Emergency Application — Electric Generators for a Sensible Transition, Applicant v. Environmental Protection Agency, et al.
Supreme Court briefJul 26, 2024
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TABLE OF CONTENTS
APPENDIX A
Order Denying Stay, West Virginia v. EPA,
No. 24-1120 (D.C. Cir. July 19, 2024) ..............................................................App.1
APPENDIX B
42 U.S.C. §7411 .................................................................................................App.4
APPENDIX C
Declarations:
Exhibit A - Declaration of Matthew B. Ballew .........................................App.11
Exhibit B - Declaration of Christian T. Beam ..........................................App.24
Exhibit C - Declaration of John T. Bridson...............................................App.52
Exhibit D - Declaration of J. Michael Brown ............................................App.86
Exhibit E - Declaration of John R. Crockett III ......................................App.125
Exhibit F - Declaration of Kevin M. Gaden ............................................App.142
Exhibit G - Declaration of Alex Glenn ....................................................App.152
Exhibit H - Declaration of Julia S. Janson .............................................App.165
Exhibit I - Declaration of William A. Johnson ........................................App.176
Exhibit J - Declaration of Todd Komaromy ............................................App.189
Exhibit K - Declaration of Tim Lafser.....................................................App.206
Exhibit L - Declaration of Dale E. Lebsack, Jr. .....................................App.401
Exhibit M - Declaration of Jacob Williams .............................................App.414
APPENDIX A
USCA Case #24-1120
Document #2065493
Filed: 07/19/2024
Page 1 of 3
United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
____________
No. 24-1120
September Term, 2023
EPA-89FR39798
Filed On: July 19, 2024
State of West Virginia, et al.,
Petitioners
v.
Environmental Protection Agency and
Michael S. Regan, Administrator, United
States Environmental Protection Agency,
Respondents
-----------------------------Louisiana Public Service Commission, et al.,
Intervenors
-----------------------------Consolidated with 24-1121, 24-1122,
24-1124, 24-1126, 24-1128, 24-1142,
24-1143, 24-1144, 24-1146, 24-1152,
24-1153, 24-1155, 24-1222, 24-1226,
24-1227, 24-1233
BEFORE:
Millett, Pillard, and Rao, Circuit Judges
ORDER
Upon consideration of the motions for stay, the oppositions thereto, the replies,
the Rule 28(j) letter, and the responses thereto; and the motions to participate as amici
curiae and the lodged amicus briefs, it is
ORDERED that the motions of the Chamber of Commerce, the Sierra Club, the
Environmental Defense Fund, and Professor Rachel Rothschild to participate as amici
curiae be granted. The Clerk is directed to file the lodged amicus briefs. It is
App.1
USCA Case #24-1120
Document #2065493
Filed: 07/19/2024
Page 2 of 3
United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
____________
No. 24-1120
September Term, 2023
FURTHER ORDERED that the motions for stay be denied. Petitioners have not
satisfied the stringent requirements for a stay pending this court’s review. See Nken v.
Holder, 556 U.S. 418, 434 (2009); D.C. CIRCUIT HANDBOOK OF PRAC. AND INTERNAL
PROCS. 33 (2021).
On the merits, petitioners dispute whether the Environmental Protection Agency
(“EPA”) acted arbitrarily or capriciously in determining that carbon capture and other
emission control technologies are adequately demonstrated, or that specific degrees of
emission mitigation are achievable with those technologies. But petitioners have not
shown they are likely to succeed on those claims given the record in this case. Nor
does this case implicate a major question under West Virginia v. EPA, 142 S. Ct. 2587
(2022), because EPA has claimed only the power to “set emissions limits under Section
111 based on the application of measures that would reduce pollution by causing the
regulated source to operate more cleanly[,]” a type of conduct that falls well within
EPA’s bailiwick, id. at 2610.
On irreparable harm, actual compliance deadlines do not commence until 2030
or 2032—years after this case will be resolved. Though the first deadline for States to
submit state implementation plans is May 2026, the only consequence of failing to
submit a state plan is the promulgation of a federal plan—which the States can replace
with their own plans later. EPA Opp., Ex. 1, Goffman Decl. ¶ 100. To the extent
petitioners claim harm due to the need for long-term planning, a stay will not help
because the risk remains that the distant deadlines in EPA’s rule will come back into
force at the end of the case.
EPA has suggested that this case be expedited as an alternative means of
protecting all parties’ interests. Accordingly, to ensure this case can be argued and
considered as early as possible in the court's 2024 term, it is
FURTHER ORDERED that the parties submit, within 14 days from the date of
this order, proposed formats and schedules for the briefing of these cases. The parties
are strongly urged to submit a joint proposal and are reminded that the court looks with
extreme disfavor on repetitious submissions and will, where appropriate, require a joint
brief of aligned parties with total words not to exceed the standard allotment for a single
brief. Whether the parties are aligned or have disparate interests, they must provide
detailed justifications for any request to file separate briefs or to exceed in the
Page 2
App.2
USCA Case #24-1120
Document #2065493
Filed: 07/19/2024
Page 3 of 3
United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
____________
No. 24-1120
September Term, 2023
aggregate the standard word allotment. Requests to exceed the standard word
allotment must specify the word allotment necessary for each issue.
Per Curiam
FOR THE COURT:
Mark J. Langer, Clerk
BY:
Page 3
App.3
/s/
Selena R. Gancasz
Deputy Clerk
APPENDIX B
Page 6239
TITLE 42—THE PUBLIC HEALTH AND WELFARE
Pub. L. 95–95, § 107(b), added subsec. (g) relating to
Governor’s authority to issue temporary emergency
suspensions.
Subsec. (h). Pub. L. 95–190, § 14(a)(5), redesignated subsec. (g), added by Pub. L. 95–95, § 108(g), as (h). Former
subsec. (h) redesignated (i).
Subsec. (i). Pub. L. 95–190, § 14(a)(5), redesignated subsec. (h), added by Pub. L. 95–95, § 108(g), as (i). Former
subsec. (i) redesignated (j) and amended.
Subsec. (j). Pub. L. 95–190 § 14(a)(5), (6), redesignated
subsec. (i), added by Pub. L. 95–95, § 108(g), as (j) and in
subsec. (j) as so redesignated, substituted ‘‘will enable
such source’’ for ‘‘at such source will enable it’’.
1974—Subsec. (a)(3). Pub. L. 93–319, § 4(a), designated
existing provisions as subpar. (A) and added subpar. (B).
Subsec. (c). Pub. L. 93–319, § 4(b), designated existing
provisions as par. (1) and existing pars. (1), (2), and (3)
as subpars. (A), (B), and (C), respectively, of such redesignated par. (1), and added par. (2).
EFFECTIVE DATE OF 1977 AMENDMENT
Amendment by Pub. L. 95–95 effective Aug. 7, 1977, except as otherwise expressly provided, see section 406(d)
of Pub. L. 95–95, set out as a note under section 7401 of
this title.
PENDING ACTIONS AND PROCEEDINGS
Suits, actions, and other proceedings lawfully commenced by or against the Administrator or any other
officer or employee of the United States in his official
capacity or in relation to the discharge of his official
duties under act July 14, 1955, the Clean Air Act, as in
effect immediately prior to the enactment of Pub. L.
95–95 [Aug. 7, 1977], not to abate by reason of the taking
effect of Pub. L. 95–95, see section 406(a) of Pub. L.
95–95, set out as an Effective Date of 1977 Amendment
note under section 7401 of this title.
MODIFICATION OR RESCISSION OF RULES, REGULATIONS,
ORDERS,
DETERMINATIONS,
CONTRACTS,
CERTIFICATIONS, AUTHORIZATIONS, DELEGATIONS, AND OTHER
ACTIONS
All rules, regulations, orders, determinations, contracts, certifications, authorizations, delegations, or
other actions duly issued, made, or taken by or pursuant to act July 14, 1955, the Clean Air Act, as in effect
immediately prior to the date of enactment of Pub. L.
95–95 [Aug. 7, 1977] to continue in full force and effect
until modified or rescinded in accordance with act July
14, 1955, as amended by Pub. L. 95–95 [this chapter], see
section 406(b) of Pub. L. 95–95, set out as an Effective
Date of 1977 Amendment note under section 7401 of this
title.
MODIFICATION OR RESCISSION OF IMPLEMENTATION
PLANS APPROVED AND IN EFFECT PRIOR TO AUG. 7,
1977
Nothing in the Clean Air Act Amendments of 1977
[Pub. L. 95–95] to affect any requirement of an approved
implementation plan under this section or any other
provision in effect under this chapter before Aug. 7,
1977, until modified or rescinded in accordance with
this chapter as amended by the Clean Air Act Amendments of 1977, see section 406(c) of Pub. L. 95–95, set out
as an Effective Date of 1977 Amendment note under section 7401 of this title.
SAVINGS PROVISION
Section 16 of Pub. L. 91–604 provided that:
‘‘(a)(1) Any implementation plan adopted by any
State and submitted to the Secretary of Health, Education, and Welfare, or to the Administrator pursuant
to the Clean Air Act [this chapter] prior to enactment
of this Act [Dec. 31, 1970] may be approved under section 110 of the Clean Air Act [this section] (as amended
by this Act) [Pub. L. 91–604] and shall remain in effect,
unless the Administrator determines that such implementation plan, or any portion thereof, is not consistent with applicable requirements of the Clean Air Act
§ 7411
[this chapter] (as amended by this Act) and will not
provide for the attainment of national primary ambient air quality standards in the time required by such
Act. If the Administrator so determines, he shall, within 90 days after promulgation of any national ambient
air quality standards pursuant to section 109(a) of the
Clean Air Act [section 7409(a) of this title], notify the
State and specify in what respects changes are needed
to meet the additional requirements of such Act, including requirements to implement national secondary
ambient air quality standards. If such changes are not
adopted by the State after public hearings and within
six months after such notification, the Administrator
shall promulgate such changes pursuant to section
110(c) of such Act [subsec. (c) of this section].
‘‘(2) The amendments made by section 4(b) [amending
sections 7403 and 7415 of this title] shall not be construed as repealing or modifying the powers of the Administrator with respect to any conference convened
under section 108(d) of the Clean Air Act [section 7415
of this title] before the date of enactment of this Act
[Dec. 31, 1970].
‘‘(b) Regulations or standards issued under this title
II of the Clean Air Act [subchapter II of this chapter]
prior to the enactment of this Act [Dec. 31, 1970] shall
continue in effect until revised by the Administrator
consistent with the purposes of such Act [this chapter].’’
FEDERAL ENERGY ADMINISTRATOR
‘‘Federal Energy Administrator’’, for purposes of this
chapter, to mean Administrator of Federal Energy Administration established by Pub. L. 93–275, May 7, 1974,
88 Stat. 97, which is classified to section 761 et seq. of
Title 15, Commerce and Trade, but with the term to
mean any officer of the United States designated as
such by the President until Federal Energy Administrator takes office and after Federal Energy Administration ceases to exist, see section 798 of Title 15, Commerce and Trade.
Federal Energy Administration terminated and functions vested by law in Administrator thereof transferred to Secretary of Energy (unless otherwise specifically provided) by sections 7151(a) and 7293 of this title.
§ 7411. Standards of performance for new stationary sources
(a) Definitions
For purposes of this section:
(1) The term ‘‘standard of performance’’
means a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of
the best system of emission reduction which
(taking into account the cost of achieving
such reduction and any nonair quality health
and environmental impact and energy requirements) the Administrator determines has been
adequately demonstrated.
(2) The term ‘‘new source’’ means any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under this section which will be applicable to such source.
(3) The term ‘‘stationary source’’ means any
building, structure, facility, or installation
which emits or may emit any air pollutant.
Nothing in subchapter II of this chapter relating to nonroad engines shall be construed to
apply to stationary internal combustion engines.
(4) The term ‘‘modification’’ means any
physical change in, or change in the method of
App.4
§ 7411
TITLE 42—THE PUBLIC HEALTH AND WELFARE
operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the
emission of any air pollutant not previously
emitted.
(5) The term ‘‘owner or operator’’ means any
person who owns, leases, operates, controls, or
supervises a stationary source.
(6) The term ‘‘existing source’’ means any
stationary source other than a new source.
(7) The term ‘‘technological system of continuous emission reduction’’ means—
(A) a technological process for production
or operation by any source which is inherently low-polluting or nonpolluting, or
(B) a technological system for continuous
reduction of the pollution generated by a
source before such pollution is emitted into
the ambient air, including precombustion
cleaning or treatment of fuels.
(8) A conversion to coal (A) by reason of an
order under section 2(a) of the Energy Supply
and Environmental Coordination Act of 1974
[15 U.S.C. 792(a)] or any amendment thereto,
or any subsequent enactment which supersedes such Act [15 U.S.C. 791 et seq.], or (B)
which qualifies under section 7413(d)(5)(A)(ii) 1
of this title, shall not be deemed to be a modification for purposes of paragraphs (2) and (4)
of this subsection.
(b) List of categories of stationary sources;
standards of performance; information on
pollution control techniques; sources owned
or operated by United States; particular systems; revised standards
(1)(A) The Administrator shall, within 90 days
after December 31, 1970, publish (and from time
to time thereafter shall revise) a list of categories of stationary sources. He shall include a
category of sources in such list if in his judgment it causes, or contributes significantly to,
air pollution which may reasonably be anticipated to endanger public health or welfare.
(B) Within one year after the inclusion of a
category of stationary sources in a list under
subparagraph (A), the Administrator shall publish proposed regulations, establishing Federal
standards of performance for new sources within
such category. The Administrator shall afford
interested persons an opportunity for written
comment on such proposed regulations. After
considering such comments, he shall promulgate, within one year after such publication,
such standards with such modifications as he
deems appropriate. The Administrator shall, at
least every 8 years, review and, if appropriate,
revise such standards following the procedure
required by this subsection for promulgation of
such standards. Notwithstanding the requirements of the previous sentence, the Administrator need not review any such standard if the
Administrator determines that such review is
not appropriate in light of readily available information on the efficacy of such standard.
Standards of performance or revisions thereof
shall become effective upon promulgation. When
implementation and enforcement of any requirement of this chapter indicate that emission lim1 See References in Text note below.
Page 6240
itations and percent reductions beyond those required by the standards promulgated under this
section are achieved in practice, the Administrator shall, when revising standards promulgated under this section, consider the emission
limitations and percent reductions achieved in
practice.
(2) The Administrator may distinguish among
classes, types, and sizes within categories of new
sources for the purpose of establishing such
standards.
(3) The Administrator shall, from time to
time, issue information on pollution control
techniques for categories of new sources and air
pollutants subject to the provisions of this section.
(4) The provisions of this section shall apply to
any new source owned or operated by the United
States.
(5) Except as otherwise authorized under subsection (h) of this section, nothing in this section shall be construed to require, or to authorize the Administrator to require, any new or
modified source to install and operate any particular technological system of continuous
emission reduction to comply with any new
source standard of performance.
(6) The revised standards of performance required by enactment of subsection (a)(1)(A)(i)
and (ii) 1 of this section shall be promulgated not
later than one year after August 7, 1977. Any
new or modified fossil fuel fired stationary
source which commences construction prior to
the date of publication of the proposed revised
standards shall not be required to comply with
such revised standards.
(c) State implementation and enforcement of
standards of performance
(1) Each State may develop and submit to the
Administrator a procedure for implementing
and enforcing standards of performance for new
sources located in such State. If the Administrator finds the State procedure is adequate, he
shall delegate to such State any authority he
has under this chapter to implement and enforce
such standards.
(2) Nothing in this subsection shall prohibit
the Administrator from enforcing any applicable
standard of performance under this section.
(d) Standards of performance for existing
sources; remaining useful life of source
(1) The Administrator shall prescribe regulations which shall establish a procedure similar
to that provided by section 7410 of this title
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 (i) for which air quality criteria have not been issued or which is not included on a list published under section 7408(a)
of this title or emitted from a source category
which is regulated under section 7412 of this
title but (ii) 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. Regulations of the
Administrator under this paragraph shall permit the State in applying a standard of performance to any particular source under a plan sub-
App.5
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TITLE 42—THE PUBLIC HEALTH AND WELFARE
mitted under this paragraph to take into consideration, among other factors, the remaining useful life of the existing source to which such
standard applies.
(2) The Administrator shall have the same authority—
(A) to prescribe a plan for a State in cases
where the State fails to submit a satisfactory
plan as he would have under section 7410(c) of
this title in the case of failure to submit an
implementation plan, and
(B) to enforce the provisions of such plan in
cases where the State fails to enforce them as
he would have under sections 7413 and 7414 of
this title with respect to an implementation
plan.
