Page 1 of 43

MEMORANDUM

From: Office of Air Quality Planning and Standards

U.S. Environmental Protection Agency

To: EGU NSPS Docket (EPA-HQ-OAR-2013-0603)

Date: June, 2014

Subject: Amended Regulatory Text (Broad Applicability)

Amended Regulatory Text

On January 8, 2014, the EPA proposed amendments (79 FR 1430) to the regulatory text of 

subparts Da and KKKK to include greenhouse gas (GHG) standards for new electric generating 

units (EGUs). As an alternative to amending proposed subparts Da and KKKK, the EPA coproposed creating a new subpart TTTT to include the proposed GHG standards. We intend to 

finalize the proposed amendments for modified and reconstructed EGUs following the approach 

finalized in the new source proposal published on January 8, 2014. For example, if the new 

source requirements are included in subparts Da and KKKK and use the applicability described 

in detail in docket item EPA-HQ-OAR-2013-0495-0062, the proposed requirements in this 

proposal would be added to those amendments. 

To facilitate understanding the amendments being proposed in this proposal and allow interested 

persons to see how the proposed amendments for modified and reconstructed sources relate to 

the amendments from January 8, 2014 for newly constructed sources, the following document 

uses track changes to demonstrate the GHG standards for the proposed standards for modified 

and reconstructed EGUs on top of the regulatory text proposed on January 8, 2014.

In addition, in docket item EPA-HQ-OAR-2013-0495-0062 of the January 8, 2014, proposal, the 

EPA elaborated upon the request for comment included in the preamble on whether the general 

applicability of the proposed standards should be broadened and based on design characteristics 

instead of design characteristics and operating parameters. Under this approach, a GHG emission 

standard would apply during periods when certain conditions are met and no numerical GHG 

emission standard would apply during periods when one or more of those conditions are not met. 

In other words, although there would be no numerical emission limit, the facility would remain 

subject to the standard of performance. The track changes of the proposed amendments in this 

proposal include this expanded applicability approach. This broad applicability approach could 

have implications for the corresponding 111(d) rulemaking since it would include non-natural 

gas-fired and low capacity factor stationary combustion would be included in the 111(b) 

applicability. 
Page 2 of 43

Subpart Da-— Standards of Performance for Electric Utility Steam Generating Units

2. Section 60.46Da is added to read as follows:

§60.46Da Standards for carbon dioxide (CO2).

(a) Your affected facility is subject to this section if it meets the conditions specified in 

paragraphs (a)(1) or (a)(2) of this section, except as specified in paragraph (b) of this section.

(1) Construction commenced after January 8, 2014 and the facility was constructed for 

the purpose of supplying and supplies more than one-third of its potential electric output capacity 

and more than 219,000 MWh as net electric sales on an annual basis; or

(2) Modification or reconstruction commenced after [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER], and the affected facility was constructed for 

the purpose of supplying more than one-third of its potential electric output and more than 

219,000 MWh as net-electric sales on an annual basis, 

(b) The following EGUs are not subject to this section:

(1) The proposed Wolverine EGU project described in Permit to Install No. 317-07 

issued by the Michigan Department of Environmental Quality, Air Quality Division, effective 

June 29, 2011 (as revised July 12, 2011).

(2) The proposed Washington County EGU project described in Air Quality Permit No. 

4911-303-0051-P-01-0 issued by the Georgia Department of Natural Resources, Environmental 

Protection Division, Air Protection Branch, effective April 8, 2010, provided that construction 

had not commenced for NSPS purposes as of January 8, 2014.

(3) The proposed Holcomb EGU project described in Air Emission Source Construction 

Permit 0550023 issued by the Kansas Department of Health and Environment, Division of 

Environment, effective December 16, 2010, provided that construction had not commenced for 

NSPS purposes as of January 8, 2014.

(c) As owner or operator of an affected facility subject to this section, you shall not cause 

to be discharged into the atmosphere from the affected facility any gases that contain CO2 in 

excess of the emissions limit specified in this paragraph.

(1) As owner or operator of an affected facility for which construction commenced after 

January 8, 2014, you shall not cause to be discharged into the atmosphere from the affected 

facility any gases that contain CO2 in excess of the emissions limit specified in paragraph 

(c)(1)(i), (c)(1) (ii), or (c)(1) (iii) of this section.

(i) 500 kilograms (kg) of CO2 per megawatt-hour (MWh) of gross energy output (1,100 

lb CO2/MWh) on a 12-operating month rolling average basis;

(ii) 480 kg of CO2 per MWh of gross energy output (1,050 lb CO2/MWh) on an 84-

operating month rolling average basis; or

(iii) If the affected facility combusts fossil fuel for 10.0 percent or less of the heat input 

during any 3 consecutive calendar years no numerical emission standard.

(2) As owner or operator of an affected facility for which reconstruction commenced 

after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], you shall not 

cause to be discharged into the atmosphere from the affected facility any gases that contain CO2
Page 3 of 43

in excess of the emissions limit specified in paragraph (c)(2)(i), (c)(2)(ii), or (c)(2)(iii) of this 

section.

(i) If the design rated capacity of your affected facility is 590 MW (2,000 MMBtu/h) or 

less, 950 kg CO2/MWh of net energy output (2,100 lb CO2/MWh) on a 12-operating month 

rolling average basis; 

(ii) If the design rated capacity of your affected facility is greater than 590 MW (2,000 

MMBtu/h), then 820 kg CO2/MWh of net energy output (1,900 lb CO2/MWh) on a 12-operating 

month rolling average basis; or

(iii) If the affected facility combusts fossil fuel for 10.0 percent or less of the heat input 

during any 3 consecutive calendar years no numerical emission standard.

(3) As owner or operator of an affected facility for which modification commenced after 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], you shall not cause to 

be discharged into the atmosphere from the affected facility any gases that contain CO2 in excess 

of the emissions limit specified in paragraph (c)(3)(i) or (c)(3)(ii) of this section.

(i) If the facility is not subject to an approved CAA section 111(d) plan (state or federal)

at the time of the modification, a CO2 emissions limit specified in paragraph (c)(3)(i)(A),

(c)(3)(i)(B), or (c)(3)(i)(C) of this section.

(A) a site-specific12-operating month rolling average CO2 emission limit calculated as 2 

percent lower than (i.e., 98 percent) the best demonstrated annual historical operating 

performance for the affected facility using historical CO2 emissions data for the calendar years 

2002 through the most recent full calendar year the affected facility was operating prior to the 

modification using either recorded net output emission rate data or gross electrical output and 

CO2 emissions data as reported under part 75 of this chapter. If incomplete or no data has been 

submitted under part 75 of this chapter, the Administrator or delegated authority shall approve 

the use of alternate data sources. The equivalent net output-based standard shall be calculated 

from gross output-based data assuming a 7.5 percent auxiliary (i.e., parasitic) load (i.e., the best 

annual value is divided by 0.925);

(B) If the design rated capacity of your affected facility is 590 MW (2,000 MMBtu/h) or 

less, 950 kg CO2/MWh of net energy output (2,100 lb CO2/MWh) on a 12-operating month 

rolling average basis; or

(C) If the design rated capacity of your affected facility is greater than 590 MW (2,000 

MMBtu/h), 820 kg CO2/MWh of net energy output (1,900 lb CO2/MWh) on a 12-operating 

month rolling average basis.

(ii) If the facility is subject to an approved CAA section 111(d) plan (state or federal) at 

the time of the modification, a site-specific 12-operating month rolling average CO2 emission 

limit determined by the CAA section 111(d) implementing authority based on the affected 

facility performing an energy assessment by an energy professional or engineer that have 

expertise in evaluating energy systems to identify applicable energy efficiency projects that you 

will implement at the affected facility to improve the affected facility’s operating performance.

You must maintain a copy of the most recent energy assessment report. The energy assessment

must include at a minimum the elements in paragraphs (c)(3)(ii)(A) through (c)(3)(ii)(C) of this 
Page 4 of 43

section.(A) A visual inspection of the facility to identify steam leaks or other sources of reduced

efficiency,

(B) A review of available engineering plans and facility operation and maintenance 

procedures and logs, and

(C) A comprehensive report detailing the ways to improve efficiency, the cost of specific 

improvements, benefits, and the time frame for recouping those investments.

(d) You must make compliance determinations at the end of each operating month, as 

provided in paragraphs (d)(1) and (d)(2) of this section. For the purpose of this section, operating 

month means a calendar month during which any fossil fuel is combusted in the affected facility.

(1) If you are subject to a 12-operating month CO2 emissions limit, you must determine 

compliance monthly by calculating the average CO2 emissions rate for the affected facility at the 

end of each 12-operating month period that includes, as the last month, the month for which you 

are determining compliance.

(2) If you are subject to an 84-operating month CO2 emissions limit, you must determine 

compliance monthly by calculating the average CO2 emissions rate for the affected facility at the 

end of each 84-operating month period that includes, as the last month, the month for which you 

are determining compliance.

(e) You must conduct an initial compliance determination with the CO2 emissions limit

for your affected facility within 30 days after accumulating the required number of operating 

months for the compliance period with which you have elected to comply (i.e., 12-operating 

months or 84-operating months). The first operating month included in this compliance period is 

the month in which emissions reporting is required to begin under § 75.64(a) of this chapter.

(f) You must monitor and collect data to demonstrate compliance with the CO2 emissions 

limit according to the requirements in paragraphs (f)(1) through (4) of this section.

(1) You must prepare a monitoring plan in accordance with the applicable provisions in § 

75.53(g) and (h) of this chapter. 

(2) You must measure the hourly CO2 mass emissions from each affected facility using 

the procedures in paragraphs (f)(2)(i) through (vii) of this section, except as provided in 

paragraph (f)(3) of this section.

(i) You must install, certify, operate, maintain, and calibrate a CO2 continuous emission 

monitoring system (CEMS) to directly measure and record CO2 concentrations in your affected 

facility’s exhaust gases that are emitted to the atmosphere and an exhaust gas flow rate 

monitoring system according to §75.10(a)(3)(i) of this chapter. If you measure CO2

concentration on a dry basis, you must also install, certify, operate, maintain, and calibrate a 

continuous moisture monitoring system, according to §75.11(b) of this chapter. 

(ii) For each monitoring system used to determine the CO2 mass emissions, you must 

meet the applicable certification and quality assurance procedures in §75.20 of this chapter and 

Appendices B and D to part 75 of this chapter.

(iii) You must use a laser device to measure the dimensions of each exhaust gas stack or 

duct at the flow monitor and the reference method sampling locations prior to the initial setup 

(characterization) of the flow monitor. For circular stacks, you must make measurements of the 
Page 5 of 43

diameter at three or more distinct locations and average the results. For rectangular stacks or 

ducts, you must make measurements of each dimension (i.e., depth and width) at three or more 

distinct locations and average the results. If the flow rate monitor or reference method sampling 

site is relocated, you must repeat these measurements at the new location.

(iv) You can only use unadjusted exhaust gas volumetric flow rates to determine the 

hourly CO2 mass emissions from the affected facility; you must not apply the bias adjustment 

factors described in section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow 

rate data.

(v) If you choose to use Method 2 in Appendix A-1 to this part to perform the required 

relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a 

calibrated Type-S pitot tube or pitot tube assembly. You must not use the default Type-S pitot 

tube coefficient.

(vi) If two or more affected facilities share a common exhaust gas stack and are subject to 

the same CO2 emissions limit in paragraph (c) of this section, you may monitor the hourly CO2

mass emissions at the common exhaust gas stack rather than monitoring each affected facility 

separately.

