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For the reasons stated in the preamble, title 40, chapter I, 

part 60, 70, 71, and 98 of the Code of the Federal Regulations 

is amended as follows:

PART 60-- STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

1. The authority citation for part 60 continues to read as 

follows:

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

2. Part 60 is amended by adding subpart TTTT to read as 

follows:

Subpart TTTT Standards of Performance for Greenhouse Gas 

Emissions for Electric Generating Units 

Sec.

Applicability

§60.5508 What is the purpose of this subpart?

§60.5509 Am I subject to this subpart?

Emission Standards

§60.5515 Which greenhouse gases are regulated by this subpart?

§60.5520 What CO2 emissions standard must I meet?

General Compliance Requirements

§60.5525 What are my general requirements for complying with 

this subpart? 

Monitoring and Compliance Determination Procedures 

§60.5535 How do I monitor and collect data to demonstrate 

compliance? 

§60.5540 How do I demonstrate compliance with my CO2 emissions 

standard and determine excess emissions? 

Notifications, Reports, and Records
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§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 EGU?

§60.5575 Who implements and enforces this subpart?

§60.5580 What definitions apply to this subpart?

Applicability

§60.5508 What is the purpose of this subpart?

This subpart establishes emission standards and compliance 

schedules for the control of greenhouse gas (GHG) emissions from 

a steam generating unit, IGCC, or a stationary combustion 

turbine that commences construction after January 8, 2014 or 

commences modification or reconstruction after June 18, 2014. An 

affected steam generating unit, IGCC, or stationary combustion 

turbine shall, for the purposes of this subpart, be referred to 

as an affected EGU.

§60.5509 Am I subject to this subpart?

(a) Except as provided for in paragraph (b) of this 

section, the GHG standards included in this subpart apply to any 

steam generating unit, IGCC, or stationary combustion turbine 

that commenced construction after January 8, 2014 or commenced 

modification or reconstruction after June 18, 2014 that meets 
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the relevant applicability conditions in paragraphs (a)(1) and 

(a)(2) of this section.

(1) Has a base load rating greater than 260 GJ/h (250 

MMBtu/h) of fossil fuel (either alone or in combination with any 

other fuel), and

(2) Serves a generator capable of selling greater than 25 

MW of electricity to a utility power distribution system. 

(b) You are not subject to the requirements of this subpart 

if your affected EGU meets any of the conditions specified in

paragraphs (b)(1) through (b)(8) of this section.

(1) Your EGU is a steam generating unit or IGCC that is 

currently and always has been subject to a federally enforceable 

permit condition limiting annual net-electric sales to no more 

than one-third of its potential electric output or 219,000 MWh, 

whichever is greater.

(2) Your EGU is capable of combusting 50 percent or more 

non-fossil fuel and is also subject to a federally enforceable 

permit condition limiting the annual capacity factor for all 

fossil fuels combined of 10 percent (0.10) or less.

(3) Your EGU is a combined heat and power unit that is 

subject to a federally enforceable permit condition limiting 

annual net-electric sales to no more than the product of the 

unit's net design efficiency and the unit's potential electric 

output or 219,000 MWh, whichever is greater.
Page 4 of 60

(4) Your EGU serves a generator along with other steam 

generating unit(s), IGCC, or stationary combustion turbine(s)

where the effective generation capacity (determined based on a 

prorated output of the base load rating of each steam generating 

unit, IGCC, or stationary combustion turbine) is 25 MW or less.

(5) Your EGU is a municipal waste combustor that is subject 

to subpart Eb of this part.

(6) Your EGU is a commercial or industrial solid waste 

incineration unit that is subject to subpart CCCC of this part.

(7) Your EGU is a steam generating unit(s) or IGCC that 

undergoes a modification resulting in an hourly increase in CO2

emissions (mass per hour) of 10 percent or less (2 significant 

figures). Modified units that are not subject to the 

requirements of this subpart pursuant to this subsection 

continue to be existing units under section 111 with respect to 

CO2 emissions standards.

(8) Your EGU is a stationary combustion turbine that is not 

capable of combusting natural gas (e.g., not connected to a 

natural gas pipeline).

Emission Standards

§60.5515 Which 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.
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(1) For the 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 §51.166(b)(48) and in any SIP approved by 

the EPA that is interpreted to incorporate, or specifically 

incorporates, §51.166(b)(48) of this chapter.

(2) For the 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 §52.21(b)(49) of this chapter.

(3) For the purposes of 40 CFR §70.2 of this chapter, 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 of this chapter.

(4) For the 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 
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that otherwise is "subject to regulation" as defined in 40 CFR 

§71.2 of this chapter. 

§60.5520 What CO2 emission standard must I meet?

(a) For each affected EGU subject to this subpart, you must 

not discharge from the affected EGU any gases that contain CO2 in 

excess of the applicable CO2 emission standard specified in 

Table 1 or Table 2 of this subpart, consistent with paragraphs 

(b) and (c) of this section, as applicable.

(b) Except as specified in paragraph (c) of the section, 

you must comply with the applicable gross energy output standard

and your operating permit must include monitoring, 

recordkeeping, and reporting methodologies based on the 

applicable gross energy output standard. For the remainder of 

this subpart, where the term “gross or net energy output” is 

used, the term that applies to you is “gross energy output.”

(c) As an alternate to meeting the requirements in 

paragraph (b) of this section, an owner or operator of a 

stationary combustion turbine may petition the Administrator in 

writing to comply with the alternate applicable net energy 

output standard. If the Administrator grants the petition, 

beginning on the date the Administrator grants the petition, the 

source must comply with the applicable net energy output based 

standard included in this subpart. Your operating permit must 

include monitoring, recordkeeping, and reporting methodologies 
Page 7 of 60

based on the applicable net energy output standard. For the 

remainder of this subpart, where the term “gross or net energy 

output” is used, the term that applies to you is “net energy 

output.” Owners or operators complying with the net output based 

standard must petition the Administrator to switch back to

complying with the gross energy output based standard.

General Compliance Requirements

§60.5525 What are my general requirements for complying with 

this subpart?