In promulgating a standard of performance
under a plan prescribed under this paragraph,
the Administrator shall take into consideration,
among other factors, remaining useful lives of
the sources in the category of sources to which
such standard applies.
(e) Prohibited acts
After the effective date of standards of performance promulgated under this section, it
shall be unlawful for any owner or operator of
any new source to operate such source in violation of any standard of performance applicable
to such source.
(f) New source standards of performance
(1) For those categories of major stationary
sources that the Administrator listed under subsection (b)(1)(A) of this section before November
15, 1990, and for which regulations had not been
proposed by the Administrator by November 15,
1990, the Administrator shall—
(A) propose regulations establishing standards of performance for at least 25 percent of
such categories of sources within 2 years after
November 15, 1990;
(B) propose regulations establishing standards of performance for at least 50 percent of
such categories of sources within 4 years after
November 15, 1990; and
(C) propose regulations for the remaining
categories of sources within 6 years after November 15, 1990.
(2) In determining priorities for promulgating
standards for categories of major stationary
sources for the purpose of paragraph (1), the Administrator shall consider—
(A) the quantity of air pollutant emissions
which each such category will emit, or will be
designed to emit;
(B) the extent to which each such pollutant
may reasonably be anticipated to endanger
public health or welfare; and
(C) the mobility and competitive nature of
each such category of sources and the consequent need for nationally applicable new
source standards of performance.
(3) Before promulgating any regulations under
this subsection or listing any category of major
stationary sources as required under this subsection, the Administrator shall consult with
appropriate representatives of the Governors
and of State air pollution control agencies.
(g) Revision of regulations
(1) Upon application by the Governor of a
State showing that the Administrator has failed
§ 7411
to specify in regulations under subsection (f)(1)
of this section any category of major stationary
sources required to be specified under such regulations, the Administrator shall revise such regulations to specify any such category.
(2) Upon application of the Governor of a
State, showing that any category of stationary
sources which is not included in the list under
subsection (b)(1)(A) of this section contributes
significantly to air pollution which may reasonably be anticipated to endanger public health or
welfare (notwithstanding that such category is
not a category of major stationary sources), the
Administrator shall revise such regulations to
specify such category of stationary sources.
(3) Upon application of the Governor of a State
showing that the Administrator has failed to
apply properly the criteria required to be considered under subsection (f)(2) of this section,
the Administrator shall revise the list under
subsection (b)(1)(A) of this section to apply properly such criteria.
(4) Upon application of the Governor of a State
showing that—
(A) a new, innovative, or improved technology or process which achieves greater continuous emission reduction has been adequately demonstrated for any category of stationary sources, and
(B) as a result of such technology or process,
the new source standard of performance in effect under this section for such category no
longer reflects the greatest degree of emission
limitation achievable through application of
the best technological system of continuous
emission reduction which (taking into consideration the cost of achieving such emission reduction, and any non-air quality health and
environmental impact and energy requirements) has been adequately demonstrated,
the Administrator shall revise such standard of
performance for such category accordingly.
(5) Unless later deadlines for action of the Administrator are otherwise prescribed under this
section, the Administrator shall, not later than
three months following the date of receipt of
any application by a Governor of a State, either—
(A) find that such application does not contain the requisite showing and deny such application, or
(B) grant such application and take the action required under this subsection.
(6) Before taking any action required by subsection (f) of this section or by this subsection,
the Administrator shall provide notice and opportunity for public hearing.
(h) Design, equipment, work practice, or operational standard; alternative emission limitation
(1) For purposes of this section, if in the judgment of the Administrator, it is not feasible to
prescribe or enforce a standard of performance,
he may instead promulgate a design, equipment,
work practice, or operational standard, or combination thereof, which reflects the best technological system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, and any non-
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§ 7411
TITLE 42—THE PUBLIC HEALTH AND WELFARE
air quality health and environmental impact
and energy requirements) the Administrator determines has been adequately demonstrated. In
the event the Administrator promulgates a design or equipment standard under this subsection, he shall include as part of such standard
such requirements as will assure the proper operation and maintenance of any such element of
design or equipment.
(2) For the purpose of this subsection, the
phrase ‘‘not feasible to prescribe or enforce a
standard of performance’’ means any situation
in which the Administrator determines that (A)
a pollutant or pollutants cannot be emitted
through a conveyance designed and constructed
to emit or capture such pollutant, or that any
requirement for, or use of, such a conveyance
would be inconsistent with any Federal, State,
or local law, or (B) the application of measurement methodology to a particular class of
sources is not practicable due to technological
or economic limitations.
(3) If after notice and opportunity for public
hearing, any person establishes to the satisfaction of the Administrator that an alternative
means of emission limitation will achieve a reduction in emissions of any air pollutant at
least equivalent to the reduction in emissions of
such air pollutant achieved under the requirements of paragraph (1), the Administrator shall
permit the use of such alternative by the source
for purposes of compliance with this section
with respect to such pollutant.
(4) Any standard promulgated under paragraph
(1) shall be promulgated in terms of standard of
performance whenever it becomes feasible to
promulgate and enforce such standard in such
terms.
(5) Any design, equipment, work practice, or
operational standard, or any combination thereof, described in this subsection shall be treated
as a standard of performance for purposes of the
provisions of this chapter (other than the provisions of subsection (a) of this section and this
subsection).
(i) Country elevators
Any regulations promulgated by the Administrator under this section applicable to grain elevators shall not apply to country elevators (as
defined by the Administrator) which have a
storage capacity of less than two million five
hundred thousand bushels.
(j) Innovative technological systems of continuous emission reduction
(1)(A) Any person proposing to own or operate
a new source may request the Administrator for
one or more waivers from the requirements of
this section for such source or any portion
thereof with respect to any air pollutant to encourage the use of an innovative technological
system or systems of continuous emission reduction. The Administrator may, with the consent of the Governor of the State in which the
source is to be located, grant a waiver under this
paragraph, if the Administrator determines
after notice and opportunity for public hearing,
that—
(i) the proposed system or systems have not
been adequately demonstrated,
(ii) the proposed system or systems will operate effectively and there is a substantial
Page 6242
likelihood that such system or systems will
achieve greater continuous emission reduction
than that required to be achieved under the
standards of performance which would otherwise apply, or achieve at least an equivalent
reduction at lower cost in terms of energy,
economic, or nonair quality environmental
impact,
(iii) the owner or operator of the proposed
source has demonstrated to the satisfaction of
the Administrator that the proposed system
will not cause or contribute to an unreasonable risk to public health, welfare, or safety in
its operation, function, or malfunction, and
(iv) the granting of such waiver is consistent
with the requirements of subparagraph (C).
In making any determination under clause (ii),
the Administrator shall take into account any
previous failure of such system or systems to
operate effectively or to meet any requirement
of the new source performance standards. In determining whether an unreasonable risk exists
under clause (iii), the Administrator shall consider, among other factors, whether and to what
extent the use of the proposed technological system will cause, increase, reduce, or eliminate
emissions of any unregulated pollutants; available methods for reducing or eliminating any
risk to public health, welfare, or safety which
may be associated with the use of such system;
and the availability of other technological systems which may be used to conform to standards
under this section without causing or contributing to such unreasonable risk. The Administrator may conduct such tests and may require
the owner or operator of the proposed source to
conduct such tests and provide such information
as is necessary to carry out clause (iii) of this
subparagraph. Such requirements shall include a
requirement for prompt reporting of the emission of any unregulated pollutant from a system
if such pollutant was not emitted, or was emitted in significantly lesser amounts without use
of such system.
(B) A waiver under this paragraph shall be
granted on such terms and conditions as the Administrator determines to be necessary to assure—
(i) emissions from the source will not prevent attainment and maintenance of any national ambient air quality standards, and
(ii) proper functioning of the technological
system or systems authorized.
Any such term or condition shall be treated as
a standard of performance for the purposes of
subsection (e) of this section and section 7413 of
this title.
(C) The number of waivers granted under this
paragraph with respect to a proposed technological system of continuous emission reduction
shall not exceed such number as the Administrator finds necessary to ascertain whether or
not such system will achieve the conditions
specified in clauses (ii) and (iii) of subparagraph
(A).
(D) A waiver under this paragraph shall extend
to the sooner of—
(i) the date determined by the Administrator, after consultation with the owner or
operator of the source, taking into consider-
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TITLE 42—THE PUBLIC HEALTH AND WELFARE
§ 7411
ation the design, installation, and capital cost
of the technological system or systems being
used, or
(ii) the date on which the Administrator determines that such system has failed to—
(I) achieve at least an equivalent continuous emission reduction to that required to
be achieved under the standards of performance which would otherwise apply, or
(II) comply with the condition specified in
paragraph (1)(A)(iii),
§ 701, Nov. 15, 1990, 104 Stat. 2672, and, as so amended,
subsec. (d) of section 7413 no longer relates to final
compliance orders.
Subsection (a)(1) of this section, referred to in subsec.
(b)(6), was amended generally by Pub. L. 101–549, title
VII, § 403(a), Nov. 15, 1990, 104 Stat. 2631, and, as so
amended, no longer contains subpars.
and that such failure cannot be corrected.
A prior section 111 of act July 14, 1955, was renumbered section 118 by Pub. L. 91–604 and is classified to
section 7418 of this title.
(E) In carrying out subparagraph (D)(i), the
Administrator shall not permit any waiver for a
source or portion thereof to extend beyond the
date—
(i) seven years after the date on which any
waiver is granted to such source or portion
thereof, or
(ii) four years after the date on which such
source or portion thereof commences operation,
whichever is earlier.
(F) No waiver under this subsection shall
apply to any portion of a source other than the
portion on which the innovative technological
system or systems of continuous emission reduction is used.
(2)(A) If a waiver under paragraph (1) is terminated under clause (ii) of paragraph (1)(D), the
Administrator shall grant an extension of the
requirements of this section for such source for
such minimum period as may be necessary to
comply with the applicable standard of performance under this section. Such period shall not
extend beyond the date three years from the
time such waiver is terminated.
(B) An extension granted under this paragraph
shall set forth emission limits and a compliance
schedule containing increments of progress
which require compliance with the applicable
standards of performance as expeditiously as
practicable and include such measures as are
necessary and practicable in the interim to minimize emissions. Such schedule shall be treated
as a standard of performance for purposes of
subsection (e) of this section and section 7413 of
this title.
(July 14, 1955, ch. 360, title I, § 111, as added Pub.
L. 91–604, § 4(a), Dec. 31, 1970, 84 Stat. 1683;
amended Pub. L. 92–157, title III, § 302(f), Nov. 18,
1971, 85 Stat. 464; Pub. L. 95–95, title I,
§ 109(a)–(d)(1), (e), (f), title IV, § 401(b), Aug. 7,
1977, 91 Stat. 697–703, 791; Pub. L. 95–190,
§ 14(a)(7)–(9), Nov. 16, 1977, 91 Stat. 1399; Pub. L.
95–623, § 13(a), Nov. 9, 1978, 92 Stat. 3457; Pub. L.
101–549, title I, § 108(e)–(g), title III, § 302(a), (b),
title IV, § 403(a), Nov. 15, 1990, 104 Stat. 2467, 2574,
2631.)
REFERENCES IN TEXT
Such Act, referred to in subsec. (a)(8), means Pub. L.
93–319, June 22, 1974, 88 Stat. 246, as amended, known as
the Energy Supply and Environmental Coordination
Act of 1974, which is classified principally to chapter
16C (§ 791 et seq.) of Title 15, Commerce and Trade. For
complete classification of this Act to the Code, see
Short Title note set out under section 791 of Title 15
and Tables.
Section 7413 of this title, referred to in subsec. (a)(8),
was amended generally by Pub. L. 101–549, title VII,
CODIFICATION
Section was formerly classified to section 1857c–6 of
this title.
PRIOR PROVISIONS
AMENDMENTS
1990—Subsec. (a)(1). Pub. L. 101–549, § 403(a), amended
par. (1) generally, substituting provisions defining
‘‘standard of performance’’ with respect to any air pollutant for provisions defining such term with respect to
subsec. (b) fossil fuel fired and other stationary sources
and subsec. (d) particular sources.
Subsec. (a)(3). Pub. L. 101–549, § 108(f), inserted at end
‘‘Nothing in subchapter II of this chapter relating to
nonroad engines shall be construed to apply to stationary internal combustion engines.’’
Subsec. (b)(1)(B). Pub. L. 101–549, § 108(e)(1), substituted ‘‘Within one year’’ for ‘‘Within 120 days’’,
‘‘within one year’’ for ‘‘within 90 days’’, and ‘‘every 8
years’’ for ‘‘every four years’’, inserted before last sentence ‘‘Notwithstanding the requirements of the previous sentence, the Administrator need not review any
such standard if the Administrator determines that
such review is not appropriate in light of readily available information on the efficacy of such standard.’’,
and inserted at end ‘‘When implementation and enforcement of any requirement of this chapter indicate
that emission limitations and percent reductions beyond those required by the standards promulgated
under this section are achieved in practice, the Administrator shall, when revising standards promulgated
under this section, consider the emission limitations
and percent reductions achieved in practice.’’
Subsec. (d)(1)(A)(i). Pub. L. 101–549, § 302(a), which directed the substitution of ‘‘7412(b)’’ for ‘‘7412(b)(1)(A)’’,
could not be executed, because of the prior amendment
by Pub. L. 101–549, § 108(g), see below.
Pub. L. 101–549, § 108(g), substituted ‘‘or emitted from
a source category which is regulated under section 7412
of this title’’ for ‘‘or 7412(b)(1)(A)’’.
Subsec. (f)(1). Pub. L. 101–549, § 108(e)(2), amended par.
(1) generally, substituting present provisions for provisions requiring the Administrator to promulgate regulations listing the categories of major stationary
sources not on the required list by Aug. 7, 1977, and regulations establishing standards of performance for such
categories.
Subsec. (g)(5) to (8). Pub. L. 101–549, § 302(b), redesignated par. (7) as (5) and struck out ‘‘or section 7412 of
this title’’ after ‘‘this section’’, redesignated par. (8) as
(6), and struck out former pars. (5) and (6) which read
as follows:
‘‘(5) Upon application by the Governor of a State
showing that the Administrator has failed to list any
air pollutant which causes, or contributes to, air pollution which may reasonably be anticipated to result in
an increase in mortality or an increase in serious irreversible, or incapacitating reversible, illness as a hazardous air pollutant under section 7412 of this title the
Administrator shall revise the list of hazardous air pollutants under such section to include such pollutant.
‘‘(6) Upon application by the Governor of a State
showing that any category of stationary sources of a
hazardous air pollutant listed under section 7412 of this
title is not subject to emission standards under such
section, the Administrator shall propose and promulgate such emission standards applicable to such category of sources.’’
App.8
§ 7412
TITLE 42—THE PUBLIC HEALTH AND WELFARE
1978—Subsecs. (d)(1)(A)(ii), (g)(4)(B). Pub. L. 95–623,
§ 13(a)(2), substituted ‘‘under this section’’ for ‘‘under
subsection (b) of this section’’.
Subsec. (h)(5). Pub. L. 95–623, § 13(a)(1), added par. (5).
Subsec. (j). Pub. L. 95–623, § 13(a)(3), substituted in
pars. (1)(A) and (2)(A) ‘‘standards under this section’’
and ‘‘under this section’’ for ‘‘standards under subsection (b) of this section’’ and ‘‘under subsection (b) of
this section’’, respectively.
1977—Subsec. (a)(1). Pub. L. 95–95, § 109(c)(1)(A), added
subpars. (A), (B), and (C), substituted ‘‘For the purpose
of subparagraphs (A)(i) and (ii) and (B), a standard of
performance shall reflect’’ for ‘‘a standard for emissions of air pollutants which reflects’’, ‘‘and the percentage reduction achievable’’ for ‘‘achievable’’, and
‘‘technological system of continuous emission reduction which (taking into consideration the cost of
achieving such emission reduction, and any nonair
quality health and environment impact and energy requirements)’’ for ‘‘system of emission reduction which
(taking into account the cost of achieving such reduction)’’ in existing provisions, and inserted provision
that, for the purpose of subparagraph (1)(A)(ii), any
cleaning of the fuel or reduction in the pollution characteristics of the fuel after extraction and prior to
combustion may be credited, as determined under regulations promulgated by the Administrator, to a source
which burns such fuel.
Subsec. (a)(7). Pub. L. 95–95, § 109(c)(1)(B), added par.
(7) defining ‘‘technological system of continuous emission reduction’’.
