[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 [www.gpo.gov]
[FR Doc No: 2024-27872]
[[Page 101305]]
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 (NOX) 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 NOX 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 NOX 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 (SO2)
emissions, because after reviewing the current SO2
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:
Federal eRulemaking Portal: https://www.regulations.gov
(our preferred method). Follow the online instructions for submitting
comments.
Email: [email protected]. Include Docket ID No. EPA-
HQ-OAR-2024-0419 in the subject line of the message.
Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2024-0419.
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.
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 https://www.regulations.gov, 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: [email protected].
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 [email protected]. 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
https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance. 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 https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance or
contact the public hearing team at (888) 372-8699 or by email at
[email protected]. 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:
https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance.
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 https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance.
[[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 [email protected] 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 Regulations.gov 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 Regulations.gov.
Written Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2024-0419, at https://www.regulations.gov (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 https://www.regulations.gov 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 https://www.epa.gov/dockets/commenting-epa-dockets for additional submission methods; the full EPA
public comment policy; information about CBI or multimedia submissions;
and general guidance on making effective comments.
The https://www.regulations.gov 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
https://www.regulations.gov, your email address will be automatically
captured and included as part of the comment that is placed in the
public docket and made available on the internet. If you submit an
electronic comment, the EPA recommends that you include your name and
other contact information in the body of your comment and with any
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 https://www.regulations.gov. 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 [email protected], 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 [email protected] 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 NOX
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
NOX nitrogen oxide
NSPS new source performance standards
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act
O2 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
PM2.5 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
SO2 sulfur dioxide
SSM startup, shutdown, and malfunction
ULSD ultra-low sulfur diesel
UMRA Unfunded Mandates Reform Act
U.S.C. United States Code
VCS voluntary consensus standard
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. NOX Emission Standards
C. SO2 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 https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance. Following publication in the Federal
Register, the EPA will post the Federal Register version of the
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 https://www.regulations.gov.
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 https://www.epa.gov/stationary-sources-air-pollution/stationary-gas-and-combustion-turbines-new-source-performance.
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.
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\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.
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C. What are the current NSPS requirements?
The NSPS for stationary combustion turbines includes standards of
performance to limit emissions of nitrogen oxide (NOX) and
sulfur dioxide (SO2). 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 NOX 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
(O2).\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 NOX 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) NOX are intended to be interpreted as parts
per million by volume dry (ppmvd) at 15 percent O2,
unless otherwise noted.
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Specifically, in subpart KKKK, the EPA identifies 14 subcategories
of stationary combustion turbines and establishes NOX
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 NOX performance
standard is identified for each of the 14 subcategories, and the limits
range from 15 ppm to 150 ppm (see Table 1: NOX Emission
Standards; 71 FR 38483, July 6, 2006).
The standards of performance for SO2 emissions in
subpart KKKK reflect the use of low-sulfur fuels. The fuel sulfur
content limit is 26 ng SO2/J (0.060 lb SO2/MMBtu)
heat input for combustion turbines located in continental areas and 180
ng SO2/J (0.42 lb SO2/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 SO2 standard that limits
the discharge into the atmosphere of any gases that contain
SO2 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 https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
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D. What data and information were used to support this action?
The Agency analyzed hourly NOX 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:
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\
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\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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Combustion turbine manufacturer specifications sheets for
NOX and other criteria pollutant emissions for common
combustion turbine makes and models.\5\
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\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.
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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 NOX emissions as well as the cost effectiveness of
post-combustion SCR for certain sizes and models of turbines.
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 https://cfpub.epa.gov/rblc/.
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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.
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\7\ U.S. Energy Information Administration (EIA). (June 12,
2024). Form EIA-860 data. Available at https://www.eia.gov/electricity/data/eia860/.
\8\ See the U.S. Environmental Protection Agency's (EPA)
National Electric Energy Data System database. NEEDS rev 06-06-2024.
Accessed at https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
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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.
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\9\ See EPA-HQ-OAR-2024-0135, available at https://www.regulations.gov.
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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 NOX.
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.
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\10\ See 89 FR 39798; May 9, 2024.
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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 NOX 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 NOX 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 NOX 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
NOX 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 NOX standards for stationary combustion turbines
that plan to co-fire hydrogen.
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\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.
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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
NOX 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.
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\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.
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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:
Expected growth for the source category, including how
many new facilities, reconstructions, and modifications may trigger
NSPS in the future.
Pollution control measures, including advances in control
technologies, process operations, design or efficiency improvements, or
other systems of emission reduction, that are ``adequately
demonstrated'' in the regulated industry.
Available information from the implementation and
enforcement of current requirements indicating that emission
limitations and percent reductions beyond those required by the current
standards are achieved in practice.
Costs (including capital and annual costs) associated with
implementation of the available pollution control measures.
The amount of emission reductions achievable through
application of such pollution control measures.
Any non-air quality health and environmental impact and
energy requirements associated with those control measures.
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.
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\14\ The EPA uses the higher heating value (HHV) when specifying
heat input ratings.
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Proposed subpart KKKKa maintains the NOX 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 NOX 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 SO2 performance standards in subparts GG,
KKKK, or those proposed in new subpart KKKKa. The SO2
standards in subparts J and Ja are more stringent than the
SO2 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 SO2 and/or NOX
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
NOX natural gas-fired duct burners typically contribute 15
ppm to 25 ppm NOX corrected to 15 percent O2, and
ultra-low NOX duct burners are available that contribute
approximately 3 ppm NOX corrected to 15 percent
O2. 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 NOX 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 NOX control
technologies. The proposed BSER for control of NOX 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 NOX performance standards proposed
in section III.B.12. The EPA's determination of the subcategories,
BSER, and NOX 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
NOX emission control technologies it evaluated as part of
its review of the NSPS. These include dry combustion controls (e.g.,
lean premix/dry low NOX (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
NOX: 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
NOX 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 NOX 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
NOX emission standards for modified sources. The EPA is
proposing in new subpart KKKKa that the BSER and NOX
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
NOX 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 NOX 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. NOX Formation
Nitrogen oxides (NOX) 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 (NO2) 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, NOX also reacts with
water, oxygen, and other chemicals in the air to form particulate
matter (PM) and contributes to acid deposition. NOX is also
a criteria pollutant for which there are National Ambient Air Quality
Standards (NAAQS). The NAAQS for NOX 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 NOX are primarily
respiratory effects, including irritation of the eyes, nose, throat,
and lungs. Exposure to low levels of NOX can lead to fluid
build-up in the lungs. Inhalation of high levels of NOX 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 NO2 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 NO2.\19\
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\17\ U.S. Environmental Protection Agency (EPA). Nitrogen
Dioxide (NO2) Pollution. Available at https://www.epa.gov/no2-pollution/primary-national-ambient-air-quality-standards-naaqs-nitrogen-dioxide.
\18\ Agency for Toxic Substances and Disease Registry (ATSDR).
(March 25, 2014). ToxFAQs for Nitrogen Oxides. Toxic Substances
Portal fact sheet. Available at https://wwwn.cdc.gov/TSP/ToxFAQs/ToxFAQsDetails.aspx?faqid=396&toxid=69.
\19\ U.S. Environmental Protection Agency (EPA). Nitrogen
Dioxide (NO2) Pollution. Available at https://www.epa.gov/no2-pollution/basic-information-about-no2#Effects.
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In addition, environmental effects of NOX 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 NOX emissions are a function of thermal and
organic (i.e., fuel) NOX. Thermal NOX is formed
in a well-defined, high-temperature reaction between nitrogen and
oxygen from the combustion air. Meanwhile, organic NOX is
formed from fuel-bound nitrogen that reacts with oxygen in the
combustion chamber. Thermal NOX accounts for the majority of
NOX 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 NOX emissions,
while SCR technology catalytically promotes the conversion of
NOX to nitrogen gas (N2) 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 NOX formed in the
combustion process.
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3. Subcategorization Approach and NOX Emission Standards in
40 CFR Part 60, Subpart KKKK
In subpart KKKK, the EPA lists 14 subcategories of stationary
combustion turbines and identifies NOX standards for
affected sources in each subcategory based on the application of dry or
wet NOX 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 NOX 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 NOX
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:
NOX Emission Standards (71 FR 38483; July 6, 2006). The
NOX 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.
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\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.
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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.
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\22\ If any of these conditions are applicable, the combustion
turbine would be in this subcategory.
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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 NOX 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 NOX 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
NOX 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 NOX
emissions from these smaller turbine designs. The results of this
technology review demonstrate that multiple manufacturers have
developed dry combustion controls that can achieve NOX
emission rates comparable to the NOX 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 NOX 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 NOX
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
NOX 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 NOX 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 NOX
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 NOX 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 NOX 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.
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\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).
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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 NOX
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 NOX 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 NOX 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
NOX 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 NOX 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
NOX 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 NOX 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 NOX 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 NOX
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 NOX 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 NOX combustion controls--were not as
effective at reducing NOX from a technical standpoint.\25\
At part-load operation and low ambient temperatures, it is more
challenging to maintain stable combustion using dry low NOX
(DLN) and adjustments to the combustion system are required--resulting
in higher NOX emission rates. Therefore, in subpart KKKK,
the Agency identified diffusion flame combustion as the BSER for hours
of part-load operation or low ambient temperatures.\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
NOX 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 NOX
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 NOX 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 NOX standards of
performance in subpart KKKK is based on parts per million (ppm)
corrected to 15 percent O2 and the form of alternate output-
based NOX standards is determined on a pounds per megawatt
hour-gross (lb/MWh-gross) basis. 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
NOX 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 NOX
emissions rate on a ppm basis when corrected to 15 percent
O2 while absolute NOX emissions may not
significantly change. Since actual emissions to the atmosphere are the
measure of environmental impacts, the NOX 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 NOX
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 NOX 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 NOX emission standards in
existing subpart KKKK are based on a 4-hour rolling average for simple
cycle turbines and a 30-operating-day average for combustion turbines
with a HRSG (e.g., combined cycle and CHP combustion turbines). 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 NOX/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 NOX
emissions rate on a lb NOX/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 NOX 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
NOX in subpart KKKKa.
Under the existing NSPS in subpart KKKK, newly constructed
stationary combustion turbines are subject to more stringent
NOX 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 NOX 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 NOX 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 NOX
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 NOX controls use combustors
that are diffusion controlled where fuel and air are injected
separately. The resultant diffusion flame combustion can lead to the
creation of hot spots that produce high levels of thermal
NOX. In contrast, combustion controls consist of operational
or design modifications that govern combustion conditions to reduce
NOX formation. Combustion controls are widely available for
new combustion turbines and are generally low cost and provide
substantial reductions in NOX emissions relative to
combustion turbines without combustion controls. In subpart KKKK, the
EPA identified combustion controls as the BSER for limiting
NOX 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
NOX 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 NOX 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 NOX formation. Wet control
systems are designed to a specific water-to-fuel ratio that has a
direct impact on the controlled NOX emission rate and is
generally controlled by the combustion turbine inlet temperature and
ambient temperature. Wet control systems have demonstrated the ability
to limit NOX emissions to as low as 25 ppm for stationary
combustion turbines firing natural gas and between 42 ppm 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 NOX control. Thus, water
injected into the combustor flame area lowers the temperature and,
consequently, reduces NOX 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 NOX control technologies make it
an attractive option for peaking combustion turbines or other sources
that operate infrequently.
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\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
NOX 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.
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\31\ Innovative Steam Technologies. GTI. Accessed at https://otsg.com/industries/powergen/gti/.
\32\ Bahrami, S., et al (2015). Performance Comparison between
Steam Injected Gas Turbine and Combined Cycle during Frequency
Drops. Energies 2015, Volume 8. https://doi.org/10.3390/en8087582.
\33\ Mitsubishi Power. Smart-AHAT (Advanced Humid Air Turbine.
Accessed at https://power.mhi.com/products/gasturbines/technology/smart-ahat.
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Dry low NOX (DLN) combustion control systems were
commercially introduced more than 30 years ago. The basis of dry
NOX 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 NOX.
Lean combustion may be combined with staged combustion to achieve
additional NOX reductions. Staged combustion is designed to
reduce the residence time of the combustion air in the presence of the
flame at peak temperature. The longer the residence time, the greater
the potential for thermal NOX formation. When increasing the
air/fuel ratio, excess air is added to the mixture, 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 NOX
emission concentrations to 25 ppm, while advanced ultra-low DLN
technology can further reduce NOX 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 NOX. 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 NOX 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 NOX 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 NOX control that has been installed
on combustion turbines (both simple and combined cycle), utility
boilers, industrial boilers, process heaters, and reciprocating
internal combustion engines. Many stationary combustion turbines in the
power sector currently utilize the NOX 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 NOX
emission rates of 25 ppm and potentially higher annual capacity
factors. The larger units tend to be frame-type combustion turbines
with NOX 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 NOX control or combined with other
technologies, including the wet and dry combustion controls discussed
previously.
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\34\ See the U.S. Environmental Protection Agency's (EPA) Clean
Air Markets Program Data at https://campd.epa.gov/data.
\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.
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The SCR process is based on the chemical reduction of the
NOX molecule via a nitrogen-based reducing agent
[[Page 101325]]
(reagent) and a solid catalyst. To remove NOX, the reagent,
commonly ammonia (NH3, anhydrous and aqueous) or urea-
derived ammonia, is injected into the post-combustion flue gas of the
combustion turbine. The reagent reacts selectively with the flue gas
NOX within a specific temperature range and in the presence
of the catalyst and oxygen to reduce the NOX into molecular
nitrogen (N2) and water vapor (H2O). SCR employs
a ceramic honeycomb or metal-based surface with activated catalytic
sites to increase the rate of the reduction reaction. Over time,
however, the catalyst activity decreases, requiring replacement,
washing/cleaning, rejuvenation, or regeneration to extend the life of
the catalyst. Catalyst designs and formulations are generally
proprietary. The primary components of the SCR include the ammonia
storage and delivery system, ammonia injection grid, and the catalyst
reactor.
The 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 NOX
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 NOX
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 NOX limit of 15 ppm have installed
SCR. This correlation between high-efficiency combustion turbines and
increased NOX 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 NOX 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 NOX 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 NOX emissions
concentration. Too much ammonia injection can result in excess ammonia
emissions (i.e., ammonia slip) and too little can result in higher
NOX emissions. The EPA is soliciting comment on if it can be
challenging to adjust ammonia injection rates during rapid load changes
to maintain NOX emissions rates while at the same time
minimizing ammonia slip, particularly for combustion turbines not
selling electricity to the electric grid.
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\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 NOX 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 NOX emission
concentrations as low as 9 ppm while SCR could achieve NOX
emission concentrations of 2 to 4 ppm. Furthermore, for SCR to
effectively remove NOX 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 NOX, 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.
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\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 NOX emissions. Although
determinations concerning cost reasonableness in one statutory or
programmatic context may not necessarily translate to another, these
regulatory precedents offer points of comparison with respect to the
same pollutant that can be informative in evaluating the most cost-
effective opportunities for abatement of a common pollutant across
multiple program arenas. As described in more detail in the
subcategory-specific sections below, the EPA has identified a cost of
$12,000 per ton of NOX abated as the cost effectiveness
range for small units operating at base load; a range of $12,000 to
$5,100 per ton of NOX 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 NOX 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 NOX 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
NOX 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 NOX
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 NOX 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 NOX, respectively.
Similarly, combustion turbines with SCR and complying with a short-term
emissions standard of 3 ppm NOX have long-term emission
rates of 2 ppm NOX. 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 NOX 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 https://www.osti.gov/biblio/1973266.
---------------------------------------------------------------------------
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 NOX emissions at part-load operations and low
ambient temperatures. In addition, SCR is only effective at reducing
NOX under certain temperatures at part loads and is not as
effective at reducing NOX as at design conditions. The only
technology the EPA has identified for all part-load 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\
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\39\ A BSER of diffusion flame combustion includes DLN that is
less effective at reducing NOX 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 NOX
(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 NOX
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 NOX Emissions
Manufacturer NOX 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 NOX 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 NOX 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 NOX 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 NOX 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 NOX 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 NOX by approximately 7 tons relative to the
subpart KKKK emission standards.
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\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 O2, unless
otherwise noted.
\41\ This turbine model is guaranteed at 100 ppm NOX
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 NOX.
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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 NOX 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 NOX emissions rate.
Given that dry combustion controls are capable of meeting a 15 ppm
or even a 9 ppm NOX 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 NOX 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 NOX 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 NOX 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
NOX 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 NOX
guaranteed emission rates of 15 ppm or less relative to the costs of
comparable combustion turbines with 25 ppm NOX 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
NOX or lower are reasonable--as compared to those with
emission rates of 25 ppm NOX--the Agency may finalize
NOX 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 NOX-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 NOX 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 NOX
guarantees of 15 ppm would reduce the efficiency and output by 2
percent relative to a comparable 25 ppm NOX 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 NOX 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
NOX for small combustion turbines would be $19,000/ton
NOX, $6,500/ton NOX, and $5,300/ton
NOX 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 NOX 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 NOX emissions
rate relative to a combustion turbine guaranteed at 25 ppm
NOX, for each ton of NOX reduced an additional 70
tons of CO2 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 CO2 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
NOX combustor, uncontrolled emissions of other criteria and
hazardous air pollutants (HAP) could increase by approximately 2
percent.
Wet combustion controls can reduce NOX 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 NOX 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 NOX,
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
NOX, 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 NOX
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 NOX Emissions
The percent reduction in NOX 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 NOX
emission from combustion turbines to approximately 3 ppm. Compared to
the NOX 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 NOX 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 NOX) 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 NOX 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 NOX, $31,000/ton
NOX, and $12,000/ton NOX 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
NOX. Under this baseline, the estimated cost effectiveness
of SCR for small turbines is $317,000/ton NOX, $56,000/ton
NOX, and $21,000/ton NOX, 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 NOX (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.,
PM2.5). 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 NOX emissions rate prior to the SCR, the
amount of ammonia emitted per ton of NOX 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
NOX, the EPA estimates that for each ton of NOX
controlled, 0.06 tons, 0.1 tons, and 0.2 tons of ammonia are emitted
from SCR controls on combustion turbines with guaranteed NOX
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 NOX baseline
and 0.06 tons of ammonia per ton of NOX 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 CO2 per ton of NOX reduced depends on the
amount of NOX entering the SCR. The EPA estimates that for
each ton of NOX controlled, 5 tons, 8 tons, and 16 tons of
CO2 are emitted as a result of the SCR on combustion
turbines with guaranteed NOX 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 NOX baseline and 5 tons of
CO2 per ton of NOX 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 NOX 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 NOX
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 NOX Emissions
Manufacturer NOX 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 NOX
emission rate performance guarantees of 25 ppm while for most natural
gas-fired frame units using dry combustion controls, the guaranteed
NOX 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,
particularly steam injection, can achieve a 15 ppm or lower
NOX emission rate when gaseous fuels are used; if not, then
the EPA also requests comment on whether wet combustion controls should
continue to be considered a BSER technology on which emissions
standards are based, at least for medium combustion turbines using
natural gas.
The EPA is not aware of any advances in wet combustion controls
that would reduce NOX emissions when medium combustion
turbines are using non-natural gas fuels.
iii. Costs
The use of dry combustion controls that can achieve 25 ppm
NOX has been standard equipment for natural gas-fired
[[Page 101331]]
stationary combustion turbines sold nationwide for multiple years, and
combustion controls consistent with the existing standards in subpart
KKKK represent little costs to the regulated community. Like the
subcategory for small combustion turbines, at this time, the Agency
does not have capital or O&M cost information for medium combustion
turbines with NOX emission rate guarantees of 15 ppm
relative to the costs of comparable combustion turbines with 25 ppm
NOX guarantees. Therefore, in this proposal, the EPA
solicits comment and information on such capital and O&M costs. To the
extent the Agency receives information that the costs of dry combustion
controls with NOX emission rates of 15 ppm are reasonable,
the Agency may finalize NOX emission standards for natural
gas-fired medium combustion turbines operating at low loads (i.e., at
12-calendar-month capacity factors of less than or equal to 20 percent)
consistent with these guaranteed performance levels. As discussed
further in this section, for medium stationary combustion turbines
operating at intermediate and base loads (i.e., at 12-calendar-month
capacity factors of greater than 20 percent), this question would not
be relevant for the rule as proposed, since those units would also be
subject to an emissions standard based on application of SCR. The EPA
also is soliciting additional information on potential impacts of low
NOX combustors on the operation of medium combustion
turbines. In particular, the Agency is seeking information on potential
reductions in efficiency and/or output of medium combustion turbines
using combustion controls that are capable of achieving 15 ppm
NOX or less.
Based on analysis like that performed for small combustion
turbines, the EPA projects that the use of a stationary combustion
turbine with NOX guarantees of 15 ppm would reduce the
efficiency and output relative to a comparable 25 ppm NOX
combustion turbine by 2 percent.
