430 F.3d 457 (D.C. Cir. 2005).
\119\ See, e.g., 42 U.S.C. 7401(b)(3) and (4), 7402(a) and (b),
and 7416.
\120\ 80 FR 64762 (``States will have the flexibility to choose
from a range of plan approaches and measures, including numerous
measures beyond those considered in setting the CO2
emission performance rates'').
---------------------------------------------------------------------------
(5) Commenters' Attempt To Recharacterize the BSER in the CPP as
Applying to Sources By Pointing to ``Reduced Utilization'' Is
Unavailing and Clearly Precluded by the CAA
(a) The CPP Rejected ``Reduced Utilization'' as a ``System'' for
Purposes of CAA Section 111.
Some commenters claim reduced utilization can be ``applied to'' a
source as an ``operational method'' for reducing emissions. In the CPP,
however, the EPA was clear that reduced utilization on its own ``does
not fit within our historical and current interpretation of the BSER.''
\121\ The EPA explained: ``Specifically, reduced generation by itself
is about changing the amount of product produced rather than producing
the same product with a process that has fewer emissions,'' \122\ and
the EPA has historically based pollution control on ``methods that
allow the same amount of production but with a lower-emitting
process.'' \123\ In proposing to repeal the CPP, the EPA noted that,
``[w]hereas 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.'' \124\
Accordingly, ``predicating a section 111 standard on a source's non-
performance would inappropriately inject the Agency into an owner/
operator's production decisions.'' \125\ The EPA is finalizing our
proposal that reduced utilization cannot be considered a ``best system
of emission reduction'' under CAA section 111(a)(1) because, as the EPA
said in the CPP, the EPA has never identified reduced utilization as
the BSER and the EPA interprets CAA section 111 to authorize emission
limits based on controls that reduce emissions without restricting
production. In addition, because the CPP was not premised on ``reduced
utilization''--indeed, the EPA expressly renounced that as a basis for
the CPP--commenters' attempt to justify the CPP on that basis is
unavailing.
---------------------------------------------------------------------------
\121\ 80 FR 64780.
\122\ Id.
\123\ 80 FR 64782 n.602.
\124\ 83 FR 44752.
\125\ Id.
---------------------------------------------------------------------------
(b) Standards of Performance Cannot Be Based on Reduced Utilization
Even if the CPP could be reframed as employing reduced utilization,
it would fail to satisfy statutory criteria.
CAA section 302(l) provides that a ``standard of performance''
means ``a requirement of continuous emission reduction, including any
requirement relating to the operation or maintenance of a source to
assure continuous reduction.'' Previously, the Agency has argued that
the definitions in CAA section 111(a)(1) ``are more specific'' and
therefore controlling,\126\ but, to the extent that section 302(l)
applies, that definition is met when a standard ``applies continuously
in that the source is under a continuous obligation to meet its
emission rate . . . .'' \127\
---------------------------------------------------------------------------
\126\ See Brief of Respondent at 129-30, New Jersey v. EPA, No.
05-1097 (consolidated) (D.C. Cir. May 4, 2007).
\127\ 80 FR 64841. See also 70 FR 28617 (``Even if the 302(l)
definition applied to the term `standard of performance' as used in
section 111(d)(1), [the] EPA believes that a cap-and-trade program
meets the definition. . . . That is, there is never a time when
sources may emit without needing allowances to cover those
emissions.'').
---------------------------------------------------------------------------
Here, the Agency concludes that CAA section 302(l) is relevant to
interpreting CAA section 111.\128\ Statutes should be construed ``so as
to avoid rendering superfluous'' any statutory language: ``a statute
should be construed so that effect is given to all its provisions, so
that no part will be inoperative or superfluous, void or insignificant.
. . .'' \129\ Under the CAA, only section 111 requires the
establishment of ``standards of performance.'' Thus, ignoring the
generally applicable definition in CAA section 302(l) in interpreting
CAA section 111 would read it out of the statute. Nor is this a
situation where Congress provided that the provision-specific
definition in CAA section 111 was to supplant the general definition in
CAA section 302(l). First, the opening phrase of CAA section 302
indicates that the section 302 definitions apply ``[w]hen used in this
chapter.'' By contrast, the definitions provisions in some statutes
begins with text that expressly provides that the general statutory
definitions are supplanted by provision-specific definitions. See,
e.g., Clean Water Act (CWA) section 502 (33 U.S.C. 1362) (which begins
``Except as otherwise specifically provided . . . .''). Second, one of
the CAA section 302 definitions expressly states that it is supplanted
by provision-specific definitions.\130\
---------------------------------------------------------------------------
\128\ Indeed, the provisions of CAA section 302 are supplanted
by provision-specific definitions only to the extent that those
specific provisions ``expressly'' do so. See, e.g., Alabama Power v.
Costle, 636 F.2d 323, 370 (D.C. Cir. 1979) (holding that CAA section
169(1) is controlled by the general definition in CAA section 302(j)
with respect to the ``rule requirement'' in CAA section 302(j) that
is not expressly supplanted by CAA section 169(1)).
\129\ Hibbs v. Winn, 542 U.S. 88, 101 (2004). Cf. Brief of
Respondent at 129, New Jersey v. EPA (``[s]pecific terms prevail
over the general in the same or another statute which might
otherwise be controlling.'' (citation and quotation marks omitted)).
\130\ See CAA section 302(j) (which defines ``major stationary
source'' and ``major emitting facility'' and begins ``Except as
otherwise expressly provided, . . . .'').
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However, the Agency was wrong to conclude that ``a requirement of
continuous emission reduction'' means only that a standard of
performance need apply ``on a continuous basis.'' In fact, Congress
used such phrasing in the preceding definition under CAA section
302(k). The terms ``emission limitation'' and ``emission standard''
mean ``a requirement . . . which limits the quantity, rate, or
concentration of emissions of air pollutants on a continuous basis,
including any requirement relating to the operation or maintenance of a
source to assure continuous emission reduction. . . .'' \131\ Whereas
emission limitations and emission standards apply ``on a continuous
basis, including any requirement . . . to assure continuous emission
reduction,'' standards of performance must impose a ``requirement of
continuous emission reduction.''
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\131\ 42 U.S.C. 7602(k) (emphasis added). See H.R. 6161, Rep.
No. 95-294, 92 (May 12, 1977) (``Without an enforceable emission
limitation which will be complied with at all times, there can be no
assurance that ambient standards will be attained and maintained.
Any emission limitation under the [CAA], therefore must be met on a
constant basis. . . .'') (emphasis added).
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When Congress made explicit the requirement for ``continuous
emission reduction,'' it was to ``affirm the decisions of four U.S.
courts of appeals cases that the [A]ct requires continuous emission
reductions to be applied.'' \132\ Thus, as scholar David Currie
observed,
[[Page 32532]]
Congress ``intended to forbid reliance on intermittent control
strategies, such as temporary use of low-sulfur fuels or reductions in
plant output . . . .'' \133\ Because standards of performance cannot be
based on intermittent control strategies, basing BSER on reduced
utilization is statutorily precluded for purposes of CAA section 111.
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\132\ H.R. Conf. Rep. No. 95-564, 514 (Aug. 3, 1977); see also
H.R. No. 95-294, 190 (May 12, 1977) (``To make clear the committee's
intent that intermittent or supplemental control measures are not
appropriate technological systems for new sources (and to prevent
the litigation which has been conducted with respect to use of
intermittent or supplemental systems at existing sources), the
committee adopted language clearly stating that continuous emission
reduction technology would be required to meet the requirements of
this section.''); and id. at 92 (``By defining the terms `emission
limitation,' `emmission [sic] standard,' and `standard of
performance,' the committee has made clear that constant or
continuous means of reducing emissions must be used to meet these
requirements.''). For example, ``The Sixth Circuit has agreed with
the Fifth, upholding the EPA's rejection of a provision that would
have allowed `intermittent' controls when necessary to meet ambient
standards, adding on the basis of a stray remark of the Supreme
Court in Train that `emission standards' were only those limiting
the `composition' of an emission, not restrictions on operation or
on the content of fuels.'' David P. Currie, Federal Air-Quality
Standards and Their Implementation, 365 American Bar Foundation
Research Journal, 376 n.58 (1976).
\133\ David P. Currie, Direct Federal Regulation of Stationary
Sources Under the Clean Air Act, 128 U. Pa. L. Rev. 1389, 1431
(1980) (emphasis added). Professor Curie also suggests that ``the
requirement of continuous controls . . . may even have been implicit
in the original section 111.'' Id.
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Finally, basing the BSER on reduced utilization contravenes the
plain meaning of a ``standard of performance.'' As the Supreme Court
held most recently in Weyerhaeuser v. FWS, 139 S. Ct. 361 (2018),\134\
and previously in Solid Waste Agency of Northern Cook County, courts
must give statutory terms meaning, even where they are part of a larger
statutorily defined phrase.\135\ In the phrase ``standard of
performance,'' the term ``performance'' is defined as ``[t]he
accomplishment, execution, carrying out, . . . [or] doing of any action
or work,'' \136\ and thus refers to the source's manufacturing or
production of product. Reduced utilization does not involve
improvements to a source's emissions during ``performance;'' instead it
calls for non-performance--the cessation or limitation of manufacturing
or production --of a source. Accordingly, reduced utilization cannot
form the basis of a ``standard of performance'' under CAA section 111.
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\134\ 139 S.Ct. at 368-69 (rejecting environmental group's
contention that statutory definition of ``critical habitat'' is
complete and does not require independent inquiry into meaning of
the term ``habitat,'' which the statute left undefined).
\135\ 531 U.S. at 172 (requiring that the word ``navigable'' in
the Clean Water Act's statutorily defined term ``navigable waters''
be given ``effect'').
\136\ The Oxford English Dictionary (2d ed. 1989) (1. The
carrying out of a command, duty, purpose, promise, etc.; execution,
discharge, fulfilment. 2. a. The accomplishment, execution, carrying
out, working out of anything ordered or undertaken; the doing of any
action or work; working, action (personal or mechanical'') and
American Heritage Dictionary of the English Language (2d ed. 1969)
(``1. The act of performing, or the state of being performed.''
[perform 1. To begin and carry through to completion]).
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The definition of ``standard of performance,'' and the scope of the
``best system of emission reduction'' contained within, confers
considerable discretion on the EPA to interpret the statute and make
reasonable policy choices pursuant to Chevron step two as to what is
the best system to reduce emissions of a particular pollutant from a
particular type of source. However, by making clear that the
``application'' of the BSER must be to the source, Congress spoke
directly in Chevron step one terms to the question of whether the BSER
may contain measures other than those that can be put into operation at
a particular source: It may not. The approach to BSER in the CPP is
thus unlawful and the CPP must be repealed.
C. Independence of the Repeal of the Clean Power Plan
Although this action appears in the same document as the ACE rule
and the revisions to the emission guidelines implementing regulations,
the repeal of the CPP is a distinct final agency action that is not
contingent upon the promulgation of ACE or the new implementing
regulations. As explained above, Congress spoke directly to the
question of whether CAA section 111 authorizes the EPA to issue
regulations pursuant to CAA section 111(d) that call for the
establishment of standards of performance based on the types of
measures that comprised the second and third building blocks of the
CPP's BSER permits the Agency's to consider generation-shifting as a
potential system of emission reduction in developing emission
guidelines. The answer to that question is no.
The CPP described itself as a ``significant step forward in
reducing [GHG] emissions in the U.S.'' and relied ``in large part on
already clearly emerging growth in clean energy innovation, development
and deployment . . . .'' 80 FR 64663. Market-based forces have already
led to significant generation shifting in the power sector. However,
the fact that those market forces have had that result does not confer
authority on the EPA beyond what Congress conferred in the CAA.
The EPA does not deny that, if it were validly within the Agency's
authority under the statute, regulations that can only be complied with
through widespread implementation of generation shifting might be a
workable policy for achieving sector-wide carbon-intensity reduction
goals. But what is not legal cannot be workable. The CPP's reliance on
generation shifting as the basis of the BSER is simply not within the
grant of statutory authority to the Agency. The text of CAA section 111
is clear, leaving no interpretive room on which the EPA could seek
deference for the CPP's grid-wide management approach. Accordingly, EPA
is obliged to repeal the CPP to avoid acting unlawfully.
Because the EPA exceeded its statutory authority when it
promulgated the CPP, the EPA's repeal of that rule will remain valid
even if a future reviewing court were to find fault with the separate
and distinct legal interpretations and record-based findings
underpinning the ACE rule (see Section III) or the new implementing
regulations (see Section IV). The EPA today repeals the CPP as a
separate action, distinct from its promulgation of the ACE rule and of
revisions to its regulations implementing section 111(d). The EPA would
repeal the CPP today even if it were not yet prepared to promulgate
these other regulations, or indeed if it knew that those other
regulations would not survive judicial review.
III. The Affordable Clean Energy Rule
A. The Affordable Clean Energy Rule Background
1. Regulatory Background
In December 2017, the EPA published an Advanced Notice of Proposed
Rule Making (ANPRM) to solicit comment on what the Agency should
include in CAA section 111(d) emission guidelines, including soliciting
comment on the respective roles of the states and the EPA; what systems
of emission reduction might be available and appropriate for reducing
GHG emissions from existing coal-fired EGUs; and potential
flexibilities that could be afforded under the NSR program to improve
the implementation of a future rule.\137\ The EPA received more than
270,000 comments on the ANPRM.
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\137\ See 82 FR 61507 (December 28, 2017).
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Informed by the ANPRM, the EPA then published the ACE proposal,
which consisted of three distinct actions: (1) Emission guidelines for
GHG emissions from existing coal-fired EGUs, based on application of
HRI measures as the BSER; (2) new emission guideline implementation
regulations; and (3) revisions to the NSR program to facilitate the
implementation of efficiency projects at EGUs.\138\
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\138\ See 83 FR 44746 (August 31, 2018).
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In this final action, the EPA has determined that the BSER for
CO2 emissions from existing coal-fired EGUs is HRI, in the
form of a specific set of technologies and operating and maintenance
practices that can be applied at and to certain existing coal-fired
EGUs, which is consistent with the legal interpretation adopted in the
repeal of the CPP (see above section II). Also, in this action, the EPA
has provided information for state plan development. The state plan
development discussion is consistent with the new implementing
regulations for CAA section 111(d) emission guidelines discussed
separately in section IV of this preamble.
[[Page 32533]]
As noted above, the EPA also proposed revisions to the NSR program
in parallel with the ACE rule and the new implementing regulations. The
EPA is not finalizing NSR revisions at this time; instead, the EPA
intends to take final action on the proposed revisions at a later date
in a separate notification of final action.
2. Public Comment and Hearing on the ACE Proposal
The Administrator signed the ACE proposal on August 21, 2018, and,
on the same day, the EPA made this version available to the public at
https://www.epa.gov/stationary-sources-air-pollution/proposal-affordable-clean-energy-ace-rule. The 60-day public comment period on
the proposal began on August 31, 2018, the day of publication in the
Federal Register. The EPA held a public hearing on October 1, 2018, in
Chicago, Illinois, and extended the public comment period until October
31, 2018, to allow for 30 days of public comment following the public
hearing. The EPA received nearly 500,000 comments on the ACE proposal.
B. Legal Authority To Regulate EGUs
In the CPP, the EPA stated that the Agency's then-concurrent
promulgation of standards of performance under CAA section 111(b)
regulating CO2 emissions from new, modified, and
reconstructed EGUs triggered the need to regulate existing sources
under CAA section 111(d).\139\ In ACE, the EPA is not re-opening any
issues related to this conclusion, but for the convenience of
stakeholders and the public, the EPA summarizes the explanation
provided in the CPP here.
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\139\ See 80 FR 64715.
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CAA section 111(d)(1) requires the Agency to promulgate regulations
under which the 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.''
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. In the CPP, the EPA noted that, at
that time, the Agency was concurrently finalizing a rulemaking under
CAA section 111(b) for CO2 emissions from new sources, which
provided the requisite predicate for applicability of CAA section
111(d).\140\
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\140\ Id.
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The EPA explained in the CAA section 111(b) rule (80 FR 64529) that
``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.' '' Then, for the source categories listed under CAA section
111(b)(1)(A), the Administrator promulgates, under CAA section
111(b)(1)(B), ``standards of performance for new sources within such
category.'' The EPA further took the position that, because EGUs had
previously been listed, it was unnecessary to make an additional
finding as a prerequisite for regulating CO2. The Agency
expressed the view that, under CAA 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 pollutant-specific 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 the standard for
making such a listing. The Agency further took the position 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.'' \141\
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\141\ See 80 FR 64531.
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That CAA section 111(b) rulemaking remains in effect, although the
EPA has proposed to revise it.\142\ That rule continues to provide the
requisite predicate for applicability of CAA section 111(d).
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\142\ See 83 FR 65424.
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C. Designated Facilities for the Affordable Clean Energy Rule
The EPA is finalizing that a designated facility \143\ subject to
this regulation is any coal-fired electric utility steam generating
unit that: (1) Is not an integrated gasification combined cycle (IGCC)
unit (i.e., utility boilers, but not IGCC units); (2) was in operation
or had commenced construction on or before January 8, 2014; \144\ (3)
serves a generator capable of selling greater than 25 megawatts (MW) to
a utility power distribution system; and (4) has a base load rating
greater than 260 gigajoules per hour (GJ/h) (250 million British
thermal units per hour (MMBtu/h)) heat input of coal fuel (either alone
or in combination with any other fuel). Consistent with the new
implementing regulations, the term ``designated facility'' is used
throughout this preamble to refer to the sources affected by these
emission guidelines.\145\ For this action, consistent with prior CAA
section 111 rulemakings concerning EGUs, the term ``designated
facility'' refers to a single EGU that is affected by these emission
guidelines.
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\143\ The term ``designated facility'' means ``any existing
facility 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 40 CFR 60.21a(b).
\144\ Under CAA section 111, the determination of whether a
source is a new source or an existing source (and thus potentially a
designated facility) is based on the date that the EPA proposes to
establish standards of performance for new 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).
\145\ The EPA recognizes, however, that the word ``facility'' is
often understood colloquially to refer to a single power plant,
which may have one or more EGUs co-located within the plant's
boundaries.
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The EPA's applicability criteria for ACE differ from those in the
CPP because the EPA's determination of the BSER is only for coal-fired
electric utility steam generating units. In the ACE proposal, the EPA
did not identify a BSER for IGCC units, oil- or natural gas-fired
utility boilers, or fossil fuel-fired stationary combustion turbines
and, thus, such units are not designated facilities for purposes of
this action. In the ACE proposal (and previously in the ANPRM), the EPA
solicited information on the cost and performance of technologies that
may be considered as the BSER for fossil fuel-fired stationary
combustion turbines and other fossil-fuel fired EGUs. The EPA currently
does not have adequate information to determine a BSER for these EGUs
and, if appropriate, the EPA will address GHG emissions from these EGUs
in a future rulemaking.
A coal-fired EGU for purposes of this rulemaking (and consistent
with the definition of such units in the Mercury and Air Toxics
Standards (MATS) (77 FR 9304)) is an electric utility steam generating
unit that burns coal for more than 10.0 percent of the average annual
heat input during the three previous calendar years. Further, for
purposes of this rulemaking, the following EGUs will be excluded from a
state's plan: (1) Those units subject to 40 CFR part 60, subpart TTTT
as a result of commencing
[[Page 32534]]
a qualifying 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
megawatt-hour (MWh) or less on an annual basis; (3) a stationary
combustion turbine that meets the definition of a simple cycle
stationary combustion turbine, a combined cycle stationary combustion
turbine, or a combined heat and power combustion turbine; (4) an IGCC
unit; (5) non-fossil-fuel 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; (6) 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;
(7) a municipal waste combustor unit subject to 40 CFR part 60, subpart
Eb; (8) commercial or industrial solid waste incineration units that
are subject to 40 CFR part 60, subpart CCCC; or (9) a steam generating
unit that fires more than 50-percent non-fossil fuels.
D. Regulated Pollutant
The air pollutant regulated in this final action is GHGs. However,
the standards in this rule are expressed in the form of limits solely
on emissions of CO2, and not the other constituent gases of
the air pollutant GHGs.\146\ The EPA is not establishing a limit on
aggregate GHGs or separate emission limits for other GHGs (such as
methane (CH4) or nitrous oxide (N2O)) as other
GHGs represent significantly less than one percent of total estimated
GHG emissions (as CO2 equivalent) from fossil fuel-fired
electric power generating units.\147\ Notwithstanding the form of the
standard, consistent with other EPA regulations addressing GHGs, the
air pollutant regulated in this rule is GHGs.\148\
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\146\ In the 2009 Endangerment Finding for mobile sources, the
EPA defined the relevant ``air pollution'' as the atmospheric mix of
six long-lived and directly emitted greenhouse gases: Carbon dioxide
(CO2), methane (CH4), nitrous oxide
(N2O), hydrofluorocarbons (HFCs), perfluorocarbons
(PFCs), and sulfur hexafluoride (SF6). See 74 FR 66497.
Additionally, note that the new CAA section 111(d) implementing
regulations at 40 CFR 60.22a(b)(1) do not change the requirement of
the previous implementing regulations, 40 CFR 60.22(b)(1) that
emission guidelines provide information concerning known or
suspected endangerment of public health or welfare caused, or
contributed to, by the designated pollutant. For this emission
guideline, that information is contained in the 2009 Endangerment
Finding.
\147\ EPA Greenhouse Gas Reporting Program; www.epa.gov/ghgreporting/.
\148\ See, e.g., 79 FR 34960.
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E. Determination of the Best System of Emission Reduction
1. Guiding Principles in Determining the BSER
CAA section 111(d)(1) directs the EPA to promulgate regulations
establishing a procedure similar to that under CAA section 110,\149\
under which states submit state plans that establish ``standards of
performance'' for emissions of certain air pollutants from existing
sources which, if they were new sources, would be subject to new source
standards under CAA section 111(b), and that provide for the
implementation and enforcement of those standards of performance.
Because CAA section 111(a)(1) defines ``standard of performance'' for
purposes of all of section 111, and because federal standards for new
sources established under section 111(b) and standards for existing
sources established by a state plan under section 111(d) are both
``standards of performance,'' it is the EPA's responsibility to
determine the BSER for designated facilities for standards developed
under both CAA section 111(b) for new sources and section 111(d) for
existing sources.\150\ In making this determination, the EPA identifies
all ``adequately demonstrated'' ``system[s] of emission reduction'' for
a particular source category and then evaluates those systems to
determine which is the ``best,'' \151\ while ``taking into account''
the factors of ``cost . . . non-air quality health and environmental
impact and energy requirements.'' \152\ 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.\153\
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\149\ CAA section 110 governs state implementation plans, or
SIPs, which states develop and submit for EPA approval and which are
used to ensure attainment and maintenance of the National Ambient
Air Quality Standards (NAAQS) for criteria pollutants.
\150\ See also 40 CFR 60.22a. However, while the BSER underlying
both new- and existing-source performance standards is determined by
the EPA, the performance standards for new sources are directly
established by the EPA under section 111(b), whereas states
establish performance standards (applying the BSER) for existing
sources in their jurisdiction in their state plans under section
111(d), and Congress has expressly required that EPA permit states,
in establishing performance standards for existing sources, to take
into account the remaining useful life of the source and other
source-specific factors. See 42 U.S.C. 7411(d)(1).
\151\ The D.C. Circuit recognizes that the EPA's evaluation of
the ``best'' system must also include ``the amount of air pollution
as a relevant factor to be weighed . . . .'' Sierra Club v. Costle,
657 F.2d 298, 326 (D.C. Cir. 1981). Additionally, a system cannot be
``best'' if it does more harm than good due to cross-media
environmental impacts. See Portland Cement, 486 F. 2d at 384; Sierra
Club, 657 F.2d at 331; see also Essex Chemical Corp., 486 F.2d 427,
439 (D.C. Cir. 1973) (remanding standard to consider solid waste
disposal implications of the BSER determination). Nevertheless, CAA
section 111 does not require the ``greatest degree of emission
control'' or ``mandate that the EPA set standards at the maximum
degree of pollution control technologically achievable.'' Sierra
Club, 657 F.2d at 330.
\152\ The EPA may consider energy requirements on both a source-
specific basis and a sector-wide, region-wide or nationwide basis.
Considered on a source-specific basis, ``energy requirements''
entail, for example, the impact, if any, of the system of emission
reduction on the source's own energy needs. As discussed in this
document, a consideration of ``energy requirements'' informs the
EPA's judgment that repowering and refueling coal-fired facilities
to be fueled by natural gas is not appropriate for consideration as
BSER here.
\153\ Lignite Energy, 198 F.3d 930, 933 (D.C. Cir. 1999).
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The CAA limits ``standards of performance'' to systems that can be
applied at and to a stationary source (i.e., as opposed to off-site
measures that are implemented by an owner or operator, such as
subsidizing lower-emitting sources) and that lead to continuous
emission reductions (i.e., are not intermittent control techniques).
Such systems include add-on controls and lower-emitting processes/
practices/designs that can be applied to a designated facility, i.e., a
building, structure, facility, or installation regulated under CAA
section 111.\154\ As discussed in section II of this preamble, this is
the only permissible interpretation of the scope of the EPA's authority
under CAA section 111. But this clear outer bound on the EPA's
authority leaves the Agency considerable room for interpretation and
policy choice within that scope in determining the BSER that has been
adequately demonstrated to address a particular source category's
emission of a given pollutant. 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.'' \155\ While some of these cases suggest that ``[t]he
Administrator may make a projection based on existing technology,''
\156\ the D.C. Circuit has also
[[Page 32535]]
noted that ``there is inherent tension'' between considering a
particular control technique as both ``an emerging technology and an
adequately demonstrated technology.'' \157\ Nevertheless, the 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.'' \158\ The
essential question, therefore, is whether the BSER is ``available.''
\159\
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\154\ See section 111(a)(3) for definition of ``stationary
source.''
\155\ Essex Chemical Corp., 486 F.2d 375, 433-34 (D.C. Cir.
1973).
\156\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973).
\157\ 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'').
\158\ Sierra Club, 657 F.2d at 364. It is not clear whether
these cases would have applied the same technology-forcing
philosophy to the regulation of existing sources, as at least one
case noted that section 111 ``looks toward what may fairly be
projected for the regulated future, rather than the state of the art
at present, since it is addressed to standards for new plants--old
stationary source pollution being controlled through other
regulatory authority.'' Portland Cement, 486 F.2d at 391 (emphasis
added).
\159\ See Portland Cement v. Ruckelshaus, 486 F.2d at 391.
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In considering the availability of different systems of emission
reduction, the ``EPA must examine the effects of technology on the
grand scale,'' because CAA section 111 standards are, after all, ``a
national standard with long-term effects.'' \160\ To that end, the
Agency must ``consider the representativeness for the industry as a
whole of the tested plants on which it relies. . . .'' \161\ A CAA
section 111 standard, therefore, ``cannot be based on a `crystal ball'
inquiry.'' \162\
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\160\ Id. at 330.
\161\ Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 432-33 (D.C. Cir.
1980).
\162\ Essex Chemical Corp., 486 F.2d at 391.
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Whereas the EPA establishes performance standards for new sources
under CAA section 111(b), section 111(d) provides that states are
primarily responsible for regulating existing sources. This bifurcated
approach dovetails with testimony offered during development of the CAA
Amendments of 1970 (which established the section 111 program)--
specifically, Secretary Finch explained that ``existing stationary
sources of air pollution are so numerous and diverse that the problems
they pose can most efficiently be attacked by state and local
agencies.'' \163\ Indeed, Congress eventually made explicit the
requirement that the EPA allow states to take into account the
``remaining useful life'' of an existing source, ``among other
factors,'' when applying a standard of performance to any particular
source.\164\ Accordingly, the Agency's identification of the BSER is
based on what is ``adequately demonstrated'' and broadly achievable for
a source category across the country, while each state--which will be
more familiar with the operational and design characteristics of
actually existing sources within their borders--is responsible for
developing source-specific standards reflecting application of the
BSER.\165\ Indeed, Congress has expressly provided that the EPA must
permit states to take into consideration a source's remaining useful
life, among other factors, when applying a standard of performance to a
particular source.\166\
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\163\ Testimony of Robert Finch, Secretary of Health, Education,
and Welfare (which regulated air pollution prior to the
establishment of the EPA) in support of S. 3466/H.R. 15848, before
the House Subcommittee on Public Health and Welfare, H. Hearing (May
16, 1970), 1970 CAA Legis. Hist. at 1369.
\164\ 42 U.S.C. 7411(d)(1).
\165\ This approach is analogous to the NAAQS program: Where
``[e]ven with air quality standards being set nationally . . . the
steps needed to deal with existing stationary sources would
necessarily vary from one State to another and, within States, from
one area to another . . . .'' Id.
\166\ 42 U.S.C. 7411(d)(1).
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In the ACE proposal, the EPA provided a discussion of the
identified systems of emission reduction and explained why certain
systems were eliminated from consideration at a preliminary state or
were otherwise determined not to be the ``best system.'' The EPA
received public comments that challenged or refuted the Agency's
evaluation of these systems of emission reduction. A discussion of
those reduction measures and a summary of significant public comments
are provided below.
The EPA proposed that ``heat rate improvement'' (HRI, which may
also be referred to as ``efficiency improvement'') is the BSER for
existing coal-fired EGUs. In this action, after consideration of public
comments, the EPA is finalizing its proposed determination that HRI is
the BSER. The basis for the final determination and a summary of
significant public comments received on the proposed determination are
discussed below.