(vii) If the exhaust gases from the affected facilities are emitted to the atmosphere 

through multiple stacks (or if the exhaust gases are routed to a common stack through multiple 

ducts and you choose to monitor in the ducts), you must monitor the hourly CO2 mass emissions 

and the “stack operating time” (as defined in § 72.2 of this chapter) at each stack or duct 

separately. 

(3) As an alternative to complying with paragraph (f)(2) of this section, for affected 

facilities that do not combust any solid fuel, you may determine the hourly CO2 mass emissions 

by using Equation G-4 in Appendix G to part 75 of this chapter according to the requirements 

specified in paragraphs (f)(3)(i) and (f)(3)(ii) of this section. 

(i) You must implement the applicable procedures in Appendix D to part 75 of this 

chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of 

fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel 

combusted.

(ii) You may determine site-specific carbon-based F-factors (Fc) using Equation F-7b in 

section 3.3.6 of Appendix F to part 75 of this chapter, and you may use these Fc values in the 

emissions calculations instead of using the default Fc values in the Equation G-4 nomenclature.

(4) You must install, calibrate, maintain, and operate a sufficient number of watt meters 

to continuously measure and record the gross or net electric output from the affected facility.

These measurements must be performed using 0.2 class electricity metering instrumentation and 

calibration procedures as specified under ANSI Standards No. C12.20. You must also meet the 

requirements specified in paragraphs (f)(4)(i) and (ii) of this section, as applicable.

(i) If your affected facility is a combined heat and power unit as defined in § 60.42Da, 

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

record the total useful thermal output. For process steam applications, you must install, calibrate, 

maintain, and operate meters to continuously determine and record steam flow rate, temperature, 

and pressure. If your affected facility has a direct mechanical drive application, you must submit 
Page 6 of 43

a plan to the Administrator or delegated authority for approval of how gross or net energy output 

will be determined. Your plan shall ensure that you install, calibrate, maintain, and operate 

meters to continuously determine and record each component of the determination.

(ii) If two or more affected facilities have steam generating units that serve a common 

electric generator, you must apportion the combined hourly gross or net electric output to each 

individual affected facility using a plan approved by the Administrator (e.g., using steam load or 

heat input to each affected facility). Your plan shall ensure that you install, calibrate, maintain, 

and operate meters to continuously determine and record each component of the determination.

(g) You must demonstrate compliance with the CO2 emissions limit using the procedures 

specified in paragraphs (g)(1) and (2) of this section.

(1) You must calculate the CO2 mass emissions rate for your affected facility using the 

calculation procedures in paragraphs (g)(1)(i) through (v) of this section with the hourly CO2

mass emissions and gross or net energy output data determined and recorded according to the 

procedures in paragraph (f) of this section for each operating hour in the applicable compliance 

period (i.e., 12-operating months or 84-operating months).

(i) You must only use operating hours in the compliance period for which you have valid 

data for all the parameters you use to determine the hourly CO2 mass emissions and gross or net

output data. You must not use operating hours which use the substitute data provisions of part 75 

of this chapter for any of the parameters in the calculation. For the compliance determination 

calculation, you must obtain valid hourly values for a minimum of 95 percent of the operating 

hours in the applicable compliance period.

(ii) You must calculate the total CO2 mass emissions by summing all of the valid hourly

CO2 mass emissions values for the applicable compliance period. If exhaust gases from the 

affected facility are emitted to the atmosphere through multiple stacks or ducts, you must 

calculate the total CO2 mass emissions for the affected facility by summing the total CO2 mass 

emissions from each of the individual stacks or ducts.

(iii) For each operating hour of the compliance period used in paragraph (g)(1)(ii) of this 

section to calculate the total CO2 mass emissions, you must determine the affected facility’s 

corresponding hourly gross or net energy output using the appropriate definitions in § 60.42Da 

and paragraph (k) of this section and using the procedure specified in paragraphs (g)(3)(iii)(A) 

through (D) of this section.

(A) Calculate Pgross/net for your affected facility using the following equation:

/ = 

() + () + () − ()

T

+ 0.75 × [ () + () + () ]

Where: 

Pgross/net = Gross or net energy output of your affected facility in megawatt-hours 

(MWh).

(Pe)ST = Electric energy output plus mechanical energy output (if any) of steam 

turbines in MWh.

(Pe)CT = Electric energy output plus mechanical energy output (if any) of stationary
Page 7 of 43

combustion turbine(s) in MWh.

(Pe)IE = Electric energy output plus mechanical energy output (if any) of your 

affected facility’s integrated equipment that provides electricity or 

mechanical energy to the affected facility or auxiliary equipment in MWh.

(Pe)FW = Electric energy used to power boiler feedwater pumps at steam generating 

units in MWh. This term is not applicable to IGCC facilities or facilities 

complying with a net output based standard.

(Pt)PS = Useful thermal output of steam (measured relative to SATP conditions, as 

applicable) that is used for applications that do not generate additional 

electricity, produce mechanical energy output, or enhance the performance 

of the affected facility. This term is calculated using the equation specified 

in paragraph (g)(3)(iii)(B) of this section in MWh.

(Pt)HR = Non steam useful thermal output (measured relative to SATP conditions, 

as applicable) that is used for applications other than steam generation or 

performance enhancement of the affected facility in MWh.

(Pt)IE = Useful thermal output (relative to SATP conditions, as applicable) from 

any integrated equipment that is used for applications that do not generate 

additional steam, electricity, produce mechanical energy output, or 

enhance the performance of the affected facility in MWh.

T = Electric Transmission and Distribution Factor.

T = 0.95 for a combined heat and power affected facility where at least on 

an annual basis 20.0 percent of the total gross or net energy output consists 

of electric or direct mechanical output and 20.0 percent of the total gross 

or net energy output consists of useful thermal output on a rolling 3 year 

basis.

T = 1.0 for all other affected facilities.

(B) If applicable to your affected facility, calculate (Pt)PS using the following equation:

() =

 × 

3.6 × 10

Where:

Qm = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating 

hour.

H = Enthalpy of the steam at (measured temperature and pressure relative to 

SATP conditions, as applicable) in Joules per kilogram (J/kg) (or Btu/lb).

3.6 x 109= Conversion factor (J/MWh) (or 3.413 x 106 Btu/MWh).

(C) For an operating hour in which there is no gross or net electric load, but there is 

mechanical or useful thermal output, you must still determine the gross or net energy output for 
Page 8 of 43

that hour. In addition, for an operating hour in which there is no useful output, you must still 

determine the hourly CO2 emissions for that hour. For hours or partial hours where there the

gross generation equal to or less than the auxiliary loads, net electric output shall be counted as 

zero for this calculation.

(D) If hourly CO2 mass emissions are determined for a common stack, you must 

determine the hourly gross or net energy output (electric, thermal, and/or mechanical, as 

applicable) by summing the hourly loads for the individual affected facility and you must express 

the operating time as “stack operating hours” (as defined in § 72.2 of this chapter).

(iv) You must calculate the total gross or net energy output by summing the hourly gross 

or net energy output values for the affected facility determined from paragraph (g)(1)(iii) of this 

section for all of the operating hours in the applicable compliance period. 

(v) You must calculate the CO2 mass emissions rate for the applicable compliance period 

interval by dividing the total CO2 mass emissions value from paragraph (g)(1)(ii) of this section 

by the total gross or net energy output value from paragraph (g)(1)(iv) of this section.

(2) You must determine compliance with the CO2 emissions limit in paragraph (c) of this 

section is determined as specified in paragraphs (g)(2)(i) and (ii) of this section using the CO2

mass emissions rate for your affected facility that you determined in paragraph (g)(1) of this 

section.

(i) If the CO2 mass emissions rate for your affected facility is less than or equal to the 

CO2 emissions limit applicable to your affected facility, then your affected facility is in 

compliance with the CO2 emissions limit. If you attain compliance with the CO2 emissions limit

at a common stack for two or more affected facilities subject to the same CO2 emissions limit, 

each affected facility sharing the stack is in compliance with the CO2 emissions limit.

(ii) If the CO2 mass emissions rate for the affected facility is greater than the CO2

emissions limit in paragraph (c) of this section applicable to the affected facility, then the 

affected facility has excess CO2 emissions. 

(h) You must prepare and submit notifications and reports according to paragraphs (h)(1) 

through (4) of this section.

(1) You must prepare and submit the notifications in §§ 60.7(a)(1) and (a)(3) and 60.19, 

as applicable to your affected facility.

(2) You must prepare and submit notifications in § 75.61 of this chapter, as applicable to 

your affected facility. 

(3) You must submit electronic quarterly reports according to the requirements specified 

in paragraphs (h)(3)(i) through (iii) of this section.

(i) Initially, after you have accumulated the required number of operating months for the 

CO2 emission limit compliance period that you have chosen to comply with (i.e., 12-operating 

months or 84-operating months), you must submit a report for the calendar quarter that includes 

the final (12th- or 84th) operating month no later than 30 days after the end of that quarter. 

Thereafter, you must submit a report for each subsequent calendar quarter no later than 30 days 

after the end of the quarter.
Page 9 of 43

(ii) In each quarterly report you must include the information in paragraphs (h)(3)(ii)(A) 

through (E) of this section.

(A) The CO2 emission limit compliance period with which you have chosen to comply.

(B) Any months in the calendar quarter that you are not counting as operating months.

(C) For each operating month in the calendar quarter, the corresponding average CO2

mass emissions rate for the applicable compliance period interval that you determined according 

to paragraph (g) of this section. 

(D) The percentage of valid CO2 mass emission rates in each compliance period (i.e., the 

total number of valid CO2 mass emission rates in that period divided by the total number of 

operating hours in that period, multiplied by 100 percent).

(E) Any operating months in the calendar quarter with excess CO2 emissions.

(iii) In the final quarterly report of each calendar year you must include the following:

(A) Net electric output sold to an electric grid over the calendar year; and

(B) The potential electric output of the facility.

(iv) You must submit each electronic report using the Emissions Collection and 

Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in 

the EPA Office of Atmospheric Programs.

(4) You must meet all applicable reporting requirements and submit reports as required 

under subpart G of part 75 of this chapter. 

(5) If your affected unit uses geologic sequestration to meet the applicable emissions 

limit, you must report in accordance with the requirements of 40 CFR part 98, subpart PP and 

either:

(i) if injection occurs onsite, report in accordance with the requirements of 40 CFR part 

98, subpart RR, or

(ii) if injection occurs offsite, transfer the captured CO2 to a facility or facilities that 

reports in accordance with the requirements of 40 CFR part 98, subpart RR.

(i) For each affected electric utility stream generating unit, you must maintain records 

according to paragraphs (i)(1) through (i)(8) of this section.

(1) You must comply with the applicable recordkeeping requirements and maintain 

records as required under subpart F of part 75 of this chapter.

(2) You must maintain records of the calculations you performed to determine the total 

CO2 mass emissions for each operating month, and the averages for each compliance period 

interval (i.e., 12-operating months or 84-operating months, as applicable to the CO2 emissions 

limits). 

(3) You must maintain records of the applicable data recorded and calculations performed 

that you used to determine the gross or net energy output for each operating month.

(4) You must maintain records of the calculations you performed to determine the 

percentage of valid CO2 mass emission rates in each compliance period. 
Page 10 of 43

(5) You must maintain records of the calculations you performed to assess compliance 

with each applicable CO2 emissions limit in paragraph (c) of this section. 

(6) Your records must be in a form suitable and readily available for expeditious review.

