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Subpart KKKK—Standards of Performance for Stationary Combustion Turbines 

Introduction 

§60.4300 What is the purpose of this subpart? 

This subpart establishes emission standards and compliance schedules for the control of emissions from stationary 

combustion turbines that commenced construction, modification, or reconstruction after February 18, 2005. 

Applicability 

§60.4305 Does this subpart apply to my stationary combustion turbine? 

(a) You are subject to this subpart if you own or operate a stationary combustion turbine that commenced 

construction, modification, or reconstruction after February 18, 2005, and that has a base load rating equal to or 

greater than 2.9 megawatts (MW) (10 million British thermal units per hour (MMBtu/h)), except as provided for 

in §60.4310. Any additional heat input from duct burners used with heat recovery steam generating 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. 

(b) For the purpose of this subpart, only the combustion turbine engine itself is used to determine whether the 

affected facility is new or reconstructed. Other equipment included in the definition of a stationary combustion 

turbine is not included when determining if a facility is new or reconstructed. 

(c) A combustion turbine engine subject to this subpart is not subject to subpart GG of this part. 

(d) Duct burners that do not burn any solid fuels when used with a heat recovery steam generating unit that is part 

of either a combined cycle combustion turbine or a combined heat and power (CHP) combustion turbine subject 

to this subpart are not subject to subpart D, Da, Db, or Dc of this part, as applicable. 

(e) If you own or operate either a stationary combustion turbine (including a combined cycle combustion turbine 

or a CHP combustion turbine) that commenced construction, modification, or reconstruction on or before 

February 18, 2005, you may submit a written petition to the Administrator requesting that the stationary 

combustion turbine be allowed to comply with the applicable requirements for modified units under this subpart 

as an alternative to complying with subpart GG of this part, and with subparts D, Da, Db, and Dc of this part, as 

applicable. If the Administrator or delegated authority approves the petitioner’s request, the affected facility must 

comply with the requirements for modified units under this subpart unless the combustion turbine engine is 

reconstructed or replaced with a new facility in the future. 

(f) If you are an owner or operator of a non-major 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 a non-major source under 

this subpart. Notwithstanding the previous sentence, you must continue to comply with the provisions of this 

subpart, as applicable. 

§60.4310 What stationary combustion turbines are not subject to this subpart? 

(a) An integrated gasification combined cycle electric utility steam generating unit subject to subpart Da of this 

part is not subject to this subpart. 

(b) A stationary combustion turbine used in a combustion turbine test cell/stand as defined in §60.4420 is not 

subject to this subpart. 

(c) A stationary combustion turbine subject to subpart Ea, subpart Eb, or subpart AAAA of this part is not subject 

to this subpart. 

(d) A stationary combustion turbine subject to an EPA approved State or Federal plan implementing under 

authority of Clean Air Act sections 111(d)/129 either subpart Cb or subpart BBBB of this part is not subject to 

this subpart. 

Emission Standards 

§60.4315 What pollutants are regulated by this subpart? 

The pollutants regulated by this subpart are nitrogen oxides (NOX) and sulfur dioxide (SO2). 

§60.4320 What NOX emissions standard must I meet? 

Comment [CF1]: The turbine engine is the 

technology that controls emissions. If it is new or 

reconstructed that emissions standard must apply. 

When a turbine is replaced at a combined cycle or 

CHP facility with a new turbine it is considered a 

new stationary combustion turbine and not 

reconstructed. 

If an affected facility adds a HRSG to an existing 

turbine it is still covered by subpart GG and D, Da, 

Db, or Dc. 

Comment [CF2]: HRSG burning a solid fuel 

would also have to comply with one of the steam 

generating units NSPS (D, Da, Db, or Dc). 

Comment [CF3]: Allow units to comply with 

subpart KKKK in place of GG and D, Da, Db, Dc. 

Comment [CF4]: Clarify title V exemption 

Comment [CF5]: Exempt turbines covered by the 

MSW rules from all the requirements 

(recordkeeping, reporting, emission standards, etc) 

of subpart KKKK. 
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(a) For each simple cycle stationary combustion turbine, except as provided for in paragraph (d) of this section, 

you must not discharge into the atmosphere from the affected facility any gases that contain NOX in excess of the 

applicable emissions standard as determined on a 4-operating hour basis and according to the requirements 

specified in paragraph (c) of this section. 

(b) For each combined-cycle combustion turbine or CHP combustion turbine except as provided for in paragraph 

(d) of this section, you must not discharge into the atmosphere from the affected facility any gases that contain 

NOX into the atmosphere from the affected facility in excess of the applicable emissions standard on a 30-

operating day basis and according to the requirements specified in paragraph (c) of this section. 

(c) For the purpose of determining compliance with the applicable emissions standard in paragraphs (a) and (b) of 

this section, you must meet the requirements specified in paragraphs (c)(1) through (c)(4), as applicable to your 

affected facility. 

(1) The NOX emissions standard that is applicable to your affected facility shall be determined on an operating 

hour basis except as provided for in paragraph (c)(2) of this section. Determining the hourly NOX emission 

standards for your affected facility requires recording hourly data and maintaining records according to the 

requirements in §60.4390. 

(2) As an alternative to the requirements specified in paragraph (c)(1) of this section, you may elect to use the 

lowest emissions standard determined using Table 1 of this subpart that is applicable to your affected facility for 

the entire required compliance period. 

(3) During each operating hour when only natural gas is combusted in the combustion turbine engine, you must 

meet the applicable NOX emissions standard determined using Table 1 of this subpart for a stationary combustion 

firing natural gas. During each operating hour when any fuel other than natural gas is combusted in the 

combustion turbine engine, you must meet the applicable NOX emissions standard determined using Table 1 of 

this subpart for a stationary combustion firing fuels other than natural gas. If multiple fuels are combusted during 

a given operating hour, then the highest applicable NOX emissions standard is applied for the entire operating 

hour. 

(4) If you have two or more combustion turbine engines connected to a single electric generator, each of the 

combustion turbine engines must meet the applicable NOX emissions standard determined using Table 1 of this 

subpart. 

(d) Stationary combustion turbines specified in paragraphs (d)(1) through (3) of this section are exempt from the 

applicable NOX emissions standard in paragraphs (a) and (b) of this section. 

(1) An emergency combustion turbine, as defined in §60.4420; 

(2) A stationary combustion turbine used for research and development of equipment for combustion turbine 

emissions control techniques or efficiency improvements as determined by the Administrator or delegated 

authority on a case-by-case basis; and 

(3) A stationary combustion turbine that combusts byproduct fuels for which a facility-specific NOX emissions 

standard has been established by the Administrator according to the requirements of paragraphs (d)(3)(i) and (ii). 

(i) You may request a facility-specific NOX emissions standard by submitting a written request to the 

Administrator or delegated authority explaining why your affected facility when burning the byproduct fuel is 

unable to comply with the applicable NOX emissions standard determined using Table 1 of this subpart. 

(ii) If the Administrator approves the request, a letter will be sent to the facility describing the facility-specific 

NOX emissions standard. You must use the compliance procedures detailed in the letter and make the letter 

available to the public. If the Administrator determines it is appropriate, the conditions and requirements of the 

letter can be reviewed and changed at any point. 

(e) For affected facilities for which construction, modification, or reconstruction commenced before [INSERT 

DATE 1 DAY AFTER PUBLICATION IN THE FEDERAL REGISTER], you must meet the NOX emissions 

standard applicable under this section to your affected facility during all times when the affected facility is 

operating except during periods of startup, shutdown, or malfunction. For each affected facility for which 

construction, reconstruction, or modification commenced after [INSERT DATE OF PUBLICATION IN THE 

FEDERAL REGISTER], you must meet the NOX emissions standard applicable under this section to your 

affected facility during all times when the affected facility is operating (including periods of startup, shutdown, 

Comment [CF6]: Add in equations to clarify how 

units with CEMS demonstrate compliance 

continuous compliance. The heat-input weighted 

average must be used for the lb/MWh and new 

lb/MMBtu options. The ppm option uses just the 

simple numerical average – compliance easier since 

no need to measure fuel use at the same time. 

Comment [CF7]: Take comment on changing 4-

hour average to an operating daily average with 

minimum of 3 hours of data or roll data over to next 

operating day 

Comment [CF8]: Require the natural gas 

standard only if the fuel combusted in the turbine 

engine meets the definition of natural gas for the 

entire operating hour

Comment [CF9]: Add in ability to petition for 

facility-specific NOx standard – similar to subpart 

Db. 
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and malfunction). 

§60.4330 What SO2 emissions standard must I meet? 

(a) For each stationary combustion turbine, except as provided for in paragraphs (b) through (g) of this section, 

you must not cause to be discharged into the atmosphere from the affected facility any gases that contain SO2 in 

excess of either: 

(1) 110 nanograms per Joule (ng/J) (0.90 pounds per megawatt-hour (lb/MWh)) gross energy output; or 

(2) 26 ng SO2/J (0.060 lb SO2/MMBtu) heat input. 

(b) As an alternative to the requirements of paragraph (a) of this section, for each stationary combustion turbine 

combusting 50 percent or more low-Btu gas per calendar month based on total heat input using the higher heating 

value of the fuel, you may limit the sulfur content of the fuel to no more than either: 

(1) 650 milligrams of sulfur per standard cubic meter (mg/scm) (28 grains (gr) of sulfur per 100 standard cubic 

feet (scf)); or 

(2) 65 ng SO2/J (0.15 lb SO2/MMBtu) heat input. 

(c) For each stationary combustion turbine located in a noncontinental area, you must not cause to be discharged 

into the atmosphere from the affected facility any gases that contains SO2 in excess of either: 

(1) 780 ng/J (6.2 lb/MWh) gross energy output; or 

(2) 180 ng SO2/J (0.42 lb SO2/MMBtu) heat input. 

(d) For each stationary combustion turbine for which the Administrator determines that the affected facility does 

not have access to natural gas and the removal of sulfur compounds from the fuel would cause more 

environmental harm than benefit, you must not cause to be discharged into the atmosphere from the affected 

facility any gases that contain SO2 in excess of either: 

(1) 780 ng/J (6.2 lb/MWh) gross energy output; or 

(2) 180 ng SO2/J (0.42 lb SO2/MMBtu) heat input. 

(e) A stationary combustion turbine that is subject to SO2 emission standards under either subpart J or Ja of this 

part is not subject to the SO2 emission standards in this subpart. 

(f) A combustion turbine that is subject to a federally enforceable requirement limiting the sulfur content of 

gaseous fuels combusted in the stationary combustion turbine to no more than 460 mg/scm (20 gr/100 scf) and/or 

for liquid fuels no more than 0.050 weight percent sulfur is not subject to the SO2 emission standards in this 

subpart. 

(g) For affected facilities for which construction, modification, or reconstruction commenced before [INSERT 

DATE 1 DAY AFTER PUBLICATION IN THE FEDERAL REGISTER], you must meet the SO2 emissions 

standard applicable under this section to your affected facility during all times when the affected facility is 

operating except during periods of startup, shutdown, or malfunction. For each affected facility for which 

construction, reconstruction, or modification commenced after [INSERT DATE OF PUBLICATION IN THE 

FEDERAL REGISTER], you must meet the SO2 emissions standard applicable under this section to your affected 

facility during all times when the affected facility is operating (including periods of startup, shutdown, and 

malfunction). 

General Compliance Requirements 

§60.4333 What are my general requirements for complying with this subpart? 

(a) You must operate and maintain your stationary combustion turbine, air pollution control equipment, and 

monitoring equipment in a manner consistent with good air pollution control practices for minimizing emissions 

at all times including during startup, shutdown, and malfunction. 

(b) If you own or operate a stationary combustion turbine subject to a NOX emissions standard in §60.4320, you 

must conduct an initial performance test according to §60.8 using the applicable methods in §60.4400 or 

§60.4405. Thereafter, unless you perform continuous monitoring consistent with §§60.4335, 60.4340(b), or 

60.4345, you must conduct subsequent performance tests according to the applicable requirements in paragraphs 

(b)(1) through (b)(6) of this section. 

(1) Except as provided for in paragraphs (b)(2) through (b)(5) of this section, you must conduct subsequent 

Comment [CF10]: Amended language allows for 

fuel mixing to achieve the SO2 standard. 

Comment [CF11]: Add in equations to clarify 

how units with CEMS demonstrate compliance 

continuous compliance. The heat-input weighted 

average must be used for the lb/MWh and new 

lb/MMBtu options. The ppm option uses just the 

simple numerical average – compliance easier since 

no need to measure fuel use at the same time. 

Comment [CF12]: Changed biogas to low-Btu 

gas 

Comment [CF13]: Add in equivalent 

concentration based alternative approximately 

equivalent to 500 ppm S by volume 

Comment [CF14]: SO2 standards in J and Ja 

more stringent than on KKKK. Amendment lowers 

burden and does not increase emissions. 

