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Proposed Rule2024-27872

Review of New Source Performance Standards for Stationary Combustion Turbines and Stationary Gas Turbines

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Published

December 13, 2024

Issuing agencies

Environmental Protection Agency

Abstract

The Environmental Protection Agency (EPA) is proposing amendments to the Standards of Performance for new, modified, and reconstructed stationary combustion turbines and stationary gas turbines based on a review of available control technologies for limiting emissions of criteria air pollutants. This review of the new source performance standards (NSPS) is required by the Clean Air Act (CAA). As a result of this review, the EPA is proposing to establish size-based subcategories for new, modified, and reconstructed stationary combustion turbines that also recognize distinctions between those that operate at varying loads or capacity factors and those firing natural gas or non-natural gas fuels. In general, the EPA is proposing that combustion controls with the addition of post-combustion selective catalytic reduction (SCR) is the best system of emission reduction (BSER) for limiting nitrogen oxide (NO<INF>X</INF>) emissions from this source category, with certain, limited exceptions. Based on the application of this BSER and other updates in technical information, the EPA is proposing to lower the NO<INF>X</INF> standards of performance for most of the stationary combustion turbines included in this source category. In addition, for new, modified, and reconstructed stationary combustion turbines that fire or co-fire hydrogen, the EPA is proposing to ensure that those sources are subject to the same level of control for NO<INF>X</INF> emissions as sources firing natural gas or non-natural gas fuels, depending on the percentage of hydrogen fuel being utilized. The EPA is proposing to maintain the current standards for sulfur dioxide (SO<INF>2</INF>) emissions, because after reviewing the current SO<INF>2</INF> standards, we propose to find that the use of low-sulfur fuels remains the BSER. Finally, the Agency is proposing amendments to address specific technical and editorial issues to clarify the existing regulations.

Full Text

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<title>Federal Register, Volume 89 Issue 240 (Friday, December 13, 2024)</title>
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[Federal Register Volume 89, Number 240 (Friday, December 13, 2024)]
[Proposed Rules]
[Pages 101306-101356]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2024-27872]

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Vol. 89

Friday,

No. 240

December 13, 2024

Part V

Environmental Protection Agency

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40 CFR Part 60

Review of New Source Performance Standards for Stationary Combustion
Turbines and Stationary Gas Turbines; Proposed Rule

Federal Register / Vol. 89, No. 240 / Friday, December 13, 2024 /
Proposed Rules

[[Page 101306]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2024-0419; FRL-11542-01-OAR]
RIN 2060-AW21

Review of New Source Performance Standards for Stationary
Combustion Turbines and Stationary Gas Turbines

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: The Environmental Protection Agency (EPA) is proposing
amendments to the Standards of Performance for new, modified, and
reconstructed stationary combustion turbines and stationary gas
turbines based on a review of available control technologies for
limiting emissions of criteria air pollutants. This review of the new
source performance standards (NSPS) is required by the Clean Air Act
(CAA). As a result of this review, the EPA is proposing to establish
size-based subcategories for new, modified, and reconstructed
stationary combustion turbines that also recognize distinctions between
those that operate at varying loads or capacity factors and those
firing natural gas or non-natural gas fuels. In general, the EPA is
proposing that combustion controls with the addition of post-combustion
selective catalytic reduction (SCR) is the best system of emission
reduction (BSER) for limiting nitrogen oxide (NO<INF>X</INF>) emissions
from this source category, with certain, limited exceptions. Based on
the application of this BSER and other updates in technical
information, the EPA is proposing to lower the NO<INF>X</INF> standards
of performance for most of the stationary combustion turbines included
in this source category. In addition, for new, modified, and
reconstructed stationary combustion turbines that fire or co-fire
hydrogen, the EPA is proposing to ensure that those sources are subject
to the same level of control for NO<INF>X</INF> emissions as sources
firing natural gas or non-natural gas fuels, depending on the
percentage of hydrogen fuel being utilized. The EPA is proposing to
maintain the current standards for sulfur dioxide (SO<INF>2</INF>)
emissions, because after reviewing the current SO<INF>2</INF>
standards, we propose to find that the use of low-sulfur fuels remains
the BSER. Finally, the Agency is proposing amendments to address
specific technical and editorial issues to clarify the existing
regulations.

DATES:
Comments. Comments must be received on or before March 13, 2025.
Comments on the information collection provisions submitted to the
Office of Management and Budget (OMB) under the Paperwork Reduction Act
(PRA) are best assured of consideration by OMB if OMB receives a copy
of your comments on or before January 13, 2025. For specific
instructions, please see the PRA discussion in the Statutory and
Executive Order Reviews section of this document.
Public Hearing. If anyone contacts us requesting a public hearing
on or before December 18, 2024, we will hold a virtual public hearing.
See SUPPLEMENTARY INFORMATION for information on requesting and
registering for a public hearing.

ADDRESSES: You may send comments, identified by Docket ID No. EPA-HQ-
OAR-2024-0419, by any of the following methods:
<bullet> Federal eRulemaking Portal: <a href="https://www.regulations.gov">https://www.regulations.gov</a>
(our preferred method). Follow the online instructions for submitting
comments.
<bullet> Email: <a href="/cdn-cgi/l/email-protection#57367a3639337a257a3338343c32231732273679303821">[email&#160;protected]</a>. Include Docket ID No. EPA-
HQ-OAR-2024-0419 in the subject line of the message.
<bullet> Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2024-0419.
<bullet> Mail: U.S. Environmental Protection Agency, EPA Docket
Center, Docket ID No. EPA-HQ-OAR-2024-0419, Mail Code 28221T, 1200
Pennsylvania Avenue NW, Washington, DC 20460.
<bullet> Hand/Courier Delivery: EPA Docket Center, WJC West
Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004.
The Docket Center's hours of operation are 8:30 a.m.-4:30 p.m., Monday-
Friday (except Federal Holidays).
Instructions: All submissions received must include the Docket ID
No. for this rulemaking. Comments received may be posted without change
to <a href="https://www.regulations.gov">https://www.regulations.gov</a>, including any personal information
provided. For detailed instructions on sending comments and additional
information on the rulemaking process, see the SUPPLEMENTARY
INFORMATION section below.

FOR FURTHER INFORMATION CONTACT: John Ashley, Sector Policies and
Programs Division (D243-02), Office of Air Quality Planning and
Standards, 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: <a href="/cdn-cgi/l/email-protection#93f2e0fbfff6eabdf9fcfbfdd3f6e3f2bdf4fce5">[email&#160;protected]</a>.

SUPPLEMENTARY INFORMATION:
Participation in virtual public hearing. To request a virtual
public hearing, contact the public hearing team at (888) 372-8699 or by
email at <a href="/cdn-cgi/l/email-protection#c291929286b2b7a0aeaba1aaa7a3b0abaca582a7b2a3eca5adb4">[email&#160;protected]</a>. If requested, the public hearing
will be held via virtual platform. The EPA will announce the date of
the hearing and additional details on the virtual public hearing at
<a href="https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance">https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance</a>. The hearing will
convene at 11:00 a.m. Eastern Time (ET) and will conclude at 4:00 p.m.
ET. The EPA may close a session 15 minutes after the last pre-
registered speaker has testified if there are no additional speakers.
The EPA will begin pre-registering speakers for the hearing no
later than 1 business day after a request has been received. The EPA
will accept registrations on an individual basis. To register to speak
at the virtual hearing, please use the online registration form
available at <a href="https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance">https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance</a> or
contact the public hearing team at (888) 372-8699 or by email at
<a href="/cdn-cgi/l/email-protection#feadaeaeba8e8b9c92979d969b9f8c979099be9b8e9fd0999188">[email&#160;protected]</a>. The last day to pre-register to speak at the
hearing will be December 26, 2024. Prior to the hearing, the EPA will
post a general agenda that will list pre-registered speakers at:
<a href="https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance">https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance</a>.
The EPA will make every effort to follow the schedule as closely as
possible on the day of the hearing; however, please plan for the
hearing to run either ahead of schedule or behind schedule.
Each commenter will have 4 minutes to provide oral testimony. The
EPA encourages commenters to submit a copy of their oral testimony as
written comments electronically to the rulemaking docket.
The EPA may ask clarifying questions during the oral presentations
but will not respond to the presentations at that time. Written
statements and supporting information submitted during the comment
period will be considered with the same weight as oral testimony and
supporting information presented at the public hearing.
Please note that any updates made to any aspect of the hearing will
be posted online at <a href="https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance">https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance</a>.

[[Page 101307]]

While the EPA expects the hearing to go forward as described in this
section, please monitor our website or contact the public hearing team
at (888) 372-8699 or by email at <a href="/cdn-cgi/l/email-protection#b8ebe8e8fcc8cddad4d1dbd0ddd9cad1d6dff8ddc8d996dfd7ce">[email&#160;protected]</a> to determine
if there are any updates. The EPA does not intend to publish a document
in the Federal Register announcing updates.
If you require the services of a translator or a special
accommodation such as audio description, please pre-register for the
hearing with the public hearing team and describe your needs by
December 20, 2024. The EPA may not be able to arrange accommodations
without advanced notice.
Docket. The EPA has established a docket for this rulemaking under
Docket ID No. EPA-HQ-OAR-2024-0419. All documents in the docket are
listed in the <a href="http://Regulations.gov">Regulations.gov</a> index. Although listed in the index, 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 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. With the exception of such
material, publicly available docket materials are available
electronically in <a href="http://Regulations.gov">Regulations.gov</a>.
Written Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2024-0419, at <a href="https://www.regulations.gov">https://www.regulations.gov</a> (our preferred
method), or the other methods identified in the ADDRESSES section. Once
submitted, comments cannot be edited or removed from the docket. The
EPA may publish any comment received to its public docket. Do not
submit to EPA's docket at <a href="https://www.regulations.gov">https://www.regulations.gov</a> any information
you consider to be CBI or other information whose disclosure is
restricted by statute. This type of information should be submitted as
discussed in the Submitting CBI section of this document.
Multimedia submissions (audio, video, etc.) must be accompanied by
a written comment. The written comment is considered the official
comment and should include discussion of all points you wish to make.
The EPA will generally not consider comments or comment contents
located outside of the primary submission (i.e., on the Web, cloud, or
other file sharing system). Please visit <a href="https://www.epa.gov/dockets/commenting-epa-dockets">https://www.epa.gov/dockets/commenting-epa-dockets</a> for additional submission methods; the full EPA
public comment policy; information about CBI or multimedia submissions;
and general guidance on making effective comments.
The <a href="https://www.regulations.gov">https://www.regulations.gov</a> website allows you to submit your
comment anonymously, which means the EPA will not know your identity or
contact information unless you provide it in the body of your comment.
If you send an email comment directly to the EPA without going through
<a href="https://www.regulations.gov">https://www.regulations.gov</a>, your email address will be automatically
captured and included as part of the comment that is placed in the
public docket and made available on the internet. If you submit an
electronic comment, the EPA recommends that you include your name and
other contact information in the body of your comment and with any
digital storage media you submit. If the EPA cannot read your comment
due to technical difficulties and cannot contact you for clarification,
the EPA may not be able to consider your comment. Electronic files
should not include special characters or any form of encryption and be
free of any defects or viruses.
Submitting CBI. Do not submit information containing CBI to the EPA
through <a href="https://www.regulations.gov">https://www.regulations.gov</a>. Clearly mark the part or all of
the information that you claim to be CBI. For CBI information on any
digital storage media that you mail to the EPA, note the docket ID,
mark the outside of the digital storage media as CBI, and identify
electronically within the digital storage media the specific
information that is claimed as CBI. In addition to one complete version
of the comments that includes information claimed as CBI, you must
submit a copy of the comments that does not contain the information
claimed as CBI directly to the public docket through the procedures
outlined in the Written Comments section of this document. If you
submit any digital storage media that does not contain CBI, mark the
outside of the digital storage media clearly that it does not contain
CBI and note the docket ID. Information not marked as CBI will be
included in the public docket and the EPA's electronic public docket
without prior notice. Information marked as CBI will not be disclosed
except in accordance with procedures set forth in 40 Code of Federal
Regulations (CFR) part 2.
Our preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol (FTP),
or other online file sharing services (e.g., Dropbox, OneDrive, Google
Drive). Electronic submissions must be transmitted directly to the
Office of Air Quality Planning and Standards (OAQPS) CBI Office at the
email address <a href="/cdn-cgi/l/email-protection#0b646a7a7b786869624b6e7b6a256c647d">[email&#160;protected]</a>, and as described above, should include
clear CBI markings and note the docket ID. 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 <a href="/cdn-cgi/l/email-protection#f9969888898a9a9b90b99c8998d79e968f">[email&#160;protected]</a> to request a file transfer link.
If sending CBI information through the postal service, please send it
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,
Research Triangle Park, North Carolina 27711, Attention Docket ID No.
EPA-HQ-OAR-2024-0419. The mailed CBI material should be double wrapped
and clearly marked. Any CBI markings should not show through the outer
envelope.
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
ASTM American Society for Testing and Materials
BACT best achievable control technology
BPT benefit-per-ton
BSER best system of emission reduction
Btu British thermal unit
CAA Clean Air Act
CBI Confidential Business Information
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CFR Code of Federal Regulations
CHP combined heat and power
CO carbon monoxide
DLE dry low-emission
DLN dry low NO<INF>X</INF>
EGU electric generating unit
EJ environmental justice
EPA Environmental Protection Agency
ERT Electronic Reporting Tool
FR Federal Register
FTP file transfer protocol
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
kW kilowatt
LAER lowest achievable emission rate

[[Page 101308]]

lb/MWh pounds per megawatt-hour
lb/MMBtu pounds per million British thermal units
mg/scm milligrams per standard cubic meter
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
NO<INF>X</INF> nitrogen oxide
NSPS new source performance standards
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act
O<INF>2</INF> oxygen
O&M operating and maintenance
OAQPS Office of Air Quality Planning and Standards
OMB Office of Management and Budget
PDF portable document format
PM particulate matter
PM<INF>2.5</INF> particulate matter (diameter less than or equal to
2.5 micrometers)
ppm parts per million
ppmv parts per million by volume
ppmw parts per million by weight
PRA Paperwork Reduction Act
RACT reasonably available control technology
RBLC RACT/BACT/LAER Clearinghouse
RFA Regulatory Flexibility Act
RIA regulatory impact analysis
scf standard cubic feet
scm standard cubic meter
SCR selective catalytic reduction
SO<INF>2</INF> 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
VOC volatile organic compound(s)
WFR water-to-fuel ratio

Organization of this document. The information in this preamble is
organized as follows:

I. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document and other related
information?
II. Background
A. What is the statutory authority for this action?
B. What is this source category?
C. What are the current NSPS requirements?
D. What data and information were used to support this action?
E. What outreach and engagement did the EPA conduct?
F. How did the EPA consider environmental justice in the
development of this action?
G. How does the EPA perform the NSPS review?
H. 2012 NSPS Proposal
III. What actions are we proposing?
A. Applicability
B. NO<INF>X</INF> Emission Standards
C. SO<INF>2</INF> Emission Standards
D. Consideration of Other Criteria Pollutants
E. Additional Subpart KKKKa Proposals
F. Additional Request for Comments
G. Proposal of NSPS Subpart KKKKa Without Startup, Shutdown,
Malfunction Exemptions
H. Testing and Monitoring Requirements
I. Electronic Reporting
J. Compliance Dates
K. Severability
IV. 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?
F. What analysis of environmental justice did we conduct?
V. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 14094: Modernizing Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA) and
1 CFR Part 51
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations and Executive Order 14096: Revitalizing Our Nation's
Commitment to Environmental Justice for All

I. General Information

A. Does this action apply to me?

The source category that is the subject of this proposal is
composed of any industry using a newly constructed, modified, or
reconstructed stationary combustion turbine as defined in section II.B
of this preamble and regulated under Clean Air Act (CAA) section 111,
New Source Performance Standards. 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 221112 (Fossil Fuel Electric Power Generation), 486210
(Pipeline Transportation of Natural Gas), 22111 (Electric Power
Generation), 211130 (Natural Gas Extraction), 221210 (Natural Gas
Distribution), 325110 (Petrochemical Manufacturing), and 2111 (Oil and
Gas Extraction). The NAICS codes serve as a guide for readers outlining
the entities that this proposed action is likely to affect. Please see
the accompanying Regulatory Impact Analysis (RIA) in the docket for
this proposed rulemaking for a complete list of potentially affected
sources and their NAICS codes. The proposed standards, once
promulgated, will be directly applicable to affected facilities that
begin construction, reconstruction, or modification after the date of
publication of the proposed standards in the Federal Register. Federal,
State, local, and Tribal government entities that own and/or operate
stationary combustion turbines subject to existing 40 Code of Federal
Regulations (CFR) part 60, subparts GG or KKKK, or proposed 40 CFR part
60, subpart KKKKa, may be affected by these proposed amendments and
standards.

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 action is available via the internet at <a href="https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance">https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance</a>. Following publication in the Federal
Register, the EPA will post the Federal Register version of the
proposal and key technical documents at this same web page. In
accordance with 5 U.S.C. 553(b)(4), a summary of this proposed rule may
be found at Docket ID No. EPA-HQ-OAR-2024-0419 at <a href="https://www.regulations.gov">https://www.regulations.gov</a>.
Memoranda showing the edits that would be necessary to incorporate
the changes to 40 CFR part 60, subparts GG and KKKK and 40 CFR part 60,
subpart KKKKa proposed in this action are available in the docket.
Following signature by the EPA Administrator, the EPA also will post a
copy of this document to <a href="https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance">https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance</a>.

