1

Fellner, Christian

From: Hutson, Nick

Sent: Thursday, December 19, 2013 2:52 PM

To: Fellner, Christian

Subject: Please docket - FW: Revised (RLSO) versions of regulatory text

Attachments: EO 12866 EGU GHG NSPS 2060-AQ91 NPRM 20130628 REGTEXT_083013.docx; EO 

12866 EGU GHG NSPS 2060-AQ91 NPRM 20130628 REGTEXT_083013x.pdf

From: Hutson, Nick 

Sent: Friday, August 30, 2013 5:38 PM 

To: Frey, Nathan J. 

Cc: Culligan, Kevin; Wayland, Robertj; Tsirigotis, Peter 

Subject: Revised (RLSO) versions of regulatory text 

Revised regulatory text is attached.

From: Hutson, Nick 

Sent: Friday, August 30, 2013 5:36 PM 

To: 'Frey, Nathan J.' 

Cc: Culligan, Kevin; Wayland, Robertj; Tsirigotis, Peter 

Subject: Revised (RLSO) versions of preamble; EPA response 

Nathan

Attached to this email are three files:

(1) A PDF version of the redline changes to the preamble

(2) A MSWord version of the redline changes to the preamble

(3) An updated ‘EPA Response’ to the Interagency Comments

In emails immediately following this one, I will send versions of the ...

(1) Revised regulatory language

(2) Revised RIA chapters; and

(3) A DRAFT version of a TSD entitled “Fossil Fuel‐Fired Boiler and IGCC EGU Projects Under Development:

Status and Approach”

We have made many changes in response to comments from OMB and the Interagency Workgroup.  We are still

considering some comments.  Those are noted in the text and in the EPA Response.  We can continue to discuss specific

comments and other aspects of the package once you have had the opportunity to see the edits in these revised

versions.

Have a nice holiday and a relaxing time off next week.

Regards,

Nick
2

Nick Hutson, PhD

Energy Strategies Group

U.S. Environmental Protection Agency

Research Triangle Park, NC 27711

(919) 541‐2968

hutson.nick@epa.gov
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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 proposed to be amended as follows: 

PART 60--[AMENDED] 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. 

Subpart Da-—[Amended] Standards of Performance for Electric 

Utility Steam Generating Units

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

§§ 60.46Da Standards for carbon dioxide (CO2) 

(a) Your electric utility steam generating unit or IGCC 

electric utility steam generating unit is subject to this 

section if construction commenced on or after [INSERT DATE OF

FINAL RULE PUBLICATION IN THE FEDERAL REGISTER], and the 

affected facility meets the conditions specified in paragraph 

(a)(1) and (a)(2) of this subsection, except as specified in 

paragraph (b) of this section. 

(1) The affected facility burns fossil fuel for more than 

10.0 percent of the average annual heat input during any 3 

consecutive calendar years. 
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(2) The affected facility supplies more than one-third of 

its potential electric output and more than 219,000 MWh netelectrical output to a utility power distribution system for 

sale. 

(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 a complete request for an applicability 

determination for the project has been submitted to [INSERT 

APPROPRIATE EPA CONTACT INFORMATION] no later than 120 days 

after [DATE OF FINAL RULE PUBLICATION IN THE FEDERAL 

REGISTERINSERT DATE OF FEDERAL REGISTER PUBLICATION] and EPA 

determines that construction had not commenced for NSPS purposes 

as of [DATE OF FINAL RULE PUBLICATION IN THE FEDERAL 

REGISTERINSERT DATE OF PUBLICATION FOR 111(a)(2) PURPOSES]. 

(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, 
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effective December 16, 2010, provided that a complete request 

for an applicability determination for the project has been 

submitted to [INSERT APPROPRIATE EPA CONTACT INFORMATION] no 

later than 120 days after [DATE OF FINAL RULE PUBLICATION IN THE 

FEDERAL REGISTERINSERT DATE OF FEDERAL REGISTER PUBLICATION] and 

EPA determines that construction had not commenced for NSPS 

purposes as of [DATE OF FINAL RULE PUBLICATION IN THE FEDERAL 

REGISTERINSERT DATE OF PUBLICATION FOR 111(a)(2) PURPOSES]. 

(c) No 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 limitation specified in either 

paragraph (c)(1) or (c)(2) of this subsection. 

(1) 450 500 kilograms (kg) of CO2 per megawatt-hour (MWh) of 

gross energy output (1,000 1,100 lb CO2/MWh) on a 12-operating 

month rolling average basis; or 

(2) 480 kg of CO2 per MWh of gross energy output (1,050 lb 

CO2/MWh) on a 60-operating month rolling average basis. 

(d) Your affected facility must be in compliance at all 

times with the applicable CO2 emission limitation in paragraph 

(c) of this section for which you have elected to comply. 