The EPA estimates the incremental costs based on the reduced
efficiency of low, intermediate, and base load medium combustion
turbines. These costs are determined at annual capacity factors of 5
percent, 30 percent, and 60 percent, respectively, and using a 486
MMBtu/h model plant. Assuming no additional capital or operating costs,
the costs of a NOX standard of 15 ppm for medium combustion
turbines would be $19,000/ton NOX, $6,500/ton
NOX, and $5,300/ton NOX, respectively, for low,
intermediate, and base load combustion turbines.
The EPA is also soliciting comment on the capital and O&M costs of
dry combustion controls compared to wet combustion controls.
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 NOX emissions
rate relative to a combustion turbine guaranteed at 25 ppm
NOX, for each ton of NOX reduced an additional 70
tons of CO2 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 CO2 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 emission
rates of other pollutants are unchanged by the lower NOX
combustor, uncontrolled emissions of other criteria and hazardous air
pollutants (HAP) could increase by approximately 2 percent.
Wet combustion controls can reduce NOX emissions by 70
to 80 percent but require highly purified water.\44\ 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.
---------------------------------------------------------------------------
\44\ U.S. Environmental Protection Agency (EPA). (April 2002).
Appendix B.17: Water or Steam Injection Review Draft. Available at
https://www3.epa.gov/ttnchie1/mkb/documents/B_17a.pdf.
---------------------------------------------------------------------------
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 NOX emissions rate when firing natural gas.
v. Promotion, Development, and Implementation of Technology
While combustion controls are a mature technology for new
combustion turbines, requiring their use on medium combustion turbines
will ensure that developers continue to advance the technology for
these units.
b. Selective Catalytic Reduction
The EPA is proposing that SCR in combination with combustion
controls is the BSER for new and reconstructed stationary combustion
turbines with base load ratings of greater than 250 MMBtu/h of heat
input and less than or equal to 850 MMBtu/h and that will be utilized
as intermediate or base load units with 12-calendar-month capacity
factors of greater than 20 percent.
As discussed in the previous section for small base load combustion
turbines, SCR has been installed and is currently operating on many
sizes and designs of stationary combustion turbines, and the technology
appears to be readily available for further deployment for medium
combustion turbines operating at intermediate and base load capacity
factors. Based on the application of combustion controls with SCR, in
new subpart KKKKa, the EPA is proposing an associated emissions
standard of 3 ppm NOX for natural gas-fired units. For
medium non-natural gas-fired combustion turbines utilized as
intermediate or base load units, the EPA also proposes to include SCR
with combustion controls in the determination of the BSER, and proposes
an associated emissions standard of 9 ppm NOX, 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 reciprocating engines. Therefore,
the EPA is proposing that the use of SCR for NOX 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 greater than
250 MMBtu/h of heat input and less than or equal to 850 MMBtu/h and
operating at greater than a 20 percent capacity factor.
ii. Extent of Reductions in NOX Emissions
The percent reduction in NOX emissions from SCR depends
on the level of control achieved through combustion controls but is
generally greater than 70 percent and can approach 90 percent in
certain cases. In conjunction with dry combustion controls on medium
natural gas-fired combustion turbines, SCR has been demonstrated to
reduce NOX emissions to approximately 3 ppm compared to 25
ppm with just dry combustion controls. This represents almost a 90
percent
[[Page 101332]]
reduction in NOX emissions. The current NOX
standard in subpart KKKK for combustion turbines of this size firing
non-natural gas fuels is 74 ppm. This standard is based on the
application of wet combustion controls alone. In new subpart KKKKa,
based upon application of SCR in combination with combustion controls,
the EPA is proposing a NOX emission standard of 9 ppm for
medium combustion turbines utilized as intermediate or base load units
and firing non-natural gas fuels. This proposed standard represents
approximately a 90 percent reduction compared to the current standard
of 74 ppm.
iii. Costs
The EPA estimated the incremental costs of SCR on a per-ton basis
using the current NSPS emissions standard for this subcategory (a
baseline of 25 ppm NOX) and assuming emissions are reduced
to 3 ppm NOX. The medium model plant used by the EPA was a
486 MMBtu/h stationary 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 cost estimates, the EPA assumed the combustion turbine
had a HRSG and would use conventional SCR. The estimated capital cost
of the hot SCR is $3.6 million, and the estimated capital cost of
conventional SCR is $2.4 million. The estimated cost effectiveness is
$62,000/ton NOX, $12,000/ton NOX, and $5,100/ton
NOX for low, intermediate, and base load medium combustion
turbines, respectively, compared to the baseline emissions rate of 25
ppm in current subpart KKKK. The EPA also evaluated the incremental
control costs as compared to combustion controls achieving an emissions
rate of 15 ppm NOX. Under this alternative baseline, the
estimated cost effectiveness is $110,000/ton NOX, $22,000/
ton NOX, and $8,700/ton NOX for low,
intermediate, and base load medium combustion turbines, respectively.
The EPA proposes that the costs of SCR are reasonable for new and
reconstructed medium size intermediate load or base load combustion
turbines firing natural gas or non-natural gas fuels. The EPA
recognizes that if it were to conclude that a 15 ppm emissions rate
were achievable for these medium turbines using only combustion
controls, then the per-ton incremental cost of SCR against that
baseline would increase to $22,000/ton. Nonetheless, in reviewing all
of the relevant cost considerations (as discussed in section
III.B.7.b), the EPA does not find this result so high as to render SCR
as applied in this instance no longer capable of being considered the
BSER. The EPA requests comment on the cost factor for SCR on medium-
sized stationary combustion turbines.
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 NOX (unreacted ammonia) or passing around 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., PM2.5).
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 NOX emissions rate prior to the SCR, the amount of
ammonia emitted per ton of NOX 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 NOX,
the EPA estimates that for each ton of NOX controlled, 0.06
tons of ammonia are emitted from SCR controls on combustion turbines
with base load ratings of greater than 250 MMBtu/h of heat input and
less than or equal to 850 MMBtu/h and with guaranteed NOX
emission rates of 25 ppm.
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 CO2 per ton of NOX reduced depends on the
amount of NOX entering the SCR. The EPA estimates that for
each ton of NOX controlled, 5 tons of CO2 are
emitted as a result of the SCR on combustion turbines with base load
ratings of greater than 250 MMBtu/h of heat input and less than or
equal to 850 MMBtu/h with guaranteed NOX emission rates of
25 ppm.
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
greater than 250 MMBtu/h of heat input and less than or equal to 850
MMBtu/h and that operate at intermediate or base load capacity factors.
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 going back 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
NOX reductions in spite of these modest effects on other
pollutants and associated energy requirements.
v. Promotion and 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 stationary combustion turbines. SCR is
applicable to multiple industries, and advancement for combustion
turbines can be transferred to these industries.
11. BSER for Large Combustion Turbines
This section describes the proposed BSER for new, modified, and
reconstructed stationary combustion turbines in new subpart KKKKa with
base load ratings of greater than 850 MMBtu/h of heat input. Like the
subcategories of small and medium combustion turbines, the EPA is
proposing to further subdivide large combustion turbines according to
whether they will be utilized as low, intermediate, or base load units.
The proposed BSER and corresponding NOX emission standards
will also depend on whether these turbines burn natural gas or non-
natural gas fuels. For large combustion turbines in this subcategory,
the proposed BSER is the use of SCR in combination with combustion
controls for intermediate and base load units (i.e., those with 12-
calendar-month capacity factors greater than 20 percent). For large
combustion turbines that will be utilized as low load units (i.e., at
12-
[[Page 101333]]
calendar-month capacity factors of less than or equal to 20 percent),
the proposed BSER is the use of dry combustion controls for combustion
turbines firing natural gas and wet combustion controls for combustion
turbines firing non-natural gas fuels.
a. Combustion Controls
This section describes the availability of combustion controls used
by owners/operators of large stationary combustion turbines. Dry
combustion controls, such as lean premix/DLN, are mature technologies
that were determined to be the BSER in existing subpart KKKK and
continue to be used as NOX emission controls on new natural
gas-fired stationary combustion turbines. Wet combustion controls were
not part of the BSER for large natural gas-fired combustion turbines in
subpart KKKK because the technology had not demonstrated the ability to
achieve a NOX emissions rate of 15 ppm--the limit set in
subpart KKKK for new, modified, and reconstructed large natural gas-
fired combustion turbines based on dry combustion controls.
i. Adequately Demonstrated
Dry combustion controls are widely available from major
manufacturers of large aeroderivative and frame type stationary
combustion turbines that burn natural gas. Combustion controls are
mature technologies and have been demonstrated for multiple years in
various end-use applications, and in new subpart KKKKa, the EPA is
proposing to maintain that dry combustion controls are adequately
demonstrated for new, modified, and reconstructed natural gas-fired
turbines in this large subcategory. For new, modified, and
reconstructed large turbines that burn non-natural gas fuels, the EPA
is proposing to maintain that wet combustion controls are adequately
demonstrated for control of NOX emissions.
ii. Extent of Reductions in NOX Emissions
Manufacturer NOX emission rate performance guarantees
for large natural gas-fired stationary combustion turbines using dry
combustion controls are primarily 9 ppm and 25 ppm, respectively. New
aeroderivative and high-efficiency frame units are currently guaranteed
at 25 ppm NOX while less efficient frame units have
guaranteed NOX emission rates of 9 ppm or 15 ppm, and, in
certain applications, 5 ppm. Even considering the potential reduction
in efficiency, a 9 ppm NOX combustion turbine emits
approximately 40 percent less NOX than a 15 ppm
NOX combustion turbine.
The EPA is not aware of any advances in combustion controls for
non-natural gas-fired fuels. Therefore, in new subpart KKKKa, the EPA
is proposing to maintain that wet combustion controls (i.e., water or
steam injection) are the BSER for new, modified, and reconstructed
large stationary combustion turbines that burn non-natural gas fuels
and that operate at low loads. As discussed below in section III.B.12,
the EPA also is proposing to maintain from subpart KKKK an associated
emissions rate of 42 ppm NOX for this subcategory of large
turbines.
iii. Costs
The use of combustion controls able to achieve 15 ppm NOx or less
has been standard equipment for combustion turbines sold in the United
States for multiple years, and combustion controls consistent with the
existing standards in subpart KKKK represent little cost to the
regulated community. When subpart KKKK was finalized in 2006, the
largest aeroderivative combustion turbine available at the time had a
base load rating of less than 850 MMBtu/h of heat input. However, less-
efficient frame units greater than 850 MMBtu/h were available with
guaranteed NOX emission rates of 15 ppm or less. Since
subpart KKKK was finalized in 2006, several aeroderivative combustion
turbines greater than 850 MMBtu/h have been developed and large frame
turbines have increased efficiency, and as a consequence, most
guaranteed NOX emission rates have increased to 25 ppm.
These large aeroderivative and high-efficiency frame combustion
turbines, even when operating at lower capacity factors, could only
comply with the current standards in subpart KKKK by installing SCR.
Therefore, in new proposed subpart KKKKa, SCR costs are included in the
baseline level of control for these units at all loads. The EPA is
soliciting comment on whether combustion controls are being developed
for the high-efficiency machines currently guaranteed at 25 ppm
NOX that would reduce the guaranteed NOX
emissions rate.
At this time, the Agency does not have detailed capital or O&M cost
information and is soliciting comment on the costs of combustion
turbines with NOX guarantees of 9 ppm and/or 5 ppm relative
to the costs of comparable combustion turbines with 15 ppm or 25 ppm
guarantees. To the extent the Agency receives information that the
costs of combustion controls with emission rates of 9 ppm or 5 ppm are
reasonable, the Agency could finalize emission standards consistent
with these guaranteed levels (at least in that subcategory where the
EPA has not also proposed SCR as part of the BSER). The EPA is also
soliciting additional information on potential impacts of low
NOX combustors on the operation of combustion turbines. In
particular, the Agency is seeking information on potential reductions
in efficiency and/or output of combustion controls that are capable of
achieving 9 ppm and/or 5 ppm NOX or less.
Based on design information in Gas Turbine World 2021, the EPA
projected that the use of a combustion turbine with NOX
guarantees of 9 ppm would reduce the efficiency and output relative to
a comparable 15 ppm NOx combustion turbine by 2 percent. The EPA
estimated the incremental costs of a BSER based on the use of DLN
guaranteed at 9 ppm NOX based on the reduced efficiency of
low, intermediate, and base load combustion turbines. These costs were
determined at annual capacity factors of 5 percent, 30 percent, and 60
percent, respectively. Assuming no additional capital or operating
costs, the costs of achieving a rate of 9 ppm using only combustion
controls for large combustion turbines would be $22,000/ton
NOX, $9,300/ton NOX, and $8,000/ton
NOX for low, intermediate, and base load combustion
turbines, respectively. The Agency is soliciting comment on the costs
and other impacts of low NOX dry combustion controls,
particularly as associated with achieving an emissions rate of 9 ppm.
iv. Non-Air Quality Health and Environmental Impacts and Energy
Requirements
Due to the potential efficiency loss of a combustion turbine
guaranteed at 9 ppm NOX, relative to one guaranteed at 15
ppm NOX, for each ton of NOX reduced an
additional 110 tons of CO2 would be emitted. This reduction
in efficiency is in the combustion turbine engine, and the Agency is
soliciting comment on whether this reduction in efficiency is less
important to combined cycle and CHP combustion turbines because the
lost turbine engine efficiency could be partially recovered in the
HRSG. If emission rates of other pollutants are unchanged by the low
NOX combustor, emissions of other criteria and hazardous air
pollutants (HAP) would increase by approximately 2 percent.
In general, 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,
[[Page 101334]]
whether in conjunction with controls capable of meeting a 25 ppm or a
15 ppm emissions rate when firing natural gas.
v. Promotion, Development, and Implementation of Technology
While combustion controls are a mature technology for stationary
combustion turbines, requiring their use on new, modified, and
reconstructed combustion turbines of greater than 850 MMBtu/h will
ensure that developers continue to advance the technology for these
units.
b. Selective Catalytic Reduction
The EPA is proposing in new subpart KKKKa that the costs of SCR are
reasonable on a nationwide basis for new, modified, and reconstructed
stationary combustion turbines with base load ratings of greater than
850 MMBtu/h of heat input and utilized as intermediate and base load
units. However, for large stationary combustion turbines that will be
utilized at low loads, the EPA is proposing in new subpart KKKKa that
the costs of SCR are not reasonable.
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 reciprocating engines. Therefore,
the EPA is proposing that the use of SCR for NOX control has
been adequately demonstrated for all combustion turbines that would be
subject to new subpart KKKKa, including new, modified, and
reconstructed stationary combustion turbines with base load ratings of
greater than 850 MMBtu/h of heat input and operating at greater than a
20 percent capacity factor.
ii. Extent of Reductions in NOX Emissions
The percent reduction in NOX emissions from SCR depends
on the level of control achieved through combustion controls but is
generally greater than 70 percent and can approach 90 percent in
certain cases. In conjunction with dry combustion controls on large
natural gas-fired combustion turbines, SCR has been demonstrated to
reduce NOX emissions to approximately 3 ppm compared to 15
ppm with just dry combustion controls. This represents an 80 percent
reduction in NOX emissions. The NOX standard in
existing subpart KKKK for combustion turbines of this size firing non-
natural gas fuels is 42 ppm. This standard is based on the application
of wet combustion controls. In new subpart KKKKa, based upon
application of SCR in combination with combustion controls, the EPA is
proposing a NOX emission standard of 9 ppm for new,
modified, and reconstructed large combustion turbines utilized as
intermediate or base load units and firing non-natural gas fuels. This
proposed standard represents approximately an 80 percent reduction
compared to the current standard of 42 ppm.
iii. Costs
The EPA estimated the incremental costs of SCR on a per-ton basis
using the current NSPS emissions standard (15 ppm NOX) in
subpart KKKK and assuming the NOX is reduced to 3 ppm. The
large model plant used by the EPA was a 4,450 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 $10
million and the estimated capital cost of conventional SCR is $6
million. The estimated cost effectiveness is $33,000/ton
NOX, $8,400/ton NOX, and $3,800/ton
NOX for low, intermediate, and base load combustion
turbines, respectively. In the event the EPA were to conclude that
combustion controls alone could achieve emissions rates of 9 ppm or 5
ppm, the EPA also evaluated the incremental control costs based on
combustion controls achieving an emissions rate of 3 ppm
NOX. Under this baseline, the estimated cost effectiveness
is $65,000/ton NOX, $16,000/ton NOX, and $6,400/
ton NOX for low, intermediate, and base load turbines in the
9 ppm baseline cases, respectively, and $190,000/ton NOX,
$42,000/ton NOX, and $16,000/ton NOX for the low,
intermediate, and base load turbines in the 5 ppm baseline cases,
respectively. For the reasons discussed in section III.B.7.b, the EPA
proposes that SCR is cost-reasonable for intermediate and base load
large combustion turbines.
The EPA recognizes that if it were to conclude that a 9 ppm or a 5
ppm NOX emissions rate were achievable for large natural
gas-fired turbines using only dry combustion controls, then the per-ton
incremental cost of SCR against that baseline would increase as
described. Nonetheless, in reviewing all of the relevant cost
considerations (as discussed in section III.B.7.b), the EPA does not
find the resulting cost figures so exorbitantly high that it renders
SCR as applied in those instances no longer capable of being considered
the BSER--with the potential exception of the incremental cost
associated with a 5 ppm baseline in the intermediate load subcategory.
The EPA requests comment on the cost factor for SCR on large-sized
turbines.
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 NOX (unreacted ammonia) or passing around 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., PM2.5).
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 NOX emissions rate prior to the SCR, the amount of
ammonia emitted per ton of NOX 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 NOX,
the EPA estimates that for each ton of NOX controlled, 0.1
tons of ammonia are emitted from SCR controls on combustion turbines
with base load ratings of greater than 850 MMBtu/h of heat input and
with guaranteed NOX emission rates of 15 ppm.
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
[[Page 101335]]
output by 0.3 percent. Similar to ammonia, the CO2 per ton
of NOX reduced depends on the amount of NOX
entering the SCR. The EPA estimates that for each ton of NOX
controlled, 8 tons of CO2 are emitted as a result of the SCR
on combustion turbines with base load ratings of greater than 850
MMBtu/h of heat input with guaranteed NOX emission rates of
15 ppm.
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
greater than 850 MMBtu/h of heat input and that operate at intermediate
or base load capacity factors. 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
NOX reductions in spite of these modest effects on other
pollutants and associated energy requirements.
v. Promotion and 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.
12. Proposed NOX Emissions Standards for New and
Reconstructed Stationary Combustion Turbines in 40 CFR Part 60, Subpart
KKKKa
This section describes the proposed emissions standards, based on
the identified BSER, for each of the proposed subcategories of new and
reconstructed stationary combustion turbines in new subpart KKKKa. The
EPA used two primary sources of information for the proposed emission
standards--combustion turbine manufacturer guaranteed NOX
emission rates and hourly emissions database information reported to
the EPA and available from CAMPD. The EPA considered, but did not use,
permitted emission rates because the numeric standards differ in terms
of the averaging period used for compliance purposes and under what
operating conditions the standards are applicable. Similarly, the EPA
is not proposing to base the proposed emission standards on stack
performance test information because these emission rates are
representative of what can be achieved under the conditions of a
performance test and do not necessarily represent what is achievable
under other operating conditions. The EPA is proposing that
manufacturer guarantees represent appropriate NOX emission
standards for determination of the BSER based on the use combustion
controls. The EPA is also proposing that the analysis of hourly
emissions data allows the Agency to evaluate the appropriate numeric
standards of the BSER based on the use of post-combustion SCR in
combination with combustion controls while also identifying under what
conditions the emission standards are applicable.
a. Emissions Standards for Small Combustion Turbines
The NOX standards in subpart KKKK for small natural gas-
fired stationary combustion turbines range from 100 ppm for mechanical
drive applications with base load ratings of less than or equal to 50
MMBtu/h \45\ of heat input to 25 ppm for certain combustion turbines
with base load ratings of greater than 50 MMBtu/h of heat input and
less than or equal to 850 MMBtu/h. The current NOX standards
in subpart KKKK for small non-natural gas-fired stationary combustion
turbines range from 150 ppm for mechanical drive applications with base
load ratings of less than or equal to 50 MMBtu/h \46\ of heat input to
74 ppm for certain combustion turbines with base load ratings of
greater than 50 MMBtu/h of heat input and less than or equal to 850
MMBtu/h.
---------------------------------------------------------------------------
\45\ The NOX emissions standard in subpart KKKK for
natural gas-fired electric generating combustion turbines with base
load ratings of less than or equal to 50 MMBtu/h is 42 ppm.
\46\ The NOX emissions standard in subpart KKKK for
non-natural gas-fired electric generating combustion turbines with
base load ratings of less than or equal to 50 MMBtu/h is 96 ppm.
