Page **1** of **46**

**MEMORANDUM**

From: Office of Air Quality Planning and Standards U.S. Environmental Protection Agency To: EGU NSPS Docket ( EPA

- HQ

- OAR

- 2013

- 0 603 ) Date: June, 2014 Subject: Amended Regulatory Text ( Proposed Applicability)

Amended Regulatory

Text

On January

8 , 2014 , the EPA proposed amendments (79 FR 1430) to the regulatory t ext of subparts Da and KKKK to include greenhouse gas (GHG) standards for new electric generating units (EGUs). As an alternative to amending proposed subparts Da and KKKK, the E PA co
proposed creating a new subpart TTTT to include the proposed GHG standards. We intend to finalize the proposed amendments for modified and reconstructed EGUs following the approach finalized in the new source proposal published on January 8 , 201 4

. Fo r example, if the new source requirements are included in subparts Da and KKKK, the proposed requirements in this proposal would be added to those amendments

.
T o facilitate understanding the amendments being proposed in this proposal and allow interested persons to see how the proposed amendments for modified and reconstructed sources relate to the amendments from Ja nuary 8 , 2014 for newly constructed sources , the following document
uses track changes to demonstrate the GHG standards for the proposed stan dards for modified and reconstructed EGUs on top of the regulatory text proposed on January 8, 2014

.Page **2** of **46**

**Subpart Da**

**- —**  **Standards of Performance for Electric Utility Steam Generating Units** 2. Section 60.46Da is added to read as follows: **§60.46Da Standards for carbon dioxide (CO**  **2 )** 

**.** (a) Your affected facility

is subject to this section if it meets the conditions specified in paragraphs (a)(1) or (a)(2) of this section, except as specified in paragraph (b) of this section. (1) C onstruction commenced after January 8, 2014 and meets the conditions specified in paragraphs (a)(1)(i), (a)(1)(ii), and (a)(1)(iii) of this section. (i ) The affected facility

was constructed for the purpose of suppl yi ng more than one

- third of its potential electric output capacity and more than 219,000 MWh as net electric sales on an annual basis; ( ii ) The affected facility

combusts fossil fuel for more than 10.0 percent of the heat input during an y 3 consecutive calendar years ; and ( iii ) The affected facility supplies more than one

- third of its potential electric output and more than 219,000 MWh net

- electric output to a utility power distribution sy st em for sale on an annual basis. (2) M odification or reconstruction commenced after [ INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] , and the affected facility was constructed for the purpose of suppl yi ng more than one

- third of its potential electric output and more than 219,000 MWh as net

- electric sales on an annual basis , (b) The following EGUs are not subject to this section: (1) The proposed Wolverine EGU project described in Permit to Install No. 3 17

- 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 th e Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, effective April 8, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014

. (3) The proposed Holcomb EGU project describ ed in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment, effective December 16, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014

. (c) As owner or operator of an affected facility subject to this section, you shall not cause to be discharged into the atmosphere from the affected facility an y gases that contain CO 2 in excess of the emissions limit specified in this paragraph

. (1) A s owner or operator of an affected facility for which construction commenced after January 8, 2014 , you shall not cause to be discharged into the atmosphere from the affected facility any gases that contain CO 2 in excess of the emissions limit specified in paragraph (c)(1) (i) or (c)(1) (ii) of this section

. (i ) 500 kilograms (kg) of CO 2 per megawatt

- hour (MWh) of gross energy output (1,100 lb CO 2 /MWh) on a 12

- operating month rolling average basis; orPage **3** of **46**

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

- operating month rolling average basis

. (2) As owner or operator of an affected facility for which re construction commenced after [ INSERT DATE OF PUBLICATION IN THE FEDERAL REGI STER ] , you shall not cause to be discharged into the atmosphere from the affected facility an y gases that contain CO 2 in excess of the emissions limit specified in paragraph (c)(2) (i) or (c)(2)(ii) of this section

. (i) If the design rated capacity of your affected facility

is 590 MW (2,000 MMBtu/h ) or less, 9 5 0 kg CO 2 /MWh of net energy output (2, 1 00 lb CO 2 /MWh) on a 12

- operating month rolling average basis; or (ii) If the design rated capacity of your affected facility

is greater than 590 MW (2,000 MMBtu/h), then 820 kg CO 2 /MWh of net energy output (1, 9 00 lb CO 2 /MWh) on a 12

- operat ing month rolling average basis. (3) As owner or operator of an affected facility for which modification commenced after [ IN SERT DATE OF PUBLICATION IN THE FEDERALREGI STER] , you shall not cause to be discharged into the atmosphere from the affected facility an y gases that contain CO 2 in excess of the emissions limit specified in paragraph (c)( 3 )(i) or (c)( 3 )(ii) of this section. (i) If the facility

is not subject to an approved CAA section 111(d) plan (state or federal) at the time of the modification , a CO 2 emissions limit specified in paragraph (c)( 3 )(i) (A) , (c)( 3 )(i) (B) , or (c)(3)(i) (C ) of this section. (A) a site

- specific 12

- operating month rolling average CO 2 emission limit calculated as 2 percent lower than (i.e., 98 percent) the best demonstrated annual historical operating performance for the affected facility using historical CO 2 emissions data for the calendar ye ars 2002 through the most recent full c alendar ye ar the affected facility was operating prior to the modification using either recorded net output emission rate data or gross electrical output and CO 2 emissions data as reported under part 75 of this chapter

. If incomplete or no data has been
submitted under part 75 of this chapter, the Administrator or delegated authority shall approve the use of alternate data sources. T he equivalent net output

- based standard shall be calculated from gross output

- based data assuming a 7.5 percent auxiliary (i.e., parasitic) load (i.e., the best annual value is divided by 0.925); (B ) If the design rated capacity of your affected facility

is 590 MW (2,000 MMBtu/h ) or less, 9 5 0 kg CO 2 /MWh of net energy output (2, 1 00 lb CO 2 /MWh) on a 12

- operating month rolling average basis; or ( C ) If the design rated capacity of your affected facility

is greater than 590 MW (2,000 MMBtu/h), 820 kg CO 2 / MWh of net energy output (1, 9 00 lb CO 2 /MWh) on a 12

- operating month rolling average basis. (ii) If the facility

is subject to an approved CAA section 111(d) plan (state or federal) at the time of the modification , a site

- specific 12

- operating month rolling average CO 2 emission limit determined by

the CAA section 111(d) implementing authority based on the affected facility performin g an energy

assessment by

an energy

professional or engineer that have expertise in evaluating energy s ys tems to identify applicable energy efficiency

projects that you will implement at the affected facility to improve the affected facility ’s operating pe rformance. You must maintain a copy of the most recent energy assessment report. The energy assessmentPage **4** of **46**

must include at a minimum the elements in paragraph s ( c)(3)(ii)(A) through (c)(3)(ii) ( C) of this section

. (A) A visual inspection of the facility to identify

steam leaks or other s ources of red uced efficiency , ( B ) A review of available engineering plans and facility operation and maintenance procedure s and logs , and ( C ) A comprehensive report detailing the way s to improve efficiency , the cost of specific improvements, benefits, and the time frame for recouping those investments

. (d) You must make compliance determinations at the end of each operating month, as provided in paragraphs (d)(1) and (d)(2) of this sectio n. For the purpose of this section, operating month means a calendar month during which an y fossil fuel is combusted in the affected facility

. (1) If you are subject to a 12

- operating month CO 2 emissions limit , you must determine compliance monthly

by calculating the average CO 2 emissions rate for the affected facility at the end of each 12

- operating month period that includes, as the last month, the month for which you are determining compl iance. (2) If you are subject to an 84

- operating month CO 2 emissions limit , you must determine compliance monthly

by calculating the average CO 2 emissions rate for the affected facility at the end of each 84

- operating month period that includes, as the last month, the month for which you are determining compliance. (e) You must conduct an initial compliance determination with the CO 2 emissions limit for your affected facility within 30 day s after accumulating the required number of operating months for the compliance period with which you have elected to compl y (i.e., 12

- operating months or 84

- operating months)