However, cCompliance determinations are only to be made at the 

end of each operating month, as provided in paragraphs (d)(1) 
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and (d)(2) of this subssection. For the purpose of this section, 

operating month means a calendar month during which any fossil 

fuel is combusted in an affected facility at any time. 

(1) If you elect to comply with the CO2 emissions limitation 

in paragraph (c)(1) of this section, you must determine 

compliance monthly by calculating the average CO2 emissions rate 

for the affected facility at the end of each preceding 12-

operating month period. 

(2) If you elect to comply with the CO2 emissions limitation 

in paragraph (c)(2) of this section, you must determine 

compliance monthly by calculating the average CO2 emissions rate 

for the affected facility at the end of each preceding 60-

operating month period. 

(e) You must conduct an initial CO2 emissions limitation 

determination for your affected facility within 30 days after 

the required number of operating months for the CO2 emissions

limitation operating month compliance period that you have 

elected to comply with have been accumulated (i.e., 12-operating 

months or 60-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 chapterpart. 
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(f) You must monitor and collect data to demonstrate 

compliance with the CO2 emissions limitation according to the 

requirements specified 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 

chapterpart. 

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

affected facility using the procedures specified in paragraphs 

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

paragraph (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 the exhaust 

gases from your affected facility that are vented to the 

atmosphere and an exhaust gas flow rate monitoring system 

according to §§ 75.10(a)(3)(i) of this chapterpart. If CO2

concentration is measured 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 chapterpart. 

(ii) For each monitoring system used to determine the CO2

mass emissions, you must meet the applicable certification and 
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quality assurance procedures in §§ 75.20 of this chapterpart and 

appendices B and D to part 75 of this chapterpart. 

(iii) You must use a laser device to measure each exhaust 

gas stack or duct dimensions at the flow monitor and the 

reference method sampling locations prior to the initial setup 

(characterization) of the flow monitor. For circular stacks, 

make three determinations of the diameter at three or more 

distinct locations and average the results. For rectangular 

stacks or ducts, make three measurements of each dimension at 

three or more distinct locations (i.e., depth and width) and 

average the results. If the flow rate monitor or reference 

method sampling site is relocated, repeat these measurements at 

the new location. 

(iv) Only unadjusted exhaust gas volumetric flow rates can 

be used to determine the hourly CO2 mass emissions from the 

affected facility; the bias adjustment factors described in 

Section 7.6.5 of Appendix A to part 75 of this chapterpart

cannot be applied to the exhaust gas flow rate data. 

(v) If you elect 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. Use of 

the default Type-S pitot tube coefficient is not permitted. 
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(vi) If two or more affected facilities share a common 

exhaust gas stack and are subject to the same CO2 emissions 

limitation in paragraph (c) of this section, you may monitor the 

hourly CO2 mass emissions at the common exhaust gas stack in 

place of monitoring each affected facility separately. 

(vii) If the exhaust gases from the affected facilities are 

vented 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 chapterpart) at each stack or duct 

separately. 

(3) You must install, calibrate, maintain, and operate a 

sufficient number of watt meters to continuously measure and 

record the gross electrical output from the affected facility, 

and you must 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 of this subpart, you must also 

install, calibrate, maintain, and operate meters to continuously 

determine and record the total useful recovered thermal energy. 

For process steam applications, you will need to install, 

calibrate, maintain, and operate meters to continuously 
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determine and record this information includes steam flow rate, 

temperature, and pressure. If the combined heat and power unit 

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, ensuring you, 

install, calibrate, maintain, and operate meters to continuously 

determine and record each component of the determination..

(ii) If two or more affected facilities steam generating 

units serve a common electrical generator, you must apportion 

the combined hourly gross electrical 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).), ensuring 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 

limitation using the procedures specified in paragraphs (g)(1) 

and (2) of this section. 

(1) You must calculate the CO2 mass emissions output-based 

rate for your affected facility using the hourly CO2 mass 

emissions and gross energy output data determined and recorded 

according to the procedures specified in paragraph (f) of this 

section for each operating hour in the applicable operating 
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month compliance period for the CO2 emissions limitation (i.e., 

12-operating months or 60-operating months), and the calculation 

procedures specified in paragraphs (g)(1)(i) through (v) of this 

section. 

(i) Use only operating hours in the operating month 

compliance period for which quality-assured data are obtained 

for all parameters used to determine the hourly CO2 mass 

emissions. No operating hours in which the substitute data 

provisions of part 75 of this chapterpart are used for any of 

those parameters are to be included 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 operating month compliance period for 

the CO2 emissions limitation applicable to the affected facility. 

