[Federal Register Volume 91, Number 10 (Thursday, January 15, 2026)]
[Rules and Regulations]
[Pages 1910-2005]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2026-00677]
[[Page 1909]]
Vol. 91
Thursday,
No. 10
January 15, 2026
Part III
Environmental Protection Agency
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40 CFR Part 60
New Source Performance Standards Review for Stationary Combustion
Turbines and Stationary Gas Turbines; Final Rule
Federal Register / Vol. 91, No. 10 / Thursday, January 15, 2026 /
Rules and Regulations
[[Page 1910]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2024-0419; FRL-11542-02-OAR]
RIN 2060-AW21
New Source Performance Standards Review for Stationary Combustion
Turbines and Stationary Gas Turbines
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: The U.S. Environmental Protection Agency (EPA, or Agency) is
finalizing amendments to the new source performance standards (NSPS)
for stationary combustion turbines and stationary gas turbines pursuant
to a review required by the Clean Air Act (CAA). As a result of this
review, the EPA is establishing subcategories for new, modified, or
reconstructed stationary combustion turbines based on size, rates of
utilization, design efficiency, and fuel type. The EPA determined that
combustion controls are the best system of emission reduction (BSER)
for nitrogen oxide (NOX) emissions for most new, modified,
or reconstructed stationary combustion turbines. For one subcategory,
the BSER for NOX is combustion controls with the addition of
selective catalytic reduction (SCR). The EPA further determined that
the BSER for sulfur dioxide (SO2) emissions has not changed
since the last NSPS review. Based on these determinations, the Agency
is promulgating standards of performance in a new subpart of the Code
of Federal Regulations (CFR). The Agency is also adding a subcategory
for stationary combustion turbines that are used in temporary
applications, exempting certain sources from title V requirements, and
finalizing other provisions. The EPA is finalizing amendments to
existing regulations to address or clarify specific technical and
editorial issues.
DATES: This final rule is effective on January 15, 2026. The
incorporation by reference of certain publications listed in the rule
is approved by the Director of the Federal Register as of January 15,
2026. The incorporation by reference of certain other material listed
in the rule was approved by the Director of the Federal Register as of
July 8, 2004, and July 6, 2006.
ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2024-0419. All documents in the docket are
listed on the https://www.regulations.gov website. Although listed,
some information is not publicly available, e.g., Confidential Business
Information (CBI) or other information whose disclosure is restricted
by statute. Certain other material, such as copyrighted material, is
not placed on the internet and will be publicly available only as
portable document format (PDF) versions that can only be accessed on
the EPA computers in the docket office reading room. Certain databases
and physical items cannot be downloaded from the docket but may be
requested by contacting the docket office at (202) 566-1744. The docket
office has up to 10 business days to respond to these requests. Except
for such material, all documents are available electronically in
Regulations.gov or on the EPA computers in the docket office reading
room at the EPA Docket Center, WJC West Building, Room Number 3334,
1301 Constitution Ave. NW, Washington, DC. The Public Reading Room
hours of operation are 8:30 a.m. to 4:30 p.m. Eastern Standard Time
(EST), Monday through Friday. The telephone number for the Public
Reading Room is (202) 566-1744, and the telephone number for the EPA
Docket Center is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: For information about this final rule,
contact John Ashley, Industrial Processing and Power Division (D243-
02), Office of Clean Air Programs, U.S. Environmental Protection
Agency, 109 T.W. Alexander Drive, P.O. Box 12055, RTP, North Carolina
27711; telephone number: (919) 541-1458; and email address:
[email protected].
SUPPLEMENTARY INFORMATION:
Preamble acronyms and abbreviations. Throughout this document the
use of ``we,'' ``us,'' or ``our'' is intended to refer to the EPA. We
use multiple acronyms and terms in this preamble. While this list may
not be exhaustive, to ease the reading of this preamble and for
reference purposes, the EPA defines the following terms and acronyms
here:
ANSI American National Standards Institute
ASME American Society of Mechanical Engineers
ASTM American Society for Testing and Materials
BPT benefit-per-ton
BSER best system of emission reduction
Btu British thermal unit
CAA Clean Air Act
CAMPD Clean Air Markets Program Data
CBI Confidential Business Information
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CEMS continuous emissions monitoring system
CFR Code of Federal Regulations
CHP combined heat and power
CMS continuous monitoring system
CO carbon monoxide
CO2 carbon dioxide
DLE dry low-emission
DLN dry low-NOX
EIA Economic Impact Analysis
EPA Environmental Protection Agency
ERT Electronic Reporting Tool
FR Federal Register
GE General Electric
GHG greenhouse gas
GJ gigajoule(s)
gr grains
HAP hazardous air pollutant
HHV higher heating value
HRSG heat recovery steam generator
ICR information collection request
ISA Integrated Science Assessment
kW kilowatt
LAER lowest achievable emission rate
LCOE levelized cost of electricity
lb/MWh pounds per megawatt-hour
lb/MMBtu pounds per million British thermal units
MJ megajoules
MMBtu/h million British thermal units per hour
MW megawatt
MWh megawatt-hour
NAICS North American Industry Classification System
NEI National Emissions Inventory
NESHAP national emission standards for hazardous air pollutants
NETL National Energy Technology Laboratory
ng/J nanograms per joule
NOX nitrogen oxide
NSPS new source performance standards
NSR New Source Review
NSSN National Standards System Network
NTTAA National Technology Transfer and Advancement Act
O2 oxygen gas
O&M operating and maintenance
OEM original equipment manufacturers
OMB Office of Management and Budget
PDF portable document format
PM particulate matter
PM2.5 particulate matter (diameter less than or equal to
2.5 micrometers)
ppm parts per million
ppmv parts per million by volume
ppmvd parts per million by volume dry
ppmw parts per million by weight
PRA Paperwork Reduction Act
PSD Prevention of Significant Deterioration
RATA relative accuracy test audit
RFA Regulatory Flexibility Act
RICE reciprocating internal combustion engines
scf standard cubic feet
scm standard cubic meter
SCR selective catalytic reduction
SO2 sulfur dioxide
SSM startup, shutdown, and malfunction
ULSD ultra-low-sulfur diesel
UMRA Unfunded Mandates Reform Act
U.S.C. United States Code
VCS voluntary consensus standard
[[Page 1911]]
VOC volatile organic compound(s)
Table of Contents
I. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document and other related
information?
C. Judicial Review and Administrative Review
II. Background
A. What is the statutory authority for this final action?
B. How does the EPA perform the NSPS review?
C. What is the source category regulated in this final action?
D. The Role of the NSPS
III. What changes did we propose for the stationary combustion
turbines and stationary gas turbines NSPS?
IV. What actions are we finalizing and what is our rationale for
such decisions?
A. Applicability
B. NOX Emissions Standards
C. SO2 Emissions Standards
D. Consideration of Other Criteria Pollutants
E. Additional Amendments
F. NSPS Subpart KKKKa Without Startup, Shutdown, and Malfunction
Exemptions
G. Testing and Monitoring Requirements
H. Electronic Reporting
I. Other Final Amendments
J. Effective Date and Compliance Date
K. Severability
V. Summary of Cost, Environmental, and Economic Impacts
A. What are the air quality impacts?
B. What are the secondary impacts?
C. What are the cost impacts?
D. What are the economic impacts?
E. What are the benefits?
VI. What actions are we not finalizing and what is our rationale for
such decisions?
A. Clarification to the Definition of Stationary Combustion
Turbine
B. Definition of Noncontinental Area
C. Affected Facility
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Executive Order 14192: Unleashing Prosperity Through
Deregulation
C. Paperwork Reduction Act (PRA)
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act (UMRA)
F. Executive Order 13132: Federalism
G. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
H. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
J. National Technology Transfer and Advancement Act (NTTAA) and
1 CFR Part 51
K. Congressional Review Act (CRA)
I. General Information
A. Does this action apply to me?
The source category that is the subject of this final action is
composed of stationary combustion turbines and stationary gas turbines
regulated under CAA section 111. Based on the number of sources of
stationary combustion turbines listed in the 2020 National Emissions
Inventory (NEI), most, but not all, are accounted for by the following
2022 North American Industry Classification System (NAICS) codes. These
include 2111 (Oil and Gas Extraction), 2211 (Electric Power Generation,
Transmission, and Distribution), 2212 (Natural Gas Distribution), 3251
(Basic Chemical Manufacturing), 4862 (Pipeline Transportation of
Natural Gas), and 518210 (Data Processing, Hosting, and Related
Services). The NAICS codes serve as a guide for readers outlining the
types of entities that this final action is likely to affect.
The NSPS codified in 40 CFR part 60, subpart KKKKa, are directly
applicable to affected facilities that began construction,
modification, or reconstruction after December 13, 2024. Federal,
State, local, and Tribal government entities that own and/or operate
stationary combustion turbines subject to 40 CFR part 60, subpart
KKKKa, are affected by these amendments and standards. If you have any
questions regarding the applicability of this action to a particular
entity, you should carefully examine the applicability criteria found
in 40 CFR part 60, subparts GG, KKKK, and KKKKa, and consult the person
listed in the FOR FURTHER INFORMATION CONTACT section of this preamble,
your State air pollution control agency with delegated authority for
NSPS, or your EPA Regional Office.
B. Where can I get a copy of this document and other related
information?
In addition to being available in the docket, an electronic copy of
this final action is available on the internet at https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance. Following publication in the Federal
Register, the EPA will post the Federal Register version of the final
rule and key technical documents at this same website.
C. Judicial Review and Administrative Review
Under CAA section 307(b)(1), judicial review of this final action
is available only by filing a petition for review in the United States
Court of Appeals for the District of Columbia Circuit by March 16,
2026. Under CAA section 307(b)(2), the requirements established by this
final rule may not be challenged separately in any civil or criminal
proceedings brought by the EPA to enforce the requirements.
CAA section 307(d)(7)(B) further provides that ``[o]nly an
objection to a rule or procedure which was raised with reasonable
specificity during the period for public comment (including any public
hearing) may be raised during judicial review.'' This section also
provides a mechanism for the EPA to convene a proceeding for
reconsideration ``[i]f the person raising an objection can demonstrate
to the EPA that it was impracticable to raise such objection within
[the period for public comment] or if the grounds for such objection
arose after the period for public comment, (but within the time
specified for judicial review) and if such objection is of central
relevance to the outcome of the rule.'' Any person seeking to make such
a demonstration to us should submit a Petition for Reconsideration to
the Office of the Administrator, U.S. Environmental Protection Agency,
Room 3000, WJC South Building, 1200 Pennsylvania Ave. NW, Washington,
DC 20460, with a copy to both the person(s) listed in the preceding FOR
FURTHER INFORMATION CONTACT section, and the Associate General Counsel
for the Air and Radiation Law Office, Office of General Counsel (Mail
Code 2344A), U.S. Environmental Protection Agency, 1200 Pennsylvania
Ave. NW, Washington, DC 20460.
II. Background
A. What is the statutory authority for this final action?
The EPA's authority for this final rule is CAA section 111, which
governs the establishment of standards of performance for stationary
sources. CAA section 111(b)(1)(A) requires the EPA Administrator to
promulgate a list of categories of stationary sources that the
Administrator, ``in his judgment,'' finds ``causes, or contributes
significantly to, air pollution which may reasonably be anticipated to
endanger public health or welfare.'' The EPA has the authority under
this section to define the scope of the source categories; to
determine, consistent with the statutory requirements, the pollutants
for which standards should be developed; and to distinguish among
classes, types, and sizes within categories in establishing
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the standards.\1\ Once the EPA lists a source category that contributes
significantly to dangerous air pollution, the EPA must, under CAA
section 111(b)(1)(B), establish ``standards of performance'' for ``new
sources'' in the source category. These standards are referred to as
new source performance standards, or NSPS. The NSPS are national
requirements that apply directly to the sources subject to them.
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\1\ 42 U.S.C. 7411(b)(2) provides the EPA the authority to
establish subcategories.
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Under CAA section 111(a)(1), a ``standard of performance'' is
defined as ``a standard for emissions of air pollutants'' that is
determined in a specified manner. When the EPA establishes or revises a
performance standard, CAA section 111(a)(1) provides that such standard
must ``reflect[ ] 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.'' Thus, the
term ``standard of performance'' as used in CAA section 111 makes clear
that the EPA must determine both the ``best system of emission
reduction . . . adequately demonstrated'' (BSER) for emissions of the
relevant air pollutants by regulated sources in the source category and
the ``degree of emission limitation achievable through the application
of the [BSER].'' \2\ As explained further below, to determine the BSER,
the EPA first identifies the ``system[s] of emission reduction'' that
are ``adequately demonstrated,'' and then determines the ``best'' of
those adequately demonstrated systems, ``taking into account'' factors
including ``cost,'' ``nonair quality health and environmental impact,''
and ``energy requirements.'' The EPA then derives from that system an
``achievable'' ``degree of emission limitation.'' The EPA must then,
under CAA section 111(b)(1)(B), promulgate ``standard[s] for
emissions''--the NSPS--that reflect that level of stringency. The EPA
may determine that different sets of sources have different
characteristics relevant for determining the BSER for emissions of the
relevant air pollutants and may subcategorize sources accordingly.\3\
CAA section 111(b)(5) generally precludes the EPA from prescribing a
particular technological system that must be used to comply with a
standard of performance. Rather, sources can select any measure or
combination of measures that will achieve the standard.
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\2\ West Virginia v. EPA, 597 U.S. 697, 709 (2022).
\3\ 42 U.S.C. 7411(b)(2).
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Pursuant to the definition of new source in CAA section 111(a)(2),
standards of performance apply to facilities that begin construction,
modification, or reconstruction after the date of publication of the
proposed standards in the Federal Register. Under CAA section
111(a)(4), ``modification'' means any physical change in, or change in
the method of 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. Changes to an
existing facility that do not result in an increase in emissions are
not considered modifications. Under the provisions in 40 CFR 60.15,
reconstruction means the replacement of components of an existing
facility such that: (1) the fixed capital cost of the new components
exceeds 50 percent of the fixed capital cost that would be required to
construct a comparable entirely new facility; and (2) it is
technologically and economically feasible to meet the applicable
standards. Pursuant to CAA section 111(b)(1)(B), the standards of
performance or revisions thereof shall become effective upon
promulgation.
1. Key Elements of Determining a Standard of Performance
Congress first defined the term ``standard of performance'' when
enacting CAA section 111 in the 1970 Clean Air Act, amended the
definition in the Clean Air Act Amendments (CAAA) of 1977, and then
amended the definition again in the 1990 CAAA to largely restore the
definition as it read in the 1970 CAA. The D.C. Circuit has reviewed
CAA section 111 rulemakings on numerous occasions since 1973 and has
developed a body of caselaw that interprets the term.\4\
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\4\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C.
Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C.
Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981);
Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999);
Portland Cement Ass'n v. EPA, 665 F.3d 177 (D.C. Cir. 2011);
American Lung Ass'n v. EPA, 985 F.3d 914 (D.C. Cir. 2021), rev'd in
part, West Virginia v. EPA, 597 U.S. 697 (2022). See also Delaware
v. EPA, 785 F.3d 1 (D.C. Cir. 2015).
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The basis for standards of performance is the ``degree of emission
limitation'' that is ``achievable'' by sources in the source category
by application of the ``best system of emission reduction'' that the
EPA determines is ``adequately demonstrated'' (BSER). As explained
further below in this section, the D.C. Circuit has explained that
systems are not ``adequately demonstrated'' if they are ``purely
theoretical or experimental.'' \5\ The D.C. Circuit has stated that in
determining the ``best'' adequately demonstrated system for the
pollutants at issue, the EPA must also take into account ``the amount
of air pollution'' reduced.\6\ The D.C. Circuit has also stated that
the EPA may weigh the various factors identified in the statute and
caselaw to determine the ``best'' system and has emphasized that the
EPA has significant discretion in weighing the factors.\7\
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\5\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 (D.C.
Cir. 1973).
\6\ See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir.
1981). The D.C. Circuit has stated that EPA must also take into
account ``technological innovation.'' See id. at 347.
\7\ See Lignite Energy Council, 198 F.3d at 933 (``Because
section 111 does not set forth the weight that should be assigned to
each of these factors, we have granted the agency a great degree of
discretion in balancing them.'').
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After determining the BSER, the EPA sets an achievable emission
limit based on application of the BSER.\8\ For a CAA section 111(b)
rule, the EPA determines the standard of performance that reflects the
achievable emission limit. For a CAA section 111(d) rule, the States
have the obligation of establishing standards of performance for the
affected sources that reflect the degree of emission limitation that
the EPA has determined and provided to States as part of an emission
guideline. In applying these standards to existing sources, States are
permitted to take a source's remaining useful life and other factors
into account.
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\8\ See, e.g., Oil and Natural Gas Sector: New Source
Performance Standards and National Emission Standards for Hazardous
Air pollutants Reviews (77 FR 49494; August 16, 2012) (describing
the three-step analysis in setting a standard of performance).
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In identifying ``system[s] of emission reduction, the EPA has
historically followed a ``technology-based approach'' that focuses on
``measures that improve the pollution performance of individual
sources,'' such as ``add-on controls.'' \9\ The EPA departed from its
historical approach in a significant way in the 2015 Clean Power Plan
(CPP) \10\ by setting a BSER in which the ``system'' of emissions
reduction involved shifting electricity generation from one type of
fuel to another. In West Virginia v. EPA, the Supreme Court applied the
major questions doctrine to hold that the term ``system'' did not
provide the requisite clear authorization to support the CPP's BSER,
which the Court described as ``carbon emissions
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caps based on a generation shifting approach'' \11\ that capped
``emissions at a level that will force a nationwide transition away
from the use of coal to generate electricity[.]'' \12\ The Court
explained that the EPA's BSER ``forc[es] a shift throughout the power
grid from one type of energy source to another,'' which constituted ``
`unprecedented power over American industry' '' and was different in
kind from the type of ``system'' of emissions reduction envisioned by
CAA section 111(d).\13\
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\9\ See West Virginia v. EPA, 597 U.S. at 727 (internal
quotations removed).
\10\ 80 FR 64662 (Oct. 23, 2015).
\11\ West Virginia v. EPA, 597 U.S. at 732.
\12\ Id. at 734.
\13\ Id. at 728 (citation omitted).
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To qualify for selection as the BSER, the system of emission
reduction must be ``adequately demonstrated'' as ``the Administrator
determines.'' The plain text of CAA section 111(a)(1), and in
particular the terms ``adequately'' and ``the Administrator
determines,'' confer discretion to the EPA in identifying the
appropriate system, including making scientific and technological
determinations and considering a broad range of policy
considerations.\14\ However, the terms ``adequately'' and
``demonstrated,'' as well as applicable caselaw, make clear that the
EPA may not determine that a ``purely theoretical or experimental''
system is ``adequately demonstrated.'' \15\
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\14\ Nat'l Asphalt Pavement Ass'n v. Train, 539 F.2d 775, 786
(D.C. Cir. 1976); Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427,
434 (D.C. Cir. 1973).
\15\ Essex Chem. Corp., 486 F.2d at 433-34; see Portland Cement
Assn. v. Ruckelshaus, 486 F.2d 375, 391-92 (D.C. Cir. 1973) (EPA may
not base an ``adequately demonstrated'' determination on a ``
`crystal ball' inquiry'') (citation omitted).
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In addition, CAA section 111(a)(1) requires the EPA to account for
``the cost of achieving [the emission] reduction'' in determining the
adequately demonstrated BSER. Although the CAA does not describe how
the EPA is to account for costs to affected sources, the D.C. Circuit
has formulated the cost standard in various ways, including stating
that the EPA may not adopt a standard the cost of which would be
``excessive'' or ``unreasonable.'' \16\ The EPA has considerable
discretion in considering cost under section 111(a), both in
determining the appropriate level of costs and in balancing costs with
other BSER factors.\17\ The D.C. Circuit has repeatedly upheld the
EPA's consideration of cost in reviewing standards of performance.\18\
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\16\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
See 79 FR 1430, 1464 (January 8, 2014); Lignite Energy Council, 198
F.3d at 933 (costs may not be ``exorbitant''); Portland Cement Ass'n
v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975) (costs may not be
``greater than the industry could bear and survive'').
\17\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
\18\ See Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440
(D.C. Cir. 1973); Portland Cement Ass'n v. Ruckelshaus, 486 F.2d
375, 387-88 (D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298,
313 (D.C. Cir. 1981).
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The Agency does not apply a brightline test in determining what
level of cost is reasonable. In evaluating whether the cost
reasonableness of a particular system of emission reduction, the EPA
considers various costs associated with the particular air pollution
control measure or a level of control, including capital costs and
operating costs, and the emission reductions that the control measure
or particular level of control can achieve. The Agency considers these
costs in the context of the industry's overall capital expenditures and
revenues. The Agency also considers cost effectiveness analysis as a
useful metric, and a means of evaluating whether a given control
achieves emission reduction at a reasonable cost. A cost effectiveness
analysis allows comparisons of relative costs and outcomes (effects) of
two or more options. In general, cost effectiveness is a measure of the
outcomes produced by resources spent. In the context of air pollution
control options, cost effectiveness typically refers to the annualized
cost of implementing an air pollution control option divided by the
amount of pollutant reductions realized annually. Notably, a cost
effectiveness analysis is not intended to constitute or approximate a
benefit-cost analysis in which benefits are compared to costs but
rather is intended to provide a metric to compare the relative cost of
different air pollution control options. The EPA typically has
considered cost effectiveness along with various associated cost
metrics, such as capital costs and operating costs, total costs, costs
as a percentage of capital for a new facility, and the cost per unit of
production. In many contexts, the cost per unit of production may be
passed on to consumers, including ratepayers in the utility context and
consumers of end products in other contexts.
Under CAA section 111(a)(1), the EPA is required to take into
account ``any nonair quality health and environmental impact and energy
requirements'' in determining the BSER. Nonair quality health and
environmental impacts may include the impacts of the disposal of
byproducts of the air pollution controls, or requirements of the air
pollution control equipment for water.\19\ Energy requirements may
include the impact, if any, of the air pollution controls on the
source's own energy needs.\20\ In addition, based on the D.C. Circuit's
interpretations of CAA section 111, energy requirements may also
include the impact, if any, of the air pollution controls on the energy
supply for a particular area or nationwide.\21\ In addition, the EPA
has considered under this statutory factor whether possible controls
would create risks to the reliability of the electricity system.
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\19\ Portland Cement Ass'n v. Ruckelshaus, 465 F.2d 375, 387-88
(D.C. Cir. 1973), cert. denied, 417 U.S. 921 (1974).
\20\ For details on the modeled energy requirements associated
with CCS, please see section 6.4 of the RIA for this rule.
\21\ See Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44
FR 33583-84; June 11, 1979); 79 FR 1430, 1465 (January 8, 2014)
(citing Sierra Club v. Costle, 657 F.2d at 351).
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After the EPA evaluates the statutory factors with respect to
adequately demonstrated control technologies, the EPA compares the
various systems of emission reductions and determines which system is
``best,'' and therefore represents the BSER. The D.C. Circuit has also
held that the term ``best'' authorizes the EPA to consider factors in
addition to the ones enumerated in CAA section 111(a)(1) that further
the purpose of the statute. In particular, consistent with the plain
language and the purpose of CAA section 111(a)(1), which requires the
EPA to determine the ``best system of emission reduction'' (emphasis
added), the EPA must consider the quantity of emissions at issue.\22\
In determining which adequately demonstrated system of emission
reduction is the ``best,'' the EPA has broad discretion. In Sierra Club
v. Costle, 657 F.2d 298 (D.C. Cir. 1981), the court explained that
``section 111(a) explicitly instructs the EPA to balance multiple
concerns when promulgating a NSPS'' \23\ and emphasized that ``[t]he
text gives the EPA broad discretion to weigh different factors in
setting the standard,'' including the amount of emission reductions,
the cost of the controls, and the non-air quality environmental impacts
and energy requirements.\24\
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\22\ Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981).
The D.C. Circuit has also held that Congress intended for CAA
section 111 to create incentives for new technology and therefore
that the EPA is required to consider technological innovation as one
of the factors in determining the ``best system of emission
reduction.'' See id. at 346-47.
\23\ Sierra Club v. Costle, 657 F.2d at 319; see also AEP v.
Connecticut, 564 U.S. 410, 427 (2011).
\24\ Sierra Club v. Costle, 657 F.2d at 321; see also New York
v. Reilly, 969 F.2d at 1150.
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The EPA then establishes a standard of performance that reflects
the degree of emission limitation achievable through the implementation
of the BSER. A standard of performance is
[[Page 1914]]
``achievable'' if a technology can reasonably be projected to be
available to an individual source at the time it is constructed so as
to allow it to meet the standard.\25\ For purposes of evaluating the
source category and determining BSER, the EPA can determine whether
subcategorization is appropriate based on classes, types, and sizes of
sources, and may identify a different BSER and establish different
performance standards for each subcategory. The result of the analysis
and BSER determination leads to standards of performance that apply to
facilities that begin construction, reconstruction, or modification
after the date of publication of the proposed standards in the Federal
Register. Because the NSPS reflect the BSER under conditions of proper
operation and maintenance, in doing its review, the EPA also evaluates
and determines the proper testing, monitoring, recordkeeping and
reporting requirements needed to ensure compliance with the emission
standards.
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\25\ Sierra Club v. Costle, 657 F.2d at 364, n.276.
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B. How does the EPA perform the NSPS review?
CAA section 111(b)(1)(B) requires the EPA to, ``at least every 8
years, review and, if appropriate, revise'' the standards of
performance applicable to new, modified, or reconstructed sources.
However, 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 the standard. If
the EPA revises the standards of performance, they must reflect the
degree of emission limitation achievable through the application of the
BSER, which is selected from among adequately demonstrated technologies
after consideration of the cost of achieving such reduction and any
nonair quality health and environmental impact and energy
requirements.\26\ When conducting a review of an existing performance
standard, the EPA may, as appropriate and consistent with the statutory
requirements, add emission limits for pollutants or emission sources
not currently regulated for that source category.
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\26\ See 42 U.S.C. 7411(a)(1).
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In reviewing an NSPS for a source category to determine whether it
is ``appropriate'' to revise the standards of performance, the EPA
evaluates the statutory factors, which may include consideration of the
following information: \27\
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\27\ See generally 42 U.S.C. 7411; 76 FR 65653, 65658 (Oct. 24,
2011).
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Expected growth for the source category, including how
many new facilities, modifications, or reconstructions may trigger NSPS
in the future.
Pollution control measures, including advances in control
technologies, process operations, design or efficiency improvements, or
other systems of emission reduction, that the Administrator determines
have been ``adequately demonstrated'' in the regulated industry.
Available information from the implementation and
enforcement of current requirements indicating that emission
limitations and percent reductions beyond those required by the current
standards are achieved in practice.
Costs (including capital and annual costs) associated with
implementation of the available pollution control measures.
The amount of emission reductions achievable through
application of such pollution control measures.
Any non-air quality health and environmental impact and
energy requirements associated with those control measures.
C. What is the source category regulated in this final action?
The EPA first promulgated NSPS for stationary gas turbines on
September 10, 1979.\28\ These standards of performance are codified in
40 CFR part 60, subpart GG, and are applicable to sources that
commenced construction, modification, or reconstruction after October
3, 1977. The standards of performance in subpart GG regulate emissions
of NOX and SO2 from all new, modified, or
reconstructed simple and regenerative cycle gas turbines and the gas
turbine portion of a combined cycle steam/electric generating system.
The EPA last reviewed and revised the NOX and SO2
standards of performance on July 6, 2006, and promulgated 40 CFR part
60, subpart KKKK, which is applicable to stationary combustion turbines
that commenced construction, modification, or reconstruction after
February 18, 2005.\29\ In subpart KKKK, the definition of the source
was expanded to include all equipment, including but not limited to the
combustion turbine; the fuel, air, lubrication, and exhaust gas
systems; the control systems (except emission control equipment); the
heat recovery system (including heat recovery steam generators (HRSG)
and duct burners); and any ancillary components and sub-components
comprising any simple cycle, regenerative/recuperative cycle, and
combined cycle stationary combustion turbine, and any combined heat and
power (CHP) stationary combustion turbine-based system.
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\28\ See 44 FR 52792 (Sept. 10, 1979).
\29\ See 71 FR 38482 (July 6, 2006).
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The stationary combustion turbine source category consists of
combustion turbines with design base load ratings (i.e., maximum heat
input at ISO conditions) equal to or greater than 10.7 gigajoules per
hour (GJ/h) (10 million British thermal units per hour (MMBtu/h)) \30\
based on the higher heating value (HHV) of the fuel and applies to
combustion turbines and their associated HRSG and duct burners, as
described above. The source is ``stationary'' because the combustion
turbine is not self-propelled or intended to be propelled while
performing its function. Combustion turbines may, however, be mounted
on a vehicle (or trailer) for portability and still be considered
stationary. As discussed in section IV.B.2.e of this preamble, the EPA
is amending the applicability of subparts KKKK and KKKKa to provide
that combustion turbines that are subject to applicable CAA title II
standards are not subject to the NSPS. To the EPA's knowledge, no such
stationary combustion turbines are currently being used in temporary
applications.
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\30\ The base load rating is based on the heat input to the
combustion turbine engine. Any additional heat input from duct
burners used with HRSG units or fuel preheaters is not included in
the heat input value used to determine the applicability of this
subpart to a given stationary combustion turbine. However, this
subpart does apply to emissions from any HRSG and duct burners that
are associated with a combustion turbine subject to this subpart.
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The NOX standards in subparts GG and KKKK are generally
based on the application of combustion controls (as the BSER) and allow
the turbine owner or operator the choice of meeting a concentration-
based emission standard or an output-based emission standard. The
concentration-based emission limits are in units of parts per million
by volume dry (ppmvd) at 15 percent oxygen gas (O2).\31\ The
output-based emission limits are in units of mass per unit of useful
recovered energy, nanograms per joule (ng/J) or pounds per megawatt-
hour (lb/MWh). Each NOX limit in subparts GG and KKKK is
based on the application of combustion controls as the BSER, but
individual standards may differ for individual
[[Page 1915]]
subcategories of combustion turbines based on the following factors:
the fuel input rating at base load, the fuel used, the application, the
load, and the location of the turbine.\32\ The fuel input rating of the
turbine does not include any supplemental fuel input to the heat
recovery system and refers to the rating of the combustion turbine
itself.
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\31\ Throughout this document, all references to parts per
million (ppm) NOX are intended to be interpreted as ppmvd
at 15 percent O2, unless otherwise noted.
\32\ Throughout this document, all uses of the term ``turbine''
refer to a ``combustion turbine'' as defined in subparts KKKK and
KKKKa.
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The standards of performance for SO2 emissions in
subparts GG and KKKK reflect the BSER of using low-sulfur fuels for all
new, modified, or reconstructed combustion turbines, regardless of
class, size, or type. The input-based SO2 standard applies
to the sulfur content of the fuel combusted in the turbine. The NSPS
also includes an optional output-based standard that limits the
discharge of excess SO2 into the atmosphere as a fraction of
the gross energy output of the combustion turbine.\33\
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\33\ See the 2024 Proposed Rule (89 FR 101310; Dec. 13, 2024)
for further discussion of the specific subcategories in previous
NSPS and the applicable limits for NOX and SO2
emissions in those rules.
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Combustion turbines are a large and diverse source category.
Thousands of stationary combustion turbines are operating across
numerous industrial sectors. For instance, in the utility sector alone,
there are approximately 3,400 existing stationary combustion
turbines.\34\ Generally, existing combustion turbine sources are
subject to either subpart KKKK or subpart GG.
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\34\ See the U.S. Environmental Protection Agency's (EPA)
National Electric Energy Data System database. NEEDS rev 06-06-2024.
Accessed at https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
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The EPA last revised the NSPS for stationary combustion turbines in
2006, when it promulgated subpart KKKK. In 2022, certain parties filed
a complaint in Federal district court pursuant to CAA section 304
alleging that the EPA had failed to fulfill a nondiscretionary duty
under CAA section 111(b)(1)(B) to review and, if appropriate, revise
this NSPS within 8 years of the 2006 revision. The EPA resolved this
litigation through entering a consent decree establishing judicially
enforceable deadlines for the EPA to propose and finalize this NSPS
review.\35\ The EPA is discharging its obligations under the consent
decree in this final rule.
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\35\ See Consent Decree, Environmental Defense Fund et al. v.
EPA, No. 3:22-cv-07731-WHO (N.D. Cal. July 27, 2023).
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The EPA proposed the current review of the stationary combustion
turbines NSPS on December 13, 2024. We received 167 unique comments
from private citizens, environmental and public health advocacy groups,
community organizations, Tribes, and States. The EPA also received
unique comments from numerous industrial sectors, including electric
utilities, public power cooperatives, original equipment manufacturers
(OEMs), trade groups and associations, and certain sectors of the oil
and gas industry. In addition, thousands of similar comments were
submitted by individuals as part of mass mailer campaigns. A summary of
significant comments we timely received regarding the 2024 Proposed
Rule and our responses are provided in this preamble. A summary of all
other public comments on the proposal and the EPA's responses to those
comments is available in the Summary of Public Comments and Responses:
Review of New Source Performance Standards for Stationary Combustion
Turbines and Stationary Gas Turbines, Docket ID No. EPA-HQ-OAR-2024-
0419. In this action, the EPA is finalizing decisions and revisions
pursuant to its CAA section 111(b)(1)(B) review of the NSPS for
stationary combustion turbines and stationary gas turbines that reflect
our consideration of all the comments received.
D. The Role of the NSPS
The role of NSPS in relation to other requirements of the Act is to
establish a minimum Federal baseline for pollution control performance
that all new, modified, or reconstructed facilities within a specific
source category must meet. While independently established by the EPA
and based strictly on the statutory criteria, in practice, NSPS often
act as a starting point for permitting requirements, such as emission
limits and standards that may be established through other programs
(e.g., the New Source Review (NSR) permitting program or State and
local requirements). NSPS are directly enforceable against sources.\36\
However, effective implementation is often achieved through
collaboration with State and local authorities, who may have delegated
authority to implement NSPS and who are typically responsible for
incorporating NSPS requirements into operating permits.
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\36\ See 42 U.S.C. 7411(e).
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Permitting decisions may result in more stringent emissions
standards for individual sources than the NSPS based on different legal
requirements and case-by-case assessments of the appropriate
requirements for individual facilities considering source-specific
information, such as the local air quality conditions.\37\ For example,
a permitting authority evaluating permit requirements for a new
combustion turbine in an area that has been designated as non-
attainment for ozone under the National Ambient Air Quality Standards
(NAAQS) program must set a standard based on the ``lowest achievable
emissions rate'' (LAER) (and also must offset new emissions with
reductions from other sources).\38\ Under a LAER analysis, a
NOX emissions standard lower than what is required in this
final rule may be appropriate (e.g., an emissions standard of less than
5 ppm NOX based on the application of SCR). That decision
does not necessarily mean the same level of emissions performance must
be required for all combustion turbines in the country through the
NSPS. The reverse is also true--it is not necessarily appropriate to
use the emission standards in an NSPS as the sole justification for not
requiring additional emissions reduction measures under facility-
specific permitting authorities.
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\37\ Experience with emissions control technologies gained
through permitting for specific projects can often help inform the
EPA when conducting its periodic reviews of the NSPS.
\38\ 42 U.S.C. 7503.
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III. What changes did we propose for the stationary combustion turbines
and stationary gas turbines NSPS?
On December 13, 2024, the EPA proposed the current review of, and
several revisions to, the stationary combustion turbines and stationary
gas turbines NSPS. In that action, we proposed to establish size-based
subcategories for new, modified, or reconstructed stationary combustion
turbines in 40 CFR part 60, subpart KKKKa that also recognized
distinctions between those sources that operate at varying loads or
capacity factors, those firing natural gas or non-natural gas fuels,
and those that operate in unique locations. Capacity factor or
``utilization'' level or rate is a ratio that measures how often a
stationary combustion turbine is operating at its maximum rated heat
input. The ratio is based on heat input, or actual heat input, compared
to the base load rating, or potential maximum heat input, under
specified conditions.
The EPA proposed post-combustion SCR in addition to combustion
controls to be the BSER for limiting NOX emissions from
certain combustion turbines in the small, medium, and large size-based
subcategories. The EPA proposed SCR to be adequately demonstrated and
generally cost-effective for combustion turbines in this
[[Page 1916]]
source category when those turbines are operated at higher utilization
rates. The EPA also proposed that a BSER that includes SCR satisfies
the other statutory criteria under CAA section 111(a)(1). We sought
comment on these proposed determinations, including on the issues set
forth below.
However, the EPA recognized that as the size of a combustion
turbine diminishes and/or as the level of operation (i.e., utilization
on an annual basis) of a combustion turbine diminishes or becomes more
variable, the incremental cost-effectiveness on a per-ton basis and
efficacy of SCR technology also diminishes. Thus, at smaller sizes and
at lower rates of utilization, we proposed to establish standards of
performance based on a BSER of combustion controls without SCR.
Specifically, for small combustion turbines (i.e., at proposal, those
that have a base load heat input rating less than or equal to 250
MMBtu/h) that operate at an annual capacity factor less than or equal
to 40 percent (i.e., at proposal, ``low'' and ``intermediate''
utilization combustion turbines), we proposed that the use of
combustion controls alone remains the BSER. For medium combustion
turbines (i.e., at proposal, those that have a base load heat input
rating greater than 250 MMBtu/h and less than or equal to 850 MMBtu/h)
that operate at capacity factors less than or equal to 20 percent
(i.e., low-utilization combustion turbines), we proposed that
combustion controls alone remain the BSER. Likewise, for large
combustion turbines (i.e., those that have a base load heat input
rating greater than 850 MMBtu/h) that operate at capacity factors less
than or equal to 20 percent (i.e., low-utilization combustion
turbines), we proposed that combustion controls alone remain the BSER.
Based on the application of these NOX control
technologies, the EPA proposed to lower the NOX standards of
performance for most of the stationary combustion turbines in this
source category relative to subpart KKKK. In addition, the EPA proposed
to maintain the current standards for SO2 emissions after
finding that the use of low-sulfur fuels remains the BSER.
The Agency also proposed amendments or requested comment to address
several technical and editorial issues that had arisen under the
existing regulations in subparts GG and KKKK, which also could be
relevant to the new subpart KKKKa. These included, among other things,
whether to revise the definition of ``reconstruction'' for this source
category; how to address unique challenges faced by newer higher
efficiency combustion turbines in meeting the current subpart KKKK
standard of performance of 15 ppm NOX for large turbines;
whether to include alternative, optional mass-based NOX
standards of performance; whether to adjust the current approach to the
part-load NOX standards; whether to provide a process for
site-specific NOX standards of performance when burning
byproduct fuels; how to address co-firing of non-natural gas fuels,
including hydrogen; whether and how to handle certain kinds of
emergency operations; whether to include an exemption from title V
permitting for non-major sources under CAA section 502(a); whether to
address other criteria air pollutants; and whether to create a
subcategory or exemption for combustion turbines used in temporary
applications, such as for less than 1 year, similar to current NSPS and
national emission standards for hazardous air pollutants (NESHAP)
provisions for internal combustion engines and industrial boilers.\39\
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\39\ See the proposed rule preamble for additional discussion
about these and other proposals and requests for comment (89 FR
101306; Dec. 13, 2024). See section IV of this preamble for
discussion of the proposals being finalized in subpart KKKKa and
section VI of this preamble for discussion of the proposals not
being finalized in this action.
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IV. What actions are we finalizing and what is our rationale for such
decisions?
The EPA is finalizing revisions to the NSPS for stationary
combustion turbines and stationary gas turbines pursuant to its CAA
section 111(b)(1)(B) review. The EPA is promulgating the NSPS revisions
in a new subpart, 40 CFR part 60, subpart KKKKa. The revised NSPS
subpart is applicable to affected sources constructed, modified, or
reconstructed after December 13, 2024. A complete list of the final
subcategories and associated emissions standards being finalized in
this action is provided in Table 1 in section IV.B.5 of this preamble.
After considering comments critical of the proposed size-based
subcategory threshold between small and medium combustion turbines, the
EPA has decided to retain in subpart KKKKa the general size-based
subcategories from subpart KKKK. This includes subcategories for new,
modified, or reconstructed stationary combustion turbines with base
load ratings greater than 850 MMBtu/h of heat input (i.e., large), base
load ratings greater than 50 MMBtu/h and less than or equal to 850
MMBtu/h of heat input (i.e., medium), and base load ratings less than
or equal to 50 MMBtu/h of heat input (i.e., small). In addition,
certain subcategories of new stationary combustion turbines in subpart
KKKKa reflect the correlation between the level of utilization of a
combustion turbine and the cost effectiveness of available control
technologies in limiting NOX emissions. This correlation was
discussed in the proposed rule and generated significant input in
public comments.\40\ The final rule therefore subcategorizes large and
medium combustion turbines according to how they are operated--either
at high rates of utilization or low rates of utilization. A new large
or medium combustion turbine with a 12-calendar-month capacity factor
greater than 45 percent is subcategorized as a high-utilization source.
A new large or medium combustion turbine with a 12-calendar-month
capacity factor less than or equal to 45 percent is subcategorized as a
low-utilization source. Small combustion turbines are not being further
subcategorized based on utilization.
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\40\ The proposal differentiated the cost effectiveness of
combustion controls and SCR for combustion turbines operating at
low, intermediate, and base load levels. See 89 FR 101315.
---------------------------------------------------------------------------
In addition, taking into consideration public comments in response
to the EPA's discussion in the proposal of the unique challenges faced
by new large higher efficiency combustion turbines, we are finalizing
two subcategories for large low-utilization turbines based on the
design efficiency of the turbine, which accounts for different levels
of emissions performance that can be achieved by combustion controls
alone (i.e., without SCR).\41\ Specifically, for new large turbines
with low rates of utilization (i.e., a 12-calendar-month capacity
factor less than or equal to 45 percent) and design efficiencies
greater than or equal to 38 percent on a HHV basis, the EPA is
finalizing a determination that the BSER is the use of combustion
controls alone.\42\ For new large turbines with low rates of
utilization (i.e., a 12-calendar-month capacity factor less than or
equal to 45 percent) and design efficiencies less than 38 percent, the
EPA is finalizing a
[[Page 1917]]
determination that the BSER is the use of combustion controls with
NOX emissions rate guarantees based on the use of
technologies such as lean premix combustion and dry low-NOX
(DLN) or ultra DLN burners.\43\
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\41\ Efficiency for purposes of subcategorization in 40 CFR part
60, subpart KKKKa refers to the design efficiency of a specific
class or type of stationary combustion turbine according to
manufacturer specifications. Turbine manufacturers list this value
as a percentage based on the HHV of the individual turbine design.
\42\ The 38 percent HHV design efficiency is equal to 42 percent
on a lower heating value (LHV) basis. In relation to the design
efficiency rating of a combustion turbine, ratings based on the HHV
will appear lower, as the calculation includes a portion of heat
that may not be recoverable in many applications. Efficiency ratings
based on the LHV will appear higher because they exclude the energy
lost with the water vapor in the exhaust.
\43\ Dry combustion controls that include the use of lean
premix, DLN, ultra DLN, and other technologies are often referred to
as ``advanced'' combustion controls by turbine manufacturers and the
regulated community. These technologies are generally more effective
at NOX control than other dry combustion controls but are
not available for all types, sizes, and applications of new,
modified, or reconstructed stationary combustion turbines. The EPA
uses the same terminology in this preamble to make the same
distinction.
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The EPA is finalizing a determination that the BSER is the use of
various types of combustion controls (i.e., without SCR) for all but
one subcategory of new, modified, or reconstructed stationary
combustion turbines. For that one subcategory--new large turbines with
high rates of utilization (i.e., 12-calendar-month capacity factors
greater than 45 percent)--the BSER is combustion controls with SCR.
The standards of performance for each subcategory of stationary
combustion turbine in subpart KKKKa reflect the degree of emission
limitation achievable based upon application of the BSER. For new large
high-utilization turbines firing natural gas with a BSER of combustion
controls with SCR, the NOX standard is 5 ppm. For new large
natural gas-fired turbines with low rates of utilization, the
NOX standard is 25 ppm for higher efficiency classes of
turbines and 9 ppm for lower efficiency classes.
For new medium high-utilization combustion turbines firing natural
gas, the NOX standard is 15 ppm based on the performance of
dry combustion controls. For new medium low-utilization turbines firing
natural gas, the NOX standard is 25 ppm based on the
performance of water- or steam-injection combustion controls. The high/
low utilization threshold--greater than or less than or equal to a 45
percent capacity factor--is the same for new medium combustion turbines
as for new large combustion turbines. And for all new small combustion
turbines firing natural gas, the NOX standard is 25 ppm
based on combustion controls regardless of the level of
utilization.\44\
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\44\ See Table 1 of this preamble for a complete listing of
subcategories and associated NOX emissions standards.
---------------------------------------------------------------------------
This action maintains subcategories for modified and reconstructed
stationary combustion turbines that are generally consistent with the
subcategories in subpart KKKK. As discussed in section IV.B.6, these
subcategories are based on a BSER of combustion controls with
associated NOX standards of performance. As discussed in
section VI.A of this preamble, the EPA is not finalizing the proposed,
category-specific definition of ``reconstruction'' for combustion
turbines.
Some of the other final determinations reflected in subpart KKKKa
include: the creation of a new subcategory for stationary temporary
combustion turbines; lowering the threshold that defines part-load
operations to any hour when the heat input of the combustion turbine is
less than or equal to 70 percent of the base load rating; allowing
owners or operators to petition the Administrator for a site-specific
NOX standard when burning byproduct fuels; a provision that
operation during a ``system emergency'' (Energy Emergency Alert levels
1, 2, or 3) is not included in calculating a turbine's 12-calendar-
month utilization; an exemption from title V permitting for combustion
turbines that are not major sources or located at major sources under
CAA section 502(a); and retention of the SO2 standards from
subpart KKKK for all new, modified, or reconstructed stationary
combustion turbines.45 46
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\45\ Energy Emergency Alert levels 1, 2, and 3 are defined by
the North American Electric Reliability Corporation (NERC)
Reliability Standard EOP-011-2, or its successor, or equivalent.
\46\ See section IV.B.7.d of this preamble for discussion of
site-specific NOX standards for stationary combustion
turbines in subpart KKKKa. See sections IV.B.3-4 for discussion of
the BSER for the different subcategories of stationary combustion
turbines. See section IV.B.5 for discussion of the associated
NOX standards based on the application of the BSER.
---------------------------------------------------------------------------
The EPA is finalizing corresponding amendments in subparts GG and
KKKK with respect to several of these ancillary issues, which will be
applicable to combustion turbines subject to those subparts as of the
effective date of this final rule. Specifically:
In subpart GG, the EPA is finalizing that turbines subject
to subparts Da, KKKK, or KKKKa are not subject to subpart GG.
In subpart KKKK, the EPA is finalizing a clarification
that only the heat input to the combustion turbine engine is used for
applicability purposes and that combustion turbines regulated under
subpart KKKK are exempt from subparts KKKKa and GG. The EPA is also
finalizing that emergency, military, and firefighting combustion
turbines are exempt from the NOX emission standards in
subpart KKKK. Additionally, the EPA is finalizing flexibilities
regarding when performance tests must be conducted after long periods
of non-operation and that owners or operators can use fuel records to
comply with their SO2 standard. The EPA is finalizing a low-
Btu alternative to the SO2 standard in subpart KKKK, as well
as a concentration-based alternate SO2 standard. Finally,
the EPA is finalizing the requirement for approval from the delegated
authority for certain monitoring and compliance tasks that are already
covered under 40 CFR part 75 and specifications about including duct
burners in performance tests.
In both subparts GG and KKKK, the EPA is finalizing that
as an alternative to being subject to either of those subparts, owners
or operators of combustion turbines that otherwise meet those subparts'
applicability criteria may petition the Administrator to become subject
to subpart KKKKa instead. The EPA is also finalizing in both subparts
GG and KKKK that turbines subject to subparts J or Ja are not subject
to the respective SO2 standard in subparts GG or KKKK and
that NOX continuous emissions monitoring systems (CEMS)
installed and certified according to 40 CFR part 75 can be used to
monitor NOX emissions, where approved. The EPA is finalizing
standard electronic reporting requirements for turbines subject to
subparts GG or KKKK and that an additional test method (EPA Method 320)
can be used to determine NOX and diluent concentration in
subparts GG and KKKK.
It is the EPA's understanding and intention that none of these
changes alter the stringency or increase any regulatory burdens with
respect to the existing combustion turbines subject to subparts GG and
KKKK, and nothing in this final rule is intended to have retroactive
effect (that is, to govern any conduct or activities occurring prior to
the effective date of this final rule).
This action finalizes standards of performance in subpart KKKKa
that apply at all times, including during periods of startup, shutdown,
and malfunction (SSM), and other changes such as electronic reporting
that also apply to previous NSPS subparts GG and KKKK. These topics are
discussed below in sections IV.F-H.
A. Applicability
The source category that is the subject of this final action is
composed of new, modified, or reconstructed stationary combustion
turbines with a base load rating of greater than 10 MMBtu/h of heat
input.\47\ The standards of
[[Page 1918]]
performance, codified in 40 CFR part 60, subpart KKKKa, are directly
applicable to affected sources that began construction, modification,
or reconstruction after December 13, 2024--the date of publication of
the proposed standards in the Federal Register. The final amendments to
subparts GG and KKKK are directly applicable to the affected facilities
already subject to those subparts. Stationary combustion turbines
subject to the standards in subpart KKKKa are not subject to the
requirements of subparts GG or KKKK. The HRSG and duct burners subject
to the standards in subpart KKKKa are exempt from the requirements of
40 CFR part 60, subpart Da (the Utility Boiler NSPS) as well as
subparts Db and Dc (the Industrial/Commercial/Institutional Boiler
NSPS), continuing the approach previously established in subpart KKKK.
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\47\ The base load rating is the maximum heat input of the
combustion turbine engine at ISO conditions. The EPA uses the HHV
when specifying heat input ratings.
---------------------------------------------------------------------------
Subpart KKKKa maintains certain exemptions from NOX
emissions standards promulgated previously in subparts GG and KKKK. In
1977, in subpart GG, the EPA determined that it was appropriate to
exempt emergency combustion turbines from the NOX limits.
These included emergency-standby combustion turbines, military
combustion turbines, and firefighting combustion turbines. Subpart KKKK
further defined emergency combustion turbines as units that operate in
emergency situations, such as turbines that supply electric power when
the local utility service is interrupted. Additional exemptions being
maintained from subpart KKKK include: (1) stationary combustion turbine
test cells/stands, (2) integrated gasification combined cycle (IGCC)
combustion turbine facilities covered by subpart Da of 40 CFR part 60
(the Utility Boiler NSPS), and (3) stationary combustion turbines that,
as determined by the Administrator or delegated authority, are used
exclusively for the research and development of control techniques and/
or efficiency improvements relevant to stationary combustion turbine
emissions.
In general, and as discussed in the following sections, the EPA is
finalizing minor changes in wording and writing style to add clarity to
the applicability language in subparts GG and KKKK and to track with
language being finalized in subpart KKKKa. The Agency does not intend
for these editorial revisions to applicability and/or updates to the
test methods to substantively change any of the technical requirements
of existing subparts GG and KKKK.
1. Exemptions for Combustion Turbines Subject to More Stringent
Standards
The EPA is finalizing as proposed provisions to make clear that
stationary combustion turbines at petroleum refineries subject to 40
CFR part 60, subparts J or Ja are not subject to the SO2
performance standards in subparts GG, KKKK, or KKKKa. The
SO2 standards in subparts J and Ja are more stringent than
the SO2 limits in subparts GG, KKKK, or KKKKa. This
clarification simplifies compliance for owners or operators of
petroleum refineries without an increase in pollutant emissions by
minimizing overlap of competing NSPS for different source categories.
The EPA received supportive and no adverse comments on the subpart J
and Ja related amendments. The EPA is unaware of additional source
categories or facilities with stationary combustion turbines that are
subject to more stringent NSPS that should not be subject to the
SO2 and/or NOX performance standards in subparts
GG, KKKK, or KKKKa. Further, no commenters identified any such
categories or facilities.
2. Petition To Comply With 40 CFR Part 60, Subpart KKKKa
The EPA is finalizing as proposed a provision that will allow
owners or operators of stationary combustion turbines currently covered
by subparts GG or KKKK, and any associated steam generating unit
subject to an NSPS, to petition the Administrator to comply with
subpart KKKKa in lieu of complying with subparts GG, KKKK, and any
associated steam generating unit NSPS. Since the applicability of
subpart KKKKa encompasses any associated heat recovery equipment,
owners or operators can have the flexibility to comply with one NSPS
instead of multiple NSPS. The Administrator will only grant the
petition if it is determined that compliance with subpart KKKKa would
be equivalent to, or more stringent than, compliance with subparts GG,
KKKK, or any associated steam generating unit NSPS.
Also, if any solid fuel as defined in subpart KKKKa is burned in
the HRSG, the HRSG is covered by the applicable steam generating unit
NSPS and not subpart KKKKa. The intent of the solid fuel exclusion in
subpart KKKKa is that it is only applicable to new turbines burning
liquid and gaseous fuels. The exclusion prevents a large solid fuel-
fired boiler from using the exhaust from a combustion turbine engine to
avoid the requirements of the applicable steam generating unit NSPS.
B. NOX Emissions Standards
1. Overview
This section discusses the EPA's final BSER determinations for
NOX emissions for each of the subcategories of new,
modified, or reconstructed stationary combustion turbines and the
associated standards of performance. The EPA explains in section IV.B.2
of this preamble the subcategory approach it is adopting in subpart
KKKKa. Sections IV.B.3 and IV.B.4 of this preamble present the EPA's
BSER analysis of the NOX control technologies the EPA
evaluated as part of this review of the NSPS, which include dry
combustion controls, wet combustion controls (e.g., water or steam
injection), and post-combustion SCR. Dry combustion controls include
``advanced'' systems that incorporate lean premix with dry low-
NOX (DLN) or ultra DLN burners to reduce the flame
temperature and further limit NOX formation. In section
IV.B.5 of this preamble, the EPA sets out the final NOX
performance standards, based on the application of a particular BSER
for each subcategory of stationary combustion turbine.
In determining the subcategories, BSER, and NOX
standards in this action, the EPA considered multiple characteristics
of combustion turbines within the source category. These included
whether the size of a new, modified, or reconstructed stationary
combustion turbine is small, medium, or large; whether the affected
source is of a type that typically operates at high or low annual
capacity factors (i.e., utilization); whether certain affected sources
are higher or lower efficiency designs; whether the affected source
operates at full load or part load; and whether the affected source
burns natural gas, non-natural gas (such as gaseous hydrogen or liquid
distillate), or a combination of fuels.
In section IV.B.6 of this preamble, the EPA explains the final BSER
determinations and NOX emission standards for modified and
reconstructed sources. The EPA is finalizing NOX emission
standards for modified and reconstructed stationary combustion turbines
that are different than those for new sources and reflect the EPA's
determination that combustion controls without SCR are the BSER for
these sources. This approach reflects comments that explained that many
existing turbines undergoing modification or reconstruction face
unique, site-specific challenges to retrofitting SCR, which can
dramatically increase costs.
Furthermore, in sections IV.B.2.d and IV.B.7.b of this preamble,
the EPA
[[Page 1919]]
discusses the NOX control technologies that the EPA has
determined to be the BSER for each of the non-natural gas subcategories
and also explains its approach to characterizing new, modified, or
reconstructed stationary combustion turbines that elect to co-fire with
hydrogen as either natural gas-fired or non-natural gas-fired.
Specifically, combustion turbines that elect to co-fire with natural
gas blended with hydrogen are subject to the same BSER and
NOX performance standards as those applicable to either
natural gas-fired or non-natural gas-fired combustion turbines,
depending on the size- and utilization-based subcategory. Section
IV.B.2.e of this preamble includes discussion of the new subcategory
for stationary combustion turbines used in temporary applications.
2. Subcategorization
This section describes the subcategorization approach being
finalized in subpart KKKKa. The discussion that follows begins with a
summary of the subcategories in the proposed rule and concludes with a
discussion of the final subcategory determinations and the Agency's
rationale in support of those decisions. As noted in the proposal, the
EPA bases subcategories on the characteristics of combustion turbines
that are relevant to the reasonableness of potential BSER controls
(i.e., characteristics that make potential controls reasonable or
unreasonable in accordance with one or more of the BSER factors in CAA
section 111(a)(1)). Therefore, the availability and performance of
NOX controls for different designs, sizes, etc., of
stationary combustion turbines have informed the Agency's
subcategorization decisions.
To this end, this section discusses the characteristics of various
combustion turbines--such as their size, utilization level, and
efficiency--and why these characteristics are appropriate bases for
subcategorization of sources, as well as how they impact the
determinations of the BSER and associated NOX standards of
performance.\48\ Summaries of significant comments received during the
public comment period and the EPA's responses to those comments are
included in the appropriate sections below. The EPA's further response
to comments on the proposal, including any comments not discussed in
this preamble, can be found in the EPA's response to comments document
in the docket for this rule.49 50
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\48\ See Table 1 in section IV.B.5 of this preamble.
\49\ EPA-HQ-OAR-2024-0419. Summary of Public Comments and
Responses: Review of New Source Performance Standards for Stationary
Combustion Turbines and Stationary Gas Turbines.
\50\ See sections IV.B.3-7 of this preamble and Table 1 in
section IV.B.5 of this preamble for information about the final BSER
determinations and NOX standards of performance for all
new, modified, or reconstructed stationary combustion turbines in
subpart KKKKa.
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a. Subcategorization Based on Size
At proposal, the EPA continued the approach from subpart KKKK of
determining subcategories based on combustion turbine size, as
reflected by the base load rated heat input of an individual combustion
turbine.\51\ As discussed in the proposal, the size of a combustion
turbine is related to its intended application, whether industrial or
utility, and the combination of those factors influences the
availability and performance of NOX combustion controls,
making it a relevant consideration for subcategorization and subsequent
BSER determinations.\52\ The EPA proposed to maintain some of the size
cutoffs for defining subcategories from subpart KKKK and proposed to
revise others.
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\51\ The base load rating only includes the heat input to the
combustion turbine engine and does not include the rated input from
associated duct burners.
\52\ See 89 FR 101317 (Dec. 13, 2024).
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The proposed subcategory of large combustion turbines included new,
modified, or reconstructed sources with base load ratings greater than
850 MMBtu/h of heat input. This subcategory of large turbines
maintained the size-based threshold from subpart KKKK. However, the
proposed size-based thresholds for medium and small combustion turbines
were revised relative to subpart KKKK. The EPA proposed that the size-
based subcategory for medium combustion turbines included new,
modified, or reconstructed sources with base load ratings greater than
250 MMBtu/h of heat input and less than or equal to 850 MMBtu/h. The
EPA proposed that the size-based subcategory for small combustion
turbines included new, modified, or reconstructed sources with base
load ratings less than or equal to 250 MMBtu/h of heat input. In
addition, for the subcategories of medium and small combustion
turbines, the EPA proposed to include both new and reconstructed units
in the same size subcategory; and the EPA proposed to determine the
same BSER and NOX emission standards for both new and
reconstructed units. This was also in contrast to subcategorizations in
subpart KKKK.
In particular, the proposed subcategorization approach for small
stationary combustion turbines represented a significant shift from
that in subpart KKKK. The EPA proposed that a separate subcategory of
combustion turbines smaller than 50 MMBtu/h of heat input is not
necessary because multiple turbine manufacturers have developed dry
combustion controls capable of limiting NOX emissions to the
same rates as those achieved by larger combustion turbines (e.g., those
up to 250 MMBtu/h of heat input) for both electrical and mechanical
drive applications. This same rationale also led the EPA to propose
that separate subcategories for new small combustion turbines, based on
whether they serve electrical or mechanical drive applications, are no
longer necessary.
The EPA received significant comments on the size-based
subcategorization approach for large, medium, and small stationary
combustion turbines.
Many commenters opposed the proposed elimination of the 50 MMBtu/h
threshold that distinguishes between the small and medium size
subcategories of combustion turbines in the previous NSPS (subpart
KKKK). Specifically, the commenters stated that the elimination of the
subcategory for very small combustion turbines impacted the EPA's
proposed determination of the BSER and associated standards of
performance, which they argued were not appropriate for the smallest
turbines, i.e., those less than 50 MMBtu/h of heat input. Separately,
commenters asserted that the proposed 250 MMBtu/h size threshold did
not meaningfully correspond with the emissions performance or other
characteristics of models of combustion turbines currently on the
market. For example, commenters from the natural gas pipeline industry
indicated that they use industrial turbines in sizes of up to 320
MMBtu/h at compressor stations and advocated that the small size
subcategory should be increased to that, while the BSER of combustion
controls from subpart KKKK should be maintained. There was consistent
agreement among these commenters that the subcategory of small
combustion turbines with base load ratings less than or equal to 50
MMBtu/h of heat input should be maintained in subpart KKKKa. One
commenter indicated that turbines with base load ratings less than 20
MMBtu/h should have their own subcategory.
The EPA agrees with the commenters that it is appropriate to
maintain a subcategory for new combustion turbines with base load
ratings less than or equal to 50 MMBtu/h of heat input.
[[Page 1920]]
As described in sections IV.B.3-5 of this preamble, the Agency has
further examined the available controls for the source category and
their reasonableness based on the varying characteristics of different
types of combustion turbines. At proposal, the EPA believed that 250
MMBtu/h represented an inflection point above which SCR would be cost-
reasonable at intermediate and high levels of utilization (and
therefore the BSER) and below which SCR would not be cost-reasonable
(and combustion controls would comprise the BSER) except for high-
utilization turbines. However, based on updated information, the Agency
is not determining that SCR is the BSER for any units smaller than 850
MMBtu/h. There is therefore no reason to define the boundary between
small and medium combustion turbines at 250 MMBtu/h.\53\
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\53\ The EPA noted in the proposal that ``if the EPA were to
determine that SCR was not an appropriate BSER for all small
stationary combustion turbines, then it may be appropriate to adjust
the size-based thresholds such that turbines of greater than 50,
100, or 150 MMBtu/h of heat input should be treated as `medium'
turbines.'' 89 FR 101318.
---------------------------------------------------------------------------
Moreover, the EPA's review also indicates that the available
combustion controls for turbines with base load ratings less than or
equal to 50 MMBtu/h of heat input are more limited and can achieve
different emission reductions relative to combustion turbines with base
load ratings greater than 50 MMBtu/h of heat input.\54\ For example,
the manufacturer guaranteed NOX emission rates for these
small combustion turbines is generally 25 ppm based on the use of dry
combustion controls. However, as the size of the combustion turbine
increases above 50 MMBtu/h, manufacturers have developed more effective
dry combustion controls with manufacturer guaranteed NOX
emissions rates decreasing to 15 ppm. This includes many models of
industrial and frame type combustion turbines larger than 50 MMBtu/h
and smaller than 250 MMBtu/h that would have fallen into the proposed
small turbine subcategory. These differences between combustion
turbines smaller or larger than 50 MMBtu/h and the availability and
performance of the different combustion controls each sized group can
employ leads the Agency to conclude that subpart KKKK's size-based
cutoff of 50 MMBtu/h between small and medium combustion turbines
remains the appropriate threshold for differentiating between small-
and medium-sized combustion turbines in subpart KKKKa.
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\54\ See the discussion of the determination of the BSER and
NOX standards for new small combustion turbines in
section IV.B.5.c of this preamble.
---------------------------------------------------------------------------
The EPA disagrees with commenters that a subcategory for new
combustion turbines with base load ratings less than or equal to 20
MMBtu/h of heat input is appropriate, as there are no significant
differences in the performance of new combustion controls for turbines
less than or equal to 20 MMBtu/h and combustion turbines greater than
20 MMBtu/h and less than or equal to 50 MMBtu/h.\55\ However,
combustion controls that achieve emission rates of 25 ppm or lower for
small combustion turbines are not available for certain existing small
combustion turbines that modify or reconstruct, and SCR is not cost
reasonable. Therefore, the EPA agrees that a subcategory for combustion
turbines with base load ratings less than or equal to 20 MMBtu/h of
heat input--with higher NOX standards based on application
of different BSER--is appropriate for modified and reconstructed
combustion turbines only.
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\55\ See the manufacturer specification sheet in the rulemaking
docket for additional information about available models of
stationary combustion turbines.
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The EPA is finalizing, as proposed, that subpart KKKKa will not
include additional subcategories for new, modified, or reconstructed
small combustion turbines to distinguish between those that are
electrical drive versus those that are mechanical drive. While the EPA
did receive comments requesting that it maintain the distinction
between electrical and mechanical drive turbines as in subpart KKKK,
the Agency does not believe it is necessary given that the final rule
does not treat new and reconstructed combustion turbines the same way,
and existing electrical or mechanical drive turbines that modify or
reconstruct can meet the final NOX standards of performance
for small modified or reconstructed units in subpart KKKKa using
combustion controls.\56\
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\56\ See section IV.B.6 of this preamble for discussion of the
subcategory for small modified and reconstructed combustion
turbines.
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In subpart KKKKa, after completion of the technology review and
consideration of comments provided by stakeholders, the EPA is
finalizing the same size-based subcategory approach as the previous
combustion turbine criteria pollutant NSPS (subpart KKKK). The final
subcategories in subpart KKKKa include combustion turbines with base
load ratings greater than 850 MMBtu/h of heat input (i.e., large),
those with base load ratings greater than 50 MMBtu/h and less than or
equal to 850 MMBtu/h of heat input (i.e., medium), and those with base
load ratings less than or equal to 50 MMBtu/h of heat input (i.e.,
small). Like subpart KKKK, these subcategories are based on the base
load rating of the turbine engine and do not include any supplemental
fuel input to the heat recovery system.
b. Subcategorization Based on Utilization
In the proposed rule, in addition to subcategorizing combustion
turbines according to size, the EPA proposed to subcategorize
stationary combustion turbines further depending on 12-calendar-month
capacity factors (i.e., utilization). Although the EPA had not
previously subcategorized on this basis in subparts GG or KKKK, it has
differentiated between combustion turbines on the basis of utilization
in other contexts since 2015.\57\ Subcategorizing on this basis is
appropriate for combustion turbines in the utility sector because a
source's pattern of operation (e.g., how often it is in operation over
different time frames) generally tracks with how turbines are
configured (e.g., as simple cycle versus combined cycle, etc.).
Patterns of utilization and configuration in turn impact the
feasibility, emission reductions that would be achieved by, and cost-
reasonableness of different types of NOX emissions controls.
For example, in the utility sector, project developers do not typically
construct combined cycle combustion turbine systems to serve peak
demand where they would be expected to start and stop often. Similarly,
project developers in the utility sector do not typically construct and
install simple cycle combustion turbines to operate at higher capacity
factors to provide base load power. Combustion turbines used in the
utility sector typically fall into both the medium and large
subcategories. Similar patterns exist for combustion turbines used in
the commercial, institutional, and industrial power generating sectors,
which are typically turbines in the small and medium subcategories. In
the non-utility sector, project developers typically construct CHP
turbines for high-utilization applications and simple cycle turbines
for low-utilization applications, such as providing backup power. Thus,
turbine utilization is a useful proxy for certain characteristics of
turbines--classes, types, sizes, and modes of operation--that are
relevant for the systems of emission reduction that the EPA may
[[Page 1921]]
evaluate to be the BSER and therefore for the resulting standards of
performance.
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\57\ See, e.g., Standards of Performance for Greenhouse Gas
Emissions from New, Modified, and Reconstructed Stationary Sources:
Electric Utility Generating Units (88 FR 33318; Oct. 23, 2015).
---------------------------------------------------------------------------
While it is generally the case that utilization tracks turbine size
and mode of operation (e.g., simple versus combined cycle), there are
exceptions. Industrial mechanical drive applications (i.e., not
electric generating) primarily use turbines from the small and medium
subcategories but have different utilization characteristics. These
turbines tend to operate at more variable loads as compared to
combustion turbines used to generate electricity. Their frequent
operation may result in their subcategorization as high-utilization
facilities, but they are primarily in simple cycle configurations
because heat recovery is generally not a technically or economically
viable option. However, the amount of utilization and the mode of
operation remain relevant for the systems of emission reduction that
the EPA may evaluate to be the BSER and therefore for the resulting
standards of performance.
The EPA proposed that combustion turbines with 12-calendar-month
capacity factors greater than 40 percent would be subcategorized as
high capacity factor (i.e., base load or high-utilization) units, those
with capacity factors greater than 20 percent and less than or equal to
40 percent were proposed to be subcategorized as intermediate capacity
factor/utilization units, and those with capacity factors less than or
equal to 20 percent were proposed to be subcategorized as low capacity
factor/utilization units. The proposed capacity factor/utilization
thresholds were chosen to reflect what, at proposal, were believed to
be reasonable cut points above and below which different NOX
controls would be cost-effective based on sources' operational
characteristics. The proposed thresholds were also designed to align
with thresholds in the 2024 NSPS for greenhouse gas (GHG) emissions
from new combustion turbines.\58\
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\58\ See 89 FR 39798, 39913 (May 9, 2024). The EPA proposed to
repeal the 2024 NSPS for GHG emissions for new combustion turbines,
as well as for other new and existing fossil fuel-fired power
plants, on June 17, 2025. 90 FR 25752.
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The EPA received significant comments on the subcategorization of
stationary combustion turbines according to capacity factor (i.e.,
utilization). Several commenters recommended that the upper capacity
factor threshold for defining small low-utilization combustion turbines
be increased to at least 25 percent or as high as 40 percent in subpart
KKKKa to not restrict the operation of simple cycle peaking units that
will have to support higher demand variability in the future due to
increased deployment of intermittent generation. According to the
commenters, a lower capacity factor threshold coupled with an emission
limit based on SCR would exacerbate the risk and complexity of
operating combustion turbines essential for grid firming generation and
reliability during extreme weather events and seasonal demands, and
constraining these assets could lead to capacity shortfalls that
increase the potential of higher-emitting generation being called upon.
Another commenter stated that the EPA should set the capacity factor-
based subcategories in subpart KKKKa to better reflect the changing
operational characteristics for certain combustion turbines used in
simple cycle mode and the typical capacity factors of combined cycle
units. Specifically, the commenter stated that an annual capacity
factor of 60 percent is a more appropriate demarcation between simple
cycle and combined cycle turbines. The commenter expects that some
frame type simple cycle turbines will be required to operate at
capacity factors of more than 40 percent in the future as demand for
power climbs, largely due to the boom in artificial intelligence and
the associated data centers. In addition, the commenter stated that a
threshold of 60 percent would help differentiate between units that
operate in simple cycle mode and those that operate in combined cycle
mode.
Based on the EPA's updated analysis of the cost and feasibility of
available controls for combustion turbines, the Agency is determining
in this final rule that SCR does not qualify as the BSER for any
subcategory of stationary combustion turbines with 12-calendar-month
capacity factors less than or equal to 45 percent.\59\ Therefore, the
proposed ``intermediate load'' subcategory that would have covered
combustion turbines operating at annual capacity factors greater than
20 percent and less than or equal to 40 percent is no longer necessary.
Moreover, the EPA has not found differences in the reasonableness of
combustion controls based on a combustion turbine's utilization that
would make distinguishing between ``low'' and ``intermediate'' load
turbines appropriate. Therefore, the proposed low-utilization threshold
referenced by the commenter is not included in final subpart KKKKa.
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\59\ See sections IV.B.3 and IV.B.5 of this preamble.
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After deciding that three utilization-based subcategories are
unnecessary and shifting to just two in this final rule (``high
utilization'' and ``low utilization''), the EPA further considered the
cutoff between these two subcategories. To determine an appropriate
capacity factor that generally reflects the differences between
turbines that operate in simple cycle mode and those that operate in
combined cycle mode, the EPA evaluated the 12-calendar-month capacity
factors of simple cycle turbines in the electric utility power sector
that have commenced operation since January 1, 2020. To account for
variability, the EPA calculated the 99 percent confidence maximum
capacity factor for each combustion turbine. The 99 percent confidence
maximum 12-calendar-month capacity factor for recently constructed
simple cycle turbines was 43 percent. To account for potential future
uncertainty, the EPA is finalizing a 12-calendar-month utilization rate
threshold of 45 percent to delineate between low- and high-utilization
turbines.60 61
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\60\ While the fleetwide average capacity factor of both medium
and large simple cycle turbines is increasing, the average and
maximum capacity factors of both medium and large simple cycle
turbines that have recently commenced operation has remained
relatively constant.
\61\ See section IV.B.2.g of this preamble for discussion of the
EPA's decision not to establish subcategories based on whether a
combustion turbine operates in a simple cycle or combined cycle
configuration.
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In this final rule, the EPA is subcategorizing large and medium
combustion turbines as high- or low-utilization units depending on 12-
calendar-month capacity factors (i.e., utilization rates). The high-
utilization subcategories include large and medium turbines utilized at
12-calendar-month capacity factors greater than 45 percent. The low-
utilization subcategories include large and medium combustion turbines
utilized at 12-calendar-month capacity factors less than or equal to 45
percent. Large and medium combustion turbines that exceed the 12-
calendar-month capacity factor threshold of 45 percent will be subject
to the high-utilization NOX standards, and owners or
operators of such facilities must achieve the applicable NOX
standard, presumably through the operation of additional emission
control technology relative to that required for low-utilization
combustion turbines. The EPA is not subcategorizing small combustion
turbines by utilization and the same BSER and emissions standard is
applicable to all new small combustion turbines regardless of the
utilization level because utilization level is not determinative of the
[[Page 1922]]
reasonableness of NOX controls for these units.