---------------------------------------------------------------------------
As discussed in section III.B.9, in new subpart KKKKa, the proposed
BSER for the subcategory of small stationary combustion turbines with
base load ratings of less than or equal to 250 MMBtu/h of heat input is
SCR in combination with combustion controls when operating as a base
load unit. The proposed BSER is combustion controls alone when
operating as a low or intermediate load unit. The EPA is proposing in
new subpart KKKKa an emissions rate of 3 ppm NOX for these
small base load units and 25 ppm NOX for low and
intermediate load small turbines firing natural gas. The EPA solicits
comment on whether small units burning natural gas can achieve a 15 ppm
or 9 ppm NOX emissions rate using combustion controls alone.
Also, in new subpart KKKKa, the proposed BSER for small combustion
turbines is SCR in combination with combustion controls when operating
as a base load unit and firing non-natural gas fuels and is wet
combustion controls alone when operating as a low or intermediate load
unit and firing non-natural gas fuels. The EPA is proposing in new
subpart KKKKa an emissions rate of 9 ppm NOX for these small
base load combustion turbines and is proposing to maintain an emissions
rate of 74 ppm NOX for low and intermediate load small
turbines firing non-natural gas. The EPA is proposing to maintain the
NOX emission standards for small non-natural gas-fired
combustion turbines operating as intermediate or low load units because
the EPA is not aware of any improvements in the performance of wet
combustion controls for these combustion turbines. Please refer to
Table 1 for the remaining proposed emissions standards.
b. Emissions Standards for Medium Combustion Turbines
The EPA is proposing in new subpart KKKKa to create a medium size-
based subcategory for stationary combustion turbines with base load
ratings of greater than 250 MMBtu/h of heat input and less than or
equal to 850 MMBtu/h. Within this subcategory, the EPA is proposing to
further divide these combustion turbines into low, intermediate, and
base load units and according to whether they burn natural gas or non-
natural gas fuels. See the discussion in section III.B.4. Also, as
discussed in section III.B.7, the EPA is proposing in new subpart KKKKa
that the BSER for medium natural gas-fired combustion turbines utilized
as intermediate and base load units (i.e., at 12-calendar-month
capacity factors of greater than 20 percent) is combustion controls in
combination with SCR. For medium combustion turbines firing natural gas
and utilized as low load units (i.e., at 12-calendar-month capacity
factors of less than or equal to 20 percent), the EPA is proposing that
the BSER is combustion controls alone. The proposed NOX
emissions standard for intermediate and base load medium-sized
combustion turbines firing natural gas is 3 ppm while the proposed
NOX emissions standard for low load medium-sized combustion
turbines is 25 ppm. Please refer to Table 1 for the remaining proposed
emissions standards.
[[Page 101336]]
i. Low Load Medium Combustion Turbines
The current NOX standards in subpart KKKK for medium
natural gas-fired combustion turbines is 25 ppm. For this proposed
action, the EPA reviewed hourly emissions data from two medium
aeroderivative simple cycle facilities without SCR that recently
commenced operation. The proposed 25 ppm NOX emissions rate
is consistent with the 99.7 percent confidence interval of the 4-hour
rolling emissions rate at higher loads.\47\ The combustion turbines at
these facilities were able to maintain their emissions rate until
hourly loads of approximately 70 percent were reached. However, as
discussed in relation to small turbines in section III.B.9, the EPA
requests comment on whether a NOX emissions rate as low as
15 ppm might be achievable based on combustion controls alone for
medium combustion turbines operating at low capacity factors on an
annual basis. The EPA also requests comment on whether SCR should be an
appropriate component of the BSER for medium combustion turbines
operating at low capacity factors, and if so, whether 3 ppm would be an
appropriate NOX emissions rate that low-load sources can
achieve.
---------------------------------------------------------------------------
\47\ The Martin Drake facility in Colorado uses General Electric
LM2500XPRESS combustion turbines with dry combustion controls and
has maintained the proposed emission standards 99.7 percent of the
time. The Mustang facility in Oklahoma uses Siemens SGT-A65
combustion turbines with water injection and has maintained the
proposed emission standards 99.97 percent of the time.
---------------------------------------------------------------------------
The NOX standard in subpart KKKK for medium non-natural
gas-fired combustion turbines is 74 ppm. Manufacturer guarantees for
fuels other than natural gas are more limited, but reported values
range between 42 ppm and 58 ppm. While the EPA is proposing to maintain
the same non-natural gas standard for low capacity factors as in
existing subpart KKKK, the EPA is soliciting comment on the achievable
emission rates of medium combustion turbines when combusting distillate
oil and other non-natural gas fuels. The EPA is particularly interested
in emissions rates achievable using dry and/or wet combustion controls.
The Agency also is soliciting comment on the costs of including wet
combustion controls on combustion turbines that only operate on
distillate oil or other non-natural gas fuels during natural gas
curtailments or other infrequent events. To the extent the control
costs are significantly higher for owners/operators of these units
relative to costs for owners/operators that already use demineralized
water, including for power augmentation for periods of high ambient
temperatures, the Agency would consider subcategorizing these units
when burning non-natural gas fuels. For these units, dry combustion
controls when firing non-natural gas fuels may be more appropriate. The
EPA is soliciting comment on a range of 42 ppm to 58 ppm NOX
for medium combustion turbines operating at low capacity factors for
the final rule.
ii. Intermediate and Base Load Medium Combustion Turbines
As noted previously, the EPA is proposing that combustion controls
in combination with SCR is the BSER for medium combustion turbines
operating at intermediate and base load capacity factors. Due to the
limited number of medium combustion turbines operating at intermediate
and base load capacity factors that have recently commenced
construction, the EPA reviewed the emissions rates of medium simple
cycle turbines with SCR. The EPA specifically reviewed hourly emissions
rate information for highly efficient medium simple cycle turbines to
account for the BSER in the final Carbon Pollution Standards, which is
based on the use of highly efficient generation. Based on the analysis
of the hourly data from these facilities, the EPA is proposing that a
NOX emissions rate of 3 ppm, based on the application of
combustion controls in combination with SCR, has been demonstrated for
medium combustion turbines operating at intermediate or base loads. The
Bayonne Energy Center in New Jersey uses Siemens SGT-A65 combustion
turbines with water injection plus SCR and has the lowest
NOX emissions rate for highly efficient medium combustion
turbines. The facility has maintained the proposed emissions standard
100 percent of the time. The EPA evaluated a NOX emissions
rate of 2 ppm for periods of high load operation, but the historical 4-
hour compliance rate drops to 91.82 percent. Based on current
information, it does not appear that 2 ppm NOX is
consistently achievable for highly efficient medium combustion
turbines.
c. Emissions Standards for Large Combustion Turbines
The NOX emission standards for stationary combustion
turbines in subpart KKKK with base load ratings of greater than 850
MMBtu/h of heat input are 15 ppm when combusting natural gas and
operating at high loads, 42 ppm when combusting fuels other than
natural gas and operating at high loads, and 96 ppm when operating at
part loads. These existing NOX standards are based on the
application of dry and/or wet combustion controls alone or diffusion
flame combustion at part load. Furthermore, these large combustion
turbines are not subcategorized by annual capacity factors. In new
subpart KKKKa, for large new, modified, or reconstructed stationary
combustion turbines with base load ratings of greater than 850 MMBtu/h
of heat input, the EPA is proposing to lower the NOX
emission standards to 3 ppm for natural gas-fired turbines and 5 ppm
for large non-natural gas-fired turbines operating as intermediate or
base load units (i.e., at 12-calendar-month capacity factors of greater
than 20 and 40 percent, respectively). These proposed NOX
standards are based on the application of a BSER of combustion controls
in combination with SCR. The EPA also is proposing to maintain the same
NOX emission standards as in subpart KKKK for low load
(i.e., at 12-calendar-month capacity factors of less than or equal to
20 percent) large stationary combustion turbines--dry or wet combustion
controls without SCR.
i. Low Load Large Combustion Turbines
The proposed BSER in new subpart KKKKa for low load (i.e., at 12-
calendar-month capacity factors of less than or equal to 20 percent)
large stationary combustion turbines with base load ratings of greater
than 850 MMBtu/h of heat input is combustion controls--the same as
subpart KKKK. The EPA is proposing that there have not been significant
changes in combustion controls for this subcategory and to maintain the
emission standards in subpart KKKK--15 ppm NOX for large
natural gas-fired low load combustion turbines and 42 ppm
NOX for large non-natural gas-fired combustion turbines.
ii. Intermediate and Base Load Large Combustion Turbines
The EPA is proposing in new subpart KKKKa that combustion controls
in combination with SCR is the BSER for intermediate and base load
(i.e., at 12-calendar-month capacity factors greater than 20 percent)
combustion turbines with base load ratings of greater than 850 MMBtu/h
of heat input. For this review of the NSPS, the EPA reviewed hourly
emissions rate information for highly efficient large combined cycle
combustion turbines to account for the BSER in the final Carbon
Pollution Standards, which is based on the use of highly efficient
generation. American Electric Power's (AEP) Dresden energy facility in
Ohio was one of the combined cycle combustion turbines identified by
the EPA in the Carbon Pollution Standards rulemaking with a
[[Page 101337]]
long-term low GHG emissions rate. The Dresden facility has SCR
installed and has maintained a NOX emissions rate of 4 ppm
99.99 percent of the time by highly efficient combined cycle turbines
with SCR. However, this facility is relatively old (began operations in
2012), and the EPA also reviewed NOX emissions data for more
recently built highly efficient combined cycle facilities. For example,
the Okeechobee Clean Energy Center in Florida, the Port Everglades
combined cycle facility in Florida, and the Eagle Valley Generating
Station in Indiana all use higher efficiency combustion turbine engines
in combination with combustion controls and SCR and all have maintained
the proposed emissions rate of 3 ppm NOX 100 percent of the
time. For large simple cycle combustion turbines, the units with the
lowest NOX emission rates are at Ocotillo Power Plant in
Arizona. The facility uses General Electric LMS100 models with water
injection plus SCR and has maintained the proposed emissions standard
99.84 percent of the time. The EPA believes that the emissions rate at
the Ocotillo Power Plant could be improved through enhanced catalyst
management and ammonia injection, which could reduce the emissions rate
to the level achieved by the simple cycle turbines at the Bayonne
Energy Center. Based on the analysis of the hourly data from these
facilities, the EPA is proposing in new subpart KKKKa that a
NOX emissions rate of 3 ppm has been demonstrated for large
highly efficient intermediate and base load combustion turbines. The
EPA also evaluated a NOX emissions rate of 2 ppm for periods
of high load operation. While the combined cycle facilities have
maintained a high load emissions rate of 2 ppm NOX 99.73
percent of the time, the Ocotillo Power Plant has only maintained a
high load emissions rate of 2 ppm 66.02 percent of the time. Based on
current information, it does not appear that 2 ppm NOX is
consistently achievable for highly efficient large combustion turbines.
The EPA is soliciting comment on the ability of large frame simple
cycle turbines using SCR to achieve the proposed emissions rate.
d. Emission Standards for Combustion Turbines Operating at Part Loads,
Located North of the Arctic Circle, or Operating at Ambient
Temperatures of Less Than 0 [deg]F
As discussed previously in section III.B.4.f, existing subpart KKKK
subcategorizes stationary combustion turbines operating at part load
(i.e., less than 75 percent of the base load rating) and combustion
turbines operating at low ambient temperatures.\48\ The hourly
NOX emissions standard is less stringent during any hour
when either of these conditions is met regardless of the type of fuel
being burned. Subpart KKKK also has different hourly NOX
emissions standards depending on if the output of the combustion
turbine is less than or equal to 30 MW (150 ppm NOX) or
greater than 30 MW (96 ppm NOX) during part-load operation
or when operating at low ambient temperatures. As described in section
III.B.4.f, in new subpart KKKKa, the EPA is proposing to amend this
size threshold for this subcategory such that the 150 ppm rate would be
applicable to combustion turbines with base load ratings of less than
or equal to 250 MMBtu/h of heat input and the 96 ppm rate would be
applicable to combustion turbines with base load ratings greater than
250 MMBtu/h. In new subpart KKKKa, the EPA is proposing to maintain
that the BSER for turbines operating at part load or at low ambient
temperatures is diffusion flame combustion for all fuel types. Thus,
the EPA also is proposing to maintain, based on the application of
diffusion flame combustion, that the part-load and low ambient
temperature NOX emission standards are 150 ppm for turbines
with base load ratings of less than or equal to 250 MMBtu/h of heat
input and 96 ppm for combustion turbines with base load ratings greater
than 250 MMBtu/h. In addition, the proposed part-load standard includes
all periods of part-load operation, including startup and shutdown.
However, in contrast to the part-load standards in existing subpart
KKKK, in new subpart KKKKa, the EPA is proposing to lower the part-load
threshold from less than 75 percent load to less than 70 percent of the
combustion turbine's base load rating. See section III.B.4.f for
additional discussion of this proposed reduction in the part-load
threshold.
---------------------------------------------------------------------------
\48\ While the EPA refers to this as the part-load standard, it
includes an independent temperature component as well.
---------------------------------------------------------------------------
The determination to propose maintaining the BSER and
NOX emission standards in new subpart KKKKa for combustion
turbines operating at part load or low ambient temperatures is based on
a review of reported maximum hourly emissions rate data for recently
constructed combustion turbines. The hourly data includes all periods
of operation, including periods of startup and shutdown. For combustion
turbines with base load ratings of greater than 250 MMBtu/h of heat
input, 88 percent of simple cycle turbines and 98 percent of combined
cycle turbines reported a maximum hourly NOX emissions rate
of less than 96 ppm. Based on this information, the EPA is proposing in
new subpart KKKKa that a part-load standard of 96 ppm, which includes
periods of startup and shutdown, is appropriate for combustion turbines
with base load ratings of greater than 250 MMBtu/h of heat input. The
EPA does not have CEMS data for combustion turbines with base load
ratings of less than 250 MMBtu/h of heat input and is proposing to
maintain the existing part-load standard in new subpart KKKKa of 150
ppm NOX.
Finally, recognizing the wide discrepancy in the emissions
standards for part-load operation as compared to full load (i.e., above
70 percent on an hourly basis), the EPA in section III.B.4.f requests
comment on a number of specific options for reducing that discrepancy.
13. Proposed Determination of BSER and NOX Emissions
Standards for Modified Stationary Combustion Turbines in 40 CFR Part
60, Subpart KKKKa
This section describes the proposed BSER and emission standards for
modified stationary combustion turbines. For purposes of this subpart,
the EPA would apply the definition of modification in the General
Provisions, 40 CFR 60.14. The general rule under those provisions
defines a ``modification'' as ``any physical change in, or change in
the method of operation of, a stationary source'' that either
``increases the amount of any air pollutant emitted by such source or .
. . results in the emission of any air pollutant not previously
emitted.'' Id. 60.14(a).
In existing subpart KKKK, the BSER for modified combustion turbines
is the use of combustion controls. While the BSER is generally the same
as for new combustion turbines, the emissions standards are generally
higher for a given subcategory to reflect that combustion controls can
be more challenging to apply to modified combustion turbines compared
to newly constructed combustion turbines. The NOX emissions
standards for modified combustion turbines in subpart KKKK range from
150 ppm to 15 ppm for turbines with base load ratings of less than or
equal to 50 MMBtu/h of heat input and greater than 850 MMBtu/h,
respectively.
Lean premix/DLN technology is specific to each combustion turbine
model (i.e., a combustor designed for a particular turbine model cannot
simply
[[Page 101338]]
be installed on a different turbine model). If a combustion turbine
were to be modified and more advanced DLN technology is not
commercially available, the only option for the owner/operator to
reduce the maximum hourly emissions rate would be to install SCR.
However, one of the few ways the EPA is aware of that a combustion
turbine can be modified such that the test in 60.14 modification
criteria are triggered is if the owner/operator elects to upgrade the
combustor technology to either increase the base load rating of the
combustion turbine or to burn a fuel with a higher emissions rate. If
an owner/operator replaces a combustor with another version with the
same ratings as the previous combustor, such that the emission rate to
the atmosphere of NOX or SO2 is not increased,
the combustion turbine would not trigger the NSPS modification
criteria. The EPA is soliciting comment on whether there are other
actions that could increase the potential hourly emissions rate of a
combustion turbine and thus may constitute ``modifications'' and
whether any unique considerations exist for this subcategory.
For modified small and medium combustion turbines with base load
ratings of less than or equal to 850 MMBtu/h of heat input, the EPA is
proposing in new subpart KKKKa that the BSER is the use of combustion
controls. A difference relative to the BSER for new and reconstructed
combustion turbines compared to the BSER for certain modified
combustion turbines, is that due to potentially high retrofit
costs,\49\ the EPA is proposing that SCR does not qualify as the BSER
for modified medium base load combustion turbines. The emissions
standard for all small and medium modified natural gas-fired combustion
turbines is 25 ppm NOX when operating at high loads. The
proposed part load and non-natural gas standards for modified sources
are the same as for new and reconstructed combustion turbines.
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\49\ The EPA estimates that retrofitting a 90 MW combined cycle
combustion turbine operating at a 65 percent capacity factor with
SCR would cost approximately $12,000/ton NOX. For a 50 MW
simple cycle combustion turbine operating at a 15 percent capacity
factor, the estimated cost is approximately $102,000/ton
NOX. See the EGU NOX Mitigation Strategies Final Rule
Technical Support Document in the regulatory docket (Docket ID EPA-
HQ-OAR-2021-0668) for the final Federal ``Good Neighbor Plan'' for
the 2015 Ozone National Ambient Air Quality Standards.
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For modified combustion turbines with base load rating greater than
850 MMBtu/h, the EPA is proposing the same BSER and emissions standards
as for new and reconstructed combustion turbines. The EPA is proposing
that when retrofit costs are accounted for, the costs of SCR are
reasonable and the same emissions standards are appropriate.
14. Combustion Turbines Firing Hydrogen
The EPA is proposing in subpart KKKKa to categorize new, modified,
and reconstructed stationary combustion turbines that burn hydrogen as
either natural gas-fired sources or non-natural gas-fired sources--
depending upon the amount of hydrogen that is co-fired. Furthermore,
the EPA is proposing that combustion turbines burning hydrogen should
be subject to the same standards of performance for NOX
emissions as stationary combustion turbines firing natural gas or non-
natural gas fuels. Specifically, the EPA is proposing that affected
sources that burn less than or equal to 30 percent (by volume) hydrogen
(blended with methane) should be categorized as natural gas-fired
combustion turbines and subject to the same NOX standards as
combustion turbines burning natural gas, as defined in 60.4325a,
according to the appropriate size-based subcategory listed in Table 1
to subpart KKKKa of part 60. Furthermore, for combustion turbines that
burn greater than 30 percent (by volume) hydrogen (blended with
methane), the EPA is proposing to categorize these sources as non-
natural gas-fired combustion turbines and the applicable NOX
limit is proposed to be the same as the standard for non-natural gas-
fired combustion turbines, again, depending on the classification of
non-natural gas fuels in 60.4325a and the particular size-based
subcategory listed in Table 1. See Table 1 to subpart KKKKa of part 60
for a complete listing of all subcategories of combustion turbines and
their corresponding NOX limits. The EPA solicits comment on
the 30 percent (by volume) hydrogen threshold and its appropriateness
for determining whether an affected source should be subject to the
NOX standard for natural gas or non-natural gas fuels. The
EPA also solicits comment on alternative blend thresholds, from a low
of 20 percent (by volume) blend to a high of 50 percent (by volume)
blend, and whether an alternative volume would be a more appropriate
basis for determining an applicable NOX standard.
For this proposed action, the EPA evaluated the ability of new
stationary combustion turbines to operate with certain percentages (by
volume) of hydrogen blended into their fuel systems. This evaluation
included the identification of specific properties of hydrogen that can
impact NOX emissions when the gas is combusted. The Agency
also conducted an analysis of available control technologies and their
ability to limit NOX emissions when hydrogen is fired. The
EPA also consulted with major combustion turbine manufacturers to
collect information about improvements in available control
technologies and assess the outlook for potential future turbine
designs with hydrogen capabilities.
Although industrial combustion turbines have been burning byproduct
fuels containing large percentages of hydrogen for decades, utility
combustion turbines have only recently begun to co-fire smaller amounts
of hydrogen as a fuel to generate electricity. Most turbine
manufacturers are rapidly addressing technical challenges in new models
of combustion turbines, such as the development of improved designs and
components that can withstand higher temperatures or modified
combustors that can reduce NOX emissions.
a. Characteristics of Hydrogen Gas That Impact NOX Emissions
Some of the technical challenges of firing hydrogen in a combustion
turbine result from the physical characteristics of hydrogen gas.
