[Federal Register Volume 82, Number 248 (Thursday, December 28, 2017)]
[Proposed Rules]
[Pages 61507-61519]
[FR Doc No: 2017-27793]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2017-0545; FRL-9972-50-OAR]
RIN 2060-AT67

State Guidelines for Greenhouse Gas Emissions from Existing
Electric Utility Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Advance notice of proposed rulemaking.

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SUMMARY: An advance notice of proposed rulemaking (ANPRM) is a notice
intended to solicit information from the public as the Environmental
Protection Agency (EPA) considers proposing a future rule. In this
ANPRM, the EPA is considering proposing emission guidelines to limit
greenhouse gas (GHG) emissions from existing electric utility
generating units (EGUs) and is soliciting information on the proper
respective roles of the state and federal governments in that process,
as well as information on systems of emission reduction that are
applicable at or to an existing EGU, information on compliance
measures, and information on state planning requirements under the
Clean Air Act (CAA). This ANPRM does not propose any regulatory
requirements.

DATES: Comments must be received on or before February 26, 2018.

ADDRESSES: Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2017-0545, at http://www.regulations.gov. Follow the online
instructions for submitting comments. Once submitted, comments cannot
be edited or removed from Regulations.gov. The EPA may publish any
comment received to its public docket. Do not submit electronically any
information you consider to be Confidential Business Information (CBI)
or other information whose disclosure is restricted by statute.
Multimedia submissions (audio, video, etc.) must be accompanied by a
written comment. The written comment is considered the official comment
and should include discussion of all points you wish to make. The EPA
will generally not consider comments or comment contents located
outside of the primary submission (i.e., on the Web, cloud, or other
file sharing system).
    Comments may also be submitted by mail. Send your comments to: EPA
Docket Center, U.S. EPA, Mail Code 28221T, 1200 Pennsylvania Ave. NW,
Washington, DC 20460, Attn: Docket No. ID EPA-HQ-OAR-2017-0545.
    For additional submission methods, the full EPA public comment
policy, information about CBI or multimedia submissions, and general
guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.
    Instructions. Direct your comments on the proposed rule to Docket
ID No. EPA-HQ-OAR-2017-0545. The EPA's policy is that all comments
received will be included in the public docket and may be made
available online at http://www.regulations.gov, including any personal
information provided, unless the comment includes information claimed
to be CBI or other information whose disclosure is restricted by
statute. Do not submit information that you consider to be CBI or
otherwise protected through http://www.regulations.gov or email. The
http://www.regulations.gov website is an ``anonymous access'' system,
which means the EPA will not know your identity or contact information
unless you provide it in the body of your comment. If you send an email
comment directly to the EPA without going through http://www.regulations.gov, your email address will be automatically captured
and included as part of the comment that is placed in the public docket
and made available on the internet. If you submit an electronic
comment, the EPA recommends that you include your name and other
contact information in the body of your comment and with any disk or
CD-ROM you submit. If the EPA cannot read your comment due to technical
difficulties and cannot contact you for clarification, the EPA may not
be able to consider your comment. Electronic files should avoid the use
of special characters, any form of encryption, and be free of any
defects or viruses.
    Docket. The EPA has established a new docket for this action under
Docket ID No. EPA-HQ-OAR-2017-0545. The EPA previously established a
docket for the October 23, 2015, Clean Power Plan (CPP) under Docket ID
No. EPA-HQ-OAR-2013-0602. All documents in the docket are listed in the
http://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy
form. Publicly available docket materials are available either
electronically at http://www.regulations.gov or in hard copy at the EPA
Docket Center (EPA/DC), EPA WJC West Building, Room 3334, 1301
Constitution Ave. NW, Washington, DC. The Public Reading Room is open
from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding holidays.
The telephone number for the Public Reading Room is<PHONE_NUMBER>, and
the telephone number for the EPA Docket Center is<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Dr. Nick Hutson, Energy Strategies
Group, Sector Policies and Programs Division (D243-01), U.S.
Environmental Protection Agency, Research Triangle Park, NC 27711;
telephone number:<PHONE_NUMBER>; email address: [email protected].

SUPPLEMENTARY INFORMATION: Submitting CBI. Do not submit information
that you consider to be CBI electronically through http://www.regulations.gov or email. Send or deliver information identified as
CBI to only the following address: OAQPS Document Control Officer (Room
C404-02), Environmental Protection Agency, Research Triangle Park,
North Carolina 27711; Attn: Docket ID No. EPA-HQ-OAR-2017-0545.
    Clearly mark the part or all of the information that you claim to
be CBI. For CBI information in a disk or CD-ROM that you mail to the
EPA, mark the outside of the disk or CD-ROM as CBI and then identify
electronically within the disk or CD-ROM the specific information that
is claimed as CBI. In addition to one complete version of the comment
that includes information claimed as CBI, a copy of the comment that
does not contain the information claimed as CBI must be submitted for
inclusion in the public docket. If you submit a CD-ROM or disk that
does not contain CBI, mark the outside of the disk or CD-ROM clearly
that it does not contain CBI. Information marked as CBI will not be
disclosed except in accordance with procedures set forth in 40 Code of
Federal Regulations (CFR) part 2.
    Organization of This Document. The following outline is provided to
aid in locating information in this preamble.

I. General Information

    A. What is the purpose of this ANPRM?
    B. Introduction
    C. Where can I get a copy of this document?
II. Background
III. The Statutory and Regulatory Framework under CAA Section 111(d)
    A. Introduction
    B. States' Role and Responsibilities under CAA Section 111(d)
    C. The EPA's Interpretation of CAA Section 111(a)(1)
    D. The EPA's Role and Responsibilities under CAA Section 111(d)
IV. Available Systems of GHG Emission Reduction
    A. Heat Rate Improvements for Boilers
    B. Heat Rate Improvements at Natural Gas-fired Combustion
Turbines
    C. Other Available Systems of GHG Emission Reduction
    D. EGU Source Categories and Subcategories
V. Potential Interactions with Other Regulatory Programs
    A. New Source Review (NSR)
    B. New Source Performance Standards (NSPS)
VI. Statutory and Executive Order Reviews

I. General Information

A. What is the purpose of this ANPRM?

    An ANPRM is an action intended to solicit information from the
public in order to inform the EPA as the Agency considers proposing a
future rule. In light of the proposed repeal of the CPP, 82 FR 48035
(October 16, 2017), this ANPRM focuses on considerations pertinent to a
potential new rule establishing emission guidelines for GHG (likely
expressed as carbon dioxide (CO2)) \1\ emissions from
existing EGUs. In this ANPRM, the EPA sets out and requests comment on
the roles, responsibilities, and limitations of the federal government,
state governments, and regulated entities in developing and
implementing such a rule, and the EPA solicits information regarding
the appropriate scope of such a rule and associated technologies and
approaches.
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    \1\ The air pollutants of interest in this ANPRM are GHGs.
However, any emission guidelines in a potential rule likely would be
expressed as guidelines to limit emissions of CO2 as it
is the primary GHG emitted from fossil fuel-fired EGUs.
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B. Introduction

    When an agency considers proposing a new regulation, it should
inform the public of the need and statutory authority for its action.
In particular, for this ANPRM, the EPA believes it appropriate to
inform the public of the reasons why the Agency is considering a future
rulemaking addressing greenhouse gas emissions from existing electric
utility generating units. The EPA is mindful that its regulatory powers
are limited to those delegated to it by Congress. Here, the Clean Air
Act--as interpreted by the EPA and the federal courts, in particular
the Supreme Court and the Court of Appeals for the District of Columbia
Circuit--determines the scope of whatever obligation and authority the
EPA may have.
    When passing and amending the CAA, Congress sought to address and
remedy the dangers posed by air pollution to human beings and the
environment. While the text of the CAA does not reflect an explicit
intent on the part of Congress to address the potential effects of
elevated atmospheric GHG concentrations, the U.S. Supreme Court in
Massachusetts v. EPA, 549 U.S. 497 (2007), concluded that Congress had
drafted the CAA broadly enough so that GHGs constituted air pollutants
within the meaning of the CAA. Based on this decision, the EPA
subsequently determined that emissions of GHGs from new motor vehicles
cause or contribute to air pollution that may reasonably be anticipated
to endanger public health or welfare. This determination required the
EPA to regulate GHG emissions from motor vehicles.
    Thereafter, the EPA moved to regulate GHG emissions from two types
of stationary sources: Fossil fuel-fired electric utility steam
generating units and fossil fuel-fired stationary combustion turbines
(collectively, EGUs). Under CAA section 111(b) the EPA Administrator is
required to list a category of stationary sources and adopt regulations
establishing standards of performance for that category ``if in his
judgment [the category of sources] causes, or contributes significantly
to, air pollution which may reasonably be anticipated to endanger
public health or welfare.'' 42 U.S.C. 7411(b)(1)(A).
    In October 2015, the EPA promulgated standards of performance for
new fossil fuel-fired EGUs. 80 FR 64510 (October 23, 2015). The EPA
took the position that no new or separate endangerment finding was
necessary, explaining that ``[u]nder the plain language of CAA section
111(b)(1)(A), an endangerment finding is required only to list a source
category,'' id. at 64529-30, and that such a finding had already been
made for the fossil fuel-fired EGU source categories many years before.
Further, the EPA stated that ``section 111(b)(1)(A) does not provide
that an endangerment finding is made as to specific pollutants.'' Id.
at 64530. The EPA continued that ``[t]his contrasts with other CAA
provisions that do require the EPA to make endangerment findings for
each particular pollutant that the EPA regulates under those
provisions.'' Id. (citing CAA sections 202(a)(1), 211(c)(1), and
231(a)(2)(A).\2\
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    \2\ In response to commenters who had argued that the EPA was
``required to make a new endangerment finding before it may regulate
CO2 from EGUs,'' the EPA reiterated its disagreement, but
then added that, ``even if CAA section 111 required the EPA to make
endangerment and cause-or-contribute significantly findings as
prerequisites'' for its CAA section 111(b) rulemaking, the
``information and conclusions'' set forth in the preamble
accompanying the final rule ``should be considered to constitute the
requisite endangerment finding.'' 80 FR 64530.
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    Given this understanding of the CAA, the EPA disclaimed explicit
reliance on the endangerment finding that it had previously made under
CAA section 202(a)(1) with respect to GHG emissions from new motor
vehicles for its decision to establish standards of performance for GHG
emissions from EGUs. To the contrary, the EPA said, ``once a source
category is listed'' under CAA section 111(b)(1)(A), ``the CAA does not
specify what pollutants should be the subject of standards from that
source category.'' 80 FR 64530. Rather, the EPA continued, ``the
statute, in section 111(b)(1)(B), simply directs the EPA to propose and
then promulgate `. . . standards of performance for new sources within
such category,' '' with the CAA otherwise giving no ``specific
direction or enumerated criteria . . . concerning what pollutants from
a given source category should be the subject of standards.'' Id. The
EPA then pointed out that it had ``previously interpreted [CAA section
111(b)(1)(B)] as granting it the discretion to determine which
pollutants should be regulated.'' Id. In the instant case, the EPA went
on to explain, the Agency had a ``rational basis for concluding that
emissions of GHGs from fossil fuel-fired power plants, which are the
major U.S. source of GHG air pollution, merit regulation under CAA
section 111.'' Id. While the EPA said that it was not required to make
a new or separate endangerment finding, the Agency did point to the
endangerment finding it had made in 2009 under CAA section 202(a)(1) as
providing the ``rational basis'' for regulating GHG emissions from
EGUs. Id.