Even combustion turbines that operate at consistent utilization
levels for the life of the facility, the 12-calendar-month utilization
rates vary over the life of the turbine. To estimate the variability in
12-calendar-month utilization rates, the EPA reviewed the maximum 12-
calendar-month capacity factors and the average capacity factors of
combined cycle and simple cycle turbines in the power sector that have
commenced operation since 2020. The median percentage that the maximum
capacity factor is greater than the average capacity factor is 11
percent for combined cycle turbines and 15 percent for simple cycle
turbines. Assuming this is the only factor impacting the relationship
between the maximum and average capacity factor, the maximum 12-
calendar-month capacity factors of combined cycle and simple cycle
turbines with average capacity factors of 40 percent is 44 and 46
percent, respectively. Therefore, the EPA used a 45 percent
applicability threshold as representative of combustion turbines with
an average capacity factor of 40 percent. The 40 percent value was used
when evaluating cost and other BSER factors for control technologies
for combustion turbines in the high-utilization subcategories. The EPA
acknowledges that this approach is conservative. Once that investment
is made, the control technology would likely be used for the life of
the facility even if the combustion turbine were to be subcategorized
as low utilization in the future. For example, in the utility sector,
the average 30-year capacity factor of combined cycle and simple cycle
combustion turbines is 51 percent and 9 percent, respectively. Combined
cycle turbines initially operate on average at a capacity factor of 66
percent, and by year 30, the capacity factor drops to 37 percent.\62\
Simple cycle combustion turbines initially operate at a capacity factor
of 13 percent and drop to 5 percent by year 30. For combined cycle and
simple cycle turbines, the maximum capacity factor is 28 percent higher
and 49 percent higher than the 30-year lifetime average capacity
factor, respectively. In conclusion, the EPA determined it is
appropriate to use a 40 percent utilization rate when evaluating the
BSER factors, but this translates for implementation purposes into a
utilization subcategory threshold of 45 percent based on the 12-
calendar-month capacity factor to accommodate for the variability of a
combustion turbine that operates at a consistent utilization over the
life of the unit.
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\62\ At year 24, combined cycle turbines would become low-
utilization turbines and the NSPS BSER would no longer be based on
the use of SCR. The EPA costing analysis assumes the high-
utilization BSER (i.e., SCR) continues to operate the entire 30-year
period. Assuming the SCR ceases operation in year 24 would decrease
the cost effectiveness of SCR.
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c. Subcategorization Based on Efficiency
The Agency noted in the proposed rule that ``[t]he EPA's review of
combustion turbine emissions data and applied control technologies . .
. demonstrates a correlation between the efficiency of new turbine
designs and NOX emissions using combustion controls.'' \63\
We went on to state that turbine manufacturers have endeavored to
increase the efficiency of new turbine designs, but that there is a
tradeoff between efficiency and NOX emissions such that some
models of large higher efficiency turbines cannot meet a 15 ppm
NOX standard.\64\ We discussed and requested comment on the
relationship between turbine efficiency and the effectiveness of
combustion controls in our analysis of combustion controls for large
combustion turbines.\65\ Based on comments received in response to its
requests, the EPA is determining that it is appropriate to further
subcategorize large low-utilization combustion turbines in subpart
KKKKa based on the manufacturer's design efficiency rating.
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\63\ 89 FR at 101325.
\64\ Id.
\65\ See, e.g., id. at 101333 (solicitation for comment on
whether combustion controls are being developed for large, high-
efficiency turbines currently guaranteed at 25 ppm that would reduce
the NOX emission rate).
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When subpart KKKK was finalized in 2006, the largest available
aeroderivative combustion turbine had a base load rating of less than
850 MMBtu/h of heat input, and less efficient frame units greater than
850 MMBtu were available with manufacturer guaranteed NOX
emission rates of 15 ppm or less. Thus, the subcategories in subpart
KKKK were designed to reflect the distinctions between the sizes and
feasibility of different types of combustion controls between more
efficient turbines that were less than 850 MMBtu/h and less efficient
turbines that were greater than 850 MMBtu/h.
Since subpart KKKK was finalized, incremental advances have been
made to the design of the aeroderivative turbine that had been used to
define the 850 MMBtu/h threshold, and the base load rating of that
specific turbine model is now approximately 1,000 MMBtu/h.\66\ Further,
new frame type turbines have become available that have higher
efficiencies. The most common way to increase the efficiency of a
combustion turbine is to increase the firing temperature. However, an
increase in firing temperature also results in increased formation of
thermal NOX. Several frame turbines have become commercially
available since 2013 that have design efficiencies of at least 38
percent on a HHV basis \67\ and guaranteed NOX emission
rates of 25 ppm. In essence, the state of the source category has
evolved since 2006 so that there are now more types of large combustion
turbines available, and those combustion turbines have a broader range
of efficiencies, which affects NOX formation and the
emission reductions that can be achieved using combustion controls.
Given the subsequent development of the industry and the EPA's further
understanding of how large, higher efficiency turbines are operated
today (i.e., of the intersection between size, utilization, and
efficiency), for the purposes of subpart KKKKa, the Agency is
determining it is appropriate to subcategorize large, low-utilization
combustion turbines depending on whether their design efficiency is
less than 38 percent or greater than or equal to 38 percent.\68\
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\66\ The larger version became available in 2013. See the Excel
file docket item titled combustion turbine manufacturer
specifications proposal docket number EPA-HQ-OAR-2024-0419-0020
attachment 3.
\67\ This value is equal to a design efficiency rating of 42
percent on a lower heating value (LHV) basis.
\68\ This characteristic was not analyzed or understood to be
relevant at the time the BSER analysis was conducted for subpart
KKKK.
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Several commenters requested that the EPA consider subcategorizing
large combustion turbines further to reflect the performance of
available combustion controls in relation to the utilization and design
efficiencies of certain classes or types of available combustion
turbines. Other commenters stated that the EPA should revise the size-
based subcategories in subpart KKKKa to capture and accommodate
variations within certain classes of combustion turbines that could
bear significantly on the cost of NOX controls.
Specifically, commenters suggested that the EPA should create
additional subcategories for large combustion turbines to distinguish
between classes of turbines with distinct NOX profiles and
for which SCR has materially different marginal costs and benefits. The
commenters asserted that doing so would account for variation in the
BSER, NOX reductions, and cost effectiveness for three
classes of large
[[Page 1923]]
frame turbines used in the power industry. Specifically, the commenters
suggested the following:
Simple cycle frame turbines (90 to 150 MW) with a
NOX performance standard of 5 ppm reflecting advanced DLN
combustion controls as BSER for intermediate and base load. The
performance standard should be 15 ppm based on DLN for the low-
utilization subcategory.
Simple cycle frame turbines (200 to 320 MW) with a
performance standard of 9 ppm reflecting advanced DLN combustion
controls as BSER for intermediate and base load. The performance
standard should be 15 ppm based on DLN for the low-utilization
subcategory.
Simple cycle frame turbines (greater than 320 MW) with a
performance standard of 25 ppm reflecting DLN combustion controls as
BSER for all load subcategories. There is no advanced DLN technology
for these very large turbines.
All units in combined cycle mode (i.e., base load) with a
performance standard based on SCR as BSER.
The EPA agrees with the commenters that since subpart KKKK was
finalized in 2006, new higher efficiency classes of frame type
combustion turbines have become commercially available, and the sizes
of these large turbines range from approximately 290 MW to 450 MW.
There are also two aeroderivative turbine designs that are large higher
efficiency units with NOX emission rates of 25 ppm.\69\ As
pointed out by the commenters, these classes of combustion turbines are
generally larger than earlier generation designs and these frame type
turbines are differentiated from earlier models by their higher firing
temperatures that result in higher NOX emissions.\70\
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\69\ Variations of the General Electric (GE) LMS100.
\70\ Examples include GE's 7HA series (7HA.01, 7HA.02, and
7HA.03), Siemens' 9000HL, and Mitsubishi's M501J series that
includes the M501JAC.
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As discussed above, the EPA is determining that it is appropriate
to further subcategorize large, low-utilization combustion turbines
according to efficiency. The new subcategorization approach for these
turbines reflects the distinctions between large, higher efficiency
turbines and large, lower efficiency turbines when those turbines are
operating at low levels of utilization. This distinction is not
relevant when these turbines are operating at high utilization because,
regardless of the efficiency of the turbine, combustion controls with
the addition of SCR is reasonable for large turbines operating at high
utilization.\71\ However, at low utilization, there is a clear
distinction between the technical feasibility of achieving different
emission rates using combustion controls based on the efficiency of the
turbine. Efficiency is thus an appropriate basis for subcategorization
for large combustion turbines operating at low utilization.
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\71\ See section IV.B.3 of this preamble.
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Further subcategorization according to design efficiency is only
reasonable for combustion turbines in the large subcategory. For
instance, the EPA is not aware of any commercially available models of
new medium combustion turbines with design efficiencies greater than 38
percent on a HHV basis. For the subcategory of new small combustion
turbines, the most efficient model of which we are aware achieves an
efficiency of 35 percent on a HHV basis. Regardless of the design
efficiencies of new small and medium combustion turbines, we did not
identify a distinct correlation between efficiency and the manufacturer
guaranteed NOX emission rates. On the other hand, for
combustion turbines in the large subcategory, we identified a clear
correlation between design efficiency and manufacturer guaranteed
NOX emissions.
For subpart KKKKa, the EPA determines this additional
subcategorization is appropriate because it reflects, in part,
improvements in the design efficiency of stationary combustion
turbines. These developments in the current combustion turbine
marketplace--as evidenced by a review of manufacturer specification
data and as stated in public comments--continued to evolve since the
promulgation of subpart KKKK in 2006. Additionally, distinguishing
between combustion turbines in subpart KKKKa based on utilization has
the effect of elucidating distinctions in the reasonableness of
controls when turbines are operating at low versus high utilization;
these distinctions were not evident based on the subcategorization
approach in subpart KKKK. As discussed in section IV.B.5 of this
preamble, this results in a higher NOX emissions standard
for the class of large low-utilization higher efficiency combustion
turbines relative to subpart KKKK. It also results in a lower
NOX emissions standard for the class of large low-
utilization lower efficiency combustion turbines than was determined
for other classes of large turbines in subpart KKKK.
The EPA notes that subcategorizing large low-utilization combustion
turbines by design efficiency can impact the availability of large
turbines for use as high-utilization units. For example, combined cycle
facilities can be built in stages--initially the simple cycle portion
is installed and the HRSG and steam turbine are installed later. This
occurs when developers elect to go ahead and install the simple cycle
portion to meet current low-utilization loads, and as demand increases
over time, they add the steam portion of the combined cycle facility to
meet high-utilization loads. Under this planned staging of construction
and generation, the combustion turbine could operate as a simple cycle
unit for years. For other installations, the simple cycle portion of
the combined cycle facility is completed prior to the remainder of the
combined cycle facility due to unforeseen events, such as delays in the
availability of materials necessary to complete the steam portion of
the facility or delays in the availability of a second (or third)
combustion turbine engine for a combined cycle facility with multiple
turbines serving a single steam turbine. The ability to begin operating
the simple cycle portion of the facility prior to the completion of the
combined cycle project could have significant financial benefit to the
developer and provide additional resources to assist in grid stability.
And because the SCR for combined cycle turbines is included in the
HRSG, the simple cycle turbine would be operating without SCR in both
scenarios.
Without a subcategory for large low-utilization combustion turbines
based on efficiency, developers would not be able to use models with
efficiencies of 38 percent or greater as simple cycle turbines--even on
a short-term basis. The lack of a subcategory would provide a perverse
regulatory incentive to install lower efficiency combustion turbines so
that they could be operated on a short-term basis in simple cycle mode.
This would result in higher overall emissions because when the HRSG
becomes operational, the resulting lower efficiency combined cycle
facility with a lower efficiency turbine engine would have higher
emissions compared to these higher efficiency turbine engines that
result in a more efficient and lower emitting combined cycle facility.
d. Subcategorization of Non-Natural Gas-Fired Combustion Turbines
Consistent with subpart KKKK, the EPA proposed that when a
combustion turbine fires a fuel that is more than 50 percent non-
natural gas (e.g., either a gaseous fuel, such as hydrogen, or a liquid
fuel, such as oil) while under full load for a portion of an hour of
operation, then that combustion turbine
[[Page 1924]]
is subject to the appropriate non-natural gas NOX emission
standard--based on the application of the BSER--for that entire hour of
full-load operation. However, we also solicited comment on eliminating
the 50 percent requirement so that the non-natural gas emissions
standard would apply when any amount of non-natural gas fuel is burned
in the combustion turbine engine at full load. In general, we proposed
that the BSER for most sources firing non-natural gas fuels is the use
of wet combustion controls (i.e., water or steam injection) and/or
diffusion flame combustion. (Diffusion flame combustion is where fuel
and air are injected at the combustor and are mixed only by diffusion
prior to ignition. Generally, it is not considered a type of combustion
control technology per se because the EPA is not aware of diffusion
flame combustors broadly available that are able to achieve significant
NOX reduction in combustion turbines, though for some
subcategories the EPA identifies this technology as the BSER in the
absence of any other method of control.) Accordingly, we proposed
NOX standards for non-natural gas-fired sources in subpart
KKKKa based on the application of the BSER for each size-based
subcategory.
Several commenters opposed the EPA's proposal to define sources in
subpart KKKKa as non-natural gas-fired when more than 50 percent of the
heat input is from a non-natural gas fuel at full load. For example,
according to one commenter, widespread industry practice when switching
from natural gas to oil is to reduce load and switch from lean premix/
DLN combustion controls (for natural gas) to diffusion flame (for oil).
This can lead to a short-term spike in emissions, which, according to
the commenter, necessitates a higher, less stringent NOX
limit. Should such a spike in NOX emissions occur when less
than 50 percent of the fuel being combusted is fuel oil, the source
would be subject to the (lower, more stringent) NOX standard
for natural gas.\72\ Commenters further explained that given the effect
on emissions of switching fuels, it could be difficult for a source to
meet a lower NOX standard for natural gas combustion when a
non-natural gas fuel is being combusted, including when the non-natural
gas fuel represents less than 50 percent of the total heat input during
the hour. The commenters asserted that a more reasonable approach would
be to apply the highest applicable NOX emissions standard
for any hour when any amount of non-natural gas fuel is combusted--as
in the Industrial Boiler NESHAP--and pointed out the EPA's
acknowledgement in the proposal that eliminating the 50 percent
threshold ``could provide a more accurate representation of the
performance of applicable control technologies.'' 73 74
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\72\ See Table 1 in section IV.B.5 of this preamble for the
NOX standards for subcategories of natural gas-fired
stationary combustion turbines.
\73\ See 40 CFR part 63, subpart DDDDD.
\74\ See 89 FR 101318 (Dec. 13, 2024).
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Other commenters stated the EPA's concern that eliminating the 50
percent requirement would incentivize operators to burn a small amount
of non-natural gas fuel to be subject to a higher NOX
emissions limit is unfounded. Specifically, the commenters asserted
that reducing load makes fuel switching impractical by causing
generation to be less efficient, meaning there is little to no
incentive for an operator to conduct a fuel switch to take advantage of
a less stringent standard.
Further, several commenters responded to a solicitation for comment
in the proposal regarding whether multiple fuels could be combusted
simultaneously in a combustion turbine engine and whether it is
necessary to temporarily cease operation or reduce load to switch from
natural gas to distillate oil. According to commenters, the design and
operation of combustion systems do not allow for multiple fuels to be
combusted simultaneously in turbines operating under full load--except
for specific designs of dual-fuel combustion turbines used in certain
industrial processes. The commenters explained that for combustion
turbines not designed to operate in dual-fuel mode, different gaseous
fuel streams can be premixed and fired (e.g., natural gas and refinery
fuel gas or natural gas and hydrogen). A combustion turbine operator
cannot simply switch between liquid and gaseous fuels while operating
at full load if the turbine is not designed for dual-fuel operation. In
general, most combustion turbines are not dual-fuel designs and either
start on gas or oil and continue to operate on the same fuel as the
unit loads, or, to improve reliability in cold weather, units will
start on gas and transition to oil at or before the full speed no load
(FSNL) operating condition. In all cases, turbines with dry or wet
combustion controls never operate at full load while simultaneously
firing both natural gas and fuel oil. The combustion characteristics of
the higher hydrocarbon, distillate oil differ from the combustion
characteristics of natural gas. These fuels are incompatible with
systems that were engineered for methane gas, most notably regarding
poor flashback margin, which can result in significant damage to
premixed, dry combustion controls.
In subpart KKKKa, the EPA is maintaining the provision from subpart
KKKK that non-natural gas hours are defined as any hour when more than
50 percent non-natural gas fuels are fired in the combustion turbine at
full load (i.e., when the heat input is greater than 70 percent of the
base load rating). In these situations, the non-natural gas
NOX standard applies for the entire reporting hour--even if
non-natural gas fuel was fired for only a portion of the hour.\75\
Specifically, if the total heat input is greater than 50 percent from
non-natural gas fuels (e.g., distillate oil, hydrogen, and fuels other
than natural gas), the combustion turbine is subject to the applicable
NOX standard in the non-natural gas-fired subcategory and
that NOX standard must be met for the entire hour. This is
consistent with the approach for subcategorizing hours based on load.
For example, if the turbine is operated at part load (i.e., 75 percent
and 70 percent of the base load rating in subparts KKKK and KKKKa,
respectively) at any point during the hour, the part-load standard is
applicable for the entire hour even if the average load exceeds the
full load threshold. While the EPA appreciates commenters' explanation
that fuel switching to obtain more lenient emissions standards is
unlikely to occur because it is not economical, the 50 percent non-
natural gas threshold has proven workable in subpart KKKK and retaining
this threshold in subpart KKKKa avoids any regulatory incentive to
unnecessarily combust small amounts of non-natural gas fuels.
Similarly, if multiple fuels are burned during an hour of operation and
the total heat input is less than or equal to 50 percent non-natural
gas (and more than 50 percent natural gas), then the turbine is subject
to a NOX limit that is prorated based on the heat input of
the fuels during the hour. For example, if a turbine burns 75 percent
by heat input natural gas and 25 percent non-natural gas, the
applicable hourly NOX standard is 0.75 times the applicable
natural gas standard, plus 0.25 times the applicable non-natural gas
standard.\76\
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\75\ For example, an affected facility could burn 51 percent
non-natural gas fuel for 1 minute of an hour and 100 percent natural
gas for the remaining 59 minutes. In this extreme situation, the
entire hour would be considered a non-natural gas-fired hour.
\76\ This example assumes the natural gas and non-natural gas
fuels are using different fuel nozzles. If the fuels are mixed prior
to combustion, the natural gas/non-natural gas determination is
based on the fuel mixture. If the mixture meets the definition of
natural gas, the natural gas standard is applicable. And if the
mixture does not meet the definition of natural gas, the non-natural
gas standard is applicable.
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[[Page 1925]]
It is important to make clear that the NOX standards for
natural gas and non-natural gas hours apply only when combustion
turbines are operating at full load. As explained by commenters, most
combustion turbines decrease load during fuel switching, and regardless
of the heat input from a particular fuel being fired for a portion of
an operating hour, those turbines would be subject to the part-load
NOX standards, which are higher than the individual natural
gas- and non-natural gas-fired NOX standards. See section
IV.B.2.f of this preamble for an explanation of subcategorization for
turbines operating at part load.
In subpart KKKKa, the EPA is also finalizing as proposed, with one
exception, that the NOX standards of performance are based
on the type of fuel being burned in the combustion turbine engine
alone. Fuel choice impacts combustion turbine engine NOX
emissions to a greater degree than it impacts such emissions from a
duct burner. Therefore, the EPA concludes that this approach provides a
more accurate representation of the performance of applicable control
technologies. The natural gas standard applies at those times when the
fuel input to the combustion turbine engine meets the definition of
natural gas, regardless of the fuel, if any, that is burned in the duct
burners. The one exception is for byproduct fuels. For turbines burning
byproduct fuels, the applicable emissions standard is based on the
total heat input to the turbine, including and fuel burned in the duct
burners. See section IV.B.7.d of this preamble for further discussion
of turbines burning byproduct fuels.
e. Subcategory for Temporary Combustion Turbines
At proposal, the EPA requested comment on creating either a
subcategory or an exemption for stationary combustion turbines used in
temporary applications. Many commenters generally supported some form
of streamlined compliance for temporary applications. Some commenters
raised concerns that a full exemption could have unintended
consequences. After considering these comments, the Agency is
finalizing a new subcategory in subpart KKKKa for small and medium
stationary combustion turbines (i.e., up to 850 MMBtu/h in size) used
in temporary applications. This subcategory reflects a BSER
determination of combustion controls with an associated standard of 25
ppm NOX when combusting natural gas and 74 ppm
NOX when burning non-natural gas fuels, along with a
streamlined approach to compliance that primarily relies on maintaining
documentation of manufacturer certification. Such turbines may be used
in a single location for up to 24 months. The EPA is also amending
subpart KKKK to include an optional subcategory for stationary
temporary combustion turbines with the same BSER, NOX
standards, and recordkeeping and reporting requirements as for the
subcategory of stationary temporary combustion turbines in subpart
KKKKa.\77\
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\77\ The emission standards for temporary turbines are
consistent with the standards in subpart KKKK.
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As discussed in the proposal, a streamlined approach to NSPS
compliance for temporary combustion turbine applications would bring
this NSPS into alignment with similar approaches that are available in
the boilers NSPS and in the reciprocating internal combustion engines
(RICE) NSPS. The EPA has historically considered portable boilers and
RICE used for limited periods of time to be temporary equipment not
subject to regulation under their respective NSPS or NESHAP
subparts.\78\ The Agency observed at proposal that the absence of any
such provisions in the combustion turbines NSPS is anomalous insofar as
combustion turbines tend to have lower air pollutant emissions than are
emitted by an equivalent level of power generation from RICE. Further,
in the proposal, the EPA noted that the permitting, testing, and
monitoring requirements typically applicable for a combustion turbine
subject to an NSPS may not be appropriate or suitable for combustion
turbines needed quickly and only for limited periods of time. Temporary
combustion turbines are generally operated in short-term situations but
can also provide power during extended emergency or emergency-like
situations (e.g., a natural disaster damages the electric grid) while
the primary generating equipment is not available, while transmission
and/or generation capacity is being repaired and/or upgraded, or for
some other unforeseen event.\79\ Since permitting itself could take
longer than the need for temporary generation, the Agency solicited
comment on whether an applicability exemption or subcategorization
would be appropriate for temporary combustion turbines under subparts
GG, KKKK, and KKKKa.
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\78\ See, e.g., 40 CFR 60.4200(a), 60.4230(a), 60.40b(m), and
60.40c(i). (We note that at proposal we inadvertently cited similar
but separate provisions of the RICE NSPS related to ``replacement''
engines. Cf. 40 CFR 60.4200(e), 60.4230(f).)
\79\ Note that a separate exemption is available for ``emergency
turbines'' in subpart KKKK, which is also being included in subpart
KKKKa. See 40 CFR 60.4310(a); id. 60.4420 (definition of ``emergency
combustion turbine''). However, this provision may not be clearly
applicable in all circumstances in which temporary turbines are
needed.
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The EPA also requested comment at proposal on whether the BSER for
temporary combustion turbines is the use of combustion control
technology consistent with the otherwise applicable subcategory--25 ppm
NOX for units with base load ratings of 850 MMBtu/h or less
and 15 ppm NOX for larger units. Relatedly, we solicited
comment on the appropriate testing and recordkeeping criteria for such
regulatory provisions.
Multiple commenters supported the idea of a subcategory or
exemption. Comments, particularly from industry stakeholders, supported
a BSER of combustion controls and indicated that turbines used in
temporary applications are generally capable of meeting a
NOX standard of 25 ppm using combustion controls. The same
commenters also generally opposed requiring SCR for temporary turbines,
the complexity of which would tend to defeat the purpose of being able
to bring in such turbines quickly for immediate and short-term power
supply. The EPA agrees that combustion controls are the BSER for
temporary turbines, and the Agency applies the BSER analysis set forth
in section IV.B.3 of this preamble explaining why SCR is not the BSER
for small and medium turbines.
The Agency is limiting the scope of the temporary combustion
turbines subcategory so that large combustion turbines (i.e., those
with a base load rated heat input greater than 850 MMBtu/h) cannot
qualify for treatment as temporary combustion turbines. In general,
large combustion turbines are not used in temporary applications--these
turbines tend to be frame type units that are more challenging to
transport and operate without more extensive onsite preparation.
The EPA finds 25 ppm to be the appropriate standard of performance
for NOX emissions from temporary combustion turbines. (The
EPA is not establishing a separate SO2 standard of
performance for this subcategory--in other words, the otherwise
applicable SO2 standard will apply).) Most trailer-mounted
turbines, which would likely be intended to remain in the same location
for less than 2 years and so can be considered representative of
typical temporary turbines, have standard
[[Page 1926]]
emission guarantees of 25 ppm NOX. There are some trailer-
mounted turbines with lower standard emission guarantees, but these are
less efficient designs with lower rated outputs. For example, an
emissions standard of 15 ppm NOX would limit the
availability of temporary turbines to those less efficient models with
lower rated outputs--significantly increasing costs for the regulated
community and resulting in increased fuel use. Combustion systems
capable of achieving 15 ppm NOX are generally more complex
and physically larger than comparable combustion systems capable of
achieving 25 ppm NOX. For example, more complex combustion
control systems generally have more fuel nozzles and burners, premix
larger amounts of air with the fuel, and have more sophisticated
control systems. This increases the physical size and cost of a
combustion turbine for a given rated output. Furthermore,
aeroderivative turbines are generally physically smaller than frame
units for the same rated output. Most aeroderivative turbines have
guaranteed emission rates of 25 ppm NOX. The ability to
transport a temporary turbine is a critical feature and an emissions
standard of less than 25 ppm NOX would increase the physical
size per rated output of combustion turbines that could meet that
emissions standard and undermine the purpose of the subcategory. In
addition, as discussed in section IV.B.4 of this preamble, combustion
controls capable of achieving 25 ppm NOX qualify as the BSER
for small combustion turbines and low-utilization medium turbines--both
of which are potential temporary turbines. While some medium temporary
turbines may operate at high utilization levels for limited periods of
time, there will be periods when the turbine will be in storage, being
transported to a new location, or otherwise not operating. On balance,
the EPA anticipates that medium temporary turbines will have
utilization levels of less than 45 percent. Therefore, we conclude that
combustion controls capable of achieving 25 ppm NOX are the
BSER for the temporary turbines subcategory.
Commenters recommended increasing the allowable period of operation
at a single location to 18 months or 2 years to account for situations
where temporary power is needed for longer than the 12-month period
mentioned in the proposal. The Agency agrees with commenters that a 12-
calendar-month period may not be sufficient for all situations. In
addition, a 24-month period is consistent with a longstanding policy
within the Prevention of Significant Deterioration (PSD) permitting
program, which recognizes that emissions occurring for no longer than
that period of time may be considered temporary and therefore excluded
from modeling analysis.\80\ We note that 24 months is the total
residence time permitted from when a temporary turbine commences
operation. The final temporary turbine subcategory is for turbines used
at a single location for up to 24 months.
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\80\ See 43 FR 26380, 26394 (June 19, 1978).
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Some commenters also stated that the subcategory should be
available to combustion turbines used in temporary applications
regardless of whether they meet criteria for portability. To simplify
compliance and avoid potentially complicated regulatory determinations,
the EPA is not requiring temporary combustion turbines to be portable
in nature or meet indicia of portability to qualify for this
subcategory.\81\ Commenters noted there may be applications where a
temporary combustion turbine can be transported to a location and
installed onsite for a time-limited purpose, but may not meet a
definition of ``portable'' such as that included, for example, in the
definition of ``temporary boilers.'' \82\ Given other criteria the EPA
is finalizing that limit the scope of a new subcategory for temporary
combustion turbines, we agree a requirement to be portable serves
little benefit and is not needed.\83\
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\81\ Note that combustion turbines that are mounted on a vehicle
for portability continue to be subject to the NSPS, as they have
been under subparts GG and KKKK. See, e.g., 40 CFR 60.4420
(definition of ``stationary combustion turbine'').
\82\ See 40 CFR 60.41b.
\83\ Note that, as a separate matter, to be considered a
``nonroad engine'' for purposes of mobile source regulation under
Title II, a unit must, among other things, meet the criteria in the
definition at 40 CFR 1068.30, paragraph 1, such as being ``portable
or transportable.''
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Monitoring, recordkeeping, and reporting requirements are
substantially reduced for the subcategory of temporary turbines. In the
final rule, the EPA is requiring only that the owner or operator of a
turbine falling within the temporary turbines subcategory maintain
documentation onsite that each temporary turbine has been certified by
its manufacturer to meet a NOX emissions rate of 25 ppm, and
that each turbine has been performance tested at least once in the
prior 5 years (for turbines older than 5 years, after the initial sale
by the manufacturer). Annual performance testing is not required for
turbines in the temporary subcategory. We anticipate that a test every
5 years will be sufficient to ensure that temporary turbines are
properly maintained so as to continue to meet the 25-ppm limit.
Consistent with the proposal, the EPA finds that several conditions
on the use or replacement of temporary turbines are necessary to ensure
the subcategory does not inadvertently create a means of avoiding
requirements that apply under the NSPS for turbines used in non-
temporary capacities. Under the final rule, should a temporary
combustion turbine remain in place for longer than 24 months, then it
would not be considered temporary for any period of its operation, and
any failure of the owner or operator to comply with the otherwise
applicable requirements of the relevant NSPS, even in the initial 24
months of operation, would be an enforceable violation of the Act. In
addition, the final rule does not allow the replacement of a temporary
combustion turbine with another temporary combustion turbine to
maintain temporary status beyond the 24-month period. However, as an
anticipated normal function for these types of turbines, temporary
turbines may be used to replace or substitute the generation provided
by non-temporary turbines (or other types of generators) when those
units are taken offline (e.g., for maintenance work). In addition, the
relocation of a temporary stationary combustion turbine within a
facility does not restart the 24-calendar month residence time.
The EPA is not finalizing a complete exemption from the NSPS for
temporary combustion turbines. In response to the alternative exemption
approach on which the Agency sought comment, multiple commenters
supported an exemption approach like the NSPS for RICE. However, for
RICE, the exemption from the NSPS for equipment operating in a single
location of up to 12 months works in conjunction with regulations
promulgated under title II of the Act to bring these RICE within the
definition of ``nonroad engines'' as set forth at 40 CFR 1068.30. Such
units are then subject to regulations that the EPA has promulgated for
nonroad engines pursuant to title II of the Act.\84\
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\84\ See 42 U.S.C. 7547; see also, e.g., 40 CFR 60, subparts III
and JJJ; 40 CFR part 1039.
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Under both the statute and EPA regulations, combustion turbines in
general are considered a kind of internal combustion engine that
therefore could in theory be regulated as nonroad engines.\85\
Historically, however, the EPA has not regulated combustion turbines,
even those that may be portable, as nonroad engines, but rather
[[Page 1927]]
as stationary sources.\86\ The current definition of ``nonroad engine''
at 40 CFR 1068.30 excludes engines that are subject to an NSPS. All
combustion turbines meeting the applicability criteria of the NSPS for
combustion turbines are subject to those NSPS standards (including
portable turbines) and thus have been excluded from the definition of
nonroad engines. An exemption from the NSPS for qualifying stationary
temporary applications would potentially bring portable combustion
turbines within the definition of nonroad engine at 40 CFR 1068.30.
However, the kinds of turbines that are used in stationary temporary
applications are not currently subject to any title II regulations or
standards. Finalizing an exemption for temporary or portable combustion
turbines without ensuring a workable framework for compliance under
title II could leave these engines subject to no emission standards at
all.
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\85\ See 42 U.S.C. 7550(1) and 7602(z).
\86\ See 42 U.S.C. 7411(a)(3). See 40 CFR 60.331(a); 40 CFR
60.4420 (definition of ``stationary combustion turbine'').
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Nonetheless, the Agency recognizes the significant interest several
stakeholders have expressed in treating combustion turbines used in
stationary temporary applications as nonroad engines subject to
regulation under title II. There could be benefits in the form of
reduced permitting burden and further streamlined compliance
obligations for the purchasers and users of such turbines. At the same
time, manufacturers of combustion turbines that are treated as nonroad
engines would be subject to compliance obligations under title II,
including, for example, obtaining certificates of conformity. Such
turbines would be treated as other nonroad engines under title II and
permitting requirements would not apply to emissions from the engine
because such turbines would no longer be considered a part of the
stationary source. Commenters on this rule identified concerns with the
air quality effects if many temporary combustion turbines were brought
together and operated in a single location and suggested imposing
operating or total-emissions constraints and air quality considerations
to prevent these consequences.\87\
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\87\ The EPA notes that under the subcategory approach to
temporary stationary combustion turbines, which was are finalizing
in subpart KKKKa, permitting authorities may take these kinds of
considerations into account in determining appropriate emissions
limitations or other requirements.
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The EPA believes these matters deserve further investigation before
rulemaking action is taken to consider regulating portable combustion
turbines used in temporary applications under title II rather than
under the NSPS. The EPA is not promulgating any such regulations under
title II in this action. In this final rule, the EPA is including a
conditional exclusion in subpart KKKKa that will exclude combustion
turbines from the definition of ``stationary combustion turbine,'' if
the turbine meets the definition of ``nonroad engine'' under title II
of the Act and applicable regulations, and is certified to meet
emission standards promulgated pursuant to title II of the Act, along
with all related requirements. This provision will become operative if
the EPA in the future adopts nonroad emission standards and
certification requirements for portable combustion turbines.
Even in the absence of a complete exemption from the NSPS, the EPA
believes creating the subcategory for temporary combustion turbines in
this action can facilitate actions that reduce the permitting burden
faced both by sources and permitting authorities. Note that the EPA is
separately exercising authority granted to it under CAA section 502(a)
to exempt from title V permitting any combustion turbines that are not
major sources.\88\ The EPA expects that the application of combustion
turbines at sites with a potential to emit below the title V permitting
major source threshold (as referenced in the last sentence of CAA
section 502(a)) would also emit below major NSR emissions thresholds
and thus only be subject to minor NSR program requirements. CAA section
110(a)(2)(C) requires States to develop a program to regulate the
construction and modification of any stationary source, including minor
NSR requirements as necessary, to assure that NAAQS are achieved. Minor
NSR requirements are required to be approved into a State
Implementation Plan (SIP), Tribal Implementation Plan (TIP), or Federal
Implementation Plans (FIP) and are often mechanisms to assist in
achieving and maintaining the NAAQS.\89\ The CAA and the EPA's
regulations are less prescriptive regarding the minor NSR program
requirements. Therefore, reviewing authorities generally have
significant flexibility in designing their minor NSR programs,
including any air permitting programs for minor sources. Minor NSR
permits are almost exclusively issued by State, local, and other
authorized reviewing authorities, although the EPA issues minor NSR
permits for most areas of Indian country where Tribes have not
developed TIPs or requested delegation to administer minor NSR air
permitting programs for their jurisdictions. With the creation of the
temporary combustion turbines subcategory in this action, the EPA
believes authorized reviewing authorities may find it efficient to
pursue further streamlining of minor-source permitting for such
sources, including developing a general permit for such sources, or
issuing a permit by rule for these sources.
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\88\ See section IV.E.5 of this preamble for further discussion.
\89\ See 42 U.S.C. 7410(a)(2)(C).
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Even where temporary combustion turbines comprise or are part of a
major source for purposes of NSR permitting, the temporary turbines
subcategory will assist States in identifying emissions from such
sources that may be excluded from parts of the permit review because
they are temporary. Under the EPA's PSD regulations, temporary
emissions can be excluded from the analysis of whether the emissions
increases that would result from construction or modification of a
major stationary source cause or contribute to a violation of air
quality standards.\90\ As discussed above, the 24-month period we are
finalizing for this subcategory accords with the duration the EPA has
used for decades to classify temporary emissions in the PSD program.
Sources with characteristics that place them within this subcategory
will have a straightforward means of showing that emissions from these
sources are temporary to apply this PSD exemption for temporary
emissions in the review of a PSD permit application.
---------------------------------------------------------------------------
\90\ See 40 CFR 51.166(i)(3); 40 CFR 52.21(i)(3).
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Further, the standards of performance in this final rule are
legally and practically enforceable and thus can serve to inform
calculations of the potential to emit of these sources for purposes of
determining whether they are major sources for NSR applicability
purposes. Sources may, of course, also voluntarily accept, in an
enforceable permit condition, more stringent emissions limits, or limit
their operating time, to reduce their potential to emit so as to become
synthetic-minor sources for NSR applicability purposes.
f. Subcategory for Combustion Turbines Operating at Part Loads, Located
North of the Arctic Circle, or Operating at Ambient Temperatures of
Less Than 0 [deg]F
When the EPA promulgated subpart GG (the original stationary gas
turbine criteria pollutant NSPS) in 1979, the NOX standards
and compliance requirements were based on performance testing. Based on
subsequent rulemakings, owners or
[[Page 1928]]
operators of a gas turbine subject to subpart GG with a NOX
CEMS began determining excess emissions on a 4-hour rolling average
basis. The EPA found that a 4-hour basis is the approximate time
required to conduct a performance test using the performance test
methods specified in subpart GG. This 4-hour rolling average became the
default for determining the emission rates of gas turbines, and, in
2006, the EPA retained it in the subsequent review of the stationary
combustion turbine criteria pollutant NSPS.
When the EPA proposed subpart KKKK in 2005, the NOX
performance emissions data were based on stack performance tests, which
are representative of emission rates at high hourly loads, rather than
CEMS data. The final NOX standards for high hourly loads
were consistent with the performance test data and manufacturer
guarantees. To avoid confusion with the annual ``utilization'' levels
discussed elsewhere in this document, we will refer to high hourly
loads as ``full loads,'' in contrast with ``part loads''; utilization
levels on an annual basis are referred to as ``low-utilization'' and
``high-utilization.'' Manufacturer guarantees are only applicable
during specific conditions, which include the load of the combustion
turbine (i.e., when the load meets certain specifications) and the
ambient temperature (i.e., generally above 0 [deg]F). When combustion
turbines are operated at part loads and/or at low ambient temperatures,
low-NOX combustion controls--the identified BSER in subpart
KKKK--were not as effective at reducing NOX from a technical
standpoint.\91\ At part-load operation and low ambient temperatures, it
is more challenging to maintain stable combustion using DLN and
adjustments to the combustion system are required--resulting in higher
NOX emission rates. Therefore, in subpart KKKK, the Agency
identified diffusion flame combustion as the BSER for hours of part-
load operation or low ambient temperatures.\92\
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\91\ The ambient temperature of combustion turbines located
north of the Arctic Circle would often be below 0 [deg]F, and these
units are included in the low ambient temperature subcategory
regardless of the actual ambient temperature. As we found with
subpart KKKK, the costs of requiring combustion controls that would
rarely be used are not reasonable.
\92\ Combustion turbines have multiple modes of operation that
are applicable at different operating loads and when the combustion
turbine is changing loads. The modes are specific to each combustion
turbine model. The identified BSER of diffusion flame combustion
also includes periods of operation that use less effective DLN
compared to operation at full loads.
---------------------------------------------------------------------------
In subpart KKKK, a part-load hour is defined as any hour when the
heat input rate is less than 75 percent of the base load rating of the
combustion turbine. If the heat input rate drops below 75 percent at
any point during the hour, the entire hour is considered a part-load
hour, and the part-load standard is applicable during that hour.
Determination of the 4-hour emissions standard is calculated by
averaging the four previous hourly emission standards. Under this
approach, the ``full load'' standard (i.e., the standard of performance
that has been established for the relevant subcategory as discussed
elsewhere in this notice) would not be applicable until a minimum of 6
continuous operating hours. The initial and final hours would be
startup and shutdown, respectively, and the part-load standard is
applicable during those hours. If the combustion turbines were
operating at full load during the middle 4 hours, the full load
standard would be applicable to that 4-hour average. The emission
standards for the remaining hours would be a blended standard that is
between the part-load and full load standards. This approach was viewed
as appropriate to account for the different applicable BSERs. Subpart
KKKK also includes a 30-operating-day rolling average standard that is
applicable to combustion turbines with a HRSG. The 30-operating-day
rolling average was included in subpart KKKK because the HRSG was part
of the affected facility, and a longer averaging period is necessary to
account for variability when complying with the alternate output-based
emissions standard.
The EPA is finalizing the same short-term 4-hour standard for part
load in subpart KKKKa along with the blended standard approach.
Specifically, the applicable emissions standard is based on the heat
input weighted average of the four applicable hourly emissions
standards. However, as discussed at proposal, the EPA is finalizing two
changes to the part-load subcategory. First, the CEMS data analyzed by
the EPA indicates that emissions tend to slowly increase at lower
loads, but, in general, combustion turbines can maintain compliance
with the emissions standards at hourly loads of 70 percent and greater,
not just at loads of 75 percent and greater, as reflected in subpart
KKKK.\93\ Therefore, the EPA determines in subpart KKKKa that this
subcategory applies for any hour when the heat input is less than or
equal to 70 percent of the base load rating. The EPA notes that
lowering the part-load threshold brings more operating periods under
the otherwise-applicable standards of performance.
---------------------------------------------------------------------------
\93\ To maintain flame stability during part-load operation, dry
combustion controls must increase the relative amount of the fuel
going to the diffusion flame portion of combustion system. This
inherently results in an increase in the NOX emissions
rate. Similarly, to maintain stable operation during part-load
operation, the relative amount of water injected for wet combustion
controls must be reduced.
---------------------------------------------------------------------------
Second, the EPA is finalizing a different size threshold for
subcategorizing the part-load emission standards. Subpart KKKK
subcategorizes the part-load emissions standard based on the rated
output of the turbine (i.e., combustion turbines with outputs greater
than 30 MW have a more stringent part-load standard than smaller
combustion turbines). For subpart KKKKa, the EPA proposed to
subcategorize the part-load standard based on the heat input rating
(i.e., turbines with base load heat input ratings greater 250 MMBtu/h
would have a more stringent standard (96 ppm NOX) than
smaller combustion turbines at part load (150 ppm NOX)).
In this action, since the final size-based subcategorization
approach no longer includes the proposed 250 MMBtu/h of heat input size
threshold for combustion turbines operating at full load, and because
the proposal did not otherwise identify a basis for amending the part-
load size threshold, the EPA is retaining in subpart KKKKa a size
threshold that is comparable to the 30 MW output threshold in subpart
KKKK. However, instead of using an output metric, subpart KKKKa sets a
threshold to distinguish the two size-based, part-load subcategories at
less than, or equal to or greater than, 300 MMBtu/h of heat input. All
new combustion turbines with base load ratings of greater than 300
MMBtu/h have design rated outputs of greater than 30 MW, and all new
combustion turbines with base load ratings of less than 300 MMBtu/h
have design rated outputs of less than 30 MW. This maintains
consistency with the use of a heat-input metric for other size-based
subcategories in the NSPS.
In the proposed rule for subpart KKKKa, the EPA solicited comment
with respect to a concern that the standards for the part-load
subcategory are significantly less stringent than the otherwise
applicable standards of performance and could create a perverse
incentive to operate at part loads. The Agency also solicited comment
on possible solutions. Commenters largely disagreed that the part-load
standards substantially eroded the stringency of the NSPS or created a
perverse incentive for sources to operate at lower hourly
[[Page 1929]]
loads to obtain the higher emissions standards. One commenter submitted
graphical data illustrating that it typically will not be economically
advantageous to operate at part-load for extended periods of time, and
other commenters that own or operate combustion turbines stated that
extended part-load operations are not consistent with their practices.
After considering these comments, the EPA agrees that further
changes from subpart KKKK's approach to part-load operations are not
needed in subpart KKKKa. The EPA finds the commenters' explanations
credible that the part-load subcategory does not unduly weaken the
NSPS. Nonetheless, as the EPA discussed in the proposal, we believe the
use of an optional, alternative approach to compliance using mass-based
limits could be an effective way to simplify compliance for some
combustion turbines while also ensuring overall good emissions
performance consistent with the revised standards of performance in
subpart KKKKa.\94\
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\94\ See section IV.E.4 of this preamble for discussion of the
optional, alternative mass-based NOX standards.
---------------------------------------------------------------------------
Additionally, in subpart KKKKa, the EPA is maintaining as proposed
the same ambient temperature subcategorization and BSER as in subpart
KKKK. If at any point during an operating hour the ambient temperature
is below 0 [deg]F, or if the combustion turbine is located north of the
Arctic Circle, the BSER is the use of diffusion flame combustion with
the corresponding part-load standard.
Dry combustion controls are less effective at reducing
NOX emissions at part-load operations and low ambient
temperatures. In addition, SCR is only effective at reducing
NOX under certain temperatures at part loads and is not as
effective at reducing NOX as at design conditions. The only
technology the EPA has identified for all part-load operations and/or
low ambient temperatures is the use of diffusion flame combustion.
Therefore, in subpart KKKKa, the EPA determines that diffusion flame
combustion is the BSER for these conditions as proposed.\95\
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\95\ A BSER of diffusion flame combustion includes DLN that is
less effective at reducing NOX than DLN under design
conditions.
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g. Subcategorization Based on Other Factors
In response to the proposed rule, several commenters recommended
that subpart KKKKa subcategorize stationary combustion turbines based
on whether they operate as simple or combined cycle units and/or
whether they are aeroderivative or frame type units. These commenters
recommended that the EPA re-evaluate its BSER determinations to better
address the physical and operational differences between simple and
combined cycle turbine configurations because of the technical and
economic effects these differences have on controlling emissions.
Specifically, the commenters cited the higher exhaust temperatures of
simple cycle frame turbines and noted the challenges this would create
for operating SCR. One commenter noted that due to the different
capabilities of the equipment, the base load subcategory should be
split so that simple cycle and combined cycle units are not in the same
group.
While the EPA appreciates the differences between these types of
units and discusses such differences as appropriate throughout this
preamble, it is not subcategorizing based on simple versus combined
cycle or aeroderivative versus frame type combustion turbines in
subpart KKKKa. For aeroderivative and frame type combustion turbines,
separate subcategories might not be technically viable. For example,
aeroderivative turbines share components and are adapted from aircraft
jet engines, and while they tend to be lighter and have higher pressure
ratios and efficiencies than similar-sized frame units, there is
overlap and no clear distinction between the technologies. In addition,
and critically, there are no inherent differences in the performance of
combustion controls or SCR between aeroderivative and frame type
combustion turbines.\96\
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\96\ See the manufacturer specification sheet in the rulemaking
docket for additional information about available models of
stationary combustion turbines.
---------------------------------------------------------------------------
Further, the EPA believes it is more appropriate to address the
differences between combustion turbines operating in simple cycle and
combined cycle configurations through subcategorizing by
utilization.\97\ While there are clearly differences between simple and
combined cycle configurations, those differences are not necessarily
determinative of the reasonableness of different types of
NOX controls because they are superseded by another basis or
bases for subcategorization. That is, there are other characteristics
of turbines that, when accounted for under the EPA's subcategorization
approach in this final rule, obviate the need to subcategorize by
simple cycle versus combined cycle configuration because such
differences are already effectively accounted for by the utilization
subcategories.
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\97\ See discussion in section IV.B.2.b of this preamble.
---------------------------------------------------------------------------
In the utility sector, simple cycle turbines tend to operate at
much lower capacity factors (e.g., the average lifetime capacity factor
is 9 percent) than combined cycle turbines (e.g., the average lifetime
capacity factor is 51 percent). However, there is some overlap in
capacity factors. For example, in 2024, 3 percent of simple cycle
turbines operated at capacity factors greater than 30 percent, and 19
percent of combined cycle turbines operated at capacity factors less
than 30 percent. As discussed in section IV.B.2.b of this preamble, the
capacity factor or utilization level impacts the cost effectiveness of
NOX controls. This is the case regardless of whether a
turbine is in a simple cycle versus a combined cycle configuration.
After accounting for utilization (in addition to the other types of
subcategorizations the EPA is providing in this final rule), there is
no further basis for differentiating between simple and combined cycle
turbines from the perspective of selecting the BSER and standards for
NOX. Furthermore, establishing separate subcategories could
create a regulatory incentive to install simple cycle turbines instead
of combined cycle turbines--although the same controls are reasonable
for both, and simple cycle turbines emit more NOX per unit
of useful energy output. To avoid this perverse environmental outcome,
the EPA is establishing standards of performance that are achievable by
both simple and combined cycle combustion turbines under the
subcategories in this final rule. In addition, to establish separate
subcategories for simple and combined cycle turbines, the Agency would
have to determine how to subcategorize CHP facilities that operate with
and without an associated steam turbine, turbines using steam
injection, and recuperated turbines. While these turbines recover
energy from the turbine exhaust, that energy is not necessarily used to
generate electricity with a steam turbine, so these would not be
considered a combined cycle since they are not using two separate
thermodynamic cycles. However, since these types of combustion turbines
are recovering thermal energy and the exhaust gas temperatures are
lower, the costs of SCR are lower compared to simple cycle turbines.
The EPA notes that new CHP facilities often replace existing boilers
(or boilers that would have been built if CHP were not installed) and
offer significant environmental benefit compared to generating the
electricity and thermal
[[Page 1930]]
energy separately. Increasing the costs of new small, medium or low-
utilization CHP to the point that sources are disincentivized from
using CHP could have the perverse environmental outcome of increasing
overall emissions. The Agency has considered these broader impacts in
determining not to subcategorize between simple and combined cycle
turbines.
3. Evaluation of SCR Under BSER Factors
In the proposal of subpart KKKKa in December 2024, the EPA proposed
to find SCR justified under the BSER factors for combustion turbines of
all sizes, albeit not below a 40 percent capacity factor for turbines
equal to or smaller than a base load rating of 250 MMBtu/h of heat
input, and not below a 20 percent capacity factor for turbines larger
than that size.\98\ Since the proposal, the EPA has undertaken a review
of the BSER criteria in relation to SCR considering the extensive
technical comments submitted. The EPA's closer evaluation of cost
information concerning SCR as well as information concerning the
difficulty of application of SCR for certain subcategories, and other
downsides of SCR in terms of its emissions and energy impacts have led
the EPA to conclude that SCR is not justified under the BSER factors
for all but new large high-utilization combustion turbines.
---------------------------------------------------------------------------
\98\ See 89 FR 101322-23.
---------------------------------------------------------------------------
The EPA is determining for subpart KKKKa that SCR is part of the
BSER for new large high-utilization stationary combustion turbines
(i.e., that are utilized at 12-calendar-month capacity factors greater
than 45 percent). For these types of combustion turbines, SCR has been
nearly universally adopted in recent years, and the EPA has determined
it is cost-effective, achieving substantial reductions in
NOX emissions at costs that are comparable to those that the
EPA has found reasonable in other rules over the past several decades.
The EPA received no significant, adverse comments asserting that SCR is
not appropriately part of the BSER for this subcategory of new
combustion turbines.
A review of recent rules and determinations, multiple relevant cost
metrics, and the adoption of SCR technology across certain types and
sizes of power sector stationary combustion turbines in recent years,
all support our determination that this technology is cost-reasonable
for the subcategory of large high-utilization turbines, to which we
apply it as BSER in subpart KKKKa.
However, for all other combustion turbine subcategories, the EPA is
determining that SCR is not part of the BSER under present
circumstances. For these other subcategories, SCR is not cost
reasonable in relation to the amount of NOX emission
reductions that can be achieved, presents implementation and
operational challenges, has high energy impacts, and has other non-air
quality and environmental impacts that are not justified in relation to
the relatively small reduction in NOX emissions beyond the
standards that can be achieved with combustion controls.
The SCR process is based on the chemical reduction of
NOX via a reducing agent (reagent) and a solid catalyst. To
remove NOX, the reagent, commonly ammonia (NH3,
anhydrous and aqueous) or urea-derived ammonia, is injected into the
post-combustion flue gas of the combustion turbine. The reagent reacts
selectively with the flue gas NOX within a specific
temperature range and in the presence of the catalyst and oxygen to
reduce the NOX into molecular nitrogen (N2) and
water vapor (H2O). SCR employs a ceramic honeycomb or metal-
based surface with activated catalytic sites to increase the rate of
the reduction reaction. Over time, however, the catalyst activity
decreases, requiring replacement, washing/cleaning, rejuvenation, or
regeneration to extend the life of the catalyst. Catalyst designs and
formulations are generally proprietary. The primary components of the
SCR include the ammonia storage and delivery system, ammonia injection
grid, and the catalyst reactor. The technology can be applied as a
standalone NOX control or combined with other technologies,
including wet and dry combustion controls.
The EPA's proposed BSER of combustion controls with the addition of
post-combustion SCR for most new and reconstructed combustion turbines
generated a significant adverse response from the regulated community
and certain States during the public comment period. Other commenters
supported broad application of SCR as the BSER.
Many commenters stated that the proposed BSER is problematic and
impractical because it would require SCR on industrial combustion
turbines as well as those that operate at variable loads. According to
the commenters, this would introduce significant operating complexity,
increase annual operating costs, and result in unreasonable costs and
operating burden for these installations. Instead, these commenters
argued that the need for SCR should be determined on a site-specific
basis as part of NSR air permitting.
Additionally, commenters stated that SCR systems on simple cycle
turbines are complicated, expensive, and pose design challenges when
compared to combined cycle operations. For example:
SCR systems require specific temperature ranges to operate
effectively, typically between 315 [deg]C and 400 [deg]C (600 [deg]F
and 750 [deg]F). For simple cycle turbines with higher exhaust
temperatures, additional cooling air may be needed to cool the exhaust
flow and avoid damage to the SCR catalyst structure and operation. The
costs associated with installation, operation, and maintenance of such
cooling air systems were not adequately addressed by the EPA in the
proposal.
The installation of SCR systems requires sufficient space
for the catalyst and ammonia injection systems. Therefore, it can be
infeasible to install SCR on an existing installation that is modifying
or reconstructing; the cost of SCR on a simple cycle frame turbine can
be 30 percent to 50 percent of the cost of the turbine alone while
doubling the space requirements.
SCR is difficult even for combined cycle units in the case
of existing turbines going through modifications or reconstructions. An
existing turbine may have been installed without SCR in mind, so
replacement of the HRSG could be required for a combined cycle unit,
which is more expensive (estimated at $50 million) than the SCR system
itself (estimated at $14 million).
SCR systems are generally more effective in steady-state
operations. Combustion turbines that frequently start and stop or
operate under variable loads could face challenges in optimizing SCR
performance.
Implementing and operating an SCR system involves not only
engineering, design, and installation costs but also additional
maintenance and operational costs, including the handling and storage
of ammonia or urea, catalyst replacement, and monitoring. For this
reason, SCR is not viable for remote sites that have no full-time
operator (e.g., unattended compressor stations).
The EPA developed the proposed limits based on utility
data, not data adequately characterizing industrial installations. The
EPA should revise its cost analysis, which will demonstrate the
requirement to achieve emissions rates associated with SCR is
inappropriate for non-utility units.
Due in part to these concerns, several commenters stated that the
EPA underestimated the cost for SCR relative
[[Page 1931]]
to recent cost estimates received from manufacturers and technology
providers and submitted information to that effect. Furthermore, the
commenters contended that considering more accurate cost estimates, SCR
costs would not be ``relatively low,'' as the EPA stated at proposal,
and the technology would not be the BSER for medium and small
combustion turbines, including industrial turbines, low-utilization
turbines, and existing sources that modify or reconstruct.
These commenters stated that the EPA should re-analyze its proposed
BSER determination based on the design and operational differences
among different types of combustion turbines. In addition, commenters
provided several cost estimates that result in the incremental cost
effectiveness of installing SCR at values generally greater than
$20,000/ton NOX abated to achieve the proposed
NOX emissions limits, which exceed the levels that the EPA
has historically considered to be cost effective.
Taking into consideration the SCR cost information submitted by
commenters, the EPA has updated the BSER cost analysis from proposal.
This cost analysis supports a conclusion that the BSER for most
subcategories of new, modified, or reconstructed combustion turbines
subject to subpart KKKKa is the use of combustion controls alone (i.e.,
without SCR). The updated cost analysis nonetheless also supports our
conclusion that SCR is the BSER for large high-utilization turbines--
turbines with base load ratings greater than 850 MMBtu/h of heat input
that are utilized at capacity factors greater than 45 percent on a 12-
calendar-month basis. The new combustion turbines subject to a standard
of performance based on the BSER of combustion controls with SCR have,
over the past 5 years, almost exclusively used combined cycle
technology and have operated as base load units (i.e., at high
utilization rates). This means that the technical issues associated
with SCR raised by commenters are not a factor for new large high-
utilization sources in this subcategory.
a. Adequately Demonstrated
SCR is a mature and well-understood post-combustion add-on
NOX control that has been installed on combustion turbines
(both simple and combined cycle), utility boilers, industrial boilers,
process heaters, and reciprocating internal combustion engines. Many
natural gas-fired combustion turbines in the power sector currently
utilize SCR. While costs and operational challenges can vary quite
dramatically among different types of combustion turbines in ways that
are relevant to other BSER factors (as discussed in the sections that
follow), the EPA is not aware that SCR is completely unavailable to any
type of natural gas-fired combustion turbine. Therefore, in general the
EPA considers SCR to be a technically feasible and available technology
for control of NOX emissions from natural gas-fired
stationary combustion turbines. In that sense, SCR can be considered to
be ``adequately demonstrated''; however, after considering all of the
BSER factors as described in the sections that follow, the EPA finds
that SCR in a number of combustion turbine applications is not the BSER
for most subcategories of combustion turbines.
For non-natural gas-fired combustion turbines, commenters noted
that SCR has not been demonstrated on liquid fuel-fired turbines
(including distillate and biofuels) operating at high-utilization rates
and that biofuels can poison SCR catalysts. The EPA does not have long-
term performance information for various types of non-natural gas-fired
combustion turbines and due to potential complications, such as
catalyst deactivation due to impurities in the fuel, the EPA is not
determining that SCR is technically feasible for all non-natural gas-
fired turbines.
b. Extent of Reductions in NOX Emissions
The percent reduction in NOX emissions from SCR depends
on the level of control achieved through combustion controls. For a
combustion turbine using standard combustion controls (i.e., a
guaranteed full load emissions rate of 25 p.m. NOX)
reductions can approach 90 percent. The percent reduction across SCR is
lower if the combustion turbine is equipped with advanced combustion
controls. In conjunction with dry combustion controls on natural gas-
fired combustion turbines, SCR has been demonstrated to reduce long-
term NOX emission rates to approximately 3 ppm for multiple
types of turbines.\99\
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\99\ See section IV.B.5.a.i of this preamble for discussion of
the determination of the NOX standards of performance for
the subcategory of combustion turbines subject to a BSER that
includes SCR in subpart KKKKa.
---------------------------------------------------------------------------
c. Costs
In response to significant adverse comments concerning the EPA's
proposed cost analysis for SCR, the EPA has revised its cost analysis.
The full, final cost analysis is available in the SCR Costing technical
support document available in the docket for this action.\100\ This
section summarizes key findings from this updated analysis.
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\100\ See Docket ID No. EPA-HQ-OAR-2024-0419.
---------------------------------------------------------------------------
In 2006, when subpart KKKK was promulgated, SCR was evaluated as a
potential BSER and was determined to not meet the statutory criteria.
The estimated cost of achieving incremental NOX reductions
with the use of SCR was $9,000/ton (adjusted to 2024$) compared to the
lean premix and DLN systems that were available at that time. The EPA
determined that these costs were not reasonable in promulgating subpart
KKKK.
SCR is widely adopted as a NOX emissions control
strategy for certain stationary combustion turbines, particularly for
large turbines in the utility sector. However, during the technology
review for this action, the EPA found that information contained in the
records of permitting actions requiring SCR on combustion turbines is
not consistent or well-developed for purposes of informing a detailed
cost analysis for an NSPS. Generally, if a source was required (or
chose voluntarily) to install SCR and went forward with a new
combustion turbine project or installation, the cost of SCR presumably
did not undermine the economic viability of that project. Nonetheless,
just because individual projects have been economically viable with SCR
installation does not necessarily mean SCR installation on all
combustion turbines is cost-justified on a national basis, nor does it
necessarily reflect the best or most cost-effective means of achieving
overall reductions in NOX emissions. These considerations
will be discussed further in sections IV.B.3.c.ii and iii below.
Before proceeding with our evaluation of SCR under the BSER
factors, the Agency first notes that standalone SCR (i.e., without
combustion controls) is not the BSER. The EPA estimates that SCR
without combustion controls would be able to reduce NOX
emissions by 90 percent and achieve emission rates like turbines with
25 ppm and 15 ppm NOX guarantees based on combustion
controls alone. The exact achievable level would depend on the
uncontrolled NOX emissions rate of the relevant turbine. The
estimated cost effectiveness of SCR without combustion controls is
approximately $5,000/ton for low-utilization large turbines and $2,000/
ton for high-utilization large turbines. However, the combustion
controls analyzed in this technology review can achieve the same level
of emissions reduction at significantly lower cost. As discussed in
greater detail in section IV.B.4.c of this
[[Page 1932]]
preamble, combustion control costs are approximately $2,000/ton for
low-utilization large turbines and $100/ton for high-utilization large
turbines, without any of the secondary environmental and energy impacts
associated with SCR.\101\ Therefore, SCR alone is not the BSER for any
subcategory. The remainder of this section considers whether SCR should
be a part of the BSER, as a technology applied in addition to
combustion controls.
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\101\ See section IV.B.3.d of this preamble.
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For this final rule, as in the proposal, the EPA estimated the
capital and operating costs of SCR primarily using information from the
U.S. Department of Energy's (DOE) National Energy Technology Laboratory
(NETL) flexible generation report.\102\ The NETL report includes
detailed costing information on aeroderivative simple cycle turbines
using hot SCR and frame combined cycle turbines using conventional SCR.
For information not available in the NETL report, the EPA used
information from its cost control manual and applied Agency engineering
judgment.\103\ One commenter provided detailed comments on the SCR
costing analysis that the EPA incorporated, as appropriate, into the
cost estimations. Other commenters provided cost comparisons that
suggest the costs of SCR for simple cycle turbines have been
underestimated.\104\
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\102\ Oakes, M.; Konrade, J.; Bleckinger, M.; Turner, M.;
Hughes, S.; Hoffman, H.; Shultz, T.; and Lewis, E. (May 5, 2023).
Cost and Performance Baseline for Fossil Energy Plants, Volume 5:
Natural Gas Electricity Generating Units for Flexible Operation.
U.S. Department of Energy (DOE). Office of Scientific and Technical
Information (OSTI). Available at https://www.osti.gov/biblio/1973266.
\103\ EPA Air Pollution Control Manual, Chapter 2 Selective
Catalytic Reduction. June 2019. Available at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution.
\104\ For detailed information on the costing analysis, see the
SCR Costing technical support document included in the docket for
this action.
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The EPA determines for purposes of subpart KKKKa that the costs of
SCR are reasonable on a nationwide basis for new large high-utilization
stationary combustion turbines (i.e., with base load ratings greater
than 850 MMBtu/h of heat input and utilized at 12-calendar-month
capacity factors greater than 45 percent) and therefore that SCR is
part of the BSER for this subcategory. However, for new large low-
utilization stationary combustion turbines (i.e., utilized at 12-
calendar-month capacity factors less than or equal to 45 percent), and
for all medium and small combustion turbines, the EPA determines that
the costs of SCR are not reasonable and therefore that SCR is not part
of the BSER for these subcategories, particularly in light of the other
factors discussed in the following sections.
i. Large High-Utilization Combustion Turbines
Based on information reported to EPA's Clean Air Markets Program
Data (CAMPD), most new construction of large high-utilization
combustion turbines is projected to be combined cycle facilities. As
described in section IV.B.5 of this preamble, the maximum 12-calendar-
month capacity factor of recently constructed large simple cycle
turbines is less than 45 percent. Large turbines are almost exclusively
used to generate electrical power, and at high levels of utilization,
the levelized cost of electricity (LCOE) of combined cycle turbines is
approximately the same as or lower than the LCOE for simple cycle
turbines. Therefore, the EPA's primary costing analysis for large high-
utilization turbines is based only on the impacts and costs of using
SCR on combined cycle turbines. The costs for large high capacity
factor simple cycle turbines are provided for completeness, and while
these costs are higher than for combined cycle turbines, simple cycle
turbines are generally not expected to operate at the high utilization
levels that would trigger the SCR-based BSER subcategory.
There are several indicators that broadly support the cost-
reasonableness of SCR as part of the BSER for new large combined cycle
turbines that plan to operate at high rates of utilization. The cost of
SCR as a percentage of the capital costs associated with constructing a
new combined cycle turbine is estimated to be approximately 1 percent.
The estimation of spent capital cost for SCR is approximately $3
million to $7 million (2024$) depending on the size of the combined
cycle turbine. The capital costs of SCR on a capacity basis range from
$10 per kilowatt (kW) to $20/kW, depending on the size of the combined
cycle turbine. These costs translate into a relatively low cost per
unit of energy output, and their effects on prices or costs to the
consumer are relatively small and manageable. Total SCR cost
(annualized capital costs, fixed costs, and operating costs) per unit
of production (i.e., electricity generation) is approximately $0.66/
MWh, which represents a 2 percent increase in the LCOE for a new 370 MW
combined cycle combustion turbine operating at a 12-calendar-month
capacity factor of 51 percent for 30 years. This effect on the cost of
electricity generation compares favorably with cost analyses that have
been conducted in the past.\105\
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\105\ See, e.g., 80 FR 64510, 64565, tbl. 9 (Oct. 23, 2015).
While this comparison is useful to illustrate in a relative sense
this cost metric as used in prior EPA analyses, reference to this
prior rulemaking notice should not be understood as endorsing any
legal of factual determinations made at that time.
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Turning to the $/ton cost-effectiveness metric: In the final cost
analysis for this rule, the EPA finds that the cost effectiveness on a
$/ton of NOX controlled basis varies significantly based on
the percent reduction and the size of the combined cycle turbine. SCR
costs decrease with economies of scale and there is no single $/ton
figure that can be used to broadly represent SCR costs.
For combined cycle turbines with combustion controls guaranteed at
25 ppm NOX, the incremental costs to reduce NOX
concentrations to 3 ppm range from $3,200/ton to $4,600/ton.\106\ For
combined cycle turbines with combustion controls guaranteed at 15 ppm
NOX, the incremental costs to reduce NOX
concentrations to 3 ppm range from $4,400/ton to $6,800/ton.\107\ For
combined cycle turbines with combustion controls guaranteed at 9 ppm
NOX, the incremental costs to reduce NOX
concentrations to 3 ppm range from $7,300/ton to $12,000/ton.\108\ For
combined cycle turbines with combustion controls guaranteed at 5 ppm
NOX, the incremental costs to reduce the NOX
concentration to 3 ppm range from $13,000/ton to $22,000/ton.\109\
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\106\ The EPA reviewed the previous 5 years of emissions data to
determine long-term emission rates of turbines. A long-term
emissions rate of 3 ppm NOX was used for a turbine
complying with a short-term emissions rate of 5 ppm NOX.
The long-term emissions rate of a turbine with a 25 ppm
NOX guarantee is 20 ppm NOX. Using a long-term
emissions rate of 2 ppm or 4 ppm as representative for a combustion
turbine with SCR would not change the BSER determinations.
\107\ The long-term emissions rate of a turbine with a 15 ppm
NOX guarantee is 14 ppm NOX.
\108\ The long-term emissions rate of a turbine with a 9 ppm
NOX guarantee is 7 ppm NOX. The SCR costs are
estimated by assuming the SCR uses two catalyst layers instead of
three.
\109\ The EPA assumed the long-term emissions rate of a turbine
with a 5 ppm NOX guarantee is 5 ppm NOX. The
SCR costs are estimated by assuming the SCR uses two catalyst layers
instead of three.
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SCR costs decrease with economies of scale, and the low end of each
range is more representative of the typical size of new combined cycle
turbines. The EPA has concluded that the costs of SCR for large high-
utilization turbines with combustion controls and guaranteed
NOX emission rates of 9 ppm or greater are reasonable.
Therefore, for these types of turbines, the EPA finds SCR to be cost-
effective. While the Agency finds the incremental costs of SCR from
[[Page 1933]]
a 5-ppm baseline would not be considered cost-effective, the large
high-utilization turbines for which the EPA is including SCR in the
BSER do not achieve an emissions rate this low with combustion controls
alone. (Further, as discussed in more detail below, the EPA is setting
the standard of performance associated with SCR at 5 ppm, meaning that
to the extent large, high-utilization combustion turbines are, or come
to be, capable of achieving 5 ppm with combustion controls alone, SCR
would not need to be installed to meet the emissions standard.)
The costs of SCR for new large high-utilization combustion turbines
on a per-ton of NOX abated basis (i.e., $/ton) compare
favorably with prior EPA rulemakings that regulate NOX
emissions. Although determinations concerning cost reasonableness in
one statutory or programmatic context may not necessarily translate to
another, these regulatory precedents offer points of comparison with
respect to the same pollutant that can be informative in evaluating the
most cost-effective opportunities for abatement of a common pollutant
across multiple program arenas and therefore are relevant to the BSER
analysis. That is particularly true when the relevant statutory
provisions involve cost considerations similar to CAA section
111(a)(1).
In prior NSPS and CAA rules, the EPA generally found incremental
costs in the range of $7,400/ton of NOX abated to be cost
effective (escalated to 2024$).\110\ The EPA has also recognized that
an SCR with incremental costs of approximately $12,000/ton of
NOX abated may be justifiably rejected as not cost-
reasonable (escalated to 2024$).\111\
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\110\ See, e.g., 71 FR 9866, 9870 (Feb. 27, 2006) (finding an
incremental cost for SCR on boilers of approximately $5,000/ton to
be reasonable).
\111\ See, e.g., 77 FR 20894, 20929 (Apr. 6, 2012) (approving
State determination rejecting SCR where incremental cost was
estimated at $8,845).
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In the proposed rule, the EPA cited the Federal Implementation Plan
Addressing Regional Ozone Transport for the 2015 Ozone National Ambient
Air Quality Standard rulemaking (commonly known as the Good Neighbor
Plan), as a comparison point. In that rule, the EPA estimated SCR costs
for retrofit applications of $14,000/ton of NOX abated
(escalated to 2024$) as the appropriate representative cost threshold
for defining ``significant contribution'' under CAA section
110(a)(2)(D)(i)(I).\112\ However, upon further review and taking into
account comments with respect to this particular rule comparison, the
EPA no longer believes the Good Neighbor Plan is an appropriate
comparator. First, we did not grapple at proposal with the Supreme
Court's decision to stay enforcement of the Good Neighbor Plan as
likely arbitrary and capricious.\113\ Although the Court addressed the
Agency's failure to consider a different aspect of the problem, its
opinion raised significant doubts about the adequacy of the EPA's
analysis and engagement with comments received. Because the Good
Neighbor Plan was never implemented and its assumptions about cost
reasonableness were not tested in the real world, we do not believe the
cost analysis in that rule is entitled to significant weight as a
regulatory precedent. Second, the cost analysis in the Good Neighbor
Plan assessed retrofit costs for coal units for the purpose of
promoting attainment of the NAAQS and therefore does not directly
translate to the situation here. As noted elsewhere in this preamble,
more stringent standards may be appropriate under the specific set of
facts presented in an individual permitting context than would be
appropriate for a NSPS. Similarly, more stringent standards, and
greater associated costs, may be appropriate when necessary to meet
statutory requirements for nonattainment areas. Finally, the EPA is in
the process of reconsidering the Good Neighbor Plan, and as such, no
longer believes this cost-per-ton figure should serve as an appropriate
comparison point. Although that process is not yet complete, its
initiation reflects the Agency's significant concerns with the analysis
and justifications underlying the Good Neighbor Plan.
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\112\ See 88 FR 36654 and 36746 (June 5, 2023).
\113\ Ohio v. EPA, 603 U.S. 279, 292-94 (2024).
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Turning to simple cycle turbines: The costs of SCR for simple cycle
combustion turbines are higher, especially for frame type turbines. SCR
catalysts require specific operating temperatures to control
NOX effectively, and the exhaust temperatures of simple
cycle turbines are generally too high to be used directly in the SCR.
The exhaust gases need to be cooled, generally through injecting
tempering air to cool the exhaust to avoid damaging the SCR catalyst.
