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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 (Proposed 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 co-proposed 

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, 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. 

 
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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 construction commenced after 

[DATE OF PUBLICATION IN THE FEDERAL REGISTER], and the affected facilityit meets 

the conditions specified in paragraphs (a)(1) andor (a)(2) of this section, except as specified in 

paragraph (b) of this section. 

(1) Construction commenced after January 8, 2014 and meets the conditions specified in 

paragraphs (a)(1)(i), (a)(1)(ii), and (a)(1)(iii) of this section. 

(i) The affected facility was constructed for the purpose of supplying more than one-third 

of its potential electric output capacity and more than 219,000 MWh as net-electric sales on an 

annual basis; 

(ii) The affected facility combusts fossil fuel for more than 10.0 percent of the heat input 

during any 3 consecutive calendar years; and.

(2iii) The affected facility supplies more than one-third of its potential electric output and 

more than 219,000 MWh net-electric output to a utility power distribution system for sale on an 

annual basis. 

(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 limitationlimit specified in either paragraphs (c)(1) or (c)(2) of this 

sectionparagraph. 

(1(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 
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facility any gases that contain CO2 in excess of the emissions limit specified in paragraph 

(c)(1)(i) or (c)(1) (ii) 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; or 

(2ii) 480 kg of CO2 per MWh of gross energy output (1,050 lb CO2/MWh) on an 84-

operating month rolling average basis. 

(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

in excess of the emissions limit specified in paragraph (c)(2)(i) or (c)(2)(ii) 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; or 

(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. 

(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 
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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 

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 electare subject to comply with thea 12-operating month CO2 emissions 

limitation in paragraph (c)(1) of this sectionlimit, 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 electare subject to comply with thean 84-operating month CO2 emissions 

limitation in paragraph (c)(2) of this sectionlimit, 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 

limitationlimit 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 

limitationlimit 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
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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 

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

you mustcalibration 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 recovered thermal energyoutput. 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 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 limitationlimit 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: 
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ܲ௚௥௢௦௦ܲ௚௥௢௦௦/௡௘௧ = 

ሺܲ݁ሻௌ் ൅ 	 ሺܲ݁ሻ஼் 	൅	 ሺܲ݁ሻூா െ ሺܲ݁ሻிௐ

T 	൅ 	0.75

ൈ ሾ ሺܲݐሻ௉ௌ 	൅	 ሺܲݐሻுோ 	൅	 ሺܲݐሻூா ሿ

Where: a

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

(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. This term is not applicable to IGCC facilities or facilities 

complying with a net output based standard. 

(Pt)PS = Useful thermal energy output of steam (measured relative to ISOSATP

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 = HourlyNon steam useful thermal energy output (measured relative to 

ISOSATP conditions from heat recovery, as applicable) that is used for 

applications other than steam generation or performance enhancement of 

the affected facility in MWh. 

(Pt)IE = Useful thermal energy output (relative to ISOSATP conditions, as 

applicable) from any integrated equipment that provides thermal energy 

tois used for applications that do not generate additional steam, electricity, 

produce mechanical energy output, or enhance the performance of the 

affected facility or auxiliary equipment 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 energy 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: 
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ሺܲݐሻ௉ௌ 	ൌ	

ܪ	 ൈ௠ 	ܳ

3.6	 ൈ	10ଽ

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 

ISOSATP 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 

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

determine the hourly gross CO2 emissions for that hourCO2 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 limitationlimit 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 limitationlimit applicable to your affected facility, then your affected facility is in 

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

emissions limitationlimit at a common stack for two or more affected facilities subject to the 

same CO2 emissions limitationlimit, each affected facility sharing the stack is in compliance with 

the CO2 emissions limitationlimit. 

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

emissions limitationlimit 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. 
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(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 limitationlimit 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. 

(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 limitationlimit 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. 
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(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 

limitationslimits). 

(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. 