Compliance with the applicable CO2 emission standard of this 

subpart shall be determined on a 12-operating month rolling 

average basis. See Tables 1-2 for the applicable CO2 emission 

standards.

(a) You must be in compliance with the emission standards 

in this subpart that apply to your affected EGU at all times. 

However, you must determine compliance with the emission 

standards only at the end of the applicable operating month, as 

provided in paragraph (a)(1).

(1) For each affected EGU 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 EGU at the end of the initial 

and each subsequent 12-operating month period.

(2) For each affected EGU subject to the CO2 emissions 
Page 8 of 60

standard for multi-fuel units, you must determine the total heat 

input in million Btu’s (MMBtu) from natural gas (HTIPng) and the 

total heat input from all other fuels combined (HTIPo) using one 

of the methods under §60.5535(d)(2). You must then use the 

following equation to determine the applicable emissions 

standard (EL) during the compliance period:

 emission	standard = 

120 x HTIP + (160 x HTIP

)

Total	Heat	Input	from	All	Fuels

Where:

CO2 emission standard = the emission standard during the 

compliance period in units of lb/MMbtu.

HTIPng = the heat input in MMBtu from natural gas during the 

compliance pe riod.

HTIPo = the heat input in MMBtu from all fuels other than 

natural gas that were fired during the compliance 

period.

120 = allowable emission rate in lbs of CO2/MMBtu for heat 

input derived from natural gas.

160 = allowable emission rate in lbs of CO2/MMBtu for heat 

input derived from all fuels other than natural 

gas.

(b) At all times you must operate and maintain each 

affected EGU, including associated equipment and monitoring 

equipment, in a manner consistent with safety and good air 
Page 9 of 60

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 EGU.

(c) Within 30 days after the end of the initial compliance 

period (i.e., no more than 30 days after the first 12-operating 

month compliance period), you must make an initial compliance 

determination for your affected EGU(s) with respect to the 

applicable emissions standard in Table 1 or Table 2 of this 

subpart, in accordance with the requirements in this subpart. 

The first operating month included in the initial 12-operating 

month compliance period shall be determined as follows: 

(1) For an affected EGU that commences commercial operation 

(as defined in §72.2 of this chapter) on or after the effective 

date of this rule, the first month of the initial compliance 

period shall be the first operating month (as defined in 

§60.5580) after the calendar month in which emissions reporting 

is required to begin under:

(i) §63.5555(c)(3)(i), for units subject to the Acid Rain 

Program; or 

(ii) §63.5555(c)(3)(ii)(A), for units that are not in the 
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Acid Rain Program.

(2) For an affected EGU that has commenced commercial 

operation (as defined in §72.2 of this chapter) prior to the 

effective date of this rule:

(i) If the date on which emissions reporting is required to 

begin under §75.64(a) of this chapter has passed prior to the 

effective date of this rule, emissions reporting shall begin 

according to §63.5555(c)(3)(i) (for Acid Rain program units), or 

according to §63.5555(c)(3)(ii)(B) (for units that are not 

subject to the Acid Rain Program). The first month of the 

initial compliance period shall be the first operating month (as 

defined in §60.5580) after the calendar month in which the rule 

becomes effective; or

(ii) If the date on which emissions reporting is required 

to begin under §75.64(a) of this chapter occurs on or after the 

effective date of this rule, then the first month of the initial 

compliance period shall be the first operating month (as defined 

in §60.5580) after the calendar month in which emissions 

reporting is required to begin under §63.5555(c)(3)(ii)(A).

(3) For a modified or reconstructed EGU that becomes 

subject to this subpart, the first month of the initial 

compliance period shall be the first operating month (as defined 

in §60.5580) after the calendar month in which emissions 

reporting is required to begin under §63.5555(c)(3)(iii).
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Monitoring and Compliance Determination Procedures

§60.5535 How do I monitor and collect data to demonstrate 

compliance?

(a) You must prepare a monitoring plan to quantify the 

hourly CO2 mass emission rate (tons/hr), in accordance with the 

applicable provisions in §75.53(g) and (h) of this chapter. The 

electronic portion of the monitoring plan must be submitted 

using the ECMPS Client Tool and must be in place prior to 

reporting emissions data and/or the results of monitoring system 

certification tests under this subpart. The monitoring plan 

must be updated as necessary. Monitoring plan submittals must 

be made by the Designated Representative (DR), the Alternate DR, 

or a delegated agent of the DR (see §60.5555(c)).

(b) You must determine the hourly CO2 mass emissions in 

kilograms (kg) from your affected EGU(s) according to paragraphs 

(b)(1) through (5) of this section, or, if applicable, as 

provided in paragraph (c) of this section.

(1) For an affected coal-fired EGU or for an IGCC unit you 

must, and for all other affected EGUs you may, install, certify, 

operate, maintain, and calibrate a CO2 continuous emission 

monitoring system (CEMS) to directly measure and record hourly 

average CO2 concentrations in the affected EGU exhaust gases 

emitted to the atmosphere, and a flow monitoring system to 

measure hourly average stack gas flow rates, according to 
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§75.10(a)(3)(i) of this chapter. As an alternative to direct 

measurement of CO2 concentration, provided that your EGU does not 

use carbon separation (e.g., carbon capture and storage), you 

may use data from a certified oxygen (O2) monitor to calculate 

hourly average CO2 concentrations, in accordance with 

§75.10(a)(3)(iii) 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.

Alternatively, you may either use an appropriate fuel-specific 

default moisture value from §75.11(b) or submit a petition to 

the Administrator under §75.66 of this chapter for a sitespecific default moisture value.

(2) For each continuous 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 A and B to part 75 of this chapter.

(3) You must use only unadjusted exhaust gas volumetric 

flow rates to determine the hourly CO2 mass emissions rate from 

the affected EGU; 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.

(4) You must select an appropriate reference method to 

setup (characterize) the flow monitor and to perform the on-
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going RATAs, in accordance with part 75 of this chapter. If you 

use a Type-S pitot tube or a pitot tube assembly for the flow 

RATAs, you must calibrate the pitot tube or pitot tube assembly; 

you may not use the 0.84 default Type-S pitot tube coefficient 

specified in Method 2. 