Frame turbines require higher amounts of air tempering than
aeroderivative turbines because the exhaust temperature of the most
efficient frame-type combustion turbine is approximately 200[deg]C
higher than the most efficient aeroderivative combustion turbines. For
utility units at high utilization rates, it is generally more cost
effective to cool the exhaust prior to the SCR using the HRSG instead
of tempering air. Since a HRSG does not increase the volume of exhaust
gas entering the SCR, the SCR can be smaller and less costly, and the
recovered thermal energy can be used to generate additional useful
output. The EPA notes that there are technologies other than air
tempering and a traditional HRSG that can be used to cool the exhaust
gas prior to the SCR reactor. For example, a new combined cycle turbine
could be designed with a relatively simple, lower cost HRSG and the
recovered thermal energy (i.e., steam) could be used in a relatively
simple, lower cost steam turbine or injected into the combustion
turbine itself (i.e., a steam injection combustion turbine). These
technologies have efficiencies and costs that range between more
standard simple and combined cycle turbine configurations.
To estimate the costs of SCR on large simple cycle turbines, the
EPA scaled costs based on the NETL 50 MW simple cycle turbine using dry
combustion controls. These costs incorporate tempering air and are more
representative of the SCR costs for large simple cycle turbines than
the 100 MW simple cycle model plant the EPA used at proposal. The 100
MW aeroderivative model plant is a simple cycle turbine that uses
compressor intercooling and wet combustion controls--both of which
lower the exhaust temperature and reduce the need for tempering air. In
response to specific concerns raised by commenters, the EPA
incorporated several of the suggested adjustments to the SCR costing
equations.\114\ However, for simple cycle turbines, even with these
adjustments the EPA's estimated costs are significantly less than the
example costs provided by other commenters. Because the EPA finds
commenters' information credible and representative, this suggests that
actual costs could be as high as twice the EPA's derived costs.
Consequently, the EPA's cost analysis for simple cycle turbines likely
represents best-case scenario costs.
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\114\ The EPA continues to primarily use SCR costs derived from
the NETL Flexible Generation Report. Differences in the final rule
include using SCR fixed costs dervied from the EPA's pollution
Control Manual, accounting for capacity payments, using the base
cost of the combustion turbine without SCR when determining the
value of the lost electric sales, and using the six-tenths rule when
estimating the capital costs of SCR for different combustion turbine
sizes.
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The cost of SCR as a percentage of the capital costs associated
with constructing a new simple cycle turbine is estimated to be
approximately 5 percent. The estimation of spent capital cost of the
SCR reactor is approximately $8 million to $18 million (2024$),
depending on the size of the turbine.
[[Page 1934]]
The capital costs on a capacity basis range from $45/kW to $80/kW,
depending on the size of the simple cycle turbine. These costs
translate into a higher cost per unit of energy output, and in terms of
their likely effect on prices or costs to the consumer, are higher than
for combined cycle turbines. Total costs (annualized capital costs,
fixed costs, and operating costs) in terms of cost per unit of
production (in terms of electricity generation) translate to $2/MWh, a
4 percent increase in the LCOE for a 240 MW simple cycle combustion
turbine operating at a 12-calendar-month capacity factor of 51 percent
for 30 years.
For a simple cycle turbine with combustion controls guaranteed at
25 ppm NOX, the incremental costs to reduce the
NOX concentration to 3 ppm range from $6,800/ton to $10,000/
ton. For a simple cycle turbine with combustion controls guaranteed at
15 ppm NOX, the incremental costs to reduce the
NOX concentration to 3 ppm range from $10,000/ton to
$16,000/ton. For a simple cycle turbine with combustion controls
guaranteed at 9 ppm NOX, the incremental costs to reduce the
NOX concentration to 3 ppm range from $17,000/ton to
$28,000/ton. And for simple cycle turbines with combustion controls
guaranteed at 5 ppm NOX, the incremental costs to reduce the
NOX concentration to 3 ppm NOX range from
$33,000/ton to $54,000/ton. While these estimates generally exceed what
has historically been considered cost-reasonable for NOX
emissions reductions, the EPA does not anticipate simple cycle turbines
will generally fall into the large high-utilization subcategory because
they will not be utilized at or above the 45 percent capacity factor on
a 12-calendar-month basis. At high levels of utilization, the fuel
savings of combined cycle turbine outweigh the increase in capital
costs and the large high-utilization subcategory is almost exclusively
combined cycle and combined heat and power turbines. Therefore, these
costs do not change the EPA's determination that the costs of SCR are
reasonable for large high utilization combustion turbines.
ii. Large Low-Utilization Combustion Turbines
The EPA concludes that SCR is not cost-reasonable for all other
subcategories of new stationary combustion turbines, including large
combustion turbines that are designed and operated as low-utilization
units.
Most large low-utilization combustion turbines operate as simple
cycle turbines in the utility sector. Historical data indicates that
simple cycle turbines in the utility sector typically have utilization
rates of less than 20 percent, considerably lower than the 45 percent
utilization level that defines the high-utilization subcategory. The
long-term, fleetwide average utilization for large simple cycle
turbines is approximately 9 percent. While some combined cycle turbines
may also occasionally operate below a 45 percent utilization level on a
12-month basis, this is more unusual. Therefore, the EPA uses the costs
of SCR for simple cycle turbines rather than combined cycle turbines
when evaluating low-utilization turbines.
While some indicators could support the cost-reasonableness of SCR
as a part of the BSER for large simple cycle turbines operated at low
rates of utilization, others do not. In particular, the EPA finds that
the incremental $/ton cost ranges for NOX abatement are
substantially higher than the EPA has found reasonable in prior rules
(see section IV.B.3.c.ii). Therefore, the EPA is determining in subpart
KKKKa that the costs of SCR are not reasonable for new large low-
utilization combustion turbines.
The EPA estimates using its SCR cost model that the capital cost of
SCR as a percentage of the capital costs associated with constructing
new simple cycle turbines is estimated to be approximately 3 to 4
percent. The estimation of spent capital cost is approximately $5
million to $17 million (2024$) depending on the size of the simple
cycle turbine. The capital cost on a capacity basis ranges from $40/kW
to $80/kW depending on the size of the simple cycle turbine. These
costs translate into significantly higher costs per unit of energy
output relative to large high-utilization turbines. Total costs
(annualized capital costs, fixed costs, and operating costs) in terms
of costs per unit of production (in terms of electricity generation)
for a simple cycle turbine operated at a 9 percent capacity factor for
30 years translate to $8/MWh to $14/MWh, a 5 to 8 percent increase in
the LCOE, depending on the size of the turbine. However, several
industry commenters asserted that estimated SCR costs for large simple
cycle turbines are far higher than the estimates derived from the EPA's
primary data sources. As discussed in the SCR Costing technical support
document included in the docket, as a reasonable bounding assumption we
assume the capital costs that could be experienced by some firms may be
up to three times higher than the estimates derived from our primary
data sources. Increasing the EPA estimated capital costs by a factor of
three results in an increase in the costs of electricity generation for
a typical simple cycle turbine that is higher than prior EPA rules.
Nonetheless, the EPA notes that at the upper end of the utilization
threshold, the increase in the cost of electricity from simple cycle
turbines would still be comparable with previous EPA rules.
In contrast, the costs on a per-ton basis, even using the EPA-
derived costs, do not compare favorably with prior EPA rulemakings
regulating NOX emissions. The cost effectiveness of the $/
ton of NOX controlled vary significantly based on the
utilization of the simple cycle turbine, the percent reduction, and the
size of the simple cycle turbine. Nonetheless, the historical, long-
term capacity factor of 9 percent, along with a relatively conservative
25 ppm manufacturer guaranteed emissions rate, is a reasonably accurate
representative example. For simple cycle turbines with combustion
controls guaranteed at 25 ppm NOX operating at a 30-year
capacity factor of 9 percent, the incremental costs to reduce the
NOX concentration to 3 ppm range from $27,000/ton to
$46,000/ton. The $/ton costs would be even higher for turbines with
lower guaranteed NOX emission rates (such as 15 or 9
ppm).\115\ The EPA has determined these costs to be not reasonable.
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\115\ See SCR Costing technical support document in the docket.
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Even assuming a simple cycle turbine is operated at an average
capacity factor of 40 percent for 30 years (the upper end of the
subcategory threshold), the EPA has determined the costs are not
reasonable. For simple cycle turbines with combustion controls
guaranteed at 25 ppm NOX, the incremental costs to reduce
the NOX concentration to 3 ppm range from $8,000/ton to
$12,000/ton. While these costs are closer to the range of costs the EPA
has considered reasonable in previous rulemakings, commenters with
experience in this area provided information indicating a range of
capital costs that may be considerably higher than used in our primary
cost analysis. As described earlier in this section, to incorporate
this information, we use a three-fold increase in capital cost as a
bounding assumption, and we applied adjustments to the cost model to
reflect these additional inputs to illustrate the increase in cost that
may be associated with SCR installation on at least some large simple
cycle turbines. This results in an incremental cost effectiveness of
$15,000/ton to $25,000/ton. Again, costs on a $/ton basis would be even
higher for turbines with lower guaranteed NOX emission
[[Page 1935]]
rates based on combustion controls. Therefore, the Agency determines
that the costs of SCR are not reasonable for large low-utilization
turbines in subpart KKKKa.
iii. Medium and Small Turbines
Unlike the large combustion turbine subcategory, which is dominated
by utility units, the medium and small size subcategories include a
significant number of combustion turbines used in the industrial and
institutional sectors.
The medium low-utilization subcategory is primarily comprised of
utility sector simple cycle turbines. Due to economies of scale, the
relative costs of SCR are higher for medium simple cycle turbines than
for large simple cycle turbines. The incremental control costs of SCR
on medium combustion turbines with a guaranteed NOX
emissions rate of 25 ppm range from $32,000/ton to $150,000/ton
depending on the turbine size. This corresponds to a 5 to 18 percent
increase in the cost of electricity and the $/MWh costs range from $10/
MWh to $47/MWh. Even assuming a new medium simple cycle combustion
turbine operates near the 45 percent utilization threshold, the
incremental control costs range from $9,000/ton to $37,000/ton
NOX abated. The Agency has determined the costs of SCR are
not reasonable for any new, modified, or reconstructed medium low-
utilization combustion turbines.
The medium high-utilization subcategory is primarily comprised of
industrial simple cycle combustion turbines that serve mechanical drive
applications, and about one-third of the units operate in either
industrial CHP or utility sector combined cycle applications.
Consistent with the proposed rule, the EPA used a 30-year capacity
factor of 60 percent when estimating the incremental impacts of SCR for
CHP and mechanical drive applications. Mechanical drive applications
are projected to comprise most of the new medium high-utilization
turbines. For medium mechanical drive applications using a turbine with
a 25 ppm NOX guarantee, the incremental control costs range
from $10,000/ton to $25,000/ton NOX abated depending on the
size of the turbine. These costs are higher than the Agency considers
reasonable. (See prior rule examples in section IV.B.3.c.i.) The
control costs would be even higher on a per-ton basis for combustion
turbines using combustion controls with lower NOX
guarantees. In addition, turbines with mechanical drive applications
tend to be at the smaller end of the medium size subcategory--resulting
in even higher control costs (on a $/ton basis) for such units.
Finally, commenters provided cost information that suggest the EPA's
estimated SCR costs may be unreasonably low for simple cycle
turbines.\116\ Therefore, SCR does not qualify as the BSER for new,
modified, or reconstructed medium mechanical applications.
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\116\ See SCR Costing technical support document.
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For medium CHP and combined cycle turbine applications using a
turbine with a 25 ppm NOX guarantee, the NOX
control costs for SCR range from $5,000/ton to $15,000/ton depending on
the size of the turbine and the application. For medium CHP and
combined cycle turbine applications using a turbine with a 15 ppm
NOX guarantee, the control costs for SCR range from $7,000/
ton to $23,000/ton depending on the size of the turbine and the
application. The average base load rating of medium institutional and
industrial CHP combustion turbines is 220 MMBtu/h, and the
corresponding cost of control is $10,000/ton NOX abated. SCR
would not be cost reasonable for medium-sized CHP applications using a
turbine with an emissions guarantee less than or equal to 15 ppm
NOX.
The average base load rating of medium combined cycle combustion
turbines is 740 MMBtu/h, and the corresponding cost of control is
$7,000/ton NOX abated for facilities using a turbine with a
guaranteed NOX emissions rate of 15 ppm. The cost of control
for medium combined cycle applications using a turbine with a
guaranteed NOX emissions rate of 9 ppm using combustion
controls is $13,000/ton.
Reviewing the cost-estimate ranges for all the types of turbines
included in the medium subcategory, we observe that certain cost-per-
ton figures at the lower end of the range fall within or approach a
level that may be considered reasonable. However, the Agency has
determined that it is not appropriate to subcategorize by turbine type
(i.e., simple cycle vs. combined cycle or aeroderivative vs. frame
type) as discussed earlier in section IV.B.2.g of this preamble. As
discussed further in section IV.B.3.d below, issues with SCR on small
and medium turbines addressed under other BSER factors, including
operational and maintenance challenges, ammonia slip, and energy
requirements, tip the scale against SCR as the BSER for any new,
modified, or reconstructed medium turbine regardless of size or level
of utilization within that subcategory.
Small combustion turbines are used primarily in the industrial and
institutional sectors. For small combustion turbines, the incremental
costs of SCR for a 50 MMBtu/h combined cycle turbine with
NOX combustion control guarantees of 25 ppm is $13,000/ton
NOX abated. The Agency has determined that this cost is not
reasonable. Since SCR costs on a $/ton basis will be even higher for
small low-utilization combustion turbines and for small combustion
turbines with lower guaranteed NOX emission rates based on
the use of combustion controls, the EPA has determined that the costs
of SCR are not reasonable for all new, modified, or reconstructed small
combustion turbines regardless of the level of utilization.
iv. Response to Comments Regarding SCR Costs
With respect to the ``cost of emissions reduction'' BSER factor,
one commenter opposed the cost analysis presented at proposal as over-
reliant on the incremental $/ton metric in evaluating SCR as the BSER.
The commenter contended that judicial precedents as well as
longstanding EPA practice take a more flexible view of the role of
cost, that the cost can be assessed for BSER as a whole rather than by
the incremental costs of individual components, and that under CAA
section 111, costs simply need not be excessive, i.e., so great that
they would drive the industry to ruin.
As an initial matter, the EPA agrees that the Agency has
traditionally looked at several metrics to evaluate cost as part of the
BSER analysis, and that the statute affords the Agency discretion in
how this factor can be considered under CAA section 111(a)(1).\117\ In
this rulemaking, as the analysis above sets forth, the Agency evaluated
costs using those same metrics that have been used in prior NSPS
rulemakings, including total cost, cost as a percentage of capital
cost, incremental cost-per-ton of pollutant reduced, and cost per unit
of production (in this case, electricity production or LCOE). Overall,
our cost analysis shows that while some of these cost metrics suggested
at proposal that SCR may be cost-reasonable for more subcategories of
combustion turbines than the large high-utilization subcategory, the
incremental cost-per-ton in many of these circumstances far exceed what
the Agency has found to be cost-effective in prior CAA rulemakings.
That is particularly true considering the additional information
submitted by commenters experienced in the procurement of SCR
technologies showing that the EPA underestimated the actual costs of
procurement,
[[Page 1936]]
installation, and operation at proposal, which the Agency has since
incorporated into its analysis through adjustments to the cost model.
In addition, for reasons further explained in the following section,
other BSER factors weigh against identifying SCR as the BSER, including
that SCR involves ammonia slip, which can lead to the formation of
criteria pollutants.
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\117\ See Lignite Energy Council, 198 F.3d at 933.
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With respect to the claim that the EPA is giving undue weight to
the incremental cost effectiveness of SCR and is using more rigid cost
tests than supported by relevant case law, the EPA disagrees. Use of
that metric here, including the incorporation of emissions reductions
achieved through technologies used to comply with existing subpart KKKK
as a baseline, is consistent with many prior NSPS rulemakings and
applicable case law confirming the EPA's broad discretion in analyzing
costs under CAA section 111(a)(1).\118\ Particularly in the NSPS
technology review context, considering incremental costs and emissions
reductions of a relevant emissions technology is necessarily part of
the ``review'' required by CAA section 111(b)(1)(B). The EPA has given
weight to incremental cost-effectiveness (on a $/ton basis) in
evaluating different technologies within BSER analysis in many rules
while, as here, also considering several other cost metrics.
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\118\ See Section II.A.1 of this preamble for further discussion
of the case law under CAA section 111.
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The EPA has historically used incremental costing as part of NSPS
technology reviews as a way of evaluating whether the marginal cost of
an adequately demonstrated additional emissions control supports
selecting that control as the BSER. For example, when the EPA first
determined SCR to be the BSER for coal-fired utility boilers, we used
the existing NSPS standards, which were based on combustion control
technologies, as the baseline when determining whether the incremental
costs of SCR were reasonable and whether the technology qualified as
the BSER.\119\ That cost analysis was upheld by the D.C. Circuit in
Lignite.\120\ In addition, when the EPA later reviewed the NSPS for
coal-fired electric generating units, the Agency evaluated the
incremental impacts of additional NOX reductions from the
SCR when determining the amended emissions standard and did not include
the reductions from the use of combustion controls when determining the
cost effectiveness of the amended emissions standard.\121\ Furthermore,
when promulgating subpart KKKK, the EPA did not use the original NSPS
subpart GG as the baseline, because the NOX performance
standards in subpart GG were primarily based on diffusion flame
combustion, and the EPA recognized that combustion controls would meet
BSER factors. Thus, the Agency first evaluated the level of combustion
control that could be achieved and then determined if the incremental
impacts of SCR were reasonable.\122\ The EPA has also considered
incremental costs in any number of other NSPS rulemakings in addition
to these.\123\ The EPA disagrees with commenter's assertion that
considering the incremental costs of a technology from a baseline of
either an existing standard or a less costly emissions control
technology is inconsistent with longstanding practice or case law.
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\119\ See 62 FR 36948, 36955, 36958 (July 9, 1997).
\120\ See 198 F.3d 930, 933.
\121\ See 71 FR 9870 (Feb. 27, 2006).
\122\ See Memorandum, NOX Control Technology Cost Per
Ton for Stationary Combustion Turbines 7-8 (December 21, 2004),
available at docket ID EPA-HQ-OAR-2004-0490-0114; Memorandum,
Response to Public Comments on Proposed Standards of Performance for
Stationary Combustion Turbines 53, available at docket ID EPA-HQ-
OAR-0490-0322.
\123\ See, e.g., 89 FR 16820, 16864 (Mar. 8, 2024); 87 FR 35608,
35627 (June 10, 2022); 80 FR 64510, 64559 (Oct. 23, 2015); and 77 FR
56422, 56443 (Sept. 12, 2012). Citations to these examples are not
intended to imply endorsement of the rules themselves, only that the
Agency has had a consistent practice of looking at incremental costs
in NSPS rulemakings.
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Further, cost-effectiveness figures evaluated across other CAA
rules and programs provide a meaningful comparison to assist in
determining what level of cost has generally been considered cost-
effective for reducing emissions of a given pollutant. Here, for the
subcategories of combustion turbines for which the EPA finds SCR is not
cost-reasonable, the incremental $/ton values are well in excess of
incremental cost values that have been deemed cost-effective in the
past (see examples cited in section IV.B.3.c.i.).
For this category of sources, and in the context of conducting an
NSPS review where the previous BSER was combustion controls, the EPA
finds it particularly important to focus on the incremental $/ton of
SCR rather than looking only at the total cost-effectiveness of an
``SCR with combustion control'' BSER as a whole. The SCR in this case
is an additional control, to be combined with controls that are already
widely used to comply with the current NSPS (and, indeed, largely built
directly into most turbine models by the manufacturer). Failing to
present or consider the incremental cost of SCR to the use of
combustion controls alone would effectively mask the true driver of a
large portion of the cost of a revised BSER that includes SCR.
In the case of combustion turbines, dry combustion controls are an
inherent part of the affected facility and cannot be easily removed or
modified and the end user has limited ability to change the way the
combustion controls are operated. For turbines with wet combustion
controls, if the water injection is turned off, thermal NOX
would increase, but the increased combustion flame temperature and
exhaust gas temperature potentially will result in damage to turbine
components.
For this source category, it is generally the case that combustion
turbine manufacturers have integrated combustion control technologies
into the design of the turbine itself for decades, and turbines are
sold with manufacturer guarantees of a specific level of NOX
performance already built into the machine. Given that these controls
are essentially priced into the retail cost of the turbine itself, it
is difficult to generate reliable cost estimates for many types of
combustion control technologies in isolation. Substantial improvements
in NOX performance are readily achieved through combustion
control technologies integrated into the turbine at the time of
manufacture, and the cost of these controls is reflected in the price
of purchase of the unit itself.
In contrast, SCR is an add-on technology that typically must be
purchased separately and installed on-site, often through dedicated
vendors and sub-contracts. The SCR is essentially an additional
facility that must be constructed separately with its own footprint. As
a practical matter, the costs associated with SCR are borne separately
and are clearly additional to the costs of combustion controls.
Further, combustion controls are now capable of achieving relatively
low NOX emissions rates that approach what can be achieved
with SCR. It makes sense to consider the incremental cost-effectiveness
of a technology when that technology comes at substantially increased
capital costs and operating and maintenance (O&M) costs over the life
of its operation and, compared with a baseline level of emissions
performance that is reflective of current or revised BSER
determinations for combustion controls, only achieves modestly improved
emissions performance compared to a far less costly technology.
The commenter also argues that SCR costs must be reasonable because
many combustion turbines in recent years
[[Page 1937]]
have been required to install or have voluntarily installed SCR, citing
to a variety of permitting decisions. The EPA agrees that SCR is
generally an adequately demonstrated technology for combustion
turbines. However, this commenter's argument collapses the statutory
requirement that the Administrator find that a potential control
technology is ``adequately demonstrated'' with the factors the
Administrator must consider, including the cost of emissions reduction,
when selecting the BSER. Many of the permitting decisions cited by the
commenter lack meaningful or probative cost analysis with respect to
SCR and focus instead on whether SCR is capable of being installed on
the particular source at issue. In addition, many of the commenter's
examples are for large high-utilization combined cycle turbines for
which the EPA agrees that SCR is cost reasonable. However, the Agency
disagrees that SCR is cost-reasonable for all subcategories on a
nationwide basis, such that it must be included as part of the BSER for
all combustion turbines. Whether SCR is cost-reasonable for smaller or
lower utilization combustion turbines in particular permitting contexts
is a determination that should continue to be made on a case-by-case
basis by local and State permitting authorities, taking into
consideration an array of localized factors, including air quality
planning and NAAQS attainment status.\124\
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\124\ The EPA further notes that the analysis required in
promulgating or reviewing an NSPS is materially different than the
analysis required for permitting. For example, CAA section 111(b)(2)
authorizes the Agency to distinguish only among classes, types, and
sizes of new sources, whereas permitting decisions focus on
particular sources in a facility-specific way. 42 U.S.C. 7411(b)(2).
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d. Non-Air Quality Health and Environmental Impacts and Energy
Requirements
Post-combustion SCR has several drawbacks compared to combustion
controls technologies. SCR operation has associated ammonia emissions,
a criteria pollutant precursor, reduces the output of the combustion
turbine, and requires energy to operate. That auxiliary load energy is
typically drawn from the combustion turbine itself, reducing the
efficiency of its overall power generation and resulting in
proportionally increased emissions of other air pollutants that result
from combustion turbine operation.\125\
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\125\ Note that in this section we evaluate a range of
environmental impacts associated with SCRs. To the extent these
impacts are not explicitly covered under the ``nonair quality health
and environmental impact'' factor, they are nonetheless statutorily
relevant in identifying the ``best'' system of emissions reduction.
See section II.A.1 of this preamble.
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Post-combustion SCR uses ammonia as a reagent, and some ammonia is
emitted either by passing through the catalyst bed without reacting
with NOX (unreacted ammonia) or by passing around the
catalyst bed through leaks in the seals. Both types of excess ammonia
emissions are referred to as ``ammonia slip.'' Ammonia is a precursor
to the formation of fine particulate matter (i.e., PM2.5).
Ammonia slip typically increases as the catalyst beds age and is often
limited to 10 ppm or less in operating permits. Ammonia catalysts,
consisting of an additional catalyst bed after the SCR catalyst, reacts
with the ammonia that passes through and around the catalyst to reduce
overall ammonia slip. In the NETL model plants used in the EPA's
analysis of SCR, no additional ammonia catalyst was included, and
ammonia emissions were limited to 10 ppm at the end of the catalyst's
service life. For estimating secondary impacts, the EPA assumed average
ammonia emissions of 3.5 ppm. Assuming the ammonia slip is 3.5 ppm
regardless of the NOX emissions rate prior to the SCR, the
amount of ammonia emitted per ton of NOX controlled
increases with combustion controls that achieve lower NOX
emission rates prior to the SCR. For example, assuming the
NOX emissions rate is decreased from the manufacturer
guaranteed rate of 15 ppm to 3 ppm with the addition of SCR, the EPA
estimates that for each ton of NOX controlled, 0.12 tons of
ammonia will be emitted from SCR controls. For combustion turbines with
guaranteed NOX emission rates of 9 ppm and 5 ppm, the EPA
estimates the relative ammonia emissions increase to 0.33 tons and 0.65
tons of ammonia per ton of NOX controlled,
respectively.\126\ According to information submitted by commenters,
ammonia slip increases as the percentage of NOX reduced by
SCR increases above 80 percent. For example, the ammonia slip at 85
percent reduction is nearly double the ammonia slip at 80 percent
reduction. And at 94 percent reduction, the ammonia slip is 10 times as
high relative to 80 percent reduction.
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\126\ Ammonia has a lower molecular weight (17) than
NO2 (46). Thus, although more molecules of ammonia are
being emitted in the example of a combustion turbine with a
guaranteed NOX emissions rate of 5 ppm, the mass of
NOX is greater.
---------------------------------------------------------------------------
Several commenters supportive of SCR technology called on the EPA
to establish standards of performance for ammonia slip and took the
view that this would be sufficient to mitigate this downside of SCR
technology. First, as these and other comments acknowledged, ammonia
slip is typically addressed through identifying facility-specific
practices and conditions in the permitting process, and the EPA
continues to view permitting as the appropriate mechanism for
addressing this concern. Second, a standard of performance would still
not eliminate ammonia emissions from SCR operation. Our analysis
assumes ammonia emissions of 3.5 ppm, while these commenters called for
setting an emissions limit of 2 ppm. Other commenters, however, stated
that permitted ammonia emissions rates are often in the range of 7 to
10 ppm. In short, ammonia emissions of some level are a downside of SCR
that at present cannot be entirely avoided, regardless of whether a
limit is set, and it is reasonable to assume that such a hypothetical
limit would be at or near the rate already assumed in our analysis.
The use of SCR also reduces the efficiency of a combustion turbine
through the auxiliary/parasitic load requirements to run the SCR and
the backpressure created from the catalyst bed. This not only reduces
the net energy output of combustion turbines but also translates into
increases in other types of emissions to the extent the turbine must
run longer to produce the same amount of energy to meet energy
requirements.\127\
---------------------------------------------------------------------------
\127\ Among the pollutants that would potentially increase in
association with this increase in operation is formaldehyde, a
hazardous air pollutant regulated for combustion turbines at major
sources under CAA section 112. See generally 40 CFR part 63, subpart
YYYY.
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In general, the EPA does not believe that these effects, on their
own, exclude SCR from being part of the BSER. However, these impacts
are sufficiently adverse that, in the case of minimal incremental
NOX reductions from SCR as compared with combustion controls
alone, they support a conclusion that SCR is not part of the BSER.
Thus, the non-air quality health and environmental impacts and energy
requirements of SCR support the conclusion that SCR does not qualify as
the BSER for turbines with combustion controls capable of achieving 5
ppm NOX. For combined cycle turbines using less effective
combustion controls, the non-air quality and environmental impacts do
not necessarily eliminate SCR as the BSER, and these effects do not
change our determination that SCR is part of the BSER for large high-
utilization combustion turbines. With respect to the low-utilization
and small and medium combustion turbines for which the EPA identifies a
range of cost-
[[Page 1938]]
effectiveness values for SCR, the lower ends of which may be considered
reasonable at least under some scenarios, the EPA finds these downsides
to SCR are sufficient to tip the scale away from including SCR in the
BSER.
Some commenters asserted that SCR, when used in combination with
combustion controls, is clearly the BSER even if it has downsides under
some BSER factors. These commenters asserted that statutory language
and case law requires the EPA to prioritize and maximize emissions
reductions.
The EPA agrees with the commenter that adequately demonstrated
technologies that achieve the greatest amount of emissions reduction
need to be carefully considered under all the BSER factors. However,
the statutory language does not bear out the commenters' claim that the
EPA must always mandate the most emissions reductions possible through
our BSER determinations, heedless of the other statutory factors
Congress directed the Agency to consider in CAA section 111(a)(1). In
general, the courts have recognized that the EPA has considerable
discretion in weighing those factors,\128\ and a general policy of
selecting the technology with the greatest emissions reductions
irrespective of the ``cost of achieving such reduction,'' ``nonair
quality health and environmental impact[s],'' and ``energy
requirements'' would be inconsistent with the statute.\129\
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\128\ See, e.g., Sierra Club v. Costle, 657 F.2d 298, 346-47
(D.C. Cir. 1981).
\129\ 42 U.S.C. 7411(a)(1).
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Here, the analyses above supply important and persuasive
information that SCR is not the BSER for many types of combustion
turbine applications for cost and other reasons. If the Agency were to
follow the approach suggested by some commenters and include a
stringent standard of performance across the board for combustion
turbines that could only be met with SCR, it could discourage the
development of other control technologies that do not suffer from
similar drawbacks and would likely increase emissions of other
pollutants.\130\ For example, a BSER that includes SCR could
substantially reduce the incentive to improve combustion control design
and performance. Once SCR is installed on a unit, the type of
combustion control used matters less. Taking ammonia costs as an
example, while less ammonia is required and those costs are reduced
with improved combustion controls in combination with SCR, the savings
are small relative to the overall annual costs of SCR. All else being
equal, the annual SCR costs for a 50 MW simple cycle turbine with a 15
ppm NOX guarantee is 0.9 percent lower than for a turbine
with a 25 ppm NOX guarantee (an annual savings of
$6,000).\131\ Similarly, the annual costs of a turbine with a 9 ppm
NOX guarantee are 0.7 percent ($5,000) lower than a
comparable turbine with a 15 ppm NOX guarantee. These
incremental reductions in SCR costs are relatively low and not likely
to offer a competitive advantage for an end user purchasing a turbine
with combustion controls with lower guaranteed NOX emission
rates. The economic incentive for manufacturers to invest in improved
combustion controls is to gain a competitive advantage by developing
turbines that do not require SCR, at least in certain situations. If a
BSER determination is made that effectively mandates SCR for all new
combustion turbines, regardless of the level of emissions reduction
achieved with combustion controls, there would be little incentive for
manufacturers to invest in improved combustion controls. This could
lead to increased costs for users of energy, increased fuel use (from
the efficiency loss associated with SCR), and increased ammonia
emissions.
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\130\ See id. (``We have no reason to believe Congress meant to
foreclose in section 111(a) any consideration by EPA of the
stimulation of technologies that promise significant cost, energy,
nonair health and environmental benefits. . . . [W]hen balancing the
enumerated factors to determine the basic standard it is appropriate
to consider which level of required control will encourage or
preclude development of a technology that promises significant
advantages with respect to those concerns.'').
\131\ These costs are derived using the EPA's cost model as
proposed and without adjusting based on the information provided by
commenters intended to demonstrate that the EPA's estimated capital
costs of SCR for simple cycle turbine are low. Using higher capital
costs would reduce the percent reduction in savings from improved
combustion controls.
---------------------------------------------------------------------------
Other commenters stated in response to the proposed rule that the
EPA should exclude SCR as a component of the BSER for large combustion
turbines utilized at lower capacity factors because the proposed SCR
costs, as well as the proposed 3 ppm NOX standards for large
simple cycle turbines that result from including SCR in the BSER, are
arbitrary and unreasonable. Instead, according to the commenters, the
BSER for these large turbines should be advanced DLN or DLN combustion
controls with associated NOX emission limits, as
appropriate. The commenters argued that the proposed determination of
the BSER did not consider the full costs of adding SCR to larger simple
cycle turbines (i.e., those greater than 850 MMBtu/h). Specifically,
the hot exhaust gases require cooling prior to the SCR, resulting in an
approximate doubling of capital costs. Such costs would cause an entire
class of larger frame-type turbines to be eliminated from consideration
for use due to cost. According to two commenters, large turbines have
guaranteed NOX emission rates ranging from 5 ppm to 25 ppm
by utilizing only combustion controls. The commenters added that the
exclusion of SCR as the BSER for these turbines would support the
creation of additional subcategories for combustion turbines with base
load rated heat inputs greater than 850 MMBtu/h.
Based on a review of comments, the EPA is not including in subpart
KKKKa the proposed subcategory for all sizes of new and reconstructed
combustion turbines that would operate at intermediate loads (i.e., at
12-calendar-month capacity factors greater than 20 percent and less
than or equal to 40 percent). The EPA is also determining in subpart
KKKKa that SCR does not qualify as the BSER for large low-utilization
combustion turbines (i.e., with 12-calendar-month utilization levels
less than or equal to 45 percent). Instead, the EPA is determining that
the BSER is the use of combustion controls for all sizes of new low-
utilization combustion turbines. These changes address commenters'
concerns about being required to install SCR for simple cycle turbines,
which, as discussed in section IV.B.2, have not historically operated
at high utilization levels. For large high-utilization combustion
turbines, including simple cycle turbines, the BSER includes the use of
SCR as proposed, for the reasons discussed above.
4. Evaluation of Combustion Controls Under BSER Factors
Since proposal, the EPA has undertaken a careful review of the BSER
criteria in relation to combustion controls and has considered the
extensive technical comments submitted. This includes information about
the availability and performance of wet combustion controls (i.e.,
steam or water injection), dry combustion controls, and the performance
of advanced combustion controls for certain types and classes of
available stationary combustion turbines. Advanced combustion controls
generally refer to dry combustion controls that have been tuned,
upgraded, or modified to improve the combustion process in such a
manner as to limit the formation of thermal NOX. These
include technologies such as lean premixed combustion, DLN and ultra
DLN burners, staged combustion, and flue gas recirculation, which
generally
[[Page 1939]]
result in lower NOX emission rates than non-advanced
combustion controls.\132\
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\132\ Unless otherwise indicated, ``combustion controls'' is
used in this preamble as an umbrella term to refer to both
combustion controls and advanced combustion controls. Advanced
combustion controls have guaranteed emission rates of less than 25
ppm NOX.
---------------------------------------------------------------------------
The basis of dry combustion control or DLN combustion control is to
premix the fuel and air and supply the combustion zone with a
homogenous, lean mixture of fuel and air. Lean premix means the air-to-
fuel ratio contains a low quantity of fuel, and the DLN combustors in
the turbine are designed to sustain ignition of this lean premix air/
fuel mixture at a lower peak flame temperature, thereby limiting the
formation of thermal NOX. Lean combustion may be combined
with staged combustion to achieve additional NOX reductions.
Staged combustion is designed to reduce the residence time of the
combustion air in the presence of the flame at peak temperature. The
longer the residence time, the greater the potential for thermal
NOX formation. When increasing the air/fuel ratio, excess
air is added to the mixture, which both leans the combustion air by
adding more air to the air/fuel ratio and decreases the residence time
at peak flame temperatures.
Wet combustion controls involve the injection of water (or steam)
into the flame area of the combustion reaction to reduce the peak flame
temperature in the combustion zone and limit thermal NOX
formation.\133\ Wet control systems are designed to a specific water-
to-fuel ratio that has a direct impact on the controlled NOX
emission rate and is generally controlled by the combustion turbine
inlet temperature and ambient temperature. Water injection also
increases the mass flow rate and the power output, but the energy
required to vaporize the water can reduce overall efficiency.
---------------------------------------------------------------------------
\133\ In general, the addition of water or steam will not
increase emissions of carbon monoxide (CO) or unburned hydrocarbons.
However, at higher injection rates, emissions of CO and unburned
hydrocarbons can increase.
---------------------------------------------------------------------------
Steam injection is like water injection, except that steam is
injected into the compressor and/or through the fuel nozzles directly
into the combustion chamber instead of water. Steam injection reduces
NOX emissions and has the advantage of improved efficiency
and larger increases in the output of the combustion turbine. When
compared to standard simple cycle turbines, combustion turbines using
steam injection are more efficient but more complex with higher capital
costs. Conversely, compared to standard combined cycle combustion
turbines, the combustion turbines using steam injection are simpler and
have shorter construction times and lower capital costs but also lower
efficiencies.\134\ Combustion turbines using steam injection can start
quickly, have good part-load performance, and can respond to rapid
changes in demand. Since the exhaust gas is cooled, it reduces or
eliminates the need for air tempering prior to any associated SCR and
thereby lowers the costs of SCR.
---------------------------------------------------------------------------
\134\ Bahrami, S., et al (2015), Performance Comparison between
Steam Injected Gas Turbine and Combined Cycle during Frequency
Drops. Energies 2015, Volume 8. Accessed at https://doi.org/10.3390/en8087582; Mitsubishi Power, Smart-AHAT (Advanced Humid Air Turbine.
Accessed at https://power.mhi.com/products/gasturbines/technology/smart-ahat.)
---------------------------------------------------------------------------
The EPA is determining that combustion controls continue to be
either the BSER or part of the BSER for all subcategories of new,
modified, or reconstructed stationary combustion turbines in subpart
KKKKa. This is the result of a revised BSER analysis since proposal
that supports the conclusion that combustion controls alone, without
the addition of SCR, are the BSER for all but one subcategory of new
stationary combustion turbines and for all modified or reconstructed
turbines.
The different types of dry combustion controls have been standard
equipment on stationary combustion turbines for decades and have been
shown to be cost-effective while achieving substantial reductions in
NOX. Furthermore, the technology has continued to improve,
as demonstrated by the lower guaranteed NOX emission rates
of advanced combustion controls for certain sizes, classes, and types
of new turbines compared to the performance of combustion controls that
were available when subpart KKKK was promulgated in 2006. For certain
classes of turbines, advanced combustion controls with DLN or ultra DLN
have demonstrated the ability to achieve NOX emission rates
comparable to the NOX emission rates achieved by combustion
turbines that operate with SCR but at lower cost and without the
drawbacks of SCR discussed elsewhere in this preamble.
Wet combustion controls (including steam-injection), by contrast,
are also a mature combustion control technology but generally there
have not been significant improvements in emissions performance with
these technologies over time. Wet combustion controls remain the
appropriate control type for non-gaseous fuels. However, in general,
for natural gas-fired combustion turbines, the EPA bases its BSER
determinations and emissions standards on dry combustion controls.
Nonetheless, this preamble also discusses circumstances in which wet
controls may be able to meet the selected emissions standards for
certain subcategories firing natural gas.
Based on the EPA's revised analysis, the BSER for most
subcategories of new, modified, and reconstructed combustion turbines
subject to subpart KKKKa is the use of wet, dry, or advanced dry
combustion controls alone (i.e., without SCR).
a. Adequately Demonstrated
Combustion controls were determined to be the BSER in subpart KKKK
and continue to be widely used as NOX emission controls on
new stationary combustion turbines.\135\ In that sense, combustion
controls can be considered to be ``adequately demonstrated''; however,
after considering all of the BSER factors as described in the sections
that follow, the EPA finds that different types of combustion controls
have varying degrees of feasibility and emissions performance in
relation to specific combustion turbine applications. Thus, in
generally finding that combustion controls are an ``adequately
demonstrated'' technology for the source category, the EPA does not
mean to imply that the most stringent combustion control technologies
necessarily qualify as the BSER for all subcategories of combustion
turbines. The various combustion control technologies and our
evaluation of them under the BSER factors are further discussed in this
and the sections that follow.
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\135\ See 71 FR 38482 (July 6, 2006).
---------------------------------------------------------------------------
Combustion control systems were commercially introduced more than
30 years ago and consist of operational or design modifications that
govern combustion conditions to reduce NOX formation. The
control technology is widely available from major manufacturers of
natural gas-fired aeroderivative and frame type stationary combustion
turbines and is a mature technology that has been demonstrated in
various end-use applications.\136\ In
[[Page 1940]]
subpart KKKKa, the EPA maintains that combustion controls are, as a
general matter, adequately demonstrated for new, modified, or
reconstructed natural gas-fired turbines of all sizes. However, the
availability of dry combustion controls that can achieve a particular
guaranteed NOX emission rate (e.g., 25 ppm, 15 ppm, 9 ppm,
and 5 ppm) varies between the subcategories and applications. The
availability of more advanced combustion controls that can achieve
NOX emission rates less than 25 ppm tends to correlate with
turbine size. For example, according to turbine manufacturer
specifications and information in Gas Turbine World, most models of
combustion turbines with guaranteed NOX emission rates of 9
ppm would fall within the large turbine subcategory, whereas the
availability of 9 ppm NOX turbines is generally more limited
in the medium and small subcategories. Similarly, as discussed in
section IV.B.2.c of this preamble, dry combustion controls can achieve
differing NOX emission rates depending in part on the
efficiency of the turbine model to which they are applied. Thus, the
EPA is determining that combustion controls with different guaranteed
NOX emission rates are adequately demonstrated for different
subcategories of combustion turbines, based primarily on the current
state of development of those controls as evidenced by availability of
turbines of different sizes and efficiencies that meet certain
guaranteed NOX emission rates.
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\136\ Combustion turbine manufacturers publish information about
their products, including the different combustion controls for each
model of combustion turbine commercially available. This includes
combustion turbine size, rated output, emission controls, and
guaranteed NOX emission rates. This information is also
summarized in the combustion turbine specification sheet included in
the docket for this rulemaking (Docket ID: EPA-HQ-OAR-2024-0419);
See also Siemens gas turbines at https://www.siemens-energy.com/global/en/home/products-services/product-offerings/gas-turbines.html; GE/Vernova gas turbines at https://www.gevernova.com/gas-power/products/gas-turbines; Mitsubishi Power gas turbines at
https://power.mhi.com/products/gasturbines; and Solar Turbines at
https://www.solarturbines.com/en_US/products.html.
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Specifically, for the subcategory of large low-utilization
combustion turbines, the EPA finds that advanced combustion controls
that have guaranteed NOX emission rates of 9 ppm are
adequately demonstrated for less efficient turbine designs. For large
low-utilization combustion turbines with higher efficiencies, advanced
combustion control technologies are not as effective, i.e., cannot
achieve the same emission rates due to the higher combustion
temperatures necessary for increased efficiency. Therefore, based on
the capabilities of controls available for such turbines, the EPA finds
that advanced combustion controls with guaranteed NOX
emission rates lower than 25 ppm are not adequately demonstrated for
these higher efficiency turbine models, whereas dry combustion controls
with guaranteed rates of 25 ppm are adequately demonstrated for this
subcategory of large low-utilization combustion turbines.
The subcategories of medium combustion turbines include many models
of combustion turbines designed to be operated at higher levels of
utilization. For these applications and turbines sizes, dry combustion
controls have manufacturer guaranteed NOX emission rates of
15 ppm, and the EPA is determining that such controls are adequately
demonstrated for medium high-utilization combustion turbines. For many
models of medium combustion turbines designed to be operated at lower
levels of utilization, both wet and dry combustion controls achieve the
same manufacturer guaranteed emission rate of 25 ppm NOX.
Wet combustion controls have particular benefits for medium turbines
operating at approximately 20 percent annual utilization or less, while
at utilizations of 20 to 40 percent, dry combustion controls are more
cost effective. However, as stated above, both wet and dry combustion
controls achieve the same NOX emission rate for combustion
turbines in the medium low-utilization subcategory and both are
adequately demonstrated.
While some small combustion turbines can be equipped with advanced
combustion controls with guaranteed NOX emission rates of
less than 25 ppm, such controls are not widely available across the
entire subcategory. Therefore, the EPA has determined that such
advanced combustion controls have not been adequately demonstrated for
the small combustion turbine subcategory. Based on information from
turbine manufacturers and commenters, the EPA determines combustion
controls, both wet and dry, with guaranteed NOX emission
rates of 25 ppm are adequately demonstrated for all small combustion
turbines.
For new turbines that burn non-natural gas fuels (e.g., distillate
oil), the EPA maintains that wet combustion controls only are
adequately demonstrated for control of NOX emissions. I.e.,
dry combustion controls are not adequately demonstrated for such
turbines because, as discussed in sections IV.B.2.d and IV.7.a of this
preamble, dry combustion controls have limited applicability to limit
NOX emissions when liquid fuels are fired. Wet combustion
controls (e.g., water or steam injection) are a mature combustion
control technology that has been used since the 1970s to control
NOX emissions from combustion turbines. As discussed above,
the EPA also maintains that wet combustion controls are available for
certain natural gas-fired combustion turbines as an alternative to dry
combustion controls. The emission standards for small and medium
turbines in subpart KKKK could be achieved using either wet or dry
combustion controls. However, wet combustion controls were not part of
the BSER for large natural gas-fired combustion turbines in subpart
KKKK because the technology had not demonstrated the ability to achieve
NOX emissions rates of less than 25 ppm.\137\
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\137\ The emissions standard in subpart KKKK for large natural
gas-fired turbines is 15 ppm NOX.
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b. Extent of Reductions in NOX Emissions
Combustion turbines without NOX controls use combustors
that are diffusion controlled where fuel and air are injected
separately. The resultant diffusion flame combustion can lead to the
creation of hot spots that produce high levels of thermal
NOX--as high as 200 ppm. Combustion controls are widely
available for new combustion turbines and provide substantial
reductions in NOX emissions relative to combustion turbines
without combustion controls.
The level of NOX reduction that can be achieved with dry
combustion controls depends on the combustion systems that have been
developed for the specific turbine product line. Development of dry
combustion systems is a research intensive and expensive undertaking
that is specific to each turbine product line (i.e., combustors
developed for a specific turbine model cannot be used on a different
turbine model). While almost all combustion systems developed by
manufacturers and third parties can achieve 25 ppm NOX when
burning natural gas, some combustion systems with more advanced
technologies can achieve 15 ppm, 9 ppm, or 5 ppm NOX. The
feasibility of lower NOX emissions is additionally impacted
by the characteristics of the turbine. For example, compact turbines
that can start and stop quickly (typical of aeroderivative turbines)
and turbines with high firing temperatures (typical of higher
efficiency turbines) have emission guarantees of 25 ppm NOX.
And turbines that are physically larger on a per MW of output basis,
and turbines with lower firing temperatures, frequently have available
combustion systems with emission guarantees of 15 ppm NOX or
less. The operating parameters that influence guaranteed NOX
emission rates include turbine load, fuel, and ambient conditions,
which are like the parameters used to determine the applicable hourly
emissions standards in this final rule, meaning that the EPA's BSER
determinations and standards reflect the
[[Page 1941]]
real-world conditions in which turbines will be operating. Based on
emissions information reported to CAMPD, these guaranteed emission
rates are being achieved in practice. For all these reasons, the EPA
has determined that it is appropriate to use manufacturer guarantees
for the purposes of assessing the extent of NOX emission
reductions for the BSER analysis, as well as for establishing emission
standards in subpart KKKKa.
Wet control systems are simpler to implement and have demonstrated
the ability to limit NOX emissions to as low as 25 ppm for
stationary combustion turbines firing natural gas and between 42 ppm
and 74 ppm for sources firing non-natural gas fuels. The EPA is not
aware of any advances in combustion controls for non-natural gas-fired
fuels relative to the analysis it conducted for subpart KKKK in 2006.
c. Costs
The EPA initially assessed costs relative to a starting point of a
combustion turbine with a base load rating of less than 850 MMBtu/h of
heat input using combustion controls with a NOX emissions
rate guarantee of 25 ppm, and a guarantee of 15 ppm NOX for
a turbine with a base load rating greater than 850 MMBtu/h of heat
input. These are appropriate initial baselines because, absent the
revisions to the NSPS being finalized in this action, they are the
standards to which natural gas-fired combustion turbines are subject
under subpart KKKK. Thus, in this rulemaking, the EPA is assessing
incremental costs associated with revising the existing NOX
standards.
Importantly, the EPA believes that the costs of combustion controls
are reasonable for the source category because turbine manufacturers
are currently making, and end users (including in the utility,
industrial, and institutional sectors) are currently purchasing and
operating, combustion turbines with guaranteed NOX emission
rates of 25 ppm, 15 ppm, and 9 ppm.\138\ In general, due to more
complex combustion systems (e.g., additional fuel nozzles and burners,
premixing larger amounts of air with the fuel, and more sophisticated
control systems) and/or maintenance requirements, costs increase as the
guaranteed NOX emissions rate of a combustion turbine
decreases. Moreover, assessing the incremental costs of combustion
controls is different from assessing the costs of other, add-on
pollution controls because combustion controls are integrated into the
up-front design and manufacture of combustion turbines. It can
therefore be difficult to disentangle the costs of the controls from
the costs of the turbines themselves. The EPA has endeavored to do so,
but this cost analysis of combustion controls relies more heavily on
the overall availability and costs of different sizes, classes, etc.,
of turbines and their associated controls, as well as the current use
of specific types of turbines in specific applications, as indicators
of cost reasonableness than might be appropriate in other contexts.
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\138\ See the inventory in the docket of turbines that have
recently commenced operation in the U.S.
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As stated above, the fact that turbines with combustion controls
guaranteeing NOX emission rates ranging from 9 ppm to 25 ppm
are being purchased and used today is an indicator that the incremental
capital and operating costs of combustion controls (including advanced
combustion controls) relative to diffusion flame turbines are
reasonable.\139\ However, the characteristics of how a turbine is
operated can impact the cost effectiveness of combustion controls. For
example, if a unit is operating less it will emit less NOX,
while the capital cost of the combustion controls remains relatively
unaffected. As a result, all else being held equal, the cost per ton of
NOX reduced increases as utilization decreases. Therefore,
while the capital costs of combustion controls are generally reasonable
for the source category, for certain subcategories of combustion
turbines, the cost effectiveness of certain combustion controls to meet
particular guaranteed NOX emission rates may not be.
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\139\ As discussed in section IV.B.4.a of this preamble, while
combustion controls are broadly available for and used in the source
category, advanced combustion controls are currently less available
for smaller turbine sizes and are not available for large, high-
efficiency turbines. As a corollary to their lack of general
availability for such turbines, advanced combustion controls would
also de facto not be cost reasonable for small and large, high-
efficiency turbines.
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In the 2024 proposed rule, the Agency solicited comment on detailed
capital and O&M cost information and other impacts for combustion
turbines with NOX guarantees of 15 ppm, 9 ppm and 5 ppm
relative to the costs of comparable combustion turbines with 25 ppm
NOX guarantees. The EPA stated in the proposal that to the
extent the Agency received information that the costs of more advanced
combustion controls are reasonable, NOX emission standards
consistent with these guaranteed levels could be finalized.\140\ In
response, commenters did not provide significant additional information
on the incremental cost impacts of combustion controls with different
guaranteed NOX emission rates (i.e., on the differences in
costs between 25 ppm, 15 ppm, 9 ppm, and 5 ppm combustion systems,
respectively); however, they did provide information on the cost of
combustion controls capable of achieving 25 ppm NOX
emissions relative to diffusion flame combustion. According to
commenters' information, adding dry combustion controls increased the
capital costs relative to a comparable combustion turbine using
diffusion flame combustion but the efficiency and operating costs for
turbines were unaffected by controlling emissions to 25 ppm
NOX.\141\ In contrast, the EPA's estimates of incremental
emissions reductions from combustion systems capable of achieving 15
ppm and 9 ppm NOX relative to a 25 ppm NOX
combustion system include capital costs as well as efficiency and
operating costs of controls. This indicates that the EPA's estimated
impacts of the incremental costs and efficiency impacts of improvements
in combustion controls may be conservatively high.
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\140\ See 89 FR at 101328, 101331, 101333 (requesting
information on, among other things, the capital and O&M costs of
combustion controls to meet varying emission rates for small,
medium, and large combustion turbines).
\141\ See the Electric Power Research Institute (EPRI)
supporting materials.
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In evaluating the costs and cost reasonableness of different types
of combustion controls, the EPA considered the applications for which
turbines in different subcategories are designed and the corresponding
ways in which they are operated. Small- and medium-sized turbines that
operate at low levels of utilization include, but are not limited to,
peaking turbines, which are often simple cycle turbines used to provide
power during peak summer demand when ambient temperatures are high.
They also include turbines that are not, strictly speaking, peaking
turbines but that operate 40 percent of the time or less on an annual
basis. For both types of turbines (i.e., peaking turbines and other
low-utilization turbines), wet and dry combustion controls that achieve
a NOX emission rate of 25 ppm are adequately demonstrated.
Thus, for the purposes of these revisions to subpart KKKKa, the EPA
estimated the costs of wet combustion controls at 25 ppm NOX
compared to dry combustion controls at 25 ppm NOX. Although
wet combustion controls are sometimes less effective at reducing
emissions than dry combustion controls, the use of wet combustion
controls increases the design output of simple cycle turbines and can
reduce capacity and efficiency losses because of high ambient
[[Page 1942]]
temperatures relative to the use of dry combustion controls. Wet
combustion controls also have lower capital costs than dry combustion
controls. However, wet combustion controls require highly purified
water and reduce the turbine efficiency, which contributes to higher
operating costs relative to the sue of dry combustion controls. Based
on information provided by commenters, at a NOX emissions
standard of 25 ppm, the use of wet combustion controls results in lower
overall costs than the use of dry combustion controls, but only up to a
utilization rate of approximately 20 percent, which is consistent with
a turbine that is operated in peaking applications.\142\ The costs of
dry combustion controls at these relatively low rates of utilization
would be higher.\143\ For annual utilization rates above 20 percent,
dry combustion controls are generally more cost reasonable than wet
combustion controls. Given that the low-utilization subcategory for
medium combustion turbines encompasses both of these applications--
peaking turbines at the lowest end of the utilization spectrum and
turbines that operate more frequently but still below 40 percent annual
utilization--and that both wet and dry combustion controls for turbines
with these characteristics achieve 25 ppm NOX, the EPA is
determining that the costs of combustion controls that can meet this
emission rate, whether wet or dry, are reasonable.
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\142\ This does not account for potential financial benefits of
certain wet combustion controls (e.g., inlet fogging and wet
compression used in combination with direct injection of water into
the combustor or steam injection) reducing the efficiency and output
losses that result from high ambient temperatures. However, given
that the cutoff for the low utilization subcategory is 40 percent
and that, below this threshold, both dry and wet combustion controls
are reasonable under various circumstances and regardless can
achieve the same NOX emission rate, we did not find it
necessary to further account for these potential benefits.
\143\ See the Electric Power Research Institute (EPRI)
supporting materials.
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Notwithstanding the preceding analysis of and conclusions about the
costs of wet and dry combustion controls that achieve 25 ppm
NOX for certain small and medium turbines, the EPA also
evaluated the costs of advanced combustion controls for all sizes of
combustion turbines (i.e., including small and medium turbines). For
medium and small turbines with combustion systems with emission
guarantees of less than 25 ppm NOX, most are 15 ppm
NOX turbines with the availability of 9 ppm NOX
turbines being more limited. Since combustion turbines with 9 ppm
NOX are not widely available within the medium and small
turbines subcategories, the EPA is not considering combustion controls
with 9 ppm NOX guarantees as a potential BSER for these
subcategories.
To estimate the costs of advanced dry combustion controls capable
of achieving 15 ppm NOX, relative to a turbine with a
combustion system capable of achieving 25 ppm NOX, the EPA
used three costing models.\144\ The first reduced the efficiency of the
combustion turbine and the corresponding output by 2 percent while
leaving everything else constant. The second approach is based on
available information for an aeroderivative turbine with multiple
combustion system options and reduced the heat rate, output, and
variable costs of the lower NOX turbine. The third assumed
an increase in capital costs of the turbine with lower NOX
emission rates but similar performance.\145\
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\144\ See the NOX control technology technical
support document included in the docket for this rulemaking.
\145\ The costs of advanced DLN may be approximately $24/kW
(2024$). See Control Technologies Review for Gas Turbines in Simple,
Combined Cycle and Cogeneration Systems, Eastern Research Group,
Inc., September 1, 2014. The third costing model may be more
relevant to frame type turbine because the size of the combustor is
less of an issue relative to aeroderivative turbines. Other sources
report the costs of advanced DLN as approximately $2.6/kW. See Cost
Analysis of NOX Control Alternatives for Stationary Gas
Turbines. Onsite Sycom Energy Corporation. November 5, 1999.
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For medium low-utilization turbines operating at a capacity factor
of 9 percent, the cost effectiveness of advanced combustion controls
with 15 ppm NOX guarantees ranges from $22,000/ton to
$46,000/ton NOX abated.\146\ The EPA does not consider these
costs reasonable and therefore, based on both the preceding analysis of
wet and dry combustion controls that achieve 25 ppm NOX for
medium low-utilization turbines and the high cost-per-ton figures here,
the Agency is determining that the use of combustion controls capable
of achieving 15 ppm NOX does not qualify as the BSER for
medium low-utilization turbines. Due to economies of scale, the
incremental control costs would be even higher for small turbines
relative to those for medium turbines. Therefore, the Agency also does
not consider the use of combustion controls capable of achieving 15 ppm
NOX as the BSER for small low-utilization turbines.\147\
However, at a utilization level of 40 percent, the cost effectiveness
of combustion controls for medium turbines is $8,000/ton to $10,000/ton
NOX abated. Considering that this is likely an overestimate
and that there are limited, if any, secondary environmental impacts,
the EPA considers these costs reasonable, and the use of combustion
controls with guaranteed emission rates of 15 ppm NOX could
qualify as the BSER for medium high-utilization turbines. The
incremental control costs of more advanced combustion controls for
small turbines are higher than for medium turbines and, although the
costs may appear reasonable before considering cost adjustments as
discussed in section IV.B.4.a of this preamble, the EPA has determined
that small turbines with 15 ppm NOX guarantees are not
available across the entire subcategory and therefore do not qualify as
the BSER.
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\146\ For the medium low-utilization subcategory, most affected
facilities will use simple cycle turbines. The EPA has already
determined that wet combustion controls have not been demonstrated
to be able to achieve 15 ppm NOX and these costs are
shown for completeness. Even if the costs were reasonable the Agency
would not necessarily determine the dry combustion controls with
emission guarantees of 15 ppm NOX is the BSER for the
low-utilization medium turbine subcategory or the small turbine
subcategory.
\147\ Even if the incremental control costs of more advanced
combustion controls for small turbines were reasonable, as discussed
in section IV.B.4.a, the EPA has determined that small turbines with
15 ppm NOX guarantees are not available across the entire
subcategory and therefore would not qualify as the BSER.
---------------------------------------------------------------------------
As explained in sections IV.B.3 and IV.B.5 of this preamble, the
EPA is determining that the BSER for large high-utilization turbines of
any efficiency is combustion controls with SCR. Further, as discussed
in section IV.B.4.a of this preamble, advanced combustion controls are
not adequately demonstrated for large, higher efficiency combustion
turbines operating at lower levels of utilization. Therefore, the EPA's
cost analysis of advanced combustion controls for large turbines
focuses on low-utilization, lower efficiency combustion turbines.
For large low-utilization, lower efficiency combustion turbines,
the EPA considered advanced combustion controls that can achieve
NOX emission rates of 9 ppm. At a capacity factor of 9
percent, the cost effectiveness of combustion controls for large
turbines with 9 ppm NOX guarantees ranges from $15,000/ton
to $33,000/ton NOX abated relative to a baseline of 15 ppm
NOX. The Agency reviewed the design information in Gas
Turbine World to assess the impacts on turbine performance of advanced
combustion controls to achieve NOX guarantees of 9 ppm
versus 15 ppm. This assessment revealed that, when accounting for size
(which the Agency did not do at proposal), there was no significant
difference in performance between
[[Page 1943]]
turbines with 15 ppm and 9 ppm NOX guarantees (at proposal,
the EPA estimated a 2 percent increase in heat rate). In addition,
within the large low-utilization, lower efficiency combustion turbine
subcategory (large low-utilization turbines with design efficiencies of
less than 38 percent), most new turbines have emission guarantees of 9
ppm NOX or less. Due to the similar design performance
characteristics of large turbines with 15 ppm and 9 ppm NOX
emission guarantees, and that most of the large lower efficiency
combustion turbines available have NOX emission guarantees
of 9 ppm, for the purposes of this analysis, the Agency is assuming
that the costs and performance of large lower efficiency turbines are
similar regardless of whether the NOX emissions guarantee is
15 ppm or 9 ppm. Therefore, the incremental costs of amending the
NOX emissions standard for large low-utilization, lower
efficiency combustion turbines from 15 ppm to 9 ppm is minimal.
Furthermore, relative to a baseline of 25 ppm NOX, the cost
effectiveness ranges from $8,000/ton to $17,000/ton. The EPA has
determined that the cost effectiveness values are likely on the low end
of this range, $8,000/ton. The EPA considers these costs reasonable.
Therefore, it is not appropriate to amend the standard to 25 ppm
NOX. Moreover, the EPA estimates that the incremental costs
of a BSER based on the use of advanced combustion controls guaranteed
at 9 ppm NOX relative to advanced combustion controls
guaranteed to achieve 15 ppm NOX likely does not represent a
significant cost and could qualify as the BSER, at least for the large
low-utilization turbine subcategory.\148\
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\148\ The capital costs may be approximately the same for
turbines with NOX emission guarantees of 15 ppm or 9 ppm.
The operation and maintenance costs are higher due to more rigorous
maintenance requirements. Cost Analysis of NOX Control
Alternative for Stationary Gas Turbines, ONSITE SYCOM Energy
Corporation, November 5, 1999.
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d. Non-Air Quality Health and Environmental Impacts and Energy
Requirements \149\
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\149\ To the extent any impacts are not explicitly covered under
the ``nonair quality health and environmental impact'' factor, they
are nonetheless statutorily relevant in identifying the ``best''
system of emissions reduction. See Section II.A.1 of this preamble.
---------------------------------------------------------------------------
Due to the potential efficiency loss of a combustion turbine with
NOX guarantees of 15 ppm and 9 ppm relative to a combustion
turbine with NOX guarantees of 25 ppm, for each ton of
NOX reduced, additional emissions may be generated. This
reduction in efficiency is in the combustion turbine engine and at
least a portion of the lost turbine engine efficiency can be partially
recovered in the HRSG of combined cycle and CHP facilities. If emission
rates of other pollutants are unchanged by the low-NOX
combustor, the loss of efficiency would mean that emissions of other
criteria and hazardous air pollutants (HAP) would increase by a maximum
of approximately 2 percent. However, as noted previously, the
efficiency differences between large turbines with 15 ppm
NOX and 9 ppm NOX guarantees is negligible and
actual reductions in efficiency may be less.
In general, the EPA finds that the non-air quality health and
environmental impacts and energy requirements of both dry and wet
combustion controls are acceptable, whether in conjunction with
controls capable of meeting 25 ppm, 15 ppm, 9 ppm, or 5 ppm
NOX emission standards when firing natural gas.
5. Revised NSPS for Stationary Combustion Turbines
The following sections describe the EPA's determinations of the
BSER and the degree of NOX emission limitation achievable
through application of the BSER for each subcategory of stationary
combustion turbine in subpart KKKKa. These determinations are based on
the results of a technology review of demonstrated NOX
emission controls, including information received during the public
comment period. The following sections describe each of the combustion
turbine subcategories, each BSER technology determination, and the
associated NOX standards of performance in subpart KKKKa.
The control technologies the EPA evaluated for each size-based
subcategory, whether the combustion turbine is utilized at a high or
low rate on a 12-calendar-month basis, whether the combustion turbine
is more or less efficient, whether the combustion turbine burns natural
gas or non-natural gas fuels, or whether the combustion turbine is
operated at full or part loads on an hourly basis, include dry
combustion controls (i.e., lean premix/DLN), wet combustion controls
(i.e., water or steam injection) (together, ``combustion controls''),
and post-combustion SCR.\150\
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\150\ See section IV.B.2 of this preamble for additional
discussion of the EPA's approach to subcategorization. See sections
IV.B.3-4 for discussion of the EPA's application of the BSER
criteria for these general control technology types, including
further consideration of costs, emission reductions, and non-air
quality health and environmental impacts and energy requirements, as
applies to combustion turbines in the large, medium, and small
subcategories. For additional discussion of the EPA's review of
these control technologies, see the proposal, 89 FR 101323, and the
technical support documents included in the docket for this
rulemaking.
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The EPA used three primary sources of information for determining
appropriate emission standards--combustion turbine manufacturer
guaranteed NOX emission rates, information provided in
public comments, and hourly emissions database information reported to
the EPA and available from CAMPD. The EPA considered, but did not use,
permitted emission rates (i.e., emission rates included in permits to
construct or operate) because the numeric standards differ in terms of
the averaging period used for compliance purposes and the operating
conditions under which the standards are applicable. Similarly, the EPA
did not base the NOX emission standards on stack performance
test information because these emission rates are representative of
what can be achieved under the conditions of a performance test and do
not necessarily represent what is achievable under other operating
conditions. Therefore, the EPA determines that manufacturer guarantees
represent appropriate NOX emission standards for
determination of the BSER based on the use combustion controls. The EPA
also determines that the analysis of hourly emissions data allows the
Agency to evaluate the appropriate numeric NOX standards
associated with a BSER based on the use of post-combustion SCR in
combination with combustion controls while also identifying under what
conditions the emission standards are applicable.
Table 1--Subpart KKKKa NOX Emission Standards
------------------------------------------------------------------------
Combustion turbine
Combustion turbine type base load rated NOX emission
heat input (HHV) standard
------------------------------------------------------------------------
New, firing natural gas with >850 MMBtu/h...... 5 ppm at 15
utilization rate >45 percent. percent O2 or
0.018 lb/MMBtu.
[[Page 1944]]
New, firing natural gas with >850 MMBtu/h...... 25 ppm at 15
utilization rate <=45 percent percent O2 or
and with design efficiency >=38 0.092 lb/MMBtu.
percent.
New, firing natural gas with >850 MMBtu/h...... 9 ppm at 15
utilization rate <=45 percent percent O2 or
and with design efficiency <38 0.035 lb/MMBtu.
percent.
New, modified, or reconstructed, >850 MMBtu/h...... 42 ppm at 15
firing non-natural gas. percent O2 or
0.16 lb/MMBtu.
Modified or reconstructed, firing >850 MMBtu/h...... 25 ppm at 15
natural gas, at all utilization percent O2 or
rates with design efficiency 0.092 lb/MMBtu.
>=38 percent.
Modified or reconstructed, firing >850 MMBtu/h...... 15 ppm at 15
natural gas, at all utilization percent O2 or
rates with design efficiency <38 0.055 lb/MMBtu.
percent.
New, firing natural gas at >50 MMBtu/h and 15 ppm at 15
utilization rates >45 percent. <=850 MMBtu/h. percent O2 or
0.055 lb/MMBtu.
New, firing natural gas at >50 MMBtu/h and 25 ppm at 15
utilization rates <=45 percent. <=850 MMBtu/h. percent O2 or
0.092 lb/MMBtu.
Modified or reconstructed, firing >20 MMBtu/h and 42 ppm at 15
natural gas. <=850 MMBtu/h. percent O2 or
0.15 lb/MMBtu.
New, firing non-natural gas...... >50 MMBtu/h and 74 ppm at 15
<=850 MMBtu/h. percent O2 or
0.29 lb/MMBtu.
Modified or reconstructed, firing >20 MMBtu/h and 96 ppm at 15
non-natural gas. <=850 MMBtu/h. percent O2 or
0.37 lb/MMBtu.
New, firing natural gas.......... <=50 MMBtu/h...... 25 ppm at 15
percent O2 or
0.092 lb/MMBtu.
New, firing non-natural gas...... <=50 MMBtu/h...... 96 ppm at 15
percent O2 or
0.37 lb/MMBtu.
Modified or reconstructed, all <=20 MMBtu/h...... 150 ppm at 15
fuels. percent O2 or
0.55 lb/MMBtu.
New, firing natural gas, either >50 MMBtu/h....... 25 ppm at 15
offshore turbines, turbines percent O2 or
bypassing the heat recovery 0.092 lb/MMBtu.
unit, and/or temporary turbines.
Located north of the Arctic <=300 MMBtu/h..... 150 ppm at 15
Circle (latitude 66.5 degrees percent O2 or
north), operating at ambient 0.55 lb/MMBtu.
temperatures less than 0 [deg]F
(-18 [deg]C), modified or
reconstructed offshore turbines,
operated during periods of
turbine tuning, byproduct-fired
turbines, and/or operating at
less than 70 percent of the base
load rating.
Located north of the Arctic >300 MMBtu/h...... 96 ppm at 15
Circle (latitude 66.5 degrees percent O2 or
north), operating at ambient 0.35 lb/MMBtu.
temperatures less than 0 [deg]F
(-18 [deg]C), modified or
reconstructed offshore turbines,
operated during periods of
turbine tuning, byproduct-fired
turbines and/or operating at
less than 70 percent of the base
load rating.
Heat recovery units operating All sizes......... 54 ppm at 15
independent of the combustion percent O2 or
turbine. 0.20 lb/MMBtu.
------------------------------------------------------------------------
a. Large Combustion Turbines
As noted previously, the EPA is finalizing a size-based subcategory
for stationary combustion turbines with base load ratings greater than
850 MMBtu/h of heat input (i.e., large turbines).\151\ The subcategory
is divided further based on whether the annual utilization of the
combustion turbine is greater than or less than or equal to a 12-
calendar-month capacity factor of 45 percent. The large low-utilization
combustion turbine subcategory includes separate subcategories based on
whether the design efficiency of the turbine engine is 38 percent or
greater based on the HHV of the fuel.
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\151\ Subcategories are based on the base load rating of the
turbine engine and do not include any supplemental fuel input to the
heat recovery system.
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These emission standards for large combustion turbines only apply
to new natural gas-fired sources operating at full load. In subpart
KKKKa, the EPA establishes separate subcategories, BSER, and
NOX standards for turbines operating at part load, turbines
burning non-natural as fuels, and modified and reconstructed combustion
turbines.
i. Large High-Utilization Combustion Turbines
This section describes the emissions standards in subpart KKKKa,
based on the identified BSER, for the subcategory of new large
stationary combustion turbines operated at high rates of utilization.
The EPA is finalizing, largely as proposed, a determination that the
use of combustion controls in combination with SCR is the BSER for
large high-utilization combustion turbines operating at full load. The
EPA proposed a NOX emission standard of 3 ppm for large
natural gas-fired combustion turbines utilized at intermediate and high
capacity factors and 5 ppm for the same combustion turbines when firing
non-natural gas fuels. In the proposed rule, the EPA solicited comment
on a range of 2 ppm to 5 ppm NOX when firing natural gas in
recognition of the potential for some variation in SCR performance
among different units and operating conditions.\152\
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\152\ See sections IV.7.a and IV.7.c for the final BSER
determinations and NOX standards of performance for the
subcategories of combustion turbines firing non-natural gas fuels
and turbines operating at part load.
---------------------------------------------------------------------------
In response to the proposed rule, several commenters stated that
the proposed emissions standard for large, high-utilization turbines
firing natural gas of 3 ppm NOX is too stringent and not
consistently achievable. Commenters provided descriptions and examples
of how the effectiveness of SCR can be impacted by many factors, such
as load changes and ambient conditions. For example, during variable
load operation, the absolute mass of NOX entering the SCR
system, the temperature of the combustion turbine exhaust, and exhaust
flow characteristics change. Furthermore,
[[Page 1945]]
SCR performance is impacted by catalyst temperature and flow
characteristics, and the ammonia injection rate must be adjusted to
maintain the exhaust NOX emissions concentration. Too much
ammonia injection can result in excess ammonia emissions (i.e., ammonia
slip) and too little can result in higher NOX emissions. In
addition, commenters stated that it can be challenging to adjust
ammonia injection rates during rapid load changes to maintain
NOX emissions rates while at the same time minimizing
ammonia slip, particularly for combustion turbines not selling
electricity to the electric grid. Other commenters stated that emission
standards of combustion turbines required to meet LAER should not be
used to support the cost effectiveness of SCR as a control technology.
Other commenters supported an emissions standard consistent with the
lowest emitting turbines--2 ppm NOX.
In consideration of these comments, to determine the appropriate
NOX standard of performance for large high-utilization
combustion turbines firing natural gas, the EPA also reviewed
additional NOX emissions data reported to CAMPD.
Specifically, the EPA reviewed the NOX emission rates of 91
combined cycle and CHP turbines at 46 separate stationary sources, and
the NOX emissions rates of 143 simple cycle turbines at 43
separate stationary sources. The demonstrated natural gas-fired high-
load emissions rates of the 26 recent large combined cycle and CHP
turbines with SCR range from 1.5 ppm NOX to 8.4 ppm
NOX with a median reported value of 2.7 ppm
NOX.\153\ Two facilities had demonstrated emission rates
greater than 5 ppm NOX. One of the facilities is the first
installation of a highly efficient combined cycle turbine that recently
became commercially available.\154\ While this turbine has a relatively
high NOX emissions rate, the Agency anticipates that the
manufacturer and owners or operators of future installations will learn
from the performance of this initial installation. The other facility
had higher emissions during the initial 6 months of operation and has
demonstrated an emissions rate below 5 ppm NOX after this
initial period. All other turbines have demonstrated that an emissions
standard of 5 ppm NOX is achievable for combined cycle
turbines. There are three turbines with emission rates between 4.3 ppm
and 4.8 ppm NOX. These are all high-efficiency turbines
equipped with combustion controls capable of achieving 25 ppm
NOX in combination with SCR. While not the only combined
cycle facilities using these higher efficiency models, they account for
the variability in performance at different locations. A more stringent
standard could restrict the use of these highly efficient turbines and
result in greater overall fuel use and the environmental impacts
associated with increased fuel use.