II. Background

A. What is the statutory authority for this action?

The EPA's authority for this proposed rule is CAA section 111,
which governs the establishment of standards of performance for
stationary sources. Section 111(b)(1)(A) of the CAA requires the EPA
Administrator to list categories

[[Page 101309]]

of stationary sources that in the Administrator's judgment cause or
contribute significantly to air pollution that may reasonably be
anticipated to endanger public health or welfare. The EPA must then
issue performance standards for new (and modified or reconstructed)
sources in each source category pursuant to CAA section 111(b)(1)(B).
These standards are referred to as new source performance standards, or
NSPS. The EPA has the authority to define the scope of the source
categories, determine the pollutants for which standards should be
developed, set the emission level of the standards, and distinguish
among classes, types, and sizes within categories in establishing the
standards.
CAA section 111(b)(1)(B) requires the EPA to ``at least every 8
years review and, if appropriate, revise'' new source performance
standards. 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. When conducting a review of an existing performance standard,
the EPA has the discretion and authority to add emission limits for
pollutants or emission sources not currently regulated for that source
category.
In setting or revising a performance standard, CAA section
111(a)(1) provides that performance standards are to 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.'' The term ``standard of
performance'' in CAA section 111(a)(1) makes clear that the EPA is to
determine both the best system of emission reduction (BSER) for the
regulated sources in the source category and the degree of emission
limitation achievable through application of the BSER. The EPA must
then, under CAA section 111(b)(1)(B), promulgate standards of
performance for new sources that reflect that level of stringency. 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.
Pursuant to the definition of new source in CAA section 111(a)(2),
standards of performance apply to facilities that begin construction,
reconstruction, or modification 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.

B. What is this source category?

Sources subject to the proposed NSPS are stationary combustion
turbines with a design base load rating (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)),\1\ based on
the higher heating value (HHV) of the fuel, that commence construction,
modification, or reconstruction after December 13, 2024. A stationary
combustion turbine is defined as 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. The source is ``stationary'' because 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.
---------------------------------------------------------------------------

\1\ The base load rating is based on the heat input to the
combustion turbine engine. 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 HRSG and duct burners that are associated with a combustion
turbine subject to this subpart.
---------------------------------------------------------------------------

C. What are the current NSPS requirements?

The NSPS for stationary combustion turbines includes standards of
performance to limit emissions of nitrogen oxide (NO<INF>X</INF>) and
sulfur dioxide (SO<INF>2</INF>). The EPA last revised the NSPS on July
6, 2006, and promulgated 40 CFR part 60, subpart KKKK, which is
applicable to stationary combustion turbines for which construction,
modification, or reconstruction was commenced after February 18, 2005
(71 FR 38482). Standards of performance for the source category of
stationary gas turbines were originally promulgated in 40 CFR part 60,
subpart GG (44 FR 52792; September 10, 1979) and only apply to sources
that were new prior to 2005.
The NO<INF>X</INF> standards in subpart KKKK are based on the
application of combustion controls (as the best system of emission
reduction) 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
(O<INF>2</INF>).\2\ 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 NO<INF>X</INF> limit in subpart
KKKK is based on the application of combustion controls as the BSER,
but individual standards may differ for individual 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. 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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\2\ Throughout this document, all references to parts per
million (ppm) NO<INF>X</INF> are intended to be interpreted as parts
per million by volume dry (ppmvd) at 15 percent O<INF>2</INF>,
unless otherwise noted.
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Specifically, in subpart KKKK, the EPA identifies 14 subcategories
of stationary combustion turbines and establishes NO<INF>X</INF>
emission limits for each. The current size-based subcategories include
turbines with a design heat input rating of less than or equal to 50
MMBtu/h, those with a design heat input rating of greater than 50
MMBtu/h and less than or equal to 850 MMBtu/h, and those with a design
heat input rating greater than 850 MMBtu/h. There are separate

[[Page 101310]]

subcategories for combustion turbines operating at part load, for
modified and reconstructed combustion turbines, heat recovery units
operating independent of the combustion turbine, and turbines operating
at low ambient temperatures. A specific NO<INF>X</INF> performance
standard is identified for each of the 14 subcategories, and the limits
range from 15 ppm to 150 ppm (see Table 1: NO<INF>X</INF> Emission
Standards; 71 FR 38483, July 6, 2006).
The standards of performance for SO<INF>2</INF> emissions in
subpart KKKK reflect the use of low-sulfur fuels. The fuel sulfur
content limit is 26 ng SO<INF>2</INF>/J (0.060 lb SO<INF>2</INF>/MMBtu)
heat input for combustion turbines located in continental areas and 180
ng SO<INF>2</INF>/J (0.42 lb SO<INF>2</INF>/MMBtu) heat input in
noncontinental areas. This is approximately equivalent to 0.05 percent
sulfur by weight (500 parts per million by weight (ppmw)) for fuel oil
in continental areas and 0.4 percent sulfur by weight (4,000 ppmw) for
fuel oil in noncontinental areas, respectively. Subpart KKKK also
includes an optional output-based SO<INF>2</INF> standard that limits
the discharge into the atmosphere of any gases that contain
SO<INF>2</INF> in excess of 110 ng/J (0.90 lb/MWh) gross energy output
for turbines located in continental areas and 780 ng/J (6.2 lb/MWh)
gross energy output for turbines located in noncontinental areas.
Thousands of stationary combustion turbines are operating across
numerous industrial sectors. In the utility sector alone, there are
approximately 3,400 existing stationary combustion turbines.\3\ Each of
these affected sources is subject to either subpart KKKK or subpart GG.
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\3\ See the U.S. Environmental Protection Agency's (EPA)
National Electric Energy Data System database. NEEDS rev 06-06-2024.
Accessed at <a href="https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs">https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs</a>.
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D. What data and information were used to support this action?

The Agency analyzed hourly NO<INF>X</INF> emissions data reported
to the EPA's Clean Air Markets Program Data (CAMPD) under 40 CFR part
75 and other data and information available in the Energy Information
Administration's (EIA) and the EPA's databases. In addition, the Agency
reviewed other available information sources to determine whether there
have been developments in practices, processes, or control technologies
by stationary combustion turbines. These include the following:
<bullet> Air permit limits and selected compliance options from
permits that were available online. Not all States provide online
access to air permits, but the EPA was able to obtain and review State
permits for approximately 70 stationary combustion turbines that are
currently subject to subpart KKKK to inform the BSER technology review
and obtain other relevant information about the source category, such
as monitoring approaches applied.\4\
---------------------------------------------------------------------------

\4\ See the Research Summary Memo in the docket for this
rulemaking for a summary of the results from this State permit
search.
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<bullet> Combustion turbine manufacturer specifications sheets for
NO<INF>X</INF> and other criteria pollutant emissions for common
combustion turbine makes and models.\5\
---------------------------------------------------------------------------

\5\ See the Combustion Turbine Manufacturer Specsheet Memo in
the docket for this rulemaking for a summary of the review of
turbine manufacturers' specification sheets.
---------------------------------------------------------------------------

<bullet> Communication with combustion turbine manufacturers,
including Siemens, General Electric, Mitsubishi, and Solar Turbines.
The Agency also communicated with the Gas Turbine Association (GTA),
which represents industries in the affected NAICS categories and their
members. Discussions focused on current combustion control technologies
to reduce NO<INF>X</INF> emissions as well as the cost effectiveness of
post-combustion SCR for certain sizes and models of turbines.
<bullet> Search of the Agency's Reasonably Available Control
Technology (RACT)/Best Available Control Technology (BACT)/Lowest
Achievable Emission Rate (LAER) Clearinghouse (RBLC) database.\6\
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\6\ U.S. Environmental Protection Agency (EPA). RACT/BACT/LAER
Clearinghouse (RBLC). Available at <a href="https://cfpub.epa.gov/rblc/">https://cfpub.epa.gov/rblc/</a>.
---------------------------------------------------------------------------

A variety of sources were used to compile a list of existing
facilities constructed in the past 5 years that are subject to subpart
KKKK. That list was used to estimate the approximate number of new
sources that may be subject to this proposed rulemaking. The list was
based on data collected from Form EIA-860,\7\ the EPA's National
Electric Energy Data System (NEEDS) database,\8\ and information
collected during the Agency's ongoing work to review the National
Emission Standards for Hazardous Air Pollutants (NESHAP) for combustion
turbines under 40 CFR part 63, subpart YYYY. Form EIA-860 contains
information about currently operating and planned individual electric
generators, which includes their location, prime mover, and capacity.
NEEDS is an EPA database of electric generators that serves as a
resource for modeling the sector. NEEDS includes source information
about existing and planned units, information about the combustion
turbines themselves, and data about their air emission controls. The
list of sources compiled for the EPA's review of the NESHAP only
includes combustion turbines that are located at major sources of toxic
air emissions. These source lists are included in the docket for this
proposal.
---------------------------------------------------------------------------

\7\ U.S. Energy Information Administration (EIA). (June 12,
2024). Form EIA-860 data. Available at <a href="https://www.eia.gov/electricity/data/eia860/">https://www.eia.gov/electricity/data/eia860/</a>.
\8\ See the U.S. Environmental Protection Agency's (EPA)
National Electric Energy Data System database. NEEDS rev 06-06-2024.
Accessed at <a href="https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs">https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs</a>.
---------------------------------------------------------------------------

E. What outreach and engagement did the EPA conduct?

As part of this rulemaking, the EPA engaged and consulted with the
public, including communities with environmental justice (EJ) concerns,
and industry representatives, through several interactions. The EPA
opened a non-regulatory docket \9\ and posted framing questions
intended to solicit specific public input about ways the Agency could
design a broad approach to the regulation of greenhouse gases (GHGs)
and other air pollutants from combustion turbines under CAA sections
111 and 112 that protects human health and the environment. Several
stakeholders posted comments to the non-regulatory docket pertaining to
the review of the NSPS and subpart KKKK. Those comments were reviewed
as part of this proposed action.
---------------------------------------------------------------------------

\9\ See EPA-HQ-OAR-2024-0135, available at <a href="https://www.regulations.gov">https://www.regulations.gov</a>.
---------------------------------------------------------------------------

The EPA also held a public policy forum on May 17, 2024, at the EPA
headquarters in Washington, DC. The forum included a series of panels
and interactive discussion sessions that provided an opportunity for
the Agency to hear a broad range of views and exchange of ideas
concerning upcoming proposed regulations impacting air pollution
emissions from stationary combustion turbines. Although the focus of
the public policy forum was to discuss the regulation of GHG emissions
from stationary combustion turbines in the power sector, there was also
some discussion of the 8-year review of the NSPS and standards of
performance for criteria pollutant emissions, such as NO<INF>X</INF>.
The forum included a wide range of stakeholders as members of panel
discussions, as part of the in-person audience and attending virtually.
Key groups represented included: State and local air agencies, Tribal
Nations, affected companies, representatives of the EJ community,
technology vendors, environmental non-governmental organizations, and
electric reliability organizations and industry trade groups.

[[Page 101311]]

The EPA also consulted with representatives of State and local
governments in the process of developing this action to permit them to
have meaningful and timely input into their development. The EPA
invited the following 10 national organizations representing State and
local elected officials to a virtual meeting on August 15, 2024: (1)
National Governors Association; (2) National Conference of State
Legislatures; (3) Council of State Governments; (4) National League of
Cities; (5) U.S. Conference of Mayors; (6) National Association of
Counties; (7) International City/County Management Association; (8)
National Association of Towns and Townships; (9) County Executives of
America; and (10) Environmental Council of States. Also, the EPA
invited air and utility professional groups who may have State and
local government members, including the Association of Air Pollution
Control Agencies; National Association of Clean Air Agencies; American
Public Power Association; Large Public Power Council; National Rural
Electric Cooperative Association; National Association of Regulatory
Utility Commissioners; and National Association of State Energy
Officials to participate in the meeting. The purpose of the
consultation was to provide general background on the rulemaking,
answer questions, and solicit input from State and local governments.
The EPA has also engaged with major combustion turbine
manufacturers such as Siemens, General Electric, Mitsubishi, and Solar
Turbines, as well as with industry trade groups such as the Gas Turbine
Association (GTA), for assistance with some of the data collection
efforts previously identified in section II.D. Specifically, this
included updates on any technology developments and cost estimates that
would impact turbine performance and/or criteria pollutant emissions
for most new models of available combustion turbines.

F. How did the EPA consider environmental justice in the development of
this action?

Consistent with applicable Executive orders and EPA policy, the
Agency carefully considered the potential implications of this proposed
action on communities with EJ concerns. As part of the regulatory
development process for this rulemaking, and consistent with feedback
we received during the development of the final New Source Performance
Standards for Greenhouse Gas Emissions From New, Modified, and
Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission
Guidelines for Greenhouse Gas Emissions From Existing Fossil Fuel-Fired
Electric Generating Units; and Repeal of the Affordable Clean Energy
Rule (i.e., the Carbon Pollution Standards),\10\ the EPA continued its
outreach with interested parties, including communities with EJ
concerns. These opportunities gave the EPA a chance to hear directly
from the public, including from communities potentially impacted by
this proposed rule. The EPA took this feedback into account in the
development of this proposal.
---------------------------------------------------------------------------

\10\ See 89 FR 39798; May 9, 2024.
---------------------------------------------------------------------------

The EPA's examination of potential EJ concerns in this proposed
rule includes a proximity demographic analysis for 130 existing
facilities that are currently subject to NSPS subpart KKKK. This
represents facilities that might modify or reconstruct in the future
and become subject to the proposed requirements in new subpart KKKKa.
The locations of newly constructed sources that will become subject to
subpart KKKKa are not known, thus, we are limited in our ability to
estimate the potential EJ impacts of this rulemaking. As discussed in
detail in section IV.F of this preamble, the results of the proximity
demographic analysis indicate that the percent of population that is
Black, Hispanic/Latino, or Asian living within 50 kilometers (km) of
existing facilities with stationary combustion turbines is above the
national average. In addition, the percent of population living within
50 km of existing facilities with stationary combustion turbines is
also above the national average for linguistic isolation and people
with one or more disabilities. Furthermore, within 5 km of the existing
facilities with stationary combustion turbines, the percent of
population is above the national average for people living below the
poverty level and people living below two times the poverty level.
However, for the areas located downwind of any stationary
combustion turbines that may be covered by new subpart KKKKa, we
anticipate the proposed changes to the NSPS will generally reduce the
potential emission impacts, in particular NO<INF>X</INF> emissions.
Specifically, for most subcategories of new, modified, and
reconstructed stationary combustion turbines, the EPA is proposing
combustion controls with SCR as the BSER and, accordingly, is proposing
more protective NO<INF>X</INF> standards of performance for affected
sources based on the application of SCR post-combustion control
technology and updated information on combustion control efficacy.
Although this proposed rule does not preclude the construction of new
combustion turbines, and emissions may increase as a result of
increased operation of newly-constructed capacity, this proposed rule,
if finalized, would ensure that any additional NO<INF>X</INF> emissions
from certain affected sources are reduced to a level consistent with
the application of state-of-the-art control technology. Any source that
commences construction, modification, or reconstruction after the date
of publication of this proposal will be subject to the standards of
performance that are ultimately finalized. Further, frontline
communities have consistently raised concerns about increases in
NO<INF>X</INF> emissions from newly constructed stationary combustion
turbines that plan to co-fire with hydrogen.\11\ This proposed rule,
when finalized, will help address those concerns by establishing more
protective NO<INF>X</INF> standards for stationary combustion turbines
that plan to co-fire hydrogen.
---------------------------------------------------------------------------

\11\ See, for example, Docket ID No. EPA-HQ-OAR-2023-0072-0470,
Docket ID No. EPA-HQ-OAR-2023-0072-0527, Docket ID No. EPA-HQ-OAR-
2023-0072-0658, Docket ID No. EPA-HQ-OAR-2024-0135-0080, and Docket
ID No. EPA-HQ-OAR-2024-0135-0114.
---------------------------------------------------------------------------

Additionally, sources that install stationary combustion turbines
that meet the applicability of NSPS subpart KKKKa will likely be
subject to the New Source Review (NSR) preconstruction permitting
program and, more specifically, the requirements of the ``major NSR''
program. Major NSR permitting requirements can offer protections for
communities that are near sources that will experience an increase in
NO<INF>X</INF> and other emissions resulting from the installation and
operation of new, modified, or reconstructed stationary combustion
turbines. Under the major NSR program, the permitting requirements that
apply to a source depend on the air quality designation at the location
of the source for each of its emitted pollutants at the time the permit
is issued. Major NSR permits for sources located in an area that is
designated as attainment or unclassifiable for the National Ambient Air
Quality Standards (NAAQS) for its pollutants are referred to as
Prevention of Significant Deterioration (PSD) permits. Sources subject
to PSD must, among other requirements, comply with emission limitations
that reflect the Best Available Control Technology (BACT) for ``each
pollutant subject to regulation'' \12\ as specified by CAA

[[Page 101312]]

sections 165(a)(4) and 169(3) and demonstrate through dispersion
modeling techniques that the emissions from the project will not cause
or contribute to a violation of the NAAQS or ``PSD increments.'' \13\
Sources can often make this air quality demonstration based on the BACT
level of control or, in some cases, may need to accept more stringent
air quality-based limitations to model compliance with the ambient
standards. Major NSR permits for sources located in nonattainment areas
and that emit at or above the specified major NSR threshold for the
pollutant for which the area is designated as nonattainment are
referred to as Nonattainment NSR (NNSR) permits. Sources subject to
NNSR must, among other requirements, meet the Lowest Achievable
Emission Rate (LAER) pursuant to CAA sections 171(3) and 173(a)(2) for
any pollutant subject to NNSR and must obtain emission ``offsets''
(i.e., creditable decreases in emissions) from other sources in the
area to compensate for the expected emission increases caused by the
new source or modification. These required elements of PSD and NNSR
permits can serve to further reduce potential emission impacts from
stationary combustion turbines beyond the levels that would be required
by the proposed changes to NSPS subpart KKKKa.
---------------------------------------------------------------------------

\12\ For the PSD program, ``regulated NSR pollutant'' includes
any criteria air pollutant and any other air pollutant that meets
the requirements of 40 CFR 52.21(b)(50). Some of these non-criteria
pollutants include greenhouse gases, fluorides, sulfuric acid mist,
hydrogen sulfide, and total reduced sulfur.
\13\ PSD increments are margins of ``significant'' air quality
deterioration above a baseline concentration that establish an air
quality ceiling, typically below the NAAQS, for each PSD area.
---------------------------------------------------------------------------

With respect to consideration of specific EJ concerns within the
NSR permitting procedures, when the EPA is the issuing authority for
the major NSR permit, it has legal authority to consider potential
disproportionate environmental burdens on a case-by-case basis, taking
into account case-specific factors germane to any individual permit
decision. Although the minimum requirements for an approvable State NSR
permitting program do not require the permitting authorities to reflect
EJ considerations in their permitting decisions, States that implement
NSR programs under an EPA-approved State implementation plan (SIP) have
discretion to consider EJ in their NSR permitting actions and adopt
additional requirements in the permitting decision to address potential
disproportionate environmental burdens. Also, the NSR permit review
process provides the discretion for permitting authorities to provide
enhanced engagement for communities with EJ concerns. This includes
opportunities to enhance EJ by facilitating increased public
participation in the formal permit consideration process (e.g., by
granting requests to extend public comment periods, holding multiple
public meetings, or providing translation services at hearings in areas
with limited English proficiency) and taking informal steps to enhance
participation earlier in the process, such as inviting community groups
to meet with the permitting authority and express their concerns before
a draft permit is developed.