    By regulating GHG emissions from new stationary sources under CAA
section 111(b), the EPA concluded that, under the regulations that the
EPA had previously adopted for implementing CAA section 111(d), it
triggered obligations to regulate GHG from existing sources. See 40 CFR
60.22(a). Pursuant to those regulatory obligations, the EPA,
simultaneously with the new-source rule, issued regulations pertaining
to GHG emissions from existing stationary sources. It was under CAA
section 111(d), a rarely used provision, that EPA issued its ``Clean
Power Plan.'' \3\
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    \3\ Nothing in this ANPRM should be construed as addressing or
modifying the prior findings made under titles I and II of the CAA
discussed in the preceding paragraphs with respect to endangerment
and the requirements under 111. The ANPRM mentions them merely to
explain the genesis of the CPP. Moreover, this ANPRM does not
propose any modifications to the GHG regulations on new stationary
sources promulgated under CAA section 111(b). The EPA has previously
announced that it is undertaking a review of those regulations, and,
at the conclusion of that review, if appropriate, ``will initiate
proceedings to suspend, revise or rescind'' those regulations. 82 FR
16330 (April 4, 2017). The EPA is not soliciting comment on those
actions in this ANPRM.
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    After considering the statutory text, context, legislative history,
and purpose, and in consideration of the EPA's historical practice
under CAA section 111 as reflected in its other existing CAA section
111 regulations and of certain policy concerns, the EPA has proposed to
repeal the CPP. 82 FR 48035. At the same time, the EPA continues to
consider the possibility of replacing certain aspects of the CPP in
coordination with a proposed revision. Therefore, this ANPRM solicits
comment on what the EPA should include in a potential new existing-
source regulation under CAA section 111(d), including comment on
aspects of the States' and the EPA's role in that process, on the Best
System of Emission Reduction (BSER) in this context under the statutory
interpretation contained in the proposed repeal of the CPP, on what
systems of emission reduction may be available and appropriate, and the
interaction of a potential new existing-source regulation with the New
Source Review (NSR) program and with New Source Performance Standards
under CAA section 111(b).
    Section 111(d)(1) of the CAA 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.'' 42 U.S.C. 7411(d). CAA section 111(d)(1) also requires
the Administrator to ``permit the State in applying a standard of
performance to any particular source under a plan submitted under this
paragraph to take into consideration, among other factors, the
remaining useful life of the existing source to which such standard
applies.'' Id.
    As the plain language of the statute provides, the EPA's authorized
role under section 111(d)(1) is to develop a procedure for States to
establish standards of performance for existing sources. ``Section
111(d) grants a more significant role to the states in development and
implementation of standards of performance than does [section
111(b)].'' \4\ 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.'' Am. Elec. Power Co. v.
Connecticut, 131 S. Ct. 2527, 2539 (2011). 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, Sec.  7411(d)(1).'' Id. at 2537-38.
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    \4\ Jonas Monast, Tim Profeta, Brooks Rainey Pearson, and John
Doyle, Regulating Greenhouse Gas Emissions from Existing Sources:
Section 111(d) and State Equivalency, 42 Envtl. L., 10206, (2012).
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    As contemplated by CAA section 111(d)(1), States possess the
authority and discretion to establish appropriate standards of
performance for existing sources. CAA section 111(a)(1) defines
``standard of performance'' as ``a standard of emissions of air
pollutants which reflects'' what is colloquially referred to as the
``Best System of Emission Reduction'' or ``BSER''--i.e., ``the degree
of emission limitation achievable through the application of the best
system of emission reduction which (taking into account the cost of
achieving such reduction and any nonair quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.'' 42 U.S.C. 7411(a)(1)
(emphasis added).
    The EPA's principal task under CAA section 111(d)(1), as
implemented by the EPA's regulations, is to publish a guideline
document for use by the States, with that guideline document
containing, among other things, an ``emission guideline'' that reflects
the BSER, as determined by the Agency, for the category of existing
sources being regulated. See 40 CFR 60.22(b) (``Guideline documents
published under this section will provide information for the
development of State plans, such as: . . . (5) An emission guideline
that reflects the application of the best system of emission reduction
(considering the cost of such reduction) that has been adequately
demonstrated.''). In undertaking this task, the EPA is to specify
``different emission guidelines . . . for different sizes, types, and
classes of . . . facilities when costs of control, physical
limitations, geographical location, or similar factors make
subcategorization appropriate.'' 40 CFR 60.22(b)(5).
    In short, under the EPA's regulations implementing CAA section
111(d), the guideline document serves to ``provide information for the
development of state plans.'' 40 CFR 60.22(b), with the ``emission
guideline,'' reflecting BSER as determined by the EPA, being the
principal piece of information States use to develop their plans--plans
which, under the statute, ``establish[] standards of performance for .
. . existing source[s].'' 42 U.S.C. 7411(d)(1).
    Because the Clean Air Act cannot necessarily be applied to GHGs in
the same manner as other pollutants, Utility Air Regulatory Group, 134
S. Ct. 2427, 2455 (2014) (Alito, J., concurring in part and dissenting
in part), it is fortuitous that the regulations implementing CAA
section 111(d) recognize that States possess considerable flexibility
in developing their plans in response to the emission guideline(s)
established by the EPA.\5\ 40 CFR 60.24(c) specifies that the
``emission standards'' adopted by States ``shall be no less stringent
than the corresponding emission guideline(s)'' published by the EPA.
That is to say, in those circumstances where the Agency, in an exercise
of discretion, chooses to make its emission guideline binding,\6\
state-adopted