Comment [CF15]: Simplify compliance by 

exempting owner/operators of affected facilities 

burning only pipeline quality natural gas and 500 

ppm S distillate oil from the SO2 standard. Both fuels 

have potential SO2 emissions of less than 0.060 

lb/MMBtu. 

Comment [CF16]: Facilities with water/steam 

injection, parametric monitoring, or CEMS not 

required to perform an annual test. 
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performance tests within 12 calendar months following the date the previous performance test was required to be 

conducted. Performance tests must be separated by a minimum of 9 calendar months. 

(2) If the NOX emission result from the most recent performance test is less than or equal to 75 percent of the NOX

emissions standard for the stationary combustion turbine, you may reduce the frequency of subsequent 

performance tests to 24 calendar months following the date the previous performance test was required to be 

conducted. Performance tests must be separated by a minimum of 21 calendar months. If the results of any 

subsequent performance test exceed 75 percent of the NOX emissions standard for the stationary combustion 

turbine, you must resume annual performance testing. 

(3) An affected facility that has not operated for the 60 calendar days prior to the due date of a performance test is 

not required to perform the subsequent performance test until 45 calendar days after the next operating day. The 

delegated permitting authority must be notified of recommencement of operation consistent with §60.4375(d). 

(4) If you own or operate an affected facility that has operated 50 operating hours or less in total or with a 

particular fuel since the date the previous performance test was required to be conducted you may request an 

extension from the otherwise required performance test until after the affected facility has operated more than 50 

operating hours in total or with a particular fuel since the date of the previous performance test was required to be 

conducted. A request for an extension under this paragraph must be addressed to the relevant air division or office 

director of the appropriate Regional Office of the U.S. EPA as identified in §60.4(a) for his or her approval at 

least 30 calendar days prior to the date on which the performance test is required to be conducted. If an exemption 

is approved, a performance test must be conducted within 45 calendar days after the day the facility reaches 50 

hours of operation since the date the previous performance test was required to be conducted. When the facility 

has operated more than 50 operating hours since the date the previous performance test was required to be 

conducted, the delegated permitting authority must be notified consistent with §60.4375(e). 

(5) For a facility at which a group consisting of no more than five similar stationary combustion turbines (i.e., 

same manufacturer and model number) is operated, you may request the use of a custom testing schedule by 

submitting a written request to the Administrator or delegated authority. The minimum requirements of the 

custom schedule include the conditions specified in paragraphs (5)(i) through (v) of this section. 

(i) Emissions from the most recent performance test for each individual affected facility are 75 percent or less of 

the applicable standard; 

(ii) Each stationary combustion turbine uses the same emissions control technology; 

(iii) Each stationary combustion turbine is operated in a similar manner; 

(iv) Each stationary combustion turbine and its emissions control equipment are maintained according to the 

manufacturer’s recommended maintenance procedures; and 

(v) A performance test is conducted on each affected facility at least once every 5 calendar years. 

(6) A stationary combustion turbine subject to a NOX emissions standard in §60.4320 that exchanges the 

combustion turbine engine for an overhauled combustion turbine engine as part of an exchange program, must 

conduct an initial performance test according to §60.8 using the applicable methods in §60.4400. 

(c) Except as provided for in paragraphs (c)(1) or (2) of this section, for each stationary combustion turbine 

subject to a NOX emissions standard in §60.4320, you must demonstrate continuous compliance using a 

continuous emissions monitoring system (CEMS) for measuring NOX emissions according to the provisions in 

§60.4345. If your stationary combustion turbine is equipped with a NOX CEMS, those measurements must be 

used to determine excess emissions. 

(1) If your stationary combustion turbine uses water or steam injection but not post-combustion controls to meet 

the applicable NOX emissions standard in §60.4320, you may elect to demonstrate continuous compliance using 

either the pounds per million British thermal units (lb/MMBtu) or the part per million (ppm) standard according to 

the provisions in §60.4335. 

(2) If your stationary combustion turbine does not use water injection, steam injection, or post-combustion 

controls to meet the applicable NOX emissions standard in §60.4320, you may elect to demonstrate continuous 

compliance with either the lb/MMBtu or ppm standard according to the provisions in §60.4340. 

(d) An owner or operator of a stationary combustion turbine subject to an SO2 emissions standard in §60.4330 

must demonstrate compliance using one of the methods specified in paragraphs (d)(1) through (4) of this section. 

Comment [CF17]: Avoid consecutive testing that 

would satisfy 2 years requirements. Allow to test 3 

months early. 

Comment [CF18]: Add automatic extension of 

performance test requirement for owner/operators of 

turbines that are not operating. 

Comment [CF19]: Add ability of low capacity 

factor turbines to request an extension on the date of 

the required performance test. Fuel specific so can 

request extension on rarely fired backup fuels as 

well. 

Comment [CF20]: Multiple similar units only 

have to test once every 5 years. Since less that 75% 

of applicable standard is required 60.4333(b)(2) 

automatically applies 

Comment [CF21]: Turbine that are replaced as 

part of a turbine replacement maintenance program 

must be tested upon startup 

Comment [CF22]: Turbine that are replaced as 

part of a turbine replacement maintenance program 

must be tested upon startup 

Comment [CF23]: If facility has a CEMS it must 

use the readings to report excess emissions. 

Comment [CF24]: Sections 60.4335 and 60.4340 

do not require monitoring of the output so have to 

comply with one of the input-based options. 
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(1) Conduct an initial performance test according to §60.8 and use the applicable methods in §60.4415. 

Thereafter, you must conduct subsequent performance tests within 12 calendar months following the date the 

previous performance test was required to be conducted. Performance tests must be separated by a minimum of 9 

calendar months. An affected facility that has not operated for the 60 calendar days prior to the due date of a 

performance test is not required to perform the subsequent performance test until 45 calendar days after the next 

operating day; 

(2) Conduct an initial performance test according to §60.8 and use the applicable methods in §60.4415. 

Thereafter, conduct subsequent fuel sulfur analyses using the applicable methods specified in §60.4360 and at the 

frequency specified in §60.4365; 

(3) Conduct an initial performance test according to §60.8 and use the applicable methods in §60.4415. 

Thereafter, maintain records (such as a current, valid purchase contract, tariff sheet, or transportation contract) 

documenting that total sulfur content for the initial and subsequent fuel combusted in your stationary combustion 

turbine at all times does not exceed applicable conditions specified in §60.4370; or 

(4) Conduct an initial performance test according to §60.8 using the applicable methods in §60.4415. Thereafter, 

continue to monitor SO2 emissions using a CEMS according to the requirements specified in §60.4372. 

(e) If you elect to comply with an input-based standard (lb/MMBtu) and your affected facility includes use of one 

or more heat recovery steam generating units, then you must determine compliance with the applicable NOX and 

SO2 emission standards according to the procedures specified in paragraphs (e)(1) or (2) of this section as 

applicable to the heat recovery steam generating unit configuration used for your affected facility. 

(1) For a configuration where a single combustion turbine engine is exhausted through the heat recovery steam 

generating unit, you must measure both the emissions at the exhaust stack for the heat recovery steam generating 

unit and the fuel flow to the combustion turbine engine and any associated duct burners. 

(2) For a configuration where two or more combustion turbine engines are exhausted through a heat recovery 

steam generating unit, you must measure both the total emissions at the exhaust stack for the heat recovery steam 

generating unit and the total fuel flow to each combustion turbine engine and any associated duct burners. The 

applicable emissions standard for the affected facility is equal to the most stringent emissions standard for any 

individual combustion turbine engine. 

(f) If you elect to comply with an output-based standard (lb/MWh) and your affected facility includes use of one 

or more heat recovery steam generating units, then you must determine compliance with the applicable NOX and 

SO2 emission standards according to the procedures in paragraphs (f)(1), (2), or (3) of this section as applicable to 

the heat recovery steam generating unit configuration used for your affected facility. 

(1) For a configuration where a single combustion turbine engine is exhausted through the heat recovery steam 

generating unit, you must measure both the emissions at the exhaust stack for the heat recovery steam generating 

unit and the total electrical, mechanical energy, and useful thermal output of the stationary combustion turbine (as 

applicable). 

(2) For a configuration where two or more combustion turbine engines are exhausted through a single heat 

recovery steam generating unit, you must measure both the total emissions at the exhaust stack for the heat 

recovery steam generating unit, and the total electrical, mechanical energy, and useful thermal output of the heat 

recovery steam generating unit and each combustion turbine engine (as applicable). The applicable emissions 

standard for the affected facility is equal to the most stringent emissions standard for any individual combustion 

turbine engines. 

(3) For a configuration where your combustion turbine engines are exhausted through two or more heat recovery 

steam generating units which serve a common steam turbine or steam header, you must measure both the 

emissions at the exhaust stack for each heat recovery steam generating unit and the total electrical or mechanical 

energy output of each combustion turbine engine (as applicable). To determine the gross energy output of the 

steam produced by the heat recovery steam generating unit, you must develop a custom method and provide 

information, satisfactory to the Administrator or delegated authority, apportioning the gross energy output of the 

steam produced by the heat recovery steam generating units to each of the affected stationary combustion 

turbines. 

§60.4334 Affirmative Defense for Violation of Emission Standards During Malfunction. 

In response to an action to enforce the standards set forth in paragraphs §§60.4320 and 60.4330 you may assert an 

Comment [CF25]: Add in grace period so 

facilities do not have to startup just to test. 

Comment [CF26]: Clarify procedures to address 

more complicated (interconnected) configurations. 

Comment [CF27]: Essentially treat the 

configuration as a single affected facility except new 

and reconstruction is based on each individual 

turbine engine and the applicable standard is the 

most stringent standard for each turbine. 

Comment [CF28]: Include SO2 in output based 

option since might be firing fuel that does not meet 

input based standard. 

Comment [CF29]: Essentially treat the 

configuration as a single affected facility except new 

and reconstruction is based on each individual 

turbine engine and the applicable standard is the 

most stringent standard for each turbine. 
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affirmative defense to a claim for civil penalties for violations of such standards that are caused by malfunction, 

as defined at 40 CFR 60.2. Appropriate penalties may be assessed; however, if you fail to meet your burden of 

proving all of the requirements in the affirmative defense, the affirmative defense shall not be available for claims 

for injunctive relief. 

(a) To establish the affirmative defense in any action to enforce such a standard, you must timely meet the 

reporting requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that: 

(1) The violation: 

(i) Was caused by a sudden, infrequent, and unavoidable failure of air pollution control equipment, process 

equipment, or a process to operate in a normal or usual manner, and 

(ii) Could not have been prevented through careful planning, proper design or better operation and maintenance 

practices; and 

(iii) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; and 

(iv) Was not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and 

(2) Repairs were made as expeditiously as possible when a violation occurred. Off-shift and overtime labor were 

used, to the extent practicable to make these repairs; and 

(3) The frequency, amount and duration of the violation (including any bypass) were minimized to the maximum 

extent practicable; and 

(4) If the violation resulted from a bypass of control equipment or a process, then the bypass was unavoidable to 

prevent loss of life, personal injury, or severe property damage; and 

(5) All possible steps were taken to minimize the impact of the violation on ambient air quality, the environment, 

and human health; and 

(6) All emissions monitoring and control systems were kept in operation if at all possible, consistent with safety 

and good air pollution control practices; and 

(7) All of the actions in response to the violation were documented by properly signed, contemporaneous 

operating logs; and 

(8) At all times, the affected source was operated in a manner consistent with good practices for minimizing 

emissions; and 

(9) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate 

the primary causes of the malfunction and the violation resulting from the malfunction event at issue. The analysis 

must also specify, using best monitoring methods and engineering judgment, the amount of any emissions that 

were the result of the malfunction. 

(b) Report. The owner or operator seeking to assert an affirmative defense shall submit a written report to the 

Administrator or delegated authority with all necessary supporting documentation, that it has met the 

requirements set forth in paragraph (a) of this section. This affirmative defense report shall be included in the first 

periodic compliance, deviation report or excess emission report otherwise required after the initial occurrence of 

the violation of the relevant standard (which may be the end of any applicable averaging period). If such 

compliance, deviation report or excess emission report is due less than 45 days after the initial occurrence of the 

violation, the affirmative defense report may be included in the second compliance, deviation report, or excess 

emission report due after the initial occurrence of the violation of the relevant standard. 

Monitoring

§60.4335 How do I demonstrate compliance with my NOX emissions standard without using a NOX CEMS 

if I use water or steam injection? 

If you qualify and elect to demonstrate continuous compliance according to the provisions of §60.4333(c)(1), you 

must install, calibrate, maintain, and operate a continuous monitoring system to monitor and record the fuel 

consumption and the ratio of water or steam to fuel fired in the combustion turbine engine consistent with the 

requirements in §60.4342. Water or steam only needs to be injected when a fuel is being combusted that requires 

water or steam injection for compliance with the applicable NOX emissions standard. 