Pub. L. 95–95, § 109(f), added par. (7) directing that
under certain circumstances a conversion to coal not
be deemed a modification for purposes of pars. (2) and
(4).
Subsec. (a)(7), (8). Pub. L. 95–190, § 14(a)(7), redesignated second par. (7) as (8).
Subsec. (b)(1)(A). Pub. L. 95–95, § 401(b), substituted
‘‘such list if in his judgment it causes, or contributes
significantly to, air pollution which may reasonably be
anticipated to endanger’’ for ‘‘such list if he determines
it may contribute significantly to air pollution which
causes or contributes to the endangerment of’’.
Subsec. (b)(1)(B). Pub. L. 95–95, § 109(c)(2), substituted
‘‘shall, at least every four years, review and, if appropriate,’’ for ‘‘may, from time to time,’’.
Subsec. (b)(5), (6). Pub. L. 95–95, § 109(c)(3), added pars.
(5) and (6).
Subsec. (c)(1). Pub. L. 95–95, § 109(d)(1), struck out
‘‘(except with respect to new sources owned or operated
by the United States)’’ after ‘‘implement and enforce
such standards’’.
Subsec. (d)(1). Pub. L. 95–95, § 109(b)(1), substituted
‘‘standards of performance’’ for ‘‘emission standards’’
and inserted provisions directing that regulations of
the Administrator permit the State, in applying a
standard of performance to any particular source under
a submitted plan, to take into consideration, among
other factors, the remaining useful life of the existing
source to which the standard applies.
Subsec. (d)(2). Pub. L. 95–95, § 109(b)(2), provided that,
in promulgating a standard of performance under a
plan, the Administrator take into consideration,
among other factors, the remaining useful lives of the
sources in the category of sources to which the standard applies.
Subsecs. (f) to (i). Pub. L. 95–95, § 109(a), added subsecs. (f) to (i).
Subsecs. (j), (k). Pub. L. 95–190, § 14(a)(8), (9), redesignated subsec. (k) as (j) and, as so redesignated, substituted ‘‘(B)’’ for ‘‘(8)’’ as designation for second subpar. in par. (2). Former subsec. (j), added by Pub. L.
95–95, § 109(e), which related to compliance with applicable standards of performance, was struck out.
Pub. L. 95–95, § 109(e), added subsec. (k).
1971—Subsec. (b)(1)(B). Pub. L. 92–157 substituted in
first sentence ‘‘publish proposed’’ for ‘‘propose’’.
EFFECTIVE DATE OF 1977 AMENDMENT
Amendment by Pub. L. 95–95 effective Aug. 7, 1977, except as otherwise expressly provided, see section 406(d)
Page 6244
of Pub. L. 95–95, set out as a note under section 7401 of
this title.
REGULATIONS
Section 403(b), (c) of Pub. L. 101–549 provided that:
‘‘(b) REVISED REGULATIONS.—Not later than three
years after the date of enactment of the Clean Air Act
Amendments of 1990 [Nov. 15, 1990], the Administrator
shall promulgate revised regulations for standards of
performance for new fossil fuel fired electric utility
units commencing construction after the date on which
such regulations are proposed that, at a minimum, require any source subject to such revised standards to
emit sulfur dioxide at a rate not greater than would
have resulted from compliance by such source with the
applicable standards of performance under this section
[amending sections 7411 and 7479 of this title] prior to
such revision.
‘‘(c) APPLICABILITY.—The provisions of subsections (a)
[amending this section] and (b) apply only so long as
the provisions of section 403(e) of the Clean Air Act [42
U.S.C. 7651b(e)] remain in effect.’’
TRANSFER OF FUNCTIONS
Enforcement functions of Administrator or other official in Environmental Protection Agency related to
compliance with new source performance standards
under this section with respect to pre-construction,
construction, and initial operation of transportation
system for Canadian and Alaskan natural gas transferred to Federal Inspector, Office of Federal Inspector
for the Alaska Natural Gas Transportation System,
until first anniversary of date of initial operation of
Alaska Natural Gas Transportation System, see Reorg.
Plan No. 1 of 1979, eff. July 1, 1979, §§ 102(a), 203(a), 44
F.R. 33663, 33666, 93 Stat. 1373, 1376, set out in the Appendix to Title 5, Government Organization and Employees. Office of Federal Inspector for the Alaska Natural Gas Transportation System abolished and functions and authority vested in Inspector transferred to
Secretary of Energy by section 3012(b) of Pub. L.
102–486, set out as an Abolition of Office of Federal Inspector note under section 719e of Title 15, Commerce
and Trade. Functions and authority vested in Secretary of Energy subsequently transferred to Federal
Coordinator for Alaska Natural Gas Transportation
Projects by section 720d(f) of Title 15.
PENDING ACTIONS AND PROCEEDINGS
Suits, actions, and other proceedings lawfully commenced by or against the Administrator or any other
officer or employee of the United States in his official
capacity or in relation to the discharge of his official
duties under act July 14, 1955, the Clean Air Act, as in
effect immediately prior to the enactment of Pub. L.
95–95 [Aug. 7, 1977], not to abate by reason of the taking
effect of Pub. L. 95–95, see section 406(a) of Pub. L.
95–95, set out as an Effective Date of 1977 Amendment
note under section 7401 of this title.
MODIFICATION OR RESCISSION OF RULES, REGULATIONS,
ORDERS,
DETERMINATIONS,
CONTRACTS,
CERTIFICATIONS, AUTHORIZATIONS, DELEGATIONS, AND OTHER
ACTIONS
All rules, regulations, orders, determinations, contracts, certifications, authorizations, delegations, or
other actions duly issued, made, or taken by or pursuant to act July 14, 1955, the Clean Air Act, as in effect
immediately prior to the date of enactment of Pub. L.
95–95 [Aug. 7, 1977] to continue in full force and effect
until modified or rescinded in accordance with act July
14, 1955, as amended by Pub. L. 95–95 [this chapter], see
section 406(b) of Pub. L. 95–95, set out as an Effective
Date of 1977 Amendment note under section 7401 of this
title.
§ 7412. Hazardous air pollutants
(a) Definitions
For purposes of this section, except subsection
(r) of this section—
App.9
APPENDIX C
E XHIBITS
Exhibit A ..................................................... Declaration of Matthew B. Ballew
Exhibit B ........................................................ Declaration of Christian T. Beam
Exhibit C ........................................................... Declaration of John T. Bridson
Exhibit D ........................................................ Declaration of J. Michael Brown
Exhibit E ...................................................... Declaration of John R. Crockett III
Exhibit F ...........................................................Declaration of Kevin M. Gaden
Exhibit G .................................................................. Declaration of Alex Glenn
Exhibit H ..............................................................Declaration of Julia S. Janson
Exhibit I ...................................................... Declaration of William A. Johnson
Exhibit J .......................................................... Declaration of Todd Komaromy
Exhibit K ................................................................... Declaration of Tim Lafser
Exhibit L ...................................................... Declaration of Dale E. Lebsack, Jr.
Exhibit M............................................................ Declaration of Jacob Williams
App.10
Exhibit A
App.11
Case No. 24-1128
UNITEDSTATESCOURTOFAPPEALS
FORTHEDISTRICT
OFCOLUMBIA
CIRCUIT
ELECTRIC GENERATORS FOR A SENSIBLE TRANSITION,
Petitioner,
v.
U.S. ENVIRONMENTAL PROTECTION AGENCY, MICHAELS. REGAN
Respondents.
On Petition for Review of Final Agency Action
of the United States Environmental Protection Agency
DECLARATION OF MATTHEW B. BALLEW IN SUPPORT OF
PETITIONER ELECTRIC GENERATORS FOR A SENSIBLE
TRANSITION MOTION TO STAY
I, Matthew B Ballew, declare and state as follows:
1.
I am the Director of Innovation Strategy at Vistra Corp. ("Vistra") and
am authorized to make this declaration based on my personal knowledge. I support
internal and external teams in technology maturation efforts for emerging
decarbonization systems. The maturation of Carbon Capture and Sequestration
(CCS) technologies is one of Vistra's strategic priorities for ensuring an energy
transition focused on maintaining and improving reliability, affordability, and
1
App.12
sustainability. We work with research institutes, universities, transportation and
sequestration vendors, and carbon capture technology providers to advance the
analysis and design of potential CCS applications at Vistra. In that capacity, I am
intimately familiar with EPA's final rule entitled "EPA New Source Performance
Standards For Greenhouse Gas Emissions From New, Modified, And Reconstructed
Fossil Fuel-Fired Electric Generating Units; Emission Guidelines For Greenhouse
Gas Emissions From Existing Fossil Fuel-Fired Electric Generating Units; And
Repeal Of The Affordable Clean Energy Rule," ("Final GHG Rule") and its impact
on Vistra's existing and future operations.
INTRODUCTION
2.
I am providing this declaration on behalf of Oak Grove Management
Company, LLC ("the company"), one ofVistra's indirect subsidiaries that owns and
operates the Oak Grove Power Plant ("Oak Grove"), in support of Petitioner' motion
to stay EPA's Final GHG Rule. EPA's Final GHG Rule, if not stayed, will cause
significant irreparable harm to the company because it requires the commitment of
near-term costs and resources to implement CCS at Oak Grove that would be lost
even if Petitioners are successful on the merits.
3.
In light of its fast-approaching compliance deadlines, EPA's Final
GHG Rule places the company in the untenable position of having to make
commitments and expend substantial costs to implement CCS immediately based
2
App.13
upon an EPA rule that has now been challenged by 27 states and numerous other
parties, state plans that have not yet been finalized or approved by EPA, and
technologies and infrastructure that have not been developed, are not yet available
for commercial deployment, and are unaffordable.
4.
Such commitments include but are not limited to the soliciting and
securing of bids from contractors to perform work, procuring equipment, mobilizing
resources and employees, securing approvals for major capital expenditures,
applying for and securing the necessary local, state and federal permits and
approvals, and communicating and working with numerous stakeholders. The costs
of undertaking such near-term activities would likely exceed $10 million dollars per
plant if not more. Should EPA' s Final GHG Rule later be invalidated, multi-millions
in costs would be lost and would not be recoverable.
5.
In addition to impacts on existing coal assets, the final rule could stifle
the development and construction of newly permitted efficient combined cycle gas
turbine plants to serve as much needed replacement baseload capacity for expected
coal retirements across the country. For example, the final rule would require new
baseload gas-fueled combustion turbines with a capacity factor greater than 40%
(which must use combined cycle technology) to achieve 90% capture of CO2
beginning Jan. 1, 2032. For the same reasons discussed below that apply to Oak
Grove, CCS is also currently not adequately demonstrated at scale and if this
3
App.14
technology does not materialize and remains infeasible, the final rule could impede
the development of new gas-fueled baseload plants at a time when significantly
increased power demand is expected across the country.
VISTRA OVERVIEW AND OUR OPERATIONS IN THE STATE OF TEXAS
6.
Vistra is the largest competitive power generator in the United States
with a capacity of approximately 41,000 megawatts, or enough to power 20 million
homes, operating in all of the major competitive wholesale markets in the country.
Because Vistra only operates in wholesale deregulated competitive power markets,
we are incentivized to operate as efficiently as possible and offer electricity at the
lowest price that will cover our short run marginal costs, which drives down
wholesale electricity prices. Unlike some of our peers in regulated markets, we do
not operate as a vertically integrated monopoly and cannot recover our costs from
ratepayers for costs such as CCS even if that technology was currently adequately
demonstrated. Vistra is a leader in the energy transition and expansion with an
unyielding focus on reliability, affordability, and sustainability, powered by a
diverse portfolio that includes natural gas, nuclear, coal, solar, and battery energy
storage facilities. The company continues to grow its zero-carbon resources,
operating the second-largest fleet of competitive nuclear power plants in the country,
substantial battery energy storage capacity, and a growing number of solar facilities.
4
App.15
7.
Vistra subsidiaries own and/or operate approximately 16,000
megawatts (MW) of installed fossil generation capacity in Texas, which includes
4,650 MW of coal. This capacity is located at a total of 50 electric generating units
(EGUs) at seventeen sites in Texas. Thirteen units are subject to additional
regulation under the final rule, and thus increased compliance costs. Since 2018,
Vistra subsidiaries have retired approximately 4,100 MW of coal-fueled generation
capacity in ERCOT, including the Monticello, Big Brown, and Sandow power
plants, which resulted in the reduction of approximately 24M metric tons CO2e of
annual GHG emissions in Texas.
8.
Vistra's entire generating portfolio in Texas is approximately 19,000
MW, which includes 2,400 MW of nuclear generation and 506 MW of solar and
battery energy storage. Vistra is also one of the largest wind purchasers in Texas.
Vistra subsidiaries employ approximately 3,715 full-time employees and contracts
with independent contractors to work at the company's facilities in Texas. Vistra
and its subsidiaries spend approximately $2 billion annually in the form of salaries,
taxes, fuel, maintenance, and other operating and capital expenditures, and its impact
on gross state product and gross domestic product is substantial.
9.
Vistra agrees that climate change is an issue that must be addressed
collectively, with all participants doing their part to reduce their environmental
footprint, and we have committed to combating climate change through, most
5
App.16
importantly, the reduction of 60% of our Scope 1 and Scope 2 CO2e emissions by
2030, compared to a 2010 baseline, and achieving net zero carbon emissions by
2050. Vistra is well on its way to meeting that 60% reduction target having already
achieved 80% of those targeted reductions (equivalent to annual reduction of more
than 85 million metric tons) by the end of 2023. Since 2010, Vistra and its
subsidiaries have retired or announced the retirement of more than 19,000 megawatts
at 23 coal and natural gas plants. We also believe that the transition to zero carbon
emissions should take place in an orderly fashion, accounting for the reliability needs
of the states in which we operate and the affordability needs of our customers.
THE COMPANY'S OAK GROVE PLANT
10.
In 2010, construction of the Oak Grove Power Plant was completed
near Franklin, Texas. The plant includes two 800-MW coal-fired units featuring
first-of-a-kind environmental controls.
In addition to its state-of-the-art
environmental controls that reduce NOx emissions, SO2and PM, Oak Grove is the
nation's first pulverized coal plant fueled by lignite to utilize new activated carbon
sorbent injection technology to remove mercury. Units 1 and 2 at Oak Grove
generate enough electricity to power 850,000 Texas homes on a typical summer day.
11.
Because Units 1 and 2 operate nearly all of the time and are not
expected to retire before January 1, 2039, they would be subject to the requirements
applicable to "long term" existing units under EPA's Final GHG Rule.
6
App.17
Such
requirements include an emission rate limit based on application of CCS with 90%
capture by January 1, 2032.
CCS consists of three primary components: (1)
capturing CO2 produced by power generation; (2) transporting that CO2by pipeline
or other means; and (3) storing the CO2 in deep underground injection control wells
at a sequestration site. As I understand it, CCS with 90% capture has not been
consistently demonstrated at any electric generating unit in the world. The scale of
a CCS plant at Oak Grove to achieve 90% capture would be an order of magnitude
larger than the two demonstration plants currently using CCS. Moreover, there are
no existing CO2 pipelines to transport any captured CO2 from Oak Grove and it
appears that the nearest existing sequestration site is over 800 miles away in Macon
County, IL, of which a pipeline to this location from Oak Grove would be expected
to cost $1-2B. That site does not have near enough capacity to store Oak Grove's
CO2, much less CO2 from other power plants in the United States.
12.
Despite these logistical challenges, the company has been exploring the
potential costs associated with installing a carbon capture facility at Oak Grove. We
project that these costs alone (i.e., not including the costs associated with transport
and sequestration) could exceed $5 billion. That cost would be more than twice what
it cost to build the Oak Grove Power Plant. And because carbon capture technology
has not been demonstrated at this scale, there is no guarantee that the carbon capture
plant would work as required by the rules.
7
App.18
IF NOT STAYED, EPA FINAL GHG
RULE WILL RESULT IN IRREPARABLE HARM
13.
EPA's Final GHG Rule requires compliance with standards that are
based on systems of emission reduction that have not been adequately demonstrated
and performance standards that are not achievable. If not stayed, compliance with
these requirements will require the company to start maldng major resource, capital
and infrastructure decisions very soon-before the many challenges to EPA' s Final
GHG Rule are resolved in this Court (or ultimately the Supreme Court) and before
any state plan is developed, submitted and approved by EPA. This forces the
company to expend costs and resources now based upon an EPA rule that is being
challenged, state plans that have not been developed, finalized or approved by EPA,
and technologies that are not available for commercial deployment.
14.