(ii) Calculate the total CO2 mass emissions by summing all 

of the valid hourly CO2 mass emissions values determined for the 

applicable operating month compliance period interval. In a case 

for which exhaust gases from the affected facility are vented to 

the atmosphere through multiple stacks or ducts, the total CO2

mass emissions for the affected facility is calculated by 

summing the total CO2 mass emissions determined from each of the 

individual stacks or ducts. 
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(iii) For each operating hour of the operating month 

compliance period used in paragraph (g)(1)(ii) of this section 

to calculate the total CO2 mass emissions, determine the affected 

facility’s corresponding hourly gross energy output using the 

appropriate definition in §§ 60.42Da of this subpart for your 

affected facility. For an operating hour in which there is no 

gross electrical load, but there is mechanical or useful thermal 

output, you must still determine the gross energy output for 

that hour. In the case for which hourly CO2 mass emissions are 

determined for a common stack, then the hourly gross energy 

output (electrical, thermal, and/or mechanical, as applicable) 

is determined by summing the hourly loads for the individual 

affected facility and the operating time is expressed as “stack 

operating hours” (as defined in §§ 72.2 of this chapterpart). 

(iv) Calculate the total gross energy output by summing the 

hourly gross 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 operating month compliance 

period interval. 

(v) Calculate the CO2 mass emissions output-based rate for 

the applicable operating month compliance period interval by 

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

value from paragraph (g)(1)(iv) of this section. 

(2) Compliance with the CO2 emissions limitation 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 output-based rate for your affected facility 

determined in paragraph (g)(1) of this section. 

(i) If the CO2 mass emissions output-based rate for the your

affected facility is less than or equal to the CO2 emissions 

limitation in paragraph (c) of this section applicable to your 

affected facility, then the your affected facility is determined 

to be in compliance with the CO2 emissions limitation. If 

compliance with the CO2 emissions limitation is attained at a 

common stack for two or more affected facilities subject to the 

same CO2 emissions limitation, each affected facility sharing the 

stack is in compliance with the CO2 emissions limitation

considered to be in compliance. 

(ii) If the CO2 mass emissions output-based rate for the 

affected facility is greater than the CO2 emissions limitation in 

paragraph (c) of this section applicable to your affected 

facility, then the affected facility has is determined to have 

excess CO2 emissions. 
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(h) You must prepare and submit notifications and reports 

according to paragraphs (h)(1) through (4) of this section. 

(1) You must prepare and submit the notifications specified 

in §§§ 60.7(a)(1) and (a)(3) and §§ 60.19 of this part, as 

applicable to your affected facility. 

(2) You must prepare and submit notifications specified in 

§§ 75.61 of this chapterpart, 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 the required number of operating 

months for the CO2 emission limitation operating month compliance 

period that you have elected to comply with have been 

accumulated (i.e., 12-operating months or 60-operating months), 

a report for the calendar quarter that includes the twelfth12th-

(or sixtieth) operating month must be submitted no later than 30 

days after the end of that quarter. Thereafter, a report for 

each subsequent calendar quarter must be submitted no later than 

30 days after the end of the quarter. 

(ii) Each quarterly report must include the information 

specified in paragraphs (h)(3)(ii)(A) through (E) of this 

section. 
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(A) Identification of the CO2 emission limitation operating 

month compliance period with which you have elected to comply. 

(B) Identification of any months in the calendar quarter 

that are not operating months. 

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

corresponding average CO2 mass emissions output-based rate for 

the applicable operating month compliance period interval, as 

determined according to paragraph (g) of this section. 

(D) Percentage of valid CO2 mass emission rates in each 

operating month 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) Identification of any operating months in the calendar 

quarter with excess CO2 emissions. 

(iii) The final quarterly report of each calendar year must 

contain the following: 

(A) Gross electric output sold to an electric grid over the 

4 quarters of the calendar year; and 

(B) The potential electric output of the facility. 

(iv) Each electronic report must be submitted using the 

Emissions Collection and Monitoring Plan System (ECMPS) Client 
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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 

chapterpart. 

(5) Any affected unit that employs geologic sequestration 

to meet the applicable emission limit must report 40 CFR Part 98 

Subpart PP and either:

(i) if injection occurs onsite, report under 40 CFR Part 98 

subpart RR, or

(ii) if injection occurs offsite, transfer the captured CO2 

to a facility or facilities that reports under 40 CFR Part 98 

subpart RR.

(i) For each affected electric utility stream generating 

unit, you must maintain records according to paragraphs (i)(1) 

through (i)(8) of this section. 

(1) You must comply with the applicable recordkeeping 

requirements and maintain records as required under subpart F of 

part 75 of this chapterpart. 

(2) You must maintain records of the calculations performed 

to determine the total CO2 mass emissions for each operating 

month, and averages for each operating month compliance period 

Formatted: Line spacing: Double
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interval (i.e., 12-operating months or 60-operating months, as 

applicable to the CO2 emissions limitations). 

(3) You must maintain records of the applicable data 

recorded and calculations performed used to determine the gross 

energy output for each operating month. 

(4) You must maintain records of the calculations performed 

to determine the percentage of valid CO2 mass emission rates in 

each operating month compliance period. 

