101306 Federal Register / Vol. 89, No. 240 / Friday, December 13, 2024 / Proposed Rules 

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: a-and-r-docket@epa.gov. 

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: ashley.john@epa.gov. 

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 

SPPDpublichearing@epa.gov. 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-combustionturbines-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 preregistered 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-combustionturbines-new-source-performance or 

contact the public hearing team at (888) 

372–8699 or by email at SPPDpublic

hearing@epa.gov. The last day to preregister 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-sourcesair-pollution/stationary-gas-andcombustion-turbines-new-sourceperformance. 

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-combustionturbines-new-source-performance. 


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

hearing@epa.gov 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 preregister 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 oaqpscbi@

epa.gov, 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 oaqpscbi@epa.gov 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 


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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-airpollution/stationary-gas-andcombustion-turbines-new-sourceperformance. 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-combustionturbines-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 


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Federal Register / Vol. 89, No. 240 / Friday, December 13, 2024 / Proposed Rules 101309 

1The 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. 

2Throughout 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. 

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 subcomponents 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. 

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. 

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 


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3See 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. 

4See the Research Summary Memo in the docket 

for this rulemaking for a summary of the results 

from this State permit search. 

5See the Combustion Turbine Manufacturer 

Specsheet Memo in the docket for this rulemaking 

for a summary of the review of turbine 

manufacturers’ specification sheets. 

6U.S. Environmental Protection Agency (EPA). 

RACT/BACT/LAER Clearinghouse (RBLC). 

Available at https://cfpub.epa.gov/rblc/. 

7U.S. Energy Information Administration (EIA). 

(June 12, 2024). Form EIA–860 data. Available at 

https://www.eia.gov/electricity/data/eia860/. 

8See 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. 

9See EPA–HQ–OAR–2024–0135, available at 

https://www.regulations.gov. 

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. 

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

• Combustion turbine manufacturer 

specifications sheets for NOX and other 

criteria pollutant emissions for common 

combustion turbine makes and models.5

• 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

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. 

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. 

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. 


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10See 89 FR 39798; May 9, 2024. 

11See, 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. 

12 For the PSD program, ‘‘regulated NSR 

pollutant’’ includes any criteria air pollutant and 

any other air pollutant that meets the requirements 

Continued 

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. 

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 newlyconstructed 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 stateof-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. 

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 


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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. 

13PSD 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. 

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 qualitybased 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. 

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-bycase basis, taking into account casespecific 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 nonair 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 


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14The EPA uses the higher heating value (HHV) 

when specifying heat input ratings. 

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. 

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. 


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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 


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15The 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. 

16Capacity 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. 

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. 

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 perton 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. 

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 


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17U.S. Environmental Protection Agency (EPA). 

Nitrogen Dioxide (NO2) Pollution. Available at 

https://www.epa.gov/no2-pollution/primarynational-ambient-air-quality-standards-naaqsnitrogen-dioxide. 

18Agency 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. 

19U.S. Environmental Protection Agency (EPA). 

Nitrogen Dioxide (NO2) Pollution. Available at 

https://www.epa.gov/no2-pollution/basicinformation-about-no2#Effects. 

20Our 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. 

21The 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. 

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

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 welldefined, 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. 

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 sizebased 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 nonnatural 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 nonnatural 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. 

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 


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22 If any of these conditions are applicable, the 

combustion turbine would be in this subcategory. 

23EGUs 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. 

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 °F,22 and 

HRSG units operating independent of 

the combustion turbine. 

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. 

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 


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24EGU 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). 

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-operatingmonth 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. 

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 mediumsized 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-operatingmonth 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 


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25The ambient temperature of combustion 

turbines located north of the Arctic Circle would 

often be below 0 °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. 

26Combustion 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. 

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 °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

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 partload 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 


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27A 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. 

is proposing two changes to the partload 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 partload 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. 