If the Oak Grove units attempted to proceed with CCS with 90%
capture, for example, the company would be required to start the process now of
seeking approval for the construction and operation of a CCS plant on-site, as well
as a CO2 pipeline to connect Oak Grove to a sequestration site, which would include
permitting for a Class VI well. The company would be forced to undertake this
effort even though: (1) EPA's Final GHG Rule is subject to numerous challenges in
this Court; (2) neither Texas nor any other state has submitted state plans for EPA's
approval, as required under EPA's GHG Rule; (3) CCS has not been adequately
demonstrated and EPA's performance standards based on CCS are not achievable;
8
App.19
(4) any CO2 pipeline from Oak Grove would likely have to be sited through
numerous local communities in Texas and other states and likely cross major
waterways; (5) such a pipeline would likely encounter significant local and national
opposition, thereby significantly delaying (if not cancelling) the project; (6) many
communities have objected to or adopted moratoriums prohibiting CO2
pipelines/sequestration sites; and (7) there is no permitted Class VI sequestration site
in the country that has the capacity to store Oak Grove's CO2, even if the units could
somehow consistently capture 90%-a
level of capture that has yet to be
accomplished anywhere for a meaningful length of time.
15.
Oak Grove produces 12 to 13 million metric tons of CO2per year. The
carbon capture systems that EPA relies on in the final rule have only been able to
capture between 1 and 1.5 million metric tons per year.
16.
Further, installation of CCS would cause reliability concerns because
the technologies that the company has researched, none of which are commercially
demonstrated, would reduce the output of units 1 and 2 by an estimated 30% to
power the CCS process itself and therefore that output would not be available to
power the grid. Oak Grove historically operates at a 90% or greater capacity during
the hottest months in Texas. There is significant demand expected in Texas for new
data center load, electrification of vehicles and increased electric cooling and heating
9
App.20
load, and thus any reduction in generation as a result of the parasitic load 1 for CCS
could have significant consequences for the Texas grid, especially given the
intermittent nature of any new renewables that are brought online. Simply put,
significant reliability issues would be expected ifbaseload units, like Oak Grove, are
required to commit 30% capacity to CCS efforts.
17.
These reliability concerns would be exacerbated if units like Oak Grove
were required to retire because of an inability to comply with the CCS provisions in
the final rule. The Electric Reliability Council of Texas, Inc. recently stated in
comments submitted to EPA that "depending on untested and unproven technologies
to meet the nation's future electric demand while also forcing the retirement of
dispatchable generators presents an unacceptable level of risk to the reliability of the
power supply." The process of building a carbon capture plant at Oak Grove would
take many years, as there are many phases of developing such a massive project. The
technology would need to be studied to understand the design parameters and
associated risks to get to the pilot demonstration stage. After that stage, the company
would need to build a full-scale first-of-a-kind prototype. Each of these steps is
critical to ensure the safety of the facility and would take years to complete. If it
were to start this process immediately, the company has estimated that it might be
Parasitic load is amount of electricity fuat is needed to run the CCS process itself and would not be
available to supply electricity to the grid.
1
10
App.21
able to begin construction on a carbon capture plant in 2032 (the deadline EPA has
set for compliance), even with no opposition or permitting delays. With any legal
challenges to construction, local opposition or permitting delays, the projected
timeline would be much longer. The Final GHG Rule's provision allowing states to
provide a compliance date extension of up to one year is a wholly inadequate
remedy.
18.
Even assuming the company could install an operational plant with
90% capture at Oak Grove by the EPA' s deadline, that carbon would need to be
transported by CO2 pipeline to a sequestration site, as discussed above. Such a CO2
pipeline would give rise to numerous regulatory and permitting challenges, which
would result in additional delays or cancellation. Because no workable regulatory
framework exists for CO2 pipelines, such a project would also be subject to a
mishmash of complicated federal
and state regulatory and permitting
requirements-a process that can take many years to complete. Additionally, CO2
will need to be sequestered in Class VI deep underground injection control (UIC)
wells that must ensure the geology in the project area can receive and contain the
CO2within the zone where it will be injected. The permitting for these wells is very
onerous and only 18 permitted wells have been approved in the country.2 Finally,
2 Current Class VI Projects under Review at EPA
IUS EPA
11
App.22
because no adequate sequestration site exists, the company would be proceeding
with hope that such a site is one day established before EPA's compliance deadline.
19.
Forging ahead and expending such massive resources and tens of
millions of dollars in near-term costs in the face of so much uncertainty regarding
the validity of the final rule, the provisions of any EPA-approved state plan, and
unproven technology and undeveloped infrastructure will inevitably result in
significant economic waste, stranded assets and irreparable harm to the company.
20.
I declare that the foregoing is true and correct based on current
knowledge.
Executed this ~3 day ofMay 2024.
Matthew B Ballew
12
App.23
Exhibit B
App.24
IN THE UNITEDSTATES
COURTOF APPEALS
FORTHE DISTRICTOF COLUMBIACIRCUIT
ELECTRIC
GENERATORS
FORA SENSIBLETRANSITION,
Petitioner,
v.
Case No.: 24-1128
U.S. ENVIRONMENTALPROTECTIONAGENCY,
Respondent.
DECLARATION
OF CHRISTIANT. BEAM
I, Christian T. Beam, declare as follows:
1.
I am executive vice president of Energy Services for American Electric Power. In that
role, I oversee AEP's generation, transmission, nuclear, supply chain, procurement, fleet, and
safety and health organizations.
2.
I am over the age of 18 years, and I am competent to testify concerning the matters in
this declaration. I have personal knowledge of the facts set forth in this declaration, and if called
and sworn as a witness, could and would competently testify to them.
3.
Previously, I served as president and chief operating officer of Appalachian Power
Company, serving approximately 1 million customers in West Virginia, Virginia, and Tennessee.
4.
Prior to that, I was vice president, Projects, Controls and Construction, responsible for all
aspects of project management, project controls, commissioning, and construction activities
within AEP's Generation organization. I was also managing director, Projects and Construction,
from November 2010 to January 2013. In this role I was responsible for project management of
AEP's Western fleet, all new generating projects, and the commissioning and construction
activities within the Generation organization.
App.25
5.
My work experiences offer me a unique perspective on the implications of the
Greenhouse Gas (GHG) Rule on the entire AEP system.
6.
I offer these declarations on behalf of AEP and our operating companies, including
Appalachian Power Company, Kentucky Power Company, Public Service Company of Oklahoma,
Southwestern Power Company, and Wheeling Power Company, who are all members of Electric
Generators for a Reliable Transition. The Clean Power Plan, the precursor to this rule, took
several years to litigate. This litigation will surely take as long. Yet, critical decisions about
whether to opt into a "retirement" category as a means of compliance with not just the GHG
Rule but also EPA'snewly revised Effluent limitations Guidelines (ELG)Rule must be made by
the end of next year-18 months from now, and most likely before the litigation has concluded.
As shown herein, without a ruling to stay the GHG Rule pending the outcome of this litigation,
AEPwill be forced to make commitments that - practically speaking - are irreversible and will
impact citizens in all of our states for decades to come, including decisions potentially leading to
premature retirement of coal plants and replacement with generation that is neither as reliable
nor affordable.
AEPis Proudof its EnvironmentalProgressand Goals
7.
AEP is one of the largest investor-owned electric public utility holding companies in the
United States. AEP'selectric utility operating companies provide generation, transmission and
distribution services to approximately 5.6 million retail customers in Arkansas, Indiana,
Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee,Texas,Virginia and West Virginia.
AEP currently employs approximately 17,000 people.
8.
AEP's subsidiaries operate an extensive portfolio of assets including approximately
225,000 circuit miles of distribution lines and approximately 40,000 circuit miles of transmission
lines, including approximately 2,200 circuit miles of 765 kV lines, the backbone of the electric
interconnection grid in the eastern United States.
9.
As of December 31, 2023, AEP owns approximately 23,000 MWs of regulated generating
capacity - one of the largest complements of generation in the United States.
10.
AEP has already made tremendous reductions in all air emissions, including CO2,and has
a goal of net-zero CO2emissions by 2045. Even without a GHG rule to mandate reductions, AEP
2023 CO2emissions (43M metric tons) were 72% less than in 2005 (152M metric tons). And
between 1990 and 2023, AEP reduced SO2emissions by 98% and NOx emissions by 96%, while
2023 mercury air emissions have been reduced by 98% from 2001 levels.
11.
AEP's climate goals include an 80% reduction of scope 1 GHG emissions by 2030 as
compared to 2005 levels and net-zero scope 1 and scope 2 GHG emissions by 2045. 1
12.
AEP- once one of the largest coal-fired generators of electricity in the country- will go
from having owned more than 50 coal-fired units located at more than 20 power plant sites,
1 See AEP's Corporate Sustainability
Report, available at https://www.aee.com/investors/ESG
App.26
.
with over 25,000 MW nameplate generating capacity, in 2005, to just 8 coal-fired units at 5
power plant sites, with just over 6,500 MW nameplate generating capacity, in 2029. Put
another way, in 2005, coal was 70% of AEP's nameplate generating capacity. Before the GHG
Rule, and without factoring in how it might affect decisions about the retirement of coal plants,
AEP was projecting that by 2033, coal would be just 17% of our generating capacity. During this
same time, renewable generation has gone from 4% in 2005 to an expected 46% in 2033.
13.
Between 2000 and 2021, AEP invested an estimated $9 billion in environmental controls
in its coal-fueled generating fleet. These investments resulted in significant reductions in
emissions and were made in compliance with environmental regulations. The investments we
make in the electric power system are long-term investments, made after review and approval
by regulatory commissions that ensure the investments are sound and make sense in light of
the anticipated operating life of a unit.
14.
More recently, since 2016, AEP has spent over $460 million at the Amos, Flint Creek,
Mitchell, Mountaineer, and Turk plants to comply with environmental regulations targeting the
electric utility industry, including - to date -- $315 million on the ELGRule2 and $110 million on
the Coal Combustion Residuals (CCR)Rule,3so that these 5 coal-fired power plants can continue
to operate and provide reliable power into the future. These expenditures were approved by
regulators based on the premise that the plants would be in operation for some time to come.
15.
On April 25, 2024, EPAannounced not only the new GHG Rule, but three other major
rules targeted at the electric utility industry- revisions to the Mercury Air Toxics Standards
(MATS) Rule, the Effluent Limitation Guidelines (ELG}Rule, and the Legacy Coal Combustion
Residuals (CCR}Rule.
16.
While each of these new regulations purports to address a specific air, water or waste
issue, the rules taken as a whole demonstrate in no uncertain terms a policy choice by EPAto
force electric generation away from fossil fuels and towards renewable resources. EPAis
dictating energy policy by purporting to offer compliance options that, upon closer examination,
offer only one viable option - the early retirement of coal-fired generation with a shift to natural
gas or renewables.
17.
At the same time that AEP is facing significant load growth, with over 100,000 MW of
new load expected in the near term, AEP still has an obligation to reliably serve all customers
located in our service territories. Meeting the substantial load growth needs would be
challenging even without the GHG Rule; with the GHG Rule, the challenges of providing reliable
and affordable energy are magnified.
2 The ELGRule establishes wastewater
discharge standards that apply to coal-fired power plants. See 40 CFRPart
243.
3 The CCRRule is establishes requirements for the management and disposal of coal combustion residuals (coal
ash) from power plants. See 40 CFRPart 257, subpart D.
App.27
18.
In light of this, AEP has serious concerns about the impacts of the GHG Rule on grid
reliability and our ability to meet growing demand for affordable, reliable electricity. For the
reasons set forth below, AEP will be concretely and irreparably harmed if the GHG Rule is not
stayed pending this litigation.
AEPhasObligationsas both a PublicUtility and a Load-ServingEntity in RegionalTransmission
Organizations
19.
The Federal Power Act prioritizes reliability of the supply of electricity. Section 21S(b)
grants the Federal Energy Regulatory Commission jurisdiction over "all users, owners, and
operators of the bulk-power system" for "purposes of approving reliability standards" and
enforcing such standards.4
20.
The Federal Power Act also requires that wholesale energy and transmission rates be
"just and reasonable."5
21.
State regulatory agencies in each of our states oversee the delivery of electricity to
ensure that the service is just and reasonable.
22.
Regional Transmission Operators (RTOs)and/or Independent System Operators (ISOs)
are independent, membership-based, non-profit organizations that coordinate, control, and
monitor the electric grid to support reliability. AEPoperates within the PJMInterconnection,
L.L.C.(PJM), the Midcontinent Independent System Operator (MISO), the Southwest Power Pool
{SPP)and the Electric Reliability Council of Texas (ERCOT)RTOs/lSOs.
23.
One way RTOs/lSOsensure adequate supply of resources to meet peak demand is
through required reserve margins. A reserve margin is the amount of unused available
capability of an electric power system as a percentage of total capability. For example, a reserve
margin of 15% means that an electric system has an excess capacity in the amount of 15% of
expected peak demand. Different types of generation are allocated differing amounts of
"capacity credit" towards meeting the reliability requirements of the RTO/1SO.
24.
The retirement of fossil generation requires the addition of significantly more renewable
resources just to maintain the status quo, because 1 MW of solar or wind generation does not
carry the same reliability "capacity credit" of 1 MW of fossil generation from the RTO/1SO
perspective.
25.
For example, PJM assigns an Effective Load Carrying Capability (ELCC)to various types of
generation. In PJM,coal fired generation can have a typical ELCCrating of 84%- meaning it is
available to provide electricity roughly 84% of the time, taking maintenance and other outages
into account when the generation is not available. Therefore, a 1000 MW coal plant counts for
about 840 MW towards reliability needs of the system (1000 X 84% = 840 MW). Natural gas
4 See 16 U.S. Code§
8240.
5 See 16 U.S. Code § 824d.
App.28
fired combustion turbines can have a typical ELCCof 62%. On the other hand, on•shore wind
has an ELCCof 35% and single-axis tracking solar panels may have an ELCCof only 14%
depending on location. This means is that you would need 2400 MW of on-shore wind (HCC of
35%) to replace that same 840 MW (2400 X 35% = 840 MW). If you assume that 1000 MW coal
plant is replaced by tracking solar with a 14% HCC rating, you get 6000 MW (840/.14 = 6000
MW). Meaning, 6000 MW of tracking solar is needed to replace 1000 MW of coal from a
reliability perspective and this does not fully address service during night time and early
morning peak demands.
26.
In PJM and other RTOs,renewable resources are expected to receive even less capacity
credit towards reliability going forward as penetration increases.6 Consequently, dispatchable
generation is always going to be required to support the supply of electricity "at the flip of a
switch," day or night, and not just when renewables are available. Multiple MWs of renewable
generation are needed to replace each MW of dispatchable, fossil•fired generation to maintain
reliability. The system must always be balanced, meaning until there is a solution for storage,
we must make what is consumed in real time.
27.
While storage, such as batteries, can be part of the solution to providing this
dispatchable power, the magnitude of the scale and costs of these resources, which themselves
produce no energy, are not a reasonable sole replacement option for the on•call generation
benefit that fossil resources provide.
28.
The RTOsare already recognizing reliability concerns - even without the impacts of the
GHG Rule. SPP,in a statement on the GHGRule, notes "SPP is not expressing these concerns
about a hypothetical resource adequacy scenario in the future. SPPand other grid operators
are currently working to develop planning and operations policies and practices to deal with
resource adequacy issues that have already manifested." 7 SPPnotes its concerns about
resource adequacy were identified before the GHG Rule was finalized, and says that it did not
consider the additional at·risk generation that may retire and not be adequately replaced as a
result of the GHG Rule. "This outcome would further intensify the need for generating capacity
and associated transmission upgrades in the SPPregion, likely at a pace and cost unprecedented
for the industry." 8
29.
PJM has issued a similar statement, which notes, "[t]he Final Rule imposes the most
stringent requirements on new gas and existing coal units that operate as baseload units.
Although EPAhas focused on these units given that they have greater emissions, these baseload
units provide a critical reliability role. We are seeing vastly increased demand as a result of new
data center load, electrification of vehicles and increased electric heating load. The future
demand for electricity cannot be met simply through renewables given their intermittent
6 See, for example, PJM preliminary ELCCclass ratings through 2034. See https://www.pim.com/•
/media/plan n i ng/res-adeg/elcc/prel iminarv-elcc;-da ss-ratings-for-period-2026-202 7-t h rgygh-2034-2035.ashx
7 See SPPStatement on the Recent Greenhouse Gas Emission Rule (attached hereto as Exhibit A).
8
Id.