. The first operating month included in this compliance period is the month in which emissions reporting is required to begin under § 75.64(a) of this chapter. (f) You must monitor and collect data to demonstrate compliance with the CO 2 emissions limit according to the requirements in paragraphs (f)(1) through (4) of t his section. (1) You must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter. (2) You must measure the hourly CO 2 mass emissions from each affected facility using the procedures in paragraphs (f)( 2)(i) through (vii) of this section, except as provided in paragraph (f)(3) of this section. (i) You must install, certify , operate, maintain, and calibrate a CO 2 continuous emission monitoring sy stem (CEMS) to directly measure and record CO 2 concentrations in your affected facility ’s exhaust gases that are emitted to the atmosphere and an exhaust gas flow rate monitoring sy stem according to §75.10(a)(3)(i) of this chapter. If you measure CO 2 concentration on a dry

basis, you must also install , certify , operate, maintain, and calibrate a continuous moisture monitoring s ys tem, according to §75.11(b) of this chapter. (ii) For each monitoring sy stem used to determine the CO 2 mass emissions, you must meet the applicable certification and quality a ssurance procedures in §75.20 of this chapter and Appendices B and D to part 75 of this chapter. (iii) You must use a laser device to measure the dimensions of each exhaust gas stack or duct at the flow monitor and the reference method sampling locations p rior to the initial setupPage **5** of **46**

(characterization) of the flow monitor. For circular stacks, you must make measurements of the diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, you must make measurements of ea ch dimension (i.e., depth and width) at three or more distinct locations and average the results. If the flow rate monitor or reference method sampling site is relocated, you must repeat these measurements at the new location. (iv) You can onl y use unadjus ted exhaust gas volumetric flow rates to determine the hourly CO 2 mass emissions from the affected facility ; you must not appl y the bias adjustment factors described in s ection 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate dat a. (v) If you choose to use Method 2 in Appendix A

- 1 to this part to perform the required relative accuracy

test audits (RATAs) of the part 75 flow rate monitoring s ystem, you must use a calibrated T yp e
- S pitot tube or pitot tube assembly . You must not use the default Ty pe
- S pitot tube coefficient. (vi) If two or more affected facilities share a common exhaust gas stack and are subject to the same CO 2 emissions limit in paragraph (c) of this section, you may monitor the hourly

CO 2 mass emissions at the common exhaust gas stack rather than monitoring each affected facility separately

. (vii) If the exhaust gases from the affected facilities are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you choose to monitor in the ducts), you must monitor the hourly CO 2 mass emissions and the “stack operating time” (as defined in § 72.2 of this chapter) at each stack or duct separately

. (3) As an alternative to complying with par agraph (f)(2) of this section, for affected facilities that do not combust any solid fuel, you may

determine the hourly

CO 2 mass emissions by using Equation G

- 4 in Appendix G to part 75 of this chapter according to the requirements specified in paragraphs (f)(3)(i) and (f)(3)(ii) of this section. (i) You must implement the applicable procedures in Appendix D to part 75 of this chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinat ions of the gross calorific value (GCV) of each fuel combusted. (ii) You may

determine site

- specific carbon

- based F

- factors (F c ) using Equation F

- 7b in section 3.3.6 of Appendix F to part 75 of this chapter, and you may use these F c values in the emissions calculations instead of using the default F c values in the Equation G

- 4 nomenclature. (4) You must install, calibrate, maintain, and operate a sufficient number of watt m eters to continuously

measure and record the gross or net electric output from the af fected facilit y

. These m easurements must be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12. 20

. Y ou must also meet the requirements specified in paragraphs (f)( 4)(i) and (ii) of this section, as applicable. (i) If your affected facility is a combined heat and power unit as defined in § 60.42Da, yo u must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful thermal output . For process steam applications , you must install, calibrate, maintain, and operate meters to continuously determine and record steam flow rate, temperature,Page **6** of **46**

and pressure. If your affected facility has a direct mechanical dri ve application, you must submit a plan to the Administrator or delegated authority for approval of how gross or net energy output will be determined. Your plan shall ensure that yo u install, calibrate, maintain, and operate meters to continuously

determine and record each component of the determination. (ii) If two or more affected facilities have steam generating units that serve a common electric generator, you must apportion the combined hourly gross o r net electric output to each individual affected fac ility using a plan approved by the Administrator (e.g., using steam load or heat input to each affected facility). Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the d etermination. (g) You must demonstrate compliance with the CO 2 emissions limit using the procedures specified in paragraphs (g)(1) and (2) of this section. (1) You must calculate the CO 2 mass emissions rate for your affected facility using the
ca lculation procedures in paragraphs (g)(1)(i) through (v) of this section with the hourly CO 2 mass emissions and gross or net energy output data determined and recorded according to the procedures in paragraph (f) of this section for each operating hour in the applicable compliance period (i.e., 12

- operating months or 84

- operating months). (i) You must only

use operating hours in the compliance period for which you have valid data for all the parameters you use to determine the hourly CO 2 mass emissions and gross or net output data. You must not use operating hours which use the substitute data provisions of part 75 of this chapter for an y of the parameters in the calculation. For the compliance determination calculation, you must obtain valid hourly values f or a minimum of 95 percent of the operating hours in the applicable compliance period. (ii) You must calculate the total CO 2 mass emissions by summing all of the valid hourly CO 2 mass emissions values for the applicable compliance period. If exhaust gases from the affected facility

are emitted to the atmosphere through multiple stacks or ducts, you must calculate the total CO 2 mass emissions for the affected facility by summing the total CO 2 mass emissions from each of the individual stacks or ducts. (iii) For each operating hour of the compliance period used in paragraph (g)(1)(ii) of this section to calculate the total CO 2 mass emissions, you must determine the affected facility ’s corresponding hourl y gross or net energy output using the appropriate definitions in § 60.42Da and paragraph (k) of this section and using the procedure specified in paragraphs (g)(3)(iii)(A) through (D) of this section. (A) Calculate P gross /net for your affected facility using the following equation:

/ = ( ) + ( ) + ( )

− ( ) T + 0

. 75 × [ ( ) + ( ) + ( ) ]

Where: P gross /net = Gross or net energy output of your affected facility in megawatt

- hours ( MWh )

. (Pe) ST = Electric energy output plus mechanical energy output (if any) of steam turbines in MWh.Page **7** of **46**

(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 energ y output (if an y) of your affected facility ’s integrated equipment that provides electricity or mechanical energy

to the affected facility

or auxiliary

equipment in MWh. (Pe) FW = Electric energy used to power boiler feedwater pumps at steam generating unit s in MWh. This term is not applicable to IGCC facilities or facilities complying with a net output based standard

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

applicable) that is used for applications that do not generate additional electricit y, produce mechanical energy output, or enhance the performance of the affected facility . This term is calculated using the equation specified in paragraph (g)(3)(iii)(B) of this sect ion in MWh. (Pt) HR = Non steam u seful thermal output ( measured relative to SATP conditions ,

as applicable) that is used for applications other than steam generation or performance enhancement of the affected facility in M Wh. (Pt) IE = Useful thermal output (relative to SATP conditions , as applicable) from

any integrated equipment that is used for applications that do not generate additional steam, electricity , produce mechanical energy output, or enhance the performance of the affected facility in MWh. T = Electric Transmission and Distribution Factor.

T = 0.95 for a combined heat and power affected facility where at least on an annual basis 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and 20.0 percent of the total gross or net energy

output consists of useful thermal output on a rolling 3 ye ar basis. T = 1.0 for all other affected facilities.

(B) I f applicable to your affected facility , calculate (Pt) PS using the following equation: ( ) = ×

3

. 6 × 10 Where: Q m = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating

hour. H = Enthalpy

of the steam at ( measured temperature and pressure relative to SATP conditions , as applicable) in Joules per kilogram (J/kg) (or Btu/lb). 3.6 x 10 9 = Conversion factor (J/MWh) (or 3.413 x 10 6 Btu/MWh).Page **8** of **46**

(C) For an operating hour in which there is no gross or net electric load, but there is mechanical or useful thermal output, you must still determine the gross or net energy output for that hour. In addition, for an operating hour in which there is no useful output, you must still determine the hourl y CO 2 emissions for that hour. For hours or partial hours where there the gross generation equal to or less than the auxiliary loads , net electric output shall be counted as
zero for this calculation