2. Heat Rate Improvement Is the BSER for Existing Coal-Fired EGUs
a. Background and BSER Determination
Heat rate is a measure of efficiency that is commonly used in the
power sector. The heat rate is the amount of energy or fuel heat input
(typically measured in British thermal units, Btu) required to generate
a unit of electricity (typically measured in kilowatt-hours, kWh). The
lower an EGU's heat rate, the more efficiently it converts heat input
to electrical output. As a result, an EGU with a lower heat rate
consumes less fuel per kWh of electricity generated and, as a result,
emits lower amounts of CO2--and other air pollutants--per
kWh generated (as compared to a less efficient unit with a higher heat
rate). Heat rate data from existing coal-fired EGUs indicate that there
is potential for improvement across the source category.
Heat rate improvement measures can be applied--and some measures
have already been applied--to all existing EGUs (supporting the
Agency's determination that HRI measures are the BSER). However, the
U.S. fleet of existing coal-fired EGUs is a diverse group of units with
unique individual characteristics that are spread across the
country.\167\ As a result, heat rates of existing coal-fired EGUs in
the U.S. vary substantially. Thus, even though 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 HRI that can improve CO2 emission
performance across the existing coal-fired EGU fleet, this potential
may vary considerably at the unit level--including because particular
units may not be able to employ certain HRI measures, or may have
already done so. Accordingly, the EPA identified several available
technologies and equipment upgrades, as well as best operating and
maintenance practices, that EGU owners or operators may apply to
improve an individual EGU's heat rate. The EPA referred to these HRI
technologies and techniques as ``candidate technologies'' and solicited
comment on their technical feasibility, applicability, performance, and
cost.
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\167\ For example, 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. Moreover,
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.
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The EPA received numerous public comments, both supporting and
opposing, the proposed determination that HRI is the BSER. Many
commenters supported the proposed concept of a unit-specific, state-led
evaluation of HRI potential as a means of establishing a unit-specific
standard of performance. The commenters argued that it is not possible
to adopt uniform, nationally applicable standards of performance based
on implementation of particular HRI technologies because each
individual unit is subject to a unique combination of factors that can
affect the unit's heat rate and HRI potential, many of which are
geographically driven and outside the control of a
[[Page 32536]]
source. The EPA agrees with these commenters. As previously mentioned,
the U.S. fleet of existing coal-fired EGUs is diverse in terms of size,
vintage, fuel usage, design, geographic location, etc. The HRI
potential for each unit will be influenced by source-specific factors
such as the EGU's past and projected utilization rate, maintenance
history, and remaining useful life (among other factors). Therefore,
standards of performance must be established from a unit-level
evaluation of the application of the BSER and consideration of other
factors at the unit level. States are in the best position to make
those evaluations and to consider of other unit-specific factors, and
indeed CAA section 111(d)(1) directs EPA to permit states to take such
factors into consideration as they develop plans to establish
performance standards for existing sources within their jurisdiction.
Other commenters opposed the proposed use of unit-specific HRI
plans because the commenters believe that this interpretation is
inconsistent with the legislative history and that this approach does
not enable significant emissions reductions. Some commenters said that
defining BSER in terms of operational efficiency (heat rate) is not
consistent with the understanding reflected in the EPA's historic
practice in all previous CAA section 111(d) rules, where the BSER was
determined based on a specific emission reduction technology. The EPA
disagrees with the contention. The EPA proposed that HRI through the
application of a specific set of emission reduction technologies
(discussed in more detail below) and operational practices is the BSER.
That approach is consistent with the direction given in the statute. It
is also an approach that recognizes the challenges of applying a single
specific emission reduction technology within such a diverse population
of designated facilities.
After consideration of public comment, the EPA affirms its
determination that, as proposed, HRI is the BSER for existing coal-
fired EGUs.
b. The List of Candidate Technologies
While a large number of HRI measures have been identified in a
variety of studies conducted by government agencies and outside
groups,\168\ some of those identified technologies have limited
applicability and many provide only negligible HRI. The EPA stated in
the proposal that it believed that requiring a state in developing its
plan to evaluate the applicability to each of its sources of the entire
list of potential HRI options--including those with limited
applicability and with negligible benefits--would be overly burdensome
to the states. Therefore, the EPA identified and proposed a list of the
``most impactful'' HRI 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 are listed in Table 1 below. Those technologies, equipment
upgrades, and best operating and maintenance practices were deemed to
be ``most impactful'' because they can be applied broadly and are
expected to provide significant HRI without limitations due to
geography, fuel type, etc. The EPA solicited comment on each of the
proposed candidate technologies and on whether any additional
technologies should be added to the list, and on whether there is
additional information that the EPA should be aware of and consider in
determining the BSER and establishing the candidate technologies for
HRI measures.
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\168\ See Table 3 in ANPRM, 82 FR 61515.
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The EPA received numerous public comments on the list of candidate
technologies. Some commenters stated that there are additional
available HRI technologies that should be added to the list of
candidate technologies, while many other commenters agreed that the
proposed list of ``candidate technologies'' is reasonable and should be
considered the core group for states to evaluate in establishing
standards of performance. Commenters agreed that the proposed list of
``candidate technologies'' focuses the states' standard-setting process
on those HRI measures with the greatest ability to impact
CO2 emissions. Commenters further stated that the EPA's
proposed candidate technology list will limit the burden on states by
eliminating the need to consider measures that would almost certainly
be rejected due to negligible emission reduction benefits,
disproportionate costs, or availability. However, commenters also noted
that there may be additional HRI opportunities available to a
significant number of designated facilities and that states should not
be required to limit their evaluations to just the ``candidate
technologies'' in establishing unit-specific standards of performance.
Some commenters suggested that the EPA establish a process whereby HRI
solutions can be added to the list of ``candidate technologies.''
Commenters also stated that some of the equipment upgrades and
operating practices proposed as candidate technologies have the
potential to improve an EGU's net heat rate by reducing auxiliary load
but would have no impact on the unit's gross heat rate.\169\ Comments
regarding gross versus net heat rate, and gross- versus net-based
standards of performance, are discussed in more detail below in section
III.F.1.c of this preamble.
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\169\ The gross heat rate is the fuel heat input required to
generate a unit of electricity (typically presented in Btu/kWh-
gross). The net heat rate is the fuel heat input required to
generate a unit of electricity minus the electricity that is used to
power facility auxiliary equipment (typically presented in Btu/kWh-
net).
---------------------------------------------------------------------------
The EPA considered the public comments on the BSER technologies and
believes that the proposed list still represents the most broadly
applicable and impactful collection of HRI measures. Therefore, the EPA
is, in this action, finalizing the proposed technologies, equipment
upgrades, and best operating and maintenance practices provided in
Table 1 of the proposal \170\ as the final list of ``candidate
technologies'' whose applicability to each designated facility within
their boundaries states must evaluate in establishing a standard of
performance for that source in their state plans under CAA section
111(d).
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\170\ See 83 FR 44757.
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The technologies and operating and maintenance practices listed and
described below are generally available and appropriate for all types
of EGUs. However, some existing EGUs will have already implemented some
of the listed HRI technologies, equipment upgrades, and operating and
maintenances practices. There will also be unit-specific physical or
cost considerations that will limit or prevent full implementation of
the listed HRI technologies and equipment upgrades. States will
consider these and other factors when establishing unit-level standards
of performance. The final list of ``candidate technologies''--with the
range of expected percent HRI--is provided below in Table 1.
[[Page 32537]]
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 Operating and Maintenance (O&M) Practices...... Can range from 0 to >2.0% depending on the unit's historical O&M practices.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Two of the technologies shown in Table 1--``Blade Path Upgrade
(Steam Turbine)'' and ``Redesign/Replace Economizer''--are candidate
technologies that are expected to offer some of the largest
improvements in unit-level heat rate. However, based on public comments
from the ANPRM and the ACE proposal, those also are HRI technologies
that have the most potential to trigger NSR requirements. Industrial
stakeholders and commenters have indicated, if such HRI trigger NSR,
the resulting requirements for analysis, permitting, and capital
investments will greatly increase the cost of implementing those HRI
technologies and, in the absence of NSR reforms, states will be more
likely to determine that those technologies are not cost-effective when
analyzing ``other factors'' in determining a standard of performance
for an individual facility.
For the ACE proposal, the EPA reflected this in assumptions made in
the power sector modeling, using the Integrated Planning Model (IPM),
to assess potential costs and benefits of the proposed rule. In that
modeling, the EPA assumed two different levels of potential HRI (in
percentage terms)--a lower expected HRI without NSR reform and a higher
expected HRI with NSR reform.\171\
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\171\ See 80 FR 44783.
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As mentioned earlier in this preamble, the EPA is not taking final
action on the proposed NSR reforms in this final rulemaking action; the
EPA intends to take final action on that proposal in a separate final
action at a later date. Without finalization of NSR reforms, the EPA
anticipates that states in some instances may determine, when
considering other factors, that the candidate technologies, ``Blade
Path Upgrade (Steam Turbine)'' and ``Redesign/Replace Economizer,'' are
less appropriate for application to a particular source or sources than
the EPA anticipated would be when it proposed the ACE Rule.
Nevertheless, the EPA is retaining these two candidate technologies as
part of the final BSER, because it still expects these technologies to
be generally applicable across the fleet of existing EGUs, and because
the costs of the technologies themselves are generally economical and
reasonable.
c. Level of Stringency Associated With the BSER
As discussed in section III.B above, the EPA has the authority and
responsibility to determine the BSER. CAA section 111(d)(1), meanwhile,
clearly assigns states the role of developing a plan that establishes
standards of performance for designated facilities (with EPA's
authority to promulgate a federal plan serving as a backstop in the
event that a state fails to develop a satisfactory plan \172\). Based
on these statutory divisions of roles and responsibilities, the EPA
proposed to determine the BSER as HRI achievable through implementation
of certain technologies, equipment upgrades, and improved O&M
practices. The EPA also declined to propose a standard of performance
that presumptively reflects application of the BSER because the
establishment of standards of performance for existing sources is the
states' role.\173\ While declining to provide a presumptive standard,
the EPA also proposed to provide information on the degree of emission
limitation achievable through application of the BSER by providing a
range of reductions and costs associated with each of the candidate
technologies identified as part of the BSER.\174\
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\172\ See section 111(d)(2).
\173\ See 83 FR 44764.
\174\ See 83 FR 44757, Table 1.
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The EPA received numerous comments from states and industry
requesting that the EPA provide a presumptive standard, or at minimum,
additional guidance and clarity on how states could derive a standard
of performance that meets the requirements of this regulation.
Additionally, several commenters contended that under CAA section
111(a)(1), the EPA is legally obligated to identify ``the degree of
emission limitation achievable through the application of the [BSER]''
(i.e., a level of stringency) because such degree of emission
limitation is inextricably linked with the determination of the BSER,
which is the EPA's statutory role and responsibility. Upon
consideration of these comments, especially the widespread request for
more guidance from the EPA on developing appropriate standards of
performance, the EPA agrees that it has a responsibility under the CAA
to identify the degree of emission reduction that it determines to be
achievable through the application of the BSER.
While the CAA provides that the responsibility to establish
standards of performance is a state's responsibility, the EPA is
identifying the degree of emission limitation achievable through the
application of the BSER (i.e., the level of stringency) associated with
the candidate technologies. By providing the level of emissions
reductions achievable using the candidate technologies the EPA is
fulfilling its responsibility as part of the BSER determination. In
this instance, the EPA has identified the degree of emission limitation
achievable through application of the BSER by providing ranges of
expected reductions associated with each of the technologies. These
ranges are provided in Table 1, clearly presenting the percentage
improvement ranges that can be expected when each candidate technology
comprising the BSER is applied to a designated facility. Defining the
ranges of HRI as the degree of emission limitation achievable through
application of the BSER is consistent with the EPA's position at
proposal, where EPA noted that ``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
[[Page 32538]]
will depend upon a range of unit-specific factors. The states will use
the information provided by the 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.'' \175\ For purposes of the final ACE rule, states will
utilize the ranges of HRI the EPA has provided in developing standards
of performance but may ultimately establish standards of performance
for one or more existing sources within their jurisdiction that reflect
a value of HRI that falls outside of these ranges. See section
III.F.1.a of this preamble.
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\175\ See 83 FR 44763.
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It is reasonable for the EPA to express the ``degree of emission
limitation achievable through application of the BSER'' as a set of
ranges of values, rather than a single number, that reflects
application of the candidate technologies as a whole. This approach is
reasonable in light of the nature of what the EPA has identified as the
adequately demonstrated BSER (as well as of the structure of section
111 in general and the interplay between section 111(a)(1) and section
111(d) in particular): A suite of candidate technologies that the EPA
anticipates will be generally applicable to EGUs at the fleet-wide
level but not all of which may be applicable or warranted at the level
of a particular facility due to source-specific factors such as the
site-specific operational and maintenance history, the design and
configuration, the expected operating plans, etc. Because of the
importance for applicability of the BSER of these source-specific
factors, and because the application and installation of the candidate
technologies will result in varying degrees of reductions based on
application of each of the BSER technologies into the existing
infrastructure of the EGU, the EPA has provided ranges of HRI
associated with each technology. This accounts for some of the
variation that is expected among the designated facilities (see section
III.F.1.a.(1) of this preamble for discussion of variable emission
performance at and between designated facilities). While these ranges
represent the degree of emission reduction achievable through
application of the BSER, a particular designated facility may have the
potential for more or less HRI as a result of the application of the
candidate technology based on source-specific characteristics. As
further discussed in section III.F. of this preamble, the level of
stringency associated with each candidate technology is to be used by
states in the process of establishing a standard of performance, and in
this process, states may also consider source-specific factors such as
variability that may result in a different level of stringency.\176\
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\176\ As described later in the preamble in section III.F., the
EPA envisions states will develop standards of performance for
designated facilities in a two -step process where states first
apply the BSER and then consider source-specific factors such as
remaining useful life.
---------------------------------------------------------------------------
d. Detail on the HRI Technologies & Techniques
(1) 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 plant's performance and minimizing emissions during
periods of rapid load changes--conditions that commenters claimed to be
more prevalent now than was the case 5 to 10 years ago. 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 (PM) (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 ISB 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.
Commenters recommended that the EPA disaggregate its analysis of
neural networks and ISB because these technologies do not have to be
deployed together and implementing one without the other may be
appropriate in many cases. The EPA agrees that the technologies do not
have to be implemented together and states must evaluate the
applicability and effectiveness of both technologies. The technologies
were listed together to emphasize that they are often implemented
together and that the resulting HRIs from each are not necessarily
additive.
(2) 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. For example, 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.
Commenters stated that because upgrading an electric boiler feed
pump impacts only net heat rate (and not gross heat rate), it should be
excluded from the candidate technologies list. The EPA disagrees that
candidate technologies affecting only the net heat rate should be
removed from the candidate technologies list. These technologies
improve the efficiency and reduce emissions from the plant by reducing
the auxiliary power load, allowing for more of the produced power to be
placed on the grid. As is discussed below in section III.F.1.c., the
state will determine whether to establish standards of performance as
gross output-based standards or as net output-based standards. If
states establish gross output-based standards, it will be up to the
states to determine how to account for emission reductions that are
attributable to technologies affecting only the net output.
[[Page 32539]]
(3) 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.
The air pre-heater may be regenerative (rotary) or recuperative
(tubular or plate). A major difficulty associated with the use of
regenerative air pre-heaters is air in-leakage from the combustion air
side to the flue gas side. Air in-leakage affects boiler efficiency due
to lost heat recovery and affects the axillary load since any in-
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
in-leakage.
The EPA received comments that claimed the applicability of air
pre-heater seals is limited, and that low-leakage seals are not
feasible on certain units while other commenters agreed that the HRI
estimates for leakage reduction are reasonable, and HRI improvement
from 0.25 to 1.0 percent is achievable. The EPA agrees that the HRI
estimates for air heater and duct in-leakage are reasonable. The EPA
agrees that low-leakage seals are not feasible for certain units (e.g.,
those using recuperative air heaters). However, the EPA is finalizing a
determination that this candidate technology is an element of the BSER
because limiting air in-leakage in the air heater and associated duct
work can be evaluated on all units and limiting the amount of air in-
leakage will improve the efficiency of the unit.
(4) Variable Frequency Drives (VFDs)
VFD on induced draft (ID) fans. The increased pressure required to
maintain proper flue gas flow through downstream air pollutant control
equipment may require additional fan power, which can be achieved by an
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 the 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, units with oversized fans can benefit
from VFD controls. Under these scenarios, VFDs can significantly
improve the unit heat rate. VFDs as motor controllers offer many
substantial improvements to electric motor power requirements. The
drives provide benefits such as soft starts, which reduce initial
electrical load, excessive torque, and subsequent equipment wear during
startups; provide precise speed control; and enable high-efficiency
operation of motors at less than the maximum efficiency point. During
load turndown, plant auxiliary power could be reduced by 30-60 percent
if all large motors in a plant were efficiently controlled by VFD. With
unit loads varying throughout the year, the benefits of using VFDs on
large-size equipment, such as FD or ID fans, boiler feedwater and
condenser circulation water pumps, can have significant impacts. 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.
Some commenters stated that VFDs should be excluded from the
candidate technologies list because the efficiency improvements are
likely near zero when the EGU operates as a baseload unit. Commenters
further stated that VFD installation may not be reasonable because of
their high cost, large physical size, and significant cooling
requirements. The EPA agrees that VFD HRIs will be less effective for
units that operate consistently at high capacity factors at base load
conditions. However, due to the changing nature of the power sector
(increased use of natural gas-fired generating sources, more
intermittent renewable generating sources, etc.), many coal-fired EGUs
are cycling more often and the heat rate of such units will benefit
from installation of VFD technology. In evaluating the applicability of
the BSER technologies, states will consider ``other factors'' that will
include expected utilization rate, remaining useful life, physical/
space limitations, etc. That evaluation of ``other factors'' will
identify whether implementation of a BSER candidate technology is
reasonable. The EPA is finalizing a determination that this candidate
technology is an element of the BSER because it contributes to emission
reductions and it is broadly applicable at reasonable cost.
Commenters also stated that VFDs only impact net heat rate, so
efficiency improvements may not be cost-effective. As stated earlier,
if the states choose to establish gross output-based standards of
performance, it will be up to the states to determine how to account
for emission reductions attributable to improvement to net heat rate.
(5) 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.
Commenters stated that steam turbine blade path upgrades may not be
achievable for every turbine because of the potentially significant
variability in an individual turbine's parameters when considering
costs. Commenters further noted that these are large investments that
can require lengthly outages and long lead times.
[[Page 32540]]
Other commenters noted that these steam turbine blade path upgrades
have been commercially available for over 10 years and that the HRI
estimates in Table 1 appear reasonable.
The EPA agrees that steam turbine blade path upgrades are
commercially available and that the HRI estimates in Table 1 appear to
be consistent with other estimates of HRI achievable from this type of
upgrade. As mentioned earlier, based on public comments responding to
the ANPRM and the ACE proposal, this HRI measure has the potential to
trigger NSR requirements (in the absence of NSR program reforms), and
the EPA anticipates that, among the candidate technologies identified
as comprising the BSER, states may be relatively more likely to
determine in light of the resulting requirements for analysis,
permitting, and capital investments that this candidate technology is
not economically feasible when evaluating it in the process of
establishing standards of performance for particular existing sources
within their jurisdiction. Nevertheless, the EPA is finalizing a
determination that steam turbine blade bath upgrades are part of the
BSER because the EPA anticipates they will still be generally available
and feasible at a sufficient scale among the nationwide fleet.
(6) 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.
Commenters stated that redesigning or replacing an economizer may
be limited for some units by the need to maintain appropriate
temperatures at a downstream SCR system for nitrous oxides (NOx)
control. Commenters also stated that applicability of this measure will
be site-specific because boiler layout and construction varies widely
between units. Commenters stated that the values in Table 1 appear to
reflect a major economizer redesign which may not be possible for many
units. The EPA agrees that there will likely be site-specific factors
that must be considered to determine whether economizer redesign/
replacement is a feasible HRI option (as is the case for all the BSER
candidate technologies). Nevertheless, the EPA is finalizing a
determination that economizer upgrades (or replacement) are part of the
BSER because the EPA anticipates they will still be generally available
and feasible at a sufficient scale among the nationwide fleet. As
mentioned earlier, states may take into consideration site-specific
characteristics (``other factors'') when establishing a standard of
performance for each unit.
(7) HRI Techniques--Best Operating and Maintenance Practices
Many unit operators can achieve additional HRI by adopting best O&M
practices. The amount of achievable HRI will vary significantly from
unit to unit, ranging from no improvement to potentially more than 2.0
percent depending on the unit's historical O&M practices. In setting a
standard of performance for a specific unit or subcategory of units,
states will evaluate 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.
Some commenters agreed that HRI training can improve staff
awareness of plant efficiency measures, which should result in improved
plant performance. Other commenters stated that the benefits of HRI
training are highly variable and depend on existing equipment and
staff. Some commenters stated that the operating staff already
routinely undergo HRI training and that states should not be required
to consider these measures in developing their plans. The EPA agrees
that the benefits will be variable from unit to unit depending upon the
unit's historical O&M practices. If operating staff at a source already
undergo routine HRI training, then the state will note that in the
standard-setting process. Just as an EGU that has recently installed
new or reconstructed boiler feed pumps would not be expected to replace
those pumps, a source that already has an effective HRI training
program in place would not be expected to implement a new HRI training
program. The EPA is finalizing a determination that this practice is an
element of the BSER because it can result in emission reductions and
can be broadly implemented at reasonable cost.
(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.
Commenters stated that the benefits of on-site appraisals are
variable, speculative, and site-specific. Commenters stated that no
state should determine what opportunities a coal-fired EGU might find
during an on-site appraisal, and, therefore, that states should not be
required to evaluate the applicability of on-site appraisals when
developing their plans and establishing standards of performance for
existing sources within their jurisdiction. The EPA agrees that the
benefits of on-site appraisals will be variable and site-specific. As
with other BSER measures, it will be up to each state to determine the
extent of this requirement. States may require that the owner/operator
perform an on-site appraisal to identify areas for HRI or the state may
choose to have a third party conduct an on-site HRI appraisal.
(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
ineffective operation 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.
[[Page 32541]]
Commenters stated that improved steam surface condenser cleaning is
a viable O&M option. Commenters stated that the need for such cleaning
can be determined by enhanced monitoring of condenser performance. The
EPA agrees with this assessment and notes that many owner/operators may
already have steam surface condenser cleaning as part of routine O&M
for their units. The EPA is finalizing a determination that this O&M
practice is an element of the BSER because it provides opportunity for
heat rate improvement and is broadly applicable.
e. Cost of HRI
The EPA finds that the costs of the HRI technologies and practices
that the EPA has identified as the BSER and provided in Table 1 are
reasonable because they improve the efficiency of the units to which
they are applied. This results in lower operating costs (especially
lower fuel costs). In fact, these HRI technologies and practices are
the types of efficiency improvement measures that some owners and
operators have reasonably implemented at times over the course of the
operating life of their EGUs. In specific circumstances the cost to
implement one or more of the technologies may be determined to be
unreasonable--after consideration of source-specific factors. This will
be determined when states establish standards by applying the BSER and
taking other factors, including remaining useful life, into
consideration.
(1) Reasonableness of Cost
As mentioned earlier, under CAA section 111(a)(1), the EPA
determines ``the best system of emission reduction which (taking into
account the cost of achieving such reduction . . .) . . . has been
adequately demonstrated.'' 42 U.S.C. 7411(a)(1) (emphasis added). In
several cases, the D.C. Circuit has elaborated on this cost factor in
various ways, stating that the EPA may not adopt a standard for which
costs would be ``exorbitant,'' \177\ ``greater than the industry could
bear and survive,'' \178\ ``excessive,'' \179\ or ``unreasonable.''
\180\ These formulations appear to be synonymous and suggest a cost-
reasonableness standard. Therefore, in this action, the EPA has
evaluated whether the costs of HRI are considered to be reasonable as a
general matter across the fleet of existing sources.
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\177\ Lignite Energy, 198 F.3d at 933.
\178\ Portland Cement, 513 F.2d at 508.
\179\ Sierra Club, 657 F.2d at 343.
\180\ 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 a large percentage of the overall costs of power
production. 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 designated
facilities can be relatively low depending upon each EGU's 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 costs are
reasonable. While some EGUs may not realize the full potential of cost
recuperation from fuel savings, the EPA finds that the net costs of
implementing HRIs as an approach to reducing CO2 emissions
from fossil fuel-fired EGUs are reasonable because they are not
exorbitant or excessive. In fact, these HRIs are the types of
efficiency improvement measures that some owners and operators have
reasonably implemented at times over the course of the operating life
of their EGUs.
It will be up to the states to, either directly or indirectly, take
cost into consideration in establishing unit-specific standards of
performance. CAA section 111(d) explicitly allows the states to take
into consideration, among other factors, the remaining useful life of
the existing source in applying the standard of performance. For
example, a state may find that an HRI technology is applicable for an
affected coal-fired EGU but find that the costs are not reasonable when
consideration is given to the timeframe for the planned retirement of
the source (i.e., the source's remaining useful life). A state may find
that an HRI technology is applicable for an affected coal-fired EGU but
find that the costs are not reasonable because the source is already
implementing that HRI technology and it would not be reasonable to
expect the source to replace that HRI technology with a newer version
of the same technology.
There are several ways that cost can be considered. For example,
when evaluating costs for criteria pollutants in a BACT analysis or for
a ``beyond-the-floor'' analysis for HAP under CAA section 112, 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. Therefore,
there are 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,
the 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.'' \181\ The 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.'' \182\
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\181\ 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.
\182\ 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.
---------------------------------------------------------------------------
(2) 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 Sargent
& Lundy Study \183\ updated to $2016.\184\ These costs correspond to
ranges of HRI (percent) presented earlier in Table 1.
---------------------------------------------------------------------------
\183\ ``Coal-Fired Power Plant Heat Rate Reductions'' Sargent &
Lundy report SL-009597 (2009) Available in the rulemaking docket at
EPA-HQ-OAR-2017-0355-21171.
\184\ The conversion factor comes from Federal Reserve Economic
Data (FRED). See https://fred.stlouisfed.org.
[[Page 32542]]
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
These costs presented in Table 2 represent both capital and O&M
costs. Investments in HRI measures at EGUs should also result in fuel
savings which can offset some or all of the cost of the HRI. However,
the EPA does not suggest that HRI measures should meet any particular
economic criterion (e.g., pay for themselves through reduced fuel
costs) in order to be applied in state plans for the establishment of
source-specific standards of performance.
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).
Because the heat rate improvement technologies result in fuel
savings and other potential cost savings and the listed candidate
technologies are the types of improvements and equipment upgrades that
have been previously undertaken, the EPA finds that the costs of the
HRI technologies and practices that have been identified as the BSER
and provided in Table 1 are reasonable.
f. Non-Air Quality Health and Environmental Impacts, Energy
Requirements, and Other Considerations
As directed by CAA section 111(a)(1), the EPA has taken into
account non-air quality health and environment 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). The EPA has also taken into account energy
requirements. All of these candidate technologies, when implemented,
would have the effect of improving the efficiency of the coal-fired
EGUs to which they are applied. As such, the EGU would be expected to
use less fuel to produce the same amount of electricity as it did prior
to the efficiency (heat rate) improvement. None of the 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 designated
facilities 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 final emissions guidelines encourage technological
development by promoting further development and market penetration of
equipment upgrades and process changes that improve plant efficiency
leading to reasonable reductions in CO2 emissions.
3. Discussion of ``Rebound Effect''
At proposal, the EPA solicited comment on potential CO2
emissions and generation changes that might occur as a result of
efficiency improvements at designated facilities, including potential
increased generation to the point of a net increase in emissions from a
particular facility, also referred to as the ``rebound effect.'' In
some instances, it is possible that certain sources increase in
generation (relative to some baseline) as a result of lower operating
costs from adoption of candidate technologies to improve their
efficiency. The EPA conducted analysis and modeling for the ACE
proposal, and found that while there were instances (in some scenarios)
where a limited number of designated facilities that adopted HRI
increased generation to the point of increasing mass emissions
notwithstanding the lower emissions rate resulting from HRI adoption,
due to their improved efficiency and marginally improved economic
competitiveness relative to other electric generators, the designated
facilities as a group reduce emissions because they can generate higher
levels of electricity with a lower overall emission rate.
Some commenters on the proposed rule highlighted environmental and
legal concerns with the rebound effect as undermining the BSER, while
others commented that the concern was de minimis, not rooted in any
legal basis, and not germane to establishing standards of performance.
On one side, some commenters asserted that the determined BSER is not
properly designed because it would not achieve emission reductions if
it results in higher utilization and, therefore, emission increases.
Some doubted the EPA claims of lower systemwide emissions and said the
EPA had not adequately analyzed the concern. Some asserted that the
assumptions used in the analysis do not reflect real world
considerations that efficiency of all fossil fuel plants degrades over
time, rather than being static. Also, some asserted that the EPA had
understated the amount of coal capacity that will likely retire in its
analysis, and, thus, the remaining coal fleet will consist of more
efficient and competitive units that may end up emitting more than the
EPA's analysis shows. In addition, some asserted that the EPA's
proposed NSR reforms allow sources to extend lifetimes without
requiring controls, exacerbating rebound issues.
Other commenters asserted that CAA section 111 does not require the
Agency to obtain absolute reductions in emissions at a sector-wide
level, and the EPA's obligation is to determine the BSER through
evaluation of emissions performance per output at the unit-level. Some
commenters stated that any rebound effect from more efficient units is
most likely to come at expense of lower-efficiency coal units, negating
the effect. Also, commenters contended that rebound is unlikely to
change the
[[Page 32543]]
dispatch order and/or utilization of units based upon the levels of HRI
that are reasonable and part of ACE, and, thus, any rebound effect
would be de minimis.