G. How does the EPA perform the NSPS review?

As noted in section II of this preamble, CAA section 111 requires
the EPA to, at least every 8 years, review and, if appropriate, revise
the standards of performance applicable to new, modified, and
reconstructed sources. If the EPA revises the standards of performance,
those standards must reflect the degree of emission limitation
achievable through the application of the BSER considering the cost of
achieving such reduction and any non-air quality health and
environmental impact and energy requirements. CAA section 111(a)(1).
Section 111 of the CAA requires the EPA to consider a number of
factors, including cost, in determining ``the best system of emission
reduction . . . adequately demonstrated.'' CAA section 111(a)(1). The
D.C. Circuit has long recognized that ``[CAA] section 111 does not set
forth the weight that [ ] should [be] assigned to each of these
factors;'' therefore, ``[the court has] granted the agency a great
degree of discretion in balancing them.'' Lignite Energy Council v.
EPA, 198 F.3d 930, 933 (D.C. Cir. 1999).
In reviewing an NSPS to determine whether it is ``appropriate'' to
revise the standards of performance, the EPA evaluates the statutory
factors identified in the paragraphs above, which may include
consideration of the following information:
<bullet> Expected growth for the source category, including how
many new facilities, reconstructions, and modifications may trigger
NSPS in the future.
<bullet> Pollution control measures, including advances in control
technologies, process operations, design or efficiency improvements, or
other systems of emission reduction, that are ``adequately
demonstrated'' in the regulated industry.
<bullet> 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.
<bullet> Costs (including capital and annual costs) associated with
implementation of the available pollution control measures.
<bullet> The amount of emission reductions achievable through
application of such pollution control measures.
<bullet> Any non-air quality health and environmental impact and
energy requirements associated with those control measures.
The courts have recognized that the EPA has ``considerable
discretion under [CAA] section 111,'' id., on how it considers cost
under CAA section 111(a)(1). In evaluating whether the cost of a
particular system of emission reduction is reasonable, 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 monetized benefits are compared to
costs, but rather is intended to provide a metric to compare the
relative cost of emissions reductions.
The statute does not identify a specific way in which the EPA is to
assess cost, and the Agency does not apply a brightline test in
determining what level of cost is reasonable. Rather, in evaluating
whether the cost of a control is reasonable, 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

[[Page 101313]]

of capital for a new facility, and the cost per unit of production. In
addition, other factors identified in CAA section 111(a) may bear on
the EPA's evaluation of cost. For instance, if there is evidence of use
of a technology across many of the recently constructed sources in a
particular category, such evidence would provide a powerful indication
that the cost of that technology is reasonable, or at a minimum, is not
excessive. See, e.g., 89 FR 16820, 16864-65; March 8, 2024.
After the EPA evaluates the statutory factors, the EPA compares the
various systems of emission reductions and determines which system is
``best'' and therefore represents the BSER. The EPA then establishes a
standard of performance that reflects the degree of emission limitation
achievable through the implementation of the BSER. In performing this
analysis, 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, modification, or reconstruction 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.

H. 2012 NSPS Proposal

On September 5, 2006, a petition for reconsideration of the revised
NSPS was filed by the Utility Air Regulatory Group (UARG). The EPA
granted reconsideration of subpart KKKK, and, on August 29, 2012,
proposed to amend subpart KKKK as well as the original NSPS, subpart GG
of 40 CFR part 60. See 77 FR 52554 (2012 NSPS Proposal). The proposed
rulemaking addressed specific issues identified by the petitioners as
well as other technical and editorial issues.
Specifically, the EPA proposed to clarify the intent in applying
and implementing specific rule requirements, to correct unintentional
technical omissions and editorial errors, and address various other
issues that were identified since promulgation of subpart KKKK. The EPA
has not taken further action on this proposed rule, and, in this
action, proposes in the following section to include applicable
clarifications and technical corrections in new subpart KKKKa.

III. What actions are we proposing?

A. Applicability

The source category that is the subject of this proposed action is
composed of new stationary combustion turbines with a base load rating
(maximum heat input of the combustion turbine engine at ISO conditions)
of greater than 10 MMBtu/h of heat input.\14\ The standards of
performance, proposed to be codified in 40 CFR part 60, subpart KKKKa,
once promulgated, would be directly applicable to affected sources that
begin construction, modification, or reconstruction after the date of
publication of the proposed standards in the Federal Register. The
applicability of sources that would be subject to proposed subpart
KKKKa is similar to that for sources subject to existing 40 CFR part
60, subpart KKKK. The proposed amendments to subparts GG and KKKK, once
promulgated, would be directly applicable to the affected facilities
already subject to those subparts. Stationary combustion turbines
subject to the proposed standards in new subpart KKKKa would not be
subject to the requirements of subparts GG or KKKK. The HRSG and duct
burners subject to the proposed standards in subpart KKKKa would be
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.
---------------------------------------------------------------------------

\14\ The EPA uses the higher heating value (HHV) when specifying
heat input ratings.
---------------------------------------------------------------------------

Proposed subpart KKKKa maintains the NO<INF>X</INF> exemptions
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 NO<INF>X</INF> limits. These included
emergency-standby combustion turbines, military combustion turbines,
and firefighting combustion turbines. Subpart KKKK further defines
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 in 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.
1. Revisions to 40 CFR Part 60, Subpart GG and 40 CFR Part 60, Subpart
KKKK That Would Also Be Included in 40 CFR Part 60, Subpart KKKKa
The EPA is proposing to make two revisions to subparts GG and KKKK
that also are proposed to be included in a new subpart KKKKa.
Therefore, revised subparts GG and KKKK use similar regulatory text as
subpart KKKKa except where specifically stated. This section describes
provisions that would be included in all three subparts. The proposed
amendments also include updating 40 CFR 60.17 (incorporations by
reference) to include additional test methods identified in subpart
KKKKa and revising the wording and writing style to clarify the
requirements of the NSPS. The Agency does not intend for these
editorial revisions to substantively change any of the technical
requirements of the existing subparts GG and KKKK. To the extent that
the EPA determines that the revisions do have unintended substantive
effects, corrections will be made in the final action on the proposed
rule.
a. Exemptions for Combustion Turbines Subject to More Stringent
Standards
The EPA is proposing that stationary combustion turbines at
petroleum refineries subject to subparts J or Ja of 40 CFR part 60 are
not subject to the SO<INF>2</INF> performance standards in subparts GG,
KKKK, or those proposed in new subpart KKKKa. The SO<INF>2</INF>
standards in subparts J and Ja are more stringent than the
SO<INF>2</INF> limits currently in subparts GG, KKKK, or proposed to be
included in new subpart KKKKa. This proposed action would simplify
compliance for owners or operators of petroleum refineries without an
increase in pollutant emissions. The EPA is soliciting comment on
whether there are additional source categories of facilities with
stationary combustion turbines that are subject to more stringent NSPS
that should not be subject to the SO<INF>2</INF> and/or NO<INF>X</INF>
standards in subparts GG, KKKK, or those proposed to be included in new
subpart KKKKa.

[[Page 101314]]

b. Owners/Operators of Combustion Turbines Subject to 40 CFR Part 60,
Subpart GG or 40 CFR Part 60, Subpart KKKK Can Petition To Comply With
40 CFR Part 60, Subpart KKKKa
The EPA is proposing to 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 have the option
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 would have the
flexibility to comply with one NSPS instead of multiple NSPS. The
Administrator will only grant the petition if they determine 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, the EPA is clarifying that if any solid fuel as defined in
new proposed subpart KKKKa is burned in the HRSG, the HRSG would be
covered by the applicable steam generating unit NSPS and not subpart
KKKKa. The EPA is not aware of any existing stationary combustion
turbines subject to subparts GG or KKKK that burn solid fuel in the
HRSG, but the intent of this amendment is to cover only liquid and
gaseous fuels. The amendment would prevent 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.
2. Applicability of 40 CFR Part 60, Subpart KKKKa That Is Different
From the Applicability of 40 CFR Part 60, Subpart KKKK
This section describes applicability provisions proposed in new
subpart KKKKa that are different from the applicability provisions in
existing subpart KKKK.
a. Clarification to Definition of Stationary Combustion Turbine
The combustion turbine engine (i.e., the air compressor, combustor,
and turbine sections) is the primary source of emissions from a
stationary combustion turbine. In subpart KKKK, the definition of the
affected source includes the HRSG and associated duct burners at
combined cycle and CHP facilities. See 71 FR 38483; July 6, 2006. This
means that the replacement of only the combustion turbine portion of a
combined cycle or CHP facility may not constitute a new affected
facility. This also means the cost to replace only the combustion
turbine engine portion at an existing combined cycle or CHP facility
may not constitute most of the costs compared to the replacement of the
combustion turbine engine portion and the HRSG portion. This, in turn,
is relevant to determining whether an affected source has
``reconstructed'' because, in general, a reconstructed facility is one
that has had components replaced to the extent that the fixed capital
costs of the new components exceed 50 percent of the fixed capital
costs that would be required to construct a comparable entirely new
facility. See 40 CFR 60.15. When the definition of an affected facility
was expanded in subpart KKKK, it was not the intent of the EPA to
change the determination of whether an existing combustion turbine is
``new'' or ``reconstructed.'' The EPA is proposing that it is
appropriate that owners or operators of combined cycle and CHP
facilities that entirely replace or undertake major capital investments
in the combustion turbine engine portion of the facility invest in
emissions control equipment as well.
In new subpart KKKKa, the EPA is proposing to maintain the
definition of the affected source that was promulgated in subpart KKKK.
However, to clarify the applicability of this definition when
determining whether an existing combustion turbine engine should be
considered to be ``new'' or ``reconstructed,'' the EPA is proposing to
amend the rule language in new subpart KKKKa. The new language would
clarify that the test for determining if an affected facility is a new
source would be based on whether the combustion turbine portion of the
affected facility is entirely replaced. The reconstruction
applicability determination would be based on whether the fixed capital
costs of the replacement of components of the combustion turbine engine
portion exceed 50 percent of the fixed capital costs that would be
required to install only a comparable new combustion turbine engine
portion of the affected facility. The purpose of the 50 percent cost
threshold is to ensure that sources that undertake sufficiently large
capital investments as to effectively be ``new'' sources are required
to invest in emissions controls as well, and do not avoid performance
standards that would otherwise apply to new sources. In the case of a
stationary combustion turbine, which is the regulated source for this
source category, a capital investment that amounts to 50 percent of the
replacement cost of the combustion turbine engine portion itself is
sufficiently major as to make it appropriate to require the owner or
operator to invest in emissions controls to meet the requirements in
subpart KKKKa. This approach would not consider the costs to replace
the HRSG (or its components) when only components of the combustion
turbine engine portion are being replaced.
This approach to applying the definition of a reconstructed source
would ensure that if an existing combined cycle or CHP facility
replaces only the combustion turbine engine portion (or its
components), then only the replaced portion (i.e., the combustor) would
be considered in a cost analysis to determine whether the source is
reconstructed and thus subject to the NSPS performance standards in
subpart KKKKa. For example, if a combined cycle turbine engine is
replaced at an existing facility subject to subpart KKKK while the HRSG
(or its components) is not replaced, then the cost to replace only the
combined cycle turbine engine portion would be considered in the
applicability determination. If the new turbine engine is determined to
be a reconstructed source, then it would be subject to the proposed
performance standards for reconstructed combustion turbines in subpart
KKKKa. The HRSG at this hypothetical facility would also become subject
to subpart KKKKa. It would make no practical difference for a HRSG to
remain subject to subpart KKKK while the turbine becomes subject to
subpart KKKKa, because the EPA is proposing to maintain the same
treatment of the HRSG as in subpart KKKK.
In addition, compliance with subpart KKKKa would be minimally
impacted by any potential reconstruction of the HRSG. Since the
proposed standards in subpart KKKKa are input-based, with optional
alternative output-based standards, the efficiency of the HRSG is not
essential for demonstrating compliance. Further, the presence of duct
burners should not significantly impact the emissions rate since low
NO<INF>X</INF> natural gas-fired duct burners typically contribute 15
ppm to 25 ppm NO<INF>X</INF> corrected to 15 percent O<INF>2</INF>, and
ultra-low NO<INF>X</INF> duct burners are available that contribute
approximately 3 ppm NO<INF>X</INF> corrected to 15 percent
O<INF>2</INF>. Under this approach, the replacement or addition of a
new combustion turbine engine to a facility while retaining the
existing HRSG would be considered a reconstruction, resulting in the
applicability of subpart KKKKa. Likewise, the replacement or addition
of

[[Page 101315]]

a HRSG associated with a combustion turbine engine covered by subparts
KKKK or GG would not result in the entire facility being subject to
subpart KKKKa. Nonetheless, the Agency emphasizes that this treatment
only concerns the meaning of ``new'' and ``reconstruction'' for
purposes of subpart KKKKa; existing facilities making physical or
operational changes must separately evaluate whether those changes
constitute ``modification'' under 40 CFR 60.14 and thereby become
subject to subpart KKKKa as a modified source.\15\ See sections III.B.4
of this preamble for discussion of the EPA's proposed approach for
subcategorization and section III.B.12 for discussion of the proposed
emission standards in subpart KKKKa.
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\15\ The EPA proposed a similar approach to reconstruction for
subpart KKKK in the 2012 NSPS Proposal. The Agency is not finalizing
this change in subpart KKKK and is not altering the approach to
reconstruction for purposes of determining the applicability of that
subpart. Nonetheless, all existing sources that engage in
reconstruction or modification after the date of this proposal would
thereby become subject to subpart KKKKa and sources that meet the
proposed new or reconstruction test under subpart KKKKa, if
finalized, would be subject to subpart KKKKa and would no longer be
subject to subpart KKKK.
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B. NOX Emission Standards

1. Overview
This section discusses and proposes requirements for stationary
combustion turbines that commence construction, modification, or
reconstruction after December 13, 2024. The EPA is proposing that these
requirements will be codified in 40 CFR part 60, subpart KKKKa. The EPA
explains in section III.B.2 how NO<INF>X</INF> formation occurs when
fuel is burned in a stationary combustion turbine. Section III.B.3
discusses the subcategories the EPA promulgated in subpart KKKK as
compared to the subcategory approach being proposed in new subpart
KKKKa. Notably, in section III.B.4, the EPA is proposing size-based
subcategories that reflect our consideration of the performance of
different combustion turbine designs and current NO<INF>X</INF> control
technologies. The proposed BSER for control of NO<INF>X</INF> emissions
for each proposed subcategory of combustion turbines is discussed in
sections III.B.7 through III.B.11, and the application of a particular
BSER corresponds to the NO<INF>X</INF> performance standards proposed
in section III.B.12. The EPA's determination of the subcategories,
BSER, and NO<INF>X</INF> standards in this action considers multiple
factors. These include whether the size of a new, modified, or
reconstructed stationary combustion turbine is small, medium, or large
(i.e., base load); whether the affected source would operate at high or
low hourly duty cycles; whether the affected source would operate at
low, intermediate, or high annual capacity factors; and whether the
affected source would burn natural gas, non-natural gas (such as
distillate fuels), hydrogen, or a combination of the three.
As mentioned previously, in section III.B.7, the EPA describes the
NO<INF>X</INF> emission control technologies it evaluated as part of
its review of the NSPS. These include dry combustion controls (e.g.,
lean premix/dry low NO<INF>X</INF> (DLN) systems), wet combustion
controls (e.g., water or steam injection), and post-combustion
selective catalytic reduction (SCR). This is followed by a discussion
of the EPA's proposed determination of the BSER for each of the
subcategories of combustion turbines.
To summarize the EPA's proposed BSER determinations for
NO<INF>X</INF>: In general, the EPA is proposing that combustion
controls with the addition of post-combustion SCR is the BSER for
combustion turbines in the small, medium, and large subcategories.
Since subpart KKKK was promulgated in 2006, it has become clear that
SCR technology is a widely available and frequently adopted
NO<INF>X</INF> emissions control strategy for a wide range of sizes and
types of combustion turbines. In general, and as described in more
detail in the sections that follow, the EPA finds that SCR is
adequately demonstrated for this source category, is generally cost-
effective, and satisfies the other statutory criteria under CAA section
111(a)(1). However, the Agency also recognizes that as the size of a
combustion turbine diminishes and/or as the level of operation of a
combustion turbine diminishes or becomes more variable, the cost-
effectiveness on a per-ton basis and efficacy of SCR technology also
diminishes.
Thus, at smaller sizes and at lower operating levels, the EPA
proposes to establish standards that are based on the use of combustion
controls without SCR. Specifically, for small combustion turbines
(i.e., those that have a base load heat input rating of less than or
equal to 250 MMBtu/h) that operate at an annual capacity factor \16\
less than or equal to 40 percent (i.e., low and intermediate load
combustion turbines), the EPA is proposing that the use of combustion
controls alone remains the BSER. For medium combustion turbines (i.e.,
those that have a base load heat input rating of greater than 250
MMBtu/h but less than or equal to 850 MMBtu/h) that operate at capacity
factors less than or equal to 20 percent (i.e., low load combustion
turbines), the EPA is proposing that combustion controls alone remain
the BSER. Likewise, for large combustion turbines (i.e., those that
have a base load heat input rating of greater than 850 MMBtu/h) that
operate at capacity factors less than or equal to 20 percent (i.e., low
load combustion turbines), the EPA is proposing that the use of
combustion controls alone remains the BSER.
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\16\ Capacity factor 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.
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As discussed in further detail in the sections that follow, the EPA
is requesting comment on several alternative approaches to determining
the BSER and appropriate NO<INF>X</INF> emission standards,
particularly for small combustion turbines (i.e., those that have a
base load heat input rating of less than or equal to 250 MMBtu/h).
Also, the EPA is taking comment on different ways of defining the size
and capacity factor thresholds for establishing the subcategories
described in this proposal.
In section III.B.13, the EPA explains the proposed BSER and
NO<INF>X</INF> emission standards for modified sources. The EPA is
proposing in new subpart KKKKa that the BSER and NO<INF>X</INF>
emission standards for modified stationary combustion turbines are the
same as those for certain corresponding new and reconstructed
subcategories. For other subcategories, the proposed BSER and
NO<INF>X</INF> emission stanards for modified sources are different.
Furthermore, in section III.B.14, the EPA explains its proposed
approach to characterize new, modified, and reconstructed stationary
combustion turbines that elect to co-fire with a percentage blend of
hydrogen (by volume) as either natural gas-fired or non-natural gas-
fired sources. Depending on whether the combustion turbine co-fires
more or less than 30 percent hydrogen (by volume), it is proposed to be
subject to the same BSER and NO<INF>X</INF> performance standards
applicable to either natural gas-fired or non-natural gas-fired
combustion turbines in the same size-based subcategory. This section
also includes a discussion of the technologies the EPA is proposing as
BSER for each of the non-natural gas subcategories and the basis for
proposing those controls, and not others, as the BSER.
2. NO<INF>X</INF> Formation
Nitrogen oxides (NO<INF>X</INF>) are a group of gases that are
produced by stationary combustion turbines when fuel is