§60.4340 How do I demonstrate compliance with my NOX emissions standard without using a NOX CEMS 

if I do not use water or steam injection? 
Page 7 of 29 

(a) If you qualify and elect to demonstrate continuous compliance according to the provisions of §60.4333(c)(2), 

you must demonstrate compliance with the NOX emissions standard using the methods specified in either 

paragraphs (a)(1) through (3) of this section. 

(1) Conduct performance tests according to requirements in §60.4400; 

(2) Monitor the NOX emissions rate using the methodology in appendix E to part 75 of this chapter, or the low 

mass emissions methodology in §75.19; or 

(3) Install, calibrate, maintain, and operate an operating parameter continuous monitoring system according to the 

requirements specified in paragraph (b) of this section and consistent with the requirements specified in §60.4342. 

(b) Continuous operating parameter monitoring must be performed using the methods specified in paragraphs 

(b)(1) through (4) of this section as applicable to the stationary combustion turbine. 

(1) Selection of the operating parameters used to comply with this paragraph must be identified in the 

performance test report, and are subject to the review and approval of the delegated permitting authority. 

(2) For a lean premix stationary combustion turbine, you must continuously monitor the appropriate parameters to 

determine whether the unit is operating in low-NOX mode when low-NOX operation is required to comply with 

the applicable emission NOX standard. 

(3) For a stationary combustion turbine other than a lean premix stationary combustion turbine, you must define 

parameters indicative of the unit's NOX formation characteristics, and monitor these parameters continuously. 

(4) You must perform the parametric monitoring described in section 2.3 in appendix E to part 75 of this chapter 

or in §75.19(c)(1)(iv)(H). 

§60.4342 How do I monitor NOX control operating parameters? 

(a) If you monitor steam or water to fuel ratio according to §60.4335 or other parameters according to §60.4340, 

the applicable parameters must be continuously monitored and recorded during the performance test, to establish 

acceptable values and ranges. You may supplement the performance test data with engineering analyses, design 

specifications, manufacturer's recommendations, and other relevant information to define the acceptable 

parametric ranges more precisely. You must develop and keep on-site a parameter monitoring plan which explains 

the procedures used to document proper operation of the NOX emission controls. The plan must include the 

information specified in paragraphs (a)(1) through (6) of this section: 

(1) Identification of the parameters to be monitored and show there is a significant relationship to emissions and 

proper operation of the NOX emission controls; 

(2) Selected parameter ranges (or designated conditions) indicative of proper operation of the stationary 

combustion turbine NOX emission controls, or describe the process by which such range (or designated condition) 

will be established; 

(3) Explanation of the process you will use to make certain that you obtain data that are representative of the 

emissions or parameters being monitored (such as detector location, installation specification if applicable); 

(4) Description of quality assurance and control practices used to ensure the continuing validity of the data; 

(5) Description of the frequency of monitoring and the data collection procedures which you will use (e.g., you 

are using a computerized data acquisition over a number of discrete data points with the average (or maximum 

value) being used for purposes of determining whether an exceedance has occurred); and 

(6) Justification for the proposed elements of the monitoring. If a proposed performance specification differs from 

manufacturer recommendation, you must explain the reasons for the differences. You must submit the data 

supporting the justification, but you may refer to generally available sources of information used to support the 

justification. You may rely on engineering assessments and other data, provided you demonstrate factors which 

assure compliance or explain why performance testing is unnecessary to establish indicator ranges. 

(b) The ratio of water or steam to fuel and parameter continuous monitoring system ranges must be reestablished 

at least 60 calendar months following the previous calibration and each time the combustion turbine engine is 

replaced with an overhauled turbine engine as part of an exchange program. An affected facility that has not 

operated for 60 calendar days prior to the due date of a recalibration you are not required to perform the 

subsequent recalibration until 45 calendar days after the next operating day. 

§60.4345 How do I demonstrate compliance with my NOX emissions standard using a NOX CEMS? 

Comment [CF30]: NOx estimation protocol for 

gas-fired peaking and oil-fired peaking. Allow 

without approval. 

Comment [CF31]: Optional SO2, NOx, and CO2 

emission calculation for low mass emissions (LME) 

units. 

Low mass emissions excepted methodology, 

calculations, and values. Allow without approval. 

Comment [CF32]: Add in 60 month performance 

test to assure the control is still working properly. 

Comment [CF33]: Add in grace period so 

facilities do not have to startup just to verify 

calibration. 
Page 8 of 29 

(a) Each CEMS measuring NOX emissions used to meet the requirements of this subpart, must meet the 

requirements in paragraphs (a)(1) through (7) of this section. 

(1) You must install, certify, maintain, and operate a NOX monitor to determine the hourly average NOX

emissions in the units of the standard with which you are complying; 

(2) If you elect to comply with the ppm emissions standard, you must also install a diluent gas (oxygen (O2) or 

carbon dioxide (CO2)) monitor; 

(3) If you elect to comply with an input-based emissions standard, you must install, calibrate, maintain, and 

operate either a fuel flow meter (or flow meters) or an O2 or CO2 CEMS and a stack flow meter to continuously 

measure the heat input to the affected facility; 

(4) If you elect to comply with an output-based emissions standard, you must also install, calibrate, maintain, and 

operate both a watt meter (or meters) to continuously measure the gross electrical output from the affected facility 

and a stack flow meter. If you have a CHP combustion turbine and elect to comply with an output-based 

emissions standard, you must also install, calibrate, maintain, and operate meters to continuously determine the 

total useful recovered thermal energy. For steam this includes flow rate, temperature, and pressure. If you have a 

direct mechanical dive application and elect to comply with the output-based emissions standard you must submit 

a plan to the Administrator or delegated authority for approval of how gross energy output will be determined. 

(5) If you elect to comply with the part load NOX emissions standard, you must install, calibrate, maintain, and 

operate either a fuel flow meter (or flow meters) or an O2 or CO2 CEMS and a stack flow meter to continuously 

measure the heat input to the affected facility. 

(6) If you elect to comply with the temperature dependent NOX emissions standard, you must install, calibrate, 

maintain, and operate a thermometer to continuously monitor the ambient temperature. 

(7) If you burn natural gas with fuels other than natural gas and elect to comply with the fuels other than natural 

gas NOX emissions standard, you must install, calibrate, maintain, and operate a device to continuously monitor 

when a fuel other than natural gas fuel is combusted in the combustion turbine engine. 

(b) Each NOX CEMS must be installed and certified according to Performance Specification 2 (PS 2) in appendix 

B to this part. The span value must be 125 percent of the highest applicable standard or highest anticipated hourly 

NOX emissions rate. For stationary combustion turbines that do not use post-combustion technology to reduce 

emissions of NOX to comply with the requirements of this subpart, the delegated permitting authority may 

approve the use of the NOX and diluent CEMS that are installed and certified according to appendix A of part 75 

of this chapter in lieu of Procedure 1 in appendix F to this part and the requirements of §60.13 of this part, except 

that the relative accuracy test audit (RATA) of the CEMS must be performed on a lb/MMBtu basis. 

(c) During each full operating hour, both the NOX monitor and the diluent monitor must complete a minimum of 

one cycle of operation (sampling, analyzing, and data recording) for each 15-minute quadrant of the hour. For 

partial operating hours, at least one data point must be obtained with each monitor for each quadrant of the hour in 

which the unit operates. For operating hours in which required quality assurance and maintenance activities are 

performed on the CEMS, a minimum of two data points (one in each of two quadrants) are required for each 

monitor. 

(d) Each fuel flow meter must be installed, calibrated, maintained, and operated according to the manufacturer's 

instructions. Alternatively fuel flow meters that meet the installation, certification, and quality assurance 

requirements in appendix D to part 75 of this chapter are acceptable for use under this subpart. 

(e) Each watt meter, steam flow meter, and each pressure or temperature measurement device must be installed, 

calibrated, maintained, and operated according to manufacturer's instructions. 

(f) You must develop, submit to the delegated permitting authority for approval, maintain, and adhere to an onsite quality assurance (QA) plan for all of the continuous monitoring equipment you use to comply with this 

subpart. At a minimum, such a QA plan must address the requirements of §§60.13(d), (e), and (h) of this part. For 

the CEMS and fuel flow meters, the owner or operator of a stationary combustion turbine that does not use post 

combustion technology to reduce emissions of NOX to comply with the requirements of this subpart may, with 

approval of the delegated permitting authority, satisfy the requirements of this paragraph by implementing the QA 

program and plan described in section 1 in appendix B to part 75 of this chapter in lieu of the requirements in 

§60.13(d)(1). 

Comment [CF34]: Mechanical output not as 

straight forward to measure as electrical output in all 

situations. 

Comment [CF35]: Specifications and test 

procedures. 

Comment [CF36]: Optional SO2 emissions data 

protocol for gas-fired and oil-fired units. Allow 

without approval. 

Comment [CF37]: Quality assurance and quality 

control procedures 
Page 9 of 29 

§60.4350 How do I use the NOX CEMS data to determine excess emissions? 

(a) If you demonstrate continuous compliance using a CEMS for measuring NOX emissions, excess emissions are 

defined as the applicable compliance period for the stationary combustion turbine (either 4-operating hours or 30-

operating days), during which the average NOX emissions from your affected facility measured by the CEMS is 

greater than the applicable maximum allowable NOX emissions standard specified in §60.4320 as determined 

using the procedures specified in this section that apply to your stationary combustion turbine. 

(b) The NOX CEMS data for each operating hour as measured according to the requirements in §60.4345 must be 

used to determine the hourly average NOX emissions. The hourly average for a given operating hour is the 

average of all data points for the operating hour. However, for any periods during which the NOX, diluent, flow, 

watt, steam pressure, or steam temperature monitors (as applicable) are out-of-control, the data points are not used 

in determining the hourly average NOX emissions. All data points that are not collected during out-of-control 

periods must be used to determine the hourly average NOX emissions. 

(c) For each operating hour in which an hourly average is obtained, the data acquisition and handling system must 

calculate and record the hourly average NOX emissions in units of ppm or lb/MMBtu, using the appropriate 

equation from EPA Method 19 in appendix A-7 of this part. For any hour in which the hourly average O2

concentration exceeds 19.0 percent O2 (or the hourly average CO2 concentration is less than 1.0 percent CO2), a 

diluent cap value of 19.0 percent O2 or 1.0 percent CO2 (as applicable) may be used in the emission calculations. 

(d) Correction of measured NOX concentrations to 15 percent O2 is only allowed if you elect to comply with the 

ppm standard in Table 1. 

(e) Data used to meet the requirements of this subpart shall not include substitute data values derived from the 

missing data procedures of part 75 of this chapter, nor shall the data be bias adjusted according to the procedures 

of part 75 of this chapter. 

(f) All required fuel flow rate, steam flow rate, temperature, pressure, and megawatt data must be reduced to 

hourly averages. However, for any periods during which the flow, watt, steam pressure, or steam temperature 

monitors (as applicable) are out-of-control, the data points are not used in determining the appropriate hourly 

average value 

(g) Calculate the hourly average NOX emissions rate, in units of the emissions standard under §60.4320, using 

either ppm or lb/MMBtu for units complying with the input-based standard or equation 1 of this subpart for units 

complying with the output-based standard: 

(1) For a stationary combustion turbine complying with an output-based emissions standard use Equation 1. 

 

P

NO Q E x h   (Eq. 1) 

Where: 

 E = Hourly NOX emissions rate, in lb/MWh, 

 (NOX)h = Average hourly NOX emissions rate, in lb/MMBtu, 

 Q = Hourly heat input to the stationary combustion turbine, in MMBtu, measured using the fuel 

flowmeter(s), e.g., calculated using Equation D–15a in appendix D to part 75 of this chapter, 

an O2 or CO2 CEMS and a stack flow meter, or the methodologies in appendix F to part 75 of 

this chapter, and 

 P = Gross energy output of the stationary combustion turbine in MWh. 

(2) The gross energy output is calculated as the sum of the total electrical and mechanical energy generated by the 

combustion turbine engine, the additional electrical or mechanical energy (if any) generated by the steam turbine 

following the heat recovery steam generating unit, and the total useful thermal energy output that is not used to 

generate additional electricity or mechanical output, expressed in equivalent MWh, as calculated using Equations 

2 and 3 of this subpart: 

 P = ሺPeሻt

T + ሺPeሻcT + Ps + Po (Eq. 2) 

Comment [CF38]: Allow correction of O2 for 

owner/operators using the ppm standard. No need for 

units using the lb/MMBtu or lb/MWh standards to 

correct percent O2 measurements. 
Page 10 of 29 

Where: 

 P = Gross energy output of the stationary combustion turbine system in MWh, 

 (Pe)t = Electrical or mechanical energy output of the stationary combustion turbine in MWh, 

 (Pe)c = Electrical or mechanical energy output (if any) of the steam turbine in MWh, 

 Ps = Useful thermal energy of the steam, measured relative to ISO conditions, not used to generate 

additional electric or mechanical output, in MWh, and 

 Po = Other useful heat recovery, measured relative to ISO conditions, not used for steam generation or 

performance enhancement of the stationary combustion turbine. 