The EPA agrees with the commenters who do not see the rebound
effect as undermining the BSER determination in this rule, because this
rule is aimed at improving a source's emissions rate performance at the
unit-level. Indeed, in repealing the ``percent reduction'' requirement
from the 1977 CAA Amendments, Congress expressly acknowledged that
standards of performance were to be expressed as an emissions
rate.\185\ In addition, as noted above, this rule results in overall
reductions of emissions of CO2. Because the BSER in this
rule improves the emissions rate of designated facilities and results
in overall reductions, the limited rebound effect that may occur does
not undermine the BSER.
---------------------------------------------------------------------------
\185\ See 1990 CAA Amendments, section 403, 104 Stat. at 2631
(``the Administrator shall promulgate revised regulations for
standards of performance . . . that, at a minimum, require any
source subject to such revised standards to emit sulfur dioxide at a
rate not greater than would have resulted from compliance by such
source with the applicable standards of performance under this
section prior to such revision'') (emphasis added).
---------------------------------------------------------------------------
Nonetheless, to the extent commenters have asserted that ACE would
cause an increase in aggregate CO2 emissions due to some
sources operating more, this concern is not supported by our analysis.
The EPA conducted updated modeling and analysis for the final ACE rule
(see Chapter 3 of the RIA for more details) and confirmed that
aggregate CO2 emissions from the group of designated
facilities are anticipated to decrease (outweighing any potential
CO2 increases related to increased generation by certain
units).
The final ACE rule establishes the BSER, and a framework for states
to determine rate-based standards of performance for designated
facilities. The BSER for ACE is expressed as a rate-based approach,
which should necessarily result in rate-based emission reductions. The
modeling and analysis show individual units and the entire coal fleet
reducing emission rates, as well as an aggregate decrease in mass
emissions. As such, any potential ``rebound effect'' is determined to
be small and manageable (if necessary) and does not require any
specific remedy in the final rule. However, if a state determines that
the source-specific factors of a designated facility dictate that the
rebound effect is an issue that should be considered in setting the
standard of performance, that is within the state's discretion to
consider in the process of establishing a standard of performance for
that particular existing source. As noted above and as a result of
modeling, the EPA does not expect these considerations to be necessary
in the state plan development process.
4. Systems That Were Evaluated But Are Not Part of the Final BSER
The EPA identified several systems of GHG emission reduction that
may be applied at or to designated facilities but did not propose that
they should be part of the BSER. The Agency solicited comment on the
rationale for eliminating or not identifying those alternative systems
as part of the BSER. After consideration of public comments, the EPA is
not revising its proposed determination and is not including any
additional or different systems of emission reduction in the final BSER
determination. A description of the considered systems of emission
reduction that are not part of the final BSER along with a summary of
significant public comments is provided below.
The EPA previously considered co-firing (including 100 percent
conversion) with natural gas and implementation of carbon capture and
storage (CCS) as potential BSER options. See 80 FR 64727. In that
analysis, the EPA found some natural gas co-firing and CCS measures to
be technically feasible but determined that switching from coal to gas
is ``a relatively costly approach to CO2 reductions at
existing coal steam boilers when compared to other measures such as
heat rate improvements. . .'' \186\ and that the cost to implement CCS
for existing source standards is not reasonable and that ``CCS is not
an appropriate component of the [BSER].'' \187\ A more detailed
description of the current consideration of these technologies is
provided below.
---------------------------------------------------------------------------
\186\ Technical Support Document (TSD) for Carbon Pollution
Guidelines for Existing Power Plants: Emission Guidelines for
Greenhouse Gas Emissions from Existing Stationary Sources: Electric
Utility Generating Units; Chapter 6, June 10, 2014, Available at
Docket Item No. EPA-HQ-OAR-2013-0602-36852.
\187\ Id. Chapter 7
---------------------------------------------------------------------------
a. Natural Gas Repowering
Coal-fired utility boilers can reduce their emissions by firing
natural gas instead of--or in combination with--coal. This can be done
in three different ways: (1) By repowering, (2) by co-firing, or (3) by
refueling. Repowering is when an existing coal-fired boiler is replaced
with one or more natural gas-fired stationary combustion turbines,
while still utilizing the existing steam turbines. Co-firing and
refueling involve the burning of natural gas at an existing
boiler.\188\
---------------------------------------------------------------------------
\188\ Co-firing and refueling are discussed in section III.E.4.b
of this preamble.
---------------------------------------------------------------------------
In the ACE proposal, the EPA did not consider natural gas
repowering as a potential system of emission reduction (i.e., as a
candidate for the BSER) based on the reasoning that this option would
fundamentally redefine the existing sources subject to the rule.\189\
Some commenters argued, however, that coal-fired utility boilers can
reduce emissions through natural gas repowering and it should be the
BSER. Other commenters argued that the `redefining the source' concept
from PSD was inappropriate for application to NSPS. After considering
public comments on this issue, the EPA concludes that repowering should
not be considered for purposes of CAA section 111(d). As described in
more detail below, repowering is not a ``system'' of emission reduction
for a source at all because it cannot be applied to the existing
sources subject to this rule (steam generating units). Rather,
repowering these existing units would replace them entirely with a
different type of source (stationary combustion turbines) that would be
subject to the NSPS in 40 CFR part 60, subpart TTTT.\190\ Even if
repowering were to be evaluated to determine if it was part of the
BSER, the EPA has found non-air quality health and environmental
impacts and energy requirements that demonstrate that repowering is not
part of the BSER.\191\
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\189\ See 83 FR 44753.
\190\ The EPA is not concluding whether or not the `redefining
the source' concept can or should be applied in the context of the
NSPS program.
\191\ These non-air quality health and environmental impacts and
energy requirements are discussed in more detail below in the
discussion of refueling and co-firing. Except to the extent that
discussion involves the inefficient combustion of natural gas, the
non-air quality health and environmental impacts and energy
requirements found for these technologies are similar, if not
identical, to those the EPA has found for repowering.
---------------------------------------------------------------------------
As described above, a ``standard of performance'' under CAA section
111(d) must be ``establishe[d]'' for an ``existing source.'' However,
repowering a coal-fired boiler--that is, the replacement of a boiler
with a stationary combustion turbine--creates a ``new source,'' which
is regulated directly by the EPA under 40 CFR part 60, subpart TTTT
(establishing standards for the control of GHG emissions from new,
modified, or reconstructed steam generating units, IGCCs, or stationary
combustion turbines). The ``best system of emission reduction'' for an
existing source,
[[Page 32544]]
therefore, simply cannot be the creation of a new source that is
regulated under separate authority. Otherwise, the EPA could subvert
the provisions of CAA section 111(d) (which authorizes states to
regulate existing sources in the first instance) and require all
existing sources to transform into ``new sources,'' which the Agency
can directly regulate under CAA section 111(b). Therefore, repowering a
coal-fired boiler is not a ``system'' within the scope of the BSER.
b. Natural Gas Co-Firing and Refueling
Some coal-fired utility boilers use natural gas or other fuels
(such as distillate fuel oil) for startup operations, for maintaining
the unit in ``warm standby,'' or for NOX control (either
directly as a combustion fuel or in configuration referred to as
natural gas reburn). During such 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 could
decrease by approximately 4 percent.
Commenters stated that the EPA should determine that natural gas
co-firing is the BSER because it is technically feasible, readily
available, achieves significant emission reductions, and may be the
most cost-effective option for some facilities. Some commenters also
provided data (from EIA) to assert that co-firing is widely used and
adequately demonstrated at coal-fired EGUs. The commenters contended
that a significant number of coal-fired EGUs have the capacity to burn
both natural gas and coal. One commenter asserted that 35 percent of
coal-fired utility boilers across 33 states co-fired with natural gas.
Another commenter provided a table listing coal-fired EGUs that have
recently converted to natural gas or are co-firing with natural gas.
One commenter cited data from the EIA and claimed that 48 percent of
steam generating EGUs are already co-firing some amount of natural gas.
While the EPA agrees with the assertion that there are existing
coal plants that have some access to a supply of natural gas, the EPA
disagrees that the data demonstrate that co-firing is a system of
emission reduction that has been or that could be implemented on a
nationwide scale at reasonable cost. The EPA believes that commenters
have conflated operational co-firing (i.e., co-firing coal and natural
gas to generate electricity) with startup co-firing (i.e., only using
natural gas to heat up a utility boiler or to maintain temperature
during standby periods). Coal-fired boilers always use a secondary fuel
(most often natural gas or distillate fuel oil), utilizing burners
specifically configured to bring the boiler from a cold, non-operating
status to a temperature where coal, the primary fuel, can be safely
introduced for normal operations.
The EPA conducted its own analysis using EIA fuel use data from
2017.\192\ The EPA's analysis supports the assertion that nearly 35
percent of coal-fired units co-fired (in either sense of co-firing as
described above) with natural gas in 2017. However, very few--less than
four percent of coal-fired units--co-fired with natural gas in an
amount greater than five percent of the total annual heat input. This
strongly suggests that most of the natural gas that was utilized at
these sites was used as a secondary fuel for unit startup or to
maintain the unit in ``warm standby'' rather than as a primary fuel for
generation of electricity. Further, the small number of units that co-
fired with greater than five percent natural gas during 2017 operated
at an average capacity factor of only 24 percent--indicating that they
are not the most economical units and are not dispatched as frequently
as those units that used less than five percent natural gas. For
comparison, in 2017, 62 percent of coal-fired utility boilers co-fired
with some amount of distillate fuel oil and, as with natural gas, the
vast majority of those units used less than 5 percent distillate fuel
oil (again, strongly suggesting that it is primarily used as a
secondary fuel for startup and warm standby).
---------------------------------------------------------------------------
\192\ See the memorandum ``2017 Fuel Usage at Affected Coal-
fired EGUs,'' available in the rulemaking docket (Docket ID No. EPA-
HQ-OAR-2017-0355).
---------------------------------------------------------------------------
The EPA also disagrees that the data demonstrate that co-firing can
be considered at the national level as an adequately demonstrated
system of emission reduction and that there are easy paths to expand it
at a reasonable cost. The EIA 923 fuel use data indicated that about 65
percent of coal-fired utility boilers use something other than natural
gas as the secondary fuel for periods of startup and standby
operations. Distillate fuel oil is by far the most commonly used
secondary fuel. While the use of distillate fuel oil does not
necessarily mean that the unit lacks access to natural gas, it suggests
that for many of those units, there is an inadequate supply to serve
even as a secondary fuel for startup and standby operations. The 2018
average price \193\ of distillate fuel oil was more than four times
higher than that of natural gas; so, if there was an adequate supply of
natural gas, then it would be much more economically favorable to
utilize that natural gas rather than the much more expensive distillate
fuel oil. As explained earlier, for plants that require additional or
new pipeline capacity, the capital cost of constructing new pipeline
laterals is approximately $1 million per mile of pipeline built.
Therefore, a 50-mile gas pipeline would add $50 million--$100/kW for a
typical 500 MW unit--to the capital costs of adding co-firing
capability.
---------------------------------------------------------------------------
\193\ The 2018 average U.S. power generation fuel costs for
natural gas was $3.52 per million Btu while the cost for distillate
fuel oil for power generation was $16.13 per million Btu. U.S. EIA
Short Term Energy Outlook, https://www.eia.gov/outlooks/steo/tables/pdf/2tab.pdf.
---------------------------------------------------------------------------
As mentioned earlier, the EPA has previously evaluated the costs
associated with using natural gas refueling or co-firing as a GHG
mitigation option. See 79 FR 34875. For a typical base-load coal-fired
EGU, the average cost of CO2 reductions achieved through co-
firing with 10 percent natural gas would be approximately $136 per ton
of CO2. While a utility boiler that is converted to 100
percent natural gas-fired can offset some of the capital costs by
reducing its fixed operating and maintenance costs (though, as
discussed below, the costs would still be considerably higher than the
HRI technologies that the EPA identified as the BSER), a unit that is
co-firing natural gas with coal would continue to bear the fixed costs
associated with equipment needed for coal combustion, raising the cost
per ton of CO2 reduced.
In determining the BSER, CAA section 111(a)(1) also directs the EPA
to take into account non-air quality health and environmental impacts
and energy requirements. The EPA is unaware of any significant non-air
quality health or environmental impacts associated with natural gas co-
firing. However, in taking energy requirements into account, the EPA
notes that co-firing natural gas in coal-fired utility boilers is not
the best or most efficient use of natural gas and, as noted above, can
lead to less efficient operation of utility boilers. NGCC stationary
combustion turbine units are much more efficient at using natural gas
as a fuel for generating 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 utility boilers to satisfy an emission standard at the
utility boiler. Some commenters disagreed with the EPA's claim that
increased use of natural gas in a utility boiler would
[[Page 32545]]
come at the expense of its use in more efficient NGCC units. The EPA
did not intend to imply that there is now (or that there will be) a
restricted supply of natural gas. Instead, the EPA suggested that, if
there were to be an increase in the use of natural gas, the more
efficient use for that increased natural gas would be as fuel for
under-utilized NGCC units rather than in less efficient utility
boilers. The EPA does not believe that establishing a BSER that, for
all practical purposes, would mandate increased use of natural gas in
utility boilers is good policy.
Given that a natural gas co-firing-based BSER would result in
standards that are more costly than standards based on application of
the candidate technologies for heat rate improvements, that such a BSER
would encourage inefficient use of natural gas, that implementation
would be even more expensive and challenging for those units that
currently have limited or no access to natural gas, the EPA concludes
that co-firing natural gas in coal-fired boilers is not the BSER.
Some commenters requested that co-firing be added to the list of
HRI candidate technologies (discussed in more detail below), the
combination of which would represent the BSER. However, whereas all
coal-fired utility boilers can apply (or have already applied) HRI
measures, natural gas co-firing does not satisfy the same CAA section
111(a)(1) criteria (see above). Moreover, co-firing can negatively
impact a unit's heat rate (efficiency) due to the high hydrogen content
of natural gas and the resulting production of water as a combustion
by-product.\194\ 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) to maintain steam temperatures at or within design
limits, or for other technical reasons. Accordingly, natural gas co-
firing cannot be applied in combination with the HRI measures
identified as the BSER. However, natural gas co-firing might be
appropriate for certain sources as a compliance option. For a
discussion of compliance options, see below section III.F.2.
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\194\ Natural gas firing or co-firing degrades the boiler's
efficiency (relative to the use of coal) primarily due to the
increased production of water. Some of the heat that is produced in
the combustion process will be used to heat that flue gas moisture
(which will exit with the stack gases) rather than to converting
water in the boiler tubes to steam. The efficiency declines because
there is less heat available to produce useful steam.
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Some commenters also suggested that the EPA's concerns about using
gas inefficiently were not persuasive because the United States has
such an abundant supply of natural gas. The EPA disagrees for many of
the same reasons that the Agency relied upon to reject the
consideration of natural gas as the BSER. First, it is on the higher
end of the cost of the measures the EPA considered even for units with
ready natural gas availability; second, many designated facilities do
not have natural gas availability, so it is not broadly applicable.
The same factors discussed above lead the Agency to conclude that
refueling also cannot be BSER. Refueling is when an existing coal-fired
boiler is converted to a natural gas-fired boiler (i.e., firing 100%
natural gas). In the ACE proposal, the EPA did not consider natural gas
refueling as a potential system of emission reduction (i.e., as a
candidate for the BSER) based on the reasoning that this option would
fundamentally redefine the existing sources subject to the rule.\195\
Some commenters argued, however, that coal-fired utility boilers can
reduce emissions through natural gas refueling and should be the BSER.
Other commenters argued that the `redefining the source' concept from
PSD was inappropriate for application to NSPS.\196\ After considering
public comments on this issue, the EPA concludes that natural gas
refueling, like natural gas co-firing, is not the BSER.
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\195\ See 83 FR 44753.
\196\ As with repowering, the EPA is not concluding whether or
not the ``redefining the source'' concept can or should be applied
in the context of the NSPS program.
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The EPA has previously evaluated the costs associated with using
natural gas refueling or co-firing as a GHG mitigation option.\197\ The
capital costs of plant modifications required to switch a coal-fired
EGU completely to natural gas are roughly $100-300/kW, not including
any costs associated with constructing additional pipeline capacity.
Many coal-fired plants do not have immediate and ready access to any
supply of natural gas. Others that do have access to a supply of
natural gas have only a limited supply (i.e., enough for startup and
warm standby firing, but not enough for full load firing). For plants
that require additional pipeline capacity, the capital cost of
constructing new pipeline laterals is approximately $1 million per mile
of pipeline built. A 50-mile gas pipeline would add $50 million--$100/
kW for a typical 500 MW unit--to the capital costs of the conversion.
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\197\ See 79 FR 34875.
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While a coal-fired utility boiler that is converted to a 100
percent natural gas-fired boiler could offset some of the capital costs
by reducing its fixed operating and maintenance costs, in most cases,
the most significant cost change associated with switching from coal to
gas is likely to be the difference in fuel cost. Using the EIA's
projections of future coal and natural gas prices, switching a utility
boiler from coal-fired to natural gas-fired could more than double the
unit's fuel cost per MWh of generation. For a typical base-load coal-
fired EGU, the average cost of CO2 reductions achieved
through gas conversion would be approximately $75 per ton of
CO2. This cost could also be much higher as there would very
likely be an increase in natural gas prices corresponding to the
increased demand from widespread coal-to-gas conversion.
The EPA also found that consideration of energy requirements (as
required by CAA section 111(a)(1)) provides additional reasons why
refueling natural gas in a utility boiler should not be considered
BSER.\198\ Burning natural gas in a utility boiler is not the best use
of such fuel as it is much less efficient than burning it in a
combustion turbine. New natural gas combined cycle (NGCC) units can
convert the heat input from natural gas to electricity with an
efficiency of more than 50 percent.\199\ A coal-fired utility boiler
that is repurposed to burn 100 percent natural gas will see a reduction
in efficiency of up to five percent (to less than 40 percent
efficiency) as the higher hydrogen content in the natural gas fuel will
lead to higher moisture losses that will negatively impact the boiler
efficiency.\200\ Widespread refueling is not a practice that the EPA
should be promoting as it is not the most efficient use of natural gas.
Utilities choosing to increase use of natural gas in a combined cycle
or simple cycle combustion turbine is a more efficient way to utilize
natural gas for electricity generation. In reaching this determination,
the EPA is mindful of Congress's direction to ``tak[e] into account . .
. energy requirements'' in determining the best system of emission
reduction in CAA section 111(a)(1). Consideration of ``energy
requirements'' is one of the factors informing the EPA's judgment that
it would be inappropriate to base performance standards on an
[[Page 32546]]
inherently energy-inefficient practice such as refueling.
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\198\ See 83 FR 44762.
\199\ ``Cost and Performance Baseline for Fossil Energy Plants
Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity''
Rev. 3, DOE/NETL-2015/1723 (July 2015).
\200\ ``Leveraging Natural Gas: Technical Considerations for the
Conversion of Existing Coal-Fired Boilers'', Babcock Power Services,
Presented at 2014 ASME Power Conference (July 2014), Baltimore, MD.
Available in the rulemaking docket.
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NGCC units have become the preferred option for intermediate and
baseload natural gas power generation. Other technologies (such as
simple cycle aeroderivative turbines) offer significant advantages for
peaking purposes in that they can start up quickly and require fewer
staff to operate. Some combination of aeroderivative turbines and
flexible combined cycle units offer advantages in both efficiency and
the flexibility to change loads when compared to utility boilers. For
these reasons, the power sector has moved away from the use of gas-
fired boilers. There have been no new natural gas-fired utility boilers
built since the 1980s.
There have been some cases where coal-fired utility boilers have
chosen to refuel (i.e., have chosen to convert to natural gas-firing).
In those cases, the motivation was largely to preserve reserve capacity
without investing in the air pollution controls needed to meet air
emission standards--especially MATS.\201\ The EPA examined fuel use
data submitted by plant owner/operators to the U.S. Energy Information
Administration (EIA) on Form 923.\202\ According to that data, there
were 131 natural gas-fired utility boilers \203\ in 2012 and 170 such
units in 2017. The average capacity factor for those units was only 11
percent in 2012 and 2017. Between 2012 (before the MATS compliance
date) and 2017 (after MATS was fully in effect), 39 utility boilers
converted from coal-fired units to become natural gas-fired utility
boilers. Those natural gas-fired utility boilers operated at an average
capacity factor of less than 10 percent, indicating that they were
likely utilized only during periods of high demand.
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\201\ See 40 CFR part 63, subpart UUUUU.
\202\ Monthly fuel use data is submitted to the EIA on Form 923.
Available at https://www.eia.gov/electricity/data/eia923/. For
details of the EPA data analysis, see the memorandum ``2017 Fuel
Usage at Affected Coal-fired EGUs'' available in the rulemaking
Docket ID No. EPA-HQ-OAR-2017-0355.
\203\ Natural gas-fired utility boilers are those with capacity
of more than 25 MW that use more than 90 percent natural gas on a
heat input basis.
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These non-air quality health and environmental impacts and energy
requirements demonstrate that refueling is not the BSER.
c. Biomass Co-Firing
The EPA previously proposed that co-firing of biomass in coal-fired
utility boilers is not the BSER for existing fossil fuel-fired sources
due to cost and achievability considerations.\204\ Although biomass co-
firing methods are technically feasible and can be cost-effective for
some designated facilities, these factors and others (namely, that any
potential net reductions in emissions from biomass use occur outside of
the regulated source and are outside of the control of the designated
facility, which is incompatible with the interpretation of the EPA's
authority and the permissible scope of BSER as set forth in section II
above) are the considerations that prevent its adoption as the BSER for
the source category.
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\204\ See ACE proposal and 80 FR 64756.
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In the ACE proposal, the EPA sought comment on the inclusion of
forest-derived and non-forest biomass as non-BSER compliance options
for affected units to meet state plan standards.\205\ In response, the
EPA received comments both supporting and opposing the use of biomass
for compliance (as discussed in section III.F.2.b); however, commenters
also spoke to the appropriateness of including biomass firing as part
of the BSER. Some commenters noted that co-firing with biomass cannot
be a ``system of emission reduction'' as it increases CO2
emissions at the source. Commenters further asserted that the EPA has
failed to demonstrate how firing biomass meets the CAA section 111
requirements and the criteria for qualifying as a system of emission
reduction described in the Proposed Repeal and the ACE proposal.
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\205\ See 83 FR 44766.
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Upon consideration of comments and in accordance with the plain
language of CAA section 111 (discussed above in section II.B), the EPA
is now clarifying that biomass does not qualify as a system of emission
reduction that can be incorporated as part of, or in its entirety, as
the BSER. As described in section III.F.2 of this preamble. the BSER
determination must include systems of emission reduction that are
achievable at the source. While the firing of biomass occurs at a
designated facility, biomass firing in and of itself does not reduce
emissions of CO2 emitted from that source. Specifically,
when measuring stack emissions, combustion of biomass emits more mass
of emissions per Btu than that from combustion of fossil fuels, thereby
increasing CO2 emissions at the source. Recognition of any
potential CO2 emissions reductions associated with biomass
utilization at a designated facility relies on accounting for
activities not applied at and largely not under the control of that
source, including consideration of offsite terrestrial carbon effects
during biomass fuel growth, which are not a measure of emissions
performance at the level of the individual designated facility. Use of
biomass in affected units is therefore not consistent with the plain
meaning of ``standard of performance'' and cannot be considered as part
of the BSER.\206\
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\206\ Notwithstanding this conclusion in the context of CAA
section 111(d), the EPA believes that a PSD permitting authority may
still reach the conclusion that use of some type(s) of biomass is
BACT for greenhouse gases in the context of a PSD permit application
where the applicant proposes to use biomass, as discussed in the
EPA's Guidance for Determining Best Available Control Technology for
Reducing Carbon Dioxide Emissions from Bioenergy Production (March
2011). While biomass combustion may result in more greenhouse gas
emissions (in particular CO2) per unit of production than
combustion of fossil fuels, a comparative analysis of biomass and
other fuels may not be required in the BACT context. As EPA has
observed, ``where a proposed bioenergy facility can demonstrate that
utilizing a particular type of biogenic fuel is fundamental to the
primary purpose of the project, then at the first step of the top-
down process, permitting authorities can rely on that to determine
that use of another fuel would redefine the proposed source.''
Bioenergy BACT Guidance at 15. Moreover, even if biomass is compared
to fossil fuels and ranked lower at Step 3 of a top-down BACT
analysis, broader offsite environmental, economic, and energy
considerations related to biomass use (e.g., any potential offsite
net carbon sequestration associated with growth of the biomass
feedstock) may be considered in Step 4 of a top-down BACT analysis.
See Bioenergy BACT Guidance at 20-21. It is therefore consistent to
determine that the firing of biomass does not qualify as a
``standard of performance'' for setting or complying with the BSER
because it does not reduce the GHG emissions of a fossil fuel-fired
source, while also allowing the consideration of any potential
offsite environmental, economic, or energy attributes when
considering an application that treats biomass as BACT for a
proposed biomass facility in the PSD permitting context.
---------------------------------------------------------------------------
Additionally, many commenters agreed with the ACE proposal that
biomass co-firing should not be part of the BSER because it is not
sufficiently cost-effective, there is not a reliable supply of biomass
fuel accessible nationally, co-firing with biomass has a negative
impact on unit heat rate, and co-firing requirements would ``redefine
the source.'' Many commenters supported inclusion of fuel co-firing as
a component of the BSER but focused primarily on argument for natural
gas co-firing (as discussed earlier). Some of these commenters
specifically asserted that biomass use is a widely available and proven
GHG reduction technology.
As discussed by the EPA previously in the ACE proposal and other
instances,\207\ biomass fuel use opportunities are dependent upon many
regional considerations and limitations--namely fuel supply proximity,
reliability and cost--that prevent its adoption as BSER on a national
level (whereas nearly all sources can or have implemented some form of
HRI measures). The infrastructure, proximity, and cost aspects of co-
firing biomass at existing
[[Page 32547]]
coal EGUs are similar in nature and concept to those of natural gas.
While there are a few existing coal-fired EGUs that currently co-fire
with biomass fuel, those are in relatively close proximity to cost-
effective biomass supplies. Therefore, even if biomass firing could be
considered a ``system of emission reduction,'' the EPA is not able to
include the use of biomass fuels as part of the BSER in this action due
to the current cost and achievability considerations and limitations
discussed above. Additional discussion on biomass is provided in
section III.F.2.b. below.
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\207\ See 80 FR 64756.
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d. Carbon Capture and Storage (CCS) \208\
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\208\ 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, the EPA considers these terms to be
interchangeable and for convenience will exclusively use the term
CCS.
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In the ACE proposal, the EPA noted that while CCS is an advanced
emission reduction technology that is currently under development, the
Agency must balance the promotion of innovative technologies against
their economic, energy, and non-air quality health and environmental
impacts. The EPA proposed that neither CCS nor partial CCS are
technologies that can be considered the BSER for existing fossil fuel-
fired EGUs and explicitly solicited comment on any new information
regarding the availability, applicability, costs, or technical
feasibility of CCS technologies.
Many commenters agreed with EPA's proposed finding that CCS
(including partial CCS) should not be part of the BSER. The commenters
stated that it is not adequately demonstrated, sufficiently cost-
effective, or nationally available. Other commenters disagreed and
claimed that CCS is technically feasible and adequately demonstrated
and should be part of BSER, asserting that the EPA has previously
provided evidence in the record during the 2016 denial of petitions for
reconsideration of the CPP that CCS had been successfully implemented
at power plants. Commenters also asserted that there are many vendors
that offer carbon capture technologies for power plants, which
demonstrates that the technology is commercially available and
adequately demonstrated.
CCS is a difficult and complicated process, requiring numerous
pieces of process equipment to capture CO2 from the exhaust
gas, compress it for transport, transport it in a CO2
pipeline, inject it, and then monitor the injection space to ensure the
CO2 remains stored. Currently there are only two large-scale
commercial applications of post-combustion CCS at a coal-fired power
plant--the Boundary Dam project in Saskatchewan, Canada and the Petra
Nova project at the W.A. Parish plant near Houston, Texas.\209\
Commenters noted that both of the demonstration projects were heavily
subsidized by government support and were able to generate additional
income from the sale of captured CO2 for enhanced oil
recovery (EOR) and, without these subsidies, neither project would have
been economically viable.
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\209\ Several commenters noted that the Petra Nova project
received funding from the U.S. Department of Energy (DOE) through
the Clean Coal Power Initiative and stated that the project is,
pursuant to section 402(i) of the Energy Policy Act of 2005
(EPAct05), therefore, precluded from being used to demonstrate that
the technology is ``adequately demonstrated'' under section 111 of
the CAA. Some commenters noted that the DOE funding was only for the
initial 60 MW slip-stream demonstration project, but the CCS project
at Petro Nova was later expanded to a 240 MW slip-stream and no
federal funding was received for this expansion.
---------------------------------------------------------------------------
Commenters addressed the cost of installing CCS on an existing
coal-fired EGU and noted that it can be much costlier and more
technically challenging to retrofit the technology to an existing EGU
as compared to installation on a newly constructed unit (where the
system can be incorporated into the design and space allocation of the
new plant). Other commenters claimed that CCS can achieve significant
emission reductions (up to 90 percent), that there is opportunity for
some sources to generate income from the sale of captured
CO2, and that there are additional financial incentives from
the recently approved 2018 Internal Revenue Code (IRC) section 45Q tax
credits for stored CO2, so now CCS may be more cost-
effective than HRI options for some facilities. One commenter performed
modeling runs that included the section 45Q tax credit and found that,
for some sources, CCS would provide much greater emission reductions
than HRI options at a reasonable cost and concluded that the EPA should
include CCS as part of the BSER. Other commenters minimized the impact
of the section 45Q tax credit for a variety of reasons.