. (D) If hourl y CO 2 mass emissions are determined for a common stack, you must determine the hourl y gross or net energy output (electric, thermal, and/or mechanical, as applicable) b y summing the hourly loads for the individual affected facility and you must express the oper ating time as “stack operating hours” (as defined in § 72.2 of this chapter). (iv) You must calculate the total gross or net energy output by

summing the hourly

gross or net energy

output values for the affected facility determined from paragraph (g)(1)(ii i) of this section for all of the operating hours in the applicable compliance period. (v) You must calculate the CO 2 mass emissions rate for the applicable compliance period interval by

dividing the total CO 2 mass emissions value from paragraph (g)(1)(ii ) of this section by the total gross or net energy output value from paragraph (g)(1)(iv) of this section. (2) You must determine compliance with the CO 2 emissions limit in paragraph (c) of this section is determined as specified in paragraphs (g )(2)(i) and (ii) of this section using the CO 2 mass emissions rate for your affected facility that you determined in paragraph (g)(1) of this section. (i) If the CO 2 mass emissions rate for your affected facility is less than or equal to the CO 2 emissions limit applicable to your affected facility, then your affected facility is in compliance with the CO 2 emissions limit . I f you attain compliance with the CO 2 emissions limit at a common stack for two or more affected facilities subject to the same CO 2 emissions limit , each affected facility

sharing the stack is in compliance with the CO 2 emissions limit

. (ii) If the CO 2 mass emissions rate for the affected facility is greater than the CO 2 emissions limit in paragraph (c) of this section applicable to the affected facility , then the affected facility

has excess CO 2 emissions. (h) You must prepare and submit notifications and reports according to paragraphs (h)(1) through (4) of this section. (1) You must prepare and submit the notifications in § § 60.7(a)(1) and (a)(3) and 60.19, as applicable to your affected facility

. (2) You must prepare and submit notifications in § 75.61 of this chapter, as applicable to yo ur affected facility

. (3) You mu st submit electronic quarterl y reports according to the requirements specified in paragraphs (h)(3)(i) through (iii) of this section. (i) Initially , after you have accumulated the required number of operating months for the CO 2 emission limit compliance period that you have chosen to compl y with (i.e., 12

- operating months or 84

- operating months), you must submit a report for the calendar quarter that includes the final (12th

- or 84th) operating month no later than 30 day s after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter no later than 30 days after the end of the quarter.Page **9** of **46**

(ii) In each quarterl y report you must include the information in paragraphs (h)(3)(ii)(A) through (E) of this section. (A) The CO 2 emission limit compliance period with which you have chosen to comply

. (B) An y months in the calendar quarter that you are not counting as operating months. (C) For each operating month in the calendar quarter, the corresponding average C O 2 mass emissions rate for the applicable compliance period interval that you determined according to paragraph (g) of this section. (D) The percentage of valid CO 2 mass emission rates in each compliance period (i.e., the total number of valid CO 2 mass em ission rates in that period divided b y the total number of operating hours in that period, multiplied by 100 percent). (E) An y operating months in the calendar quarter with excess CO 2 emissions. (iii) In the final quarterl y report of each calendar year you must include the following: (A) Net electric output sold to an electric grid over the calendar ye ar; and (B) The potential electric output of the facility

. (iv) You must submit each electronic report using the Emissions Collection and Monitoring Plan Sy st em (ECMPS) Client Tool provided by the Clean Air Markets Division in the EPA Office of Atmospheric Programs. (4) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter. (5) If your aff

ected unit uses geologic sequestration to meet the applicable emissions limit, you must report in accordance with the requirements of 40 CFR p art 98 , s ubpart PP and either: (i) if injection occurs onsite, report in accordance with the requirements of 40 CF R p art 98 , subpart RR, or (ii) if injection occurs offsite, transfer the captured CO 2 to a facility or facilities that reports in accordance with the requirements of 40 CFR p art 98 , subpart RR. (i) For each affected electric utility stream generating unit, you must maintain records according to paragraphs (i)(1) through (i)(8) of this section. (1) You must comply

with the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter. (2) You must maintain records of the calculations you performed to determine the total CO 2 mass emissions for each operating month, and the averages for each compliance period interval (i.e., 12

- operating months or 84

- operating months, as applicable to the CO 2 emissions limits ). (3) You must maintain records of the applicable data recorded and calculations performed that you used to determine the gross or net energy output for each operating month. (4) You must maintain records of the calculations you performed to de termine the percentage of valid CO 2 mass emission rates in each compliance period.Page **10** of **46**

(5) You must maintain records of the calculations you performed to assess compliance with each applicable CO 2 emissions limit in paragraph (c) of this section. ( 6) Your records must be in a form suitable and readily available for expeditious review. (7) You must maintain each record for 5 ye ars after the date of each occurrence, measurement, maintenance, corrective action, report, or record except those records re quired to demonstrate compliance with an 84

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

- operating month compliance period for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. (8) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may maintain th e records off site and electronically for the remaining year(s) as required by this subpart. (j) PSD and Title V Thresholds for Greenhouse Gases

. (1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from new affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in an y S IP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48). (2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from new affected facilities, the “pollutant that is subject to the standard promulgated under secti on 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49). (3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from new affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 70.2. (4) For purposes of 40 CFR 71.2, with respect to greenhouse ga s emissions from new affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 71.2. (k) For purposes of this section, the following definitions apply : Gross energy

output means: ( i ) Except as provided under paragraph ( ii ) of this definition, for electric utility steam generating units, the gross electric or mechanical output from the affected facility (i ncluding, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) minus any electricity

used to power the feedwater pumps plus 75 percent of the useful thermal output ; ( ii ) For electric utility

steam generating unit combined heat and power facilitie s where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on a rolling 3 year basis, the gross electric or me chanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders)Page **11** of **46**

minus any

electricit y used to power the feedwater pumps, that difference divided by 0.95, plus 75 percent of the useful thermal output ; ( iii ) Except as provided under paragraph ( i v ) of this definition, for a IGCC electric utility generating unit, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine( s), and gas expanders) plus 75 percent of the useful thermal output ; or ( iv ) For IGCC electric utility generating unit combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on a rolling 3 year basis, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) divided by

0.95, plus 75 percent of the useful thermal output

. IGCC facility

is an integrated gasification combined cycle electric utility steam generating unit , which means an electric utility combined cycle facility

that is designed to burn fuels containing 50 percent (by heat input) or more solid

- derived fuel not meeting the definition of natural gas plus an y integrated equipment that provides electricity or useful thermal output to either the affected facility or auxiliary equipment. The Administrator may waive the 50 per cent solid

- derived fuel requirement during periods of the gasification s ys tem construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the facility

during operation. Net

- electric sales means : ( i ) Except as provided under paragraph ( ii ) of this definition, the gross electric sales to the utility power distribution sy stem minus purchased power , or ( ii ) For combined heat and power facilities where at least 20.0 percent of the total gross or net energy

output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output, the gross electric sales to the utility power distribution sy stem minus purchas ed power of the thermal host facility or facilities ; and (iii ) Electricity

supplied to other facilities that produce electricity to offset auxiliary loads
are included when calculating net

- electric sales

. Net

- electric output means: the amount of gross generation the generator (s) produces (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) , as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary

loads); such uses include fuel handling equipment , pumps, fans, pollution control equipment , other electricity needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale). Net energy

output means: (i) Except as provided under paragraph (ii) of this definition, the net electric or mechanical out

put from the affected facility plus 75 percent of the useful thermal output; or (ii) For combined heat and power facilities where at least 20.0 percent of the total gross or net energy

output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a rolling 3 year basis, thePage **12** of **46**

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

. Potential electric output means: (i ) Either 33 percent or the design net electric output efficiency , at the election of the owner/operator of the affected facility , (ii) Multiplied by

the maximum design heat input capacity of the steam generating unit, (Btu/h) (iii) Divided by

3,413 Btu/KWh, (iv) Divided b y 1,000 kWh/MWh, and (v) Multiplied by

8,760 h/y

r. (vi) For example, a 35 percent efficient steam generating unit with a 100 MW (341 MMBtu/h) fossil

- fuel heat input capacit y would have a 310,000 MWh 12 month potential electric output c apacit y. Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F) ) and 10 0.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of wat er at SATP conditions is 5 0 Btu/ lb

. Steam generating unit means an y furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (nuclear steam generators are not included) plus an y integrated equipment that provides electricity or useful thermal output to either the boiler or aux iliary equipment. Useful thermal output means the thermal energy made available for use in any heating application (e.g., steam delivered to an industrial process for a heating application , including thermal cooling applications) that is not used for electric generation, mechanical output at the affected facility , or to directly enhance the performance of the affected facility (e.g., economizer output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered useful the rmal output)

. Useful thermal output for affected facilities with no condensate return (or other thermal energy

input to the affected facility) or where measuring the energy in the condensate (or other thermal energy input to the affected facility) would not meaningfull y impact the emission rate calculation is measured against the energy in the thermal output at SATP conditions. Affected facilities with meaningful energy in the condensate return (or other thermal energy input to the affected facilit y) must measure the energy in the condensate and subtract that energy relative to SATP conditions f r om the measured thermal output.Page **13** of **46**