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\153\ The EPA determined the achievable emissions rate for each
turbine by calculating the 99.9 percentile of the 4-hour rolling
averages using full load hours when only natural gas was the
reported fuel. Combustion turbines with reported achievable emission
rates that are 10 percent or higher than the applicable standard
under subpart KKKK were excluded from the calculations when
reporting the demonstrated emission rates for combustion turbines.
\154\ The EPA only evaluated the reported data 6 months after
initial operation to account for the initial shake down period. The
EPA is also excluding the initial 6 months of operation for
combustion turbines where it appears the SCR might not have been
consistently operated.
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While the EPA's SCR costing analysis primarily focused on large
high-utilization combined cycle turbines, the EPA also evaluated the
performance of large low-utilization simple cycle turbines with SCR to
determine the achievability of the NSPS for these units in case owners
or operators of new simple cycle combustion turbines choose to operate
as high-utilization sources, assuming installation of SCR. The
achievable NOX emissions rate of the four recent large
simple cycle turbines with SCR ranges from 2.2 ppm to 30 ppm
NOX with a median reported value of 11 ppm NOX.
Like the combined cycle turbine mentioned above, the highest emitting
simple cycle turbine is the first installation of a higher efficiency
model that recently became commercially available. While this turbine
has a relatively high NOX emissions rate, the Agency
anticipates that the manufacturer and owners or operators of future
installations will learn from the performance of this initial
installation. The NOX emissions standards for the remaining
three turbines range from 2.2 ppm to 7.3 ppm NOX. There is
one other highly efficient large simple cycle turbine with SCR that has
been installed. This facility uses a different turbine model that began
operation in 2019 and has been able to achieve an emission rate of 9
ppm NOX. While none of the large higher efficiency simple
cycle turbines have demonstrated that 5 ppm NOX is
consistently achievable, the Agency does not project any large simple
cycle turbine operating as high-utilization turbines. However, the
mass-based standard allows large higher efficiency simple turbines with
SCR to operate in excess of a 12-calendar-month utilization rate of 45
percent while maintaining compliance with the NSPS.
Due to the limited number of large simple cycle turbines with SCR,
the EPA also reviewed the performance of recent medium low-utilization
simple cycle turbines with SCR. The NOX emissions rate of
the 62 recent medium simple cycle turbines with SCR ranges from 2 ppm
to 26 ppm NOX with a median reported value of 6.8 ppm
NOX. While only 37 percent of recent medium simple cycle
turbines have maintained an emissions rate of 5 ppm NOX or
less, the Agency finds that 5 ppm is an appropriate emissions standard
for high-utilization large simple cycle turbines. Turbines operating at
higher utilizations would have steadier loads and the operator would be
able to optimize the SCR for greater emission reduction.
Considering these factors, the EPA is finalizing a NOX
standard of performance of 5 ppm for large high-utilization turbines
firing natural gas based on the application of a BSER of combustion
controls in combination with SCR. Available data indicate that SCR
installed on new large stationary combustion turbines, when operated in
conjunction with combustion controls, is generally capable of achieving
a NOX emissions rate of 5 ppm when combustion turbines are
operating at high rates of utilization and firing natural gas.
Therefore, for this subcategory of stationary combustion turbines for
which the EPA determines SCR is a component of the BSER and which are
firing natural gas, the EPA determines that the emissions standard is 5
ppm. For new large combustion turbines operating at high rates of
utilization and firing non-natural gas fuels, the EPA determines the
NOX standard to be 42 ppm based on the application of a BSER
of wet combustion controls with the addition of post-combustion SCR.
While some combustion turbine facilities have generally been
capable of reaching an emissions rate of 3 ppm or less, the 5-ppm
emissions standard in this case will allow sources to use higher
efficiency classes of turbines in combined cycle configurations, to use
combustion controls without SCR, and to minimize ammonia emissions.
The EPA finds some commenters' call for a 2 ppm NOX
emissions standard to be unrealistically stringent. Only two-thirds of
recent (i.e., since 2020 large, combined cycle turbines and no simple
cycle facility evaluated by the EPA have been able to achieve an
emissions rate of 2 ppm NOX. As a practical matter, it would
prohibit the use of high-utilization simple cycle turbines with SCR,
and to maintain any compliance
[[Page 1946]]
margin, would at a minimum restrict developers of new combined cycle
turbines to use turbine designs with the lowest emitting combustion
controls in combination with SCR and high ammonia injection rates. This
would result in increased costs, fuel use, and ammonia emissions. Thus,
while the EPA acknowledges that some combustion turbine facilities have
generally been capable of reaching an emissions rate of 2 or 3 ppm
using SCR, the Agency believes it is important that all of the
combustion turbines in the subcategory for which SCR is the BSER are
capable of achieving the emissions standard, taking into account
natural variability and temporary fluctuations in emissions
performance, as well as cost, fuel, and emissions downsides associated
with a more stringent emissions standard.
Finally, as the EPA noted at proposal, an emissions standard of 5
ppm can also potentially be met by certain classes of stationary
combustion turbines solely with the use of advanced combustion controls
rather than SCR. Given that SCR has some additional cost, pollutant,
and energy impacts associated with it, there is benefit to a standard
that at least some sources may be capable of meeting without installing
SCR, and which will help incentivize the further development and
deployment of increasingly advanced combustion controls. Thus, the
NOX standard for large high-utilization turbines is set at
an emissions rate that also recognizes the environmental benefit of
continued development of combustion controls, which, if capable of
achieving the same or similar emissions performance, have substantial
advantages over SCR.
ii. Large Low-Utilization Combustion Turbines
For large combustion turbines utilized at low capacity factors, the
EPA proposed that the BSER is the use of dry combustion controls when
firing natural gas and wet combustion controls when firing non-natural
gas fuels. The EPA proposed on that basis to maintain the same
NOX emission standards as in subpart KKKK for large
combustion turbines utilized at low capacity factors--15 ppm for
natural gas-fired turbines and 42 ppm for non-natural gas-fired
turbines.
(A.) Higher Efficiency Combustion Turbines
This section describes the emissions standards the EPA is
finalizing in subpart KKKKa, based on the identified BSER, for the
subcategory of new large stationary combustion turbines operated at low
rates of utilization and with higher efficiencies. Specifically, this
subcategory includes combustion turbines with a base load rating
greater than 850 MMBtu/h of heat input, a 12-calendar-month capacity
factor less than or equal to 45 percent, and a design efficiency
greater than or equal to 38 percent based on the HHV of the fuel.
Commenters noted that large turbines with simple cycle design
efficiencies of 38 percent or greater all have guaranteed
NOX emission rates of 25 ppm and have become commercially
available since subpart KKKK was finalized. Based on the BSER analysis
in section IV.B.3 of this preamble, the EPA determines that SCR does
not qualify as the BSER for these turbines. The only commercially
available combustion controls are guaranteed at 25 ppm NOX.
Therefore, for this subcategory of stationary combustion turbines for
which the EPA determines combustion controls to be the BSER and which
are firing natural gas, the EPA determines that the NOX
standard of performance is 25 ppm. Likewise, for this subcategory, the
EPA determines that the NOX emissions standard is 42 ppm
when firing non-natural gas fuels (based on the use of wet combustion
controls) and 96 ppm when operating at less than 70 percent of the base
load rating (based on the use of diffusion flame combustion). The EPA
is not aware of any advances in wet combustion controls that would
reduce NOX emissions lower than the emission standards in
subpart KKKK when large combustion turbines are using non-natural gas
fuels.
(B.) Lower Efficiency Combustion Turbines
This section describes the emissions standards for new large
stationary combustion turbines operated at low rates of utilization and
with lower efficiencies. Specifically, this subcategory includes
combustion turbines with a base load rated heat input greater than 850
MMBtu/h, a 12-calendar-month capacity factor less than or equal to 45
percent, and a design efficiency less than 38 percent based on the HHV
of the fuel.
For this subcategory, the EPA determines that SCR does not meet the
BSER criteria and that the BSER is the use of advanced dry combustion
controls when firing natural gas, the use of wet combustion controls
when firing non-natural gas fuels, and the use of diffusion flame
combustion when operating at less than 70 percent of the base load
rating (i.e., when operating at part load).
The BSER for large, low-utilization, lower efficiency combustion
turbines burning natural gas is the use of advanced combustion
controls. The EPA reviewed the standard NOX guaranteed
emission rates of 13 commercially available large combustion turbines
with design efficiencies less than 38 percent. Five of the turbines
have standard guarantees of 9 ppm NOX. Four of the turbines
have standard guarantees of 15 ppm NOX, and four of the
turbines have standard guarantees of 25 ppm NOX.
Of the four turbines with 15 ppm NOX standard
guarantees, two have available upgrade packages that reduce the
guaranteed emissions rate to 9 ppm NOX or less. In addition,
the manufacturer of one of the other turbines has developed a newer
design that is similar in size, more efficient, and available with
combustion controls guaranteed at 9 ppm NOX. The remaining
15-ppm turbine is on the lower end of the large turbine subcategory
(905 MMBtu/h and 88 MW) and the manufacturer offers a similar size, but
less efficient, frame type turbine with emission guarantees of 9 ppm
NOX or less. The same manufacturer also offers similar sized
aeroderivative turbines with significantly higher efficiencies that
would be classified as a medium turbine (660 MMBtu/h and 71 MW) that
can meet the low-utilization medium turbine emissions standard without
SCR. As noted previously, large low-utilization turbines are primarily
used in the utility sector and the fuel flexibility and other
characteristics of frame type turbines are not as critical. Therefore,
the EPA finds that many turbine models with emission guarantees of 9
ppm NOX exist that can meet the needs for all owners or
operators. As such, the EPA finds that 9 ppm is the appropriate
standard of performance for new large low-utilization lower efficiency
combustion turbines firing natural gas.
Even for large, lower efficiency turbine models not manufactured to
meet a 9-ppm emissions standard, the EPA generally anticipates that
these models will continue to be sold and operated at little
incremental cost under this rule, because this is already occurring in
the commercial marketplace. Three of the four large, lower efficiency
turbine models with 25 ppm NOX guarantees were available
when subpart KKKK was finalized and have been subject to an emissions
standard of 15 ppm NOX since 2006. The remaining large
turbine with a 25 ppm NOX guarantee became commercially
available in 2013 but is primarily intended for combined cycle
[[Page 1947]]
applications.\155\ In any case, under subpart KKKK, these turbine
models have continued to be marketed and typically install and operate
SCR to meet the subpart KKKK 15 ppm standard. The EPA anticipates that
updating the emissions standard for turbines in this subcategory from
an emissions rate of 15 ppm to 9 ppm will not induce a change in how
these turbine models are currently brought to market or used. In other
words, even if their manufacturers, owners, or operators elect not to
upgrade the combustion control performance to achieve a 9-ppm rate,
they will still be able to meet the new standard using SCR, as is
already occurring in the baseline under subpart KKKK. In the case of
continued use of SCR for these turbine models, the EPA calculates a
slight increase in incremental costs associated with going from a 15
ppm NOX emissions standard to a 9 ppm NOX
emissions standard. Specifically, the Agency estimates that the
incremental costs to achieve the standard in KKKKa for these turbines
using SCR is from the use of additional ammonia for a cost
effectiveness of $1,000/ton. These costs are reasonable.
---------------------------------------------------------------------------
\155\ The same manufacturer offers a slightly smaller turbine
(260 MW compared to 310 MW) that was commercially available when
subpart KKKK was finalized. The smaller turbine has the same simple
cycle efficiency and has a guaranteed NOX emissions rate
of 9 ppm.
---------------------------------------------------------------------------
To confirm that a 9 ppm NOX standard is appropriate, the
EPA also reviewed the turbine models of the 20 large simple cycle
turbines that have commenced operation in the utility sector since
2020. Four of these units use SCR and the other 16 units do not. The 16
turbines without SCR are models that have emission guarantees of 9 ppm
NOX and the reported emission rates support that the
combustors are achieving 9 ppm NOX. As discussed previously,
these data support finding that the BSER need not include SCR.
Therefore, lowering the emissions standard from 15 ppm to 9 ppm for
large low-utilization, lower efficiency turbines would not represent
significant costs to the regulated community.
For this subcategory, the EPA determines that the NOX
emissions standard is 42 ppm when firing non-natural gas fuels and 96
ppm when operating at less than 70 percent of the base load rating.
b. Medium Combustion Turbines
The EPA is finalizing a size-based subcategory for stationary
combustion turbines with base load ratings greater than 50 MMBtu/h and
less than or equal to 850 MMBtu/h of heat input (i.e., medium). As
discussed in section IV.B.2.b of this preamble, the subcategory is
divided further based on whether the annual utilization of the
combustion turbine is greater than or less than or equal to a 12-
calendar-month capacity factor of 45 percent.
i. Medium High-Utilization Combustion Turbines
The EPA proposed the use of combustion controls with SCR as the
BSER for medium intermediate- and high-utilization combustion turbines
operating at full load and a NOX emissions standard of 3 ppm
when firing natural gas and 9 ppm when firing non-natural gas. The EPA
proposed the use of diffusion flame combustion as the BSER when
operating at part load with a NOX emissions standard of 96
ppm or 150 ppm (depending on the base load rating of the individual
turbine). For this subcategory, as described in section IV.B.3, the EPA
has determined that SCR does not meet the BSER criteria for new medium
high-utilization combustion turbines (i.e., those with 12-calendar-
month capacity factors greater than 45 percent). In subpart KKKKa, the
BSER for medium high-utilization combustion turbines is the use of
advanced dry combustion controls when firing natural gas, wet
combustion controls when firing non-natural gas fuels, and diffusion
flame combustion when operating at part load (i.e., less than 70
percent of the base load rating).
In response to the proposed rule, several commenters stated that
the proposed 3 ppm NOX limit for medium-sized units
operating at 20 percent to 40 percent capacity factors are not
achievable without SCR. The commenters added that based on guarantees
from manufacturers, the EPA should increase the proposed NOX
limit from 3 ppm to 9 ppm for medium-sized units operating at capacity
factors of less than 40 percent based on the use of dry combustion
controls. Furthermore, a review of EPRI research found that most dry
combustion control NOX guarantees ranged from 9 ppm to 25
ppm. The commenters stated that the EPA's data showed that not all dry
combustion controls can achieve 15 ppm NOX for medium-sized
turbines. The commenters stated that the most efficient combustion
turbines operate at higher temperatures, which results in higher
NOX emissions.
The EPA agrees with the commenters that manufacturer NOX
emission rate performance guarantees for medium natural gas-fired
stationary combustion turbines using dry combustion controls range from
9 ppm to 25 ppm. While a few natural gas-fired high-efficiency
aeroderivative combustion turbines have available combustor upgrades
that have NOX emission rate performance guarantees of 15
ppm, most have standard NOX emission rate performance
guarantees of 25 ppm. However, most natural gas-fired frame units using
dry combustion controls have available guaranteed NOX
emissions rates of 15 ppm or lower; of these, half have standard
emission guarantees of 15 ppm NOX or less and only four
frame units do not have available combustor options with guarantees of
less than 25 ppm NOX. The manufacturer of these four
turbines offers models with similar outputs, often with higher
efficiencies, that have guaranteed emission rates of 15 ppm
NOX or less available. The fact that frame units with dry
combustion controls are more common than aeroderivative or turbines
using wet controls at high utilization rates supports a standard for
medium high-utilization turbines of 15 ppm NOX. The EPA
considered, but rejected, the use of combustion controls with
guaranteed emission rates of 9 ppm NOX as the BSER. Many of
the most efficient medium turbines are aeroderivative turbines and only
a select few have available emission guarantees of less than 25 ppm
NOX. Maintaining a high-utilization emissions standard of 15
ppm NOX provides a strong incentive for manufacturers to
invest in technology development and commercialize combustors with 15
ppm NOX emission guarantees. In addition, while 13 turbines
offer available combustor upgrades with NOX emission
guarantees of 9 ppm, only two models have standard guarantees of 9 ppm
NOX. An emissions standard more stringent than 15 ppm would
likely require the use of SCR for many applications, and the Agency has
determined that SCR does not meet the BSER criteria for medium
turbines.
With the adjustments in subcategories described in section IV.B.2,
and the associated BSER analysis for combustion controls in section
IV.B.4, the EPA is finalizing a NOX emissions standard of 15
ppm for this subcategory when firing natural gas. The NOX
emission standards are 74 ppm when combusting non-natural gas fuels and
96 ppm or 150 ppm (depending on the base load rating) when operating at
part load. These NOX standards are based on the application
of dry and/or wet combustion controls at full load and diffusion flame
combustion at part load.
ii. Medium Low-Utilization Combustion Turbines
The medium low-utilization turbine subcategory is primarily
composed of
[[Page 1948]]
utility sector simple cycle turbines, the majority of which are
aeroderivative designs equipped with SCR. However, as described in
section IV.B.3 of this preamble, the EPA has determined that SCR does
not meet the BSER criteria for any medium combustion turbines. The EPA
proposed a NOX emissions standard of 25 ppm for medium low-
utilization combustion turbines (i.e., those with 12-calendar-month
capacity factors less than or equal to 45 percent) firing natural gas,
74 ppm NOX when firing non-natural gas, and 96 ppm or 150
ppm (depending on the base load rating) when operating at part load
(i.e., at less than 70 percent of the base load rating).
Regarding emission standards associated with combustion controls,
some commenters supported the proposed emission standards, stating that
most aeroderivative combustion turbines and combustion turbines using
wet combustion controls have emission guarantees of 25 ppm
NOX.
The EPA agrees with commenters and is finalizing a BSER of
combustion controls for this subcategory. The reported emissions rates
of these turbines indicate that they are using combustion turbines and
controls with emission guarantees of 25 ppm NOX or less. The
medium low-utilization turbines without SCR appear to be using units
with NOX emission guarantees of 25 ppm NOX. An
emissions standard of 25 ppm NOX is consistent with the
guaranteed emissions rate of most aeroderivative turbines that have
characteristics that make them valuable for low-utilization
applications--they can start quickly without increasing maintenance
requirements and they have relatively high efficiency. Although the
EPA's BSER determination is based on its conclusion that dry combustion
controls are reasonable for the subcategory, in certain applications or
circumstances (notably for the lowest utilization peaking turbines),
wet combustion controls that can achieve the same emission rate (25 ppm
NOX) potentially have comparative advantages in terms of
cost. This overlap corroborates the reasonableness of a final emission
standard of 25 ppm NOX, which can be achieved using either
wet or dry combustion controls. Therefore, the Agency is finalizing the
emissions standard as proposed.
The emission standards for new medium stationary combustion
turbines operating at low rates of utilization (i.e., at 12-calendar-
month capacity factors less than or equal to 45 percent) is 25 ppm. For
low-utilization medium turbines firing non-natural gas fuels, the
NOX standard in subpart KKKKa is 74 ppm.
c. Small Combustion Turbines
The EPA is finalizing a size-based subcategory for stationary
combustion turbines with base load ratings less than or equal to 50
MMBtu/h of heat input (i.e., small). The final BSER for all turbines in
this subcategory is combustion controls.
The EPA proposed NOX emission standards of 3 ppm for
small natural gas-fired combustion turbines that operate at high
utilization rates and 9 ppm for the same combustion turbines when
firing non-natural gas fuels. The EPA proposed NOX emission
standards for small combustion turbines utilized at intermediate and
low utilization rates of 25 ppm for natural gas-fired turbines, 74 ppm
for non-natural gas-fired turbines, and 150 ppm for turbine operating
at part loads.
With respect to emission standards associated with combustion
controls, some commenters supported maintaining the subpart KKKK
emission standard for small turbines--42 ppm NOX for
electric generating and 100 ppm NOX for mechanical drive
applications. Other commenters stated that space constraints do not
allow the same combustor design considerations as for larger turbines
and that small turbines cannot achieve less than 25 ppm NOX.
As discussed in section IV.B.3 of this preamble, the EPA has
determined that SCR does not meet the BSER criteria for small
combustion turbines at any utilization level. The Agency therefore has
determined that combustion controls remain the BSER for the
subcategory. The EPA agrees with commenters that combustion controls
are more limited for small turbines than medium and large turbines. To
determine the appropriate emissions standard the EPA reviewed
information on manufacturer NOX emission guarantees. One
small turbine has a NOX emissions rate guarantee of 5 ppm
and a high design efficiency. However, this is a higher-cost
recuperated turbine model that is only capable of burning natural gas
(i.e., not dual-fuel capable). The fuel limitation does not cover the
source category as a whole and the EPA has determined the performance
of this single turbine should not be used when establishing the
NOX emissions standard for this subcategory. Most of the
remaining turbines have emission guarantees of 25 ppm NOX.
The EPA considered, but rejected, an emissions standard of 15 ppm
NOX. Turbines with 15 ppm NOX guarantees are only
available in the 2 MW size category and this would require the use of
SCR on the 1.5 MW and 3.5 MW turbines in the source category. As many
of these turbines are used in industrial mechanical applications, it is
necessary to match the load to the output of the turbine. Restricting
the availability of turbines would result in turbines running at part
load, which would result in inefficient operation and higher
NOX emission rates or the use of higher-emitting
reciprocating engines. Therefore, the EPA has determined that the BSER
for small natural gas-fired turbines is dry combustion controls that
can meet a NOX emission rate of 25 ppm, and the emissions
standard for these turbines is 25 ppm. The EPA notes that this
emissions standard is also achievable using wet combustion controls.
The EPA is not aware of any improvements in the performance of wet
combustion controls or improvements in the part-load performance for
these combustion turbines. Therefore, the EPA is maintaining the same
standards as in subpart KKKK--96 ppm when firing non-natural gas fuels
and 150 ppm when operating at part load (i.e., at less than 70 percent
of the base load rating).
6. Revised NSPS for Modified and Reconstructed Stationary Combustion
Turbines
This section describes the BSER and emission standards for modified
and reconstructed stationary combustion turbines subject to subpart
KKKKa. The EPA proposed to include reconstructed stationary combustion
turbines in the same size-based subcategories as new stationary
combustion turbines. The EPA believed at proposal that reconstructed
turbines could likely incorporate the same technologies to reduce
NOX as part of the reconstruction process at little or no
additional cost compared to a greenfield facility. Therefore, the EPA
proposed BSERs and NOX standards of performance for large,
medium, and small reconstructed combustion turbines were identical to
those proposed for new combustion turbines for each size-based
subcategory. Identical rationale applied to modified large combustion
turbines, which we proposed to subcategorize with the same BSER and
NOX standards of performance as new and reconstructed large
turbines.
For modified medium and small combustion turbines, the EPA proposed
that the BSER is the use of combustion controls and that SCR did not
qualify as part of the BSER for these sources due to potentially high
retrofit costs, regardless of level of utilization. Based
[[Page 1949]]
on the BSER of combustion controls, the EPA proposed NOX
standards of performance for all modified medium and small combustion
turbines of 25 ppm when firing natural gas and 74 ppm when firing non-
natural gas fuels.
Several commenters criticized the EPA's proposal to subcategorize
modified and reconstructed turbines with BSER and NOX
emission standards identical to new turbines, including the proposed
BSER determinations with respect to SCR. These commenters stated that
subpart KKKKa should group reconstructed units with modified turbines
because the same retrofit technology limitations and cost factors
apply. Another commenter, however, asserted that it is more difficult
and expensive to retrofit an existing unit to meet more stringent
standards. For example, some owners or operators might have to pay
millions of dollars to replace and redesign the HRSG to retrofit the
unit with SCR in addition to the millions of dollars spent in SCR
capital costs. Reconstruction costs are also higher because of factors
such as downtime, demolition, space constraints, and replacement of
equipment. The commenter stated that the EPA did not adequately support
grouping reconstructed and new combustion turbines together and that
the proposed NSPS should have included a more thorough analysis before
applying SCR as part of the BSER for reconstructed turbines.
The EPA agrees with commenters' assertions that the costs of
retrofitting combustion turbines with SCR is significantly higher than
for new turbines. Consequently, the EPA is determining that SCR does
not qualify as the BSER for reconstructed or modified large high-
utilization combustion turbines and is finalizing separate BSER and
standards for such turbines. In subpart KKKK, the standards for
modified and reconstructed combustion turbines are generally higher for
a given subcategory than for newly constructed turbines because
combustion controls can be more challenging to apply to modified and
reconstructed combustion turbines compared to newly constructed
combustion turbines. The different NOX standards for
modified and reconstructed combustion turbines with the same BSER as
new combustion turbines are necessary because lean premix/DLN
technology is specific to each combustion turbine model (i.e., a
combustor designed for a particular turbine model cannot simply be
installed on a different turbine model).
In subpart KKKKa, the EPA is determining that the use of combustion
controls alone (without SCR) is the BSER for modified and reconstructed
combustion turbines of all sizes. For modified and reconstructed
stationary combustion turbines with base load ratings less than or
equal to 20 MMBtu/h of heat input (i.e., small), the EPA is not aware
of technology developments and therefore the numerical NOX
standard for all small modified and reconstructed turbines in subpart
KKKKa is the same as the NOX standard in subpart KKKK. All
small modified and reconstructed stationary combustion turbines are
subject to a NOX emissions standard of 150 ppm whether they
burn natural gas or non-natural gas fuels. The EPA has determined that
modified and reconstructed combustion turbines with base load ratings
between 20 MMBtu/h and 850 MMBtu/h can achieve the same emissions rates
as larger turbines and these turbines are subcategorized as medium
turbines. The EPA is not aware of technological developments for
modified or reconstructed medium combustion turbines and is therefore
maintaining the emission standards in subpart KKKK--42 ppm
NOX for modified and reconstructed medium natural gas-fired
combustion turbines and 96 ppm NOX for modified and
reconstructed medium non-natural gas-fired combustion turbines.
Modified and reconstructed combustion turbines cannot achieve the same
emissions rates as new combustion turbines because manufacturers have
not developed combustor upgrade packages for all combustion turbines
and even for specific models with combustor upgrade packages there
might physical space constraints making the combustor upgrade
impractical. Similarly, for modified and reconstructed large lower
efficiency and non-natural gas-fired turbines the EPA is finalizing
emissions standards consistent with subpart KKKK--15 ppm NOX
for large lower efficiency natural gas-fired combustion turbines and 42
ppm NOX for large non-natural gas-fired combustion turbines.
For modified and reconstructed large natural gas-fired higher
efficiency combustion turbines the EPA is finalizing an emissions
standard consistent with that for newly constructed combustion
turbines--25 ppm NOX. For modified and reconstructed large
high utilization turbines that EPA has determined that even if the
practical limitations can be overcome the cost of retrofitting SCR is
not reasonable.
7. Revised NSPS for Other Subcategories of Stationary Combustion
Turbines
a. Non-Natural Gas Emissions Standard
The EPA is not aware of any advances in NOX combustion
controls for non-natural gas-fired fuels relative to the analysis it
conducted for subpart KKKK in 2006. Dry combustion controls have
limited applicability to liquid fuels because the technology typically
functions by premixing gaseous fuels and air into a homogenous mixture
prior to combustion, which is not possible with liquid fuels.
Advancements in wet combustion controls are limited by the amount of
water that can be injected before the flame is prematurely quenched,
resulting in increased CO and unburned hydrocarbon emissions. Contrary
to dry combustion controls, this limitation of wet combustion controls
does not prevent the technology from effectively reducing
NOX emissions during the combustion of liquid fuels. Wet
combustion controls just do not reduce NOX emissions as
effectively as dry combustion controls when gaseous fuels are burned.
Therefore, in subpart KKKKa, the EPA maintains that wet combustion
controls (i.e., water or steam injection) are the BSER for new,
modified, or reconstructed stationary combustion turbines that burn
non-natural gas fuels.
In subpart KKKKa, based on application of the BSER of wet
combustion controls, the EPA maintains the NOX emissions
standards for each subcategory of new, modified, or reconstructed
combustion turbines firing non-natural gas.\156\ Specifically, for
large turbines, the EPA maintains a NOX standard of 42 ppm
for all new, modified, or reconstructed turbines firing non-natural gas
fuels. For medium combustion turbines, the EPA maintains NOX
standards of 74 ppm NOX for new turbines and 96 ppm for
modified and reconstructed combustion turbines when firing non-natural
gas fuels. For small combustion turbines, the EPA maintains a
NOX standard of 96 ppm for new turbines and 150 ppm
NOX for modified and reconstructed turbines.
---------------------------------------------------------------------------
\156\ See table 1 in section IV.B.5 of this preamble.
---------------------------------------------------------------------------
b. Combustion Turbines Firing Hydrogen
The EPA proposed that combustion turbines that burn less than or
equal to 30 percent (by volume) hydrogen (blended with natural gas)
should be subcategorized as natural gas-fired combustion turbines and
subject to the same BSER and NOX standards of performance as
other new, modified, or reconstructed natural gas-fired
[[Page 1950]]
combustion turbines.\157\ For combustion turbines that burn greater
than 30 percent (by volume) hydrogen (blended with natural gas), the
EPA proposed to subcategorize these sources as non-natural gas-fired
combustion turbines and the applicable NOX limit was
proposed to be the same as the standard for non-natural gas-fired
combustion turbines, again, depending on the particular size-based
subcategory listed in table 1 of this preamble.
---------------------------------------------------------------------------
\157\ See table 1 in section IV.B.5 for a list of the size-based
subcategories in subpart KKKKa and see 40 CFR 60.4420a for the
definition of natural gas.
---------------------------------------------------------------------------
The proposal also included a solicitation for comment on the
proposed 30 percent (by volume) hydrogen threshold and its
appropriateness for determining whether an affected source should be
subject to the NOX standard for natural gas or non-natural
gas fuels. We also sought comment on the costs associated with co-
firing high percentages (by volume) of hydrogen, including information
about hydrogen-ready turbine designs, components, upgrades, and
retrofits. The EPA also requested data from co-firing demonstrations,
especially NOX emissions data associated with the
performance of various combustion controls with and without SCR.
In response to the proposed rule, commenters asserted that the
importance of establishing NOX standards of performance for
combustion turbines co-firing hydrogen in subpart KKKKa considering the
characteristics of hydrogen gas and the potential for increased
formation of thermal NOX from its combustion. Some
commenters stressed the need for further research because the efficacy
of hydrogen co-firing, including critical issues of fuel costs and
availability, is not yet fully established. Other commenters stated
that while some demonstrations of co-firing hydrogen with natural gas
have been conducted, and the results have been promising regarding
NOX emissions, there is insufficient industry experience and
data at this time to support the EPA's proposal that turbines co-firing
up to 30 percent hydrogen (by volume) can consistently meet the natural
gas NOX standard for each size-based subcategory. Several of
the commenters who stated that it is premature to establish
NOX standards of performance for hydrogen co-firing
commensurate with the NOX standards for natural gas-fired
combustion turbines also stated that the EPA should subcategorize
hydrogen co-firing like the approach for non-natural gas fuels with a
separate BSER and NOX standards.
In accordance with the limited data received in response to the
proposal, the EPA agrees that the NOX emissions rate of
combustion turbines co-firing hydrogen includes uncertainty and remains
in the early stages of research and development. The EPA also
recognizes the concerns of several commenters that the co-firing of
hydrogen gas does increase the temperature of combustion, and a higher
firing temperature leads to the formation of thermal NOX.
However, until more data is available about the performance of
different sizes and designs of combustion turbines co-firing various
percentages of hydrogen (by volume), and the performance of different
combustion controls under those conditions, at this time the Agency is
not able to establish hydrogen-specific NOX standards of
performance in subpart KKKKa as proposed.
Even though subpart KKKKa does not establish NOX
standards for hydrogen co-firing that are determined according to a
specific percentage of hydrogen (by volume) blended with natural gas,
in this final action, the subcategories of fuel-based NOX
standards in subpart KKKKa would apply to all new, modified, and
reconstructed combustion turbines that elect to co-fire hydrogen. It is
the EPA's understanding that hydrogen is generally mixed with natural
gas prior to entering the combustor, and once the heating value or the
methane concentration of the fuel blend no longer meets the definition
of natural gas in 40 CFR 60.4420a, the fuel would be considered a non-
natural gas fuel and subject to the non-natural gas NOX
standards for those operating hours.
In terms of percentages of hydrogen (by volume), this means that
when a combustion turbine co-fires up to approximately 25 percent
hydrogen (by volume), the blended fuel meets the definition of natural
gas and would be subject to the size-based subcategory NOX
standard for a turbine firing natural gas. If the blended fuel is
greater than approximately 25 percent (by volume) hydrogen, the fuel no
longer meets the definition of natural gas and the size-based
subcategory NOX standards for non-natural gas fuels apply.
The EPA acknowledges that there is not much practical difference
between establishing a subcategory and NOX standard based on
a co-firing limit of 30 percent (by volume) hydrogen and the
approximate 25 percent threshold that results from the application of
the definition of natural gas in subpart KKKKa. But based on limited
data, we are not able to support a determination that more stringent
NOX standards for hydrogen co-firing are applicable at this
time.
Again, based on limited data, the EPA expects that the performance
of combustion controls without SCR will be effective at limiting the
formation of thermal NOX in accordance with the
NOX standards for natural gas and non-natural gas fuels when
co-firing with hydrogen. The EPA notes that if the hydrogen and natural
gas are fed into the combustor with separate burners, the applicable
NOX standard would be calculated differently. If the energy
content is greater than 50 percent of the heat input, the non-natural
gas standard would be applicable. At lower mixing levels, the
applicable hourly NOX standard would be prorated based on
the relative heat input of the hydrogen and natural gas.\158\
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\158\ Instructions for calculating NOX emissions on a
lb/MMBtu basis, based upon the ratio of natural gas to hydrogen (by
percent volume) in the fuel blend, is included in the memorandum
Fuel-Based F-Factors for Firing of Hydrogen and Hydrogen Blends in
Combustion Turbines located in the docket for this rulemaking (See
Docket ID No. EPA-HQ-OAR-2024-0419).
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See the 2024 Proposed Rule preamble (89 FR 101338; December 13,
2024) for additional information about hydrogen co-firing in stationary
combustion turbines, including sections III.B.14.a through III.B.14.d
for discussions of the characteristics of hydrogen gas that impact
NOX emissions, hydrogen and combustion controls, hydrogen
and SCR, and future combustion turbine capabilities.
c. Part-Load NOX Standards
As discussed previously in section IV.B.2.g of this preamble,
existing subpart KKKK subcategorizes stationary combustion turbines
operating at part load (i.e., less than 75 percent of the base load
rating) and combustion turbines operating at low ambient
temperatures.\159\ The hourly NOX emissions standard is less
stringent during any hour when either of these conditions is met
regardless of the type of fuel being burned. Subpart KKKK also has
different hourly NOX emissions standards depending on if the
output of the combustion turbine is less than or equal to 30 MW (150
ppm NOX) or greater than 30 MW (96 ppm NOX)
during part-load operation or when operating at low ambient
temperatures. As described in section IV.B.2.g of this preamble, in
subpart KKKKa, the EPA is changing this size threshold for this
subcategory such that the 150 ppm NOX
[[Page 1951]]
emissions standard would be applicable to combustion turbines with base
load ratings less than or equal to 300 MMBtu/h of heat input and the 96
ppm NOX emissions standard would be applicable to combustion
turbines with base load ratings greater than 300 MMBtu/h. In subpart
KKKKa, the EPA maintains that the BSER for turbines operating at part
load or at low ambient temperatures is diffusion flame combustion for
all fuel types. Thus, the EPA also maintains, based on the application
of diffusion flame combustion, that the part-load and low ambient
temperature NOX emission standards are 150 ppm for turbines
with base load ratings of less than or equal to 300 MMBtu/h of heat
input and 96 ppm for combustion turbines with base load ratings greater
than 300 MMBtu/h. In addition, the proposed part-load standard includes
all periods of part-load operation, including startup and shutdown.
However, in contrast to the part-load standards in subpart KKKK, in
subpart KKKKa, the EPA lowers the part-load threshold from less than 75
percent load to less than 70 percent of the combustion turbine's base
load rating.\160\
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\159\ While the EPA refers to this as the part-load standard, it
includes an independent temperature component as well.
\160\ See section IV.B.2.g of this preamble for additional
discussion of this reduction in the part-load threshold.
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The part-load emissions standards effectively accommodate periods
of startup and shutdown for this source category. The determination to
maintain the BSER and NOX emission standards in subpart
KKKKa for combustion turbines operating at part load or low ambient
temperatures is based on a review of reported maximum emissions rate
data for recently constructed combustion turbines. The data includes
all periods of operation, including periods of startup and shutdown.
For combustion turbines with base load ratings of greater than 300
MMBtu/h and that recently commenced operation, 80 percent of simple
cycle turbines and 98 percent of combined cycle turbines reported a
maximum NOX emissions rate of less than 96 ppm. Based on
this information, in subpart KKKKa, the EPA maintains that a part-load
standard of 96 ppm, which includes periods of startup and shutdown, is
appropriate for combustion turbines with base load ratings of greater
than 300 MMBtu/h of heat input. The EPA does not have CEMS data for
combustion turbines with base load ratings of less than 250 MMBtu/h of
heat input and maintains the existing part-load standard in subpart
KKKKa of 150 ppm NOX.
Since startups and shutdowns are part of the regular operating
practices of stationary combustion turbines, subpart KKKKa includes a
part-load NOX emissions standard that applies during periods
of startup and shutdown. Since periods of startup and shutdown are by
definition periods of part load, and since the ``part-load standard''
is based on the emissions rate achieved by a diffusion flame combustor
instead of the combustion controls and/or SCR otherwise identified as
the BSER, the Agency concludes that this standard is appropriate to
accommodate periods of startup and shutdown. Through analysis of CEMS
data, the EPA determines that, given the part-load limits, including
periods of startup and shutdown would not result in non-compliance with
the NSPS. This also ensures this rule complies with the statutory
requirement that NSPS standards of performance apply on a continuous
basis.\161\ The EPA analyzed NOX CEMS data from existing
multiple combustion turbines and the theoretical compliance rate with a
4-hour rolling average, including all periods of operation, was
demonstrated to be achievable.\162\
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\161\ See 42 U.S.C. 7411(a)(1), 7602(k), 7602(l).
\162\ When determining the applicable standard for the hour in
conducting this analysis, the EPA assumed the combustion turbine was
operated at the hourly average capacity factor for the entire 60-
minute period. However, under the rule, the part-load standard is
applicable to the entire hour if the combustion turbine operates at
part-load at any point during the hour. Note that for this analysis,
hours with less than 60 minutes of operation were assigned the part-
load standard regardless of the reported hourly average capacity
factor.
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d. Site-Specific NOX Standard
The EPA is finalizing as proposed a provision allowing for a site-
specific NOX standard for an owner or operator of a
stationary combustion turbine that burns byproduct fuels. The owner or
operator would be required to petition the Administrator for a site-
specific standard, and, if appropriate, the Agency would conduct a
notice and comment rulemaking to establish a site-specific standard.
The Agency considers it appropriate to promulgate this provision
because subpart KKKKa covers the HRSG that was previously covered by
subpart Db when the site-specific NOX standard was adopted
for industrial boilers. The Agency also solicited comment on and is
finalizing amending subpart KKKK to provide a provision allowing for a
site-specific NOX standard for an owner or operator of an
existing stationary combustion turbine that burns byproduct fuels.
Several commenters supported finalizing a provision allowing for a
site-specific NOX standard for combustion turbines burning
byproduct fuels. Several commenters explained that there are
environmental benefits to combusting byproduct fuels (a.k.a.,
associated gas or opportunity fuels) in a turbine and that a case-by-
case or site-specific NOX standard would encourage their use
as an alternative to flaring, diesel gensets, or spark ignition gas
engines, especially for byproduct fuels recovered from oil and gas
drilling operations. However, one commenter noted that associated gas
is not the same as ``pipeline quality'' natural gas and typically
contains higher amounts of heavy alkanes and diluents such as carbon
dioxide. According to the commenter, these substances create changes in
fuel composition and increase the variability of emissions that, in
turn, increase the operational variability of these types of combustion
turbines. Another commenter supported amending subpart KKKK with the
same rule language to maintain consistency with subpart KKKKa and added
that this provision should be expanded so that facilities can request a
site-specific standard for other reasons, such as using turbine exhaust
to provide direct heat to a process.
Another commenter stated that the EPA's proposal to allow for a
site-specific NOX standard for turbines using byproduct
fuels is too broad or loosely defined. The commenter expressed concern
that facilities could blend small amounts of waste gases with regular
fuels to claim byproduct status while allowing for higher
NOX emissions than otherwise allowed under the NSPS. To
address these concerns, the commenter suggested that the final NSPS
narrow the definition of ``byproduct fuels'' to prevent misuse, require
periodic emissions testing to ensure compliance, set a minimum
NOX reduction requirement as it relates to site-specific
facilities using byproduct fuels, and limit the scope of this exemption
so only unavoidable cases qualify.
For byproduct fuels not meeting the combustion characteristics of
natural gas, DLN combustion systems have limited technical
availability. In addition, byproduct fuels can contain high amounts of
fuel-bound nitrogen. Since fuel-bound nitrogen forms NOX by
a reaction of nitrogen bound in the fuel with oxygen in the combustion
air directly (i.e., is not thermally dependent), water injection also
has limited technical availability to reduce fuel-bound NOX.
Subpart GG includes a provision for increasing the applicable
NOX emission standards by up to 50 ppm based on the amount
of fuel-bound nitrogen.\163\ The EPA considered
[[Page 1952]]
including a similar provision in subparts KKKK and KKKKa. With this
provision, a turbine using water injection to reduce thermal
NOX and burning byproduct fuels with high fuel-bound
nitrogen must comply with a standard between 92 ppm NOX and
146 ppm NOX. These emission standards are similar to the
part-load standards in subparts KKKK and KKKKa, which are based on the
use of diffusion flame combustion while burning fuels with low fuel-
bound nitrogen. Further, for locations where byproduct fuels are
available, high-purity water required for wet combustion controls is
not necessarily available. In these situations, if the fuel-bound
nitrogen is low, the expected emission rates would be similar to the
part-load standards in subpart KKKKa. The EPA is finalizing a BSER of
diffusion flame combustion for byproduct fuel-fired combustion turbines
with low fuel-bound nitrogen, and diffusion flame combustion with wet
combustion controls for byproduct fuel-fired combustion turbines with
high fuel-bound nitrogen. Therefore, the Agency is determining in
subpart KKKKa that it is appropriate to apply the same NOX
standard developed for the part-load subcategory to facilities burning
byproduct fuels.\164\ This NOX standard recognizes the
environmental benefit of reduced flaring or direct venting to the
atmosphere. To address concerns about misuse of the provision, the
emissions standard would be determined using the weighed emissions
standard approach similar to turbines that are co-firing natural gas
and non-natural gas fuels. Turbines that are only co-firing a small
portion of byproduct fuel with natural gas would be subject to an
emissions standard that is close to that of natural gas.
---------------------------------------------------------------------------
\163\ See 40 CFR 60.332(a)(4).
\164\ See section IV.B.7.c of this preamble for discussion of
the part-load NOX standards in subpart KKKKa.)
---------------------------------------------------------------------------
The EPA appreciates commenters' concern regarding breadth but
ultimately disagrees that the provision, as proposed, was unnecessarily
broad. If the NSPS is overly restrictive in the use of byproduct fuels
in a combustion turbine, then those byproduct fuels would be flared or
vented directly to the atmosphere. While the Agency expects that the
byproduct NOX standard in subpart KKKKa will allow most
types of byproducts fuels to be combusted in turbines some may still
exceed the standard (e.g., byproduct fuel with high fuel bound nitrogen
content without available water for wet combustion controls).
Therefore, to not limit the use of byproduct fuels the EPA is including
the provision to allow owners or operators to petition for a site-
specific standard.
e. Subcategory for HRSG Units Operating Independent of the Combustion
Turbine
The affected facility under subpart KKKK (and the proposed affected
facility under subpart KKKKa) includes the HRSG of CHP and combined
cycle facilities. Although not common practice, it is possible that the
HRSG could operate and generate useful thermal output while the
combustion turbine itself is not operating. In subpart KKKK, the EPA
subcategorized this type of operation and based the NOX
emissions standard on the use of combustion controls for a steam
generating unit under one of the steam generating unit NSPS. The EPA
proposed the same BSER and emissions standard in subpart KKKKa and
received no comments. In subpart KKKKa, the EPA maintains the same
approach and subcategorizes operation of the HRSG independent of the
combustion turbine engine with the same emissions standard as in
subpart KKKK.
8. Additional Amendments to the NOX Standards
a. Form of the Standard
The form of the concentration-based NOX standards of
performance in subpart KKKK is based on ppm corrected to 15 percent
O2 and the form of alternate output-based NOX
standards is determined on a pounds per megawatt hour-gross (lb/MWh-
gross) basis. Manufacturer guarantees are often reported and operating
permits are often issued in ppm (corrected to an O2 or
CO2 basis). Aligning the form of the NSPS with common
practice simplifies the understanding of the emission standards and
reduces the burden to the regulated community. While not the primary
form of the standard, the alternate output-based form of lb/MWh-gross
in subpart KKKK recognizes the environmental benefit of highly
efficient generation.
In subpart KKKKa, the EPA is continuing the approach of expressing
the primary form of the standard on an input basis. The EPA is
including input-based NOX standards on both a ppm basis and
in the form of pounds per million British thermal units (lb/MMBtu). The
EPA is also finalizing optional, alternate output-based standards in
both a gross- and net-output form.
There are advantages to allowing the input-based standard to be
expressed on either a ppm or lb/MMBtu basis. As described in section
IV.B.7.b of this preamble, co-firing hydrogen can increase the
NOX emissions rate on a ppm basis when corrected to 15
percent O2 while absolute NOX emissions may not
significantly change. Since actual emissions to the atmosphere are the
true measure of environmental impacts, the NOX emission
standards in the form of lb/MMBtu are a superior measure of
environmental performance when comparing emissions from different fuel
types. However, throughout this document, the EPA refers to
NOX emission rates using ppm for ease of comparison with
performance guarantees and permitted emission rates. The standards in
subpart KKKKa include both a ppm and equivalent lb/MMBtu for a natural
gas-fired combustion turbine or a distillate oil-fired combustion
turbine for the natural gas- and non-natural gas-fired NOX
emission standards, respectively.
The EPA also proposed optional, alternate output-based
NOX standards that owners or operators could elect to comply
with instead of the input-based standards. Commenters opposed the
output-based standards as proposed because, in their view, the values
would allow greater NOX emissions than the input-based
standards. The Agency disagrees that the output-based standards are
less environmentally protective and is including them in subpart KKKKa.
For the large high-utilization and large low-utilization subcategories,
the EPA evaluated operating data and amended the efficiency value used
to calculate the output-based standard. Based on available data and
likely operating parameters, the EPA believes the optional output-based
standards are likely to be most relevant to large high-utilization
combustion turbines. The other output-based standards currently in
subpart KKKK are largely maintained.
Subpart KKKK uses an assumed efficiency of 23 percent, 27 percent,
and 44 percent to convert from the input to equivalent output-based
standards for small, medium, and large turbines, respectively.\165\ The
lower efficiencies were intended to be representative of the
performance of simple cycle turbines while the higher efficiency is
representative of the performance of combined cycle turbines. For
purposes of subpart KKKKa, the EPA reviewed the 30-operating-day
efficiencies of combined cycle turbines, including all periods of
operation (i.e., including part-load and non-natural gas-fired hours)
that have recently commenced operation. The achievable 30-operating-
[[Page 1953]]
day gross efficiencies vary from 37 to 59 percent with an average of 50
percent. The EPA also reviewed the 30-operating-day emission rates of
combined cycle turbines that recently commenced operation. The
demonstrated achievable emission rates vary from 0.030 lb
NOX/MWh-gross to 0.10 lb NOX/MWh-gross. The upper
range includes turbines that have maintained 4-hour full load emission
rates of less than 5 ppm NOX. Based on this review, for the
large high-utilization combustion turbine subcategory, the EPA has
determined it is appropriate to increase the efficiency used to convert
the input-based standard to an equivalent output-based standard to 50
percent, and therefore the optional output-based standard is 0.12 lb
NOX/MWh-gross during all periods of operation.\166\ (Note
that part-load subcategorization is not available for combustion
turbines opting to comply with the output-based standards. Among other
things, the much longer 30-day averaging time makes the part-load
standard less necessary.)
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\165\ See 71 FR 38489.
\166\ The output-based emissions standard is scaled by a factor
of 1.4 for non-natural gas fuels.
---------------------------------------------------------------------------
For the large low-utilization subcategories, the EPA uses a 38
percent efficiency to determine the optional output-based standards for
the high-efficiency subcategory. The BSER analysis for this subcategory
is based on the use of simple cycle turbine technology and 38 percent
is the subcategorization criteria. For the low-efficiency subcategory,
the average lower efficiency simple cycle turbines that recently
commenced operation is 30 percent. The EPA used this value to determine
the optional output-based standards for the subcategory.
As noted above, for subcategories where the input-based standard
was not changed the EPA is finalizing the same optional output-based
standards currently in subpart KKKK.
The EPA determines in subpart KKKKa that owners/operators can elect
to comply the alternate output-based standards in either the form of
gross- or net-output. Net output is the combination of the gross
electrical (or mechanical) output of the combustion turbine engine and
any output generated by the HRSG minus the parasitic power
requirements. A parasitic load for a stationary combustion turbine
represents any of the auxiliary loads or devices powered by
electricity, steam, hot water, or directly by the gross output of the
stationary combustion turbine that does not contribute to electrical,
mechanical, or thermal output. One reason for including alternate net-
output based standards is that while combustion turbine engines that
require high fuel gas feed pressures typically have higher gross
efficiencies, they also often require fuel compressors that have
potentially larger parasitic loads than combustion turbine engines that
require lower fuel gas pressures. Gross output from electrical utility
units is reported to CAPD and the EPA can evaluate gross output-based
emission rates directly.\167\ For units calculating net-output, as an
alternative to continuously monitoring parasitic loads, the EPA
determines in subpart KKKKa that estimating parasitic loads is adequate
and would minimize compliance costs. A calibration would be required to
determine the parasitic loads at four load points: less than 25 percent
load; 25 to 50 percent load; 50 to 75 percent load; and greater than 75
percent load. Once the parasitic load curve is determined, the
appropriate amount would be subtracted from the gross output to
determine the net output.
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\167\ Net output is not reported to CAMPD.
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b. Recognizing the Benefit of Avoided Line Losses for CHP Facilities
In subpart KKKKa, the EPA recognizes the environmental benefit of
generating electricity on-site by CHP facilities, which avoids line
losses associated with the transmission and distribution of electricity
over long distances. Actual line losses vary from location to location,
but to recognize the benefit of avoided transmission and distribution
losses of electricity, subpart KKKKa includes a benefit of 5 percent
when determining the electric output for CHP facilities. This benefit
applies only to CHP facilities where at least 20 percent of the annual
output is useful thermal output. This restriction is intended to
prevent CHP facilities that provide a trivial amount of thermal energy
from qualifying for the 5 percent transmission and distribution
benefit.
C. SO2 Emissions Standards
For new, modified, or reconstructed stationary combustion turbines,
the BSER for limiting emissions of SO2 has been demonstrated
to be the firing of low-sulfur fuels. Since the promulgation of the
original NSPS in 1979 (subpart GG), the sulfur content of natural gas
has continued to decline, and the increased stringency of this best
system was reflected in an updated BSER analysis for combustion
turbines when the EPA promulgated subpart KKKK in 2006, which lowered
the SO2 standards for this source category.
In conducting our review of the SO2 standards for
purposes of new subpart KKKKa, we continue to find, as proposed, that
natural gas continues to be the primary fuel fired in most stationary
combustion turbines, and the sulfur content of delivered natural gas in
the U.S. is limited to 20 grains or less total sulfur per 100 standard
cubic feet (gr/100 scf).\168\ Distillate fuel oil (i.e., diesel fuel)
is a secondary or backup fuel for most combustion turbines, and due to
EPA regulations dating back to 1993, its sulfur content must be limited
by fuel producers. The sulfur content of distillate fuel oil in
continental areas must not contain more than 500 parts per million by
weight (ppmw) sulfur. This is considered low-sulfur diesel and is
widely available as a fuel for stationary combustion turbines. However,
in noncontinental areas, the availability of this low-sulfur fuel is
uncertain, and fuel oil can contain as much as 4,000 ppmw sulfur. These
sulfur contents are approximately equivalent to 0.05 percent by weight
sulfur in continental areas and 0.4 percent by weight in noncontinental
areas.
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\168\ See generally 40 CFR part 72; see also 58 FR 3650 (Jan.
11, 1993).
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In subpart KKKKa, we are retaining the existing standards of
performance from subpart KKKK. In the proposed rule, the EPA explained
how the regulation and production of low-sulfur fuels has changed since
the promulgation of subpart KKKK in 2006. This includes the
availability in continental areas of ``pipeline'' quality natural gas
with a sulfur content often less than 20 gr/100 scf. For example,
depending on the U.S. region, the sulfur content of pipeline natural
gas can be as low as 0.5 gr/100 scf. And for combustion turbines that
potentially fire liquefied natural gas (LNG), the fuel is typically
sulfur-free other than the sulfur added as an odorant for safety.
Regarding diesel fuel, the sulfur content has also been reduced over
time, generally in reaction to the promulgation of increasingly
stringent diesel production standards for on-road and nonroad vehicles,
locomotives, and certain types of marine vessels.\169\ Today, ultra-low
sulfur diesel (ULSD) that is limited to 15 ppmw is produced and
available to combustion turbine facilities in continental areas.
Therefore, in the proposal, we acknowledged that pipeline natural gas
and ultra-low sulfur diesel (ULSD) are available fuels that can be
fired in stationary combustion turbines in continental areas and
solicited comment on the extent of the
[[Page 1954]]
current use of ULSD at affected facilities, including information on
the availability of ULSD in both continental and noncontinental areas.
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\169\ See 69 FR 38958 (June 29, 2004).
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Commenters stated that natural gas remains the primary fuel fired
in most stationary combustion turbines, and the burning of distillate
fuel oil is a secondary or backup/emergency fuel in many cases.
However, reliable access to ULSD in certain areas remains questionable,
as does documented information about its consistent use in non-utility
sectors that operate stationary combustion turbines. Therefore, for
purposes of subpart KKKKa, the EPA does not have sufficient information
to support a determination that lower sulfur fuels than those we
identified in 2006 are the BSER or to amend the associated
SO2 standards relative to subpart KKKK. The EPA notes that
owners or operations of stationary combustion turbines typically use
natural gas and fuel oil as delivered without additional processing.
Technically there are limited viable options for end users to remove
additional sulfur, and even if the technology was viable, the costs
would be high. Moreover, while most of the pipeline and liquified
natural gas available in the continental U.S. may contain less than 20
gr/scf sulfur, demonstrations of compliance with the SO2
standard in the NSPS may be based on the use of tariff sheets. Setting
an SO2 standard that cannot use tariff sheets for the
initial and ongoing compliance determinations would require site-
specific performance testing. These tests could be costly when proper
sampling is accounted for, with limited to no environmental benefit,
given the already-very-low amount of sulfur in the typical fuel supply.
Therefore, to align the SO2 standards with the lower sulfur
content of natural gas and ULSD in continental areas, the allowable
sulfur content in tariff sheets would also need to be updated, or an
exemption would need to be established for owners or operators of
combustion turbines burning pipeline quality natural gas or LNG. Such
impacts and alternatives would need to be considered when weighing the
potential cost of compliance against potential environmental benefits.
Based on this review, the EPA maintains that, as in subpart KKKK,
limiting burning to low-sulfur fuels continues to be the BSER for
SO2 emissions from new, modified, or reconstructed
stationary combustion turbines, regardless of the rated heat input,
size, or utilization of the turbine. Accordingly, the application of
this BSER is reflected in the SO2 standards in subpart
KKKKa, which are identical to those promulgated in subpart KKKK and are
the same for all turbines.
Specifically, an affected source may not cause to be discharged
into the atmosphere from a new, modified, or reconstructed stationary
combustion turbine any gases that contain SO2 in excess of
110 ng/J (0.90 lb/MWh) gross energy output or 26 ng SO2/J
(0.060 lb SO2/MMBtu) heat input. The EPA continues to
recognize that low-sulfur fuels may be less available on islands and
other offshore areas. For turbines located in noncontinental areas
(including offshore turbines), an affected source may not cause to be
discharged into the atmosphere any gases that contain SO2 in
excess of 780 ng/J (6.2 lb/MWh) gross energy output or 180 ng
SO2/J (0.42 lb SO2/MMBtu) heat input.
The EPA expects no additional SO2 emissions reductions
based on the standards in subpart KKKKa. Although the EPA anticipates
that the demand for electric output from stationary combustion turbines
in the power and industrial sectors will increase during the next 8
years, the Agency does not expect significant increases in
SO2 emissions from the sector prior to the next CAA-required
review of the NSPS. The EPA also does not expect any adverse energy
impacts from the SO2 standards in subpart KKKKa. All
affected sources can comply with the rule without any additional
controls, and the BSER and standards have not changed from subpart KKKK
in 2006.
In terms of compliance with subpart KKKKa, the use of low-sulfur
fuels may be demonstrated by using the fuel quality characteristics in
a current, valid purchase contract, tariff sheet, or transportation
contract, or through representative fuel sampling data that show that
the potential sulfur emissions of the fuel do not exceed the standard.
This is consistent with the monitoring and reporting requirements in
subpart KKKK.
D. Consideration of Other Criteria Pollutants
In the proposal, the EPA discussed whether there was any need to
establish standards of performance for criteria pollutants beyond
NOX and SO2, including for CO and particulate
matter (PM). Although such consideration of additional criteria
pollutants is not required by CAA section 111(b)(1)(B) as part of the
review of existing standards of performance for particular air
pollutants, the EPA has authority to regulate additional air pollutants
when doing so is consistent with CAA section 111. As in the proposed
rule, the EPA does not believe that standards of performance for CO or
PM are necessary for this source category at this time but will
continue to consider these topics.
1. Carbon Monoxide
Carbon monoxide is a product of incomplete combustion when there is
insufficient residence time at high temperature, or incomplete mixing
to complete the final step in fuel carbon oxidation. Turbine
manufacturers have significantly reduced CO emissions from combustion
turbines by developing lean premix technology, which is incorporated
into most current turbine designs. Lean premix combustion not only
produces lower NOX than diffusion flame technology but also
lowers CO and volatile organic compounds (VOC). In the 2005 NSPS
proposal, the EPA determined that ``with the advancement of turbine
technology and more complete combustion through increased efficiencies,
and the prevalence of lean premix combustion technology in new
turbines, it is not necessary to further reduce CO in the proposed
rule,'' and the EPA retained its view that no CO emission limitation
need be developed for the combustion turbine NSPS.\170\
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\170\ 70 FR 8314, 8320-21 (Feb. 18, 2005).
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2. Particulate Matter
Particulate matter (PM) emissions from combustion turbines result
primarily from carryover of noncombustible trace constituents in the
fuel. Particulate matter emissions are negligible with natural gas
firing due to the low sulfur content of natural gas. Emissions of PM
are only marginally significant with distillate oil firing because of
the low ash content and are expected to decline further as the sulfur
content of distillate oil decreases due to other regulatory
requirements as discussed previously. As such, the EPA retains its view
that no PM emission limitation need be developed for the combustion
turbine NSPS.
E. Additional Amendments
1. Clarification of Fuel Analysis Requirements for Determination of
SO2 Compliance
The EPA is adding rule language in subpart KKKKa to clarify the
intent of the rule in that if a source elects to perform fuel sampling
to demonstrate compliance with the SO2 standard, the initial
test must be conducted using a method that measures multiple sulfur
compounds (e.g., hydrogen sulfide, dimethyl sulfide, carbonyl sulfide,
and thiol compounds). Alternate test procedures can be used only if the
[[Page 1955]]
measured sulfur content is less than half of the applicable standard.
In addition, subpart KKKKa allows fuel blending to achieve the
applicable SO2 standard. Under the rule language, an owner
or operator of an affected facility may burn higher sulfur fuels if the
average fuel fired meets the applicable SO2 standard at all
times. Finally, the primary method of controlling emissions is through
selecting fuels containing low amounts of sulfur or through fuel
pretreatment operations that can operate at all times, including
periods of startup and shutdown as discussed below in section IV.F.
2. Expanding the Application of Low-Btu Gases
For stationary combustion turbines combusting 50 percent or more
biogas (based on total heat input) per calendar month, subpart KKKK
established a maximum allowable SO2 emissions standard of 65
ng SO2/J (0.15 lb SO2/MMBtu) heat input. This
standard was set to avoid discouraging the development of energy
recovery projects that burn landfill gases to generate electricity in
stationary combustion turbines.\171\ Stationary combustion turbine
technologies using other low-Btu gases are also commercially available.
These technologies can burn low-Btu content gases recovered from other
activities, such as steelmaking (e.g., blast furnace gas and coke oven
gas) and coal bed methane. Like biogas, substantial environmental
benefits can be achieved by using these low-Btu gases to fuel
combustion turbines instead of flaring or direct venting to the
atmosphere. Therefore, in subparts KKKK and KKKKa, the EPA is amending
and expanding the application of the existing 65 ng SO2/J
(0.15 lb SO2/MMBtu) heat input emissions standard to include
stationary combustion turbines combusting 50 percent or more (on a heat
input basis) any gaseous fuels that have heating values less than 26
megajoules per standard cubic meter (MJ/scm) (700 Btu/scf) per calendar
month.
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\171\ See 74 FR 11858 (Mar. 20, 2009).
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To account for the environmental benefit of productive use and
simplify compliance for low-Btu gases, the Agency considers it
appropriate to base the SO2 standard on a fuel concentration
basis as an alternative to a lb/MMBtu basis. The original proposed
subpart KKKK standard for SO2 was based on the sulfur
content in distillate oil and included a standard of 0.05 percent
sulfur by weight (500 ppmw).\172\ In general, emission standards are
applied to a gaseous mixture by volume (parts per million by volume
(ppmv)), not by weight (ppmw). Basing the standard on a volume basis
would simplify compliance and minimalize burden to the regulated
community. Therefore, the EPA includes in subparts KKKK and KKKKa a
fuel specification standard of 650 mg sulfur/scm (or 28 gr sulfur/100
scf) for low-Btu gases. This is approximately equivalent to a standard
of 500 ppmv sulfur and is in the units directly reported by most test
methods.
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\172\ See 70 FR at 8319-20.
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3. Amendments To Simplify NSPS
This rulemaking includes some additional amendments for subparts
KKKK and KKKKa that are intended to simplify the regulatory burden.
a. Compliance Demonstration Exemption for Units Out of Operation
The EPA includes in subpart KKKKa, and is amending in subpart KKKK,
that units that have been out of operation for 60 days or longer at the
time of a required performance test are not required to conduct the
performance test until 45 days after the facility is brought back into
operation, or until after 10 operating days, whichever is longer. The
EPA concludes that it is not appropriate to require an affected
facility that is not currently in operation to start up for the sole
purpose of conducting a performance test to demonstrate compliance with
the NSPS.
Similarly, owners or operators of a combustion turbine that has
operated 50 hours or less since the previous performance test was
required to be conducted can request an extension of the otherwise
required performance test from the appropriate EPA Regional Office
until the turbine has operated more than 50 hours. This provision is
specific to a particular fuel, and an owner or operator permitted to
burn a backup fuel, but that rarely does so, can request an extension
on testing on that particular fuel until it has been burned for more
than 50 hours.
b. Authorization of a Single Emissions Test
For both subparts KKKKa and KKKK, we are finalizing the
availability of a streamlined emissions test procedure for groups of no
more than five similar stationary combustion turbines at a single
source under common ownership. Such units (or ``affected facilities'')
may not be equipped with SCR and use dry combustion control equipment.
Specifically, for any given calendar year, the Administrator or
delegated authority may authorize a single emissions test as adequate
demonstration for up to five units of the same combustion turbine model
and using the same dry combustion control technology, so long as: (1)
the most recent performance test for each affected facility shows that
performance of each affected facility is 75 percent or less of the
applicable emissions standard; (2) the manufacturer's recommended
maintenance procedures for each turbine and its control device are
followed; and (3) each affected facility conducts a performance test
for each pollutant for which it is subject to a standard at least once
every 5 years.
DLN combustion results in relatively stable emission rates.
Furthermore, the DLN combustor is a fundamental part of a combustion
turbine, and if similar maintenance procedures are followed, the Agency
concludes that emission rates will likely be comparable between
combustion turbines of the same make and model. Therefore, the
additional compliance costs associated with testing each affected
facility (i.e., each individual combustion turbine) are not needed to
ensure emissions standards are being met, under the conditions
specified.
c. Verification of Proper Operation of Emission Controls
Turbine engine performance can deteriorate with operation and age.
Operational parameters need to be verified periodically to ensure
proper operation of emission controls. Therefore, the EPA is finalizing
a requirement in subpart KKKKa that facilities using the water- or
steam-to-fuel ratio as a demonstration of continuous compliance with
the NOX emissions standard to verify the appropriate ratio
or parameters at a minimum of once every 60 months. The Agency
concludes this would not add significant burden since most affected
facilities are already required to conduct performance testing at least
every 5 years through title V requirements or other State permitting
requirements.
d. Compliance for Multiple Turbine Engines With a Single HRSG
The previous NSPS (subpart KKKK) does not state how multiple
combustion turbine engines that are exhausted through a single HRSG
would demonstrate compliance with the NOX standards.
Therefore, the EPA includes procedures in subpart KKKKa for
demonstrating compliance when multiple combustion turbine engines are
exhausted through a single HRSG and when steam from multiple combustion
turbine HRSGs is used in a single steam turbine. Subpart KKKK is being
amended to include the same procedures.
[[Page 1956]]
Furthermore, subpart KKKK requires approval from the permitting
authority for any use of the 40 CFR part 75 NOX monitoring
provisions in lieu of the specified 40 CFR part 60 procedures, but the
Agency's review concludes that approval is an unnecessary burden for
facilities using combustion controls only. Therefore, the EPA includes
in subpart KKKKa and is amending subpart KKKK to allow sources using
only combustion controls to use the NOX monitoring in 40 CFR
part 75 to demonstrate continuous compliance without requiring prior
approval. However, if the source is using post-combustion control
technology (i.e., SCR) to comply with the requirements of the NSPS,
then approval from the delegated authority is required prior to using
the 40 CFR part 75 CEMS procedures instead of the 40 CFR part 60
procedures.
e. System Emergency
The EPA determines it is appropriate to add a provision to subpart
KKKKa clarifying the calculation of utilization levels when turbines
are operated for ``system emergencies.'' Operation during system
emergencies would not be included when determining the utilization-
based subcategorization. In addition, for owners or operators that
elect to comply with the mass-based standards, emissions during system
emergencies would not be included when determining 12-calendar-month
emissions.\173\ The Agency concludes that this subcategorization
approach is necessary to provide flexibility, maintain system
reliability, and minimize overall costs to the sector.\174\ The EPA
defines system emergency in subpart KKKKa to mean periods when the
Reliability Coordinator has declared an Energy Emergency Alert levels
1, 2, or 3 which should follow NERC Reliability Standard EOP-011-2 or
its successor, or equivalent.\175\ This provision ensures that
stationary combustion turbines intended for less frequent operation are
available for grid reliability purposes during grid emergencies without
being subject to an emission standard that the unit might not be able
to meet without an investment in additional controls.
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\173\ See discussion of the optional, alternative mass-based
NOX emission standards in section IV.E.4 of this
preamble. During system emergencies the owner/operator of a
combustion turbine complying with the mass-based standard still
would be subject to a 4-hour emissions standard of 0.83 lb
NOX/MW-rated output or the current hourly emissions rate
necessary to comply with the 12-calendar month emissions standard of
0.48 tons NOX/MW-rated output, whichever is more
stringent. For example, if a combustion turbine operated for 4,000
hours prior to the system emergency the 4-hour emissions standard
during the system emergency would be 0.24 lb NOX/MW-rated
output.
\174\ See 80 FR 64612 (Oct. 23, 2015) and 89 FR 39914-15 (May 9,
2024).
\175\ The EPA determines it necessary to add ``or equivalent''
for areas not covered by NERC Reliability Standard EOP-011-2, for
example Puerto Rico. The definition therefore differs slightly from
the definition that had been promulgated in subpart TTTTa.
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These provisions in subpart KKKKa are like those included in other
EPA rulemakings that affect facilities in the power sector, such as in
Standards of Performance for Greenhouse Gas Emissions from New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units in 2015, and in the Carbon Pollution Standards
promulgated in May 2024.\176\
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\176\ See 40 CFR 60.5580 and 60.5580a. See also 40 CFR part 60,
subparts TTTT and TTTTa.
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f. Exemptions Included From Subpart GG
The EPA included exemptions for combustion turbines used in certain
military applications and firefighting applications from the standards
of performance for stationary gas turbines in 40 CFR part 60, subpart
GG.\177\ The EPA is finalizing including these exemptions from subpart
GG in subparts KKKK and KKKKa. The exemptions include military
combustion turbines for use in other than a garrison facility, military
combustion turbines installed for use as military training facilities,
and firefighting combustion turbines. These combustion turbines only
operate during critical situations.
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\177\ See 40 CFR 60.332(g).
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4. Alternative Mass-Based NOX Standards
The EPA solicited comment on and is finalizing short-term and long-
term mass-based NOX standards in subpart KKKKa as an
optional alternative to the input- and output-based NOX
standards for stationary combustion turbines. Owners or operators can
choose to comply with both a short-term, 4-operating-hour rolling mass-
based NOX standard and a long-term, 12-calendar-month
rolling mass-based NOX standard. The optional, alternative
mass-based NOX standards are designed to provide regulatory
flexibility and potentially reduce compliance burden.
The implementation of mass-based NOX standards is more
straightforward than for the input- and output-based standards because
there is no consideration of separate standards for full- and part-load
hours. Mass-based standards are a better indicator of environmental
impact because, in subpart KKKKa, mass-based standards are based on
total NOX emitted by the turbine. In addition, mass-based
standards recognize the environmental benefit of efficient generation
and provide a regulatory incentive for owners or operators of new
combustion turbines to purchase the most efficient turbine designs.
The short-term, 4-operating-hour rolling mass-based standard is
0.83 lb NOX/MW-rated output and the long-term, 12-calendar-
month rolling mass-based standard is 0.48 tons NOX/MW-rated
output when combusting natural gas. As noted in the proposed rule, the
4-operating-hour rolling mass-based NOX standard is
calculated based on the short-term NOX emissions from large
low-utilization combustion turbines with a BSER of combustion controls;
the 12-calendar-month rolling mass-based NOX standard is
calculated based on the long-term NOX emissions from large
high-utilization combustion turbines with a BSER of combustion controls
with SCR.\178\
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\178\ The short- and long-term mass-mased NOX
standards are most relevant to combustion turbines where the low-
utilization and high-utilization input-based (or output-based)
emission standards vary significantly.
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For owners or operators that elect to comply with the NSPS
according to the 4-operating-hour and 12-calendar-month rolling mass-
based NOX standards, the individual combustion turbine is
not subject to the input-based NOX emission standards in
table 1 of subpart KKKKa or subcategorization according to its 12-
calendar-month capacity factor.\179\ Instead, the combustion turbine is
subject to the same 4-operating-hour rolling mass-based NOX
emissions standard regardless of the actual utilization in addition to
the 12-calender-month rolling mass-based NOX standard. The
EPA discussed in the proposed rule that an optional, alternative short-
term rolling mass-based NOX emission standard functions as
an alternative to the 4-operating-hour input-based low-utilization
NOX standard. The 4-operating-hour rolling mass-based
NOX emission standard ensures the use of combustion controls
at all times. Likewise, the 12-calendar-month rolling mass-based
NOX emission standard functions as an alternative to the 4-
operating-hour input-based high-utilization NOX standard.
The 12-calendar-month rolling mass-based NOX standard
ensures that high-utilization combustion turbines achieve greater
NOX reductions with advanced
[[Page 1957]]
combustion controls or combustion controls with SCR.
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\179\ The optional output-based NOX standards would
also not be applicable.
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Some commenters disagreed with the optional, alternative mass-based
NOX standards being the primary NOX standards in
subpart KKKKa. The commenters stated that such mass-based standards
could restrict the use of high-utilization, simple cycle combustion
turbines as well as the operation of combustion turbines at part load.
While the EPA agrees that a mass-based NOX standard is not
appropriate as the primary NOX standard for this source
category, it increases regulatory flexibility and could reduce
regulatory compliance burden for certain owners or operators of
combustion turbines. For example, some permits for combustion turbines
include annual mass limitations and EGUs in the utility sector are
often subject to emissions trading programs. Optional, alternative
mass-based NOX standards can reduce compliance burden for
owners or operators of these turbines. Therefore, alternative, mass-
based NOX standards are included as a compliance option in
subpart KKKKa.