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

with each applicable CO2 emissions limitationlimit 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 
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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

measured relative to ISO conditions 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);;

(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) 

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

75 percent of the useful thermal output measured relative to ISO conditions 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);;

(iii) Except as provided under paragraph (iiiv) 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 measured relative to ISO conditions 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);; 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 measured relative to ISO conditions 

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);.

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

utility power distribution system minus purchased power on a calendar year basis, 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 on a calendar year basis.; 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 

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 (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. 

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 
Page 13 of 49

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 14 of 49

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 meets the applicability conditions in 

paragraphs (c)(1) through (c)(5) of this section. 

(1) Commenced construction after January 8, 2014 or it commenced reconstruction or 

modification after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]; 

(2) Has a design heat input to the turbine engine greater than 73 MW (250 MMBtu/h); 

(3) Combusts fossil fuel for more than 10.0 percent of the heat input during any 3 

consecutive calendar years. 

(4) Combusts over 90% natural gas on a heat input basis on a 3 year rolling average 

basis; and 

(5) Was constructed for the purpose of supplying, and supplies, one-third or more of its 

potential electric output and more than 219,000 MWh net-electrical output to a utility 

distribution system on a 3 year rolling average basis. 

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 
Page 15 of 49

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: 

§ 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. 
Page 16 of 49

(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 

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 recovered thermal energyoutput. 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 
Page 17 of 49

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 

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: 

ܲ௚௥௢௦௦ = 

ሺܲ݁ሻ஼் ൅ 	 ሺܲ݁ሻௌ் 	൅ 	 ሺܲ݁ሻூா

T 	൅ 	0.75 ൈ ሾ	ሺܲݐሻ௉ௌ 	൅	 ሺܲݐሻுோ 	൅	 ሺܲݐሻூா	ሿ

Where: 
Page 18 of 49

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

megawatt-hours in (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. 

(Pt)PS = Useful thermal energy output of steam (relative to ISOSATP 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. CalculatedThis is calculated using the equation 

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

(Pt)HR = Useful thermal energy output (relative to ISOSATP 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 energy output (relative to ISOSATP conditions, as 

applicable) from any integrated equipment that provides input tois used for 

applications that do not generate additional steam, electricity, produce 

mechanical energy output, or enhance the performance of the affected 

facility or auxiliary equipment 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 energy 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: 

ሺܲݐሻ௉ௌ 	ൌ	

ܪ	 ൈ௠ 	ܳ

3.6	 ൈ	10ଽ

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 

ISOSATP conditions, as applicable) in Joules per kilogram (J/kg) (or 
Page 19 of 49

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). 

(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 
Page 20 of 49

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; 

(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 
Page 21 of 49

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. 

(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 ISOSATP conditions (except for GHG calculations in § 60.4374 as 
Page 22 of 49

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 

ISOSATP 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 outputsales means: 

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

power on a 3 calendar year rolling average basis; 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 on a three calendar year rolling average basis; 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) 
Page 23 of 49

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, 

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 24 of 49

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

Table 2 toof 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 (850MMBtu850 

MMBtu/h). 

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 (850MMBtu850 

MMBtu/h). 

500 kg of CO2 per MWh of gross output 

(1,100 lb CO2/MWh) on a 12-operating 

month rolling average

 
Page 25 of 49

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

Table 3 toof 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 26 of 49

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

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

Utility 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? 

60.5530 Affirmative defense for violation of emission standards during malfunction 

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 
Page 27 of 49

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

REGISTER]. 

§ 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 commencescommenced

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

DATE OF PUBLICATION IN THE FEDERAL REGISTER] that meets the relevant 

applicability conditions in paragraphs (a)(1), and (a)(2), or (a)(3) of this section. 