 T = Electric Transmission and Distribution Factor. Equal to 0.95 for CHP combustion turbine where 

at least 20.0 percent of the total gross useful energy output consists of electric or direct 

mechanical output and 20.0 percent of the total gross useful energy output consists of useful 

thermal output on an annual basis. Equal to 1.0 for all other combustion turbines. 

Btu MWh

Q H P m

s 3.413 10 / 6 

  (Eq. 3) 

Where: 

 Ps = Useful thermal energy of the steam, measured relative to ISO conditions, not used to 

generate additional electric or mechanical output, in MWh, 

 Qm = Measured steam flow in lb, 

H = Enthalpy of the steam at measured temperature and pressure relative to ISO conditions, in 

Btu/lb, and 

 3.413 x 106

 = Conversion factor from Btu to MWh. 

(3) For mechanical drive applications complying with the output-based standard, use equation 4 of this subpart: 

 

BL AL

NO E x m

  (Eq. 4) 

Where: 

 E = NOX emissions rate in lb/MWh, 

 (NOx)m = NOX emissions rate in lb/h, 

 BL = Manufacturer's base load rating of turbine, in MW, and 

 AL = Actual load as a percentage of the base load rating. 

(h) For each simple cycle stationary combustion turbines, excess NOX emissions are determined on a 4-operating 

hour averaging period basis using the NOX CEMS data and procedures specified in paragraphs (h)(1) through (4) 

of this section as applicable to the NOX emissions standard in Table 1 to this subpart. 

(1) For each 4-operating hour period, compute the 4-operating hour rolling average NOX emissions as the heat 

input weighted average of the hourly average of NOX emissions for a given operating hour and the 3 operating 

hours immediately preceding that operating hour using the applicable equation in paragraphs (h)(2) through (4) of 

this section. If the 4-operating hour period contains more than one operating hour with no data points (one or 

more continuous monitors was out-of-control for the entire hour), report the 4-operating hour rolling average NOX

emissions rate determined for the period as occurring during a period with monitor downtime. 

(2) If you elect to comply with the applicable heat input-based emissions rate standard, calculate both the 4-

operating hour rolling average NOX emissions rate and the applicable 4-operating hour rolling average NOX

emissions standard, calculated using hourly values from in Table 1, using Equation 5 of this subpart. 

Comment [CF39]: Add in equations to clarify 

how units with CEMS demonstrate compliance 

continuous compliance. The heat-input weighted 

average must be used for the lb/MWh and new 

lb/MMBtu options. The ppm option uses just the 

simple numerical average – compliance easier since 

no need to measure fuel use at the same time. 
Page 11 of 29 

 











 4

1

4

1

i

i

i

i i

Q

E Q

E (Eq. 5) 

Where: 

E = 4-operating hour rolling average NOX emissions (lb/MMBtu or ng/J), 

Ei = Hourly average NOX emissions rate or emissions standard for operating hour “i” (lb/MMBtu or 

ng/J), and 

Qi = Total heat input to stationary combustion turbine for operating hour “i” (MMBtu or J as 

appropriate). 

(3) If you elect to comply with the applicable output-based emissions rate standard, calculate the 4-operating hour 

rolling average NOX emissions rate using equation 6-1 of this subpart. Calculate the applicable 4-operating hour 

rolling average NOX emissions standard, calculated using hourly values from in Table 1, using Equation 6-2 of 

this subpart. 

 











 4

1

4

1

i

i

i

i i

P

E Q

E (Eq. 6-1) 

Where: 

E = 4-operating hour rolling average NOX emissions rate (lb/MWh or ng/J), 

Ei = Hourly average NOX emissions rate for operating hour “i (lb/MMBtu or ng/J), 

Qi = Total heat input to stationary combustion turbine for operating hour “i” (MMBtu or J as 

appropriate), and 

Pi = Total gross energy output from stationary combustion turbine for operating hour “i” (MWh or J). 

 











 4

1

4

1

i

i

i

i i

P

E P

E (Eq. 6-2) 

Where: 

E = 4-operating hour rolling average NOX emissions standard (lb/MWh or ng/J), 

Ei = Hourly NOX emissions standard for operating hour “i (lb/MWh or ng/J), and 

Pi = Total gross energy output from stationary combustion turbine for operating hour “i” (MWh or J). 

(4) If you elect to comply with the applicable concentration standard using a numerical average, calculate both the 

4-operating hour rolling average NOX emissions rate and the applicable 4-operating hour rolling average NOX

emissions standard, calculated using hourly values from in Table 1, using Equation 7 of this subpart. 

 

 

4

4

1

  i

Cavei

E (Eq. 7) 

Where: 

E = 4-operating hour rolling average NOX emissions (ppm), and 

Cavei = 1-hour average NOX concentration as determined using the procedure in §60.13(h) or emissions 

standard for operating hour “i” (ppm). 
Page 12 of 29 

(i) For each combined cycle combustion turbine and CHP combustion turbine, you must determine excess 

emissions on a 30 operating-day rolling average basis. The measured emissions rate is the NOX emissions 

measured by the CEMS for a given operating day and the 29 operating days immediately preceding that day. 

Once each day, calculate a new 30-operating day average measured emissions rate using all hourly average values 

based on non out-of-control NOX emission data for all operating hours during the previous 30-operating day 

operating period. Report any 30-operating day periods for which you have less than 75 percent data availability as 

monitor downtime. If you elect to comply with the applicable heat input-based emissions rate standard, calculate 

both the measured emissions rate and emissions standard using Equation 8 of this subpart. If you elect to comply 

with the applicable output-based emissions rate standard, calculate the measured emissions rate using Equations 

9-1 of this subpart and calculate the emissions standard using Equations 9-2 of this subpart. If you elect to comply 

with the applicable concentration standard using a numerical average, calculate the measured emissions rate and 

emissions standard using Equation 10 of this subpart. 

 











 n

i

i

n

i

i i

Q

E Q

E

1

1 (Eq. 8) 

Where: 

E = 30-operating day rolling average NOX measured emissions rate or emissions standard for 

combined cycle combustion turbines and CHP combustion turbines (lb/MMBtu or ng/J), 

Ei = Hourly average NOX emissions rate or emissions standard for non out-of-control operating hour 

“i” (lb/MMBtu or ng/J), 

Qi = Total heat input to stationary combustion turbine for non out-of-control operating hour “i” 

(MMBtu or J as appropriate), and 

n = Total number of non out-of-control operating hours in the 30 operating-day period. 

 











 n

i

i

n

i

i i

P

E Q

E

1

1 (Eq. 9-1) 

Where: 

E = 30-operating day average NOX measured emissions rate for combined cycle combustion turbines 

and CHP combustion turbines (lb/MWh or ng/J), 

Ei = Hourly average NOX emissions rate for non out-of-control operating hour “i” (lb/MMBtu or 

ng/J), 

Qi = Total heat input to stationary combustion turbine for non out-of-control operating hour “i” 

(MMBtu or J as appropriate), 

Pi = Total gross energy output from stationary combustion turbine for non out-of-control operating 

hour “i” (MWh or J), and 

n = Total number of operating non out-of-control hours in the 30 operating-day period. 

 











 n

i

i

n

i

i i

P

E P

E

1

1 (Eq. 9-2) 

Where: 

E = 30-operating day average NOX emissions standard for combined cycle combustion turbines and 

CHP combustion turbines (lb/MWh or ng/J), 
Page 13 of 29 

Ei = Hourly NOX emissions standard for non out-of-control operating hour “i” (lb/MWh or ng/J), 

Pi = Total gross energy output from stationary combustion turbine for non out-of-control operating 

hour “i” (MWh or J), and 

n = Total number of operating non out-of-control hours in the 30 operating-day period. 

 

n

C

E

n

i

 avei

  1 (Eq. 10) 

Where: 

E = 30-operating day rolling average NOX measured emissions rate or emissions standard for 

combined cycle combustion turbines and CHP combustion turbines (ppm), 

Cavei = 1-hour average NOX concentration as determined using the procedure in §60.13(h) or emissions 

standard for non out-of-control operating hour “i” (ppm), and 

n = Total number of operating hours in the 30 operating-day period. 

§60.4360 How do I use fuel sulfur analysis to determine the total sulfur content of the fuel combusted in my 

stationary combustion turbine? 

(a) If you elect to demonstrate compliance with a SO2 emissions standard according to §60.4333(d)(2), the fuel 

analyses may be performed either by you, a service contractor retained by you, the fuel vendor, or any other 

qualified agency as determined by the delegated permitting authority using the sampling frequency specified in 

§60.4365. 

(b) Representative fuel analysis samples may be collected either manually or by an automatic sampling system. 

For automatic sampling, following ASTM D5287 (incorporated by reference, see §60.17) for gaseous fuels or 

ASTM D4177 (incorporated by reference, see §60.17) for liquid fuels. For reference purposes when manually 

collecting gaseous samples, see Gas Processors Association Standard 2166 (incorporated by reference, see 

§60.17). For reference purposes when manually collecting liquid samples, see either Gas Processors Association 

Standard 2174 or the procedures for manual pipeline sampling in section 14 of ASTM D4057 (both of which are 

incorporated by reference, see §60.17). 

(c) Each collected fuel analysis sample must be analyzed for the total sulfur content of the fuel and heating value 

using the methods specified in paragraphs (c)(1) or (2) of this section, as applicable to the fuel type. 

(1) For the sulfur content of liquid fuels, ASTM D129, or alternatively D1266, D1552, D2622, D4294, or D5453 

(all of which are incorporated by reference, see §60.17). For the heating value of liquid fuels, ASTM D240 or 

D4809 (both of which are incorporated by reference, see §60.17); or 

(2) For the sulfur content of gaseous fuels, ASTM D1072, or alternatively D3246, D4468, or D6667 (all of which 

are incorporated by reference, see §60.17). If the total sulfur content of the gaseous fuel during the most recent 

compliance demonstration was less than half the applicable standard, ASTM D4084, D4810, D5504, or D6228, or 

Gas Processors Association Standard 2377 (all of which are incorporated by reference, see §60.17), which 

measure the major sulfur compounds, may be used. For the heating value of gaseous fuels, ASTM D1826, or 

alternatively D3588, D4891, or D7164, or Gas Processors Association Standard 2172 (all of which are 

incorporated by reference, see §60.17). 

§60.4365 How frequently must I determine the fuel sulfur content? 

(a) If you are complying with requirements in §60.4360, the total sulfur content of all fuels combusted in each 

stationary combustion turbine subject to an SO2 emissions standard in §60.4330 must be determined according to 

the schedule specified in paragraphs (a)(1) or (2) of this section, as applicable to the fuel type, unless you 

determine a custom schedule for the stationary combustion turbine according to paragraph (b) of this section. 

(1) Liquid fuel. Use one of the total sulfur sampling options and the associated sampling frequency described in 

sections 2.2.3, 2.2.4.1, 2.2.4.2, and 2.2.4.3 in appendix D to part 75 of this chapter (i.e. flow proportional 

sampling, daily sampling, sampling from the unit's storage tank after each addition of fuel to the tank, or sampling 

each delivery prior to combining it with liquid fuel already in the intended storage tank). 

(2) Gaseous fuel. If the fuel is supplied without intermediate bulk storage, the sulfur content value of the gaseous 

Comment [CF40]: Add heating value tests since 

SO2 standard is in lb/MMBtu. Clarify the original 

intent of the rule that the initial sulfur test must 

measure all sulfur compounds, not just H2S. 
Page 14 of 29 

fuel must be determined and recorded once per operating day. 

(b) Custom schedules. As an alternative to the requirements of paragraph (a) of this section, you may implement 

custom schedules for determination of the total sulfur content of gaseous fuels, based on the design and operation 

of the affected facility and the characteristics of the fuel supply using the procedures provided in either paragraph 

(b)(1) and (2) of this section. Either you or the fuel vendor may perform the sampling. As an alternative to using 

one of these procedures, you may use a custom schedule that has been substantiated with data and approved by 

the Administrator or delegated authority as a change in monitoring prior to being used to comply with the 

applicable standard in §60.4330. 

(1) You may determine and implement a custom sulfur sampling schedule for your stationary combustion turbine 

using the procedure specified in paragraphs (b)(1)(i) through (iv) of this section. 

(i) Obtain daily total sulfur content measurements for 30 consecutive operating days, using the applicable 

methods specified in this subpart. Based on the results of the 30 daily samples, the required frequency for 

subsequent monitoring of the fuel's total sulfur content must be as specified in paragraph (b)(1)(ii), (iii), or (iv) of 

this section, as applicable. 

(ii) If none of the 30 daily measurements of the fuel's total sulfur content exceeds half the applicable standard, 

subsequent sulfur content monitoring may be performed at 12-month intervals provided the fuel source or supplier 

does not change. If any of the samples taken at 12-month intervals has a total sulfur content greater than half but 

less than the applicable standard, follow the procedures in paragraph (b)(1)(iii) of this section. If any measurement 

exceeds the applicable standard, follow the procedures in paragraph (b)(1)(iv) of this section. 