[[Page 101316]]

burned at high temperatures. These gases are a mixture of nitric oxide
(NO) and nitrogen dioxide (NO<INF>2</INF>) and play a major role as
precursor pollutants in atmospheric reactions with volatile organic
compounds (VOC) that produce ozone (i.e., smog), particularly on hot
summer days. As a precursor pollutant, NO<INF>X</INF> also reacts with
water, oxygen, and other chemicals in the air to form particulate
matter (PM) and contributes to acid deposition. NO<INF>X</INF> is also
a criteria pollutant for which there are National Ambient Air Quality
Standards (NAAQS). The NAAQS for NO<INF>X</INF> include a 1-hour
standard at a level of 100 parts per billion (ppb) based on the 3-year
average of the 98th percentile of the yearly distribution of 1-hour
daily maximum concentrations, and an annual standard at a level of 53
ppb.\17\ The direct health effects of NO<INF>X</INF> are primarily
respiratory effects, including irritation of the eyes, nose, throat,
and lungs. Exposure to low levels of NO<INF>X</INF> can lead to fluid
build-up in the lungs. Inhalation of high levels of NO<INF>X</INF> can
lead to burning, spasms, and swelling of tissues in the throat and
upper respiratory tract, reduced oxygenation of the body tissues, and
build-up of fluid in the lungs, and death.\18\ Elevated concentrations
of NO<INF>2</INF> can exacerbate asthma in the short term and may
contribute to asthma development in the long term. People with asthma,
as well as children and the elderly, are generally at greater risk for
the health effects of NO<INF>2</INF>.\19\
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\17\ U.S. Environmental Protection Agency (EPA). Nitrogen
Dioxide (NO<INF>2</INF>) Pollution. Available at <a href="https://www.epa.gov/no2-pollution/primary-national-ambient-air-quality-standards-naaqs-nitrogen-dioxide">https://www.epa.gov/no2-pollution/primary-national-ambient-air-quality-standards-naaqs-nitrogen-dioxide</a>.
\18\ Agency for Toxic Substances and Disease Registry (ATSDR).
(March 25, 2014). ToxFAQs for Nitrogen Oxides. Toxic Substances
Portal fact sheet. Available at <a href="https://wwwn.cdc.gov/TSP/ToxFAQs/ToxFAQsDetails.aspx?faqid=396&toxid=69">https://wwwn.cdc.gov/TSP/ToxFAQs/ToxFAQsDetails.aspx?faqid=396&toxid=69</a>.
\19\ U.S. Environmental Protection Agency (EPA). Nitrogen
Dioxide (NO<INF>2</INF>) Pollution. Available at <a href="https://www.epa.gov/no2-pollution/basic-information-about-no2#Effects">https://www.epa.gov/no2-pollution/basic-information-about-no2#Effects</a>.
---------------------------------------------------------------------------

In addition, environmental effects of NO<INF>X</INF> pollution
include adverse effects on foliage, and, via nitrogen deposition,
effects on ecosystems, such as the acidification of aquatic and
terrestrial ecosystems and nutrient enrichment.
Total NO<INF>X</INF> emissions are a function of thermal and
organic (i.e., fuel) NO<INF>X</INF>. Thermal NO<INF>X</INF> is formed
in a well-defined, high-temperature reaction between nitrogen and
oxygen from the combustion air. Meanwhile, organic NO<INF>X</INF> is
formed from fuel-bound nitrogen that reacts with oxygen in the
combustion chamber. Thermal NO<INF>X</INF> accounts for the majority of
NO<INF>X</INF> emitted by stationary combustion turbines because
natural gas typically does not have a high nitrogen composition.\20\ As
discussed in more detail below, dry and wet combustion controls reduce
the peak flame temperatures, thus limiting NO<INF>X</INF> emissions,
while SCR technology catalytically promotes the conversion of
NO<INF>X</INF> to nitrogen gas (N<INF>2</INF>) in the exhaust gases of
stationary combustion turbines.
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\20\ Our BSER analysis focuses on traditional turbines where the
fuel is combusted in air. There is at least one vendor developing
new turbines where the fuel is combusted in pure oxygen. In that
case, there would be no thermal NO<INF>X</INF> formed in the
combustion process.
---------------------------------------------------------------------------

3. Subcategorization Approach and NO<INF>X</INF> Emission Standards in
40 CFR Part 60, Subpart KKKK
In subpart KKKK, the EPA lists 14 subcategories of stationary
combustion turbines and identifies NO<INF>X</INF> standards for
affected sources in each subcategory based on the application of dry or
wet NO<INF>X</INF> combustion controls. The size-based subcategories
include combustion turbines with base load ratings of less than or
equal to 50 MMBtu/h of heat input, those with base load ratings greater
than 50 MMBtu/h of heat input and less than or equal to 850 MMBtu/h,
and those with base load ratings greater than 850 MMBtu/h of heat
input. These subcategories are based on the rating of the turbine
engine, do not include any supplemental fuel input to the heat recovery
system, and are consistent with combustion control technologies (and
manufacturer guarantees) available at the time that subpart KKKK was
promulgated for different size combustion turbines. Within each size-
based subcategory there are individual NO<INF>X</INF> standards based
on whether the combustion turbine is burning natural gas or non-natural
gas fuels and reflect the availability of wet or dry low NO<INF>X</INF>
combustion controls for different fuels.
There are also separate subcategories in subpart KKKK for modified
and reconstructed stationary combustion turbines (reflecting more
limited availability of combustion controls); heat recovery units
operating independent of the combustion turbine (reflecting the
emissions rate of a boiler); combustion turbines operating at part load
or operating at low ambient temperatures (or north of the Arctic
Circle); and offshore turbines (reflecting the ability of combustion
controls to operate under these conditions). See Table 1:
NO<INF>X</INF> Emission Standards (71 FR 38483; July 6, 2006). The
NO<INF>X</INF> standards within these 14 subcategories in subpart KKKK
are as low as 15 ppm for combustion turbines firing natural gas with a
design heat input rating of greater than 850 MMBtu/h and as high as 150
ppm for sources firing non-natural gas fuels with a design heat input
rating of less than or equal to 50 MMBtu/h.
4. Proposed Subcategorization Approach in 40 CFR Part 60, Subpart KKKKa
The EPA is proposing three size-based subcategories in subpart
KKKKa for stationary combustion turbines that commence construction,
modification, or reconstruction after December 13, 2024. The proposed
subcategories include combustion turbines with base load ratings of
less than or equal to 250 MMBtu/h of heat input, those with base load
ratings of greater than 250 MMBtu/h of heat input and less than or
equal to 850 MMBtu/h, and those with base load ratings greater than 850
MMBtu/h of heat input.\21\ Like subpart KKKK, these subcategories are
based on the rating of the turbine engine and do not include any
supplemental fuel input to the heat recovery system and are consistent
with combustion control technologies (and manufacturer guarantees)
currently available for different sized combustion turbines.
---------------------------------------------------------------------------

\21\ The EPA is proposing the same BSER regardless of the end
use of the combustion turbine--direct mechanical and electric
generating applications would be subject to the same emission
standards.
---------------------------------------------------------------------------

For the purposes of subpart KKKKa, the EPA refers to stationary
combustion turbines as small (base load ratings of less than or equal
to 250 MMBtu/h of heat input), medium (base load ratings of greater
than 250 MMBtu/h of heat input and less than or equal to 850 MMBtu/h),
and large (base load ratings of greater 850 MMBtu/h of heat input),
respectively. In addition, the EPA is proposing to further
subcategorize small, medium, and large combustion turbines as low load,
intermediate load, or base load units depending on 12-calendar-month
capacity factors. Low load combustion turbines would be those with a
12-calendar-month capacity factor of less than or equal to 20 percent.
Intermediate load combustion turbines would be those with a 12-
calendar-month capacity factor of greater than 20 percent but less than
or equal to 40 percent. Base load combustion turbines would be those
with a 12-calendar-month capacity factor greater than 40 percent. For
each of these proposed subcategories, the EPA proposes to carry forward
to new subpart KKKKa the current subpart KKKK approach to subcategorize
stationary combustion turbines further depending on whether they are
natural

[[Page 101317]]

gas-fired or non-natural gas-fired. In addition, the EPA proposes to
carry forward to new subpart KKKKa the current subpart KKKK
subcategorization for combustion turbines operating at part loads,
combustion turbines located north of the Arctic Circle, combustion
turbines operating at ambient temperatures of less than 0 [deg]F,\22\
and HRSG units operating independent of the combustion turbine.
---------------------------------------------------------------------------

\22\ If any of these conditions are applicable, the combustion
turbine would be in this subcategory.
---------------------------------------------------------------------------

a. Size-Based Subcategories
This section discusses the EPA's proposals to create size-based
subcategories for new, modified, and reconstructed stationary
combustion turbines in new subpart KKKKa that are different from the
size-based subcategory approach established in existing subpart KKKK.
Specifically, the EPA is proposing size-based subcategories for
combustion turbines that have base load ratings less than or equal to
250 MMBtu/h of heat input, base load ratings greater than 250 MMBtu/h
of heat input and less than or equal to 850 MMBtu/h, and base load
ratings greater than 850 MMBtu/h of heat input. The EPA also is
proposing to divide these subcategories of combustion turbines further
based on their utilization (i.e., 12-calendar-month capacity factor),
depending on whether they operate as low, intermediate, or base load
units. The proposed BSER and applicable NO<INF>X</INF> emission
standards would depend on the size of the stationary combustion turbine
as determined by its base load rated heat input and on how it is
utilized based on its 12-calendar-month capacity factor.
The proposed subcategories in subpart KKKKa are based in part on
the availability and performance of NO<INF>X</INF> combustion controls
for different designs and sizes of stationary combustion turbines.
These factors were also key to determining the size-based subcategories
in current subpart KKKK. For example, as discussed previously, subpart
KKKK includes a subcategory for combustion turbines with a base load
rated heat input of less than or equal to 50 MMBtu/h, and this
subcategory was determined to be appropriate because the EPA had found
that combustion controls for these size combustion turbines have
limited availability relative to larger combustion turbines. Therefore,
the EPA further divided this subcategory into electric generating and
mechanical drive applications and determined the BSER for electric
applications to be water injection and the BSER for mechanical drive
applications to be available combustion controls.
For combustion turbines in the subcategory of sources with greater
than 50 MMBtu/h of heat input and less than or equal to 850 MMBtu/h of
heat input, the BSER in subpart KKKK is combustion controls available
for aeroderivative combustion turbines, because, when subpart KKKK was
proposed in 2005, the largest aeroderivative combustion turbines were
less than 850 MMBtu/h.
For the subcategory of combustion turbines that are greater than
850 MMBtu/h of heat input, the BSER in subpart KKKK is combustion
controls available for frame combustion turbines. The EPA had
determined that frame combustion turbines are generally physically
larger per amount of output than aeroderivative combustion turbines,
given larger areas to stage combustion that results in lower
NO<INF>X</INF> emissions.
b. Combustion Turbines Less Than or Equal to 250 MMBtu/h
The EPA is proposing in subpart KKKKa to create a subcategory for
all new and reconstructed stationary combustion turbines with base load
ratings of less than or equal to 250 MMBtu/h of heat input (i.e., small
turbines). The EPA is proposing this size-based subcategory for small
stationary combustion turbines based, in part, on a review of available
combustion controls and manufacturer guarantees for NO<INF>X</INF>
emissions from these smaller turbine designs. The results of this
technology review demonstrate that multiple manufacturers have
developed dry combustion controls that can achieve NO<INF>X</INF>
emission rates comparable to the NO<INF>X</INF> emission rates achieved
by larger models of combustion turbines for both electrical and
mechanical applications. This subcategory of small combustion turbines
with base load ratings of less than or equal to 250 MMBtu/h of heat
input also is proposed to be appropriate because it supports
consistency across multiple rulemakings and approximately corresponds
to the 25 MW threshold for a combustion turbine to be considered an
electric generating unit (EGU) in the recently promulgated NSPS for
greenhouse gas (GHG) emissions (i.e., the Carbon Pollution
Standards).\23\ See 89 FR 39798; May 9, 2024.
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\23\ EGUs are subject to different regulatory criteria outside
of the NSPS as compared to small industrial combustion turbines
(e.g., greenhouse gas standards of performance). These other
regulatory criteria can be accounted for in the baseline levels of
control the EPA uses when evaluating the BSER.
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In new subpart KKKKa, different from the existing subcategories in
subpart KKKK, the EPA is not proposing a subcategory for stationary
combustion turbines with base load ratings of less than or equal to 50
MMBtu/h of heat input. The EPA proposes to determine that this
subcategory is no longer necessary since multiple manufacturers have
developed effective dry combustion controls for nearly all new turbines
smaller than 50 MMBtu/h of heat input, and these dry combustion
controls are capable of limiting NO<INF>X</INF> emissions to the same
rates as those achieved by larger combustion turbines for both
electrical and mechanical applications. According to the subcategory
approach proposed in subpart KKKKa, any new or reconstructed stationary
combustion turbine with a base load rating of less than or equal to 50
MMBtu/h of heat input would be included in the subcategory of
combustion turbines with base load ratings of less than or equal to 250
MMBtu/h of heat input and subject to the same NO<INF>X</INF>
performance standards. Also, the EPA is proposing in new subpart KKKKa
that electrical and mechanical applications can apply identical
combustion controls and that separate subcategories for these sources
are no longer necessary.
The EPA also is proposing in new subpart KKKKa to further
subcategorize stationary combustion turbines with base load ratings of
less than or equal to 250 MMBtu/h of heat input according to capacity
factors. Small low load stationary combustion turbines would be those
with 12-calendar-month capacity factors of less than or equal to 20
percent, small intermediate load stationary combustion turbines would
be those with 12-calendar-month capacity factors greater than 20
percent and less than or equal to 40 percent, and small base load
stationary combustion turbines would be those with 12-calendar-month
capacity factors greater than 40 percent.
According to this subcategorization approach, the EPA is proposing
in new subpart KKKKa that all new and reconstructed stationary
combustion turbines with base load ratings of less than or equal to 250
MMBtu/h of heat input and that are utilized as low or intermediate load
units (i.e., with 12-calendar-month capacity factors less than or equal
to 40 percent) would have a BSER of combustion controls. Furthermore,
as discussed in section III.B.12, the EPA is proposing that these small
low and intermediate load combustion turbines would be subject to a
NO<INF>X</INF> performance standard based upon application of the
proposed BSER

[[Page 101318]]

and whether they burn natural gas or non-natural gas fuels.
The EPA also is proposing in subpart KKKKa that all new and
reconstructed stationary combustion turbines with base load ratings of
less than or equal to 250 MMBtu/h of heat input that are utilized as
base load units (i.e., with 12-calendar-month capacity factors greater
than 40 percent) would have a BSER of combustion controls plus
additional post-combustion SCR technology. The EPA proposes in section
III.B.12 that these small base load stationary combustion turbines
would be subject to a NO<INF>X</INF> performance standard based upon
application of the proposed BSER and whether they burn natural gas or
non-natural gas fuels.
As for modified stationary combustion turbines with base load
ratings of less than or equal to 250 MMBtu/h of heat input, the EPA is
proposing in subpart KKKKa that the BSER is combustion controls--
regardless of 12-calendar-month capacity factor. All small modified
stationary combustion turbines would be subject to a NO<INF>X</INF>
performance standard based application of the proposed BSER and whether
they burn natural gas or non-natural gas fuels.
In this action, the EPA is soliciting comment on whether the base
load rating of less than or equal to 250 MMBtu/h of heat input is an
appropriate threshold to distinguish between small and medium
stationary combustion turbines for purposes of determining the BSER and
proposing NO<INF>X</INF> standards in subpart KKKKa. For example, as
discussed further in section III.B.9, 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.
c. Combustion Turbines Greater Than 250 MMBtu/h and Less Than or Equal
to 850 MMBtu/h
The EPA is proposing to create a subcategory in new subpart KKKKa
for new and reconstructed medium stationary combustion turbines, which
would be turbines with base load ratings of greater than 250 MMBtu/h of
heat input and less than or equal to 850 MMBtu/h. Furthermore, in
subpart KKKKa, the EPA is proposing to divide this medium subcategory
into low load (12-calendar-month capacity factors of less than or equal
to 20 percent), intermediate load (12-calendar-month capacity factors
greater than 20 percent and less than or equal to 40 percent), and base
load (12-calendar-month capacity factors greater than 40 percent) with
separate proposed BSER and NO<INF>X</INF> emission standards, as
discussed in sections III.B.10 and III.B.12.
The EPA also is soliciting comment on whether it is appropriate for
medium stationary combustion turbines that are EGUs \24\ to determine
their utilization thresholds according to 12-operating-month electric
sales instead of 12-calendar-month capacity factors. Some new and
reconstructed stationary combustion turbines that would be subject to
new subpart KKKKa also meet the applicability criteria in the Carbon
Pollution Standards and are considered EGUs. Determining the
utilization thresholds for combustion turbine EGUs based on 12-
operating-month electric sales would better align this proposal with
the subcategorization approach in the final Carbon Pollution Standards.
---------------------------------------------------------------------------