Perhaps the most significant challenge is that the flame speed of
hydrogen gas is an order of magnitude higher than that of methane
(i.e., natural gas); at hydrogen blends of 70 percent or greater, the
flame speed is essentially tripled compared to pure natural gas.\50\ A
higher flame speed can lead to localized higher temperatures, which can
increase thermal stress on the turbine's components as well as increase
thermal NOX emissions.51 52 It is necessary in
combustion for the working fluid flow rate to move faster
[[Page 101339]]
than the rate of combustion. When the combustion speed is faster than
the working fluid, a phenomenon known as ``flashback'' occurs, which
can damage injectors or other components and lead to upstream
complications.\53\ Other differences include a hotter hydrogen flame
(4,089 [deg]F) compared to a natural gas flame (3,565 [deg]F) \54\ and
a wider flammability range for hydrogen than natural gas.\55\ It is
also important that hydrogen and natural gas are adequately mixed to
avoid temperature ``hotspots,'' which can also lead to formation of
greater volumes of NOX.\56\
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\50\ National Energy Technology Laboratory (NETL). (August 12,
2022). A Literature Review of Hydrogen and Natural Gas Turbines:
Current State of the Art with Regard to Performance and
NOX Control. A white paper by NETL and the U.S.
Department of Energy (DOE). Accessed at https://netl.doe.gov/sites/default/files/publication/A-Literature-Review-of-Hydrogen-and-Natural-Gas-Turbines-081222.pdf.
\51\ Guarco, J., Langstine, B., Turner, M. (2018). Practical
Consideration for Firing Hydrogen Versus Natural Gas. Combustion
Engineering Association. Accessed at https://cea.org.uk/practical-considerations-for-firing-hydrogen-versus-natural-gas/.
\52\ Douglas, C., Shaw, S., Martz, T., Steele, R., Noble, D.,
Emerson, B., and Lieuwen, T. (2022). Pollutant Emissions Reporting
and Performance Considerations for Hydrogen-Hydrocarbon Fuels in Gas
Turbines. Journal of Engineering for Gas Turbines and Power. Volume
144, Issue 9: 091003. Accessed at https://asmedigitalcollection.asme.org/gasturbinespower/article/144/9/091003/1143043/Pollutant-Emissions-Reporting-and-Performance.
\53\ Inoue, K., Miyamoto, K., Domen, S., Tamura, I., Kawakami,
T., & Tanimura, S. (2018). Development of Hydrogen and Natural Gas
Co-firing Gas Turbine. Mitsubishi Heavy Industries Technical Review.
Volume 55, No. 2. June 2018. Accessed at https://power.mhi.com/randd/technical-review/pdf/index_66e.pdf.
\54\ Andersson, M., Larfeldt, J., Larsson, A. (2013). Co-firing
with hydrogen in industrial gas turbines. Accessed at http://sgc.camero.se/ckfinder/userfiles/files/SGC256(1).pdf.
\55\ Andersson, M., Larfeldt, J., Larsson, A. (2013). Co-firing
with hydrogen in industrial gas turbines. Accessed at http://sgc.camero.se/ckfinder/userfiles/files/SGC256(1).pdf.
\56\ Guarco, J., Langstine, B., Turner, M. (2018). Practical
Consideration for Firing Hydrogen Versus Natural Gas. Combustion
Engineering Association. Accessed at https://cea.org.uk/practical-considerations-for-firing-hydrogen-versus-natural-gas/.
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b. Hydrogen and Combustion Controls
The industrial and aeroderivative combustion turbines currently
capable of co-firing at least 30 percent hydrogen (by volume) are
generally simple cycle turbines that utilize wet low-emission (WLE) or
diffusion flame combustion. For these turbines, water or steam
injection is used to control emissions of NOX, and the level
of demineralized water injection can be varied for different levels of
NOX control. In addition, exhaust gas recirculation (EGR) in
diffusion flame combustion turbines further reduces the oxygen
concentration in the combustor and limits combustion temperatures and
NOX formation.
In terms of larger, heavy-duty frame combustion turbines that can
co-fire 30 percent hydrogen (by volume), these models generally utilize
WLE, dry low-emission (DLE), or DLN combustors. The more commonly used
NOX control for combined cycle turbines is DLN combustion.
Even though the ability to fire hydrogen in combustion turbines using
DLN combustors to reduce emissions of NOX is currently more
limited, all major manufacturers have developed DLN combustors for base
load combined cycle combustion turbines that can fire hydrogen.\57\
Moreover, the major manufacturers are designing combustion turbines
that will be capable of combusting 100 percent hydrogen by 2030, with
DLN designs that assure acceptable levels of NOX
emissions.58 59
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\57\ Siemens Energy (2021). Overcoming technical challenges of
hydrogen power plants for the energy transition. NS Energy. Accessed
at https://www.nsenergybusiness.com/news/overcoming-technical-challenges-of-hydrogen-power-plants-for-energy-transition/.
\58\ Simon, F. (2021). GE eyes 100% hydrogen-fueled power plants
by 2030. Accessed at https://www.euractiv.com/section/energy/news/ge-eyes-100-hydrogen-fuelled-power-plants-by-2030/.
\59\ Patel, S. (2020). Siemens' Roadmap to 100% Hydrogen Gas
Turbines. Accessed at https://www.powermag.com/siemens-roadmap-to-100-hydrogen-gas-turbines/.
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c. Hydrogen and SCR
According to manufacturers, stationary combustion turbines firing
less than 30 percent (by volume) hydrogen to date have not demonstrated
measured increases in NOX emissions. This analysis is based
on the results of technology demonstrations and test burns on units
with combustion controls and/or SCR. While DLN combustion controls can
achieve low levels of NOX, many new simple cycle and
combined cycle combustion turbines with plans to fire hydrogen also use
SCR for additional NOX control. For example, a search in the
NEEDS database \60\ reveals that 16 existing stationary combustion
turbines at six facilities list hydrogen as a fuel along with natural
gas and/or distillate. In terms of control, 15 of these units have
installed SCR and 10 have installed combustion controls. As discussed
earlier in section III.B.7.b, the design level of control from SCR can
be tied to the exhaust gas concentration. At higher levels of incoming
NOX from the combustion of hydrogen, either the reagent
injection rate can be increased and/or the size of the catalyst bed can
be increased.\61\
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\60\ See the U.S. Environmental Protection Agency's (EPA)
National Electric Energy Data System database. NEEDS rev 06-06-2024.
Accessed at https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
\61\ Siemens Energy (2021). Overcoming technical challenges of
hydrogen power plants for the energy transition. NS Energy. Accessed
at https://www.nsenergybusiness.com/news/overcoming-technical-challenges-of-hydrogen-power-plants-for-energy-transition/.
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Other recent studies have also shown that stationary combustion
turbines firing less than 30 percent (by volume) hydrogen to date have
not demonstrated measured increases in NOX emissions. In one
such study, a NOX ppm versus percent hydrogen correction
curve was developed to illustrate that this NOX ppm
correction would be negligible for hydrogen/methane blends of less than
30 percent hydrogen, but begins to noticeably increase at hydrogen
blends of greater than 30 percent.\62\ However, it is the volumetric
stack concentrations of pollutants, and not their actual mass
production rates, which are measured using NOX CEMS. As
such, an additional fuel-based F-factor \63\ is needed to properly
convert NOX concentrations in ppm to units of lb/MMBtu. F-
factors for various fuels, such as natural gas and fuel oil, are listed
in EPA Method 19 of 40 CFR part 60, appendix A. However, F-factors for
hydrogen/methane blends (on a percent hydrogen basis) are not readily
available in the EPA test methods. As such, a table of F-factors for
hydrogen/methane blends is included in the docket for this proposed
rule.
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\62\ At 30 percent hydrogen, the NOX ppm correction
factor would be approximately 1.034 at 29.53 in. Hg and an adiabatic
flame temperature of 3,140 [deg]F. Georgia Institute of Technology
and Electric Power Research Institute. NOX Emissions from Hydrogen-
Methane Fuel Blends. See Docket ID No. EPA-HQ-OAR-2024-0419.
\63\ An F-Factor is the ratio of the gas volume of the products
of combustion to the heat content of the fuel.
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Several developers have announced installations with plans to
initially co-fire lower percentages of hydrogen (by volume) before
gradually increasing their co-firing percentages--to as high as 100
percent in some cases--depending on the availability of hydrogen fuel
supplies. See 88 FR 33255, 33305; May 23, 2023. The goals of equipment
manufacturers and the fact that existing combustion turbines have
successfully demonstrated the ability to fire various percentages of
hydrogen (by volume), combined with the potential for increased
NOX emissions, align with the EPA's decision to address the
issue of hydrogen firing in combustion turbines as proposed in new
subpart KKKKa.
d. Future Combustion Turbine Capabilities
As mentioned earlier, most turbine manufacturers are working to
increase the levels of hydrogen combustion in new and existing turbine
models while limiting emissions of NOX. This is true of the
three largest turbine manufacturers in the world: General Electric (GE)
and Siemens both have goals to develop 100 percent DLE or DLN hydrogen
combustion capability in their turbines by 2030.64 65 66
Mitsubishi
[[Page 101340]]
is targeting development of 100 percent DLN hydrogen combustion capable
turbines by 2025.\67\
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\64\ Simon, F. (2021). GE eyes 100% hydrogen-fueled power plants
by 2030. Accessed at https://www.euractiv.com/section/energy/news/ge-eyes-100-hydrogen-fuelled-power-plants-by-2030/.
\65\ Patel, S. (2020). Siemens' Roadmap to 100% Hydrogen Gas
Turbines. Accessed at https://www.powermag.com/siemens-roadmap-to-100-hydrogen-gas-turbines/.
\66\ de Vos, Rolf (2022). Ten fundamentals to hydrogen
readiness. Accessed at https://www.siemens-energy.com/global/en/news/magazine/2022/hydrogen-ready.html.
\67\ Power Magazine (2019). High Volume Hydrogen Gas Turbines
Take Shape. Accessed at https://www.powermag.com/high-volume-hydrogen-gas-turbines-take-shape/.
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Turbine models such as the GE 7HA.02 can co-fire 50 percent
hydrogen (by volume) with the DLN 2.6e combustor, GE's most recent
combustor design.\68\ GE offers other DLE and DLN combustion turbines
that can co-fire up to 33 percent hydrogen (by volume) and a diffusion
flame model that can co-fire 85 percent hydrogen (by
volume).69 70
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\68\ General Electric (GE). (February 2022). Hydrogen Overview
(online brochure). Accessed at https://www.ge.com/content/dam/gepower-new/global/en_US/downloads/gas-new-site/future-of-energy/hydrogen-overview.pdf.
\69\ General Electric (GE). (2022). Hydrogen Overview for
Aeroderivative Gas Turbines. Accessed at https://www.ge.com/content/dam/gepower-new/global/en_US/images/gas-new-site/microsites/en/sa/saudi-industrial/h2-aero-overview-march24-2022-ga-r2.pdf.
\70\ General Electric (GE) (2019, February). Power to Gas:
Hydrogen for Power Generation. Accessed at https://www.ge.com/content/dam/gepower/global/en_US/documents/fuel-flexibility/GEA33861%20Power%20to%20Gas%20-%20Hydrogen%20for%20Power%20Generation.pdf.
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Siemens offers an upgrade package called ``H2DeCarb'' to enable its
E- and F-Class turbines to combust larger quantities of hydrogen
(typically 50 to 60 percent).\71\ Furthermore, Siemens currently offers
heavy-duty combustion turbines with hydrogen blending capabilities of
30 to 50 percent (by volume), depending on the turbine model and type
of combustion system.\72\ Other Siemens models include aeroderivative
engines and medium industrial combustion turbines that range from 10 to
75 percent hydrogen (by volume) capability.\73\
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\71\ Siemens Energy Zero Emission Hydrogen Turbine Center.
Accessed at https://www.siemens-energy.com/global/en/priorities/future-technologies/hydrogen/zehtc.html.
\72\ Siemens (2022). Hydrogen power and heat with Siemens Energy
gas turbines. Accessed at https://www.siemens-energy.com/global/en/offerings/technical-papers/download-hydrogen-gas-turbine-readiness-white-paper.html.
\73\ Siemens (2020). Hydrogen power with Siemens gas turbines.
https://www.infrastructureasia.org/-/media/Articles-for-ASIA-Panel/
Siemens-Energy_-Hydrogen-Power-with-Siemens-Gas-Turbines.ashx.
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Mitsubishi has also been developing advanced combustors to fire
high levels of hydrogen with limited NOX emissions in
addition to supporting hydrogen production and storage
infrastructure.\74\ For example, the manufacturer has developed several
frame models that range between 30 and 1,280 MW in size that can co-
fire 30 percent hydrogen (by volume) with currently available DLN
technologies, and each of the available combustion turbine models is
being developed to fire 100 percent hydrogen with DLN
combustors.75 76
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\74\ Mitsubishi Heavy Industries. Accessed at https://solutions.mhi.com/power/decarbonization-technology/hydrogen-gas-turbine/.
\75\ Mitsubishi Heavy Industries (2021). Hydrogen Power
Generation Handbook. Accessed at https://solutions.mhi.com/sites/default/files/assets/pdf/et-en/hydrogen_power-handbook.pdf.
\76\ See https://power.mhi.com/special/hydrogen.
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With several models of larger combustion turbines able to co-fire
lower percentages of hydrogen (by volume) with current technologies,
some new and existing facilities have announced plans to initially co-
fire up to 30 percent hydrogen (by volume) and up to 100 percent when
the additional fuel becomes available. As noted earlier, certain
turbine models will require combustor upgrades or retrofits before
being ready to eventually fire 100 percent hydrogen. These pre-planned
retrofits align to turbine compatibility with blending high volumes and
operating exclusively on hydrogen.
Some of the turbine projects that have recently been built or that
are currently under construction are being developed with the
understanding that advanced combustors will be retrofittable to the
types of turbines installed at these facilities. It is worth noting
that in many cases, existing turbines can co-fire larger volumes of
hydrogen without significant re-engineering. These older turbines have
a simpler design that accommodates switching from natural gas to
hydrogen. However, almost all new turbines are designed with more
sophisticated burners that closely control the mixture of air and fuel
to maximize efficiency while limiting NOX generation,
specifically for burning natural gas, not hydrogen. Because hydrogen
has very different characteristics from natural gas, such as higher
flame temperature, these burners need to be re-engineered to
accommodate large volumes of hydrogen while also still adequately
limiting NOX generation. Depending on the changes necessary
for a combustion turbine to accommodate the firing of hydrogen, a
permitting authority may require that a source undertaking such a
retrofit be subject to an NSR permitting process, independent of
whether the source triggers the NSPS modification or reconstruction
criteria.
The EPA solicits comment on issues concerning stationary combustion
turbines that are planning to co-fire or are designed to co-fire
greater than 30 percent (by volume) hydrogen in the future. Topics of
interest include costs, control technology considerations and
challenges, and NOX emissions. Specifically, the EPA seeks
comment on the costs associated with co-firing high percentages (by
volume) of hydrogen. This includes information on turbine designs and
necessary components, upgrades, and retrofits. The EPA also solicits
comment on whether SCR is an effective NOX emission control
technology for combustion turbines co-firing high percentages (by
volume) of hydrogen and whether there are advancements being made in
SCR technology to better control NOX emissions when hydrogen
is co-fired. Furthermore, the EPA solicits comment on specific
combustion turbine demonstrations or emissions test data in which high
percentages (by volume) of hydrogen have been co-fired in a combustion
turbine, under what operating conditions or load, the duration, the
NOX emission control technology used, and the recorded
NOX emissions correlated to various percentages (by volume)
of hydrogen during the demonstration or test burn.
15. Collocated Battery Storage and Potential NOX Emissions
At a few locations in the U.S., both simple cycle and combined
cycle combustion turbine EGUs have been located at the same site as
battery storage technology. Battery storage works by converting
electrical energy to chemical energy and back again as needed--during
those conversions some of the energy is lost as heat and other
inefficiencies so that the roundtrip efficiency is typically around 85
percent.\77\ Consequently, the net generation from the battery is
negative (the electrical energy output is less than the electrical
energy input). However, by being able to be charged when electricity
demand is low and discharged when it is high, battery storage can
provide a useful role to the grid.
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\77\ National Renewable Energy Laboratory (NREL). 2024 Annual
Technology Baseline. Utility-Scale Battery Storage. U.S. Department
of Energy (DOE). Available at https://atb.nrel.gov/electricity/2024/utility-scale_battery_storage.
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In some cases, collocated battery storage and combustion turbine
EGUs operate independently--the batteries are charged by grid
electricity and provide arbitrage and/or ancillary services while the
combustion turbines are dispatched as normal (see for example, the Moss
Landing Power Plant, Moss Landing, California \78\). Often, the
batteries in this case are lithium-ion based with a 4-hour
[[Page 101341]]
storage duration and various capacities. The electricity charging the
battery may come from a mix of non-fossil and fossil generating
sources, the latter of which would have associated NOX and
other emissions. Regardless of the source of grid energy charging the
battery, because the efficiency of the battery is less than 100 percent
and the net generation of the battery is negative, the cumulative
emission rate of the power plant on a lb/MWh-net basis would
necessarily be higher. Regarding the operation of the combustion
turbine, because it is likely independent of the battery, it is unclear
whether the NOX emissions would be directly impacted.
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\78\ U.S. Energy Information Administration (EIA). Form 860.
Schedule 3, Energy Storage Data. 2022. Available at https://www.eia.gov/electricity/data/eia860/.
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In a different configuration, the battery is integrated with the
combustion turbine, so that the combustion turbine may charge the
battery directly (although it is possible it could also be charged from
the grid). This integrated case is sometimes referred to as a hybrid
combustion turbine.\79\ The latter has been applied at a few simple
cycle combustion turbines (see for example, Center Hybrid, Norwalk,
California \80\). By integrating battery storage with the combustion
turbine, the hybrid simple cycle combustion turbine has the capability
of providing contingency (``spinning'') reserves (i.e., the ability to
start up almost instantly), ancillary services, and/or provide black-
start capability.81 82 The battery for the hybrid combustion
turbine is typically sized to provide about 30 minutes to 1 hour of
generation, and sized around 20 percent of the capacity of the
associated combustion turbine EGU. In a wholesale market where the unit
provides contingency reserves only, the hybrid unit can receive payment
for the ability to provide those services, potentially with limited
operation of the combustion turbine part of the unit. Systemwide, it is
possible this could displace base load fossil generation that would
otherwise be operating at lower loads (and with potentially higher
hourly NOX emission rates) to provide reserve margins.
However, how the hybrid unit operates depends on the market valuation
of contingency reserves and how the owner of the unit chooses to bid
the unit. While there is a potential systemwide benefit to hybrid
combustion turbines, the direct impact on the emission rates of the
combustion turbine at the unit level is unclear. Modifications may be
made to enable generation of the combustion turbine at low loads (i.e.,
to pick up from the capacity of the battery), subsequently, the unit
could operate more at low loads where it may be less efficient and the
NOX produced from combustion is higher. Aside from
potentially affecting the loads the unit operates at, it is unclear
whether there is a direct technical impact on the NOX
emission rate of the unit. As a further complication, when installing
collocated battery storage, it may be that changes to NOX
controls could have been made at the same time (e.g., installation or
updates to SCR) that directly impacted historical NOX
emissions data.
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\79\ GE Vernova. LM6000 Hybrid EGT. Available at https://www.gevernova.com/gas-power/services/gas-turbines/upgrades/hybrid-egt.
\80\ U.S. Energy Information Administration (EIA). Form 860.
Schedule 3, Energy Storage Data. 2022. U.S. Department of Energy
(DOE). Available at https://www.eia.gov/electricity/data/eia860/.
\81\ Gridwell. Report on Hybrid Storage Technology. July 2018.
Available at https://www.gridwell.com/_files/ugd/fe68bf_ff74a8c24c6d4907b8bea661be9f99df.pdf.
\82\ Electric Power Research Institute (EPRI). Hybridized Gas
Turbine Plus Battery Energy Storage Systems. September 2021.
Available at https://www.epri.com/research/products/000000003002022317.
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The EPA is soliciting comment on the potential impact of collocated
battery storage on unit level NOX emissions of combustion
turbines, particularly in the case of the hybrid combustion turbine,
including any data that would support any asserted impact on an hourly
or instantaneous basis and the technical root cause of such an impact.