standards may not be less stringent than the federal emission
guidelines. However, the implementing regulations also provide that,
where the EPA has not exercised its discretion to make its emission
guideline binding, States ``may provide for the application of less
stringent emissions standards,'' where a State makes certain
demonstrations. 40 CFR 60.24(f) (emphasis added).\7\ Those
demonstrations include a case-by-case determination that a less
stringent standard is ``significantly more reasonable'' due to such
considerations as cost of control, a physical limitation of installing
necessary control equipment, and other factors specific to the
facility. 40 CFR 60.24(f).
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    \5\ Subpart B of 40 CFR part 60 sets forth the procedures and
requirements for States' submittal of, and the EPA's action on,
state plans for control of designated pollutants from designated
facilities under section 111(d) of the CAA (we refer to these as the
``implementing regulations'').
    \6\ The implementing regulations authorize the EPA to make its
emission guideline binding on the States only where the EPA has
specifically determined that the pollutant that is the target of
regulation ``may cause or contribute to endangerment of public
health.'' 40 CFR 60.24(c).
    \7\ States are, as a general matter, free to adopt more
stringent standards than federal standards under CAA title I. See 42
U.S.C. 7416.
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    Additionally, while CAA section 111(d)(1) clearly authorizes States
to develop state plans that establish performance standards and
provides States with certain discretion in determining appropriate
standards, CAA section 111(d)(2) provides the EPA specifically a role
with respect to such state plans. This provision requires the EPA to
prescribe a plan for a State ``in cases where the State fails to submit
a satisfactory plan.'' The EPA therefore is charged with determining
whether state plans developed and submitted under section 111(d)(1) are
satisfactory,'' and 40 CFR 60.27 accordingly provides 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 EPA, particularly where EPA makes an emission guideline
binding as described above, to consider when reviewing and taking
action on a submitted state plan, as 40 CFR 60.27(c) references the
ability of the EPA to find a state plan as ``unsatisfactory because the
requirements of (the implementing regulations) have not been met.'' \8\
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    \8\ See also 40 FR at 53343 (``If there is to be substantive
review, there must be criteria for the review, and EPA believes it
is desirable (if not legally required) that the criteria be made
known in advance to the States, to industry, and to the general
public. The emission guidelines, each of which will be subjected to
public comment before final adoption, will serve this function.'').
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    Through this ANPRM, the EPA solicits information on multiple
aspects of a potential rule that would establish emission guidelines
for States to establish performance standards for GHG emissions from
existing EGUs. To facilitate effective and efficient provision and
review of comments, we here identify main areas in which we are
soliciting comment and request that commenters include the
corresponding numeric identifier(s) when providing comments. We
emphasize that we are not limiting comment to these identified areas,
but that we are identifying these to provide a framework and consistent
approach for commenters. In the following discussion, we solicit
comment on (1) the roles and responsibilities of the States and the EPA
in regulating existing EGUs for GHGs. As discussed below, we are
particularly interested in comment on (1a) the suitability of
provisions of the EPA's regulations that set forth the procedures and
requirements for States' submittals of, and the EPA's action on, state
plans for controlling emissions under CAA section 111, as applied in
this context of regulating existing EGUs for GHG and on (1b) the extent
of involvement and roles of the EPA in developing emission guidelines,
including, but not limited to, providing sample state plan text,
determining the BSER, considering existing or nascent duplicative state
programs, and reviewing state plan submittals; the roles of the States
in this endeavor, including determining the scope of most appropriate
emissions standards, e.g., setting unit-by-unit or broader-based
standards; and joint considerations, such as the form of the emission
standard, i.e., rate- or mass-based, and compliance flexibilities, such
as emissions averaging and trading.
    We further solicit comment on (2) application, in the specific
context of limiting GHG emissions from existing EGUs, of reading CAA
section 111(a)(1) as limited to emission measures that can be applied
to or at a stationary source, at the source-specific level. Note that
the solicitation in this ANPRM is application- and context-specific;
comments on interpreting CAA section 111(a)(1) as generally applied to
CAA section 111(d) should be submitted to the docket on the CPP repeal
proposal. See 82 FR 48035.
    Under this source-specific reading of CAA section 111(a)(1), we
solicit comment on (3) how to best define the BSER and develop GHG
emission guidelines for existing EGUs, specifically with respect to
(3a) identifying the BSER that can be implemented at the level of an
affected source, including aspects related to efficiency (heat rate)
improvement technologies and practices as well as other systems of
emission reduction; (3b) considering whether GHG emission guidelines
for existing EGUs should include presumptively approvable limits; and
(3c) aspects relating to use of carbon capture and storage (CCS) as a
compliance option to reduce GHG emissions. With respect to
applicability of a potential rule, we solicit comment on (3d) criteria
for determining affected sources and on (3e) potential subcategories
and any effects on an appropriate corresponding BSER and standards.
    Additionally, we solicit comment on (4) potential interactions of a
possible rule limiting GHG emissions from existing EGUs with existing
statutory and regulatory programs, such as New Source Review (NSR)
applicability and permitting criteria and processes and impacts on
state plans of New Source Performance Standards (NSPS) coverage of
existing sources that undergo reconstruction or modification sufficient
to trigger regulation as a new source in that federal program.
    We again emphasize that we list these main areas in which we are
soliciting comment only to provide a conceptual and organizational
structure for providing comments and not to limit comment; we encourage
provision of (5) any other comment that may assist the Agency in
considering setting emission guidelines to limit GHG emissions from
existing EGUs.

C. Where can I get a copy of this document?

    In addition to being available in the docket, an electronic copy of
this ANPRM will also be available on the internet. Following signature
by the EPA Administrator, a copy of this ANPRM will be posted at the
following address: https://www.epa.gov/Energy-Independence. Following
publication in the Federal Register, the EPA will post the Federal
Register version of the ANPRM and key technical documents at this same
website.

II. Background

    In accordance with Executive Order 13783, 82 FR 16093 (March 31,
2017), the EPA has reviewed the CPP and issued a notice of proposed
repeal on October 16, 2017, 82 FR 48035. As discussed in that notice,
the EPA proposes a change in the legal interpretation underlying the
CPP to an interpretation that is consistent with the text, context,
structure, purpose, and legislative history of the CAA, as well as with
the Agency's historical understanding and exercise of its statutory
authority. If the proposed interpretation were to be finalized, the CPP
would be repealed. 82 FR 48038-39. The EPA also explains in that
proposal that the Agency is considering the scope of its legal
authority to issue

a potential new rule and, in this ANPRM, is soliciting information on
systems of emission reduction that are in accord with the legal
interpretation discussed in the CPP repeal proposal and information on
potential compliance measures and state planning requirements.

III. The Statutory and Regulatory Framework under CAA Section 111(d)

A. Introduction

    As discussed above, the EPA's authorized role under CAA section
111(d) is to establish a procedure under which States submit plans
establishing standards of performance for existing sources, reflecting
the application of the best system of emission reduction (BSER) that
the EPA has determined is adequately demonstrated for the source
category. Under the statute and the EPA's implementing regulations, the
States have authority and discretion to establish less stringent
standards where appropriate.
    This ANPRM solicits comment, as specified below, on certain aspects
of the proper implementation of this statutory and regulatory framework
with respect to GHG emissions from existing EGUs. This ANPRM further
solicits comment both on the proper application in this context of the
interpretation of CAA section 111 contained in the proposed repeal of
the CPP--under which a BSER is limited to measures that apply to and at
individual sources, on the source-specific level--and on the EPA's
proper role and responsibilities under CAA section 111 as applied to
GHG emissions from existing EGUs.

B. States' Role and Responsibilities Under CAA Section 111(d)

1. Designing State Plans
    The implementing regulations at subpart B of 40 CFR part 60 set
forth the procedures and requirements for States' submittal of, and the
EPA's action on, state plans for control of designated pollutants from
designated facilities under CAA section 111(d). A summary of the
implementing regulations and a discussion of the basic concepts
underlying them appear in the preamble published in connection with its
promulgation (40 FR 53340, November 17, 1975). In brief, the
implementing regulations provide that after a standard of performance
applicable to emissions of a designated pollutant from new sources is
promulgated, the Administrator will publish a draft guideline document
containing information pertinent to the control of the same pollutant
from designated (i.e., existing) facilities. The Administrator will
also publish a notice of availability of the draft guideline document,
and invite comments on its contents. After publication of a final
guideline document for the pollutant in question, the States will have
9 months to develop and submit plans for control of that pollutant from
designated facilities. Within 4 months after the date for submission of
plans, the Administrator will approve or disapprove each plan (or
portion thereof). If a state plan (or portion thereof) is disapproved,
the Administrator will promulgate a federal plan (or portion thereof)
within 6 months after the date for plan submission. These and related
provisions of the implementing regulations were patterned after section
110 of the CAA and 40 CFR part 51 (concerning adoption and submittal of
state implementation plans (SIPs) under CAA section 110).
    As discussed in the preamble to the implementing regulations, those
regulations provide certain flexibilities available to States in
establishing state plans. For example, as provided in 40 CFR 60.24,
States may consider certain factors such as cost and other limitations
in setting emission standards or compliance schedules. After the
implementing regulations were first promulgated, CAA section 111(d) was
amended to authorize States ``to take into consideration, among other
factors, the remaining useful life'' of existing sources when applying
standards to such sources. Public Law 95-95, 109(b), 91 Stat. 685, 699
(August 7, 1977). The EPA solicits comment on the proper application of
this provision to a potential new rule addressing GHG emissions from
existing EGUs, and whether any change to that provision--or to other
provisions of the implementing regulations, particularly those
establishing the time frames for States to submit their plans to the
EPA, for the EPA to act on those plans, and for the EPA to develop its
own plan or plans in the absence of an approvable state submission, as
well as criteria for approval of state plans--is warranted in the
context of such a potential new rulemaking. The EPA further solicits
comment on which mechanisms, if any, presently available under CAA
section 110 for SIPs may also be appropriate for the EPA to adopt and
utilize in the context of state plans submitted under CAA section
111(d) (e.g., conditional approvals). The EPA also solicits comment on
whether any other changes to the implementing regulations are
appropriate.
2. Application of Standards to Sources
    Historically, the EPA has provided States with guidance on the
preparation of state plans (for example, by providing model rules or
sample rule language). While providing this text provides States with a
clear direction in creating their state plans, the EPA understands that
it may also be perceived as sending a signal of limiting flexibility
and limiting the consideration of other factors that are unique to each
State and situation. The EPA is soliciting comment on whether it would
be beneficial to States for the EPA to provide sample state plan text
as part of the development of emission guidelines.
    Each State has its own unique circumstances to consider when
regulating air pollution emissions from the power industry within that
State. A prime example is the remaining useful life (RUL) of the
State's fleet of EGUs. A State may take into account the RUL of sources
within its fleet, such as how much longer an EGU will operate and how
viable it is to invest in upgrades that can be applied at or to the
source, when establishing emission standards as part of its state plan.
These are source-specific considerations and play a role in a State
evaluating the future of a fleet. The EPA solicits comment on the role
of a State in setting unit-by-unit or broader emission standards for
EGUs within its borders, including potential advantages of such an
approach (e.g., it provides flexibility to tailor standards that take
into account the characteristics specific to each boiler or turbine)
and potential challenges (e.g., the impact that varying requirements
could have on emissions and dispatch in such an interconnected system).
The EPA also solicits comment on an approach where the EPA determines
what systems may constitute BSER without defining presumptive emission
limits and then allows the States to set unit-by-unit or broader
emission standards based on the identified BSER while considering the
unique circumstances of the State and the EGU. The EPA requests more
information on the burden that it would create for States to determine
unit-by-unit emission standards for each EGU, for determining what the
remaining useful life of a given source is and how that should impact
the level of the standard and on what role subcategorization can play
in the emission standard setting process.
    The process that the State of North Carolina used in the
development of its draft rule,\9\ in response to the CPP, may

provide a useful example of a process a State could go through to
determine unit-level emission standards based on technology that can be
applied at or to a source.\10\ In that draft rule, North Carolina
developed a menu of potential heat rate improvements. The State then
examined these potential opportunities on a unit-by-unit basis,
determined that some units had opportunities for cost-effective
improvements and developed unit-specific emission standards consistent
with those rates. North Carolina determined that other units did not
have such opportunities (for reasons including that a given heat rate
improvement opportunity was not applicable to a particular unit, that
it had already been applied, or that the unit was scheduled to retire
soon (i.e., RUL)).
---------------------------------------------------------------------------