\24\ EGU stationary combustion turbines are those that meet the
applicability requirements of proposed subpart KKKKa and also the
applicability requirements of subpart TTTTa as described in 40 CFR
60.5509a (See 89 FR 40036).
---------------------------------------------------------------------------

d. Combustion Turbines Greater Than 850 MMBtu/h
In new subpart KKKKa, the EPA is proposing to maintain the
subcategory of large stationary combustion turbines with base load
ratings of greater than 850 MMBtu/h of heat input, similar to the
existing subcategory for large combustion turbines in subpart KKKK.
However, the EPA is proposing in subpart KKKKa to further divide these
combustion turbines into three subcategories based on the rolling 12-
calendar-month utilization. As discussed for the small- and medium-
sized combustion turbines, this proposed subcategorization is
consistent with the Carbon Pollution Standards and includes
subcategories for large combustion turbines with greater than 850
MMBtu/h of heat input that operate at low, intermediate, or base load
capacity factors. In terms of capacity factors, the large low load
stationary combustion turbines would be those with 12-calendar-month
capacity factors of less than or equal to 20 percent, the large
intermediate load stationary combustion turbines would be those with
12-calendar-month capacity factors greater than 20 percent and less
than or equal to 40 percent, and the large base load stationary
combustion turbines would be those with 12-calendar-month capacity
factors greater than 40 percent.
The EPA also is soliciting comment on whether it is appropriate for
large stationary combustion turbines that are EGUs to determine their
utilization thresholds according to 12-operating-month electric sales
instead of 12-calendar-month capacity factors. Some new and
reconstructed large stationary combustion turbines that would be
subject to new subpart KKKKa also meet the applicability criteria in
the Carbon Pollution Standards and are considered EGUs. Determining the
utilization thresholds for combustion turbine EGUs based on 12-
operating-month electric sales would better align this proposal with
the subcategorization approach in the final Carbon Pollution Standards.
e. Natural Gas and Non-Natural Gas Subcategories
In subpart KKKK, stationary combustion turbines are categorized as
non-natural gas-fired sources when greater than 50 percent of the heat
input is from a non-natural gas fuel during part of an hour of
operation. The EPA is proposing to maintain that categorization in new
subpart KKKKa.
In the 2012 NSPS Proposal discussed in section II.H, the EPA
proposed to base the emissions standard only on the fuel burned in the
combustion turbine engine (i.e., any fuel combusted in the duct burners
of the HRSG would not impact the applicable emissions rate) and to
eliminate the 50 percent fuel 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. This proposed change was
intended to avoid creating a compliance issue when combustion turbines
switch from utilizing gaseous fuels (that can utilize lean premix/DLN
combustion) to liquid fuels (that utilize diffusion flame combustion).
As previously noted, the EPA took no further action on the 2012
NSPS Proposal. In this action, the EPA is soliciting comment on whether
to adopt, in subpart KKKKa, the approach included in the 2012 NSPS
Proposal. The EPA believes that this approach could provide a more
accurate representation of the performance of applicable control
technologies and is soliciting comment on the specifics of co-firing
fuels in a combustion turbine engine and how combustion turbines switch
fuels. Specifically, the EPA seeks comment on whether multiple fuels
can be combusted simultaneously in a combustion turbine engine, which
fuels can be combusted in combination, and under what conditions. The
EPA also seeks comment on whether it is necessary for a combustion
turbine to temporarily cease operation or reduce load to switch from
natural gas to distillate oil, or can switch fuels while operating at
high loads. Finally, if switching can be done at high loads, the

[[Page 101319]]

EPA seeks comment on at what point it is necessary to switch from lean
premix/DLN combustion, which is only applicable to gaseous fuels, to
diffusion flame combustion. Specifically, whether it is necessary to
operate using diffusion flame combustion while utilizing natural gas
prior to switching to fuel oil, and if this could create a compliance
issue for hours during fuel switching. The EPA is soliciting comment on
if this issue is technically accurate.
A potential issue with removing the 50 percent fuel requirement is
that this treatment could create an incentive for an owner/operator to
combust a small amount of non-natural gas fuel and thereby obtain a far
less stringent emissions standard. Therefore, the EPA is soliciting
comment on what mitigating provisions would be necessary to ensure that
this treatment only operates in the narrow window where it might be
appropriate for legitimate technical reasons. Specifically, if the EPA
were to remove the 50 percent fuel requirement, the EPA also solicits
comment on limiting the number of hours a combustion turbine may burn
multiple fuel types, through longer averaging times for determining
compliance, and/or through mass-based caps on the total emissions that
are permitted during periods of fuel switching.
The EPA is proposing in new subpart KKKKa that the NO<INF>X</INF>
standards are based on the type of fuel being burned in the combustion
turbine engine alone. Contrary to subpart KKKK, this would not account
for the type of fuel being burned in duct burners associated with the
HRSG. In subpart KKKK, the applicable NO<INF>X</INF> standards are
based on the total heat input to the stationary combustion turbine,
including any associated duct burners. However, fuel choice impacts
combustion turbine engine NO<INF>X</INF> emissions to a greater degree
than it impacts such emissions from a duct burner. Therefore, in
subpart KKKKa, the Agency is proposing to include that the
NO<INF>X</INF> standard be based on the type of fuel being burned in
the combustion turbine engine alone. The natural gas standard would
apply 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 Agency is also proposing to add a provision allowing for a
site-specific NO<INF>X</INF> standard for an owner/operator of a
stationary combustion turbine that burns by-product fuels. The owner/
operator would be required to petition the Administrator for a site-
specific standard using a procedure similar to what is currently
required by subpart Db of 40 CFR part 60 (the Industrial Boiler NSPS).
The Agency considers it appropriate to propose this provision because
new subpart KKKKa covers the HRSG that was previously covered by
subpart Db when the site-specific standard was adopted for industrial
boilers. The Agency also solicits comment on whether to amend existing
subpart KKKK to provide a provision allowing for a site-specific
NO<INF>X</INF> standard for an owner/operator of a stationary
combustion turbine that burns by-product fuels.
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 subpart GG (the original stationary gas turbine criteria
pollutant NSPS) was promulgated in 1979, the NO<INF>X</INF> emission
standards and compliance were based on performance testing. Based on
subsequent rulemakings, owners/operators of a gas turbine subject to
subpart GG with a NO<INF>X</INF> continuous emissions monitoring system
(CEMS) began determining excess emissions on a 4-hour rolling average
basis. The 4-hour basis was determined to be the approximate time
required to conduct a performance test using the performance test
method specified in subpart GG. This 4-hour rolling average became the
default for determining the emission rates of gas turbines, and, in
2006, was used in the subsequent review of the stationary combustion
turbine criteria pollutant NSPS (subpart KKKK).
When subpart KKKK was proposed in 2005, the NO<INF>X</INF>
performance emissions data were again based on stack performance tests,
which are representative of emission rates at high hourly loads, rather
than on CEMS data. The final NO<INF>X</INF> standards for high hourly
loads were consistent with the performance test data and manufacturer
guarantees. Manufacturer guarantees are only applicable during specific
conditions, which include the load of the combustion turbine and the
ambient temperatures. When combustion turbines are operated at part
loads and/or at low ambient temperatures, the identified BSER in
subpart KKKK--low NO<INF>X</INF> combustion controls--were not as
effective at reducing NO<INF>X</INF> from a technical standpoint.\25\
At part-load operation and low ambient temperatures, it is more
challenging to maintain stable combustion using dry low NO<INF>X</INF>
(DLN) and adjustments to the combustion system are required--resulting
in higher NO<INF>X</INF> 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.\26\
---------------------------------------------------------------------------

\25\ 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. The costs of requiring
combustion controls that would rarely be used are determined not to
be reasonable.
\26\ 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 high 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 high hourly load standard 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 turbine were
operating at high loads during the middle 4 hours, the high 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 high-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 proposing to use the same short-term 4-hour standard in
new subpart KKKKa along with the blended standard approach.
Specifically, the applicable emissions standard would be based on the
heat input weighted average of the four applicable hourly emissions
standards. However, the EPA

[[Page 101320]]

is proposing 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 are
capable of maintaining emission rates at loads of 70 percent and
greater rather than at loads of 75 percent or greater, as reflected in
subpart KKKK. Therefore, the EPA is proposing 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
since emission rates increase at lower loads, lowering the part-load
threshold would bring more operating periods under the high-load
subcategory. It could also result in a higher numeric standard. Longer
averaging periods reduce, but do not eliminate, the need for a part-
load standard. Even under a 30-operating-day average, combustion
turbines will, on occasion, have to operate under part-load conditions
for relatively long periods. Establishing an emissions rate that
includes all periods of operation and that is achievable decreases the
emission reduction required for combustion turbines operating at high
hourly capacity factors.\27\ Establishing absolute mass-based limits is
one potential approach to reduce emissions during all periods of
operation. In the Additional Requests for Comment section below, the
EPA is soliciting comment on mass-based standards in addition to short-
term emission rates to address any regulatory incentive for owners or
operators to reduce operating loads so that the part-load standard is
applicable.
---------------------------------------------------------------------------

\27\ A single emissions standard that applies at all times would
presumably need to be set at a numeric level that accounts for the
highest hourly emission rates--typically during startup and
shutdown.
---------------------------------------------------------------------------

Second, the EPA is proposing a different size threshold for
subcategorizing the part-load emission standards. Existing 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). New subpart KKKKa proposes 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 than smaller combustion turbines).
In addition to these two proposed changes from subpart KKKK, the
EPA is soliciting comment on a number of topics and concerns associated
with the part-load subcategory. Currently, there are no limits on the
number of hours per year that a combustion turbine could remain in
part-load operation and thus gain the benefit of the part-load
emissions standard. In this respect, we note that the threshold for the
part-load subcategory, even though proposed to be reduced to 70 percent
for subpart KKKKa, remains 30 percent higher than what would be
considered ``base load'' operation if measured on an annual basis
(i.e., a 40 percent capacity factor). Further, the BSER for the part-
load subcategory is diffusion flame technology, and the associated
emissions standards for that BSER are substantially less stringent than
the standards that would apply in non-part load operation. In fact, the
proposed part-load standard for small combustion turbines of 150 ppm
NO<INF>X</INF> is 50 times less stringent than the 3 ppm standard for
such turbines operating at base load on a 12-calendar-month capacity
factor basis (which assumes SCR operation in conjunction with
combustion controls). Likewise, the proposed part-load NO<INF>X</INF>
standard for medium and large combustion turbines of 96 ppm is 32 times
less stringent.
The EPA requests comment on measures that can be taken to reduce
this discrepancy and/or to narrow the scope of application of the part-
load standard so as to eliminate perverse incentives to take advantage
of a grossly less stringent emissions standard. The EPA requests
comment on a maximum limit to the number of hours per year that the
part-load standard can be applied. The EPA requests comment on limiting
the part-load standard only to those hours when a combustion turbine is
in startup or shutdown mode of operation. The EPA requests comment on
longer averaging times coupled with the elimination or shrinking of
this subcategory so that the emissions standards are set in such a way
that they can be complied with even when combustion turbines are in
part-load status.
Furthermore, the EPA requests comment on the efficacy of combustion
control technology operated in conjunction with SCR when units are in
part-load operation. The EPA notes that while there may be some loss in
efficiency in combustion controls or in SCR performance in part-load
operation, these technologies do not lose all value. Therefore, the EPA
requests comment on whether it is appropriate to exclude these
technologies from the BSER for part-load operation. If it is not
appropriate, then the EPA requests comment on what emissions
performance these technologies can achieve in part-load operation. The
EPA notes that even if there is some reduction in efficiency,
combustion controls in combination with SCR could still achieve
emissions rates in part-load operation as low as 9 ppm or 3 ppm, thus
calling into question whether emissions rates as high as 96 ppm or 150
ppm would be unjustified to sustain.
With respect to the use of longer averaging periods, the EPA
believes these could potentially be a part of the solution if the
emission standards were set at such a level that they accommodate some
part-load hours of operation where there is lower emissions control
efficiency. However, under this approach, this may not entirely remove
the need for a part-load standard. Even under a 30-operating-day
average, combustion turbines will on occasion have to operate under
part-load conditions for relatively long periods. Establishing an
emissions rate that includes all periods of operation and that is
achievable poses an equally concerning request that it would reduce the
stringency of the emissions reductions that are required for combustion
turbines operating at high hourly capacity factors.
With this concern in mind, the EPA also requests comment on whether
a mass-based emissions standard set over a longer period, such as
monthly or annually, could effectively ensure that part-load operation
is kept to a minimum so that an overall environmental result is
achieved that is in line with the more stringent emissions rates
associated with the EPA's proposed BSER determinations that include
combustion controls and SCR. Absolute mass-based limits can incentivize
reduced emissions during all periods of operation. In such an approach,
a mass-based cap would be established through multiplying an assigned
emissions rate that factors in some degree of part-load operation by a
reasonable assumption concerning operating levels over the period in
question. In the Additional Requests for Comment section, the EPA is
soliciting comment on mass-based standards in addition to short-term
emission rates. Among the reasons why such an approach may be both
environmentally effective and also reduce regulatory burdens, as
discussed in that section, is that any such approach could be tailored
to effectively address any regulatory incentive for owners/operators to
reduce operating loads so that the part-load standard is applicable.
Additionally, in subpart KKKKa, the EPA is proposing to maintain
the same ambient temperature subcategorization

[[Page 101321]]

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. However,
many of the same concerns associated with the part-load standard could
be of concern with the ambient temperature subcategorization. For
instance, it may be that while combustion controls and SCR lose some
performance in these cold conditions, they can still effectively reduce
emissions to a substantially greater degree than diffusion flame
technology alone. Therefore, the EPA similarly requests comment on
whether any of the factors or approaches described above in conjunction
with limiting the loss in stringency associated with the part-load
subcategory could appropriately be applied to the ambient temperature
subcategorization.
g. 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 combined heat and
power (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 subcategorizes this type of
operation and bases the NO<INF>X</INF> emissions standard on the use of
combustion controls for a steam generating unit under one of the steam
generating unit NSPS. The EPA is proposing to maintain the same
approach in subpart KKKKa and to subcategorize operation of the HRSG
independent of the combustion turbine engine with the same emissions
standard as in subpart KKKK.
5. Form of the Standard
The form of the concentration-based NO<INF>X</INF> standards of
performance in subpart KKKK is based on parts per million (ppm)
corrected to 15 percent O<INF>2</INF> and the form of alternate output-
based NO<INF>X</INF> standards is determined on a pounds per megawatt
hour-gross (lb/MWh-gross) basis. Also, manufacturer guarantees are
often reported in ppm and operating permits are often issued in ppm.
Aligning the form of the NSPS with common practice simplifies
understanding of the emission standards and reduces burden to the
regulated community. While not the primary form of the standard, the
alternate output-based form of lb/MWh-gross recognizes the
environmental benefit of highly efficient generation.
In new subpart KKKKa, the EPA is proposing input-based
NO<INF>X</INF> standards in the form of pounds per million British
thermal units (lb/MMBtu) and alternate output-based standards in both a
gross- and net-output form. As described in the hydrogen combustion
section (III.B.14), co-firing hydrogen can increase the NO<INF>X</INF>
emissions rate on a ppm basis when corrected to 15 percent
O<INF>2</INF> while absolute NO<INF>X</INF> emissions may not
significantly change. Since actual emissions to the atmosphere are the
measure of environmental impacts, the NO<INF>X</INF> emission standards
in the form of lb/MMBtu is a superior measure of environmental
performance when comparing emissions from different fuel types.
However, throughout this document, the EPA refers to NO<INF>X</INF>
emission rates using ppm for ease of comparison with performance
guarantees and permitted emission rates. The actual proposed standards
in new subpart KKKKa are in the form of an equivalent lb/MMBtu for a
natural gas-fired combustion turbine or a distillate oil-fired
combustion turbine for the proposed natural gas- and non-natural gas-
fired NO<INF>X</INF> emission standards, respectively.
Consistent with the final Carbon Pollution Standards, the EPA is
proposing in subpart KKKKa that the alternate output-based standards be
in the form of both gross- and 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 is reported to CAMPD and
the EPA can evaluate gross-output based emission rates directly.\28\
While this emissions rate is representative of combined cycle turbines
without carbon capture and storage (CCS) equipment, the Carbon
Pollution Standards require all new base load combustion turbines to
install CCS by 2032. To account for the efficiency loss due to CCS, the
EPA proposes to use the ratio of the National Energy Technology
Laboratory (NETL) combined cycle model plants. Specifically, the
achievable gross-output efficiency will be determined by reviewing
reported hourly data. The ratio of the NETL combined cycle turbine
without CCS gross efficiency will be compared to the NETL combined
cycle turbine with CCS gross and net efficiency. These ratios will be
multiplied by the reported gross-output emission rate values to
determine the proposed alternate output-based standards. As an
alternative to continuously monitoring parasitic loads, the EPA is
proposing in new 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. The EPA is requesting comment on
this approach and whether a four-load test is appropriate or whether a
curve fit of three loads greater than 25 percent load is sufficient.
---------------------------------------------------------------------------

\28\ Net output is not reported to CAMPD.
---------------------------------------------------------------------------

6. Averaging Period
As described previously, the NO<INF>X</INF> 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). For
this review of the NSPS, the EPA analyzed hourly emissions data using
three averaging periods--a 4-hour rolling average, an operating-day
average, and a 30-operating-day average. The EPA is proposing in new
subpart KKKKa that the emission standards for all combustion turbines
complying with the input-based standard (lb NO<INF>X</INF>/MMBtu) would
be determined on a 4-hour rolling average. According to the EPA's
review of hourly emissions data, combustion turbines using combustion
controls alone and combustion controls in combination with SCR have a
relatively steady emissions profile. The Agency is proposing that
shortening the compliance period for combined cycle and CHP units would
provide similar levels of environmental protection as the current
averaging periods in subpart KKKK. Permits are often based on daily
operations and the EPA is soliciting