In establishing appropriate mass-based NOX standards,
the Agency considered the hourly standards that would otherwise be
applicable. In subpart KKKKa, owners or operators of all new natural
gas-fired combustion turbines operating at full load that comply with
the input-based NOX standard are subject to a 4-operating-
hour standard of no more than 25 ppm (0.092 lb NOX/
MMBtu).\180\ The maximum hourly mass-based emissions of NOX
can be determined according to this input-based NOX
emissions standard and the design efficiency of the turbine. Further,
the maximum mass-based NOX emissions rate can be normalized
based on the design rated output of the turbine.\181\ Similar to input-
based standards, while the absolute allowable NOX emissions
are determined according to the size of the turbine, the emissions
standard is not. Based on reported design efficiencies and
NOX emission rate guarantees, the EPA determined the design
mass-based NOX emission rates of available new simple cycle
turbines. The maximum hourly design mass-based NOX emissions
rate of a large turbine meeting the full load, input-based emissions
standard is 0.83 lb NOX/MW-rated output.\182\ Therefore, in
subpart KKKKa, the EPA is finalizing a 4-operating-hour emissions
standard of 0.83 lb NOX/MW-rated output when firing natural
gas. For example, a turbine with a 100 MW rated output at design
conditions could comply with the 4-operating-hour standard if the
cumulative emissions are maintained at or below 332 lb NOX
(83 lb NOX/h over a 4-hour period). Similarly, the 4-
operating-hour mass-based emissions standard for a turbine with a 200
MW rated design output is 664 lb NOX. The corresponding
emissions standard for non-natural gas fuels is 1.5 lb NOX/
MW-rated output.\183\ The objective of the 4-operating-hour standard is
to establish an emissions standard based on the use of the BSER for
low-utilization turbines (i.e., combustion controls) and a more
stringent standard cannot be established without restricting the use of
a turbine model beyond what was determined as the BSER for low-
utilization turbines.
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\180\ Large high-utilization combustion turbines are subject to
an emissions standard of 25 ppm NOX when the HRSG is
bypassed regardless of the efficiency of the turbine engine.
\181\ The hourly design mass-based NOX emissions
standard is calculated by multiplying the input-based emissions rate
(lb NOX/MMBtu) by the base load rating of the turbine
(MMBtu/h). The product is the design output of the turbine in lb
NOX/h. The design output can be normalized to the rated
output of the turbine by dividing the design output (lb
NOX/h) by the rated output of the turbine (MW). This
produces units of lb NOX/MW*h, but the hour in the
denominator is eliminated when the value is multiplied by an hour.
This results in a mass-based emissions standard of lb
NOX/MW-design rated output. Numerically this value is the
same as the value of the design output-based emissions rate, which
is calculated by multiplying the input-based emissions rate (lb
NOX/MMBtu) by 3.412 MMBtu/MWh and diving the product by
the efficiency (in HHV) of the turbine.
\182\ For large low-utilization combustion turbines, the mass-
based NOX emissions standard depends on the efficiency of
the turbine. The maximum hourly design emissions rate varies between
0.31 and 0.37 lb NOX/MW-rated output for large lower
efficiency turbines with 9 ppm NOX guarantees to 0.79 and
0.83 lb NOX/MW-capacity for large higher efficiency
turbines with 25 ppm NOX guarantees. While combined cycle
turbines would use combustion controls with SCR to comply with the
high-utilization standard, hours when the HRSG is bypassed would be
subcategorized. The input-based emissions standard for these hours
is 25 ppm NOX without any efficiency requirement of the
turbine engine itself. The design emissions rate for these turbines
could be as high as 1.0 including only the output from the turbine
engine. When the output of the steam turbine is included, the
maximum design emissions rate is 0.68 lb NOX/MW-rated
output.
\183\ The non-natural gas standard was calculated using an
input-based emissions rate of 42 ppm NOX (0.16 lb
NOX/MMBtu) and an efficiency of 30.5 percent. This
represents the emissions rate that is achievable for all large
simple cycle turbines in compliance with the input = based non-
natural gas standard.
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As the Agency has noted, a challenge of establishing standards of
performance for combustion turbines is that emission rates increase at
lower loads. In the NSPS, the EPA addresses this issue for input-based
NOX standards by subcategorizing turbine operating hours as
either full-load or part-load hours. A lower numeric NOX
standard (e.g., 25 ppm) applies during operation at full load and a
higher numeric NOX standard (e.g., 96 ppm) is applicable
during hours of operation at part load. The relationship between the
emissions and load is complex and the Agency must balance the
stringency of the full-load emissions standard and the full-load
threshold and the part-load standard.\184\ Since the same 4-operating-
hour mass-based NOX standard applies during all periods of
operation (i.e., hours are not subcategorized as full- or part-load)
and the relative stringency of the input-based and mass-based standards
varies with the load of the turbine. At the base load rating of the
turbine, the mass-based standard and the input-based standard (i.e., 25
ppm NOX) are essentially equivalent. When the turbine is
operating above the base load rating (e.g., during periods of operation
at cold ambient conditions), the mass-based standard is more stringent,
and compliance requires a lower input-based emissions rate.
Consequently, turbines that are not able to reduce emissions below 25
ppm NOX might not be able to operate above the base load
rating of the turbine. When the turbine is operated between 70 and 100
percent of the base load rating (e.g., at full load but below the base
load rating) the input-based standard is theoretically more stringent.
However, combustion control guarantees extend to 70 percent of the base
load rating or lower and owners or operators are not able to adjust the
operation of DLN systems, and, in practice, compliance with the mass-
based standard would not result in an increase in NOX
emissions during operation between 70 and 100 percent of the base load
rating.
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\184\ See 89 FR 101320 (Dec. 13, 2024).
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During part-load operation, the BSER is diffusion flame combustion
for both high- and low-utilization turbines. At 70 percent of the base
load rating (the part-load threshold), the input-based emission
standard is 3.8 times higher than the full-load input-based emissions
standard, and the allowable mass-based emissions are 2.7 times higher
than the allowable mass-based NOX emissions for a natural
gas-fired turbine operating at full load.\185\ This is difficult to
avoid using the input-based NOX standard since the part-load
standard includes all periods of operation at part load, including
periods of startup and shutdown, and an achievable emissions standard
has to account for all periods of operation when the NOX
standard is applicable. While the part-load emission
[[Page 1958]]
standards are significantly higher than the full-load emission
standards, the absolute hourly emissions do not vary as much between
part-load and full-load hours.\186\ Since the mass-based standards are
not subcategorized for part-load operation they are more
environmentally protective when turbines are operating between
approximately 25 and 70 percent of the base load rating. For example,
the input-based part-load NOX emissions standard for large
turbines is 96 ppm. For a 100 MW simple cycle turbine, the allowable
hourly emission rates when complying with the input-based, part-load
NOX emissions standard are 220 lb/h and 80 lb/h at 70
percent and 25 percent of the base load rating, respectively. The mass-
based NOX emissions standard is 83 lb/h regardless of the
load of the turbine. At these loads, demonstrating compliance with the
mass-based standard requires operating at an input-based NOX
emissions rate that is lower than the NSPS input-based NOX
emissions standard. Turbines rarely operate at less than 25 percent of
the base load rating, and most part-load emissions occur between 25 and
70 percent of the base load rating. Therefore, the optional,
alternative mass-based NOX standard offers superior
environmental protection compared to the input-based standards by
recognizing the environmental benefit of reducing emissions below what
is required by the input-based NOX emissions standard. Mass-
based standards also eliminate any potential regulatory incentive to
switch to part-load operation so that the higher part-load, input-based
NOX standard is applicable during that hour.
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\185\ The comparisons are done assuming a full load standard of
25 ppm NOX and a part-load standard of 25 ppm
NOX. The part load input-based emissions standard is 19
times higher than the 5 ppm NOX standard.
\186\ Even though the concentration of NOX emissions
is higher at part loads (which increases the mass emissions rate)
the lower amount of fuel being combusted reduces the mass emissions
rate.
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The 12-calendar-month mass-based standard functions as an
alternative to the 4-operating-hour input-based high-utilization
standard and ensures that high-utilization turbines achieve greater
reductions in NOX based on a BSER of combustion controls
with SCR. In subpart KKKKa, new high-utilization natural gas-fired
turbines operating at full load and complying with the input-based
NOX emissions standard are subject to a 4-operating-hour
emissions standard of 5 ppm. Like the 4-operating-hour standard, the
maximum 12-calendar-month mass-based NOX emissions of a
turbine can be determined based on the input-based emissions standard
and the design efficiency of the turbine. Based on reported design
efficiencies and using an input-based NOX emissions rate of
5 ppm, the EPA determined the average 12-calendar-month design mass-
based NOX emission rates of new large combined cycle
turbines to be 0.52 ton NOX/MW-rated output and range from
0.48 to 0.60 ton NOX/MW-rated output. At a constant, input-
based emissions rate, the potential annual NOX emissions
(when corrected to the design rated output) is strictly a function of
the design efficiency--more efficient turbines have lower design mass-
based emission rates. The EPA considered, but rejected, using these
values to set the 12-calendar-month mass-based NOX emissions
standard. A 4-operating-hour average accounts for short-term spikes in
emissions, and on a 12-calendar-month basis, the EPA projects that
high-utilization turbines will emit at a rate of 4 ppm NOX.
The EPA, therefore, used 4 ppm NOX when determining the 12-
calendar-month mass-based NOX emissions standard. Based on
design efficiencies, the average maximum 12-calendar-month mass-based
emissions rate of large, combined cycle turbines is 0.42 ton
NOX/MW-rated output and range from 0.38 to 0.48 ton
NOX/MW-rated output. Therefore, the 12-calendar-month mass-
based NOX standard is 0.48 tons NOX/MW-rated
output. A turbine with a 400 MW rated output at design conditions could
comply with the 12-calendar-month standard if the cumulative
NOX emissions are maintained at or below 192 tons over each
rolling 12-calendar-month period. Setting a lower standard would
restrict turbine models beyond what was determined to be the BSER
(i.e., combustion controls with SCR) for high-utilization
turbines.\187\ The corresponding mass-based NOX standard for
non-natural gas-fired turbines is 0.81 tons NOX/MW-rated
output.\188\
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\187\ The most efficient combined cycle design could emit at an
emission rate of 5 ppm NOX and still comply with the 12-
calendar month emissions standard. To operate at a 100 percent
capacity factor, owners or operators of simple cycle turbines would
have to reduce the NOX emissions rate to between 2.6 ppm
to 3.4 ppm depending on the efficiency of the turbine.
\188\ While the EPA has determined that SCR is not the BSER for
non-natural gas-fired turbines, natural gas-fired combined cycle
turbines can fire distillate for short periods of time as a backup
fuel. The EPA used a factor of 1.7 to determine the 12-calendar-
month non-natural gas-fired mass-based standard. The 12-calendar-
month standard is determined based on the relative heat inputs of
natural gas and non-natural gas fuels during the 12-calendar-month
period.
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Like the 4-operating-hour mass-based standard, the 12-calendar-
month mass-based NOX standard is not subcategorized by full-
and part-load hours. While the 12-calendar-month mass-based standard
provides short-term flexibilities relative to the input-based standards
for high-utilization turbines operating at full loads (e.g., an owner
or operator of a large high-utilization turbine operating at full load
would not be in violation of the mass-based NOX emissions
standard in the NSPS if a single 4-operating-hour period at full load
exceeds 5 ppm NOX), it is more environmentally protective
over a 12-calendar-month period. Under the input-based standards, the
average allowable NOX emissions rate of a large high-
utilization turbine where 95 percent of the heat input is during full-
load hours and 5 percent during part-load hours is 9.6 ppm
NOX. This is 2.4 times higher than the emissions rate used
to derive the 12-calendar-month mass-based emissions rate. Even at a
12-calendar-month capacity factor of 50 percent, the allowable mass-
based NOX emissions of a turbine complying with the input-
based standards are higher than the allowable mass-based NOX
emissions of the same turbine operating at a 12-calendar-month capacity
factor of 100 percent and complying with the mass-based standards. For
example, the allowable annual emissions of a 400 MW combined cycle
turbine operating at a 12-calendar-month capacity factor of 50 percent
and complying with the input-based standards is 228 tons
NOX. The same combined cycle turbine operating at a 100
percent capacity factor over a 12-calendar-month period complying with
the mass-based emission standards would be limited to 192 tons of
NOX.
The benefits of mass-based NOX standards include
recognizing the environmental benefit of efficiency--more efficient
combustion turbines achieving the same input-based emissions rate
(e.g., lb NOX/MMBtu) would be able to operate at higher
capacity factors while still maintaining emissions below the annual
standard. This approach also incentivizes reduced emissions during all
periods of operation, including during startup and shutdown. It ensures
that part-load operation is either kept to a minimum or emissions are
lower than required by the NSPS so that both the 4-operating-hour and
12-calendar-month absolute mass-based NOX limits are
fulfilled. The mass-based standards eliminate regulatory incentive to
switch to part-load operation so that the higher part-load
NOX standard is applicable during an operating hour. The
mass-based standards also complement each other. As finalized, the 4-
operating-hour mass-based NOX emissions standard is more
stringent at 12-calendar-month
[[Page 1959]]
utilization rates of 13 percent and less. At higher utilization rates,
the 12-calendar-month mass-based NOX emissions standard is
more stringent. For example, the potential 12-calendar-month
NOX emissions of a 100 MW simple cycle turbine operating at
a 9 percent capacity factor complying with the 4-operating-hour mass-
based emissions standard is approximately 33 tons NOX. The
corresponding 12-calendar-month mass-based NOX emissions
standard is less stringent (48 tons NOX). At a 20 percent
utilization rate, the potential 12-calendar-month NOX
emissions based on compliance with the 4-operating-hour mass-based
emissions standard is 73 tons NOX. The corresponding 12-
calendar-month mass-based emissions standard is more stringent (48 tons
NOX). Further, to maintain compliance with the 12-calendar-
month mass-based emissions standard, the turbine would have to emit at
an input-based emissions rate of 16 ppm NOX. To the extent
this approach results in lower overall emissions while also avoiding
the need to use SCR control technology, it provides an incentive for
manufacturers to continue to improve combustion controls and to expand
the operating conditions over which the combustion controls can
operate.
Additional benefits include lowering compliance costs and providing
flexibility to the regulated community--like conditions often included
in operating permits. In addition, a 12-calendar-month mass-based
NOX emissions standard recognizes the complex relationship
between the choice of combustion controls (and the impact of those
controls on other pollutants), the anticipated operation of the
combustion turbine, and the use of SCR. The flexibility would allow the
owner or operator of the combustion turbine to work with the permitting
authority to determine the appropriate emissions reduction strategy for
each specific project.
5. Exemption of Non-Major Sources From Title V Permitting
The EPA has decided to exempt certain lower-emitting stationary
combustion turbines subject to subparts GG, KKKK, or subpart KKKKa from
title V permitting requirements. CAA section 502(a) authorizes the
Administrator to exempt certain sources subject to CAA section 111
(NSPS) standards from the requirements of title V if the Administrator
finds that compliance with such requirements is ``impracticable,
infeasible, or unnecessarily burdensome'' on such sources.\189\
However, any exemption from title V permitting under this provision
cannot extend to any sources that are ``major sources'' as that term is
defined at CAA section 501(2).\190\
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\189\ 42 U.S.C. 7661a(a).
\190\ Id.; see also id. 7661(2).
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The EPA has previously established permitting exemptions under this
provision for several NSPS, particularly in circumstances where the
affected facilities are numerous and relatively low-emitting, the
burdens and process of obtaining permits would be substantial for
permitting authorities and the sources (such as numerous small
businesses, farms, or residences), and where compliance with applicable
standards can be assured through the manufacture or design of the
equipment or facility in question.\191\
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\191\ See, e.g., 40 CFR 60.4200(c) (``If you are an owner or
operator of an area source subject to this subpart, you are exempt
from the obligation to obtain a permit under 40 CFR part 70 or 40
CFR part 71, provided you are not required to obtain a permit under
40 CFR 70.3(a) or 40 CFR 71.3(a) for a reason other than your status
as an area source under this subpart.'') and 40 CFR 70.3(b)(4)(i)
(``The following source categories are exempted from the obligation
to obtain a part 70 permit: All sources and source categories that
would be required to obtain a permit solely because they are subject
to part 60, subpart AAA--Standards of Performance for New
Residential Wood Heaters.'').
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At proposal, the EPA explained that it had not determined that
title V permitting is ``impracticable, infeasible, or unnecessarily
burdensome'' for sources subject to subparts GG, KKKK, or KKKKa.
However, the EPA discussed the statutory factors and requested comment
as to whether there are circumstances in which the burdens and costs of
going through title V permitting for combustion turbines would not be
justified in light of the purposes of title V. The EPA specifically
requested comment on whether there are appropriate size, emissions, or
other characteristics that could be appropriately used to define
sources that may warrant exemption under CAA section 502(a), and what
specific features of these sources would justify such an exemption in
light of the statutory criteria.
The EPA previously proposed a title V exemption for combustion
turbines in a reconsideration proceeding concerning subparts GG and
KKKK.\192\ In conjunction with that proposal, the EPA prepared a
memorandum in 2012 describing the proposed section 502(a) exemption
from title V permitting requirements for non-major stationary
combustion turbines subject to subparts GG or KKKK under the relevant
statutory factors. The Agency cited to this document in the proposal in
seeking comment.\193\
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\192\ See 77 FR 52554, 52557-58 (Aug. 29, 2012).
\193\ See 89 FR 101347; U.S. EPA, Exemption of non-major source
subject to new source performance standards for stationary gas
combustion turbines under 40 CFR subpart KKKK from Title V
permitting requirements (June 2012) (EPA-HQ-OAR-2004-0490-0331)
(hereinafter ``2012 Memorandum''), available in the docket.
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After considering comments, the EPA is finalizing a title V
exemption for non-major combustion turbines that fall into the small
and medium subcategories and the large low-utilization subcategory
under subpart KKKKa and for all non-major combustion turbines under
subparts GG and KKKK. For combustion turbines in these subcategories
and/or under these subparts, the EPA finds that compliance with title V
permitting is unnecessarily burdensome, as discussed in the 2012
Memorandum.
The EPA has developed a four-factor balancing test in determining
under CAA section 502(a) whether compliance with title V is
``unnecessarily burdensome.'' These four factors are: (1) whether Title
V permitting would result in significant improvements in compliance
with emission standards; (2) whether Title V permitting would impose
significant burdens on the area source category; (3) whether the costs
are justified, taking into account potential gains; and (4) whether
there are existing enforcement programs in place sufficient to ensure
compliance.\194\ The EPA has historically also considered whether such
an exemption would adversely affect public health, welfare, or the
environment.\195\ In exercising the discretion conferred by statute,
the Administrator considers the factors in combination, and not every
factor must point in the same direction to support an exemption.
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\194\ 70 FR 75320, 75323 (Dec. 19, 2005); see U.S. Sugar Corp.
v. EPA, 830 F.3d 579, 647 (D.C. Cir. 2016).
\195\ See, e.g., 70 FR 75323.
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As explained in the 2012 Memorandum, the EPA has considered and
balanced these factors and finds that they support granting the title V
exemption for the identified non-major combustion turbines. Please
refer to that memorandum for a full explanation of our reasoning.
We note that in adopting the analysis set forth in the 2012
Memorandum included in the docket as the primary rationale for this
exemption, we have specifically considered whether any information or
analysis in that document is out of date. The circumstances described
there remain applicable. The 2012 Memorandum noted that as many as 1 in
10 new
[[Page 1960]]
combustion turbines may be owned by small entities, and in the EIA for
this action, we identify that a comparable percentage of new affected
units may be owned by small entities. See EIA section 5.2.2.
The EPA is not extending the title V exemption to large high-
utilization combustion turbines under subpart KKKKa. We note that for
the small, medium, and low-utilization subcategories, and for turbines
subject to subparts GG or KKKK, combustion controls are the BSER, and
these controls typically are integrated into the unit itself and come
with manufacturer guarantees of NOX performance that are
generally sufficient to comply with the relevant standards. Similarly,
the vast majority of combustion turbines comply with the applicable
SO2 standards through firing low-sulfur fuels and do not
need to install or operate add-on control technologies. In contrast,
turbines in the large high-utilization subcategory are subject to a
NOX standard that is premised on a BSER that includes SCR,
which is an add-on control technology. Effective emissions control with
SCR depends on continuing operational and maintenance practices, and a
title V operating permit is typically appropriate to establish
facility-specific conditions to ensure those practices are in place.
Further, in most cases, large high-utilization turbines have
sufficiently high potential to emit that they are often either
individually large enough to constitute a major source, at a facility
that is a major source, and/or are affected sources under acrid rain
rules.\196\ Because the EPA cannot extend title V permitting exemptions
to major sources, there is therefore little practical effect in
including such turbines within the scope of the exemption.
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\196\ A 200 MW combined cycle facility complying with the
standards in this final rule would have an annual potential
emissions rate of approximately 100 tons of NOX. Affected
sources under acid rain rules are required to obtain title V permits
regardless of their potential emissions. See 42 U.S.C. 7651g.
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Many commenters generally supported finalizing a title V exemption.
One commenter opposed any title V exemption for any sources on grounds
that title V permitting is an important mechanism for transparency and
accountability. The commenter stated that permitting authorities have
strengthened permit conditions to ensure adequate monitoring and other
compliance assurance requirements through the public participation
process required by title V.
While the EPA recognizes the value of title V permitting, the Act
clearly contemplates that title V permitting may be impracticable,
infeasible, or unnecessarily burdensome in the case of smaller, lower-
emitting units that are not located at major sources or constitute
major sources in their own right. The commenter did not supply any
information to counter with specificity the findings set forth in the
2012 Memorandum cited at proposal. The 2012 Memorandum explained, for
example, that the monitoring and recordkeeping requirements of subpart
KKKK (which generally are being carried over into subpart KKKKa) are
sufficient to demonstrate compliance. The commenter did not offer any
information that that conclusion is flawed, and the Agency continues to
find that the monitoring and recordkeeping requirements in subparts
KKKK and KKKKa are sufficient to demonstrate compliance.
We note that States remain free to subject all stationary
combustion turbines to their operating permits programs if they so
choose. Further, new source review (NSR) construction permitting
generally applies and is not included in the title V exemption being
finalized in this action. NSR permitting processes afford public
participation. Thus, the EPA is finalizing a title V exemption for
small and medium combustion turbines and large low-utilization turbines
that are subject KKKKa and all turbines subject to GG and KKKK unless
the units are co-located at a major source or major sources themselves.
F. NSPS Subpart KKKKa Without Startup, Shutdown, Malfunction Exemptions
Consistent with Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008),
the EPA has established standards in this rule that apply at all times.
We are finalizing in subpart KKKKa a provision at 40 CFR 60.4320a(d)
that overrides 40 CFR 60.8(c). In finalizing the standards in this
rule, the EPA has considered startup and shutdown periods. These
periods are accounted for through the adjusted emissions standards that
apply during part-load operation and potentially when firing non-
natural gas fuels. This approach continues the approach applied in
subpart KKKK, which has, to the EPA's knowledge, worked well and has
not created compliance challenges. The EPA received several adverse
comments against the inclusion of 40 CFR 60.4320a(d) in subpart KKKKa,
and we have responded to these comments in the response to comments
document in the docket.
Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. Malfunctions,
in contrast, are neither predictable nor routine. Instead, they are, by
definition, sudden, infrequent, and not reasonably preventable failures
of emissions control, process, or monitoring equipment.\197\ The EPA
interprets CAA section 111 as not requiring emissions that occur during
periods of malfunction to be factored into development of CAA section
111 standards. Nothing in CAA section 111 or in case law requires that
the EPA consider malfunctions when determining what standards of
performance reflect the degree of emission limitation achievable
through ``the application of the best system of emission reduction''
that the EPA determines is adequately demonstrated. While the EPA
accounts for variability in setting emissions standards, nothing in CAA
section 111 requires the Agency to consider malfunctions as part of
that analysis. The EPA is not required to treat a malfunction in the
same manner as the type of variation in performance that occurs during
routine operations of a source. A malfunction is a failure of the
source to perform in a ``normal or usual manner'' and no statutory
language compels the EPA to consider such events in setting CAA section
111 standards of performance. The EPA's approach to malfunctions in the
analogous circumstances (setting ``achievable'' standards under CAA
section 112) has been upheld as reasonable by the D.C. Circuit in U.S.
Sugar Corp. v. EPA, 830 F.3d 579, 606-610 (2016).
---------------------------------------------------------------------------
\197\ See 40 CFR 60.2.
---------------------------------------------------------------------------
G. Testing and Monitoring Requirements
1. Averaging Period
The NOX emission standards in existing subpart KKKK are
based on a 4-hour rolling average for simple cycle turbines and a 30-
operating-day average for combustion turbines with a HRSG (e.g.,
combined cycle and CHP combustion turbines). The EPA solicited comment
on finalizing a 4-hour average for all turbines, finalizing a daily
standard, or finalizing a 30-operating-day standard. Some commenters
supported a 4-hour standard for all turbines while others supported
maintaining the 30-operating-day standard for combined cycle turbines,
stating that it is necessary to address variability, periods of
startup, and when the SCR has not reached the design temperature.
[[Page 1961]]
For subpart KKKKa, the EPA analyzed hourly emissions data using 4-
hour full-load rolling averages for both simple and combined cycle
turbines. Since the analysis was done using reported 4-hour averages,
the Agency disagrees with commenters that a longer averaging period is
necessary to account for variability and periods of startup. As
discussed in section IV.B.8.b above, periods of startup and shutdown
would be considered part-load hours (if the turbine operates at less
than 70 percent of the base load rating at any point during an hour,
the entire hour is considered a part-load hour). The emissions standard
for part-load hour is based on the use of diffusion flame combustion
and not the use of combustion controls or combustion controls in
combination with SCR. Further, when exhaust gases are bypassing the
HRSG (e.g., as may occur during startup, shutdown, or when the turbine
is intentionally operated in simple cycle mode) those hours are
subcategorized with an emissions standard of 25 ppm NOX. The
higher hourly emission standards would be blended with any full-load
hours in the same 4-operating-hour period to determine a blended
average for that 4-operating-hour period. The data analysis
demonstrates that the emission standards in this final rule are
achievable on a 4-operating-hour basis. Therefore, the EPA is
finalizing in subpart KKKKa that the emission standards for all
combustion turbines complying with the input-based standard (ppm or lb
NOX/MMBtu) would be determined on a 4-hour rolling average.
Subpart KKKK currently includes alternate output-based standards
that owners or operators can elect to comply with instead of the input-
based standard. The EPA proposed output-based standards, on both a
gross- and net-output basis, as an alternative to the heat input-based
standards. Owners or operators electing to use the output-based
standards would demonstrate compliance on a 30-operating-day average.
The longer averaging period is appropriate because both the
NOX emissions rate on a lb NOX/MMBtu basis and
the efficiency of the combustion turbine can vary--increasing the
overall variability. See section IV.B.8.a for further discussion of
this topic.
2. Demonstrating Compliance With NOX Emissions Standards
Using CEMS
All affected sources must conduct an initial performance test
pursuant to 40 CFR 60.8 (and as further specified in subparts KKKK and
KKKKa). Thereafter, varying monitoring and performance test methods
apply depending on the type of emissions control used.
For combustion turbines using SCR or other post-combustion
controls, subpart KKKKa requires that continuous compliance with the
applicable NOX standard must be demonstrated with a
NOX CEMS. Among other things, those NOX
measurements must be used to determine and report excess emissions of
NOX as well as monitor availability. In addition, if a
stationary combustion turbine is equipped with a NOX CEMS,
those measurements must be used to determine excess emissions. Owners
or operators of combustion turbines not using post-combustion controls
may elect to install a NOX CEMS as an alternative to the
otherwise required monitoring methods.
For combustion turbines that do not use post-combustion controls
and that do not have installed CEMS, subpart KKKKa provides two
NOX monitoring approaches to demonstrate compliance
depending on the nature of the combustion controls used, as described
in sections IV.G.3 and IV.G.4.
3. Demonstrating Compliance With NOX eMissions Standards
Without Using CEMS for Water or Steam Injection Combustion Controls
Owners or operators of affected sources that (1) use water or steam
injection but not post-combustion controls and (2) elect not to use a
NOX CEMS, must continuously monitor the water- or steam-to-
fuel ratio of the affected source to demonstrate compliance. This
requires the installation and operation of a continuous monitoring
system (CMS) that monitors and records both the fuel consumption and
the ratio of water- or steam-to-fuel being fired in the turbine. Owners
or operators of affected combustion turbines using combustion controls
that elect not to use a NOX CEMS must conduct performance
testing at a minimum of once every 12 months, except as otherwise
specified in 40 CFR 60.4331a(c)(2), 40 CFR 60.4333a(b)(2), and 40 CFR
60.4333a(b)(5)(v).
4. Demonstrating Compliance With NOX Emissions Standards
Without Using CEMS for Non-Water or Non-Steam Injection Combustion
Controls
Owners or operators of affected sources that (1) do not use water
or steam injection or post-combustion controls and (2) elect not to use
a NOX CEMS, must then (a) conduct performance tests
according to 40 CFR 60.4400a, (b) monitor the NOX emissions
rate using the Appendix E or low mass emissions methodology of 40 CFR
part 75, or (c) install, calibrate, maintain, and operate an operating
parameter CMS according to 40 CFR 60.4340a(b)(1)-(4).
H. Electronic Reporting
To increase the ease and efficiency of data submittal and data
accessibility, the EPA is finalizing, as proposed, a requirement that
owners or operators of stationary combustion turbine facilities subject
to existing NSPS subparts GG and KKKK and subpart KKKKa submit
electronic copies of initial and periodic performance test reports
(including relative accuracy test audits (RATAs)), and compliance
reports through the EPA's Central Data Exchange (CDX) using the
Compliance and Emissions Data Reporting Interface (CEDRI). A
description of the electronic data submission process is provided in
the memorandum, Electronic Reporting Requirements for New Source
Performance Standards (NSPS) and National Emission Standards for
Hazardous Air Pollutants (NESHAP) Rules, available in the docket for
this action. The final rule requires that performance test results be
submitted in the format generated through the use of the EPA's
Electronic Reporting Tool (ERT) or an electronic file consistent with
the xml schema on the ERT website.\198\ Similarly, performance
evaluation results of CEMS that include a RATA must be submitted in the
format generated through the use of the ERT or an electronic file
consistent with the xml schema on the ERT website. Alternatively,
electronic files consistent with the xml schema on the ERT website
accompanied by all the information required by 40 CFR 60.8(f)(2) in PDF
may be submitted.\199\
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\198\ https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert.
\199\ A PDF of the full stack test report (i.e., performance
test report and/or RATA) may optionally be submitted as an
attachment to the ERT package test data but is not required.
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Specifically, the final requires that (1) for NSPS subpart GG, the
reports specified in 40 CFR 60.334(k), (2) for NSPS subpart KKKK, the
reports specified in 40 CFR 60.4375, and (3) for NSPS subpart KKKKa,
the reports specified in 40 CFR 60.4375a, owners or operators use the
appropriate spreadsheet template to submit information to CEDRI.\200\
The final version of the template[s] for these
[[Page 1962]]
reports will be located on the CEDRI website.\201\
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\200\ 40 CFR 60.334(k), 60.4375, and 60.4375a also now include
updated language reflecting the EPA's current report submittal
procedures regarding CDX, CEDRI, ERT, and CBI.
\201\ https://www.epa.gov/electronic-reporting-air-emissions/cedri.
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Furthermore, the EPA is finalizing in subparts GG, KKKK, and KKKKa,
as proposed, provisions that allow owners or operators the ability to
seek extensions for submitting electronic reports for circumstances
beyond the control of the facility, i.e., for a possible outage in CDX
or CEDRI or for a force majeure event, in the time just prior to a
report's due date, as well as the process to assert such a claim.
I. Other Final Amendments
The EPA requested comment on whether it is appropriate in subpart
KKKKa to divide the thermal output from district energy systems by a
factor (i.e., 0.95 or 0.90) that would account for the net efficiency
benefits of district energy systems. The Agency received no comments on
the solicitation and is finalizing a factor of 0.95, which is the same
as the electric transmission and distribution factor.
J. Effective Date and Compliance Dates
Pursuant to CAA section 111(b)(1)(B), the effective date of the
final rule requirements in subparts KKKKa, KKKK, and GG will be the
promulgation date. Affected sources that commence construction,
reconstruction, or modification after December 13, 2024, must comply
with all requirements of subpart KKKKa no later than the effective date
of the final rule or upon startup, whichever is later.
K. Severability
This final action contains several discrete components, which the
EPA views as severable as a practical matter--i.e., they are
functionally independent and operate in practice independently of the
other components. These discrete components are generally delineated by
the section headings within section IV of this document. In general,
each of the final BSER determinations and associated emissions
standards for each subcategory function independently of the others, as
do any differences in the rule associated with modified or
reconstructed units. In addition, the several other provisions of
subpart KKKKa included in this final rule (and any associated changes
to subparts GG and KKKK) generally function independently of one
another.
V. Summary of Cost, Environmental, and Economic Impacts
A. What are the air quality impacts?
During the period 2025-2032, the EPA estimates that approximately
44 new stationary combustion turbines per year will be installed in the
U.S. and would be affected by this rule. The EPA estimates that 26 of
these combustion turbines will be in the electric utility power sector.
For affected combustion turbines in the electric utility power sector,
the BSER in subpart KKKKa is generally consistent with the control
technologies in the baseline. That is, based on data reported to the
EPA, the Agency anticipates that new combined cycle facilities
(including combined cycle CHP facilities) would already have plans to
use controls or otherwise achieve emissions rates equivalent to the
emissions standards finalized in this NSPS, though in some cases new
combined cycle turbines may have to upgrade and/or operate the controls
more intensively than existing counterparts to meet the NSPS
requirements in subpart KKKKa. The EPA estimates that most new simple
cycle combustion turbines generating electricity would be in the low-
utilization subcategory and have combustion controls consistent with
the standards and would not be impacted by this action. The EIA for
this final rule includes additional details of EPA's methodology for
estimating cost, environmental, and other economic impacts, as well as
a discussion of the limitations and uncertainties.
Based on information collected as part of a separate combustion
turbine NESHAP rulemaking, the EPA projects that each year
approximately 10 new, modified, or reconstructed direct mechanical
drive combustion turbines (e.g., compressors) will be subject to the
NOX standards in subpart KKKKa. However, none of these units
are expected to incur increased costs because of this rule.
Table 2 below presents the projected change in NOX
emissions under the final rule from 2025 to 2032. NOX
emissions are a precursor to ozone and fine particulate matter.
Table 2--Net NOX Emission Changes in First 8 Years After the Rule Is
Final
[tons]
------------------------------------------------------------------------
Net annual NOX emission changes
Year relative to baseline (tons)
------------------------------------------------------------------------
2025.................................. 0 to 0
2026.................................. 0 to 0
2027.................................. 41 to 88
2028.................................. -26 to 68
2029.................................. -94 to 47
2030.................................. -161 to 27
2031.................................. -229 to 5
2032.................................. -296 to -15
------------------------------------------------------------------------
The range in the projected emissions changes in Table 2 is due to
the uncertainty in the number of higher efficiency turbines that will
be constructed in the future. See section V.C of this preamble for
further discussion on this topic. We also note that there are no
expected SO2 reductions because of the rule. All estimates
and assumptions of emissions reductions have been documented in the
rulemaking docket.
B. What are the secondary impacts?
The requirements in subpart KKKKa are not anticipated to result in
significant energy impacts. The only energy requirement is a potential
small increase in fuel consumption, resulting from operating the
NOX control equipment and back pressure caused by an add-on
emission control device, such as an SCR. However, many entities will be
able to comply with the final rule
[[Page 1963]]
without the use of add-on control devices. Because the cost of the
identified BSER control technologies is a relatively small percentage
of the total costs associated with building and operating combustion
turbines in the various subcategories for which those technologies are
BSER, the EPA does not anticipate significant secondary effects in
terms of switching to other methods of electricity generation or
mechanical output.
While no new installations of SCR beyond the baseline are
anticipated to be required by this rule, some large high-utilization
combustion turbines may need to run their SCR more to comply with the
NOX emission limit. The slightly increased application of
SCR for large high-utilization combustion turbines is estimated to
modestly increase emissions of ammonia (NH3). Therefore,
subpart KKKKa is estimated to increase NH3 emissions by 1
ton in 2027; 12 tons in 2028; 22 tons in 2029; 33 tons in 2030; 44 tons
in 2031; and 54 tons in 2032. It should be noted that these are likely
overestimates, because we assumed SCR installation as a proxy for
combustion controls for industrial sources in this analysis, given the
lack of data on combustion control costs. Compliance in many cases will
likely be achieved through combustion controls, which would lead to
reduced ammonia emissions compared to these estimates. The EPA notes
that emissions may also increase generally to the extent that emissions
control strategies used make a turbine less efficient and therefore
result in additional utilization.
C. What are the cost impacts?
To comply with the requirements of this final rule, some new units
will incur capital costs associated with installation of controls or
upgrades to planned controls, while some units that modify or
reconstruct are expected to incur some increased operating costs of
their controls to meet the rule requirements. These capital costs and
increased operating costs were estimated based on model plants from the
DOE NETL flexible generation report.\202\ For the analysis period 2025-
2032, the total estimated capital cost is $13.7 million (2024$), and
the operation and maintenance costs are $9.5 million (2024$). Combined,
this represents a present value in 2024 of $19.4 million (2024$) and an
equivalent annualized value of $2.77 million (2024$) at a 3 percent
discount rate, and a present value of $15.5 million (2024$) and an
equivalent annualized value of $2.59 million (2024$) at a 7 percent
discount rate.
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\202\ Oakes, M.; Konrade, J.; Bleckinger, M.; Turner, M.;
Hughes, S.; Hoffman, H.; Shultz, T.; and Lewis, E. (May 5, 2023).
Cost and Performance Baseline for Fossil Energy Plants, Volume 5:
Natural Gas Electricity Generating Units for Flexible Operation.
U.S. Department of Energy (DOE). Office of Scientific and Technical
Information (OSTI). Available at https://www.osti.gov/biblio/1973266.
---------------------------------------------------------------------------
There is also a deregulatory aspect of this rule. New natural gas-
fired combustion turbines in the large, low-utilization subcategory
that are higher efficiency (i.e., with a base load rated heat input
greater than 850 MMBtu/h, utilized at a 12-calendar-month capacity
factor less than or equal to 45 percent, and with a design efficiency
greater than or equal to 38 percent on a HHV basis) are subject to a
less stringent NOX emission limit than they otherwise would
have been subject to under the previous NSPS. When subpart KKKK was
promulgated in 2006, these classes of large, higher efficiency turbines
did not exist. They are a newer technology that is now commercially
available, and subpart KKKKa is recognizing this fact along with the
environmental and economic benefits of operating higher efficiency
designs at lower levels of utilization.
To account for the rule accommodating these higher efficiency
turbines, we conduct an additional analysis where we compare the
construction and operations of these higher efficiency turbines under
the final rule to a baseline where lower efficiency turbines compliant
with the 2006 NOX standards are constructed instead. How
many new turbines will take advantage of this subcategory in the future
is uncertain, so we assume two to four single turbines are constructed
for each 5-year period beginning in 2027. Specifically, EPA has
identified 28 frame-type combustion turbines that have commenced
operation in the previous 5 years. One of these turbines was a large
high-efficiency combustion turbine with SCR controls. An additional six
large turbines completed during this period have comparable or higher
utilization rates. The EPA presumes that a subset of these turbines
would have considered the new large higher efficiency subcategory had
it been available. Therefore, the EPA identified two to four turbines
per 5-year period as a likely range for the rate of new turbines
availing themselves of this higher efficiency subcategory. Although we
assume that the higher efficiency turbines have more expensive capital
costs, the fuel savings lead to overall cost savings for the turbine
operators. The present value in 2024 of the combined capital cost and
fuel savings for these turbines under the deregulatory provision is
projected to be $53.2 million to $106.2 million (2024$) with an
equivalent annualized value of $7.58 million to $15.2 million (2024$)
at a 3 percent discount rate, and a present value of $21.5 million to
$43.0 million (2024$) with an equivalent annualized value of $3.60
million to $7.19 million (2024$) at a 7 percent discount rate, where
the range reflects the assumption of two to four higher efficiency
turbines constructed during the analysis period.
The present value in 2024 of the net regulatory cost savings is
projected to be $33.8 million to $87.0 million (2024$) with an
equivalent annualized value of $4.81 million to $12.4 million (2024$)
at a 3 percent discount rate, and a present value of $5.98 million to
$27.5 million (2024$) with an equivalent annualized value of $1.01
million to $4.60 million (2024$) at a 7 percent discount rate, where
the range again reflects uncertainty about the number of higher
efficiency turbines that will be constructed during the analysis
period.
D. What are the economic impacts?
Economic impact analyses focus on changes in market prices and
output levels. If changes in market prices and output levels in the
primary markets are significant enough, impacts on other markets may
also be examined. Both the magnitude of costs needed to comply with a
rule and the distribution of these costs among affected facilities can
have a role in determining how the market will change in response to a
rule.
This final rule generally requires new, modified, or reconstructed
stationary combustion turbines to meet more stringent emission
standards for the release of NOX into the environment than
required under subparts GG or KKKK. While the units impacted by these
requirements are generally expected to construct using emissions
control devices that would already be compliant with the revised NSPS,
some units may incur some increased costs to meet the rule
requirements. These changes may result in higher costs of production
for affected producers and impact broader markets these entities serve.
As shown in section 2.5 of the EIA, the types of turbines affected by
this rulemaking are primarily used in the power sector and in the oil
and natural gas transmission sector but are located in smaller numbers
in many economic sectors.
However, because the increased costs discussed in the previous
section are small in comparison to the sales of the average owner of a
combustion turbine, the costs of this rule are not expected to result
in a significant market impact, regardless of whether they are passed
on
[[Page 1964]]
through market relationships or absorbed by the firms. For more
information on these impacts, please refer to the economic impact
analysis in the rulemaking docket.
E. What are the benefits?
Combustion turbines are a source of NOX and
SO2 emissions. The health effects of exposure to these
pollutants are briefly discussed in this section. The revised NSPS is
expected to result in reductions of NOX emissions from new,
modified, or reconstructed units.
The EPA is obligated to present the Agency's best scientific
understanding when developing policies and regulations and to ensure
the public is not misled regarding the level of scientific
understanding. Historically, however, the EPA's analytical practices
often provided the public with a false sense of precision and more
confidence regarding the monetized impacts of fine particulate matter
(PM2.5) and ozone than the underlying science could fully
support, especially as overall emissions have significantly decreased,
and impacts have become more uncertain. The EPA has seen the
uncertainties expand even further with the use of benefit-per-ton (BPT)
monetized values. Although intended as a screening tool when full-form
photochemical modeling was not feasible, the BPT approach reduces
complex spatial and atmospheric relationships into an average value per
ton, which magnifies uncertainty in the resulting monetized estimates.
Examples of uncertainties include but are not limited to:
epidemiological uncertainty (e.g., concentration-response functions,
mortality valuation); economic factors (e.g., discount rates, income
growth); and methodological assumptions (e.g., health thresholds,
linear relationships, spatial relationships).
However, the EPA historically provided point estimates instead of
just ranges or only quantifying emissions, which leads the public to
believe the Agency has a better understanding of the monetized impacts
of exposure to PM2.5 and ozone than in reality. Therefore,
to rectify this error, the EPA is no longer monetizing benefits from
PM2.5 and ozone but will continue to quantify the emissions
until the Agency is confident enough in the modeling to properly
monetize those impacts.
Historically, the EPA estimated the monetized benefits of avoided
PM2.5- and ozone-related impacts, which accounted for most,
if not all, of the monetized benefits of many air regulations--even
when the regulation was not regulating PM2.5 or ozone--
within Regulatory Impact Analyses (RIAs).\203\ Throughout these
analyses, the EPA acknowledged significant uncertainties related to
monetized PM2.5 and ozone impacts. The EPA has and is
considering various techniques for characterizing the uncertainty in
such estimates, such as estimating the fraction of avoided health
effects occurring at various concentration ranges, sensitivity
analyses, and alternate concentration-response assumptions. Because of
the significant impacts of environmental regulations on the U.S.
economy, it is essential that the Agency have confidence in the
estimated benefits of an action prior to utilizing these estimates in a
regulatory context.
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\203\ See OMB's 2017 Report to Congress on Benefits and Costs of
Federal Regulations and Agency Compliance with the Unfunded Mandates
Reform Act for fuller discussion on uncertainties at https://trumpwhitehouse.archives.gov/wp-content/uploads/2019/12/2019-CATS-5885-REV_DOC-2017Cost_BenefitReport11_18_2019.docx.pdf.
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In particular, the EPA is interested in evaluating the validity of
estimating the benefits of air quality improvements relative to the
National Ambient Air Quality Standards (NAAQS) for PM2.5 and
ozone. These standards, which have been set at a level which the
Administrator judges to be requisite to protect public health or
welfare with an adequate margin of safety, are widely understood to
represent the divide between clean air and air with an unacceptable
level of pollution.
The limitations of the BPT approach are even more pronounced due to
the compounding effects of emissions reductions typically occurring
across many geographic areas simultaneously, with varying proximity to
population centers; differing atmospheric transformation pathways for
nitrous oxides (NOX), Volatile Organic Compounds (VOCs), and
secondary PM2.5; and region-specific photochemical and
meteorological conditions. Using a national BPT estimate implicitly
assumes uniform marginal health benefits for each ton of reduced
emissions, an assumption not supported given heterogeneity in exposure
patterns and atmospheric chemistry. As more areas achieve or maintain
attainment with the NAAQS, the uncertainties associated with low-
concentration health effects grow, and marginal benefits become more
difficult to characterize with precision.
Therefore, it may be appropriate for the EPA to separate exposures
and impacts above the level of the standard from those occurring at
lower ambient concentrations. The EPA will investigate this prior to
estimating these impacts in a regulatory analysis even for
informational purposes. The EPA will seek peer review for new methods
developed from this work consistent with the OMB's Peer Review
Guidance.\204\
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\204\ OMB Memorandum M-05-03, Memorandum for the Heads of
Executive Departments and Agencies: Issuance of OMB's ``Final
Information Quality Bulletin for Peer Review'' (2005), available at
https://www.federalregister.gov/documents/2005/01/14/05-769/final-information-quality-bulletin-for-peer-review.
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1. Benefits of NOX Reductions
Nitrogen dioxide (NO2) is the criteria pollutant that is
central to the formation of nitrogen oxides (NOX), and
NOX emissions are a precursor to ozone and fine particulate
matter.\205\
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\205\ Additional information is available in the ISA at https://www.epa.gov/isa/integrated-science-assessment-isa-oxides-nitrogen-health-criteria.
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Based on many recent studies discussed in the ozone Integrated
Science Assessment (ISA),\206\ the EPA has identified several key
health effects that may be associated with exposure to elevated levels
of ozone. Exposures to high ambient ozone concentrations have been
linked to increased hospital admissions and emergency room visits for
respiratory problems. Repeated exposure to ozone may increase
susceptibility to respiratory infection and lung inflammation and can
aggravate preexisting respiratory disease, such as asthma. Prolonged
exposures can lead to inflammation of the lung, impairment of lung
defense mechanisms, and irreversible changes in lung structure, which
could in turn lead to premature aging of the lungs and/or chronic
respiratory illnesses such as emphysema, chronic bronchitis, and
asthma.
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\206\ See Ozone ISA at https://assessments.epa.gov/isa/document/&deid=348522.
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Children typically have the highest ozone exposures since they are
active outside during the summer when ozone levels are the highest.
Further, children are more at risk than adults from the effects of
ozone exposure because their respiratory systems are still developing.
Adults who are outdoors and moderately active during the summer months,
such as construction workers and other outdoor workers, also are among
those with the highest exposures. These individuals, as well as people
with respiratory illnesses such as asthma, especially children with
asthma, experience reduced lung function and increased respiratory
symptoms, such as chest pain and cough, when exposed to relatively low
ozone levels during periods of moderate exertion.
NOX emissions can react with ammonia, VOCs, and other
compounds
[[Page 1965]]
to form PM2.5.\207\ Studies have linked PM2.5
(alone or in combination with other air pollutants) with a series of
negative health effects. Short-term exposure to PM2.5 has
been associated with premature mortality, increased hospital
admissions, bronchitis, asthma attacks, and other cardiovascular
outcomes. Long-term exposure to PM2.5 has been associated
with premature death, particularly in people with chronic heart or lung
disease. Children, the elderly, and people with cardiopulmonary
disease, such as asthma, are most at risk from these health effects.
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\207\ PM2.5 health effects are discussed in detail in
the ISA at https://www.epa.gov/isa/integrated-science-assessment-isa-particulate-matter.
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Reducing the emissions of NOX from stationary combustion
turbines can help to improve some of the effects mentioned above,
either those directly related to NOX emissions, or the
effects of ozone and PM2.5 resulting from the combination of
NOX with other pollutants.
2. Benefits of SO2 Reductions
High concentrations of SO2 can cause inflammation and
irritation of the respiratory system, especially during physical
activity.\208\ Exposure to very high levels of SO2 can lead
to burning of the nose and throat, breathing difficulties, severe
airway obstruction, and can be life threatening. Long-term exposure to
persistent levels of SO2 can lead to changes in lung
function.
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\208\ Health effects are discussed in detail in the ISA
available at https://www.epa.gov/isa/integrated-science-assessment-isa-sulfur-oxides-health-criteria.
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Sensitive populations include asthmatics, individuals with
bronchitis or emphysema, children, and the elderly. PM can also be
formed from SO2 emissions. Secondary PM is formed in the
ambient air through a number of physical and chemical processes that
transform gases, such as SO2, into particles. Overall,
emissions of SO2 can lead to some of the effects discussed
in this section--either those directly related to SO2
emissions, or the effects of PM resulting from the combination of
SO2 with other pollutants. Maintaining the standards of
performance for emissions of SO2 from all stationary
combustion turbines will continue to protect human health and the
environment from the adverse effects mentioned above.
3. Disbenefits From Increased Emissions of NH3 and
NOX
Ammonia is a precursor to PM2.5 formation and an
increase in NH3 formation may lead to an increase in
PM2.5. An increase in PM2.5 is associated with
significant mortality and morbidity health outcomes such as premature
mortality, stroke, lung cancer, metabolic and reproductive effects,
among others.
There are also potential NOX disbenefits associated with
the use of higher efficiency combustion turbines. As previously noted,
new natural gas-fired combustion turbines in the large, low-utilization
subcategory that are higher efficiency (i.e., with a base load rated
heat input greater than 850 MMBtu/h, operating at a 12-calendar-month
capacity factor less than or equal to 45 percent, and with a design
efficiency greater than or equal to 38 percent) are subject to a less
stringent NOX emission limit than otherwise applicable under
the previous NSPS (subpart KKKK). These higher NOX emissions
create disbenefits relative to the baseline with lower efficiency
turbines.
VI. What actions are we not finalizing and what is our rationale for
such decisions?
The EPA is not finalizing certain proposed revisions to the NSPS
for stationary combustion turbines and stationary gas turbines pursuant
to CAA section 111(b)(1)(B) review.
A. Clarification to the Definition of Stationary Combustion Turbine
To clarify the applicability of the definition of a stationary
combustion turbine when determining whether an existing combined cycle
or CHP facility should be considered ``new'' or ``reconstructed,'' the
EPA proposed to amend the rule language in subpart KKKKa. In subpart
KKKK, the definition of the affected source includes the HRSG and
associated duct burners at combined cycle and CHP facilities.\209\ The
amended language was intended to clarify that the test for determining
if an existing facility is a new source would be based on whether only
the combustion turbine portion of the affected combined cycle/CHP
facility (i.e., HRSG, etc.) was entirely replaced. The reconstruction
applicability determination was proposed to be based on whether the
fixed capital costs of the replacement of components of the combustion
turbine portion (i.e., the air compressor, combustor, and turbine
sections) exceeded 50 percent of the fixed capital costs of installing
only a comparable new combustion turbine portion of the affected
facility. The EPA proposed that it was appropriate for owners or
operators of combined cycle and CHP facilities that entirely replace or
undertake major capital investments in the combustion turbine portion
of the facility to invest in emissions control equipment as well.
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\209\ See 71 FR 38483; July 6, 2006.
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This specific portion of the 2024 Proposed Rule raised numerous
questions and concerns in public comments and opposition to amending
the definition of the source as proposed in subpart KKKKa was
consistent across all sectors. Therefore, in this final action, the EPA
is not finalizing any proposed revisions to the definition of
stationary combustion turbines that would impact a reconstruction
analysis to determine whether an existing combined cycle or CHP
combustion turbine should be subject to the requirements for new
sources under subpart KKKKa.
See the EPA's response to comments document in the docket for this
rule for complete summaries of comments regarding this specific
proposal and the EPA's responses.
B. Definition of Noncontinental Area
The EPA's review of low-sulfur fuels for this NSPS indicates that
since subpart KKKK was promulgated, the availability of low-sulfur
diesel has increased in States and territories previously defined as
noncontinental areas for purposes of compliance with the SO2
emission standards in subpart KKKK. As a result, in subpart KKKKa, the
EPA proposed to remove Hawaii, the Commonwealth of Puerto Rico, and the
U.S. Virgin Islands from the definition of noncontinental area. This
proposed change would require new, modified, or reconstructed
stationary combustion turbines in Hawaii, Puerto Rico, and the Virgin
Islands to demonstrate compliance with the lower SO2
standards in subpart KKKKa for affected sources in continental areas.
The continental standards are based on fuel oil with sulfur content
limited to approximately 0.05 percent sulfur by weight (500 ppmw).
Based on available information, the EPA also proposed to maintain
in subpart KKKKa that Guam, American Samoa, the Northern Mariana
Islands, and offshore platforms be included in the definition of
noncontinental area and those locations would continue to be allowed to
meet the existing standards for higher sulfur fuels. This is due to the
fact these locations continue to have limited access to the same low-
sulfur fuels as facilities in continental areas.
In response to the proposal, several commenters, including
commenters from the State of Hawaii, opposed the removal of Hawaii, the
Commonwealth of Puerto Rico, and the U.S. Virgin Islands from the
definition of
[[Page 1966]]
noncontinental area. Specifically, commenters stated that the proposal
would disproportionately affect island utilities that must rely on
liquid fuels and that lack the compliance options of utilities located
in continental areas. The commenters also highlighted some of the
regulatory precedents that exist in rules previously promulgated in the
power sector in which the EPA has acknowledged the need to set more
relaxed standards in Hawaii and other remote islands. The commenters
also stated that an additional supporting factor for the non-
continental exemption is the attainment status of Hawaii for all
regulated pollutants. Another commenter stated that before proposing to
determine that these locations have the same access to low-sulfur fuels
as continental areas, the EPA should provide additional information to
support the proposed new SO2 standards for affected sources
located in Hawaii, Puerto Rico, and the Virgin Islands (i.e., cost
effectiveness analysis). Should additional EPA analyses support the
proposed new SO2 standards, the EPA should include a delayed
compliance date (i.e., 5 years) for affected sources to use their
remaining higher sulfur fuel oil supplies and to allow fuel oil
suppliers time to develop reliable long-term supplies of low sulfur
fuel oil to those areas.
This specific proposal raised numerous questions and concerns in
public comments and opposition to amending the definition of the
noncontinental areas as proposed in subpart KKKKa was consistent from
affected stakeholders. Therefore, in this action, the EPA is not
finalizing the proposed revisions to the definition of noncontinental
area for new sources under subpart KKKKa.
C. Affected Facility
The EPA requested comment on treating multiple combustion turbine
engines connected to a single generator, separate combustion turbines
engines using a single HRSG, and separate combustion turbine engines
with separate HRSG that use a single steam turbine or otherwise combine
the useful thermal output as single affected facilities. The Agency is
not finalizing any changes that would treat multiple turbines as a
single affected facility.
VII. Statutory and Executive Order Reviews
Additional information about these statutes and Executive Orders
can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is a significant regulatory action that was submitted
to the Office of Management and Budget (OMB) for review. Any changes
made in response to OMB recommendations have been documented in the
docket. An economic impact analysis (EIA) was prepared for this action
and is available in the docket.
The EIA estimates the costs from 2025-2032 associated with the
application of the BSER to stationary combustion turbines with a heat
input at peak load equal to or greater than 10.7 GJ/h (10 MMBtu/h),
based on the HHV of the fuel, that commence construction, modification,
or reconstruction after the date of publication of the 2024 Proposed
Rule in the Federal Register. These costs are relative to the baseline
of the existing NSPS (subpart KKKK). Table 3 below provides a summary
of the estimated costs associated with the application of the BSER to
these new, modified, or reconstructed stationary combustion turbines
and stationary gas turbines.
Table 3--Estimated Monetized Costs of Combustion Turbines NSPS
[Millions, 2024$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% Discount rate 7% Discount rate
-------------------------------------------------------------------------------------------------------
PV EAV PV EAV
--------------------------------------------------------------------------------------------------------------------------------------------------------
Impacts associated with Costs............. $19.4................... $2.77................... $15.5................... $2.59.
subcategories with
increased stringency.
Impacts associated with Avoided Costs..... $53.2 to $106........... $7.58 to $15.2.......... $21.5 to $43.0.......... $3.60 to $7.19.
subcategories with
decreased stringency.
-------------------------------------------------------------------------------------------------------
Net Costs............... .................. -$87.0 to -$33.8........ -$12.4 to -$4.81........ -$27.5 to -$5.98........ -$4.60 to -$1.01.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: Values rounded to three significant figures. The range reflect the assumption of two to four higher efficiency turbines constructed during the
analysis period.
The net benefits associated with the regulated pollutants are the
net cost savings of this final action presented above in Table 3.
Potential non-quantified impacts are expected from changes in
NOX emissions. The EIA presents a discussion of the
projected costs and benefits of this action, as well as a discussion of
uncertainty and additional impacts that the EPA could not quantify or
monetize.
B. Executive Order 14192: Unleashing Prosperity Through Deregulation
This action is considered an Executive Order 14192 deregulatory
action. Details on the estimated cost savings of this final rule can be
found in EPA's analysis of the potential costs and benefits associated
with this action.
C. Paperwork Reduction Act (PRA)
The information collection activities in this rule have been
submitted for approval to OMB under the PRA. The Information Collection
Request (ICR) document that the EPA prepared has been assigned EPA ICR
number 7810.01. You can find a copy of the ICR in the docket for this
rule, and it is briefly summarized here. The information collection
requirements are not enforceable until OMB approves them. As noted in
section IV.H, the template for the semiannual report for these subparts
will be on the CEDRI website.\210\
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\210\ See https://www.epa.gov/electronic-reporting-air-emissions/cedri.
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The EPA is finalizing amendments to the NSPS for stationary
combustion turbines and stationary gas turbines to establish size-based
subcategories for new, modified, or reconstructed stationary combustion
turbines, update NOX standards of performance for certain
stationary combustion turbines and address specific technical and
editorial issues to clarify the existing regulations. The EPA is also
finalizing amendments to add electronic reporting requirements for
submittal of certain reports and performance test results.
This information will be collected to assure compliance with 40 CFR
part 60, existing subparts GG, KKKK, and new subpart KKKKa. The total
estimated burden and cost for reporting and recordkeeping due to these
amendments
[[Page 1967]]
are presented here and are not intended to be cumulative estimates that
include the burden associated with the requirements of the existing 40
CFR part 60, subparts GG and KKKK, and new 40 CFR part 60, subpart
KKKKa. The ICR reflects both the total burden for subject units to
comply with GG, KKKK, and KKKKa and the incremental burden associated
with the requirements of these final amendments.
Respondents/affected entities: Owners or operators of new,
modified, or reconstructed stationary combustion turbines.
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 5.
Frequency of response: Semi-annual.
Total estimated burden: 310 hours per year. Burden is
defined at 5 CFR 1320.3(b).
Total estimated cost: $36,000 per year, includes $0
annualized capital or operation & maintenance costs.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB
approves this ICR, the Agency will announce that approval in the
Federal Register and publish a technical amendment to 40 CFR part 9 to
display the OMB control number for the approved information collection
activities contained in this final rule.
D. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. In
making this determination, the EPA concludes that the impact of concern
for this rule is any significant adverse economic impact on small
entities and that the Agency is certifying that this rule will not have
a significant economic impact on a substantial number of small entities
because the rule relieves regulatory burden. The small entities subject
to the requirements of this action include small businesses and small
governmental entities. The rule relieves regulatory burden by modifying
several provisions that could impact small entities. Amendments to
simplify the NSPS are discussed in section IV.E.3 of this preamble, and
other flexibilities in this final rule, including an exemption from
title V permitting for certain non-major combustion turbines, are also
discussed in section IV.E. While not quantified, these amendments are
expected to result in cost savings for affected entities. In addition,
section V.C of this preamble discusses cost savings associated with the
less stringent NOX emission limit for certain large, higher
efficiency turbines. Because this is a relatively new technology, the
EPA is unable to estimate the number of small entities that will
experience regulatory relief under this provision. For this reason, the
EIA only considers potential costs as a conservative approach. For all
small entities projected to experience economic impact, those impacts
are estimated to be less than one percent of revenues.
E. Unfunded Mandates Reform Act (UMRA)
This action does not contain an unfunded mandate of $100 million
(adjusted annually for inflation) or more (in 1995 dollars) as
described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or
uniquely affect small governments. The costs involved in this action
are estimated not to exceed $187 million in 2024$ ($100 million in
1995$ adjusted for inflation using the GDP implicit price deflator) or
more in any one year.
F. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government.
G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have Tribal implications as specified in
Executive Order 13175. The EPA is not aware of any stationary
combustion turbine owned or operated by Indian Tribal governments.
However, if there are any, it will neither impose direct compliance
costs on federally recognized Tribal governments nor preempt Tribal
law. Thus, Executive Order 13175 does not apply to this final rule.
Consistent with the EPA Policy on Consultation and Coordination
with Indian Tribes, the EPA offered government-to-government
consultation with Tribes in April 2024. The offer of direct
consultation was declined.
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
Executive Order 13045 directs Federal agencies to include an
evaluation of the health and safety effects of the planned regulation
on children in Federal health and safety standards and explain why the
regulation is preferable to potentially effective and reasonably
feasible alternatives. This action is not subject to Executive Order
13045 because it is not a significant regulatory action under section
3(f)(1) of Executive Order 12866.
However, the EPA's Policy on Children's Health applies to this
action. This action is consistent with the EPA's Policy on Children's
Health because the new technology-based standards provide a maximum
level of emission control that is implementable for all stationary
combustion turbines. As described in the proposal, the EPA also
considered more stringent NOX standards for most
subcategories of new, modified, or reconstructed units based on an
expanded application post-combustion control technology, but determined
that this technology (specifically, SCR) is not the BSER other than for
new large high-utilization combustion turbines.
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution, or use of energy. This action includes defining and
setting emission limits for affected new, modified, and reconstructed
sources; applicability-related and definitional changes; changes to the
startup, shutdown, and malfunction (SSM) provisions; and the testing,
monitoring, recordkeeping, and reporting requirements. This does not
impact energy supply, distribution, or use and the EPA does not expect
a significant change in retail electricity prices or availability on
average across the contiguous U.S. for natural gas-fired generation, or
significant impacts on utility power sector delivered natural gas
prices.
J. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51
This action involves technical standards. As discussed in the
proposal preamble,\211\ the EPA conducted searches for the Review of
New Source Performance Standards for Stationary Combustion Turbines
through the Enhanced National Standards Systems Network (NSSN) Database
managed by the American National Standards
[[Page 1968]]
Institute (ANSI). Searches were conducted for EPA Methods 1, 2, 3A, 6,
6C, 7E, 8, 19, and 20 of 40 CFR part 60, appendix A. No applicable
voluntary consensus standards (VCS) were identified for EPA Methods 1,
2, 3A, 6, 6C, 7E, 8, 19, and 20. All potential standards were reviewed
to determine the practicality of the VCS for this rulemaking. One VCS
was identified as an acceptable alternative to EPA test methods for the
purpose of this final rule: \212\
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\211\ 89 FR 101306 (Dec. 13, 2024).
\212\ ANSI/ASME PTC 19.10-1981 Part 10 (2010) has been removed
as a VCS alternative due to withdrawn or outdated testing
methodologies.
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American Society for Testing and Materials (ASTM) D6348-12
(R2020), ``Determination of Gaseous Compounds by Extractive Direct
Interface Fourier Transform (FTIR) Spectroscopy,'' is an acceptable
alternative to EPA Method 320, with the conditions discussed below.
When using ASTM D6348-12 (R2020), the following conditions must be
met:
(1) The test plan preparation and implementation in the Annexes to
ASTM D 6348-12 (R2020), Sections A1 through A8 are mandatory; and
(2) In ASTM D6348-12 (R2020) Annex A5 (Analyte Spiking Technique),
the percent (%) R must be determined for each target analyte (Equation
A5.5). For the test data to be acceptable for a compound, %R must be
70% >= R <= 130%. If the %R value does not meet this criterion for a
target compound, the test data is not acceptable for that compound and
the test must be repeated for that analyte (i.e., the sampling and/or
analytical procedure should be adjusted before a retest). The %R value
for each compound must be reported in the test report, and all field
measurements must be corrected with the calculated %R value for that
compound by using the following equation:
Reported Results = ((Measured Concentration in Stack))/(%R) x 100
The search identified 13 VCS that were potentially applicable for
this final rule in lieu of EPA reference methods. However, these have
been determined to not be practical due to lack of equivalency,
documentation, validation of data, and other important technical and
policy considerations. Additional information for the VCS search and
determinations can be found in the memorandum titled, Voluntary
Consensus Standard Search Results for New Source Performance Standards
Review for Stationary Combustion Turbines and Stationary Gas Turbines
(40 CFR part 60, subpart KKKKa).
In addition, final rule updates to 40 CFR 60.17 (incorporations by
reference) are to include additional test methods identified in subpart
KKKKa. The Agency does not intend for these editorial revisions to
substantively change any of the technical requirements of existing
subparts GG and KKKK. These test methods are: ASTM D129-00; ASTM D240-
19; ASTM D396-98; ASTM D975-08a; ASTM D1072-90 (Reapproved 1999); ASTM
D1266-98 (Reapproved 2003); ASTM D1552-03; ASTM D1826-94 (Reapproved
2003); ASTM D2622-05; ASTM D3246-05; ASTM D3588-98 (Reapproved 2003);
ASTM D3699-08; ASTM D4057-95 (Reapproved 2000); ASTM D4084-05; ASTM
D4177-95 (Reapproved 2000); ASTM D4294-03; ASTM D4468-85 (Reapproved
2000); ASTM D4809-18; ASTM D4810-88 (Reapproved 1999); ASTM D4891-89
(Reapproved 2006); ASTM D5287-97 (Reapproved 2002); ASTM D5453-05; ASTM
D5504-20; ASTM D5623-24; ASTM D6228-98 (Reapproved 2003); ASTM D6348-12
(Reapproved 2020); ASTM D6522-20; ASTM D6667-04; ASTM D6751-11b; ASTM
D7039-24; ASTM D7467-10; GPA 2140-17; GPA 2166-17; GPA 2172-09; GPA
2174-14; and GPA 2377-86.
The EPA is also finalizing the option for facilities to use 40 CFR
part 63, Appendix A, EPA Method 320 for NOX testing of
sources subject to either subparts GG, KKKK, or KKKKa.\213\ This will
also provide testing flexibility and increase efficiency for test firms
concurrently performing formaldehyde testing on KKKK and KKKKa sources
subject to the stationary combustion turbine NESHAP requirements under
40 CFR part 63, subpart YYYY. Similarly, the EPA allows the option to
use ASTM Method D6348-12 (2020) as an equivalent FTIR alternative to
Method 320 provided the conditions specified above are met.
---------------------------------------------------------------------------
\213\ EPA Method 320 can also be used to determine moisture
(H2O) content, when necessary. However, EPA Method 320
cannot be used to determine the O2 content of the flue
gas stream. The oxygen content must be determined via a method
prescribed by the NSPS, which in turn is used to correct the
NOX ppm concentration to 15 percent O2, where
applicable.
---------------------------------------------------------------------------
In accordance with the requirements of 1 CFR part 51, the EPA is
incorporating the following four voluntary consensus standards by
reference in the final rule.
ASTM D5504-20, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence, covers the determination of sulfur-containing
compounds in high methane content gaseous fuels such as natural gas. It
can be used to determine the sulfur content of gaseous fuels in the
rule.
ASTM D5623-24, Standard Test Method for Sulfur Compounds
in Light Petroleum Liquids by Gas Chromatography and Sulfur Selective
Detection, covers the determination of volatile sulfur-containing
compounds in light petroleum liquids. It can be used to determine the
sulfur content of liquid fuels in the rule.
ASTM D6348-12, Determination of Gaseous Compounds by
Extractive Direct Interface Fourier Transform (FTIR) Spectroscopy. It
can be used as an equivalent FTIR alternative to Method 320 provided
the conditions specified above are met.
ASTM D7039-24, Standard Test Method of Sulfur in Gasoline,
Diesel Fuel, Jet Fuel, Kerosine, Biodiesel, Biodiesel Blends, and
Gasoline-Ethanol Blends by Monochromatic Wavelengths Dispersive X-ray
Fluorescence Spectrometry, covers the determination of total sulfur by
monochromatic wavelength-dispersive X-ray fluorescence spectrometry in
various fuels. It can be used to determine the sulfur content of liquid
fuels in the rule.
The EPA determined that the ASTM standards are reasonably available
because they are available for purchase or access from the following
addresses: ASTM International, 100 Barr Harbor Drive, Post Office Box
C700, West Conshohocken, PA 19428-2959, +1.610.832.9500, www.astm.org.
K. Congressional Review Act (CRA)
This action is subject to the Congressional Review Act (CRA), and
the EPA will submit a rule report to each House of the Congress and to
the Comptroller General of the United States. This action is not a
``major rule'' as defined by 5 U.S.C. 804(2).
List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedures,
Air pollution control, Incorporation by reference, Reporting and
recordkeeping requirements.
Lee Zeldin,
Administrator.
For the reasons set forth in the preamble, the Environmental
Protection Agency amends part 60 of title 40, chapter I, of the Code of
Federal Regulations as follows:
[[Page 1969]]
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart A--General Provisions
0
2. Amend Sec. 60.17 by revising paragraphs (h) and (m)(1) through (4)
and (6) to read as follows:
Sec. 60.17 Incorporations by reference.
* * * * *
(h) ASTM International, 100 Barr Harbor Drive, P.O. Box CB700, West
Conshohocken, Pennsylvania 19428-2959; phone: (800) 262-1373; website:
www.astm.org.
(1) ASTM A99-76, Standard Specification for Ferromanganese; IBR
approved for Sec. 60.261.
(2) ASTM A99-82 (Reapproved 1987), Standard Specification for
Ferromanganese; IBR approved for Sec. 60.261.
(3) ASTM A100-69, Standard Specification for Ferrosilicon; IBR
approved for Sec. 60.261.
(4) ASTM A100-74, Standard Specification for Ferrosilicon; IBR
approved for Sec. 60.261.
(5) ASTM A100-93, Standard Specification for Ferrosilicon; IBR
approved for Sec. 60.261.
(6) ASTM A101-73, Standard Specification for Ferrochromium; IBR
approved for Sec. 60.261.
(7) ASTM A101-93, Standard Specification for Ferrochromium; IBR
approved for Sec. 60.261.
(8) ASTM A482-76, Standard Specification for Ferrochromesilicon;
IBR approved for Sec. 60.261.
(9) ASTM A482-93, Standard Specification for Ferrochromesilicon;
IBR approved for Sec. 60.261.
(10) ASTM A483-64, Standard Specification for Silicomanganese; IBR
approved for Sec. 60.261.
(11) ASTM A483-74 (Reapproved 1988), Standard Specification for
Silicomanganese; IBR approved for Sec. 60.261.
(12) ASTM A495-76, Standard Specification for Calcium-Silicon and
Calcium Manganese-Silicon; IBR approved for Sec. 60.261.
(13) ASTM A495-94, Standard Specification for Calcium-Silicon and
Calcium Manganese-Silicon; IBR approved for Sec. 60.261.
(14) ASTM D86-78, Distillation of Petroleum Products; IBR approved
for Sec. Sec. 60.562-2(d); 60.593(d); 60.593a(d); 60.633(h).
(15) ASTM D86-82, Distillation of Petroleum Products; IBR approved
for Sec. Sec. 60.562-2(d); 60.593(d); 60.593a(d); 60.633(h).
(16) ASTM D86-90, Distillation of Petroleum Products; IBR approved
for Sec. Sec. 60.562-2(d); 60.593(d); 60.593a(d); 60.633(h).
(17) ASTM D86-93, Distillation of Petroleum Products; IBR approved
for Sec. 60.593a(d).
(18) ASTM D86-95, Distillation of Petroleum Products; IBR approved
for Sec. Sec. 60.562-2(d); 60.593(d); 60.593a(d); 60.633(h).
(19) ASTM D86-96, Distillation of Petroleum Products, approved
April 10, 1996; IBR approved for Sec. Sec. 60.562-2(d); 60.593(d);
60.593a(d); 60.633(h); 60.5401(f); 60.5401a(f); 60.5402b(d);
60.5402c(d).