(7) You must maintain each record for 5 years after the date of each occurrence, 

measurement, maintenance, corrective action, report, or record except those records required to 

demonstrate compliance with an 84-operating month compliance period. You must maintain 

records required to demonstrate compliance with an 84-operating month compliance period for at 

least 10 years following the date of each occurrence, measurement, maintenance, corrective 

action, report, or record.

(8) You must maintain each record on site for at least 2 years after the date of each 

occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. 

You may maintain the records off site and electronically for the remaining year(s) as required by

this subpart.

(j) PSD and Title V Thresholds for Greenhouse Gases. (1) For purposes of 40 

CFR 51.166(b)(49)(ii), with respect to GHG emissions from new affected facilities, the 

“pollutant that is subject to the standard promulgated under section 111 of the Act” shall 

be considered to be the pollutant that otherwise is subject to regulation under the Act as 

defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted 

to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48).

(2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from 

new affected facilities, the “pollutant that is subject to the standard promulgated under 

section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to 

regulation under the Act as defined in 40 CFR 52.21(b)(49).

(3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from new 

affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of 

the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as 

defined in 40 CFR 70.2.

(4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from 

new affected facilities, the “pollutant that is subject to any standard promulgated under 

section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject 

to regulation" as defined in 40 CFR 71.2.

(k) For purposes of this section, the following definitions apply:

Gross energy output means:

(i) Except as provided under paragraph (ii) of this definition, for electric utility steam 

generating units, the gross electric or mechanical output from the affected facility (including, but 

not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) minus 

any electricity used to power the feedwater pumps plus 75 percent of the useful thermal output;

(ii) For electric utility steam generating unit combined heat and power facilities where at 

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

and at least 20.0 percent of the total gross energy output consists of useful thermal output on a 

rolling 3 year basis, the gross electric or mechanical output from the affected facility (including, 

but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) 
Page 11 of 43

minus any electricity used to power the feedwater pumps, that difference divided by 0.95, plus 

75 percent of the useful thermal output;

(iii) Except as provided under paragraph (iv) of this definition, for a IGCC electric utility

generating unit, the gross electric or mechanical output from the affected facility (including, but 

not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) plus 75 

percent of the useful thermal output; or

(iv) For IGCC electric utility generating unit combined heat and power facilities where at 

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

and at least 20.0 percent of the total gross energy output consists of useful thermal output on a 

rolling 3 year basis, the gross electric or mechanical output from the affected facility (including, 

but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) 

divided by 0.95, plus 75 percent of the useful thermal output.

IGCC facility is an integrated gasification combined cycle electric utility steam 

generating unit, which means an electric utility combined cycle facility that is designed to burn 

fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition 

of natural gas plus any integrated equipment that provides electricity or useful thermal output to 

either the affected facility or auxiliary equipment. The Administrator may waive the 50 percent 

solid-derived fuel requirement during periods of the gasification system construction, startup and 

commissioning, shutdown, or repair. No solid fuel is directly burned in the facility during 

operation.

Net-electric sales means:

(i) Except as provided under paragraph (ii) of this definition, the gross electric sales to the 

utility power distribution system minus purchased power, or

(ii) For combined heat and power facilities where at least 20.0 percent of the total gross 

or net energy output consists of electric or direct mechanical output and at least 20.0 percent of 

the total gross or net energy output consists of useful thermal output, the gross electric sales to 

the utility power distribution system minus purchased power of the thermal host facility or 

facilities; and

(iii) Electricity supplied to other facilities that produce electricity to offset auxiliary loads 

are included when calculating net-electric sales.

Net-electric output means: the amount of gross generation the generator(s) produces

(including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas 

expander(s)), as measured at the generator terminals, less the electricity used to operate the plant 

(i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control 

equipment, other electricity needs, and transformer losses as measured at the transmission side of 

the step up transformer (e.g., the point of sale).

Net energy output means:

(i) Except as provided under paragraph (ii) of this definition, the net electric or 

mechanical output from the affected facility plus 75 percent of the useful thermal output; or

(ii) For combined heat and power facilities where at least 20.0 percent of the total gross 

or net energy output consists of electric or direct mechanical output and at least 20.0 percent of 

the total gross or net energy output consists of useful thermal output on a rolling 3 year basis, the 
Page 12 of 43

net electric or mechanical output from the affected facility divided by 0.95, plus 75 percent of the 

useful thermal output.

Potential electric output means: 

(i) Either 33 percent or the design net electric output efficiency, at the election of the 

owner/operator of the affected facility, 

(ii) Multiplied by the maximum design heat input capacity of the steam generating unit,

(Btu/h)

(iii) Divided by 3,413 Btu/KWh, 

(iv) Divided by 1,000 kWh/MWh, and 

(v) Multiplied by 8,760 h/yr. 

(vi) For example, a 35 percent efficient steam generating unit with a 100 MW (341 

MMBtu/h) fossil-fuel heat input capacity would have a 310,000 MWh 12 month potential 

electric output capacity. 

Standard ambient temperature and pressure (SATP) conditions means 298.15

Kelvin (25

o C, 77 o

F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The 

enthalpy of water at SATP conditions is 50 Btu/lb.

Steam generating unit means any furnace, boiler, or other device used for 

combusting fuel for the purpose of producing steam (nuclear steam generators are not 

included) plus any integrated equipment that provides electricity or useful thermal output 

to either the boiler or auxiliary equipment.

Useful thermal output means the thermal energy made available for use in any heating 

application (e.g., steam delivered to an industrial process for a heating application, including 

thermal cooling applications) that is not used for electric generation, mechanical output at the 

affected facility, or to directly enhance the performance of the affected facility (e.g., economizer 

output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered 

useful thermal output). Useful thermal output for affected facilities with no condensate return (or 

other thermal energy input to the affected facility) or where measuring the energy in the 

condensate (or other thermal energy input to the affected facility) would not meaningfully impact 

the emission rate calculation is measured against the energy in the thermal output at SATP

conditions. Affected facilities with meaningful energy in the condensate return (or other thermal 

energy input to the affected facility) must measure the energy in the condensate and subtract that 

energy relative to SATP conditions from the measured thermal output. 
Page 13 of 43

Subpart KKKK -— Standards of Performance for Stationary Combustion Turbines

3. Section 60.4305 is amended by adding paragraph (c) to read as follows:

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

* * * * *

(c) For purposes of regulation of greenhouse gases, the applicable provisions of this 

subpart affect your stationary combustion turbine if it serves a generator capable of selling greater 

than 25 MW to a utility power distribution system and commenced construction after January 8, 

2014 or it commenced reconstruction or modification after [INSERT DATE OF PUBLICATION 

IN THE FEDERAL REGISTER].

4. Section 60.4315 is revised to read as follows:

§ 60.4315 What pollutants are regulated by this subpart?

(a) The pollutants regulated by this subpart are nitrogen oxides (NOX), sulfur dioxide 

(SO2), and greenhouse gases. 

(b)(1) The greenhouse gases regulated by this subpart consist of carbon dioxide (CO2).

(2) PSD and Title V Thresholds for Greenhouse Gases. (i) For purposes of 40 

CFR 51.166(b)(49)(ii), with respect to GHG emissions from affected stationary

combustion turbine, the “pollutant that is subject to the standard promulgated under 

section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to 

regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by 

the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 

51.166(b)(48).

(ii) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from 

affected stationary combustion turbines, the “pollutant that is subject to the standard 

promulgated under section 111 of the Act” shall be considered to be the pollutant that 

otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49).

(iii) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from 

affected stationary combustion turbines, the “pollutant that is subject to any standard 

promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise 

is "subject to regulation" as defined in 40 CFR 70.2.

(iv) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected 

stationary combustion turbines, the “pollutant that is subject to any standard promulgated under 

section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to 

regulation" as defined in 40 CFR 71.2. 

5. Section 60.4326 is added to read as follows:

§ 60.4326 What CO2 emissions standard must I meet?

You must not discharge from your affected stationary combustion turbine into the 

atmosphere any gases that contain CO2 in excess of the applicable CO2 emissions standard 

specified in Table 2 of this subpart.

6. Section 60.4333 is amended by adding paragraph (c) to read as follows:
Page 14 of 43

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

* * * * *

(c) If you own or operate an affected stationary combustion turbine subject to a CO2

emissions standard in §60.4326, you must make compliance determinations on a 12-operating 

month rolling average basis, and you must determine compliance monthly by calculating the 

average CO2 emissions rate for the affected stationary combustion turbine at the end of each 12-

operating month period.

7. Section 60.4373 is added under undesignated center heading “Monitoring” to read as 

follows:

§ 60.4373 How do I monitor and collect data to demonstrate compliance with my CO2 

emissions standard using a CO2 CEMS?

(a) You must prepare a monitoring plan in accordance with the applicable provisions in § 

75.53(g) and (h) of this chapter. 

(b) You must measure the hourly CO2 mass emissions from each affected stationary

combustion turbine using the procedures in paragraphs (b)(1) through (5) of this section, except 

as provided in paragraph (c) of this section.

(1) You must install, certify, operate, maintain, and calibrate a CO2 continuous emission 

monitoring system (CEMS) to directly measure and record CO2 concentrations in the stationary

combustion turbine exhaust gases emitted to the atmosphere and an exhaust gas flow rate 

monitoring system according to § 75.10(a)(3)(i) of this chapter. If you measure CO2

concentration on a dry basis, you must also install, certify, operate, maintain, and calibrate a 

continuous moisture monitoring system, according to § 75.11(b) of this chapter. 

(2) For each monitoring system that you use to determine the CO2 mass emissions, you 

must meet the applicable certification and quality assurance procedures in § 75.20 of this chapter 

and Appendices B and D to part 75 of this chapter.

(3) You must use a laser device to measure the dimensions of each exhaust gas stack or 

duct at the flow monitor and the reference method sampling locations prior to the initial setup 

(characterization) of the flow monitor. For circular stacks, you must make measure of the 

diameter at three or more distinct locations and average the results. For rectangular stacks or 

ducts, you must measure each dimension (i.e., depth and width) at three or more distinct 

locations and average the results. If the flow rate monitor or reference method sampling site is 

relocated, you must repeat these measurements at the new location.

(4) You must use unadjusted exhaust gas volumetric flow rates only to determine the 

hourly CO2 mass emissions from the affected stationary combustion turbine; you must not apply 

the bias adjustment factors described in section 7.6.5 of Appendix A to part 75 of this chapter to 

the exhaust gas flow rate data.

(5) If you chose to use Method 2 in Appendix A-1 to this part to perform the required 

relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a 

calibrated Type-S pitot tube or pitot tube assembly. You must not use the default Type-S pitot 

tube coefficient.

(c) As an alternative to complying with paragraph (b) of this section, you may determine 
Page 15 of 43

the hourly CO2 mass emissions by using Equation G-4 in Appendix G to part 75 of this chapter 

according to the requirements specified in paragraphs (c)(1) and (2) of this section. 

(1) You must implement the applicable procedures in appendix D to part 75 of this 

chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of 

fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel 

combusted.

(2) You may determine site-specific carbon-based F-factors (Fc) using Equation F-7b in 

section 3.3.6 of Appendix F to part 75 of this chapter, and you may use these Fc values in the 

emissions calculations instead of using the default Fc values in the Equation G-4 nomenclature.