    \9\ https://files.nc.gov/ncdeq/Air%20Quality/rules/hearing/111dRules.pdf.
    \10\ The EPA is not otherwise endorsing nor judging whether this
draft plan was or is adequate to meet any previous or future CAA
section 111(d) emission guidelines.
---------------------------------------------------------------------------

    Another example of a unit-by-unit heat rate improvement analysis
can be found in the final CAA section 111(b) GHG standards of
performance for modified fossil fuel-fired steam generating EGUs (80 FR
64510, October 23, 2015). There, the EPA determined that the BSER for
existing steam generating EGUs that trigger the modification provisions
is the affected EGU's own best potential performance as determined by
that source's historical performance. Relying on this BSER, the EPA
finalized an emission standard that is based on a unit-specific
emission limitation consistent with each modified unit's best 1-year
historical performance and can be met through a combination of best
operating practices and equipment upgrades. See 80 FR 64658. The EPA
seeks comment on this approach to evaluate unit-specific heat rate
improvement opportunities. We also seek comment on potential
limitations to this approach, such as the potential for degradation of
heat rate over time and the effects of changing operating conditions
(e.g., changing from stable baseload operations to variable load-
following operations or vice-versa).
    The EPA is aware that some States have already developed, or are in
the process of developing, programs to limit GHG emissions from EGUs.
The EPA requests comment on how these programs could interact with, or
perhaps, satisfy, a potential rule under CAA section 111(d) to regulate
GHG emissions from existing EGUs.
a. Rate-Based and Mass-Based Compliance Options and Other Potential
Compliance Flexibilities
    The Agency's existing CAA section 111 rules (both new-source rules
under 111(b) and existing-source rules under 111(d)) are all based on
emission rate standards (e.g., mass of pollutant per unit of heat input
or production). The potential opportunities for improvements in a
unit's GHG performance seem similarly amenable to emission rate
standards. The EPA requests comment on whether emission guidelines for
GHG emission rate standards is all that it or the States should
consider in a potential future rulemaking or whether the use of mass-
based emission standards should also be considered.
    In addition to the form of the emission standard, the EPA solicits
comment on what factors the EPA should consider when reviewing State
plans, as well as additional compliance flexibilities States should be
able to employ in developing state plans. Should States be able to
develop plans that allow emissions averaging? If so, should averaging
be limited to units within a single facility, to units within a State,
to units within an operating company, or beyond the State or company?
If averaging is not limited between units in different States or
between units owned by the same company, are any special requirements
needed to facilitate such trading? Should mass-based trading be
considered? If so, how should rate-based compliance instruments
intended to meet unit-specific emission rates be translated into mass-
based compliance instruments? Should rate-based trading programs be
able to interact with mass-based trading programs? What considerations
should States and the EPA take into account when determining
appropriate implementing and enforcing measures for emission standards?
The EPA requests information and feedback on all of these questions and
on what limitations, if any, apply to States as they set standards.

C. The EPA's Interpretation of CAA Section 111(a)(1)

    In the CPP repeal proposal, the EPA explained that the
Administrator proposes to return to the traditional reading of CAA
section 111(a)(1) as being limited to emission reduction measures that
can be applied to or at a stationary source, at the source-specific
level. Under this reading, such measures must be based on a physical or
operational change to a building, structure, facility, or installation
at that source, rather than measures that the source's owner or
operator can implement on behalf of the source at another location. The
EPA is not soliciting comment through this ANPRM on this proposed
interpretation; rather, comments on interpreting CAA section 111(a)(1)
should be submitted on the CPP repeal proposal. Here, the EPA is
requesting comment on how the program should be implemented assuming
adoption of that proposed interpretation.

D. The EPA's Role and Responsibilities Under CAA Section 111(d)

    The EPA has certain responsibilities to fulfill and certain
authority to act when issuing a rule under CAA section 111(d).
Specifically, the EPA is required to prescribe regulations establishing
a procedure under which States submit plans that establish standards of
performance for existing sources and that provide for the
implementation and enforcement of such standards. The EPA's regulations
implementing CAA section 111(d) created a process by which the EPA
issues ``emission guidelines'' reflecting the Administrator's judgment
on the degree of control attainable with the BSER that has been
adequately demonstrated for existing sources in relevant source
categories. See generally 40 FR 53340 (November 17, 1975). The EPA has
set emission guidelines consistent with this approach for five source
categories under CAA section 111(d).\11\ These earlier emission
guidelines shared a number of common features or elements:
---------------------------------------------------------------------------

    \11\ These categories are: Phosphate Fertilizer Plants, see 42
FR 12022 (March 1, 1977); Sulfuric Acid Plants, see 42 FR 55796
(October 18, 1977); Kraft Pulp Mills, see 44 FR 29828 (May 22,
1979); Primary Aluminum Plants, see 45 FR 26294 (April 17, 1980);
and Municipal Solid Waste Landfills, see 61 FR 9905 (March 12,
1996). (Note that the Agency also finalized CAA section111(d)
emission guidelines for municipal waste combustors, see 56 FR 5514
(February 11, 1991); however, those rules were subsequently
withdrawn and superseded by requirements under CAA section 129, see
60 FR 65387 (December 19, 1995)).

     A description of the BSER that has been adequately
demonstrated based on controls or actions that could be implemented
at the level of the individual source;
     A consideration of the degree of emission limitation
achievable, taking into account costs and energy and environmental
impacts from the application of the BSER;
     A compliance schedule;
     A level or degree of emission reductions achievable
with application of the BSER;
     Rule language implementing the emission guideline; and
     Other information to facilitate the development of
state plans.

    Once the EPA issues an emission guideline, States develop CAA
section 111(d) plans establishing standards of performance for the
covered sources within their borders and providing procedures for the
implementation and enforcement of such standards similar to the process
used for SIPs for National Ambient Air Quality Standards under CAA
section 110. In accordance with CAA section 111(d)(1), state plans
may--when applying a standard of performance to a particular source--
``take into consideration, among other factors, the remaining useful
life'' of an existing source to which such standard applies. 42 U.S.C.
7411(d)(1). The state plans are submitted to the EPA for review and
approval or disapproval through notice-and-comment rulemaking. In cases
where a State fails to submit a ``satisfactory'' plan, the EPA has
authority to prescribe a plan for that State. Where a State fails to
enforce an EPA-approved plan, the EPA has the authority to enforce the
provisions of such a plan.
    The EPA is taking comment on how best to define the BSER and to
develop emission guidelines for EGUs for emissions of GHG.
Specifically, we are requesting comment on the following three
subjects:
    (1) Identifying the BSER that can be implemented at the level of an
affected source (section IV below discusses what such a BSER might look
like in more detail).
    (2) Whether emission guidelines for EGUs for emissions of GHG
should include presumptively approvable limits.
    (3) How much discretion States have to depart from the EPA's
emission guidelines.
    As discussed in the proposed repeal of the CPP, there have been
significant changes in the power sector since the CPP was finalized. We
take comment on how these changes should be factored into any analysis
that the EPA does regarding determination of a BSER that can be applied
to or at an individual source, at the source-specific level. In
particular, the EPA is interested in comment on how the EPA should
consider the impact on the benefits and costs of any potential new rule
from state programs to reduce GHG emissions from existing EGUs that are
not federally mandated.
1. BSER
    The EPA's traditional approach to establishing the BSER focused on
technological or operational measures that can be applied to or at a
single source. The Agency is now requesting comment on how to take an
approach to regulating GHG from existing EGUs in line with its prior
practice under CAA section 111(d) whereby it would consider only
measures that can be applied at or to individual sources to develop the
BSER and emission guidelines.\12\ The types of measures that may be
considered are discussed in more detail below in section IV.
---------------------------------------------------------------------------

    \12\ As noted above, the EPA is not soliciting comment through
this ANPRM on that proposed interpretation. Rather, comments on how
the EPA should interpret CAA section 111(a)(1) should be submitted
to the docket for the CPP repeal proposal.
---------------------------------------------------------------------------

2. Presumptively Approvable Limits
    As discussed in section IV of this document, with regard to coal-
fired EGUs, the potential for emission reductions at the unit-level or
source-level may vary widely from unit to unit. Consequently, broadly
applicable, presumptively approvable emission limitations (even at a
subcategorized level) may not be appropriate for GHG emissions from
EGUs. Therefore, in this ANPRM, the EPA is taking comment on an
approach where the Agency defines BSER or otherwise provides emission
guidelines without providing a presumptively approvable emission
limitation.

IV. Available Systems of GHG Emission Reduction

    The EPA has examined technologies and strategies that could
potentially be applied at or to existing EGUs to reduce emissions of
GHG. The Agency primarily focused on opportunities for heat rate (or
efficiency) improvements at fossil fuel-fired steam generating EGUs to
be a part of the BSER.