[[Page 101322]]

comment on whether aligning these periods could reduce the reporting
burden. To avoid situations where the daily average would be based on
limited data that does not account for variability, emissions averages
would only be determined for operating days with 4 or more hours of
CEMS data that are not out-of-control. Data from operating days with
fewer than 4 hours of CEMS data that are not out-of-control would be
rolled over to the next operating day until 4 or more hours of data are
available. A benefit of this approach is that all non-out-of-control
emissions data would be used in determining excess emissions. Under the
subpart KKKK approach, any 4 operating hours with more than 1 hour of
monitor downtime is reported as monitor downtime and the emissions from
the remaining hours are excluded. The EPA proposes to carry this
approach forward in proposed subpart KKKKa. However, this could
potentially exclude reliable monitoring data and complicate
determinations that emissions are in or out of compliance with the
emissions standards. Thus, in the alternative, the EPA is soliciting
comment on basing compliance for all combustion turbines on a 4-hour
rolling average basis where only those hours with monitor downtime are
excluded.
Subpart KKKK currently includes alternate gross output-based
standards that owners and operators can elect to comply with instead of
the input-based standard. The output-based standard was determined
using an efficiency that is representative of a combined cycle turbine,
so, in practice, only owners and operators of combined cycle or CHP
facilities would elect to use the output-based standard. The EPA is
proposing to include output-based standards, on both a gross- and net-
output basis, as an alternative to the heat input-based standards.
Owners and 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 NO<INF>X</INF>
emissions rate on a lb NO<INF>X</INF>/MMBtu basis and the efficiency of
the combustion turbine can vary--increasing the overall variability.
7. Proposed Determinations of the BSER for New, Modified, and
Reconstructed Stationary Combustion Turbines in 40 CFR Part 60, Subpart
KKKKa
Sections III.B.7 through III.B.11 describe the EPA's proposed BSER
determinations for the different size-based subcategories in subpart
KKKKa based on a review of demonstrated NO<INF>X</INF> emission control
technologies. The following sections describe each of the proposed
combustion turbine subcategories and each proposed BSER technology
determination. The control technologies the EPA evaluated for each
size-based subcategory, whether the combustion turbine operates as a
low load, intermediate load, or base load unit, or whether the
combustion turbine burns natural gas or non-natural gas fuels, 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. In sections III.B.7.a and
III.B.7.b, the EPA describes the basic characteristics and performance
of dry and wet combustion controls and then SCR, including information
concerning costs. In sections III.B.9 through III.B.11, the EPA applies
the BSER criteria for these two general technology types, including
further consideration of costs, emission reductions, and non-air
quality health and environmental impacts and energy requirements, as
applied to the small, medium, and large subcategories proposed for
NO<INF>X</INF> in subpart KKKKa.
Under the existing NSPS in subpart KKKK, newly constructed
stationary combustion turbines are subject to more stringent
NO<INF>X</INF> emission standards than reconstructed and modified
combustion turbines. The proposed subcategorization approach in subpart
KKKKa does not maintain this structure. Specifically, in subpart KKKKa,
the EPA is proposing that the same BSER and NO<INF>X</INF> emission
standards are applicable to both new and reconstructed combustion
turbines, regardless of the subcategory. In addition, the EPA is
proposing that the BSER and NO<INF>X</INF> emission standards for
``modified'' sources are the same as for the corresponding new and
reconstructed sources for certain subcategories, and different for
others as explained in more detail below in section III.B.13. The EPA
is proposing to use the same emissions analysis for both new and
reconstructed stationary combustion turbines. For each of the
subcategories, the EPA is proposing that the proposed BSER results in
the same standard of performance for new stationary combustion turbines
and reconstructed stationary combustion turbines because reconstructed
turbines could likely incorporate technologies to reduce NO<INF>X</INF>
as part of the reconstruction process at little or no cost compared to
a greenfield facility.
Under the EPA's General Provisions for the NSPS program, a
reconstructed source would still be able to obtain an alternative
emissions standard on a case-by-case basis. A reconstructed stationary
combustion turbine is not required to meet the standards if doing so is
deemed to be ``technologically and economically'' infeasible.\29\ This
provision requires a case-by-case reconstruction determination in the
light of considerations of economic and technological feasibility.
However, this case-by-case determination would consider the identified
BSER, as well as technologies the EPA considered, but rejected, as BSER
for a nationwide rule. One or more of these technologies could be
technically feasible and of reasonable cost, depending on site-specific
feasibility.
---------------------------------------------------------------------------

\29\ See 40 CFR 60.15(b)(2).
---------------------------------------------------------------------------

The EPA is proposing in new subpart KKKKa that for small natural
gas-fired stationary combustion turbines (i.e., those with base load
ratings of less than or equal to 250 MMBtu/h of heat input) operating
as base load units (i.e., at 12-calendar-month capacity factors of
greater than 40 percent), the BSER is dry combustion controls in
combination with SCR. The EPA is proposing wet combustion controls in
combination with SCR as the BSER for small, base load, non-natural gas-
fired stationary combustion turbines. However, for small combustion
turbines operating at low or intermediate loads (i.e., at 12-calendar-
month capacity factors of less than or equal to 40 percent), the
proposed BSER is dry combustion controls for natural gas-fired units
and wet combustion controls for non-natural gas-fired units. The
proposed BSER for small low and intermediate load combustion turbines
does not include SCR.
In new subpart KKKKa, for medium stationary combustion turbines
(i.e., those with base load ratings greater than 250 MMBtu/h of heat
input and less than or equal to 850 MMBtu/h) the EPA is proposing that
the BSER is dry or wet combustion controls in combination with SCR for
both natural gas-fired and non-natural gas-fired combustion turbines.
However, for medium stationary combustion turbines that operate as low
load units (i.e., at 12-calendar-month capacity factors of less than or
equal to 20 percent) and that are natural gas-fired, the EPA is
proposing that the BSER is dry combustion controls and does not include
SCR. The EPA is proposing that the BSER for medium, low load, non-
natural gas-fired combustion turbines is wet combustion controls and
does not include SCR.
The EPA is proposing in new subpart KKKKa that for large stationary
combustion turbines (i.e., those with base load ratings greater than
850 MMBtu/h of heat input) that operate at

[[Page 101323]]

intermediate or high loads (i.e., at 12-calendar-month capacity factors
of greater than 20 percent), the BSER is dry or wet combustion controls
in combination with SCR for both natural gas-fired and non-natural gas-
fired combustion turbines. Additionally, in subpart KKKKa, the EPA is
proposing that for large stationary combustion turbines that operate at
low loads (i.e., at 12-calendar-month capacity factors of less than or
equal to 20 percent) and that are natural gas-fired, the BSER is dry
combustion controls and does not include SCR. The EPA is proposing that
the BSER for large, low load, non-natural gas-fired combustion turbines
is wet combustion controls and does not include SCR.

Table 1--Proposed BSER and NOX Emission Standards
----------------------------------------------------------------------------------------------------------------
NOX emission NOX emission
Combustion turbine standard (lb/ rate
Combustion turbine type fuel BSER MMBtu) equivalent
(ppm)
----------------------------------------------------------------------------------------------------------------
New or reconstructed with capacity Natural gas.......... Combustion controls.. 0.092 25
factor <=40 percent and base load Non-natural gas...... Combustion controls.. 0.290 74
rating <=250 MMBtu/h.
New or reconstructed with capacity Natural gas.......... Combustion controls 0.011 3
factor >40 percent and base load Non-natural gas...... with SCR. 0.035 9
rating <=250 MMBtu/h. Combustion controls
with SCR.
Modified combustion turbines, all Natural gas.......... Combustion controls.. 0.092 25
loads with base load rating <=250 Non-natural gas...... Combustion controls.. 0.290 74
MMBtu/h.
New or reconstructed with capacity Natural gas.......... Combustion controls.. 0.092 25
factor <=20 percent and base load Non-natural gas...... Combustion controls.. 0.290 74
rating >250 MMBtu/h and <=850
MMBtu/h.
New or reconstructed with capacity Natural gas.......... Combustion controls 0.011 3
factor >20 percent and base load Non-natural gas...... with SCR. 0.035 9
rating >250 MMBtu/h and <=850 Combustion controls
MMBtu/h. with SCR.
Modified combustion turbines, all Natural gas.......... Combustion controls.. 0.092 25
loads with base load rating >250 Non-natural gas...... Combustion controls.. 0.290 74
MMBtu/h and <=850 MMBtu/h.
New, modified, or reconstructed Natural gas.......... Combustion controls.. 0.055 15
with capacity factor <=20 percent Non-natural gas...... Combustion controls.. 0.150 42
and base load rating >850 MMBtu/h.
New, modified, or reconstructed Natural gas.......... Combustion controls 0.011 3
with capacity factor >20 percent Non-natural gas...... with SCR. 0.019 5
and base load rating >850 MMBtu/h. Combustion controls
with SCR.
New, modified, or reconstructed Natural gas.......... Combustion controls.. 0.092 25
offshore combustion turbines, all Non-natural gas...... Combustion controls.. 0.290 74
sizes and loads.
Combustion turbines with base load Natural gas or non- Diffusion flame 0.58 150
rating <=250 MMBtu/h operating at natural gas. combustion controls.
part load, sites north of the
Arctic Circle, and/or ambient
temperatures of less than 0
[deg]F.
Combustion turbines with base load Natural gas or non- Diffusion flame 0.37 96
rating >250 MMBtu/h operating at natural gas. combustion controls.
part load, sites north of the
Arctic Circle, and/or ambient
temperatures of less than 0
[deg]F.
Heat recovery units operating Natural gas or non- Combustion controls.. 0.21 54
independent of the combustion natural gas.
turbine(s).
----------------------------------------------------------------------------------------------------------------

a. Dry and Wet Combustion Controls
Combustion turbines without NO<INF>X</INF> 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
NO<INF>X</INF>. In contrast, combustion controls consist of operational
or design modifications that govern combustion conditions to reduce
NO<INF>X</INF> formation. Combustion controls are widely available for
new combustion turbines and are generally low cost and provide
substantial reductions in NO<INF>X</INF> emissions relative to
combustion turbines without combustion controls. In subpart KKKK, the
EPA identified combustion controls as the BSER for limiting
NO<INF>X</INF> emissions from stationary combustion turbines firing
natural gas and non-natural gas fuels (e.g., distillate oil). The
specific technologies described in subpart KKKK for the control of
NO<INF>X</INF> from natural gas-fired combustion turbines are dry
controls based on a lean premix/DLN combustion system. See 71 FR 38482;
July 6, 2006.
Wet combustion controls (e.g., water injection) are a mature
combustion control technology that has been used since the 1970s to
control NO<INF>X</INF> emissions from combustion turbines. This system
involves 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 NO<INF>X</INF> formation. Wet control
systems are designed to a specific water-to-fuel ratio that has a
direct impact on the controlled NO<INF>X</INF> emission rate and is
generally controlled by the combustion turbine inlet temperature and
ambient temperature. Wet control systems have demonstrated the ability
to limit NO<INF>X</INF> emissions to as low as 25 ppm for stationary
combustion turbines firing natural gas and between 42 ppm to 75 ppm for
sources firing non-natural gas liquid fuels.
Wet combustion controls can be combined with technologies that
decrease the negative impacts of higher ambient temperatures on the
efficiency and output of combustion turbine engines and/or that
increase the

[[Page 101324]]

efficiency and output of the combustion turbine engine. Intercooling
technologies that inject demineralized water into the combustor through
the fuel nozzles also provide NO<INF>X</INF> control. Thus, water
injected into the combustor flame area lowers the temperature and,
consequently, reduces NO<INF>X</INF> emissions.\30\ Water injection
also increases the mass flow rate and the power output, but the energy
required to vaporize the water can reduce overall efficiency. In
general, the lower capital costs and higher variable costs of water
injection compared to other NO<INF>X</INF> control technologies make it
an attractive option for peaking combustion turbines or other sources
that operate infrequently.
---------------------------------------------------------------------------

\30\ 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
NO<INF>X</INF> emissions and has the advantage of improved efficiency
and larger increases in the output of the combustion turbine. Multiple
vendors offer different variations of steam injection. The basic
process uses a relatively simple and low-cost HRSG to produce steam,
but instead of recovering the energy by expanding the steam through a
steam turbine, the steam is injected into the combustion chamber and
the energy is extracted by the combustion turbine engine.\31\
Combustion turbines using steam injection have characteristics of both
simple cycle and combined cycle units. For example, when compared to
standard simple cycle turbines, they are more efficient but more
complex with higher capital costs. Conversely, compared to combined
cycle combustion turbines, they are simpler and have shorter
construction times, have lower capital costs, but have lower
efficiencies.32 33 Combustion turbines using steam injection
can start quickly, have good part load performance, and can respond to
rapid changes in demand. A potential drawback of steam injection is
that the additional pressure drop across the HRSG can reduce the
efficiency of the combustion turbine when the facility is running
without the steam injection operating.
---------------------------------------------------------------------------

\31\ Innovative Steam Technologies. GTI. Accessed at <a href="https://otsg.com/industries/powergen/gti/">https://otsg.com/industries/powergen/gti/</a>.
\32\ Bahrami, S., et al (2015). Performance Comparison between
Steam Injected Gas Turbine and Combined Cycle during Frequency
Drops. Energies 2015, Volume 8. <a href="https://doi.org/10.3390/en8087582">https://doi.org/10.3390/en8087582</a>.
\33\ Mitsubishi Power. Smart-AHAT (Advanced Humid Air Turbine.
Accessed at <a href="https://power.mhi.com/products/gasturbines/technology/smart-ahat">https://power.mhi.com/products/gasturbines/technology/smart-ahat</a>.
---------------------------------------------------------------------------

Dry low NO<INF>X</INF> (DLN) combustion control systems were
commercially introduced more than 30 years ago. The basis of dry
NO<INF>X</INF> control is to premix the fuel and air and supply the
combustion zone with a completely 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 low peak flame
temperature, thereby limiting the formation of thermal NO<INF>X</INF>.
Lean combustion may be combined with staged combustion to achieve
additional NO<INF>X</INF> 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 NO<INF>X</INF> formation. When increasing the
air/fuel ratio, excess air is added to the mixture, and not only does
this lean the combustion air by adding more air to the air/fuel ratio,
but it also decreases the residence time at peak flame temperatures.
Dry combustion control systems can typically limit NO<INF>X</INF>
emission concentrations to 25 ppm, while advanced ultra-low DLN
technology can further reduce NO<INF>X</INF> emissions to 15 or 9 ppm
and to as low as 5 ppm for certain large frame combustion turbine
designs. DLN combustion systems are complex and sensitive to the load
of the combustion turbine and changes in load. The premixed fuel is
typically supplied by multiple injection ports and lean-premix flame
zones. A diffusion flame pilot zone is sometimes required to maintain
combustion stability in the lean premix zones and contributes to
thermal NO<INF>X</INF>. During steady State operation the fuel supplied
to the pilot zone is minimized. However, during variable load operation
and lower loads, it is necessary to increase the percentage of fuel
supplied to the pilot zone and NO<INF>X</INF> emissions increase above
the steady State high load conditions.
DLN is less effective with distillate fuel oil (and other liquid
fuels) because distillate fuel oil has a higher peak flame temperature
than natural gas and results in higher NO<INF>X</INF> formation rates,
and it is more challenging to achieve unform mixing of the air and
fuel.
b. Selective Catalytic Reduction
Selective catalytic reduction (SCR) is a mature and well understood
post-combustion add-on NO<INF>X</INF> 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 stationary combustion turbines in the
power sector currently utilize the NO<INF>X</INF> reduction
capabilities of SCR. For example, based on information reported to the
EPA's Clean Air Markets Program Data (CAMPD) in the last five years,
SCR has been installed on all new power sector combined cycle
combustion turbines and a majority of recent power sector simple cycle
combustion turbines.\34\ Specifically, of the new power sector simple
cycle turbines constructed in the last 5 years, 88 percent (59 of 67)
of those smaller than 850 MMBtu/h and 46 percent (11 of 24) of those
larger than 850 MMBtu/h have installed SCR. Most simple cycle turbines
in the power sector operate at low annual capacity factors (i.e., less
than 20 percent).\35\ A potential reason why more medium simple cycle
combustion turbines have been required to use SCR is because most of
these units are aeroderivative designs with guaranteed NO<INF>X</INF>
emission rates of 25 ppm and potentially higher annual capacity
factors. The larger units tend to be frame-type combustion turbines
with NO<INF>X</INF> guarantees of 15 ppm or 9 ppm. Since the capital
costs are more dependent on the controlled emissions rate and not the
percent reduction, the incremental control costs of SCR can be higher
and emission reductions lower for large frame units relative to medium
aeroderivative units. In addition, the exhaust temperature of the most
efficient frame-type combustion turbine is approximately 200 [deg]C
higher than the most efficient aeroderivative combustion turbines. The
exhaust must be cooled prior to the SCR, and so the higher exhaust
temperatures increase the cost of the SCR system. The technology can be
applied as a standalone NO<INF>X</INF> control or combined with other
technologies, including the wet and dry combustion controls discussed
previously.
---------------------------------------------------------------------------

\34\ See the U.S. Environmental Protection Agency's (EPA) Clean
Air Markets Program Data at <a href="https://campd.epa.gov/data">https://campd.epa.gov/data</a>.
\35\ Based on operating data reported to the EPA's Clean Air
Markets Program Data, the EPA projects that approximately 10 percent
of simple cycle turbines would operate at 12-calendar-month capacity
factors of greater than 20 percent and would be subcategorized as
intermediate load combustion turbines. The proposed BSER for this
subcategory is based on the use of combustion controls in
combination with SCR. All of the projected intermediate load simple
cycle turbines are aeroderivative designs and have SCR in the base
case.
---------------------------------------------------------------------------

The SCR process is based on the chemical reduction of the
NO<INF>X</INF> molecule via a nitrogen-based reducing agent

[[Page 101325]]