**Subpart KKKK**

**- —**  **Standards of Performance for Stationary Combustion Turbines** 3. Section 60.4305 is amended b y adding paragr aph (c) to read as follows: **§ 60.4305 Does this subpart apply to my stationary combustion turbine?**

* * * * * (c) For purposes of regulation of greenhouse gases, the applicable provisions of this subpart affect your stationary combustion turbine if it meets the applicability conditions in paragraphs (c)(1) through (c)(5) of this section. (1) C ommenced construction after January 8, 2014 or it commenced reconstruction or modification after [ INSERT DATE OF PUBLICATION IN THE FEDERALREGI STER] ; (2) Has a de sign heat input to the turbine engine greater than 73 MW (250 MMBtu/h); (3) Combusts fossil fuel for more than 10.0 percent of the heat input during any 3 consecutive calendar years. (4) Combusts over 90% natural gas on a heat input basis on a 3 y ear roll ing average basis; and (5) Was constructed for the purpose of suppl yi ng, and supplies, one

- third or more of its potential electric output and more than 219,000 MWh net

- electrical output to a utility distribution sy stem on a 3 year rolling average basis. 4. Section 60.4315 is revised to read as follows: **§ 60.4315 What pollutants are regulated by this subpart?** (a) The pollutants regulated by this subpart are nitrogen oxides (NO X ), sulfur dioxide (SO 2 ), and greenhouse gases. (b)(1) The greenhouse gases regu lated b y this subpart consist of carbon dioxide (CO 2 ). (2) PSD and Title V Thresholds for Greenhouse Gases

. (i) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from affected stationary combustion turbine, the “pollutant that is subj ect 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 S IP approved b y the EPA that is interpreted to incorpo rate, or specifically incorporates, 40 CFR 51.166(b)(48). (ii) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from affected stationary

combustion turbines, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49). (iii) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected stationary

combustion turbines, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 70.2. (iv) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected stationary combustion turbines, the “pollutant that is subject to any standard promulgated underPage **14** of **46**

section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 71.2. 5. Section 60.4326 is added to read as follows: **§ 60.4326 What CO 2**  **emissions standard must I meet?** You must not discharge from your affected stationary combustion turbine into the atmosphere an y gases that contain CO 2 in excess of the applicable CO 2 emissions standard specified in Table 2 of this subpart

. 6. Section 60.4333 is amended b y adding paragraph (c) to read as follows: **§ 60.4333 What are my general requirements for complying with this subpart?**

* * * * * (c) If you own or operate an affected stationary combustion turbine subject to a CO 2 emissions standard in §60.4326, you must make compliance determinations on a 12

- operating month rolling average basis, and you must determine compliance monthly by calculating the average CO 2 emissions rate for the affected stationary combustion turbine at the end of each 12

- operating month period. 7. Section 60.4373 is added under undesignated center heading “Monitoring” to read as follows: **§ 60.4373 How do I monitor and collect data to demonstrate compliance with my CO**  **2 emissions standard using a CO**  **2 CEMS?**  (a) You must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter. (b) You must measure the hourly CO 2 mass emission s from each affected stationary combustion turbine using the procedures in paragraphs (b)(1) through (5) of this section, except as provided in paragraph (c) of this section. (1) You must install, certify , operate, maintain, and calibrate a CO 2 continuous emission monitoring sy stem (CEMS) to directly measure and record CO 2 concentrations in the stationary combustion turbine exhaust gases emitted to the atmosphere and an exhaust gas flow rate monitoring sy stem according to § 75.10(a)(3)(i) of this chapter. I f you measure CO 2 concentration on a dry

basis, you must also install, certify , operate, maintain, and calibrate a continuous moisture monitoring s ys tem, according to § 75.11(b) of this chapter. (2) For each monitoring system that you use to determine the CO 2 mass emissions, you must meet the applicable certification and quality assurance procedures in § 75.20 of this chapter and Appendices B and D to part 75 of this chapter. (3) You must use a laser device to measure the dimensions of each exhaust gas sta ck or duct at the flow monitor and the reference method sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, you must make measure of the diameter at three or more distinct locations and average the res ults. For rectangular stacks or ducts, you must measure each dimension (i.e., depth and width) at three or more distinct locations and average the results. If the flow rate monitor or reference method sampling site is relocated, you must repeat these measurements at the new location.Page **15** of **4 6** 

(4) You must use unadjusted exhaust gas volumetric flow rates only to determine the hourly CO 2 mass emissions from the affected stationary combustion turbine; you must not appl y the bias adjustment factors described in s ec tion 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data. (5) If you chose to use Method 2 in Appendix A

- 1 to this part to perform the required relative accuracy

test audits (RATAs) of the part 75 flow rate monitoring s ystem, you must use a calibrated T yp e
- S pitot tube or pitot tube assembly . You must not use the default Ty pe
- S pitot tube coefficient. (c) As an alternative to complying with paragraph (b) of this section, you may determine the hourly

CO 2 mass emissions by

using Equation G

- 4 in Appendix G to part 75 of this chapter according to the requirements spec ified in paragraphs (c)(1) and (2) of this section. (1) You must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted. (2) You may

determine site

- specific carbon

- based F

- factors (F c ) using Equation F

- 7b in section 3.3.6 of Appendix F to part 75 of this chapter, and you may use these F c values in the emissions calculations instead of using the default F c values in the Equation G

- 4 nomenclature. (d) You must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously

measure and record the gross electric output from the affected stationary combustion turbine. These m easurements must be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. If the affected stationary

combustion turbine is a CH P stationary combustion turbine, you must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful thermal output . For process steam applications, you will need to install, calibrate, maint ain, and operate meters to continuously determine and record steam flow rate, temperature, and pressure. If the affected stationary combustion turbine has a direct mechanical drive application, you must submit a plan to the Administrator or delegated autho rity for approval of how gross energy

output will be determined. Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination. (e) If two or more affected stationary combustion turbines serve a common electric generator, you must apportion the combined hourly gross output to the individual stationary combustion turbines using a plan approved b y the Administrator (e.g., using steam load or heat input to each affected stationary combustion turbine). Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination. (f) In accordance with § 60.13(g), if two or more stationary combust ion turbines that implement the continuous emission monitoring provisions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard under § 60.4326, you may monitor the hourl y CO 2 mass emissions at the common stack in lieu of monitoring each stationary combustion turbine separatel y. If you choose this option, the hourly gross load (electric, thermal, and/or mechanical, as applicable) must be the sum of the hourly loads for thePage **16** of **46**

individual stationary

comb ustion turbines and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter). If you attain compliance with the applicable emissions standard in § 60.4326 at the common stack, each stationary combustion turbine sharing the stack is in compliance. (g) In accordance with § 60.13(g), if the exhaust gases from a stationary combustion turbine that implements the continuous emission monitoring provisions in paragraph (b) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and yo u chose to monitor in the ducts), you must monitor the hourly

CO 2 mass emissions and the “stack operating time” (as defined in § 72.2 of this chapter) at each stack or duct separatel y. In this case, you determine compliance with the applicable emissions standard in § 60.4326 by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing b y the total gross output for the unit. 8 . Section 60.4374 is added under undesignated center heading “Monitoring” to read as follows: **§ 60.4374 How do I demonstrate compliance with my CO 2**  **emissions standard and determine excess emissions?**  (a) You must calculate the CO 2 mass emissions rate for your affected stationary combustion turbine by

using the hourl y CO 2 mass emissions and total gross output data determined and recorded according to the procedures in § 60.4373 for the compliance period for the CO 2 emissions standard applicable to the affec ted stationary combustion turbine, and the calculation procedures in paragraphs (a)(1) through (a)(5) of this section. (1) You must only

use operating hours in the compliance period for the compliance determination calculation for which you obtained valid data for all parameters you used to determine the hourl y CO 2 mass emissions and gross output data, are used for the compliance determination calculation. You must not include operating hours in which you used the substitute data provisions of part 75 of th is chapter for an y of the parameters in the calculation. For the compliance determination calculation, you must obtain valid hourly CO 2 mass emission values for a minimum of 95 percent of the operating hours in the compliance period. (2) You must calculate the total CO 2 mass emissions by summing the hourly

CO 2 mass emissions values for the affected stationary combustion turbine determined to be valid according to the conditions specified in paragraph (a)(1) of this section for all of the operating hours in the applicable compliance period. (3) For each operating hour of the compliance period used in paragraph (a)(2) of this section to calculate the total CO 2 mass emissions, you must determine the affected stationary combustion turbine’s corresponding hourl y gross output (P gross ) by appl yi ng the appropriate definitions in § § 60.4420 and 60.4421 of this subpart and according to the procedures specified in paragraphs (a)(3)(i) and (iv) of this section . (i) Calculate P gross for your affected stationary combustio n turbine using the following equation:

= ( ) + ( ) + ( )

T + 0

. 75 × [ ( ) + ( ) + ( ) ]
Where:Page **17** of **46**

P gross = Gross energy output of your affected stationary combustion turbine in megawatt

- hours ( MWh )

. (Pe) CT = Electric energy output plus mechanical energy output (if any) of stationary combustion turbines in MWh. (Pe) ST = Electric energy output plus mechanical energy output (if any) of steam turbines in MWh. (Pe) IE = Electric energy output plus mechanical energy output (if any) of your affected stationary

combustion turbine’s integrated equipment that provides electricity

to the affected facility

or auxiliary

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

appli cable) that is used for applications that do not generate additional electricit y, produce mechanical energy output, enhance the performance of the affected facility

. This is c alculated using the equation specified in paragraph (a)(3)(ii) of this section in MWh. (Pt) HR = Useful thermal output (relative to SATP conditions , as applicable) from

heat recovery

that is used for applications other than steam generation or performance enhancement of the affected facility in MWh. (Pt) IE = Useful thermal output (relative to SATP conditions , as applicable) from

any integrated equipment that is used for applications that do not generate additional steam, electricity , produce mechanical energy output, or enhance the performan ce of the affected facility in MWh. T = Electric Transmission and Distribution Factor.

T = 0.95 for a CHP stationary combustion turbine where at least on an annual basis 20.0 percent of the total gross energy output consists of elec tric or direct mechanical output and 20.0 percent of the total gross energy output consists of useful thermal output on a rolling 3 ye ar basis. T = 1.0 for all other affected stationary combustion turbines.

(ii) If applicable to your affected stati onary combustion turbine, calculate (Pt) PS using the following equation: ( ) = × 3

. 6 × 10 Where: Q m = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating

hour. H = Enthalpy

of the steam at measured temperature and pressure (relative to SATP conditions , as applicable) in Joules per kilogram (J/kg) (or Btu/lb). 3.6 x 10 9 = Conversion factor (J/MWh) (or 3.413 x 10 6 Btu/MWh).Page **18** of **46**

(iii) You must determine the hourly gross energy

output for each operating hour in which there is no electric output, but there is mechanical output or useful thermal output. In addition yo u must determine the hourly gross CO 2 emissions for each operating hour in which there is no useful output. ( iv) In the case for which compliance is demonstrated according to § 60.4373(f) for affected stationary

combustion turbines that vent to a common stack, then you must calculate the hourly gross energy

output (electric, mechanical, and/or thermal, as applica ble) b y summing the hourly gross energy

output you determined for each of your individual affected stationary combustion turbines that vent to the common stack; and you must express the operating time as “stack operating hours” (as defined in § 72.2 of thi s chapter). (4) You must calculate the total gross output for the affected stationary combustion turbine’s compliance period by summing the hourly

gross output values for the affected stationary combustion turbine determined from paragraph (a)(2) of this section for all of the operating hours in the applicable compliance period. (5) You must calculate the CO 2 mass emissions rate for the affected stationary combustion turbine by

dividing the total CO 2 mass emissions value as calculated according to the requ irements of paragraph (a)(2) of this section by the total gross output value as calculated according to the requirements of paragraph (a)(4) of this section. (b) If the CO 2 mass emissions rate for the affected stationary combustion turbine determined according to the procedures specified in paragraph (a) of this section is less than or equal to the CO 2 emissions standard in Table 2 of this subpart applicable to the affected stationary combustion turbine, then your affected stationary combustion turbine is in compliance with the emissions standard. If the average CO 2 mass emissions rate is greater than the CO 2 emissions standard in Table 2 of this subpart applicable to the aff ected stationary

combustion turbine, then your affected stationary combustion turbine has excess CO 2 emissions. 9. Section 60.4375 is amended b y revising the section heading to read as follows: **§ 60.4375 What reports must I submit to comply with my NO x**  **and SO**  **2 emissions limits?** 

* * * * * 10. Section 60.4376 is added to read as follows: **§ 60.4376 What notifications and reports must I submit to comply with my CO 2**  **emissions standard?**  (a)(1) You must prepare and submit the notifications specified in § § 60.7(a)( 1) and (a)(3) and 60.19, as applicable to your affected stationary combustion turbine. (2) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable to your affected stationary combustion turbine. (b) You must prepare and submit reports according to paragraphs (b)(1) through (d) of this section, as applicable. (1) For stationary

combustion turbines that are required, by § 60.4333(c), to conduct initial and on

- going compliance determinations on a 12

- operating month rollin g average basis for the standard in § 60.4326, you must submit electronic quarterl y reports as follows. After you have accumulated the first 12

- operating months for the affected stationary combustion turbine,Page **19** of **46**

yo u must submit a report for the calendar quart er that includes the 12th

- operating month no later than 30 day s after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 day s after the end of the quarter. (2) In each quarterl y report, yo u must include the following information, as applicable: (i) Each rolling average CO 2 mass emissions rate for which the last (12th) operating month in a 12

- operating month compliance period falls within the calendar quarter. You must calculate each average CO 2 mass emissions rate according to the requirements of § 60.4374. You must report the dates (month and year) of the 1st and 12th

- operating months in each compliance period for which you performed a CO 2 mass emissions rate calculation. If there are no
co mpliance periods that end in the quarter, you must include a statement to that effect ; (ii) If one or more compliance periods end in the quarter, you must identify each operating month in the calendar quarter with excess CO 2 emissions; (iii) The percentage of valid CO 2 mass emission rates (as defined in § 60.4374) in each 12

- operating month compliance period described in paragraph (b)(2)(i) of this section (i.e., the total number of valid CO 2 mass emission rates in that period divided b y the total number of operating hours in that period, multiplied by 100 percent); and (iv) The CO 2 emissions standard (as identified in Table 2 of this subpart) with which your affected stationary

combustion turbine is complying. (3) The final quarterly

report of each calendar ye ar must contain the following: (i) Net electric output sold to an electric grid over the 4 quarters of the calendar year; and (ii) The potential electric output of the stationary combustion turbine. (c) You must submit all electronic reports required un der paragraph (b) of this section using the Emissions Collection and Monitoring Plan Sy stem (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 requirem ents and submit reports as required under subpart G of part 75 of this chapter. 11. Section 60.4391 is added to read as follows: **§ 60.4391 What records must I maintain to comply with my CO 2**  **emissions limits?** (a) You must maintain records of the information you used to demonstrate compliance with this subpart as specified in § 60.7(b) and (f). (b) You must follow the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter. (c) You must keep records of the calculations you performed to determine the total CO 2 mass emissions for: (1) Each operating month (for all affected units); (2) Each compliance period, including, as applicable, each 12

- operating month compliance period. (d) You must keep records of the applicable data recorded and calculations performed that you used to determine your affected stationary combustion turbine’s gross output for eachPage **20** of **46**

operating month. (e) You must keep records of the calculations you performed to determine the percentage of valid CO 2 mass emission rates in each compliance period. (f) You must keep records of the calculations you performed to assess compliance with each applicable CO 2 mass emissions standard in § 60.4326. (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). (h)(1) Your records must be in a form suitable and readil y available for expeditious review. (2) You must keep each record for 5 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record to demonstrate compliance with a 12

- operating month emissions standard. (3) You must keep each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may keep the records off site and electronically for the remaining ye ar(s) as required b y this subpart. 12. Section 60.4395 is revised to read as fol lows: **§ 60.4395 When must I submit my reports?** All of your reports required under § 60.7(c) must be postmarked by the 30th day

after the end of each 6

- month period, except as specified in § 60.4376 13. Section 60.4421 is added to read as follows: **§ 60.4421 What definitions with respect to CO 2**  **emissions apply to this subpart?** As used in this subpart: Base load rating means 100 percent of the manufacturer's design heat input capacity of the combustion turbine engine at I SO conditions using the higher heating value of the fuel (heat input from duct burners is not included). Excess emissions means a specified averaging period over which either: (1) The CO 2 emissions rate of your affected stationary combustion turbine exceeds the applicable emissions standard in Table 2 of this subpart or § 60.4330; or (2) The recorded value of a particular monitored parameter is outside the acceptable range specified in the parameter monitoring plan for the affected unit. Gross energy

output means: (1) The gross electric or direct mechanical output from both the combustion turbine engine and an y associated steam turbine(s) or integrated equipment plus any useful thermal outp ut measured relative to SATP conditions (except for GHG calculations in § 60. 4374 as only 75 percent credit is given) that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application).Page **21** of **46**