(1) A steam generating unit or IGCC that commenced construction after January 8, 2014 

and has a design heat inputbase load rating greater than 73 MW (250 MMBtu/h) heat input of 

fossil fuel (either alone or in combination with any other fuel), combusts fossil fuel for more than 

10.0 percent of the average annual heat input during a 3 year rolling average basis, and was 

constructed for the purpose of supplying, and supplies, one-third or more of its potential electric 

output and more than 219,000 MWh as net-electric salesoutput to a utility distribution system on 

an annual basis. 

(2(2) A steam generating unit or IGCC that commenced modification or reconstruction 

after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] and has a base load 

rating greater than 73 MW (250MMBtu/h) heat input of fossil fuel (either alone or in 

combination with any other fuel) and 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 sales on an 

annual basis. 

(3) A stationary combustion turbine that has a design heat input to the turbine enginebase 

load rating greater than 73 MW (250 MMBtu/h), combusts fossil fuel for more than 10.0 percent 

of the average annual heat input during a 3 year rolling average basis, combusts over 90% 

natural gas on a heat input basis on a 3 year rolling average basis, and was constructed for the 

purpose of supplying, and supplies, one-third or more of its potential electric output and more 

than 219,000 MWh as net-electrical salesoutput to a utility distribution system on a 3 year rolling 

average basis. 

(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. 
Page 28 of 49

(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. 

(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 stack into the atmosphere any gases that contain CO2 in excess of the applicable 

CO2 emissions standard specified in Table 1 of this subpart.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 
Page 29 of 49

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?

(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 
Page 30 of 49

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.

§ 60.5530 Affirmative defense for violation of emission standards during malfunction. 

In response to an action to enforce the standards set forth in § 60.5520, you may assert an 

affirmative defense to a claim for civil penalties for violations of such standards that are caused 

by malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be assessed if you fail to 

meet your burden of proving all of the requirements in the affirmative defense. The affirmative 

defense shall not be available for claims for injunctive relief. 

(a) Assertion of affirmative defense. To establish the affirmative defense in any action to 

enforce such a standard, you must timely meet the reporting requirements in paragraph (b) of this 

section, and must prove by a preponderance of evidence that: 

(1) The violation: 

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

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

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

operation and maintenance practices; 

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

or planned for; 

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

maintenance; 

(2) Repairs were made as expeditiously as possible when the violation occurred; 

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

minimized to the maximum extent practicable; 

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

bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; 

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

quality, the environment, and human health; 

(6) All emissions monitoring and control systems were kept in operation if at all 

possible, consistent with safety and good air pollution control practices; 

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

contemporaneous operating logs; 

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

practices for minimizing emissions; and 

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

correct, and eliminate the primary causes of the malfunction and the violation resulting from the 

malfunction event at issue. The analysis shall also specify, using best monitoring methods and 

engineering judgment, the amount of any emissions that were the result of the malfunction. 

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

written report to the Administrator to demonstrate, with all necessary supporting documentation, 
Page 31 of 49

that it has met the requirements set forth in paragraph (a) of this section. This affirmative defense 

report is due after the initial occurrence of the exceedance of the standard in § 60.5520, and on 

the same quarterly reporting schedule as in § 60.5555 (which may be the end of any applicable 

averaging period). If such quarterly report is due less than 45 days after the initial occurrence of 

the violation, the affirmative defense report may be included in the following quarterly report 

required in § 60.5555(a). 

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 

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 
Page 32 of 49

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 recovered thermal energyoutput. 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 

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? 
Page 33 of 49

(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: 

ܲ௚௥௢௦௦ܲ௚௥௢௦௦/௡௘௧ = 

ሺܲ݁ሻௌ் ൅ 	 ሺܲ݁ሻ஼் 	൅	 ሺܲ݁ሻூா െ ሺܲ݁ሻிௐ

T 	൅ 	0.75

ൈ ሾ ሺܲݐሻ௉ௌ 	൅	 ሺܲݐሻுோ 	൅	 ሺܲݐሻூா ሿ

Where: a 

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

(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 or, IGCC 

facilities, or facilities complying with a net output based standard. 
Page 34 of 49