(d) You must install, calibrate, maintain, and operate a sufficient number of watt meters 

to continuously measure and record the gross electric output from the affected stationary

combustion turbine. These measurements must be performed using 0.2 class electricity metering 

instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. If the 

affected stationary combustion turbine is a CHP stationary combustion turbine, you must also 

install, calibrate, maintain, and operate meters to continuously determine and record the total 

useful thermal output. For process steam applications, you will need to install, calibrate, 

maintain, and operate meters to continuously determine and record steam flow rate, temperature, 

and pressure. If the affected stationary combustion turbine has a direct mechanical drive 

application, you must submit a plan to the Administrator or delegated authority for approval of 

how gross energy output will be determined. Your plan shall ensure that you install, calibrate, 

maintain, and operate meters to continuously determine and record each component of the 

determination.

(e) If two or more affected stationary combustion turbines serve a common electric 

generator, you must apportion the combined hourly gross output to the individual stationary 

combustion turbines using a plan approved by the Administrator (e.g., using steam load or heat 

input to each affected stationary combustion turbine). Your plan shall ensure that you install, 

calibrate, maintain, and operate meters to continuously determine and record each component of 

the determination.

(f) In accordance with § 60.13(g), if two or more stationary combustion turbines that 

implement the continuous emission monitoring provisions in paragraph (b) of this section share a 

common exhaust gas stack and are subject to the same emissions standard under § 60.4326, you 

may monitor the hourly CO2 mass emissions at the common stack in lieu of monitoring each 

stationary combustion turbine separately. If you choose this option, the hourly gross load 

(electric, thermal, and/or mechanical, as applicable) must be the sum of the hourly loads for the 

individual stationary combustion turbines and you must express the operating time as “stack 

operating hours” (as defined in § 72.2 of this chapter). If you attain compliance with the 

applicable emissions standard in § 60.4326 at the common stack, each stationary combustion 

turbine sharing the stack is in compliance.

(g) In accordance with § 60.13(g), if the exhaust gases from a stationary combustion 

turbine that implements the continuous emission monitoring provisions in paragraph (b) of this 

section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed 

to a common stack through multiple ducts and you chose to monitor in the ducts), you must 

monitor the hourly CO2 mass emissions and the “stack operating time” (as defined in § 72.2 of 

this chapter) at each stack or duct separately. In this case, you determine compliance with the 
Page 16 of 43

applicable emissions standard in § 60.4326 by summing the CO2 mass emissions measured at the 

individual stacks or ducts and dividing by the total gross output for the unit.

8. Section 60.4374 is added under undesignated center heading “Monitoring” to read as 

follows:

§ 60.4374 How do I demonstrate compliance with my CO2 emissions standard and 

determine excess emissions?

(a) You must calculate the CO2 mass emissions rate for your affected stationary

combustion turbine by using the hourly CO2 mass emissions and total gross output data 

determined and recorded according to the procedures in § 60.4373 for the compliance period for 

the CO2 emissions standard applicable to the affected stationary combustion turbine, and the 

calculation procedures in paragraphs (a)(1) through (a)(5) of this section.

(1) You must only use operating hours in the compliance period for the compliance 

determination calculation for which you obtained valid data for all parameters you used to 

determine the hourly CO2 mass emissions and gross output data, are used for the compliance 

determination calculation. You must not include operating hours in which you used the substitute 

data provisions of part 75 of this chapter for any of the parameters in the calculation. For the 

compliance determination calculation, you must obtain valid hourly CO2 mass emission values 

for a minimum of 95 percent of the operating hours in the compliance period.

(2) You must calculate the total CO2 mass emissions by summing the hourly CO2 mass 

emissions values for the affected stationary combustion turbine determined to be valid according 

to the conditions specified in paragraph (a)(1) of this section for all of the operating hours in the 

applicable compliance period.

(3) For each operating hour of the compliance period used in paragraph (a)(2) of this 

section to calculate the total CO2 mass emissions, you must determine the affected stationary

combustion turbine’s corresponding hourly gross output (Pgross) by applying the appropriate 

definitions in §§ 60.4420 and 60.4421 of this subpart and according to the procedures specified 

in paragraphs (a)(3)(i) and (iv) of this section .

(i) Calculate Pgross for your affected stationary combustion turbine using the 

following equation:

 = 

() + () + ()

T

+ 0.75 × [ () + () + () ]

Where:

Pgross = Gross energy output of your affected stationary combustion turbine in 

megawatt-hours (MWh).

(Pe)CT = Electric energy output plus mechanical energy output (if any) of stationary

combustion turbines in MWh.

(Pe)ST = Electric energy output plus mechanical energy output (if any) of steam 

turbines in MWh.

(Pe)IE = Electric energy output plus mechanical energy output (if any) of your 

affected stationary combustion turbine’s integrated equipment that 

provides electricity to the affected facility or auxiliary equipment in MWh.
Page 17 of 43

(Pt)PS = Useful thermal output of steam (relative to SATP conditions, as 

applicable) that is used for applications that do not generate additional 

electricity, produce mechanical energy output, enhance the performance of 

the affected facility. This is calculated using the equation specified in 

paragraph (a)(3)(ii) of this section in MWh.

(Pt)HR = Useful thermal output (relative to SATP conditions, as applicable) from 

heat recovery that is used for applications other than steam generation or 

performance enhancement of the affected facility in MWh.

(Pt)IE = Useful thermal output (relative to SATP conditions, as applicable) from 

any integrated equipment that is used for applications that do not generate 

additional steam, electricity, produce mechanical energy output, or 

enhance the performance of the affected facility in MWh.

T = Electric Transmission and Distribution Factor.

T = 0.95 for a CHP stationary combustion turbine where at least on an 

annual basis 20.0 percent of the total gross energy output consists of 

electric or direct mechanical output and 20.0 percent of the total gross 

energy output consists of useful thermal output on a rolling 3 year basis.

T = 1.0 for all other affected stationary combustion turbines.

(ii) If applicable to your affected stationary combustion turbine, calculate (Pt)PS using the 

following equation:

() =

 × 

3.6 × 10

Where:

Qm = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating 

hour.

H = Enthalpy of the steam at measured temperature and pressure (relative to 

SATP conditions, as applicable) in Joules per kilogram (J/kg) (or Btu/lb).

3.6 x 109= Conversion factor (J/MWh) (or 3.413 x 106 Btu/MWh).

(iii) You must determine the hourly gross energy output for each operating hour in which 

there is no electric output, but there is mechanical output or useful thermal output. In addition 

you must determine the hourly gross CO2 emissions for each operating hour in which there is no 

useful output.

(iv) In the case for which compliance is demonstrated according to § 60.4373(f) for 

affected stationary combustion turbines that vent to a common stack, then you must calculate the 

hourly gross energy output (electric, mechanical, and/or thermal, as applicable) by summing the 

hourly gross energy output you determined for each of your individual affected stationary

combustion turbines that vent to the common stack; and you must express the operating time as 

“stack operating hours” (as defined in § 72.2 of this chapter).
Page 18 of 43

(4) You must calculate the total gross output for the affected stationary combustion 

turbine’s compliance period by summing the hourly gross output values for the affected 

stationary combustion turbine determined from paragraph (a)(2) of this section for all of the 

operating hours in the applicable compliance period.

(5) You must calculate the CO2 mass emissions rate for the affected stationary

combustion turbine by dividing the total CO2 mass emissions value as calculated according to the 

requirements of paragraph (a)(2) of this section by the total gross output value as calculated 

according to the requirements of paragraph (a)(4) of this section.

(b) If the CO2 mass emissions rate for the affected stationary combustion turbine 

determined according to the procedures specified in paragraph (a) of this section is less than or 

equal to the CO2 emissions standard in Table 2 of this subpart applicable to the affected 

stationary combustion turbine, then your affected stationary combustion turbine is in compliance 

with the emissions standard. If the average CO2 mass emissions rate is greater than the CO2

emissions standard in Table 2 of this subpart applicable to the affected stationary combustion 

turbine, then your affected stationary combustion turbine has excess CO2 emissions.

9. Section 60.4375 is amended by revising the section heading to read as follows:

§ 60.4375 What reports must I submit to comply with my NOx and SO2 emissions limits?

* * * * *

10. Section 60.4376 is added to read as follows:

§ 60.4376 What notifications and reports must I submit to comply with my CO2 emissions 

standard?

(a)(1) You must prepare and submit the notifications specified in §§ 60.7(a)(1) and (a)(3) 

and 60.19, as applicable to your affected stationary combustion turbine.

(2) You must prepare and submit notifications specified in § 75.61 of this chapter, as 

applicable to your affected stationary combustion turbine. 

(b) You must prepare and submit reports according to paragraphs (b)(1) through (d) of 

this section, as applicable.

(1) For stationary combustion turbines that are required, by § 60.4333(c), to conduct 

initial and on-going compliance determinations on a 12-operating month rolling average basis for 

the standard in § 60.4326, you must submit electronic quarterly reports as follows. After you 

have accumulated the first 12-operating months for the affected stationary combustion turbine, 

you must submit a report for the calendar quarter that includes the 12th-operating month no later 

than 30 days after the end of that quarter. Thereafter, you must submit a report for each 

subsequent calendar quarter, no later than 30 days after the end of the quarter. 

(2) In each quarterly report, you must include the following information, as applicable:

(i) Each rolling average CO2 mass emissions rate for which the last (12th) operating 

month in a 12-operating month compliance period falls within the calendar quarter. You must 

calculate each average CO2 mass emissions rate according to the requirements of § 60.4374. You 

must report the dates (month and year) of the 1st and 12th-operating months in each compliance 

period for which you performed a CO2 mass emissions rate calculation. If there are no 

compliance periods that end in the quarter, you must include a statement to that effect;
Page 19 of 43

(ii) If one or more compliance periods end in the quarter, you must identify each 

operating month in the calendar quarter with excess CO2 emissions;

(iii) The percentage of valid CO2 mass emission rates (as defined in § 60.4374) in each 

12-operating month compliance period described in paragraph (b)(2)(i) of this section (i.e., the 

total number of valid CO2 mass emission rates in that period divided by the total number of 

operating hours in that period, multiplied by 100 percent); and

(iv) The CO2 emissions standard (as identified in Table 2 of this subpart) with which your 

affected stationary combustion turbine is complying.

(3) The final quarterly report of each calendar year must contain the following:

(i) Net electric output sold to an electric grid over the 4 quarters of the calendar year; and

(ii) The potential electric output of the stationary combustion turbine.

(c) You must submit all electronic reports required under paragraph (b) of this section 

using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by 

the Clean Air Markets Division in the Office of Atmospheric Programs of the EPA.

(d) You must meet all applicable reporting requirements and submit reports as required 

under subpart G of part 75 of this chapter. 

11. Section 60.4391 is added to read as follows:

§ 60.4391 What records must I maintain to comply with my CO2 emissions limits?

(a) You must maintain records of the information you used to demonstrate compliance 

with this subpart as specified in § 60.7(b) and (f).

(b) You must follow the applicable recordkeeping requirements and maintain records as 

required under subpart F of part 75 of this chapter.

(c) You must keep records of the calculations you performed to determine the total CO2

mass emissions for:

(1) Each operating month (for all affected units);

(2) Each compliance period, including, as applicable, each 12-operating month 

compliance period.

(d) You must keep records of the applicable data recorded and calculations performed 

that you used to determine your affected stationary combustion turbine’s gross output for each 

operating month.

(e) You must keep records of the calculations you performed to determine the percentage 

of valid CO2 mass emission rates in each compliance period. 

(f) You must keep records of the calculations you performed to assess compliance with 

each applicable CO2 mass emissions standard in § 60.4326.

(g) You must keep records of the calculations you performed to determine any sitespecific carbon-based F-factors you used in the emissions calculations (if applicable).