App.29
nature. Yet in the very years when we are projecting significant increases in the demand for
electricity, the Final Rule may work to drive premature retirement of coal units that provide
essential reliability services and dissuade new gas resources from coming online. The EPAhas
not sufficiently reconciled its compliance dates with the need for generation to meet
dramatically increasing load demands on the system."9
30.
SPP,MISO, PJM and ERCOTall told EPAthe same thing in their joint comments on the
proposed rule. 10 The reliability concerns are not hypothetical. They are real and they existed
before the GHG Rule was finalized. The rule serves to make the situation worse.
31.
If LSEscan't provide the capacity that the RTOrequires to ensure reliability on peak
usage days, there are significant consequences. Using SPPas an example, in the event AEP fails
to fulfill its SPPplanning reserve margin requirement, AEP and its customers are exposed to
significant deficiency charges, potential penalties, and service risks. First, AEP would be subject
to a deficiency charge of up to $171,500/MW under the SPPRTO'sOpen Access Transmission
Service Tariff (SPPTariff). Second, AEP and its customers may be subject to reliability
compliance penalties assessed by the North American Electric Reliability Corporation (NERC)to
SPPand/or AEP due to the violation of reliability standards. The violation of NERCstandards
can result in penalties, which can reach up to $1 million per day per violation, a substantial
financial burden for any organization. Finally, AEP'scustomers will be subject to lower levels of
reliability including a higher likelihood of being subject to controlled service interruptions to
maintain the power balance on the grid and prevent cascading outages across the system.
The ElectricGrid is Already Strained
32.
Our nation's electric system is under significant strain today. According to NERC,this is
especially true for our electric supply.11
33.
NERCis a not-for-profit international regulatory authority whose mission is to assure the
effective and efficient reduction of risks to the reliability and security of the grid. NERCdevelops
and enforces Reliability Standards; annually assessesseasonal and long-term reliability;
monitors the bulk power system through system awareness; and educates, trains, and certifies
industry personnel. NERCis the Electric Reliability Organization (ERO)for North America, subject
to oversight by the Federal Energy Regulatory Commission (FERC)and governmental authorities
in Canada.
9 PJM Statement
on the Newly Issued EPAGreenhouse Gas and Related Regulations, available at 20240508- ·m•
state me nt-o n-th e-new ly~issued·epa-green house-gas-and-rel ated-regu Iations. ashx (attached hereto as ExhibJt B)
10 https://www.regulations.gov/comment/EPA-HQ-OAR
·2023-0072-8207
11 James B. Robb, "The Reliability and Resiliency of Electric Servke in the United States in Light of Recent Reliability
Assessments and Alerts," Testimony Before the Senate Energy and Natural Resources Committee, p.2, (June 1,
2023), D47C2B83-A0A7-4E0B-ABF2•9574D9990Cll (senate.gov).
App.30
34.
In its 2024 Summer Assessment, NERCnoted that "(a] large part of North America could
be at risk of supply shortfalls during heat waves and extreme summer conditions that can affect
generation or wind output or the transmission systems." NERCalso noted that Texas, in which
AEP provides significant transmission service, is at elevated risk.12
35.
Reliability constraints are not limited to the summer. In its 2023 Winter Reliability
Assessment, NERCfound that over the course of the December-February winter period, a large
portion of North America was at risk of insufficient electricity supplies during peak periods. 13
36.
In MISO, an area in which AEPoperates and which NERCidentified as at greater risk of
electricity supply shortfalls, in addition to new wind and natural-gas-fired generation, the
extension of fossil-fired plants was necessary to increase available resources to help with
reliability constraints. 14
37.
NERCis not alone in its assessment. PJM,the RTOgoverning thirteen states plus the
District of Columbia, has also raised concerns about the rapid retirement of dispatchable
generation and their fear that the current pace of new generation is not sufficient to keep up
with expected retirements. 15 PJMwent so far as to say that, "For the first time in recent history,
PJMcould face decreasing reserve margins should these trends continue." 16
For ExistingGeneration in an AlreadyConstrainedSystem,The Rule RequiresThat Companies
ChooseBetween UnreasonableComplianceAlternativeson an UnrealisticTimeframe, Further
JeopardizingReliabilityand IncreasingCosts
38.
As the President and CEOof NERCtestified before Congress last year, "[m]anaging the
pace of change is the central challenge for reliability. The rapid evolution of the generation
resource mix is altering the operational characteristics of the grid. Through the transition ...
[u]ntil energy, capacity, and essential reliability services are fully replaced, the retirement of
traditional units must be managed." 17
39.
Despite this warning, the GHG Rule does the opposite - it will essentially force early
retirements of reliable "traditional units."
40.
Under the rule, existing coal-fired power plants must elect to either (a) install CCSand
capture 90% of their CO2emissions by 2032, (b) reconfigure units to cofire 40% natural gas by
2030 and retire by 2039, (c) convert to 100% gas firing by 2030, or (d) make no modifications
12 NERC,"2024
Summer Reliability Assessment," NERC_SRA_lnfographic_2024.pdf.
Reliability Assessment," p.S, Report (nerc.com).
13 NERC,"2023 Winter
14 fd.
15 PJM, Inc., ''Energy Transition in PJM: Resource Retirements, Replacements, and Risks (Feb. 24, 2023), p.2, energytransition-in-pjm-resource-retirements-replacements-and-risks.ashx.
l&
Id.
17 Robb testimony,
p. 8.
App.31
and retire before 2032. Whatever compliance strategy is chosen has its own obstacles to
completion within the allotted timeframe.
41.
Absent a stay, the rule becomes effective on July 8, 2024, setting in motion the process
of state plan development. State submissions are due by 2026 and EPAhas indicated that
approval of State Plans is expected by 2027. However, EPA'strack record of approving SIP
revisions shows that a one-year approval of a state plan (let alone 50 state plans!) is quite
ambitious and much quicker than typical SIPsubmission approvals. 18 Until state plans are
developed and approved, utilities won't know with certainty what their legal obligations are in
each state. Thus, AEP is faced with a difficult choice. AEPcan wait until there is certainty
surrounding the state plan, in which case we likely cannot make regulatory filings to seek
approval for and recovery of costs associated with compliance until 2027 at the earliest.
Alternatively, AEP must proceed to incur those costs - significant costs - at risk, without
knowing the final requirements of the state plans and whether EPAwilt approve them, and
without assurance that a regulatory commission will authorize recovery of those costs through
rates. If AEP incurs millions or billions of dollars in costs in pursuit of requirements to comply
with the GHG rule and those requirements are tater vacated by the court, a commission could
very well conclude we shouldn't have based our spending decisions on state plan requirements
that weren't final. Yet to meet the compliance deadlines of the GHG Rule, we will have no
choice but to do just that. A stay is needed so that we don't have to make consequential
decisions of this magnitude before we have certainty around the requirements that must be
met.
42.
To further complicate matters, for all of our coal plants, more than one state has a say in
the regulatory process. Our Amos and Mountaineer Plants are regulated by both the Virginia
and West Virginia Public Service Commissions. Our Mitchell Plant is co-owned by two operating
companies - Kentucky Power and Wheeling Power -- and is regulated by the Kentucky Public
Service Commission and the West Virginia Public Service Commission. In SWEPCO,three
different states - Texas,Louisiana, and Arkansas - have a say in what we can ultimately do and
seek recovery for at our Flint Creek and Turk plants. Any compliance decisions we make before
the state plans are finalized and without commission approval - decisions that may cost billions
of dollars - are done at risk and subject to scrutiny and disallowance by multiple state
regulatory commissions. If we wait for regulatory approval, we are likely to have less than 5
years to implement compliance strategies under the rule.
18 In fact, according to a 2021 report
by the EPAOffice of Inspector General,,as of January 1, 2021, approximately
39 percent of the 903 active state implementation plan submittals awaiting EPAaction were considered
epaoig 20210614-21-e•
backlogged. See Jmps:/Jwww.eoa.-1:ov/sites/default/files/2021·06/documents/
0163 O.pdf For purposes of the report, a submittal is considered backlogged when it is not acted upon by the EPA
with 12 months from the date of the completeness determination. Thus, there is a very real likelihood that state
plans won't be a pp roved until sometime after 2027.
App.32
43.
AEP can't make decisions about compliance with the GHG Rule in a vacuum. EPA'sother
recently adopted rules must also be taken into consideration. In particular, the ELGRule
requires companies to decide, by December of 2025, whether to install costly Zero Liquid
Discharge {ZLD) technology or retire by 2034. This ELGrule decision-point essentially
accelerates the GHG Rule's retirement decision timeline by several years to coincide. In other
words, when ELGand GHG rule requirements are both taken into consideration, companies
must decide whether to retire coal plants or not by the end of next year- a mere 18 months
from now. These decisions must be made before we know how each state will implement the
GHG Rule in its state plan, or in all probability, before we can ascertain whether the regulatory
commissions will approve recovery of costs associated with such decisions.
44.
If, in order to comply with the ELGRule, a coal plant elects to install ZLD - which is
estimated to cost approximately $120 million per site, •· it must do so by December 31, 2029,
and even then - because of the requirements of the GHG Rule - it could only operate that plant
until 2032, unless it also installs CCS.
AEPCannot in Good Faith PursueCCSas a ComplianceOption Because90% CCSis Not a
ProvenTechnologyThat Can Be Deployedat Utility Scaleby 2032
45.
AEP,perhaps more than any other utility in the United States, is uniquely qualified to
speak about the challenges inherent in deploying CCSto reduce CO2emissions. AEP has firsthand experience with development and demonstration of the technology in an integrated
configuration at a coal-combustion power plant. CCSis a promising technology, but significant
development challenges remain that will require years - perhaps decades - to resolve. A
comprehensive review of those challenges, coupled with experiences of private and public
entities developing the technologies, reveals that CCShas yet to be demonstrated as the BSER.
46.
CCSdevelopment challenges include technical, financial, regulatory, legal and practical
concerns related to each of the capture, transport, and storage aspects of the process. Even
though much investment has gone into advancement of CCStechnologies, these technologies
have not yet been demonstrated to be viable for reducing CO2emissions at fossil fueled power
plants. Simply put, there exists not a single coal or gas power plant in operation today in the US
with integrated CCScapturing and permanently sequestering 90% of the CO2produced by that
plant. Not one! At the current pace of development, CCSis not likely to be adequately
demonstrated as a viable control option, if at all, for many years.
47.
AEP'sAppalachian Power Operating Company undertook a carbon sequestration
demonstration project at our Mountaineer plant from 2007 - 2011, with geologic evaluations
and other preparatory working starting in 2003. While AEP did successfully deploy a CO2
capture system on a validation scale slip-stream process, that represented only a 20 MW
electric equivalent, or 1.5% of the Mountaineer Plant's 1,300 MW capacity. AEPdid not
construct or operate a full-scale capture CCSsystem.
App.33
48.
Over the course of nearly a decade working on the CCSproject, we learned that the
practical considerations of trying to deploy CCSalone are sufficient to support our claims that
CCSis not currently the BSER(i.e., demonstrated and achievable) and cannot be deployed by
2032, as the rule requires. CCSrequires the construction of an entirely new chemical plant to
capture CO2,the development of a pipeline to transport CO2,and the identification and
evaluation of areas suitable for sequestration, followed by the acquisition of property rights
from hundreds of people and the issuance of controversial injection permits - all within 5 years
or less, based on the state plan development timelines outlined above. Preliminary
assessmentsindicate that CCScompliance costs for an individual coal plant alone could easily be
several billion dollars.
49.
Based on our experiences with the Mountaineer CCSdemonstration project, which we
have shared extensively with EPAin comments on the proposed GHGRule and prior
rulemakings, we have concluded that it is not feasible to meet the Rule's deadline of 2032 to
install CCS- or for that matter a 2033 deadline if AEPgets an extension - at any of our plants.
In addition, 90% CO2capture has never been sustainably achieved anywhere at this scale, and it
is highly unlikely to be achieved by 2032. In short, CCSis not an option, and AEP must either
convert its existing coal-fired plants to 100% gas by 2030, co-fire 40% natural gas by 2030 and
retire by 2039, or shut the plants down by 2032.
Co-Firingwith Natural Gas Is Not a Viable ComplianceOption Becauseof the AssociatedELG
Rule ComplianceObligations
50.
Altering existing coal-fired boilers to allow them to co-fire up to 40% natural gas would
require a significant investment in not only the gas co-fired retrofit, but also in the
aforementioned ZLD compliance costs under the ELGRule, which the units would still be subject
to because coal would still be a fuel source. Additionally, co-firing with gas would provide less
flexibility than other dispatchable energy sources.
51.
Financially, this option also doesn't appear to make sense because any unit so converted
could only operate through 2039, when the GHG Rule would require it to retire. The cost of ZLD
to comply with ELG,coupled with the short remaining life of such a plant under the GHGRule
over which to recover the costs of that technology makes the gas co-firing option unreasonable,
uneconomical, and not one that would be likely to receive regulatory commission approval.
52.
While it is unlikely that we would pursue co-firing given the economics costs with
deploying ZLD,if we were to change our mind, that compliance options would require us to be
working now to design, engineer, and build out the conversion, including ordering custom
designed parts that would have no real value if the court were to vacate the rule and eliminate
this requirement. Absent a stay, AEPwill be harmed by the outlay of time and money to pursue
such an endeavor.
App.34
Without a Stay,AEP'sOnly RealisticOptionsare ChoosingBetween 100% Natural Gas
Conversionor Retirement of Coal Plants
53.
If the rule is not stayed, the difficulties inherent in the CCSand co-firing options detailed
above leave just two options for compliance at coal plants - conversion to natural gas firing or
retirement.
54.
Should AEPelect to comply with the rule by retiring coal plants, AEP must start in
earnest planning for the construction of a substantial amount of gas-fired generation - be it
new construction or conversion of existing coal units to burn gas - because dispatchable coalfired generation must largely be replaced with dispatchable gas-fired generation in order to
maintain reliability and meet fast-growing demand.
55.
Converting coal-fired boilers to 100% gas generation will require significant investment
in units that would likely have very low capacity factors. Additionally, due to startup and
shutdown times, these converted units would decrease grid flexibility to respond to intermittent
variable renewable energy supply at a time where more flexibility is needed.
56.
Our engineers estimate that converting a coal fired boiler to natural gas will require at
least S years, under the best-case scenario, where gas is readily available. In order to meet a
January 1, 2030, deadline to convert, the physical construction process must begin now,
essentially. A timeline from a hypothetical scenario that we previously evaluated - which
assumes that work would already be underway by now - shows that air permitting, gas
interconnections, engineering, procurement and construction all take significant time and
money and - absent a stay, must be happening during the pendency of this litigation if there is
any hope of having a converted unit available by the January 1, 2030 deadline.
Timeline for coal to gasconversion
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57.
Without a stay, AEP must enter into binding contractual agreements with engineers and
consultants and purchase custom designed equipment necessary for the conversion, all before
the court will have ruled on the legal challenges to the rule. If AEP begins the work to convert a
coal plant to gas, and this litigation ultimately results in the rule being vacated, AEP is harmed
by having to cancel contracts, which can carry significant penalties, and by having expended
significant resources to pursue a technical solution that ultimately is not necessary. AEPcannot
later be made whole for these harms.
58.
Our engineers' Class IV estimates (-30% to +50% range) of the financial commitment to
convert two units to 100% natural gas is approximately $140 Million per unit. That estimate
includes engineering and design along with construction and the applicable overheads for all of
the "inside the fence" conversion needs. It does not include the cost of constructing a pipeline
to supply fuel to the plant or the cost of firm gas transmission. That estimate is roughly $20M
per year for 10 years for a total of nearly $200M. This estimate doesn't include costs for any
studies for permitting or additional property that may need to be purchased for the installation
of a gas yard.
59.
A coal plant that converts to natural gas is, in all likelihood, not going to run much. This
is because variable dispatch costs tend to go up when switching a given unit from coal to natural
gas due to the higher fuel cost, so the dispatch of the unit goes down. This is another example
of how the rule forces generation shifting, first from coal to gas, and then again from gas to
renewables, by making the costs of providing gas fired generation uneconomical.
60.
Moreover, there are opportunity costs associated with pursuing such a conversion. The
time and resources that AEP must expend to convert coal fired boilers to gas is time and money
that can't be spent pursuing other endeavors - including the development of additional
renewable projects. Compliance with the rule during the pendency of the litigation thus hurts
AEP in multiple ways.
61.
Alternatively, without a stay, by 2026, AEPwill need to commit to retire coal plants; that
is when state plan development would require AEPto select a compliance category, if not
sooner because of the ELGRule's deadline to make a similar compliance election.