(20) ASTM D129-64, Standard Test Method for Sulfur in Petroleum
Products (General Bomb Method); IBR approved for Sec. 60.106(j) and
appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
(21) ASTM D129-78, Standard Test Method for Sulfur in Petroleum
Products (General Bomb Method); IBR approved for Sec. 60.106(j) and
appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
(22) ASTM D129-95, Standard Test Method for Sulfur in Petroleum
Products (General Bomb Method); IBR approved for Sec. 60.106(j) and
appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
(23) ASTM D129-00, Standard Test Method for Sulfur in Petroleum
Products (General Bomb Method); IBR approved for Sec. 60.335(b).
(24) ASTM D129-00 (Reapproved 2005), Standard Test Method for
Sulfur in Petroleum Products (General Bomb Method); IBR Approved for
Sec. Sec. 60.4360a(c) and 60.4415(a).
(25) ASTM D240-76, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter; IBR approved for
Sec. Sec. 60.46(c); 60.296(b); and appendix A-7 to part 60: Method 19,
Section 12.5.2.2.3.
(26) ASTM D240-92, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter; IBR approved for
Sec. Sec. 60.46(c); 60.296(b); and appendix A-7: Method 19, Section
12.5.2.2.3.
(27) ASTM D240-02 (Reapproved 2007), Standard Test Method for Heat
of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, approved
May 1, 2007; IBR approved for Sec. 60.107a(d).
(28) ASTM D240-19, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter, approved November 1,
2019; IBR approved for Sec. Sec. 60.485b(g) and 60.4360a(c).
(29) ASTM D270-65, Standard Method of Sampling Petroleum and
Petroleum Products; IBR approved for appendix A-7 to part 60: Method
19, Section 12.5.2.2.1.
(30) ASTM D270-75, Standard Method of Sampling Petroleum and
Petroleum Products; IBR approved for appendix A-7 to part 60: Method
19, Section 12.5.2.2.1.
(31) ASTM D323-82, Test Method for Vapor Pressure of Petroleum
Products (Reid Method); IBR approved for Sec. Sec. 60.111(l);
60.111a(g); 60.111b; 60.116b(f).
(32) ASTM D323-94, Test Method for Vapor Pressure of Petroleum
Products (Reid Method); IBR approved for Sec. Sec. 60.111(l);
60.111a(g); 60.111b; 60.116b(f).
(33) ASTM D388-77, Standard Specification for Classification of
Coals by Rank; IBR approved for Sec. Sec. 60.41; 60.45(f); 60.41Da;
60.41b; 60.41c; 60.251.
(34) ASTM D388-90, Standard Specification for Classification of
Coals by Rank; IBR approved for Sec. Sec. 60.41; 60.45(f); 60.41Da;
60.41b; 60.41c; 60.251.
(35) ASTM D388-91, Standard Specification for Classification of
Coals by Rank; IBR approved for Sec. Sec. 60.41; 60.45(f); 60.41Da;
60.41b; 60.41c; 60.251.
(36) ASTM D388-95, Standard Specification for Classification of
Coals by Rank; IBR approved for Sec. Sec. 60.41; 60.45(f); 60.41Da;
60.41b; 60.41c; 60.251.
(37) ASTM D388-98a, Standard Specification for Classification of
Coals by Rank; IBR approved for Sec. Sec. 60.41; 60.45(f); 60.41Da;
60.41b; 60.41c; 60.251.
(38) ASTM D388-99 (Reapproved 2004)[epsiv]1(ASTM D388-
99R04), Standard Classification of Coals by Rank, approved June 1,
2004; IBR approved for Sec. Sec. 60.41; 60.45(f); 60.41Da; 60.41b;
60.41c; 60.251; 60.5580; 60.5580a.
(39) ASTM D396-78, Standard Specification for Fuel Oils; IBR
approved for Sec. Sec. 60.41b; 60.41c; 60.111(b); 60.111a(b).
(40) ASTM D396-89, Standard Specification for Fuel Oils; IBR
approved for Sec. Sec. 60.41b; 60.41c; 60.111(b); 60.111a(b).
(41) ASTM D396-90, Standard Specification for Fuel Oils; IBR
approved for Sec. Sec. 60.41b; 60.41c; 60.111(b); 60.111a(b).
(42) ASTM D396-92, Standard Specification for Fuel Oils; IBR
approved for Sec. Sec. 60.41b; 60.41c; 60.111(b); 60.111a(b).
[[Page 1970]]
(43) ASTM D396-98, Standard Specification for Fuel Oils, approved
April 10, 1998; IBR approved for Sec. Sec. 60.41b; 60.41c; 60.111(b);
60.111a(b); 60.4420a; 60.5580; 60.5580a.
(44) ASTM D975-78, Standard Specification for Diesel Fuel Oils; IBR
approved for Sec. Sec. 60.111(b) and 60.111a(b).
(45) ASTM D975-96, Standard Specification for Diesel Fuel Oils; IBR
approved for Sec. Sec. 60.111(b) and 60.111a(b).
(46) ASTM D975-98a, Standard Specification for Diesel Fuel Oils;
IBR approved for Sec. Sec. 60.111(b) and 60.111a(b).
(47) ASTM D975-08a, Standard Specification for Diesel Fuel Oils,
approved October 1, 2008; IBR approved for Sec. Sec. 60.41b; 60.41c;
60.4420a; 60.5580; 60.5580a.
(48) ASTM D1072-80, Standard Test Method for Total Sulfur in Fuel
Gases; IBR approved for Sec. 60.335(b).
(49) ASTM D1072-90 (Reapproved 1994), Standard Test Method for
Total Sulfur in Fuel Gases; IBR approved for Sec. 60.335(b).
(50) ASTM D1072-90 (Reapproved 1999), Standard Test Method for
Total Sulfur in Fuel Gases; IBR approved for Sec. Sec. 60.4360a(c) and
60.4415(a).
(51) ASTM D1137-53, Standard Method for Analysis of Natural Gases
and Related Types of Gaseous Mixtures by the Mass Spectrometer; IBR
approved for Sec. 60.45(f).
(52) ASTM D1137-75, Standard Method for Analysis of Natural Gases
and Related Types of Gaseous Mixtures by the Mass Spectrometer; IBR
approved for Sec. 60.45(f).
(53) ASTM D1193-77, Standard Specification for Reagent Water; IBR
approved for appendix A-3 to part 60: Method 5, Section 7.1.3; Method
5E, Section 7.2.1; Method 5F, Section 7.2.1; appendix A-4 to part 60:
Method 6, Section 7.1.1; Method 7, Section 7.1.1; Method 7C, Section
7.1.1; Method 7D, Section 7.1.1; Method 10A, Section 7.1.1; appendix A-
5 to part 60: Method 11, Section 7.1.3; Method 12, Section 7.1.3;
Method 13A, Section 7.1.2; appendix A-8 to part 60: Method 26, Section
7.1.2; Method 26A, Section 7.1.2; Method 29, Section 7.2.2.
(54) ASTM D1193-91, Standard Specification for Reagent Water; IBR
approved for appendix A-3 to part 60: Method 5, Section 7.1.3; Method
5E, Section 7.2.1; Method 5F, Section 7.2.1; appendix A-4 to part 60:
Method 6, Section 7.1.1; Method 7, Section 7.1.1; Method 7C, Section
7.1.1; Method 7D, Section 7.1.1; Method 10A, Section 7.1.1; appendix A-
5 to part 60: Method 11, Section 7.1.3; Method 12, Section 7.1.3;
Method 13A, Section 7.1.2; appendix A-8 to part 60: Method 26, Section
7.1.2; Method 26A, Section 7.1.2; Method 29, Section 7.2.2.
(55) ASTM D1266-87, Standard Test Method for Sulfur in Petroleum
Products (Lamp Method); IBR approved for Sec. 60.106(j).
(56) ASTM D1266-91, Standard Test Method for Sulfur in Petroleum
Products (Lamp Method); IBR approved for Sec. 60.106(j).
(57) ASTM D1266-98, Standard Test Method for Sulfur in Petroleum
Products (Lamp Method); IBR approved for Sec. Sec. 60.106(j) and
60.335(b).
(58) ASTM D1266-98 (Reapproved 2003) [egr],1 Standard
Test Method for Sulfur in Petroleum Products (Lamp Method); IBR
approved for Sec. Sec. 60.4360a(c) and 60.4415(a).
(59) ASTM D1475-60 (Reapproved 1980), Standard Test Method for
Density of Paint, Varnish Lacquer, and Related Products; IBR approved
for Sec. 60.435(d), appendix A-7 to part 60: Method 24, Sections 6.1
and 11.3.3; Method 24A, Sections 6.5,7.1, 11.2, 11.3, and 16.0.
(60) ASTM D1475-90, Standard Test Method for Density of Paint,
Varnish Lacquer, and Related Products; IBR approved for Sec.
60.435(d); appendix A-7 to part 60: Method 24, Sections 6.1 and 11.3.3;
Method 24A, Sections 6.5, 7.1, 11.2, 11.3, and 16.0.
(61) ASTM D1475-13, Standard Test Method for Density of Liquid
Coatings, Inks, and Related Products, approved November 1, 2013; IBR
approved for Sec. 60.393a(f).
(62) ASTM D1552-83, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method); IBR approved for Sec. 60.106(j)
and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
(63) ASTM D1552-95, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method); IBR approved for Sec. 60.106(j)
and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
(64) ASTM D1552-01, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method; IBR approved for Sec. 60.335(b).
(65) ASTM D1552-03, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method); IBR approved for Sec. Sec.
60.4360a(c) and 60.4415(a).
(66) ASTM D1826-77, Standard Test Method for Calorific Value of
Gases in Natural Gas Range by Continuous Recording Calorimeter; IBR
approved for Sec. Sec. 60.45(f); 60.46(c); 60.296(b); appendix A-7 to
part 60: Method 19, Section 12.3.2.4.
(67) ASTM D1826-94, Standard Test Method for Calorific Value of
Gases in Natural Gas Range by Continuous Recording Calorimeter; IBR
approved for Sec. Sec. 60.45(f); 60.46(c); 60.296(b); appendix A-7 to
part 60: Method 19, Section 12.3.2.4.
(68) ASTM D1826-94 (Reapproved 2003), Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter, approved May 10, 2003; IBR approved for
Sec. Sec. 60.107a(d) and 60.4360a(c).
(69) ASTM D1835-87, Standard Specification for Liquefied Petroleum
(LP) Gases; IBR approved for Sec. Sec. 60.41b; 60.41c.
(70) ASTM D1835-91, Standard Specification for Liquefied Petroleum
(LP) Gases; IBR approved for Sec. Sec. 60.41Da; 60.41b; 60.41c.
(71) ASTM D1835-97, Standard Specification for Liquefied Petroleum
(LP) Gases; IBR approved for Sec. Sec. 60.41Da; 60.41b; 60.41c.
(72) ASTM D1835-03a, Standard Specification for Liquefied Petroleum
(LP) Gases; IBR approved for Sec. Sec. 60.41Da; 60.41b; 60.41c;
60.4420a.
(73) ASTM D1945-64, Standard Method for Analysis of Natural Gas by
Gas Chromatography; IBR approved for Sec. 60.45(f).
(74) ASTM D1945-76, Standard Method for Analysis of Natural Gas by
Gas Chromatography; IBR approved for Sec. 60.45(f).
(75) ASTM D1945-91, Standard Method for Analysis of Natural Gas by
Gas Chromatography; IBR approved for Sec. 60.45(f).
(76) ASTM D1945-96, Standard Method for Analysis of Natural Gas by
Gas Chromatography; IBR approved for Sec. 60.45(f).
(77) ASTM D1945-03 (Reapproved 2010), Standard Method for Analysis
of Natural Gas by Gas Chromatography, approved January 1, 2010; IBR
approved for Sec. Sec. 60.107a(d); 60.5413(d); 60.5413a(d);
60.5413b(d); 60.5413c(d).
(78) ASTM D1945-14 (Reapproved 2019), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography, approved December 1,
2019; IBR approved for Sec. 60.485b(g).
(79) ASTM D1946-77, Standard Method for Analysis of Reformed Gas by
Gas Chromatography; IBR approved for Sec. Sec. 60.18(f); 60.45(f);
60.564(f); 60.614(e); 60.664(e); 60.704(d).
(80) ASTM D1946-90 (Reapproved 1994), Standard Method for Analysis
of Reformed Gas by Gas Chromatography; IBR approved for Sec. Sec.
60.18(f); 60.45(f); 60.564(f); 60.614(e); 60.664(e); 60.704(d).
[[Page 1971]]
(81) ASTM D1946-90 (Reapproved 2006), Standard Method for Analysis
of Reformed Gas by Gas Chromatography, approved June 1, 2006; IBR
approved for Sec. 60.107a(d).
(82) ASTM D2013-72, Standard Method of Preparing Coal Samples for
Analysis; IBR approved for appendix A-7 to part 60: Method 19, Section
12.5.2.1.3.
(83) ASTM D2013-86, Standard Method of Preparing Coal Samples for
Analysis; IBR approved for appendix A-7 to part 60: Method 19, Section
12.5.2.1.3.
(84) ASTM D2015-77 (Reapproved 1978), Standard Test Method for
Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter;
IBR approved for Sec. Sec. 60.45(f); 60.46(c); and appendix A-7 to
part 60: Method 19, Section 12.5.2.1.3.
(85) ASTM D2015-96, Standard Test Method for Gross Calorific Value
of Solid Fuel by the Adiabatic Bomb Calorimeter; IBR approved for
Sec. Sec. 60.45(f); 60.46(c); and appendix A-7 to part 60: Method 19,
Section 12.5.2.1.3.
(86) ASTM D2016-74, Standard Test Methods for Moisture Content of
Wood; IBR approved for appendix A-8 to part 60: Method 28, Section
16.1.1.
(87) ASTM D2016-83, Standard Test Methods for Moisture Content of
Wood; IBR approved for appendix A-8 to part 60: Method 28, Section
16.1.1.
(88) ASTM D2234-76, Standard Methods for Collection of a Gross
Sample of Coal; IBR approved for appendix A-7 to part 60: Method 19,
Section 12.5.2.1.1.
(89) ASTM D2234-96, Standard Methods for Collection of a Gross
Sample of Coal; IBR approved for appendix A-7 to part 60: Method 19,
Section 12.5.2.1.1.
(90) ASTM D2234-97a, Standard Methods for Collection of a Gross
Sample of Coal; IBR approved for appendix A-7 to part 60: Method 19,
Section 12.5.2.1.1.
(91) ASTM D2234-98, Standard Methods for Collection of a Gross
Sample of Coal; IBR approved for appendix A-7 to part 60: Method 19,
Section 12.5.2.1.1.
(92) ASTM D2369-81, Standard Test Method for Volatile Content of
Coatings; IBR approved for appendix A-7 to part 60: Method 24, Section
6.2.
(93) ASTM D2369-87, Standard Test Method for Volatile Content of
Coatings; IBR approved for appendix A-7 to part 60: Method 24, Section
6.2.
(94) ASTM D2369-90, Standard Test Method for Volatile Content of
Coatings; IBR approved for appendix A-7 to part 60: Method 24, Section
6.2.
(95) ASTM D2369-92, Standard Test Method for Volatile Content of
Coatings; IBR approved for appendix A-7 to part 60: Method 24, Section
6.2.
(96) ASTM D2369-93, Standard Test Method for Volatile Content of
Coatings; IBR approved for appendix A-7 to part 60: Method 24, Section
6.2.
(97) ASTM D2369-95, Standard Test Method for Volatile Content of
Coatings; IBR approved for appendix A-7 to part 60: Method 24, Section
6.2.
(98) ASTM D2369-10 (Reapproved 2015)e1, Standard Test Method for
Volatile Content of Coatings, approved June 1, 2015; IBR approved for
appendix A-7 to part 60: Method 24, Section 6.2.
(99) ASTM D2369-20, Standard Test Method for Volatile Content of
Coatings, approved June 1, 2020; IBR approved for Sec. Sec.
60.393a(f); 60.723(b); 60.724(a); 60.725(b); 60.723a(b); 60.724a(a);
60.725a(b).
(100) ASTM D2382-76, Heat of Combustion of Hydrocarbon Fuels by
Bomb Calorimeter (High-Precision Method); IBR approved for Sec. Sec.
60.18(f); 60.485(g); 60.485a(g); 60.564(f); 60.664(e); 60.704(d).
(101) ASTM D2382-88, Heat of Combustion of Hydrocarbon Fuels by
Bomb Calorimeter (High-Precision Method); IBR approved for Sec. Sec.
60.18(f); 60.485(g); 60.485a(g); 60.564(f); 60.704(d).
(102) ASTM D2504-67, Noncondensable Gases in C3 and Lighter
Hydrocarbon Products by Gas Chromatography; IBR approved for Sec. Sec.
60.485(g) and 60.485a(g).
(103) ASTM D2504-77, Noncondensable Gases in C3 and Lighter
Hydrocarbon Products by Gas Chromatography; IBR approved for Sec. Sec.
60.485(g) and 60.485a(g).
(104) ASTM D2504-88 (Reapproved 1993), Noncondensable Gases in C3
and Lighter Hydrocarbon Products by Gas Chromatography; IBR approved
for Sec. Sec. 60.485(g) and 60.485a(g).
(105) ASTM D2584-68 (Reapproved 1985), Standard Test Method for
Ignition Loss of Cured Reinforced Resins; IBR approved for Sec.
60.685(c).
(106) ASTM D2584-94, Standard Test Method for Ignition Loss of
Cured Reinforced Resins; IBR approved for Sec. 60.685(c).
(107) ASTM D2597-94 (Reapproved 1999), Standard Test Method for
Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing
Nitrogen and Carbon Dioxide by Gas Chromatography; IBR approved for
Sec. 60.335(b).
(108) ASTM D2622-87, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry; IBR
approved for Sec. 60.106(j).
(109) ASTM D2622-94, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry; IBR
approved for Sec. 60.106(j).
(110) ASTM D2622-98, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry; IBR
approved for Sec. Sec. 60.106(j) and 60.335(b).
(111) ASTM D2622-05, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry; IBR
approved for Sec. Sec. 60.4360a(c) and 60.4415(a).
(112) ASTM D2697-22, Standard Test Method for Volume Nonvolatile
Matter in Clear or Pigmented Coatings, approved July 1, 2022; IBR
approved for Sec. Sec. 60.393a(g); 60.723(b); 60.724(a); 60.725(b);
60.723a(b); 60.724a(a); 60.725a(b).
(113) ASTM D2879-83, Test Method for Vapor Pressure-Temperature
Relationship and Initial Decomposition Temperature of Liquids by
Isoteniscope, approved 1983; IBR approved for Sec. Sec. 60.111b;
60.116b(e) and (f); 60.485(e); 60.485a(e); 60.5403b(d); 60.5406c(d).
(114) ASTM D2879-96, Test Method for Vapor Pressure-Temperature
Relationship and Initial Decomposition Temperature of Liquids by
Isoteniscope, approved 1996; IBR approved for Sec. Sec. 60.111b;
60.116b(e) and (f); 60.485(e); 60.485a(e); 60.5403b(d); 60.5406c(d).
(115) ASTM D2879-97, Test Method for Vapor Pressure-Temperature
Relationship and Initial Decomposition Temperature of Liquids by
Isoteniscope, approved 1997; IBR approved for Sec. Sec. 60.111b;
60.116b(e) and (f); 60.485(e); 60.485a(e); 60.5403b(d); 60.5406c(d).
(116) ASTM D2879-23, Standard Test Method for Vapor Pressure-
Temperature Relationship and Initial Decomposition Temperature of
Liquids by Isoteniscope, approved December 1, 2019; IBR approved for
Sec. 60.485b(e).
(117) ASTM D2880-78, Standard Specification for Gas Turbine Fuel
Oils; IBR approved for Sec. Sec. 60.111(b) and 60.111a(b).
(118) ASTM D2880-96, Standard Specification for Gas Turbine Fuel
Oils; IBR Approved for Sec. Sec. 60.111(b) and 60.111a(b).
(119) ASTM D2908-74, Standard Practice for Measuring Volatile
Organic Matter in Water by Aqueous-Injection Gas Chromatography; IBR
approved for Sec. 60.564(j).
(120) ASTM D2908-91, Standard Practice for Measuring Volatile
Organic Matter in Water by Aqueous-Injection
[[Page 1972]]
Gas Chromatography; IBR approved for Sec. 60.564(j).
(121) ASTM D2986-71, Standard Method for Evaluation of Air, Assay
Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test; IBR
approved for appendix A-3 to part 60: Method 5, Section 7.1.1; appendix
A-5 to part 60: Method 12, Section 7.1.1; and Method 13A, Section
7.1.1.2.
(122) ASTM D2986-78, Standard Method for Evaluation of Air, Assay
Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test; IBR
approved for appendix A-3 to part 60: Method 5, Section 7.1.1; appendix
A-5 to part 60: Method 12, Section 7.1.1; and Method 13A, Section
7.1.1.2.
(123) ASTM D2986-95a, Standard Method for Evaluation of Air, Assay
Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test; IBR
approved for appendix A-3 to part 60: Method 5, Section 7.1.1; appendix
A-5 to part 60: Method 12, Section 7.1.1; and Method 13A, Section
7.1.1.2.
(124) ASTM D3173-73, Standard Test Method for Moisture in the
Analysis Sample of Coal and Coke; IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.1.3.
(125) ASTM D3173-87, Standard Test Method for Moisture in the
Analysis Sample of Coal and Coke; IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.1.3.
(126) ASTM D3176-74, Standard Method for Ultimate Analysis of Coal
and Coke; IBR approved for Sec. 60.45(f) and appendix A-7 to part 60:
Method 19, Section 12.3.2.3.
(127) ASTM D3176-89, Standard Method for Ultimate Analysis of Coal
and Coke; IBR approved for Sec. 60.45(f) and appendix A-7 to part 60:
Method 19, Section 12.3.2.3.
(128) ASTM D3177-75, Standard Test Method for Total Sulfur in the
Analysis Sample of Coal and Coke; IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.1.3.
(129) ASTM D3177-89, Standard Test Method for Total Sulfur in the
Analysis Sample of Coal and Coke; IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.1.3.
(130) ASTM D3178-73 (Reapproved 1979), Standard Test Methods for
Carbon and Hydrogen in the Analysis Sample of Coal and Coke; IBR
approved for Sec. 60.45(f).
(131) ASTM D3178-89, Standard Test Methods for Carbon and Hydrogen
in the Analysis Sample of Coal and Coke; IBR approved for Sec.
60.45(f).
(132) ASTM D3246-81, Standard Test Method for Sulfur in Petroleum
Gas by Oxidative Microcoulometry; IBR approved for Sec. 60.335(b).
(133) ASTM D3246-92, Standard Test Method for Sulfur in Petroleum
Gas by Oxidative Microcoulometry; IBR approved for Sec. 60.335(b).
(134) ASTM D3246-96, Standard Test Method for Sulfur in Petroleum
Gas by Oxidative Microcoulometry; IBR approved for Sec. 60.335(b).
(135) ASTM D3246-05, Standard Test Method for Sulfur in Petroleum
Gas by Oxidative Microcoulometry; IBR approved for Sec. Sec.
60.4360a(c) and 60.4415(a).
(136) ASTM D3270-73T, Standard Test Methods for Analysis for
Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated
Method); IBR approved for appendix A-5 to part 60: Method 13A, Section
16.1.
(137) ASTM D3270-80, Standard Test Methods for Analysis for
Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated
Method); IBR approved for appendix A-5 to part 60: Method 13A, Section
16.1.
(138) ASTM D3270-91, Standard Test Methods for Analysis for
Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated
Method); IBR approved for appendix A-5 to part 60: Method 13A, Section
16.1.
(139) ASTM D3270-95, Standard Test Methods for Analysis for
Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated
Method); IBR approved for appendix A-5 to part 60: Method 13A, Section
16.1.
(140) ASTM D3286-85, Standard Test Method for Gross Calorific Value
of Coal and Coke by the Isoperibol Bomb Calorimeter; IBR approved for
appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
(141) ASTM D3286-96, Standard Test Method for Gross Calorific Value
of Coal and Coke by the Isoperibol Bomb Calorimeter; IBR approved for
appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
(142) ASTM D3370-76, Standard Practices for Sampling Water; IBR
approved for Sec. 60.564(j).
(143) ASTM D3370-95a, Standard Practices for Sampling Water; IBR
approved for Sec. 60.564(j).
(144) ASTM D3588-98 (Reapproved 2003), Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels, approved May 10, 2003; IBR approved for Sec. Sec.
60.107a(d); 60.4360a(c); 60.5413(d); 60.5413a(d); 60.5413b(d);
60.5413c(d).
(145) ASTM D3699-08, Standard Specification for Kerosine, including
Appendix X1, approved September 1, 2008; IBR approved for Sec. Sec.
60.41b; 60.41c; 60.4420a; 60.5580; 60.5580a.
(146) ASTM D3792-79, Standard Test Method for Water Content of
Water-Reducible Paints by Direct Injection into a Gas Chromatograph;
IBR approved for appendix A-7 to part 60: Method 24, Section 6.3.
(147) ASTM D3792-91, Standard Test Method for Water Content of
Water-Reducible Paints by Direct Injection into a Gas Chromatograph;
IBR approved for appendix A-7 to part 60: Method 24, Section 6.3.
(148) ASTM D4017-81, Standard Test Method for Water in Paints and
Paint Materials by the Karl Fischer Titration Method; IBR approved for
appendix A-7 to part 60: Method 24, Section 6.4.
(149) ASTM D4017-90, Standard Test Method for Water in Paints and
Paint Materials by the Karl Fischer Titration Method; IBR approved for
appendix A-7 to part 60: Method 24, Section 6.4.
(150) ASTM D4017-96a, Standard Test Method for Water in Paints and
Paint Materials by the Karl Fischer Titration Method; IBR approved for
appendix A-7 to part 60: Method 24, Section 6.4.
(151) ASTM D4057-81, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products; IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.2.3.
(152) ASTM D4057-95, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products; IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.2.3.
(153) ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual
Sampling of Petroleum and Petroleum Products; IBR approved for
Sec. Sec. 60.4360a(b) and 60.4415(a).
(154) ASTM D4084-82, Standard Test Method for Analysis of Hydrogen
Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method); IBR
approved for Sec. 60.334(h).
(155) ASTM D4084-94, Standard Test Method for Analysis of Hydrogen
Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method); IBR
approved for Sec. 60.334(h).
(156) ASTM D4084-05, Standard Test Method for Analysis of Hydrogen
Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method); IBR
approved for Sec. Sec. 60.4360; 60.4360a(c); 60.4415(a).
(157) ASTM D4177-95, Standard Practice for Automatic Sampling of
Petroleum and Petroleum Products; IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.2.1.
(158) ASTM D4177-95 (Reapproved 2000), Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products; IBR approved
for Sec. Sec. 60.4360a(b) and 60.4415(a).
[[Page 1973]]
(159) ASTM D4239-85, Standard Test Methods for Sulfur in the
Analysis Sample of Coal and Coke Using High Temperature Tube Furnace
Combustion Methods; IBR approved for appendix A-7 to part 60: Method
19, Section 12.5.2.1.3.
(160) ASTM D4239-94, Standard Test Methods for Sulfur in the
Analysis Sample of Coal and Coke Using High Temperature Tube Furnace
Combustion Methods; IBR approved for appendix A-7 to part 60: Method
19, Section 12.5.2.1.3.
(161) ASTM D4239-97, Standard Test Methods for Sulfur in the
Analysis Sample of Coal and Coke Using High Temperature Tube Furnace
Combustion Methods; IBR approved for appendix A-7 to part 60: Method
19, Section 12.5.2.1.3.
(162) ASTM D4294-02, Standard Test Method for Sulfur in Petroleum
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectrometry; IBR approved for Sec. 60.335(b).
(163) ASTM D4294-03, Standard Test Method for Sulfur in Petroleum
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectrometry; IBR approved for Sec. Sec. 60.4360a(c) and 60.4415(a).
(164) ASTM D4442-84, Standard Test Methods for Direct Moisture
Content Measurement in Wood and Wood-base Materials; IBR approved for
appendix A-8 to part 60: Method 28, Section 16.1.1.
(165) ASTM D4442-92, Standard Test Methods for Direct Moisture
Content Measurement in Wood and Wood-base Materials; IBR approved for
appendix A-8 to part 60: Method 28, Section 16.1.1.
(166) ASTM D4444-92, Standard Test Methods for Use and Calibration
of Hand-Held Moisture Meters; IBR approved for appendix A-8 to part 60:
Method 28, Section 16.1.1.
(167) ASTM D4457-85 (Reapproved 1991), Test Method for
Determination of Dichloromethane and 1,1,1-Trichloroethane in Paints
and Coatings by Direct Injection into a Gas Chromatograph; IBR approved
for appendix A-7 to part 60: Method 24, Section 6.5.
(168) ASTM D4468-85 (Reapproved 2000), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry; IBR approved for Sec. Sec. 60.335(b); 60.4360a(c);
60.4415(a).
(169) ASTM D4468-85 (Reapproved 2006), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry, approved June 1, 2006; IBR approved for Sec. 60.107a(e).
(170) ASTM D4629-02, Standard Test Method for Trace Nitrogen in
Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and
Chemiluminescence Detection; IBR approved for Sec. Sec. 60.49b(e) and
60.335(b).
(171) ASTM D4809-95, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method); IBR
approved for Sec. Sec. 60.18(f); 60.485(g); 60.485a(g); 60.564(f);
60.704(d).
(172) ASTM D4809-06, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method),
approved December 1, 2006; IBR approved for Sec. 60.107a(d).
(173) ASTM D4809-18, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method),
approved July 1, 2018; IBR approved for Sec. Sec. 60.485b(g) and
60.4360a(c).
(174) ASTM D4810-88 (Reapproved 1999), Standard Test Method for
Hydrogen Sulfide in Natural Gas Using Length of Stain Detector Tubes;
IBR approved for Sec. Sec. 60.4360; 60.4360a(c); 60.4415(a).
(175) ASTM D4840-99(2018)e1, Standard Guide for Sample Chain-of-
Custody Procedures, approved August 2018; IBR approved for Appendix A-
7: Method 23, Section 8.2.12.
(176) ASTM D4891-89 (Reapproved 2006), Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion, approved June 1, 2006; IBR approved for Sec. Sec.
60.107a(d); 60.4360a(c); 60.5413(d); 60.5413a(d); 60.5413b(d);
60.5413c(d).
(177) ASTM D5066-91 (Reapproved 2017), Standard Test Method for
Determination of the Transfer Efficiency Under Production Conditions
for Spray Application of Automotive Paints--Weight Basis, approved June
1, 2017; IBR approved for Sec. 60.393a(h).
(178) ASTM D5087-02 (Reapproved 2021), Standard Test Method for
Determining Amount of Volatile Organic Compound (VOC) Released from
Solventborne Automotive Coatings and Available for Removal in a VOC
Control Device (Abatement), approved February 1, 2021; IBR approved for
Sec. 60.397a(e) and appendix A to subpart MMa.
(179) ASTM D5287-97 (Reapproved 2002), Standard Practice for
Automatic Sampling of Gaseous Fuels; IBR approved for Sec. Sec.
60.4360a(b) and 60.4415(a).
(180) ASTM D5403-93, Standard Test Methods for Volatile Content of
Radiation Curable Materials; IBR approved for appendix A-7 to part 60:
Method 24, Section 6.6.
(181) ASTM D5453-00, Standard Test Method for Determination of
Total Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence; IBR approved for Sec. 60.335(b).
(182) ASTM D5453-05, Standard Test Method for Determination of
Total Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence; IBR approved for Sec. Sec. 60.4360a(c) and 60.4415(a).
(183) ASTM D5504-01, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence; IBR approved for Sec. Sec. 60.334(h) and
60.4360.
(184) ASTM D5504-08, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence, approved June 15, 2008; IBR approved for Sec.
60.107a(e).
(185) ASTM D5504-20, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence, approved November 1, 2020; IBR approved for
Sec. 60.4360a(c).
(186) ASTM D5623-19, Standard Test Method for Sulfur Compounds in
Light Petroleum Liquids by Gas Chromatography and Sulfur Selective
Detection, approved July 1, 2019; IBR approved for Sec. 60.4415(a).
(187) ASTM D5623-24, Standard Test Method for Sulfur Compounds in
Light Petroleum Liquids by Gas Chromatography and Sulfur Selective
Detection, approved March 1, 2024; IBR approved for Sec. 60.4360a(c).
(188) ASTM D5762-02, Standard Test Method for Nitrogen in Petroleum
and Petroleum Products by Boat-Inlet Chemiluminescence; IBR approved
for Sec. 60.335(b).
(189) ASTM D5865-98, Standard Test Method for Gross Calorific Value
of Coal and Coke; IBR approved for Sec. Sec. 60.45(f); 60.46(c); and
appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
(190) ASTM D5865-10, Standard Test Method for Gross Calorific Value
of Coal and Coke, approved January 1, 2010; IBR approved for Sec. Sec.
60.45(f); 60.46(c); and appendix A-7 to part 60: Method 19, section
12.5.2.1.3.
(191) ASTM D5965-02 (Reapproved 2013), Standard Test Methods for
Specific Gravity of Coating Powders, approved June 1, 2013; IBR
approved for Sec. 60.393a(f).
(192) ASTM D6093-97 (Reapproved 2016), Standard Test Method for
Percent Volume Nonvolatile Matter in Clear or
[[Page 1974]]
Pigmented Coatings Using a Helium Gas Pycnometer, approved December 1,
2016; IBR approved for Sec. Sec. 60.393a(g); 60.723(b); 60.724(a);
60.725(b); 60.723a(b); 60.724a(a); 60.725a(b).
(193) ASTM D6216-20, Standard Practice for Opacity Monitor
Manufacturers to Certify Conformance with Design and Performance
Specifications, approved September 1, 2020; IBR approved for appendix B
to part 60.
(194) ASTM D6228-98, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Flame Photometric Detection; IBR approved for Sec. 60.334(h).
(195) ASTM D6228-98 (Reapproved 2003), Standard Test Method for
Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by
Gas Chromatography and Flame Photometric Detection; IBR approved for
Sec. Sec. 60.4360; 60.4360a(c); 60.4415(a).
(196) ASTM D6266-00a (Reapproved 2017), Standard Test Method for
Determining the Amount of Volatile Organic Compound (VOC) Released from
Waterborne Automotive Coatings and Available for Removal in a VOC
Control Device (Abatement), approved July 1, 2017; IBR approved for
Sec. 60.397a(e).
(197) ASTM D6348-03, Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy, approved October 1, 2003; IBR approved
for Sec. 60.73a(b); table 7 to subpart IIII; table 2 to subpart JJJJ;
Sec. 60.4245(d).
(198) ASTM D6348-12e1, Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy, approved February 1, 2012; IBR approved
for Sec. 60.5413c(b).
(199) ASTM D6348-12 (Reapproved 2020), Standard Test Method for
Determination of Gaseous Compounds by Extractive Direct Interface
Fourier Transform Infrared (FTIR) Spectroscopy, approved December 1,
2020; IBR approved for Sec. Sec. 60.4400(a) and 60.4400a(b).
(200) ASTM D6366-99, Standard Test Method for Total Trace Nitrogen
and Its Derivatives in Liquid Aromatic Hydrocarbons by Oxidative
Combustion and Electrochemical Detection; IBR approved for Sec.
60.335(b).
(201) ASTM D6377-20, Standard Test Method for Determination of
Vapor Pressure of Crude Oil: VPCRX (Expansion Method),
approved June 1, 2020; IBR approved for Sec. 60.113c(d).
(202) ASTM D6378-22, Standard Test Method for Determination of
Vapor Pressure (VPX) of Petroleum Products, Hydrocarbons, and
Hydrocarbon-Oxygenate Mixtures (Triple Expansion Method), approved July
1, 2022; IBR approved for Sec. 60.113c(d).
(203) ASTM D6420-99 (Reapproved 2004), Standard Test Method for
Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography-Mass Spectrometry, approved October 1, 2004; IBR
approved for Sec. 60.107a(d).
(204) ASTM D6420-18, Standard Test Method for Determination of
Gaseous Organic Compounds by Direct Interface Gas Chromatography-Mass
Spectrometry, approved November 1, 2018; IBR approved for Sec. Sec.
60.485(g); 60.485a(g); 60.485b(g); 60.611a; 60.614(b) and (e);
60.614a(b) and (e), 60.664(b) and (e); 60.664a(b) and (f); 60.700(c);
60.704(b) (d), and (h); 60.705(l); 60.704a(b) and (f).
(205) ASTM D6522-00, Standard Test Method for Determination of
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in
Emissions from Natural Gas-Fired Reciprocating Engines, Combustion
Turbines, Boilers, and Process Heaters Using Portable Analyzers; IBR
approved for Sec. Sec. 60.335(a) and (b).
(206) ASTM D6522-00 (Reapproved 2005), Standard Test Method for
Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen
Concentrations in Emissions from Natural Gas-Fired Reciprocating
Engines, Combustion Turbines, Boilers, and Process Heaters Using
Portable Analyzers, approved October 1, 2005; IBR approved for table 2
to subpart JJJJ, Sec. Sec. 60.5413(b); 60.5413a(b).
(207) ASTM D6522-11 Standard Test Method for Determination of
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in
Emissions from Natural Gas-Fired Reciprocating Engines, Combustion
Turbines, Boilers, and Process Heaters Using Portable Analyzers,
approved December 1, 2011; IBR approved for Sec. Sec. 60.37f(a) and
60.766(a).
(208) ASTM D6522-20, Standard Test Method for Determination of
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in
Emissions from Natural Gas-Fired Reciprocating Engines, Combustion
Turbines, Boilers, and Process Heaters Using Portable Analyzers,
approved June 1, 2020; IBR approved for Sec. Sec. 60.4400(a);
60.4400a(b); 60.5413b(b); 60.5413c(b).
(209) ASTM D6667-01, Standard Test Method for Determination of
Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum
Gases by Ultraviolet Fluorescence; IBR approved for Sec. 60.335(b).
(210) ASTM D6667-04, Standard Test Method for Determination of
Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum
Gases by Ultraviolet Fluorescence; IBR approved for Sec. Sec.
60.4360a(c) and 60.4415(a).
(211) ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1
through X3, approved July 15, 2011; IBR approved for Sec. Sec. 60.41b;
60.41c; 60.4420a; 60.5580; 60.5580a.
(212) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method); IBR approved for Sec.
60.56c(b).
(213) ASTM D6784-02 (Reapproved 2008), Standard Test Method for
Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas
Generated from Coal-Fired Stationary Sources (Ontario Hydro Method),
approved April 1, 2008; IBR approved for Sec. 60.56c(b).
(214) ASTM D6784-16, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method), approved March 1, 2016; IBR
approved for appendix B to part 60.
(215) ASTM D6911-15 Standard Guide for Packaging and Shipping
Environmental Samples for Laboratory Analysis, approved January 15,
2015; IBR approved for Appendix A-7: Method 23, Section 8.2.11;
Appendix A-8: Method 30B, Section 8.3.3.8.
(216) ASTM D7039-15a, Standard Test Method for Sulfur in Gasoline,
Diesel Fuel, Jet Fuel, Kerosine, Biodiesel, Biodiesel Blends, and
Gasoline-Ethanol Blends by Monochromatic Wavelength Dispersive X-ray
Fluorescence Spectrometry, approved July 1, 2015; IBR approved for
Sec. 60.4415(a).
(217) ASTM D7039-24, Standard Test Method for Sulfur in Gasoline,
Diesel Fuel, Jet Fuel, Kerosine, Biodiesel, Biodiesel Blends, and
Gasoline-Ethanol Blends by Monochromatic Wavelength Dispersive X-ray
Fluorescence Spectrometry, approved December 1, 2024; IBR approved for
Sec. 60.4360a(c).
(218) ASTM D7467-10, Standard Specification for Diesel Fuel Oil,
Biodiesel Blend (B6 to B20), including Appendices X1 through X3,
approved August 1, 2010; IBR approved for Sec. Sec. 60.41b; 60.41c;
60.4420a; 60.5580; 60.5580a.
[[Page 1975]]
(219) ASTM D7520-16, Standard Test Method for Determining the
Opacity of a Plume in the Outdoor Ambient Atmosphere, approved April 1,
2016; IBR approved for Sec. Sec. 60.123(c); 60.123a(c); 60.271(k);
60.272(a) and (b); 60.273(c) and (d); 60.274(i); 60.275(e); 60.276(c);
60.271a; 60.272a(a) and (b); 60.273a(c) and (d); 60.274a(h);
60.275a(e); 60.276a(f); 60.271b; 60.272b(a) and (b); 60.273b(c) and
(d); 60.274b(h); 60.275b(e); 60.276b(f); 60.374a(d); 60.2972(a); tables
1, 1a, and 1b to subpart EEEE; Sec. 60.3067(a); tables 2 and 2a to
subpart FFFF.
(220) ASTM E168-67, General Techniques of Infrared Quantitative
Analysis; IBR approved for Sec. Sec. 60.485a(d); 60.593(b);
60.593a(b); 60.632(f).
(221) ASTM E168-77, General Techniques of Infrared Quantitative
Analysis; IBR approved for Sec. Sec. 60.485a(d); 60.593(b);
60.593a(b); 60.632(f).
(222) ASTM E168-92, General Techniques of Infrared Quantitative
Analysis; IBR approved for Sec. Sec. 60.485a(d); 60.593(b);
60.593a(b); 60.632(f); 60.5400; 60.5400a(f).
(223) ASTM E168-16 (Reapproved 2023), Standard Practices for
General Techniques of Infrared Quantitative Analysis, approved January
1, 2023; IBR approved for Sec. Sec. 60.485b(d); 60.5400b(a);
60.5400c(a); 60.5401c(a).
(224) ASTM E169-63, General Techniques of Ultraviolet Quantitative
Analysis; IBR approved for Sec. Sec. 60.485a(d); 60.593(b);
60.593a(b); 60.632(f).
(225) ASTM E169-77, General Techniques of Ultraviolet Quantitative
Analysis; IBR approved for Sec. Sec. 60.485a(d); 60.593(b);
60.593a(b); 60.632(f).
(226) ASTM E169-93, General Techniques of Ultraviolet Quantitative
Analysis, approved May 15, 1993; IBR approved for Sec. Sec.
60.485a(d); 60.593(b); 60.593a(b); 60.632(f); 60.5400(f); 60.5400a(f).
(227) ASTM E169-16 (Reapproved 2022), Standard Practices for
General Techniques of Ultraviolet-Visible Quantitative Analysis,
approved November 1, 2022; IBR approved for Sec. 60.485b(d),
60.5400b(a); 60.5401b(a); 60.5400c(a); 60.5401c(a).
(228) ASTM E260-73, General Gas Chromatography Procedures; IBR
approved for Sec. Sec. 60.485a(d); 60.593(b); 60.593a(b); 60.632(f).
(229) ASTM E260-91, General Gas Chromatography Procedures; IBR
approved for Sec. Sec. 60.485a(d); 60.593(b); 60.593a(b); 60.632(f).
(230) ASTM E260-96, General Gas Chromatography Procedures, approved
April 10, 1996; IBR approved for Sec. Sec. 60.485a(d); 60.593(b);
60.593a(b); 60.632(f); 60.5400(f); 60.5400a(f); 60.5406(b);
60.5406a(b)(3); 60.5400b(a)(2); 60.5401b(a)(2); 60.5406b(b)(3);
60.5400c(a); 60.5401c(a).
(231) ASTM E260-96 (Reapproved 2019), Standard Practice for Packed
Column Gas Chromatography, approved September 1, 2019; IBR approved for
Sec. 60.485b(d).
(232) ASTM E617-13, Standard Specification for Laboratory Weights
and Precision Mass Standards, approved May 1, 2013; IBR approved for
appendix A-3: Methods 4, 5, 5H, 5I, and appendix A-8: Method 29.
(233) ASTM E871-82 (Reapproved 2013), Standard Test Method for
Moisture Analysis of Particulate Wood Fuels, approved August 15, 2013;
IBR approved for appendix A-8: Method 28R.
(234) ASTM E1584-11, Standard Test Method for Assay of Nitric Acid,
approved August 1, 2011; IBR approved for Sec. 60.73a(c).
(235) ASTM E2515-11, Standard Test Method for Determination of
Particulate Matter Emissions Collected by a Dilution Tunnel, approved
November 1, 2011; IBR approved for Sec. Sec. 60.534(c) and (d);
60.5476(f).
(236) ASTM E2618-13 Standard Test Method for Measurement of
Particulate Matter Emissions and Heating Efficiency of Outdoor Solid
Fuel-Fired Hydronic Heating Appliances, approved September 1, 2013; IBR
approved for Sec. 60.5476(g).
(237) ASTM E2779-10, Standard Test Method for Determining
Particulate Matter Emissions from Pellet Heaters, approved October 1,
2010; IBR approved for Sec. 60.534(a) and (f).
(238) ASTM E2780-10, Standard Test Method for Determining
Particulate Matter Emissions from Wood Heaters, approved October 1,
2010; IBR approved for appendix A: Method 28R.
(239) ASTM UOP539-97, Refinery Gas Analysis by Gas Chromatography,
(Copyright 1997); IBR approved for Sec. 60.107a(d).
* * * * *
(m) * * *
(1) GPA Midstream Standard 2140-17 (GPA 2140-17), Liquified
Petroleum Gas Specifications and Test Methods (Revised 2017); IBR
approved for Sec. Sec. 60.4360a(c) and 60.4415(a).
(2) GPA Midstream Standard 2166-17 (GPA 2166-17), Obtaining Natural
Gas Samples for Analysis by Gas Chromatography, (Reaffirmed 2017); IBR
approved for Sec. Sec. 60.4360a(b) and 60.4415(a).
(3) GPA Standard 2172-09 (GPA 2172-09), Calculation of Gross
Heating Value, Relative Density, Compressibility and Theoretical
Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody
Transfer (2009); IBR approved for Sec. Sec. 60.107a(d) and
60.4360a(c).
(4) GPA Standard 2174-14 (GPA 2174-14), Obtaining Liquid
Hydrocarbon Samples for Analysis by Gas Chromatography, (Revised 2014);
IBR approved for Sec. Sec. 60.4360a(b) and 60.4415(a).
* * * * *
(6) GPA Standard 2377-86 (GPA 2377-84), Test for Hydrogen Sulfide
and Carbon Dioxide in Natural Gas Using Length of Stain Tubes, 1986
Revision; IBR approved for Sec. Sec. 60.105(b); 60.107a(b); 60.334(h);
60.4360; 60.4360a(c); and 60.4415(a).
* * * * *
Subpart GG--Standards of Performance for Stationary Gas Turbines
0
3. Amend Sec. 60.330 by revising paragraph (a) and adding paragraphs
(c) through (e) to read as follows:
Sec. 60.330 Applicability and designation of affected facility.
(a) Except as provided for in paragraphs (c) through (e) of this
section, the provisions of this subpart are applicable to the following
affected facilities: All stationary gas turbines with a heat input at
peak load equal to or greater than 10.7 gigajoules (10 million Btu) per
hour, based on the lower heating value of the fuel fired.
* * * * *
(c) As an alternative to being subject to this subpart, the owner
or operator of a stationary combustion turbine meeting the
applicability of this subpart may petition the Administrator (in
writing) to become subject to the requirements for modified units in
subpart KKKKa of this part. If the Administrator grants the petition,
the affected facility is no longer subject to this subpart and is
subject to (unless the unit is modified or reconstructed in the future)
the requirements for modified units in subpart KKKKa of this part. The
Administrator can only grant the petition if it is determined that
compliance with subpart KKKKa of this part would be equivalent to, or
more stringent than, compliance with this subpart.
(d) Stationary gas turbines subject to subpart Da, KKKK, or KKKKa
of this part are not subject to this subpart.
(e) A combustion turbine that is subject to this subpart and is not
a ``major source'' or located at a ``major source'' (as that term is
defined at 42
[[Page 1976]]
U.S.C. 7661 (2)) is exempt from the requirements of 42 U.S.C. 7661a(a).
0
4. Amend Sec. 60.331 by:
0
a. Revising paragraphs (a) and (g);
0
b. Removing and reserving paragraphs (m) and (n); and
0
c. Revising paragraphs (p) and (u).
The revisions read as follows:
Sec. 60.331 Definitions.
* * * * *
(a) Stationary gas turbine means any simple cycle gas turbine,
regenerative cycle gas turbine, or any gas turbine portion of a
combined cycle steam/electric generating system that is not self-
propelled. It may, however, be mounted on a vehicle for portability.
Portable combustion turbines are excluded from the definition of
``stationary combustion turbine,'' and not regulated under this part,
if the turbine meets the definition of ``nonroad engine'' under title
II of the Clean Air Act and applicable regulations and is certified to
meet emission standards promulgated pursuant to title II of the Clean
Air Act, along with all related requirements.
* * * * *
(g) ISO standard day conditions means 288 degrees Kelvin (15
[deg]C, 59 [deg]F), 60 percent relative humidity, and 101.3 kilopascals
(14.69 psi, 1 atm) pressure.
* * * * *
(p) Gas turbine model means a group of gas turbines having the same
nominal air flow, combustor inlet pressure, combustor inlet
temperature, firing temperature, turbine inlet temperature, and turbine
inlet pressure.
* * * * *
(u) Natural gas means a fluid mixture of hydrocarbons (e.g.,
methane, ethane, or propane) that maintains a gaseous state at standard
atmospheric temperature and pressure under ordinary conditions. Natural
gas contains 20.0 grains or less of total sulfur per 100 standard cubic
feet. Equivalents of this in other units are as follows: 0.068 weight
percent total sulfur, 680 parts per million by weight (ppmw) total
sulfur, and 338 parts per million by volume (ppmv) at 15.5 degrees
Celsius total sulfur. Additionally, natural gas must be composed of at
least 70 percent methane by volume and have a gross calorific value
between 950 and 1100 British thermal units (Btu) per standard cubic
foot. Unless refined to meet the definition of natural gas in this
paragraph (u), natural gas does not include the following gaseous
fuels: landfill gas, digester gas, refinery gas, sour gas, blast
furnace gas, coal-derived gas, producer gas, coke oven gas, or any
gaseous fuel produced in a process which might result in highly
variable sulfur content or heating value.
* * * * *
0
5. Amend Sec. 60.332 by revising paragraphs (f) through (h) to read as
follows:
Sec. 60.332 Standard for nitrogen oxides.
* * * * *
(f) Stationary gas turbines using water or steam injection for
control of NOX emissions are exempt from paragraph (a) of
this section when ice fog is deemed a traffic hazard by the owner or
operator of the gas turbine.
(g) Emergency gas turbines, military gas turbines for use in other
than a garrison facility, military gas turbines installed for use as
military training facilities, and firefighting gas turbines are exempt
from paragraph (a) of this section.
(h) Stationary gas turbines engaged by manufacturers in research
and development of equipment for both gas turbine emission control
techniques and gas turbine efficiency improvements are exempt from
paragraph (a) of this section on a case-by-case basis as determined by
the Administrator.
* * * * *
0
6. Amend Sec. 60.333 by revising the introductory text and paragraph
(a) and adding paragraph (c) to read as follows:
Sec. 60.333 Standard for sulfur dioxide.
Except as provided in paragraph (c) of this section, on and after
the date on which the performance test required to be conducted by
Sec. 60.8 is completed, every owner or operator subject to the
provisions of this subpart shall comply with one or the other of the
following conditions in paragraphs (a) and (b) of this section:
(a) No owner or operator subject to the provisions of this subpart
shall cause to be discharged into the atmosphere from any stationary
gas turbine any gases which contain sulfur dioxide in excess of 0.015
percent by volume at 15 percent oxygen and on a dry basis; or
* * * * *
(c) Stationary gas turbines subject to either subpart J or Ja of
this part are not subject to the SO2 standards in this
subpart.
0
7. Amend Sec. 60.334 by revising paragraphs (b)(3)(iii), (h)(1), and
(j)(3) and adding paragraph (k) to read as follows:
Sec. 60.334 Monitoring of operations.
* * * * *
(b) * * *
(3) * * *
(iii) If the owner or operator has installed a NOX CEMS
to meet the requirements of part 75 of this chapter, and is continuing
to meet the ongoing requirements of part 75, the CEMS may be used to
meet the requirements of this section, except that the missing data
substitution methodology provided for at subpart D of part 75, is not
required for purposes of identifying excess emissions. Instead, periods
of missing CEMS data are to be reported as monitor downtime in the
excess emissions and monitoring performance report required in Sec.
60.7(c). For affected units that are also regulated under part 75, the
NOX emission rate may be monitored using a NOX
diluent CEMS that is installed and certified in accordance with
appendix A to part 75 and the QA program in appendix E to part 75, or
the low mass emissions methodology in Sec. 75.19 of this chapter.
* * * * *
(h) * * *
(1) Shall monitor the total sulfur content of the fuel being fired
in the turbine, except as provided in paragraph (h)(3) of this section.
The sulfur content of the fuel must be determined using total sulfur
methods described in Sec. 60.335(b)(10). Alternatively, if the total
sulfur content of the gaseous fuel during the most recent performance
test was less than 0.4 weight percent (4,000 ppmw), ASTM D4084-82,
D4084-94, D5504-01, D6228-98, or Gas Processors Association Standard
2377-86 (all of which are incorporated by reference, see Sec. 60.17),
which measure the major sulfur compounds may be used; and
* * * * *
(j) * * *
(3) Ice fog. Each period during which an exemption provided in
Sec. 60.332(f) is in effect shall be reported in writing to the
Administrator in the semiannual report described in paragraph (k)(3) of
this section. For each period, the ambient conditions existing during
the period, the date and time the air pollution control system was
deactivated, and the date and time the air pollution control system was
reactivated shall be reported.
* * * * *
(k) The reporting requirements for this subpart shall be as
follows:
(1) Reporting frequency. All reports required under Sec. 60.7(c)
must be electronically submitted via the Compliance and Emissions Data
Reporting Interface (CEDRI) by the 30th day following the end of each
6-month period.
(2) Electronic reporting. Beginning on March 16, 2026, within 60
days after the date of completing each performance test or CEMS
performance evaluation that includes a RATA, you must submit
[[Page 1977]]
the results following the procedures specified in paragraph (k)(4) of
this section. You must submit the report in a file format generated
using the EPA's Electronic Reporting Tool (ERT). Alternatively, you may
submit an electronic file consistent with the extensible markup
language (XML) schema listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) accompanied by the other information required by Sec.
60.8(f)(2) in PDF format.
(3) General reporting requirements. You must submit to the
Administrator semiannual reports of the following recorded information.
Beginning on January 15, 2027, or once the report template for this
subpart has been available on the CEDRI website (https://www.epa.gov/electronic-reporting-air-emissions/cedri) for one year, whichever date
is later, submit all subsequent reports using the appropriate
electronic report template on the CEDRI website for this subpart and
following the procedure specified in paragraph (k)(4) of this section.
The date report templates become available will be listed on the CEDRI
website. Unless the Administrator or delegated State agency or other
authority has approved a different schedule for submission of reports,
the report must be submitted by the deadline specified in this subpart,
regardless of the method in which the report is submitted.
(4) CEDRI and CBI. If you are required to submit notifications or
reports following the procedure specified in this paragraph (k)(4), you
must submit notifications or reports to the EPA via CEDRI, which can be
accessed through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/). The EPA will make all the information submitted through
CEDRI available to the public without further notice to you. Do not use
CEDRI to submit information you claim as CBI. Although we do not expect
persons to assert a claim of CBI, if you wish to assert a CBI claim for
some of the information in the report or notification, you must submit
a complete file in the format specified in this subpart, including
information claimed to be CBI, to the EPA following the procedures in
paragraphs (k)(4)(i) and (ii) of this section. Clearly mark the part or
all of the information that you claim to be CBI. Information not marked
as CBI may be authorized for public release without prior notice.
Information marked as CBI will not be disclosed except in accordance
with procedures set forth in 40 CFR part 2. All CBI claims must be
asserted at the time of submission. Anything submitted using CEDRI
cannot later be claimed CBI. Furthermore, under CAA section 114(c),
emissions data is not entitled to confidential treatment, and the EPA
is required to make emissions data available to the public. Thus,
emissions data will not be protected as CBI and will be made publicly
available. You must submit the same file submitted to the CBI office
with the CBI omitted to the EPA via the EPA's CDX as described earlier
in this paragraph (k)(4).
(i) The preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol, or
other online file sharing services. Electronic submissions must be
transmitted directly to the OAQPS CBI Office at the email address
[email protected], and as described above, should include clear CBI
markings. ERT files should be flagged to the attention of the Group
Leader, Measurement Policy Group; all other files should be flagged to
the attention of the Stationary Combustion Turbine Sector Lead. If
assistance is needed with submitting large electronic files that exceed
the file size limit for email attachments, and if you do not have your
own file sharing service, please email [email protected] to request a
file transfer link.
(ii) If you cannot transmit the file electronically, you may send
CBI information through the postal service to the following address:
U.S. EPA, Attn: OAQPS Document Control Office, Mail Drop: C404-02, 109
T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711. In addition to the
OAQPS Document Control Officer, ERT files should also be sent to the
attention of the Group Leader, Measurement Policy Group, and all other
files should also be sent to the attention of the Stationary Combustion
Turbine Sector Lead. The mailed CBI material should be double wrapped
and clearly marked. Any CBI markings should not show through the outer
envelope.
(5) System outage. If you are required to electronically submit a
report through CEDRI in the EPA's CDX, you may assert a claim of EPA
system outage for failure to timely comply with that reporting
requirement. To assert a claim of EPA system outage, you must meet the
requirements outlined in paragraphs (k)(5)(i) through (vii) of this
section.
(i) You must have been or will be precluded from accessing CEDRI
and submitting a required report within the time prescribed due to an
outage of either the EPA's CEDRI or CDX systems.
(ii) The outage must have occurred within the period of time
beginning 5 business days prior to the date that the submission is due.
(iii) The outage may be planned or unplanned.
(iv) You must submit notification to the Administrator in writing
as soon as possible following the date you first knew, or through due
diligence should have known, that the event may cause or has caused a
delay in reporting.
(v) You must provide to the Administrator a written description
identifying:
(A) The date(s) and time(s) when CDX or CEDRI was accessed and the
system was unavailable;
(B) A rationale for attributing the delay in reporting beyond the
regulatory deadline to EPA system outage;
(C) A description of measures taken or to be taken to minimize the
delay in reporting; and
(D) The date by which you propose to report, or if you have already
met the reporting requirement at the time of notification, the date you
reported.
(vi) The decision to accept the claim of EPA system outage and
allow an extension to the reporting deadline is solely within the
discretion of the Administrator.
(vii) In any circumstance, the report must be submitted
electronically as soon as possible after the outage is resolved.
(6) Force majeure. If you are required to electronically submit a
report through CEDRI in the EPA's CDX, you may assert a claim of force
majeure for failure to timely comply with that reporting requirement.
To assert a claim of force majeure, you must meet the requirements
outlined in paragraphs (k)(6)(i) through (v) of this section.
(i) You may submit a claim if a force majeure event is about to
occur, occurs, or has occurred or there are lingering effects from such
an event within the period of time beginning five business days prior
to the date the submission is due. For the purposes of this section, a
force majeure event is defined as an event that will be or has been
caused by circumstances beyond the control of the affected facility,
its contractors, or any entity controlled by the affected facility that
prevents you from complying with the requirement to submit a report
electronically within the time period prescribed. Examples of such
events are acts of nature (e.g., hurricanes, earthquakes, or floods),
acts of war or terrorism, or equipment failure or safety hazard beyond
the control of the affected facility (e.g., large scale power outage).
(ii) You must submit notification to the Administrator in writing
as soon as possible following the date you first knew, or through due
diligence should
[[Page 1978]]
have known, that the event may cause or has caused a delay in
reporting.
(iii) You must provide to the Administrator:
(A) A written description of the force majeure event;
(B) A rationale for attributing the delay in reporting beyond the
regulatory deadline to the force majeure event;
(C) A description of measures taken or to be taken to minimize the
delay in reporting; and
(D) The date by which you propose to report, or if you have already
met the reporting requirement at the time of notification, the date you
reported.
(iv) The decision to accept the claim of force majeure and allow an
extension to the reporting deadline is solely within the discretion of
the Administrator.
(v) In any circumstance, the reporting must occur as soon as
possible after the force majeure event occurs.
(7) Record availability. Any records required to be maintained by
this subpart that are submitted electronically via the EPA's CEDRI may
be maintained in electronic format. This ability to maintain electronic
copies does not affect the requirement for facilities to make records,
data, and reports available upon request to a delegated air agency or
the EPA as part of an on-site compliance evaluation.
0
8. Amend Sec. 60.335 by revising paragraphs (a)(3), (a)(5)(ii)(A) and
(B), (b)(2), (b)(7)(i), (b)(9)(ii), and (b)(10)(ii) to read as follows:
Sec. 60.335 Test methods and procedures.
(a) * * *
(3) To determine NOX and diluent concentration:
(i) Either EPA Method 7E in appendix A-4 to this part or EPA Method
320 in appendix A to part 63 of this chapter; and
(ii) Either EPA Method 3 or 3A in appendix A to this part.
* * * * *
(5) * * *
(ii) * * *
(A) If each of the individual traverse point NOX
concentrations, normalized to 15 percent O2, is within
10 percent of the mean normalized concentration for all
traverse points, then you may use 3 points (located either 16.7, 50.0,
and 83.3 percent of the way across the stack or duct, or, for circular
stacks or ducts greater than 2.4 meters (7.8 feet) in diameter, at 0.4,
1.2, and 2.0 meters from the wall). The 3 points shall be located along
the measurement line that exhibited the highest average normalized
NOX concentration during the stratification test; or
(B) If each of the individual traverse point NOX
concentrations, normalized to 15 percent O2, is within
5 percent of the mean normalized concentration for all
traverse points, then you may sample at a single point, located at
least 1 meter from the stack wall or at the stack centroid.
* * * * *
(b) * * *
(2) The 3-run performance test required by Sec. 60.8 must be
performed within 5 percent at 30, 50, 75, and 90-to-100
percent of peak load or at four evenly-spaced load points in the normal
operating range of the gas turbine, including the minimum point in the
operating range and 90-to-100 percent of peak load, or at the highest
achievable load point if 90-to-100 percent of peak load cannot be
physically achieved in practice. If the turbine combusts both oil and
gas as primary or backup fuels, separate performance testing is
required for each fuel. Notwithstanding these requirements, performance
testing is not required for any emergency fuel (as defined in Sec.
60.331).
* * * * *
(7) * * *
(i) Perform a minimum of 9 reference method runs, with a minimum
time per run of 21 minutes, at a single load level, between 90 and 100
percent of peak (or the highest physically achievable) load while the
source is combusting the fuel that is a normal primary fuel for that
source.
* * * * *
(9) * * *
(ii) For gaseous fuels, shall use analytical methods and procedures
that are accurate within 5 percent of the instrument range
and are approved by the Administrator.
(10) * * *
(ii) For gaseous fuels, ASTM D1072-80, D1072-90 (Reapproved 1994);
D3246-81, D3246-92, D3246-96; D4468-85 (Reapproved 2000); or D6667-01
(all of which are incorporated by reference, see Sec. 60.17). The
applicable ranges of some ASTM methods mentioned above are not adequate
to measure the levels of sulfur in some fuel gases. Dilution of samples
before analysis (with verification of the dilution ratio) may be used,
subject to the prior approval of the Administrator.
* * * * *
Subpart KKKK--Standards of Performance for Stationary Combustion
Turbines
0
9. Revise Sec. 60.4305 to read as follows:
Sec. 60.4305 Does this subpart apply to my stationary combustion
turbine?
(a) If you are the owner or operator of a stationary combustion
turbine with a heat input at peak load equal to or greater than 10.7
gigajoules (10 MMBtu) per hour, based on the higher heating value of
the fuel, which commenced construction, modification, or reconstruction
after February 18, 2005, your turbine is subject to this subpart. Only
heat input to the combustion turbine engine should be included when
determining whether or not this subpart is applicable to your
combustion turbine. Any additional heat input to associated heat
recovery steam generators (HRSG) or duct burners should not be included
when determining your peak heat input. However, this subpart does apply
to emissions from any associated HRSG and duct burners.
(b) Stationary combustion turbines regulated under this subpart are
not subject to subpart GG of this part. Heat recovery steam generators
and duct burners regulated under this subpart are not subject to
subparts Da, Db, and Dc of this part.
(c) Stationary combustion turbines subject to subpart KKKKa of this
part are not subject to this subpart.
(d) As an alternative to being subject to this subpart, the owner
or operator of an affected stationary combustion turbine meeting the
applicability of this subpart may petition the Administrator (in
writing) to become subject to the requirements for modified units in
subpart KKKKa of this part. If the Administrator grants the petition,
the affected facility is no longer subject to this subpart and is
subject to (unless the unit is modified or reconstructed in the future)
the requirements for modified units under subpart KKKKa of this part.
The Administrator can only grant the petition if it is determined that
compliance with subpart KKKKa of this part would be equivalent to, or
more stringent than, compliance with this subpart.
(e) Stationary gas turbines subject to title II of the Clean Air
Act are not subject to this subpart.
0
10. Amend Sec. 60.4310 by adding paragraphs (e) and (f) to read as
follows:
Sec. 60.4310 What types of operations are exempt from these
standards of performance?
* * * * *
(e) Military combustion turbines for use in other than a garrison
facility and military combustion turbines installed for use as military
training facilities are exempt from the NOX standards in
this subpart.
[[Page 1979]]
(f) A combustion turbine that is subject to this subpart and is not
a ``major source'' or located at a ``major source'' (as that term is
defined at 42 U.S.C. 7661 (2)) is exempt from the requirements of 42
U.S.C. 7661a(a).
0
11. Amend Sec. 60.4320 by revising paragraph (a) and adding paragraph
(c) to read as follows:
Sec. 60.4320 What emission limits must I meet for nitrogen oxides
(NOX)?
(a) Except as provided for in paragraph (c) of this section, you
must meet the emission limits for NOX specified in table 1
to this subpart.
* * * * *
(c) A stationary combustion turbine that combusts byproduct fuels
for which a facility-specific NOX emission standard has been
established by the Administrator or delegated authority according to
the requirements of paragraphs (c)(1) and (2) of this section is exempt
from the emission limits specified in table 1 to this subpart.
(1) You may request a facility-specific NOX emission
standard by submitting a written request to the Administrator or
delegated authority explaining why your affected facility, when
combusting the byproduct fuel, is unable to comply with the applicable
NOX emission standard determined using table 1 to this
subpart.
(2) If the Administrator or delegated authority approves the
request, a facility-specific NOX emissions standard will be
established in a manner that the Administrator or delegated authority
determines to be consistent with minimizing NOX emissions.
0
12. Revise Sec. 60.4325 to read as follows:
Sec. 60.4325 What emission limits must I meet for NOX if my turbine
burns both natural gas and distillate oil (or some other combination of
fuels)?
You must meet the emission limits specified in table 1 to this
subpart. If your turbine operates below 75 percent of the peak load at
any point during an operating hour, the part load standard is
applicable during the entire operating hour. For non-part load
operating hours, if your heat input is greater than or equal to 50
percent fuels other than natural gas at any point during an operating
hour, you must meet the corresponding limit for fuels other than
natural gas for that operating hour. For non-part load operating hours
when your total heat input is greater than 50 percent natural gas for
the entire operating hour while combusting some portion of non-natural
gas fuels, you must meet the corresponding emissions standard as
determined by prorating the applicable NOX standards, based
on the applicable size category in table 1 to this subpart, by the heat
input from each fuel type.
0
13. Amend Sec. 60.4330 by revising the section heading and paragraph
(a)(3) and adding paragraph (c) to read as follows:
Sec. 60.4330 What emission limits must I meet for sulfur dioxide
(SO2)?
(a) * * *
(3) For each stationary combustion turbine burning 50 percent or
more biogas and/or low-Btu gas on a calendar month basis, as determined
based on total heat input, you must not cause to be discharged into the
atmosphere from the affected source any gases that contain
SO2 in excess of:
(i) 650 milligrams of sulfur per standard cubic meter (mg/scm) (28
grains (gr) of sulfur per 100 standard cubic feet (scf)); or
(ii) 65 ng SO2/J (0.15 lb SO2/MMBtu) heat
input.
* * * * *
(c) A stationary combustion turbine subject to either subpart J or
Ja of this part is not subject to the SO2 performance
standards in this subpart.
0
14. Add Sec. 60.4331 to read as follows:
Sec. 60.4331 What are the requirements for operating a stationary
temporary combustion turbine?
(a) Notwithstanding any other provision of this subpart, you may
operate a small- or medium-size stationary combustion turbine (i.e.,
combustion turbine with a base load rating less than or equal to 850
MMBtu/h) at a single location for up to 24 consecutive months, so long
as you comply with all of the requirements in paragraphs (b) through
(e) of this section.
(b) You must meet the NOX emissions standard for
stationary temporary combustion turbines in table 1 to this subpart and
the applicable SO2 emissions standard in Sec. 60.4330.
(c) Unless you elect to demonstrate compliance through the
otherwise-applicable monitoring, recordkeeping, and reporting
requirements of this subpart, compliance with the NOX
emissions standard must be demonstrated through maintaining the
documentation in paragraphs (c)(1) and (2) of this section on-site:
(1) Each stationary temporary combustion turbine has a
manufacturer's emissions guarantee at or below the full load
NOX emissions standard in table 1 to this subpart; and
(2) Each such turbine has been performance tested at least once in
the prior 5 years as meeting the NOX emissions standard in
table 1 to this subpart.
(d) Unless you elect to demonstrate compliance through the
otherwise-applicable monitoring, recordkeeping, and reporting
requirements of this subpart, compliance with the SO2
emissions standard must be demonstrated through complying with the
provisions in Sec. 60.4365.
(e) The conditions in paragraphs (e)(1) through (3) of this section
apply in determining whether your stationary combustion turbine
qualifies as a stationary temporary combustion turbine.
(1) The turbine may only be located at the same stationary source
(or group of stationary sources located within a contiguous area and
under common control) for a total period of 24 consecutive months. This
is the total period of residence time allowed after the turbine
commences operation at the location, regardless of whether the turbine
is in operation for the entire 24-consecutive-month period.
(2) Any temporary combustion turbine that replaces a temporary
combustion turbine at a stationary source and performs the same or
similar function will be included in calculating the consecutive time
period.
(3) The relocation of a stationary temporary combustion turbine
within a single stationary source (or a group of stationary sources
located within a contiguous area and under common control) while
performing the same or similar function (i.e., serving the same
electric, mechanical, or thermal load) does not restart the 24-
calendar-month residence time period.
0
15. Amend Sec. 60.4333 by revising paragraph (b) to read as follows:
Sec. 60.4333 What are my general requirements for complying with
this subpart?
* * * * *
(b) For multiple combustion turbines and with a common heat
recovery unit, heat recovery units utilizing a common steam header, or
using a common stack, the owner or operator shall either:
(1) Determine compliance with the applicable NOX
emissions limits by measuring the emissions combined with the emissions
from the other unit(s) utilizing the common heat recovery unit. The
applicable emissions standard for the affected facility is equal to the
prorated (by heat input) emissions standards of each of the individual
combustion turbine engines that are exhausted through the single heat
recovery steam generating unit;
[[Page 1980]]
(2) For combustion turbines complying with an output-based
standard, develop, demonstrate, and provide information satisfactory to
the Administrator on methods for apportioning the combined gross energy
output from the heat recovery unit for each of the affected combustion
turbines. The Administrator may approve such demonstrated substitute
methods for apportioning the combined gross energy output measured at
the steam turbine whenever the demonstration ensures accurate
estimation of emissions related under this part; or
(3) Monitor each combustion turbine separately by measuring the
NOX emissions prior to mixing in the common stack.
0
16. Amend Sec. 60.4335 by adding paragraph (b)(5) to read as follows:
Sec. 60.4335 How do I demonstrate compliance for NOX if I use water
or steam injection?
* * * * *
(b) * * *
(5) For affected units that are also regulated under part 75 of
this chapter, the NOX emission rate may be monitored using a
NOX diluent CEMS that is installed and certified in
accordance with appendix A to part 75 and the QA program in appendix E
to part 75, or the low mass emissions methodology in Sec. 75.19 of
this chapter.
0
17. Amend Sec. 60.4340 by revising paragraphs (a) and (b)(2)(iv) to
read as follows:
Sec. 60.4340 How do I demonstrate continuous compliance for NOX if I
do not use water or steam injection?
(a) Except as provided for in paragraphs (a)(1) through (4) of this
section, if you are not using water or steam injection to control
NOX emissions, you must perform annual performance tests (no
more than 14 calendar months following the previous performance test)
in accordance with Sec. 60.4400 to demonstrate continuous compliance.
(1) If the NOX emission result from the performance test
is less than or equal to 75 percent of the NOX emission
limit for the turbine, you may reduce the frequency of subsequent
performance tests to once every 2 years (no more than 26 calendar
months following the previous performance test). If the results of any
subsequent performance test exceed 75 percent of the NOX
emission limit for the turbine, you must resume annual performance
tests.