(Pt)PS = Useful thermal energy output of steam (measured relative to ISOSATP

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. CalculatedThis is calculated using the 

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

(Pt)HR = HourlyNon steam useful thermal energy output (measured relative to 

ISOSATP 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 energy output (relative to ISOSATP conditions, as 

applicable) from any integrated equipment that provides thermal energy 

tois used for applications that do not generate additional steam, electricity, 

produce mechanical energy output, or enhance the performance of the 

affected facility or auxiliary equipment 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 energy 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: 

ሺܲݐሻ௉ௌ 	ൌ	

ܪ	 ൈ௠ 	ܳ

3.6	 ൈ	10ଽ

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 

ISOSATP 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 
Page 35 of 49

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 

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. 
Page 36 of 49

(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. 

(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 
Page 37 of 49

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. 

(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). 

Affirmative defense means, in the context of an enforcement proceeding, a response or 

defense put forward by a defendant, regarding which the defendant has the burden of proof, and 

the merits of which are independently and objectively evaluated in a judicial or administrative 

proceeding. 

Base load rating means 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, baseloadbase 
Page 38 of 49

load rating means 100 percent of the design heat input capacity of the simple cycle portion (i.e., 

the combustion turbine engine) 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 energyoutput 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 

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

measured relative to ISO conditions 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)..
Page 39 of 49

(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 measured relative to ISO conditions 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);;

(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 measured 

relative to ISO conditions 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)..

 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 

stationary combustion turbine that is designed to burn fuels containing 50 percent (by heat input) 

or more solid-derived fuel not meeting the definition of natural gas. 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 

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 outputsales means: 
Page 40 of 49

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

power on a three calendar year rolling average basis; 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 on a three calendar year rolling average basis.; and

Oil means crude oil or petroleum or a fuel derived from crude oil or petroleum, including 

distillate and residual oil, and gases derived from solid oil-derived fuels (not meeting the 

definition of natural gas). 

(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 41 of 49

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) 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 industrial 

or commercial process, or used in any heating or cooling application, i. (e., total thermal energy 

made available.g., steam delivered to an industrial process for processes and a heating 

application, including thermal cooling applications other than) that is not used for electric 

generation, mechanical output at the affected facility, or to directly enhance the performance of 

the affected facility. Thermal (e.g., economizer output for this subpart means the energy in 

recoveredis 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 ISOSATP 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 42 of 49

Table 1 toof 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 (850MMBtu850 

MMBtu/h). 

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 (850MMBtu850 

MMBtu/h).)..

500 kg of CO2 per MWh of gross output 

(1,100 lb CO2/MWh) on a 12-operating 

month rolling average 

Steam generating unit 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

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. 

 
Page 43 of 49

Table 2 toTable 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). 

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). 

460 kilograms (kg) of CO2 per megawatt-hour 

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

12-operating month rolling average 

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. 

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 

has a design heat input greater than 590 MW 

(2,000 MMBtu/h). 

860 kg of CO2 per MWh of net energy output 

(1,900 lb CO2/MWh) on a 12-operating 

month rolling average basis; 

 

 

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 44 of 49

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 

 
Page 45 of 49

PART 70 — STATE OPERATING PERMIT PROGRAMS 

17. The authority citation for part 70 continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

 18. Section 70.2 is amended: 

a. By adding in alphabetical order the definition of “Greenhouse gases,” 

 b. By revising the introductory text, removing “or” from the end of paragraph (2), adding 

“or” to the end of paragraph (3), and adding paragraph (4) to the definition of “Regulated 

pollutant (for presumptive fee calculation),” and 

 c. By revising paragraph (1) to the definition of “Subject to regulation.” 

The revision and additions read as follows: 

§ 70.2 Definitions. 