Several commenters claimed that access to appropriate
CO2 storage locations is critical to the feasibility and
cost of CCS. They described the geographic limitations of both deep
saline aquifers and depleted oil fields (EOR fields) noting that 15
states have little or no demonstrated storage capacity or have very
limited storage capacity and that EOR sites are similarly
geographically limited, with 19 states having little or no demonstrated
EOR opportunity. However, other commenters claimed that a technology
need not be feasible at every site to be a component of BSER especially
since the EPA is relying on site-specific analyses. The commenters
noted that not all HRI options are applicable to every source, so the
EPA cannot disregard CCS from the BSER options based on ``national
availability.''
Commenters noted that 60 GW (or about 20 percent) of the coal-fired
power plant capacity might be amenable to CCS based on locality and
that North America has widespread and abundant geologic storage options
with the capacity to sequester over 500 years of the U.S.'s current
energy-related CO2 emissions. Commenters claimed that 90
percent of existing coal-fired power plants are within 100 miles from
the center of a basin with adequate storage capacity and more than half
of the existing plants are less than 10 miles from the center of a
basin.
The EPA has considered all these public comments and has concluded
that, as proposed, CCS is not the BSER for emissions of CO2
from existing coal-fired EGUs--nor does it constitute a component of
the BSER, as some commenters have suggested. As discussed in section
III.E.1, above, concerning the ``guiding principles'' for identifying
the BSER under CAA section 111(d), the BSER is based on what is
adequately demonstrated and broadly achievable across the country.
Under CAA section 111(b)(1), the EPA determines ``standards of
performance'' for new sources and under section 111(d)(1), the states
determine ``standards of performance'' for existing sources within
their jurisdiction. Importantly, the term ``standard of performance''
is given a uniform definition under section 111(a)(1) for purposes of
both new and existing sources, and, in accordance with that definition,
the Administrator is required to determine the BSER as a predicate for
the standards of performance for both new and existing sources. In this
manner, the text and structure of section 111 indicate that the EPA
must make the BSER determination at the national, source-category
level. Thus, the EPA disagrees with the commenters who argue that
because the EPA is emphasizing that standard setting will be done on a
unit-by-unit (rather than fleetwide) basis, all viable emission
reduction options should be evaluated at the unit level.
Whereas HRI measures are broadly applicable to the entire existing
coal-
[[Page 32548]]
fired power plant fleet, the EPA determines that CCS or partial CCS is
not. The EPA agrees that there may be some existing coal-fired EGUs
that find the application of CCS to be technically feasible and an
economically viable control option, albeit only under very specific
circumstances. However, the high cost of CCS, including the high
capital costs of purchasing and installing CCS technology and the high
costs of operating it, including high parasitic load requirements,
prevent CCS or partial CCS from qualifying as BSER on a nationwide
basis.
According to the DOE National Energy Technology Laboratory (NETL),
the incremental cost from capital expenditures alone of installing
partial or full capture CCS \210\ on a new coal-fired EGU ranged from
$626 (for 16% capture) to $2,098 (for full capture) per kW (2011
dollars).\211\ These costs are for new CCS equipment installed on a new
facility, but they fairly represent the costs of new CCS equipment
installed on an existing facility; indeed, these costs are probably
lower than the actual costs of installing new CCS equipment on an
existing facility, because the costs of retrofitting pollution controls
on an existing facility generally are greater than the costs of
installing pollution controls on a new facility. In contrast, as noted
elsewhere, the cost of the HRI that constitute the BSER for this rule
range from $25-$47 per kW (2016 dollars). Thus, the costs of partial
CCS, considering only the capital costs and not the operating costs,
are far higher than--more than 13 times--the cost of what the EPA has
identified as the BSER.
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\210\ Full capture is considered to occur when 100 percent of
the flue gas is treated, resulting in a 90 percent reduction in
emissions of CO2 relative to a power plant without carbon capture.
\211\ ``Cost and Performance Baseline for Fossil Energy Plants
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired Power
Plants,'' une 22, 2015; DOE/NETL-2015/1720 https://www.netl.doe.gov/projects/files/[FR Doc.SupplementSensitivitytoCO2CaptureRatein[FR
Doc.CoalFiredPowerPlants_062215.pdf.
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Viewing the costs of CCS through other prisms yields the same
determination. According to NETL, the capital costs of a CCS system
with 90 percent capture increases the cost of a new coal-fired power
plant approximately 75 percent relative to the cost of constructing a
new coal-fired power plant without post-combustion control technology.
Furthermore, the additional auxiliary load required to support the CCS
system consumes approximately 20 percent of the power plant's potential
generation.\212\ The NETL Pulverized Coal Carbon Capture Retrofit
Database tool (April 2019) \213\ estimates that the operating costs of
existing coal-fired EGUs range from 22 to 44 $/MWh.\214\ The
incremental increase in generating costs, including the recovery of
capital costs over a 30-year period, due to CCS range from 56 to 77 $/
MWh.\215\ For reference, according to the EIA, the average electricity
price for all sectors in March of 2019 was 103.8 $/MWh.\216\ About 60
percent of these latter costs (60 $/MWh) are associated with generation
and 40 percent with transmission and distribution of the
electricity.\217\ Thus, the incremental increase in generating costs
due to CCS by itself would equal or exceed the average generation cost
of electricity for all sectors. The costs of partial CCS are less than
full CCS, but due to economies of scale, costs do not reduce as quickly
as reductions in the capture rate. For example, the capital costs of
treating only 18 percent of the flue gas (a 16 percent reduction in
emissions of CO2) are about 30 percent of the capital costs
of treating all of the flue gas (full capture or a 90 percent reduction
in emissions of CO2). Similarly, at full capture, treating
only 18 percent of the flue gas (a 16 percent reduction in emissions of
CO2) still increases the cost of electricity by about 28
percent of the increase that results from treating all of the flue
gas.\218\ Again, these costs are probably lower than the actual costs
of installing new CCS equipment on an existing facility. Not only are
these costs far higher than what the EPA has identified as the BSER,
they would almost certainly force the closure of the coal-fired power
plants that would be required to install them. Many of those plants
have a marginal profit margin, as demonstrated by the high rate of
plant closure and the relatively low amounts of operation (i.e.,
capacity factors) in recent years. Thus, these costs must be considered
exorbitant. See section III.E.1. for a discussion of the guiding
principles in determining the BSER.
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\212\ A CCS system requires both auxiliary steam and electricity
to operate. According to NETL, a full capture system consumes 53 MW
of direct electrical load and steam that could have otherwise been
used to generate approximately 86 MW of electricity.
\213\ https://www.netl.doe.gov/energy-analysis/details?id=2949.
\214\ Existing coal-fired power plants have generally already
paid off the initial construction (i.e., capital) expenses.
\215\ Variable operating costs represent approximately $15/MWh
and the remaining costs are recovered capital over a 30-year period.
The capital costs assume the power plant can recover the costs over
30 years. If the actual remaining useful life of the power plant
itself is less, the costs would be higher because the capital would
have to be recovered over a shorter time period. The average age of
the remaining coal fleet is approximately 42 years, and the average
age of retirement for coal-fired power plants is currently 54 years
(http://www.americaspower.org/wp-content/uploads/2018/03/Coal-Facts-August-31-2018.pdf). Therefore, a significant portion of the
existing coal-fired will likely retire in less than 30 years.
\216\ https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_5_6_a.
\217\ https://www.eia.gov/outlooks/aeo/data/browser/#/?id=8-AEO2019&cases=ref2019&sourcekey=0.
\218\ ``Cost and Performance Baseline for Fossil Energy Plants
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired
Power Plants,'' June 22, 2015; DOE/NETL-2015/1720.
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As noted above, the Boundary Dam project in Saskatchewan, Canada
and the Petra Nova project at the W.A. Parish plant near Houston, Texas
are the only large-scale commercial applications of post-combustion CCS
at a coal-fired power plant. They both have retrofit CCS or partial
CCS, and they both received significant governmental subsidies--
including, for the Petra Nova project, both direct federal grants from
the DOE through the Clean Coal Power Initiative and the IRC section 45Q
tax credits--and relied on nearby EOR opportunities. Due to the high
costs of CCS, all of these subsidies and EOR opportunities were
essential to the commercial viability of each project.\219\
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\219\ The EPA discussed the government funding and the EOR
revenue from the transport of captured CO2 to the
Hilcorp's West Ranch Oil Field in ``Standards of Performance for
Greenhouse Gas Emissions from New, Modified, and Reconstructed
Stationary Sources: Electric Generating Units,'' 80 FR 64510, 64551
(October 23, 2015).
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Some commenters have asserted that the costs of CCS are reasonable
and explain, as a central part of their assertion, that the
availability of tax credits under section 45Q, as revised by the
Bipartisan Budget Act of 2018, significantly lowers the costs of CCS.
In fact, they have asserted, that the tax credits, which have an
initial value of $35 per tonne (i.e., metric ton) for CO2
stored through EOR, offset about 70% of the cost of CCS, with EOR
offsetting the rest.\220\ However, the section 45Q tax credits are
limited in time: The credit for equipment placed in service after the
date of enactment of the Bipartisan Budget Act of 2018 is available, in
general, only for facilities and equipment for which construction
begins before January 1, 2024. IRC section 45Q(d)(1). Under the present
rule, state plans are not required to be submitted until mid-2022 and
the states have the authority to determine their sources' compliance
schedule; compliance schedules are generally expected to last 24 months
(i.e., until mid-2024), but could in some instances be longer, as noted
in preamble section
[[Page 32549]]
III.F.1.a.(2).\221\ In order for sources to implement CCS and be able
to rely on the 45Q tax credit, they would have to complete all
planning, including arranging all financing, preconstruction
permitting, and commence construction within about 18 months (by
December 31, 2023) of the state plan submittal. The EPA considers that
timetable to be impracticably short for most sources, considering the
complexity of implementation of CCS. In addition, the tax credit is, in
general, available only for the 12-year period beginning on the date
the equipment is originally placed in service. IRC section 45Q(a)(3)-
(4). Thus, it would not be available to offset much of the capital
costs of the CCS systems that are recovered over a 30-year period.\222\
Further, like any federal income tax credit, the 45Q tax credits do not
provide a benefit to a company that does not owe federal income tax,
and thus it may not benefit some coal-fired power plant owners.
Accordingly, the 45Q tax credits cannot be considered to offset the
high costs of CCS for the industry as a whole. While nearby EOR
opportunities are available for some EGUs, they alone cannot offset the
high costs of CCS, as is evident from the comments discussed above.
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\220\ EPA-HQ-OAR-2017-0355-24266 at 18.
\221\ By comparison, the implementation period for the CPP began
three years after the state plan submittal. See 80 FR at 64669.
\222\ The NETL Pulverized Coal Carbon Capture Retrofit Database
tool (April 2019) defaults to a capital recovery factor based on 30
years. Capital recovery factors based on 10 and 20 years are also
selectable. If shorter periods are selected, the $/MWh for capital
recovery would be higher. Table 10-12 of The Integrated Planning
Model (version 6) uses a 15-year capital recovery factor for
environmental retrofits, https://www.epa.gov/sites/production/files/2019-03/documents/chapter_10.pdf. Recovering costs over a 12-year
period, as opposed to a 30-year period, increased the capital
recovery factor by 40 percent.
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In addition, nearby EOR opportunities are not available for many
EGUs, which, as a result, would incur higher costs for constructing and
operating pipelines to transport CO2 long distances.
Throughout the country, 29 states are identified as having oil
reservoirs amenable to EOR, of which only 12 states have active EOR
operations.\223\ The vast majority of EOR is conducted in oil
reservoirs in the Permian Basin, which extends through southwest Texas
and southeast New Mexico. States where EOR is utilized include Alabama,
Arkansas, Colorado, Louisiana, Michigan, Mississippi, Montana, New
Mexico, Oklahoma, Texas, Utah, and Wyoming, whereas coal-fired
generation capacity is located across the country.\224\ For example,
Georgia, Minnesota, Missouri, Nevada, North Carolina, South Carolina,
and Wisconsin have coal-fired generation capacity but do not have oil
reservoirs that have been identified as amenable for EOR. In addition,
some of the states with the largest amounts of coal-fired generation
capacity have no active EOR operations, including Illinois, Indiana,
Kentucky, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia.
Even in states that are identified as having potential oil and gas
storage capacity, the amount of storage resource varies by state. In
some states, the total oil and gas storage resource is smaller than the
annual energy-related CO2 emissions from coal, including
Indiana and Virginia.\225\ The limited geographic availability of EOR,
and the consequent high costs of CCS for much of the coal fleet, by
itself means that CCS cannot be considered to be available across the
existing coal fleet.
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\223\ The United States 2012 Carbon Utilization and Storage
Atlas, Fourth Edition, U.S. Department of Energy, Office of Fossil
Energy, National Energy Technology Laboratory (NETL) and EPA
Greenhouse Gas Reporting Program, see https://www.epa.gov/ghgreporting.
\224\ U.S. Energy Information Administration, Electric Power
Annual 2017, see https://www.eia.gov/electricity/annual/pdf/epa.pdf.
\225\ The United States 2012 Carbon Utilization and Storage
Atlas, Fourth Edition, U.S. Department of Energy, Office of Fossil
Energy, National Energy Technology Laboratory (NETL) and U.S. Energy
Information Administration, Energy-Related Carbon Dioxide Emissions
by State, 2005-2016, see https://www.eia.gov/environment/emissions/state/analysis/.
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The high costs of CCS inform the Administrator's determination that
this technology is not BSER. Some commenters have suggested that CCS be
treated as BSER for some facilities on a unit-by-unit basis, but the
EPA believes that this would be inconsistent with its role under
section 111(a)(1) to determine as a general matter what is the BSER
that has been adequately demonstrated, taking into account, among other
factors, cost. To treat CCS as BSER for a handful of facilities would
result in those facilities becoming subject to high costs from CCS--
potentially much higher than those imposed on other facilities for whom
CCS is not treated as BSER. This potential disparate impact of costs is
inconsistent with the Administrator's role in determining BSER and is
another reason why the Administrator is finalizing a determination that
CCS is not BSER.
Nevertheless, while many commenters argued that CCS should not be
considered part of the BSER, they supported its use as a potential
compliance option for meeting an individual unit's standard of
performance. The EPA agrees with this assessment. Evaluation of the
technical feasibility (e.g., space considerations, integration issues,
etc.) and the economic viability (e.g., the prospects and availability
of long-term contractual arrangements for sale of captured
CO2, the cost of constructing a CO2 pipeline, the
availability of tax credits, etc.) of a CCS project is heavily
dependent on source-specific characteristics. Accordingly, state plans
may authorize such projects for compliance with this rule.
F. State Plan Development
1. Establishing Standards of Performance
CAA sections 111(d)(1) and 111(a)(1) collectively establish and
define certain roles and responsibilities for the EPA and the states.
As discussed in section III.B above, the EPA has the authority and
responsibility to determine the BSER. CAA section 111(d)(1) clearly
contemplates that states will submit plans that establish standards of
performance for designated facilities (i.e., existing sources).
States have broad flexibility in setting standards of performance
for designated facilities. However, there is a fundamental obligation
under CAA section 111(d) that standards of performance reflect the
degree of emission limitation achievable through the application of the
BSER, which derives from the definition for purposes of section 111 of
``standard of performance'' in those terms, with no distinction made
between new-source and existing-source standards. In establishing such
standards of performance, the statute expressly provides that states
may consider a source's remaining useful life and other factors.
Accordingly, based on both the mandatory and discretionary aspects of
CAA section 111(d), a certain level of process is required of state
plans: Namely, they must demonstrate the application of the BSER in
establishing a standard of performance, and if the state chooses, the
consideration of remaining useful life and other factors in applying a
standard of performance to a designated facility. The EPA anticipates
that states can correspondingly establish standards of performance by
performing two sequential steps, or alternatively, as further described
later in this section, by performing these two steps simultaneously.
The two steps to establish standards of performance are: (1) Reflect
the degree of emission limitation achievable through application of the
BSER, and, if the state chooses, (2) consider the remaining useful life
and other source-specific factors.
[[Page 32550]]
If a state chooses to develop standards of performance through a
sequential (i.e., two step) process, the state would as the first step
apply the BSER to a designated facility's emission performance (e.g.,
the average emission rate from the previous three years or a projected
emission rate under specific conditions such as load) and calculate the
resulting emission rate. In this step, states fulfill the obligation
that standards of performance reflect the degree of emission limitation
achievable by evaluating the applicability of each of the candidate
technologies that comprise the BSER to a specific designated facility
and calculating a corresponding standard of performance based on the
application of all candidate technologies that the state determines are
applicable to the specific designated facility. A state may determine
the most appropriate methodology to calculate a standard of performance
(which for purposes of this regulation will be in the form of an
emission rate, as further described in section III.F.1.c. of this
preamble) by applying the BSER to a designated facility based on the
characteristics of the specific source (e.g., load assumptions and
compliance timelines). For example, a state can start with the average
emission rate of a particular designated facility and adjust it to
reflect the application of each candidate technology and the associated
emission rate reduction.
As the second step, under this two-step, sequential process
approach, after the state calculates the emission rate that reflects
application of the BSER, the state may adjust that rate by considering
the remaining useful life of the designated facility and other source-
specific factors. It should be noted that the state is not required to
take this second step and consider remaining useful life and other
factors. Rather, the state has the discretion to do so. A discussion on
how a state can consider remaining useful life and other factors, if it
so chooses, can be found in section III.F.1.b. below. States also have
the discretion to apply a specific standard of performance to a group
of existing sources within their jurisdiction, or to all existing
sources within their jurisdiction.
As just described, the EPA believes it would be reasonable for
states to follow a sequential two-step process to establish standards
of performance. However, a state may develop its own process for
calculating standards of performance outside of this two-step process,
such as a hybridized approach which blends the two sequential steps
into one combined step, so long as the state plan submission
demonstrates application of the BSER in determining each standard of
performance, (i.e., evaluation of applicability of each and all
candidate technologies to each designated facility). For example, if a
state determines that the designated facility is able to implement only
four of the six candidate technologies (due to the remaining useful
life or other factors), the state is required to demonstrate in its
plan submission that it in fact considered the two remaining candidate
technologies in making this determination.
For the two-step approach, a state could do this by explaining in
its plan submission that it considered the application of each of the
candidate technologies in the first instance, but in the second step
the state determined that the two candidate technologies should not be
part of the methodology to calculate the EGU's standard of performance
because of remaining useful life or other factors. The state should
additionally provide a rationale for why and how it considered
remaining useful life and other factors to discount a particular
candidate technology from the calculation of a standard of performance
(e.g., by explaining that such technology has already been implemented
by a particular source).
For a hybridized approach, when the state is applying the BSER and
determining the emission reductions associated with the candidate
technologies for a specific designated facility, it may be readily
apparent that two of the candidate technologies are not reasonable to
install because, for example, those technologies have recently been
updated at the unit, independent of this final rule. This hybridized
approach, which blends application of the BSER and associated
stringency with consideration of remaining useful life and other
factors in one step to calculate a standard of performance, may be
appropriate provided that the state plan clearly demonstrates the
standard of performance (expressed as a degree of emission limitation)
that would result from application of the BSER and provides a rationale
for why and how remaining useful life and other factors were considered
to discount a particular candidate technology from the calculation of a
standard of performance. This is one illustrative way in which states
can demonstrate, in establishing a standard of performance, that they
have both fulfilled their obligation to apply the degree of emission
limitation achievable through the BSER to each designated facility and
also properly invoked their discretion in considering remaining useful
life and other factors.
In this section of the preamble, the EPA addresses discrete aspects
of the standard-setting process. It is intended to provide states
clarity and direction on each of these aspects to assist the states in
developing standards of performance. The EPA is not requiring a
specific method for states to develop standards of performance.
a. Application of the BSER
As described in other parts of this section, while the EPA's role
is to determine the BSER, CAA section 111(d)(1) squarely places the
responsibility of establishing a standard of performance for an
existing designated facility on the state as part of developing a state
plan. This final rule requires states to evaluate the applicability of
each of the candidate technologies (HRI measures) that the EPA has
determined constitute the BSER in establishing a standard of
performance for each designated facility within their jurisdiction. The
BSER is a list of candidate technologies that are HRI measures, which
states will evaluate and apply to existing sources, establishing a
standard of performance that is appropriately tailored to each existing
source.\226\ In establishing a standard of performance, a state may
consider remaining useful life and other factors as appropriate based
upon the specific characteristics of those units. In general, the EPA
envisions that 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 the
EPA's candidate technologies described earlier in section III.E), or
changes in operation of the units, among other factors the state
believes are relevant. As such, states have considerable flexibility in
determining standards of performance for units, as contemplated by the
express statutory text.
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\226\ Because the candidate technologies that comprise the BSER
can, at least in some cases, be applied in combination at an
individual source, states should evaluate both individual candidate
technologies and combinations of candidate technologies to
appropriately establish standards of performance.
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States have discretion to apply the same standard of performance to
groups of existing sources within their jurisdiction, as long as they
provide a sufficient explanation for this choice and a demonstration
that this approach will result in standards of performance achievable
at the sources. But states also
[[Page 32551]]
have discretion, expressly conferred on them by Congress in CAA section
111(d), to take into account a source's remaining useful life and other
factors when establishing a standard of performance of that source, and
much of the discussion in this final rule relates to the nature of that
discretion and the factors that should influence states' exercise of
it. As the EPA described in the proposal and as commenters have
verified, the fleet of coal-fired EGUs is diverse and each EGU has been
designed and engineered uniquely to fit the need at the time of
construction. Because each coal-fired steam boiler subject to this rule
has been designed, maintained, utilized, and upgraded uniquely, each
designated facility has a unique set of circumstances with a set of
source-specific factors governing its use. The outgrowth of the
abundance of source-specific factors has led the EPA to determine that
a tailored standard of performance (developed by states) that considers
those factors can achieve emission reductions in the fleet without
making broad assumptions about the fleet that may not be applicable to
a particular unit. The source-specific circumstances at each EGU causes
considerable variation in average emission rates across the fleet. If a
single standard of performance (i.e., a single degree of emission
limitation resulting from a particular technology or fixed set of
technologies) were to be applied to the entire fleet, the result could
be either that a large portion of the fleet would not be required to
achieve any meaningful emission reductions, or a large portion of the
fleet would face overly stringent requirements. The goal of these
emission guidelines is not to burden or shut down coal-fired EGUs--
which could compromise the stability of the power sector and thus
energy reliability to consumers, concerns which the EPA expresses,
informed by, among other factors, Congress's direction to take into
account energy requirements in determining BSER--as coal-fired EGUs
still have considerable viability as part of the power sector.
When states apply the BSER's candidate technologies to a designated
facility, the application of each technology and the associated degree
of emission limitation achievable by such application will entail
source-specific determinations. For this reason, in Table 1, the EPA
provided the degree of emission limitation achievable through
application of the BSER in the form of ranges, which capture the
reductions and costs that the EPA expects to approximate the outcome of
the application. The degree of emission limitation achievable through
application of the BSER (i.e., the ranges of improvements in Table 1)
should be used by the states in establishing a standard of performance;
however, the standard of performance calculated for a specific
designated facility may ultimately reflect a degree of emission
limitation achievable through application of the BSER outside of the
EPA's ranges because of consideration of source-specific factors. If a
state uses the sequential two-step process to establish a standard of
performance, in the first step the EPA expects that the state will use
the range of improvements for each candidate technology (and
combinations thereof where technically feasible) to develop a standard
of performance for a designated facility (the range of costs can be
used in the second step which considers the remaining useful life and
other factors as discussed in section III.F.1.b.). The ranges of HRI in
section III.E are typical of an EGU operating under normal conditions.
While a source with typical operating conditions (assuming no
consideration of remaining useful life or other factors) will have a
standard of performance with an expected improvement in performance
within the ranges in Table 1, there may be source-specific conditions
that cause the actual HRI of the applied candidate technology to fall
outside the range. For example, if a designated facility had installed
a new boiler feed pump just prior to a state's evaluation of the
designated facility, the application of that candidate technology would
yield negligible improvement in the heat rate and thus the value would
fall outside the ranges provided by the EPA (i.e., because the
technology has already been applied and the baseline emission rate
reflects that). As with the application of all the candidate
technologies, the state plan submission must identify: (1) The value of
HRI (i.e., the degree of emission limitation achievable through
application of the BSER) for the standard of performance established
for each designated facility; (2) the calculation/methodology used to
derive such value; and (3) any relevant explanation of the calculation
that can help the EPA to assess the plan. In explaining the value of
HRI that has been calculated, if the value of the HRI falls within the
range identified by the EPA for a particular candidate technology, a
state may note as such as part of its explanation. If a resulting value
of HRI falls outside the range provided by the EPA, the state should in
its state plan submission explain why this is the case based on
application of the candidate technology to a particular source. In any
instance, the state plan submission must identify the value of HRI that
has been calculated and the calculation used to derive the value of
HRI, and explain both. The states will thus use the information
provided by the EPA, but will be expected to conduct source-specific
evaluations of HRI potential, technical feasibility, and applicability
for each of the BSER candidate technologies. After a state applies the
candidate technologies to a designated facility (i.e., step one), it
can consider the remaining useful life and other factors associated
with the source and determine whether it is cost-reasonable to actually
implement that technology at the source (i.e., step two). This is
described in detail below in section III.F.1.b.
The approach to require states to tailor standards of performance
for designated facilities is both consistent with the framework of
cooperative-federalism envisioned under CAA section 111(d), and the new
implementing regulations for CAA section 111(d).\227\ The new
implementing regulations at40 CFR 60.21a(e) and 60.22a(b)(2) and (4)
require emission guidelines to reflect, and contain information on, the
degree of emission limitation achievable through the application of the
BSER. By providing the BSER and the associated level of stringency in
the form of HRIs and associated range of heat rate improvements, the
EPA is thus meeting applicable statutory and regulatory requirements
and is giving states the necessary information and direction to
establish standards of performance for existing sources that reflect
the degree of emission limitation achievable through application of the
BSER.\228\
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\227\ See 83 FR 44746.
\228\ By providing the BSER and level of stringency associated
with the BSER, ACE meets the applicable requirements of the new
implementing regulations at 40 CFR part 60, subpart Ba, regarding
the contents of an emission guideline. An ``emission guideline'' is
defined under 40 CFR 60.21a(e) as a ``final guideline document''
which must contain certain items enumerated under 40 CFR 60.22a. The
preamble, regulatory text, and record for ACE comprise the ``final
guideline document'' referenced as the emission guideline.
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(1) Variable Emission Performance
The Agency received comments that there is considerable variation
in emissions between designated facilities within the industry, as well
as considerable variation of emissions for individual units based on
the operating conditions. Commenters expressed concern that the degree
of emission limitation achievable through the application of the BSER
is similar to the
[[Page 32552]]
magnitude in the variation in the emission rate at a specific EGU due
to different operating conditions (e.g., the operating load of the
EGU). Commenters contend that because of this similarity, a designated
facility could fall out of compliance with its standard of performance
if its operating conditions change despite the source's having
installed/applied all of the candidate technologies.
Commenters further stated that oftentimes the operation of a
designated facility is not in the control of the owner/operator when it
goes to load and cycling, and because of that the emission rate varies
based on circumstances that are outside of the designated facility's
control. The commenters further state that they should not be held
accountable to standards that are not reflective of this lack of
control and variability. The EPA acknowledges commenters' concerns
about variability among designated facilities and variability of
emission performance at an individual designated facility, and believes
the flexibilities provided for states in establishing standards of
performance, as described in this section, are sufficient to
accommodate these variables. In establishing standards of performance,
states can consider the two distinct types of variable emission
performance \229\ (i.e., variation between different facilities and
variation of emissions at one facility at different times) and states
can tailor standards of performance accordingly.
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\229\ In this context, variable emission performance is a result
of underlying variability in heat rate, as emissions of
CO2 from EGUs are proportional to the unit's heat rate
performance.
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First, standards of performance should acknowledge and reflect
variability across EGUs due to unit-specific characteristics and
factors, including, but not limited to, boiler-type, size, etc. By
allowing states to establish standards of performance for individual
designated facilities (in accordance with the statute's text and
structure which provides that states in their plans shall establish
standards of performance for existing sources), the EPA expects that
standards of performance will inherently account for unit-specific
characteristics.\230\ By applying the BSER to individual designated
facilities within the state, standards of performance would account for
unit-specific characteristics such as unit design, historical operation
and maintenance. As further described in section III.F.1.b, states may
also account for anticipated future design and/or operating plans--such
as plans to operate as baseload or load following electricity
generators.
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\230\ Note that for administrative efficiency in developing a
state plan, a state may be able to calculate a uniform standard of
performance that reflects application of the BSER for a group of
designated facilities rather than performing the same calculation
multiple times for multiple individual sources if the group of
sources has similar characteristics such that application of BSER
would be consistent between the EGUs. This final rule does not
necessarily require a state to provide a discrete calculation and
separate standard of performance for each designated facility within
a group of similar designated facilities, but if a state chooses to
calculate a uniform rate for such a group of sources the plan
submission should explain how the uniform rate reflects application
of the BSER for all of the units in the group (e.g., because of
similar operating characteristics). Additionally, even if the same
emission rate is calculated for designated facilities at different
facilities that are included in such a group, such standard is
applicable to each individual designated facility, and each source
would be required to meet that standard by implementing ACE
requirements separately, consistent with the state plan requirements
described in section III.F.2 of this rule.
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Second, standards of performance should reflect variability in
emission performance at an individual designated facility due to
changes in operating conditions. Specifically, the agency believes it
would be appropriate for states to identify key factors that influence
unit-level emission performance (e.g., load, maintenance schedules, and
weather) and to establish emission standards that vary in accordance
with those factors. In other words, states could establish standards of
performance for an individual EGU that vary (i.e., differ) as factors
underlying emission performance vary. For example, states could
identify load segments (ranges of EGU load operation) that reflect
consistent emission performance within the segment and varying emission
performance between segments. States could then establish standards of
performance for an EGU that differ by load segment.