A. Heat Rate Improvements for Boilers

1. Heat Rate Improvement
    Heat rate is a measure of efficiency for fossil fuel-fired EGUs. An
EGU's heat rate is the amount of energy input, measured in British
thermal units (Btu), required to generate one kilowatt hour (kWh) of
electricity. The more efficiently an EGU operates, the lower its heat
rate will be. As a result, an EGU with a lower heat rate will consume
less fuel per kWh generated and emit lower amounts of GHG and other air
pollutants per kWh generated as compared to a less efficient unit. An
EGU's heat rate can be affected by a variety of design characteristics,
site-specific factors, and operating conditions, including:

     Thermodynamic cycle of the boiler;
     Boiler and steam turbine size and design;
     Cooling system type;
     Auxiliary equipment, including pollution controls;
     Operations and maintenance;
     Fuel quality; and
     Ambient conditions.

    The EPA has previously assessed the potential heat rate
improvements of existing coal-fired EGUs by conducting statistical
analyses using historical gross heat rate data from 2002 to 2012 for
884 coal-fired EGUs that reported both heat input and gross electricity
output to the Agency in 2012.\13\ The Agency grouped the EGUs by
regional interconnections--Western, Texas, and Eastern--and analyzed
potential heat rate improvements within each interconnection. The
results of the statistical analyses indicated that there may be
significant potential for heat rate improvement--both regionally and
nationally. However, these results represent fleet-wide average heat
rate improvement. The EPA did not conduct analyses to identify heat
rate improvement opportunities at the unit level, and the Agency
recognizes that the fleet of U.S. fossil fuel-fired EGUs is varied in
terms of size, age, fuel type, fuel usage (e.g. baseload, cycling,
etc.) boiler type, etc. The EPA solicits comment on this statistical
approach and its applicability in identifying heat rate improvement
opportunities at the unit level. The EPA also is aware that many coal-
fired EGUs now often operate under load following and cycling
conditions. The EPA solicits comment on how best to evaluate unit level
heat rate improvement opportunities while properly accounting for the
effects of changes in the historical operation of such units. The EPA
also invites comment on how heat rate is impacted when EGUs operate
outside their design conditions and what options are available to
remedy the efficiency losses these units may incur when responding to
variable load demands. The EPA also requests comment on whether there
are any data that the Agency should consider collecting either for the
purpose of proposing emission guidelines or that could ultimately be
helpful to States in developing state plans.
---------------------------------------------------------------------------

    \13\ Greenhouse Gas Mitigation Measures Technical Support
Document (TSD), Docket ID: EPA-HQ-OAR-2013-0602-36859.
---------------------------------------------------------------------------

    There are several technologies and equipment upgrades--as well as
good operating and maintenance practices--that EGU owners or operators
may utilize to reduce an EGU's heat rate, in particular for utility
boilers. Table 1 lists some technology and equipment upgrades that
owners or operators of EGUs may be able to deploy to improve heat rate.
Table 2 lists some good practices that have the potential to

reduce an EGU's heat rate. (Note, these lists of technologies and
practices, along with their respective potential heat rate
improvements, were drawn from studies listed below in Table 3.)
    The EPA is seeking comment on all technologies and practices that
may be implemented to improve heat rate--including, but not limited to,
those listed in Tables 1 and 2. Specifically, the Agency is interested
in the availability and applicability of technologies and best
operating and maintenance practices for the U.S. fossil fuel-fired EGU
fleet. We are also soliciting comment on potential heat rate
improvements from technologies and practices; on likely costs of
deploying these technologies and the good operating and maintenance
practices, including applicable planning, capital, and operating and
maintenance costs; on owner and operator experiences deploying these
technologies and employing these operating and maintenance practices;
on barriers to or from deploying these technologies and operating and
maintenance practices; and on any other technologies or operating and
maintenance practices that may exist for improving heat rate, but are
not reflected on these lists. The EPA solicits comments on any
differences in cost or effectiveness in technologies that are due to
impacts of regional or geographical considerations (e.g., regional
labor or materials costs).
    The EPA also requests comment on the merits of differentiating
between gross and net heat rate. 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). The EPA explicitly
requests comment on how the technologies and operating practices are
potentially affected by the operation of the EGU (e.g., at part load or
in cycling operations).

Table 1--Example Equipment Upgrades and Technology to Improve Heat Rates
                           at Utility Boilers
------------------------------------------------------------------------
        Equipment upgrade(s)            Potential heat rate improvement
------------------------------------------------------------------------
Replace materials handling motors     Negligible.
 and drives with more efficient
 motors and/or variable frequency
 drives to reduce ancillary energy
 consumption.
Improve coal pulverizers to produce   0.52-2.6%.
 more finely ground coal to improve
 combustion efficiency.
Use waste heat to dry low-grade coal  N/A.
 and improve combustion efficiency.
Automate boiler drains to manage      N/A.
 make-up water intake.
Improve boiler, furnace, ductwork,    N/A.
 and pipe insulation to reduce heat
 loss.
Upgrade economizer to increase heat   50-100 Btu/kWh.
 recovery.
Install a neural network and          0-150 Btu/kWh.
 advanced sensors and controls to
 optimize plant station operation.
Install intelligent sootblowers to    30-150 Btu/kWh.
 enhance furnace efficiency.
Improve seals on regenerative air     10-40 Btu/kWh.
 pre-heaters to reduce air in-
 leakage and increase heat recovery.
Install sorbent injection system to   50-120 Btu/kWh.
 reduce flue gas sulfuric acid
 content and allow increased energy
 recovery at the air heater.
Upgrade steam turbine internals to    100-300 Btu/kWh; 1.5-5.5%.
 improve efficiency and replace worn
 seals to reduce steam leakage.
Retube the condenser to restore       3-70 Btu/kWh; 1.0-3.5%.
 efficiency or expand condenser
 surface area to improve efficiency.
Replace feedwater pump seals to       N/A.
 reduce water loss.
Install solar systems to pre-heat     N/A.
 feedwater to improve efficiency.
Increase feedwater heating surface    N/A.
 to improve efficiency.
Overhaul or upgrade boiler feedwater  25-50 Btu/kWh.
 pumps to improve efficiency.
Replace centrifugal induced draft     10-50 Btu/kWh.
 (ID) fans with axial ID fans.
Replace ID fan motors with variable   10-150 Btu/kWh.
 frequency drives.
Upgrade flue-gas desulfurization      0-50 Btu/kWh.
 components (e.g., co-current spray
 tower quencher, turning vanes,
 variable frequency drives) to
 reduce pressure drop, improve flow
 distribution, and reduce ancillary
 energy consumption.
Upgrade the electrostatic             0-5 Btu/kWh.
 precipitator energy system (e.g.,
 high voltage transformer/rectifier
 sets) to improve particulate matter
 capture and reduce energy
 consumption.
Replace older motors with more        0-21 Btu/kWh.
 efficient motors to reduce
 ancillary energy consumption.
Refurbish and/or upgrade cooling      0-70 Btu/kWh.
 tower packing material to improve
 cycle efficiency.
Install condenser tube cleaning       N/A.
 system to reduce scaling, improve
 heat transfer and restore
 efficiency.
------------------------------------------------------------------------
N/A = The potential heat rate improvement is unknown.

Table 2--Example Good Practices to Improve Heat Rates at Utility Boilers
------------------------------------------------------------------------
          Good practice(s)              Potential heat rate improvement
------------------------------------------------------------------------
Reduce excess air to improve          N/A.
 combustion efficiency.
Optimize primary air temperature to   N/A.
 improve combustion efficiency.
Measure and control primary and       N/A.
 secondary air flow rates to improve
 combustion efficiency.
Tune individual burners (balance air/ N/A.
 fuel ratio) to improve combustion
 efficiency.
Conduct more frequent condenser       30-70 Btu/kWh.
 cleanings to maintain cycle
 performance.
Monitor condenser performance to      N/A.
 track efficiency/performance.
Use secondary air for ammonia         0-5 Btu/kWh.
 vaporization and dilution to reduce
 ancillary energy consumption.
Careful monitoring of the water       N/A.
 treatment system for optimal
 feedwater quality and cooling water
 performance to reduce scale build-
 up and corrosion plus maintain
 efficiency.
Conduct maintenance of cooling        N/A.
 towers (e.g., replace missing/
 damaged planks) to restore cooling
 tower efficiency.
Chemical clean scale build-up on      N/A.
 feedwater heaters to improve heat
 transfer.
Repair steam and water leaks (e.g.,   N/A.
 replace valves and steam traps) to
 reduce makeup water consumption.
Repair boiler, furnace, ductwork,     N/A.
 and air heater cracks to reduce air
 in-leakage and auxiliary energy
 consumption.
Clean air pre-heater to improve heat  N/A.
 transfer.

Adopt sliding pressure operation to   N/A.
 reduce turbine throttling losses.
Reduce attemperator activation to     N/A.
 reduce heat input.
Clean turbine blades to remove        N/A.
 deposits and improve turbine
 efficiency.
Maintain instrument calibration to    N/A.
 ensure valid operating data.
Perform on-site appraisals to         N/A.
 identify areas for improved heat
 rate performance.
Adopt training program for operating  N/A.
 and maintenance staff on heat rate
 improvements.
Adopt incentive program to reward     N/A.
 actions to improve heat rate.
Implement heat rate analytics to      N/A.
 identify real-time heat rate
 deviations.
Plant lighting upgrades to reduce     N/A.
 ancillary energy consumption.
Use predictive maintenance to avoid   N/A.
 outages and de-rate events.
------------------------------------------------------------------------
N/A = The potential heat rate improvement is unknown.