(2) For a CHP stationary

combustion turbine where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross ene rgy

output consists of useful thermal output on a rolling 3

- ye ar basis, the sum of the gross electric or direct mechanical output from both the combustion turbine engine and any associated steam turbine(s) divided by 0.95 plus any

useful thermal output mea sured relative to SATP conditions (except for GHG calculations in § 60. 4374 as only 75 percent credit is given) that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application). Net

- electric sales means: (1) The gross electric sales to the utility power distribution sy stem minus purchased power ; or (2) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy

output consists of useful thermal output on a 3 calendar year rolling average basis , the gross electric sales to the utility power distribution sy stem minus purchased power of the thermal host facility

or facilities ; and (3) Electricity

supplied to other facilities that produce electricity t o offset auxiliary loads
are included when calculating net

- electric sales. Net

- electric output means: the amount of gross generation a generator produces, as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity

needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale). Net energy

output means: (i) Except as provided under paragraph (ii ) of this definition, the net electric or mechanical output from both the combustion turbine engine and any associated steam turbine(s) or integrated equipment plus 75 percent of the useful thermal output; or (ii) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy

output consists of useful thermal output on a rolling 3 ye ar basis, the net ele ctric or mechanical output from both the combustion turbine engine and an y associated steam turbine(s) or integrated equipment divided by 0.95, plus 75 percent of the useful thermal output

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

combustion turbine. Potential electric output means 33 percent or the design electric output efficiency on a net output basis (at the election of the owner/operator of the affected facility) multiplied by the base load rating (expressed in MMBtu/h) of the stationary combustion turbine, multiplied by 10 6 Btu/MMBtu, divided b y 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/y r (e.g., a 35 percent efficient stationary combus tion turbine with a 100 MW (341 MMBtu/h) fossil

- fuel heat input capacity would have a 310,000 MWh 12

- month potential electric output capacity).Page **22** of **46**

Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F) ) and 10 0.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at S ATP conditions is 5 0 Btu/lb. Stationary

combustion turbine means all equipment, including but not limited to the combustion turbine engine, the fuel, air, lubrication and exhaust gas sy stems, control sy stems, heat recovery

s ys tem, 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 use ful thermal output to the combustion turbine engine, heat recovery

s ys tem or auxiliary

equipment. Stationary

means that the combustion turbine is not self propelled or intended to be propelled while performing its function. It may , however, be mounted on a vehicle for portability

. Useful thermal output means the thermal energy made available for use in any heating application (e.g., steam delivered to an industrial process for a heating application , including thermal cooling applications) that is not used for electric generation, mechanical output at the affected facility , or to directly enhance the performance of the affected facility (e.g., economizer output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered useful thermal output)

. Useful thermal output for affected facilities with no condensate return (or other thermal energy

input to the affected facility) or where measuring the energy in the condensate (or other thermal energy input to the affect ed facility) would not meaningfull y impact the emission rate calculation is measured against the energy in the thermal output at SATP conditions. Affected facilities with meaningful energy in the condensate return (or other thermal energy input to the affe cted facilit y) must measure the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output.Page **23** of **46**

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

**– Carbon Dioxide Emission Limits for Stationary**  **Combustion Turbines**

**Note: all numerical values have a minimum of 2 significant figures Affected Stationary Combustion Turbine**  **CO 2**  **Emission Standard** Stationary

combustion turbine that has a design heat input to the turbine engine of greater than 250 MW ( 850 MMBtu/h)

. 450 kilograms (kg) of CO 2 per megawatt

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

- operating month rolling average Stationary

combustion turbine that has a design heat input to the turbine engine greater than 73 MW (250 MMBtu/h) and equal to or less than 250 MW ( 850 MMBtu/h ). 500 kg of CO 2 per MWh of gross output (1,100 lb CO 2 /MWh) on a 12

- operating month rolling averagePage **24** of **46**

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

**– Applicability of Subpart A General Provisions to**  **Stationary Combustion Turbine CO 2**  **Emissions Standards in Subpart KKKK**

**General Provisions**  **citation Subject of**  **citation Applies to**  **subpart KKKK**  **Explanation**
§ 60.1 Applicability Yes § 60.2 Definitions Yes § 60.3 Units and Abbreviations Yes § 60.4 Address Yes
§ 60.5 Determination of

construction or modification Yes
§ 60.6 Review of plans Yes
§ 60.7 Notification and

Recordkeeping Yes Only the requirements to submit the notification in § 60.7(a)(1) and (a)(3) § 60.8 Performance tests No § 60.9 Availability of In formation Yes § 60.10 State authority Yes

§ 60.11 Compliance with

standards and maintenance requirements No

§ 60.12 Circumvention Yes § 60.13 Monitoring requirements Yes § 60.14 Modification No § 60.15 Reconstruction No § 60.16 Priority list No § 60.17 In corporations by

reference Yes
§ 60.18 General control device

requirements No
§ 60.19 General notification and

reporting requirements YesPage **25** of **46**

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

**-- Standards of Performance for Greenhouse Gas Emissions for Electric**  **Generating Units**  Sec. **Applicability**
§ 60.5508 What is the purpose of this subpart? § 60.5509 Am Isubject to this subpart?

**Emission Standards**
§ 60.5515 What greenhouse gases are regulated b y this subpart? § 60.5520 What CO 2 emissions standard must I meet?
**General Compliance Requirements**
§ 60.5525 What are my general requirements for compl yi ng 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 CO 2 emissions standard and determine excess emissions?

**Notifications, Reports, and Records**
§ 60.5550 What notifications must I submit and when? § 60.5555 What reports must Isubmit 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 m y affected facility? § 60.5575 Who implements and enforces this subpart? § 60.5580 What definitions apply to this subpart?

**Applicability § 60.5508 What is the purpose of this subpart?**  This subpart establishes emi ssion standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a steam generating unit, IGCC, or a stationary combustion turbine that commences construction after January 8, 2014 or commences modification or reconstruction after [ INSERT DATE OF PUBLICATION IN THE FEDERAL REGI STER ].Page **26** of **46**

**§ 60.5509 Am I subject to this subpart?** (a) Except as provided for in paragraph (b) of this section, the subpart applies to any steam generating unit, IGCC, or stationary combustion turbine that commence d construction after January

8, 2014 or commenced modification or reconstruction after [ INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] that meets the relevant applicability conditions in paragraphs (a)(1) and (a)(2) of this section. (1) A steam generating unit or I GCC that commenced construction after January 8, 2014 and has a design heat input greater than 73 MW (250MMBtu/h) heat input of fossil fuel (either alone or in combination with any other fuel), combusts fossil fuel for more than 10.0 percent of the average annual heat input during a 3 ye ar rolling average basis, and was constructed for the purpose of suppl yi ng, and supplies, one

- third or more of its potential electric output and more than 219,000 MWh net

- electric output to a utility distribution sy stem on an annual basis. ( 2 ) A steam generating unit or I GCC that commenced modification or reconstruction after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGI STER] and has a design heat input greater than 73 MW (250MMBtu/h) heat input of fossil fuel (either alone or in
co mbination with any

other fuel) and was constructe d for the purpose of supplying one
- third or more of its potential electric output and more than 219,000 MWh net

- electric output to a utility distribution sy stem on an annual basis. ( 3 ) A stationary

combustion turbine that has a design heat input to the turbine engine greater than 73 MW (250 MMBtu/h), combusts fossil fuel for more than 10.0 percent of the average annual heat input during a 3 ye ar rolling average basis , combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and was constructed for the purpose of supplying, and supplies, one

- third or more of its potential electric output and more than 219,000 MWh net

- electrical output to a utility distribution sy stem on a 3 ye ar rolling average basis. (b) You are not subject to the requirements of this subpart if your affected facility meets any one of the conditions specified in paragraphs (b)(1) through (b)(5) of this section. (1) The proposed Wolverine EGU project described in Permit to Install No. 317

- 07 issued by the Michigan Department of Environmental Quality , Air Quality Division, effective June 29, 2011 (as revised July 12, 2011). (2) The proposed Washington County EGU project de scribed in Air Quality Permit No. 4911

- 303

- 0051

- P

- 01

- 0 issued by the Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, effective April 8, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014

. (3) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment, effective December 16, 2010, provided that construc tion had not commenced for NSPS purposes as of January 8, 2014

. (4) Your affected facility is a municipal waste combustor unit that is subject to subpart Eb of this part. (5) Your affected facility is a commercial or industrial solid waste incineration uni t that is subject to subpart CCCC of this part. **Emission Standards**Page **27** of **46**