Another possible option to account for variable emissions is to set
standards of performance based on a standard set of conditions. A state
could establish a baseline of performance of a unit at specific load
and operational conditions and then set a standard against those
conditions via the application of the BSER. Compliance for the unit
could be demonstrated annually (or by another increment of time if
appropriate based on the level of stringency of the standard of
performance set for the unit) at those same conditions. In the interim,
between the demonstration of compliance under standardized conditions,
a state could allow for the maintenance and demonstration of fully
operational candidate technologies to be a method to demonstrate
compliance as the standard of performance must apply at all times.
The Agency believes that these approaches to providing flexibility
(and possible others not described here) in establishing standards of
performance are reasonable and appropriate by accounting for innate
variable emission performance across EGUs and at specific EGUs while
also limiting this flexibility to instances in which underlying
variable factors are evaluated and linked to variable emission
performance.
(2) Compliance Timelines
Additionally, the new implementing regulations require that
emission guidelines identify information such as a timeline for
compliance with standards of performance that reflect the application
of the BSER.\231\ However, given the source-specific nature of these
emission guidelines and the reasonably anticipated variation between
standards established for sources within a state, the 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 is superseding this aspect of 40 CFR
60.22a for purposes of ACE, as allowed under the applicability
provision in the new implementing regulations under 60.20a and allowing
for states to include an appropriate compliance deadline for each
designated facility based on its standard of performance determined as
part of the state plan process. It is important that states consider
compliance timelines that are consistent with the application of the
BSER to ensure that the compliance timeline does not undermine the BSER
determination made by the EPA. For most states, the EPA anticipates
initial compliance to be achieved by sources within twenty-four months
of the state plan submittal. If a state chooses to include a compliance
schedule (because of source-specific factors) 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 \232\). The EPA does not envision that most states will be
using increments of progress leading up to initial compliance. However,
as with the consideration of other source-specific factors, where a
state does choose to provide for a source to comply on a longer
timeframe than twenty-four months and to employ legally enforceable
increments of progress
[[Page 32553]]
along the way, the state should include in its state plan submission to
the EPA an adequate justification for why that approach is warranted.
The level of stringency can be compromised if a compliance schedule
does not adequately reflect the BSER determination.
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\231\ See 40 CFR 60.22a.
\232\ See 40 CFR 60.24a(d).
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Several commenters requested clarity on when standards of
performance must become effective (i.e., when must designated
facilities comply with their standards of performance) once a state
plan has been submitted but not yet approved by the EPA. The contents
of a state plan submission, such as standards of performance and
related requirements, are not effective or enforceable under federal
law until they are approved by the EPA. However, state plan
requirements must be fully adopted as a matter of state law, or issued
as a permit, order, or consent agreement, before the plan is submitted
to the EPA (and therefore could be enforceable as a matter of state
law, depending on when the state has chosen to make such requirements
effective).\233\ The EPA anticipates that in determining an appropriate
compliance schedule (and more specifically the initial compliance) for
designated facilities, a state will consider the anticipated timing of
review of the state's plan by the EPA and what sources may need to do
in the interim in order to assure ultimate compliance with their
standards of performance while EPA is in the process of reviewing the
plan.
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\233\ 40 CFR 60.23a, 60.27a(g)(2)(iii).
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States also have discretion in establishing a compliance schedule
for designated facilities, but the Agency urges states to use caution
as to not undermine the BSER by the determined schedules. Most programs
under CAA section 111 do not have compliance timelines greater than a
year and the Agency believes that is a good indicator for states to
take into consideration determining compliances schedules. Much of how
a compliance schedule is structured can be based on how the standard of
performance is structured. In section III.F.1.a.(1) there is a
discussion about how a state might account for variable emissions. One
of the options is to set a standard of performance under standardized
conditions to take into account many of the factors that can lead to
variable emissions from a designated facility. The standardized
conditions (e.g., load, ambient temperature, humidity etc.) that apply
to the standard of performance must also be met when there is a
compliance demonstration. Because these standardized conditions are not
maintained throughout a compliance period, the segmented nature of
demonstrating compliance could mirror the compliance schedule. For
example, a designated facility could have a monthly demonstration under
standardized conditions that mirrors a monthly compliance schedule.
This is one example to illustrate how a standard of performance can
align with a compliance schedule.
Another consideration for states in establishing standards of
performance is the emission averaging time (e.g., the amount of time
that a designated facility may average its emission rate). As described
above in section III.F.1.a.(1), EGUs may have considerably variable
emissions due to numerous operating factors. A method to account for
seasonal variability is to average a designated facility's emission
rate over the course of multiple seasons.
b. Consideration of Remaining Useful Life and Other Factors
CAA section 111(d) requires, in part, that the EPA ``shall permit
the State in applying a standard of performance to any particular
source under a plan submitted under [CAA section 111(d)] to take into
consideration, among other factors, the remaining useful life of the
existing source to which such standard applies.'' Consistent with the
requirements of this provision, the EPA is permitting states to
consider remaining useful life and other factors in establishing a
standard of performance for a particular source in this final rule.
States may do this in several ways. If a state is following the
sequential two-step process, the state would first apply all of the
candidate technologies to a designated facility to derive a standard of
performance with consideration to the EGU's historical or projected
performance, as previously described in section III.F.1.a. In the
second step of this process, the state would consider the ``remaining
useful life and other factors'' for the EGU and develop a standard of
performance accordingly. It should be noted that the consideration of
remaining useful life and other factors is a discretionary step for
states. If a state were to establish a standard of performance for a
designated facility based solely on the application of the BSER, it
would be reasonable to do so and not precluded under the statute.
The CAA explicitly provided under CAA section 111(d)(1) that states
could, under appropriate circumstances, establish standards of
performance that are less stringent than the standard that would result
from a direct application of the BSER identified by the EPA. CAA
section 111(d)(1) achieves this goal by authorizing a state, in
applying a standard of performance, to take into account a source's
remaining useful life and other source-specific factors. As such, the
EPA is promulgating, as part of the new implementing regulations at 40
CFR 60.20a-29a, a provision to permit states to take into account
remaining useful life, among other factors, in establishing a standard
of performance for a particular designated facility, consistent with
CAA section 111(d)(1)(B). The new implementing regulations (also
consistent with the previous implementing regulations) give meaning to
CAA section 111(d)(1)(B)'s reference to ``other factors'' by
identifying the following as a nonexclusive list of several factors
states may consider in establishing a standard of performances:
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
designated facility, there are important factors that influence
decisions to invest in technologies to meet a potential standard of
performance. These include factors not enumerated in the list provided
above, including timing considerations like expected life of the
source, payback period for investments, the timing of regulatory
requirements, and other source-specific criteria. The state may find
that there are space or other physical barriers to implementing certain
HRIs at specific units. Alternatively, the state may find that some HRI
options are either not applicable or have already been implemented at
certain units. The 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 a designated facility can be a unit-by-unit determination
that weighs the value of both the cost of installation and the
CO2 reductions.
The EPA received comment on the ACE proposal that the EPA should
provide more information and guidance for what could be considered
``other factors'' in addition to the considerations of the remaining
useful life. In addition, commenters also requested more information on
the remaining useful life and other source-
[[Page 32554]]
specific factors that could be considered in developing a standard of
performance. The EPA acknowledges that there are a host of things that
could be considered ``other factors'' by states that can be used to
develop a standard of performance. While the EPA cannot identify every
set of circumstances and factors that a state could consider, the EPA
agrees with the commenters that it would be helpful for states if the
EPA were to provide a non-exhaustive set of qualitative examples that
states could consider in developing standards of performance as
described below. The EPA will evaluate each standard of performance and
the factors that were considered in the development of the standard of
performance on a case by case basis. The state should include all of
the factors and how the factors were applied for each standard of
performance in the state plan. The EPA received many notable comments
that states would like more direction and assistance in developing
standards of performance. The examples are intended to help provide
this assistance, but the EPA also understands that, because there are
so many considerations for each source, states might have further
questions while developing plans. States are encouraged to reach out to
the Agency during the development of plans for further assistance.
As noted above, the consideration of the remaining useful life and
other factors most often is a reflection of cost. When the EPA
determines the BSER for a source category, the EPA typically considers
factors such as cost relative to assumptions about a typical unit.
Because the costs evaluated for the BSER determination are relative to
a typical unit, the source-specific conditions of any particular
existing designated facility that a state will evaluate in developing
its plan under CAA section 111(d) are not inherently considered. A
state's consideration of the remaining useful life and other factors
will reflect the costs associated with the source-specific conditions.
As part of the BSER determination, the EPA has provided a range of
costs associated with each candidate technology (see Table 1). These
costs are provided to serve as an indicator for states to determine
whether it is cost-reasonable for the candidate technology to be
installed. These cost ranges are certainly not intended to be
presumptive (i.e., the ranges are not an accurate representation for
each designated facility and should not be used without a justified
analysis by the state), but rather are provided as guide-posts to
states. If a state considers the remaining useful life and/or other
factors in determining a standard of performance, the state is required
to describe, justify, and quantify how the considerations were made in
its plan. Because these considerations are discretionary and source-
specific, the burden is on the state in its plan to demonstrate and
justify how they were taken into account.
A state might consider the remaining useful life of a designated
facility with a retirement date in the near future by a number of ways
in the standard setting process. One way that a state may take into
account this circumstance is in applying the BSER (either through the
sequential, two-step process or through some other method that reflects
application of the BSER), establish a standard that ultimately only
applies the less costly BSER technologies in the development of the
standard of performance that the state establishes for the particular
designated facility. The shorter life of the designated facility will
generally increase the cost of control because the time to amortize
capital costs is less. Another outcome of a state's evaluation of a
designated facility's remaining useful life may lead to the state
setting a ``business as usual'' standard. This could be an appropriate
outcome where the remaining useful life of the designated facility is
so short that imposing any costs on the EGU is unreasonable. Because a
state plan must establish standards of performance for ``any''
designated facility under CAA section 111(d), the standard applied to
this designated facility would reflect ``business as usual'' and
require the unit to perform at its current level of efficiency during
the remainder of its useful life. Under all of these examples and under
any other circumstance in which a state considers remaining useful life
or other factors in establishing a standard of performance, the state
must describe in its state plan submission such consideration and
ensure it has established a standard for every designated facility
within the state, even one with an anticipated near-term retirement
date.
Another consideration for a state in setting standards of
performance with consideration to the remaining useful life and other
factors is how the different candidate technologies interact with one
another and how they interact with the current system at a designated
facility. Commenters have expressed, and the EPA agrees, that the
application of efficiency upgrades at EGUs are not necessarily
additive. Installing HRI technologies in parallel with one another may
mitigate the effects of one or more of the technologies. While states
must apply the BSER and the degree of emission limitation achievable
through such application in calculating a standard of performance,
states may also consider the mitigating effects on the emission
reductions that would result from the installation of a particular
candidate technology, and may as a result of this consideration
determine that installing that particular candidate technology at a
particular source is not reasonable. This consideration is authorized
as one of the ``other factors'' that states may consider in
establishing a standard of performance under CAA section 111(d)(1) and
the new implementing regulations under 40 CFR 60.24a(e).
A prime example of an ``other factor'' is ruling out the
reapplication of a candidate technology. The EPA anticipates this to be
a part of many state plans. In this scenario, a designated facility
recently applied one of the candidate technologies prior to the time
ACE becomes applicable. To require that designated facility to update
that candidate technology again, as a result of ACE, would not be
reasonable because the costs will be significant with marginal, if any,
heat rate improvement.
As described in section III.F.1.c., states are obligated to set
rate-based standards of performance. These will generally be in the
form of the mass of carbon dioxide emitted per unit of energy (for
example pounds of CO2 per megawatt-hour or lb/MWh). The
emission rate can be expressed as either a net output-based standard or
as a gross output-based standard, and states have the discretion to set
standards of performance in either form. The difference between net and
gross generation is the electricity used at a plant to operate
auxiliary equipment such as fans, pumps, motors, and pollution control
devices. The gross generation is the total energy produced, while the
net generation is the total energy produced minus the energy needed to
operate the auxiliary equipment.
Most of the candidate technologies, when applied, affect the gross
generation efficiency. However, some candidate technologies, namely
improved or new variable frequency drives and improved or new boiler
feed pumps, improve the net generation by reducing the auxiliary power
requirement. Because improvements in the efficiency of these devices
represent opportunities to reduce carbon intensity at existing affected
EGUs that would not be captured in measurements of emissions per gross
MWh, states may
[[Page 32555]]
want to consider standards expressed in terms of net generation. If a
state chooses to set standards in the form of gross energy output, it
will be up to the state to determine and demonstrate how to account for
emission reductions that are achieved through measures that only affect
the net energy output.
One of the more significant changes between the ACE proposal and
this action is that the EPA is not finalizing the NSR reforms that it
proposed in the same document that it proposed ACE. While the EPA
intends to take final action on the NSR reform at a later time in a
separate action, the consequences of that action are no longer
considered in parallel with ACE. Two of the candidate technologies,
blade path upgrades and a redesigned/replaced economizer, were proposed
as part of the BSER considering that NSR would not be a barrier for
installation. Under ACE as finalized without parallel NSR reforms, the
EPA anticipates that states may take into account costs associated with
NSR as a source-specific factor in considering whether these two
technologies are reasonable. While the EPA believes that states are
more likely to determine that blade path upgrades and redesigned/
replaced economizers are not as reasonable as anticipated at proposal
when these were proposed as elements of BSER alongside proposed NSR
reforms, as discussed above, the EPA is still finalizing a
determination that these candidate technologies are elements of the
BSER because it still expects these technologies to be generally
applicable across the fleet of existing EGUs, and because the costs of
the technologies themselves are generally economical and reasonable. In
any case, under ACE as finalized, states are required to evaluate the
applicability of all candidate technologies (i.e., the BSER) to a
particular existing source when establishing a standard of performance
for that source.
c. Forms of Standards of Performance
While the EPA is allowing broad flexibility for states in
establishing standards of performance for designated facilities, the
EPA is finalizing a requirement that all standards of performance be in
the form of an allowable emission rate (i.e., rate-based standard in,
for example, lb CO2/MWh-gross). As described in the proposal
an allowable emission rate is the form that corresponds to the 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 III.E. There is a natural correlation
between the BSER and an allowable emission rate as the standard of
performance in this action. Also, by the Agency prescribing that only a
singular form of standard (i.e., an allowable emission rate) is
acceptable, it will promote continuity among states and power
companies, prevent ambiguity, and promote simplicity and ease of
administration and avoid undue burden on the states and regulated
parties.
The EPA received considerable comment that it should allow mass-
based standards of performance. While the EPA understands the appeal of
a mass-based standard for some stakeholders, this form of standard is
not compatible with the EPA's BSER determination. In fact, the EPA
believes that a mass-based standard would undermine the EPA's BSER. If
designated facilities were to have mass-based standards, it is likely
that many would meet their compliance obligation by reduced
utilization. A standard of performance that incentivizes reduced
utilization and possibly retirements does not reflect application of
the BSER. See section II.B above for a discussion of reduced
utilization and CAA section 111.
Additionally, given that the EPA has the obligation under CAA
section 111(d)(2) to determine whether state plans are
``satisfactory,'' certain programmatic bounds are appropriate to
facilitate the state's submission of, and EPA's review of, the
approvability of state plans. Having a uniform type of standard of
performance will help streamline the states' development of their
plans, as well as the EPA's review of those plans as there will be
fewer variables to consider in the development of each standard of
performance. While the Agency has experience implementing mass-based
programs, the uncertainty associated with projecting a level of
generation for designated facilities is unnecessary when there is a
more compatible format, i.e., a rate-based standard.
The EPA also notes that it is not establishing a preference or
requirement for whether a rate-based standard of performance be based
in gross or net heat rate. The EPA acknowledges that there are
ramifications of applying the BSER to establish a standard of
performance with the consideration of type of heat rate used. 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. The consideration of this factor is left to the
discretion of the state.
2. Compliance Mechanisms
Just as states have broad flexibility and discretion in setting
standards of performance for designated facilities, sources have
flexibility in how they comply with those standards. To the extent that
a state develops a standard of performance based on the application of
the BSER for a designated facility within its jurisdiction, sources
should be free to meet that standard of performance using either BSER
technologies or certain non-BSER technologies or strategies. Thus, a
designated facility 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 designated facility 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 natural gas co-firing. In keeping with past
programs that regulated designated facilities using a standard of
performance, the 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
the EPA is either unable to include as part of the BSER, or is unable
to predict. The EPA is, however, excluding some measures from use as
compliance measures: averaging and trading and bio-mass cofiring. These
measures do not meet the criteria for compliance measures. Those
criteria, which are designed to assure that compliance measures
actually reduce the source's emission rate, are two-fold: (1) The
compliance measures must be capable of being applied to and at the
source, and (2) they must be measurable at the source using data,
emissions monitoring equipment or other methods to demonstrate
compliance, such that they can be easily monitored, reported, and
verified at a unit.
With respect to the first criterion, the EPA believes that both
legal and practical concerns weigh against the inclusion of measures
that cannot qualify as a ``system of emission reduction.'' Allowing
those measures would be inconsistent with the EPA's
[[Page 32556]]
interpretation of the BSER as limited to measures that apply at and to
an individual source and reduce emissions from that source. Because
state plans must establish standards of performance--which by
definition \234\ ``reflect[ ] . . . the application of the [BSER]''--
implementation and enforcement of such standards should correspond with
the approach used to set the standard in the first place. Applying an
implementation approach that differs from standard-setting would result
in asymmetrical regulation. Specifically, a state's implementation
measures would result in a more or less stringent standard implemented
at an EGU than could otherwise be derived from application of the BSER.
---------------------------------------------------------------------------
\234\ See CAA section 111(a)(1)
---------------------------------------------------------------------------
There are certainly methods that affected EGUs could use to meet
compliance obligations that are not the BSER, but these methods still
fit the two criteria: They can be applied to and at the source and can
be measured at the source using data, emissions monitoring equipment or
other methods to demonstrate compliance, such that they can be
monitored, reported, and verified at a unit. Such examples include CCS
and natural gas cofiring.
Commenters also requested that reduced utilization be an available
compliance mechanism. While a designated facility reducing its
utilization would certainly reduce its mass of CO2
emissions, it would likely not lead to an improved emission rate. As
noted above in section III.F.1., a state can certainly take into
account a designated facility's projected decreased utilization in
setting a standard of performance, but it cannot make it the means of
meeting compliance obligations because the degree of emission
limitation achievable through the application of the BSER must still be
reflected in setting the standard of performance. See section II.B
above for a discussion of reduced utilization under CAA section
111.\235\
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\235\ For a discussion of reduced utilization in other CAA
contexts, please see ACE RTC Chapter 1, response to comment 76.
---------------------------------------------------------------------------
a. Averaging and Trading
This section discusses the question of whether averaging and
trading are permissible means for sources to comply with ACE. For a
discussion of averaging EGU-emissions over a compliance period, see
section III.F.1.a.(2). In the proposal, the EPA solicited comment on
whether CAA section 111(d) authorizes states to include averaging or
trading between existing sources in the plans they submit to meet the
requirements of final emission guidelines.\236\ Specifically, the EPA:
(1) Proposed to allow states to incorporate, as part of their plan,
emissions averaging among EGUs across a single plant; and (2) solicited
comment on whether CAA section 111(d) should be read not to authorize
states to include trading and averaging between sources.\237\
---------------------------------------------------------------------------
\236\ See 83 FR 44767-768.
\237\ Id.
---------------------------------------------------------------------------
The EPA received numerous comments on the topic of averaging and
trading for compliance with ACE. With respect to averaging across
designated facilities that are located at the same plant--including,
but not limited to, EGUs that are served by a common stack--some
commenters disapproved of this flexibility while others supported the
ability to implement ACE via averaging in state plans. On the topic of
averaging and trading between designated facilities located at
different plants, the Agency received mixed support and opposition.
Some commenters suggested that the EPA's proposed prohibition on
averaging and trading between designated facilities at different plants
was necessary given the Agency's construction of the BSER as limited to
systems that could be applied to and at the ``source'' itself. Other
commenters suggested that averaging and trading for compliance with ACE
is not precluded under CAA section 111(d). Commenters also suggested
that the statutory cross-reference under CAA section 111(d)(1) to CAA
section 110 suggests that trading could be used for implementation
under ACE. Several commenters provided examples of prior CAA section
111(d) regulations in which the agency allowed trading for
implementation (e.g., CAMR).
In this final action, the EPA determines that: Neither (1)
averaging across designated facilities located at a single plant; nor
(2) averaging or trading between designated facilities located at
different plants are permissible measures for a state to employ in
establishing standards of performance for existing sources or for
sources to employ to meet those standards. CAA section 111(d)
authorizes states to establish standards of performance for ``any
existing source,'' which the CAA defines as ``any stationary source
other than a new source.'' \238\ ``Stationary source,'' in turn, means
``any building, structure, facility, or installation which emits or may
emit any air pollutant.'' \239\ In the ACE proposal, the EPA explained
that an 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 [January 8, 2014],'' and ``serves a
generator capable of selling greater than 25 MW to a utility power
distribution system and has 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).'' \240\ The proposal then identified HRI measures
as the BSER for such units.\241\ This action finalizes the Agency's
determination that HRI measures are the BSER for designated facilities.
See sections III.C & III.E.
---------------------------------------------------------------------------
\238\ 42 U.S.C. 7411(a)(6).
\239\ Id. at section 7411(a)(3).
\240\ 83 FR 44754.
\241\ Id. at 44755.
---------------------------------------------------------------------------
Although the D.C. Circuit has recognized that the EPA may have
statutory authority under CAA section 111 to allow plant-wide emissions
averaging,\242\ the Agency's determination that individual EGUs are
subject to regulation under ACE precludes the Agency from attempting to
change the basic unit from an EGU to a combination of EGUs for purposes
of ACE implementation.\243\
---------------------------------------------------------------------------
\242\ See U.S. Sugar v. EPA, 830 F.3d 579, 627 n.18 (D.C. Cir.
2016) (pointing to the definition of ``stationary source'').
\243\ See, e.g., ASARCO v. EPA, 578 F.2d 319, 327 (D.C. Cir.
1978).
---------------------------------------------------------------------------
In ASARCO, the EPA promulgated regulations re-defining ``stationary
source'' as ``any . . . combination of . . . facilities.'' \244\ By
treating a ``combination of facilities'' as a single source, the EPA
intended to adopt a ``bubble concept,'' which would allow a facility to
``avoid complying with the applicable NSPS so long as emission
decreases from other facilities within the same source cancel out the
increases from the affected facility.'' \245\ The Court concluded,
however, that the Agency ``has no authority to rewrite the statute in
this fashion.'' \246\ In a subsequent case, the D.C. Circuit recognized
that the EPA has ``broad discretion to define the statutory terms for
`source,' [i.e., building, structure, facility or installation], so
long as guided by a reasonable application of the statute.'' \247\
---------------------------------------------------------------------------
\244\ Id. at 326 (emphasis added).
\245\ Id.
\246\ Id. at 327.
\247\ Alabama Power Co. v. Costle, 636 F.2d 323, 396 (D.C. Cir.
1979).
---------------------------------------------------------------------------
Following these two decisions, the EPA adopted a new regulation
defining ``building, structure, facility, or installation'' for
nonattainment-area
[[Page 32557]]
permitting under the NSR program as ``all of the pollutant-emitting
activities which belong to the same industrial grouping, are located on
one or more contiguous or adjacent properties, and are under the
control of the same person (or persons under common control) except the
activities of any vessel.'' \248\ That rulemaking lead to the Supreme
Court's decision in Chevron v. NRDC, 467 U.S. 837 (1984). In Chevron,
the Court recognized that ``it is certainly no affront to common
English usage to take a reference to a major facility or a major source
to connote an entire plant as opposed to its constituent parts.'' \249\
---------------------------------------------------------------------------
\248\ 46 FR 50766.
\249\ 467 U.S. at 860.
---------------------------------------------------------------------------
Here, the EPA does not need to determine whether it would have been
reasonable to interpret ``building, structure, facility, or
installation'' as an entire plant for purposes of CAA section 111
(thus, encompassing all EGUs located at a single plant). Because ACE
identifies individual EGUs as the designated facility,\250\ state plans
cannot accommodate any ``bubbling'' of EGUs for compliance with these
emission guidelines.
---------------------------------------------------------------------------
\250\ Fossil fuel-fired steam generators (i.e., EGUs) were among
the first source categories listed under CAA section 111. See 36 FR
5931. Since then, the Agency has promulgated multiple rulemakings
specifically regulating EGUs. See e.g., 40 CFR part 60, subparts D,
Da, TTTT, and UUUU. In any case, the decision to identify EGUs as
the regulated source is made under CAA section 111(b); that is
because regulations under CAA section 111(d) are authorized for
sources ``to which a standard of performance . . . would apply if
such existing source were a new source.'' In this case, new source
performance standards have been established for certain ``new,
modified, and reconstructed'' EGUs. 80 FR 64510. While the EPA
proposed to revisit several portions of those standards, see 83 FR
65424, the Agency did not propose to revise the applicability
requirements for them, id. at 65429. Accordingly, individual EGUs
continue to be the appropriate regulatory target for purposes of ACE
(and not, for example, multiple EGUs that may be co-located at a
single power plant).
---------------------------------------------------------------------------
In addition, as proposed, the EPA is precluding averaging or
trading between designated facilities located at different plants for
the following reasons.
The EPA believes that averaging or trading across designated
facilities (or between designated facilities and other power plants,
e.g., wind turbines) is inconsistent with CAA section 111 because those
options would not necessarily require any emission reductions from
designated facilities and may not actually reflect application of the
BSER.\251\ Because state plans must establish standards of
performance--which by definition ``reflects . . . the application of
the best system of emission reduction''--implementation and enforcement
of such standards should be based on improving the emissions
performance of sources to which a standard of performance applies.
Additionally, averaging or trading would effectively allow a state to
establish standards of performance that do not reflect application of
the BSER. For example, 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 any emission reductions from any other source. This
compliance strategy would undermine the EPA's determination of the BSER
in this rule, which the EPA has determined as heat rate improvements.
---------------------------------------------------------------------------
\251\ The EPA's interpretation of CAA section 111 on this point
has changed since the promulgation of the since-vacated CAMR and
does not necessarily extend to other CAA programs and provisions,
which can be distinguishable based on the applicable statutory and
regulatory requirements and programmatic circumstances. For example,
the EPA has implemented several trading programs under the so-called
Good Neighbor provision at CAA section 110(a)(2)(D)(i)(I). See
Finding of Significant Contribution and Rulemaking for Certain
States in the Ozone Transport Assessment Group Region for Purposes
of Reducing Regional Transport of Ozone (also known as the
NOX SIP Call), 63 FR 57356 (October 27, 1998); Clean Air
Interstate Rule (CAIR) Final Rule, 70 FR 25162 (May 12, 2005); Cross
State Air Pollution Rule (CSAPR) Final Rule, 76 FR 48208 (August 8,
2011); CSAPR Update Final Rule, 81 FR 74504 (October 26, 2016).
Section 110(a)(2)(A), which is applicable to the requirements of the
Good Neighbor provision, explicitly authorizes the use of marketable
permits and auctions of emission rights. Additionally, the Good
Neighbor provision prohibits emissions activity in certain
``amounts'' with respect to the NAAQS. The affirmative requirement
under this provision to reduce certain emissions means it is
appropriate to implement measures which will result in the required
emission reductions. The EPA has done so previously by implementing
trading programs to reduce ozone and particulate matter, the
regional-scale nature of which can be effectively regulated under a
trading program.
---------------------------------------------------------------------------
In light of these concerns, as proposed, the EPA concludes that
neither averaging nor trading between EGUs at different plants can be
used in state plans for ACE implementation. Regarding commenters'
assertions that the statutory text of CAA section 111(d) does not
preclude averaging or trading, the Agency finds that the statutory text
of CAA section 111(d) does not require the EPA to allow averaging or
trading as a measure for states in establishing existing-source
standards of performance or allow for sources to adopt as a compliance
measure, and the interpretation of the limits on the scope of BSER
under CAA section 111(a)(1) set forth in section II above as a basis
for the repeal of the CPP suggests that those measures are not
permissible, as they are not applied to a source.
Regarding commenters' assertions that the cross-reference in CAA
section 111(d) to CAA section 110 authorizes averaging or trading for
implementation, the Agency disagrees. The cross-reference to CAA
section 110 indicates that ``[t]he Administrator shall prescribe
regulations which shall establish a procedure similar to that provided
by CAA section 110 of this title under which each State shall submit to
the Administrator a plan . . . .'' (emphasis added). The Agency's
interpretation of this cross-reference is that it focuses on the
procedure under which states shall submit plans to the EPA. It does not
imply anything affirmative or negative about implementation mechanisms
available under CAA section 111(d). In the absence of definitive
instruction under this CAA provision, the Agency uses its best judgment
to conclude that the meaning and scope of the BSER in this rule
preclude the use of averaging or trading for covered EGUs at different
plants in state plans. Commenters also asserted that the EPA has
promulgated regulations under CAA section 111(d) that included trading
in the past, such as CAMR. As an initial matter, CAMR was vacated by
the D.C. Circuit and never implemented. Nonetheless, the Agency notes
that the CAMR included trading both in the establishment of the BSER
and as an available implementation mechanism. In the ACE rule, by
contrast, trading was not factored into the determination of the BSER
and so should not be authorized for implementation.