(h)(1) Your records must be in a form suitable and readily available for expeditious 

review.
Page 20 of 43

(2) You must keep each record for 5 years after the date of each occurrence, 

measurement, maintenance, corrective action, report, or record to demonstrate compliance with a 

12-operating month emissions standard. 

(3) You must keep each record on site for at least 2 years after the date of each 

occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. 

You may keep the records off site and electronically for the remaining year(s) as required by this 

subpart.

12. Section 60.4395 is revised to read as follows:

§ 60.4395 When must I submit my reports?

All of your reports required under § 60.7(c) must be postmarked by the 30th day after the 

end of each 6-month period, except as specified in § 60.4376

13. Section 60.4421 is added to read as follows:

§ 60.4421 What definitions with respect to CO2 emissions apply to this subpart?

As used in this subpart:

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 (heat 

input from duct burners is not included).

Excess emissions means a specified averaging period over which either:

(1) The CO2 emissions rate of your affected stationary combustion turbine exceeds the 

applicable emissions standard in Table 2 of this subpart or § 60.4330; or

(2) The recorded value of a particular monitored parameter is outside the acceptable 

range specified in the parameter monitoring plan for the affected unit.

Gross energy output means:

(1) The gross electric or direct mechanical output from both the combustion turbine 

engine and any associated steam turbine(s) or integrated equipment plus any useful thermal 

output measured relative to SATP conditions (except for GHG calculations in § 60.4374 as only

75 percent credit is given) that is not used to generate additional electric or mechanical output or 

to enhance the performance of the unit (e.g., steam delivered to an industrial process for a 

heating application).

(2) For a CHP stationary combustion turbine where at least 20.0 percent of the total gross 

energy output consists of electric or direct mechanical output and at least 20.0 percent of the total 

gross energy output consists of useful thermal output on a rolling 3-year basis, the sum of the 

gross electric 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 

SATP conditions (except for GHG calculations in § 60.4374 as only 75 percent credit is given) 

that is not used to generate additional electric or mechanical output or to enhance the 

performance of the unit (e.g., steam delivered to an industrial process for a heating application). 

Net-electric sales means: 
Page 21 of 43

(1) The gross electric sales to the utility power distribution system minus purchased 

power; or

(2) For combined heat and power facilities where at least 20.0 percent of the total gross 

energy output consists of electric or direct mechanical output and at least 20.0 percent of the total 

gross energy output consists of useful thermal output on a 3 calendar year rolling average basis, 

the gross electric sales to the utility power distribution system minus purchased power of the 

thermal host facility or facilities; and

(3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads 

are included when calculating net-electric sales.

Net-electric output means: the amount of gross generation a generator produces, as 

measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary

loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, 

other electricity needs, and transformer losses as measured at the transmission side of the step up 

transformer (e.g., the point of sale).

Net energy output means:

(i) Except as provided under paragraph (ii) of this definition, the net electric or 

mechanical output from both the combustion turbine engine and any associated steam turbine(s) 

or integrated equipment plus 75 percent of the useful thermal output; or

(ii) For combined heat and power facilities where at least 20.0 percent of the total gross 

energy output consists of electric or direct mechanical output and at least 20.0 percent of the total 

gross energy output consists of useful thermal output on a rolling 3 year basis, the net electric or 

mechanical output from both the combustion turbine engine and any associated steam turbine(s) 

or integrated equipment divided by 0.95, plus 75 percent of the useful thermal output.

Operating month means a calendar month during which any fuel is combusted in the 

affected stationary combustion turbine.

Potential electric output means 33 percent or the design electric output efficiency on a net 

output basis (at the election of the owner/operator of the affected facility) multiplied by the base 

load rating (expressed in MMBtu/h) of the stationary combustion turbine, multiplied by 106

Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 

h/yr (e.g., a 35 percent efficient stationary combustion turbine with a 100 MW (341 MMBtu/h) 

fossil-fuel heat input capacity would have a 310,000 MWh 12-month potential electric output 

capacity). 

Standard ambient temperature and pressure (SATP) conditions means 298.15 

Kelvin (25o C, 77 oF)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The 

enthalpy of water at SATP conditions is 50 Btu/lb.

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 plus any

integrated equipment that provides electricity or useful thermal output to the combustion turbine 

engine, heat recovery system or auxiliary equipment. Stationary means that the combustion 

turbine is not self propelled or intended to be propelled while performing its function. It may, 
Page 22 of 43

however, be mounted on a vehicle for portability. 

Useful thermal output means the thermal energy made available for use in any heating 

application (e.g., steam delivered to an industrial process for a heating application, including 

thermal cooling applications) that is not used for electric generation, mechanical output at the 

affected facility, or to directly enhance the performance of the affected facility (e.g., economizer 

output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered 

useful thermal output). Useful thermal output for affected facilities with no condensate return (or 

other thermal energy input to the affected facility) or where measuring the energy in the 

condensate (or other thermal energy input to the affected facility) would not meaningfully impact 

the emission rate calculation is measured against the energy in the thermal output at SATP

conditions. Affected facilities with meaningful energy in the condensate return (or other thermal 

energy input to the affected facility) must measure the energy in the condensate and subtract that 

energy relative to SATP conditions from the measured thermal output. 
Page 23 of 43

14. Table 2 of Subpart KKKK of Part 60 is added to read as follows:

Table 2 of Subpart KKKK of Part 60 – Carbon Dioxide Emission Limits for Stationary 

Combustion Turbines

Note: all numerical values have a minimum of 2 significant figures

Affected Stationary Combustion Turbine CO2 Emission Standard

Stationary combustion turbine that has a design 

heat input to the turbine engine of greater than 

250 MW (850 MMBtu/h), that combusts over 

90% natural gas on a heat input basis on a 3 

year rolling average basis, and where netelectric sales consist of more than one-third of 

its potential electric output and more than 

219,000 MWh on a 3 year rolling average 

basis.

450 kilograms (kg) of CO2 per megawatt-hour 

(MWh) of gross output (1,000 lb/MWh) on a 

12-operating month rolling average

Stationary combustion turbine that has a design 

heat input to the turbine engine greater than 73 

MW (250 MMBtu/h) and equal to or less than 

250 MW (850 MMBtu/h), that combusts over 

90% natural gas on a heat input basis on a 3 

year rolling average basis, and where netelectric sales consist of more than one-third of 

its potential electric output and more than 

219,000 MWh on a 3 year rolling average 

basis..

500 kg of CO2 per MWh of gross output (1,100 

lb CO2/MWh) on a 12-operating month rolling 

average

Stationary combustion turbine that either has a 

design heat input to the turbine engine of 73 

MW (250 MMBtu/h) or less, that combusts 

90% or less natural gas on a heat input basis on 

a 3 year rolling average basis, or where netelectric sales consist of one-third or less of its 

potential electric output or 219,000 MWh or 

less on a 3 year rolling average basis.

No emission standard
Page 24 of 43

15. Table 3 of Subpart KKKK of Part 60 is added to read as follows:

Table 3 of Subpart KKKK of Part 60 – Applicability of Subpart A General Provisions to 

Stationary Combustion Turbine CO2 Emissions Standards in Subpart KKKK

General 

Provisions 

citation

Subject of citation

Applies to 

subpart 

KKKK

Explanation

§ 60.1 Applicability Yes

§ 60.2 Definitions Yes

§ 60.3 Units and Abbreviations Yes

§ 60.4 Address Yes

§ 60.5

Determination of 

construction or 

modification

Yes

§ 60.6 Review of plans Yes

§ 60.7 Notification and 

Recordkeeping Yes

Only the requirements to 

submit the notification in § 

60.7(a)(1) and (a)(3)

§ 60.8 Performance tests No

§ 60.9 Availability of 

Information Yes

§ 60.10 State authority Yes

§ 60.11

Compliance with 

standards and 

maintenance 

requirements

No

§ 60.12 Circumvention Yes

§ 60.13 Monitoring requirements Yes

§ 60.14 Modification No

§ 60.15 Reconstruction No

§ 60.16 Priority list No

§ 60.17 Incorporations by

reference Yes

§ 60.18 General control device 

requirements No

§ 60.19 General notification and 

reporting requirements Yes
Page 25 of 43

16. Part 60 is amended by adding subpart TTTT to read as follows:

Subpart TTTT -- Standards of Performance for Greenhouse Gas Emissions for Electric 

Generating Units 

Sec.

Applicability

§ 60.5508 What is the purpose of this subpart?

§ 60.5509 Am I subject to this subpart?

Emission Standards

§ 60.5515 What greenhouse gases are regulated by this subpart?

§ 60.5520 What CO2 emissions standard must I meet?

General Compliance Requirements

§ 60.5525 What are my general requirements for complying with this subpart? 

Monitoring and Compliance Determination Procedures 

§ 60.5535 How do I monitor and collect data to demonstrate compliance? 

§ 60.5540 How do I demonstrate compliance with my CO2 emissions standard and 

determine excess emissions? 

Notifications, Reports, and Records

§ 60.5550 What notifications must I submit and when?

§ 60.5555 What reports must I submit and when?

§ 60.5560 What records must I maintain?

§ 60.5565 In what form and how long must I keep my records?

Other Requirements and Information

§ 60.5570 What parts of the General Provisions apply to my affected facility?

§ 60.5575 Who implements and enforces this subpart?

§ 60.5580 What definitions apply to this subpart?

Applicability

§ 60.5508 What is the purpose of this subpart?

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

greenhouse gas (GHG) emissions from a steam generating unit, IGCC, or a stationary

combustion turbine that commences construction after January 8, 2014 or commences 

modification or reconstruction after [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER].
Page 26 of 43

§ 60.5509 Am I subject to this subpart?

(a) Except as provided for in paragraph (b) of this section, the subpart applies to any

steam generating unit, IGCC, or stationary combustion turbine that serves a generator capable of 

selling greater than 25 MW to a utility power distribution system and that commences 

construction after January 8, 2014 or commences modification or reconstruction after [INSERT 

DATE OF PUBLICATION IN THE FEDERAL REGISTER].

(b) You are not subject to the requirements of this subpart if your affected facility meets 

any one of the conditions specified in paragraphs (b)(1) through (b)(5) of this section.

(1) The proposed Wolverine EGU project described in Permit to Install No. 317-07 

issued by the Michigan Department of Environmental Quality, Air Quality Division, effective 

June 29, 2011 (as revised July 12, 2011).

(2) The proposed Washington County EGU project described in Air Quality Permit No. 

4911-303-0051-P-01-0 issued by the Georgia Department of Natural Resources, Environmental 

Protection Division, Air Protection Branch, effective April 8, 2010, provided that construction 

had not commenced for NSPS purposes as of January 8, 2014.

(3) The proposed Holcomb EGU project described in Air Emission Source Construction 

Permit 0550023 issued by the Kansas Department of Health and Environment, Division of 

Environment, effective December 16, 2010, provided that construction had not commenced for 

NSPS purposes as of January 8, 2014.

(4) Your affected facility is a municipal waste combustor unit that is subject to subpart 

Eb of this part.

(5) Your affected facility is a commercial or industrial solid waste incineration unit that is 

subject to subpart CCCC of this part.

Emission Standards

§ 60.5515 What greenhouse gases are regulated by this subpart?

(a) The greenhouse gas regulated by this subpart is carbon dioxide (CO2).

(b) PSD and Title V Thresholds for Greenhouse Gases. (1) For purposes of 40 

CFR 51.166(b)(49)(ii), with respect to GHG emissions from affected facilities, the 

“pollutant that is subject to the standard promulgated under section 111 of the Act” shall 

be considered to be the pollutant that otherwise is subject to regulation under the Act as 

defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted 

to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48).