(5) Calculate the hourly CO2 mass emissions (kg) as 

described in paragraphs (a)(6)(i) through (iv) of this section. 

Perform this calculation only for “valid operating hours”, as 

defined in §60.5540(a)(1).

(i) Begin with the hourly CO2 mass emission rate (tons/hr), 

obtained either from Equation F-11 in Appendix F to part 75 of 

this chapter (if CO2 concentration is measured on a wet basis), 

or by following the procedure in section 4.2 of Appendix F to 

part 75 of this chapter (if CO2 concentration is measured on a 

dry basis).

(ii) Next, multiply each hourly CO2 mass emission rate by 

the EGU or stack operating time in hours (as defined in §72.2 of 

this chapter), to convert it to tons of CO2. 

(iii) Finally, multiply the result from paragraph 

(b)(5)(ii) of this section by 909.1 to convert it from tons of 

CO2 to kg. Round off to the nearest kg. 

(iv) The hourly CO2 tons/hr values and EGU (or stack) 

operating times used to calculate CO2 mass emissions are required 

to be recorded under §75.57(e) of this chapter and must be 
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reported electronically under §75.64(a)(6). You must use these 

data to calculate the hourly CO2 mass emissions. 

(c) If your affected EGU 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 according to paragraphs (c)(1) through (4) of 

this section. 

(1) You must implement the applicable procedures in 

appendix D to part 75 of this chapter to determine hourly EGU

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) For each measured hourly heat input rate, use Equation 

G-4 in Appendix G to part 75 of this chapter to calculate the 

hourly CO2 mass emission rate (tons/hr). You may determine sitespecific 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.

(3) For each “valid operating hour” (as defined in 

§60.5540(a)(1), multiply the hourly tons/h CO2 mass emission rate 

from paragraph (c)(2) of this section by the EGU or stack 

operating time in hours (as defined in §72.2 of this chapter), 

to convert it to it to tons of CO2. Then, multiply the result by 
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909.1 to convert from tons of CO2 to kg. Round off to the 

nearest two significant figures.

(4) The hourly CO2 tons/h values and EGU (or stack) 

operating times used to calculate CO2 mass emissions are required 

to be recorded under §75.57(e) of this chapter and must be 

reported electronically under §75.64(a)(6) You must use these 

data to calculate the hourly CO2 mass emissions.

(d) Consistent with §60.5520, you must determine the basis 

of the emissions standard that applies to your affected source 

in accordance with either paragraph (d)(1) or (d)(2), as 

applicable:

(1) If you operate a source subject to an emissions 

standard established on an output basis (e.g., lbs of CO2 per 

gross or net MWh of energy output), you must install, calibrate, 

maintain, and operate a sufficient number of watt meters to 

continuously measure and record the hourly gross electric output 

or net electric output, as applicable, from the affected EGU(s). 

These measurements must be performed using 0.2 class electricity 

metering instrumentation and calibration procedures as specified 

under ANSI Standards No. C12.20. For a combined heat and power

(CHP) EGU, as defined in §60.5580, you must also install, 

calibrate, maintain, and operate meters to continuously (i.e., 

hour-by-hour) determine and record the total useful thermal 

output. For process steam applications, you will need to 
Page 16 of 60

install, calibrate, maintain, and operate meters to continuously 

determine and record the hourly steam flow rate, temperature, 

and pressure. Your plan shall ensure that you install, 

calibrate, maintain, and operate meters to record each component 

of the determination, hour-by-hour.

(2) If you operate a source subject to an emissions 

standard established on a heat-input basis (e.g., lbs of CO2 per 

MMBtu of heat input), you must determine the total heat input 

for each fuel fired during the compliance period in accordance 

with one of the following procedures:

(i) Appendix D to Part 75;

(ii) The procedures for monitoring heat input under of 

40 CFR 60.107a(d); or

(iii)The procedure for monitoring heat input under 

40 CFR 98.33(a)(2) or (a)(3).

(e) Consistent with §60.5520, if two or more affected EGUs 

serve a common electric generator, you must apportion the 

combined hourly gross or net energy output to the individual 

affected EGUs according to the fraction of the total steam load 

contributed by each EGU. Alternatively, if the EGUs are 

identical, you may apportion the combined hourly gross or net 

electrical load to the individual EGUs according to the fraction 

of the total heat input contributed by each EGU.
Page 17 of 60

(f) In accordance with §60.13(g) and §60.5520, if two or 

more affected EGUs 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 in Table 1 or Table 2 of this subpart, 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 energy output (electric, thermal, and/or 

mechanical, as applicable) must be the sum of the hourly loads 

for the individual affected EGUs 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 EGU sharing the stack is in compliance.

(g) In accordance with §60.13(g) and §60.5520 if the 

exhaust gases from an affected EGU 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 Table 1 or 
Page 18 of 60

2 of this subpart by summing the CO2 mass emissions measured at 

the individual stacks or ducts and dividing by the total gross 

or net energy output for the affected EGU.

(h) Heat rate determination and design efficiency for 

combustion turbines. In accordance with xxxx, you must use an 

appropriate standard method published by a consensus-based 

standards organization if such a method exists or you may use an 

industry standard practice. Consensus-based standards 

organizations include, but are not limited to, the following: 

ASTM International, the American National Standards Institute 

(ANSI), the American Gas Association (AGA), the American Society 

of Mechanical Engineers (ASME), the American Petroleum Institute 

(API), and the North American Energy Standards Board (NAESB).]

Acceptable methods include [but are not limited to] the 

following testing and analytical methods:

(1) ASME PTC 6-2004 Steam Turbines (incorporated by 

reference, see §60.17).

(2) ASME PTC 6S Procedures for Routine Performance Test of 

Steam Turbines (incorporated by reference, see §60.17).

(3) ASME PTC 6.2-2011 Steam Turbines in Combined Cycles

(incorporated by reference, see §60.17).