16. Additional Proposed Amendments to the NOX Standards
a. NOX Part-Load Standards During Startup and Shutdown
Since startups and shutdowns are part of the regular operating
practices of stationary combustion turbines, the EPA is proposing to
include in new subpart KKKKa a part-load NOX emissions
standard that would apply during periods of startup and shutdown. Since
periods of startup and shutdown are by definition periods of low load,
and since the ``part-load standard'' is based on the emissions rate
achieved by a diffusion flame combustor instead of DLN combustion
controls, the Agency is proposing to conclude that this standard would
be appropriate. Through analysis of continuous emission monitoring
system (CEMS) data, the EPA has determined that including periods of
startup and shutdown in the standard would not result in non-compliance
with the standard. The EPA analyzed NOX CEMS data from
existing multiple combustion turbines and the theoretical compliance
rate with a 4-hour rolling average, including all periods of operation,
was demonstrated to be achievable. The Agency is unable to determine
whether any of the potential hours of theoretical non-compliant
emissions were the result of either a malfunction of the NOX
CEMS or combustion control equipment. Since the data reported to the
EPA is hourly average capacity factors, the Agency was also unable to
identify all periods when the part-load standard would apply and the
actual level of theoretical compliance would be higher.\83\
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\83\ The part-load standard is applicable to the entire hour if
the combustion turbine operates at part-load at any point during the
hour. When determining the applicable standard for the hour the EPA
assumed the combustion turbine was operated at the hourly average
capacity factor for the entire 60 minute period. Hours with less
than 60 minutes of operation were assigned the part load standard
regardless of the reported hourly average capacity factor.
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b. Recognizing the Benefit of Avoided Line Losses for CHP Facilities
We are proposing to recognize in new subpart KKKKa the
environmental benefit of electricity generated by CHP facilities to
account for the benefit of on-site generation avoiding losses from the
transmissions and distribution of the electricity. Actual line losses
vary from location to location, but we are proposing a benefit of 5
percent avoided transmission and distribution losses when determining
the electric output for CHP facilities. To avoid CHP facilities only
providing a trivial amount of thermal energy from qualifying for the
transmission and distribution benefit, we are proposing to restrict the
5 percent benefit to CHP facilities where at least 20 percent of the
annual output is useful thermal output.
C. SO2 Emission Standards
The gaseous compound SO2 is composed of sulfur and
oxygen (O2) and is a criteria air pollutant that often forms
when a fuel containing sulfur is burned. SO2 is also a
precursor to fine particulates or PM2.5, another criteria
air pollutant. Air quality standards for SO2 are designed to
protect against exposure to the entire group of sulfur oxides
(SOX); control measures that reduce SO2 can
generally be expected to reduce exposure to all gaseous SOX.
For new, modified, or reconstructed stationary combustion turbines, the
BSER for limiting emissions of SO2 has been demonstrated to
be the combustion of low-sulfur fuels. Since the promulgation of the
original NSPS in 1979, in subpart GG of 40 CFR part 60, the sulfur
content of the primary fuels fired in stationary combustion turbines
has continued to decline, and the increased stringency of this best
system is reflected in the existing NSPS, subpart KKKK of 40 CFR
[[Page 101342]]
part 60, which was amended in 2006 to lower the SO2
standards.
Again, natural gas is the primary fuel fired in most stationary
combustion turbines. Today, the sulfur content of ``pipeline quality''
natural gas in the U.S. is limited to 20 grains or less total sulfur
per 100 standard cubic feet (gr/100 scf). In noncontinental areas where
fuel availability can be limited, the sulfur content of natural gas is
permitted to be as high as 140 gr/100 scf. Distillate fuel oil (i.e.,
diesel fuel) is a secondary or backup fuel for most combustion
turbines, and due to the EPA's regulations in the transportation sector
dating back to 1993, its sulfur content must be limited by fuel
producers. In subpart KKKK, the sulfur content of distillate fuel oil
in continental areas must not contain more than 500 ppmw sulfur. This
is considered low-sulfur diesel and is widely available as a fuel for
stationary combustion turbines. However, in noncontinental areas, the
availability of this low-sulfur diesel is limited, and distillate or
fuel oil can contain as much as 4,000 ppmw sulfur. These sulfur
contents are approximately equivalent to 0.05 percent by weight sulfur
in continental areas and 0.4 percent by weight in noncontinental areas.
The application of this BSER of low-sulfur fuels is reflected in
the existing standards of performance in subpart KKKK as discussed in
section II.C and is applicable to all new, modified, or reconstructed
combustion stationary turbines constructed after February 18, 2005,
regardless of size. However, there is a subcategory for turbines
located in noncontinental areas that may not have access to the same
low-sulfur natural gas or distillate fuels as affected sources in
continental areas.
In terms of compliance with subpart KKKK, the use of low-sulfur
fuels is demonstrated by using the fuel quality characteristics in a
current, valid purchase contract, tariff sheet, or transportation
contract, or through representative fuel sampling data that show that
the potential sulfur emissions of the fuel do not exceed the standard.
It is also expected that stationary combustion turbines using low-
sulfur fuels would have lower O&M expenses associated with reduced
formation of acid compounds inside the turbine. These lower O&M
expenses are expected to reduce or even eliminate any overall costs
associated with the use of low-sulfur fuels on new, modified, or
reconstructed stationary combustion turbines.
For this rulemaking, proposed as subpart KKKKa in 40 CFR part 60,
the EPA conducted a CAA-required review of existing control
technologies for limiting SO2 emissions from new, modified,
or reconstructed stationary combustion turbines. This review focused on
the determination in subpart KKKK that the best system for limiting
emissions of SO2 from all stationary combustion turbines is
the continued use of pipeline natural gas and low-sulfur distillate
fuel oil (i.e., diesel). The sulfur content of delivered natural gas
continues to meet the fuel industry standard of 20 gr/100 scf. For
distillate fuel oil, the SO2 emissions standard in subpart
KKKK is based on distillate fuels with a sulfur content of no more than
500 ppmw in continental areas. The production of low-sulfur diesel with
a sulfur content of 500 ppmw has changed since the promulgation of
subpart KKKK as the EPA has continued to phase in more stringent diesel
production standards for on-road and nonroad vehicles, locomotives, and
certain types of marine vessels. See 69 FR 38958; June 29, 2004. As a
consequence, ultra-low sulfur diesel (ULSD) that is limited to 15 ppmw
is an available fuel that can be fired in stationary combustion
turbines in continental areas. However, pipeline natural gas remains
the primary fuel fired in most stationary combustion turbines, and the
burning of distillate fuel oil is a secondary or backup/emergency fuel
in many cases. Also, reliable access to ULSD in certain areas remains
questionable, as does documented information about its consistent use
in non-utility sectors that operate stationary combustion turbines.
This is especially true of stationary combustion turbines located in
noncontinental areas as defined in 60.4420 and proposed in 60.4420a.
Therefore, in subpart KKKKa, the EPA solicits comment on the extent of
the current use of ULSD at affected facilities, including information
on the availability of ULSD in both continental and noncontinental
areas.
The EPA's review of the NSPS did not reveal the use of any
additional control technologies that have been applied to stationary
combustion turbines to further limit SO2 emissions. This
includes flue gas desulfurization (FGD) post-combustion control
technology--the most common type of SO2 control nationwide
aside from the use of low-sulfur fuels. Generally, this control
technology is not used to limit emissions of SO2 from
natural gas-fired stationary combustion sources. Instead, FGD is used
to remove SO2 from the exhaust streams of coal- and oil-
fired utility and industrial boilers, incinerators, cement kilns, metal
smelters, and petroleum refineries. This technology was discussed in
the original NSPS, subpart GG, for stationary gas turbines, and is not
an applicable alternative for the control of SO2 emissions
from natural gas-fired stationary combustion turbines, which are
designed to fire low-sulfur fuels. The use of FGD also has
environmental impacts due to increased water usage as well as the
disposal of waste products.
Based on this review, which demonstrates that the burning of low-
sulfur fuels continues to be an effective control for SO2
emissions, the EPA is proposing to maintain in new subpart KKKKa that
the use of low-sulfur fuels is the BSER for limiting SO2
emissions from new, modified, and reconstructed stationary combustion
turbines, regardless of the rated heat input and utilization of the
turbine. Accordingly, the application of this BSER is reflected in the
SO2 standards proposed in subpart KKKKa. When the EPA's
analyses show that the BSER for affected facilities remains the same,
and available information from the implementation and enforcement of
current requirements indicate that emission limitations and percent
reductions beyond those required by the current standards are not
achieved in practice, the EPA proposes to retain the current standards.
The standards of performance proposed in subpart KKKKa are identical to
those promulgated in subpart KKKK and are the same for all turbines
regardless of size. Nonetheless, we request comment on whether ULSD has
become so widely available that it would be appropriate to update the
SO2 standards for distillate fuels at combustion turbines
based on its use, at least in continental areas, whether there are
practical barriers to its use, and/or whether a subcategory-specific
SO2 standard for firing ULSD would be appropriate.
Specifically, as proposed in section 60.4330a of subpart KKKKa, an
affected source may not cause to be discharged into the atmosphere from
a new, modified, or reconstructed stationary combustion turbine any
gases that contain SO2 in excess of 110 ng/J (0.90 lb/MWh)
gross energy output or 26 ng SO2/J (0.060 lb SO2/
MMBtu) heat input. For turbines located in noncontinental areas, an
affected source may not cause to be discharged into the atmosphere any
gases that contain SO2 in excess of 780 ng/J (6.2 lb/MWh)
gross energy output or 180 ng SO2/J (0.42 lb SO2/
MMBtu) heat input.
The EPA expects no additional SO2 reductions based on
the standards proposed in subpart KKKKa. Although the EPA anticipates
that the demand for
[[Page 101343]]
electric output from stationary combustion turbines in the power and
industrial sectors will increase during the next 8 years, the Agency
does not expect significant increases in SO2 emissions from
the sector prior to the next CAA-required review of the NSPS. The EPA
also does not expect any adverse energy impacts from the proposed
SO2 standards in subpart KKKKa. All affected sources will be
able to comply with the proposed rule without any additional controls,
and the standards and the best system have not changed from subpart
KKKK in 2006.
As such, these affected sources would be required to continue
monitoring and demonstrating compliance with the fuel sulfur content
limits as specified in 60.4365 and 60.4365a.
D. Consideration of Other Criteria Pollutants
When proposing the current subpart KKKK requirements (70 FR 8314,
February 18, 2005) (2005 NSPS Proposal), the EPA considered the need to
establish standards of performance for criteria pollutants beyond
NOX and SO2. These included carbon monoxide (CO)
and particulate matter (PM).
1. Carbon Monoxide
Carbon monoxide is a product of incomplete combustion when there is
insufficient residence time at high temperature, or incomplete mixing
to complete the final step in fuel carbon oxidation. The oxidation of
CO to CO2 at combustion turbine temperatures is a slow
reaction compared to most hydrocarbon oxidation reactions. In
combustion turbines, failure to achieve CO burnout may result from
quenching by dilution air. With liquid fuels, this can be aggravated by
carryover of larger droplets from the atomizer at the fuel injector.
Carbon monoxide emissions are also dependent on the loading of the
combustion turbine. For example, a combustion turbine operating under
full load would experience greater fuel efficiencies, which will reduce
the formation of CO.
Turbine manufacturers have significantly reduced CO emissions from
combustion turbines by developing lean premix technology. Most of the
newer designs for turbines incorporate lean premix technology. Lean
premix combustion design not only produces lower NOX than
diffusion flame technology, but also lowers CO and volatile organic
compounds (VOC). In the 2005 NSPS Proposal, the EPA determined that
``with the advancement of turbine technology and more complete
combustion through increased efficiencies, and the prevalence of lean
premix combustion technology in new turbines, it is not necessary to
further reduce CO in the proposed rule'' and the EPA proposed that no
CO emission limitation be developed for the combustion turbine NSPS.
2. Particulate Matter
In the 2005 NSPS Proposal, the EPA noted that PM emissions from
turbines result primarily from carryover of noncombustible trace
constituents in the fuel. Particulate matter emissions are negligible
with natural gas firing due to the low sulfur content of natural gas.
Emissions of PM are only marginally significant with distillate oil
firing because of the low ash content and are expected to decline
further as the sulfur content of distillate oil decreases due to other
regulatory requirements. As such, the EPA proposed that an emission
limitation for PM emissions from stationary combustion turbines is not
necessary.
3. Technology Review and Revision of the Combustion Turbine National
Emission Standards for Hazardous Air Pollutants (NESHAP)
The EPA is conducting a separate rulemaking to address deficiencies
in the current NESHAP standards (i.e., establish emission standards for
hazardous air pollutants (HAP) where no standards currently exist from
new and existing stationary combustion turbines) and conducting a
technology review (under CAA section 112(d)(6)) to evaluate whether
more stringent standards are warranted. To support that rulemaking, the
EPA collected emissions data, under authority of CAA section 114, from
a variety of combustion turbines--of differing subcategories, sizes,
ages, fuels, etc. The EPA collected emissions of HAP metals (e.g.,
nickel, chromium, etc.), acid gas HAP (hydrochloric acid and
hydrofluoric acid), and formaldehyde to assist in establishing those
emission standards. The EPA also collected emissions data for
filterable PM and CO (filterable PM is often used as a surrogate for
the non-mercury HAP metals and CO has been used as a surrogate for
organic HAP). The emissions data are available on the EPA's combustion
turbine NESHAP website \84\ and in the docket for this rulemaking.
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\84\ Stationary Combustion Turbines: National Emission Standards
for Hazardous Air Pollutants (NESHAP) accessible at: www.epa.gov/stationary-sources-air-pollution/stationary-combustion-turbines-national-emission-standards.
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As part of the combustion turbine NESHAP rulemaking, the EPA
expects to establish emission standards for stationary combustion
turbines that are located at major sources of HAP emissions.\85\ These
emission standards may include limits for the HAP metals, formaldehyde,
and the acid gas HAP. In addition, the EPA may also consider the
establishment of an alternative emission limit for filterable PM as a
surrogate for the HAP metals. Some combustion turbines are currently
subject to an emission limit for formaldehyde. As such, some combustion
turbines have installed an oxidation catalyst to control formaldehyde
emissions. Oxidation catalysts may also be used to minimize emissions
of CO.
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\85\ The term ``major source'' means any stationary source or
group of stationary sources located within a contiguous area and
under common control that emits or has the potential to emit
considering controls, in the aggregate, 10 tons per year or more of
any hazardous air pollutant or 25 tons per year or more of any
combination of hazardous air pollutants. See CAA 112(a)(1).
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At this time, the EPA believes it is prudent to defer consideration
of the need for CO and PM standards of performance until the Agency has
completed the NESHAP rulemaking, which will cover both new and existing
sources. The EPA solicits comment on this approach and on the need to
establish standards of performance for PM and CO under CAA section
111(b).
E. Additional Subpart KKKKa Proposals
1. Definition of Noncontinental Area
The EPA's review of low-sulfur fuels for this NSPS indicates that
since subpart KKKK was promulgated, the availability of low-sulfur
diesel and potentially ULSD has increased in States and territories
previously defined as noncontinental areas for purposes of compliance
with the SO2 emission standards in subpart KKKK. As a
result, in subpart KKKKa, the EPA is proposing to remove Hawaii, the
Commonwealth of Puerto Rico, and the U.S. Virgin Islands from the
definition of noncontinental area. This proposed change would require
new, modified, and reconstructed stationary combustion turbines in
Hawaii, Puerto Rico, and the Virgin Islands to demonstrate compliance
with the same SO2 standards proposed in subpart KKKKa for
continental areas. As discussed in the previous section, those
standards are based on fuel oil with sulfur content limited to
approximately 0.05 percent sulfur by weight (500 ppmw).
Based on available information reviewed for this rulemaking, the
EPA proposes to maintain in subpart KKKKa that Guam, American Samoa,
the Northern Mariana Islands, and offshore platforms be included in the
definition
[[Page 101344]]
of noncontinental area and those locations would continue to be allowed
to meet the existing standards for higher sulfur fuels. This is due to
the fact these locations continue to have limited access to the same
low-sulfur fuels as facilities in continental areas. The EPA solicits
comment on the extent to which Guam, American Samoa, the Northern
Mariana Islands, and offshore platforms have access to low-sulfur and/
or ULSD distillate fuels and whether any of those territories or
locations should no longer be included in the definition of
noncontinental area.
2. Clarification of Fuel Analysis Requirements for Determination of
SO2 Compliance
The EPA is proposing in subpart KKKKa rule language to clarify the
intent of the rule in that if a source elects to perform fuel sampling
to demonstrate compliance with the SO2 standard, the initial
test must be conducted using a method that measures multiple sulfur
compounds (e.g., hydrogen sulfide, dimethyl sulfide, carbonyl sulfide,
and thiol compounds). Alternate test procedures can be used only if the
measured sulfur content is less than half of the applicable standard.
In addition, the EPA is proposing to allow fuel blending to achieve the
applicable SO2 standard. Under the proposed language, an
owner/operator of an affected facility would be able to burn higher
sulfur fuels as long as the average fuel fired meets the applicable
SO2 standard at all times. Finally, the primary method of
controlling emissions is through selecting fuels containing low amounts
of sulfur or through fuel pretreatment operations that can operate at
all times, including periods of startup and shutdown as discussed below
in section III.G.
3. Expanding the Application of Low-Btu Gases
For stationary combustion turbines combusting 50 percent or more
biogas (based on total heat input) per calendar month, subpart KKKK in
40 CFR part 60 established a maximum allowable SO2 emissions
standard of 65 ng SO2/J (0.15 lb SO2/MMBtu) heat
input. This standard was set to avoid discouraging the development of
energy recovery projects that burn landfill gases to generate
electricity in stationary combustion turbines. See 74 FR 11858; March
20, 2009. Stationary combustion turbine technologies using other low-
Btu gases are also commercially available. These technologies can burn
low-Btu content gases recovered from steelmaking (e.g., blast furnace
gas and coke oven gas), coal bed methane, etc. Like biogas, substantial
environmental benefits can be achieved by using these low-Btu gases to
fuel combustion turbines instead of flaring or direct venting to the
atmosphere. Therefore, in subparts KKKK and KKKKa, the EPA is proposing
to amend and expand the application of the existing 65 ng
SO2/J (0.15 lb SO2/MMBtu) heat input emissions
standard to include stationary combustion turbines combusting 50
percent or more (on a heat input basis) any gaseous fuels that have
heating values less than 26 megajoules per standard cubic meter (MJ/
scm) (700 Btu/scf) per calendar month.
To account for the environmental benefit of productive use and
simplify compliance for low-Btu gases, the Agency considers it
appropriate to base the proposed SO2 standard on a fuel
concentration basis as an alternative to a lb/MMBtu basis. The original
subpart KKKK standard for SO2 that was proposed in 2005 (70
FR 8314; February 18, 2005) was based on the sulfur content in
distillate oil and included a standard of 0.05 percent sulfur by weight
(500 ppmw). In general, emission standards are applied to a gaseous
mixture by volume (ppmv), not by weight (ppmw). Basing the standard on
a volume basis would simplify compliance and minimalize burden to the
regulated community. Therefore, the EPA is proposing in subparts KKKK
and KKKKa a fuel specification standard of 650 mg sulfur/scm (or 28 gr
sulfur/100 scf) for low-Btu gases. This is approximately equivalent to
a standard of 500 ppmv sulfur and is in the units directly reported by
most test methods.
4. Proposed Amendments To Simplify NSPS
This rulemaking includes some additional proposals for subpart
KKKKa and proposed amendments to subart KKKK intended to simplify the
regulatory burden.
a. Compliance Demonstration Exemption for Units Out of Operation
The EPA is proposing in new subpart KKKKa, and proposing to amend
in subpart KKKK, that units that are out of operation at the time of a
required performance test are not required to conduct the performance
test until 45 days after the facility is brought back into operation.
The EPA concludes that it is not appropriate to require an affected
facility that is not currently in operation to start up in order to
conduct a performance test for the sole purpose of demonstrating
compliance with the NSPS.
Similarly, owners/operators of a combustion turbine that has
operated 50 hours or less since the previous performance test was
required to be conducted can request an extension of the otherwise
required performance test from the appropriate EPA Regional Office
until the turbine has operated more than 50 hours. This provision is
specific to a particular fuel, and an owner/operator permitted to burn
a backup fuel, but that rarely does so, can request an extension on
testing on that particular fuel until it has been burned for more than
50 hours.
b. Authorization of a Single Emissions Test
For similar, separate affected facilities under common ownership,
not equipped with SCR, and using dry combustion control equipment, the
EPA is proposing to include in new subpart KKKKa, and is proposing to
amend in subpart KKKK, that the Administrator or delegated authority
may authorize a single emissions test as adequate demonstration for up
to four additional separate affected facilities of the same combustion
turbine model and using the same dry combustion control technology as
long as: (1) The most recent performance test for each affected
facility shows that performance of each affected facility is 75 percent
or less of the applicable emissions standard; (2) the manufacturer's
recommended maintenance procedures for each control device are
followed; and (3) each affected facility conducts a performance test
for each pollutant for which it is subject to a standard at least once
every 5 years. Dry low NOX (DLN) combustion results in
relatively stable emission rates. Furthermore, the DLN combustor is a
fundamental part of a combustion turbine, and as long as similar
maintenance procedures are followed, the Agency has concluded that
emission rates will likely be comparable between similar combustion
turbines. Therefore, the additional compliance costs associated with
testing each affected turbine would not result in significant emissions
reductions.
c. Verification of Proper Operation of Emission Controls
Turbine engine performance can deteriorate with operation and age.