(2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from 

affected facilities, the “pollutant that is subject to the standard promulgated under section 

111 of the Act” shall be considered to be the pollutant that otherwise is subject to 

regulation under the Act as defined in 40 CFR 52.21(b)(49).

(3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected 

facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” 

shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 

CFR 70.2.
Page 27 of 43

(4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected

facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” 

shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 

CFR 71.2. 

§ 60.5520 What CO2 emissions standard must I meet?

(a) For each affected facility subject to this subpart, you must not discharge from the 

affected facility any gases that contain CO2 in excess of the applicable CO2 emissions standard 

specified in Table 1 or Table 2 of this subpart, except for owners and operators of modified 

affected facilities complying with the standards specified in paragraph (b) of this section, as 

applicable to the affected facility. 

(b) The owner or operator of a modified steam generating unit or IGCC facility

complying with the requirements of this paragraph are not required to comply with the emission 

limit in Table 2 to this subpart.

(1) If the affected facility is not subject to an approved CAA section 111(d) plan (state or 

federal) at the time of the modification, the owner/operator may elect to comply with a sitespecific 12-operating month rolling average CO2 emission limit calculated as 2 percent lower

than (i.e., 98 percent) the best demonstrated annual historical operating performance for the 

affected facility using historical CO2 emissions data for the calendar years 2002 through the most 

recent full calendar year the affected facility was operating prior to the modification using either 

recorded net output emission rate data or gross electrical output and CO2 emissions data as 

reported under part 75 of this chapter. If incomplete or no data has been submitted under part 75 

of this chapter, the Administrator or delegated authority shall approve the use of alternate data 

sources. The equivalent net output-based standard shall be calculated from gross output-based 

data assuming a 7.5 percent auxiliary (i.e., parasitic) load (i.e., the best annual value is divided 

by 0.925); or

(2) If the affected facility is subject to an approved CAA section 111(d) plan (state or 

federal) at the time of the modification, a site-specific 12-operating month rolling average CO2

emission limit determined by the CAA section 111(d) implementing authority based on the 

affected facility performing an energy assessment by an energy professional or engineer that 

have expertise in evaluating energy systems to identify applicable energy efficiency projects that 

you will implement at the affected facility to improve the affected facility’s operating 

performance. You must maintain a copy of the most recent energy assessment report. The energy

assessment must include at a minimum the elements in paragraphs (b)(2)(i) through (b)(2)(iii) of 

this section.

(i) A visual inspection of the facility to identify steam leaks or other sources of reduced 

efficiency,

(ii) A review of available engineering plans and facility operation and maintenance 

procedures and logs, and

(iii) A comprehensive report detailing the ways to improve efficiency, the cost of specific 

improvements, benefits, and the time frame for recouping those investments.

General Compliance Requirements

§ 60.5525 What are my general requirements for complying with this subpart?
Page 28 of 43

(a) You must be in compliance with the emission standards in this subpart that apply to 

your affected facility at all times. However, you must make a compliance determination only at 

the end of the applicable operating month, as provided in paragraphs (a)(1) and (2) of this 

section.

(1) For each affected facility subject to a CO2 emissions standard based on a 12-operating 

month rolling average, you must determine compliance monthly by calculating the average CO2

emissions rate for the affected facility at the end of each 12-operating month period.

(2) For each affected facility subject to a CO2 emissions standard based on an 84-

operating month rolling average, you must determine compliance monthly by calculating the 

average CO2 emissions rate for the affected facility at the end of each 84-operating month period.

(b) At all times you must operate and maintain each affected facility, including associated 

equipment and monitoring equipment, in a manner consistent with safety and good air pollution 

control practice. The Administrator will determine if you are using consistent operation and 

maintenance procedures based on information available to the Administrator that may include, 

but is not limited to, fuel use records, monitoring results, review of operation and maintenance 

procedures and records, review of reports required by this subpart, and inspection of the facility.

(c) You must conduct an initial compliance determination for your affected facility for 

the applicable emissions standard in § 60.5520, according to the requirements in this subpart, 

within 30 days after the end of the initial compliance period for the CO2 emissions standards 

applicable to your affected facility (i.e., 12-operating months or 84-operating months). The first 

operating month included in this compliance period is the month in which emissions reporting is 

required to begin under §75.64(a) of this chapter.

Monitoring and Compliance Determination Procedures 

§ 60.5535 How do I monitor and collect data to demonstrate compliance?

(a) You must prepare a monitoring plan in accordance with the applicable provisions in § 

75.53(g) and (h) of this chapter. 

(b) You must measure the hourly CO2 mass emissions from each affected facility using 

the procedures in paragraphs (b)(1) through (5) of this section, except as provided in paragraph 

(c) of this section.

(1) You must install, certify, operate, maintain, and calibrate a CO2 continuous emission 

monitoring system (CEMS) to directly measure and record CO2 concentrations in the affected 

facility exhaust gases emitted to the atmosphere and an exhaust gas flow rate monitoring system 

according to § 75.10(a)(3)(i) of this chapter. If you measure CO2 concentration on a dry basis, 

you must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring 

system, according to § 75.11(b) of this chapter. 

(2) For each monitoring system you use to determine the CO2 mass emissions, you must 

meet the applicable certification and quality assurance procedures in § 75.20 of this chapter and 

Appendices B and D to part 75 of this chapter.

(3) You must use a laser device to measure the dimensions of each exhaust gas stack or

duct at the flow monitor and the reference method sampling locations prior to the initial setup 

(characterization) of the flow monitor. For circular stacks, you must measure the diameter at 

three or more distinct locations and average the results. For rectangular stacks or ducts, you must 
Page 29 of 43

measure each dimension (i.e., depth and width) at three or more distinct locations and average 

the results. If the flow rate monitor or reference method sampling site is relocated, you must 

repeat these measurements at the new location.

(4) You must use only unadjusted exhaust gas volumetric flow rates to determine the 

hourly CO2 mass emissions from the affected facility; you must not apply the bias adjustment 

factors described in section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow 

rate data.

(5) If you choose to use Method 2 in Appendix A-1 to this part to perform the required 

relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a 

calibrated Type-S pitot tube or pitot tube assembly. You must not use the default Type-S pitot 

tube coefficient.

(c) If your affected facility exclusively combusts liquid fuel and/or gaseous fuel as an 

alternative to complying with paragraph (b) of this section, you may determine the hourly CO2

mass emissions by using Equation G-4 in Appendix G to part 75 of this chapter according to the 

requirements in paragraphs (c)(1) and (2) of this section. 

(1) You must implement the applicable procedures in appendix D to part 75 of this 

chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of 

fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel 

combusted.

(2) You may determine site-specific carbon-based F-factors (Fc) using Equation F-7b in 

section 3.3.6 of appendix F to part 75 of this chapter, and you may use these Fc values in the 

emissions calculations instead of using the default Fc values in the Equation G-4 nomenclature.

(d) You must install, calibrate, maintain, and operate a sufficient number of watt meters 

to continuously measure and record the gross or net electric output from the affected facility. 

These measurements must be performed using 0.2 class electricity metering instrumentation and 

calibration procedures as specified under ANSI Standards No. C12.20. If the affected facility is a 

CHP facility, you must also install, calibrate, maintain, and operate meters to continuously

determine and record the total useful thermal output. For process steam applications, you will 

need to install, calibrate, maintain, and operate meters to continuously determine and record 

steam flow rate, temperature, and pressure. If the affected facility has a direct mechanical drive 

application, you must submit a plan to the Administrator or delegated authority for approval of 

how gross or net energy output will be determined. Your plan shall ensure that you install, 

calibrate, maintain, and operate meters to continuously determine and record each component of 

the determination.

(e) If two or more affected facilities serve a common electric generator, you must 

apportion the combined hourly gross or net output to the individual affected facilities using a 

plan approved by the Administrator (e.g., using steam load or heat input to each affected EGU). 

Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously

determine and record each component of the determination.

(f) In accordance with § 60.13(g), if two or more affected facilities that implement the 

continuous emission monitoring provisions in paragraph (b) of this section share a common 

exhaust gas stack and are subject to the same emissions standard under § 60.5520, you may

monitor the hourly CO2 mass emissions at the common stack in lieu of monitoring each EGU 
Page 30 of 43

separately. If you choose this option, the hourly gross or net load (electric, thermal, and/or 

mechanical, as applicable) must be the sum of the hourly loads for the individual affected facility

and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this 

chapter). If you attain compliance with the applicable emissions standard in § 60.5520 at the 

common stack, each affected facility sharing the stack is in compliance.

(g) In accordance with § 60.13(g), if the exhaust gases from an affected facility that 

implements the continuous emission monitoring provisions in paragraph (b) of this section are 

emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a 

common stack through multiple ducts and you elect to monitor in the ducts), you must monitor 

the hourly CO2 mass emissions and the “stack operating time” (as defined in § 72.2 of this 

chapter) at each stack or duct separately. In this case, you must determine compliance with the 

applicable emissions standard in § 60.5520 by summing the CO2 mass emissions measured at the 

individual stacks or ducts and dividing by the total gross or net output for the affected facility.

§60.5540 How do I demonstrate compliance with my CO2 emissions standard and 

determine excess emissions?

(a) You must calculate the CO2 mass emissions rate for your affected facility by using the 

hourly CO2 mass emissions and total gross or net output data determined and recorded according 

to the procedures in § 60.5535 for each operating hour in the compliance period for the CO2

emissions standard applicable to the affected facility (i.e., 12- or 84-operating month rolling 

average period), and the calculation procedures in paragraphs (a)(1) through (a)(5) of this 

section.

(1) You can only use operating hours in the compliance period for the compliance 

determination calculation if valid data are obtained for all parameters you used to determine the 

hourly CO2 mass emissions and the gross or net output data are used for the compliance 

determination calculation. You must not include operating hours in which you used the substitute 

data provisions of part 75 of this chapter for any of those parameters in the calculation. For the 

compliance determination calculation, you must obtain valid hourly CO2 mass emission values 

for a minimum of 95 percent of the operating hours in the compliance period for the CO2 

emissions standard applicable to the affected facility.

(2) You must calculate the total CO2 mass emissions by summing the valid hourly CO2

mass emissions values for all of the operating hours in the applicable compliance period. 

(3) For each operating hour of the compliance period that you used in paragraph (a)(2) of 

this section to calculate the total CO2 mass emissions, you must determine the affected facility’s 

corresponding hourly gross or net output according to the procedures in paragraphs (a)(3)(i) and 

(ii) of this section, as appropriate for the type of affected facility. For an operating hour in which 

there is no gross or net electric load, but there is mechanical or useful thermal output, you must 

still determine the gross or net output for that hour. In addition, for operating hours in which 

there is no useful output, you still need to determine the CO2 emissions for that hour. For hours 

or partial hours where the gross generation is equal to or less than the auxiliary loads, net electric 

output shall be counted as zero for this calculation.

(i) Calculate Pgross/net for your affected facility using the following equation:

/ = 

() + () + () − ()

T

+ 0.75 × [ () + () + () ]
Page 31 of 43

Where: a

Pgross/net = Gross or net energy output of your affected facility in megawatt-hours 

(MWh).

(Pe)ST = Electric energy output plus mechanical energy output (if any) of steam 

turbines in MWh.

(Pe)CT = Electric energy output plus mechanical energy output (if any) of stationary

combustion turbine(s) in MWh.

(Pe)IE = Electric energy output plus mechanical energy output (if any) of your 

affected facility’s integrated equipment that provides electricity or 

mechanical energy to the affected facility or auxiliary equipment in MWh.