(4) ASME PTC 22 Gas Turbines (incorporated by reference, 

see §60.17).
Page 19 of 60

(5) ASME PTC 46 Overall Plant Performance (incorporated by 

reference, see §60.17).

(6) ISO 2314:2009 Gas turbines – acceptance tests

(incorporated by reference, see §60.17).

(7) DIN 1943 Thermal Acceptance of steam turbines

(incorporated by reference, see §60.17).

(8) IEC-953-2 Rules for steam turbine thermal acceptance 

tests. Part 2: Method B - Wide range of accuracy for various 

types and sizes of turbines (incorporated by reference, see 

§60.17).

§60.5540 How do I demonstrate compliance with my CO2 emissions 

standard?

(a) In accordance with §60.5520, to demonstrate compliance 

with the applicable CO2 emission standard in Table 1 or 2 of this 

subpart, for the initial and each subsequent 12-operating month 

rolling average compliance period, you must follow the 

procedures in paragraphs (a)(1) through (a)(7) of this section 

to calculate the CO2 mass emissions rate for your affected EGU(s) 

in units of the applicable emissions standard (i.e., either 

kg/MWh or lb/MMBtu). You must use the hourly CO2 mass emissions 

and either the generating load data from §60.5535(d)(1) or the 

heat input data from §60.5535(d)(2) in the calculations.
Page 20 of 60

(1) Each compliance period shall include only “valid 

operating hours” in the compliance period, i.e., operating hours 

for which: 

(i) “Valid data” (as defined in §60.5580) are obtained for 

all of the parameters used to determine the hourly CO2 mass 

emissions (kg) and, if a heat input based standard applies, all 

the parameters used to determine total heat input for the hour 

are also obtained; and 

(ii) The corresponding hourly gross or net energy output 

value is also valid data (Note: for hours with no useful output, 

zero is considered to be a valid value). 

(2) You must exclude operating hours in which:

(i) The substitute data provisions of part 75 of this 

chapter are applied for any of the parameters used to determine 

the hourly CO2 mass emissions or, if a heat input based standard 

applies, for any parameters used to determine the hourly heat 

input; or

(ii) An exceedance of the full-scale range of a continuous 

emission monitoring system occurs for any of the parameters used 

to determine the hourly CO2 mass emissions or, if applicable, to 

determine the hourly heat input; or

(iii) The total gross or net energy output (Pgross/net) or, if 

applicable, the total heat input is unavailable.
Page 21 of 60

(3) For each compliance period, at least 95 percent of the 

operating hours in the compliance period must be valid operating 

hours, as defined in paragraph (a)(1) of this section.

(4) You must calculate the total CO2 mass emissions by 

summing the valid hourly CO2 mass emissions values from §60.5535 

for all of the valid operating hours in the compliance period. 

(5) Sources subject to output based standards. For each

valid operating hour of the compliance period that was used in 

paragraph (a)(4) of this section to calculate the total CO2 mass 

emissions, you must determine Pgross/net (the corresponding hourly 

gross or net energy output in MWh) according to the procedures 

in paragraphs (a)(3)(i) and (ii) of this section, as appropriate 

for the type of affected EGU(s). For an operating hour in which 

a valid CO2 mass emissions value is determined according to 

paragraph (a)(1)(i) of this section, if there is no gross or net

electrical output, 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 a 

valid CO2 mass emissions value is determined according to 

paragraph (a)(1)(i) of this section, but there is no (i.e., 

zero) gross electrical, mechanical, or useful thermal output, 

you must use that hour in the compliance determination. For 

hours or partial hours where the gross electric output is equal 
Page 22 of 60

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 EGU using the 

following equation. All terms in the equation must be expressed 

in units of megawatt-hours (MWh). To convert each hourly gross 

or net energy output (Consistent with §60.5520) value reported 

under part 75 of this chapter to MWh, multiply by the 

corresponding EGU or stack operating time.

/ = 

() + () + () − ()

TDF + [ () + () + () ]

Where: a

Pgross/net = In accordance with §60.5520, gross or net energy 

output of your affected EGU for each valid 

operating hour (as defined in 60.5540(a)(1)) 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 EGU’s integrated 

equipment that provides electricity or mechanical 

energy to the affected EGU or auxiliary equipment 
Page 23 of 60

in MWh.

(Pe)FW = Electric energy used to power boiler feedwater 

pumps at steam generating units in MWh. Not 

applicable to stationary combustion turbines, 

IGCC EGUs, or EGUs complying with a net energy 

output based standard.

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

to SATP conditions, as applicable) that is used 

for applications that do not generate additional 

electricity, produce mechanical energy output, or 

enhance the performance of the affected EGU. This 

is calculated using the equation specified in 

paragraph (a)(5)(ii) of this section in MWh.

(Pt)HR = Non steam useful thermal output (measured 

relative to SATP conditions, as applicable) from 

heat recovery that is used for applications other 

than steam generation or performance enhancement

of the affected EGU in MWh.

(Pt)IE = Useful thermal output (relative to SATP 

conditions, as applicable) from any integrated 

equipment is used for applications that do not 

generate additional steam, electricity, produce 

mechanical energy output, or enhance the 

performance of the affected EGU in MWh.
Page 24 of 60

TDF = Electric Transmission and Distribution Factor of 

0.95 for a combined heat and power affected EGU 

where at least on an annual basis 20.0 percent of 

the total gross or net energy output consists of 

electric or direct mechanical output and 20.0 

percent of the total gross or net energy output 

consists of useful thermal output on a 12-

operating month rolling average basis, or 1.0 for 

all other affected EGUs.

(ii) If applicable to your affected EGU (for example, for 

combined heat and power), you must calculate (Pt)PS using the 

following equation:

() =

 × 



Where:

Qm = Measured steam flow in kilograms (kg) (or pounds 

(lb)) for the operating hour.

H = Enthalpy of the steam at measured temperature and 

pressure (relative to SATP conditions or the 

energy in the condensate return line, as 

applicable) in Joules per kilogram (J/kg) (or 

Btu/lb).