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 partload 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 


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28Net output is not reported to CAMPD. 

and BSER as in subpart KKKK. If at any 

point during an operating hour the 

ambient temperature is below 0 °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 outputbased 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 outputbased 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 grossand 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 nonnatural 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 fourload test is appropriate or whether a 

curve fit of three loads greater than 25 

percent load is sufficient. 

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 


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

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 outputbased 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 sizebased 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. 

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 


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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, nonnatural gas-fired combustion turbines is 

wet combustion controls and does not 

include SCR. 

TABLE 1—PROPOSED BSER AND NOX EMISSION STANDARDS

Combustion turbine type Combustion turbine fuel BSER 

NOX

emission 

standard 

(lb/MMBtu) 

NOX

emission rate 

equivalent 

(ppm) 

New or reconstructed with capacity factor ≤40 percent and base load rating ≤250 MMBtu/h.Natural gas ........................

Non-natural gas .................

Combustion controls .........

Combustion controls .........

0.092 

0.290 

25 

74 

New or reconstructed with capacity factor >40 percent and base load rating ≤250 MMBtu/h.Natural gas ........................

Non-natural gas .................

Combustion controls with 

SCR.

Combustion controls with 

SCR.

0.011 

0.035 

3 

9 

Modified combustion turbines, all loads with base 

load rating ≤250 MMBtu/h.

Natural gas ........................

Non-natural gas .................

Combustion controls .........

Combustion controls .........

0.092 

0.290 

25 

74 

New or reconstructed with capacity factor ≤20 percent and base load rating >250 MMBtu/h and 

≤850 MMBtu/h.

Natural gas ........................

Non-natural gas .................

Combustion controls .........

Combustion controls .........

0.092 

0.290 

25 

74 

New or reconstructed with capacity factor >20 percent and base load rating >250 MMBtu/h and 

≤850 MMBtu/h.

Natural gas ........................

Non-natural gas .................

Combustion controls with 

SCR.

Combustion controls with 

SCR.

0.011 

0.035 

3 

9 

Modified combustion turbines, all loads with base 

load rating >250 MMBtu/h and ≤850 MMBtu/h.

Natural gas ........................

Non-natural gas .................

Combustion controls .........

Combustion controls .........

0.092 

0.290 

25 

74 

New, modified, or reconstructed with capacity factor ≤20 percent and base load rating >850 

MMBtu/h.

Natural gas ........................

Non-natural gas .................

Combustion controls .........

Combustion controls .........

0.055 

0.150 

15 

42 

New, modified, or reconstructed with capacity factor >20 percent and base load rating >850 

MMBtu/h.

Natural gas ........................

Non-natural gas .................

Combustion controls with 

SCR.

Combustion controls with 

SCR.

0.011 

0.019 

3 

5 

New, modified, or reconstructed offshore combustion turbines, all sizes and loads.Natural gas ........................

Non-natural gas .................

Combustion controls .........

Combustion controls .........

0.092 

0.290 

25 

74 

Combustion turbines with base load rating ≤250 

MMBtu/h operating at part load, sites north of 

the Arctic Circle, and/or ambient temperatures of 

less than 0 °F.

Natural gas or non-natural 

gas.

Diffusion flame combustion 

controls.

0.58 150 

Combustion turbines with base load rating >250 

MMBtu/h operating at part load, sites north of 

the Arctic Circle, and/or ambient temperatures of 

less than 0 °F.

Natural gas or non-natural 

gas.

Diffusion flame combustion 

controls.

0.37 96 

Heat recovery units operating independent of the 

combustion turbine(s).

Natural gas or non-natural 

gas.

Combustion controls ......... 0.21 54 

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 


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30 In general, the addition of water or steam will 

not increase emissions of carbon monoxide (CO) or 

unburned hydrocarbons. However, at higher 

injection rates, emissions of CO and unburned 

hydrocarbons can increase. 

31 Innovative Steam Technologies. GTI. Accessed 

at https://otsg.com/industries/powergen/gti/. 