(5) You must maintain records of the calculations performed 

to assess compliance with each applicable CO2 emissions 

limitation 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 following the 

date of each occurrence, measurement, maintenance, corrective 

action, report, or record except those records required to 

demonstrate compliance with a 60-operating month compliance 

period. You must maintain records required to demonstrate 

compliance with a 60-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, 
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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 Thresholds for Greenhouse Gases. 

(1) For purposes of 40 CFR 51.166(b)(49)(ii), with 

respect to GHG emissions from new EGUs, 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 EGUs, 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 electric utility generating units, 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 

70.2. 

(4) For purposes of 40 CFR 71.2, with respect to 

greenhouse gas emissions from new electric utility 

generating units, the “pollutant that is subject to any 

standard promulgated under section 111 of the Act” shall be 

considered to be the pollutant that otherwise is "subject 

to regulation" as defined in 40 CFR 71.2. 

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

apply: 

Gross energy output means:

(1) For electric utility steam generating units constructed, 

reconstructed, or modified after May 3, 2011, the gross 

electrical 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 electrical or mechanical output or 

to enhance the performance of the unit (i.e., steam delivered to 

an industrial process); 

(2) For combined heat and power facilities constructed, 

reconstructed, or modified after May 3, 2011, where at least 
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20.0 percent of the total gross useful energy output consists of 

electric or direct mechanical output and at least 20.0 percent 

of the total gross useful energy output consists of thermal 

output, the gross electrical 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 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 electrical or mechanical output or to enhance the 

performance of the unit ( i.e., steam delivered to an industrial 

process); 

(3) For a IGCC electric utility generating unit constructed, 

reconstructed, or modified after May 3, 2011, the gross useful 

work performed is the gross electrical or mechanical output from 

the unit plus 75 percent of the useful thermal output measured 

relative to ISO conditions that is not used to generate 

additional electrical or mechanical output or to enhance the 

performance of the unit ( i.e., steam delivered to an industrial 

process). 

Integrated gasification combined cycle electric utility steam 

generating unit or IGCC electric utility steam generating unit

means an electric utility combined cycle gas turbinefacility

Comment [CRB1]: Check against 4K 
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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 turbine 

engine and heat recovery steam generator or to power auxiliary 

equipment.. The Administrator may waive the 50 percent solidderived 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. 

Net-electric output means 

(1) the The gross electric sales to the utility power 

distribution system minus purchased power on a calendar year 

basis, or 

(2) For combined heat and power facilities where at least 20.0 

percent of the total gross useful energy output consists of 

electric or direct mechanical output and at least 20.0 percent 

of the total gross useful energy output consists of thermal 

output, net-electric output means the gross electric sales to 

the utility power distribution system minus purchased power of 

the thermal host facilityies or facilities on a calendar year 

basis. 
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Potential electrical output capacity means 33 percent or the 

design net electric output efficiency time the maximum design 

heat input capacity of the steam generating unit, divided by 

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

hr/yr (e.g. , a 35 percent efficient steam generating unit with 

a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would 

have a 310,000 06,420 MWh 12 month potential electrical output 

capacity). For electric utility combined cycle gas turbines the 

potential electrical output capacity is determined on the basis 

of the fossil-fuel firing capacity of the steam generator 

exclusive of the heat input and electrical power contribution by 

the gas turbine. 

Steam generating unit for facilities constructed, 

reconstructed, or modified before May 4, 2011, means any 

furnace, boiler, or other device used for combusting fuel 

for the purpose of producing steam (including fossil-fuelfired steam generators associated with combined cycle gas 

turbines; nuclear steam generators are not included). For 

units constructed, reconstructed, or modified after May 3, 

2011, steam generating unit means any furnace, boiler, or 

other device used for combusting fuel for the purpose of 

producing steam (including fossil-fuel-fired steam 

generators associated with combined cycle gas turbines; 

nuclear steam generators are not included) plus any 
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integrated equipment that provides electricity or useful 

thermal output to either the boiler or to power auxiliary 

equipment. 

* * * * *

Subpart KKKK-— Standards of Performance for Stationary 

Combustion Turbines[Amended]

 3. 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 gas regulated by this subpart is 

carbon dioxide (CO2). 

(2) PSD and Thresholds for Greenhouse Gases. 

(i) For purposes of 40 CFR 51.166(b)(49)(ii), with 

respect to GHG emissions from new EGUs, 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 new EGUs, the “pollutant that 
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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 new electric utility generating 

units, 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 new electric utility generating 

units, 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. 

4. Section 60.4325 4326 is added to read as follows: 

§§ 60.4325 4326 What CO2 emissions standard must I meet? 

For each affected EGU subject to this subpart, you must not 

discharge from the EGU into the atmosphere any gases that 

contain CO2 in excess of the applicable CO2 emissions standard 

specified in Table 2 to this subpart. Each CO2 emissions standard 

has a minimum of two significant digits. 
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5. Section 60.4333 is amended by adding paragraph (gc) to 

read as follows: 

§§ 60.4333 What are my general requirements for complying with 

this subpart? 