CF = Conversion factor of 3.6 x 109 J/MWh or 3.413 x 106 
Page 25 of 60

Btu/MWh.

(6) Calculation of annual basis for standard. Sources 

complying with energy output-based standards must calculate the 

basis (i.e., denominator) of their actual annual emission rate 

in accordance with paragraph (6)(i). Sources complying with heat 

input based standards must calculate the basis of their actual 

annual emission rate in accordance with paragraph (6)(ii).

(i) In accordance with §60.5520 if you are subject to an 

output based standard, you must calculate the total gross or net

energy output for the affected EGU’s compliance period by 

summing the hourly gross or net energy output values for the 

affected EGU that you determined under paragraph (a)(5) of this 

section for all of the valid operating hours in the applicable 

compliance period.

(ii) If you are subject to a heat input based standard, you 

must calculate the total heat input for each fuel fired during 

the compliance period. The calculation of total heat input for 

each individual fuel must include all valid operating hours and 

must also be consistent with any fuel-specific procedures 

specified within your selected monitoring option under 

§60.5535(d)(2). 

(7) If you are subject to an output based standard, you 

must calculate the CO2 mass emissions rate for the affected 
Page 26 of 60

EGU(s) (kg/MWh) by dividing the total CO2 mass emissions value 

calculated according to the procedures in paragraph (a)(4) of 

this section by the total gross or net energy output value 

calculated according to the procedures in paragraph (a)(6)(i) of 

this section. Round off the result to two significant figures.

If you are subject to a heat input based standard, you must 

calculate the CO2 mass emissions rate for the affected EGU(s) 

(lb/MMBtu) by dividing the total CO2 mass emissions value 

calculated according to the procedures in paragraph (a)(4) of

this section by the total heat input calculated according to the 

procedures in paragraph (a)(6)(ii) of this section. Round off 

the result to two significant figures.

(b) In accordance with §60.5520, to demonstrate compliance 

with the applicable CO2 emission standard, for the initial and 

each subsequent 12-operating month compliance period, the CO2

mass emissions rate for your affected EGU must be determined 

according to the procedures specified in paragraph (a)(1) 

through (7) of this section and must be less than or equal to 

the applicable CO2 emissions standard in Table 1, Table 2, or the 

emissions standard calculated in accordance with §60.5525(a)(2)

of this subpart. 

Notification, Reports, and Records

§60.5550 What notifications must I submit and when?

(a) You must prepare and submit the notifications 
Page 27 of 60

specified in §60.7(a)(1) and (a)(3) and §60.19, as applicable to 

your affected EGU(s) (see Table 3 of this Subpart).

(b) You must prepare and submit notifications specified in 

§75.61 of this chapter, as applicable to your affected EGUs. 

§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 EGUs that are required by §60.5525 to 

conduct initial and on-going compliance determinations on a 12-

operating month rolling average basis, you must submit 

electronic quarterly reports as follows. After you have 

accumulated the first 12-operating months for the affected EGU, 

you must submit a report for the calendar quarter that includes 

the twelfth 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 (twelfth) operating month in a 12-operating month 

compliance period falls within the calendar quarter. You must 

calculate each average CO2 mass emissions rate for the compliance 

period according to the procedures in §60.5540. You must report 
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the dates (month and year) of the first and twelfth 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 

where your EGU violated the applicable CO2 emission standard;

(iii) If one or more compliance periods end in the quarter 

and there are no violations for the affected EGU, you must 

include a statement indicating this in the report;

(iv) The percentage of valid operating hours in each 12-

operating month compliance period described in paragraph 

(a)(1)(i) of this section (i.e., the total number of valid 

operating hours (as defined in §60.5540(a)(1)) in that period 

divided by the total number of operating hours in that period, 

multiplied by 100 percent);

(v) Consistent with §60.5520, the CO2 emissions standard (as 

identified in Table 1 or 2) with which your affected EGU must

comply; and

(vi) Consistent with §60.5520, an indication whether or not 

the hourly gross or net energy output (Pgross/net) values used in 

the compliance determinations are based solely upon gross 

electrical load.
Page 29 of 60

(3) In the final quarterly report of each calendar year, 

you must include the following:

(i) Consistent with §60.5520, gross energy output or net 

energy output sold to an electric grid over the 4 quarters of 

the calendar year; and

(ii) The potential electric output of the EGU.

(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) (1) For affected EGUs under this subpart that are also 

subject to the Acid Rain Program, you must meet all applicable 

reporting requirements and submit reports as required under 

subpart G of part 75 of this chapter. 

(2) For affected EGUs under this subpart that are not in 

the Acid Rain Program, you must also meet the reporting 

requirements and submit reports as required under subpart G of 

part 75 of this chapter, to the extent that those requirements 

and reports provide applicable data for the compliance 

demonstrations required under this subpart. 

(3) (i) For all newly-constructed affected EGUs under this 

subpart that are also subject to the Acid Rain Program, you must 

begin submitting the quarterly electronic emissions reports 
Page 30 of 60

described in paragraph (c)(1) of this section in accordance with 

§75.64(a), i.e., beginning with data recorded on and after the 

earlier of: 

(A) The date of provisional certification, as defined in 

§75.20(a)(3) of this chapter; or

(B) 180 days after the date on which the EGU commences 

commercial operation (as defined in §72.2 of this chapter). 

(ii) For newly-constructed affected EGUs under this subpart 

that are not subject to the Acid Rain Program, you must begin 

submitting the quarterly electronic reports described in 

paragraph (c)(2) of this section, beginning with data recorded 

on and after:

(A) The date on which reporting is required to begin under 

§75.64(a), if that date occurs on or after the effective date of 

this rule; or

(B) The effective date of this rule, if the date on which 

reporting would ordinarily be required to begin under §75.64(a) 

has passed prior to the effective date of this rule. 

(iii) For reconstructed or modified units, reporting of 

emissions data shall begin at the date on which the EGU becomes 

an affected unit under this subpart, provided that the ECMPS 

Client Tool is able to receive and process net energy output

data on that date. Otherwise, emissions data reporting shall be 

on a gross energy output basis until the date that the Client 
Page 31 of 60

Tool is first able to receive and process net energy output

data. 