(2) An affected facility that has not operated for the 60 calendar
days prior to the due date of a performance test is not required to
perform the subsequent performance test until 45 calendar days after
the next operating day. The Administrator or delegated authority must
be notified of recommencement of operation consistent with Sec.
60.4375(d).
(3) If you own or operate an affected facility that has operated
168 operating hours or less in total or with a particular fuel since
the date the previous performance test was required to be conducted,
you may request an extension from the otherwise required performance
test until after the affected facility has operated more than 168
operating hours in total or with a particular fuel since the date of
the previous performance test was required to be conducted. A request
for an extension under this paragraph (a)(3) must be addressed to the
relevant air division or office director of the appropriate Regional
Office of the U.S. EPA as identified in Sec. 60.4(a) for his or her
approval at least 30 calendar days prior to the date on which the
performance test is required to be conducted. If an extension is
approved, a performance test must be conducted within 45 calendar days
after the day the facility reaches 168 hours of operation since the
date the previous performance test was required to be conducted. When
the facility has operated more than 168 operating hours since the date
the previous performance test was required to be conducted, the
Administrator or delegated authority must be notified consistent with
Sec. 60.4375(d).
(4) For a facility at which a group consisting of no more than five
similar stationary combustion turbines (i.e., same manufacturer and
model number) is operated, you may request the use of a custom testing
schedule by submitting a written request to the Administrator or
delegated authority. The minimum requirements of the custom schedule
include the conditions specified in paragraphs (a)(4)(i) through (v) of
this section.
(i) Emissions from the most recent performance test for each
individual affected facility are 75 percent or less of the applicable
standard;
(ii) Each stationary combustion turbine uses the same emissions
control technology;
(iii) Each stationary combustion turbine is operated in a similar
manner;
(iv) Each stationary combustion turbine and its emissions control
equipment are maintained according to the manufacturer's recommended
maintenance procedures; and
(v) A performance test is conducted on each facility at least once
every 5 calendar years.
(b) * * *
(2) * * *
(iv) For affected units that are also regulated under part 75 of
this chapter, you can monitor the NOX emission rate using
the methodology in appendix E to part 75, or the low mass emissions
methodology in Sec. 75.19 of this chapter, the requirements of this
paragraph (b) may be met by performing the parametric monitoring
described in section 2.3 of appendix E to part 75 or in Sec.
75.19(c)(1)(iv)(H).
0
18. Amend Sec. 60.4345 by revising paragraphs (a), (c), and (e) to
read as follows:
Sec. 60.4345 What are the requirements for the continuous emission
monitoring system equipment, if I choose to use this option?
* * * * *
(a) Each NOX diluent CEMS must be installed and
certified according to Performance Specification 2 (PS 2) in appendix B
to this part, except the 7-day calibration drift is based on unit
operating days, not calendar days. Procedure 1 in appendix F to this
part is not required. Alternatively, a NOX diluent CEMS that
is installed and certified according to appendix A to part 75 of this
chapter is acceptable for use under this subpart. The relative accuracy
test audit (RATA) of the CEMS shall be performed on a lb/MMBtu basis.
* * * * *
(c) Each fuel flowmeter shall be installed, calibrated, maintained,
and operated according to the manufacturer's instructions.
Alternatively, fuel flowmeters that meet the installation,
certification, and quality assurance requirements of appendix D to part
75 of this chapter are acceptable for use under this subpart.
* * * * *
(e) The owner or operator shall develop and keep on-site a quality
assurance (QA) plan for all of the continuous monitoring equipment
described in paragraphs (a), (c), and (d) of this section. For the CEMS
and fuel flow meters, the owner or operator may satisfy the
requirements of this paragraph (e) by implementing the QA program and
plan described in section 1 of appendix B to part 75 of this chapter.
0
19. Amend Sec. 60.4350 by:
0
a. Removing and reserving paragraph (c); and
0
b. Revising paragraphs (d) and (f)(1).
The revisions read as follows:
[[Page 1981]]
Sec. 60.4350 How do I use data from the continuous emission
monitoring equipment to identify excess emissions?
* * * * *
(d) If you have installed and certified a NOX diluent CEMS to meet
the requirements of part 75 of this chapter, only quality assured data
from the CEMS shall be used to identify excess emissions under this
subpart. Periods where the missing data substitution procedures in
subpart D of part 75 are applied are to be reported as monitor downtime
in the excess emissions and monitoring performance report required
under Sec. 60.7(c).
* * * * *
(f) * * *
(1) For simple-cycle operation:
Equation 1 to Paragraph (f)(1)
[GRAPHIC] [TIFF OMITTED] TR15JA26.017
Where:
E = hourly NOX emission rate, in lb/MWh;
(NOX)h = hourly NOX emission rate, in lb/
MMBtu;
(HI)h = hourly heat input rate to the unit, in MMBtu/h, measured
using the fuel flowmeter(s), e.g., calculated using Equation D-15a
in appendix D to part 75 of this chapter; and
P = gross energy output of the combustion turbine in MW. For an hour
in which there is zero electrical load, you may calculate the
pollutant emission rate using a default electrical load value
equivalent to 5 percent of the maximum sustainable electrical load
of the turbine.
* * * * *
0
20. Amend Sec. 60.4355 by revising paragraph (b) to read as follows:
Sec. 60.4355 How do I establish and document a proper parameter
monitoring plan?
* * * * *
(b) For affected units that are also subject to part 75 of this
chapter, you may meet the requirements of this paragraph (b) by
developing and keeping on-site (or at a central location for unmanned
facilities) a QA plan, as described in Sec. 75.19(e)(5) of this
chapter or in section 2.3 of appendix E to part 75 and section 1.3.6 of
appendix B to part 75.
0
21. Revise Sec. 60.4360 to read as follows:
Sec. 60.4360 How do I determine the total sulfur content of the
turbine's combustion fuel?
You must monitor the total sulfur content of the fuel being fired
in the turbine, except as provided in Sec. 60.4365. The sulfur content
of the fuel must be determined using total sulfur methods described in
Sec. 60.4415. Alternatively, if the total sulfur content of the
gaseous fuel during the most recent performance test was less than half
the applicable limit, ASTM D4084-05, D4810-88 (Reapproved 1999), D5504-
01, or D6228-98 (Reapproved 2003), or Gas Processors Association
Standard 2377-86 (all of which are incorporated by reference, see Sec.
60.17), which measure the major sulfur compounds, may be used.
0
22. Amend Sec. 60.4375 by revising paragraph (b) and adding paragraphs
(c) through (j) to read as follows:
Sec. 60.4375 What reports must I submit?
* * * * *
(b) The notification requirements of Sec. 60.8 apply to the
initial and subsequent performance tests.
(c) An owner or operator of an affected facility complying with
Sec. 60.4340(a)(2) must notify the Administrator or delegated
authority within 15 calendar days after the facility recommences
operation.
(d) An owner or operator of an affected facility complying with
Sec. 60.4340(a)(3) must notify the Administrator or delegated
authority within 15 calendar days after the facility has operated more
than 168 operating hours since the date the previous performance test
was required to be conducted.
(e) Beginning on [March 16, 2026, within 60 days after the date of
completing each performance test or continuous emissions monitoring
systems (CEMS) performance evaluation that includes a RATA, you must
submit the results following the procedures specified in paragraph (g)
of this section. You must submit the report in a file format generated
using the EPA's Electronic Reporting Tool (ERT). Alternatively, you may
submit an electronic file consistent with the extensible markup
language (XML) schema listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) accompanied by the other information required by Sec.
60.8(f)(2) in PDF format.
(f) You must submit to the Administrator semiannual reports of the
following recorded information. Beginning on January 15, 2027, or once
the report template for this subpart has been available on the
Compliance and Emissions Data Reporting Interface (CEDRI) website
(https://www.epa.gov/electronic-reporting-air-emissions/cedri) for one
year, whichever date is later, submit all subsequent reports using the
appropriate electronic report template on the CEDRI website for this
subpart and following the procedure specified in paragraph (g) of this
section. The date report templates become available will be listed on
the CEDRI website. Unless the Administrator or delegated State agency
or other authority has approved a different schedule for submission of
reports, the report must be submitted by the deadline specified in this
subpart, regardless of the method in which the report is submitted.
(g) If you are required to submit notifications or reports
following the procedure specified in this paragraph (g), you must
submit notifications or reports to the EPA via CEDRI, which can be
accessed through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/). The EPA will make all the information submitted through
CEDRI available to the public without further notice to you. Do not use
CEDRI to submit information you claim as CBI. Although we do not expect
persons to assert a claim of CBI, if you wish to assert a CBI claim for
some of the information in the report or notification, you must submit
a complete file in the format specified in this subpart, including
information claimed to be CBI, to the EPA following the procedures in
paragraphs (g)(1) and (2) of this section. Clearly mark the part or all
of the information that you claim to be CBI. Information not marked as
CBI may be authorized for public release without prior notice.
Information marked as CBI will not be disclosed except in accordance
with procedures set forth in 40 CFR part 2. All CBI claims must be
asserted at the time of submission. Anything submitted using CEDRI
cannot later be claimed CBI. Furthermore, under CAA section 114(c),
emissions data is not entitled to confidential treatment, and the EPA
is required to make emissions data available to the public. Thus,
emissions data will not be protected as CBI and will be made publicly
available. You must submit the same file submitted to the CBI office
with the CBI omitted to the EPA via the EPA's CDX as described earlier
in this paragraph (g).
(1) The preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol, or
other online file sharing services. Electronic submissions must be
transmitted directly to the OAQPS CBI Office at the email address
[email protected], and as described above, should include clear CBI
markings. ERT files should be flagged to the attention of the Group
Leader, Measurement Policy Group; all other files should be flagged to
the attention of the Stationary Combustion Turbine Sector Lead. If
assistance is needed with submitting large electronic
[[Page 1982]]
files that exceed the file size limit for email attachments, and if you
do not have your own file sharing service, please email
[email protected] to request a file transfer link.
(2) If you cannot transmit the file electronically, you may send
CBI information through the postal service to the following address:
U.S. EPA, Attn: OAQPS Document Control Office, Mail Drop: C404-02, 109
T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711. In addition to the
OAQPS Document Control Officer, ERT files should also be sent to the
attention of the Group Leader, Measurement Policy Group, and all other
files should also be sent to the attention of the Stationary Combustion
Turbine Sector Lead. The mailed CBI material should be double wrapped
and clearly marked. Any CBI markings should not show through the outer
envelope.
(h) If you are required to electronically submit a report through
CEDRI in EPA's CDX, you may assert a claim of EPA system outage for
failure to timely comply with that reporting requirement. To assert a
claim of EPA system outage, you must meet the requirements outlined in
paragraphs (h)(1) through (7) of this section.
(1) You must have been or will be precluded from accessing CEDRI
and submitting a required report within the time prescribed due to an
outage of either the EPA's CEDRI or CDX systems.
(2) The outage must have occurred within the period of time
beginning 5 business days prior to the date that the submission is due.
(3) The outage may be planned or unplanned.
(4) You must submit notification to the Administrator in writing as
soon as possible following the date you first knew, or through due
diligence should have known, that the event may cause or has caused a
delay in reporting.
(5) You must provide to the Administrator a written description
identifying:
(i) The date(s) and time(s) when CDX or CEDRI was accessed and the
system was unavailable;
(ii) A rationale for attributing the delay in reporting beyond the
regulatory deadline to EPA system outage;
(iii) A description of measures taken or to be taken to minimize
the delay in reporting; and
(iv) The date by which you propose to report, or if you have
already met the reporting requirement at the time of the notification,
the date you reported.
(6) The decision to accept the claim of EPA system outage and allow
an extension to the reporting deadline is solely within the discretion
of the Administrator.
(7) In any circumstance, the report must be submitted
electronically as soon as possible after the outage is resolved.
(i) If you are required to electronically submit a report through
CEDRI in the EPA's CDX, you may assert a claim of force majeure for
failure to timely comply with that reporting requirement. To assert a
claim of force majeure, you must meet the requirements outlined in
paragraphs (i)(1) through (5) of this section.
(1) You may submit a claim if a force majeure event is about to
occur, occurs, or has occurred or there are lingering effects from such
an event within the period of time beginning five business days prior
to the date the submission is due. For the purposes of this section, a
force majeure event is defined as an event that will be or has been
caused by circumstances beyond the control of the affected facility,
its contractors, or any entity controlled by the affected facility that
prevents you from complying with the requirement to submit a report
electronically within the time period prescribed. Examples of such
events are acts of nature (e.g., hurricanes, earthquakes, or floods),
acts of war or terrorism, or equipment failure or safety hazard beyond
the control of the affected facility (e.g., large-scale power outage).
(2) You must submit notification to the Administrator in writing as
soon as possible following the date you first knew, or through due
diligence should have known, that the event may cause or has caused a
delay in reporting.
(3) You must provide to the Administrator:
(i) A written description of the force majeure event;
(ii) A rationale for attributing the delay in reporting beyond the
regulatory deadline to the force majeure event;
(iii) A description of measures taken or to be taken to minimize
the delay in reporting; and
(iv) The date by which you propose to report, or if you have
already met the reporting requirement at the time of the notification,
the date you reported.
(4) The decision to accept the claim of force majeure and allow an
extension to the reporting deadline is solely within the discretion of
the Administrator.
(5) In any circumstance, the reporting must occur as soon as
possible after the force majeure event occurs.
(j) Any records required to be maintained by this subpart that are
submitted electronically via the EPA's CEDRI may be maintained in
electronic format. This ability to maintain electronic copies does not
affect the requirement for facilities to make records, data, and
reports available upon request to a delegated air agency or the EPA as
part of an on-site compliance evaluation.
0
23. Amend Sec. 60.4380 by revising paragraph (b)(3) to read as
follows:
Sec. 60.4380 How are excess emissions and monitor downtime defined
for NOX?
* * * * *
(b) * * *
(3) For averaging periods during which multiple emissions standards
apply, the applicable standard for the averaging period is the heat
input weighted average of the applicable standards during each hour.
For hours with multiple emission standards, the applicable limit for
that hour is determined based on the condition that corresponded to the
highest emissions standard.
* * * * *
0
24. Revise Sec. 60.4395 to read as follows:
Sec. 60.4395 What must I submit my reports?
All reports required under Sec. 60.7(c) must be electronically
submitted via CEDRI by the 30th day following the end of each 6-month
period.
0
25. Amend Sec. 60.4400 by revising paragraphs (a)(1)(i) and (ii) and
(b)(2) to read as follows:
Sec. 60.4400 How do I conduct the initial and subsequent performance
tests, regarding NOX?
(a) * * *
(1) * * *
(i) Measure the NOX concentration (in parts per million
(ppm)), using EPA Method 7E in appendix A-4 to this part, EPA Method 20
in appendix A-7 to this part, EPA Method 320 in appendix A of part 63
of this chapter, or ASTM D6348-12 (Reapproved 2020) (incorporated by
reference, see Sec. 60.17). For units complying with the output-based
standard, concurrently measure the stack gas flow rate, using EPA
Methods 1 and 2 in appendix A to this part, and measure and record the
electrical and thermal output from the unit. Then, use the following
equation to calculate the NOX emission rate:
Equation 1 to Paragraph (a)(1)(i)
[[Page 1983]]
[GRAPHIC] [TIFF OMITTED] TR15JA26.018
Where:
E = NOX emission rate, in lb/MWh;
1.194 x 10-\7\ = conversion constant, in lb/dscf-ppm;
(NOX)c = average NOX concentration
for the run, in ppm;
Qstd = stack gas volumetric flow rate, in dscf/hr; and
P = gross electrical and mechanical energy output of the combustion
turbine, in MW (for simple cycle operation), for combined cycle
operation, the sum of all electrical and mechanical output from the
combustion and steam turbines, or, for combined heat and power
operation, the sum of all electrical and mechanical output from the
combustion and steam turbines plus all useful recovered thermal
output not used for additional electric or mechanical generation, in
MW, calculated according to Sec. 60.4350(f)(2); or
(ii) Measure the NOX and diluent gas concentrations,
using either EPA Methods 7E and 3A or EPA Method 20 in appendix A to
this part. In addition, when only natural gas is being combusted, ASTM
D6522-20 (incorporated by reference, see Sec. 60.17) can be used
instead of EPA Method 3A in appendix A-2 to this part or EPA Method 20
in appendix A-7 to this part to determine the oxygen content in the
exhaust gas. Concurrently measure the heat input to the unit, using a
fuel flowmeter (or flowmeters), and measure the electrical and thermal
output of the unit. Use EPA Method 19 in appendix A to this part to
calculate the NOX emission rate in lb/MMBtu. Then, use
equations 1 and, if necessary, 2 and 3 in Sec. 60.4350(f) to calculate
the NOX emission rate in lb/MWh.
* * * * *
(b) * * *
(2) For a combined cycle and CHP turbine systems with supplemental
heat (duct burner), you must measure the total NOX emissions
after the duct burner rather than directly after the turbine. The duct
burner must be in operation within 25 percent of 100 percent of the
peak load rating of the duct burners or the highest achievable load if
at least 75 percent of the peak load of the duct burners cannot be
achieved during the performance test.
* * * * *
0
26. Amend Sec. 60.4405 by revising paragraph (a) to read as follows:
Sec. 60.4405 How do I perform the initial performance test if I have
chosen to install a NOX-diluent CEMS?
* * * * *
(a) Perform a minimum of nine RATA reference method runs, with a
minimum time per run of 21 minutes, at a single load level, within plus
or minus 25 percent of 100 percent of peak load, while the source is
combusting the fuel that is a normal primary fuel for that source. The
ambient temperature must be greater than 0 [deg]F during the RATA runs.
* * * * *
0
27. Amend Sec. 60.4415 by revising paragraphs (a) introductory text
and (a)(2) through (4) to read as follows:
Sec. 60.4415 How do I conduct the initial and subsequent performance
tests for sulfur?
(a) You must conduct an initial performance test, as required in
Sec. 60.8. An owner or operator of an affected facility complying with
the fuel-based standard may use fuel records (such as a current, valid
purchase contract, tariff sheet, transportation contract, or results of
a fuel analysis) to satisfy the requirements of Sec. 60.8. Subsequent
SO2 performance tests shall be conducted on an annual basis
(no more than 14 calendar months following the previous performance
test). There are four methodologies that you may use to conduct the
performance tests.
* * * * *
(2) Periodically determine the sulfur content of the fuel combusted
in the turbine, a representative fuel sample may be collected either by
an automatic sampling system or manually. For automatic sampling,
follow ASTM D5287-97 (Reapproved 2002) (incorporated by reference, see
Sec. 60.17) for gaseous fuels or ASTM D4177-95 (Reapproved 2000)
(incorporated by reference, see Sec. 60.17) for liquid fuels. For
manual sampling of gaseous fuels, follow API Manual of Petroleum
Measurement Standards, Chapter 14, Section 1; GPA 2166-17; or ISO
10715:1997(E) (all incorporated by reference, see Sec. 60.17). For
manual sampling of liquid fuels, follow GPA 2174-14 or the procedures
for manual pipeline sampling in section 14 of ASTM D4057-95 (Reapproved
2000) (both incorporated by reference, see Sec. 60.17). The fuel
analyses of this section may be performed either by you, a service
contractor retained by you, the fuel vendor, or any other qualified
agency. Analyze the samples for the total sulfur content of the fuel
using:
(i) For liquid fuels, ASTM D129-00 (Reapproved 2005), or
alternatively D1266-98 (Reapproved 2003), D1552-03, D2622-05, D4294-03,
D5453-05, D5623-19, or D7039-15a (all incorporated by reference, see
Sec. 60.17); or
(ii) For gaseous fuels, ASTM D1072-90 (Reapproved 1999), or
alternatively D3246-05, D4084-05, D4468-85 (Reapproved 2000), D4810-88
(Reapproved 1999), D6228-98 (Reapproved 2003), D6667-04, or GPA 2140-
17, 2261-19, or 2377-86 (all incorporated by reference, see Sec.
60.17).
(3) Measure the SO2 concentration (in parts per million
(ppm)), using EPA Method 6, 6C, 8, or 20 in appendix A to this part.
For units complying with the output-based standard, concurrently
measure the stack gas flow rate, using EPA Methods 1 and 2 in appendix
A to this part, and measure and record the electrical and thermal
output from the unit. Then use the following equation to calculate the
SO2 emission rate:
Equation 1 to Paragraph (a)(3)
[GRAPHIC] [TIFF OMITTED] TR15JA26.019
Where:
E = SO2 emission rate, in lb/MWh;
1.664 x 10-\7\ = conversion constant, in lb/dscf-ppm;
(SO2)c = average SO2 concentration
for the run, in ppm;
Qstd = stack gas volumetric flow rate, in dscf/hr; and
P = gross electrical and mechanical energy output of the combustion
turbine, in MW (for simple-cycle operation), for combined-cycle
operation, the sum of all electrical and mechanical output from the
combustion and steam turbines, or, for combined heat and power
operation, the sum of all electrical and mechanical output from the
combustion and steam turbines plus all useful recovered thermal
output not used for additional electric or mechanical generation, in
[[Page 1984]]
MW, calculated according to Sec. 60.4350(f)(2); or
(4) Measure the SO2 and diluent gas concentrations,
using either EPA Method 6, 6C, or 8 and 3A, or 20 in appendix A to this
part. Concurrently measure the heat input to the unit, using a fuel
flowmeter (or flowmeters), and measure the electrical and thermal
output of the unit. Use EPA Method 19 in appendix A to this part to
calculate the SO2 emission rate in lb/MMBtu. Then, use
equations 1 and, if necessary, 2 and 3 in Sec. 60.4350(f) to calculate
the SO2 emission rate in lb/MWh.
* * * * *
0
28. Amend Sec. 60.4420 by:
0
a. Adding the definition of Byproduct in alphabetical order;
0
b. Revising the definitions of Duct burner and Emergency combustion
turbine;
0
c. Adding the definitions of Firefighting turbine, Garrison facility,
and Low-Btu gas in alphabetical order;
0
d. Revising the definitions of Natural gas and Noncontinental area;
0
e. Adding the definition of Offshore turbine in alphabetical order;
0
f. Revising the definition of Stationary combustion turbine; and
0
g. Adding the definition of Temporary combustion turbine in
alphabetical order.
The additions and revisions read as follows:
Sec. 60.4420 What definitions apply to this subpart?
* * * * *
Byproduct means any liquid or gaseous substance produced at
chemical manufacturing plants, petroleum refineries, pulp and paper
mills, or other industrial facilities (except natural gas and fuel
oil).
* * * * *
Duct burner means a device that combusts fuel and that is placed in
the exhaust duct from another source, such as a stationary combustion
turbine, internal combustion engine, kiln, etc., to allow the firing of
additional fuel to heat the exhaust gases.
* * * * *
Emergency combustion turbine means any stationary combustion
turbine which operates in an emergency situation. Examples include
stationary combustion turbines used to produce power for critical
networks or equipment, including power supplied to portions of a
facility, when electric power from the local utility is interrupted, or
stationary combustion turbines used to pump water in the case of fire
(e.g., firefighting turbine) or flood, etc. Emergency combustion
turbines may be operated for the purpose of maintenance checks and
readiness testing, provided that the tests are recommended by Federal,
State, or local government, agencies, or departments, voluntary
consensus standards, the manufacturer, the vendor, the regional
transmission organization or equivalent balancing authority and
transmission operator, or the insurance company associated with the
combustion turbine. Required testing of such units should be minimized,
but there is no time limit on the use of emergency combustion turbines.
Emergency combustion turbines do not include combustion turbines used
as peaking units at electric utilities or stationary combustion
turbines at industrial facilities that typically operate at low
capacity factors.
* * * * *
Firefighting turbine means any stationary combustion turbine that
is used solely to pump water for extinguishing fires.
Garrison facility means any permanent military installation.
* * * * *
Low-Btu gas means any gaseous fuels that have heating values less
than 26 megajoules per standard cubic meter (MJ/scm) (700 Btu/scf).
Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane) that maintains a gaseous state at standard
atmospheric temperature and pressure under ordinary conditions.
Additionally, natural gas must be composed of at least 70 percent
methane by volume and have a gross calorific value between 950 and
1,100 British thermal units (Btu) per standard cubic foot. Unless
refined to meet this definition of natural gas, natural gas does not
include the following gaseous fuels: landfill gas, digester gas,
refinery gas, sour gas, blast furnace gas, coal-derived gas, producer
gas, coke oven gas, or any gaseous fuel produced in a process which
might result in highly variable sulfur content or heating value.
Noncontinental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, the Northern
Mariana Islands, or offshore turbines.
Offshore turbine means a stationary combustion turbine located on a
platform or facility in an ocean, territorial sea, the outer
continental shelf, or the Great Lakes of North America and stationary
combustion turbines located in a coastal management zone and elevated
on a platform.
* * * * *
Stationary combustion turbine means all equipment, including but
not limited to the turbine, the fuel, air, lubrication and exhaust gas
systems, control systems (except emissions control equipment), heat
recovery system, and any ancillary components and sub-components
comprising any simple cycle stationary combustion turbine, any
regenerative/recuperative cycle stationary combustion turbine, any
combined cycle combustion turbine, and any combined heat and power
combustion turbine based system. Stationary means that the combustion
turbine is not self-propelled or intended to be propelled while
performing its function. It may, however, be mounted on a vehicle for
portability. Portable combustion turbines are excluded from the
definition of ``stationary combustion turbine,'' and not regulated
under this part, if the turbine meets the definition of ``nonroad
engine'' under title II of the Clean Air Act and applicable regulations
and is certified to meet emission standards promulgated pursuant to
title II of the Clean Air Act, along with all related requirements.
Temporary combustion turbine means a combustion turbine that is
intended to and remains at a single stationary source (or group of
stationary sources located within a contiguous area and under common
control) for 24 consecutive months or less.
* * * * *
0
29. Revise table 1 to subpart KKKK to read as follows:
Table 1 to Subpart KKKK of Part 60--Nitrogen Oxide Emission Limits for
New Stationary Combustion Turbines
------------------------------------------------------------------------
Combustion turbine
Combustion turbine type heat input at NOX emission
peak load (HHV) standard
------------------------------------------------------------------------
New turbine firing natural gas, <=50 MMBtu/h...... 42 ppm at 15
electric generating. percent O2 or 290
ng/J of useful
output (2.3 lb/
MWh).
[[Page 1985]]
New turbine firing natural gas, <=50 MMBtu/h...... 100 ppm at 15
mechanical drive. percent O2 or 690
ng/J of useful
output (5.5 lb/
MWh).
New turbine firing natural gas. >50 MMBtu/h and 25 ppm at 15
<=850 MMBtu/h. percent O2 or 150
ng/J of useful
output (1.2 lb/
MWh).
New, modified, or reconstructed >850 MMBtu/h...... 15 ppm at 15
turbine firing natural gas. percent O2 or 54
ng/J of useful
output (0.43 lb/
MWh)
New turbine firing fuels other <=50 MMBtu/h...... 96 ppm at 15
than natural gas, electric percent O2 or 700
generating. ng/J of useful
output (5.5 lb/
MWh).
New turbine firing fuels other <=50 MMBtu/h...... 150 ppm at 15
than natural gas, mechanical percent O2 or
drive. 1,100 ng/J of
useful output (8.7
lb/MWh).
New turbine firing fuels other >50 MMBtu/h and 74 ppm at 15
than natural gas. <=850 MMBtu/h. percent O2 or 460
ng/J of useful
output (3.6 lb/
MWh).
New, modified, or reconstructed >850 MMBtu/h...... 42 ppm at 15
turbine firing fuels other percent O2 or 160
than natural gas. ng/J of useful
output (1.3 lb/
MWh).
Modified or reconstructed <=50 MMBtu/h...... 150 ppm at 15
turbine. percent O2 or
1,100 ng/J of
useful output (8.7
lb/MWh).
Modified or reconstructed >50 MMBtu/h and 42 ppm at 15
turbine firing natural gas. <=850 MMBtu/h. percent O2 or 250
ng/J of useful
output (2.0 lb/
MWh).
Modified or reconstructed >50 MMBtu/h and 96 ppm at 15
turbine firing fuels other <=850 MMBtu/h. percent O2 or 590
than natural gas. ng/J of useful
output (4.7 lb/
MWh).
Turbines located north of the <=300 MMBtu/h or 150 ppm at 15
Arctic Circle (latitude 66.5 <=30 MW output. percent O2 or
degrees north), turbines 1,100 ng/J of
operating at less than 75 useful output (8.7
percent of peak load, modified lb/MWh).
and reconstructed offshore
turbines, and turbine
operating at temperatures less
than 0 [deg]F.
Turbines located north of the >300 MMBtu/h and 96 ppm at 15
Arctic Circle (latitude 66.5 >30 MW output. percent O2 or 590
degrees north), turbines ng/J of useful
operating at less than 75 output (4.7 lb/
percent of peak load, modified MWh).
and reconstructed offshore
turbines, and turbine
operating at temperatures less
than 0 [deg]F.
Heat recovery units operating All sizes......... 54 ppm at 15
independent of the combustion percent O2 or 110
turbine. ng/J of useful
output (0.86 lb/
MWh).
Combustion turbines bypassing >50 MMBtu/h....... 25 ppm at 15
the heat recovery unit. percent O2 or 150
ng/J of useful
output (1.2 lb/
MWh).
------------------------------------------------------------------------
0
30. Add subpart KKKKa to read as follows:
Subpart KKKKa--Standards of Performance for Stationary Combustion
Turbines
Sec.
Introduction
60.4300a What is the purpose of this subpart?
Applicability
60.4305a Does this subpart apply to my stationary combustion
turbine?
60.4310a What stationary combustion turbines are not subject to this
subpart?
Emission Standards
60.4315a What pollutants are regulated by this subpart?
60.4320a What NOX emissions standard must I meet?
60.4325a What emission limit must I meet for NOX if my
turbine burns both natural gas and distillate oil (or some other
combination of fuels)?
60.4330a What SO2 emissions standard must I meet?
60.4331a What are the requirements for operating a stationary
temporary combustion turbine?
General Compliance Requirements
60.4333a What are my general requirements for complying with this
subpart?
Monitoring
60.4335a How do I demonstrate compliance with my NOX
emissions standard without using a NOX CEMS if I use
water or steam injection?
60.4340a How do I demonstrate compliance with my NOX
emissions standard without using a NOX CEMS if I do not
use water or steam injection?
60.4342a How do I monitor NOX control operating
parameters?
60.4345a How do I demonstrate compliance with my NOX
emissions standard using a NOX CEMS?
60.4350a How do I use the NOX CEMS data to determine
excess emissions?
60.4360a How do I use fuel sulfur analysis to determine the total
sulfur content of the fuel combusted in my stationary combustion
turbine?
60.4370a How frequently must I determine the fuel sulfur content?
60.4372a How can I demonstrate compliance with my SO2
emissions standard using records of the fuel sulfur content?
60.4374a How do I demonstrate compliance with my SO2
emissions standard and determine excess emissions using a
SO2 CEMS?
Recordkeeping and Reporting
60.4375a What reports must I submit?
60.4380a How are NOX excess emissions and monitor
downtime reported?
60.4385a How are SO2 excess emissions and monitor
downtime reported?
60.4390a What records must I maintain?
60.4395a When must I submit my reports?
Performance Tests
60.4400a How do I conduct performance tests to demonstrate
compliance with my NOX emissions standard if I do not
have a NOX CEMS?
60.4405a How do I conduct a performance test if I use a
NOX CEMS?
60.4415a How do I conduct performance tests to demonstrate
compliance with my SO2 emissions standard?
Other Requirements and Information
60.4416a What parts of the general provisions apply to my affected
EGU?
60.4417a Who implements and enforces this subpart?
60.4420a What definitions apply to this subpart?
Table 1 to Subpart KKKKa of Part 60--Nitrogen Oxide Emission
Standards for Stationary Combustion Turbines
Table 2 to Subpart KKKKa of Part 60--Alternative Mass-Based
NOX Emission Standards for Stationary Combustion Turbines
Table 3 to Subpart KKKKa of Part 60--Applicability of Subpart A of
This Part to This Subpart
Introduction
Sec. 60.4300a What is the purpose of this subpart?
This subpart establishes emission standards and compliance
schedules for the control of emissions from stationary combustion
turbines that commenced
[[Page 1986]]
construction, modification, or reconstruction after December 13, 2024.
Applicability
Sec. 60.4305a Does this subpart apply to my stationary combustion
turbine?
(a) Except as provided for in Sec. 60.4310a, you are subject to
this subpart if you own or operate a stationary combustion turbine that
commenced construction, modification, or reconstruction after December
13, 2024, and that has a base load rating equal to or greater than 10.7
gigajoules per hour (GJ/h) (10 million British thermal units per hour
(MMBtu/h)). Any additional heat input from duct burners used with heat
recovery steam generating (HRSG) units or fuel preheaters is not
included in the heat input value used to determine the applicability of
this subpart to a given stationary combustion turbine. However, this
subpart does apply to emissions from any associated HRSG and duct
burner(s) that are associated with a combustion turbine subject to this
subpart.
(b) A stationary combustion turbine subject to this subpart is not
subject to subpart GG or KKKK of this part.
(c) Duct burners are not subject to subpart D, Da, Db, or Dc of
this part (as applicable) if the duct burner is used with a HRSG unit
that is part of a combustion turbine that is subject to this subpart.
(d) If you own or operate a stationary combustion turbine
(including a combined cycle combustion turbine or a CHP combustion
turbine) that commenced construction, modification, or reconstruction
on or before December 13, 2024, you may submit a written petition to
the Administrator requesting that the stationary combustion turbine
comply with the applicable requirements for modified units under this
subpart as an alternative to complying with subpart GG or KKKK of this
part, and with subparts D, Da, Db, and Dc of this part, as applicable.
If the Administrator or delegated authority approves the petitioner's
request, the affected facility must comply with the requirements for
modified units under this subpart unless the stationary combustion
turbine is reconstructed or replaced with a new facility in the future.
(e) If you own or operate a combined cycle combustion turbine or
combined heat and power combustion turbine, and changes are made after
December 13, 2024, to allow the existing combustion turbine to also
operate in simple cycle mode and those changes are determined a
modification for NSPS purposes, this subpart shall apply to the
combustion turbine only as it operates in simple cycle mode, and not to
its existing configuration in combined cycle mode.
Sec. 60.4310a What stationary combustion turbines are not subject to
this subpart?
(a) An integrated gasification combined cycle electric utility
steam generating unit subject to subpart Da of this part is not subject
to this subpart.
(b) A stationary combustion turbine used in a combustion turbine
test cell/stand, as defined in Sec. 60.4420a, is not subject to this
subpart.
(c) If any solid fuel is combusted in the HRSG, the HRSG is not
subject to this subpart.
(d) Stationary gas turbines subject to title II of the Clean Air
Act are not subject to this subpart.
Emission Standards
Sec. 60.4315a What pollutants are regulated by this subpart?
The pollutants regulated by this subpart are nitrogen oxide
(NOX) and sulfur dioxide (SO2).
Sec. 60.4320a What NOX emissions standard must I meet?
(a) Except as provided for in paragraph (c) of this section, for
each stationary combustion turbine you must not discharge into the
atmosphere from the affected facility any gases that contain an amount
of NOX that exceeds the applicable emissions standard and be
in accordance with the requirements specified in paragraph (b) of this
section. If you choose to use NOX CEMS, input-based emission
rates and standards are determined on a 4-operating-hour rolling basis
and output-based emission rates and standards are determined on a 30-
operating-day rolling basis. Mass-based emission rates are determined
on both a 4-operating-hour and 12-calendar-month rolling basis.
(b) For the purpose of determining compliance with the applicable
emissions standard, you must also meet the requirements specified in
paragraphs (b)(1) through (4) of this section, as applicable to your
affected facility.
(1) The NOX emission standard that is applicable to your
affected facility shall be determined on an operating-hour basis,
unless you elect to use the alternative provided for in paragraph
(b)(2) of this section. Determining the hourly NOX emission
standards for your affected facility requires recording hourly data and
maintaining records according to the requirements in Sec. 60.4390a.
For hours with multiple emission standards, the applicable standard for
that hour is determined based on the condition, excluding periods of
monitor downtime, that corresponds to the highest emissions standard.
For example, if your affected facility operates at 70 percent or less
of its base load rating for any portion of the hour, the emission
limit(s) in table 1 to this subpart for combustion turbines operating
at 70 percent or less of base load rating shall apply for that hour.
(2) As an alternative to the requirements specified in paragraph
(b)(1) of this section, you may elect to use the lowest NOX
emission standard that is applicable to your affected facility, as
determined using table 1 to this subpart, for the entire required
compliance period.
(3) During each operating hour when only natural gas is combusted,
you must meet the NOX emission standard as determined by the
applicable size category in table 1 or 2 to this subpart, as
applicable, which corresponds to a stationary combustion turbine firing
natural gas for that operating hour. During each operating hour when
the heat input (based on the HHV of the fuels) of the combustion
turbine engine is less than 50 percent natural gas (i.e., 50 percent or
greater non-natural gas), as defined in Sec. 60.4420a, at any point
during an operating hour, you must meet the NOX emission
standard as determined by the applicable size category in table 1 or 2
to this subpart, as applicable, which corresponds to a stationary
combustion turbine firing fuels other than natural gas for that
operating hour. During each operating hour when the heat input to the
combustion turbine engine is greater than 50 percent natural gas, as
defined in Sec. 60.4420a, during an entire operating hour while
combusting some portion of non-natural gas fuels, you must meet the
NOX emission standard as determined by prorating the
applicable NOX standards, based on the applicable size
category in table 1 or 2 to this subpart, as applicable, by the heat
input from each fuel type.
(4) If you have two or more combustion turbine engines share a
common stack, are connected to a single electric generator, or share a
steam turbine, except as provided for in paragraph (b)(4)(i) of this
section, you must monitor the hourly NOX emissions at the
common stack in lieu of monitoring each combustion turbine separately.
If you choose to comply with the output-based emissions standard, the
hourly gross or net energy output (electric, thermal, or mechanical, as
applicable) must be the sum of the hourly loads for the individual
affected combustion turbines, and you must
[[Page 1987]]
express the operating time as ``stack operating hours'' (as defined in
40 CFR 72.2). If you attain compliance with the most stringent
applicable emission standard in table 1 or 2 to this subpart, as
applicable, at the common stack, each affected combustion turbine
sharing the stack is in compliance.
(i) As an alternative to the requirements in this paragraph (b)(4),
you may either:
(A) Monitor each combustion turbine separately by measuring the
NOX emissions prior to mixing in the common stack; or
(B) Apportion the NOX emissions based on the unit's heat
input contribution to the total heat input associated with the common
stack and the appropriate F-factors. If you chose to comply with the
output-based standard, output from a common steam turbine shall be
apportioned based on the heat input to each combustion turbine. You may
also elect to develop, demonstrate, and provide information
satisfactory to the Administrator on alternate methods to apportion the
NOX emissions. The Administrator may approve such alternate
methods for apportioning the NOX emissions whenever the
demonstration ensures accurate estimation of emissions regulated under
this part.
(ii) [Reserved]
(c) Stationary combustion turbines that meet at least one of the
specifications described in paragraphs (c)(1) through (4) of this
section are exempt from the applicable NOX emission standard
in paragraphs (a) and (b) of this section.
(1) An emergency combustion turbine, as defined in Sec. 60.4420a;
(2) A stationary combustion turbine that, as determined by the
Administrator or delegated authority, is used for the research and
development of control techniques and/or efficiency improvements
relevant to stationary combustion turbine emissions; or
(3) A stationary combustion turbine that combusts byproduct fuels
for which a facility-specific NOX emissions standard has
been established by the Administrator or delegated authority according
to the requirements of paragraphs (c)(3)(i) and (ii) of this section is
exempt from the emission limits specified in tables 1 and 2 to this
subpart.
(i) You may request a facility-specific NOX emission
standard by submitting a written request to the Administrator or
delegated authority explaining why your affected facility, when
combusting the byproduct fuel, is unable to comply with the applicable
NOX emission standard determined using table 1 or 2 to this
subpart.
(ii) If the Administrator or delegated authority approves the
request, a facility-specific NOX emissions standard will be
established in a manner that the Administrator or delegated authority
determines to be consistent with minimizing NOX emissions.
(4) Military combustion turbines for use in other than a garrison
facility and military combustion turbines installed for use as military
training facilities.
(d) You must meet the applicable NOX emissions standard
to your affected facility during all times that the affected facility
is operating (including periods of startup, shutdown, and malfunction).
Sec. 60.4325a What emission limit must I meet for NOX if my turbine
burns both natural gas and distillate oil (or some other combination of
fuels)?
You must meet the emission limits specified in table 1 or 2 to this
subpart. If your turbine operates below 70 percent of the base load
rating at any point during an operating hour, the part load standard is
applicable during the entire operating hour. For non-part load
operating hours, if your stationary combustion turbine's heat input is
greater than or equal to 50 percent fuels other than natural gas at any
point during an operating hour, your combustion turbine must meet the
corresponding limit for non-natural gas. For non-part load operating
hours when your total heat input is greater than 50 percent natural gas
while combusting some portion of non-natural gas fuels, you must meet
the corresponding emissions standard as determined by prorating the
applicable NOX standards, based on the applicable size
category in table 1 or 2 to this subpart, as applicable, by the heat
input from each fuel type.
Sec. 60.4330a What SO2 emissions standard must I meet?
(a) Except as provided for in paragraphs (b) through (e) of this
section, for each new, modified, or reconstructed stationary combustion
turbine you must not cause to be discharged from the affected facility
and into the atmosphere any gases that contain an amount of
SO2 exceeding either:
(1) 110 nanograms per Joule (ng/J) (0.90 pounds per megawatt-hour
(lb/MWh)) gross energy output; or
(2) 26 ng SO2/J (0.060 lb SO2/MMBtu) heat
input.
(b) For each new, modified, or reconstructed stationary combustion
turbine combusting 50 percent or more low-Btu gas per calendar month
based on total heat input (using the HHV of the fuel), you must not
cause to be discharged from the affected facility and into the
atmosphere any gases that contain an amount of SO2 exceeding
either:
(1) 650 milligrams of sulfur per standard cubic meter (mg/scm) (28
grains (gr) of sulfur per 100 standard cubic feet (scf)); or
(2) 65 ng SO2/J (0.15 lb SO2/MMBtu) heat
input.
(c) For each new, modified, or reconstructed stationary combustion
turbine located in a noncontinental area, you must not cause to be
discharged from the affected facility and into the atmosphere any gases
that contain an amount of SO2 exceeding either:
(1) 780 ng/J (6.2 lb/MWh) gross energy output; or
(2) 180 ng SO2/J (0.42 lb SO2/MMBtu) heat
input.
(d) For each new, modified, or reconstructed stationary combustion
turbine for which the Administrator determines that the affected
facility does not have access to natural gas and that the removal of
sulfur compounds from the fuel would cause more environmental harm than
benefit, you must not cause to be discharged from the affected facility
and into the atmosphere any gases that contain an amount of
SO2 exceeding either:
(1) 780 ng/J (6.2 lb/MWh) gross energy output; or
(2) 180 ng SO2/J (0.42 lb SO2/MMBtu) heat
input.
(e) A stationary combustion turbine subject to either subpart J or
Ja of this part is not subject to the SO2 performance
standards in this subpart.
Sec. 60.4331a What are the requirements for operating a stationary
temporary combustion turbine?
(a) Notwithstanding any other provision of this subpart, you may
operate a small- or medium-size stationary combustion turbine (i.e., a
combustion turbine with a base load rating less than or equal to 850
MMBtu/h) at a single location for up to 24 consecutive months, so long
as you comply with all of the requirements in paragraphs (b) through
(e) of this section.
(b) You must meet the NOX emissions standard for
stationary temporary combustion turbines in table 1 to this subpart and
the applicable SO2 emissions standard in Sec. 60.4330a.
(c) Unless you elect to demonstrate compliance through the
otherwise-applicable monitoring, recordkeeping, and reporting
requirements of this subpart, compliance with the NOX
emissions standard must be
[[Page 1988]]
demonstrated through maintaining the documentation in paragraphs (c)(1)
and (2) of this section on-site:
(1) Each stationary temporary combustion turbine in use at the
location has a manufacturer's emissions guarantee at or below the full
load NOX emissions standard in table 1 to this subpart; and
(2) Each such turbine has been performance tested at least once in
the prior 5 years as meeting the NOX emissions standard in
table 1 to this subpart.
(d) Unless you elect to demonstrate compliance through the
otherwise-applicable monitoring, recordkeeping, and reporting
requirements of this subpart, compliance with the SO2
emissions standard must be demonstrated through complying with the
provisions in Sec. 60.4372a.
(e) The conditions in paragraphs (e)(1) through (3) of this section
apply in determining whether your stationary combustion turbine
qualifies as a stationary temporary combustion turbine.
(1) The turbine may only be located at the same stationary source
(or group of stationary sources located within a contiguous area and
under common control) for a total period of 24 consecutive months. This
is the total period of residence time allowed after the turbine
commences operation at the location, regardless of whether the turbine
is in operation for the entire 24 consecutive month period.
(2) Any temporary combustion turbine that replaces a temporary
combustion turbine at a location and performs the same or similar
function will be included in calculating the consecutive time period.
(3) The relocation of a stationary temporary combustion turbine
within a single stationary source (or group of stationary sources
located within a contiguous area and under common control) while
performing the same or similar function (i.e., serving the same
electric, mechanical, or thermal load) does not restart the 24-calendar
month residence time period.
General Compliance Requirements
Sec. 60.4333a What are my general requirements for complying with
this subpart?
(a) You must operate and maintain your stationary combustion
turbine, air pollution control equipment, and monitoring equipment in a
manner consistent with good air pollution control practices for
minimizing emissions at all times, including during startup, shutdown,
and malfunction.
(b) If you own or operate a stationary combustion turbine subject
to a NOX emissions standard in Sec. 60.4320a, you must
conduct an initial performance test according to Sec. 60.8 using the
applicable methods in Sec. 60.4400a or Sec. 60.4405a. Thereafter,
unless you perform continuous monitoring consistent with Sec.
60.4335a, Sec. 60.4340a, or Sec. 60.4345a, you must conduct
subsequent performance tests according to the applicable requirements
in paragraphs (b)(1) through (6) of this section.
(1) Except as provided for in paragraphs (b)(2) through (5) of this
section, you must conduct subsequent performance tests within 12
calendar months of the date that the previous performance test was
conducted.
(2) If the NOX emission result from the most recent
performance test is less than or equal to 75 percent of the
NOX emissions standard for the stationary combustion
turbine, you may reduce the frequency of subsequent performance tests
to 26 calendar months following the date the previous performance test
was conducted. If the results of any subsequent performance test exceed
75 percent of the NOX emissions standard for the stationary
combustion turbine, you must resume 14-calendar-month performance
testing.
(3) An affected facility that has not operated for the 60 calendar
days prior to the due date of a performance test is not required to
perform the subsequent performance test until 45 calendar days or 10
operating days, whichever is longer, after the next operating day. The
Administrator or delegated authority must be notified of recommencement
of operation consistent with Sec. 60.4375a(d).
(4) If you own or operate an affected facility that has operated
168 operating hours or less, either in total or using a particular
fuel, since the date on which the previous performance test was
conducted, you may request that the otherwise required performance test
be postponed until the affected facility has operated more than 168
operating hours, either in total or using a particular fuel, since the
date on which the previous performance test was conducted. A request
for an extension under this paragraph (b)(4) must be addressed to the
relevant air division or office director of the appropriate Regional
Office of the U.S. EPA as identified in Sec. 60.4(a) for his or her
approval at least 30 calendar days prior to the date on which the
performance test is required to be conducted. If a postponement is
approved, a performance test must be conducted within 45 calendar days
after the day that the facility reaches 168 hours of operation since
the date on which the previous performance test was conducted. When the
facility has operated more than 168 operating hours since the date on
which the previous performance test was conducted, the Administrator or
delegated authority must be notified consistent with Sec. 60.4375a(e).
(5) For a facility at which a group consisting of no more than five
similar stationary combustion turbines (i.e., same manufacturer and
model number) is operated, you may request the use of a custom testing
schedule by submitting a written request to the Administrator or
delegated authority. The minimum requirements of the custom schedule
include the conditions specified in paragraphs (b)(5)(i) through (v) of
this section.
(i) Emissions from the most recent performance test for each
individual affected facility are 75 percent or less of the applicable
standard;
(ii) Each stationary combustion turbine uses the same emissions
control technology;
(iii) Each stationary combustion turbine is operated in a similar
manner;
(iv) Each stationary combustion turbine and its emissions control
equipment are maintained according to the manufacturer's recommended
maintenance procedures; and
(v) A performance test is conducted on each affected facility at
least once every 5 calendar years.
(6) A stationary combustion turbine subject to a NOX
emissions standard in Sec. 60.4320a that exchanges the combustion
turbine engine for an overhauled combustion turbine engine as part of
an exchange program, must conduct an initial performance test according
to Sec. 60.8 using the applicable methods in Sec. 60.4400a or Sec.
60.4405a. (as applicable).
(c) Except as provided for in paragraph (c)(1) or (2) of this
section, for each stationary combustion turbine subject to a
NOX emissions standard in Sec. 60.4320a, you must
demonstrate continuous compliance using a continuous emissions
monitoring system (CEMS) for measuring NOX emissions
according to the provisions in Sec. 60.4345a. If your stationary
combustion turbine is equipped with a NOX CEMS, those
measurements must be used to determine excess emissions.
(1) If your stationary combustion turbine uses water or steam
injection but not post-combustion controls to meet the applicable
NOX emissions standard in Sec. 60.4320a, you may elect to
demonstrate continuous compliance using the pounds per million British
thermal units (lb/MMBtu) or parts per million (ppm) input-based
standard
[[Page 1989]]
according to the provisions in Sec. 60.4335a.
(2) If your stationary combustion turbine does not use water
injection, steam injection, or post-combustion controls to meet the
applicable NOX emissions standard in Sec. 60.4320a, you may
elect to demonstrate continuous compliance with an input-based standard
according to the provisions in Sec. 60.4340a.
(d) An owner or operator of a stationary combustion turbine subject
to an SO2 emissions standard in Sec. 60.4330a must
demonstrate compliance using one of the methods specified in paragraphs
(d)(1) through (4) of this section.
(1) Conduct an initial performance test according to Sec. 60.8 and
use the applicable methods in Sec. 60.4415a. Thereafter, you must
conduct subsequent performance tests within 12 calendar months
following the date the previous performance test was conducted. An
affected facility that has not operated for the 60 calendar days prior
to the due date of a performance test is not required to perform the
subsequent performance test until 45 calendar days after the next
operating day;
(2) Conduct an initial performance test according to Sec. 60.8 and
use the applicable methods in Sec. 60.4415a. Thereafter, conduct
subsequent fuel sulfur analyses using the applicable methods specified
in Sec. 60.4360a and at the frequency specified in Sec. 60.4370a;
(3) Conduct an initial performance test according to Sec. 60.8 and
use the applicable methods in Sec. 60.4415a. Thereafter, maintain
records (such as a current, valid purchase contract, tariff sheet, or
transportation contract) documenting that total sulfur content for the
initial and subsequent fuel combusted in your stationary combustion
turbine at all times does not exceed applicable conditions specified in
Sec. 60.4370a; or
(4) Conduct an initial performance test according to Sec. 60.8
using the applicable methods in Sec. 60.4415a. Thereafter, continue to
monitor SO2 emissions using a CEMS according to the
requirements specified in Sec. 60.4374a.
(e) If you elect to comply with an input-based standard (lb/MMBtu
or ppm) and your affected facility includes use of one or more heat
recovery steam generating units, then you must determine compliance
with the applicable NOX and SO2 emission
standards according to the procedures specified in paragraph (e)(1) or
(2) of this section as applicable to the heat recovery steam generating
unit configuration used for your affected facility.
(1) For a configuration where a single combustion turbine engine is
exhausted through the heat recovery steam generating unit, you must
measure both the emissions at the exhaust stack for the heat recovery
steam generating unit and the fuel flow to the combustion turbine
engine and any associated duct burners.
(2) For a configuration where two or more combustion turbine
engines are exhausted through a single heat recovery steam generating
unit, you must measure both the total emissions at the exhaust stack
for the heat recovery steam generating unit and the total fuel flow to
each combustion turbine engine and any associated duct burners. The
applicable emissions standard for the affected facility is equal to the
prorated (by heat input) emissions standards of each of the individual
combustion turbine engines that are exhausted through the single heat
recovery steam generating unit.
(f) If you elect to comply with an output-based standard (lb/MWh)
and your affected facility includes use of one or more heat recovery
steam generating units, then you must determine compliance with the
applicable NOX and SO2 emission standards
according to the procedures in paragraph (f)(1), (2), or (3) of this
section as applicable to the heat recovery steam generating unit
configuration used for your affected facility.
(1) For a configuration where a single combustion turbine engine is
exhausted through the heat recovery steam generating unit, you must
measure both the emissions at the exhaust stack for the heat recovery
steam generating unit and the total electrical, mechanical energy, and
useful thermal output of the stationary combustion turbine (as
applicable).
(2) For a configuration where two or more combustion turbine
engines are exhausted through a single heat recovery steam generating
unit, you must measure both the total emissions at the exhaust stack
for the heat recovery steam generating unit, and the total electrical,
mechanical energy, and useful thermal output of the heat recovery steam
generating unit and each combustion turbine engine (as applicable). The
applicable emissions standard for the affected facility is equal to the
most stringent emissions standard for any individual combustion turbine
engines.
(3) For a configuration where your combustion turbine engines are
exhausted through two or more heat recovery steam generating units
which serve a common steam turbine or steam header, you must measure
both the emissions at the exhaust stack for each heat recovery steam
generating unit and the total electrical or mechanical energy output of
each combustion turbine engine (as applicable). To determine the net or
gross energy output of the steam produced by the heat recovery steam
generating unit, you must develop a custom method and provide
information, satisfactory to the Administrator or delegated authority,
apportioning the net or gross energy output of the steam produced by
the heat recovery steam generating units to each of the affected
stationary combustion turbines.
(g) If you elect to comply with the mass-based standard, you must
demonstrate continuous compliance using either a CEMS for measuring
NOX emissions according to the provisions in Sec. 60.4345a
or using the methodology in appendix E to part 75 of this chapter.
Monitoring
Sec. 60.4335a How do I demonstrate compliance with my NOX emissions
standard without using a NOX CEMS if I use water or steam injection?
If you qualify and elect to demonstrate continuous compliance
according to the provisions of Sec. 60.4333a(c)(1), you must install,
calibrate, maintain, and operate a continuous monitoring system to
monitor and record the fuel consumption and the water or steam to fuel
ratio fired in the combustion turbine engine consistent with the
requirements in Sec. 60.4342a. Water or steam only needs to be
injected when a fuel is being combusted that requires water or steam
injection for compliance with the applicable NOX emissions
standard.
Sec. 60.4340a How do I demonstrate compliance with my NOX emissions
standard without using a NOX CEMS if I do not use water or steam
injection?
(a) If you qualify and elect to demonstrate continuous compliance
according to the provisions of Sec. 60.4333a(c)(2), you must
demonstrate compliance with the NOX emissions standard using
one of the methods specified in paragraphs (a)(1) through (3) of this
section.
(1) Conduct performance tests according to requirements in Sec.
60.4400a;
(2) Monitor the NOX emissions rate using the methodology
in appendix E to part 75 of this chapter, or the low mass emissions
methodology in Sec. 75.19 of this chapter; or
(3) Install, calibrate, maintain, and operate an operating
parameter
[[Page 1990]]
continuous monitoring system according to the requirements specified in
paragraph (b) of this section and consistent with the requirements
specified in Sec. 60.4342a.
(b) If you opt to demonstrate compliance according to the
procedures described in paragraph (a)(3) of this section, continuous
operating parameter monitoring must be performed using the methods
specified in paragraphs (b)(1) through (4) of this section as
applicable to the stationary combustion turbine.
(1) Selection of the operating parameters used to comply with this
paragraph (b) must be identified in the performance test report. The
selection of operating parameters is subject to the review and approval
of the Administrator or delegated authority.
(2) For a lean premix stationary combustion turbine, you must
continuously monitor the appropriate parameters to determine whether
the unit is operating in low-NOX mode during periods when
low-NOX operation is required to comply with the applicable
emission NOX standard.
(3) For a stationary combustion turbine other than a lean premix
stationary combustion turbine, you must define parameters indicative of
the unit's NOX formation characteristics and monitor these
parameters continuously.
(4) You must perform the parametric monitoring described in section
2.3 in appendix E to part 75 of this chapter or in Sec.
75.19(c)(1)(iv)(H) of this chapter.
Sec. 60.4342a How do I monitor NOX control operating parameters?
(a) If you monitor steam or water to fuel ratio according to Sec.
60.4335a or other parameters according to Sec. 60.4340a, the
applicable parameters must be continuously monitored and recorded
during the performance test, to establish acceptable values and ranges.
You may supplement the performance test data with engineering analyses,
design specifications, manufacturer's recommendations, and other
relevant information to define the acceptable parametric ranges more
precisely. You must develop and keep on-site a parameter monitoring
plan which explains the procedures used to document proper operation of
the NOX emission controls. The plan must include the
information specified in paragraphs (a)(1) through (6) of this section:
(1) Identification of the parameters to be monitored and show there
is a significant relationship to emissions and proper operation of the
NOX emission controls;
(2) Selected parameter ranges (or designated conditions) indicative
of proper operation of the stationary combustion turbine NOX
emission controls, or describe the process by which such range (or
designated condition) will be established;
(3) Explanation of the process you will use to make certain that
you obtain data that are representative of the emissions or parameters
being monitored (such as detector location, installation specification
if applicable);
(4) Description of quality assurance and control practices used to
ensure the continuing validity of the data;
(5) Description of the frequency of monitoring and the data
collection procedures which you will use (e.g., you are using a
computerized data acquisition over a number of discrete data points
with the average (or maximum value) being used for purposes of
determining whether an exceedance has occurred); and
(6) Justification for the proposed elements of the monitoring. If a
proposed performance specification differs from manufacturer
recommendation, you must explain the reasons for the differences. You
must submit the data supporting the justification, but you may refer to
generally available sources of information used to support the
justification. You may rely on engineering assessments and other data,
provided you demonstrate factors which assure compliance or explain why
performance testing is unnecessary to establish indicator ranges.
(b) The water or steam to fuel ratio and parameter continuous
monitoring system ranges must be confirmed or reestablished at least
once every 60 calendar months following the previous calibration and
each time the combustion turbine engine is replaced with an overhauled
turbine engine as part of an exchange program. An affected facility
that has not operated for 60 calendar days prior to the due date of a
recalibration or has had the combustion turbine replaced with an
overhauled turbine engine as part of an exchange program is not
required to perform the subsequent recalibration until 45 calendar days
after the next operating day.
Sec. 60.4345a How do I demonstrate compliance with my NOX emissions
standard using a NOX CEMS?
(a) Each CEMS measuring NOX emissions used to meet the
requirements of this subpart, must meet the requirements in paragraphs
(a)(1) through (6) of this section.
(1) You must install, certify, maintain, and operate a
NOX monitor to determine the hourly average NOX
emissions in the units of the standard with which you are complying.
(2) If you elect to comply with an input-based or mass-based
emissions standard, you must install, calibrate, maintain, and operate
either a fuel flow meter (or flow meters) or an O2 or
CO2 CEMS and a stack flow monitor to continuously measure
the heat input to the affected facility.
(3) If you elect to comply with an output-based emissions standard,
you must also install, calibrate, maintain, and operate both a watt
meter (or meters) to continuously measure the gross electrical output
from the affected facility and either a fuel flow meter (or flow
meters) or an O2 or CO2 CEMS and a stack flow
monitor. If you have a CHP combustion turbine and elect to comply with
an output-based emissions standard, you must also install, calibrate,
maintain, and operate meters to continuously determine the total useful
recovered thermal energy. For steam this includes flow rate,
temperature, and pressure. If you have a direct mechanical drive
application and elect to comply with the output-based emissions
standard you must submit a plan to the Administrator or delegated
authority for approval of how energy output will be determined.
(4) If you elect to comply with the part-load NOX
emissions standard, you must install, calibrate, maintain, and operate
either a fuel flow meter (or flow meters) or an O2 or
CO2 CEMS and a stack flow monitor to continuously measure
the heat input to the affected facility.
(5) If you elect to comply with the temperature dependent
NOX emissions standard, you must install, calibrate,
maintain, and operate a thermometer to continuously monitor the ambient
temperature.
(6) If you combust natural gas with fuels other than natural gas
and elect to comply with the fuels other than natural gas
NOX emissions standard, you must install, calibrate,
maintain, and operate a device to continuously monitor when a fuel
other than natural gas fuel is combusted in the combustion turbine
engine.
(b) Each NOX CEMS must be installed and certified
according to Performance Specification 2 (PS 2) in appendix B to this
part. The span value must be 125 percent of the highest applicable
standard or highest anticipated hourly NOX emissions rate.
Alternatively, span values determined according to section 2.1.2 in
appendix A to part 75 may be used. For stationary combustion turbines
that do not use post-combustion technology to reduce emissions of
NOX to comply with the
[[Page 1991]]
requirements of this subpart, you may use NOX and diluent
CEMS that are installed and certified according to appendix A to part
75 in lieu of Procedure 1 in appendix F to this part and the
requirements of Sec. 60.13, except that the relative accuracy test
audit (RATA) of the CEMS must be performed on a lb/MMBtu basis. For
stationary combustion turbines that use post-combustion technology to
reduce emissions of NOX to comply with the requirements of
this subpart, you may use NOX and diluent CEMS that are
installed and certified according to appendix A to part 75 in lieu of
Procedure 1 in appendix F to this part and the requirements of Sec.
60.13 with approval from the Administrator or delegated authority,
except that the relative accuracy test audit (RATA) of the CEMS must be
performed on a lb/MMBtu basis.
(c) During each full operating hour, both the NOX
monitor and the diluent monitor must complete a minimum of one cycle of
operation (sampling, analyzing, and data recording) for each 15-minute
quadrant of the hour. For partial operating hours, at least one data
point must be obtained with each monitor for each quadrant of the hour
in which the unit operates. For operating hours in which required
quality assurance and maintenance activities are performed on the CEMS,
a minimum of two data points (one in each of two quadrants) are
required for each monitor.
(d) Each fuel flow meter must be installed, calibrated, maintained,
and operated according to the manufacturer's instructions.
Alternatively, fuel flow meters that meet the installation,
certification, and quality assurance requirements in appendix D to part
75 of this chapter are acceptable for use under this subpart.
(e) Each watt meter, steam flow meter, and each pressure or
temperature measurement device must be installed, calibrated,
maintained, and operated according to manufacturer's instructions.
(f) You must develop, submit to the Administrator or delegated
authority for approval, maintain, and adhere to an on-site quality
assurance (QA) plan for all of the continuous monitoring equipment you
use to comply with this subpart. At a minimum, such a QA plan must
address the requirements of Sec. 60.13(d), (e), and (h). For the CEMS
and fuel flow meters, the owner or operator of a stationary combustion
turbine that does not use post-combustion technology to reduce
emissions of NOX to comply with the requirements of this
subpart may, with approval of the Administrator or delegated authority,
satisfy the requirements of this paragraph (f) by implementing the QA
program and plan described in section 1 in appendix B to part 75 of
this chapter in lieu of the requirements in Sec. 60.13(d)(1).
(g) At a minimum, non-out-of-control CEMS hourly averages shall be
obtained for 90 percent of all operating hours on a 30-operating-day
rolling average basis.
Sec. 60.4350a How do I use the NOX CEMS data to determine excess
emissions?
(a) If you demonstrate continuous compliance using a CEMS for
measuring NOX emissions, excess emissions are defined as the
applicable compliance period for the stationary combustion turbine
(either 4-operating-hours, 30-operating-days, or 12-calendar-month),
during which the average NOX emissions from your affected
facility measured by the CEMS is greater than the applicable maximum
allowable NOX emissions standard specified in Sec. 60.4320a
as determined using the procedures specified in this section that apply
to your stationary combustion turbine.
(b) The NOX CEMS data for each operating hour as
measured according to the requirements in Sec. 60.4345a must be used
to determine the hourly average NOX emissions. The hourly
average for a given operating hour is the average of all data points
for the operating hour. However, for any periods during which the
NOX, diluent, flow, watt, steam pressure, or steam
temperature monitors (as applicable) are out-of-control, the data
points are not used in determining the hourly average NOX
emissions. All data points that are not collected during out-of-control
periods must be used to determine the hourly average NOX
emissions.
(c) For each operating hour in which an hourly average is obtained,
the data acquisition and handling system must calculate and record the
hourly average NOX emissions in units of lb/MMBtu or lbs, as
applicable, using the appropriate equation from EPA Method 19 in
appendix A-7 to this part. For any hour in which the hourly average
O2 concentration exceeds 19.0 percent O2 (or the
hourly average CO2 concentration is less than 1.0 percent
CO2), a diluent cap value of 19.0 percent O2 or
1.0 percent CO2 (as applicable) may be used in the emission
calculations.
(d) Data used to meet the requirements of this subpart shall not
include substitute data values derived from the missing data procedures
of part 75 of this chapter, nor shall the data be bias adjusted
according to the procedures of part 75. For units complying with the
12-calendar-month mass-based standard, emissions for hours of missing
data shall be estimated by using the average emissions rate of non-out-
of-control hours within 10 percent of the hour of missing
data within the 12-calendar-month period. If non-out-of-control data is
not available, the maximum hourly emissions rate during the 12-
calendar-month period shall be used.
(e) All required fuel flow rate, steam flow rate, temperature,
pressure, and megawatt data must be reduced to hourly averages.
However, for any periods during which the flow, watt, steam pressure,
or steam temperature monitors (as applicable) are out-of-control, the
data points are not used in determining the appropriate hourly average
value.
(f) Calculate the hourly average NOX emissions rate, in
units of the emissions standard under Sec. 60.4320a, using lb/MMBtu or
ppm for units complying with the input-based standard, using lbs for
units complying with the mass-based standard, or lb/MWh or kg/MWh for
units complying with the output-based standard:
(1) The gross or net energy output is calculated as the sum of the
total electrical and mechanical energy generated by the combustion
turbine engine; the additional electrical or mechanical energy (if any)
generated by the steam turbine following the heat recovery steam
generating unit; the total useful thermal energy output that is not
used to generate additional electricity or mechanical output, expressed
in equivalent MWh, minus the auxiliary load as calculated using
equations 1 and 2 to this paragraph (f)(1):
Equation 1 to Paragraph (f)(1)
[GRAPHIC] [TIFF OMITTED] TR15JA26.020
[[Page 1992]]
Where:
P = Gross or net energy output of the stationary combustion turbine
system in MWh;
(Pe)t = Electrical or mechanical energy output of the
combustion turbine engine in MWh;
(Pe)c = Electrical or mechanical energy output (if any)
of the steam turbine in MWh;
PeA = Electric energy used for any auxiliary loads in MWh
(only applicable to owners/operators electing to demonstrate
compliance on a net output basis);
Ps = Useful thermal energy of the steam, measured
relative to ISO conditions, not used to generate additional electric
or mechanical output, in MWh;
Po = Other useful heat recovery, measured relative to ISO
conditions, not used for steam generation or performance enhancement
of the stationary combustion turbine; and
T = Electric Transmission and Distribution Factor. Equal to 0.95 for
CHP combustion turbine where at least 20.0 percent of the total
gross useful energy output consists of electric or direct mechanical
output and 20.0 percent of the total gross useful energy output
consists of useful thermal output on an annual basis. Equal to 1.0
for all other combustion turbines.
Equation 2 to Paragraph (f)(1)
[GRAPHIC] [TIFF OMITTED] TR15JA26.021
Where:
Ps = Useful thermal energy of the steam, measured
relative to ISO conditions, not used to generate additional electric
or mechanical output, in MWh;
Qm = Measured steam flow in lb;
H = Enthalpy of the steam at measured temperature and pressure
relative to ISO conditions, in Btu/lb; and
3.413 x 10\6\ = Conversion factor from Btu to MWh.
(2) For mechanical drive applications complying with the output-
based standard, use equation 3 to this paragraph (f)(2):
Equation 3 to Paragraph (f)(2)
[GRAPHIC] [TIFF OMITTED] TR15JA26.022
Where:
E = NOX emissions rate in lb/MWh;
(NOX)m = NOX emissions rate in lb/
h;
BL = Manufacturer's base load rating of turbine, in MW; and
AL = Actual load as a percentage of the base load rating.
(g) For each stationary combustion turbine demonstrating compliance
on a heat input-based emissions standard, excess NOX
emissions are determined on a 4-operating-hour averaging period basis
using the NOX CEMS data and procedures specified in
paragraphs (g)(1) and (2) of this section as applicable to the
NOX emissions standard in table 1 to this subpart.
(1) For each 4-operating-hour period, compute the 4-operating-hour
rolling average NOX emissions as the heat input weighted
average of the hourly average of NOX emissions for a given
operating hour and the 3 operating hours preceding that operating hour
using the applicable equation in paragraph (g)(2) of this section.
Calculate a 4-operating-hour rolling average NOX emissions
rate for any 4-operating-hour period when you have valid CEMS data for
at least 3 of those hours (e.g., a valid 4-operating-hour rolling
average NOX emissions rate cannot be calculated if 1 or more
continuous monitors was out-of-control for the entire hour for more
than 1 hour during the 4-operating-hour period).
(2) If you elect to comply with the applicable heat input-based
emissions rate standard, calculate both the 4-operating-hour rolling
average NOX emissions rate and the applicable 4-operating-
hour rolling average NOX emissions standard, calculated
using hourly values in table 1 to this subpart, using equation 4 to
this paragraph (g)(2).
Equation 4 to Paragraph (g)(2)
[GRAPHIC] [TIFF OMITTED] TR15JA26.023
Where:
E = 4-operating-hour rolling average NOX emissions (lb/
MMBtu or ng/J);
Ei = Hourly average NOX emissions rate or
emissions standard for operating hour ``i'' (lb/MMBtu or ng/J); and
Qi = Total heat input to stationary combustion turbine
for operating hour ``i'' (MMBtu or J as appropriate).
(h)(1) For each combustion turbine demonstrating compliance on an
output-based standard, you must determine excess emissions on a 30-
operating-day rolling average basis. The measured emissions rate is the
NOX emissions measured by the CEMS for a given operating day
and the 29 operating days preceding that day. Once each day, calculate
a new 30-operating-day average measured emissions rate using all hourly
average values based on non-out-of-control NOX emission data
for all operating hours during the previous 30-operating-day operating
period. Report any 30-operating-day periods for which you have less
than 90 percent data availability as monitor downtime. If you elect to
comply with the applicable output-based emissions rate standard,
calculate the measured emissions rate using equation 5 to this
paragraph (h)(1) and calculate the applicable emissions standard using
equation 6 to this paragraph (h)(1). If you elect to comply with the
applicable output-based emissions rate standard and determine the heat
input on an hourly basis, calculate the 30-operating-day rolling
average NOX emissions rate using equation 5, and determine
the applicable 30-operating-day rolling average NOX
emissions standard, calculated using values in table 1 to this subpart,
using equation 6. Hours are not subcategorized by load for the purposes
of determining the applicable output-based standard. The emissions
standard for all hours, regardless of load, is the otherwise applicable
full load emissions standard.
Equation 5 to Paragraph (h)(1)
[GRAPHIC] [TIFF OMITTED] TR15JA26.024
Where:
E = 30-operating-day average NOX measured emissions rate
combustion turbines (lb/MWh or ng/J);
Ei = Hourly average NOX emissions rate or
emissions standard for non-out-of-control operating hour ``i'' (lb/
MMBtu or ng/J);
Qi = Total heat input to stationary combustion turbine
for non-out-of-control operating hour ``i'' (MMBtu or J as
appropriate);
Pi = Total gross or net energy output from stationary
combustion turbine for non-out-of-control operating hour ``i'' (MWh
or J); and
n = Total number of operating non-out-of-control hours in the 30-
operating-day period.
Equation 6 to Paragraph (h)(1)
[[Page 1993]]
[GRAPHIC] [TIFF OMITTED] TR15JA26.025
E = 30-operating-day rolling NOX emissions standard (lb/
MWh or kg/MWh);
ENG = 30-operating-day emissions standard for natural
gas-fired combustion turbines (lb/MWh or kg/MWh);
Enon-NG = 30-operating-day emissions standard for non-
natural gas-fired combustion turbines (lb/MWh or kg/MWh);
HNG = Hours of operation combusting natural gas during
the 30-operating-day period;
Hnon-NG = Hours of operation combusting non-natural gas
fuels during the 30-operating-day period; and
HT = Total hours of operation during the 30-operating-day
period.
(2) If you elect to comply with the applicable output-based
emissions rate standard and elect to not determine the heat input on an
hourly basis, the applicable 30-operating-day emissions rolling
NOX standard is the most stringent standard applicable to
the combustion turbine. The 30-operating-day rolling NOX
emissions rate is determined as the sum of the hourly emissions divided
by the sum of the gross or net output over the 30-operating-day period.