* * * * * 

(gc) If you own or operate a stationary combustion turbine 

subject to a CO2 emissions standard in §§ 60.43254326, compliance 

determinations are to be made 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 

each preceding 12-operating month period. 

6. Section 60.4373 is added 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 

chapterpart. 

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

affected EGU using the procedures specified 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 
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directly measure and record CO2 concentrations in the EGU exhaust 

gases vented to the atmosphere and an exhaust gas flow rate 

monitoring system according to §§ 75.10(a)(3)(i) of this 

chapterpart. If CO2 concentration is measured 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 chapterpart. 

(2) 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 chapterpart and 

appendices B and D to part 75 of this chapterpart. 

(3) You must use a laser device to measure each exhaust gas 

stack or duct dimensions at the flow monitor and the reference 

method sampling locations prior to the initial setup 

(characterization) of the flow monitor. For circular stacks, 

make three determinations of the diameter at three or more 

distinct locations and average the results. For rectangular 

stacks or ducts, make three measurements of each dimension at 

three or more distinct locations (i.e., depth and width) and 

average the results. If the flow rate monitor or reference 

method sampling site is relocated, repeat these measurements at 

the new location. 

(4) Only unadjusted exhaust gas volumetric flow rates can 

be used to determine the hourly CO2 mass emissions from the 
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affected EGU; the bias adjustment factors described in Section 

7.6.5 of Appendix A to part 75 of this chapterpart cannot be 

applied to the exhaust gas flow rate data. 

(5) If you elect 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. Use of 

the default Type-S pitot tube coefficient is not permitted. 

(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 chapterpart

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 chapterpart 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 

using Equation F-7b in section 3.3.6 of appendix F to part 75 of 

this chapterpart, 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 watt 
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a sufficient number of wattmeter (and meters) to continuously 

measure and record the gross electrical output from the affected 

EGU. If the affected EGU is a CHP EGU, you must also install, 

calibrate, maintain, and operate meters to continuously 

determine and record the total useful recovered thermal energy. 

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.For steam this information includes flow rate, 

temperature, and pressure. If the CHP EGU 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, ensuring you, install, 

calibrate, maintain, and operate meters to continuously 

determine and record each component of the determination.. 

(e) If two or more affected EGUs serve a common electrical 

generator, you must apportion the combined hourly gross output 

to the individual EGUs using a plan approved by the 

Administrator (e.g., using steam load or heat input to each 

affected EGU), ensuring 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 EGUs 

that implement the continuous emission monitoring provisions in 
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paragraph (b) of this section share a common exhaust gas stack 

and are subject to the same emissions standard under §§ 

60.43254326, you may monitor the hourly CO2 mass emissions at the 

common stack in lieu of monitoring each EGU separately. If this 

option is chosen, the hourly gross load (electrical, thermal, 

and/or mechanical, as applicable) shall be the sum of the hourly 

loads for the individual EGUs and the operating time shall be 

expressed as “stack operating hours” (as defined in §§ 72.2 of 

this chapterpart). If compliance with the applicable emissions 

standard in §§ 60.43254326 is attained at the common stack, each 

EGU sharing the stack is considered to be in compliance. 

(g) In accordance with §§ 60.13(g), if the exhaust gases 

from an EGU that implements the continuous emission monitoring 

provisions in paragraph (b) of this section are vented 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 chapterpart) at each stack or duct separately. In this 

case, compliance with the applicable emissions standard in §§ 

60.43254326 is determined by summing the CO2 mass emissions 

measured at the individual stacks or ducts and dividing by the 

total gross output for the unit. 

7. Section 60.4374 is added to read as follows: 
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§§ 60.4374 How do I demonstrate compliance with my CO2 emissions 

standard and determine excess emissions? 

(a) You must calculate the CO2 mass emissions output-based 

rate for your affected EGU by using the hourly CO2 mass emissions 

and total gross output data determined and recorded according to 

the procedures specified in §§ 60.4373 for each operating hour 

in the applicable operating month compliance period for the CO2

emissions standard applicable to the affected EGU, and the 

calculation procedures specified in paragraphs (a)(1) through 

(a)(5) of this section. 

(1) Only operating hours in the operating month compliance 

period are used for the compliance determination calculation for 

which quality-assured data are obtained for all parameters used 

to determine the hourly CO2 mass emissions. No operating hours in 

which the substitute data provisions of part 75 of this 

chapterpart are used for any of those parameters are to be 

included 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 

operating month compliance period for the CO2 emissions standard 

applicable to the affected EGU. 

(2) Calculate the total CO2 mass emissions for the affected 

EGU’s operating month compliance period by summing the hourly CO2

mass emissions values for the affected EGU determined to be 
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valid according to the conditions specified in paragraph (a)(1) 

of this section for all of the operating hours in the applicable 

operating month compliance period. 