62.
A decision to retire a coal plant is a difficult one. In addition to the costs associated with
decommissioning the plant at the time of retirement, there are significant up-front costs,
including engineering studies to identify and optimize replacement generation and associated
transmission needs, and penalties for cancelling coal and other contracts. Here, too, if AEP
elects to retire a plant as the means of complying with the GHG Rule, it must incur costs now,
during the pendency of the litigation, even though retirement itself would be several years
away.
63.
Whichever compliance option AEP pursues, AEPwill be significantly harmed if the rule is
not stayed.
App.36
The RuleSignificantlylimits our Optionsfor New DispatchableGeneration
64.
Under the GHG Rule, new natural gas combustion turbines are categorized as low load
(S20% capacity), intermediate load (between 20% and 40% capacity), and baseload (>40%
capacity). Baseload natural gas turbines must install 90% carbon capture and storage (CCS)by
January 1, 2032. For reasons detailed elsewhere in this declaration and in our comments in the
GHG Rulemaking docket, 90% CCSat a utility scale is not a proven technology that is a viable
option by 2032. CCSby 2032 is perhaps even more unrealistic for baseload gas-fired generation
than for coal-fired generation, as this technology has not been fully demonstrated at a gas-fired
plant to date. Thus, absent a stay, there is no scenario in which AEPwould be able to build a
new, baseload natural gas turbine and achieve the CO2standard in the final rule.
65.
In evaluating options since the rule was finalized, AEP has realized that only a very few of
the currently available combustion turbine models available from the limited universe of
manufacturers can meet the presumptive BSERemission rates for intermediate load turbines and then, it is only under ideal, steady state operating conditions that do not represent the
range of operating conditions that the units will reasonably experience over their lifetime. The
vast majority of turbines on the market currently simply can't meet the rule's CO2 emission
limits. Yet, utilities that need to acquire dispatchable generation to ensure reliability and meet
load growth must place orders now if they hope to get any new turbines built and delivered in
time to meet anticipated demand. Based on our recent experiences, any turbines we order
today- assuming we were in a position to be ready to order something today- would most
likely not be in service for 5 - 7 years under the best circumstances. And, as demand for those
very few models that might meet the CO2standard increases, availability decreases and costs
increase.
66.
A leading turbine manufacturer with whom we have spoken has confirmed that very few
of its machines can meet a 1170 lbs. COi/MWhr-gross limit - even when assuming ideal steady
state conditions at full load, which is when these turbines are most efficient. As you move away
from full load, you lose efficiency and emissions will begin to exceed the target. We expect to
hear similar statements from the other manufacturers with whom we plan to meet.
67.
Therefore, despite EPA'spublic statements that it backed away from including hydrogen
co-firing as a BSERpathway in the final rule, the reality is that, for the vast majority of
combustion turbines readily available in the marketplace, the use of hydrogen in addition to
natural gas appears to be necessary to ensure the presumptive BSERemission limits can be met
when turbines are operated as peaking units that ramp up and down based on need and not as
baseload, steady state operation.
68.
Despite not "requiring" hydrogen co-firing, EPAnotes that sources "may elect to co-fire
hydrogen for compliance with the final standards of performance, even absent the technology
being a BSERpathway." By setting the emission limits as it has, EPAhas essentially mandated
hydrogen co-firing without calling it BSER.The problems with this are the same as were noted in
our comments on the proposed rule - there is no reliable source for hydrogen production; no
App.37
readily available pipeline infrastructure to provide hydrogen to power plant locations across the
country, and combustion turbine technology has yet to be developed to support the use of
larger blends of hydrogen co-firing so that it can be a significant portion of the fuel mix for our
turbine. Developing and permitting hydrogen pipelines is fraught with the same difficulties
facing CO2pipelines. And onsite storage is impractical given the volumes of hydrogen that would
be needed, and the unmanageable number of trucks required for delivery. Further, at the
current slow pace of development, it will be many years before these challenges to hydrogen
utilization will even begin to be addressed.
69.
Because hydrogen isn't available and is unlikely to be available by the time it is needed,
AEP cannot commit to purchase new combustion turbines as a means of providing electricity in
compliance with the rule based on an assumption that it can combust hydrogen to meet the
intermediate load BSERemission limits. Moreover, there is tremendous uncertainty
surrounding hydrogen pricing as that market has yet to emerge.
70.
Becauseof the lack of hydrogen supply, transportation and storage infrastructure, and
available combustion turbine technology to ensure that the intermediate capacity BSERlimits
can be met, any new turbines AEPbuilds will most likely be in the low load category - meaning
they would be limited to operating at 20% capacity or less. Units in this low load category are
subject to a less stringent limit that can be met. However, as a result of each turbine being
limited to 20% capacity or less, AEPwould have to commit resources to install multiple new gas
generation plants to provide the needed energy- energy that could be provided by a single
turbine but for the rule. This is because any new natural gas combustion turbine that operates
at more than a 20% capacity factor must co-fire a fuel that is not available - hydrogen - to meet
the applicable emission limit and anything operating above a 40% capacity factor must install
CCS. As discussed above, neither is a viable compliance option within the timeframe mandated
by the rule.
71.
Indeed, the rule effectively allows an unlimited number of new gas combustion turbines
to be installed without CCSand without hydrogen co-firing if they each operate less than 20% of
the time but will not allow one new turbine to operate without CCSfor 45% of the time. This
approach basically forces gas generation to be uneconomical because of the capacity
constraints placed upon individual turbines and the need to install multiple turbines operating
at limited capacity. This also demonstrates that the rule is not about the actual emissions at all,
but about forcing a policy that favors renewables over fossil fuels, putting grid reliability at
significant risk.
72.
Electing to build multiple gas-fired turbines, with each limited to operating only a
fraction of the time, is an inefficient utilization of gas for generation, is not a cost-effective
development strategy, and will be a difficult decision to justify to our state regulatory
commissions. This will needlessly increase costs for ratepayers. And, because the demand for
new turbines is already expected to grow, this artificial increase in demand resulting from the
need to purchase multiple turbines subject to capacity limitations when, but for the rule, one
App.38
could deliver the energy needed will only make it harder to get enough turbines in place and
operational in a timely manner to ensure uninterrupted power.
73.
Additionally, if multiple turbines must be built to provide replacement generation, each
additional turbine introduces an increased risk of encountering manufacturing issues, site•
specific problems, delays, etc. such that the overall risk of meeting required in•service date
increases.
74.
Even with all of the uncertainties described, if AEPelects to install new gas turbines to
either replace retiring coal generation or meet growing demand, AEP must enter into contracts
now to secure a spot in the production queue for the limited models of new turbines that might
be able to meet the presumptive BSERlimits. AEP must do so before the states have even
developed their state plans and without knowing what the approved state plan requirements
will be.
75.
Any new turbines will face long interconnection wait times if they can't repurpose
existing interconnections to the grid. A typical interconnection time in recent experience has
been several years. Those interconnection delays are expected to grow as more new generation
is added to the grid.
76.
Based on our experiences, it would cost approximately $250 million today to purchase a
225 MW turbine that would be limited to 20% capacity factor. It is very likely that these costs
will increase as demand for turbines increases as a result of this rule. tf we proceed down a
path to ordering multiple new combustion turbines and the court ultimately reverses the GHG
Rule, we will face significant penalties to cancel the contracts, or we will have committed to
purchasing significantly more generation that we need. Any expenses incurred for design and
engineering, permitting, or legal support not included in the purchase agreement will simply be
lost and rate recovery for such expenses is doubtful.
load Growth Issuesand Opportunities
77.
At the same time that EPAhas finalized the GHG Rule, the United States is experiencing
power demand growth not seen in a generation. For the first time in two decades, demand for
power is rapidly increasing, and in some areas is outpacing available capacity. Power demand
from artificial intelligence (Al), data centers, manufacturing, cryptomining and large industrial
customers is expected to double in three years.HI
78.
Not only are the number of data centers increasing, but each data center is also growing
bigger. Prior to 2021, the electricity demand from a large data center was approximately 200
MW; today it is 1,000 MW or greater. This is because the rising use of Al in various sectors is
increasing the overall power demand of data centers. For example, a typical Google search uses
Seehttps://www.spglobal. tom/ma rketintell igencekn/news-i
dem and-to-double-i n-three-years-821 l-iea-80123428.
19
App.39
nsights/I atest-n ews-head Iin es/datacente r-power-
0.3 watt-hours of electricity, while OpenAl's ChatGPTrequires 2.9 watt-hours for a requestnearly ten times more power. Assuming 9 billion searches daily, this would require almost 10
TWh of additional electricity in a year.20 As the chart below illustrates, the power demand for Al
will grow 80-fold, from 8 TWh in 2024 to 652 TWh by the beginning of the next decade.21 To
put that into perspective, 652 TWh is more energy than is used today by 60 million homes in a
year.
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79.
Finally, it should be noted that this growth is not isolated to only one part of the country.
The PJM Interconnection in its most recent long-term load forecast predicted summer peak
demand to increase by roughly 28GW by 2034 and 42GW by 2039 compared to 2024 levels.22
ERCOT,the regional transmission organization that serves most of the state of Texas,is also
predicting significant demand growth - approximately an additional 70 GW in demand by the
end of this decade, nearly doubling the demand in the entire region. 23
80.
In some instances, the demand of new customers seeking to interconnect to our system
exceeds the total amount of load currently served by AEP in those areas today. For example,
AEP has received a combined 108 gigawatts of requests for interconnection in the near-term.
This represents over 10 percent of the peak electricity demand in the entire United States.
81.
Currently, the amount of load requesting to interconnect to AEP'stransmission system
eclipses the current peak demand of AEP's operating companies in our PJMand ERCOTregions.
For AEP's Ohio, Indiana and Michigan utilities, the demand is over three times AEP'scurrent
peak load in these three states. AEP'sWest Virginia and Virginia utilities' demand would more
20 See https:ljwww.datacenterknowledge.cgm/energ,delectric:ity-demand-data-center;s-c:ould-dooble-three-years.
21 Terawatt hours, abbreviated
as TWh, is a unit of energy representing one trillion-watt hours. The average
American home uses 10,791 kilowatt-hours (kWh) of power a year. One TWh is equal to one billion kWh.
22 See PJM Publishes 2024 Long-Term Load Forecast I PJM Inside Lines
23 ERCOT,2024 RTP- Load Review Update (March 2024), PowerPoint Presentation (ercot.com)
App.40
than double the current load of Appalachian Power Company. Finally, AEPTexasis experiencing
demand over five times its current load today.
82.
As demand is rapidly increasing, our nation's electricity system is simultaneously
transforming to accommodate new forms of energy. The pace of this transformation must not
overtake the reliability needs of the system. Even without factoring in many of the large-scale
customers seeking to interconnect to the grid, NERC'sindependent technical assessments find
that the risk of electric power supply disruptions are steadily increasing, as discussed above.
Unless reliability and resilience are appropriately prioritized, current trends indicate the
potential for more frequent and more serious long duration reliability disruptions, including the
possibility of national consequence events.
83.
As new generation is developed, connecting that generation in vertically integrated
states - meaning states where utilities are responsible for the entire flow of electricity from
generation to transmission to distribution - can sometimes take five to ten years. Transmission
development has been slowing as interconnection requests are increasing. In the early 2010s,
for example, the U.S. installed an average of 1,700 miles of new high-voltage transmission miles
per year. That has dropped by nearly two-thirds to 645 miles on average in the second half of
the decade. Regulatory approvals, siting, permitting, legal challenges and supply chain
constraints pose risks to the process of connecting new generation that can have reliability
implications.
84.
If the GHG Rule is not stayed, the reliability concerns that I have outlined herein are
likely to lead to the loss of potential large-load customers, like data centers, and to cause AEP
reputational harm as well.
85.
Today, new data centers and other large consumers of electricity are seeking to build
new facilities within our service territories, as evidenced by the more than 100 gigawatts of
requests for interconnection in the near-term referenced above. If AEP is unable to meet
demand and reliably serve potential new customers, whether because AEPmust shut down
existing sources of generation or because AEP is unable to deploy new generation to meet the
growing demand, those customers that are considering developing sites within our footprint are
likely to locate elsewhere.
86.
Indeed, at a May 21, 2024, hearing before the Senate Energy and Natural Resources
Committee, one tech company executive testified that part of the reason his company- Micron
- located its manufacturing where it did was because of the proximity to a nuclear plant and
large scale hydro power that it knew it could rely on to provide energy. "[A]ccess to reliable,
affordable energy was a key part of Micron's site evaluation process."24
24 Written
Statement of Scott Gatzemeier, Micron Corporate Vice President of U.S. Front End Expansion Before The
U.S. Senate Committee on Energy And Natural Resources "Hearing To Examine The Opportunities, Risks, And
Challenges Associated With Growth In Demand For Electric Power In The United States," (May 21, 2024), available
at 83B90031-A702-4C01-A5AC>0E1CC0SA2EF2 (senate.gov).
App.41
87.
Once a Micron or a Google decides to locate somewhere, that decision is made. Every
other location that was considered has lost that opportunity permanently. A decision by the
court that vacates the GHG Rule and eliminates the reliability concerns associated with it will
come too late and cannot undo this type of harm to AEP. This loss of customers would be
irreparable. It would also result in harm to our communities, who lose out on jobs, tax revenue
and other benefits associated with the growth of such new business. Finally, it would harm
AEP's reputation as a reliable provider of electricity that is able to accommodate growth in its
service territory.
While Plant ClosuresMay Not Occurfor SeveralYears,EvenProspectivePlant ClosuresHave
Impactson Employeesand Communities
88.
Coal-fired power plants require highly skilled employees and provide well-paying jobs.
The plants also provide sizable tax revenues and stimulate associated employment in other
sectors that support both the plant and its employees. Coal-fired power plants and their
employees often are significant supporters of the communities where they are located, and
when plants are retired and decommissioned, they can leave a significant economic void.
89.
The community impacts of compliance with this rule are perhaps most stark for
Appalachian Power Company, which operates 3 coal-fired power plants in West Virginia. A
recent study found that our Amos Plant, located in Winfield, WV, generates an estimated $320
million in economic activity, $123 million in labor income and supports 1,246 jobs annually in
the region. The Mitchell Plant, located in Moundsville, WV, generates $111 million in economic
activity, $35 million in labor income and supports nearly 459 jobs annually in the region. Finally,
the Mountaineer plant, located in New Haven, WV, generates $98 million in economic activity,
$32 million in labor income and supports 414 jobs annually in the region. Combined, these
three plants located within just a few hours of each other represent more than half a billion
dollars in economic activity for the State of West Virginia, over 2000 jobs, and almost $200
million in labor income. Shutting down the plants prematurely would have a devastating impact
on West Virginia and communities in neighboring states, even before other impacts of the rule,
such as higher energy costs and reliability concerns, are taken into consideration.
90.
If AEPchooses to retire a coal-fired plant, that decision must be made before December
31, 2025 (if considering the ELGRule and the GHG Rule together) or by 2026, pursuant to state
plan requirements under the GHG Rule. Absent a stay- such a decision would most likely need
to be made during the pendency of this litigation. A decision to close a plant will impact our
employees and communities, who will need to begin making alternative plans. Employees will
face uncertain prospects for employment while the fate of the plant is in limbo during the
litigation. Hard questions to be answered include whether they should look for employment
elsewhere, including potentially relocating, or risk the chance that the plant will close if the
court doesn't vacate the rule. Communities similarly must budget for future years and must
App.42
consider uncertain scenarios in which they must identify ways to replace the tax revenues
generated by the plant if the plant closes.
91.
Even if a plant closure doesn't materialize, without a stay, the employees and the
community will have been harmed by the uncertainty and the planning efforts associated with
this uncertainty.
Compliance with the Rule Has Negative Impacts on Our Ratepayers
92.
In addition to providing reliable power to customers, we must also continue to ensure it
is affordable. AEP,in particular, serves a lower income customer base than most other utilities.
In fact, our customers are below the national average for household income in ten of the eleven
states in which we provide electric service, and in many of those states, our customers are also
below the state average for household income.
93.
AEP currently has 5 coal plants scheduled to operate well into the future. Retiring those
plants by 2032, many years ahead of schedule, in order to comply with the GHG rule, would
force us to recover undepreciated plant balance from ratepayers in several states, including
Kentucky, West Virginia and Arkansas- some of the poorest states in the country. Indeed, $460
million has been spent at these plants since 2016 to comply with MATS, ELGand CCRso that
these plants could continue operating. Retiring these plants because of the compliance
obligations of the GHG Rule, just a few years after mandating installation of costly new controls,
is a bitter pill for our regulatory commissions and ratepayers to swallow.