(i) For each combustion turbine demonstrating compliance on a mass-
based standard, you must determine excess NOX emissions on
both a rolling 4-operating-hour and rolling 12-calendar-month basis
using the NOX CEMS data and procedures specified in
paragraphs (i)(1) through (4) of this section as applicable to the
NOX emissions standard in table 2 to this subpart. In
addition, during system emergencies each combustion turbine must
determine excess NOX emissions using the procedures
specified in paragraph (i)(5) of this section.
(1) For each 4-operating-hour period, compute the 4-operating-hour
rolling NOX emissions as the sum of the hourly
NOX emissions for a given operating hour and the 3 operating
hours preceding that operating hour. Calculate a 4-operating-hour
NOX emissions rate for any 4-operating-hour period when you
have valid CEMS data for at least 3 of those hours (e.g., a valid 4-
operating-hour rolling NOX emissions rate cannot be
calculated if 1 or more continuous monitors was out-of-control for the
entire hour for more than 1 hour during the 4-operating-hour period).
(2) Calculate the applicable 4-operating-hour rolling
NOX emissions standard, calculated using hourly values in
table 2 to this subpart, using equation 7 to this paragraph (i)(2).
Equation 7 to Paragraph (i)(2)
[GRAPHIC] [TIFF OMITTED] TR15JA26.026
Where:
E = 4-operating-hour rolling NOX emissions (kg or lbs);
and
Ei = Hourly NOX emissions rate or emissions
standard for operating hour ``i'' (kg or lbs).
(3) For each 12-calendar-month period, compute the 12-calendar-
month rolling NOX emissions as the sum of the hourly
NOX emissions for a given month and the 11 calendar months
preceding the calendar month. Emissions during system emergencies are
not included when calculating the 12-calendar-month emissions rate.
(4) Calculate the applicable 12-calendar-month rolling
NOX emissions standard, calculated using hourly values in
table 2 to this subpart, using equation 8 to this paragraph (i)(4).
Heat input during system emergencies is not included when calculating
the 12-calendar-month emissions standard.
Equation 8 to Paragraph (i)(4)
[GRAPHIC] [TIFF OMITTED] TR15JA26.027
Where:
E = 12-calendar-month rolling NOX emissions (tonnes or
tons);
ENG = 12-calendar-month emissions standard for natural
gas-fired combustion turbines (tonnes or tons);
Enon-NG = 12-calendar-month emissions standard for non-
natural gas-fired combustion turbines (tonnes or tons);
HNG = Hours of operation combusting natural gas during
the 12-calendar-month period;
Hnon-NG = Hours of operation combusting non-natural gas
fuels during the 12-calendar-month period; and
HT = Total hours of operation during the 12-calendar-
month period.
(5) During system emergencies during which the owner or operator
elects to not include emissions or heat input in the 12-calendar month
calculations, the applicable average natural gas-fired emissions
standard is 0.83 lb NOX/MW-rated output (1.8 lb
NOX/MW-rated output when firing non-natural gas) or the
current emissions rate necessary to comply with the 12-calendar month
natural gas-fired emissions standard of 0.48 tons NOX/MW-
rated output (0.81 tons NOX/MW-rated output when firing non-
natural gas) whichever is more stringent. For example, if a combustion
turbine operated for 4,000 hours during the current 12-calendar month
period the applicable average natural gas-fired emissions standard
during the system emergency would be 0.24 lb NOX/MW-rated
output and the applicable average non-natural gas-fired emissions
standard during the system emergency would be 0.41 lb NOX/
MW-rated output.
Sec. 60.4360a How do I use fuel sulfur analysis to determine the
total sulfur content of the fuel combusted in my stationary combustion
turbine?
(a) If you elect to demonstrate compliance with a SO2
emissions standard according to Sec. 60.4333a(d)(2), the fuel analyses
may be performed either by you, a service contractor retained by you,
the fuel vendor, or any other qualified agency as determined by the
Administrator or delegated authority using the sampling frequency
specified in Sec. 60.4370a.
(b) Representative fuel analysis samples may be collected either by
an automatic sampling system or manually. For automatic sampling,
follow ASTM D5287-97 (Reapproved 2002) (incorporated by reference, see
Sec. 60.17) for gaseous fuels or ASTM D4177-95 (Reapproved 2000)
(incorporated by reference, see Sec. 60.17) for liquid fuels. For
reference purposes when manually collecting gaseous samples, see Gas
Processors Association Standard 2166-17 (incorporated by reference, see
Sec. 60.17). For reference purposes when manually collecting liquid
samples, see either Gas Processors Association Standard 2174-14 or the
procedures for manual pipeline sampling in section 14 of ASTM D4057-95
(Reapproved 2000) (both of which are incorporated by reference, see
Sec. 60.17).
(c) Each collected fuel analysis sample must be analyzed for the
total
[[Page 1994]]
sulfur content of the fuel and heating value using the methods
specified in paragraph (c)(1) or (2) of this section, as applicable to
the fuel type.
(1) For the sulfur content of liquid fuels, ASTM D129-00
(Reapproved 2005), or alternatively D1266-98 (Reapproved 2003), D1552-
03, D2622-05, D4294-03, D5453-05, D5623-24, or D7039-24 (all of which
are incorporated by reference, see Sec. 60.17). For the heating value
of liquid fuels, ASTM D240-19 or D4809-18 (both of which are
incorporated by reference, see Sec. 60.17); or
(2) For the sulfur content of gaseous fuels, ASTM D1072-90
(Reapproved 1999), or alternatively D3246-05, D4468-85 (Reapproved
2000), D6667-04, or D5504-20 (all of which are incorporated by
reference, see Sec. 60.17). If the total sulfur content of the gaseous
fuel during the most recent compliance demonstration was less than half
the applicable standard, ASTM D4084-05, D4810-88 (Reapproved 1999),
D5504-20, or D6228-98 (Reapproved 2003), or Gas Processors Association
Standard 2140-17 or 2377-86 (all of which are incorporated by
reference, see Sec. 60.17), which measure the major sulfur compounds,
may be used. For the heating value of gaseous fuels, ASTM D1826-94
(Reapproved 2003), or alternatively D3588-98 (Reapproved 2003), D4891-
89 (Reapproved 2006), or Gas Processors Association Standard 2172-09
(all of which are incorporated by reference, see Sec. 60.17).
Sec. 60.4370a How frequently must I determine the fuel sulfur
content?
(a) If you are complying with requirements in Sec. 60.4360a, the
total sulfur content of all fuels combusted in each stationary
combustion turbine subject to an SO2 emissions standard in
Sec. 60.4330a must be determined according to the schedule specified
in paragraph (a)(1) or (2) of this section, as applicable to the fuel
type, unless you determine a custom schedule for the stationary
combustion turbine according to paragraph (b) of this section.
(1) Use one of the total sulfur sampling options and the associated
sampling frequency described in sections 2.2.3, 2.2.4.1, 2.2.4.2, and
2.2.4.3 in appendix D to part 75 of this chapter (i.e., flow
proportional sampling, daily sampling, sampling from the unit's storage
tank after each addition of fuel to the tank or sampling each delivery
prior to combining it with liquid fuel already in the intended storage
tank).
(2) If the fuel is supplied without intermediate bulk storage, the
sulfur content value of the gaseous fuel must be determined and
recorded once per operating day.
(b) As an alternative to the requirements of paragraph (a) of this
section, you may implement custom schedules for determination of the
total sulfur content of gaseous fuels, based on the design and
operation of the affected facility and the characteristics of the fuel
supply using the procedures provided in either paragraph (b)(1) or (2)
of this section. Either you or the fuel vendor may perform the
sampling. As an alternative to using one of these procedures, you may
use a custom schedule that has been substantiated with data and
approved by the Administrator or delegated authority as a change in
monitoring prior to being used to comply with the applicable standard
in Sec. 60.4330a.
(1) You may determine and implement a custom sulfur sampling
schedule for your stationary combustion turbine using the procedure
specified in paragraphs (b)(1)(i) through (iv) of this section.
(i) Obtain daily total sulfur content measurements for 30
consecutive operating days, using the applicable methods specified in
this subpart. Based on the results of the 30 daily samples, the
required frequency for subsequent monitoring of the fuel's total sulfur
content must be as specified in paragraph (b)(1)(ii), (iii), or (iv) of
this section, as applicable.
(ii) If none of the 30 daily measurements of the fuel's total
sulfur content exceeds half the applicable standard, subsequent sulfur
content monitoring may be performed at 12-month intervals provided the
fuel source or supplier does not change. If any of the samples taken at
12-month intervals has a total sulfur content greater than half but
less than the applicable standard, follow the procedures in paragraph
(b)(1)(iii) of this section. If any measurement exceeds the applicable
standard, follow the procedures in paragraph (b)(1)(iv) of this
section.
(iii) If at least one of the 30 daily measurements of the fuel's
total sulfur content is greater than half but less than the applicable
standard, but none exceeds the applicable standard, then:
(A) Collect and analyze a sample every 30 days for 3 months. If any
sulfur content measurement exceeds the applicable standard, follow the
procedures in paragraph (b)(1)(iv) of this section. Otherwise, follow
the procedures in paragraph (b)(1)(iii)(B) of this section.
(B) Begin monitoring at 6-month intervals for 12 months. If any
sulfur content measurement exceeds the applicable standard, follow the
procedures in paragraph (b)(1)(iv) of this section. Otherwise, follow
the procedures in paragraph (b)(1)(iii)(C) of this section.
(C) Begin monitoring at 12-month intervals. If any sulfur content
measurement exceeds the applicable standard, follow the procedures in
paragraph (b)(1)(iv) of this section. Otherwise, continue to monitor at
this frequency.
(iv) If a sulfur content measurement exceeds the applicable
standard, immediately begin daily monitoring according to paragraph
(b)(1)(i) of this section. Daily monitoring must continue until 30
consecutive daily samples, each having a sulfur content no greater than
the applicable standard, are obtained. At that point, the applicable
procedures of paragraph (b)(1)(ii) or (iii) of this section must be
followed.
(2) You may use the data collected from the 720-hour sulfur
sampling demonstration described in section 2.3.6 in appendix D to part
75 of this chapter to determine and implement a sulfur sampling
schedule for your stationary combustion turbine using the procedure
specified in paragraphs (b)(2)(i) through (iii) of this section.
(i) If the maximum fuel sulfur content obtained from any of the 720
hourly samples does not exceed half the applicable standard, then the
minimum required sampling frequency must be one sample at 12-month
intervals.
(ii) If any sample result exceeds half the applicable standard, but
none exceeds the applicable standard, follow the provisions of
paragraph (b)(1)(iii) of this section.
(iii) If the sulfur content of any of the 720 hourly samples
exceeds the applicable standard, follow the provisions of paragraph
(b)(1)(iv) of this section.
Sec. 60.4372a How can I demonstrate compliance with my SO2 emissions
standard using records of the fuel sulfur content?
(a) If you elect to demonstrate compliance with a SO2
emissions standard according to Sec. 60.4333a(d)(3), you must maintain
on-site records (such as a current, valid purchase contract, tariff
sheet, or transportation contract) documenting that total sulfur
content for the fuel combusted in your stationary combustion turbine at
all times does not exceed the conditions specified in paragraph (b)
through (e) of this section, as applicable to your stationary
combustion turbine.
(b) If your stationary combustion turbine is subject to the
SO2 emissions standard in Sec. 60.4330a(a), then the fuel
[[Page 1995]]
combusted must have a potential SO2 emissions rate of 26 ng/
J (0.060 lb/MMBtu) heat input or less.
(c) If your stationary combustion turbine is subject to the
SO2 emissions standard in Sec. 60.4330a(b), then the total
sulfur content of the gaseous fuel combusted must be 650 (mg/scm) (28
gr/100 scf).
(d) If your stationary combustion turbine is subject to the
SO2 emissions standard in Sec. 60.4330a(c) or (d), the
total sulfur content of the fuel combusted must be:
(1) For natural gas, 140 gr/100 scf or less.
(2) For fuel oil, 0.40 weight percent (4,000 ppmw) or less.
(3) For other fuels, potential SO2 emissions of 180 ng/J
(0.42 lb/MMBtu) heat input or less.
(e) Representative fuel sampling data following the procedures
specified in section 2.3.1.4 or 2.3.2.4 in appendix D to part 75 of
this chapter documenting that the fuel meets the part 75 requirements
to be considered either pipeline natural gas or natural gas. Your
stationary combustion turbine may not cause to be discharged into the
atmosphere any gases that contain SO2 in excess of:
(1) 110 ng SO2/J (0.90 lb SO2/MWh) gross
energy output or 26 ng SO2/J (0.060 lb SO2/MMBtu)
heat input; or
(2) 780 ng SO2/J (6.2 lb SO2/MWh) gross
energy output or 180 ng SO2/J (0.42 lb SO2/MMBtu)
heat input if your combustion turbine is in a noncontinental area.
Sec. 60.4374a How do I demonstrate compliance with my SO2 emissions
standard and determine excess emissions using a SO2 CEMS?
(a) If you demonstrate continuous compliance using a CEMS for
measuring SO2 emissions, excess emissions are defined as the
applicable averaging period, either 4-operating-hour or 30-operating-
day, during which the average SO2 emissions from your
stationary combustion turbine measured by the CEMS exceeds the
applicable SO2 emissions standard specified in Sec.
60.4330a as determined using the procedures specified in this section
that apply to your stationary combustion turbine.
(b) You must install, calibrate, maintain, and operate a CEMS for
measuring SO2 concentrations and either O2 or
CO2 concentrations at the outlet of your stationary
combustion turbine, and record the output of the system.
(c) The 1-hour average SO2 emissions rate measured by a
CEMS must be expressed in ng/J or lb/MMBtu heat input and must be used
to calculate the average emissions rate under Sec. 60.4330a.
(d) You must use the procedures for installation, evaluation, and
operation of the CEMS as specified in Sec. 60.13 and paragraphs (d)(1)
through (3) of this section.
(1) Each CEMS must be operated according to the applicable
procedures under Performance Specifications 1, 2, and 3 in appendix B
to this part;
(2) Quarterly accuracy determinations and daily calibration drift
tests must be performed according to Procedure 1 in appendix F to this
part; and
(3) The span value of the SO2 CEMS at the outlet from
the SO2 control device (or outlet of the stationary
combustion turbine if no SO2 control device is used) must be
125 percent of either the highest applicable standard or highest
potential SO2 emissions rate of the fuel combusted.
Alternatively, SO2 span values determined according to
section 2.1.1 in appendix A to part 75 of this chapter may be used.
(e) If you have installed and certified a SO2 CEMS that
meets the requirements of part 75 of this chapter, the Administrator or
delegated authority can approve that only quality assured data from the
CEMS must be used to identify excess emissions under this subpart. You
must report periods where the missing data substitution procedures in
subpart D of part 75 are applied as monitoring system downtime in the
excess emissions and monitoring performance report required under Sec.
60.7(c).
(f) All required fuel flow rate, steam flow rate, temperature,
pressure, and megawatt data must be reduced to hourly averages.
(g) Calculate the hourly average SO2 emissions rate, in
units of the emissions standard under Sec. 60.4330a, using lb/MMBtu
for units complying with the input-based standard or using equation 1
to paragraph (g)(1) of this section for units complying with the
output-based standard:
(1) For simple cycle operation:
Equation 1 to Paragraph (g)(1)
[GRAPHIC] [TIFF OMITTED] TR15JA26.028
Where:
E = Hourly SO2 emissions rate, in lb/MWh;
(SO2)h = Average hourly SO2
emissions rate, in lb/MMBtu;
Q = Hourly heat input rate to the stationary combustion turbine, in
MMBtu, measured using the fuel flow meter(s), e.g., calculated using
Equation D-15a in appendix D to part 75 of this chapter, an
O2 or CO2 CEMS and a stack flow monitor, or
the methodologies in appendix F to part 75 of this chapter; and
P = Gross or net energy output of the stationary combustion turbine
in MWh.
(2) The gross or net energy output is calculated as the sum of the
total electrical and mechanical energy generated by the stationary
combustion turbine; the additional electrical or mechanical energy (if
any) generated by the steam turbine following the heat recovery steam
generating unit; the total useful thermal energy output that is not
used to generate additional electricity or mechanical output, expressed
in equivalent MWh, minus the auxiliary load as calculated using
equations 2 and 3 to this paragraph (g)(2); and any auxiliary load.
Equation 2 to Paragraph (g)(2)
[GRAPHIC] [TIFF OMITTED] TR15JA26.029
Where:
P = Gross energy output of the stationary combustion turbine system
in MWh;
(Pe)t = Electrical or mechanical energy output of the
stationary combustion turbine in MWh;
(Pe)c = Electrical or mechanical energy output (if any)
of the steam turbine in MWh;
PeA = Electric energy used for any auxiliary loads in
MWh;
Ps = Useful thermal energy of the steam, measured
relative to ISO conditions, not used to generate additional electric
or mechanical output, in MWh;
Po = Other useful heat recovery, measured relative to ISO
conditions, not used for steam generation or performance enhancement
of the stationary combustion turbine; and
T = Electric Transmission and Distribution Factor. Equal to 0.95 for
CHP combustion turbine where at least 20.0 percent of the total
gross useful energy output consists of electric or direct mechanical
output and 20.0 percent of the total gross useful energy output
consists of useful thermal output on an annual basis. Equal to 1.0
for all other combustion turbines.
Equation 3 to Paragraph (g)(2)
[[Page 1996]]
[GRAPHIC] [TIFF OMITTED] TR15JA26.030
Where:
Ps = Useful thermal energy of the steam, measured
relative to ISO conditions, not used to generate additional electric
or mechanical output, in MWh;
Qm = Measured steam flow rate in lb;
H = Enthalpy of the steam at measured temperature and pressure
relative to ISO conditions, in Btu/lb; and
3.413 x 10\6\ = Conversion factor from Btu to MWh.
(3) For mechanical drive applications complying with the output-
based standard, use equation 4 to this paragraph (g)(3):
Equation 4 to Paragraph (g)(3)
[GRAPHIC] [TIFF OMITTED] TR15JA26.031
Where:
E = SO2 emissions rate in lb/MWh;
(SO2)m = SO2 emissions rate in lb/
h;
BL = Manufacturer's base load rating of turbine, in MW; and
AL = Actual load as a percentage of the base load rating.
(h) For each stationary combustion turbine demonstrating compliance
on a heat input-based emissions standard, excess SO2
emissions are determined on a 4-operating-hour averaging period basis
using the SO2 CEMS data and procedures specified in
paragraphs (i)(1) and (2) of this section and as applicable to the
SO2 emission standard.
(1) For each 4-operating-hour period, compute the 4-operating-hour
rolling average SO2 emissions as the heat input weighted
average of the hourly average of SO2 emissions for a given
operating hour and the 3 operating hours preceding that operating hour
using the applicable equation in paragraph (i)(2) of this section.
Calculate a 4-operating-hour rolling average SO2 emissions
rate for any 4-operating-hour period when you have valid CEMS data for
at least 3 of those hours (e.g., a valid 4-operating-hour rolling
average SO2 emissions rate cannot be calculated if 1 or more
continuous monitors was out-of-control for the entire hour for more
than 1 hour during the 4-operating-hour period).
(2) If you elect to comply with the applicable heat input-based
emissions rate standard, calculate both the 4-operating-hour rolling
average SO2 emissions rate and the applicable 4-operating-
hour rolling average SO2 emission standard using equation 5
to this paragraph (h)(2).
Equation 5 to Paragraph (h)(2)
[GRAPHIC] [TIFF OMITTED] TR15JA26.032
Where:
E = 4-operating-hour rolling average SO2 emissions (lb/
MMBtu or ng/J);
Ei = Hourly average SO2 emissions rate or
emissions standard for operating hour ``i'' (lb/MMBtu or ng/J); and
Qi = Total heat input to stationary combustion turbine
for operating hour ``i'' (MMBtu or J as appropriate).
(i) For each combustion turbine demonstrating compliance on an
output-based standard, you must determine excess emissions on a 30-
operating-day rolling average basis. The measured emissions rate is the
SO2 emissions measured by the CEMS for a given operating day
and the 29 operating days preceding that day. Once each operating day,
calculate a new 30-operating-day average measured emissions rate using
all hourly average values based on non-out-of-control SO2
emission data for all operating hours during the previous 30-operating-
day operating period. Report any 30-operating-day periods for which you
have less than 90 percent data availability as monitor downtime.
Calculate both the 30-operating-day rolling average SO2
emissions rate and the applicable 30-operating-day rolling average
SO2 emissions standard using equation 6 to this paragraph
(i).
Equation 6 to Paragraph (i)
[GRAPHIC] [TIFF OMITTED] TR15JA26.033
Where:
E = 30-operating-day average SO2 measured emissions rate
(lb/MWh or ng/J);
Ei = Hourly average SO2 measured emissions
rate for non-out-of-control operating hour ``i'' (lb/MMBtu or ng/J);
Qi = Total heat input to stationary combustion turbine
for non-out-of-control operating hour ``i'' (MMBtu or J as
appropriate);
Pi = Total gross energy output from stationary combustion
turbine for non-out-of-control operating hour ``i'' (MWh or J); and
n = Total number of non-out-of-control operating hours in the 30-
operating-day period.
(j) At a minimum, non-out-of-control CEMS hourly averages shall be
obtained for 90 percent of all operating hours on a 30-operating-day
rolling average basis.
Recordkeeping and Reporting
Sec. 60.4375a What reports must I submit?
(a) An owner or operator of a stationary combustion turbine that
elects to continuously monitor parameters or emissions, or to
periodically determine the fuel sulfur content under this subpart, must
submit reports of excess emissions and monitor downtime, according to
Sec. 60.7(c). Excess emissions must be reported for all periods of
unit operation, including startup, shutdown, and malfunction.
(b) The notification requirements of Sec. 60.8 apply to the
initial and subsequent performance tests.
(c) An owner or operator of an affected facility complying with
Sec. 60.4333a(b)(3) must notify the Administrator or delegated
authority within 15 calendar days after the facility recommences
operation.
(d) An owner or operator of an affected facility complying with
Sec. 60.4333a(b)(4) must notify the Administrator or delegated
authority within 15 calendar days after the facility has operated more
than 168 operating hours since the date the previous performance test
was required to be conducted.
(e) Within 60 days after the date of completing each performance
test or continuous emissions monitoring systems (CEMS) performance
evaluation that includes a relative accuracy test audit (RATA), you
must submit the results following the procedures specified in paragraph
(g) of this section. You must submit the report in a file format
generated using the EPA's Electronic Reporting Tool (ERT).
Alternatively, you may submit an electronic file consistent with the
extensible markup language (XML) schema listed on the EPA's ERT website
(https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) accompanied by the other information required by
Sec. 60.8(f)(2) in PDF format.
(f) You must submit to the Administrator semiannual reports of the
following recorded information. Beginning on January 15, 2027, or once
the report template for this subpart has
[[Page 1997]]
been available on the Compliance and Emissions Data Reporting Interface
(CEDRI) website (https://www.epa.gov/electronic-reporting-air-emissions/cedri) for one year, whichever date is later, submit all
subsequent reports using the appropriate electronic report template on
the CEDRI website for this subpart and following the procedure
specified in paragraph (g) of this section. The date report templates
become available will be listed on the CEDRI website. Unless the
Administrator or delegated State agency or other authority has approved
a different schedule for submission of reports, the report must be
submitted by the deadline specified in this subpart, regardless of the
method in which the report is submitted.
(g) If you are required to submit notifications or reports
following the procedure specified in this paragraph (g), you must
submit notifications or reports to the EPA via the Compliance and
Emissions Data Reporting Interface (CEDRI), which can be accessed
through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/).
The EPA will make all the information submitted through CEDRI available
to the public without further notice to you. Do not use CEDRI to submit
information you claim as CBI. Although we do not expect persons to
assert a claim of CBI, if you wish to assert a CBI claim for some of
the information in the report or notification, you must submit a
complete file in the format specified in this subpart, including
information claimed to be CBI, to the EPA following the procedures in
paragraphs (g)(1) and (2) of this section. Clearly mark the part or all
of the information that you claim to be CBI. Information not marked as
CBI may be authorized for public release without prior notice.
Information marked as CBI will not be disclosed except in accordance
with procedures set forth in 40 CFR part 2. All CBI claims must be
asserted at the time of submission. Anything submitted using CEDRI
cannot later be claimed CBI. Furthermore, under CAA section 114(c),
emissions data is not entitled to confidential treatment, and the EPA
is required to make emissions data available to the public. Thus,
emissions data will not be protected as CBI and will be made publicly
available. You must submit the same file submitted to the CBI office
with the CBI omitted to the EPA via the EPA's CDX as described earlier
in this paragraph (g).
(1) The preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol, or
other online file sharing services. Electronic submissions must be
transmitted directly to the OAQPS CBI Office at the email address
[email protected], and as described above, should include clear CBI
markings. ERT files should be flagged to the attention of the Group
Leader, Measurement Policy Group; all other files should be flagged to
the attention of the Stationary Combustion Turbine Sector Lead. If
assistance is needed with submitting large electronic files that exceed
the file size limit for email attachments, and if you do not have your
own file sharing service, please email [email protected] to request a
file transfer link.
(2) If you cannot transmit the file electronically, you may send
CBI information through the postal service to the following address:
U.S. EPA, Attn: OAQPS Document Control Officer, Mail Drop: C404-02, 109
T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711. In addition to the
OAQPS Document Control Officer, ERT files should also be sent to the
attention of the Group Leader, Measurement Policy Group, and all other
files should also be sent to the attention of the Stationary Combustion
Turbine Sector Lead. The mailed CBI material should be double wrapped
and clearly marked. Any CBI markings should not show through the outer
envelope.
(h) If you are required to electronically submit a report through
CEDRI in the EPA's CDX, you may assert a claim of EPA system outage for
failure to timely comply with that reporting requirement. To assert a
claim of EPA system outage, you must meet the requirements outlined in
paragraphs (h)(1) through (7) of this section.
(1) You must have been or will be precluded from accessing CEDRI
and submitting a required report within the time prescribed due to an
outage of either the EPA's CEDRI or CDX systems.
(2) The outage must have occurred within the period of time
beginning 5 business days prior to the date that the submission is due.
(3) The outage may be planned or unplanned.
(4) You must submit notification to the Administrator in writing as
soon as possible following the date you first knew, or through due
diligence should have known, that the event may cause or has caused a
delay in reporting.
(5) You must provide to the Administrator a written description
identifying:
(i) The date(s) and time(s) when CDX or CEDRI was accessed and the
system was unavailable;
(ii) A rationale for attributing the delay in reporting beyond the
regulatory deadline to EPA system outage;
(iii) A description of measures taken or to be taken to minimize
the delay in reporting; and
(iv) The date by which you propose to report, or if you have
already met the reporting requirement at the time of the notification,
the date you reported.
(6) The decision to accept the claim of EPA system outage and allow
an extension to the reporting deadline is solely within the discretion
of the Administrator.
(7) In any circumstance, the report must be submitted
electronically as soon as possible after the outage is resolved.
(i) If you are required to electronically submit a report through
CEDRI in the EPA's CDX, you may assert a claim of force majeure for
failure to timely comply with that reporting requirement. To assert a
claim of force majeure, you must meet the requirements outlined in
paragraphs (i)(1) through (5) of this section.
(1) You may submit a claim if a force majeure event is about to
occur, occurs, or has occurred or there are lingering effects from such
an event within the period of time beginning 5 business days prior to
the date the submission is due. For the purposes of this section, a
force majeure event is defined as an event that will be or has been
caused by circumstances beyond the control of the affected facility,
its contractors, or any entity controlled by the affected facility that
prevents you from complying with the requirement to submit a report
electronically within the time period prescribed. Examples of such
events are acts of nature (e.g., hurricanes, earthquakes, or floods),
acts of war or terrorism, or equipment failure or safety hazard beyond
the control of the affected facility (e.g., large scale power outage).
(2) You must submit notification to the Administrator in writing as
soon as possible following the date you first knew, or through due
diligence should have known, that the event may cause or has caused a
delay in reporting.
(3) You must provide to the Administrator:
(i) A written description of the force majeure event;
(ii) A rationale for attributing the delay in reporting beyond the
regulatory deadline to the force majeure event;
(iii) A description of measures taken or to be taken to minimize
the delay in reporting; and
(iv) The date by which you propose to report, or if you have
already met the reporting requirement at the time of the notification,
the date you reported.
(4) The decision to accept the claim of force majeure and allow an
extension
[[Page 1998]]
to the reporting deadline is solely within the discretion of the
Administrator.
(5) In any circumstance, the reporting must occur as soon as
possible after the force majeure event occurs.
(j) Any records required to be maintained by this subpart that are
submitted electronically via the EPA's CEDRI may be maintained in
electronic format. This ability to maintain electronic copies does not
affect the requirement for facilities to make records, data, and
reports available upon request to a delegated air agency or the EPA as
part of an on-site compliance evaluation.
Sec. 60.4380a How are NOX excess emissions and monitor downtime
reported?
(a) For a stationary combustion turbine that uses water or steam to
fuel ratio monitoring and is subject to the reporting requirements
under Sec. 60.4375a(a), periods of excess emissions and monitor
downtime must be reported as specified in paragraphs (a)(1) through (3)
of this section.
(1) An excess emission that must be reported is any operating hour
for which the 4-operating-hour rolling average steam or water to fuel
ratio, as measured by the continuous monitoring system, is less than
the acceptable steam or water to fuel ratio needed to demonstrate
compliance with Sec. 60.4320a, as established during the most recent
performance test. Any operating hour during which no water or steam is
injected into the turbine when the specific conditions require water or
steam injection for NOX control will also be considered an
excess emission.
(2) A period of monitor downtime that must be reported is any
operating hour in which water or steam is injected into the turbine,
but the parametric data needed to determine the steam or water to fuel
ratio are unavailable or out-of-control.
(3) Each report must include the average steam or water to fuel
ratio, average fuel consumption, and the stationary combustion turbine
load during each excess emission.
(b) For reports required under Sec. 60.4375a(a), periods of excess
emissions and monitor downtime for stationary combustion turbines using
a CEMS, excess emissions are reported as specified in paragraphs (b)(1)
and (2) of this section.
(1) An excess emission that must be reported is any unit operating
period in which the 4-operating-hour average NOX emissions
rate, 30-operating-day rolling average NOX emissions rate,
4-hour mass-based emissions rate, or the 12-calendar-month mass-based
emissions rate exceeds the applicable emissions standard in Sec.
60.4320a as determined in Sec. 60.4350a.
(2) A period of monitor downtime that must be reported is any
operating hour in which the data for any of the following parameters
that you use to calculate the emission rate, as applicable, used to
determine compliance, are either missing or out-of-control:
NOX concentration, CO2 or O2
concentration, stack flow rate, heat input rate, steam flow rate, steam
temperature, steam pressure, or megawatts. You are only required to
monitor parameters used for compliance purposes.
(c) For reports required under Sec. 60.4375a(a), periods of excess
emissions and monitor downtime for stationary combustion turbines using
combustion parameters or parameters that document proper operation of
the NOX emission controls excess emissions and monitor
downtime are reported as specified in paragraphs (c)(1) and (2) of this
section.
(1) Excess emissions that must be reported are each 4-operating-
hour rolling average in which any monitored parameter (as averaged over
the 4-operating-hour period) does not achieve the target value or is
outside the acceptable range defined in the parameter monitoring plan
for the unit.
(2) Periods of monitor downtime that must be reported are each
operating hour in which any of the required parametric data that are
used to calculate the emission rate, as applicable, used to determine
compliance, are either not recorded or are out-of-control.
Sec. 60.4385a How are SO2 excess emissions and monitor downtime
reported?
(a) If you choose the option to monitor the sulfur content of the
fuel, excess emissions and monitor downtime are defined as follows:
(1) For samples obtained using daily sampling, flow proportional
sampling, or sampling from the unit's storage tank, excess emissions
occur each operating hour included in the period beginning on the date
and hour of any sample for which the sulfur content of the fuel being
fired in the stationary combustion turbine exceeds the applicable
standard and ending on the date and hour that a subsequent sample is
taken that demonstrates compliance with the sulfur standard.
(2) If the option to sample each delivery of fuel oil has been
selected, you must immediately switch to one of the other oil sampling
options (i.e., daily sampling, flow proportional sampling, or sampling
from the unit's storage tank) if the sulfur content of a delivery
exceeds 0.05 weight percent, 0.15 weight percent, or 0.40 weight
percent as applicable. You must continue to use one of the other
sampling options until all of the oil from the delivery has been
combusted, and you must evaluate excess emissions according to
paragraph (a) of this section. When all of the fuel from the delivery
has been combusted, you may resume using the as-delivered sampling
option.
(3) A period of monitor downtime begins when a required sample is
not taken by its due date. A period of monitor downtime also begins on
the date and hour of a required sample, if invalid results are
obtained. The period of monitor downtime ends on the date and hour of
the next valid sample.
(b) If you choose the option to maintain records of the fuel sulfur
content, excess emissions are defined as any period during which you
combust a fuel that you do not have appropriate fuel records or that
fuel contains sulfur greater than the applicable standard.
(c) For reports required under Sec. 60.4375a(a), periods of excess
emissions and monitor downtime for stationary combustion turbines using
a CEMS, excess emissions are reported as specified in paragraphs (c)(1)
and (2) of this section.
(1) An excess emission that must be reported is any unit operating
period in which the 4-operating-hour or 30-operating-day rolling
average SO2 emissions rate exceeds the applicable emissions
standard in Sec. 60.4330a as determined in Sec. 60.4374a.
(2) A period of monitor downtime that must be reported is any
operating hour in which the data for any of the following parameters
that you use to calculate the emission rate, as applicable, used to
determine compliance, are either missing or out-of-control:
SO2 concentration, CO2 or O2
concentration, stack flow rate, heat input rate, steam flow rate, steam
temperature, steam pressure, or megawatts. You are only required to
monitor parameters used for compliance purposes.
Sec. 60.4390a What records must I maintain?
(a) You must maintain records of your information used to
demonstrate compliance with this subpart as specified in Sec. 60.7.
(b) An owner or operator of a stationary combustion turbine that
uses the other fuels, part-load, or low temperature NOX
standards in the compliance demonstration must maintain concurrent
records of the hourly heat input, percent load, ambient
[[Page 1999]]
temperature, and emissions data as applicable.
(c) An owner or operator of a stationary combustion turbine that
uses the tuning NOX standard in the compliance demonstration
must identify the hours on which the maintenance was performed and a
description of the maintenance.
(d) An owner or operator of a stationary combustion turbine that
demonstrates compliance using the output-based standard must maintain
concurrent records of the total gross or net energy output and
emissions data.
(e) An owner or operator of a stationary combustion turbine that
demonstrates compliance using the water or steam to fuel ratio or a
parameter continuous monitoring system must maintain continuous records
of the appropriate parameters.
(f) An owner or operator of a stationary combustion turbine
complying with the fuel-based SO2 standard must maintain
records of the results of all fuel analyses or a current, valid
purchase contract, tariff sheet, or transportation contract.
Sec. 60.4395a When must I submit my reports?
Consistent with Sec. 60.7(c), all reports required under Sec.
60.7(c) must be electronically submitted via CEDRI by the 30th day
following the end of each 6-month period.
Performance Tests
Sec. 60.4400a How do I conduct performance tests to demonstrate
compliance with my NOX emissions standard if I do not have a NOX CEMS?
(a) You must conduct the performance test according to the
requirements in Sec. 60.8 and paragraphs (b) through (d) of this
section.
(b) You must use the methods in either paragraph (b)(1) or (2) of
this section to measure the NOX concentration for each test
run.
(1) Measure the NOX concentration using EPA Method 7E in
appendix A-4 to this part, EPA Method 20 in appendix A-7 to this part,
EPA Method 320 in appendix A to part 63 of this chapter, or ASTM D6348-
12 (Reapproved 2020) (incorporated by reference, see Sec. 60.17). For
units complying with the output-based standard, concurrently measure
the stack gas flow rate, using EPA Methods 1 and 2 in appendix A-1 to
this part, and measure and record the electrical and thermal output
from the unit. Then, use equation 1 to this paragraph (b)(1) to
calculate the NOX emissions rate:
Equation 1 to Paragraph (b)(1)
[GRAPHIC] [TIFF OMITTED] TR15JA26.034
Where:
E = NOX emissions rate, in lb/MWh;
1.194x10-7 = Conversion constant, in lb/dscf-ppm;
(NOX)c = Average NOX concentration
for the run, in ppm;
Qstd = Average stack gas volumetric flow rate, in dscf/h;
and
P = Average gross or net electrical and mechanical energy output of
the stationary combustion turbine, in MW (for simple cycle
operation), for combined cycle operation, the sum of all electrical
and mechanical output from the combustion and steam turbines, or,
for CHP operation, the sum of all electrical and mechanical output
from the combustion and steam turbines plus all useful recovered
thermal output not used for additional electric or mechanical
generation or to enhance the performance of the stationary
combustion turbine, in MW, calculated according to Sec. 60.4350a.
(2) Measure the NOX and diluent gas concentrations using
either EPA Method 7E in appendix A-4 to this part and EPA Method 3A in
appendix A-2 to this part, or EPA Method 20 in appendix A-7 to this
part. In addition, when only natural gas is being combusted ASTM D6522-
20 (incorporated by reference, see Sec. 60.17) can be used instead of
EPA Method 3A in appendix A-2 to this part or EPA Method 20 in appendix
A-7 to this part to determine the oxygen content in the exhaust gas.
Concurrently measure the heat input to the unit, using a fuel flowmeter
(or flowmeters), an O2 or CO2 CEMS along with a
stack flow monitor, or the methodologies in appendix F to part 75 of
this chapter, and for units complying with the output-based standard
measure the electrical, mechanical, and thermal output of the unit. Use
EPA Method 19 in appendix A-7 to this part to calculate the
NOX emissions rate in lb/MMBtu. Then, use equations 1 and,
if necessary, 2 and 3 in Sec. 60.4350a(f) to calculate the
NOX emissions rate in lb/MWh.
(c) You must use the methods in either paragraph (c)(1) or (2) of
this section to select the sampling traverse points for NOX
and (if applicable) diluent gas.
(1) You must select the sampling traverse points for NOX
and (if applicable) diluent gas according to EPA Method 20 in appendix
A-7 to this part or EPA Method 1 in appendix A-1 to this part (non-
particulate procedures) and sampled for equal time intervals. The
sampling must be performed with a traversing single-hole probe, or, if
feasible, with a stationary multi-hole probe that samples each of the
points sequentially. Alternatively, a multi-hole probe designed and
documented to sample equal volumes from each hole may be used to sample
simultaneously at the required points.
(2) As an alternative to paragraph (c)(1) of this section, you may
select the sampling traverse points for NOX and (if
applicable) diluent gas according to requirements in paragraphs
(c)(2)(i) and (ii) of this section.
(i) You perform a stratification test for NOX and
diluent pursuant to the procedures specified in section 6.5.6.1(a)
through (e) in appendix A to part 75 of this chapter.
(ii) Once the stratification sampling is completed, you use the
following alternative sample point selection criteria for the
performance test specified in paragraphs (c)(2)(ii)(A) through (C) of
this section.
(A) If each of the individual traverse point NOX
concentrations is within 10 percent of the mean
concentration for all traverse points, or the individual traverse point
diluent concentrations differs by no more than 0.5 percent
CO2 (or O2) from the mean for all traverse
points, then you may use three points (located either 16.7, 50.0 and
83.3 percent of the way across the stack or duct, or, for circular
stacks or ducts greater than 2.4 meters (7.8 feet) in diameter, at 0.4,
1.2, and 2.0 meters from the wall). The three points must be located
along the measurement line that exhibited the highest average
NOX concentration during the stratification test; or
(B) For a stationary combustion turbine subject to a NOX
emissions standard greater than 15 ppm at 15 percent O2, you
may sample at a single point, located at least 1 meter from the stack
wall or at the stack centroid if each of the individual traverse point
NOX concentrations is within 5 percent of the
mean concentration for all
[[Page 2000]]
traverse points, or the individual traverse point diluent
concentrations differs by no more than 0.3 percent
CO2 (or O2) from the mean for all traverse
points; or
(C) For a stationary combustion turbine subject to a NOX
emissions standard less than or equal to 15 ppm at 15 percent
O2, you may sample at a single point, located at least 1
meter from the stack wall or at the stack centroid if each of the
individual traverse point NOX concentrations is within
2.5 percent of the mean concentration for all traverse
points, or the individual traverse point diluent concentrations differs
by no more than 0.15 percent CO2 (or
O2) from the mean for all traverse points.
(d) The performance test must be done at any load condition within
25 percent of 100 percent of the base load rating. You may
perform testing at the highest achievable load point, if at least 75
percent of the base load rating cannot be achieved in practice. You
must conduct three separate test runs for each performance test. The
minimum time per run is 20 minutes.
(1) If the stationary combustion turbine combusts both natural gas
and fuels other than natural gas as primary or backup fuels, separate
performance testing is required for each fuel.
(2) For a combined cycle or CHP combustion turbine with
supplemental heat (duct burner), you must measure the total
NOX emissions downstream of the duct burner. The duct burner
must be in operation within 25 percent of 100 percent of
the base load rating of the duct burners or the highest achievable load
if at least 75 percent of the base load rating of the duct burners
cannot be achieved during the performance test.
(3) If water or steam injection is used to control NOX
with no additional post-combustion NOX control and you
choose to monitor the steam or water to fuel ratio in accordance with
Sec. 60.4335a, then that monitoring system must be operated
concurrently with each EPA Method 20 in appendix A-7 to this part or
EPA Method 7E in appendix A-4 to this part run and must be used to
determine the fuel consumption and the steam or water to fuel ratio
necessary to comply with the applicable Sec. 60.4320a NOX
emissions standard.
(4) If you elect to install a CEMS, the performance evaluation of
the CEMS may either be conducted separately or (as described in Sec.
60.4405a) as part of the initial performance test of the affected unit.
(5) The ambient temperature must be greater than 0 [deg]F during
the performance test. The Administrator or delegated authority may
approve performance testing below 0 [deg]F if the timing of the
required performance test and environmental conditions make it
impractical to test at ambient conditions greater than 0 [deg]F.
Sec. 60.4405a How do I conduct a performance test if I use a NOX
CEMS?
(a) If you use a CEMS the performance test must be performed
according to the procedures specified in paragraph (b) of this section.
(b) The initial performance test must use the procedure specified
in paragraphs (b)(1) through (4) of this section.
(1) Perform a minimum of nine RATA reference method runs, with a
minimum time per run of 21 minutes, at a single load level, within
25 percent of 100 percent of the base load rating while the
source is combusting the fuel that is a normal primary fuel for that
source. You may perform testing at the highest achievable load point,
if at least 75 percent of the base load rating cannot be achieved in
practice. The ambient temperature must be greater than 0 [deg]F during
the RATA runs. The Administrator or delegated authority may approve
performance testing below 0 [deg]F if the timing of the required
performance test and environmental conditions make it impractical to
test at ambient conditions greater than 0 [deg]F.
(2) For each RATA run, concurrently measure the heat input to the
unit using a fuel flow meter (or flow meters) or the methodologies in
appendix F to part 75 of this chapter, and for units complying with the
output-based standard, measure the electrical and thermal output from
the unit.
(3) Use the test data both to demonstrate compliance with the
applicable NOX emissions standard under Sec. 60.4320a and
to provide the required reference method data for the RATA of the CEMS
described under Sec. 60.4342a.
(4) Compliance with the applicable emissions standard in Sec.
60.4320a is achieved if the sum of the NOX emissions divided
by the heat input (or gross or net energy output) for all the RATA
runs, expressed in units of lb/MMBtu, ppm, lb/MWh, or kgs, does not
exceed the emissions standard.
Sec. 60.4415a How do I conduct performance tests to demonstrate
compliance with my SO2 emissions standard?
(a) If you are an owner or operator of an affected facility
complying with the fuel-based standard must submit fuel records (such
as a current, valid purchase contract, tariff sheet, transportation
contract, or results of a fuel analysis) to satisfy the requirements of
Sec. 60.8.
(b) If you are an owner or operator of an affected facility
complying with the SO2 emissions standard must conduct the
performance test by measuring the SO2 emissions in the
stationary combustion turbine exhaust gases using the methods in either
paragraph (b)(1) or (2) of this section.
(1) Measure the SO2 concentration using EPA Method 6,
6C, or 8 in appendix A-4 to this part or EPA Method 20 in appendix A-7
to this part. For units complying with the output-based standard,
concurrently measure the stack gas flow rate, using EPA Methods 1 and 2
in appendix A-1 to this part, and measure and record the electrical and
thermal output from the unit. Then use equation 1 to this paragraph
(b)(1) to calculate the SO2 emissions rate:
Equation 1 to Paragraph (b)(1)
[GRAPHIC] [TIFF OMITTED] TR15JA26.035
Where:
E = SO2 emissions rate, in lb/MWh;
1.664 x 10-7 = Conversion constant, in lb/dscf-ppm;
(SO2)c = Average SO2 concentration
for the run, in ppm;
Qstd = Average stack gas volumetric flow rate, in dscf/h;
and
P = Average gross electrical and mechanical energy output of the
stationary combustion turbine, in MW (for simple cycle operation),
for combined cycle operation, the sum of all electrical and
mechanical output from the combustion and steam turbines, or, for
CHP operation, the sum of all electrical and mechanical output from
the combustion and steam turbines plus all useful recovered thermal
output not used for additional electric or mechanical generation or
to enhance the performance of the stationary combustion turbine, in
MW, calculated according to Sec. 60.4350a(f)(2).
[[Page 2001]]
(2) Measure the SO2 and diluent gas concentrations,
using either EPA Method 6, 6C, or 8 in appendix A-4 to this part and
EPA Method 3A in appendix A-2 to this part, or EPA Method 20 in
appendix A-7 to this part. Concurrently measure the heat input to the
unit, using a fuel flowmeter (or flowmeters), an O2 or
CO2 CEMS along with a stack flow monitor, or the
methodologies in appendix F to part 75 of this chapter, and for units
complying with the output based standard measure the electrical and
thermal output of the unit. Use EPA Method 19 in appendix A-7 to this
part to calculate the SO2 emissions rate in lb/MMBtu. Then,
use equations 1 and, if necessary, 2, 3, and 4 in Sec. 60.4374a to
calculate the SO2 emissions rate in lb/MWh.
Other Requirements and Information
Sec. 60.4416a What parts of the general provisions apply to my
affected EGU?
(a) Notwithstanding any other provision of this chapter, certain
parts of the general provisions in Sec. Sec. 60.1 through 60.19,
listed in table 2 to this subpart, do not apply to your affected
combustion turbine.
(b) Small, medium, and low utilization large combustion turbines
that are subject to this subpart and are not a ``major source'' or
located at a ``major source'' (as that term is defined at 42 U.S.C.
7661(2)) are exempt from the requirements of 42 U.S.C. 7661a(a).
Sec. 60.4417a Who implements and enforces this subpart?
(a) This subpart can be implemented and enforced by the EPA, or a
delegated authority such as your State, local, or Tribal agency. If the
Administrator has delegated authority to your State, local, or Tribal
agency, then that agency, (as well as the EPA) has the authority to
implement and enforce this subpart. You should contact your EPA
Regional Office to find out if this subpart is delegated to your State,
local, or Tribal agency.
(b) In delegating implementation and enforcement authority of this
subpart to a State, local, or Tribal agency, the Administrator retains
the authorities listed in paragraphs (b)(1) through (6) of this section
and does not transfer them to the State, local, or Tribal agency. In
addition, the EPA retains oversight of this subpart and can take
enforcement actions, as appropriate.
(1) Approval of alternatives to the emissions standards.
(2) Approval of major alternatives to test methods.
(3) Approval of major alternatives to monitoring.
(4) Approval of major alternatives to recordkeeping and reporting.
(5) Performance test and data reduction waivers under Sec.
60.8(b).
(6) Approval of an alternative to any electronic reporting to the
EPA required by this subpart.
Sec. 60.4420a What definitions apply to this subpart?
As used in this subpart, all terms not defined in this section will
have the meaning given them in the Clean Air Act and in subpart A of
this part.
Annual capacity factor means the ratio between the actual heat
input to a stationary combustion turbine during a calendar year and the
potential heat input to the stationary combustion turbine had it been
operated for 8,760 hours during a calendar year at the base load
rating. Heat input during a system emergency as defined in Sec.
60.4420a is excluded when determining the annual capacity factor.
Actual and potential heat input derived from non-combustion sources
(e.g., solar thermal) are not included when calculating the annual
capacity factor.
Base load rating means 100 percent of the manufacturer's design
heat input capacity of the combustion turbine engine at ISO conditions
using the higher heating value of the fuel. The base load rating does
not include any potential heat input to an HRSG.
Biogas means gas produced by the anaerobic digestion or
fermentation of organic matter including manure, sewage sludge,
municipal solid waste, biodegradable waste, or any other biodegradable
feedstock, under anaerobic conditions. Biogas is comprised primarily of
methane and CO2.
Byproduct means any liquid or gaseous substance produced at
chemical manufacturing plants, petroleum refineries, pulp and paper
mills, or other industrial facilities (except natural gas and fuel
oil).
Combined cycle combustion turbine means any stationary combustion
turbine which recovers heat from the combustion turbine engine exhaust
gases to generate steam that is used to create additional electric
power output in a steam turbine.
Combined heat and power (CHP) combustion turbine means any
stationary combustion turbine which recovers heat from the combustion
turbine engine exhaust gases to heat water or another medium, generate
steam for useful purposes other than exclusively for additional
electric generation, or directly uses the heat in the exhaust gases for
a useful purpose.
Combustion turbine engine means the air compressor, combustor, and
turbine sections of a stationary combustion turbine.
Combustion turbine test cell/stand means any apparatus used for
testing uninstalled stationary or uninstalled mobile (motive)
combustion turbines.
Diffusion flame stationary combustion turbine means any stationary
combustion turbine where fuel and air are injected at the combustor and
are mixed only by diffusion prior to ignition.
Distillate oil means fuel oils that comply with the specifications
for fuel oil numbers 1 or 2, as defined in ASTM D396-98 (incorporated
by reference, see Sec. 60.17), diesel fuel oil numbers 1 or 2, as
defined in ASTM D975-08a (incorporated by reference, see Sec. 60.17),
kerosene, as defined in ASTM D3699-08 (incorporated by reference, see
Sec. 60.17), biodiesel as defined in ASTM D6751-11b (incorporated by
reference, see Sec. 60.17), or biodiesel blends as defined in ASTM
D7467-10 (incorporated by reference, see Sec. 60.17).
District energy system means a central plant producing hot water,
steam, and/or chilled water, which then flows through a network of
insulated pipes to provide hot water, space heating, and/or air
conditioning for commercial, institutional, or residential buildings.
Dry standard cubic foot (dscf) means the quantity of gas, free of
uncombined water, that would occupy a volume of 1 cubic foot at 293
Kelvin (20 [deg]C, 68 [deg]F) and 101.325 kPa (14.69 psi, 1 atm) of
pressure.
Duct burner means a device that combusts fuel and that is placed in
the exhaust duct from another source, such as a stationary combustion
turbine, internal combustion engine, kiln, etc., to allow the firing of
additional fuel to heat the exhaust gases.
Emergency combustion turbine means any stationary combustion
turbine which operates in an emergency situation. Examples include
stationary combustion turbines used to produce power for critical
networks or equipment, including power supplied to portions of a
facility, when electric power from the local utility is interrupted, or
stationary combustion turbines used to pump water in the case of fire
(e.g., firefighting turbine) or flood, etc. Emergency combustion
turbines may be operated for maintenance checks and readiness testing
to retain their status as emergency combustion turbines, provided that
the tests are recommended by Federal, State, or local government,
agencies, or departments, voluntary consensus standards, the
manufacturer, the vendor, the regional
[[Page 2002]]
transmission organization or equivalent balancing authority and
transmission operator, or the insurance company associated with the
combustion turbine. Required testing of such units should be minimized,
but there is no time limit on the use of emergency combustion turbines.
Emergency combustion turbines do not include combustion turbines used
as peaking units at electric utilities or combustion turbines at
industrial facilities that typically operate at low capacity factors.
Excess emissions means a specified averaging period over which
either:
(1) The NOX or SO2 emissions rate are higher
than the applicable emissions standard in Sec. 60.4320a or Sec.
60.4330a;
(2) The total sulfur content of the fuel being combusted in the
affected facility or the SO2 emissions exceeds the standard
specified in Sec. 60.4330a; or
(3) The recorded value of a particular monitored parameter,
including the water or steam to fuel ratio, is outside the acceptable
range specified in the parameter monitoring plan for the affected unit.
Federally enforceable means all limitations and conditions that are
enforceable by the Administrator or delegated authority, including the
requirements of this part and part 61 of this chapter, requirements
within any applicable State Implementation Plan, and any permit
requirements established under Sec. 52.21 or Sec. Sec. CFR 51.18 and
51.24 of this chapter.
Firefighting combustion turbine means any stationary combustion
turbine that is used solely to pump water for extinguishing fires.
Fuel oil means a fluid mixture of hydrocarbons that maintains a
liquid state at ISO conditions. Additionally, fuel oil must meet the
definition of either distillate oil (as defined in this subpart) or
liquefied petroleum (LP) gas as defined in ASTM D1835-03a (incorporated
by reference, see Sec. 60.17).
Garrison facility means any permanent military installation.
Gross energy output means:
(1) For simple cycle and combined cycle combustion turbines, the
gross useful work performed is the gross electrical or direct
mechanical output from both the combustion turbine engine and any
associated steam turbine(s).
(2) For a CHP combustion turbine, the gross useful work performed
is the gross electrical or direct mechanical output from both the
combustion turbine engine and any associated steam turbine(s) plus any
useful thermal output measured relative to ISO conditions that is not
used to generate additional electrical or mechanical output or to
enhance the performance of the unit (i.e., steam delivered to an
industrial process).
(3) For a CHP combustion turbine where at least 20.0 percent of the
total gross useful energy output consists of useful thermal output on
an annual basis, the gross useful work performed is the gross
electrical or direct mechanical output from both the combustion turbine
engine and any associated steam turbine(s) divided by 0.95 plus any
useful thermal output measured relative to ISO conditions that is not
used to generate additional electrical or mechanical output or to
enhance the performance of the unit (i.e., steam delivered to an
industrial process).
(4) For a district energy CHP combustion turbine where at least
20.0 percent of the total gross useful energy output consists of useful
thermal output on a 12-calendar-month basis, the gross useful work
performed is the gross electrical or direct mechanical output from both
the combustion turbine engine and any associated steam turbine(s)
divided by 0.95 plus any useful thermal output measured relative to ISO
conditions that is not used to generate additional electrical or
mechanical output or to enhance the performance of the unit (e.g.,
steam delivered to an industrial process) divided by 0.95.
Heat recovery steam generating unit (HRSG) means a unit where the
hot exhaust gases from the combustion turbine engine are routed in
order to extract heat from the gases and generate useful output. Heat
recovery steam generating units can be used with or without duct
burners. A heat recovery steam generating unit operating independent of
the combustion turbine engine may operate burners using ambient air.
High-utilization source means a new medium or large stationary
combustion turbine with a 12-calendar-month capacity factor greater
than 45 percent.
Integrated gasification combined cycle electric utility steam
generating unit (IGCC) means an electric utility steam generating unit
that combusts solid-derived fuels in a combined cycle combustion
turbine. No solid fuel is directly combusted in the unit during
operation.
ISO conditions mean 288 Kelvin (15 [deg]C, 59 [deg]F), 60 percent
relative humidity, and 101.325 kilopascals (14.69 psi, 1 atm) pressure.
Large combustion turbine means a stationary combustion turbine with
a base load rating greater than 850 MMBtu/h of heat input.
Lean premix stationary combustion turbine means any stationary
combustion turbine where the air and fuel are thoroughly mixed to form
a lean mixture before delivery to the combustor. Mixing may occur
before or in the combustion chamber. A lean premixed turbine may
operate in diffusion flame mode during operating conditions such as
startup and shutdown, extreme ambient temperature, or low or transient
load.
Low-Btu gas means biogas or any gas with a heating value of less
than 26 megajoules per standard cubic meter (MJ/scm) (700 Btu/scf).
Low-utilization source means a new medium or large stationary
combustion turbine with a 12-calendar-month capacity factor less than
or equal to 45 percent.
Medium combustion turbine means a stationary combustion turbine
with a base load rating greater than 50 MMBtu/h and less than or equal
to 850 MMBtu/h of heat input.
Natural gas means a fluid mixture of hydrocarbons, composed of at
least 70 percent methane by volume, that has a gross calorific value
between 35 and 41 MJ/scm (950 and 1,100 Btu/scf), and that maintains a
gaseous state under ISO conditions. Unless processed to meet this
definition of natural gas, natural gas does not include the following
gaseous fuels: Landfill gas, digester gas, refinery gas, sour gas,
blast furnace gas, coal-derived gas, producer gas, coke oven gas, or
any gaseous fuel produced in a process which might result in highly
variable CO2 content or heating value.
Net-electric output means the amount of gross generation the
generator(s) produces (including, but not limited to, output from steam
turbine(s), combustion turbine(s), and gas expander(s)), as measured at
the generator terminals, less the electricity used to operate the plant
(i.e., auxiliary loads); such uses include fuel handling equipment,
pumps, fans, pollution control equipment, other electricity needs, and
transformer losses as measured at the transmission side of the step up
transformer (e.g., the point of sale).
Net energy output means:
(1) The net electric or mechanical output from the affected
facility plus 100 percent of the useful thermal output; or
(2) For CHP facilities, where at least 20.0 percent of the total
gross or net energy output consists of useful thermal output on a 12-
calendar-month rolling average basis, the net electric or mechanical
output from the affected turbine divided by 0.95, plus 100 percent of
the useful thermal output.
[[Page 2003]]
(3) For district energy CHP facilities, where at least 20.0 percent
of the total gross or net energy output consists of useful thermal
output on a 12-calendar-month rolling average basis, the net electric
or mechanical output from the affected turbine divided by 0.95, plus
100 percent of the useful thermal output divided by 0.95.
Noncontinental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, the Northern
Mariana Islands, or offshore turbines.
Offshore turbine means a stationary combustion turbine located on a
platform or facility in an ocean, territorial sea, the outer
continental shelf, or the Great Lakes of North America and stationary
combustion turbines located in a coastal management zone and elevated
on a platform.
Operating day means a 24-hour period between midnight and the
following midnight during which any fuel is combusted at any time in
the unit. It is not necessary for fuel to be combusted continuously for
the entire 24-hour period.
Operating hour means a clock hour during which any fuel is
combusted in the affected unit. If the unit combusts fuel for the
entire clock hour, the operating hour is a full operating hour. If the
unit combusts fuel for only part of the clock hour, the operating hour
is a partial operating hour.
Out-of-control period means any period beginning with the hour
corresponding to the completion of a daily calibration error, linearity
check, or quality assurance audit that indicates that the instrument is
not measuring and recording within the applicable performance
specifications and ending with the hour corresponding to the completion
of an additional calibration error, linearity check, or quality
assurance audit following corrective action that demonstrates that the
instrument is measuring and recording within the applicable performance
specifications.
Simple cycle combustion turbine means any stationary combustion
turbine which does not recover heat from the combustion turbine engine
exhaust gases for purposes other than enhancing the performance of the
stationary combustion turbine itself.
Small combustion turbine means a stationary combustion turbine with
a base load rating less than or equal to 50 MMBtu/h of heat input.
Solid fuel means any fuel that has a definite shape and volume, has
no tendency to flow or disperse under moderate stress, and is not
liquid or gaseous at ISO conditions. This includes, but is not limited
to, coal, biomass, and pulverized solid fuels.
Stationary combustion turbine means all equipment including, but
not limited to, the combustion turbine engine, the fuel, air,
lubrication and exhaust gas systems, control systems (except post
combustion emissions control equipment), heat recovery system
(including heat recovery steam generators and duct burners); steam
turbine; fuel compressor and/or pump, any ancillary components and sub-
components comprising any simple cycle stationary combustion turbine,
any combined cycle combustion turbine, and any combined heat and power
combustion turbine based system; plus any integrated equipment that
provides electricity or useful thermal output to the combustion turbine
engine (e.g., onsite photovoltaics), heat recovery system, or auxiliary
equipment. Stationary means that the combustion turbine is not self-
propelled or intended to be propelled while performing its function. It
may, however, be mounted on a vehicle for portability. Portable
combustion turbines are excluded from the definition of ``stationary
combustion turbine,'' and not regulated under this part, if the turbine
meets the definition of ``nonroad engine'' under title II of the Clean
Air Act and applicable regulations and is certified to meet emissions
standards promulgated pursuant to title II of the Clean Air Act, along
with all related requirements.
Standard cubic foot (scf) means the quantity of gas that would
occupy a volume of 1 cubic foot at 293 Kelvin (20.0 [deg]C, 68 [deg]F)
and 101.325 kPa (14.69 psi, 1 atm) of pressure.
Standard cubic meter (scm) means the quantity of gas that would
occupy a volume of 1 cubic meter at 293 Kelvin (20.0 [deg]C, 68 [deg]F)
and 101.325 kPa (14.69 psi, 1 atm) of pressure.
System emergency means periods when the Reliability Coordinator has
declared an Energy Emergency Alert level 1, 2, or 3, which should
follow NERC Reliability Standard EOP-011-2, its successor, or
equivalent.
Temporary combustion turbine means a combustion turbine that is
intended to and remains at a single stationary source (or group of
stationary sources located within a contiguous area and under common
control) for 24 consecutive months or less.
Turbine tuning means planned maintenance or parameter performance
testing of a combustion turbine engine involving adjustment of the
operating configuration to maintain proper combustion dynamics or
testing machine operating performance. Turbine tuning is limited to 30
hours annually.
Useful thermal output means the thermal energy made available for
use in any heating application (e.g., steam delivered to an industrial
process for a heating application, including thermal cooling
applications) that is not used for electric generation or mechanical
output at the affected facility to directly enhance the performance of
the affected facility (e.g., economizer output is not useful thermal
output, but thermal energy used to reduce fuel moisture is considered
useful thermal output) or to supply energy to a pollution control
device at the affected facility (e.g., steam provided to a carbon
capture system would not be considered useful thermal output). Useful
thermal output for affected facilities with no condensate return (or
other thermal energy input to affected facilities) or where measuring
the energy in the condensate (or other thermal energy input to the
affected facilities) would not meaningfully impact the emission rate
calculation is measured against the energy in the thermal output at
SATP conditions (e.g. liquid water). Affected facilities with
meaningful energy in the condensate return (or other thermal energy
input to the affected facility) must measure the energy in the
condensate and subtract that energy relative to SATP conditions from
the measured thermal output.
Valid data means quality-assured data generated by continuous
monitoring systems that are installed, operated, and maintained
according to this part or part 75 of this chapter as applicable. For
CEMS maintained according to part 75, the initial certification
requirements in Sec. 75.20 and appendix A to part 75 must be met
before quality-assured data are reported under this subpart; for on-
going quality assurance, the daily, quarterly, and semiannual/annual
test requirements in sections 2.1, 2.2, and 2.3 of appendix B to part
75 must be met and the data validation criteria in sections 2.1.5,
2.2.3, and 2.3.2 of appendix B to part 75 must be met. For fuel flow
meters maintained according to part 75, the initial certification
requirements in section 2.1.5 of appendix D to part 75 must be met
before quality-assured data are reported under this subpart (except for
qualifying commercial billing meters under section 2.1.4.2 of appendix
D to part 75), and for on-going quality assurance, the provisions in
section 2.1.6 of appendix D to part 75 apply (except for qualifying
commercial billing meters). Any out-of-control data is not considered
valid data.
[[Page 2004]]
Table 1 to Subpart KKKKa of Part 60--Nitrogen Oxide Emission Standards for Stationary Combustion Turbines
----------------------------------------------------------------------------------------------------------------
Combustion turbine
Combustion turbine type base load rated heat Input-based NOX Optional output-based NOX
input (HHV) emission standard \1\ standard \2\
----------------------------------------------------------------------------------------------------------------
New, firing natural gas with >850 MMBtu/h.......... 5 ppm at 15 percent O2 0.054 kg/MWh-gross (0.12 lb/
utilization rate >45 percent. or 7.9 ng/J (0.018 lb/ MWh-gross) 0.055 kg/MWh-
MMBtu). net (0.12 lb/MWh-net).
New, firing natural gas with >850 MMBtu/h.......... 25 ppm at 15 percent 0.38 kg/MWh-gross (0.83 lb/
utilization rate <=45 percent and O2 or 40 ng/J (0.092 MWh-gross) 0.39 kg/MWh-net
with design efficiency >=38 lb/MMBtu). (0.85 lb/MWh-net).
percent.
New, firing natural gas with >850 MMBtu/h.......... 9 ppm at 15 percent O2 0.17 kg/MWh-gross (0.37 lb/
utilization rate <=45 percent and or 14 ng/J (0.033 lb/ MWh-gross) 0.17 kg/MWh-net
with design efficiency <38 percent. MMBtu). (0.38 lb/MWh-net).
New, modified, or reconstructed, >850 MMBtu/h.......... 42 ppm at 15 percent 0.45 kg/MWh-gross (1.0 lb/
firing non-natural gas. O2 or 70 ng/J (0.16 MWh-gross) 0.46 kg/MWh-net
lb/MMBtu). (1.0 lb/MWh-net).
Modified or reconstructed, firing >850 MMBtu/h.......... 25 ppm at 15 percent 0.38 kg/MWh-gross (0.83 lb/
natural gas, at all utilization O2 or 40 ng/J (0.092 MWh-gross) 0.39 kg/MWh-net
rates, with design efficiency >=38 lb/MMBtu). (0.85 lb/MWh-net).
percent.
Modified or reconstructed, firing >850 MMBtu/h.......... 15 ppm at 15 percent 0.28 kg/MWh-gross (0.62 lb/
natural gas, at all utilization O2 or 24 ng/J (0.055 MWh-gross) 0.29 kg/MWh-net
rates, with design efficiency <38 lb/MMBtu). (0.30 lb/MWh-net).
percent.
New, firing natural gas, at >50 MMBtu/h and <=850 15 ppm at 15 percent 0.20 kg/MWh-gross (0.43 lb/
utilization rate >45 percent. MMBtu/h. O2 or 24 ng/J (0.055 MWh-gross) 0.20 kg/MWh-net
lb/MMBtu). (0.44 lb/MWh-net).
New, firing natural gas, at >50 MMBtu/h and <=850 25 ppm at 15 percent 0.54 kg/MWh-gross (1.2 lb/
utilization rate <=45 percent. MMBtu/h. O2 or 40 ng/J (0.092 MWh-gross) 0.56 kg/MWh-net
lb/MMBtu). (1.2 lb/MWh-net).
Modified or reconstructed, firing >20 MMBtu/h and <=850 42 ppm at 15 percent 0.91 kg/MWh-gross (2.0 lb/
natural gas. MMBtu/h. O2 or 67 ng/J (0.15 MWh-gross) 0.92 kg/MWh-net
lb/MMBtu). (2.0 lb/MWh-net).
New, firing non-natural gas........ >50 MMBtu/h and <=850 74 ppm at 15 percent 1.6 kg/MWh-gross (3.6 lb/
MMBtu/h. O2 or 120 ng/J (0.29 MWh-gross) 1.6 kg/MWh-net
lb/MMBtu). (3.7 lb/MWh-net).
Modified or reconstructed, firing >20 MMBtu/h and <=850 96 ppm at 15 percent 2.1 kg/MWh-gross (4.7 lb/
non-natural gas. MMBtu/h. O2 or 160 ng/J (0.37 MWh-gross) 2.2 kg/MWh-net
lb/MMBtu). (4.8 lb/MWh-net).
New, firing natural gas............ <=50 MMBtu/h.......... 25 ppm at 15 percent 0.64 kg/MWh-gross (1.4 lb/
O2 or 40 ng/J (0.092 MWh-gross) 0.65 kg/MWh-net
lb/MMBtu). (1.4 lb/MWh-net).
New, firing non-natural gas........ <=50 MMBtu/h.......... 96 ppm at 15 percent 2.4 kg/MWh-gross (5.3 lb/
O2 or 160 ng/J (0.37 MWh-gross) 2.5 kg/MWh-net
lb/MMBtu). (5.4 lb/MWh-net).
Modified or reconstructed, all <=20 MMBtu/h.......... 150 ppm at 15 percent 3.9 kg/MWh-gross (8.7 lb/
fuels. O2 or 240 ng/J (0.55 MWh-gross) 4.0 kg/MWh-net
lb/MMBtu). (8.9 lb/MWh-net).
New, firing natural gas, either >50 MMBtu/h........... 25 ppm at 15 percent N/A.
offshore turbines, turbines O2 or 40 ng/J (0.092
bypassing the heat recovery unit, lb/MMBtu).
and/or temporary turbines.
Located north of the Arctic Circle <=300 MMBtu/h......... 150 ppm at 15 percent N/A.
(latitude 66.5 degrees north), O2 or 240 ng/J) 0.55
operating at ambient temperatures lb/MMBtu.
less than 0[deg] F (-18[deg] C),
modified or reconstructed offshore
turbines, operated during periods
of turbine tuning, byproduct-fired
turbines, and/or operating at less
than 70 percent of the base load
rating.
Located north of the Arctic Circle >300 MMBtu/h.......... 96 ppm at 15 percent N/A.
(latitude 66.5 degrees north), O2 or 150 ng/J (0.35
operating at ambient temperatures lb/MMBtu).
less than 0[deg] F (-18[deg] C),
modified or reconstructed offshore
turbines, operated during periods
of turbine tuning, byproduct-fired
turbines, and/or operating at less
than 70 percent of the base load
rating.
Heat recovery units operating All sizes............. 54 ppm at 15 percent N/A.
independent of the combustion O2 or 86 ng/J) 0.20
turbine. lb/MMBtu.
----------------------------------------------------------------------------------------------------------------
\1\ Input-based standards are determined on a 4-operating-hour rolling average basis.
\2\ Output-based standards are determined on a 30-operating-day average basis.
Table 2 to Subpart KKKKa of Part 60--Alternative Mass-Based NOX Emission
Standards for Stationary Combustion Turbines
------------------------------------------------------------------------
12-Calendar-month
4-Hour emissions emissions rate
Combustion turbine type rate (lb NOX/MW- (ton NOX/MW-rated
rated output) output)
------------------------------------------------------------------------
Natural Gas.................. 0.38 kg NOX/MW-rated 0.44 tonne NOX/MW-
output (0.83 lb NOX/ rated output (0.48
MW-rated output). ton NOX/MW-rated
output).
Non-Natural Gas.............. 0.82 kg NOX/MW-rated 0.74 tonne NOX/MW-
output (1.8 lb NOX/ rated output (0.81
MW-rated output). ton NOX/MW-rated
output).
------------------------------------------------------------------------
Table 3 to Subpart KKKKa of Part 60--Applicability of Subpart A of This Part to This Subpart
----------------------------------------------------------------------------------------------------------------
General provisions citation Subject of citation Applies to subpart KKKKa Explanation
----------------------------------------------------------------------------------------------------------------
Sec. 60.1.................... Applicability........... Yes......................
Sec. 60.2.................... Definitions............. Yes...................... Additional terms defined
in Sec. 60.4420a.
Sec. 60.3.................... Units and Abbreviations. Yes......................
[[Page 2005]]
Sec. 60.4.................... Address................. Yes...................... Does not apply to
information reported
electronically through
ECMPS. Duplicate
submittals are not
required.
Sec. 60.5.................... Determination of Yes......................
construction or
modification.
Sec. 60.6.................... Review of plans......... Yes......................
Sec. 60.7.................... Notification and Yes...................... Only the requirements to
Recordkeeping. submit the notifications
in Sec. 60.7(a)(1) and
(3) and to keep records
of malfunctions in Sec.
60.7(b), if applicable.
Sec. 60.8(a)................. Performance tests....... Yes......................
Sec. 60.8(b)................. Performance test method Yes...................... Administrator can approve
alternatives. alternate methods.
Sec. 60.8(c)................. Conducting performance No....................... Overridden by Sec.
tests. 60.4320a(d).
Sec. 60.8(d)-(f)............. Conducting performance Yes......................
tests.
Sec. 60.9.................... Availability of Yes......................
Information.
Sec. 60.10................... State authority......... Yes......................
Sec. 60.11................... Compliance with No.......................
standards and
maintenance
requirements.
Sec. 60.12................... Circumvention........... Yes......................
Sec. 60.13(a)-(h), (j)....... Monitoring requirements. Yes......................
Sec. 60.13(i)................ Monitoring requirements. Yes...................... Administrator can approve
alternative monitoring
procedures or
requirements.
Sec. 60.14................... Modification............ Yes......................
Sec. 60.15................... Reconstruction.......... Yes......................
Sec. 60.16................... Priority list........... No.......................
Sec. 60.17................... Incorporations by Yes......................
reference.
Sec. 60.18................... General control device Yes......................
requirements.
Sec. 60.19................... General notification and Yes...................... Does not apply to
reporting requirements. notifications under Sec.
75.61 of this chapter or
to information reported
through ECMPS.
----------------------------------------------------------------------------------------------------------------
[FR Doc. 2026-00677 Filed 1-14-26; 8:45 am]
BILLING CODE 6560-50-P