* * * * * 

Greenhouse gases (GHGs) means the air pollutant defined in § 86.1818-12(a) of this 

chapter as the aggregate group of six greenhouse gases: carbon dioxide, nitrous oxide, methane, 

hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. 

* * * * * 

Regulated pollutant (for presumptive fee calculation), which is used only for purposes of 

§ 70.9(b)(2), means any regulated air pollutant except the following: 

* * * 

(4) Greenhouse gases. 

* * * * * 

 Subject to regulation * * *

 (1) Greenhouse gases shall not be subject to regulation unless, as of July 1, 2011, the 

GHG emissions are at a stationary source emitting or having the potential to emit 100,000 tpy 

CO2 equivalent emissions. 

* * * * * 

 19. Section 70.9 is amended by revising paragraph (b)(2)(i), and by adding paragraph 

(b)(2)(v) to read as follows: 

§ 70.9 Fee determination and certification. 

* * * * * 

(b) * * * 

 (2)(i) The Administrator will presume that the fee schedule meets the requirements of 

paragraph (b)(1) of this section if it would result in the collection and retention of an amount not 

less than $25 per year [as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) of this 

section] times the total tons of the actual emissions of each regulated pollutant (for presumptive 

fee calculation) emitted from part 70 sources and any GHG cost adjustment required under 

paragraph (b)(2)(v) of this section. 
Page 46 of 49

* * * * * 

(v) GHG cost adjustment. The amount calculated in paragraph (b)(2)(i) of this section 

shall be increased by the GHG cost adjustment determined as follows: For each activity 

identified in the following table, multiply the number of activities performed by the permitting 

authority by the burden hours per activity, and then calculate a total number of burden hours for 

all activities. Next, multiply the burden hours by the average cost of staff time, including wages, 

employee benefits and overhead. 

Activity Burden 

hours per 

activity 

GHG completeness determination (for initial permit or updated 

application) 

GHG evaluation for a modification or related permit action 

GHG evaluation at permit renewal 

43 

7 

10 

* * * * * 

PART 71 — FEDERAL OPERATING PERMIT PROGRAMS 

20. The authority citation for part 71 continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

21. Section 71.2 is amended: 

a. By adding in alphabetical order the definition of “Greenhouse gases,” 

b. By removing “or” from the end of paragraph (2), adding “or” to the end of paragraph 

(3), and adding paragraph (4) to the definition of “Regulated pollutant (for fee calculation),” and 

c. By revising paragraph (1) of the definition of “Subject to regulation.” 

The revisions and additions read as follows:

§ 71.2 Definitions. 

* * * * * 

Greenhouse gases (GHGs) means the air pollutant defined in § 86.1818-12(a) of this 

chapter as the aggregate group of six greenhouse gases: carbon dioxide, nitrous oxide, methane, 

hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. 

* * * * * 

Regulated pollutant (for fee calculation), which is used only for purposes of § 71.9(c), 

means any “regulated air pollutant” except the following: 
Page 47 of 49

* * * * * 

(4) Greenhouse gases. 

* * * * * 

Subject to regulation * * *

 (1) Greenhouse gases shall not be subject to regulation unless, as of July 1, 2011, the 

GHG emissions are at a stationary source emitting or having the potential to emit 100,000 tpy 

CO2 equivalent emissions. 

* * * * * 

 22. Section 71.9 is amended by: 

a. Revising paragraphs (c)(1), (c)(2)(i), (c)(3), and (c)(4), and 

 b. Adding paragraph (c)(8). 

 The revisions and additions read as follows: 

§ 71.9 Permit fees. 

* * * * * 

(c) * * * (1) For part 71 programs that are administered by EPA, each part 71 source 

shall pay an annual fee which is the sum of: 

(i) $32 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this 

section) times the total tons of the actual emissions of each regulated pollutant (for fee 

calculation) emitted from the source, including fugitive emissions; and 

(ii) Any GHG fee adjustment required under paragraph (c)(8) of this section. 