Operational parameters need to be verified periodically to ensure
proper operation of emission controls. Therefore, the EPA is proposing
in new subpart KKKKa to require facilities using the water- or steam-
to-fuel ratio as a demonstration of continuous compliance with the
NOX emissions standard to verify the appropriate ratio or
parameters at a minimum of every 60 months. The Agency has concluded
this
[[Page 101345]]
would not add significant burden since most affected facilities are
already required to conduct performance testing at least every 5 years
through title V requirements or other State permitting requirements.
d. Compliance for Multiple Turbine Engines With a Single HRSG
The existing NSPS (subpart KKKK) does not state how multiple
combustion turbine engines that are exhausted through a single HRSG
would demonstrate compliance with the NOX standards.
Therefore, the EPA is proposing in new subpart KKKKa and proposing to
amend in subpart KKKK procedures for demonstrating compliance when
multiple combustion turbine engines are exhausted through a single HRSG
and when steam from multiple combustion turbine HRSGs is used in a
single steam turbine. Furthermore, the existing rule requires approval
from the permitting authority for any use of the part 75 NOX
monitoring provisions in lieu of the specified part 60 procedures, but
the Agency's review has concluded that approval is an unnecessary
burden for facilities only using combustion controls. Therefore, the
EPA is proposing in new subpart KKKKa and proposing to amend in subpart
KKKK to allow sources using only combustion controls to use the
parametric NOX monitoring in part 75 to demonstrate
continuous compliance without requiring prior approval. However, if the
source is using post-combustion control technology (i.e., SCR) to
comply with the requirements of the NSPS, then approval from the
permitting authority is required prior to using the part 75 CEMS
calibration procedures in place of the part 60 procedures.
F. Additional Request for Comments
1. Affected Facility
The EPA is considering and requesting comment on amending the
definition of the affected facility in new subpart KKKKa for systems
with multiple combustion turbine engines. Specifically, the Agency is
requesting comment on treating multiple combustion turbine engines
connected to a single generator, separate combustion turbines engines
using a single HRSG, and separate combustion turbine engines with
separate HRSG that use a single steam turbine or otherwise combine the
useful thermal output as single affected facilities. This approach
would reduce burden to the regulated community by simplifying
monitoring. The EPA is also requesting comment on how the applicable
emission standards would be determined and on how ``new'' and
``reconstruction'' would be defined in subpart KKKKa. The EPA is
specifically requesting comment on basing the emission standards on
either the base load rating of the largest single combustion turbine
engine or the combined base load ratings of the combustion turbine
engines. For an affected facility with multiple combustion turbine
engines, the EPA is requesting comment on considering the entire
facility ``new'' or ``reconstructed'' if any combustion turbine engine
is replaced with a new combustion turbine engine or reconstructed.
2. District Energy
The EPA is considering and requesting comment on an appropriate
method to recognize the environmental benefit of district energy
systems in subpart KKKKa. The steam or hot water distribution system of
a district energy system located in urban areas, college and university
campuses, hospitals, airports, and military installations eliminates
the need for multiple, smaller boilers at individual buildings. A
central facility typically has superior emission controls and consists
of a few larger boilers facilitating more efficient operation than
numerous separate smaller individual boilers. However, when the hot
water or steam is distributed, approximately 2 to 3 percent of the
thermal energy in the water and 6 to 9 percent of the thermal energy in
the steam is lost, reducing the net efficiency advantage. The EPA is
requesting comment on whether it is appropriate in subpart KKKKa to
divide the thermal output from district energy systems by a factor
(i.e., 0.95 or 0.90) that would account for the net efficiency benefits
of district energy systems. This approach would be similar to how the
electric output for CHP is considered when determining regulatory
compliance. The EPA requests that comments include technical analysis
of the net benefits in support of any conclusions.
3. Temporary Combustion Turbines
On occasion, owners/operators of industrial and commercial
facilities or utilities need temporary combustion turbines for electric
or direct mechanical energy production for short-term use while the
primary generating equipment is not available, transmission is being
repaired and/or upgraded, or for some other unforeseen event. These
combustion turbines generally have a heat input of less than 250 MMBtu/
h.\86\ Both subpart KKKK and proposed subpart KKKKa apply to
``portable'' turbines and so these units would generally be covered by
these subparts of the NSPS regulations if they meet other applicability
criteria. Temporary turbines generally can be expected to use
combustion control technology that limits NOX emissions to
rates of 25 ppm or lower. It is less clear whether SCR technologies are
capable of being used in conjunction with temporary or portable
combustion turbines. In addition, the permitting, testing, and
monitoring requirements for a combustion turbine subject to an NSPS may
not be appropriate or suitable for temporary combustion turbines. The
need for temporary combustion turbines generally is a result of
unforeseen events, and the permitting itself could take longer than the
need for temporary generation. The EPA has historically considered
engines or boilers in one location for less than a period of 180 days
to 1 year to be temporary equipment not subject to regulation under
their respective NSPS or NESHAP subparts.\87\ The EPA is soliciting
comment on whether an exemption, alternative emissions standards, and/
or other streamlined requirements would be appropriate for temporary
combustion turbines under subparts GG, KKKK, and KKKKa and the
appropriate criteria for such regulatory provisions.
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\86\ At least one provider offers a portable combustion turbines
that has base load rating greater than 250 MMBtu/h.
\87\ See, for example, 40 CFR 60.4200(e), 60.4230(f), 60.40b(m),
60.40c(i), and 63.7491(j).
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The EPA is soliciting comment on creating a subcategory for
temporary combustion turbines, defined as turbines in one location for
less than 1 year. Consistent with a BSER of combustion controls, this
subcategory would be subject to a requirement for the owners or
operators of such units to maintain records of manufacturer
certification that the combustion turbine meets an emissions standard
based on the use of combustion controls consistent with the otherwise
applicable subcategory--25 or 15 ppm NOX. This would be
similar to the NSPS for Stationary Compression Ignition Internal
Combustion Engines and the NSPS for Stationary Spark Ignition Internal
Combustion Engines, which provide that temporary replacement units
located at a stationary source for less than 1 year, and that have been
properly certified as meeting the emissions standards that would be
applicable to such engine under the appropriate nonroad engine
provisions,
[[Page 101346]]
are not required to meet any other provisions under the NSPS with
regard to such engine.\88\ Under this approach, should a temporary
combustion turbine remain in place for longer than 1 year, then it
would not be considered temporary for any period of its operation, and
any failure of the owner or operator to comply with the otherwise
applicable requirements of the relevant subpart, even in the initial
year of operation, would be an enforceable violation of the Act. In
addition, under this approach, the EPA anticipates not allowing the
replacement of a portable combustion turbine with another portable
combustion turbine so as to maintain temporary status beyond a single
year.
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\88\ 40 CFR 60.4200(e) and 60.4230(f).
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The EPA has believes that including such a provision in subpart
KKKKa may be appropriate to allow for general maintenance,
construction, temporary, and emergency power generation. The EPA
further notes that, like temporary reciprocating engines, these units
could replace other combustion turbines during periods where the main
combustion turbines were off-line (e.g., for maintenance work), owners/
operators could have little or no ability to oversee the operations of
these temporary combustion turbines, as they are generally owned and
maintained by other entities. Therefore, the EPA solicits comment on
whether it is appropriate to hold them to the requirements for similar
sources that are portable in character. The EPA notes that adding this
provision would specifically allow the use of temporary combustion
turbines as an alternative to temporary reciprocating engines, which
can have higher emission rates than combustion turbines.\89\
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\89\ The NOX emissions standard in table 1 to subpart
JJJJ of part 60 for spark ignition natural gas-fired reciprocating
engines greater than or equal to 500 HP is 82 ppmvd at 15 percent
oxygen.
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In the alternative, the EPA is soliciting comment on
subcategorizing temporary combustion turbines using an approach the
Agency has determined is appropriate for industrial boilers. The
industrial boiler NSPS and NESHAP exempt temporary boilers that are
capable of being moved from one location to another and are at a
location for less than 180 days. While there is not a requirement for
temporary boilers to meet any other requirements, the EPA is soliciting
comment on whether it would be appropriate for the owner/operator of a
temporary combustion turbine to conduct performance testing offsite and
maintain records that indicate the combustion turbines are operating at
emission rates at or below the NSPS emission standards in KKKKa. The
requirements would be similar to those in the NSPS--annually or at
least every 5 years depending on the specific situation.
4. 12-Calendar-Month NOX Standard
The EPA is soliciting comment on adding a 12-calendar-month
NOX emissions limit as an alternative to subcategorizing
combustion turbines based on capacity factor. The specific approach the
Agency is considering is that new and reconstructed combustion turbines
would be subject to the proposed short-term NOX emissions
standard (operating day or 4-hour rolling average).\90\ For example, at
high load operating conditions, the hourly standards would be 25 ppm
and 15 ppm, respectively (assuming the combustion turbines are burning
natural gas).\91\ As an alternative to the short-term standards for
combustion turbines operating at capacity factors of greater than 20
percent, all combustion turbines would also be subject to a 12-
calendar-month emissions rate of 0.75 tons NOX per MW of
design capacity. This would have the impact of allowing simple cycle
combustion turbines with NOX emissions rate guarantees of 25
ppm to operate at a 12-calendar-month capacity factor of approximately
20 percent. Owners/operators that elect to operate at higher capacity
factors would have to increase the efficiency of the unit by switching
to a combined cycle unit, investing in combustion controls with lower
NOX emission rates, and/or using SCR.\92\ Considering
currently available combustion controls, owners/operators desiring the
flexibility to operate as base load units would, as a practical matter,
have to install SCR (or otherwise achieve comparable emissions
performance). The EPA is considering, and soliciting comment on, a 12-
calendar-month emissions rate range of 0.75 to 0.46 tons NOX
per MW of design capacity for the medium combustion turbine
subcategory. The upper range is based on a highly efficient simple
cycle turbine operating at the guaranteed NOX performance
rate of 25 ppm. The lower limit is based on a highly efficient simple
cycle turbine operating at long-term typical emissions rate of 20 ppm
NOX and at a 12-calendar-month capacity factor of 15
percent. The annual standard for large combustion turbines based on
performance guarantees is 0.45 tons of NOX per MW of
capacity. This value is based on a 15 ppm NOX highly
efficient simple cycle turbine operating at a capacity factor of 20
percent. Similar to the medium size subcategory, owners/operators that
elect to operate at higher capacity factors would need to invest in
some combination of higher efficiency, combustion controls with lower
NOX emission rates, and/or SCR. The EPA is considering, and
soliciting comment on, a 12-calendar-month emissions rate range of 0.45
to 0.21 tons NOX per MW of design capacity for the large
combustion turbine subcategory. The lower limit is based on a highly
efficient simple cycle turbine operating at long-term typical emissions
rate of 7 ppm NOX (the typical long-term emissions rate of a
combustion turbine with a guaranteed emissions rate of 9 ppm
NOX) and at a 12-calendar-month capacity factor of 15
percent.
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\90\ A short-term mass based standard could also serve as an
alternative to short-term standards based on lb NOX/
MMBtu. The basic rationale would be similar to the 12-calendar-month
mass standard. For example, the 4-hour rolling mass standard would
be 3.8 lb NOX/MW and 2.3 lb NOX/MW for the 25
ppm NOX and 15 ppm NOX subcategories,
respectively.
\91\ All other standards except the intermediate and base load
NOX standards would continue to be applicable.
\92\ A 25 ppm NOX combined cycle turbine or a 15 ppm
simple cycle turbine would be able to operate up to an annual
capacity factor of approximately 30 percent.
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This approach recognizes the environmental benefit of efficiency--
more efficient combustion turbines achieving the same input-based
emissions rate (e.g., lb NOX/MMBtu) would be able to operate
at higher capacity factors while still maintaining emissions below the
annual standard. It also recognizes the environmental benefit of
minimizing NOX emissions during all periods of operation,
including startup and shutdown, and reduces the regulatory incentive to
switch to part-load operation so that the higher part-load standard is
applicable during that hour. These environmental benefits could of
course only be realized if two conditions were met: first, that the
short-term limit remained in place, in addition to the long-term mass
cap, thus ensuring a minimum level of good rate-based emissions
performance at all times, and second, that the mass cap is calculated
using accurate assumptions concerning the translation of a more
stringent emissions rate associated, e.g., with SCR operation,
multiplied by an accurate estimate of overall operation. To the extent
this approach could help achieve lower emissions overall while also
avoiding the need to retrofit SCR control technology, it also provides
an incentive for manufacturers to continue to improve combustion
controls and the operating conditions over which the combustion
controls can operate.
[[Page 101347]]
Additional benefits include lowering compliance costs and providing
flexibility to the regulated community that is similar to conditions
often included in operating permits. An annual emission limits
recognizes the complex relationship between the choice of combustion
controls (and the impact of those controls of other pollutants), the
anticipated operation of the combustion turbine, and the use of SCR.
The flexibility would allow the owner/operator of the combustion
turbine to work with the permitting authority to determine the
appropriate emissions reduction strategy for each specific project. The
EPA requests comment, however, on a potential drawback of this
approach, which is that owners/operators that install SCR that operate
at lower than anticipated capacity factors could reduce the operation
of the SCR, thus losing some environmental benefit that could otherwise
have been cost effectively achieved.
5. System Emergency
The EPA included provisions that electricity sold during hours of
operation when a unit is called upon due to a system emergency is not
counted toward the percentage electric sales subcategorization
thresholds in Standards of Performance for Greenhouse Gas Emissions
From New, Modified, and Reconstructed Stationary Sources: Electric
Utility Generating Units in 2015 and the final Carbon Pollution
Standards earlier this year. See 40 CFR part 60, subparts TTTT and
TTTTa.\93\ In those rulemakings, the Agency concluded that this
exclusion is necessary to provide flexibility, maintain system
reliability, and minimize overall costs to the sector.\94\ The EPA is
soliciting comment on whether it is appropriate to add a similar
provision for system emergencies to new subpart KKKKa that would apply
to subcategories based on annual capacity factors. The EPA further
solicits comment on defining system emergency in subpart KKKKa to mean
``periods when the Reliability Coordinator has declared an Energy
Emergency Alert level 2 or 3 as defined by NERC Reliability Standard
EOP-011-2 or its successor, or equivalent.'' This provision would
ensure that combustion turbines intended for less frequent operation
would be available for grid reliability purposes during grid
emergencies without being subject to an emission standard that the unit
might not be able to meet without an investment in additional controls.
The EPA has determined it was necessary to add ``or equivalent'' for
areas not covered by NERC Reliability Standard EOP-011-2, for example
Puerto Rico. The definition would therefore differ slightly from the
current definition in subpart TTTTa.
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\93\ See 40 CFR 60.5580 and 60.5580a.
\94\ See 80 FR 64612 (October 23, 2015) and 89 FR 39914-15 (May
9, 2024).
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6. Exemptions in Subpart GG
The EPA included exemptions for combustion turbines used in certain
military applications and firefighting applications from the standards
of performance for gas turbines in 40 CFR part 60, subpart GG.\95\ The
EPA is soliciting comment on whether it is appropriate to include these
exemptions from subpart GG in subparts KKKK and KKKKa. The exemptions
include military combustion turbines for use in other than a garrison
facility, military combustion turbines installed for use as military
training facilities, and firefighting combustion turbines. These
combustion turbines only operate during critical situations and the EPA
is soliciting comment on whether requiring advanced combustion controls
could impact reliability or otherwise impact the ability of the
combustion turbines to serve the intended purpose.
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\95\ See 40 CFR 60.332(g).
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7. Exemption of Certain Low-Emitting Facilities From Title V Permitting
The EPA is soliciting comment on whether it would be appropriate to
exempt certain low-emitting stationary combustion turbines subject to
subparts GG, KKKK, or new subpart KKKKa from title V permitting
requirements under CAA section 502(a). According to section 502(a), the
EPA may exempt certain sources subject to CAA section 111 (NSPS)
standards from the requirements of title V if the EPA finds that
compliance with such requirements is ``impracticable, infeasible, or
unnecessarily burdensome'' on such sources. However, CAA 502(a) further
states that ``. . . the Administrator may not exempt any major source
from such requirements.'' Thus, any exemption from title V permitting
under this provision cannot extend to any sources that are ``major
sources'' as that term is defined at CAA section 501(2). The EPA has
previously established permitting exemptions under this provision for
several NSPS, particularly in circumstances where the affected
facilities are numerous and individually relatively low-emitting, the
burdens and process of obtaining permits would be overwhelming for
permitting authorities and the sources (such as numerous small
businesses, farms, or residences), and where compliance with the
emissions standards can be assured through the manufacture or design of
the equipment or facility in question.\96\
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\96\ See, for example, 40 CFR 60.4200(c) (``If you are an owner
or operator of an area source subject to this subpart, you are
exempt from the obligation to obtain a permit under 40 CFR part 70
or 40 CFR part 71, provided you are not required to obtain a permit
under 40 CFR 70.3(a) or 40 CFR 71.3(a) for a reason other than your
status as an area source under this subpart.'') and 40 CFR
70.3(b)(4)(i) (``The following source categories are exempted from
the obligation to obtain a part 70 permit: All sources and source
categories that would be required to obtain a permit solely because
they are subject to part 60, subpart AAA--Standards of Performance
for New Residential Wood Heaters'').
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At this time, the EPA has not determined that title V permitting is
``impracticable, infeasible, or unnecessarily burdensome'' for sources
subject to subparts GG, KKKK, or KKKKa, and the EPA is not proposing to
exempt any such sources from title V permitting.
However, the EPA requests comment to better understand whether
there are circumstances in which the burdens and costs of going through
title V permitting, for sources, permitting authorities, and other
stakeholders and the public, would not be justified in light of the
purposes of title V to improve compliance with the Act's applicable
requirements, to provide transparency to the public concerning the
location and operation of stationary sources of air pollution, and to
ensure public participation in the process of permitting the operation
of such sources. The EPA specifically requests comment on whether there
are appropriate size-, emissions-, or other characteristics that could
be appropriately used to define sources that may warrant exemption
under CAA section 502(a), and what specific features of these sources
would justify such an exemption in light of the statutory criteria.
A memo from the EPA's 2012 NSPS Proposal describing the proposed
section 502(a) exemption from title V permitting requirements for non-
major stationary combustion turbines subject to subparts GG or KKKK is
available in the rulemaking docket.
G. Proposal of NSPS Subpart KKKKa Without Startup, Shutdown,
Malfunction Exemptions
In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C.
Cir. 2008), the United States Court of Appeals for the District of
Columbia Circuit (D.C. Circuit) vacated portions of two provisions in
the EPA's CAA section 112 regulations governing the emissions
[[Page 101348]]
of HAP during periods of SSM. Specifically, the court vacated the SSM
exemption contained in 40 CFR 63.6(f)(1) and (h)(1), holding that under
section 302(k) of the CAA, emissions standards or limitations must be
continuous in nature and that the SSM exemption violates the CAA's
requirement that some section 112 standards apply continuously. The EPA
has determined the reasoning in the court's decision in Sierra Club
applies equally to CAA section 111 because the definition of ``emission
standard'' in CAA section 302(k), and the embedded requirement for
continuous standards, also applies to the NSPS. Consistent with Sierra
Club v. EPA, we are proposing that standards in subpart KKKKa apply at
all times.
The NSPS general provisions in 40 CFR 60.11(c) currently exclude
opacity requirements during periods of startup, shutdown, and
malfunction (SSM) and the provision in 40 CFR 60.8(c) contains an
exemption from non-opacity standards. We are proposing in subpart KKKKa
specific requirements at 40 CFR 60.420a(e) that override the general
provisions for SSM provisions.
The EPA has attempted to ensure that the general provisions we are
proposing to override are inappropriate, unnecessary, or redundant in
the absence of the SSM exemption. We are specifically seeking comment
on whether we have successfully done so.
In proposing the standards in this rulemaking, the EPA has taken
into account startup and shutdown periods and, for the reasons
explained in this section of the preamble, has not proposed alternate
standards for those periods other than possible alternative
NOX standards during startup of stationary combustion
turbines. As discussed in more detail in section III.B.16.a., we are
requesting comment on whether to account for startup conditions based
on differences in load during the first 30 minutes of operation.
Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. Malfunctions,
in contrast, are neither predictable nor routine. Instead, they are, by
definition, sudden, infrequent, and not reasonably preventable failures
of emissions control, process, or monitoring equipment (40 CFR 60.2).