32Bahrami, 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. 

33Mitsubishi Power. Smart-AHAT (Advanced 

Humid Air Turbine. Accessed at https://

power.mhi.com/products/gasturbines/technology/ 

smart-ahat. 

34See the U.S. Environmental Protection 

Agency’s (EPA) Clean Air Markets Program Data at 

https://campd.epa.gov/data. 

35Based 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. 

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. 

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. 

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 postcombustion 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 °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. 

The SCR process is based on the 

chemical reduction of the NOX molecule 

via a nitrogen-based reducing agent 


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36An 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. 

(reagent) and a solid catalyst. To remove 

NOX, the reagent, commonly ammonia 

(NH3, anhydrous and aqueous) or ureaderived 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 metalbased 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 highefficiency combustion turbines subject 

to a NOX limit of 15 ppm have installed 

SCR. This correlation between highefficiency 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. 

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. 


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37The 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. 

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. 

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-operatingmonth 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 unitspecific 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 


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38Oakes, 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. 

39A BSER of diffusion flame combustion includes 

DLN that is less effective at reducing NOX than DLN 

under design conditions. 

40Throughout 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. 

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 lowemissions 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. 

8. BSER for Combustion Turbines 

Operating at Part Loads, Located North 

of The Arctic Circle, or Operating at 

Ambient Temperatures of Less Than 0 

°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

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 


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41This turbine model is guaranteed at 100 ppm 

NOX using dry combustion controls and 42 ppm 

using wet combustion controls. 

42The existing standard for non-natural gas 

mechanical drive applications is 150 ppm NOX. 

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. 

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 gasfired 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 NOXemitting 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 nonnatural 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 


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43Under 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. 

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 waterconstrained 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

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 gasfired 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 nonnatural 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 postcombustion 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 perton basis using the current NSPS 

emissions standard (25 ppm NOX) in 

subpart KKKK applicable to natural gasfired 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 perton 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 nonnatural 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 


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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 nonnatural gas fuels. 

iii. Costs 

The use of dry combustion controls 

that can achieve 25 ppm NOX has been 

standard equipment for natural gas-fired 


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44U.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. 

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 waterconstrained 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. 

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 postcombustion 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 


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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- 


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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 nonnatural 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, 


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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 postcombustion 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 


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45The 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. 

46The 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. 

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. 

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 nonnatural 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 mediumsized 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. 


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47The 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. 

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. 

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 nonnatural 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-calendarmonth 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 nonnatural 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 


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48While the EPA refers to this as the part-load 

standard, it includes an independent temperature 

component as well. 

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 °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. 

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 


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49The 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. 

50National 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/ALiterature-Review-of-Hydrogen-and-Natural-GasTurbines-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/practicalconsiderations-for-firing-hydrogen-versus-naturalgas/. 

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. 

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. 

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 gasfired 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 nonnatural 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 


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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. 

54Andersson, 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. 

55Andersson, 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/practicalconsiderations-for-firing-hydrogen-versus-naturalgas/. 

57Siemens Energy (2021). Overcoming technical 

challenges of hydrogen power plants for the energy 

transition. NS Energy. Accessed at https://

www.nsenergybusiness.com/news/overcomingtechnical-challenges-of-hydrogen-power-plants-forenergy-transition/. 

58Simon, F. (2021). GE eyes 100% hydrogenfueled power plants by 2030. Accessed at https:// 

www.euractiv.com/section/energy/news/ge-eyes100-hydrogen-fuelled-power-plants-by-2030/. 

59Patel, S. (2020). Siemens’ Roadmap to 100% 

Hydrogen Gas Turbines. Accessed at https://

www.powermag.com/siemens-roadmap-to-100- 

hydrogen-gas-turbines/. 

60See 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. 