(3) For each operating hour of the operating month 

compliance period used in paragraph (a)(2) of this section to 

calculate the total CO2 mass emissions, determine the affected 

EGU’s corresponding hourly gross output according to the 

procedures specified in paragraphs (a)(3)(i) and (ii) of this 

section, as appropriate for the type of stationary combustion 

turbine or steam generating unit used for the EGU. For an 

operating hour in which there is no gross electrical load, but 

there is mechanical or useful thermal output, you must still 

determine the gross output for that hour. 

(i) The gross output of a stationary combustion turbine 

with respect to CO2 emissions is determined as specified in 

paragraphs (a)(3)(i)(A) and (B) of this section. 

(A) The gross electrical and mechanical output from the 

stationary combustion turbine plus 75 percent of the useful 

thermal output measured relative to ISO conditions that is not 

used to generate additional electrical or mechanical output or 

to enhance the performance of the unit (e.g., steam delivered to 

an industrial process); or 

(B) For a CHP EGU where at least 20.0 percent of the total 

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

useful energy output consists of useful thermal output on an 

three calendar year rolling average basis, the gross electrical 

and mechanical output from the stationary combustion turbine 

facility divided by 0.95 plus 75 percent of the useful thermal 

output measured relative to ISO conditions that is not used to 

generate additional electrical or mechanical output or to 

enhance the performance of the unit (i.e., steam delivered to an 

industrial process). 

(ii) Gross output of a steam generating unit with respect 

to CO2 emissions is determined as specified in paragraphs 

(a)(3)(ii)(A) and (B) of this section. 

(A) The gross electrical and mechanical output from the 

steam generating unit 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 electrical or mechanical output or to enhance the 

performance of the unit (e.g., steam delivered to an industrial 

process); or 

(B) For a CHP EGU where at least 20.0 percent of the total 

gross useful energy output consists of electric or direct 

mechanical output and at least 20.0 percent of the total gross 

useful energy output consists of useful thermal output on an 

three calendar year rolling average basis, the difference of 
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gross electrical and mechanical output from the affected steam 

generating unit minus any electricity used to power the 

feedwater pumps divided by 0.95 plus 75 percent of the useful 

thermal output measured relative to ISO conditions that is not 

used to generate additional electrical or mechanical output or 

to enhance the performance of the unit (i.e., steam delivered to 

an industrial process). 

(4) Calculate the total gross output for the affected EGU’s 

compliance period by summing the hourly gross output values for 

the affected EGU determined from paragraph (a)(2) of this 

section for all of the operating hours in the applicable 

compliance period. 

(5) Calculate the CO2 mass emissions output-based rate for 

the affected EGU by dividing the total CO2 mass emissions value 

from paragraph (a)(2) of this section by the total gross output 

value from paragraph (a)(4) of this section. 

(b) If the CO2 mass emissions output-based rate for the 

affected EGU 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 

EGU, then the affected EGU is determined to be in compliance 

with the emissions standard. If the average CO2 mass emissions 

rate is greater than the CO2 emissions standard in Table 2 of 
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this subpart applicable to the EGU, then the affected EGU is 

determined to havehas excess CO2 emissions. 

8. 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? 

* * * * * 

9. 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 EGU. 

(2) You must prepare and submit notifications specified in 

§§ 75.61 of this chapterpart, as applicable to your affected 

EGU. 

(b) You must prepare and submit reports according to 

paragraphs (b) through (d) of this section, as applicable. 

(1) For EGUs that are required, pursuant to §§§ 60.4333 

(gc), to conduct initial and on-going compliance determinations 

on a 12-operating month rolling average basis with respect to 

the standard in §§ 60.43254326 you must submit electronic 
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quarterly reports as follows. After the first 12-operating 

months have been accumulated for the EGU, a report for the 

calendar quarter that includes the twelfth 12th-operating month 

shall be submitted no later than 30 days after the end of that 

quarter. Thereafter, a report for each subsequent calendar 

quarter shall be submitted, no later than 30 days after the end 

of the quarter. 

(2) Each quarterly report shall include the following 

information, as applicable: 

(i) Each rolling average CO2 mass emissions rate for which 

the last (twelfth12th) operating month in a 12-operating month 

compliance period falls within the calendar quarter. Calculate 

each average CO2 mass emissions rate according to §§§ 60.4374. 

Report the dates (month and year) of the first 1st and 

twelfth12th- operating months in each compliance period for 

which a CO2 mass emissions rate calculation is performed. If 

there are no compliance periods that end in the quarter, include 

a statement to that effect; 

(ii) Identification of each operating month in the calendar 

quarter with excess CO2 emissions. If one or more compliance 

periods end in the quarter; 

(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)(1)(i) of this section (i.e., 
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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) Indication of which compliance option is being 

followed under §§ 60.43254326. 

(3) The final quarterly report of each calendar year must 

contain 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. 

(c) All electronic reports required under paragraph (b) of 

this section shall be submitted 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 

chapterpart. 