(iii) If at least one of the 30 daily measurements of the fuel's total sulfur content is greater than half but less than 

the applicable standard, but none exceeds the applicable standard, then: 

(A) Collect and analyze a sample every 30 days for 3 months. If any sulfur content measurement exceeds the 

applicable standard, follow the procedures in paragraph (b)(1)(iv) of this section. Otherwise, follow the 

procedures in paragraph (b)(1)(iii)(B) of this section. 

(B) Begin monitoring at 6-month intervals for 12 months. If any sulfur content measurement exceeds the 

applicable standard, follow the procedures in paragraph (b)(1)(iv) of this section. Otherwise, follow the 

procedures in paragraph (b)(1)(iii)(C) of this section. 

(C) Begin monitoring at 12-month intervals. If any sulfur content measurement exceeds the applicable standard, 

follow the procedures in paragraph (b)(1)(iv) of this section. Otherwise, continue to monitor at this frequency. 

(iv) If a sulfur content measurement exceeds the applicable standard, immediately begin daily monitoring 

according to paragraph (c)(1)(i) of this section. Daily monitoring must continue until 30 consecutive daily 

samples, each having a sulfur content no greater than the applicable standard, are obtained. At that point, the 

applicable procedures of paragraph (b)(1)(ii) or (iii) of this section must be followed. 

(2) You may use the data collected from the 720-hour sulfur sampling demonstration described in section 2.3.6 in 

appendix D to part 75 of this chapter to determine and implement a sulfur sampling schedule for your stationary 

combustion turbine using the procedure specified in paragraphs (b)(2)(i) through (iii) of this section. 

(i) If the maximum fuel sulfur content obtained from any of the 720 hourly samples does not exceed half the 

applicable standard, then the minimum required sampling frequency must be one sample at 12 month intervals. 

(ii) If any sample result exceeds half the applicable standard, but none exceeds the applicable standard, follow the 

provisions of paragraph (b)(1)(iii) of this section. 

(iii) If the sulfur content of any of the 720 hourly samples exceeds the applicable standard, follow the provisions 

of paragraph (b)(1)(iv) of this section. 

§60.4370 How can I demonstrate compliance with my SO2 emissions standard using records of the fuel 

sulfur content? 

(a) If you elect to demonstrate compliance with a SO2 emissions standard according to §60.4333(d)(3), you must 

maintain on-site records (such as a current, valid purchase contract, tariff sheet, or transportation contract) 

documenting that total sulfur content for the fuel combusted in your stationary combustion turbine at all times 

does not exceed the conditions specified in paragraph (b) through (e) of this section, as applicable to your 

stationary combustion turbine. 
Page 15 of 29 

(b) If your stationary combustion turbine is subject to the SO2 emissions standard in §60.4330(a), then the fuel 

combusted must have a potential SO2 emissions rate of 26 ng/J (0.060 lb/MMBtu) heat input or less. 

(c) If your stationary combustion turbine is subject to the SO2 emissions standard in §60.4330(b), then the total 

sulfur content of the gaseous fuel combusted must be 650 (mg/scm) (28 gr/100 scf). 

(d) If your stationary combustion turbine is subject to the SO2 emissions standard in §60.4330(c) or (d), the total 

sulfur content of the fuel combusted must be: 

(1) For natural gas, 140 gr/100 scf or less. 

(2) For fuel oil, 0.40 weight percent (4,000 ppmw) or less. 

(3) For other fuels, potential SO2 emissions of 180 ng/J (0.42 lb/MMBtu) heat input or less. 

(e) Representative fuel sampling data following the procedures specified in section 2.3.1.4 or 2.3.2.4 in appendix 

D to part 75 of this chapter documenting that the fuel meets the part 75 requirements to be considered either 

pipeline natural gas or natural gas. 

§60.4372 How do I demonstrate compliance with my SO2 emissions standard and determine excess 

emissions using a SO2 CEMS? 

(a) If you demonstrate continuous compliance using a CEMS for measuring SO2 emissions, excess emissions are 

defined as the applicable averaging period, either 4-operating hour or 30-operating day, during which the average 

SO2 emissions from your stationary combustion turbine measured by the CEMS exceeds the applicable SO2

emissions standard specified in §60.4330 as determined using the procedures specified in this section that apply to 

your stationary combustion turbine. 

(b) You must install, calibrate, maintain, and operate a CEMS for measuring SO2 concentrations and either O2 or 

CO2 concentrations at the outlet of your stationary combustion turbine, and record the output of the system. 

(c) The 1-hour average SO2 emissions rate measured by a CEMS must be expressed in ng/J or lb/MMBtu heat 

input and must be used to calculate the average emissions rate under §60.4330. 

(d) You must use the procedures for installation, evaluation, and operation of the CEMS as specified in §60.13 

and paragraphs (d)(1) through (3) of this section. 

(1) Each CEMS must be operated according to the applicable procedures under Performance Specifications 1, 2, 

and 3 in appendix B of this part; 

(2) Quarterly accuracy determinations and daily calibration drift tests must be performed according to Procedure 1 

in appendix F of this part; and 

(3) The span value of the SO2 CEMS at the outlet from the SO2 control device (or outlet of the stationary 

combustion turbine if no SO2 control device is used) must be 125 percent of either the highest applicable standard 

or highest potential SO2 emissions rate of the fuel combusted. 

(e) Correction of measured SO2 concentrations to 15 percent O2 is not allowed. 

(f) If you have installed and certified a SO2 CEMS that meets the requirements of part 75 of this chapter, the 

delegated permitting authority can approve that only quality assured data from the CEMS must be used to identify 

excess emissions under this subpart. You must report periods where the missing data substitution procedures in 

subpart D of part 75 are applied as monitoring system downtime in the excess emissions and monitoring 

performance report required under §60.7(c). 

(g) All required fuel flow rate, steam flow rate, temperature, pressure, and megawatt data must be reduced to 

hourly averages. 

(h) Calculate the hourly average SO2 emissions rate, in units of the emissions standard under §60.4330, using 

lb/MMBtu for units complying with the input-based standard or using equation 11 of this subpart for units 

complying with the output-based standard: 

(1) For simple-cycle operation: 

 

P

SO Q E h   2 (Eq. 11) 

Where: 

Comment [CF41]: No need to list 20 gr/100 scf 

natural gas or 500 ppm S distillate since already 

exempt from the SO2 standard. 

Comment [CF42]: Add in procedures to use a 

SO2 CEMS.

Comment [CF43]: Since no ppm standard 

correction is not necessary. 
Page 16 of 29 

 E = Hourly SO2 emissions rate, in lb/MWh, 

 (SO2)h = Average hourly SO2 emissions rate, in lb/MMBtu, 

 Q = Hourly heat input rate to the stationary combustion turbine, in MMBtu, measured using 

the fuel flow meter(s), e.g., calculated using Equation D–15a in appendix D to part 75 of 

this chapter, an O2 or CO2 CEMS and a stack flow meter, or the methodologies in 

appendix F to part 75 of this chapter, and 

 P = Gross energy output of the stationary combustion turbine in MWh. 

(2) The gross energy output is calculated as the sum of the total electrical and mechanical energy generated by the 

stationary combustion turbine, the additional electrical or mechanical energy (if any) generated by the steam 

turbine following the heat recovery steam generating unit, and the total useful thermal energy output that is not 

used to generate additional electricity or mechanical output, expressed in equivalent MWh, as calculated using 

Equations 12 and 13 of this subpart 

P = ሺPeሻt

T + ሺPeሻc் + Ps + Po (Eq. 12) 

Where: 

 P = Gross energy output of the stationary combustion turbine system in MWh, 

 (Pe)t = Electrical or mechanical energy output of the stationary combustion turbine in MWh, 

 (Pe)c = Electrical or mechanical energy output (if any) of the steam turbine in MWh, 

 Ps = Useful thermal energy of the steam, measured relative to ISO conditions, not used to generate 

additional electric or mechanical output, in MWh, and 

 Po = Other useful heat recovery, measured relative to ISO conditions, not used for steam generation or 

performance enhancement of the stationary combustion turbine. 

 T = Electric Transmission and Distribution Factor. Equal to 0.95 for CHP combustion turbine where 

at least 20.0 percent of the total gross useful energy output consists of electric or direct 

mechanical output and 20.0 percent of the total gross useful energy output consists of useful 

thermal output on an annual basis. Equal to 1.0 for all other combustion turbines. 

Btu MWh

Q H P m

s 3.413 10 / 6 

  (Eq. 13) 

Where: 

 Ps = Useful thermal energy of the steam, measured relative to ISO conditions, not used to 

generate additional electric or mechanical output, in MWh, 

 Qm = Measured steam flow rate in lb, 

 H = Enthalpy of the steam at measured temperature and pressure relative to ISO conditions, in 

Btu/lb, and 

 3.413 x 106

 = Conversion factor from Btu to MWh. 

(3) For mechanical drive applications complying with the output-based standard, use equation 14 of this subpart: 

 

BL AL

SO

E 2 m

  (Eq. 14) 

Where: 

 E = SO2 emissions rate in lb/MWh, 

 (SO2)m = SO2 emissions rate in lb/h, 

 BL = Manufacturer's base load rating of turbine, in MW, and 

 AL = Actual load as a percentage of the base load rating. 

(i) For stationary combustion turbines other than combined cycle combustion turbines and CHP combustion 

turbines, you must determine excess emissions on a 4-operating hour rolling average basis. The “4-operating hour 
Page 17 of 29 

rolling average SO2 measured emissions rate” is the SO2 emissions measured by the CEMS for a given operating 

hour and the 3 consecutive operating hours immediately preceding that hour expressed in the units appropriate for 

the SO2 emissions standard that is applied to your stationary combustion turbine. Each operating hour, calculate 

the 4-operating hour rolling average SO2 measured emissions rate using all of the non out-of-control SO2 emission 

data obtained during the previous 4-operating hour operating period. If the 4-operating hour period contains more 

than one operating hour with no data points (one or more CEMS was out-of-control for the entire hour), report the 

4-operating hour rolling average SO2 emissions rate determined for the period as occurring during a period with 

monitor downtime. If you elect to comply with the applicable heat input-based emissions rate standard, calculate 

both the measured emissions rate and the emissions standard using Equation 15 of this subpart. If you elect to 

comply with the applicable output-based emissions standard, calculate the measured emissions rate using 

Equation 16-1 of this subpart and calculate the emissions standard using equation 16-2 of this subpart. 

 











 4

1

4

1

i

i

i

i i

Q

E Q

E (Eq. 15) 

Where: 

E = 4-operating hour rolling average SO2 measured emissions rate or emissions standard for 

stationary combustion turbines other than combined cycle combustion turbines and CHP 

combustion turbines (lb/MMBtu or ng/J), 

Ei = Hourly average SO2 emissions rate or emissions standard for non out-of-control operating hour 

“i” (lb/MMBtu or ng/J), and 

Qi = Total heat input to stationary combustion turbine for non out-of-control operating hour “i” 

(MMBtu or J as appropriate). 

 











 4

1

4

1

i

i

i

i i

P

E Q

E (Eq. 16-1) 

Where: 

E = 4-operating hour rolling average SO2 measured emissions rate for stationary combustion turbines 

other than combined cycle combustion turbines and CHP combustion turbines (lb/MWh or ng/J), 

Ei = Hourly average SO2 emissions rate for non out-of-control operating hour “i” (lb/MMBtu or ng/J), 

Qi = Total heat input to stationary combustion turbine for non out-of-control operating hour “i” 

(MMBtu or J as appropriate), and 

Pi = Total gross energy output from stationary combustion turbine for non out-of-control operating 

hour “i” (MWh or J). 

 











 4

1

4

1

i

i

i

i i

P

E P

E (Eq. 16-2) 

Where: 

E = 4-operating hour rolling average SO2 emissions standard for stationary combustion turbines other 

than combined cycle combustion turbines and CHP combustion turbines (lb/MWh or ng/J), 

Ei = Hourly SO2 emissions standard for non out-of-control operating hour “i” (lb/MMBtu or ng/J), and 

Pi = Total gross energy output from stationary combustion turbine for non out-of-control operating 

hour “i” (MWh or J). 
Page 18 of 29 

(ii) For combined cycle combustion turbines and CHP combustion turbines, you must determine excess emissions 

on a 30 operating-day rolling average basis. The excess emissions level is the heat input weighted-average of the 

SO2 emissions measured by the CEMS for a given operating day and the 29 operating days immediately 

preceding that day. Once each day, calculate a new 30-operating day average measured emissions rate using all 

hourly average values based on non out-of-control SO2 emission data for all operating hours during the previous 

30-operating day operating period. Report any 30-operating day periods for which you have less than 75 percent 

data availability as monitor downtime. If you elect to comply with the applicable heat input-based emissions 

standard, calculate the measured emissions rate and emissions rate using Equation 17 of this subpart. If you elect 

to comply with the applicable output-based standard, calculate the measured emissions rate using Equation 18-1 

of this subpart and calculate the emissions standard using Equation 18-2 of this subpart. 