    The technologies and operating and maintenance practices listed
above may not be available or appropriate for all types of EGUs; and
some owners or operators may have already deployed some of the
technologies and/or employed some of the best operating and maintenance
practices at their fossil fuel-fired EGUs. In addition, some of the
technologies and operating and maintenance practices listed above might
be alternatives to other actions on the list and, therefore, mutually
exclusive of other technologies and practices.
    Government agencies and laboratories, industry research
organizations, engineering firms, equipment suppliers, and
environmental organizations have conducted studies examining the
potential for improving heat rate in the U.S. EGU fleet or a subset of
the fleet. Table 3 provides a list of some reports, case studies, and
analyses about heat rate improvement opportunities in the U.S. The EPA
is seeking comment on the appropriateness of the studies for informing
our understanding of potential heat rate improvement opportunities. The
EPA is also seeking information on any additional publicly available
studies that identify heat rate improvement measures or demonstrate
actual or potential heat rate improvements at fossil fuel-fired EGUs,
including the appropriateness of the studies for establishing heat rate
improvement goals.

   Table 3--Heat Rate Improvement Reports, Case Studies, and Analyses
------------------------------------------------------------------------
    Heat rate improvement report organization/publication (author, if
                        known)--title--year [URL]
-------------------------------------------------------------------------
ABB Power Generation--Energy Efficient Design of Auxiliary Systems in
 Fossil-Fuel Power Plants [https://library.e.abb.com/public/5e627b842a63d389c1257b2f002c7e77/Energy%20Efficiency%20for%20Power%20Plant%20Auxiliaries-V2_0.pdf].
Alstom Engineering (Sutton)--CO2 Reduction Through Energy Efficiency in
 Coal-Fired Boilers--2011 [http://www.mcilvainecompany.com/Universal_Power/Subscriber/PowerDescriptionLinks/Jim%20Sutton%20-%20Alstom%20-%203-31-2011.pdf].
Congressional Research Service (Campbell)--Increasing the Efficiency of
 Existing Coal-fired Power Plants (R43343)--2013 [https://fas.org/sgp/crs/misc/R43343.pdf].
EIA--Analysis of Heat Rate Improvement Potential at Coal-Fired Power
 Plants--2015 [https://www.eia.gov/analysis/studies/powerplants/heatrate/pdf/heatrate.pdf].
EPA--Greenhouse Gas Mitigation Measures--2015 [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-37114].
EPRI--Range of Applicability of Heat Rate Improvements--2014 [https://www.epri.com/#/pages/product/000000003002003457].
European Commission--Integrated Pollution Prevention and Control
 Reference Document on Best Available Techniques for Large Combustion
 Plants--2006 [http://eippcb.jrc.ec.europa.eu/reference/BREF/lcp_bref_0706.pdf].
GE--Comments of the General Electric Company--2014 [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-22971].
IEA (Reid)--Retrofitting Lignite Plants to Improve Efficiency and
 Performance (CCC/264)--2016 [http://bookshop.iea-coal.org/reports/ccc-264/83861 264/83861].
IEA (Henderson)--Upgrading and Efficiency Improvement in Coal-fired
 Power Plants (CCC/221)--2013 [http://bookshop.iea-coal.org/reports/ccc-221/83186 221/83186].
Lehigh University--Reducing Heat Rates of Coal-fired Power Plants--2009
 [http://www.lehigh.edu/~inenr/leu/leu_61.pdf].
NETL--Opportunities to Improve the Efficiency of Existing Coal-fired
 Power Plants--2009 [http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/OpportImproveEfficExistCFPP-ReportFinal.pdf].
NETL--Improving the Thermal Efficiency of Coal-Fired Power Plants in the
 United States--2010 [http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/ThermalEfficCoalFiredPowerPlants-TechWorkshopRpt.pdf].
NETL--Improving the Efficiency of Coal-Fired Power Plants for Near Term
 Greenhouse Gas Emissions Reductions (DOE/NETL-2010/1411)--2010 [http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/DOE-NETL-2010-1411-ImpEfficCFPPGHGRdctns-0410.pdf].
NETL--Options for Improving the Efficiency of Existing Coal-Fired Power
 Plants (DOE/NETL-2013/1611)--2014 [https://www.netl.doe.gov/energy-analyses/temp/FY14_OptionsforImprovingtheEfficiencyofExistingCoalFiredPowerPlants_040114.pdf].
National Petroleum Council--Electric Generation Efficiency--2007 [http://www.npc.org/Study_Topic_Papers/4-DTG-ElectricEfficiency.pdf].
NRDC--Closing the Power Plant Carbon Pollution Loophole: Smart Ways the
 Clean Air Act Can Clean Up America's Biggest Climate Polluters (12-11-
 A)--2013 [https://www.nrdc.org/sites/default/files/pollution-standards-report.pdf].
Power Engineering International (Cox)--Dry Sorbent Injection for SOX
 Emissions Control--2017 [http://www.powerengineeringint.com/articles/print/volume-25/issue-6/features/dry-sorbent-injection-for-sox-emissions-control.html].
Power Mag (Korellis)--Coal-Fired Power Plant Heat Rate Improvement
 Options, Parts 1 & 2--2014 [http://www.powermag.com/coal-fired-power-plant-heat-rate-improvement-options-part-1] [http://www.powermag.com/coal-fired-power-plant-heat-rate-improvement-options-part-2].
Power Mag (Peltier)--Steam Turbine Upgrading: Low-hanging Fruit--2006
 [http://www.powermag.com/steam-turbine-upgrading-low-hanging-fruit].
Resources for the Future (Lin et al)--Regulating Greenhouse Gases from
 Coal Power Plants Under the Clean Air Act (RFF-DP-13-05)--2014 [http://www.rff.org/files/sharepoint/WorkImages/Download/RFF-DP-13-05.pdf].

S&L--Coal-fired Power Plant Heat Rate Reductions (SL-009597)--2009
 [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-36895]
 S&L--Coal Fired Power Plant Heat Rate Reduction--NRECA (SL-012541)--
 2014 [https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-22767
 Supp 33].
Sierra Club (Buckheit & Spiegel)--Sierra Club 52 Unit Study--2014 [http://content.sierraclub.org/environmentallaw/sites/content.sierraclub.org.environmentallaw/files/Appendix%201%20-%20Rate%20v%20Load%20Summary.pdf].
Storm Technologies--Applying the Fundamentals for Best Heat Rate
 Performance of Pulverized Coal Fueled Boilers--2009 [http://www.stormeng.com/pdf/EPRI2009HeatRateConference%20FINAL.pdf].
------------------------------------------------------------------------

    It has been noted that unit-level heat rate improvements, with the
resulting reductions in variable operating costs at those improved
EGUs, could lead to increases in utilization of those EGUs as compared
to other generating options. See generally 80 FR 64745. This so-called
``rebound effect'' could result in smaller overall reductions in GHG
emissions (depending on the GHG emission rates of the displaced
generating capacity). The EPA solicits comments on this potential
``rebound effect,'' on whether the EPA should consider it in a
potential future rulemaking, and on any available measures that the
Agency can take to minimize any potential effect.
2. Measuring Heat Rate at Fossil Fuel-Fired EGUs
    Accurately monitoring changes in heat rate is vital for assessing
the degree of heat rate improvement at fossil fuel-fired EGUs. Most
coal-fired EGUs already continuously monitor heat input and gross
electric output and report the information to the EPA under 40 CFR part
75. To calculate heat input, coal-fired EGUs monitor the CO2
concentration and stack volumetric flow rates. Part 75 classifies
hourly CO2 concentration and stack volumetric flow rates
measurements as valid, if the continuous emissions monitoring systems'
(CEMS') relative accuracies are within plus or minus 10 percent when
compared to federal reference methods.
    In 1999, the EPA introduced new federal reference methods to
address angular stack flow (Methods 2F and 2G) and the effect of the
stack walls on gas flow (Method 2H). In general, these alternative
measurement methods reduce or eliminate the over-estimation of stack
gas volumetric flow that results from the use of Method 2 when specific
flow conditions (e.g., angular flow) are present in the stack.
Generally, the alternative methods lead to lower flow rates, and, as a
result, lower heat input. After the introduction of these new methods,
many coal-fired EGUs adopted the alternative methods to measure flow
and calculate mass emissions. However, coal-fired EGUs are not required
to use the alternative measurement methods, and they may change methods
when conducting a Relative Accuracy Test Audit (RATA).
    The EPA is seeking comment on the level of uncertainty of
measurement of flue gas CO2 concentration and stack
volumetric flow rate; options to reduce the uncertainty associated with
CEMS at coal-fired EGUs and fuel flow monitors (40 CFR part 75,
appendix D) and 40 CFR part 75, appendix G, equation G-4 at natural
gas- and oil-fired EGUs; options for eliminating or revising 40 CFR
part 75, appendix G, equation G-1 at natural gas- and oil-fired EGUs;
and alternative approaches to accurately measure heat rate at fossil
fuel-fired EGUs.
    The EPA also requests comment on the need for and utility of direct
heat input monitoring as EGUs generally do not monitor heat input
directly, but instead calculate it from CEMS data.

