[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: swanson.nicholas@epa.gov.

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

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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).
---------------------------------------------------------------------------

    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.'').
---------------------------------------------------------------------------

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).
---------------------------------------------------------------------------

(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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

(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\
---------------------------------------------------------------------------

    \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'').
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.

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

[[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, . . . .'').
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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]).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \137\ See 82 FR 61507 (December 28, 2017).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \138\ See 83 FR 44746 (August 31, 2018).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \139\ See 80 FR 64715.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \140\ Id.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \141\ See 80 FR 64531.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    \142\ See 83 FR 65424.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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).
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    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \204\ See ACE proposal and 80 FR 64756.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \205\ See 83 FR 44766.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \207\ See 80 FR 64756.
---------------------------------------------------------------------------

d. Carbon Capture and Storage (CCS) \208\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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/.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \231\ See 40 CFR 60.22a.
    \232\ See 40 CFR 60.24a(d).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.

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

[[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\
---------------------------------------------------------------------------

    \260\ See CAA section 116; 40 CFR 60.24a(f).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \261\ OMB circular A-4, at 15.
---------------------------------------------------------------------------

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\.
---------------------------------------------------------------------------

    \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\).
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \271\ See 42 U.S.C. 7411(d).
    \272\ Id.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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

[[Page 32583]]

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

[[Page 32584]]

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