 

 











 n

i

i

n

i

i i

Q

E Q

E

1

1 (Eq. 17) 

Where: 

E = 30-operating day rolling average SO2 measured emissions rate or emissions standard for 

combined cycle combustion turbines and CHP combustion turbines (lb/MMBtu or ng/J), 

Ei = Hourly average SO2 emissions rate or emissions standard for non out-of-control operating hour 

“i” (lb/MMBtu or ng/J), 

Qi = Total heat input to stationary combustion turbine for non out-of-control operating hour “i” 

(MMBtu or J as appropriate), and 

n = Total number of non out-of-control operating hours in the 30 operating-day period. 

 











 n

i

i

n

i

i i

P

E Q

E

1

1 (Eq. 18-1) 

Where: 

E = 30-operating day average SO2 measured emissions rate for combined cycle combustion turbines 

and CHP combustion turbines (lb/MWh or ng/J), 

Ei = Hourly average SO2 measured emissions rate for non out-of-control operating hour “i” 

(lb/MMBtu or ng/J), 

Qi = Total heat input to stationary combustion turbine for non out-of-control operating hour “i” 

(MMBtu or J as appropriate), 

Pi = Total gross energy output from stationary combustion turbine for non out-of-control operating 

hour “i” (MWh or J), and 

n = Total number of non out-of-control operating hours in the 30 operating-day period. 

 











 n

i

i

n

i

i i

P

E P

E

1

1 (Eq. 18-2) 

Where: 

E = 30-operating day average SO2 emissions standard for combined cycle combustion turbines and 

CHP combustion turbines (lb/MWh or ng/J), 

Ei = Hourly SO2 emissions standard for non out-of-control operating hour “i” (lb/MWh or ng/J), 

Pi = Total gross energy output from stationary combustion turbine for non out-of-control operating 
Page 19 of 29 

hour “i” (MWh or J), and 

n = Total number of non out-of-control operating hours in the 30 operating-day period. 

Recordkeeping and Reporting 

§60.4375 What reports must I submit? 

(a) An owner or operator of a stationary combustion turbine that elects to continuously monitor parameters or 

emissions, or to periodically determine the fuel sulfur content under this subpart, must submit reports of excess 

emissions and monitor downtime, according to §60.7(c). Excess emissions must be reported for all periods of unit 

operation, including startup, shutdown, and malfunction. 

(b) An owner or operator of a stationary combustion turbine that performs performance tests to demonstrate 

compliance with this subpart must submit a written report of the results of each performance test before the close 

of business on the 60th day following the completion of the performance test, except as specified in paragraph (c) 

of this part. 

(c)(1) Within 60 days after the date of completing each performance test (see §60.8) as required by this subpart 

you must submit the results of the performance tests required by this subpart to EPA’s WebFIRE database by 

using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA’s Central 

Data Exchange (CDX) (www.epa.gov/cdx). Performance test data must be submitted in the file format generated 

through use of EPA’s Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only 

data collected using test methods on the ERT website are subject to this requirement for submitting reports 

electronically to WebFIRE. Owners or operators who claim that some of the information being submitted for 

performance tests is confidential business information (CBI) must submit a complete ERT file including 

information claimed to be CBI on a compact disk or other commonly used electronic storage media (including, 

but not limited to, flash drives) to EPA. The electronic media must be clearly marked as CBI and mailed to U.S. 

EPA/OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., 

Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to EPA via CDX as described 

earlier in this paragraph. At the discretion of the delegated authority, you must also submit these reports, 

including the confidential business information, to the delegated authority in the format specified by the delegated 

authority. 

(2) Within 60 days after the date of completing each CEMS performance evaluation test (see §60.13), you must 

submit the relative accuracy test audit data electronically into EPA’s Central Data Exchange by using the 

Electronic Reporting Tool as mentioned in paragraph (c)(1) of this section. Only data collected using test methods 

compatible with ERT are subject to this requirement to be submitted electronically to EPA’s CDX. 

(3) All reports required by this subpart not subject to the requirements in paragraphs (c)(1) and (2) of this section 

must be sent to the Administrator or delegated authority at the appropriate address listed in §63.13. The 

Administrator or delegated authority may request a report in any form suitable for the specific case (e.g., by 

commonly used electronic media such as Excel spreadsheet, on CD or hard copy). The Administrator or delegated 

authority retains the right to require submittal of reports subject to paragraph (c)(1) and (2) of this section in paper 

format. 

(d) The notification requirements of §60.8 apply to the initial and subsequent performance tests. 

(e) An owner or operator of an affected facility complying with §60.4333(b)(3) must notify the delegated 

permitting authority within 15 calendar days after the facility recommences operation. 

(f) An owner or operator of an affected facility complying with §60.4333(b)(4) must notify the delegated 

permitting authority within 15 calendar days after the facility has operated more than 50 operating hours since the 

date the previous performance test was required to be conducted. 

§60.4380 How are NOX excess emissions and monitor downtime reported? 

(a) For reports required under §60.4375(a), periods of excess emissions and monitor downtime for stationary 

combustion turbines using water or steam to fuel ratio monitoring are reported as specified in paragraphs (a)(1) 

through (3) of this section. 

(1) An excess emission that must be reported is any operating hour for which the 4-operating hour rolling average 

steam or water to fuel ratio, as measured by the continuous monitoring system, is less than the acceptable steam or 

water to fuel ratio needed to demonstrate compliance with §60.4320, as established during the most recent 

Comment [CF44]: Updated language for 

electronic reporting. 
Page 20 of 29 

performance test. Any operating hour during which no water or steam is injected into the turbine when the 

specific conditions require water or steam injection for NOX control will also be considered an excess emission. 

(2) A period of monitor downtime that must be reported is any operating hour in which water or steam is injected 

into the turbine, but the parametric data needed to determine the steam or water to fuel ratio are unavailable or 

out-of-control. 

(3) Each report must include the average steam or water to fuel ratio, average fuel consumption, and the stationary 

combustion turbine load during each excess emission. 

(b) For reports required under §60.4375(a), periods of excess emissions and monitor downtime for stationary 

combustion turbines using a CEMS, excess emissions are reported as specified in paragraphs (b)(1) through (3) of 

this section. 

(1) An excess emission that must be reported is any unit operating period in which the 4-operating hour or 30-

operating day rolling average NOX emissions rate exceeds the applicable emissions standard in §60.4320 as 

determined in §60.4350. 

(2) A period of monitor downtime that must be reported is any operating hour in which the data for any of the 

following parameters are either missing or out-of-control: NOX concentration, CO2 or O2 concentration, stack flow 

rate, heat input rate, steam flow rate, steam temperature, steam pressure, or megawatts. You are only required to 

monitor parameters used for compliance purposes. 

(3) For hours with multiple emission standards, the applicable standard for that hour is determined based on the 

condition, excluding periods of monitor downtime, that corresponded to the highest emissions standard. 

(c) For reports required under §60.4375(a), periods of excess emissions and monitor downtime for stationary 

combustion turbines using combustion parameters or parameters that document proper operation of the NOX

emission controls excess emissions and monitor downtime are reported as specified in paragraphs (c)(1) and (2) 

of this section. 

(1) Excess emissions that must be reported are each 4-operating hour rolling average in which any monitored 

parameter (as averaged over the 4 operating-hour period) does not achieve the target value or is outside the 

acceptable range defined in the parameter monitoring plan for the unit. 

(2) Periods of monitor downtime that must be reported are each operating hour in which any of the required 

parametric data are either not recorded or are out-of-control. 

§60.4385 How are SO2 excess emissions and monitor downtime reported? 

(a) If you choose the option to monitor the sulfur content of the fuel, excess emissions and monitor downtime are 

defined as follows: 

(1) For samples obtained using daily sampling, flow proportional sampling, or sampling from the unit's storage 

tank, excess emissions occur each operating hour included in the period beginning on the date and hour of any 

sample for which the sulfur content of the fuel being fired in the stationary combustion turbine exceeds the 

applicable standard and ending on the date and hour that a subsequent sample is taken that demonstrates 

compliance with the sulfur standard. 

(2) If the option to sample each delivery of fuel oil has been selected, you must immediately switch to one of the 

other oil sampling options (i.e., daily sampling, flow proportional sampling, or sampling from the unit's storage 

tank) if the sulfur content of a delivery exceeds 0.05 weight percent, 0.15 weight percent, or 0.40 weight percent 

as applicable. You must continue to use one of the other sampling options until all of the oil from the delivery has 

been combusted, and you must evaluate excess emissions according to paragraph (a) of this section. When all of 

the fuel from the delivery has been combusted, you may resume using the as-delivered sampling option. 

(3) A period of monitor downtime begins when a required sample is not taken by its due date. A period of monitor 

downtime also begins on the date and hour of a required sample, if invalid results are obtained. The period of 

monitor downtime ends on the date and hour of the next valid sample. 

(b) If you choose the option to maintain records of the fuel sulfur content, excess emissions are defined as any 

period during which you burn a fuel that you do not have appropriate fuel records or that fuel contains sulfur 

greater than the applicable standard. 

(c) For reports required under §60.4375(a), periods of excess emissions and monitor downtime for stationary 

Comment [CF45]: If you don’t need water 

injection to meet the low load standard then you 

don’t have to report those periods as excess 

emissions if you don’t inject water during those 

periods. 
Page 21 of 29 

combustion turbines using a CEMS, excess emissions are reported as specified in paragraphs (c)(1) through (2) of 

this section. 

(1) An excess emission that must be reported is any unit operating period in which the 4-operating hour or 30-

operating day rolling average SO2 emissions rate exceeds the applicable emissions standard in §60.4330 as 

determined in §60.4372. 

(2) A period of monitor downtime that must be reported is any operating hour in which the data for any of the 

following parameters are either missing or out-of-control: SO2 concentration, CO2 or O2 concentration, stack flow 

rate, heat input rate, steam flow rate, steam temperature, steam pressure, or megawatts. You are only required to 

monitor parameters used for compliance purposes. 

§60.4390 What records must I maintain? 

(a) You must maintain records of your information used to demonstrate compliance with this subpart as specified 

in §60.7. 

(b) An owner or operator of a stationary combustion turbine that uses the other fuels, part-load, or low 

temperature NOX standards in the compliance demonstration must maintain concurrent records of the hourly heat 

input, percent load, ambient temperature, and emissions data as applicable. 

(c) An owner or operator of a stationary combustion turbine that uses the tuning NOX standard in the compliance 

demonstration must identify the hours on which the maintenance was performed and a description of the 

maintenance. 

(d) An owner or operator of a stationary combustion turbine that demonstrates compliance using the output-based 

standard must maintain concurrent records of the total gross energy output and emissions data. 

(e) An owner or operator of a stationary combustion turbine that demonstrates compliance using the water or 

steam to fuel ratio or a parameter continuous monitoring system must maintain continuous records of the 

appropriate parameters. 

(f) An owner or operator of a stationary combustion turbine complying with the fuel based SO2 standard must 

maintain records of the results of all fuel analyses or a current, valid purchase contract, tariff sheet, or 

transportation contract. 

§60.4395 When must I submit my reports? 

Consistent with §60.7(c), all reports required under §60.7(c) must be postmarked by the 30th day following the 

end of each 6-month period. 

Performance Tests 

§60.4400 How do I conduct performance tests to demonstrate compliance with my NOX emissions standard 

if I do not have a NOX CEMS? 

(a) You must conduct the performance test according to the requirements in §60.8 and paragraphs (b) through (d) 

of this section. 

(b) You must use the methods in either paragraph (b)(1) or (2) of this section to measure the NOX concentration 

for each test run. 

(1) Measure the NOX concentration using EPA Method 7E in appendix A-4 of this part or EPA Method 20 in 

appendix A-7 of this part. In addition, when only natural gas is being combusted ASTM D6522 (incorporated by 

reference, see §60.17) can be used instead of EPA Method 20 in appendix A-7 of this part to determine the 

oxygen content in the exhaust gas. For units complying with the output-based standard, concurrently measure the 

stack gas flow rate, using EPA Methods 1 and 2 in appendix A-1 of this part, and measure and record the 

electrical and thermal output from the unit. Then, use Equation 19 of this subpart to calculate the NOX emissions 

rate: 

 

P

1.194 10 NO Q E x c std

7    



 (Eq. 19) 

Where: 

 E = NOX emissions rate, in lb/MWh, 
Page 22 of 29 

 1.194×10−7 = Conversion constant, in lb/dscf-ppm, 

 (NOx)c = Average NOX concentration for the run, in ppm, 

 Qstd = Average stack gas volumetric flow rate, in dscf/h, and 

 P = Average gross electrical and mechanical energy output of the stationary combustion 

turbine, in MW (for simple-cycle operation), for combined-cycle operation, the sum of all 

electrical and mechanical output from the combustion and steam turbines, or, for CHP 

operation, the sum of all electrical and mechanical output from the combustion and steam 

turbines plus all useful recovered thermal output not used for additional electric or 

mechanical generation or to enhance the performance of the stationary combustion 

turbine, in MW, calculated according to §60.4350. 