(reagent) and a solid catalyst. To remove NO<INF>X</INF>, the reagent,
commonly ammonia (NH<INF>3</INF>, 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
NO<INF>X</INF> within a specific temperature range and in the presence
of the catalyst and oxygen to reduce the NO<INF>X</INF> into molecular
nitrogen (N<INF>2</INF>) and water vapor (H<INF>2</INF>O). 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 EPA's review of combustion turbine emissions data and applied
control technologies for this proposed NSPS demonstrates a correlation
between the efficiency of new turbine designs and NO<INF>X</INF>
emissions using combustion controls. For example, manufacturers have
continuously strived to increase the efficiency of new turbine designs.
However, manufacturer specification sheets show that some models of
large, high-efficiency turbines cannot meet the 15 ppm NO<INF>X</INF>
standard established in subpart KKKK. A review of power sector data
reported to EPA's CAMPD--as well as BACT permits under the NSR
program--shows that many owners/operators of high-efficiency combustion
turbines subject to a NO<INF>X</INF> limit of 15 ppm have installed
SCR. This correlation between high-efficiency combustion turbines and
increased NO<INF>X</INF> emissions has led to SCR becoming a more
utilized control technology for the source category.
As discussed in more detail in sections III.B.9 through III.B.11,
available data indicates that SCR installed on stationary combustion
turbines, when operated in conjunction with combustion controls, is
generally capable of achieving a NO<INF>X</INF> emissions rate of 3
ppm, at least when combustion turbines are operating at intermediate or
base loads. Therefore, in general, for those subcategories of
stationary combustion turbines for which the EPA is proposing SCR as a
component of the BSER and which are firing natural gas, the EPA is
proposing an emissions standard of 3 ppm. However, the EPA is
soliciting comment on a range of possible emissions rates, from 2 to 5
ppm, recognizing the potential for some variation in SCR performance
among units and operating conditions.\36\ The EPA notes that
effectiveness of SCR can be impacted by load changes. During variable
load operation the absolute mass of NO<INF>X</INF> entering the SCR
system, the temperature of the combustion turbine exhaust, and exhaust
flow characteristics change. SCR performance is impacted by catalyst
temperature and flow characteristics and the ammonia injection rate
must be adjusted to maintain the exhaust NO<INF>X</INF> emissions
concentration. Too much ammonia injection can result in excess ammonia
emissions (i.e., ammonia slip) and too little can result in higher
NO<INF>X</INF> emissions. The EPA is soliciting comment on if it can be
challenging to adjust ammonia injection rates during rapid load changes
to maintain NO<INF>X</INF> emissions rates while at the same time
minimizing ammonia slip, particularly for combustion turbines not
selling electricity to the electric grid.
---------------------------------------------------------------------------

\36\ An emissions rate of 5 ppm could also potentially be met by
some stationary combustion turbines solely with the use of
combustion controls rather than SCR. Given that SCR has some
additional cost, pollutant, and energy impacts associated with it,
there could be benefit to a standard that at least some sources may
be capable of meeting without installing SCR. However, this
observation does not negate the EPA's proposed determination that
SCR satisfied the BSER statutory criteria.
---------------------------------------------------------------------------

The EPA also invites comments on methods for control of ammonia
emissions from SCR operation more broadly. The EPA is not proposing to
establish a BSER or standards of performance for ammonia emissions from
stationary combustion turbines. However, the EPA is soliciting comment
on opportunities to reduce ammonia emissions--either through
operational changes or though incorporation of downstream ammonia
control technology. The EPA requests comment on the commercial
availability, cost, and performance of technologies that reduce the
amount of ammonia emitted in association with SCR operation. The EPA
requests comment on whether there are practices associated with SCR
operation to limit ammonia emissions based on these technologies or
other approaches. The EPA also solicits comment on whether there are
disbenefits of using ammonia emission control technologies. The EPA
further discusses specific estimates of ammonia emissions associated
with SCR operation in its size-based subcategory discussions of the
BSER in sections III.B.9.b.iv, III.B.10.b.iv, and III.B.11.b.iv of this
document.
In 2006, when subpart KKKK was promulgated, SCR was evaluated as a
potential best system, and based on a relatively limited review of the
available information at the time, was viewed to not meet the statutory
criteria. The available information suggested that the cost of
achieving incremental reductions in NO<INF>X</INF> emission
concentrations with the use of SCR was relatively high on a per-ton
basis compared to the lean premix/DLN systems that were the dominant
controls in the combustion turbine marketplace at that time. Stack test
data and manufacturer guarantees confirmed that newer large combustion
turbines without add-on controls could achieve NO<INF>X</INF> emission
concentrations as low as 9 ppm while SCR could achieve NO<INF>X</INF>
emission concentrations of 2 to 4 ppm. Furthermore, for SCR to
effectively remove NO<INF>X</INF> from the combustion turbine exhaust,
the system's catalyst must reach a minimal operating temperature. For
peaking units or combustion turbines operating under variable loads,
the EPA understood it to be challenging for the SCR catalyst to reach
or to maintain the required operating temperature, and the EPA had not
developed the approach to subcategorization that it applied in the
Carbon Pollution Standards and is now proposing in this action, which
would distinguish between low, intermediate, and base load levels of
utilization. Therefore, based on the analysis at the time, it was
determined in subpart KKKK that SCR could be too difficult and not
incrementally cost effective on a per-ton basis to implement for
certain combustion turbines.
As will be detailed below in the subcategory-specific review of SCR
technology as BSER for NO<INF>X</INF>, the EPA has undertaken a careful
review of the BSER factors in relation to SCR, and proposes to
determine that SCR is generally a part of the BSER for stationary
combustion turbines, except for small turbines that only operate at low
or intermediate loads on a 12-calendar-month basis and medium and large
turbines that only operate at low loads on a 12-calendar-month basis. A
review of recent rules and determinations, multiple other cost metrics
that are relevant to consider, and the widespread adoption of this
technology across many types and sizes of power sector stationary
combustion turbines in recent years, all contribute to support our
determination that this technology is cost-reasonable for the
subcategories of turbines to which we propose to apply it as BSER in
subpart KKKKa.
There are a number of indicators that broadly support the cost-
reasonableness of SCR as a part of the BSER for stationary combustion
turbines of all sizes.

[[Page 101326]]

First, as described above, SCR is already widely adopted as an
emissions control strategy for many types and sizes of stationary
combustion turbines, with 100 percent of all new combined cycle units
and approximately 75 percent of all new simple cycle units in the power
sector installing SCR in the last 5 years. The EPA found the
information contained in the records of permitting actions requiring
SCR on turbines to not be particularly well developed for purposes of
informing a detailed cost analysis. However, all of the instances where
sources have chosen to install SCR and go forward with their new
turbine project or installation (whether because required by a
permitting authority or for voluntary reasons) underscores that SCR
costs do not undermine the economic viability of new combustion turbine
projects. From that perspective, the costs are clearly reasonable. If
the costs were not reasonable, then one would expect that developers
would abandon their combustion turbine projects once SCR was required.
Instead, we have seen widespread adoption in the power sector.
Second, the costs of SCR as a percentage of the total capital cost
associated with constructing a new combustion turbine are relatively
low. As described in more detail in the subcategory-specific
discussions of SCR costs further in this section, the EPA estimated
that the spent capital cost of including an SCR into the design of a
new small or medium stationary combustion turbine is typically around
$2 million to $4 million (2018$), depending on the SCR type. The
estimation of spent capital cost is approximately $4 million to $10
million (2018$) depending on SCR type for large units. These costs
typically represent approximately 1 to 4 percent of the total cost of a
new stationary combustion turbine.\37\ In the EPA's judgment, and as
reflected in the widespread adoption of SCR technology in the power
sector already, these costs on either an absolute basis or as a
percentage of capital investment, are reasonable. The EPA is not aware
of any reasons why the costs for adoption of SCR technology on newly
constructed non-power sector combustion turbines would be different
from adoption on newly constructed and comparably-sized power sector
combustion turbines. The EPA solicits comment on whether there are such
reasons or circumstances where the costs of SCR adoption would be
different for comparably-sized combustion turbines constructed in the
power sector and in non-power industrial sectors.
---------------------------------------------------------------------------

\37\ The estimated as spent capital costs of SCR vary with the
type of the SCR (hot or conventional) size of the combustion
turbine, but the estimated capital costs are approximately $70/
kilowatt (kW) for a 50 MW simple cycle turbine and $10/kW for a 400
MW combined cycle turbine.
---------------------------------------------------------------------------

Third, these costs translate into a relatively low cost per unit of
energy output and thus, in terms of their effect on prices or cost to
the consumer, are relatively small and manageable. Total costs
(annualized capital costs, fixed costs, and operating costs) in terms
of cost per unit of production (in terms of electricity generation)
translate into $3/MWh and $1/MWh, respectively, for a 50 MW simple
cycle combustion turbine operating at a 12-operating-month capacity
factor of 30 percent and a 400 MW combined cycle combustion turbine
operating at a 12-operating-month capacity factor of 60 percent,
respectively. These cost effects on generation compare favorably with
prior EPA rules. For example, the EPA identified $8.50/MWh in selecting
CCS as the BSER for certain new stationary combustion turbines in the
recently promulgated Carbon Pollution Standards. See 89 FR 39798; May
9, 2024. Likewise, in the Carbon Pollution Standards for coal-fired
EGUs, the EPA identified $18/MWh in selecting CCS for that category,
noting that this cost per unit of generation compared favorably with a
value of $18.50/MWh identified with the control stringency for EGUs
identified in the original Cross-State Air Pollution Rule (CSAPR). See
89 FR 39879, 39882.
Fourth, costs on a per-ton basis also compare favorably with prior
EPA rulemakings regulating NO<INF>X</INF> 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. As described in more detail in the
subcategory-specific sections below, the EPA has identified a cost of
$12,000 per ton of NO<INF>X</INF> abated as the cost effectiveness
range for small units operating at base load; a range of $12,000 to
$5,100 per ton of NO<INF>X</INF> abated as the cost effectiveness range
for medium units operating at intermediate or base load, respectively;
and $8,400 to $3,800 per ton of NO<INF>X</INF> abated as the cost
effectiveness range for large units operating at intermediate and base
load, respectively. As described in further detail in those sections,
these costs increase against a higher controlled baseline. Nonetheless,
in new subpart KKKKa, for those subcategories for which the EPA
proposes SCR as the BSER, these costs per ton are comparable to more
recent determinations of cost effectiveness for NO<INF>X</INF> control,
particularly following the strengthening of the ozone NAAQS in 2015 to
be more protective of human health and the environment. For instance,
the proposed SCR costs are generally lower than the estimated SCR costs
for retrofit applications in the Federal Implementation Plan Addressing
Regional Ozone Transport for the 2015 Ozone National Ambient Air
Quality Standard rulemaking, where the EPA identified $11,000/ton of
NO<INF>X</INF> as the appropriate representative cost threshold for
defining ``significant contribution'' under CAA section
110(a)(2)(D)(i)(I). That is the representative cost for the retrofit of
SCR on coal-fired EGUs, which reflects a fleetwide average with
individual units' costs ranging higher or lower than the fleetwide
average. See 88 FR 36654, 36746; June 5, 2023. As the EPA explained in
that action, its determinations of emissions control stringency for
upwind States were generally in accordance with the technology-based
emissions control determinations in areas struggling with high ozone
levels. Id. at 36661, 36838. Indeed, the EPA recognized that costs on
an individual unit basis may range higher than $20,000/ton on a unit-
specific basis and yet still be justified, particularly where the
control technology itself is no different, and those cost-per-ton
figures are merely driven by operational choices of the relevant units.
Id. at 36746-47. In such circumstances where units are of such a size
that they have the potential to emit at much higher levels if they were
to operate more, the EPA explained that cost-per-ton figures based on
historical operational data would not supply an appropriate
justification not to ensure that such sources meet an appropriate
uniform level of emissions performance that like sources would be
subject to. Id. The EPA notes that estimated reductions, costs, and
cost effectiveness of SCR in this proposal are based on short-term
achievable emission standards as opposed to estimated longer term
emission rates. Combustion turbines with guaranteed NO<INF>X</INF>
emission rates, which are only guaranteed under certain conditions,
have long-term emission rates lower than the guaranteed levels. For
example, combustion turbines with guaranteed NO<INF>X</INF> emission
rates of 25 ppm, 15 ppm, and 9 ppm have long-term emission

[[Page 101327]]

rates of 20 ppm, 14 ppm, and 7 ppm NO<INF>X,</INF> respectively.
Similarly, combustion turbines with SCR and complying with a short-term
emissions standard of 3 ppm NO<INF>X</INF> have long-term emission
rates of 2 ppm NO<INF>X</INF>. Using long-term averages for the
benefits and costs would on average increase incremental control costs.
Similarly, here, viewing the data concerning the costs as well as
the widespread deployment and efficacy of SCR technology for combustion
turbines as a whole, the EPA proposes that, with the exception of
specified circumstances of relatively permanent (i.e., 12-calendar-
month) low-load and low-emissions operating conditions, SCR is an
adequately demonstrated and cost effective NO<INF>X</INF> emissions
control technology that can readily be deployed on new, reconstructed,
and modified stationary combustion turbines of all sizes and is
therefore appropriate to include as a component of the BSER. For this
technology review, the EPA estimated the capital and operating costs of
SCR primarily using information from the U.S. Department of Energy's
(DOE) NETL flexible generation report.\38\ 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 for SCR costs on natural gas-fired boilers and Agency
engineering judgment. For detailed information on the costing analysis,
see the SCR costing technical support document included in the docket
for this proposal. More detailed cost-per-ton and other related cost
figures will be discussed in the subcategory-specific sections below,
including specific solicitations for comment on aspects of the EPA's
cost estimates for certain stationary combustion turbines.
---------------------------------------------------------------------------

\38\ 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 <a href="https://www.osti.gov/biblio/1973266">https://www.osti.gov/biblio/1973266</a>.
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8. BSER for Combustion Turbines Operating at Part Loads, Located North
of The Arctic Circle, or Operating at Ambient Temperatures of Less Than
0 [deg]F
Dry combustion controls (i.e., lean premix/DLN) are less effective
at reducing NO<INF>X</INF> emissions at part-load operations and low
ambient temperatures. In addition, SCR is only effective at reducing
NO<INF>X</INF> under certain temperatures at part loads and is not as
effective at reducing NO<INF>X</INF> as at design conditions. The only
technology the EPA has identified for all part-load operation and/or
low ambient temperatures is the use of diffusion flame combustion.
Therefore, in subpart KKKKa, the EPA is proposing that diffusion flame
combustion is the BSER for these conditions.\39\
---------------------------------------------------------------------------

\39\ A BSER of diffusion flame combustion includes DLN that is
less effective at reducing NO<INF>X</INF> than DLN under design
conditions.
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9. BSER for Small Combustion Turbines
This section describes the proposed BSER determinations for new and
reconstructed small stationary combustion turbines with base load
ratings of less than or equal to 250 MMBtu/h of heat input. For
combustion turbines that would be included in this subcategory, the
proposed BSER is the use of dry or wet combustion controls in
combination with SCR when operating as base load units (i.e., at 12-
calendar-month annual capacity factors greater than 40 percent). For
combustion turbines in this small size subcategory operating at low or
intermediate loads (i.e., at 12-calendar-month annual capacity factors
of less than or equal to 40 percent), the proposed BSER is the use of
dry combustion controls (i.e., lean premix/dry low NO<INF>X</INF>
(DLN)) when firing natural gas and wet combustion controls (i.e., water
or steam injection) when firing non-natural gas fuels.
a. Combustion Controls
This section describes the current availability and performance of
dry and wet combustion controls that have been used by owners/operators
of small stationary gas and combustion turbines to limit NO<INF>X</INF>
emissions since the original NSPS (subpart GG) was promulgated in 1979.
Both wet and dry combustion controls also were maintained as the BSER
in existing subpart KKKK in 2006. This control technology continues to
be used on new and reconstructed stationary combustion turbines,
including those with base load ratings of less than or equal to 250
MMBtu/h of heat input.
i. Adequately Demonstrated
Dry and/or wet combustion controls are widely available from major
manufacturers for combustion turbines with base load ratings of less
than or equal to 250 MMBtu/h of heat input. Combustion controls are
mature technologies that have been demonstrated for multiple years in
various end-use applications, and the EPA proposes to maintain in new
subpart KKKKa that combustion controls are adequately demonstrated for
this subcategory. Both dry and wet combustion controls have been
demonstrated on combustion turbines burning gaseous fuels. However, for
liquid fuels such as distillates, dry combustion controls are less
effective and only wet combustion controls are proposed to be the BSER.
ii. Extent of Reductions in NO<INF>X</INF> Emissions
Manufacturer NO<INF>X</INF> emission rate performance guarantees
for new natural gas-fired stationary combustion turbines with base load
ratings of less than or equal to 250 MMBtu/h of heat input and using
dry combustion controls range from 9 ppm to 25 ppm.\40\ Combustion
turbine designs that would be included in this proposed subcategory
with 9 ppm NO<INF>X</INF> guarantees tend to be less efficient and/or
smaller and the Agency does not consider this level of lean premix/DLN
available for the proposed subcategory as a whole. For example, of the
14 commercially available lean premix/DLN combustion turbines with base
load ratings of less than or equal to 50 MMBtu/h of heat input, 13 have
guaranteed NO<INF>X</INF> emission rates of less than or equal to 25
ppm. Since multiple combustion turbines are available with similar
rated outputs and with equal or greater design efficiencies (as
compared to the single unit with less advanced combustion controls),
the EPA is not proposing to include a separate subcategory in new
subpart KKKKa for stationary combustion turbines with base load ratings
of less than or equal to 50 MMBtu/h of heat input. Instead, these small
designs would have the same BSER of combustion controls and would be
required to meet the same NO<INF>X</INF> standard as larger combustion
turbines with base load ratings of less than or equal to 250 MMBtu/h of
heat input. As discussed previously in section III.B.4.b, the EPA
believes this change from subpart KKKK would have a limited impact on
the regulated community because nearly all new models of these smaller
combustion turbines have guaranteed NO<INF>X</INF> emission rates of 25
ppm or less based on the application of combustion controls. There is a
single combustion turbine model on the market with a base load rated
heat input of less than 50 MMBtu/h with a NO<INF>X</INF> emissions
guarantee of 100 ppm, but the EPA is not aware of

[[Page 101328]]

any recent new installations or reconstructions using this model.\41\
However, reducing the emissions standard for combustion turbines of
less than or equal to 50 MMBtu/h would reduce emissions for future
applications that could have, otherwise, used this 100 ppm combustion
turbine.\42\ Each combustion turbine complying with the proposed NSPS
operating at a 30 percent annual capacity factor would reduce emissions
of annual NO<INF>X</INF> by approximately 7 tons relative to the
subpart KKKK emission standards.
---------------------------------------------------------------------------

\40\ Throughout this document, all references to parts per
million (ppm) are intended to be interpreted as parts per million
volume on a dry basis (ppmvd) at 15 percent O<INF>2</INF>, unless
otherwise noted.
\41\ This turbine model is guaranteed at 100 ppm NO<INF>X</INF>
using dry combustion controls and 42 ppm using wet combustion
controls.
\42\ The existing standard for non-natural gas mechanical drive
applications is 150 ppm NO<INF>X</INF>.
---------------------------------------------------------------------------