Moreover, it is not clear that trading would qualify as a ``system
of emission reduction'' that can be applied to and at an individual
source and would lead to emission reductions from that source. Indeed,
the nature of trading as a compliance mechanism is such that some
sources would not need to apply any pollution control techniques at all
in order to comply with a cap-and-trade scheme. A compliance mechanism
under which multiple sources can comply not by any measures applied to
those sources individually, but instead by obtaining credits generated
by measures adopted at another source, is not consistent with the
interpretation of the limits on the scope of BSER adopted in section II
above. Accordingly, trading is not permissible under CAA section 111.
b. Biomass Co-Firing
The ACE proposal solicited comment on the inclusion of forest-
derived and non-forest biomass as non-BSER compliance options for
affected units to meet state plan standards. The proposal also
solicited comment on what value to
[[Page 32558]]
attribute to biogenic CO2 associated with non-forest
biomass, if included. The EPA received a range of comments both
supporting and opposing the use of forest-derived and non-forest
biomass feedstocks for compliance under this rule. Additionally, the
EPA received a range of comments regarding the valuation of
CO2 emissions from biomass combustion.
Numerous commenters supported the inclusion of biomass as a
compliance measure. Some reiterated the EPA's 2018 policy statement
regarding biogenic CO2 emissions, which laid out the
Agency's intent to treat biogenic CO2 emissions from forest
biomass from managed forests as carbon neutral in forthcoming Agency
actions. Specifically, these commenters stated that the nature of
biomass and its role in the natural carbon cycle (i.e., carbon is
sequestered during biomass growth that occurs offsite) makes biomass a
carbon-neutral fuel, and therefore that biomass should be eligible as a
compliance option under this rule. Commenters opposing the inclusion of
biomass for compliance asserted that biomass combustion does not reduce
stack GHGs emissions, as it emits more emissions per Btu than fossil
fuels, and therefore should not be eligible for compliance. Some
comments noted that the scientific rationale underlying the use of
biomass as a potential GHG reduction measure at stationary sources
relies primarily on terrestrial CO2 sequestration occurring
due to activities offsite (i.e., activities outside of and largely not
under the control of a designated facility).
The construct of this final ACE rule necessitates that measures
taken to meet compliance obligations for a source actually reduce its
emission rate in that: (1) They can be applied to 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 (see section III.F.2). While the firing of biomass
occurs at a designated facility, biomass firing in and of itself does
not reduce emissions of CO2 emitted from that source.
Specifically, when measuring stack emissions, biomass emits more
CO2 per Btu than fossil fuels, thereby increasing the
CO2 emission rate at the source. Accordingly, recognition of
any potential CO2 emissions reductions associated with
biomass firing at a designated facility relies on accounting for
activities not applied at and largely not under the control of that
source (i.e., activities outside of and largely unassociated with a
designated facility), including consideration of terrestrial carbon
effects during the biomass fuel growth. Therefore, biomass fuels do not
meet the compliance obligations and are not eligible for compliance
under this rule.
3. Submission of State Plans
CAA section 111(d)(1) provides that states shall submit to the EPA
plans that establish standards of performance for existing sources
within their jurisdiction and provide for implementation and
enforcement of such standards. Under CAA section 111(d)(2), the EPA has
the obligation to determine whether such plans are ``satisfactory.'' In
light of the statutory text, state plans implementing ACE should
include detailed information related to two key aspects of
implementation: Establishing standards of performance for covered EGUs
and providing measures that implement and enforce such standards.
Generally, the plans submitted by states must adequately document
and demonstrate the process and underlying data used to establish
standards of performance under ACE. Providing such documentation is
required so that the EPA can adequately and appropriately review the
plan to determine whether it is satisfactory; the EPA's authority to
promulgate a federal plan is triggered in ``cases where the State fails
to submit a satisfactory plan . . . .'' \252\ For example, states must
include data and documentation sufficient for the EPA to understand and
replicate the state's calculations in applying BSER to establish
standards of performance. Plans must also adequately document and
demonstrate the methods employed to implement and enforce the standards
of performance such that EPA can review and identify measures that
assure transparent and verifiable implementation. Additionally, state
plan submissions must, unless otherwise provided in a particular
emissions guideline rule, adhere to the components of the new
implementing regulations described in section IV. The following
paragraphs discuss several components that states are required to
include in their state plans as required under these final emission
guidelines.
---------------------------------------------------------------------------
\252\ CAA section 111(d)(2)(A).
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First, state plans must detail the approach or methods used by the
state to apply the BSER and establish standards of performance. The
state should include enough detail for the EPA to be able to reproduce
the state's methods and calculations. The methodology submitted should
clearly identify the approach by which states evaluate all of the HRIs
finalized in this action, both alone and in combination with each other
where technically feasible. To the extent that HRIs are not feasible to
apply at a particular EGU, states must provide a rationale (and
supporting data or metrics where relied upon) for why the calculation
would be invalid or inappropriate.
Second, state plans must identify EGUs within their borders that
meet the applicability requirements and are thereby considered a
designated facility under ACE. Plans must also include emissions and
operational data relied upon to apply BSER and determine standards of
performance. These data must include, at a minimum, an inventory of
CO2 emissions data and EGU operational data (e.g., heat
input) for designated EGUs during the most recent calendar year for
which data is available at the time of state plan development and/or
submission. State plans must also include any future projections data
relied upon to establish standards of performance, including future
operational assumptions. To the extent that state plans consider an
existing source's remaining useful life in establishing a standard of
performance for that source, the state plan must specify the exact date
by which the source's remaining useful life will be zero. In other
words, the state must establish a standard of performance that
specifies the designated facility will retire by a future date certain
(i.e., the date by which the EGU will no longer supply electricity to
the grid). It is important to note that (as with all aspects of the
state plan) the standard of performance and associated retirement date
will be federally enforceable upon approval by the EPA. In the event a
source's circumstances change so that this retirement date is no longer
feasible, states generally have the authority and ability to revise
their state plans. Such plan revisions must be adopted by the state and
submitted to the EPA pursuant to the requirements of 40 CFR 60.28a.
Third, state plans should submit detailed documentation
demonstrating in detail the application of the state's methodology to
the state's data. In other words, states should include the
calculations relied upon when applying the BSER to establish standards
of performance. States should also include detailed documentation
demonstrating the relied upon compliance mechanisms, consistent with
section III.F.2.
Regarding establishing standards of performance and ensuring
verifiable implementation for EGUs with complex
[[Page 32559]]
stack configurations, states should include approaches (e.g., formulas)
that appropriately assign emissions and generation to individual EGUs.
For example, if two EGUs share a common stack, the state should provide
a methodology for disaggregating monitoring data to the individually
covered EGUs. Another example for states to consider when appropriately
assigning emissions and setting standards of performance is
apportioning HRI that affect and improve the performance of multiple
EGUs at a plant (e.g., apportioning improvement credited to installed
variable speed drives that affect multiple designated facilities at a
plant).
As part of ensuring that regulatory obligations appropriately meet
statutory requirements such as enforceability, the EPA has historically
and consistently required that obligations placed on sources be
quantifiable, permanent, verifiable, and enforceable. The EPA is
similarly requiring that standards of performance placed on designated
facilities as part of a state plan to implement ACE be quantifiable,
permanent, verifiable, and enforceable. A state plan implementing ACE
should include information adequate to support a determination by the
EPA that the plan meets these goals.
Additionally, the EPA is finalizing a determination 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 compliance monitoring program for
assessing compliance with the standards of performance identified in
the plan. To the extent that designated facilities or states already
monitor and report relevant data to the EPA, states are encouraged to
use these existing systems to efficiently monitor and report ACE
compliance. For example, most potentially affected coal-fired EGUs
already continuously monitor CO2 emissions, heat input, and
gross electric output and report hourly data to the 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),
states may use data collected by the EPA under 40 CFR part 75 to meet
the required monitoring, reporting, and recordkeeping requirements
under these emission guidelines.
The EPA is further generally applying the new implementing
regulations for timing, process and required components for state plan
submissions and implementation for state plans required for designated
facilities. The new implementing regulations are described in detail in
section IV. In section 40 CFR 60.5740a there is a complete description
and list of what a state plan must include.
a. Electronic Submission of State Plans
The EPA will, in the near future, provide states with an electronic
means of submitting plans. While the EPA proposed the use of the SPeCS
software which has been used by the Agency for SIP submittals, the
Agency is still developing the software to be used for ACE submittals.
The EPA recommends that states submit state plans electronically as it
will provide a more structured process and provide more timely feedback
to the submitting state. The Agency also anticipates that many states
will choose to submit plans electronically as states have a level of
familiarity with EPA software, such as SPeCS. The EPA envisions the
electronic submittal system as a user-friendly, web-based system that
enables state air agencies to officially submit state plans and
associated information electronically for review. Electronic submittal
is the EPA's preferred method for receiving state plan submissions
under ACE. However, if a state prefers to submit its state plan outside
of this forthcoming system, the state must confer with its EPA Regional
Office regarding additional guidance for submitting the plan to the
EPA.
b. Approvability of State Plans That Are More Stringent Than Required
Under ACE
One issue raised by several commenters is whether the EPA can
approve, and thereby render federally enforceable, a state plan that
contains requirements for an existing source within a state's
jurisdiction that are more stringent than what is required under CAA
section 111(d).\253\ At proposal, the EPA acknowledged that CAA section
116 allows states to be more stringent than federal requirements as a
matter of state law, but also noted that nothing in section 116
provides for such more-stringent requirements to become federally
enforceable.\254\ Some commenters assert that it is not within the
EPA's authority under the CAA to approve such more-stringent
requirements as part of the federally enforceable state plan, and the
EPA should instead direct states to make such requirements exclusively
a matter of state law and enforceability. Other commenters assert that
the Supreme Court in Union Electric Co. v. EPA, 427 U.S. 246, (1976),
precluded a reading of section 116 that would functionally require two
separate sets of requirements, one at the stricter state level and one
at the federally approved level.
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\253\ Requirements under state plans generally become federally
enforceable once the EPA determines that they are ``satisfactory''
per section 111(d)(2). Section 113(a)(3) provides the EPA with the
authority, in part, to enforce any requirement of any plan approved
under the same subchapter as section 113; section 111(d) is within
the same subchapter as section 113. Additionally, section 304(a)(1)
grants citizens the authority to bring civil action against any
person in violation of an ``emission standard'' under the CAA.
Section 304(f)(1) and (3) respectively define ``emission standard''
as a standard of performance or any requirement under section 111
without regard to whether such requirement is expressed as an
emission standard. Accordingly, citizens with standing could attempt
to enforce the requirements of an EPA-approved section 111(d) state
plan.
\254\ 83 FR 44767 n.37.
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In response to the commenters who contend the EPA does not have the
authority to approve more stringent state plans, the EPA believes that
these comments have merit. However, the EPA does not think it is
appropriate at this point to predetermine the outcome of its action on
a state plan submission in this regard without going through notice-
and-comment rulemaking with regard to the approval or disapproval of
that submission.\255\
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\255\ In the CPP, the EPA took the position that because ``the
EPA's action on a 111(d)(1) state plan is structurally identical to
the EPA's action on a SIP,'' the EPA is required to approve a state
plan that is more stringent than the BSER because of CAA section 116
as interpreted by Union Electric. Legal Memorandum Accompanying
Clean Power Plan for Certain Issues at 28-30; 80 FR 64840. For the
reasons further described in this preamble, the EPA's position on
this state plan stringency issue has evolved since the EPA addressed
it in the CPP, and the Agency now identifies a potentially salient
structural distinction between CAA sections 110 and 111(d). Notably,
the BSER aspect of section 111(d) is absent from section 110, as
SIP-measures required for attainment or maintenance of the NAAQS are
not predicated on application of a specific technology. Under CAA
section 109, the EPA establishes a health-protective standard, and
CAA section 110 then gives states broad latitude on designing the
contents of SIPs intended to meet that standard. By contrast, under
CAA section 111, the EPA identifies a particular measure or set of
measures, and CAA section 111(d) more narrowly prescribes that the
contents of state plans include performance standards based on the
application of such measures, and measures that provide for the
implementation and enforcement of such standards. Given this key
distinction between CAA sections 110 and 111(d), the EPA no longer
takes the position it took in the CPP that these two statutory
schemes are ``structurally identical'' and that therefore, under
Union Electric, it must approve section 111(d) state plans that are
more stringent on this basis. See FCC v. Fox Television Stations,
Inc., 556 U.S. 502 (2009). However, for the reasons discussed in
this preamble, the EPA is not at this stage prejudging the
approvability of any future plan submission in this regard and will
evaluate any plan submission, including one that is more stringent
than what the BSER requires, on an individual basis through notice-
and-comment rulemaking.
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[[Page 32560]]
In response to the commenters who contend the EPA has the authority
to approve more stringent state plans, as an initial matter, the EPA
notes that the Court's decision in Union Electric on its face does not
apply to state plans under CAA section 111(d). The decision
specifically evaluated whether the EPA has the authority to approve a
SIP under section 110 that is more stringent than what is necessary to
attain and maintain the NAAQS. The Court specifically looked to the
requirements in CAA section 110(a)(2)(A) as part of its analysis, a
provision that is wholly separate and distinct from CAA section 111(d).
CAA section 110(a)(2)(A) requires SIPs to include any assortment of
measures that may be necessary or appropriate to meet the ``applicable
requirements'' of the CAA, which largely relate to the attainment and
maintenance of the NAAQS. CAA section 111(d), by contrast, directs
state plans to establish standards of performance for existing sources
that reflect the degree of emission limitation achievable through the
application of the BSER that EPA has determined is adequately
demonstrated--and CAA section 111(d) expressly provides that it cannot
be used to regulate NAAQS pollutants. Because the Court's holding was
in the context of section 110 and not CAA section 111(d), the EPA
believes that Union Electric does not control the question of whether
CAA section 111(d) state plans may be more stringent than federal
requirements.
Thus, Union Electric and the SIP issues that it addresses are
distinguishable from the CAA section 111(d) context. States have broad
discretion under section 110 to select the measures for inclusion in
their SIPs to meet the NAAQS, which are health- or welfare-based
standards not predicated on the application of any particular
technology, whereas state plans under 111(d) must establish standards
of performance, which are defined at CAA section 111(a)(1) as
reflecting the degree of emission limitation achievable through
application of the BSER at a source. However, the EPA is mindful that
it does not prejudge the approvability of any state plan submission,
but rather must determine whether it is ``satisfactory'' through
undertaking notice-and-comment rulemaking.\256\ Further, some issues of
approvability are most appropriately handled through the submission,
review, and approval or disapproval processes (with approvals and
disapprovals then being subject to judicial review). The EPA
anticipates that some states may wish to apply additional measures
beyond those that the EPA has identified as BSER when setting the
standard of performance, which states may believe are better suited to
particular existing sources within their jurisdiction. The EPA notes,
as stated above, that the comments suggesting that the EPA does not
have the authority to approve a state plan that establishes standards
of performance for existing sources more stringent than those that
would result from an application of the BSER identified by the EPA have
merit. However, the EPA believes that the question of whether it has
the authority to approve, and thereby render federally enforceable, a
state plan that establishes standards of performance that are more
stringent than those that would result from the application of the BSER
that the EPA has identified is addressed properly in the context of
evaluating an individual state plan.
---------------------------------------------------------------------------
\256\ See CAA section 111(d)(2), 40 CFR 60.27a(b).
---------------------------------------------------------------------------
While the EPA does not prejudge the approvability of a state plan
that establishes standards of performance for existing sources within
the state's jurisdiction that are more stringent than those that would
result from the application of the BSER that the EPA has identified,
there are clear principles and limitations imposed by CAA section
111(d) that will apply to the EPA's review of any state plan. As a
first principle, states must apply the BSER measures, as further
described in section III.E. of the preamble, and derive a standard of
performance that reflects the degree of emission limitation achievable
through application of the candidate technologies, taking into account
remaining useful life and other factors as appropriate.
As a second principle, whatever the scope of a state's authority
under state law may be to design a scheme to meet the emissions
guidelines, the EPA's authority to approve state plans that contain
standards of performance for existing sources only extends to measures
that are authorized statutorily. Specifically, the EPA's authority is
constrained to approving measures that comport with the statutory
interpretations, including interpretations of the limitations on
``standards of performance'' and the underlying BSER. For example, CAA
section 111(d)(1) clearly contemplates that state plans may only
contain requirements for existing sources, and not other entities.
Therefore, in implementing the ACE rule, the EPA may not approve state
plan requirements on entities other than existing EGUs, which are the
designated facilities under this rule.\257\ Another example that would
exceed the EPA's authority is a state plan that includes standards of
performance or implementation measures that do not result in emission
reductions from an individual designated facility, such as the use of
biomass or emissions trading, for the reasons discussed at section
III.E.4.c. and III.F.2.a, respectively. Finally, the EPA does not have
the authority to approve measures that purport to be standards of
performance but that actually do not meet the statutory and regulatory
terms for such standards. For example, under ACE, the EPA cannot
approve a standard that is a requirement for a designated facility shut
down. Such a standard is an operational standard rather than a standard
of performance.\258\ The EPA has not authorized the use of operational
standards under CAA section 111(h) because the EPA has determined that
it is feasible to prescribe a standard of performance for this source
category and pollutant, expressed as an emission rate.\259\
---------------------------------------------------------------------------
\257\ Section 111(d) clearly identifies that the regulated
entity under this provision is an existing source that would be of
the same source category as a new source regulated under section
111(b), i.e., a designated facility, as defined at 40 CFR 60.21(b).
If the EPA were to approve a state plan that contained provisions
regulating entities other than designated facilities, that approval
would give the EPA (and citizen groups) federal enforcement
authority over such entities. The EPA believes such a result would
be contrary to statements by the U.S. Supreme Court that caution an
agency against interpreting its statutory authority in a way that
``would bring about an enormous and transformative expansion in
[its] regulatory authority without clear congressional
authorization,'' Utility Air Regulatory Group v. EPA, 134 S. Ct.
2427, 2444 (2014).
\258\ This example is distinguishable from the one described in
section IV.H. where a state chooses to rely on a source's remaining
useful life in establishing a less stringent standard of performance
for that source than would otherwise result from an application of
the BSER. In that instance, a state would include the shutdown date
as a measure for implementation of a standard of performance, as
required under section 111(d)(1)(B).
\259\ The EPA also notes that for purposes of a federal plan,
the EPA is limited to promulgating a standard of performance, which,
as defined by section 111(a)(1) must reflect the degree of emission
limitation achievable by the BSER; in promulgating a standard of
performance under a federal plan, the statute directs the EPA to
take into account, among other factors, remaining useful life of the
source to which the standard applies. See section 111(d)(2).
---------------------------------------------------------------------------
As previously described, the EPA must review state plans, including
plans that establish standards of performance for a particular existing
source or sources that are more stringent than the standards that would
result from application of the BSER, through notice-and-comment
rulemaking to determine whether they are ``satisfactory''. This review
includes ensuring that the state
[[Page 32561]]
plan submission does not contravene the statute by including measures
that the EPA has no authority to approve or enforce as a matter of
federal law, and that the state actually has evaluated the BSER in
setting a standard. Though the EPA lacks the authority to approve
certain measures, thereby rendering them federally enforceable, nothing
precludes states from implementing or enforcing such requirements as a
matter of state law.\260\
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\260\ See CAA section 116; 40 CFR 60.24a(f).
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G. Impacts of the Affordable Clean Energy Rule
1. What are the air impacts?
In the RIA for this action, the Agency provides a full benefit-cost
analysis of an illustrative policy scenario representing ACE, which
models adoption of HRI measures at coal-fired EGUs. This illustrative
policy scenario represents one set of potential outcomes of state
determinations of standards of performance and compliance with those
standards by affected coal-fired EGUs. Throughout the RIA, the
illustrative policy scenario is compared against a single baseline that
does not include the CPP. As described in Chapter 2 of the RIA, the EPA
believes that a single baseline without the CPP represents a reasonable
future against which to assess the potential impacts of the ACE rule.
The EPA also provides analysis in Chapter 2 of the RIA that satisfies
any need for regulatory impact analysis that may be required by statute
or executive order for the repeal of the CPP.
The EPA has identified the BSER to be HRI. The EPA is providing
states with a list of candidate HRI technologies that must be evaluated
when establishing standards of performance. 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. The EPA does not
have sufficient information to assess HRI potential on a unit-by-unit
basis. Therefore, any analysis of the final rule is illustrative.
Nonetheless, the EPA believes that such illustrative analyses can
provide important insights.
In the RIA, the EPA evaluated an illustrative policy scenario that
assumes HRI potential and costs will differ based on unit size and
efficiency. To establish categories and HRI potential for use in the
RIA, the EPA developed a methodology that is explained in Chapter 1 of
the RIA. Designated facilities were grouped into twelve groups based on
three size categories and four efficiency categories. Cost and
performance assumptions for the candidate technologies were applied to
the groupings to establish representative and illustrative assumptions
for use in the RIA. The EPA then assumed these varying levels of HRI
potential and costs for the different groups in the power sector and
emissions modeling as an illustration of the potential impacts.
The EPA evaluates the potential impacts of the illustrative policy
scenario 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 end-of-period
discount rate. In addition, the EPA presents the assessment of costs,
benefits, and net benefits for specific snapshot years, consistent with
historic practice. These specific snapshot years are 2025, 2030, and
2035.
Overall, the impacts of the illustrative policy scenario in terms
of change in emissions, compliance costs, and other energy-sector
effects are small compared to the recent market-driven changes that
have occurred in the power sector. These larger industry trends are
discussed in detail in Chapter 2 of the RIA. In evaluating the
significance of the illustrative policy scenario, as presented in the
RIA and summarized here, it is important for context to understand that
these impacts are modest and do not diverge dramatically from baseline
expectations.
Emissions are projected to be lower under the illustrative policy
scenario than under the baseline. Table 3 shows projected aggregate
emission decreases for the illustrative policy scenario, relative to
the baseline, for CO2, SO2 and NOX
from the electricity sector.
Table 3--Projected CO2, SO2, and NOX Electricity Sector Emission Impacts for the Illustrative Policy Scenario,
Relative to the Baseline
[2025, 2030, and 2035]
----------------------------------------------------------------------------------------------------------------
CO2 (million SO2 (thousand NOX (thousand
short tons) short tons) short tons)
----------------------------------------------------------------------------------------------------------------
2025............................................................ (12) (4.1) (7.3)
2030............................................................ (11) (5.7) (7.1)
2035............................................................ (9.3) (6.4) (6.0)
----------------------------------------------------------------------------------------------------------------
Note: All estimates in this table are rounded to two significant figures.
The emissions changes in these tables do not account for changes in
HAP that may occur as a result of this rule. For projected impacts on
mercury emissions, please see Chapter 3 of the RIA. The EPA was unable
to project impacts on other HAP emissions from the illustrative policy
scenario due to methodology and resource limitations.
As noted earlier in this section, the illustrative policy scenario
is compared against a baseline that does not include the CPP. This is
because the ACE action only occurs after the repeal of the CPP. Chapter
2 of the RIA discusses the EPA's analysis of the CPP repeal. It
explains how after reviewing the comments and fully considering a
number of factors, the EPA ultimately concluded that the most likely
result of implementation of the CPP would be no change in emissions and
therefore no cost or changes in health benefits. This conclusion (i.e.,
that repeal of the CPP has little or no effect against a baseline that
includes the CPP) is appropriate for several reasons, consistent with
OMB's guidance that the baseline for analysis ``should be the best
assessment of the way the world would look absent the proposed
action.'' \261\ It is the EPA's consideration of the weight of the
evidence, taking into account the totality of the available
information, as presented in Chapter 2 of the RIA, that leads to the
finding and conclusion that there is likely to be no difference between
a world where the CPP is implemented and one where it is not. As
further explained in Chapter 2 of the RIA, the EPA comes to this
conclusion not through the use of a single analytical
[[Page 32562]]
scenario or modeling alone, but rather through the weight of evidence
that includes: Several IPM scenarios that explore a range of changes to
assumptions about implementation of the CPP; consideration of the
ongoing evolution and change of the electric sector; and recent
commitments by many utilities that include long-term CO2
reductions across the EGU fleet.
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\261\ OMB circular A-4, at 15.
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2. What are the energy impacts?
This final action has energy market implications. Overall, the
analysis to support this action indicates that there are important
power sector impacts that are worth noting, although they are small
relative to recent market-driven changes in the sector or compared to
some other EPA air regulatory actions for EGUs. The estimated impacts
reflect the EPA's illustrative analysis of the final action. States are
afforded considerable flexibility in the final action, and thus the
impacts could be different to the extent states make different choices
than those assumed in the illustrative analysis.
Table 4 presents a variety of energy market impacts for 2025, 2030,
and 2035 for the illustrative policy scenario representing ACE,
relative to the baseline.
Table 4--Summary of Certain Energy Market Impacts for the Illustrative Policy Scenario, Relative to the Baseline
[Percent change]
----------------------------------------------------------------------------------------------------------------
2025 (%) 2030 (%) 2035 (%)
----------------------------------------------------------------------------------------------------------------
Retail electricity prices.................................... 0.1 0.1 0.0
Average price of coal delivered to the power sector.......... 0.1 0.0 (0.1)
Coal production for power sector use......................... (1.1) (1.0) (1.0)
Price of natural gas delivered to power sector............... 0.0 (0.1) (0.6)
Price of average Henry Hub (spot)............................ 0.0 0.0 (0.6)
Natural gas use for electricity generation................... (0.4) (0.3) 0.0
----------------------------------------------------------------------------------------------------------------
Energy market impacts are discussed more extensively in the RIA
found in the rulemaking docket.
3. 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
baseline and illustrative policy scenario, including the cost of
monitoring, reporting, and recordkeeping. In simple terms, these costs
are an estimate of the increased power industry expenditures required
to implement the HRI required by the final action.
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 policy scenario is designed to reflect, to the extent
possible, the scope and nature of the final guidelines. However, there
is considerable uncertainty with regards to the precise measures that
states will adopt to meet the final requirements because there are
considerable flexibilities afforded to the states in developing their
state plans.
Table 5 presents the annualized compliance costs of the
illustrative policy scenario.
Table 5--Compliance Costs for the Illustrative Policy Scenario, Relative
to the Baseline
[Millions of 2016$]
------------------------------------------------------------------------
Year Cost
------------------------------------------------------------------------
2025....................................................... 290
2030....................................................... 280
2035....................................................... 25
------------------------------------------------------------------------
Note: Compliance costs equal the projected change in total power sector
generating costs plus the costs of monitoring, reporting, and
recordkeeping.
More detailed cost estimates are available in the RIA included in
the rulemaking docket.
4. 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
final action are discussed more extensively in Chapter 5 of the RIA for
this final action.
5. What are the benefits?
The EPA reports the estimated impact on climate benefits from
changes in CO2 and the estimated impact on health benefits
attributable to changes in SO2, NOX, and
PM2.5 emissions, based on the illustrative policy scenario
described previously. The 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 derived
from reductions in emissions other than CO2 as ``co-
benefits'' as they are not direct benefits from reducing the targeted
pollutant. To estimate the climate benefits associated with changes in
CO2 emissions, the EPA applied 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 these rulemakings 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
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, the EPA predicted the change in the
annual average PM2.5 and summer season ozone across the U.S.
for the years 2025, 2030, and 2035 for the illustrative policy
scenario. The 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 (BENMAP-CE). The EPA
quantified effects using concentration-response parameters
[[Page 32563]]
detailed in the RIA, which are consistent with those employed by the
Agency in the PM NAAQS and Ozone NAAQS RIAs (U.S. EPA, 2012; 2015)
(Table 6).
Table 6--Estimated Economic Value of Avoided PM2.5 and Ozone-Attributable Deaths and Illnesses for the Illustrative Policy Scenario Using Alternative Approaches to Representing PM2.5 Effects
[95% Confidence interval in parentheses; millions of 2016$] a
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2025
2030
2035
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Ozone Benefits Summed With PM Benefits
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
3% Discount rate
No-threshold model \b\...... $390 ($37 to $1,100).... t $970 ($86 to $2,800)... $490 ($47 to $1,300)... t $1,200 ($110 to $3,500) $550 ($52 to $1,500)... t $1,400 ($120 to
o o o $3,900).
Limited to above LML \c\.... $370 ($36 to $1,000).... t $480 ($42 to $1,400)... $440 ($42 to $1,200)... t $520 ($47 to $1,500)... $480 ($25 to $1,300)... t $610 ($16 to $1,800).
o o o
Effects above NAAQS \d\..... $76 ($8 to $210)........ t $250 ($23 to $760)..... $75 ($8 to $210)....... t $260 ($23 to $770)..... $90 ($10 to $250)...... t $320 ($28 to $930).
o o o
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Ozone Benefits Summed With PM Benefits
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
7% Discount rate
No-threshold model \b\...... $360 ($34 to $990)...... t $900 ($80 to $2,600)... $460 ($44 to $1,200)... t $1,100 ($100 to $3,200) $510 ($48 to $1,400)... t $1,300 ($110 to
o o o $3,600).
Limited to above LML \c\.... $350 ($33 to $950)...... t $460 ($41 to $1,300)... $410 ($39 to $1,100)... t $500 ($44 to $1,400)... $450 ($22 to $1,200)... t $590 ($13 to $1,700).
o o o
Effects above NAAQS \d\..... $76 ($8 to $210)........ t $250 ($23 to $760)..... $75 ($8 to $210)....... t $260 ($23 to $770)..... $90 ($10 to $250)...... t $320 ($28 to $930).
o o o
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures.
\b\ PM effects quantified using a no-threshold model. Low end of range reflects dollar value of effects quantified using concentration-response parameter from Krewski et al. (2009) and Smith
et al. (2008) studies; upper end quantified using parameters from Lepeule et al. (2012) and Jerrett et al. (2009). Full range of ozone effects is included, and ozone effects range from 19%
to 22% of the estimated values.