(4) If any required monitoring system has not been 

provisionally certified by the applicable date on which 

emissions data reporting is required to begin under paragraph 

(c)(3) of this section, the maximum (or in some cases, minimum) 

potential value for the parameter measured by the monitoring 

system shall be reported until the required certification 

testing is successfully completed, in accordance with §75.4(j) 

of this chapter, §75.37(b) of this chapter, or section 2.4 of 

appendix D to part 75 of this chapter (as applicable). 

Operating hours in which CO2 mass emission rates are calculated 

using maximum potential values are not “valid operating hours” 

(as defined in §60.5540(a)(1)), and shall not be used in the 

compliance determinations under §60.5540.

(d) For affected EGUs subject to the Acid Rain Program, the 

reports required under paragraphs (a) and (c)(1) of this section 

shall be submitted by:

(1) The person appointed as the Designated Representative 

(DR) under §72.20 of this chapter; or

(2) The person appointed as the Alternate Designated 

Representative (ADR) under §72.22 of this chapter; or

(3) A person (or persons) authorized by the DR or ADR under 

§72.26 of this chapter to make the required submissions.
Page 32 of 60

(e) For affected EGUs that are not subject to the Acid Rain 

Program, the owner or operator shall appoint a DR and (optional) 

an ADR to submit the reports required under paragraphs (a) and 

(c)(2) of this section. The DR and ADR must register with the 

Clean Air Markets Division (CAMD) Business System. The DR may 

delegate the authority to make the required submissions to one 

or more persons.

(f) If your affected EGU captures CO2 to meet the applicable 

emission limit, you must report in accordance with the 

requirements of 40 CFR Part 98 Subpart PP and either:

(1) Report in accordance with the requirements of 40 CFR 

Part 98 subpart RR, if injection occurs on-site, or

(2) Transfer the captured CO2 to an EGU or facility that 

reports in accordance with the requirements of 40 CFR Part 98 

subpart RR, if injection occurs off-site.

(3) Transfer the captured CO2 to a facility that has received an 

innovative technology waiver from EPA pursuant to paragraph (g) 

of this section.

(g) Any person may request the Administrator to issue a 

waiver of the requirement that captured CO2 from an affected EGU 

be transferred to a facility reporting under 40 CFR Part 98 

subpart RR. To receive a waiver, the applicant must demonstrate 

to the Administrator that its technology will store captured CO2

as effectively as geologic sequestration, and that the proposed 
Page 33 of 60

technology will not cause or contribute to an unreasonable risk 

to public health, welfare, or safety. In making this 

determination, the Administrator shall consider (among other 

factors) operating history of the technology, whether the

technology will increase emissions or other releases of any 

pollutant other than CO2, and permanence of the CO2 storage. The 

Administrator may test the system itself, or require the 

applicant to perform any tests considered by the Administrator 

to be necessary to show the technology’s effectiveness, safety, 

and ability to store captured CO2 without release. The 

Administrator may grant conditional approval of a technology, 

the approval conditioned on monitoring and reporting of 

operations. The Administrator may also withdraw approval of the 

waiver on evidence of releases of CO2 or other pollutants. The 

Administrator will provide notice to the public of any 

application under this provision, and provide public notice of 

any proposed action on a petition before the Administrator takes 

final action.

§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) (1) For affected EGUs subject to the Acid Rain Program, 

you must follow the applicable recordkeeping requirements and 
Page 34 of 60

maintain records as required under subpart F of part 75 of this 

chapter.

(2) For affected EGUs that are not subject to the Acid Rain 

Program, you must also follow the recordkeeping requirements and 

maintain records as required under subpart F of part 75 of this 

chapter, to the extent that those records provide applicable

data for the compliance determinations required under this 

subpart. Regardless of the prior sentence, at a minimum, the 

following records must be kept, as applicable to the types of 

continuous monitoring systems used to demonstrate compliance 

under this subpart:

(i) Monitoring plan records under §75.53(g) and (h) of this 

chapter;

(ii) Operating parameter records under §75.57(b)(1) through 

(b)(4) of this chapter;

(iii) The records under §75.57(c)(2) of this chapter, for 

stack gas volumetric flow rate; 

(iv) The records under §75.57(c)(3) for continuous moisture 

monitoring systems;

(v) The records under §75.57(e)(1), except for paragraph 

(e)(1)(x), for CO2 concentration monitoring systems or O2

monitors used to calculate CO2 concentration;

(vi) The records under §75.58(c)(1), paragraphs (c)(1)(i), 

(c)(1)(ii), and (c)(1)(viii) through (c)(1)(xiv), for oil flow 
Page 35 of 60

meters;

(vii) The records under §75.58(c)(4), paragraphs (c)(4)(i), 

(c)(4)(ii), (c)(4)(iv), (c)(4)(v), and (c)(4)(vii) through 

(c)(4)(xi), for gas flow meters;

(viii) The quality-assurance records under §75.59(a) of 

this chapter, paragraphs (a)(1) through (a)(12) and (a)(15), for 

CEMS;

(ix) The quality-assurance records under §75.59(a) of this 

chapter, paragraphs (b)(1) through (b)(4), for fuel flow meters; 

and

(x) Records of data acquisition and handling system (DAHS) 

verification under §75.59(e) of this chapter.

(c) You must keep records of the calculations you performed 

to determine the hourly and total CO2 mass emissions (tons) for:

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

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

month compliance period.

(d) Consistent with §60.5520, you must keep records of the 

applicable data recorded and calculations performed that you 

used to determine your affected EGU’s gross or net energy 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. 
Page 36 of 60

(f) You must keep records of the calculations you performed 

to assess compliance with each applicable CO2 mass emissions 

standard in Table 1 or 2 of this subpart.

(g) You must keep records of the calculations you 

performed to determine any site-specific 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 3 years after the 

date of conclusion of each compliance period. 

(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. Records that are accessible from a central location by a 

computer or other means that instantly provide access at the 

site meet this requirement. You may maintain the records off 

site 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 EGU?