**§ 60.5515 What greenhouse gases are regulated by this subpart?** (a) The greenhouse gas regulated b y this subpart is carbon dioxide (CO 2 ). (b) PSD and Title V Thresholds for Greenhouse Gases

. (1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subjec t to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in an y S IP 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 emi ssions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49). (3) F or purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to re gulation" as defined in 40 CFR 70.2. (4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 71.2. **§ 60.5520 What CO 2**  **emissions standard must I meet?** (a) For each affected facility subject to this subpart, you must not discharge from the affected facility an y gases that contain CO 2 in excess of the applicable CO 2 emissions standard specified in Table 1 or Table 2 of this subpart , except for owners and operators of modified affected facilities c ompl ying with the standards specified in paragraph (b) of this section, as applicable to the affected facility

. (b ) The owner or operator of a modified steam generating unit or IGCC facility complying with the requirements of this paragraph are not required to comply with the emission limit in Table 2 to this subpart

. (1) If the affected facility is not subject to an approved CAA section 111(d) plan (state or federal) at the time of the modification , the owner/operator may elect to comply

with a site

specific 12

- operating month rolling average CO 2 emission limit calculated as 2 percent lower than (i.e., 98 percent) the best demonstrated annual historical operating performance for the affected facility

using historical CO 2 emissions data for the calendar ye ars 2002 through the most recent full calendar ye ar the affected facil ity was operating prior to the modification using either recorded net output emission rate data or gross electrical output and CO 2 emissions data as reported under part 75 of this chapter . If incomplete or no data has been submitted under part 75 of this c hapter, the Administrator or delegated authority shall approve the use of alternate data sources. The equivalent net output

- based standard shall be calculated from gross output

- based data assuming a 7.5 percent auxiliary (i.e., parasitic) load (i.e., the best annual value is divided by 0.925); orPage **28** of **46**

(2) If the affected facility is s ubject to an approved CAA section 111(d) plan (state or federal) at the time of the modification , a site

- spe cific 12

- operating month rolling average CO 2 emission limit determined by the CAA section 111(d) implementing authority based on the affected facility

performing an energy

assessment by

an energy

professional or engineer that have expertise in evaluating energy s ys tems to identify

applicable energy

efficiency

projects that yo u will implement at the affected facility to improve the affected facility’s operating performance. You must maintain a copy of the most recent energ y assessment report. The energy assessment must include at a minimum the elements in paragraphs (b )(2 ) (i) through (b )(2) ( iii ) of this section

. ( i ) A visual inspection of the facility to identify

steam leaks or other sources of reduced efficiency , (ii ) A re view of available engineering plans and facility operation and maintenance procedures and logs, and (iii ) A comprehensive report detailing the way s to improve efficiency , the cost of specific improvements, benefits, and the time frame f or recouping those i nvestments. **General Compliance Requirements § 60.5525 What are my general requirements for complying with this subpart?**  (a) You must be in compliance with the emission standards in this subpart that apply to yo ur affected facility

at all times. However, you must make a compliance determination only at the end of the applicable operating month, as provided in paragraphs (a)(1) and (2) of this section. (1) For each affected facility subject to a CO 2 emissions standard based on a 12

- operating month rolling av erage, you must determine compliance monthly b y calculating the average CO 2 emissions rate for the affected facility at the end of each 12

- operating month period. (2) For each affected facility subject to a CO 2 emissions standard based on an 84

- operating month rolling average, you must determine compliance monthl y by calculating the average CO 2 emissions rate for the affected facility at the end of each 84

- operating month period. (b) At all times you must operate and maintain each affected facility , includ ing associated equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practice. The Administrator will determine if you are using consistent operation and maintenance procedures based on information available to the Administrator that may include, but is not limited to, fuel use records, monitoring results, review of operation and maintenance procedures and records, review of reports required by this subpart, and inspection of the facility

. (c) You must conduct an initial compliance determination for your affected facility for the applicable emissions standard in § 60.5520, according to the requirements in this subpart, within 30 day s after the end of the initial compliance period for the CO 2 emissions standards applicable to your affected facility (i.e., 12

- operating months or 84

- operating months). The first operating month included in this compliance period is the month in which emissions reporting is required to begin under §75.64(a) of this chapter.

**Monitoring and Compliance Determination Procedures § 60.5535 How do I monitor and collect data to demonstrate compliance?** Page **29** of **46**

(a) You must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter. (b) You must measure the hourly CO 2 mass emissions from each affected facility using the procedures in paragraphs (b)(1) through (5) of this section, except as provided in paragraph (c) of this section. (1) You must install, certify , operate, maintain, and calibr ate a CO 2 continuous emission monitoring sy stem (CEMS) to directly measure and record CO 2 concentrations in the affected facility exhaust gases emitted to the atmosphere and an exhaust gas flow rate monitoring s ys tem according to § 75.10(a)(3)(i) of this c hapter. If you measure CO 2 concentration on a dry basis, yo u must also install, certify , operate, maintain, and calibrate a continuous moisture monitoring sy stem, according to § 75.11(b) of this chapter. (2) For each monitoring system you use to determine the CO 2 mass emissions, you must meet the applicable certification and quality assurance procedures in § 75.20 of this chapter and Appendices B and D to part 75 of this chapter. (3) You must use a laser device to measure the dimensions of each exhaust gas stack or duct at the flow monitor and the reference method sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, you must measure the diameter at three or more distinct locations and average the results . For rectangular stacks or ducts, you must measure each dimension (i.e., depth and width) at three or more distinct locations and average the results. If the flow rate monitor or reference method sampling site is relocated, you must repeat these measureme nts at the new location. (4) You must use only

unadjusted exhaust gas volumetric flow rates to determine the hourly CO 2 mass emissions from the affected facility ; you must not appl y the bias adjustment factors described in s ection 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data. (5) If you choose to use Method 2 in Appendix A

- 1 to this part to perform the required relative accuracy

test audits (RATAs) of the part 75 flow rate monitoring s ystem, you must use a calibrated T yp e
- S pitot tube or pitot tube assembly . You must not use the default Ty pe
- S pitot tube coefficient. (c) If your affected facility exclusively combusts liquid fuel and/or gaseous fuel as an alternative to compl yi ng with paragraph (b) of this section, you may determine the hourly CO 2 mass emissions by

using Equation G

- 4 in Appendix G to part 75 of this chapter according to the requirements in paragraphs (c)(1) and (2) of this section. (1) You must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted. (2) You may

determine site

- specific carbon

- based F

- fact ors (F c ) using Equation F

- 7b in section 3.3.6 of appendix F to part 75 of this chapter, and you may use these F c values in the emissions calculations instead of using the default F c values in the Equation G

- 4 nomenclature. (d) You must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously

measure and record the gross or net electric output from the affected facility.Page **30** of **46**

These m easurements must be performed using 0.2 class electricity metering instrumentation and calibrati on procedures as specified under ANSI Standards No. C12. 20

. If the affected facility is a CHP facility , you must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful thermal output . For process steam applications, you will need to install, calibrate, maintain, and operate meters to continuously determine and record steam flow rate, temperature, and pressure. If the affected facility has a direct mechanical drive application, you must submit a plan to the Administrator or delegated authority for approval of how gross or net energy

output will be determined. Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination. (e) If two or more affected facilities serve a common electric generator, you must apportion the combined hourly gross or net output to the individual affected facilities using a plan approved b y the Administrator (e.g., using steam load or heat input to each affected EGU). Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination. (f) In accordance with § 60.13(g), if two or more affected facilities that implement the continuous emission monitoring provisions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard under § 60.5520, you may monitor the hourly

CO 2 mass emissions at the common stack in lieu of monitoring each EGU separately . I f you choose this option, the hourly gross or net load (electric, thermal, and/or mechanical, as applicable) must be the sum of the hourly loads for the individual affected facility and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter). If you attain compliance with the applicable emissions standard in § 60.5520 at the common stack, each affected facility sharing the stack is in compliance. ( g) In accordance with § 60.13(g), if the exhaust gases from an affected facility that implements the continuous emission monitoring provisions in paragraph (b) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly

CO 2 mass emissions and the “stack operating time” (as defined in § 72.2 of this chapter) at each stack or duct separatel y. In this case, you must determine compliance with the applicable emissions standard in § 60.5520 by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing b y the total gross or net output for the affected facility