Of the 27 available combustion turbines with dry combustion
controls and base load ratings of greater than 50 MMBtu/h of heat input
and less than or equal to 250 MMBtu/h, 25 have manufacturer performance
guarantees of 25 ppm NO<INF>X</INF> or less. Therefore, as discussed
below in section III.B.12, the EPA is proposing a BSER of dry
combustion controls in this subcategory, the application of which can
achieve a 25 ppm NO<INF>X</INF> emissions rate.
Given that dry combustion controls are capable of meeting a 15 ppm
or even a 9 ppm NO<INF>X</INF> emissions rate in certain applications
when firing natural gas, the EPA is soliciting comment on whether small
combustion turbines utilizing wet combustion controls also can achieve
a 15 ppm or lower NO<INF>X</INF> emissions rate when firing gaseous
fuels. Relatedly, the EPA requests comment on whether there are
applications for small natural gas-fired turbines where dry combustion
controls are not available such that the EPA should accommodate the
continued use of wet combustion controls, at least in some
applications. For example, advantages of wet combustion controls can
include increased output relative to dry combustion controls and
reduced efficiency losses at higher ambient temperatures. Disadvantages
can include lower efficiencies and the requirement to use large volumes
of demineralized water. The EPA is soliciting comment on whether these
relative advantages/disadvantages make water injection most applicable
to small, low load turbines. The EPA is soliciting comment on whether
small combustion turbines using steam injection can achieve an
emissions rate of 15 ppm NO<INF>X</INF> when firing natural gas. The
EPA also is soliciting comment on whether steam injection should be a
potential BSER for small stationary combustion turbines operating at
intermediate loads and firing natural gas. For example, combustion
turbine designs are available that use steam injection in combination
with water recovery that reduces the need for demineralized water and
could improve the economics of wet combustion controls for small
stationary combustion turbines that would operate at intermediate
loads.
The EPA is not aware of any advances in combustion controls that
would further reduce NO<INF>X</INF> emissions for small low and
intermediate load combustion turbines firing non-natural gas-fired
fuels. Therefore, the EPA is proposing to maintain that the wet
combustion controls identified in subpart KKKK continue to be the BSER
in new subpart KKKKa.
iii. Costs
The use of combustion controls that can achieve 25 ppm
NO<INF>X</INF> emission rates have been standard for electric and
industrial applications of natural gas-fired stationary combustion
turbines sold nationwide for multiple years, and combustion controls,
consistent with the standards promulgated in subpart KKKK represent
minimal costs to the regulated community.
Therefore, in new subpart KKKKa, the EPA maintains that costs
associated with a 25 ppm standard are clearly reasonable for the
proposed subcategory of natural gas-fired stationary combustion
turbines with a base load rating of less than or equal to 250 MMBtu/h
of heat input.
At this time, the Agency does not have detailed data on the capital
or operating and maintenance (O&M) costs for small natural gas-fired
combustion turbines with dry combustion controls and NO<INF>X</INF>
guaranteed emission rates of 15 ppm or less relative to the costs of
comparable combustion turbines with 25 ppm NO<INF>X</INF> emission rate
guarantees. In this proposal, the EPA is soliciting information on
those capital and O&M costs. To the extent the Agency receives
information that the costs of dry combustion controls for small natural
gas-fired combustion turbines with emission rates of 15 ppm
NO<INF>X</INF> or lower are reasonable--as compared to those with
emission rates of 25 ppm NO<INF>X</INF>--the Agency may finalize
NO<INF>X</INF> emission standards consistent with these more stringent
guaranteed levels in conjunction with a determination that dry
combustion controls alone are the BSER for small turbines or some
subcategory of small turbines. The EPA is also soliciting additional
information on potential impacts of lower NO<INF>X</INF>-emitting
combustors on the operation of small combustion turbines. In
particular, the Agency is seeking information on potential reductions
in efficiency and/or output of dry combustion controls that are capable
of achieving 15 ppm NO<INF>X</INF> or less.
Based on design information in Gas Turbine World 2021, the EPA
projects that the use of a combustion turbine with a base load rated
heat input of less than or equal to 250 MMBtu/h and with NO<INF>X</INF>
guarantees of 15 ppm would reduce the efficiency and output by 2
percent relative to a comparable 25 ppm NO<INF>X</INF> combustion
turbine. As part of this review of the NSPS, the EPA estimated the
incremental costs based on the reduced efficiency of these small
combustion turbines operating as low, intermediate, or base load units.
These costs are determined at annual capacity factors of 5 percent
(i.e., low load), 30 percent (i.e., intermediate load), and 60 percent
(i.e., base load), respectively, and that NO<INF>X</INF> emission rates
were reduced from 25 ppm to 15 ppm. Assuming no additional capital or
operating costs, the costs of a standard of performance of 15 ppm
NO<INF>X</INF> for small combustion turbines would be $19,000/ton
NO<INF>X</INF>, $6,500/ton NO<INF>X</INF>, and $5,300/ton
NO<INF>X</INF> for combustion turbines operating at low, intermediate,
and base load levels of utilization, respectively. The Agency is
soliciting comment regarding the cost associated with achieving a 15
ppm emissions rate for small stationary combustion turbines firing
natural gas, using either dry or wet combustion control technologies.
The EPA is also soliciting comment on the capital and O&M costs of dry
combustion controls compared to wet combustion controls.
The EPA is not aware of any advances in wet combustion controls
that would reduce NO<INF>X</INF> emissions when small combustion
turbines are using non-natural gas fuels.
iv. Non-Air Quality Health and Environmental Impacts and Energy
Requirements
As discussed in the previous section, due to the potential
efficiency loss of a natural gas-fired combustion turbine using dry
combustion controls and a guaranteed 15 ppm NO<INF>X</INF> emissions
rate relative to a combustion turbine guaranteed at 25 ppm
NO<INF>X</INF>, for each ton of NO<INF>X</INF> reduced an additional 70
tons of CO<INF>2</INF> would be emitted. This reduction in efficiency
is in the combustion turbine engine, and in this proposal, the Agency
is soliciting comment on whether this reduction in efficiency and
concomitant increase in CO<INF>2</INF> emissions is less of a concern
for combined cycle and CHP combustion turbines because the lost turbine
engine efficiency could be partially recovered in the HRSG. If

[[Page 101329]]

emission rates of other pollutants are unchanged by the lower
NO<INF>X</INF> combustor, uncontrolled emissions of other criteria and
hazardous air pollutants (HAP) could increase by approximately 2
percent.
Wet combustion controls can reduce NO<INF>X</INF> emissions by 70
to 80 percent but require highly purified water. However, the water
requirements are relatively low compared to other uses of water, and
owners/operators in water-constrained areas have the option of using
dry combustion controls. The water-to-fuel ratio (WFR) for water or
steam injection varies by the type of fuel used and the specific
turbine design. The WFR for the NETL aeroderivative combustion turbine
is 0.3 kg of water injection per kg of natural gas burned.
In general, in new subpart KKKKa, the EPA proposes to find 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 a 25 ppm or a
15 ppm NO<INF>X</INF> emissions rate when firing natural gas.
v. Promotion, Development, and Implementation of Technology \43\
---------------------------------------------------------------------------

\43\ Under longstanding precedent, the EPA has considered this
factor under CAA section 111, but even if this factor were not
considered, it would not affect our proposed determinations of the
BSER in this action.
---------------------------------------------------------------------------

While dry and wet combustion controls are a mature technology for
new and reconstructed stationary combustion turbines, maintaining their
use on small combustion turbines with a heat input rating of less than
or equal to 250 MMBtu/h will ensure that developers continue to advance
the technology for these units.
b. Selective Catalytic Reduction
SCR has been installed and is operating on a number of small
stationary combustion turbines, and the technology appears to be
readily available for further deployment for highly utilized new and
reconstructed combustion turbines with base load rated heat inputs of
less than or equal to 250 MMBtu/h. For small natural gas-fired
stationary combustion turbines operating in the base load subcategory
(i.e., above 40 percent capacity factor on a 12-calendar-month basis),
the EPA proposes to include SCR in the determination of the BSER, and
proposes an associated emissions standard of 3 ppm NO<INF>X</INF>,
assuming the SCR is operated in conjunction with combustion controls.
For small non-natural gas-fired combustion turbines utilized as base
load units, the EPA also proposes to include SCR in the determination
of the BSER, and proposes an associated emissions standard of 9 ppm
NO<INF>X</INF>, again, assuming the SCR is operated in conjunction with
combustion controls.
i. Adequately Demonstrated
The EPA is aware of SCR post-combustion control technology being
applied to combustion turbines as small as 5 MW and to large combined
cycle combustion turbine facilities that are hundreds of megawatts. In
addition, SCR has been installed on small reciprocating engines.
Therefore, the EPA is proposing that the use of SCR for NO<INF>X</INF>
control has been adequately demonstrated for all combustion turbines
that would be subject to new subpart KKKKa, including new and
reconstructed stationary combustion turbines with base load ratings of
less than or equal to 250 MMBtu/h of heat input and operating at
greater than 40 percent capacity factors.
ii. Extent of Reductions in NO<INF>X</INF> Emissions
The percent reduction in NO<INF>X</INF> emissions from SCR depends
on the level of control initially achieved through combustion controls
but is generally greater than 70 percent and can approach 90 percent in
certain cases. SCR has been demonstrated to reduce NO<INF>X</INF>
emission from combustion turbines to approximately 3 ppm. Compared to
the NO<INF>X</INF> standards for these smaller combustion turbines in
subpart KKKK (i.e., as low as 25 ppm), this represents approximately a
90 percent reduction in the emissions standard. However, if combustion
controls alone could achieve a 15 ppm NO<INF>X</INF> emissions rate,
the additional reductions that could be achieved from SCR would be
proportionately smaller.
iii. Costs
As discussed in section III.B.7.b, the EPA generally finds that SCR
has reasonable costs for stationary combustion turbines of all sizes.
For the proposed subcategory of small combustion turbines, the EPA
estimated the incremental costs of SCR on a per-ton basis using the
current NSPS emissions standard (25 ppm NO<INF>X</INF>) in subpart KKKK
applicable to natural gas-fired units with base load ratings greater
than 50 MMBtu/h of heat input and less than or equal to 850 MMBtu/h and
assuming the NO<INF>X</INF> is reduced to 3 ppm. In generating specific
capital and per-ton cost estimates, the small model plant used by the
EPA was a 150 MMBtu/h combustion turbine. For the low and intermediate
load cost estimates, the EPA assumed the combustion turbine was
operating as a simple cycle turbine and would use hot SCR. For the
model base load combustion turbine, the EPA assumed the combustion
turbine had a HRSG and would use conventional SCR. The estimated
capital cost of the hot SCR is $3 million, and the estimated capital
cost of conventional SCR is $2 million. The estimated cost
effectiveness is $170,000/ton NO<INF>X</INF>, $31,000/ton
NO<INF>X</INF>, and $12,000/ton NO<INF>X</INF> for the low,
intermediate, and base load small combustion turbines, respectively.
The EPA also evaluated the incremental control costs of SCR from a
baseline of combustion controls achieving an emissions rate of 15 ppm
NO<INF>X</INF>. Under this baseline, the estimated cost effectiveness
of SCR for small turbines is $317,000/ton NO<INF>X</INF>, $56,000/ton
NO<INF>X</INF>, and $21,000/ton NO<INF>X</INF>, respectively.
The EPA proposes that SCR is cost reasonable for natural gas- and
non-natural gas-fired stationary combustion turbines with base load
ratings of less than or equal to 250 MMBtu/h of heat input and
operating as base load units (i.e., at 12-calendar-month capacity
factors of greater than 40 percent). However, the EPA recognizes that
if it were to conclude that a 15 ppm emissions rate were achievable for
natural gas-fired combustion turbines using only combustion controls,
then the higher per-ton incremental costs of SCR compared to that
baseline may no longer be viewed as cost justified. The EPA also
recognizes that per-ton cost estimates would likely be proportionately
higher as the size of combustion turbines diminishes from the 150
MMBtu/h model plant used in this analysis. The EPA requests comment on
the cost factor for SCR on small turbines, including in relation to the
following topics: whether, reviewing all of the relevant cost
considerations (as discussed in section III.B.7.b), SCR is cost
reasonable even at lower operating loads than base load; whether SCR
would no longer be incrementally cost reasonable against a 15 ppm
baseline emissions rate; whether SCR may not be cost reasonable for
turbines smaller than 150 MMBtu/h, such as when cost factors, including
capital and operating costs, are analyzed for turbines smaller than 100
or 50 MMBtu/h.
iv. Non-Air Quality Health and Environmental Impacts and Energy
Requirements
Post-combustion SCR uses ammonia as a reagent, and some ammonia is
emitted either by passing through the catalyst bed without reacting
with NO<INF>X</INF> (unreacted ammonia) or passing around

[[Page 101330]]

the catalyst bed through leaks in the seals. Both of these types of
excess ammonia emissions are referred to as ammonia slip. Ammonia is a
precursor to the formation of fine particulate matter (i.e.,
PM<INF>2.5</INF>). Ammonia slip increases as catalyst beds age and is
often limited to 10 ppm or less in operating permits. Ammonia catalysts
are available to reduce emissions of ammonia. The ammonia catalyst
consists of an additional catalyst bed after the SCR catalyst that
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, 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. Since the ammonia slip is assumed to be 3.5 ppm
regardless of the NO<INF>X</INF> emissions rate prior to the SCR, the
amount of ammonia emitted per ton of NO<INF>X</INF> controlled
increases with combustion controls that achieve lower emission rates
prior to the SCR. Assuming the emissions rate is decreased from the
manufacturer guaranteed emission rates to an emissions rate of 3 ppm
NO<INF>X</INF>, the EPA estimates that for each ton of NO<INF>X</INF>
controlled, 0.06 tons, 0.1 tons, and 0.2 tons of ammonia are emitted
from SCR controls on combustion turbines with guaranteed NO<INF>X</INF>
emission rates of 25 ppm, 15 ppm, and 9 ppm, respectively. For
combustion turbines with base load ratings of less than or equal to 250
MMBtu/h of heat input, the EPA used a 25 ppm NO<INF>X</INF> baseline
and 0.06 tons of ammonia per ton of NO<INF>X</INF> reduced.
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. The EPA used the NETL
values to approximate auxiliary load requirements and assumed the
backpressure reduced gross output by 0.3 percent. Similar to ammonia,
the CO<INF>2</INF> per ton of NO<INF>X</INF> reduced depends on the
amount of NO<INF>X</INF> entering the SCR. The EPA estimates that for
each ton of NO<INF>X</INF> controlled, 5 tons, 8 tons, and 16 tons of
CO<INF>2</INF> are emitted as a result of the SCR on combustion
turbines with guaranteed NO<INF>X</INF> emission rates of 25 ppm, 15
ppm, and 9 ppm, respectively. For stationary combustion turbines with
base load ratings of less than or equal to 250 MMBtu/h of heat input,
the EPA used a 25 ppm NO<INF>X</INF> baseline and 5 tons of
CO<INF>2</INF> per ton of NO<INF>X</INF> reduced.
The EPA is proposing in new subpart KKKKa that the non-air quality
health and environmental impacts and energy requirements of SCR are
acceptable for stationary combustion turbines with base load ratings of
less than or equal to 250 MMBtu/h of heat input. SCR technologies have
improved in recent years to reduce these impacts, and the widespread
deployment of SCR on combustion turbines of all sizes, at least in the
power sector the last 5 years, indicates that States and permitting
authorities have found these impacts sufficiently manageable that SCR
has been mandated for NO<INF>X</INF> reductions in spite of these
modest effects on other pollutants and associated energy requirements.
v. Promotion, Development, and Implementation of Technology
Installations of SCR help reduce capital and operating costs
through learning by doing. As SCR becomes more affordable, it can be
installed on additional combustion turbines. SCR is applicable to
multiple industries, and advancement for combustion turbines can be
transferred to these industries.
10. BSER for Medium Combustion Turbines
This section describes the proposed BSER for new and reconstructed
medium combustion turbines with base load ratings of greater than 250
MMBtu/h of heat input and less than or equal to 850 MMBtu/h. For
combustion turbines in this medium subcategory, the proposed BSER is
the use of combustion controls with the addition of post-combustion SCR
for intermediate and base load combustion turbines (i.e., those with
annual capacity factors greater than 20 percent) and dry or wet
combustion controls for low load combustion turbines (i.e., those with
annual capacity factors less than or equal to 20 percent) depending on
whether natural gas or non-natural gas fuels are being fired.
a. Combustion Controls
This section describes the current availability and performance of
dry and wet combustion controls used by owners/operators of medium
stationary gas and combustion turbines to limit NO<INF>X</INF>
emissions. In 2006, these combustion controls were maintained as the
BSER in existing subpart KKKK, and this technology continues to be used
on new and reconstructed stationary combustion turbines, including
those with base load ratings of greater than 250 MMBtu/h of heat input
and less than or equal to 850 MMBtu/h.
i. Adequately Demonstrated
Dry and/or wet combustion controls are widely available from major
manufacturers for combustion turbines with base load ratings of greater
than 250 MMBtu/h of heat input and less than or equal to 850 MMBtu/h.
Combustion controls are mature technologies that have been demonstrated
for multiple years in various end-use applications, and the EPA
proposes to maintain in new subpart KKKKa that combustion controls are
adequately demonstrated for this subcategory. Both dry and wet
combustion controls have been demonstrated on combustion turbines
burning gaseous fuels. However, for liquid fuels such as distillates,
dry combustion controls are less effective and only wet combustion
controls are proposed to be the BSER.
ii. Extent of Reductions in NO<INF>X</INF> Emissions
Manufacturer NO<INF>X</INF> emission rate performance guarantees
for medium natural gas-fired stationary combustion turbines using dry
combustion controls range from 15 ppm to 25 ppm. For example, most
high-efficiency aeroderivative combustion turbines have NO<INF>X</INF>
emission rate performance guarantees of 25 ppm while for most natural
gas-fired frame units using dry combustion controls, the guaranteed
NO<INF>X</INF> emissions rate is 15 ppm. However, there is some
variability among frame units and certain designs have guaranteed
emissions rates of 25 ppm. Dry combustion controls on some medium
natural gas-fired combustion turbines appear to be capable of meeting
emissions rates as low as 9 ppm in certain applications. Like the
subcategory for small combustion turbines, the EPA is soliciting
comment in this proposal on whether wet combustion controls,
particul

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