Notwithstanding any other provision of this chapter, 

certain parts of the General Provisions in §60.1 through 60.19, 

listed in Table 3 to this subpart, do not apply to your affected 
Page 37 of 60

EGU.

§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).
Page 38 of 60

§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).

Annual capacity factor means the ratio between the actual 

heat input to an EGU during a calendar year and the potential 

heat input to the EGU had it been operated for 8,760 hours 

during a calendar year at the base load rating.

Base load rating means the maximum amount of heat input 

(fuel) that an EGU can combust on a steady state basis, as 

determined by the physical design and characteristics of the EGU

at ISO conditions. For a stationary combustion turbine, base

load rating includes the heat input from duct burners.

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, 
Page 39 of 60

etc.) containing coal, matrix material, clay, and other organic 

and inorganic material.

Combined cycle unit 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 (HRSG) to generate additional electricity.

Combined heat and power unit or CHP unit, (also known as 

“cogeneration”) means an electric generating unit that that use 

a steam-generating unit or stationary combustion turbine to 

simultaneously produce both electric (or mechanical) and useful 

thermal output from the same primary energy source.

Design efficiency means the rated overall net efficiency 

(e.g., electric plus thermal output) on a lower heating value 

basis of the EGU at the base load rating and ISO conditions.

Distillate oil means fuel oils that 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);
Page 40 of 60

or biodiesel blends as defined by the American Society of 

Testing and Materials in ASTM D7467 (incorporated by reference, 

see §60.17).

Electric Generating units or EGU means any steam generating 

unit, IGCC unit, or stationary combustion turbine that is 

subject to this rule (i.e., meets the applicability criteria)

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, the gross 

electric or direct mechanical output from both the EGU

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

combustion turbine(s), and gas expander(s)) plus 100 percent of 

the useful thermal output.

(2) For steam generating units, the gross electric or 

mechanical output from the affected EGU(s) (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 100 percent of the useful thermal output;
Page 41 of 60

(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 

12-operating month rolling average basis, the gross electric or 

mechanical output from the affected EGU (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 100 percent of the useful thermal output.

Heat recovery steam generating unit (HRSG) means an EGU 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 unit or IGCC means a 

combined cycle stationary combustion turbine that is designed to 

burn fuels containing 50 percent (by heat input) or more solidderived 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 EGU during operation.
Page 42 of 60

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 EGU(s), generate electricity 

and/or thermal energy, or to enhance the performance of the 

affected EGU. 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. 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 CO2 content or 

heating value.

Net-electric sales means 
Page 43 of 60

(1) The gross electric sales to the utility power 

distribution system minus purchased power; or

(2) For combined heat and power facilities where at least 

20.0 percent of the total gross energy output consists of 

electric or direct mechanical output and at least 20.0 percent 

of the total gross energy output consists of useful thermal 

output on an annual basis, the gross electric sales to the 

utility power distribution system minus purchased power of the 

thermal host EGU or facilities.

(3) Electricity supplied to other facilities that produce 

electricity to offset auxiliary loads are included when 

calculating net-electric sales.

(4) Electric sales that that result from a grid emergency 

are not 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:
Page 44 of 60

(i) Except as provided under paragraph (ii) of this 

definition, the net electric or mechanical output from the 

affected EGU plus 100 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 12-operating month rolling average basis, 

the net electric or mechanical output from the affected EGU

divided by 0.95, plus 100 percent of the useful thermal output;

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).

Operating month means a calendar month during which any 

fuel is combusted in the affected EGU at any time.

Petroleum means crude oil or a fuel derived from crude 

oil, including, but not limited to, distillate and residual 

oil.

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.

Potential electric output means 33 percent or the design 
Page 45 of 60

efficiency, whichever is greater, multiplied by the base load 

rating (expressed in MMBtu/h) of the EGU, 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 EGU 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. 

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, post-combustion emission 

control technology, and any ancillary components and subcomponents 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 
Page 46 of 60

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 EGU(s) 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 EGU, to 

directly enhance the performance of the affected EGU (e.g., 

economizer output is not useful thermal output, but thermal 

energy used to reduce fuel moisture is considered useful thermal 

output), or to supply energy to a pollution control device at 

the affected EGU. Useful thermal output for affected EGU(s) with 

no condensate return (or other thermal energy input to the 

affected EGU(s)) or where measuring the energy in the condensate 

(or other thermal energy input to the affected EGU(s)) would not 

meaningfully impact the emission rate calculation is measured 
Page 47 of 60

against the energy in the thermal output at SATP conditions. 

Affected EGU(s) with meaningful energy in the condensate return 

(or other thermal energy input to the affected EGU) must measure 

the energy in the condensate and subtract that energy relative 

to SATP conditions from the measured thermal output. 

System emergency means any abnormal system condition that 

the Regional Transmission Organizations (RTO), Independent 

System Operators (ISO) or control area Administrator determines 

requires immediate automatic or manual action to prevent or 

limit loss of transmission facilities or generators that could 

adversely affect the reliability of the power system and 

therefore call for maximum generation resources to operate in 

the affected area, or for the specific affected facility to 

operate to avert loss of load.

Valid data means quality-assured data generated by 

continuous monitoring systems that are installed, operated, and 

maintained according to part 75 of this chapter. For CEMS, the 

initial certification requirements in §75.20 of this chapter and 

appendix A to part 75 of this chapter must be met before 

quality-assured data are reported under this subpart; for ongoing quality assurance, the daily, quarterly, and 

semiannual/annual test requirements in sections 2.1, 2.2, and 

2.3 of appendix B to part 75 of this chapter must be met and the 

data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of 
Page 48 of 60

appendix B to part 75 of this chapter apply. For fuel flow 

meters, the initial certification requirements in section 2.1.5 

of appendix D to part 75 of this chapter must be met before 

quality-assured data are reported under this subpart (except for 

qualifying commercial billing meters under section 2.1.4.2 of 

appendix D), and for on-going quality assurance, the provisions 

in section 2.1.6 of appendix D to part 75 of this chapter apply 

(except for qualifying commercial billing meters). 