B. Heat Rate Improvements at Natural Gas-fired Combustion Turbines

    The EPA has also considered opportunities for emission reductions
at natural gas-fired stationary combustion turbines as a part of the
BSER--at both simple cycle turbines and combined cycle turbines--and
previously determined that the available emission reductions would
likely be too expensive or would likely provide only small overall
reductions. In the development of the CAA section 111(b) standards of
performance for new, modified, and reconstructed EGUs, several
commenters provided information on various options that may be
available to improve the efficiency of existing natural gas-fired
stationary combustion turbines. See 80 FR 64620. Commenters--including
turbine manufacturers--described specific technology upgrades for the
compressor, combustor, and gas turbine components that operators of
existing combustion turbines may deploy. These state-of-the-art gas
path upgrades, software upgrades, and combustor upgrades can reduce GHG
emissions by a significant amount. In addition, one turbine
manufacturer stated that existing combustion turbines can achieve the
largest efficiency improvements by upgrading existing compressors with
more advanced compressor technologies, potentially improving the
combustion turbine's efficiency by an additional margin. See 80 FR
64620.
    In addition to upgrades to the combustion turbine, the operator of
a natural gas combined cycle (NGCC) unit will have the opportunity to
improve the efficiency of the heat recovery steam generator and steam
cycle using retrofit technologies that may reduce the GHG emissions by
1.5 to 3 percent. These include (1) steam path upgrades that can
minimize aerodynamic and steam leakage losses; (2) replacement of the
existing high pressure turbine stages with state-of-the-art stages
capable of extracting more energy from the same steam supply; and (3)
replacement of low-pressure turbine stages with larger diameter
components that extract additional energy and that reduce velocities,
wear, and corrosion.
    The EPA seeks comment on the broad availability and applicability
of any heat rate (efficiency) improvements for natural gas combustion
turbine EGUs including, but not limited to, those discussed in this
ANPRM. We also seek comment on the Agency's previous determination that
the available GHG emission reduction opportunities would likely provide
only small overall GHG reductions as compared to those from heat rate
improvements at existing coal-fired EGUs. See 80 FR 64756.

C. Other Available Systems of GHG Emission Reduction

1. Broad Solicitation of Information on Other Available Systems of GHG
Emission Reduction
    The EPA is interested in obtaining information on any other systems
of GHG emission reductions that may be available for consideration as
the BSER for existing fossil fuel-fired EGUs. The EPA is also
interested in obtaining information on available systems of emission
reduction that may not meet the criteria for consideration as the BSER
(because, for example, they may not be broadly applicable), but are

emission reduction options that may be considered as compliance options
for individual units.
    The Agency solicits information on any system of emission reduction
that commenters believe to be available and applicable for reducing
emissions of GHG from existing fossil fuel-fired steam-generating EGUs
(e.g., utility boilers and integrated gasification combined cycle
(IGCC) units) and/or combustion turbines (e.g., NGCC units). The Agency
seeks information on all aspects of the systems of emission reduction--
including the availability, applicability, technical feasibility, and
the cost of any such systems of emission reduction. The EPA also seeks
information on any limitations to the application of systems of
emission reduction. In particular, the Agency is interested in whether
there are geographic limitations to the applicability of suggested
emission reduction systems. The Agency also notes that the current
fleet of existing EGUs is quite diverse in terms of generating
technology, size, location, age, fuel usage, and configuration. The EPA
is interested in obtaining information on any limitations on the use of
emission reduction systems that are due to the diverse nature of the
existing fleet of EGUs. For example, are any potential emission
reduction systems limited by geographic location? Are any potential
systems of emission reduction limited to use with only certain fossil
fuels or certain coal types?
2. Carbon Capture and Storage (CCS) \14\
---------------------------------------------------------------------------

    \14\ 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 (for example
in enhanced oil recovery) before ultimate storage. In this document,
we consider these terms to be interchangeable.
---------------------------------------------------------------------------

    The EPA has previously determined that CCS (or partial CCS) should
not be a part of the BSER for existing fossil fuel-fired EGUs because
it was significantly more expensive than alternative options for
reducing emissions. See 80 FR 64756. The EPA continues to believe that
neither CCS nor partial CCS are technologies that can be considered as
the BSER for existing fossil fuel-fired EGUs. However, if there is any
new information regarding the availability, applicability, or technical
feasibility of CCS technologies, commenters are encouraged to provide
that information to the EPA.
    The Agency recognizes that some companies may be interested in
using CCS technology as a compliance option--especially when they are
able to use the captured CO2 in enhanced oil recovery
operations (e.g., the W. A. Parish Plant in Texas). The EPA solicits
information on how potentially affected EGUs may utilize retrofit CCS
technology as a compliance option to reduce CO2 emissions
and whether those EGUs should be allowed to participate in any
intrastate or interstate trading program. The Agency also seeks
information on the appropriate level of monitoring, recordkeeping, and
reporting that should be required for sequestered CO2 in
such cases. In the final new source performance standards issued under
CAA section 111(b), the EPA requires new fossil fuel-fired EGUs to
limit CO2 emissions and identifies partial CCS as one of the
compliance options. In that final rule, any new affected EGU that uses
CCS to meet the applicable CO2 emission limit must report in
accordance with 40 CFR part 98, subpart PP (Suppliers of Carbon
Dioxide), and the captured CO2 must be injected at a
facility or facilities that reports in accordance with 40 CFR part 98,
subpart RR (Geologic Sequestration of Carbon Dioxide). See 80 FR 64654
and 40 CFR 60.5555(f). Together, these requirements ensure that the
amount of captured and sequestered CO2 will be tracked as
appropriate at project and national levels and that the status of the
CO2 in its geologic storage site will be monitored,
including air-side monitoring and reporting. The EPA solicits comment
on this approach and other alternatives that may be used when utilizing
CCS as a compliance option for meeting emission reduction requirements
in a state plan.

D. EGU Source Categories and Subcategories

1. Applicability Criteria
    The EPA has specified that an affected EGU is any existing fossil
fuel-fired electric utility steam generating unit (i.e., utility boiler
or IGCC unit) or stationary combustion turbine that meets specific
criteria. An affected EGU (either steam generating or stationary
combustion turbine) must serve a generator capable of selling more than
25 megawatts to a utility power distribution system and have a base
load heat input rating greater than 250 million Btu per hour. An
affected stationary combustion turbine EGU must meet the definition of
a combined cycle (i.e., NGCC) or combined heat and power combustion
turbine. The EPA has also specifically exempted certain EGUs from
applicability, including simple cycle turbines, certain non-fossil
units, and certain combined heat and power units. See 80 FR 64716. The
EPA solicits comment on applicability criteria in a potential new rule
and whether the Agency should retain the criteria and exemptions
previously set forth.
2. Subcategories
    CAA section 111 requires the EPA first to list source categories
that may reasonably be expected to endanger public health or welfare
and then to regulate new sources within each of those source
categories. CAA section 111(d)(1) is silent on whether the EPA may
establish subcategories for existing sources, but the EPA has
interpreted this provision to authorize the EPA to exercise discretion
as to whether and, if so, how to subcategorize existing sources subject
to CAA section 111(d). Further, the implementing regulations under CAA
section 111(d) provide that the Administrator will specify different
emission guidelines or compliance times or both ``for different sizes,
types, and classes of designated facilities when costs of the control,
physical limitations, geographical location, or similar factors make
subcategorization appropriate.'' \15\
---------------------------------------------------------------------------

    \15\ 40 CFR 60.22(b)(5).
---------------------------------------------------------------------------

    In previous rulemakings, the EPA has promulgated presumptive EGU-
related emission standards for subcategories of sources. For example,
the EPA has issued separate NSPS for sulfur dioxide (SO2)
and nitrogen oxide (NOx) emissions from EGUs that utilize coal refuse
as a subcategory of steam generating EGUs that utilize coal or other
fossil fuel. See 77 FR 9423. The EPA has also promulgated separate
standards of performance that distinguish between stationary combustion
turbines that operate to serve intermediate and baseload power demand
as opposed to those that operate to serve peak power demand. The EPA
has also issued separate standards based on coal-type. For example, in
the Mercury and Air Toxics Standards (MATS), promulgated under CAA
section 112(d)(1),\16\ the Agency issued separate mercury emission
standards for coal-fired EGUs that use lignite versus those that use
non-lignite coal. The Agency, also in the MATS rule, promulgated
separate emission standards for IGCC EGUs as compared to the standards
issued for utility boilers. See 77 FR 9487. The Agency solicits comment
on whether potentially affected EGU sources (e.g., steam generating
EGUs, stationary combustion turbines) should be grouped into

categories and subcategories for purposes of identifying the BSER.
Commenters are requested to provide justification for such
subcategorization. For example, are emissions and emission reduction
opportunities distinct for EGUs of different sizes, classes, or types--
or for EGUs utilizing different types or qualities of fossil fuels? The
EPA requests comment on subcategorization based on operation or
utilization of the EGU--i.e., based on whether the EGU (whether a
utility boiler, an IGCC unit, or a stationary combustion turbine) is
operated to serve baseload, intermediate, or peak power demand.
---------------------------------------------------------------------------

    \16\ CAA section 112(d)(1) provides that ``The Administrator may
distinguish among classes, types, and sizes of sources within a
category or subcategory in establishing such standards . . . .''
---------------------------------------------------------------------------

V. Potential Interactions with Other Regulatory Programs

A. New Source Review (NSR)

    The NSR program is a preconstruction permitting program that
requires stationary sources of air pollution to obtain permits prior to
beginning construction. The NSR program applies both to new
construction and to modifications of existing sources. New construction
and modifications that emit air pollutants over certain thresholds are
subject to major NSR requirements, while smaller emitting sources and
modifications may be subject to minor NSR requirements.\17\ Major NSR
permits for sources in attainment areas and for other pollutants
regulated under the major source program are referred to as prevention
of significant deterioration (PSD) permits, while major NSR permits for
sources emitting nonattainment pollutants and located in nonattainment
areas are referred to as nonattainment NSR (NNSR) permits.
---------------------------------------------------------------------------

    \17\ Major sources and certain other sources are also required
by the CAA to obtain title V operating permits. While title V
permits generally do not establish new emissions limits, they
consolidate requirements under the CAA into a comprehensive air
permit.
---------------------------------------------------------------------------