61Siemens Energy (2021). Overcoming technical 

challenges of hydrogen power plants for the energy 

transition. NS Energy. Accessed at https://

www.nsenergybusiness.com/news/overcomingtechnical-challenges-of-hydrogen-power-plants-forenergy-transition/. 

62At 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 °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. 63An F-Factor is the ratio of the gas volume of 

the products of combustion to the heat content of 

the fuel. 64Simon, F. (2021). GE eyes 100% hydrogenfueled power plants by 2030. Accessed at https:// 

www.euractiv.com/section/energy/news/ge-eyes100-hydrogen-fuelled-power-plants-by-2030/. 65Patel, S. (2020). Siemens’ Roadmap to 100% 

Hydrogen Gas Turbines. Accessed at https://

www.powermag.com/siemens-roadmap-to-100- 

hydrogen-gas-turbines/. 66de Vos, Rolf (2022). Ten fundamentals to 

hydrogen readiness. Accessed at https:// 

Continued 

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 °F) compared to a natural 

gas flame (3,565 °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

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 lowemission (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

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

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. 

Several developers have announced 

installations with plans to initially cofire 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 


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www.siemens-energy.com/global/en/news/ 

magazine/2022/hydrogen-ready.html. 

67Power Magazine (2019). High Volume 

Hydrogen Gas Turbines Take Shape. Accessed at 

https://www.powermag.com/high-volumehydrogen-gas-turbines-take-shape/. 

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-ofenergy/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-overviewmarch24-2022-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%20

Power%20to%20Gas%20-%20Hydrogen%20for

%20Power%20Generation.pdf. 

71Siemens Energy Zero Emission Hydrogen 

Turbine Center. Accessed at https://www.siemensenergy.com/global/en/priorities/futuretechnologies/hydrogen/zehtc.html. 

72Siemens (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-turbinereadiness-white-paper.html. 

73Siemens (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. 

74Mitsubishi Heavy Industries. Accessed at 

https://solutions.mhi.com/power/decarbonizationtechnology/hydrogen-gas-turbine/. 

75Mitsubishi Heavy Industries (2021). Hydrogen 

Power Generation Handbook. Accessed at https://

solutions.mhi.com/sites/default/files/assets/pdf/eten/hydrogen_power-handbook.pdf. 

76See https://power.mhi.com/special/hydrogen. 

77National 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. 

78U.S. Energy Information Administration (EIA). 

Form 860. Schedule 3, Energy Storage Data. 2022. 

Available at https://www.eia.gov/electricity/data/ 

eia860/. 

is targeting development of 100 percent 

DLN hydrogen combustion capable 

turbines by 2025.67

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

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

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

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 cofiring 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. 

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 


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79 GE Vernova. LM6000 Hybrid EGT. Available at 

https://www.gevernova.com/gas-power/services/ 

gas-turbines/upgrades/hybrid-egt. 

80U.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. 

82Electric Power Research Institute (EPRI). 

Hybridized Gas Turbine Plus Battery Energy Storage 

Systems. September 2021. Available at https://

www.epri.com/research/products/00000000300

2022317. 

83The 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. 

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. 

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. 

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

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 onsite 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 


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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 lowsulfur 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 lowsulfur 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 lowsulfur 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 lowsulfur 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 subcategoryspecific 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 


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84Stationary Combustion Turbines: National 

Emission Standards for Hazardous Air Pollutants 

(NESHAP) accessible at: www.epa.gov/stationarysources-air-pollution/stationary-combustionturbines-national-emission-standards. 

85The 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). 

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. 

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. 

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 


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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 LowBtu 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 lowBtu 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 


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86At least one provider offers a portable 

combustion turbines that has base load rating 

greater than 250 MMBtu/h. 

87See, for example, 40 CFR 60.4200(e), 

60.4230(f), 60.40b(m), 60.40c(i), and 63.7491(j). 

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 shortterm 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. 

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, 


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

89The NOX emissions standard in table 1 to 

subpart JJJJ of part 60 for spark ignition natural gasfired reciprocating engines greater than or equal to 

500 HP is 82 ppmvd at 15 percent oxygen. 

90A 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. 