94.
If plants are forced to retire prematurely, ratepayers are hit twice: once to pay for the
undepreciated balance on any plants forced to retire prematurely and then again, to pay for
replacement generation. And because of the fact that the infeasibility of CCSand the lack of
hydrogen infrastructure means new gas turbines will most likely be capped at 20% capacity
factor or less, it is entirely likely that multiple new turbines will need to be purchased to provide
the output that a single turbine is capable and designed to produce.
95.
Whatever compliance alternative is selected, rates for the average customer in our
operating companies that own and operate coal plants would be expected to significantly
increase.
AEP is Harmed by the GHG Rule's Implications for OVEC
96.
AEP is also directly impacted by the effects of this rule on the Ohio Valley Electric
Corporation, or OVEC,of which AEP is a partial owner, with a 43.47 % ownership share. If this
rule drives OVECto premature retirement of its generating facilities, AEPwill be faced with
having to replace approximately 940 MW of additional capacity and energy currently supplied
to AEP by OVEC.
App.43
97.
AEP references the declaration of J. Michael Brown, Environmental Safety and Health
Director for OVECfor a full description of the scenario facing OVECabsent a stay.
Conclusion
98.
In conclusion, if this rule is not stayed, AEP must decide if it will retire coal plants,
convert them to natural gas, or replace them with new turbines or renewables, and it must
make these decisions for multiple plants, across several states, each with unique circumstances
and unique challenges, while trying to ensure that sufficient capacity exists to meet customer
demand. Eachof these choices is fraught with significant risks and requires that financial
commitments begin to be made immediately, with no way for AEPto be made whole if
successful in this litigation. During this period of uncertainty, AEP must also make decisions
about how to meet load growth reliably, including deciding whether to purchase turbines that
are likely to require a fuel that is not currently available - hydrogen - to meet the rule's
intermediate subcategory emission limits or being forced to buy multiple new turbines that are
each artificially limited to operate at low capacity to stay within the rule's low load category.
The difficult choices AEP must make in the near term if this rule is not stayed will lead to harm
to AEP's customers, communities, employees and shareholders. Everybody uses electricity.
This rule increases the costs and reduces the reliability of our service - all in pursuit of a slight
acceleration of a climate goal that we have been successfully marching towards on our own,
even without the rule. For the foregoing reasons, AEPfaces imminent and irreparable harms if
the court does not stay the final rule.
t, Christian T. Beam, declare under penalty of perjury, that the foregoing is true and correct.
Executed on this 23 rd day of May, 2024.
Christian T. Beam
Executive Vice President, Energy Delivery
American Electric Power Company, Inc.
App.44
EXHIBIT A
to Declaration of Christian T. Beam
App.45
jm
STATEMENT
FOR IMMEDIATE RELEASE
PJM Statement on the Newly Issued EPA Greenhouse Gas and Related Regulations
(Valley Forge, PA – May 8, 2024) – PJM provides this statement concerning the EPA rule on New Source
Performance Standards for Greenhouse Gas Emissions and the other EPA regulations promulgated on April 25,
2024.
PJM has the responsibility to ensure both short- and longer-term reliability for the 65 million people we serve in a
region spanning 13 states plus the District of Columbia. “Reliability” in this context refers both to the day-to-day work
of managing the grid to keep the system in balance as well as ensuring that, looking forward, there are adequate
resources available and committed to serve the expected demand for electricity in future years.
Because of these unique responsibilities, PJM and other affected RTOs have been extensively involved in EPA
rulemakings dating back to the Mercury and Air Toxics Standards rule promulgated on Dec. 16, 2011. Our role in
these rulemakings has been to ensure that, in developing proposed environmental rules, EPA has appropriately
taken into account the reliability needs of our respective grids.
Consistent with this past level of involvement, PJM worked cooperatively with MISO, SPP and ERCOT (the RTOs
most affected by the EPA rule) to craft a set of detailed comments to EPA raising our collective reliability concerns
with EPA’s initial proposed greenhouse gas (GHG) rule. Our comments and subsequent meetings with EPA were
focused on:
•
Educating EPA as to the reliability needs of our respective systems and the potential impact that the thenproposed GHG Rule could have on both day-to-day reliability and resource adequacy; and
•
Providing to EPA constructive proposals to help mitigate, from a reliability perspective, potential adverse
impacts of the then-proposed Rule with a particular focus on ensuring adequate flexibility within the Rule for
grid operators to be able to address both short-term reliability issues and resource adequacy within their
regions.
– MORE –
Contact: PJMNews@pjm.com or (866) PJM-NEWS | (866) 756-6397
App.46
PJM Statement on the Newly Issued EPA Greenhouse Gas and Related Regulations / Page 2 of 3
Noting the RTO Comments, in its Final Rule issued on April 24, 2024, EPA made certain adjustments to its initial
proposal. Those adjustments altered the resources impacted by the rule and provided additional tools that can help
provide flexibility to address reliability issues. PJM is appreciative of EPA’s acknowledgment of the importance of the
existing resources to reliability, of the need for more flexibility, and its consideration of the Joint RTO Comments. The
specific adjustments that were grounded in the Joint RTO Comments and adopted in the Final Rule included:
•
Treatment of Existing Gas Resources – Removing existing gas from this rulemaking to be addressed
holistically in a separate rulemaking
•
State-Specific Compliance Flexibility – Availability of flexibility for the states to address reliability issues,
taking into account the remaining useful life and other factors that affect needed units
•
Averaging – Allowing unit owners to average their compliance obligations over multiple units to ensure
least-cost compliance
•
Emissions Trading – Authorizing states to utilize allowance trading to minimize compliance costs and
burdens
•
Mass-Based Programs – Authorizing states to potentially utilize an emissions cap rather than controlling
the rate of emissions from each affected unit
•
Short-Term Reliability Mechanisms – Allowing needed units to operate for emergencies without
jeopardizing compliance with the rule
•
Timeline Extensions – Providing extensions for retiring units needed for reliability and units needing more
time to install controls, with state discretion for longer periods
PJM’s Continuing Reliability Concerns
Although we appreciate EPA’s adoption of certain flexibility measures in response to our proposals, areas of concern
remain related to ensuring reliability given the impact of the Final EPA Rule:
•
The new rules governing both existing coal and new natural gas are premised on EPA’s finding that carbon
capture and sequestration (CCS) technology represents the “best” system of emissions reduction, which will
be commercially available at a reasonable cost. However, the availability of CCS is highly dependent on
local topology, such as salt caverns available to sequester carbon and the availability of a pipeline
infrastructure to transport carbon emissions from individual generating plants to CCS sites potentially
hundreds of miles away. There is very little evidence, other than some limited CSS projects, that this
technology and associated transportation infrastructure would be widely available throughout the country in
time to meet the compliance deadlines under the Rule.
– MORE –
App.47
PJM Statement on the Newly Issued EPA Greenhouse Gas and Related Regulations / Page 3 of 3
•
The Final Rule imposes the most stringent requirements on new gas and existing coal units that operate as
baseload units. Although EPA has focused on these units given that they have greater emissions, these
baseload units provide a critical reliability role. We are seeing vastly increased demand as a result of new
data center load, electrification of vehicles and increased electric heating load. The future demand for
electricity cannot be met simply through renewables given their intermittent nature. Yet in the very years
when we are projecting significant increases in the demand for electricity, the Final Rule may work to drive
premature retirement of coal units that provide essential reliability services and dissuade new gas resources
from coming online. The EPA has not sufficiently reconciled its compliance dates with the need for
generation to meet dramatically increasing load demands on the system.
•
The Final Rule is premised on the availability of increased access to natural gas infrastructure to support the
Rule’s “co-firing with gas” compliance option for existing coal units. The present gas pipeline system is
largely fully subscribed. Moreover, given local opposition, it has proven extremely difficult to site new
pipelines just to meet today’s needs, let alone a significantly increased need for natural gas in the future.
The Final Rule, which is premised, in part, on the availability of natural gas for co-firing or full conversion,
does not sufficiently take into account these limitations on the development of new pipeline infrastructure.
•
EPA has left many issues for development in individual state implementation plans. Although this is
appropriate and in keeping with the structure of the Clean Air Act, each of the multi-state RTOs like PJM
operate a single dispatch. As a result, states will need to coordinate and work closely together to ensure that
the individual state plans work well on a regional basis. As a result, the need for regional coordination of
individual State Implementation Plans is more important than ever. PJM values its continued collaboration
with the other affected RTOs (MISO, SPP and ERCOT) and looks forward to working with the U.S. EPA,
individual states and affected stakeholders as this process continues.
PJM Interconnection, founded in 1927, ensures the reliability of the high-voltage electric power system serving 65 million
people in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio,
Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PJM coordinates and directs the operation
of the region’s transmission grid, which includes 88,115 miles of transmission lines; administers a competitive wholesale
electricity market; and plans regional transmission expansion improvements to maintain grid reliability and relieve
congestion. PJM’s regional grid and market operations produce annual savings of $3.2 billion to $4 billion. For the latest
news about PJM, visit PJM Inside Lines at insidelines.pjm.com.
###
App.48
EXHIBIT B
to Declaration of Christian T. Beam
App.49
0Qpp
()
Southwest
Power Pool
STATEMENT ON THE RECENT EPA GREENHOUSE GAS EMISSIONS RULE
SPP issues this statement on the final rule the EPA issued on April 25, 2024, regulating greenhouse gas
(GHG) emissions from electric generating units under Section 111 of the Clean Air Act (Final Rule).
As a FERC-approved regional transmission organization (RTO), SPP is responsible for maintaining
reliability of the bulk electric system in its region covering all or part of 14 states. A key component of
SPP’s reliability-based responsibilities is assuring that sufficient resources are available when needed to
meet expected future demand.
The generating fleet in the SPP region has undergone significant changes in recent years, and SPP has
worked to keep pace by adapting its market design, operating processes, and transmission planning
practices. Through these adaptations, SPP has facilitated an ongoing transition to carbon-free generation
and is supportive of moving further toward a resource mix that reliably reduces emissions as necessary
new technology evolves. The SPP region has long been at the forefront of integrating renewable energy,
particularly wind generation. In the last decade, SPP has transitioned from a resource fleet that was
overwhelmingly made up of traditional generation to a fleet in which wind is the number-one supplier of
energy in the SPP region.
SPP’s success in integrating significant wind generation has depended largely on having sufficient flexible
thermal generation that can be called upon when wind is unavailable. However, the thermal fleet is
shrinking. Thermal units are being retired without being adequately replaced, resulting in less total, fuelassured, ramp-able capacity. Thermal units with these requisite reliability attributes also make up a
shrinking percentage of SPP’s total available generating capacity, as the growth of variable energy
resources is outpacing the addition of new thermal units. The remaining fleet is expected to carry a
potentially unsustainable burden of supplying the necessary reliability attributes needed to assure
continuous supply of electricity.
SPP sees no slowing in the growth of demand for electricity or in the growth of new load types such as
data centers, cryptocurrency mines, and electric vehicle. SPP is concerned that the current pace of new
generation development will be insufficient to offset current and projected resource retirement trends and
demand increases.
The region has also experienced extreme weather conditions that have impacted SPP’s ability to assure
energy provision during times when consumers depend the most on continuous supply of electricity. Since
Winter Storm Uri in February 2021, during which SPP was forced to interrupt service to customers for
short periods of time, Storms Elliott (December 2022) and Heather/Gerri (January 2024) presented similar
circumstances. SPP has also experienced extreme heat over the last two summers, contributing to a new
summer peak in 2023 that was 10% higher than the one set two summers prior. These challenges
underscore the increasing volatility and unpredictability of weather patterns, further highlighting the need
for enhanced grid resilience and adaptive strategies to ensure reliable energy provision in the face of such
extreme conditions.
As with previous EPA rulemakings, SPP submitted comments to the EPA in the docket for this Final Rule.
SPP submitted individual as well as joint comments with other impacted RTOs: Midcontinent Independent
System Operator, Inc.; PJM Interconnection, L.L.C.; and Electric Reliability Council of Texas, Inc. SPP
also engaged in meetings with EPA staff to discuss issues raised in the comments. SPP’s primary goal
throughout this engagement was to communicate the trending urgency of resource adequacy in the SPP
App.50
region and SPP’s sincere concerns about maintaining resource adequacy in the face of thermal generation
retirement, an otherwise changing resource mix, increasing demand, and extreme weather trends.
SPP acknowledges and expresses appreciation for EPA staff’s consideration of the comments and concerns
that SPP and other RTOs presented in the docket and subsequent meetings. SPP notes that the Final Rule
reflects changes EPA made from its proposed rule, including removing existing gas generation from the
Final Rule’s scope and including measures that may provide flexibility in dealing with reliabilityimpacting events. These changes represent a welcome step toward reflecting the importance of system
reliability and the role that existing flexible generation plays toward maintaining that reliability.
SPP remains concerned, however, about the impact the Final Rule may have on the region’s ability to
maintain resource adequacy and ensure reliability in the SPP region. SPP is concerned that limited
technological and infrastructure availability and the compliance time frame will have deleterious impacts
including the retirement of, or the decision not to build, thousands of MWs of baseload thermal generation.
If sufficient flexible thermal resources are not available to play their critical roles in SPP’s resource mix,
SPP’s ability to maintain regional reliability will be directly impacted. The Final Rule’s emissions limits
for existing coal and new gas generation are based on the EPA’s finding that carbon capture and
sequestration (CCS) technology is a viable best source of emissions reduction (BSER) in terms of
commercial availability and reasonable cost. SPP continues to be concerned that CCS has not yet been
adequately demonstrated at the required capture rate, has not been commercially produced at scale, and
will not be widely available and practicable at the level needed for the Final Rule’s 2032 compliance time
frame. Moreover, while the Final Rule contemplates a natural gas co-firing option for existing coal units
that choose to retire before 2039, SPP is concerned about the availability of gas infrastructure necessary
to adequately utilize that compliance option in that time frame.
SPP is not expressing these concerns about a hypothetical resource adequacy scenario in the future. SPP
and other grid operators are currently working to develop planning and operations policies and practices
to deal with resource adequacy issues that have already manifested. SPP’s recent Loss of Load Expectation
(LOLE) study indicated that, by 2029, as much as a 50% winter season Planning Reserve Margin (PRM)
could be necessary to maintain a one-day-in-ten-years LOLE. A PRM of that magnitude would require a
significant amount of new capacity to be added in a short time frame. It is important to note that this study
considered SPP’s existing and projected future resource mix without considering the potential impacts of
the Final Rule’s 2032 deadline for certain emissions limits. In other words, the study and its projected
increase in PRM did not consider the additional at-risk generation that may retire and not be adequately
replaced in a relatively short time frame resulting from the compliance time frames contained in the Final
Rule. This outcome would further intensify the need for generating capacity and associated transmission
upgrades in the SPP region, likely at a pace and cost unprecedented for the industry.
SPP will continue its work to maintain resource adequacy and system reliability. As part of that work,
SPP will continue to engage with stakeholders, other RTOs, and the EPA in efforts to address the
challenges presented by current and projected trends in resource availability and demand growth.
App.51
Exhibit C
App.52
IN THE UNITED STATES COURT OF APPEALS FOR
THE DISTRICT OF COLUMBIA CIRCUIT
WEST VIRGINIA, et al.,
)
)
Petitioners,
)
)
v.
)
)
U.S. ENVIRONMENTAL PROTECTION AGENCY, et al., )
)
Respondents.
)
)
DECLARATION OF JOHN T. BRIDSON
I, John T. Bridson, declare that the following statements made by me are true and accurate to
the best of my knowledge, information, and belief:
1. I am the Vice President of Generation of Evergy, Inc. ("Evergy" or the "Company"). As
Vice President of Generation, I oversee Evergy's electricity generation operations,
engineering, reliability, and power marketing. I have been in this role since June 2018. Prior
to this position, I served as Sr. Vice President Generation and Power Marketing for Westar
Energy, Inc. (“Westar”) from 2015 to 2018, Vice President Generation at Westar from 2011
to 2014, the Executive Director, Westar Generation from 2010 to 2011, and various Westar
generation engineering and plant management roles from 1993 to 2010.
2. If Evergy is required to immediately undertake steps as required in the Environmental
Protection Agency’s (“EPA”) “New Source Performance Standards for Greenhouse Gas
Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating
Units; Emission Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired
App.53
Electric Generating Units; and Repeal of the Affordable Clean Energy Rule,” 89 Fed. Reg.