Violation means a specified averaging period over which the 

CO2 emissions rate is higher than the applicable emissions 

standard located in Table 1 or Table 2 of this subpart.
Page 49 of 60

Table 1 of Subpart TTTT of Part 60 – CO2 Emission Standards for 

Affected Steam Generating Units and Integrated Gasification 

Combined Cycle Facilities that Commenced Construction after 

January 8, 2014 and Reconstruction or Modification after June 

18, 2014 (net energy output-based standards are only applicable 

to affected units subject to a federally enforceable permit

condition limiting GHG emissions on a net energy output basis)

Note: numerical values of 1,000 or greater have a minimum of 3

significant figures and numerical values of less than 1,000 have 

a minimum of 2 significant figures

Affected EGU CO2 Emission Standard

Newly constructed steam 

generating unit or integrated 

gasification combined cycle 

(IGCC)

640 kg CO2/MWh of gross energy 

output (1,400 lb CO2/MWh)

Reconstructed steam generating 

unit or IGCC that has base load 

rating of 2,100 GJ/h (2,000 

MMBtu/h) or less

910 kg of CO2 per MWh of gross

energy output (2,000 lb 

CO2/MWh)

Reconstructed steam generating 

unit or IGCC EGU that has a 

base load rating greater than 

2,100 GJ/h (2,000 MMBtu/h)

820 kg of CO2 per MWh of gross

energy output (1,800 lb 

CO2/MWh) 

Modified steam generating or 

IGCC unit

A unit-specific emission limit 

determined by the unit’s best 

historical annual CO2 emission 

rate (from 2002 to the date of 

the modification); the 

emission limit will be no 

lower than:

1. 1,800 lb CO2/MWh-gross for 

units with a base load 

rating greater than 2,000 

MMBtu/h; or

2. 2,000 lb CO2/MWh-gross for 

units with a base load 

rating of 2,000 MMBtu/h or 

less.
Page 50 of 60

Table 2 of Subpart TTTT of Part 60 – CO2 Emission Standards for

Affected Stationary Combustion Turbines that Commenced 

Construction after January 8, 2014 and Reconstruction after June 

18, 2014 (net energy output-based standards are only applicable 

to affected units subject to a federally enforceable permit 

condition limiting GHG emissions on a net energy output basis)

Note: numerical values of 1,000 or greater have a minimum of 3

significant figures and numerical values of less than 1,000 have 

a minimum of 2 significant figures

Affected EGU CO2 Emission Standard1

Newly constructed or

reconstructed stationary

combustion turbine that 

supplies more than the design 

efficiency times the potential 

electric output as net-electric 

sales on a 3 year rolling 

average basis and combusts more 

than 90% natural gas on a heat 

input basis on a 12-operating 

month rolling average basis.

450 kg of CO2 per MWh of gross 

energy output (1,000 lb 

CO2/MWh); or

470 kilograms (kg) of CO2 per 

megawatt-hour (MWh) of net

energy output (1,030 lb/MWh) 

Newly constructed or

reconstructed stationary 

combustion turbine that 

supplies one-third or the 

design efficiency, whichever is 

greater, of its potential 

electric output or less as netelectric sales on a 3 year 

rolling average basis and 

combusts more than 90% natural 

gas on a heat input basis on a 

12-operating month rolling 

average basis.

50 kg CO2 per gigajoule (GJ) 

of heat input (120 lb 

CO2/MMBtu) 

Stationary combustion turbine 

that combusts 90% or less 

natural gas on a heat input 

basis on a 12-operating month 

rolling average basis.

69 kg CO2/GJ of heat input 

(160 lb/MMBtu) 

 

1 See procedures for establishing and revising the compliance 

option under § 60.5520.
Page 51 of 60

Table 3 to 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

Does not apply to 

information 

reported 

electronically 

through ECMPS. 

Duplicate 

submittals are not 

required. 

§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 

notifications in 

60.7(a)(1) and 

(a)(3) and to keep 

records of 

malfunctions in 

§60.7(b), if 

applicable

§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 No

All monitoring is 

done according to 

Part 75 
Page 52 of 60

§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

Does not apply to 

notifications 

under

§75.61 or to 

information 

reported through 

ECMPS.
Page 53 of 60

PART 70— STATE OPERATING PERMIT PROGRAMS

3. The authority citation for part 70 continues to read as 

follows:

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

4. Section 70.2 is amended 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).”

The revision and additions read as follows:

§70.2 Definitions.

* * * * *

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.

* * * * *

5. 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 
Page 54 of 60

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.

* * * * *

(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 permit modification or 

related permit action

43

7
Page 55 of 60

GHG evaluation at permit renewal 10

* * * * *

PART 71— FEDERAL OPERATING PERMIT PROGRAMS

6. The authority citation for part 71 continues to read as 

follows:

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

7. Section 71.2 is amended 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).” 

The revisions and additions read as follows:

§71.2 Definitions.

* * * * *

Regulated pollutant (for fee calculation), which is used 

only for purposes of §71.9(c), means any “regulated air 

pollutant” except the following:

* * * * *

(4) Greenhouse gases.

* * * * *

8. 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:
Page 56 of 60

§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.
Page 57 of 60

* * * * *

(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:

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 ]
Page 58 of 60

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
Page 59 of 60

* * * * *

PART 98— MANDATORY GREENHOUSE GAS REPORTING

9. 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

10. Section 98.426 is amended by adding paragraph (h) to 

read as follows:

§98.426 Data reporting requirements.

* * * * *

(h) If you capture a CO2stream 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 subpart D facility, 

(2) Report each facility identification number associated 

with the annual GHG reports for each subpart RR facility to 

which CO2 is transferred, and

(3) Report the annual quantity of CO2 in metric tons that 

is transferred to each subpart RR facility.

11. Section 98.427 is amended by adding paragraph (d) to 

read as follows:

§98.427 Records that must be retained.
Page 60 of 60

* * * * *

(d) Facilities subject to §98.426(h) must retain records of 

CO2 in metric tons that is transferred to each subpart RR 

facility.