`[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





-----------------------------------------------------------------------





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]]


-----------------------------------------------------------------------

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.

-----------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \1\ The base load rating is based on the heat input to the 
combustion turbine engine. Any additional heat input from duct 
burners used with heat recovery steam generating (HRSG) units or 
fuel preheaters is not included in the heat input value used to 
determine the applicability of this subpart to a given stationary 
combustion turbine. However, this subpart does apply to emissions 
from any HRSG and duct burners that are associated with a combustion 
turbine subject to this subpart.
---------------------------------------------------------------------------

C. What are the current NSPS requirements?

    The NSPS for stationary combustion turbines includes standards of 
performance to limit emissions of nitrogen oxide (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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \4\ See the Research Summary Memo in the docket for this 
rulemaking for a summary of the results from this State permit 
search.
---------------------------------------------------------------------------

     Combustion turbine manufacturer specifications sheets for 
NOX and other criteria pollutant emissions for common 
combustion turbine makes and models.\5\
---------------------------------------------------------------------------

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

     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\
---------------------------------------------------------------------------

    \6\ U.S. Environmental Protection Agency (EPA). RACT/BACT/LAER 
Clearinghouse (RBLC). Available at https://cfpub.epa.gov/rblc/.
---------------------------------------------------------------------------

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

    \7\ U.S. Energy Information Administration (EIA). (June 12, 
2024). Form EIA-860 data. Available at 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.
---------------------------------------------------------------------------

E. What outreach and engagement did the EPA conduct?

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

    \9\ See EPA-HQ-OAR-2024-0135, available at https://www.regulations.gov.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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

    The EPA's examination of potential EJ concerns in this proposed 
rule includes a proximity demographic analysis for 130 existing 
facilities that are currently subject to NSPS subpart KKKK. This 
represents facilities that might modify or reconstruct in the future 
and become subject to the proposed requirements in new subpart KKKKa. 
The locations of newly constructed sources that will become subject to 
subpart KKKKa are not known, thus, we are limited in our ability to 
estimate the potential EJ impacts of this rulemaking. As discussed in 
detail in section IV.F of this preamble, the results of the proximity 
demographic analysis indicate that the percent of population that is 
Black, Hispanic/Latino, or Asian living within 50 kilometers (km) of 
existing facilities with stationary combustion turbines is above the 
national average. In addition, the percent of population living within 
50 km of existing facilities with stationary combustion turbines is 
also above the national average for linguistic isolation and people 
with one or more disabilities. Furthermore, within 5 km of the existing 
facilities with stationary combustion turbines, the percent of 
population is above the national average for people living below the 
poverty level and people living below two times the poverty level.
    However, for the areas located downwind of any stationary 
combustion turbines that may be covered by new subpart KKKKa, we 
anticipate the proposed changes to the NSPS will generally reduce the 
potential emission impacts, in particular 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.
---------------------------------------------------------------------------

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

    Additionally, sources that install stationary combustion turbines 
that meet the applicability of NSPS subpart KKKKa will likely be 
subject to the New Source Review (NSR) preconstruction permitting 
program and, more specifically, the requirements of the ``major NSR'' 
program. Major NSR permitting requirements can offer protections for 
communities that are near sources that will experience an increase in 
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.
---------------------------------------------------------------------------