    Since emission guidelines that are established pursuant to CAA
section 111(d) apply to units at existing sources, the interaction
between CAA section 111(d) and the NSR program primarily centers around
the treatment of modifications of existing sources. Generally, a major
stationary source triggers major NSR permitting requirements when it
undertakes a physical or operational change that would result in (1) a
significant emission increase at the emissions unit, and (2) a
significant net emissions increase at the source (i.e., a source-wide
``netting'' analysis that considers emission increases and decreases
occurring at the source during a contemporaneous period). See, e.g., 40
CFR 52.21(b)(2)(i). NSR regulations define what emissions rate on an
annual tonnage basis constitutes ``significant'' for NSR pollutants.
See, e.g., 40 CFR 52.21(b)(23).\18\ For example, an increase in
emissions is ``significant'' for NOX when it is at least 40
tons per year. To calculate the emissions increase from a project, the
``projected actual emissions'' (PAE) are compared to the ``baseline
actual emissions'' (BAE). For EGUs, the PAE is the maximum annual rate
(tons per year) that the modified unit is projected to emit a pollutant
in any one of the 5 years (or 10 years if the design capacity
increases) after the project, excluding any increase in emissions that
(1) is unrelated to the project, and (2) could have been accommodated
during the baseline period (commonly referred to as the ``demand growth
exclusion''). The BAE for an EGU is the average annual rate of actual
emissions during any 2-year period within the last 5 years.
---------------------------------------------------------------------------

    \18\ In the case of GHGs, EPA regulations currently do not have
a ``significant'' emissions rate. Under existing regulations, a
major source would trigger PSD permitting requirements for GHG if it
undergoes a modification that results in a significant increase in
the emissions of a pollutant other than GHGs and a GHG emissions
increase of 75,000 tons per year of carbon dioxide equivalent
(CO2e) as well as a GHG emissions increase (i.e.,
anything above zero) on a mass basis. In proposing a significant
emissions rate for GHG, the EPA has proposed to remove the mass-
based component of the NSR emissions test for GHG. See 81 FR 68110
(October 3, 2016). Furthermore, in UARG v. EPA, 134 S. Ct. 2427
(June 23, 2014), the U.S. Supreme Court held that an increase in GHG
emissions alone cannot by law trigger the NSR requirements of the
PSD program under section 165 of the CAA. Thus, unlike other NSR
pollutants, a modification that increases only GHG emissions above
the applicable level will not trigger the requirement to obtain a
PSD permit.
---------------------------------------------------------------------------

    If a physical or operational change triggers the requirements of
the major NSR program, the source must obtain a permit prior to making
the change. The pollutant(s) at issue and the air quality designation
of the area where the facility is located or proposed to be built
determine the specific permitting requirements. The CAA requires
sources to meet emission limits based on Best Available Control
Technology (BACT) for PSD permits and Lowest Achievable Emissions Rate
(LAER) for NNSR permits. CAA sections 165(a)(4), 173(a)(2). These
technology requirements for major NSR permits are not predetermined by
a rule or state plan, but are case-specific decisions made by the
permitting agency. Other requirements to obtain a major NSR permit vary
depending on whether it is a PSD or NNSR permit and a State or a
federal permit action.
    New sources and modifications that do not require a major NSR
permit generally require a minor NSR permit prior to construction.
Minor NSR permits are almost exclusively issued by state and local air
agencies, and since the CAA is less prescriptive regarding requirements
for these permits, agencies have more flexibility to design their own
programs.
    The EPA's regulations offer flexible permitting approaches that
enable sources undergoing modifications to avoid triggering major NSR.
In the case of Plantwide Applicability Limits (PALs), a source that
plans to make modifications to its emission units can avoid major NSR
requirements as long as it obtains a PAL permit and operates within the
source-wide emissions cap of the PAL. See, e.g., 40 CFR 52.21(aa). In
addition, sources can take enforceable limits on hours of operation in
order to avoid triggering major NSR requirements that would otherwise
apply to the source. Specifically, a source may voluntarily obtain a
synthetic minor source limitation--i.e., a legally and practicably
enforceable restriction that has the effect of limiting emissions below
the relevant major source level--to avoid triggering major NSR
requirements.
    Over the years, some stakeholders have expressed concerns that NSR
regulations do not adequately allow for some sources to undertake
changes to improve their operational efficiency without being
``penalized'' by having to get a major NSR permit. In the context of
EGUs, stakeholders have asserted that heat rate improvement projects
could result in greater unit availability and increase in dispatching,
which under the NSR program might translate into projected increases in
emissions that trigger major NSR permitting. Stakeholders have raised
similar concerns regarding modifying an EGU facility to enable co-
firing of natural gas or other lower-emitting fuels.
    The EPA received a number of similarly focused comments following
proposal of the CPP. Specifically, commenters contended that, if an air
agency, as part of its plan to comply with emission guidelines
established pursuant to CAA section 111(d), requires a source to make
modifications (e.g., heat rate improvement projects), it could
potentially trigger major NSR requirements. Commenters added that the
EPA has previously taken enforcement action against sources making such
modifications without getting a major NSR permit.
    Since this ANPRM solicits input on a possible rule that is based on
actions that could be implemented at the level

of an individual source, we are again inviting comment from interested
stakeholders on the topic of how the NSR program overlays with emission
guidelines established under CAA section 111(d). We are interested in
actions that can be taken to harmonize and streamline the NSR
applicability and/or the NSR permitting process with a potential new
rule. We invite comment on the following questions:

    1. Under what scenarios would EGUs be potentially subject to the
requirements of the NSR program as a result of making physical or
operational changes that are part of a strategy for regulating
existing sources under CAA section 111(d)? Do the scenarios differ
depending on site specific factors, such as the size or class of
EGU, how the EGU operates (e.g., baseload, intermediate, load
following), fuel(s) the EGU burns, or the EGU's existing level of
pollution control? If so, please explain the differences.
    2. What rule or policy changes or flexibilities can the EPA
provide as part of the NSR program that would enable EGUs to
implement projects required under a CAA section 111(d) plan and not
trigger major NSR permitting while maintaining environmental
protections?
    3. What actions can sources take--e.g., through the minor NSR
program, agreeing to a PAL--when making heat rate improvements or
co-firing with a lower emitting fuel that would allow them to
continue to serve the demand of the grid while not having excessive
permitting requirements?
    4. What approaches could be used in crafting CAA section 111(d)
plans so as to reduce the number of existing sources that will be
subject to NSR permitting? Do compliance measures, such as inter-
and intra-state trading systems, rate-based or mass-based standards,
or generation shifting to lower- or zero-emitting units, offer
favorable solutions for air agencies and sources with regard to NSR
permitting?
    5. What other approaches would minimize the impact of the NSR
program on the implementation of a performance standard for EGU
sources under CAA section 111(d)?

B. New Source Performance Standards (NSPS)

    The EPA solicits comment on whether there are any potential
interactions between a state-based program under CAA section 111(d)
covering existing fossil fuel-fired EGUs and a federal program under
CAA section 111(b) covering newly constructed, reconstructed, and
modified fossil fuel-fired EGUs. In particular, the EPA requests
information on how an existing EGU covered under a CAA section 111(d)
state plan might affect the state plan (or an interstate trading
program) if the EGU undergoes a reconstruction or modification (as
defined under CAA 111(b)).

VI. Statutory and Executive Order Reviews

    Under Executive Order 12866, titled Regulatory Planning and Review
(58 FR 51735, October 4, 1993), this is a ``significant regulatory
action.'' Accordingly, the EPA submitted this action to the Office of
Management and Budget (OMB) for review under Executive Order 12866 and
any changes made in response to OMB recommendations have been
documented in the docket for this action. Because this action does not
propose or impose any requirements, and instead seeks comments and
suggestions for the Agency to consider in possibly developing a
subsequent proposed rule, the various statutes and Executive Orders
that normally apply to rulemaking do not apply in this case. Should the
EPA subsequently determine to pursue a rulemaking, the EPA will address
the statutes and Executive Orders as applicable to that rulemaking.

    Dated: December 18, 2017.
E. Scott Pruitt,
Administrator.
[FR Doc. 2017-27793 Filed 12-27-17; 8:45 am]
 BILLING CODE 6560-50-P


Facility, POTW, and Reach Information ( fac_ info. sd2)

MP& M facility information including POTW discharged to ( if an indirect discharger) and the receiving RF1 reach along with the receiving reach's characteristics.

Data Element Definitions SITEID  Facility site identification number ( CBI: these have been masked) POTW_ NPD  NPDES number for the receiving POTW ( CBI: these have been masked) POTWFLOW  POTW flow in millions of gallons per year DISCHARG  Facility discharge type ( indirect or direct) SURVEY  Survey phase or industry type from which facility data was obtained REACHNMB  RF1 reach number for the receiving reach ( CBI: these have been masked) TYPE  RF1 reach type TYPE_ DES  Description of the RF1 reach type SEGL  Length of the RF1 reach segment in miles MFVEL  Mean flow velocity for the RF1 reach MNFLO  Mean flow volume for the RF1 reach in ft3/ sec SVTEN  Seven Q ten flow volume for the RF1 reach NSTCO  Number of counties through which the reach flows STCO1  County fips code through which the RF1 reach flows STCO2  County fips code through which the RF1 reach flows STCO3  County fips code through which the RF1 reach flows STCO4  County fips code through which the RF1 reach flows STCO5  County fips code through which the RF1 reach flows STCO6  County fips code through which the RF1 reach flows STCO7  County fips code through which the RF1 reach flows STCO8  County fips code through which the RF1 reach flows ACUTE  Acute dilution factor CHRONIC  Chronic dilution factor DCP  Estuarine dissolved concentration potential WBTYPE  Water body type SURFACE  Surface area of lake DRAINAGE  Drainage area of lake VOLUME  Volume of lake