\c\ PM effects quantified at or above the Lowest Measured Level of each long-term epidemiological study. Low end of range reflects dollar value of effects quantified down to LML of Krewski et
al. (2009) study (5.8 [micro]g/m\3\); high end of range reflects dollar value of effects quantified down to LML of Lepeule et al. (2012) study (8 [micro]g/m\3\). Full range of ozone effects
is still included, and ozone effects range from 20% to 49% of the estimated values.
\d\ PM effects only quantified at or above the annual mean of 12 to provide insight regarding the fraction of benefits occurring above the NAAQS. Range reflects effects quantified using
concentration-response parameters from Smith et al. (2008) study at the low end and Jerrett et al. (2009) at the high end. Full range of ozone effects is still included, and ozone effects
range from 91% to 95% of the estimated values.
To give readers insight to the distribution of estimated benefits
displayed in Table 6, the EPA also reports the PM benefits according to
alternative concentration cut-points and concentration-response
parameters. The percentage of estimated avoided PM2.5-
related deaths occurring in 2025 below the lowest measured levels (LML)
of the two long-term epidemiological studies the EPA uses to estimate
risk varies between 5 percent (Krewski et al. 2009) \262\ and 69
percent (Lepeule et al. 2012).\263\ The percentage of estimated avoided
premature deaths occurring in 2025 above the LML and below the NAAQS
ranges between 94 percent (Krewski et al. 2009) and 31 percent (Lepeule
et al. 2012). Less than 1 percent of the estimated avoided premature
deaths occur in 2025 above the annual mean PM2.5 NAAQS of 12
[micro]g/m\3\.
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\262\ Krewski, D., Jerrett, M., Burnett, R.T., Ma, R., Hughes,
E., Shi, Y., Turner, M.C., Pope, C.A., Thurston, G., Calle, E.E.,
Thun, M.J., Beckerman, B., DeLuca, P., Finkelstein, N., Ito, K.,
Moore, D.K., Newbold, K.B., Ramsay, T., Ross, Z., Shin, H.,
Tempalski, B., 2009. Extended follow-up and spatial analysis of the
American Cancer Society study linking particulate air pollution and
mortality. Res. Rep. Health. Eff. Inst. 5-114-36.
\263\ Lepeule, J., Laden, F., Dockery, D., Schwartz, J., 2012.
Chronic exposure to fine particles and mortality: An extended
follow-up of the Harvard Six Cities study from 1974 to 2009.
Environ. Health Perspect. https://doi.org/10.1289/ehp.1104660.
---------------------------------------------------------------------------
Table 7 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 \264\; U.S. EPA, 2011 \265\; NRC, 2002 \266\).
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\264\ U.S. EPA, 2009. Integrated Science Assessment for
Particulate Matter. U.S. Environmental Protection Agency, National
Center for Environmental Assessment, Research Triangle Park, NC.
\265\ U.S. EPA, 2011. Policy Assessment for the Review of the
Particulate Matter National Ambient Air Quality Standards. Research
Triangle Park, NC.
\266\ NRC, 2002. Estimating the Public Health Benefits of
Proposed Air Pollution Regulations. National Research Council.
Washington, DC.
Table 7--Monetized Benefits for the Illustrative Policy Scenario, Relative to the Baseline
[Millions of 2016$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Values calculated using 3% discount rate Values calculated using 7% discount rate
--------------------------------------------------------------------------------------------------------------------------
Domestic Domestic
climate Ancillary health Total benefits climate Ancillary health co- Total benefits
benefits co-benefits benefits benefits
--------------------------------------------------------------------------------------------------------------------------------------------------------
2025......................... 81 390 to 970........ 470 to 1,000............ 13 360 to 900.............. 370 to 920.
2030......................... 81 490 to 1,200...... 570 to 1,300............ 14 460 to 1,100............ 470 to 1,100.
2035......................... 72 550 to 1,400...... 620 to 1,400............ 13 510 to 1,300............ 520 to 1,300.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: All estimates are rounded to two significant figures, 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 co-benefits 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)).
The health co-benefits do not account for direct exposure to NO2, SO2, and HAP; ecosystem effects; or visibility impairment.
[[Page 32564]]
In general, the 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, the EPA is
less confident in the risk the EPA estimates from simulated
PM2.5 concentrations that fall below the bulk of the
observed data in these studies.\267\ 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.'' \268\
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\267\ 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.'' See 78 FR 3159 (January 15, 2013).
\268\ See 78 FR 3154, January 15, 2013.
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Monetized co-benefits estimates shown here do not include several
important benefit categories, such as direct exposure to
SO2, NOX, and HAP including mercury and hydrogen
chloride. Although the EPA does not have sufficient information or
modeling available to provide monetized estimates of changes in
exposure to these pollutants for this rule, the 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
these rules, which is available in the rulemaking docket.
IV. Changes to the Implementing Regulations for CAA Section 111(d)
Emission Guidelines
The EPA is finalizing new regulations to implement CAA section
111(d) (implementing regulations) which will be codified at 40 CFR part
60, subpart Ba. The current implementing regulations at 40 CFR part 60,
subpart B, were originally promulgated in 1975.\269\ Section 111(d)(1)
of the CAA explicitly requires that the EPA prescribe regulations
establishing a procedure similar to that under section 110 of the CAA
for states to submit plans to the EPA establishing standards of
performance for existing sources within their jurisdiction. The
implementing regulations have not been significantly revised since
their original promulgation in 1975. Notably, the implementing
regulations do not reflect CAA section 111(d) in its current form as
amended by Congress in 1977, and do not reflect CAA section 110 in its
current form as amended by Congress in 1990. Accordingly, the EPA
believes that certain portions of the implementing regulations do not
appropriately align with CAA section 111(d), contrary to that
provision's mandate that the EPA's regulations be ``similar'' in
procedure to the provisions of section 110. Therefore, the EPA proposed
to promulgate new implementing regulations that are in accordance with
the statute in its current form (See 83 FR 44746-44813). Agencies have
the ability to revisit prior decisions, and the 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.\270\ While the preamble for the final new implementing
regulations are part of the same Federal Register document as certain
other Agency rules (specifically, the repeal of the CPP and the
promulgation of the ACE rule), these new implementing regulations are a
separate and distinct rulemaking with its own regulatory text and
response to comments. The implementing regulations are not dependent on
the other final actions contained in this Federal Register document.
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\269\ See 40 FR 53346.
\270\ The authority to reconsider prior decisions exists in part
because the EPA's interpretations of statutes it administers ``[are
not] instantly carved in stone,'' but must be evaluated ``on a
continuing basis.'' Chevron U.S.A. Inc. v. NRDC, Inc., 467 U.S. 837,
863-64 (1984). 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).
---------------------------------------------------------------------------
The EPA proposed to largely carry over the current implementing
regulations in 40 CFR part 60, subpart B to a new subpart that will be
applicable to emission guidelines that are finalized either
concurrently with or subsequently to final promulgation of the new
implementing regulations, as well as to state plans or federal plans
associated with such emission guidelines. For purposes of regulatory
certainty, the EPA believes it is appropriate to apply these new
implementing regulations prospectively and retain the existing
implementing regulations as applicable to CAA section 111(d) emission
guidelines and associated state plans or federal plans that were
promulgated previously. Additionally, because the original implementing
regulations also applied to regulations promulgated under CAA section
129 (a provision enacted in the 1990 Amendments that builds on CAA
section 111 but provides specific authority to address facilities that
combust waste), which has its own statutory requirements distinct from
those of CAA section 111(d), the original implementing regulations
under 40 CFR part 60, subpart B continue to apply to EPA-regulations
promulgated under CAA section 129, and any associated state plans and
federal plans. The new implementing regulations are thus applicable
only to CAA section 111(d) regulations and associated state plans
issued solely under the authority of CAA section 111(d).
The EPA is aware that there are a number of cases where state plan
submittal and review processes are still ongoing for existing CAA
section 111(d) emission guidelines. Because the EPA is finalizing new
state plan and federal plan timing requirements under the implementing
regulations to more closely align CAA section 111(d) with both general
CAA section 110 state implementation plan (SIP) and federal
implementation plan (FIP) timing requirements, and because of the EPA's
understanding from experience of the realities of how long these
actions typically take, the EPA is applying the new timing requirements
to both emission guidelines published after the new implementing
regulations are finalized and to all ongoing emission guidelines
already published under CAA section 111(d). The EPA is finalizing
applicability of the timing changes to all ongoing 111(d) regulations
for the same reasons that the EPA is changing the timing requirements
prospectively. Based on years of experience working with states to
develop SIPs under CAA section 110, the EPA believes that given the
comparable amount of work, effort, coordination with sources, and the
time required to develop state plans, 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 required for state
plan development. These practical considerations regarding the time
needed for state plan development are also applicable and true for
recent emission guidelines where the state
[[Page 32565]]
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, the EPA
is not intending to substantively change those provisions from their
original promulgation and continues to rely on the record under which
they were promulgated. Therefore, the following provisions 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); and 60.29a
(Plan revisions by the Administrator).
As noted at proposal, the EPA is also sensitive to potential
confusion over whether these new implementing regulations would apply
to emission guidelines previously promulgated or to state plans
associated with prior emission guidelines, so the EPA proposed that the
new implementing regulations are applicable only to emission guidelines
and associated plans developed after promulgation of this regulation,
including the emission guidelines being proposed as part of this action
for GHGs and existing designated facilities. The EPA is finalizing this
proposed applicability of the new implementing regulations.
While the EPA is carrying over a number of requirements from the
existing implementing regulations to the new implementing regulations,
the EPA is finalizing specific changes to better align the implementing
regulations with the statute. These changes are reflected in the
regulatory text for the new implementing regulations, and include:
An explicit provision allowing specific emission
guidelines to supersede the requirements of the new implementing
regulations;
Changes to the definition of ``emission guidelines'';
Updated timing requirements for the submission of state
plans;
Updated timing requirements for the EPA's action on state
plans;
Updated timing requirements for the 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;
Elimination of the distinction between public health-based
and welfare-based pollutants in emission guidelines; and
Updated provision allowing for consideration of remaining
useful life and other factors to be consistent with CAA section
111(d)(1)(B).
Because the EPA is updating the implementing regulations and many
of the provisions from the existing implementing regulations are being
carried over, the EPA wants to be clear and transparent with regard to
the changes that are being made to the implementing regulations. As
such, the EPA is providing Table 8 that summarizes the changes being
made.
Table 8--Summary of Changes to the Implementing Regulations
------------------------------------------------------------------------
Existing implementing
New implementing regulations--Subpart regulations--Subpart B for all
Ba for all future and ongoing CAA previously promulgated CAA
section 111(d) emission guidelines section 111(d) emission
guidelines
------------------------------------------------------------------------
Explicit authority for a new 111(d) No explicit authority.
emission guidelines requirement to
supersede these implementing
regulations.
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 the EPA
standards when the EPA determines it determines it is clearly
is not feasible to prescribe or impracticable to establish an
enforce a standard of performance, emission standard.
consistent with the requirements of
CAA section 111(h).
State submission timing: 3 years from State submission timing: 9
promulgation of final emission months from promulgation of
guidelines. final emission guidelines.
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 plan submission to be appropriate: 6 months after
incomplete, finding of failure to submittal deadline.
submit a plan, or disapproval of state
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 analogous requirement.
state plan submittals.
Usage of the internet to satisfy No analogous requirement.
certain public hearing requirements.
No distinction made in treatment Different provisions for health-
between health-based and welfare-based based and welfare-based
pollutants; states may consider pollutants; state plans must
remaining useful life and other be as stringent as the EPA's
factors regardless of type of emission guidelines for health-
pollutant. based pollutants unless
variance provision is invoked.
------------------------------------------------------------------------
A. Regulatory Background
The Agency also is, in this action, clarifying the respective roles
of the states and the EPA under section 111(d), including by finalizing
revisions to the regulations implementing that section in 40 CFR part
60 subpart B. CAA section 111(d)(1) states that the EPA ``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.'' \271\ CAA section 111(d)(1) also requires the
Administrator to ``permit the State in applying a standard of
performance to any particular source
[[Page 32566]]
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.''\272\
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\271\ See 42 U.S.C. 7411(d).
\272\ Id.
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As the statute provides, the 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 CAA
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.'' \273\ The Court addressed the statutory framework as
implemented through regulation, under which the 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.] 7411(d)(1).'' \274\
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\273\ Am. Elec. Power Co. v. Connecticut, 131 S. Ct. 2527, 2539
(2011).
\274\ 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 commonly 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 non-air quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.''\275\
---------------------------------------------------------------------------
\275\ 42 U.S.C. 7411(a)(1) (emphasis added).
---------------------------------------------------------------------------
In order to effectuate the Agency's role under CAA section
111(d)(1), the EPA promulgated implementing regulations in 1975 to
provide a framework for subsequent EPA rules and state plans under CAA
section 111(d).\276\ The implementing regulations reflect the 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. The EPA is promulgating an updated version
of the implementing regulations. Under the revised implementing
regulations, the EPA effectuates its role by publishing ``emission
guidelines'' \277\ that, among other things, contain the EPA's
determination of the BSER for the category of existing sources being
regulated.\278\ In undertaking this task, the 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.'' \279\
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\276\ See 40 CFR part 60, subpart B (hereafter referred to as
the ``implementing regulations'').
\277\ See section IV.B. for the changes to the definition of
``emission guidelines'' as part of the EPA's new implementing
regulations.
\278\ 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.'').
\279\ 40 CFR 60.22(b)(5).
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In short, under the EPA's revised regulations implementing CAA
section 111(d), which tracks with the existing implementing regulations
in this regard, the guideline documents serve to ``provide information
for the development of state plans.'' \280\ The ``emission
guidelines,'' reflecting the degree of emission limitation achievable
through application of the BSER determined by the Administrator to be
adequately demonstrated, are the principal piece of information states
rely on to develop their plans that establish standards of performance
for existing sources. Additionally, the Act requires that the 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.\281\
---------------------------------------------------------------------------
\280\ 40 CFR 60.22a(b).
\281\ 42 U.S.C. 7411(d)(1).
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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 the EPA specifically a role
with respect to such state plans. This provision authorizes the EPA to
prescribe a plan for a state ``in cases where the State fails to submit
a satisfactory plan.'' \282\ The EPA therefore is charged with
determining whether state plans developed and submitted under CAA
section 111(d)(1) are ``satisfactory,'' and the new implementing
regulations at 40 CFR 60.27a accordingly provide timing and procedural
requirements for the 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 the EPA to consider when reviewing and taking action on
a submitted state plan, as the new implementing regulations at 40 CFR
60.27a(c) reference the ability of the EPA to find a state plan as
``unsatisfactory because the requirements of (the implementing
regulations) have not been met.'' \283\
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\282\ Id. 7411(d)(2)(A).
\283\ 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.'').
---------------------------------------------------------------------------
B. Provision for Superseding Implementing Regulations
The EPA proposed to include a provision in the new implementing
regulations that expressly allows for any emission guidelines to
supersede the applicability of the implementing regulations as
appropriate, parallel to a provision contained in the 40 CFR part 63
General Provisions implementing section 112 of the CAA. The EPA cannot
foresee all of the unique circumstances and factors associated with
particular future emission guidelines, and therefore different
requirements may be necessary for a particular 111(d) rulemaking that
the EPA cannot envision at this time. The EPA is finalizing this
provision as proposed.
C. Changes to the Definition of ``Emission Guidelines''
The existing implementation regulations under 40 CFR 60.21(e)
contain a definition of ``emission guidelines,'' defining them as
guidelines which reflect the degree of emission reduction achievable
through the application of the BSER 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 emission guidelines 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.\284\ The preambles for both the proposed and final existing
implementing regulations suggest that ``emission guidelines''
[[Page 32567]]
would be guidelines provided by the EPA that reflect the degree of
emission limitation achievable by the BSER. In the proposal for this
action, the EPA described that it is important to 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, the EPA also explained that it did not believe
anything in CAA section 111(a)(1) or 111(d) compels the 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 proposed new implementing regulations, the EPA proposed to re-
define ``emission guidelines'' as final guideline documents published
under 40 CFR 60.22a(a) that include information on the degree of
emission reduction achievable through the application of the BSER which
(taking into account the cost of such reduction and any non-air quality
health and environmental impact and energy requirements) the EPA has
determined has been adequately demonstrated for designated facilities.
---------------------------------------------------------------------------
\284\ See 40 CFR 60.22(b).
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The EPA received substantial comments regarding this proposed
change to the implementing regulations. Commenters contend that because
CAA section 111(a)(1) requires the EPA to identify the BSER, it is also
the EPA's statutory responsibility to identify the degree of emission
limitation achievable through application of the BSER. According to
commenters, the identification of a BSER without an accompanying
emission limitation reflecting its application is an incomplete
identification of the system of emission reduction itself, as it is the
manner and degree of application of a system that often determines the
quantity and cost of the emission reductions achieved, as well as any
implications for energy requirements--factors that are statutorily a
component of the BSER analysis delegated to the EPA.
The EPA has considered carefully these comments and is not
finalizing the proposed changes to the definition of ``emission
guidelines'' regarding the aspect of such guidelines reflecting the
degree of emission limitation achievable through application of the
BSER. The EPA is finalizing a definition of ``emission guidelines''
that requires them to reflect the degree of emission limitation of
emission achievable through application of the BSER, as well as updates
to the definition consistent with CAA section 111(a)(1) (e.g.,
including a reference to ``energy requirements'' which was not present
in the original definition). Relatedly, the EPA is not finalizing
changes to proposed 40 CFR 60.21a(e) requiring the EPA in emission
guidelines to provide information on the degree of emission limitation
achievable through application of the BSER rather than such degree of
emission limitation itself. While the statute is ambiguous as to whose
role (i.e., the EPA's or the states') it is to determine the degree of
emission limitation achievable through application of the BSER in the
context of standards of performance for existing sources, the EPA
believes it is reasonable to construe this aspect of CAA section 111 as
included within the EPA's obligation to determine the BSER. While
states are better positioned to evaluate source-specific factors and
circumstances in establishing standards of performance, the EPA agrees
with commenters that because the EPA evaluates components such as cost
of emission reductions and environmental impacts on a broader,
systemwide scale when determining the BSER, if a state instead were to
determine the degree of emission limitation achievable for the sources
within its borders, these factors will naturally be re-balanced on a
smaller scale than the EPA's calculation and likely re-define the BSER
in the process. Under the cooperative federalism structure of CAA
section 111, the EPA determines the BSER and the associated level of
stringency (i.e., the degree of emission limitation achievable through
application of the BSER), but states may where appropriate relax this
level of stringency when establishing standards of performance by
accounting for source-specific factors such as remaining useful life.
Accordingly, given the EPA's role in determining the BSER, the EPA is
retaining the requirement from the original implementing regulations
that emission guidelines reflect the degree of emission limitation
achievable through application of the BSER, rather than finalizing the
proposed change that emission guidelines provide information on such
degree of emission limitation achievable.
D. Updates to Timing Requirements
The timing requirements in the existing implementing regulations
for state plan submissions, the EPA's action on state plan submissions,
and the EPA's promulgation of federal plans generally track the timing
requirements for SIPs and federal implementation plans (FIPs) under the
1970 version of the CAA. The existing implementing regulations at
60.23(a)(1) require state plans to be submitted to the EPA within nine
months after publication of final emission guidelines, unless otherwise
specified in emission guidelines. Congress subsequently revised the SIP
and FIP timing requirements in section 110 as part of the 1990 CAA
Amendments. The EPA proposed to update accordingly the timing
requirements regarding state and federal plans under CAA section 111(d)
to be consistent with the current timing requirements for SIPs and FIPs
under section 110.\285\
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\285\ See 84 FR 44746-813.
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Commenters contend that premising the proposed longer timelines for
state plans based on the timelines for SIPs and FIPs is inappropriate
because CAA section 111(d) state plans are narrower in scope and less
complex than section 110 SIPs for a number of reasons. According to
commenters, these reasons include: (1) Because state plans cover one
source category, whereas SIPs cover the different types of sources
whose emissions must be reduced to meet an ambient air quality
standard; (2) because sources under state plans are required to meet an
emission standard expressed as a rate or mass limitation, whereas SIPs
are required to assure that ambient air within a state stay below the
NAAQS, which requires monitoring, modeling, and other complicated
considerations; and (3) EPA already does a substantial percentage of
the work for states in the first instance by determining the BSER and
the degree of emission limitation achievable through application of the
BSER.
While it is correct that the main requirement under CAA section
111(d) is for state plans to establish standards of performance for
designated facilities, and that these existing-source performance
standards are informed by the degree of emission limitation achievable
through application of the BSER that EPA identifies, CAA section
111(d)(1)(B) also requires state plans to include measures that provide
for the implementation and enforcement of such standards. The
implementing regulations further clarify what those measures may be,
such as monitoring, reporting, and recordkeeping requirements, but the
regulations do not specify the types of measures that may satisfy those
requirements (e.g., what type of monitoring is adequate to measure
compliance for a particular source category). Nor do the implementing
regulations contain an exhaustive list of implementation and
enforcement measures given that the nature of a specific state plan, or
individual source subject to a state plan, may necessitate tailored
implementation
[[Page 32568]]
and enforcement measures that the EPA has not, or cannot, prescribe.
Establishment of standards of performance under CAA section 111(d)
state plans also may not be as straightforward as commenters suggest,
as states have the authority to consider remaining useful life and
other factors in applying a standard to a designated facility. While
the EPA defines the degree of emission limitation achievable through
application of the BSER, it is the state that must evaluate whether
there are source-specific considerations which necessitate development
of a different standard than the degree of emission limitation that the
EPA identifies. Commenters do not provide any information suggesting
development of such standards, or development of appropriate
implementation and enforcement measures generally, would take some
shorter period of time to formulate and adopt for submission of a state
plan than the three years the EPA proposed. Therefore, for these
reasons, commenters fail to recognize that while CAA section 111(d) is
not the same as CAA section 110 in the scope of its requirements, state
plans under CAA section 111(d) have their own complexities and
realities that take time to address in the development of state plans.
To the contrary, it has been the EPA's experience over decades in
the SIP context that states often do need and take much, if not all, of
the three-year period under section 110 for the process of developing
and adopting SIPs, even if a required SIP submission is relatively
narrow in scope and nature. To the extent the EPA determines a shorter
timeline is appropriate for the submission of state plans under CAA
section 111(d), for example based on the nature of the pollution
problem involved, the EPA has authority under the implementing
regulations to impose a shorter deadline in specific emission
guidelines. Relatedly, the EPA also proposed that it would be required
to propose a federal plan ``within'' two years, and nothing in this
provision precludes the EPA from promulgating a federal plan at any
period within that span of two years if it deems appropriate.
For all of these reasons and based on its experience, the EPA
believes it is at least reasonable to construe Congress's direction
that it establish a procedure ``similar'' under that of CAA section 110
to authorize it to provide the same timing requirements for state and
federal plans under CAA section 111(d) as Congress provided under CAA
section 110, and indeed that this direction may indicate Congress's
specific intention that the EPA adopt those same timing requirements.
The EPA is finalizing, as part of new implementing regulations, a
requirement that states adopt and submit a state plan to the EPA within
three years after the notice of the availability of the final emission
guidelines. 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, the 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 CAA section 111(d), this timing also allows
states to interact and work with the Agency in the development of their
state plans and to minimize the chances of unexpected issues arising
that could slow down eventual approval of state plans. The EPA notes
that nothing in CAA section 111(d) or the implementing regulations
preclude states from submitting state plans earlier than the applicable
deadline. The EPA also is finalizing to give itself discretion to
determine, in specific emission guidelines, that a shorter time period
for the submission of state plans particular to that emission
guidelines 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, the EPA will review plan
submittals to determine whether they are ``satisfactory'' pursuant to
CAA section 111(d)(2)(A). Given the flexibilities CAA section 111(d)
and emission guidelines generally accord to states, and the EPA's prior
experience on reviewing and acting on SIPs under section 110, the EPA
is extending the period for EPA review and approval or disapproval of
plans from the four-month period provided in the 1975 implementing
regulations to a twelve-month period after a determination of
completeness (either affirmatively by the EPA or by operation of law,
see section IV.F. for the new implementing regulations' treatment of
completeness) as part of the new implanting regulations. This timeline
will provide adequate time for the EPA to review plans and follow
notice-and-comment rulemaking procedures to ensure an opportunity for
public comment on the EPA's proposed action on a state plan.
The EPA additionally is extending the timing for the EPA to
promulgate a federal plan from six months in the existing implementing
regulations to two years, as part of the new implementing regulations.
This two-year timeline is consistent with the FIP deadline under
section 110(c) of the CAA. The EPA is finalizing provisions in the new
implementing regulations \286\ that provide that it has the authority
to promulgate a federal plan within two years if it:
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\286\ 40 CFR 60.27a(c).
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Finds that a state failed to submit a plan required by
emission guidelines and CAA section 111(d);
Makes a finding that a state plan submission is
incomplete, as described under the new completeness requirements and
criteria in 40 CFR 60.27a(g); or
Disapproves a state plan submission.
E. Compliance Deadlines
The previous implementing regulations required 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.\287\ However, as described in
section IV.D, the EPA is finalizing updates to the timing requirements
for the submission of, and action on, state plans. Consequently, it
follows that the requirement for increments of progress also should be
updated in order to align with the new timelines. Given that the EPA is
finalizing 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), the EPA 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 the EPA's review
of such plans. This way, sources subject to a plan will have more
certainty that their regulatory compliance obligations would not change
between the period when a state plan is due and when the EPA acts on a
plan. Accordingly, the EPA is requiring that states include provisions
for increments of progress where their state plans contain compliance
schedules longer than 24 months from
[[Page 32569]]
the date when state plans are due for particular emission guidelines.
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\287\ 40 CFR 60.24(e)(1).
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F. Completeness Criteria
Similar to requirements regarding determinations of completeness
under CAA section 110(k)(1), the EPA is finalizing completeness
criteria that provide the Agency with a means to determine whether a
state plan submission includes the minimum elements necessary for the
EPA to act on the submission. The EPA determines completeness simply by
comparing the state's submission against these completeness criteria.
In the case of SIPs under CAA section 110(k)(1), the EPA promulgated
completeness criteria in 1990 at appendix V to 40 CFR part 51.\288\ The
EPA is adopting 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).
---------------------------------------------------------------------------
\288\ 55 FR 5830; February 16, 1990.
---------------------------------------------------------------------------
The 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 guidelines. The
completeness criteria in this action are those that would generally
apply to all plan submissions under CAA section 111(d), but specific
emission guidelines may supplement these general criteria with
additional requirements.
The completeness criteria that the EPA is finalizing 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; or issued the permit, order, or consent
agreement (hereafter ``document'') in final form. 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 applicable procedural
requirements of the state's regulations, 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.; and
(8) Compilation of public comments and the state's response
thereto.
In addition, 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; and
(6) Demonstration that each emission standard is quantifiable,
permanent, verifiable, and enforceable.
The EPA intends that these criteria generally be applicable to all
CAA section 111(d) plans submitted on or after the date on which 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, the EPA is finalizing that the EPA will determine whether a state
plan is complete (i.e., meets the completeness criteria) by no later
than 6 months after the date, if any, by which a state is required to
submit the plan. The EPA requires that 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 completeness criteria, shall on that date be deemed by
operation of law to be a complete state plan. Then, as previously
discussed, the EPA relatedly is finalizing that the EPA will act on a
state plan submission through notice-and-comment rulemaking 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, the EPA
will 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, the EPA will notify the state that its submission is
incomplete and that it therefore has not submitted a required plan, and
the EPA will also publish a finding of failure to submit in the Federal
Register, which triggers the EPA's obligation to promulgate a federal
plan for the state. This determination that a submission is incomplete
and that 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.
G. Standard of Performance
As previously described, the implementing regulations were
promulgated in 1975 and effectuated the 1970 version of the CAA as it
existed at that time. The 1970 version of CAA 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.'' The EPA has not since revised the implementing
regulations to reflect this change in terminology. For clarity's sake
and to better track with statutory requirements, the EPA is determining
to include a definition of ``standard 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.'' In any event, the current definition of
``emission standard'' in the implementing regulations is incomplete and
would need to be revised. For
[[Page 32570]]
example, the definition encompasses equipment standards, which is an
alternative form of standard provided for in CAA section 111(h) under
certain circumstances. However, CAA 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
the EPA's CAMR.\289\ 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, the EPA signaled its intent to
remove this reference as part of its MATS rule.\290\ However, in the
final regulatory text of that rulemaking, the EPA did not take action
removing this reference, and it remains as a vestigial artifact.
---------------------------------------------------------------------------
\289\ 70 FR 28605.
\290\ 77 FR 9304.
---------------------------------------------------------------------------
For these reasons, the EPA is replacing 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 of air pollutants that
reflects the degree of emission limitation achievable through the
application by the state of the BSER which (taking into account the
cost of achieving such reduction and any non-air quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated. Several commenters
expressed concern that the proposed definition of ``standard of
performance'' in conjunction with the proposal to strike the reference
to allowance-based systems precluded states from including mass-based
standards of performance. Commenters misunderstand the EPA's proposal,
which did not propose that the new definition of ``standard of
performance'' itself would specify either rate-based or mass-based
standards. As explained at proposal, the new definition is intended to
track the definition of the same term in CAA section 111(a)(1), which
does not specify that standards of performance must be rate or mass-
based. Rather, the EPA may determine in particular emission guidelines
the appropriate form of the standard that a state plan must include,
based on considerations specific to those emission guidelines, such as
the BSER determination, the nature of the pollutant and affected
source-category being regulated, and other relevant factors. The EPA
believes the term ``standard of performance'' alone does not require or
preclude that the standard be in rate or mass-based form, whereas the
prior definition of ``emission standard'' was actually more restrictive
in that it specified rate-based standards and allowance-based systems,
but it did not identify other mass-based standards (such as limits) as
permissible.