(Pe)FW = Electric energy used to power boiler feedwater pumps at steam generating 

units in MWh. Not applicable to stationary combustion turbines, IGCC 

facilities, or facilities complying with a net output based standard.

(Pt)PS = Useful thermal output of steam (measured relative to SATP conditions, as 

applicable) that is used for applications that do not generate additional 

electricity, produce mechanical energy output, or enhance the performance 

of the affected facility. This is calculated using the equation specified in 

paragraph (g)(3)(iii)(B) of this section in MWh.

(Pt)HR = Non steam useful thermal output (measured relative to SATP conditions, 

as applicable) from heat recovery that is used for applications other than 

steam generation or performance enhancement of the affected facility in 

MWh.

(Pt)IE = Useful thermal output (relative to SATP conditions, as applicable) from 

any integrated equipment that is used for applications that do not generate 

additional steam, electricity, produce mechanical energy output, or 

enhance the performance of the affected facility in MWh.

T = Electric Transmission and Distribution Factor.

T = 0.95 for a combined heat and power affected facility where at least on 

an annual basis 20.0 percent of the total gross or net energy output consists 

of electric or direct mechanical output and 20.0 percent of the total gross 

or net energy output consists of useful thermal output on a rolling 3 year 

basis.

T = 1.0 for all other affected facilities.

(ii) If applicable to your affected facility, you must calculate (Pt)PS using the following 

equation:

() =

 × 

3.6 × 10

Where:
Page 32 of 43

Qm = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating 

hour.

H = Enthalpy of the steam at measured temperature and pressure (relative to 

SATP conditions, as applicable) in Joules per kilogram (J/kg) (or Btu/lb).

3.6 x 109= Conversion factor (J/MWh) (or 3.413 x 106 Btu/MWh).

(4) You must calculate the total gross or net output for the affected facility’s compliance 

period by summing the hourly gross or net output values for the affected facility that you 

determined from paragraph (a)(2) of this section for all of the operating hours in the applicable 

compliance period.

(5) You must calculate the CO2 mass emissions rate for the affected facility by dividing 

the total CO2 mass emissions value calculated according to the procedures in paragraph (a)(2) of 

this section by the total gross or net output value calculated according to the procedures in 

paragraph (a)(4) of this section.

(b) If the CO2 mass emissions rate for your affected facility that you determined 

according to the procedures specified in paragraph (a) of this section is less than or equal to the 

CO2 emissions standard in Table 1 of this subpart applicable to the affected facility, then your 

affected facility is in compliance with the emissions standard. If the average CO2 mass emissions 

rate is greater than the CO2 emissions standard in Table 1 of this subpart applicable to the 

affected facility, then your affected facility has excess CO2 emissions.

Notification, Reports, and Records

§ 60.5550 What notifications must I submit and when?

(a) You must prepare and submit the notifications specified in §§ 60.7(a)(1) and (a)(3) 

and 60.19, as applicable to your affected facility.

(b) You must prepare and submit notifications specified in § 75.61 of this chapter, as 

applicable to your affected facility. 

§ 60.5555 What reports must I submit and when?

(a) You must prepare and submit reports according to paragraphs (a) through (d) of this 

section, as applicable.

(1) For affected facilities that are required by § 60.5525 to conduct initial and on-going 

compliance determinations on a 12- or 84-operating month rolling average basis for the standard 

in § 60.5520 you must submit electronic quarterly reports as follows. After you have 

accumulated the first 12-operating months for the affected facility (or, the first 84-operating 

months for an affected facility electing to comply with the 84-operating month standard), you 

must submit a report for the calendar quarter that includes the twelfth (or eighty-fourth) 

operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a 

report for each subsequent calendar quarter, no later than 30 days after the end of the quarter. 

(2) In each quarterly report you must include the following information, as applicable:

(i) Each rolling average CO2 mass emissions rate for which the last (12th or eightyfourth) operating month in a 12- or 84-operating month compliance period falls within the 
Page 33 of 43

calendar quarter. You must calculate each average CO2 mass emissions rate according to the 

procedures in § 60.5540. You must report the dates (month and year) of the first and twelfth (or 

eighty-fourth) operating months in each compliance period for which you performed a CO2 mass 

emissions rate calculation. If there are no compliance periods that end in the quarter, you must 

include a statement to that effect;

(ii) If one or more compliance periods end in the quarter you must identify each operating 

month in the calendar quarter with excess CO2 emissions;

(iii) The percentage of valid CO2 mass emission rates (as defined in § 60.5540) in each 

12- or 84-operating month compliance period described in paragraph (a)(1)(i) of this section (i.e., 

the total number of valid CO2 mass emission rates in that period divided by the total number of 

operating hours in that period, multiplied by 100 percent); and

(iv) The CO2 emissions standard (as identified in Table 1 of this subpart) with which your 

affected facility is complying.

(3) In the final quarterly report of each calendar year, you must include the following:

(i) Gross electric output sold to an electric grid over the 4 quarters of the calendar year; 

and

(ii) The potential electric output of the facility.

(b) You must submit all electronic reports required under paragraph (a) of this section 

using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by

the Clean Air Markets Division in the Office of Atmospheric Programs of EPA.

(c) You must meet all applicable reporting requirements and submit reports as required 

under subpart G of part 75 of this chapter. 

(d) If your affected unit employs geologic sequestration to meet the applicable emission 

limit, you must report in accordance with the requirements of 40 CFR part 98, subpart PP and 

either:

(1) if injection occurs onsite, report in accordance with the requirements of 40 CFR part 

98, subpart RR, or

(2) if injection occurs offsite, transfer the captured CO2 to a facility or facilities that 

reports in accordance with the requirements of 40 CFR part 98, subpart RR.

§ 60.5560 What records must I maintain?

(a) You must maintain records of the information you used to demonstrate compliance 

with this subpart as specified in § 60.7(b) and (f).

(b) You must follow the applicable recordkeeping requirements and maintain records as 

required under subpart F of part 75 of this chapter.

(c) You must keep records of the calculations you performed to determine the total CO2

mass emissions for:

(1) Each operating month (for all affected units);

(2) Each compliance period, including, as applicable, each 12-operating month 

compliance period and the 84-operating month compliance period.
Page 34 of 43

(d) You must keep records of the applicable data recorded and calculations performed 

that you used to determine your affected facility’s gross or net output for each operating month.

(e) You must keep records of the calculations you performed to determine the percentage 

of valid CO2 mass emission rates in each compliance period. 

(f) You must keep records of the calculations you performed to assess compliance with 

each applicable CO2 mass emissions standard in § 60.5520.

(g) You must keep records of the calculations you performed to determine any sitespecific carbon-based F-factors you used in the emissions calculations (if applicable).

§ 60.5565 In what form and how long must I keep my records?

(a) Your records must be in a form suitable and readily available for expeditious review.

(b) You must maintain each record for 5 years after the date of each occurrence, 

measurement, maintenance, corrective action, report, or record except those records required to 

demonstrate compliance with an 84-operating month compliance period. You must maintain 

records required to demonstrate compliance with an 84-operating month compliance period for at 

least 10 years following the date of each occurrence, measurement, maintenance, corrective 

action, report, or record.

(c) You must maintain each record on site for at least 2 years after the date of each 

occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. 

You may maintain the records off site and electronically for the remaining year(s) as required by

this subpart.

Other Requirements and Information

§ 60.5570 What parts of the General Provisions apply to my affected facility?

Notwithstanding any other provision of this chapter, certain parts of the General 

Provisions in §§ 60.1 through 60.19, listed in Table 2 of this subpart, do not apply to your 

affected facility.

§ 60.5575 Who implements and enforces this subpart?

(a) This subpart can be implemented and enforced by the EPA, or a delegated authority 

such as your state, local, or tribal agency. If the Administrator has delegated authority to your 

state, local, or tribal agency, then that agency (as well as the EPA) has the authority to implement 

and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart 

is delegated to your state, local, or tribal agency.

(b) In delegating implementation and enforcement authority of this subpart to a state, 

local, or tribal agency, the Administrator retains the authorities listed in paragraphs (b)(1) 

through (5) of this section and does not transfer them to the state, local, or tribal agency. In 

addition, the EPA retains oversight of this subpart and can take enforcement actions, as 

appropriate.

(1) Approval of alternatives to the emission standards.

(2) Approval of major alternatives to test methods.

(3) Approval of major alternatives to monitoring.
Page 35 of 43

(4) Approval of major alternatives to recordkeeping and reporting.

(5) Performance test and data reduction waivers under § 60.8(b).

§ 60.5580 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).

Base load rating means the maximum amount of heat input (fuel) that a steam generating 

unit can combust on a steady state basis, as determined by the physical design and characteristics 

of the steam generating unit at ISO conditions. For a stationary combustion turbine, base load

rating means 100 percent of the design heat input capacity of the simple cycle portion of the 

stationary combustion turbine at ISO conditions (heat input from duct burners is not included).

Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite 

by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, 

see § 60.17), coal refuse, and petroleum coke. Synthetic fuels derived from coal for the purpose 

of creating useful heat, including but not limited to solvent-refined coal, gasified coal (not 

meeting the definition of natural gas), coal-oil mixtures, and coal-water mixtures are included in 

this definition for the purposes of this subpart.

Coal refuse means waste products of coal mining, physical coal cleaning, and coal 

preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay, and other 

organic and inorganic material.

Combined cycle facility means an electric generating unit that uses a stationary

combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat 

recovery steam generating unit to generate additional electricity.

Combined heat and power facility or CHP facility, (also known as “cogeneration”) means 

an electric generating unit that that use a steam-generating unit or stationary combustion turbine 

to simultaneously produce both electric (or mechanical) and useful thermal output from the same 

primary energy source.

Distillate oil means fuel oils that contain no more than 0.05 weight percent nitrogen and 

comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society 

of Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17); diesel fuel oil 

numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 

(incorporated by reference, see § 60.17); kerosene, 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).

Excess emissions means a specified averaging period over which the CO2 emissions rate 

is higher than the applicable emissions standard located in Table 1 of this subpart.

Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous 

fuel derived from such material for the purpose of creating useful heat.

Gaseous fuel means any fuel that is present as a gas at ISO conditions and includes, but is 

not limited to, natural gas, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and 
Page 36 of 43

gasified coal.

Gross energy output means:

(1) For stationary combustion turbines and IGCC facilities, the gross electric or direct 

mechanical output from both the unit (including, but not limited to, output from steam turbine(s), 

combustion turbine(s), and gas expander(s)) plus 75 percent of the useful thermal output.

(2) For electric utility steam generating units, the gross electric or mechanical output 

from the affected facility (including, but not limited to, output from steam turbine(s), combustion 

turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps plus 75 

percent of the useful thermal output;

(3) For combined heat and power facilities where at least 20.0 percent of the total gross 

energy output consists of electric or direct mechanical output and 20.0 percent of the total gross 

energy output consists of useful thermal output on a rolling 3 year basis, the gross electric or 

mechanical output from the affected facility (including, but not limited to, output from steam 

turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the 

feedwater pumps (the electric auxiliary load of boiler feedwater pumps is not applicable to IGCC 

facilities), that difference divided by 0.95, plus 75 percent of the useful thermal output.