The EPA interprets CAA section 111 as not requiring emissions that
occur during periods of malfunction to be factored into development of
CAA section 111 standards. Nothing in CAA section 111 or in case law
requires that the EPA consider malfunctions when determining what
standards of performance reflect the degree of emission limitation
achievable through ``the application of the best system of emission
reduction'' that the EPA determines is adequately demonstrated. While
the EPA accounts for variability in setting emissions standards,
nothing in CAA section 111 requires the Agency to consider malfunctions
as part of that analysis. The EPA is not required to treat a
malfunction in the same manner as the type of variation in performance
that occurs during routine operations of a source. A malfunction is a
failure of the source to perform in a ``normal or usual manner'' and no
statutory language compels the EPA to consider such events in setting
CAA section 111 standards of performance. The EPA's approach to
malfunctions in the analogous circumstances (setting ``achievable''
standards under CAA section 112) has been upheld as reasonable by the
D.C. Circuit in U.S. Sugar Corp. v. EPA, 830 F.3d 579, 606-610 (D.C.
Cir. 2016).
H. Testing and Monitoring Requirements
Owners/operators of affected sources that (1) use water or steam
injection and (2) elect not to use a NOX CEMS, must then
continuously monitor the water- or steam-to-fuel ratio of the affected
source to demonstrate compliance. This requires the installation and
operation of a continuous monitoring system that monitors and records
both the fuel consumption and the ratio of water- or steam-to-fuel
being fired in the turbine. Owners/operators of affected combustion
turbines using dry combustion controls that elect not to use a
NOX CEMS must conduct performance testing at a minimum of
every 5 years. Owners/operators of combustion turbines using SCR must
use a NOX CEMS to demonstrate compliance with the applicable
emissions standards (owners/operators of combustion turbines not using
SCR may elect to use a NOX CEMS as an alternative to the
otherwise required monitoring).
I. Electronic Reporting
The EPA is proposing that owners and operators of stationary
combustion turbine facilities subject to NSPS subparts GG and KKKK, and
the proposed new subpart KKKKa, submit electronic copies of the initial
and periodic performance test reports, CEMS performance evaluation
reports (including relative accuracy test audits), and compliance
reports through the EPA's Central Data Exchange (CDX) using the
Compliance and Emissions Data Reporting Interface (CEDRI). A
description of the electronic data submission process is provided in
the memorandum Electronic Reporting Requirements for New Source
Performance Standards (NSPS) and National Emission Standards for
Hazardous Air Pollutants (NESHAP) Rules, available in the docket for
this action. The proposed rule requires that performance test results
collected using test methods that are supported by the EPA's Electronic
Reporting Tool (ERT) as listed on the ERT website \97\ at the time of
the test be submitted in the format generated through the use of the
ERT or an electronic file consistent with the xml schema on the ERT
website, and other performance test results be submitted in portable
document format (PDF) using the attachment module of the ERT.
Similarly, performance evaluation results of continuous emissions
monitoring systems (CEMS) measuring relative accuracy test audit (RATA)
pollutants that are supported by the ERT at the time of the test must
be submitted in the format generated through the use of the ERT or an
electronic file consistent with the xml schema on the ERT website, and
other performance evaluation results be submitted in PDF using the
attachment module of the ERT.
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\97\ See https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert.
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Specifically, the proposed rule requires that (1) for NSPS subpart
GG, the reports specified in 40 CFR 60.334, (2) for NSPS subpart KKKK,
the reports specified in 40 CFR 60.4375, and (3) for NSPS subpart
KKKKa, the reports specified in 40 CFR 60.4375a, owners and operators
use the appropriate spreadsheet template to submit information to
CEDRI. A draft version of the proposed template(s) for these reports is
included in the docket for this action.\98\ The EPA specifically
requests comment on the content, layout, and overall design of the
template(s).
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\98\ See Docket ID. No. EPA-HQ-OAR-2024-0419.
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Additionally, the EPA has identified two broad circumstances in
which electronic reporting extensions may be provided. These
circumstances are (1) Outages of the EPA's CDX or CEDRI, which preclude
an owner or operator from accessing the system and submitting the
required reports and (2) force majeure events, which are defined as
events that will be or have been caused by circumstances beyond the
control of the affected facility, its contractors, or any entity
controlled by the affected facility that prevent an owner or operator
from complying with the requirement to submit a report electronically.
Examples of force majeure events are acts of nature, acts of war or
terrorism, or equipment failure
[[Page 101349]]
or safety hazards beyond the control of the facility. The EPA is
providing these potential extensions to protect owners and operators
from noncompliance in cases where they cannot successfully submit a
report by the reporting deadline for reasons outside of their control.
In both circumstances, the decision to accept the claim of needing
additional time to report is within the discretion of the
Administrator, and reporting should occur as soon as possible.
The electronic submittal of the reports addressed in this proposed
rulemaking will increase the usefulness of the data contained in those
reports, is in keeping with current trends in data availability and
transparency, will further assist in the protection of public health
and the environment, will improve compliance by facilitating the
ability of regulated facilities to demonstrate compliance with
requirements and by facilitating the ability of delegated State, local,
Tribal, and territorial air agencies and the EPA to assess and
determine compliance, and will ultimately reduce burden on regulated
facilities, delegated air agencies, and the EPA. Electronic reporting
also eliminates paper-based, manual processes, thereby saving time and
resources, simplifying data entry, eliminating redundancies, minimizing
data reporting errors, and providing data quickly and accurately to the
affected facilities, air agencies, the EPA, and the public. Moreover,
electronic reporting is consistent with the EPA's plan \99\ to
implement Executive Order 13563 and is in keeping with the EPA's
agency-wide policy \100\ developed in response to the White House's
Digital Government Strategy.\101\ For more information on the benefits
of electronic reporting, see the memorandum Electronic Reporting
Requirements for New Source Performance Standards (NSPS) and National
Emission Standards for Hazardous Air Pollutants (NESHAP) Rules,
referenced earlier in this section.
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\99\ EPA's Final Plan for Periodic Retrospective Reviews, August
2011. Available at: https://www.regulations.gov/document?D=EPA-HQ-OA-2011-0156-0154.
\100\ E-Reporting Policy Statement for EPA Regulations,
September 2013. Available at: https://www.epa.gov/sites/default/files/2016-03/documents/epa-ereporting-policy-statement-2013-09-30.pdf.
\101\ Digital Government: Building a 21st Century Platform to
Better Serve the American People, May 2012. Available at https://obamawhitehouse.archives.gov/sites/default/files/omb/egov/digital-government/digital-government.html.
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J. Compliance Dates
Pursuant to CAA section 111(b)(1)(B), the effective date of the
final rule requirements in subpart KKKKa will be the promulgation date.
Affected sources that commence construction, reconstruction, or
modification after December 13, 2024 must comply with all requirements
of subpart KKKKa, no later than the effective date of the final rule or
upon startup, whichever is later.
K. Severability
This proposed action contains several discrete components, which
the EPA views as severable as a practical matter--i.e., they are
functionally independent and if finalized as proposed would operate in
practice independently of the other components. These discrete
components are generally delineated by the section headings within this
section III of this document. In general, each of the proposed BSER
determinations and associated emissions standards for each subcategory
function independently of the others, as do any differences in the
proposed rule associated with modified or reconstructed units. In
addition, the several other proposed changes to subparts GG and KKKK
and the associated proposals for new subpart KKKKa generally function
independently of one another. The EPA invites comment on the
severability of this proposed rule, and in particular whether any
components are not functionally independent, and if not, why not.
IV. Summary of Cost, Environmental, and Economic Impacts
A. What are the air quality impacts?
During the period 2025-2032, the EPA estimates that approximately
251 new stationary combustion turbines will be installed in the U.S.
and would be affected by this rule, as proposed. The EPA estimates that
153 of these combustion turbines will be in the electric utility power
sector. For affected combustion turbines in the electric utility power
sector, the proposed BSER in subpart KKKKa is generally consistent with
the control technologies in the baseline. That is, based on data
reported to the EPA, the Agency anticipates that new combined cycle
facilities (including combined cycle CHP facilities) would already have
plans to install the controls proposed in this NSPS, though in some
cases it is expected that the combined cycle turbines would have to
upgrade and/or operate the controls more intensively to meet the
proposed NSPS requirements in new subpart KKKKa. The EPA estimates the
majority of new simple cycle combustion turbines generating electricity
would be in the low load subcategory and have combustion controls
consistent with the proposed standards and would not be impacted by the
proposal. Approximately 10 percent of simple cycle turbines would
operate as intermediate load combustion turbines, but based on the
historical baseline, these combustion turbines would already have SCR.
It is expected that the intermediate load simple cycle EGUs would have
to upgrade and/or operate their NOX controls more
intensively to meet the proposed NSPS requirements in new subpart
KKKKa. The EPA anticipates that none of the five new non-combined cycle
CHP turbines \102\ would have SCR in the baseline and would have to
install SCR to comply with the proposed emission standards.\103\
Relative to the historic baseline, the proposed emission standards
would result in approximately 30 utility units being expected to incur
additional costs under the proposed NSPS requirements in subpart KKKKa.
Based on information in Form EIA-860 and a review of permits, the EPA
anticipates that 30 new small EGUs will be built during the analysis
period. Six of these combustion turbines would be low load units and
would be expected to install combustion controls in the baseline
consistent with the proposed emission standards. The EPA estimates that
the remaining 24 combustion turbines would be base load CHP facilities
and that the proposed BSER of combustion controls in combination with
SCR would apply. Furthermore, according to the data, four facilities
would have SCR in the baseline with permitted emission rates consistent
with the proposed emission standards in subpart KKKKa and thus would
not be impacted. However, one facility with SCR would need to upgrade
its SCR equipment to comply with the proposed NOX standards.
The remaining 19 small CHP facilities do not have SCR in the baseline.
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\102\ Non-combined cycle CHP turbines include a combustion
turbine engine and a HRSG and all the useful thermal output is used
for heating applications and not to generate additional electricity
(i.e., the facility does not have a steam turbine). These facilities
are sometimes referred to as simple cycle CHP turbines. Combined
cycle CHP turbines use a portion of the energy in the steam to
generate additional electricity and a portion for heating
applications.
\103\ Three of the CHP facilities without a steam turbine are
not listed in CAMPD.
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Based on information collected as part of the proposed combustion
turbine NESHAP rulemaking as discussed previously in sections II.D and
III.D.3, the EPA projects 52 direct mechanical drive combustion
turbines (e.g., compressors) would be subject to the proposed
NOX standards in subpart KKKKa. The EPA estimates that all
52
[[Page 101350]]
of these units would operate as base load combustion turbines and would
be subject to the proposed NOX emission standards in subpart
KKKKa based on application of the BSER of combustion controls in
combination with SCR. None of these 52 combustion turbines have SCR in
the baseline and would be projected to install SCR to comply with the
proposed emission standards. In total, this proposed rule is estimated
to reduce NOX emissions by 198 tons in 2027; 714 tons in
2028; 1,229 tons in 2029; 1,744 tons in 2030; 2,259 tons in 2031; and
2,659 tons in 2032. There are no expected SO2 reductions as
a result of the rule, as proposed. All emissions reductions estimates
and assumptions have been documented in the docket to the proposed
rule.
B. What are the secondary impacts?
The requirements in new subpart KKKKa are not anticipated to result
in significant energy impacts. The only energy requirement is a
potential small increase in fuel consumption, resulting from operating
the NOX control equipment and back pressure caused by an
add-on emission control device, such as an SCR. However, certain
entities would be able to comply with the proposed rule without the use
of add-on control devices. The EPA is soliciting comment on whether the
proposed requirements would result in fewer new combustion turbines
being constructed, modified, or reconstructed and if that would result
in increased generation from existing EGUs, including coal-fired EGUs,
or greater reliance on reciprocating engines to meet energy needs.
However, because the cost of combustion controls and SCR is a
relatively small percentage of the total costs associated with building
and operating combustion turbines, the EPA does not anticipate
significant secondary effects in terms of switching to other methods of
electricity generation or mechanical output.
The increased application of SCR is estimated to increase emissions
of ammonia (NH3) and carbon dioxide (CO2).
Therefore, proposed subpart KKKKa is estimated to increase
NH3 emissions by 21 tons in 2027; 65 tons in 2028; 108 tons
in 2029; 152 tons in 2030; 196 tons in 2031; and 232 tons in 2032.
CO2 emissions are estimated to increase by 1,597 tons in
2027; 4,921 tons in 2028; 8,244 tons in 2029; 11,568 tons in 2030;
14,891 tons in 2031; and 17,680 tons in 2032.
C. What are the cost impacts?
To comply with the requirements of this proposed rule, some units
will incur capital costs associated with installation of SCR or
upgrades to existing controls, while some units are expected to incur
increased operating costs of their existing controls to meet the
proposed requirements. These capital and increased operating costs were
estimated based on model plants from the DOE NETL flexible generation
report.\104\ For the analysis period 2025-2032, the present value of
the expected costs of the proposed rule is approximately $166 million
(2023$), while the equivalent annualized value of the costs over the
analysis period is $22.6 million (2023$).
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\104\ Oakes, M.; Konrade, J.; Bleckinger, M.; Turner, M.;
Hughes, S.; Hoffman, H.; Shultz, T.; and Lewis, E. (May 5, 2023).
Cost and Performance Baseline for Fossil Energy Plants, Volume 5:
Natural Gas Electricity Generating Units for Flexible Operation.
U.S. Department of Energy (DOE). Office of Scientific and Technical
Information (OSTI). Available at https://www.osti.gov/biblio/1973266.
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D. What are the economic impacts?
Economic impact analyses focus on changes in market prices and
output levels. If changes in market prices and output levels in the
primary markets are significant enough, impacts on other markets may
also be examined. Both the magnitude of costs needed to comply with a
rule and the distribution of these costs among affected facilities can
have a role in determining how the market will change in response to a
rule.
This proposed rule requires new, modified, or reconstructed
stationary combustion turbines to meet emission standards for the
release of NOX into the environment. While the units
impacted by these requirements are expected to already have installed
any required emissions control devices, some units are expected to
incur increased operating costs of their existing controls to meet the
proposed requirements. These changes may result in higher costs of
production for affected producers and impact broader product markets if
these costs are transmitted through market relationships.
However, because the increased operating costs discussed in the
previous section are very small in comparison to the sales of the
average owner of a combustion turbine, the costs of this proposed rule
are not expected to result in a significant market impact, regardless
of whether they are passed on to through market relationships or
absorbed by the firms. For more information on these impacts, please
refer to the economic impact analysis in the public docket.
E. What are the benefits?
Combustion turbines are a source of NOX and
SO2 emissions. The health effects of exposure to these
pollutants are briefly discussed in this section. Because the proposed
NSPS is expected to result in reductions of NOX emissions,
the EPA estimated the monetized benefits related to avoided premature
mortality and morbidity associated with reduced exposure to
NOX as a precursor to ozone and PM2.5 using a
``benefit-per-ton'' (BPT) approach.\105\ These results are summarized
below.
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\105\ See https://www.epa.gov/benmap/sector-based-pm25-benefit-ton-estimates and https://www.epa.gov/system/files/documents/2024-06/source-apportionment-tsd-2024.pdf.
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1. Benefits of NOX Reductions
Nitrogen dioxide (NO2) is the criteria pollutant that is
central to the formation of nitrogen oxides (NOX), and
NOX emissions are a precursor to ozone and fine particulate
matter.\106\
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\106\ Additional information is available in the ISA at https://www.epa.gov/isa/integrated-science-assessment-isa-oxides-nitrogen-health-criteria.
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Based on many recent studies discussed in the ozone ISA,\107\ the
EPA has identified several key health effects that may be associated
with exposure to elevated levels of ozone. Exposures to high ambient
ozone concentrations have been linked to increased hospital admissions
and emergency room visits for respiratory problems. Repeated exposure
to ozone may increase susceptibility to respiratory infection and lung
inflammation and can aggravate preexisting respiratory disease, such as
asthma. Prolonged exposures can lead to inflammation of the lung,
impairment of lung defense mechanisms, and irreversible changes in lung
structure, which could in turn lead to premature aging of the lungs
and/or chronic respiratory illnesses such as emphysema, chronic
bronchitis, and asthma.
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\107\ See Ozone ISA at https://assessments.epa.gov/isa/document/&deid=348522.
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Children typically have the highest ozone exposures since they are
active outside during the summer when ozone levels are the highest.
Further, children are more at risk than adults from the effects of
ozone exposure because their respiratory systems are still developing.
Adults who are outdoors and moderately active during the summer months,
such as construction workers and other outdoor workers, also are among
those with the highest exposures. These individuals, as well as people
with respiratory illnesses such as asthma, especially children with
asthma, experience reduced lung function and increased respiratory
symptoms, such as chest pain and cough, when exposed to relatively low
[[Page 101351]]
ozone levels during periods of moderate exertion.
NOX emissions can react with ammonia, VOCs, and other
compounds to form PM2.5.\108\ Studies have linked
PM2.5 (alone or in combination with other air pollutants)
with a series of negative health effects. Short-term exposure to
PM2.5 has been associated with premature mortality,
increased hospital admissions, bronchitis, asthma attacks, and other
cardiovascular outcomes. Long-term exposure to PM2.5 has
been associated with premature death, particularly in people with
chronic heart or lung disease. Children, the elderly, and people with
cardiopulmonary disease, such as asthma, are most at risk from these
health effects.
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\108\ PM2.5 health effects are discussed in detail in
the ISA at https://www.epa.gov/isa/integrated-science-assessment-isa-particulate-matter.
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Reducing the emissions of NOX from stationary combustion
turbines can help to improve some of the effects mentioned above,
either those directly related to NOX emissions, or the
effects of ozone and PM2.5 resulting from the combination of
NOX with other pollutants.
To estimate the monetized benefits of the NOX emission
reductions associated with this rulemaking, we multiplied the BPT
estimates for the industrial boilers sector by the corresponding
emission decreases expected from this proposed rule. Since EPA does not
have BPT values for the combustion turbines sector, EPA chose a
surrogate sector, industrial boilers, for the calculations. Industrial
boilers were chosen because both turbines and boilers generally fire
natural gas, and both have NOX controls, and vent to the
atmosphere through a stack. Since, since this proposed rule is an NSPS,
we do not know where the new turbines will be located. Therefore, we
used the national average BPT values for the industrial boilers BPT
sector and multiplied it by the emissions values. However, EPA
acknowledges the limitations of using surrogate sectors for BPT
estimations.
The benefit-per-ton estimates comprise several point estimates of
mortality and morbidity. The two benefits estimates are separated by
the word ``and'' to signify that they are two separate estimates and do
not represent lower- and upper-bound estimates. Because NOX
contributes to the formation of both PM2.5 and ozone, there
are two sets of BPT estimates for NOX, and these are added
together in the analysis. Considering that the estimated NOX
emission reductions from this rulemaking are annual, we estimated the
whole year with NOX as a PM2.5 precursor, then as
a 5-month seasonal precursor to ozone to simulate the warmer months.
Also, since some of the ammonia used in the SCR for NOX
reduction passes through the SCR and is emitted, we include
NH3 disbenefits in the health effects estimation.
For the proposed rule, the lower estimate of the present value in
2024 of the monetized NOX emission reductions is $200
million at a 2 percent discount rate, while the upper estimate is $670
million. The equivalent annualized value of the lower estimate is $27
million at a 2 percent discount rate, while the upper estimate is $92
million. All estimates are reported in 2023 dollars.
The EPA recognizes the uncertainty introduced by the use of the BPT
estimate based on industrial boilers. The EPA also has calculated the
value of NOX emissions reductions based on BPTs from two
alternative sectors: electricity generating units (EGUs) and oil and
gas transmission. Based on the EGU-based BPT, the lower estimate of the
present value in 2024 of the monetized NOX emission
reductions is $150 million at a 2 percent discount rate while the upper
estimate is $750 million. The equivalent annualized value of the lower
estimate is $21 million at a 2 percent discount rate while the upper
estimate is $100 million. Based on the oil and gas transmission-based
BPT, the lower estimate of the present value in 2024 of the monetized
NOX emission reductions is $180 million at a 2 percent
discount rate while the upper estimate is $620 million. The equivalent
annualized value of the lower estimate is $24 million at a 2 percent
discount rate while the upper estimate is $84 million.
2. Benefits of SO2 Reductions
High concentrations of sulfur dioxide (SO2) can cause
inflammation and irritation of the respiratory system, especially
during physical activity.\109\ Exposure to very high levels of
SO2 can lead to burning of the nose and throat, breathing
difficulties, severe airway obstruction, and can be life threatening.
Long-term exposure to persistent levels of SO2 can lead to
changes in lung function.
---------------------------------------------------------------------------
\109\ Health effects are discussed in detail in the ISA
available at https://www.epa.gov/isa/integrated-science-assessment-isa-sulfur-oxides-health-criteria.