(2) Measure the NOX and diluent gas concentrations, using either EPA Method 7E in appendix A-4 of this part 

and EPA Method 3A in appendix A-2 of this part, or EPA Method 20 in appendix A-7 of this part. In addition, 

when only natural gas is being combusted ASTM D6522 (incorporated by reference, see §60.17) can be used 

instead of EPA Method 3A in appendix A-2 of this part or EPA Method 20 in appendix A-7 of this part to 

determine the oxygen content in the exhaust gas. Concurrently measure the heat input to the unit, using a fuel 

flowmeter (or flowmeters), an O2 or CO2 CEMS along with a stack flow meter, or the methodologies in appendix 

F to part 75 of this chapter, and for units complying with the output-based standard measure the electrical, 

mechanical, and thermal output of the unit. Use EPA Method 19 in appendix A-7 of this part to calculate the NOX

emissions rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 of this subpart in §60.4350(f) to 

calculate the NOX emissions rate in lb/MWh. 

(c) You must use the methods in either paragraph (c)(1) or (2) of this section to select the sampling traverse points 

for NOX and (if applicable) diluent gas. 

(1) You must select the sampling traverse points for NOX and (if applicable) diluent gas according to EPA 

Method 20 in appendix A-7 of this part or EPA Method 1 in appendix A-1 of this part (non-particulate 

procedures), and sampled for equal time intervals. The sampling must be performed with a traversing single-hole 

probe, or, if feasible, with a stationary multi-hole probe that samples each of the points sequentially. 

Alternatively, a multi-hole probe designed and documented to sample equal volumes from each hole may be used 

to sample simultaneously at the required points. 

(2) As an alternative to paragraph (c)(1) of this section, you may select the sampling traverse points for NOX and 

(if applicable) diluent gas according to requirements in paragraphs (c)(2)(i) and (ii) of this section. 

(i) You perform a stratification test for NOX and diluent pursuant to the procedures specified in section 6.5.6.1(a) 

through (e) in appendix A of part 75 of this chapter. 

(ii) Once the stratification sampling is completed, you use the following alternative sample point selection criteria 

for the performance test specified in paragraphs (c)(2)(ii)(A) through ( 

(A) If each of the individual traverse point NOX concentrations is within ±10 percent of the mean concentration 

for all traverse points, or the individual traverse point diluent concentrations differs by no more than ±0.5 percent 

CO2 (or O2) from the mean for all traverse points, then you may use three points (located either 16.7, 50.0 and 

83.3 percent of the way across the stack or duct, or, for circular stacks or ducts greater than 2.4 meters (7.8 feet) in 

diameter, at 0.4, 1.2, and 2.0 meters from the wall). The three points must be located along the measurement line 

that exhibited the highest average NOX concentration during the stratification test; or 

(B) For a stationary combustion turbine subject to a NOX emissions standard greater than 15 ppm at 15 percent 

O2, you may sample at a single point, located at least 1 meter from the stack wall or at the stack centroid if each of 

the individual traverse point NOX concentrations is within ±5 percent of the mean concentration for all traverse 

points, or the individual traverse point diluent concentrations differs by no more than ±0.3 percent CO2 (or O2) 

from the mean for all traverse points; or 

(C) For a stationary combustion turbine subject to a NOX emissions standard less than or equal to 15 ppm at 15 

percent O2, you may sample at a single point, located at least 1 meter from the stack wall or at the stack centroid if 

each of the individual traverse point NOX concentrations is within ±2.5 percent of the mean concentration for all 

traverse points, or the individual traverse point diluent concentrations differs by no more than ±0.15 percent CO2

(or O2) from the mean for all traverse points. 
Page 23 of 29 

(d) The performance test must be done at any load condition within plus or minus 25 percent of 100 percent of the 

base load rating. You may perform testing at the highest achievable load point, if at least 75 percent of the base 

load rating cannot be achieved in practice. You must conduct three separate test runs for each performance test. 

The minimum time per run is 60 minutes. 

(1) If the stationary combustion turbine combusts both natural gas and fuels other than natural gas as primary or 

backup fuels, separate performance testing is required for each fuel. 

(2) For a combined cycle or CHP combustion turbine with supplemental heat (duct burner), you must measure the 

total NOX emissions downstream of the duct burner. The duct burner must be in operation during the performance 

test. 

(3) If water or steam injection is used to control NOX with no additional post-combustion NOX control and you 

choose to monitor the steam or water to fuel ratio in accordance with §60.4335, then that monitoring system must 

be operated concurrently with each EPA Method 20 in appendix A-7 of this part or EPA Method 7E in appendix 

A-4 of this part run and must be used to determine the fuel consumption and the steam or water to fuel ratio 

necessary to comply with the applicable §60.4320 NOX emissions standard. 

(4) If you elect to install a CEMS, the performance evaluation of the CEMS may either be conducted separately or 

(as described in §60.4405) as part of the initial performance test of the affected unit. 

(5) The ambient temperature must be greater than 0°F during the performance test. The delegated permitting 

authority may approve performance testing below 0o

F if the timing of the required performance test and 

environmental conditions make it impractical to test at ambient conditions greater than 0oF. 

§60.4405 How do I conduct a performance test if I use a NOX CEMS? 

(a) If you use a CEMS the performance test must be performed according to the procedures specified in paragraph 

(b) of this section. 

(b) The initial performance test must use the procedure specified in paragraphs (b)(1) through (4) of this section. 

(1) Perform a minimum of nine RATA reference method runs, with a minimum time per run of 21 minutes, at a 

single load level, within plus or minus 25 percent of 100 percent of the base load rating. You may perform testing 

at the highest achievable load point, if at least 75 percent of the base load rating cannot be achieved in practice. 

The ambient temperature must be greater than 0 °F during the RATA runs. The delegated permitting authority 

may approve performance testing below 0 o

F if the timing of the required performance test and environmental 

conditions make it impractical to test at ambient conditions greater than 0 oF. 

(2) For each RATA run, concurrently measure the heat input to the unit using a fuel flow meter (or flow meters) 

or the methodologies in appendix F to part 75 of this chapter, and for units complying with the output-based 

standard, measure the electrical and thermal output from the unit. 

(3) Use the test data both to demonstrate compliance with the applicable NOX emissions standard under §60.4320 

and to provide the required reference method data for the RATA of the CEMS described under §60.4342. 

(4) Compliance with the applicable emissions standard in §60.4320 is achieved if the sum of the NOX emissions 

divided by the heat input (or gross energy output) for all the RATA runs, expressed in units of lb/MMBtu or 

lb/MWh, does not exceed the emissions standard. 

§60.4415 How do I conduct performance tests to demonstrate compliance with my SO2 emissions standard? 

(a) An owner or operator of an affected facility complying with the fuel based standard must submit fuel records 

(such as a current, valid purchase contract, tariff sheet, transportation contract, or results of a fuel analysis) to 

satisfy the requirements of §60.8. 

(b) An owner or operator of an affected facility complying with the SO2 emissions standard must conduct the 

performance test by measuring the SO2 emissions in the stationary combustion turbine exhaust gases using the 

methods in either paragraph (b)(1) or (2) of this section. 

(1) Measure the SO2 concentration using EPA Methods 6, 6C, 8 in appendix A-4 of this part, or EPA Method 20 

in appendix A-7 of this part. In addition, the American Society of Mechanical Engineers (ASME) standard, 

ASME PTC 19–10–1981–Part 10, “Flue and Exhaust Gas Analyses,” manual methods for sulfur dioxide 

(incorporated by reference, see §60.17) can be used instead of EPA Method 6 in appendix A-4 of this part or EPA 

Method 20 in appendix A-7 of this part. For units complying with the output based standard, concurrently 

Comment [CF46]: Make consistent with other 

NSPS rules. Performance test should be for a 

nominal hour. 

Comment [CF47]: Allow permitting authority to 

account for site specific conditions and approve 

testing below 0 o

F in special circumstances 

Comment [CF48]: Allow permitting authority to 

account for site specific conditions and approve 

testing below 0 o

F in special circumstances 
Page 24 of 29 

measure the stack gas flow rate, using EPA Methods 1 and 2 in appendix A-1 of this part, and measure and record 

the electrical and thermal output from the unit. Then use Equation 20 of this subpart to calculate the SO2

emissions rate: 

 

P

SO Q E   c  std 



2

7 1.664 10

 (Eq. 20) 

Where: 

 E = SO2 emissions rate, in lb/MWh, 

 1.664×10−7

 = Conversion constant, in lb/dscf-ppm, 

 (SO2)c = Average SO2 concentration for the run, in ppm, 

 Qstd = Average stack gas volumetric flow rate, in dscf/h, and 

 P = Average gross electrical and mechanical energy output of the stationary combustion 

turbine, in MW (for simple-cycle operation), for combined-cycle operation, the sum of all 

electrical and mechanical output from the combustion and steam turbines, or, for CHP 

operation, the sum of all electrical and mechanical output from the combustion and steam 

turbines plus all useful recovered thermal output not used for additional electric or 

mechanical generation or to enhance the performance of the stationary combustion 

turbine, in MW, calculated according to §60.4350(f)(2). 

(2) Measure the SO2 and diluent gas concentrations, using either EPA Methods 6, 6C, or 8 in appendix A-4 of this 

part and EPA Method 3A in appendix A-2 of this part, or EPA Method 20 in appendix A-7 of this part. In 

addition, you may use the manual methods for sulfur dioxide ASME PTC 19–10–1981–Part 10 (incorporated by 

reference, see §60.17). Concurrently measure the heat input to the unit, using a fuel flowmeter (or flowmeters), an 

O2 or CO2 CEMS along with a stack flow meter, or the methodologies in appendix F to part 75 of this chapter, 

and for units complying with the output based standard measure the electrical and thermal output of the unit. Use 

EPA Method 19 in appendix A-7 of this part to calculate the SO2 emissions rate in lb/MMBtu. Then, use 

Equations 11 and, if necessary, 12 and 13 of this subpart in §60.4372 to calculate the SO2 emissions rate in 

lb/MWh. 

Definitions 

§60.4420 What definitions apply to this subpart? 

As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in 

subpart A (General Provisions) of this part. 

Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a 

defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and 

objectively evaluated in a judicial or administrative proceeding.

Base load rating means 100 percent of the manufacturer's design heat input capacity of the combustion turbine 

engine at ISO conditions using the higher heating value of the fuel. 

Biogas means gas produced by the anaerobic digestion or fermentation of organic matter including manure, 

sewage sludge, municipal solid waste, biodegradable waste, or any other biodegradable feedstock, under 

anaerobic conditions. Biogas is comprised primarily of methane and CO2.

Byproduct means any liquid or gaseous substance produced at chemical manufacturing plants, petroleum 

refineries, or pulp and paper mills (except natural gas and fuel oil) and combusted in a stationary combustion 

turbine. Gaseous substances with CO2 levels greater than 50 percent or carbon monoxide levels greater than 10 

percent are not byproduct. 

Combined cycle combustion turbine means any stationary combustion turbine which recovers heat from the 

combustion turbine engine exhaust gases to generate steam that is used exclusively to create additional power 

output in a steam turbine. 

Combined heat and power (CHP) combustion turbine means any stationary combustion turbine which recovers 

heat from the combustion turbine engine exhaust gases to heat water or another medium, generate steam for useful 

purposes other than exclusively for additional electric generation, or directly uses the heat in the exhaust gases for 

Comment [CF49]: Removed unnecessary 

definitions and added “Byproduct”, “Federally 

enforceable”, “Combustion turbine engine”, “turbine 

tuning,” “Offshore turbine”, “Out-of-control period”, 

“solid fuel”, and “fuel oil.” Changed “peak load” to 

“base load,” and “unit operating hour” and “unit 

operating day” to “operating hour” and “operating 

day.” Clarified “stationary combustion turbine” to 

include additional components. Amended “natural 

gas” to include synthetic natural gas - If consistent 

quality & meets the definition of natural gas then the 

same NOx standard should apply. 
Page 25 of 29 

a useful purpose. 

Combustion turbine engine means the air compressor, combustor, and turbine sections of a stationary combustion 

turbine. 

Combustion turbine test cell/stand means any apparatus used for testing uninstalled stationary or uninstalled 

mobile (motive) combustion turbines. 

Distillate oil means fuel oil that complies with the specifications for fuel oil numbers 1 or 2, as defined by the 

American Society for Testing and Materials in ASTM D396 (incorporated by reference, see §60.17), diesel fuel 

oil numbers 1 or 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated 

by reference, see §60.17), kerosine, as defined by the American Society of Testing and Materials in ASTM D3699 

(incorporated by reference, see §60.17), biodiesel as defined by the American Society of Testing and Materials in 

ASTM D6751 (incorporated by reference, see §60.17), or biodiesel blends as defined by the American Society of 

Testing and Materials in ASTM D7467 (incorporated by reference, see §60.17). 