Heat recovery steam generating unit (HRSG) means a unit in which 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 facility or IGCC facility means a combined cycle 

facility that has a design heat input greater than 73 MW (250MMBtu/h) heat input of fossil fuel 

(either alone or in combination with any other fuel), was constructed for the purpose of 

supplying one-third or more of its potential electric output and more than 219,000 MWh for netelectric sales on an annual basis, and is designed to burn fuels containing 50 percent (by heat 

input) or more solid-derived fuel not meeting the definition of natural gas plus any integrated 

equipment that provides electricity or useful thermal output to either the affected facility or 

auxiliary equipment. The Administrator may waive the 50 percent solid-derived fuel requirement 

during periods of the gasification system construction, startup and commissioning, shutdown, or 

repair. No solid fuel is directly burned in the unit during operation.

ISO conditions means 288 Kelvin (15o C), 60 percent relative humidity and 101.3 

kilopascals pressure.

Liquid fuel means any fuel that is present as a liquid at ISO conditions and includes, but 

is not limited to, distillate oil and residual oil. 

Mechanical output means the useful mechanical energy that is not used to operate the 

affected facility, generate electricity and/or thermal energy, or to enhance the performance of the 

affected facility. Mechanical energy measured in horsepower hour should be converted into 

MWh by multiplying it by 745.7 then dividing by 1,000,000.

Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), 

composed of at least 70 percent methane by volume or that has a gross calorific value between 

35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard 

cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 
Page 37 of 43

20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not 

include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast 

furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a 

process which might result in highly variable sulfur content or heating value.

Net-electric sales means:

(1) The gross electric sales to the utility power distribution system minus purchased 

power; or

(2) For combined heat and power facilities where at least 20.0 percent of the total gross 

energy output consists of electric or direct mechanical output and at least 20.0 percent of the total 

gross energy output consists of useful thermal output, the gross electric sales to the utility power 

distribution system minus purchased power of the thermal host facility or facilities; and

(3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads 

are included when calculating net-electric sales.

Net-electric output means: the amount of gross generation the generator(s) produces 

(including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas 

expander(s)), as measured at the generator terminals, less the electricity used to operate the plant 

(i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control 

equipment, other electricity needs, and transformer losses as measured at the transmission side of

the step up transformer (e.g., the point of sale).

Net energy output means:

(i) Except as provided under paragraph (ii) of this definition, the net electric or 

mechanical output from the affected facility plus 75 percent of the useful thermal output; or

(ii) For combined heat and power facilities where at least 20.0 percent of the total gross 

or net energy output consists of electric or direct mechanical output and at least 20.0 percent of 

the total gross or net energy output consists of useful thermal output on a rolling 3 year basis, the 

net electric or mechanical output from the affected facility divided by 0.95, plus 75 percent of the 

useful thermal output;

Operating month means a calendar month during which any fuel is combusted in the 

affected facility at any time.

Petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, 

distillate and residual oil.

Potential electric output means 33 percent or the design electric output efficiency on a net 

output basis multiplied by the maximum design heat input capacity (expressed in MMBtu/h) of 

the steam generating unit, multiplied by 106 Btu/MMBtu, divided by 3,413 Btu/KWh, divided by

1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 percent efficient affected facility with 

a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 310,000 MWh 12 month 

potential electric output capacity). 

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. 
Page 38 of 43

Standard ambient temperature and pressure (SATP) conditions means 298.15 

Kelvin (25o C, 77 oF)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The 

enthalpy of water at SATP conditions is 50 Btu/lb.

Stationary combustion turbine means all equipment, including but not limited to the 

turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except 

emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, postcombustion emission control technology, and any ancillary components and sub-components 

comprising any simple cycle stationary combustion turbine, any combined cycle combustion 

turbine, and any combined heat and power combustion turbine based system plus any integrated 

equipment that provides electricity or useful thermal output to the combustion turbine engine, 

heat recovery system or auxiliary equipment. 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. If a stationary combustion turbine burns any solid fuel 

directly it is considered a steam generating unit.

Steam generating unit means any furnace, boiler, or other device used for combusting 

fuel and producing steam (nuclear steam generators are not included) that has a design heat input 

greater than 73 MW (250MMBtu/h) heat input of fossil fuel (either alone or in combination with 

any other fuel) and that was constructed for the purpose of supplying one-third or more of its 

potential electric output and more than 219,000 MWh as net-electric salesan annual basis plus 

any integrated equipment that provides electricity or useful thermal output to the affected facility

or auxiliary equipment.

Useful thermal output means the thermal energy made available for use in any heating 

application (e.g., steam delivered to an industrial process for a heating application, including 

thermal cooling applications) that is not used for electric generation, mechanical output at the 

affected facility, or to directly enhance the performance of the affected facility (e.g., economizer 

output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered 

useful thermal output). Useful thermal output for affected facilities with no condensate return (or 

other thermal energy input to the affected facility) or where measuring the energy in the 

condensate (or other thermal energy input to the affected facility) would not meaningfully impact 

the emission rate calculation is measured against the energy in the thermal output at SATP

conditions. Affected facilities with meaningful energy in the condensate return (or other thermal 

energy input to the affected facility) must measure the energy in the condensate and subtract that 

energy relative to SATP conditions from the measured thermal output..
Page 39 of 43

Table 1 of Subpart TTTT of Part 60 – CO2 Emission Standards for Affected Facilities that 

Commenced Construction after January 8, 2014

Note: all numerical values have a minimum of 2 significant figures

Affected Facility CO2 Emission Standard

Stationary combustion turbine that has a base 

load rating heat input to the turbine engine of 

greater than 250 MW (850 MMBtu/h), that 

combusts over 90% natural gas on a heat 

input basis on a 3 year rolling average basis, 

and where net-electric sales consist of more 

than one-third of its potential electric output 

and more than 219,000 MWh on a 3 year 

rolling average basis.

450 kilograms (kg) of CO2 per megawatt-hour 

(MWh) of gross output (1,000 lb/MWh) on a 

12-operating month rolling average

Stationary combustion turbine that has a 

design heat input to the turbine engine greater 

than 73 MW (250 MMBtu/h) and equal to or 

less than 250 MW (850 MMBtu/h), that 

combusts over 90% natural gas on a heat 

input basis on a 3 year rolling average basis, 

and where net-electric sales consist of more 

than one-third of its potential electric output 

and more than 219,000 MWh on a 3 year 

rolling average basis.

500 kg of CO2 per MWh of gross output

(1,100 lb CO2/MWh) on a 12-operating 

month rolling average

Stationary combustion turbine that either has 

a design heat input to the turbine engine of 73 

MW (250 MMBtu/h) or less, that combusts 

90% or less natural gas on a heat input basis 

on a 3 year rolling average basis, or where 

net-electric sales consist of one-third or less 

of its potential electric output or 219,000 

MWh or less on a 3 year rolling average basis.

No emission standard

Steam generating unit that burns fossil fuel 

for more than 10.0 percent of the heat input 

during a 3 year rolling average basis.

500 kg of CO2 per MWh of gross energy

output (1,100 lb CO2/MWh) on a 12-

operating month rolling average basis; 

or

480 kg of CO2 per MWh of gross energy

output (1,050 lb CO2/MWh) on an 84-

operating month rolling average basis.

Integrated gasification combined cycle 

(IGCC) facility that burns fossil fuel for more 

than 10.0 percent of the heat input during a 3 

year rolling average basis.

500 kg of CO2 per MWh of gross energy

output (1,100 lb CO2/MWh) on a 12-

operating month rolling average basis; 

or

480 kg of CO2 per MWh of gross energy

output (1,050 lb CO2/MWh) on an 84-
Page 40 of 43

operating month rolling average basis.

Steam generating unit or IGCC facility that 

burns fossil fuel for 10.0 percent or less of the 

heat input during a 3 year rolling average 

basis.

No emission standard
Page 41 of 43

Table 2 of Subpart TTTT of Part 60 – CO2 Emission Standards for Affected Facilities (as 

applicable)

1

that Commenced Reconstruction or Modification after [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER] 

Note: all numerical values have a minimum of 2 significant figures

Affected Facility CO2 Emission Standard

Stationary combustion turbine that has a 

design heat input to the turbine engine greater 

than 73 MW (250 MMBtu/h) and equal to or 

less than 250 MW (850 MMBtu/h), that 

combusts over 90% natural gas on a heat 

input basis on a 3 year rolling average basis, 

and where net-electric sales consist of more 

than one-third of its potential electric output 

and more than 219,000 MWh on a 3 year 

rolling average basis.

510 kg of CO2 per MWh of gross output 

(1,100 lb CO2/MWh) on a 12-operating 

month rolling average

Stationary combustion turbine that has a base 

load rating heat input to the turbine engine of 

greater than 250 MW (850 MMBtu/h), that 

combusts over 90% natural gas on a heat 

input basis on a 3 year rolling average basis, 

and where net-electric sales consist of more 

than one-third of its potential electric output 

and more than 219,000 MWh on a 3 year 

rolling average basis.

460 kilograms (kg) of CO2 per megawatt-hour 

(MWh) of gross output (1,000 lb/MWh) on a 

12-operating month rolling average

Stationary combustion turbine that either has 

a design heat input to the turbine engine of 73 

MW (250 MMBtu/h) or less, that combusts 

90% or less natural gas on a heat input basis 

on a 3 year rolling average basis, or where 

net-electric sales consist of one-third or less 

of its potential electric output or 219,000 

MWh or less on a 3 year rolling average 

basis.

No emission standard

Steam generating unit or integrated 

gasification combined cycle (IGCC) facility

that has a design heat input of 590 MW 

(2,000 MMBtu/h) or less and that burns fossil 

fuel for more than 10.0 percent of the heat 

input during a 3 year rolling average basis.

950 kg of CO2 per MWh of net energy output 

(2,100 lb CO2/MWh) on a 12-operating 

month rolling average basis; 

Steam generating unit or IGCC facility that 860 kg of CO2 per MWh of net energy output 

 

1 The emission standards in Table 2 are not applicable to modified steam generating units and IGCC facilities 

subject to an approved CAA section 111(d) plan at the time of the modification or modified steam generating units 

and IGCC facilities not subject to an approved CAA section 111(d) plan at the time of the modification that elect to 

comply with an emission standard based on historical operating data.
Page 42 of 43

has a design heat input greater than 590 MW 

(2,000 MMBtu/h) and that burns fossil fuel 

for more than 10.0 percent of the heat input 

during a 3 year rolling average basis.

(1,900 lb CO2/MWh) on a 12-operating 

month rolling average basis; 

Steam generating unit or IGCC facility that 

burns fossil fuel for 10.0 percent or less of the 

heat input during a 3 year rolling average 

basis.

No emission standard
Page 43 of 43

Table 3 of Subpart TTTT of Part 60 – Applicability of Subpart A General Provisions to 

Subpart TTTT

General 

Provisions 

citation

Subject of citation

Applies to 

subpart 

TTTT

Explanation

§ 60.1 Applicability Yes

§ 60.2 Definitions Yes Additional terms defined 

in § 60.5580

§ 60.3 Units and Abbreviations Yes

§ 60.4 Address Yes

§ 60.5

Determination of 

construction or 

modification

Yes

§ 60.6 Review of plans Yes

§ 60.7 Notification and 

Recordkeeping Yes

Only the requirements to 

submit the notification in § 

60.7(a)(1) and (a)(3)

§ 60.8 Performance tests No

§ 60.9 Availability of 

Information Yes

§ 60.10 State authority Yes

§ 60.11

Compliance with 

standards and 

maintenance 

requirements

No

§ 60.12 Circumvention Yes

§ 60.13 Monitoring requirements Yes

§ 60.14 Modification No

§ 60.15 Reconstruction No

§ 60.16 Priority list No

§ 60.17 Incorporations by

reference Yes

§ 60.18 General control device 

requirements No

§ 60.19 General notification and 

reporting requirements Yes