91All other standards except the intermediate and 

base load NOX standards would continue to be 

applicable. 

92A 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. 

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. 

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

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 shortterm standards for combustion turbines 

operating at capacity factors of greater 

than 20 percent, all combustion turbines 

would also be subject to a 12-calendarmonth 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 longterm 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 longterm 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. 

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. 


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93See 40 CFR 60.5580 and 60.5580a. 

94See 80 FR 64612 (October 23, 2015) and 89 FR 

39914–15 (May 9, 2024). 95See 40 CFR 60.332(g). 

96See, 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’’). 

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. 

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. 

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

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 


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101348 Federal Register / Vol. 89, No. 240 / Friday, December 13, 2024 / Proposed Rules 

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

98See Docket ID. No. EPA–HQ–OAR–2024–0419. 

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. 

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). 

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 


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Federal Register / Vol. 89, No. 240 / Friday, December 13, 2024 / Proposed Rules 101349 

99EPA’s Final Plan for Periodic Retrospective 

Reviews, August 2011. Available at: https://

www.regulations.gov/document?D=EPA-HQ-OA2011-0156-0154. 

100E-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/digitalgovernment/digital-government.html. 

102Non-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. 

103Three of the CHP facilities without a steam 

turbine are not listed in CAMPD. 

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 agencywide 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. 

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. 

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 


khammond on DSK9W7S144PROD with PROPOSALS3
101350 Federal Register / Vol. 89, No. 240 / Friday, December 13, 2024 / Proposed Rules 

104Oakes, 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. 

105See https://www.epa.gov/benmap/sectorbased-pm25-benefit-ton-estimates and https://

www.epa.gov/system/files/documents/2024-06/ 

source-apportionment-tsd-2024.pdf. 

106Additional information is available in the ISA 

at https://www.epa.gov/isa/integrated-scienceassessment-isa-oxides-nitrogen-health-criteria. 

107See Ozone ISA at https://assessments.epa.gov/ 

isa/document/&deid=348522. 

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 

$22.6 million (2023$). 

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. 

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

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. 

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 


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108PM2.5 health effects are discussed in detail in 

the ISA at https://www.epa.gov/isa/integratedscience-assessment-isa-particulate-matter. 

109Health effects are discussed in detail in the 

ISA available at https://www.epa.gov/isa/ 

integrated-science-assessment-isa-sulfur-oxideshealth-criteria. 

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. 

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. 

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 


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110U.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/technicalguidance-assessing-environmental-justiceregulatory-analysis. 

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. 

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 

Demographic group Nationwide 

Population 

within 50 km 

of 130 facilities 

Population 

within 5 km 

of 130 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 


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TABLE 2—PROXIMITY DEMOGRAPHIC ASSESSMENT RESULTS FOR STATIONARY COMBUSTION TURBINES NSPS— 

Continued 

Demographic group Nationwide 

Population 

within 50 km 

of 130 facilities 

Population 

within 5 km 

of 130 facilities 

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/lawsregulations/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. 


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TABLE 3—ESTIMATED MONETIZED BENEFITS, COSTS, DISBENEFITS, NON-MONETIZED IMPACTS, AND NET BENEFITS OF

PROPOSED COMBUSTION TURBINES NSPS 

Costs and benefits 

Present value (PV) 

(2 percent discount rate in 

millions of 2023$) 

Equivalent annualized value 

(EAV) 

(2 percent discount rate in 

millions of 2023$) 

Monetized benefits ................................................................................................ $195 and $674 ........................ $26.7 and $92.0. 

Alternative calculation of monetized benefits ....................................................... $150 and $750 ........................ $21 and $100. 

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: Semiannual. 

• 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 


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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 


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101356 Federal Register / Vol. 89, No. 240 / Friday, December 13, 2024 / Proposed Rules 

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 


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