10. Section 60.4390 is amended by revising the section 

heading to read as follows: 

§§ 60.4390 What records must I maintain to comply with my NOx and 

SO2 emissions limits? 

* * * * * 
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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 your information 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 chapterpart. 

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

determine the total CO2 mass emissions for: 

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

(2) Each compliance period, including, as applicable, each 

12-operating month compliance period. 

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

and calculations performed used to determine your affected EGU’s 

gross output for each operating month. 

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

determine the percentage of valid CO2 mass emission rates in each 

compliance period. 

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

assess compliance with each applicable CO2 mass emissions 

standard in §§ 60.43254326. 
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(g) You must keep records of the calculations performed to 

determine any site-specific carbon-based F-factors 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 following 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 amended to read as follows: 

§§ 60.4395 When must I submit my reports? 

Consistent with §§ 60.7(c), all reports required under §§ 

60.7(c) must be postmarked by the 30th day following the end of 

each 6-month period, 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? 

Base load rating means 100 percent of the manufacturer's design 
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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). 

Electric generating unit or EGU means any steam electric 

generating unit or stationary combustion turbine that generates 

electricity. 

Excess emissions means a specified averaging period over which 

either: 

(1) tThe NOX, CO2 or SO2 emissions rate are higher than the 

applicable emissions standard in §§ 60.4320, §§ 60.43254326 or 

§§ 60.4330; or

(2) tThe total sulfur content of the fuel being combusted in the 

affected facility or the SO2 emissions exceeds the standard 

specified in §§ 60.4330; or 

(3) tThe recorded value of a particular monitored parameter, 

including ration of water or steam to fuel, is outside the 

acceptable range specified in the parameter monitoring plan for 

the affected unit. 

Gross useful energy output means: 

(1) For simple cycle and combined cycle combustion turbines, the 

gross useful work performed is the gross electrical or direct 

mechanical output from both the combustion turbine engine and 

any associated steam turbine(s). 
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(2) For a CHP combustion turbine, the gross useful work 

performed is the gross electrical or direct mechanical output 

from both the combustion turbine engine and any associated steam 

turbine(s)(divide by 0.95) plus any useful thermal output 

measured relative to ISO conditions (except for GHG calculations 

in §§ 60.4374 as only 75 percent credit is given) that is not 

used to generate additional electrical or mechanical output or 

to enhance the performance of the unit (i.e., steam delivered to 

an industrial process). 

Heat recovery steam generating unit (HRSG) means a unit where 

the hot exhaust gases from the combustion turbine engine are 

routed in order to extract heat from the gases and generate 

useful output. Heat recovery steam generating units can be used 

with or without duct burners. 

Integrated gasification combined cycle electric utility steam 

generating unit (IGCC) means an electric utility steam 

generating unit that burns solid-derived fuels in a combinedcycle combustion turbine plus any integrated equipment that 

provides electricity or useful thermal output to either the 

turbine engine and HRSG or to power auxiliary equipment. No 

solid fuel is directly combusted in the unit during operation. 

Net-electric output means: 
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(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 useful energy output consists of 

electric or direct mechanical output and at least 20.0 percent 

of the total gross useful energy output consists of useful 

thermal output on a 3 calendar year rolling average basis, netelectric output means 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. 

Operating month means a calendar month during which any fuel is 

combusted in the EGU at any time. 

Potential electric output means 33 percent or the design 

electric output efficiency on a net output basis times 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 EGU with a 100 MW (341 

MMBtu/h) fossil-fuel heat input capacity would have a 

306,420310,000 MWh 12- month potential electrical output 

capacity). 

Stationary combustion turbine means all equipment, including but 

Comment [CRB2]: ? 
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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 

either the boiler or to power 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. 

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 either the 

boiler or to power auxiliary equipment. 

System emergency means any abnormal system condition that 

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. 

* * * * *

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

follows: 

Table 2 to Subpart KKKK of Part 60 – EGU CO2 Emission Standards Formatted: Font: Bold
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Affected EGU CO2 Emission Standard 

Stationary combustion turbine 

that has a design heat input to 

the turbine engine of greater 

than 250 MW (850MMBtu/h), that 

burns 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 

supplies one-third or more of 

its potential electric output 

and more than 219,000 MWh netelectrical output to a utility 

distribution system on a 3 year 

rolling average basis. 

450 kilograms (kg) of CO2 per 

megawatt-hour (MWh) of gross 

output (1,000 lb/MWh) on a 12-

operating month rolling average 

Stationary combustion turbine 

that has a design heat input to 

the turbine engine greater than 

73 MW (250 MMBtu/h) and equal 

to or less than 250 MW 

(850MMBtu/h), that burns 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 that 

supplies one-third or more of 

its potential electric output 

and more than 219,000 MWh netelectrical output to a utility 

distribution system on a 3 year 

rolling average basis. 