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

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

G. How does the EPA perform the NSPS review?

    As noted in section II of this preamble, CAA section 111 requires 
the EPA to, at least every 8 years, review and, if appropriate, revise 
the standards of performance applicable to new, modified, and 
reconstructed sources. If the EPA revises the standards of performance, 
those standards must reflect the degree of emission limitation 
achievable through the application of the BSER considering the cost of 
achieving such reduction and any non-air quality health and 
environmental impact and energy requirements. CAA section 111(a)(1).
    Section 111 of the CAA requires the EPA to consider a number of 
factors, including cost, in determining ``the best system of emission 
reduction . . . adequately demonstrated.'' CAA section 111(a)(1). The 
D.C. Circuit has long recognized that ``[CAA] section 111 does not set 
forth the weight that [ ] should [be] assigned to each of these 
factors;'' therefore, ``[the court has] granted the agency a great 
degree of discretion in balancing them.'' Lignite Energy Council v. 
EPA, 198 F.3d 930, 933 (D.C. Cir. 1999).
    In reviewing an NSPS to determine whether it is ``appropriate'' to 
revise the standards of performance, the EPA evaluates the statutory 
factors identified in the paragraphs above, which may include 
consideration of the following information:
     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.
---------------------------------------------------------------------------

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

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

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

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

[[Page 101317]]

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

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

a. Size-Based Subcategories
    This section discusses the EPA's proposals to create size-based 
subcategories for new, modified, and reconstructed stationary 
combustion turbines in new subpart KKKKa that are different from the 
size-based subcategory approach established in existing subpart KKKK. 
Specifically, the EPA is proposing size-based subcategories for 
combustion turbines that have base load ratings less than or equal to 
250 MMBtu/h of heat input, base load ratings greater than 250 MMBtu/h 
of heat input and less than or equal to 850 MMBtu/h, and base load 
ratings greater than 850 MMBtu/h of heat input. The EPA also is 
proposing to divide these subcategories of combustion turbines further 
based on their utilization (i.e., 12-calendar-month capacity factor), 
depending on whether they operate as low, intermediate, or base load 
units. The proposed BSER and applicable 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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

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

[[Page 101319]]

EPA seeks comment on at what point it is necessary to switch from lean 
premix/DLN combustion, which is only applicable to gaseous fuels, to 
diffusion flame combustion. Specifically, whether it is necessary to 
operate using diffusion flame combustion while utilizing natural gas 
prior to switching to fuel oil, and if this could create a compliance 
issue for hours during fuel switching. The EPA is soliciting comment on 
if this issue is technically accurate.
    A potential issue with removing the 50 percent fuel requirement is 
that this treatment could create an incentive for an owner/operator to 
combust a small amount of non-natural gas fuel and thereby obtain a far 
less stringent emissions standard. Therefore, the EPA is soliciting 
comment on what mitigating provisions would be necessary to ensure that 
this treatment only operates in the narrow window where it might be 
appropriate for legitimate technical reasons. Specifically, if the EPA 
were to remove the 50 percent fuel requirement, the EPA also solicits 
comment on limiting the number of hours a combustion turbine may burn 
multiple fuel types, through longer averaging times for determining 
compliance, and/or through mass-based caps on the total emissions that 
are permitted during periods of fuel switching.
    The EPA is proposing in new subpart KKKKa that the 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \39\ A BSER of diffusion flame combustion includes DLN that is 
less effective at reducing NOX than DLN under design 
conditions.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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/.
---------------------------------------------------------------------------

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
---------------------------------------------------------------------------

    \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/.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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/.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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/.
---------------------------------------------------------------------------

    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
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \78\ U.S. Energy Information Administration (EIA). Form 860. 
Schedule 3, Energy Storage Data. 2022. Available at https://www.eia.gov/electricity/data/eia860/.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \88\ 40 CFR 60.4200(e) and 60.4230(f).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \95\ See 40 CFR 60.332(g).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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'').
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \97\ See https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    \98\ See Docket ID. No. EPA-HQ-OAR-2024-0419.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 $22.6 million (2023$).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \106\ Additional information is available in the ISA at https://www.epa.gov/isa/integrated-science-assessment-isa-oxides-nitrogen-health-criteria.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \107\ See Ozone ISA at https://assessments.epa.gov/isa/document/&deid=348522.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \108\ PM2.5 health effects are discussed in detail in 
the ISA at https://www.epa.gov/isa/integrated-science-assessment-isa-particulate-matter.
---------------------------------------------------------------------------

    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`