Dry standard cubic foot (dscf) means the quantity of gas, free of uncombined water, that would occupy a volume 

of 1 cubic foot at 293 Kelvin (20.0 o

C) and 101.325 kPa of pressure.

Duct burner means a device that combusts fuel and that is placed in the exhaust duct from another source, such as 

a stationary combustion turbine, internal combustion engine, kiln, etc., to allow the firing of additional fuel to heat 

the exhaust gases. 

Emergency combustion turbine means any stationary combustion turbine which operates in an emergency 

situation. Examples include stationary combustion turbines used to produce power for critical networks or 

equipment, including power supplied to portions of a facility, when electric power from the local utility is 

interrupted, or stationary combustion turbines used to pump water in the case of fire or flood, etc. Emergency 

stationary combustion turbines do not include stationary combustion turbines used as peaking units at electric 

utilities or stationary combustion turbines at industrial facilities that typically operate at low capacity factors. 

Emergency combustion turbines may be operated for maintenance checks and readiness testing to retain their 

status as emergency combustion turbines, provided that the tests are required by the manufacturer, the vendor, or 

the insurance company associated with the turbine. Required testing of such units should be minimized, but there 

is no time limit on the use of emergency combustion turbines. 

Excess emissions means a specified averaging period over which either (1) the NOX or SO2 emissions rate are 

higher than the applicable emissions standard in §60.4320 or §60.4330; (2) the total sulfur content of the fuel 

being combusted in the affected facility or the SO2 emissions exceeds the standard specified in §60.4330; or (3) 

the recorded value of a particular monitored parameter, including ration of water or steam to fuel, is outside the 

acceptable range specified in the parameter monitoring plan for the affected unit. 

Federally enforceable means all limitations and conditions that are enforceable by the Administrator or delegated 

authority, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State 

Implementation Plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 

51.24 

Fuel oil means a fluid mixture of hydrocarbons that maintains a liquid state at ISO conditions. Additionally, fuel 

oil must meet the definition of either distillate oil or residual oil as defined by the American Society for Testing 

and Materials in ASTM D396 (incorporated by reference, see §60.17) or diesel fuel as defined by the American 

Society for Testing and Materials in ASTM D975 (incorporated by reference, see §60.17). 

Gross useful energy output means: 

(1) For simple cycle and combined cycle combustion turbines, the gross useful work performed is the gross 

electrical or direct mechanical output from both the combustion turbine engine and any associated steam 

turbine(s). 

(2) For a CHP combustion turbine, the gross useful work performed is the gross electrical or direct mechanical 

output from both the combustion turbine engine and any associated steam turbine(s) plus any useful thermal 

output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output 

or to enhance the performance of the unit (i.e., steam delivered to an industrial process). 

(3) For a CHP combustion turbine where at least 20.0 percent of the total gross useful energy output consists of 

electric or direct mechanical output and 20.0 percent of the total gross useful energy output consists of useful 

Comment [CF50]: Need to add definition for 

SO2 exemption.

Comment [CF51]: Delete “before the exhaust 

gases enter a heat recovery steam generating unit” to 

clarify that any additional combustion with turbine 

engine exhaust is a duct burner. 
Page 26 of 29 

thermal output on an annual basis, the gross useful work performed is the gross electrical or direct mechanical 

output from both the combustion turbine engine and any associated steam turbine(s) divided by 0.95 plus any 

useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or 

mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process). 

Heat recovery steam generating unit means a unit where the hot exhaust gases from the combustion turbine 

engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam 

generating units can be used with or without duct burners. 

Integrated gasification combined cycle electric utility steam generating unit (IGCC) means an electric utility 

steam generating unit that burns solid-derived fuels in a combined-cycle combustion turbine. No solid fuel is 

directly combusted in the unit during operation. 

ISO conditions means 288 Kelvin (15 o

C), 60 percent relative humidity and 101.325 kilopascals (kPa) pressure. 

Lean premix stationary combustion turbine means any stationary combustion turbine where the air and fuel are 

thoroughly mixed to form a lean mixture before delivery to the combustor. Mixing may occur before or in the 

combustion chamber. A lean premixed turbine may operate in diffusion flame mode during operating conditions 

such as startup and shutdown, extreme ambient temperature, or low or transient load. 

Low-Btu gas means biogas or any gas with a heating value of less than 26 megajoules per standard cubic meter 

(MJ/scm) (700 Btu/scf). 

Natural gas means a fluid mixture of hydrocarbons, composed of at least 70 percent methane by volume or that 

has a gross calorific value between 35 and 41 MJ/scm (950 and 1,100 Btu/scf), that maintains a gaseous state 

under ISO conditions. In addition, natural gas contains 460 mg/scm (20.0 gr/100 scf) or less of total sulfur. 

Finally, natural gas does not include any gaseous fuel produced in a process which might result in highly variable 

heating value. 

Noncontinental area means Guam, American Samoa, the Northern Mariana Islands, or offshore platforms. 

Offshore turbine means a stationary combustion turbine located on a platform in an ocean 

Operating day means a 24-hour period between 12 midnight and the following midnight during which any fuel is 

combusted at any time in the unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour 

period. 

Operating hour means a clock hour during which any fuel is combusted in the affected unit. If the unit combusts 

fuel for the entire clock hour, it is considered to be a full operating hour. If the unit combusts fuel for only part of 

the clock hour, it is considered to be a partial operating hour. 

Out-of-control period means any period beginning with the quadrant corresponding to the completion of a daily 

calibration error, linearity check, or quality assurance audit that indicates that the instrument is not measuring and 

recording within the applicable performance specifications and ending with the quadrant corresponding to the 

completion of an additional calibration error, linearity check, or quality assurance audit following corrective 

action that demonstrates that the instrument is measuring and recording within the applicable performance 

specifications. 

Simple cycle combustion turbine means any stationary combustion turbine which does not recover heat from the 

combustion turbine engine exhaust gases for purposes other than enhancing the performance of the stationary 

combustion turbine itself. 

Solid fuel means any fuel that has a definite shape and volume, has no tendency to flow or disperse under 

moderate stress, and is not liquid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, 

and pulverized solid fuels. 

Stationary combustion turbine means all equipment, including but not limited to the combustion turbine engine, 

the fuel, air, lubrication and exhaust gas systems, control systems, heat recovery system, steam turbine, fuel 

compressor, heater, and/or pump, post-combustion emission control technology, and any ancillary components 

and sub-components. Stationary means that the combustion turbine is not self propelled or intended to be 

propelled while performing its function. It may, however, be mounted on a vehicle for portability. 

Standard cubic foot (scf) means the quantity of gas that would occupy a volume of 1 cubic foot at 293 Kelvin 

(20.0 o

C) and 101.325 kPa of pressure. 

Comment [CF52]: Add definition of low btu gas 

to include blast furnace gas, coke oven gas, etc. 

Digester gas can have a heating value of slightly 

more than 600 Btu/scf, but to account for variability 

lets say 700 Btu/scf (HHV). 

Comment [CF53]: Make similar to part 75 

definition of natural gas 

Comment [CF54]: Remove Hawaii, Puerto Rico, 

and Virgin Islands from definition. 

Comment [CF55]: CAMD definition in 40 CFR 

72.2 uses hour as the time period, but since KKKK 

allows the use of any data to determine an hourly 

average only the quadrant of out-of-control data is 

excluded. 
Page 27 of 29 

Standard cubic meter (scm) means the quantity of gas that would occupy a volume of 1 cubic meter at 293 Kelvin 

(20.0 o

C) and 101.325 kPa of pressure. 

Turbine tuning means planned maintenance of a lean premix combustion turbine engine involving adjustment of 

the operating configuration to maintain proper combustion dynamics. Turbine tuning is limited to 30 hours 

annually. 

Useful thermal output means the thermal energy made available for processes and applications other than 

electrical or mechanical generation or to enhance the performance of the stationary combustion turbine (i.e., the 

thermal energy made available for use in any industrial or commercial process or used in any heating application). 

Useful thermal output for this subpart is measured relative to the enthalpy of the thermal output in its most 

prevalent form at ISO conditions (e.g., liquid water). 
Page 28 of 29 

Table 1 to Subpart KKKK of Part 60 - Nitrogen Oxide Emission Standards for Stationary Combustion Turbines 

Note: all numerical values have two significant figures 

Combustion turbine type 

Combustion 

turbine heat input 

at base load rating 

(HHV) 

NOX emissions standard

Alternate NOX

emissions 

standard in 

ppm at 15 

percent O2

New turbine firing natural gas, electric 

generating 

≤ 15 MW (50 

MMBtu/h) 

67 ng/J (0.16 lb/MMBtu) 

heat input or 290 ng/J of 

gross energy output (2.3 

lb/MWh) 

42 

New turbine firing natural gas, 

mechanical drive 

≤ 15 MW (50 

MMBtu/h) 

160 ng/J (0.37 lb/MMBtu) 

heat input or 690 ng/J of 

gross energy output (5.5 

lb/MWh) 

100 

New turbine firing natural gas 

> 15 MW (50 

MMBtu/h) and ≤

250 MW (850 

MMBtu/h) 

40 ng/J (0.093 lb/MMBtu) 

heat input or 150 ng/J of 

gross energy output (1.2 

lb/MWh) 

25 

New, modified, or reconstructed turbine 

firing natural gas 

> 250 MW (850 

MMBtuh) 

24 ng/J (0.056 lb/MMBtu) 

heat input or 54 ng/J of 

gross energy output (0.43 

lb/MWh) 

15 

New turbine firing fuels other than 

natural gas, electric generating 

≤ 15 MW (50 

MMBtu/h) 

160 ng/J (0.38 lb/MMBtu) 

heat input or 710 ng/J of 

gross energy output (5.6 

lb/MWh) 

96 

New turbine firing fuels other than 

natural gas, mechanical drive 

≤ 15 MW (50 

MMBtu/h) 

250 ng/J (0.59 lb/MMBtu) 

heat input or 1,100 ng/J of 

gross energy output (8.7 

lb/MWh) 

150 

New turbine firing fuels other than 

natural gas 

> 15 MW (50 

MMBtu/h) and ≤

250 MW (850 

MMBtu/h) 

120 ng/J (0.29 lb/MMBtu) 

heat input or 470 ng/J of 

gross energy output (3.7 

lb/MWh) 

74 

New, modified, or reconstructed turbine 

firing fuels other than natural gas 

> 250 MW (850 

MMBtu/h) 

73 ng/J (0.17 lb/MMBtu) 

heat input or 160 ng/J of 

gross energy output (1.3 

lb/MWh) 

42 

Modified or reconstructed turbine ≤ 15 MW (50 

MMBtu/h) 

250 ng/J (0.59 lb/MMBtu) 

heat input or 1,100 ng/J of 

gross energy output (8.7 

lb/MWh) 

150 

Modified or reconstructed turbine firing 

natural gas 

> 15 MW (50 

MMBtu/h) and ≤

250 MW (850 

MMBtu/h) 

67 ng/J (0.16 lb/MMBtu) 

heat input or 250 ng/J of 

gross energy output (2.0 

lb/MWh) 

42 
Page 29 of 29 

Modified or reconstructed turbine firing 

fuels other than natural gas 

> 15 MW (50 

MMBtu/h) and ≤

250 MW (850 

MMBtu/h) 

160 ng/J (0.38 lb/MMBtu) 

heat input or 600 ng/J of 

gross energy output (4.8 

lb/MWh) 

96 

Turbines located north of the Arctic 

Circle (latitude 66.5 degrees north), 

turbines operating at less than 75 

percent of the base load rating, turbines 

operated during periods of turbine 

tuning, startup, or shutdown, modified 

and reconstructed offshore turbines, or 

turbines operating at temperatures less 

than minus 17 °C 

≤ 100 MW (340 

MMBtu/h) 

250 ng/J (0.59 lb/MMBtu) 

heat input or 1,100 ng/J of 

gross energy output (8.7 

lb/MWh) 

150 

Turbines located north of the Arctic 

Circle (latitude 66.5 degrees north), 

turbines operating at less than 75 

percent of the base load rating, turbines 

operated during periods of turbine 

tuning, startup, or shutdown, modified 

and reconstructed offshore turbines, or 

turbines operating at temperatures less 

than minus 17 °C 

> 100 MW (340 

MMBtu/h) 

160 ng/J (0.38 lb/MMBtu) 

heat input or 610 ng/J of 

gross energy output (4.8 

lb/MWh) 

96 

Heat recovery units operating 

independent of the combustion turbine 

engine 

All sizes 

86 ng/J (0.20 lb/MMBtu) 

heat input or 110 ng/J of 

gross energy output (0.90 

lb/MWh) 

50