500 kg of CO2 per MWh of gross 

output (1,100 lb CO2/MWh) on a 

12-operating month rolling 

average 

15. Table 3 to Subpart KKKK of Part 60 is added to reads

as follows: 
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Table 3 to Subpart KKKK of Part 60 – Applicability of Subpart A 

General Provisions to EGU 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 

Additional terms 

defined in §§ 

60.4420 

§§ 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 
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§§ 60.17 Incorporations by 

reference Yes 

§§ 60.18 

General control 

device 

requirements 

No 

§§ 60.19 

General 

notification and 

reporting 

requirements 

Yes 

PART 70—[AMENDED] STATE OPERATING PERMIT PROGRAMS

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

follows: 

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

 17. Section 70.2 is amended 

a. By adding a new definition of “Greenhouse gases,” 

 b. By adding new paragraph (4) to the definition of 

“Regulated pollutants (for presumptive fee calculation),” and

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

to regulation.”

The revision and additions read as follows:by adding new 

paragraph (4) to the definition of “Regulated pollutants (for 

presumptive fee calculation)” to 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 

Formatted: Indent: First line: 0.5"

Formatted: Indent: First line: 0.5"
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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: 

* * * * *

(1) Carbon monoxide;

(2) Any pollutant that is a regulated air pollutant solely 

because it is a Class I or II substance to a standard 

promulgated under or established by title VI of the Act; or

(3) Any pollutant that is a regulated air pollutant solely 

because it is subject to a standard or regulation under section 

112(r) of the Act;

(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.

* * * * *

Formatted: FR Paragraph, Line spacing: 

single

Formatted: Font:

Formatted: No underline

Formatted: Indent: First line: 0.5"

Formatted: Font: Italic, Underline
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 18. Section 70.9 is amended by revising paragraph 

(b)(2)(i), and by adding a new 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 

the 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 

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average cost of staff time, including wages, employee benefits 

and overhead. 

Activity Burden 

hours 

per 

activity 

GHG completeness determination (for initial 

permit or updated applicationPreparing a 

permit application (add GHG to a non-GHG 

permit) 

Modification due to GHG 

Modification to address GHG in a non-GHG 

permit 

Address GHG at permit renewal 

43

40

97

104

* * * * * 

PART 71—[AMENDED] FEDERAL OPERATING PERMIT PROGRAMS

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

follows: 

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

20. Section 71.2 is amended:

a. By adding a new definition of “Greenhouse gases,”

b. By adding a new 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:

is proposed to be amended by adding new paragraph (4) to 

the definition of “Regulated pollutant (for fee calculation)” to 

read as follows:

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§ 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: 

(1) Carbon monoxide;

(2) Any pollutant that is a regulated air pollutant solely 

because it is a Class I or II substance to a standard 

promulgated under or established by title VI of the Act; or

(3) Any pollutant that is a regulated air pollutant solely 

because it is subject to a standard or regulation under section 

112(r) of the Act;

* * * * *

(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 

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stationary source emitting or having the potential to emit 

100,000 tpy CO2 equivalent emissions.

* * * * * 

 21. Section 71.9 is amended by:

a. By revising paragraph (c)(1) and adding new 

paragraphs (c)(1)(i) and (c)(1)(ii),

 b. By revising paragraph (c)(2)(i) and adding new 

paragraphs (c)(2)(i)(A) and (c)(2)(i)(B), 

 c. By revising paragraphs (c)(3) and (c)(4), and

 d. By adding a new paragraph (c)(8).

a. By revising paragraph ©(1), 

b. By revising paragraph ©(2)

c. By adding a new paragraph ©(8).

 The revisions and additions read as follows: 

§ 71.9 Fee determination and certification. 

* * * * * 

(c) * * *Establishment of fee schedule. 

(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 
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(ii) Aany GHG fee adjustment required under paragraph 

(c)©(8) of this section. 

(2) For part 71 programs that are fully delegated pursuant 

to § 71.10: 

(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) Aany GHG fee 49adjusttment required under paragraph 

(c)(8) of this section. 

(ii) Where the delegate State collects fees from part 71 sources 

under State law which are sufficient to fund the delegated part 

71 program, the EPA may suspend its collection of part 71 fees. 

The specific terms and conditions regarding the suspension of 

fee collection will be addressed in the applicable delegation 

agreement pursuant to § 71.10.

* * * * *

(4) For programs that are delegated in part, the fee shall 

be computed using the following formula:

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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

Preparing a permit application (add GHG to a 

non-GHG permit) 

GHG evaluation for a permit Mmodification or

related permit actiondue to GHG 

Modification to address GHG in a non-GHG 

$2,236

$2,080

$364468

$208520

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permit 

GHG evaluation at Address GHG at permit 

renewal 

* * * * * 

PART 98—[AMENDED] MANDATORY GREENHOUSE GAS REPORTING

22. The authority citation for part 98 continues is revised

to read as follows: 

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

Subpart PP—[AMENDED] 

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

read as follows: 

§§ 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 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 

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

is transferred to each subpart RR facility. 

24. 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 subpart RR 

facility.