---------------------------------------------------------------------------
Sensitive populations include asthmatics, individuals with
bronchitis or emphysema, children, and the elderly. PM can also be
formed from SO2 emissions. Secondary PM is formed in the
atmosphere through a number of physical and chemical processes that
transform gases, such as SO2, into particles. Overall,
emissions of SO2 can lead to some of the effects discussed
in this section--either those directly related to SO2
emissions, or the effects of PM resulting from the combination of
SO2 with other pollutants. Proposing to maintain the
standards of performance for emissions of SO2 from all
stationary combustion turbines would continue to protect human health
and the environment from the adverse effects mentioned above.
3. Disbenefits From Increased Emissions of NH3 and
CO2
Ammonia is a precursor to PM2.5 formation and an
increase in NH3 formation may lead to an increase in
PM2.5. An increase in PM2.5 is associated with
significant mortality and morbidity health outcomes such as premature
mortality, stroke, lung cancer, metabolic and reproductive effects,
among others. The estimated ammonia disbenefits were estimated using
the ammonia emission increases reported above with the same BPT
approach used for NOX based on applying a proxy sector BPT
value. For the proposed rule, the lower estimate of the present value
in 2024 of the monetized NH3 disbenefits is $76 million at a
2 percent discount rate, while the upper estimate is $160 million. The
equivalent annualized value of the lower estimate is $10 million at a 2
percent discount rate, while the upper estimate is $21 million. All
estimates are reported in 2023 dollars.
The climate impacts of the CO2 emissions increases
expected from this proposed rule were monetized using estimates of the
social cost of greenhouse gases. For this proposed rule, the present
value in 2024 of the monetized CO2 emission increases is
$12.6 million at a 2 percent discount rate, and the equivalent
annualized value is $1.72 million at a 2 percent discount rate. These
estimates are reported in 2023 dollars.
F. What analysis of environmental justice did we conduct?
For purposes of analyzing regulatory impacts, the EPA relies upon
its June 2016 ``Technical Guidance for Assessing Environmental Justice
in Regulatory Analysis,'' which provides recommendations that encourage
analysts to conduct the highest quality analysis feasible, recognizing
that data limitations, time, resource constraints, and analytical
challenges will vary by media and circumstance. The Technical Guidance
states that a regulatory action
[[Page 101352]]
may involve potential EJ concerns if it could: (1) Create new
disproportionate impacts on communities with EJ concerns; (2)
exacerbate existing disproportionate impacts on communities with EJ
concerns; or (3) present opportunities to address existing
disproportionate impacts on communities with EJ concerns through this
action under development. The EPA's EJ technical guidance states that
``[t]he analysis of potential EJ concerns for regulatory actions should
address three questions: (A) Are there potential EJ concerns associated
with environmental stressors affected by the regulatory action for
population groups of concern in the baseline? (B) Are there potential
EJ concerns associated with environmental stressors affected by the
regulatory action for population groups of concern for the regulatory
option(s) under consideration? (C) For the regulatory option(s) under
consideration, are potential EJ concerns created or mitigated compared
to the baseline?'' \110\ The environmental justice analysis is
presented for the purpose of providing the public with as full as
possible an understanding of the potential impacts of this proposed
action. The EPA believes that analyses like this can inform the
public's understanding, place EPA's action in context, and help,
identify and illustrate the extent of potential burdens and
protections. The EPA notes that analysis of such impacts is distinct
from the determinations proposed in this action under CAA section 111,
which are based solely on the statutory factors the EPA is required to
consider under that section.
---------------------------------------------------------------------------
\110\ U.S. Environmental Protection Agency (EPA). (June 2016).
Technical Guidance for Assessing Environmental Justice in Regulatory
Analysis. Section 3. Page 11. Available at https://www.epa.gov/environmentaljustice/technical-guidance-assessing-environmental-justice-regulatory-analysis.
---------------------------------------------------------------------------
The locations of newly constructed sources that will become subject
to the proposed Stationary Combustion Turbines and Stationary Gas
Turbines NSPS (40 CFR part 60, subpart KKKKa) are not known. Therefore,
to examine the potential for any EJ issues that might be associated
with the proposed NSPS, we performed a proximity demographic analysis
for 130 existing facilities that are currently subject to NSPS subpart
KKKK that have been constructed in the past five years. These represent
facilities that might modify or reconstruct in the future and become
subject to the proposed KKKKa requirements. This proximity demographic
analysis characterized the individual demographic groups of the
populations living within 5 km (~3 miles) and within 50 km (~31 miles)
of the existing facilities. The 5 km radius was used for the near
proximity because it captures a large enough population to provide
demographic data without excessive uncertainty for most facilities. We
do note, however, that one facility has zero population living within 5
km and another two facilities have less than 100 people living within 5
km. The EPA then compared the data from this analysis to the national
average for each of the demographic groups. It should be noted that
proximity to affected facilities does not indicate that any exposures
or impacts will occur and should not be interpreted as a direct measure
of exposure or impact. This limits the usefulness of proximity analyses
when attempting to answer questions from the EPA's EJ Technical
Guidance. The results of the proximity demographic analysis are shown
in Table 2 of this preamble. The percent of the population living
within 5 km of existing facilities with stationary combustion turbines
is above the national average for the following racial/ethnicity
demographics: Black (14 percent versus 12 percent nationally),
Hispanic/Latino (20 percent versus 19 percent nationally), and Asian (9
percent versus 6 percent nationally). In addition, the percent of
population living within 5 km of the existing facilities with
stationary combustion turbines is above the national average for the
following demographics: people living below the poverty level (15
percent versus 13 percent nationally), people living below two times
the poverty level (30 percent versus 29 percent nationally), linguistic
isolation (6 percent versus 5 percent nationally), and people with one
or more disabilities (13 percent versus 12 percent nationally). The
percent of the population living within 50 km of existing facilities
with stationary combustion turbines is above the national average for
the following racial/ethnicity demographics: Black (14 percent versus
12 percent nationally), Hispanic/Latino (22 percent versus 19 percent
nationally), and Asian (7 percent versus 6 percent nationally). In
addition, the percent of population living within 50 km of existing
facilities with stationary combustion turbines and stationary gas
turbines is above the national average for linguistic isolation (7
percent versus 5 percent nationally) and people with one or more
disabilities (13 percent versus 12 percent nationally).
Table 2--Proximity Demographic Assessment Results for Stationary Combustion Turbines NSPS
----------------------------------------------------------------------------------------------------------------
Population within Population within
Demographic group Nationwide 50 km of 130 5 km of 130
facilities facilities
----------------------------------------------------------------------------------------------------------------
Total Population....................................... 334,369,975 145,990,767 6,177,476
----------------------------------------------------------------------------------------------------------------
Race and Ethnicity by Percent
----------------------------------------------------------------------------------------------------------------
White.................................................. 58 52 52
Black.................................................. 12 14 14
American Indian and Alaska Native...................... 0.5 0.2 0.3
Asian.................................................. 6 7 9
Hispanic or Latino (white and nonwhite)................ 19 22 20
Other and Multiracial.................................. 4 4 4
----------------------------------------------------------------------------------------------------------------
Age by Percent
----------------------------------------------------------------------------------------------------------------
Age 0 to 17 years...................................... 22 21 19
Age 18 to 64 years..................................... 61 62 67
Age >= 65 years........................................ 17 16 14
----------------------------------------------------------------------------------------------------------------
[[Page 101353]]
Income by Percent
----------------------------------------------------------------------------------------------------------------
Below Poverty Level.................................... 13 12 15
Below 2x Poverty Level................................. 29 27 30
----------------------------------------------------------------------------------------------------------------
Education by Percent
----------------------------------------------------------------------------------------------------------------
Over 25 and without a High School Diploma.............. 11 11 10
----------------------------------------------------------------------------------------------------------------
Linguistically Isolated by Percent
----------------------------------------------------------------------------------------------------------------
Linguistically Isolated................................ 5 7 6
----------------------------------------------------------------------------------------------------------------
Disabilities by Percent
----------------------------------------------------------------------------------------------------------------
People with One or More Disabilities................... 12 13 13
----------------------------------------------------------------------------------------------------------------
Notes:
The demographic percentages are based on the 2020 Decennial Census' block populations, which are linked
to the Census' 2018-2022 American Community Survey (ACS) five-year demographic averages at the block group or
tract level. To derive demographic percentages, it is assumed a block's demographics are the same as the block
group or tract in which it is contained. Demographics are tallied for all blocks falling within the indicated
radius.
To avoid double counting, the ``Hispanic or Latino'' category is treated as a distinct demographic
category for these analyses. A person is identified as one of six racial/ethnic categories above: White,
Black, American Indian or Alaska Native, Asian, Other and Multiracial, or Hispanic/Latino. A person who
identifies as Hispanic or Latino is counted as Hispanic/Latino for this analysis, regardless of what race this
person may have also identified as in the Census.
As indicated above, the locations of any new stationary combustion
turbines that would be subject to NSPS subpart KKKKa are not known. In
addition, it is not known which existing turbines may be modified or
reconstructed and subject to NSPS subpart KKKKa. Thus, we are limited
in our ability to estimate the potential EJ impacts of this rulemaking.
However, we anticipate the changes to NSPS subpart KKKKa will generally
minimize future emissions in surrounding communities of new, modified,
or reconstructed turbines. Specifically, the EPA is proposing that the
standards should be revised downward based on the identification of SCR
as the BSER for limiting NOX for certain larger and/or
higher operating combustion turbines and based on updated information
concerning improved combustion control performance at all combustion
turbines firing natural gas. The changes will have beneficial effects
on air quality and public health for populations exposed to emissions
from new, modified, or reconstructed stationary combustion turbines and
will provide additional health protection for most populations,
including communities with EJ concerns.
The methodology and the results (including facility-specific
results) of the demographic analysis are presented in the document
titled Analysis of Demographic Factors for Populations Living Near
Existing Facilities Subject to the Stationary Combustion Turbines and
Stationary Gas Turbines NSPS (Subpart KKKK and KKKKa), which is
available in the docket for this action.
V. Statutory and Executive Order Reviews
Additional information about these statutes and Executive orders
can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 14094: Modernizing Regulatory Review
This proposed NSPS is a ``significant regulatory action'' as
defined in Executive Order 12866, as amended by Executive Order 14094.
Accordingly, the EPA submitted this proposed rule to OMB for Executive
Order 12866 review. Documentation of any changes made in response to
the Executive Order 12866 review is available in the docket. The EPA
prepared an economic analysis of the potential impacts associated with
this action. This analysis is discussed in section IV of this preamble
and is also available in the docket.
The RIA estimates the costs and monetized human health benefits
from 2025-2032 associated with the application of the proposed BSER to
stationary combustion turbines with a heat input at peak load equal to
or greater than 10.7 GJ/h (10 MMBtu/h), based on the higher heating
value (HHV) of the fuel, that commence construction, modification, or
reconstruction after the date of publication of this proposed rule in
the Federal Register. These costs and monetized human health benefits
are relative to the baseline of the existing NSPS (subpart KKKK). Table
3 below provides a summary of the estimated monetized benefits, costs,
and net benefits associated with the application of the proposed BSER
to these new, modified, or reconstructed stationary combustion turbines
and stationary gas turbines.
[[Page 101354]]
Table 3--Estimated Monetized Benefits, Costs, Disbenefits, Non-Monetized Impacts, and Net Benefits of Proposed
Combustion Turbines NSPS
----------------------------------------------------------------------------------------------------------------
Equivalent annualized value (EAV) (2
Costs and benefits Present value (PV) (2 percent discount percent discount rate in millions of
rate in millions of 2023$) 2023$)
----------------------------------------------------------------------------------------------------------------
Monetized benefits............. $195 and $674.......................... $26.7 and $92.0.
Alternative calculation of $150 and $750.......................... $21 and $100.
monetized benefits.
Total annual costs............. $166................................... $22.6.
Monetized disbenefits.......... $88.4 and $169......................... $12.1 and $23.0.
--------------------------------------------------------------------------------
Non-monetized impacts.......... Any other climate, health, and environmental impacts or costs associated with
increased use of existing emissions controls, including non-monetized impacts
of NOX and NH3 as well as effects of other criteria and hazardous air
pollutants.
----------------------------------------------------------------------------------------------------------------
Net benefits................... -$58.7 and $340........................ -$8.01 and $46.4.
----------------------------------------------------------------------------------------------------------------
Notes: Values rounded to three significant figures. Monetized benefits were calculated using BPT estimates. The
BPT estimates comprise several point estimates of mortality and morbidity. The two benefits estimates are
separated by the word ``and'' to signify that they are two separate estimates and do not represent lower- and
upper-bound estimates. Alternative calculation of monetized benefits reflects alternative assumptions
regarding the monetization of emissions changes.
B. Paperwork Reduction Act (PRA)
The information collection activities in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the PRA. The Information Collection Request (ICR) document
that the EPA prepared has been assigned EPA ICR number 2177.09. You can
find a copy of the ICR in the docket for this rulemaking, and it is
briefly summarized here.
Respondents/affected entities: Owners and operators of
new, modified, or reconstructed stationary combustion turbines.
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 5.
Frequency of response: Semi-annual.
Total estimated burden: 310 hours per year. Burden is
defined at 5 CFR 1320.3(b).
Total estimated cost: $36,000 per year, includes $0
annualized capital or operation & maintenance costs.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
Submit your comments on the Agency's need for this information, the
accuracy of the provided burden estimates and any suggested methods for
minimizing respondent burden to the EPA using the docket identified at
the beginning of this rulemaking. The EPA will respond to any ICR-
related comments in the final rule. You may also send your ICR-related
comments to OMB's Office of Information and Regulatory Affairs (OIRA)
using the interface at www.reginfo.gov/public/do/PRAMain. Find this
particular information collection by selecting ``Currently under
Review--Open for Public Comments'' or by using the search function. OMB
must receive comments no later than January 13, 2025.
C. Regulatory Flexibility Act (RFA)
I certify that this proposed NSPS will not have a significant
economic impact on a substantial number of small entities under the
RFA. The small entities subject to the requirements of this proposed
rule are private companies, investor-owned utilities, cooperatives,
municipalities, and sub-divisions that would seek to build and operate
stationary combustion turbines in the future. Based on an analysis of
the existing combustion turbines constructed over the past five years
and assuming that the percentage of small entities in that analysis is
representative of the percentage of small entities who will own
combustion turbines in the future, the EPA has estimated that one
turbine constructed in each year from 2028-2032 may be owned by a small
entity. Assuming that this entity will have sales that are an average
of the existing small entities, the affected small entity is estimated
to have annual compliance costs of 0.01 percent of its sales. Details
of this analysis are presented in the Economic Impact Analysis for the
New Source Performance Standards Review for Stationary Combustion
Turbines.
D. Unfunded Mandates Reform Act (UMRA)
This proposed NSPS does not contain an unfunded mandate of $100
million (adjusted annually for inflation) or more (in 1995 dollars) as
described in UMRA, 2 U.S.C. 1531-1538. The costs involved in this
action are estimated not to exceed $183 million in 2023$ ($100 million
in 1995$ adjusted for inflation using the GDP implicit price deflator)
or more in any one year.
E. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government.
Although the direct compliance costs may not be substantial, the
EPA nonetheless elected to consult 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. These 10
organizations representing elected State and local officials have been
identified by the EPA as the ``Big 10'' organizations appropriate to
contact for purpose of consultation with elected officials. Also, the
EPA invited air and
[[Page 101355]]
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. In the spirit of E.O.
13132, and consistent with EPA policy to promote communications between
State and local governments, the EPA specifically solicits comment on
this proposed action from State and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This proposed NSPS does not have Tribal implications as specified
in Executive Order 13175. The proposed rule will not have substantial
direct effects on Tribal governments, on the relationship between the
Federal government and Indian tribes, or on the distribution of power
and responsibilities between the Federal government and Indian tribes.
The EPA is not aware of any stationary combustion turbine owned or
operated by Indian Tribal governments. However, if there are any, the
effect of the proposed rule on communities of Tribal governments would
not be unique or disproportionate to the effect on other communities.
Thus, Executive Order 13175 does not apply to this proposed rule.
Because the EPA is aware of Tribal interest in these proposed rules
and consistent with the EPA Policy on Consultation and Coordination
with Indian Tribes, the EPA offered government-to-government
consultation with Tribes in April 2024.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
Executive Order 13045 directs Federal agencies to include an
evaluation of the health and safety effects of the planned regulation
on children in Federal health and safety standards and explain why the
regulation is preferable to potentially effective and reasonably
feasible alternatives. While the environmental health or safety risks
addressed by this action present a disproportionate risk to children
because children typically have the highest ozone exposures since they
are active outside during the summer when ozone levels are the highest
and children are more at risk than adults from the effects of ozone
exposure because their respiratory systems are still developing, this
action is not subject to Executive Order 13045 because it is not a
significant regulatory action under section 3(f)(1) of Executive Order
12866, as amended by Executive Order 14094.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This proposed NSPS is not a ``significant energy action'' because
it is not likely to have a significant adverse effect on the supply,
distribution or use of energy. The EPA does not expect a significant
change in retail electricity prices on average across the contiguous
U.S., coal-fired electricity generation, natural gas-fired electricity
generation, or utility power sector delivered natural gas prices.
I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51
This proposed action involves technical standards. Therefore, the
EPA conducted searches for the Review of New Source Performance
Standards for Stationary Combustion Turbines through the Enhanced
National Standards Systems Network (NSSN) Database managed by the
American National Standards Institute (ANSI). Searches were conducted
for EPA Methods 1, 2, 3A, 6, 6C, 7E, 8, 19, and 20 of 40 CFR part 60,
appendix A. No applicable voluntary consensus standards were identified
for EPA Methods 7E, 8, and 19. All potential standards were reviewed to
determine the practicality of the voluntary consensus standards (VCS)
for this rulemaking. One VCS were identified as an acceptable
alternative to EPA test methods for the purpose of this proposed rule.
The voluntary consensus standard ANSI/ASME PTC 19-10-1981 Part 10
(2010), ``Flue and Exhaust Gas Analyses'' is an acceptable alternative
to EPA Methods 6 and 7 manual portion only and not the instrumental
portion.
The search identified 13 VCS that were potentially applicable for
this proposed rule in lieu of EPA reference methods. However, these
have been determined to not be practical due to lack of equivalency,
documentation, validation of data and other important technical and
policy considerations. In this rule, the EPA is proposing to include in
a final EPA rule regulatory text for 40 CFR part 60, subpart KKKKa that
includes incorporation by reference. In accordance with requirements of
1 CFR 51.5, the EPA is proposing to incorporate by reference VCS ANSI/
ASME PTC 19.10-1981 Part 10, ``Flue and Exhaust Gas Analyses,'' a
method for quantitatively determining the gaseous constituents of
exhausts resulting from stationary combustion and includes a
description of the apparatus, and calculations used which are used in
conjunction with Performance Test Codes to determine quantitatively, as
an acceptable alternative to EPA Methods 6 and 7 of appendix A to 40
CFR part 60 for the manual procedures only and not the instrumental
procedures. The ANSI/ASME PTC 19.10-1981 Part 10 method incorporates
both manual and instrumental methodologies for the determination of
oxygen content. The manual method segment of the oxygen determination
is performed through the absorption of oxygen. This method is available
at the American National Standards Institute (ANSI) and the American
Society of Mechanical Engineers (ASME). Contact ANSI at 1899 L Street
NW, 11th floor, Washington, DC 20036; phone: (202) 293-8020; website:
https://www.ansi.org. Contact ASME at Two Park Avenue, New York, NY
10016-5990; phone (800) 843-2763; website: https://www.asme.org. The
incorporation by reference of certain other material that will be
included in the final rule was approved by the Director of the Federal
Register as of July 3, 2017.
For additional information, please see the August 27, 2024,
memorandum titled, Voluntary Consensus Standard Results for Review of
New Source Performance Standards for Stationary Combustion Turbines,
available in the rulemaking docket.
The EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially
applicable voluntary consensus standard (VCS) and to explain why such
standards should be used in this regulations.
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
For new sources constructed after the date of publication of this
proposed action under CAA section 111(b), the EPA believes that it is
not practicable to
[[Page 101356]]
assess whether the human health or environmental conditions that exist
prior to this action result in disproportionate and adverse effects on
communities with environmental justice concerns because the location
and number of new sources is unknown.
The determination that an impact is disproportionate is a policy
judgment, as discussed in the EJ Technical Guidance. While the
locations of newly constructed sources that will become subject to the
proposed action are not known, the EPA examined the potential for any
EJ issues that might be associated with the proposed NSPS by performing
a proximity demographic analysis for 130 existing facilities that are
currently subject to NSPS subpart KKKK. These represent facilities that
might modify or reconstruct in the future and become subject to the
proposed KKKKa requirements. This proximity demographic analysis is
summarized in section IV.F of this preamble.
Michael S. Regan,
Administrator.
[FR Doc. 2024-27872 Filed 12-12-24; 8:45 am]
BILLING CODE 6560-50-P