(2) * * * 

(i) Where the EPA has not suspended its part 71 fee collection pursuant to paragraph 

(c)(2)(ii) of this section, the annual fee for each part 71 source shall be the sum of: 

(A) $24 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this 

section) times the total tons of the actual emissions of each regulated pollutant (for fee 

calculation) emitted from the source, including fugitive emissions; and 

(B) Any GHG fee adjustment required under paragraph (c)(8) of this section. 

* * * * * 

(3) For part 71 programs that are administered by EPA with contractor assistance, the per 

ton fee shall vary depending on the extent of contractor involvement and the cost to EPA of 

contractor assistance. The EPA shall establish a per ton fee that is based on the contractor costs 

for the specific part 71 program that is being administered, using the following formula: 

Cost per ton=( E ×32)+[(1− E )×$ C ] 

 Where E represents EPA's proportion of total effort (expressed as a percentage of total 

effort) needed to administer the part 71 program, 1- E represents the contractor's effort, and C

represents the contractor assistance cost on a per ton basis. C shall be computed by using the 

following formula: 
Page 48 of 49

C =[ B + T + N ] divided by 12,300,000 

 Where B represents the base cost (contractor costs), where T represents travel costs, and 

where N represents nonpersonnel data management and tracking costs. In addition, each part 71 

source shall pay a GHG fee adjustment for each activity as required under paragraph (c)(8) of 

this section. 

(4) For programs that are delegated in part, the fee shall be computed using the following 

formula: 

Cost per ton=( E ×32)+( D ×24)+[(1− E − D )×$ C ] 

 Where E and D represent, respectively, the EPA and delegate agency proportions of total 

effort (expressed as a percentage of total effort) needed to administer the part 71 program, 1− E

− D represents the contractor's effort, and C represents the contractor assistance cost on a per ton 

basis. C shall be computed using the formula for contractor assistance cost found in paragraph 

(c)(3) of this section and shall be zero if contractor assistance is not utilized. In addition, each 

part 71 source shall pay a GHG fee adjustment for each activity as required under paragraph 

(c)(8) of this section. 

* * * * * 

 (8) GHG fee adjustment. The annual fee shall be increased by a GHG fee adjustment for 

any source that has initiated an activity listed in the following table since the fee was last paid. 

The GHG fee adjustment shall be equal to the set fee provided in the table for each activity that 

has been initiated since the fee was last paid: 

Activity Set fee 

GHG completeness determination (for initial permit or updated 

application) 

GHG evaluation for a permit modification or related permit 

action 

GHG evaluation at permit renewal 

$2,236 

$364 

$520 

* * * * * 

PART 98 — MANDATORY GREENHOUSE GAS REPORTING 

 23. The authority citation for part 98 is revised to read as follows: 

Authority: 42 U.S.C. 7401-7671q. 

Subpart PP—Suppliers of Carbon Dioxide 

 24. Section 98.426 is amended by adding paragraph (h) to read as follows: 
Page 49 of 49

§ 98.426 Data reporting requirements. 

* * * * * 

(h) If you capture a CO2 stream from an electricity generating unit that is subject to 

subpart D of this part and transfer CO2 to any facilities that are subject to subpart RR of this part, 

you must: 

(1) Report the facility identification number associated with the annual GHG report for 

the facility that is subject to subpart D of this part, 

(2) Report each facility identification number associated with the annual GHG reports for 

each facility that is subject to subpart RR of this part to which CO2 is transferred, and 

(3) Report the annual quantity of CO2 in metric tons that is transferred to each facility 

that is subject to subpart RR of this part. 

25. Section 98.427 is amended by adding paragraph (d) to read as follows: 

§ 98.427 Records that must be retained. 

* * * * * 

 (d) Facilities subject to § 98.426(h) must retain records of CO2 in metric tons that is 

transferred to each facility that is subject to subpart RR of this part.