39,798 (May 9, 2024) (“Rule”) while the Rule is litigated, the immediate and substantial
impacts to Evergy include, but may not be limited to:
•
Accelerating, by over 12 years, retirement decisions for coal-fired units to comply with
the Rule, immediately impacting Evergy’s Integrated Resource Plan (“IRP"), our
regularly updated 20-year regulatory resource planning document;
•
Prematurely retiring of approximately 3,983 megawatts ("MW") of coal-fired units,
constituting more than 67% of Evergy's coal-fired generating capacity by 2032 due to
the length of time required to receive regulatory approval, permit, construct, and
commission equipment that would be necessary for affected units to meet natural gas
co-firing or carbon capture and storage (“CCS”) conversions requiring Evergy to
immediately start investing resources in planning for expedited replacement of
generating sources;
•
Prematurely retiring the coal-fired units will also cause the loss of nearly 650 full-time
jobs by 2032 at the time of premature shuttering combined with the more immediate
impact of inability to attract and maintain qualified plant employees when job
elimination is imminent due to premature retirement; and
•
Prematurely retiring the coal-fired units will result in insufficient generation resources
to comply with the minimum reserve margin due to the risk of timely replacement
generation installation requiring Evergy to immediately attempt to negotiate contracts
for dispatchable resources in a capacity and energy constrained economic environment.
3. It takes many years to plan and implement changes to our generating and transmission
resources, Evergy would have to begin activities immediately regardless of the specifics of
App.54
any state plan later adopted to implement the Rule. Many of these impacts cannot be
reversed once the changes to the generating and transmission resources have begun.
4. I provide this declaration in support of our Motion to Stay EPA's Rule. This declaration is
based on my personal knowledge of facts and analysis conducted by Evergy staff and me.
Evergy
5. Evergy is a public holding company incorporated in 2017 and headquartered in Kansas City,
Missouri.
Evergy operates primarily through the following wholly-owned subsidiaries
listed below.
•
Evergy Kansas Central, Inc. is an integrated, regulated electric utility and provides
electricity to customers in the state of Kansas. It has one active wholly-owned
subsidiary with significant operations, Evergy Kansas South, Inc.
•
Evergy Metro, Inc. is an integrated, regulated electric utility that provides electricity to
customers in the states of Missouri and Kansas.
•
Evergy Missouri West, Inc. is an integrated, regulated electric utility that provides
electricity to customers in the state of Missouri.
The subsidiaries conduct business in their respective service territories using the name
Evergy. Evergy serves approximately 1.7 million customers located in Kansas and Missouri.
Customers include approximately 1.5 million residences, 0.2 million commercial firms, and
7,800 industrials, municipalities and other electric utilities.
6. The core tenets of Evergy’s strategy are as follows:
•
Affordability – operating the business cost-effectively and investing in technology and
infrastructure to keep rates affordable and improve regional rate competitiveness,
mitigating fuel and purchased power volatility by investing in a diverse generation fleet;
App.55
•
Reliability – targeting transmission and distribution infrastructure investment to support
reliability, flexibility, public safety, and resiliency; deploying new technology to
improve preventive maintenance and customer restorations times; and
•
Sustainability – investing at sustainable capital expenditure levels to maintain reliability
and customer affordability for the long-term and balancing clean energy investment to
continue fuel diversification and enable a responsible generation portfolio transition.
7. Evergy's total capacity by fuel type, including both owned generating capacity and power
purchase agreements, is as follows:
•
•
•
•
•
•
Coal: 5,930 MW (38%)
Wind: 4,525 MW (29%)
Natural Gas and Oil: 4,065 MW (26%)
Uranium: 1,106 MW (7%)
Solar and Landfill Gas 22 MW
Total 15,648 MW
8. Evergy Kansas Central, Evergy Metro and Evergy Missouri West are members of the
Southwest Power Pool (“SPP”). The SPP is a Federal Electric Reliability Commission
(“FERC”) approved regional transmission organization with the responsibility to ensure
reliable power supply, adequate transmission infrastructure and competitive wholesale
electricity prices in the region. As SPP members, Evergy Kansas Central, Evergy Metro
and Evergy Missouri West are required to maintain a minimum reserve margin of 15%.
This net positive supply of capacity is maintained through generation asset ownership,
capacity agreements, power purchase agreements and peak demand reduction programs.
The reserve margin is designed to support reliability of the region's electric supply.
9. The Evergy Companies are committed to a long-term strategy to reduce carbon dioxide
(“CO2”) emissions in a cost-effective and reliable manner. In 2023, Evergy achieved a
reduction of CO2 emissions, from owned generation, by half from 2005 levels. Evergy has
App.56
a goal to achieve net-zero carbon dioxide equivalent emissions, for scope 1 and scope 2
emissions, by 2045 with an interim goal of a 70% reduction of owned generation CO2
emissions from 2005 levels by 2030 through the responsible transition of the Evergy
Companies' generation fleet. The trajectory and timing of achieving these emissions
reductions are expected to be dependent on many external factors, including enabling
technology developments, the reliability of the power grid, availability of transmission
capacity, supportive energy policies and regulations, and other factors.
10. Public attention is currently focused on transitioning to a low carbon future, including
reducing greenhouse gas emissions and closing coal-fired generating units. Diversity of fuel
supply has historically provided cost and reliability benefits. For example, because
renewable generation can be intermittent, diversity of baseload generation fuel, including a
mix of coal and natural gas, has helped to maintain a consistent availability of power. In
addition, the Evergy Companies must prudently utilize the generation assets that regulators
have allowed the Evergy Companies to include in rates. The Evergy Companies use an IRP,
a detailed analysis that estimates factors that influence the future supply and demand for
electricity, to inform the manner in which they supply electricity. The IRP considers
forecasts of future electricity demand, fuel prices, transmission improvements, new
generating capacity, cost of environmental compliance, integration of renewables, energy
storage, energy efficiency and demand response initiatives. Strategies that the Evergy
Companies are pursuing to reduce emissions include:
•
•
•
•
•
retiring fossil fuel generation;
developing renewable energy facilities;
grid investment and advancement;
collaborating with regulators to offer customers the opportunity to procure
electricity produced with renewable resources; and
investing in customer energy efficiency programs.
App.57
11. Since 2005, the Evergy Companies have added over 4,600 MWs of renewable generation,
while retiring more than 2,400 MWs of fossil generation. The Evergy Companies are also
committed to transparency. On its website, http://investors.evergy.com, Evergy provides
quantitative and qualitative data regarding various environmental, social and governance
matters, including information related to emissions, waste and water.
12. As of December 31, 2023, the Evergy Companies had 4,658 employees, including 2,473
represented by five local unions of the International Brotherhood of Electrical Workers and
one local union of the United Government Security Officers of America. The Evergy
Companies employ 1,650 generation employees, 1,447 transmission and distribution
employees and 1,561 support employees that work primarily in the states of Kansas and
Missouri.
Evergy’s Integrated Resource Plan
13. Evergy has and applies tools to assess and project the status of our power plants to ensure
reliability and availability as part of an annual resource planning process. Every three years,
as required by the Missouri Public Service Commission ("MPSC") and the Kansas
Corporation Commission (“KCC”), the Company files an IRP. The fundamental objective
of the resource planning process is to provide the public with energy services that are safe,
reliable, and efficient, at just and reasonable rates, in a manner that serves the public
interest and is consistent with state energy and environmental policies. This objective
requires that the utility shall:
•
Consider demand-side resources, renewable energy, and supply-side resources on an
equivalent basis;
•
Use minimization of the present worth of long-run utility costs as the primary selection
App.58
criterion; and
•
Identify and where possible, quantitatively analyze any other considerations which are
critical to meeting the fundamental objective of the resource planning process.
Developing the IRP is a very time intensive task, and we recently submitted the plan to
the MPSC in April 2024 and KCC in May 2024.
14. Evergy is committed to a long-term strategy to reduce CO2 emissions in a cost-effective
and reliable manner. Evergy's coal fleet is aging and is increasingly at risk due to tightening
environmental regulations. As a result, each Evergy utility's IRP is built with a goal of
responsibly transitioning its fleet away from coal over time, while maintaining a diverse
fuel mix and sufficient flexibility to adjust plans as policy and technology change. A
responsible transition means one that focuses on maintaining reliability and affordability
while also reducing environmental impact over time.
15. Evergy current strategy to advance this responsible transition is outlined in the preferred
plan identified through the IRP. This plan includes the measured retirement of coal plants
over time and the replacement of this capacity and energy with a mix of renewable
resources, demand-side management programs, and new dispatchable resources. In addition
to replacing capacity, these additions also allow Evergy to meet increasing requirements
driven by higher resource adequacy requirements and load growth / economic development.
This resource plan is designed to be robust across a variety of uncertainties and to include a
diverse mix of resources that reduce the risk to both reliability and customer costs which
can come from “putting all of your eggs in one basket”. Despite the robustness of the risk
analysis performed, however, the future remains inherently uncertain and, as a result,
maintaining flexibility and continuing to adjust plans over time is imperative. The goal of
App.59
this preferred plan is to outline the Company’s current long-term strategy for meeting
customer energy needs, but also to particularly focus on the robustness of near-term
decisions which must be made to begin executing on that strategy. Given the increasing
capacity and energy requirements for Evergy, there is significant urgency to continue
executing on both supply- and demand-side additions outlined in the first three to five years
of this preferred plan. The analysis performed in this IRP will be used to support separate
regulatory filings related to these resource additions. These filings must be supported by the
IRP and not only by resource-specific evaluations because the evaluation of resource
decisions cannot be performed in a vacuum. The integrated analysis of risks and resource
options, along with customer needs for energy and capacity, is required to reflect the tradeoffs inherent in any resource decision. Any resource added (or not added) today has an
impact on future resource decisions in the same way that past resource decisions impact
decisions going-forward. Integrated analysis of these trade-offs is performed in IRP filings
and updated annually in order to make necessary adjustments to Evergy’s long-term
resource plan when conditions change.
16. The preferred plan meets the fundamental planning objectives to provide the public with
energy services that are safe, reliable, and efficient, at just and reasonable rates, in
compliance with all legal mandates, and in a manner that serves the public interest and is
consistent with state energy and environmental policies. The selected preferred plan is the
lowest-cost alternative resource plan on an expected value basis. As the inputs to the
preferred plan change, the plan will be reviewed and updated to meet the ongoing planning
objective.
17. Evergy’s consolidated plan, comprised of the summation of Evergy Metro’s, Evergy
App.60
Missouri West’s, and Evergy Kansas Central’s preferred plans, is shown in the figure
below. While evaluating consolidated plans can be and has been informative, particularly
given many of Evergy’s generating resources are jointly-owned by different Evergy
utilities, Evergy does not perform full integrated planning or select a preferred plan at the
consolidated level. This analysis is completed at the individual utility level and then
consolidated to produce the view below. Evergy is needing more accredited capacity due to
higher load growth and more stringent reserve margin requirements. While all thermal
resources were modeled as natural gas-fired resources throughout the twenty-year IRP
analysis, additions beyond 2035 are shown as "non-emitting firm, dispatchable resources"
consistent with recent IRPs. For planning purposes, Evergy assumes that new, non-emitting
dispatchable technologies will be available and cost-effective in the future which could
replace what is currently assumed to be conventional natural gas generation.
App.61
Total Evergy
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,t·'PreferredPlan includes a placeholder for an additional coal retirement in 2030 assumed to be Jeffrey Unit 2 (733 MW)
Impact of EPA’s Rule on Evergy’s Fossil Fuel-Fired Units
18. The graphic above displays Evergy’s current resource plan. Applying the plan’s resources
and current plan retirement dates to the subcategories identified in EPA’s “Emission
Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric
Generating Units”, to Evergy’s fossil-fuel fired units results in the premature shuttering of
approximately 3,983 megawatts of coal-fired units, constituting more than 67% of Evergy's
coal-fired generating capacity by 2032 due to inability to meet natural gas or carbon capture
and storage (“CCS”) conversions requirements as further discussed below.
App.62
19. Evergy’s current resource plan units can be subcategorized pursuant to the Rule based on
the generation source fuel type and the retirement dates as follows:
•
Natural Gas-Fired (40 CFR 60.5775b(c)(7&8)) – Units demonstrating low or
intermediate unit standard before January 1, 2030:
o 2028 Gas conversion - Lawrence Unit 5 (373 MW)
o 2030 Retirement date – Lake Road Unit 4/6 (95 MW)
•
Coal-Fired Exempt (40 CFR 60.5775b(c)(7&8)) - Units demonstrating that they plan
to permanently cease operating before January 1, 2032:
o 2028 Retirement - Lawrence Unit 4 (107 MW)
o 2030 Retirement date – Jeffrey Units 2 and 3 (1,466 MW)
•
Coal-Fired Medium – Term (40 CFR 60.5775b(c)(2)) - Units operating on or after
January 1, 2032, and demonstrating that they plan to permanently cease operating
before January 1, 2039, while co-firing 40% (by heat input) natural gas with emission
limitation of a 16% reduction in emission rate (lb CO2/MWh gross basis) by January 1,
2030.
o 2032 Retirement – La Cygne Unit 1 (750 MW)
•
Coal-Fired Long – Term (40 CFR 60.5775b(c)(1)) - Units operating on or after
January 1, 2039, with CCS with 90 percent capture of CO2 (88.4% reduction in
emission rate lb/MWh gross) by January 1, 2032.
o 2039 Retirement – Jeffrey Unit 1 (733 MW), La Cygne Unit 2 (668 MW), Iatan
Unit 1 (618 MW)
o Retirement outside the 20-year planning horizon – Iatan Unit 2 (652), Hawthorn
Unit 5 (562 MW)
20. Evergy is required by state regulation to utilize at least a twenty-year planning horizon, and
Evergy looks at a longer horizon in some planning decisions. Most of the activities we
undertake require years, and sometimes decades, to plan and execute. The nature of the
utility planning process requires us to take actions well in advance of a forecasted event or
need in order to ensure that we maintain our ability to provide the most cost-effective and
reliable electric service possible to our customers. Evergy, its regulators and customers will
be harmed by the immediate need to modify the resource commitment, begin implementing
that plan and potentially reverse those efforts if the rule stays in place.
App.63
21. Natural Gas Conversion of Coal-Fired Medium – Term Units (40 CFR 60.5775b(c)(2)) It is
not reasonably possible for Evergy to plan, permit, contract, construct, commission and
procure natural gas service for these primarily rural sites at the scale and with the firm
delivery needed and to also modify the boilers for natural gas operations in the next 6 years
to be compliant with the Rule. As natural gas is not reasonably available to the units in this
subcategory, the units would be required to immediately announce prematurely retirement by
2032. This totals to 750 MW of 5,930 MW or 13% of Evergy’s coal-fired fleet.
Anticipated Schedule for this Category:
a. Plan (2-3 years estimate) – update IRP to determine if replacement generation or
natural gas modification is the most cost-effective and reliable option for
customers and receive regulatory approval.
i.
Updating the IRP is a detailed, time-intensive process that can easily
require over one year for the team to complete, file, and respond to
MPSC, KCC, or other stakeholders.
ii. Receiving regulatory approval is the next step after the IRP is updated
and is similarly a detailed, time-intensive process that may require a case
be filed, heard, and order received that can require over one year.
iii. Consultant feasibility engineering studies are required to determine the
boiler modifications required.
b. Permit (1-3 years estimate) – permitting necessary boiler modifications for
natural gas operation and gas line.
i. Permitting of modifications to support 40% natural gas operations will
require substantial resources for the number of units selected. There
are limited consultants available to complete this work.
ii. Permitting of new natural gas lines for gas operations will require
substantial resources for the unit impacted and the limited consultants
available to complete the work. Further, the unit will require a
substantial addition of a trunk line to the unit from the interstate pipeline
that may also have to be updated for capacity and pressure requirements.
c. Contract (3-5 years estimate) – contracting for boiler modification and pipeline
and associated facilities.
i. Detailed design and engineering for on-site boiler modifications and
supporting infrastructure such as regulating stations.
ii. Interstate pipeline firm capacity agreements will likely be required in
order to meet SPP capacity accreditation requirements. Capacity may be
limited by interstate pipeline capacity and pressure.
App.64
iii.
Where firm capacity does not exist, the interstate pipeline will have to be
upgraded, which will be required to be completed before natural gas can
be delivered. These upgrades are performed by the pipelines and natural
gas providers and are not directly managed by Evergy. If upgrades are
not sufficient to supply the capacity, the natural gas providers may have
to pursue the install
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