Similarly, other commenters stated that the definition in the
implementing regulations should be clarified to encompass unambiguously
rates of any kind (e.g., input-based or output-based), quantities,
concentrations, or percentage reductions, consistent with statutory
language. However, as previously described, the term ``standard of
performance'' alone does not specify which form the standard must take,
and such specification is appropriately made in a particular emission
guideline depending on considerations such as the nature of the BSER,
source category, and pollutant for that rule. Therefore, the EPA is
finalizing the definition of ``standard of performance'' as proposed
and clarifying that the definition alone does not preclude any form of
rate or mass-based standards, but particular emission guidelines may
specify the appropriate form of standards that a state plan under such
guidelines can or cannot include.
The EPA is further finalizing a definition of standard of
performance that incorporates CAA section 111(h)'s allowance for
design, equipment, work practice, or operational standards as
alternative standards of performance under the statutorily prescribed
circumstances. The previous implementing regulations allowed for state
plans to prescribe equipment specifications when emission rates are
``clearly impracticable'' as determined by the 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, the EPA is establishing in the new
implementing regulations the ``not feasible to prescribe or enforce''
language as the condition under which alternative standards may be
established.
H. Remaining Useful Life and Other Factors Provisions
The EPA believes that the previous implementing regulations'
distinction between public health-based and welfare-based pollutants is
not a distinction unambiguously required under CAA section 111(d) or
any other applicable provision of the statute. The 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 the EPA's emission guidelines. However, CAA section
111(d)(1)(B) states that the EPA's regulations ``shall'' permit states
to take into account, among other factors, a designated facility's
remaining useful life when establishing an appropriate standard of
performance. In other words, Congress explicitly envisioned under CAA
section 111(d)(1)(B) that states could implement standards of
performance that vary from the EPA's emission guidelines under
appropriate circumstances. Notably, the pre-existing implementing
regulations at Sec. 60.24(f) contain a provision that allows for
states to also apply less stringent standards on sources under certain
circumstances.\291\ However, this provision attaches to the distinction
between health-based and welfare-based pollutants and is available to
the states only under the EPA's discretion. This provision was also
promulgated prior to Congress's addition of the requirement in CAA
section 111(d)(1)(B) that the 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 this provision may not account for all of the factors
envisioned under CAA section 111(d)(1)(B). Given all of these
considerations, the EPA is finalizing in the new implanting regulations
provisions that remove the distinction between health-based and
welfare-based pollutants and associated requirements contingent upon
this distinction. The EPA is also finalizing a new provision to permit
states to take into account remaining useful life, among other
[[Page 32571]]
factors, in establishing a standard of performance for a particular
designated facility, consistent with CAA section 111(d)(1)(B).
---------------------------------------------------------------------------
\291\ The EPA is hereafter no longer referring to 40 CFR
60.24(f) or its corollary under the new implementing regulations as
the ``variance provision.'' The EPA is instead using the phrase
``remaining useful life and other factors'' when referring to this
provision, as this phrase is consistent with the terminology used in
CAA section 111(d)(1) and better reflects the states' role and
authority in establishing standards of performance under CAA section
111(d) generally.
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Under this new ``remaining useful life and other factors''
provision, these following factors may be considered, among others:
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
designated facility, it is not possible for the EPA to define each and
every circumstance that states may consider when applying a standard of
performance under CAA section 111(d); accordingly, this list is not
intended to be exclusive of other source-specific factors that a state
may permissibly take into account in developing a satisfactory plan
establishing standards of performance for existing sources within its
jurisdiction. Such ``other factors'' referred to under the remaining
useful life and other factors provision may be ones that influence
decisions to invest in technologies to meet a potential performance
standard. Such other factors may include timing considerations like
payback period for investments, the timing of regulatory requirements,
and other unit-specific criteria. A state may account for remaining
useful life and other factors as it determines appropriate for a
specific source, so long as the state adopts a reasonable approach and
adequately explains that approach in its submission to the EPA.
V. 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 final action is an economically significant action that was
submitted to the OMB for review. Any changes made in response to OMB
recommendations have been documented in the docket. The EPA prepared an
analysis of the compliance cost, benefit, and net benefit impacts
associated with this action in the analytical timeframe of 2023 to
2037. This analysis, which is contained in the Regulatory Impact
Analysis (RIA) for this final action, is consistent with Executive
Order 12866 and is available in the docket for this action.
In the RIA for this final action, the Agency provides a full
benefit-cost analysis of an illustrative policy scenario representing
ACE, which models HRI at coal-fired EGUs. This illustrative policy
scenario, described in greater detail in section III.F above,
represents potential outcomes of state determinations of standards of
performance, and compliance with those standards by affected coal-fired
EGUs. Throughout the RIA, the illustrative policy scenario is compared
against a single baseline. As described in Chapter 2 of the RIA, the
EPA believes that a single baseline without the CPP represents a
reasonable future against which to assess the potential impacts of the
ACE rule. The EPA also provides analysis in Chapter 2 of the RIA that
satisfies any need for regulatory impact analysis that may be required
by statute or executive order for the repeal of the CPP.
The EPA evaluates the potential regulatory impacts of the
illustrative policy scenario using the present value (PV) of costs,
benefits, and net benefits, calculated for the timeframe of 2023-2037
from the perspective of 2016, using both a three percent and seven
percent end-of-period discount rate. In addition, the EPA presents the
assessment of costs, benefits, and net benefits for specific snapshot
years, consistent with historic practice. These specific snapshot years
are 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
baseline and illustrative policy scenario, including the cost of
monitoring, reporting, and recordkeeping. The EPA also 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. More detailed
descriptions of the cost and benefit impacts of these rulemakings are
presented in section III.F above.
Table 9 presents the PV and equivalent annualized value (EAV) of
the estimated costs, domestic climate benefits, ancillary health co-
benefits, and net benefits of the illustrative policy scenario for the
timeframe of 2023-2037, relative to the baseline. 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. Table 10 presents the
estimates for the specific snapshot years of 2025, 2030, and 2035.
---------------------------------------------------------------------------
\292\ Smith, R.L., Xu, B., Switzer, P., 2009. Reassessing the
relationship between ozone and short-term mortality in U.S. urban
communities. Inhal. Toxicol. 21 Suppl 2, 37-61. https://doi.org/10.1080/08958370903161612.
\293\ Jerrett, M., Burnett, R.T., Pope, C.A., Ito, K., Thurston,
G., Krewski, D., Shi, Y., Calle, E., Thun, M., 2009. Long-term ozone
exposure and mortality. N. Engl. J. Med. 360, 1085-95. https://doi.org/10.1056/NEJMoa0803894.
Table 9--Present Value and Equivalent Annualized Value of Compliance Costs, Domestic Climate Benefits, Ancillary Health Co-Benefits, and Net Benefits,
Illustrative Policy Scenario, 3 and 7 Percent Discount Rates, 2023-2037
[Millions of 2016$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Costs Domestic climate Ancillary health co-benefits Net benefits
---------------------- benefits -------------------------------------------------------------------------------
----------------------
3% 7% 3% 7% 3% 7% 3% 7%
--------------------------------------------------------------------------------------------------------------------------------------------------------
Present Value............... 1,600 970 640 62 4,000 to 9,800.... 2,000 to 5,000.... 3,000 to 8,800.... 1,100 to 4,100.
Equivalent Annualized Value. 140 110 53 6.9 330 to 820........ 220 to 550........ 250 to 730........ 120 to 450.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: All estimates are rounded to two significant figures, 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 and NOX emissions and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Smith et al.
(2009) \292\ to Lepeule et al. (2012) with Jerrett et al. (2009)).\293\
[[Page 32572]]
Table 10--Compliance Costs, Domestic Climate Benefits, Ancillary Health Co-Benefits, and Net Benefits in 2025, 2030, and 2035, Illustrative Policy
Scenario, 3 and 7 Percent Discount Rates
[Millions of 2016$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Costs Domestic climate Ancillary health co-benefits Net benefits
---------------------- benefits -------------------------------------------------------------------------------
----------------------
3% 7% 3% 7% 3% 7% 3% 7%
--------------------------------------------------------------------------------------------------------------------------------------------------------
2025........................ 290 290 81 13 390 to 970........ 360 to 900........ 180 to 760........ 84 to 630.
2030........................ 280 280 81 14 490 to 1,200...... 460 to 1,100...... 300 to 1,000...... 200 to 860.
2035........................ 25 25 72 13 550 to 1,400...... 510 to 1,300...... 600 to 1,400...... 500 to 1,200.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: All estimates are rounded to two significant figures, 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 and NOX 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)).
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 final action the Agency
presents 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 11 presents the PV and EAV of the estimated costs, benefits,
and net benefits associated with the targeted pollutant,
CO2, for the timeframe of 2023-2037, relative to the
baseline. In Table 11 and Table 12, negative net benefits are indicated
with parenthesis.
Table 11--Present Value and Equivalent Annualized Value of Compliance Costs, Climate Benefits, and Net Benefits Associated With Targeted Pollutant
(CO2), Illustrative Policy Scenario, 3 and 7 Percent Discount Rates, 2023-2037
[Millions of 2016$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Costs Domestic climate benefits Net benefits associated with
---------------------------------------------------------------- the targeted pollutant (CO2)
3% 7% 3% 7% -------------------------------
3% 7%
--------------------------------------------------------------------------------------------------------------------------------------------------------
Present Value........................................... 1,600 970 640 62 (980) (910)
Equivalent Annualized Value............................. 140 110 53 6.9 (82) (100)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: Negative net benefits indicate forgone net benefits. All estimates are rounded to two significant figures, 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 12 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 11.
Table 12--Compliance Costs, Climate Benefits, and Net Benefits Associated With Targeted Pollutant (CO2) in 2025, 2030, and 2035, Illustrative Policy
Scenario, 3 and 7 Percent Discount Rates
[Millions of 2016$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Costs Domestic climate benefits Net benefits associated with
---------------------------------------------------------------- the targeted pollutant (CO2)
3% 7% 3% 7% -------------------------------
3% 7%
--------------------------------------------------------------------------------------------------------------------------------------------------------
2025.................................................... 290 290 81 13 (210) (280)
2030.................................................... 280 280 81 14 (200) (260)
2035.................................................... 25 25 72 13 47 (11)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: Negative net benefits indicate forgone net benefits. All estimates are rounded to two significant figures, 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 32573]]
Throughout the RIA for this action, the EPA considers a number of
sources of uncertainty, both quantitatively and qualitatively. The RIA
also summarizes other potential sources of benefits and costs that may
result from these rules 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 regulatory
action. Details on the estimated costs of this final rule can be found
in the EPA's analysis of the potential costs and benefits associated
with this action.
C. Paperwork Reduction Act (PRA)
The information collection activities in this rule have been
submitted for approval to the Office of Management and Budget (OMB)
under the PRA. The Information Collection Request (ICR) document that
the EPA prepared has been assigned the EPA ICR number 2503.04. A copy
of the ICR can be found in the docket for this rule, and it is briefly
summarized here. The information collection requirements are not
enforceable until OMB approves them.
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 the 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--the 48 contiguous states;
Respondent's obligation to respond: The EPA expects state plan
submissions from 43 of the 48 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 and
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 the
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB
approves this ICR, the Agency will announce the approval in the Federal
Register and publish a technical amendment to 40 CFR part 9 to display
the OMB control number for the approved information collection
activities contained in this final rule.
D. Regulatory Flexibility Act (RFA)
After considering the economic impacts of this rule on small
entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. This final
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 develop and
submit to the EPA plans that establish performance standards for
existing sources within their jurisdiction, 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 the 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.\294\
---------------------------------------------------------------------------
\294\ See American Trucking Ass'n 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).
---------------------------------------------------------------------------
E. Unfunded Mandates Reform Act (UMRA)
This action does not contain an unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments.
This action 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 IV.A. above, but this burden is estimated to be below $100
million in any one year. Thus, this rule is not subject to the
requirements of section 203 or section 205 of the Unfunded Mandates
Reform Act (UMRA).
This 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
The 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. The Agency understands the burden that these actions will
have on states and is committing to providing aid and guidance to
states through the plan development process. The EPA will be available
at the states initiative to provide clarity for developing plans,
including standard of performance setting and compliance initiatives.
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 designated facilities
located in their area of Indian country. Tribes are not required to
develop plans to implement the guidelines under CAA section 111(d) for
designated facilities. The EPA notes that this final rule does not
directly impose specific requirements on EGU sources, including those
located in Indian country; before developing any standards of
performance for existing sources on tribal land, the EPA would consult
with leaders from affected tribes. This action also will not have
substantial direct costs or impacts 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
[[Page 32574]]
specified in Executive Order 13175. Thus, Executive Order 13175 does
not apply to the action.
Executive Order 13175 requires the EPA to develop an accountable
process to ensure ``meaningful and timely input by tribal officials in
the development of regulatory policies that have tribal implications.''
The EPA has concluded that this action does not have tribal
implications as specified in E.O. 13175. It would not impose
substantial direct compliance costs on tribal governments that have
designated facilities located in their area of Indian country. Tribes
are not required to develop plans to implement the guidelines under CAA
section 111(d) for designated facilities. This action also will not
have substantial direct cost or impacts 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.
Consistent with EPA Policy on Consultation and Coordination with
Indian Tribes, the EPA consulted with tribal officials during the
development of this action to provide an opportunity to have meaningful
and timely input. On August 24, 2018, consultation letters were sent to
584 tribal leaders that provided information and offered consultation
regarding the EPA's development of this rule. On August 30, 2018, the
EPA provided a presentation overview on the Proposal: Affordable Clean
Energy (Rule) on the monthly National Tribal Air Association/EPA Air
Policy call. At the request of the tribes, two consultation meetings
were held: One with the Navajo Nation on October 11, 2018, and one with
the Samish Indian Nation on October 16, 2018. The Samish Indian Nation
opened their consultation to other tribes--also participating in this
meeting for informational purposes only were seven tribes (Blue Lake
Rancheria, Cherokee Nation Environmental Program, La Jolla Band of
Luise[ntilde]o Indians, Leech Lake Band of Ojibwe, Muscogee (Creek)
Nation Office of Environmental Services, Nez Perce Tribe, The Quapaw
Tribe) and the National Tribal Air Association. In the meetings, the
tribes were presented information from the proposal. The tribes asked
general clarifying questions and indicated that they would submit
formal comments. Comments on the proposal were received from the Navajo
Nation, the Samish Indian Nation, Blue Lake Rancheria, Leech Lake Band
of Ojibwe, Nez Perce Tribe, and the National Tribal Air Association, in
addition to the Keweenaw Bay Indian Community, the Fond du Lac Band,
the 1854 Treaty Authority, and the Sac and Fox Nation. Tribal
commenters insisted on meaningful government-to-government consultation
with potentially impacted tribes, and that the final rule require
states to consult with indigenous and vulnerable communities as they
develop state plans. More specific comments can be found in the docket.
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is subject to Executive Order 13045 because it is an
economically significant regulatory action as defined by Executive
Order 12866. The EPA believes that this action will achieve
CO2 emission reductions resulting from implementation of
these emission guidelines, as well as ozone and PM2.5
emission reductions as a co-benefit, and will further improve
children's health.
Moreover, this 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 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 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, the EPA estimated
in the RIA that the rule could result in more than a one percent
decrease in coal production in 2025 (or a reduction of more than a 5
million tons per year) and less than a one percent reduction in natural
gas use in the power sector (or more than a 25 million MCF reduction in
production on an annual basis). The energy impacts the EPA estimates
from these rules may be under- or over-estimates of the true energy
impacts associated with this action. For more information on the
estimated energy effects, please refer to the RIA for these
rulemakings, which is in the public docket.
J. National Technology Transfer and Advancement Act (NTTAA)
This rulemaking does not involve technical standards.
K. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
The EPA believes that this 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 EPA believes that this action will achieve
CO2 emission reductions resulting from implementation of
these final guidelines, as well as ozone and PM2.5 emission
reductions as a co-benefit, and will further improve environmental
justice communities' health as discussed in the RIA.
With regards to the repeal, Chapter 2 of the RIA explains why the
EPA believes that the power sector is already on path to achieve the
CO2 reductions required by the CPP, therefore the EPA does
not believe it would have any significant impact on EJ effected
communities.
With regards to ACE, as described in Chapter 4 of the RIA, the EPA
finds that most of the eastern U.S. will experience PM and ozone-
related benefits as a result of this action. While the EPA expects
areas in the southeastern U.S. to experience a modest increase in fine
particle levels, areas including the Midwest will experience reduced
levels of PM, yielding significant benefits in the form of fewer
premature deaths and illnesses. On balance, the positive benefits of
this action significantly outweigh the estimated disbenefits.
Moreover, this 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.
L. Congressional Review Act (CRA)
This action is subject to the CRA, and the EPA will submit a rule
report to each House of the Congress and to the Comptroller General of
the United States. This action is a ``major rule'' as defined by 5
U.S.C. 804(2).
VI. 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)).
[[Page 32575]]
List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.
Dated: June 19, 2019.
Andrew R. Wheeler,
Administrator.
Therefore, 40 CFR chapter I is amended as follows:
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
0
2. 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.
Sec. 60.20a Applicability.
(a) The provisions of this subpart apply upon publication of a
final emission guideline under Sec. 60.22a(a) if implementation of
such final guideline is ongoing as of July 8, 2019 or if the final
guideline is published after July 8, 2019.
(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 this Act), or a standard issued under State authority.
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 of this part:
(a) Designated pollutant means any air pollutant, the emissions of
which are 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)(1)(A) of the Act.
(b) Designated facility means any existing facility (see Sec.
60.2) 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. 60.2).
(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 guideline set forth in subpart C of
this part, or in a final guideline document published under Sec.
60.22a(a), 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 such reduction and any non-air 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
and upon or after promulgation of standards of performance for control
of a designated pollutant from affected facilities, 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) Information concerning known or suspected endangerment of
public health or welfare caused, or contributed to, by the designated
pollutant.
(2) A description of systems of emission reduction which, in the
[[Page 32576]]
judgment of the Administrator, have been adequately demonstrated.
(3) Information on the degree of emission limitation 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.
(4) Incremental periods of time normally expected to be necessary
for the design, installation, and startup of identified control
systems.
(5) The degree of emission limitation achievable through 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 degrees of emission limitation 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.
(6) Such other available information as the Administrator
determines may contribute to the formulation of State plans.
(c) The emission guidelines and compliance times referred to in
paragraph (b)(5) of this section will be proposed for comment upon
publication of the draft guideline document, and after consideration of
comments will be promulgated in subpart C of this part with such
modifications as may be appropriate.
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 in accordance with the provisions under this
section.
(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
(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 paragraph (d) of this section 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.
(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) Any compliance schedule extending more than 24 months from the
date required for submittal of the
[[Page 32577]]
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.
(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 of this part 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 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 or plan revision shall show that the State has legal
authority to carry out the plan or plan revision, 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
[[Page 32578]]
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 Sec. 60.27a(g), 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 promulgate, through notice-and-comment
rulemaking, a federal plan, or portion thereof, at any time within two
years after the Administrator:
(1) Finds that a State fails to submit a required plan or plan
revision or finds that the plan or plan revision does not satisfy the
minimum criteria under paragraph (g) of this section; or
(2) 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 promulgate a final federal plan as
described in paragraph (c) of this section unless the State corrects
the deficiency, and the Administrator approves the plan or plan
revision, before the Administrator promulgates such federal plan.
(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(e).
(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 submit a required complete plan or
plan revision, or whose required plan or plan revision is disapproved
by the Administrator; 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 reviewed for completeness as described in
paragraphs (g)(1) through (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 Sec. 60.27a 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; or issued the permit, order, consent agreement
(hereafter ``document'') in final form. 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, including
indication of the changes made (such as redline/strikethrough) to the
existing approved plan, where applicable. 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. If the regulation/document provided by the State for approval and
incorporation by reference into the plan is a copy of an existing
publication, the State submission should, whenever possible, include a
copy of the publication cover page and table of contents;
(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. 60.23a,
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. 60.23a;
(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 designated facility, identification of
standards of performance for the designated facilities, and monitoring,
recordkeeping and reporting requirements that will determine compliance
by each designated facility;
(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
[[Page 32579]]
(vi) Demonstration that each emission standard is quantifiable,
non-duplicative, permanent, verifiable, and enforceable.
Sec. 60.28a Plan revisions by the State.
(a) Any revision to a state plan shall be adopted by such State
after reasonable notice and public hearing. For plan revisions required
in response to a revised emission guideline, such plan revisions shall
be submitted to the Administrator within three years, or shorter if
required by the Administrator, after notice of the availability of a
final revised emission guideline is published under Sec. 60.22a. All
plan revisions must be submitted 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.
Subpart UUUU [Removed]
0
3. Remove subpart UUUU.
0
4. Add subpart UUUUa to read as follows:
Subpart UUUUa--Emission Guidelines for Greenhouse Gas Emissions
From Existing 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 Designated Facilities
60.5770a Does this subpart directly affect EGU owners or operators
in my State?
60.5775a What designated facilities must I address in my State plan?
60.5780a What EGUs are excluded from being designated facilities?
60.5785a What applicable monitoring, recordkeeping, and reporting
requirements do I need to include in my plan for designated
facilities?
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?
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 a designated facility. 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 subpart A or 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 designated facilities.
(b) PSD and Title V Thresholds for Greenhouse Gases.
(1) For the purposes of Sec. 51.166(b)(49)(ii) of this chapter,
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) of this
chapter 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) of this chapter,
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 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. 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 designated facilities that commenced construction on
or before January 8, 2014, 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 contiguous United States with no
designated facilities for which construction commenced on or before
January 8, 2014, 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, my plan is incomplete,
or my plan is not approvable?
(a) If you do not submit a complete or an approvable plan the EPA
will
[[Page 32580]]
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 designated facilities 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, a designated facility for which
construction commenced on or before January 8, 2014 is found in your
State, you will be found to have failed to submit a plan as required,
and a Federal plan implementing the emission guidelines contained in
this subpart, when promulgated by the EPA, will apply to that
designated facility until you submit, and the EPA approves, a 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 designated facilities. Consistent with Sec.
60.25a(a), you must identify the designated facilities covered by your
plan and all designated facilities in your State that meet the
applicability criteria in Sec. 60.5775a. In addition, you must include
an inventory of CO2 emissions from the designated facilities
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 designated facility according to Sec. 60.5755a
and compliance periods for each standard of performance according to
Sec. 60.5750a. Each standard of performance must reflect the degree of
emission limitation achievable through application of the heat rate
improvements described in Sec. 60.5740a. In applying the heat rate
improvements described in Sec. 60.5740a, a state may consider
remaining useful life and other factors, as provided for in Sec.
60.24a(e).
(3) Identification of applicable monitoring, reporting, and
recordkeeping requirements for each designated facility. You must
include in your plan all applicable monitoring, reporting and
recordkeeping requirements for each designated facility 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 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 designated facility 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
designated facility:
(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; and
(vii) Improved operating and maintenance practices.
(2)(i) As part of the summary under paragraph (a)(1) of this
section regarding the applicability of each heat rate improvement to
each designated facility, you must include an evaluation of the
following degree of emission limitation achievable through application
of the heat rate improvements:
Table 1 to Paragraph (a)(2)(i)--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
rrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrr
Improved Operating and Maintenance (O&M) Practices...... Can range from 0 to > 2.0% depending on the unit's historical O&M practices.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(ii) In applying a standard of performance, if you consider
remaining useful life and other factors for a designated facility 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 designated
facility's standard of performance is quantifiable,
[[Page 32581]]
permanent, verifiable, and enforceable according to Sec. 60.5755a.
(4) Your plan demonstration must include the information listed in
paragraphs (a)(4)(i) through (v) of this section as applicable.
(i) A summary of each designated facility's anticipated future
operation characteristics, including:
(A) Annual generation;
(B) CO2 emissions;
(C) Fuel use, fuel prices, fuel carbon content;
(D) Fixed and variable operations and maintenance costs;
(E) Heat rates; and
(F) Electric generation capacity and capacity factors.
(ii) A timeline for implementation.
(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 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. 60.23a(g).
(6) 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. Sec. 60.26a and
60.5740a(a)(6);
(ii) Materials supporting calculations for designated facility'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 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 July 8, 2022.
Sec. 60.5750a What schedules and compliance periods must I include in
my plan?
The EPA is superseding the requirement at Sec. 60.22a(b)(5) for
EPA to provide compliance timelines in the emission guidelines. Each
standard of performance for designated facilities regulated under the
plan must include a compliance period that ensures the standard of
performance reflects the degree of emission limitation achievable
though application of the heat rate improvements used to calculate the
standard. The schedules and compliance periods included in a plan must
follow the requirements of Sec. 60.24a.
Sec. 60.5755a What standards of performance must I include in my
plan?
(a) You must set a standard of performance for each designated
facility 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 and associated
degree of emission limitation achievable included in Sec.
60.5740a(a)(1) and (2) to the designated facility. You must include a
demonstration in your plan submission for how you considered each heat
rate improvement and associated degree of emission limitation
achievable in calculating each standard of performance.
(i) In applying a standard of performance to any designated
facility, you may consider the source-specific factors included in
Sec. 60.24a(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 designated facilities included
under your plan must be demonstrated to be quantifiable, verifiable,
permanent, and enforceable with respect to each designated facility.
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) A designated facility's standard of performance is quantifiable
if it can be reliably measured in a manner that can be replicated.
(d) A designated facility'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) A designated facility'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) A designated facility'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 designated facility 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 a designated
facility 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) through (h), in the
case of a State, pursuant to its plan, State law or CAA section 304, as
applicable, and in the 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.
Sec. 60.5765a What must I do to meet my plan obligations?
To meet your plan obligations, you must demonstrate that your
designated facilities are complying with their standards of performance
as specified in Sec. 60.5755a.
Applicability of Plans to Designated Facilities
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, designated facility 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
[[Page 32582]]
guidelines contained in this subpart by July 8, 2022, 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
designated facility within the State that commenced construction on or
before January 8, 2014.
Sec. 60.5775a What designated facilities must I address in my State
plan?
(a) The EGUs that must be addressed by your plan are any designated
facility that commenced construction on or before January 8, 2014.
(b) A designated facility is a steam generating unit that meets the
relevant applicability conditions specified in paragraphs (b)(1)
through (3) of this section, 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).
(3) Is an electric utility steam generating unit that burns coal
for more than 10.0 percent of the average annual heat input during the
3 previous calendar years.
Sec. 60.5780a What EGUs are excluded from being designated
facilities?
(a) An EGU that is excluded from being a designated facility 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 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 a
simple cycle stationary combustion turbine, a combined cycle stationary
combustion turbine, or a 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 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;
(7) An EGU that is a municipal waste combustor unit that is subject
to subpart Eb of this part;
(8) An EGU that is a commercial or industrial solid waste
incineration unit that is subject to subpart CCCC of this part; or
(9) A steam generating unit that fires more than 50 percent non-
fossil fuels.
(b) [Reserved]
Sec. 60.5785a What applicable monitoring, recordkeeping, and
reporting requirements do I need to include in my plan for designated
facilities?
(a) Your plan must include monitoring, recordkeeping, and reporting
requirements for designated facilities. 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) Including 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. After the effective date of the plan, States must keep
records of all information relied upon in support of any continued
demonstration that the final standards of performance are being
achieved.
(b) You must keep records of all data submitted by the owner or
operator of each designated facility that is used to determine
compliance with each designated facility emissions standard or
requirements in an approved State plan, consistent with the designated
facility requirements listed in Sec. 60.5785a.
(c) If your State has a requirement for all hourly CO2
emissions and generation information to be used to calculate compliance
with an annual emissions standard for designated facilities, any
information that is submitted by the owners or operators of designated
facilities to the EPA electronically pursuant to requirements in part
75 of this chapter 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 these
emission guidelines following the procedures in paragraphs (b) through
(e) of this section unless you submit through the procedure described
in paragraph (f) 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 may be reported through EPA's electronic reporting system to be
named and made available at a later date.
(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
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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 July 8, 2022, 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 the EPA electronic reporting system. 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.
(f) If, in lieu of the requirements described in paragraphs (b)
through (e) of this section, you choose to submit a paper copy or an
electronic version by other means you must confer with your EPA
Regional Office regarding the additional guidelines for submitting your
plan.
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, and Ba
of this part.
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 a designated facility, the
reported CO2 emission rate of a designated facility used by
a designated facility to demonstrate compliance with its CO2
standard of performance.
Combined cycle unit means an electric generating unit that uses a
stationary combustion turbine from which the heat from the turbine
exhaust gases is recovered by a heat recovery steam generating unit to
generate additional electricity.
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 a designated
facility to comply with a standard of performance.
Designated facility means a steam generating unit that meets the
relevant applicability conditions in section Sec. 60.5775a, except as
provided in Sec. 60.5780a.
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 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
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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 designated facility 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.
Simple cycle combustion turbine means any stationary combustion
turbine which does not recover heat from the combustion turbine engine
exhaust gases for purposes other than enhancing the performance of the
stationary combustion turbine itself.
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 designated facility, to directly enhance the performance
of the designated facility (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 designated facility. Useful thermal output for
designated facility(s) with no condensate return (or other thermal
energy input to the designated facility(s)) or where measuring the
energy in the condensate (or other thermal energy input to the
designated facility(s)) would not meaningfully impact the emission rate
calculation is measured against the energy in the thermal output at
SATP conditions. Designated facility(s) with meaningful energy in the
condensate return (or other thermal energy input to the designated
facility) must measure the energy in the condensate and subtract that
energy relative to SATP conditions from the measured thermal output.
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.
[FR Doc. 2019-13507 Filed 7-5-19; 8:45 am]
BILLING CODE 6560-50-P