. **§60.5540 How do I demonstrate compliance with my CO**  **2 emissions standard and**  **determine excess emissions?** (a) You must calculate the CO 2 mass emissions rate for your affected facility b y using the hourly CO 2 mass emissions and total gross or net output data determined and recorded according to the procedures in § 60.5535 for each operating hour in the compliance period for the CO 2 emissions standard applicable to the affected facility (i.e., 12

- or 84

- operating month rolling average period), and the calculation procedure s in paragraphs (a)(1) through (a)(5) of this section. (1) You can only

use operating hours in the compliance period for the compliance determination calculation if valid data are obtained for all parameters you used to determine the hourly CO 2 mass emissi ons and the gross or net output data are used for the compliance determination calculation. You must not include operating hours in which you used the substitutePage **31** of **46**

data provisions of part 75 of this chapter for an y of those parameters in the calculation. For the compliance determination calculation, you must obtain valid hourly CO 2 mass emission values for a minimum of 95 percent of the operating hours in the compliance period for the CO 2 emissions standard applicable to the affected facility

. (2) You must ca lculate the total CO 2 mass emissions by summing the valid hourly CO 2 mass emissions values for all of the operating hours in the applicable compliance period. (3) For each operating hour of the compliance period that you used in paragraph (a)(2) of this s ection to calculate the total CO 2 mass emissions, you must determine the affected facility ’s corresponding hourl y gross or net output according to the procedures in paragraphs (a)(3)(i) and (ii) of this section, as appropriate for the type of affected faci lity . For an operating hour in which there is no gross or net electric load, but there is mechanical or useful thermal output, you must still determine the gross or net output for that hour. In addition, for operating hours in which there is no useful output, you still need to determine the CO 2 emissions for that hour. For hours or partial hours where the gross generation is equal to or less than the auxiliary loads , net electric
output shall be counted as zero for this calculation

. (i) Calculate P gross /net for your affected facility using the following equation:

/ = ( ) + ( ) + ( )

− ( ) T + 0

. 75 × [ ( ) + ( ) + ( ) ]
Where: a P gross /net = Gross or net energy output of your affected facility in megawatt

- hours ( MWh )

. (Pe) ST = Electric energy output plus mechanical energy output (if any) of steam turbines in MWh. (Pe) CT = Electric energy output plus mechanical energy output (if any) of stationary combustion turbine(s) in MWh. (Pe) IE = Electric energy output plus mechanical energy output (if any) of your affected facility ’s integrated equipment that provides electricity or mechanical energy

to the affe cted facility

or auxiliary

equipment in MWh. (Pe) FW = Electric energy used to power boiler feedwater pumps at steam generating units in MWh. Not applicable to stationary combustion turbines , IG CC facilities , or facilities complying with a net output bas ed 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 electricit y, produce mechanical energy output, or enhance the performan ce of the affected facility

. This is c alculated using the equation specified in paragraph (g)(3)(iii)(B) of this section in MWh. (Pt) HR = Non steam useful thermal output ( measured relative to SATP conditions ,

as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected facility in MWh. (Pt) IE = Useful thermal output (relative to SATP conditions , as applicable) fromPage **32** of **46**

any integrated equipment th at is used for applications that do not generate additional steam, electricity , produce mechanical energy output, or enhance the performance of the affected facility in MWh. T = Electric Transmission and Di stribution Factor.

T = 0.95 for a combined heat and power affected facility where at least on an annual basis 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and 20.0 percent of the total gross or net e nergy

output consists of useful thermal output on a rolling 3 ye ar basis. T = 1.0 for all other affected facilities.

(ii) If applicable to your affected facility, you must calculate (Pt) PS using the following equation: ( ) = × 3

. 6 × 10 Where: Q m = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating

hour. H = Enthalpy

of the steam at measured temperature and pressure (relative to SATP conditions , as applicable) in Joules per kilogram (J/kg) (or Btu/lb). 3.6 x 10 9 = Conversion factor (J/MWh) (or 3.413 x 10 6 Btu/MWh).

(4) You must calculate the total gross or net output for the affected facility ’s compliance period by summing the hourly

gross or net output values for the affected facility that you determined from paragraph (a)(2) of this section for all of the operating hours in the applicable compliance period. (5) You must calculate the CO 2 mass emissions rate for the affected facility by dividing the total CO 2 mass emissions value calculated according to th e procedures in paragraph (a)(2) of this section by

the total gross or net output value calculated according to the procedures in paragraph (a)(4) of this section. (b) If the CO 2 mass emissions rate for your affected facilit y that you determined according to the procedures specified in paragraph (a) of this section is less than or equal to the CO 2 emissions standard in Table 1 of this subpart applicable to the affected facility, then your affected facility

is in compliance with the emissions standard. If th e average CO 2 mass emissions rate is greater than the CO 2 emissions standard in Table 1 of this subpart applicable to the affected facility , then yo ur affected facility has excess CO 2 emissions. **Notification, Reports, and Records § 60.5550 What**  **notifications must I submit and when?** (a) You must prepare and submit the notifications specified in § § 60.7(a)(1) and (a)(3)Page **33** of **46**

and 60.19, as applicable to your affected facility

. (b) You must prepare and submit notifications specified in § 75.61 of this cha pter, as applicable to your affected facility. **§ 60.5555 What reports must I submit and when?** (a) You must prepare and submit reports according to paragraphs (a) through (d) of this section, as applicable. (1) For affected facilities that are required b y § 60.5525 to conduct initial and on

- going compliance determinations on a 12

- or 84

- operating month rolling average basis for the standard in § 60.5520 you must submit electronic quarterl y reports as follows. After you have accumulated the first 12

- operatin g months for the affected facility (or, the first 84

- operating months for an affected facility electing to compl y with the 84

- operating month standard), you must submit a report for the calendar quarter that includes the twelfth (or eighty - fourth) operatin g month no later than 30 day s after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 day s after the end of the quarter. (2) In each quarterl y report you must include the following inform ation, as applicable: (i) Each rolling average CO 2 mass emissions rate for which the last (12th or eighty fourth) operating month in a 12

- or 84

- operating month compliance period falls within the calendar quarter. You must calculate each average CO 2 mass e missions rate according to the procedures in § 60.5540. You must report the dates (month and year) of the first and twelfth (or eight y - fourth) operating months in each compliance period for which you performed a CO 2 mass emissions rate calculation. If there are no compliance periods that end in the quarter, you must include a statement to that effect ; (ii) If one or more compliance periods end in the quarter you must identify each operating month in the calendar quarter with excess CO 2 emissions; (i ii) The percentage of valid CO 2 mass emission rates (as defined in § 60.5540) in each 12

- or 84

- operating month compliance period described in paragraph (a)(1)(i) of this section (i.e., the total number of valid CO 2 mass emission rates in that period divid ed by the total number of operating hours in that period, multiplied by 100 percent); and (iv) The CO 2 emissions standard (as identified in Table 1 of this subpart) with which your affected facility

is complying

. (3) In the final quarterly

report of each c alendar year, you must include the following: (i) Gross electric output sold to an electric grid over the 4 quarters of the calendar ye ar; and (ii) The potential electric output of the facility

. (b) You must submit all electronic reports required under par agraph (a) of this section using the Emissions Collection and Monitoring Plan Sy stem (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of EPA. (c) You must meet all applicable reporting requirements and su bmit reports as required under subpart G of part 75 of this chapter.Page **34** of **46**

(d) If your affected unit employ s geologic sequestration to meet the applicable emission limit, you must report in accordance with the requirements of 40 CFR p art 98 , s ubpart PP and eith er: (1) if injection occurs onsite, report in accordance with the requirements of 40 CFR p art 98 , subpart RR, or (2) if injection occurs offsite, transfer the captured CO 2 to a facility or facilities that reports in accordance with the requirements of 40 CFR p art 98 , subpart RR. **§ 60.5560 What records must I maintain?** (a) You must maintain records of the information you used to demonstrate compliance with this subpart as sp ecified in § 60.7(b) and (f). (b) You must follow the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter. (c) You must keep records of the calculations you performed to determine the total CO 2 mass emissions for: (1) Each operating month (for all affected units); (2) Each compliance period, including, as applicable, each 12

- operating month compliance period and the 84

- operating month compliance period. (d) You must keep records of the applicable data recorded and calculations performed that you used to determine your affected facility ’s gross or net output for each operating month. (e) You must keep records of the calculations you performed to determine the percentage of valid CO 2 mass emission r ates in each compliance period. (f) You must keep records of the calculations you performed to assess compliance with each applicable CO 2 mass emissions standard in § 60.5520. (g) You must keep records of the calculations you performed to determine any s ite

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 5 ye ars after the date of each occurrence, measurement, maintenance, corrective action, report, or record except those records required to demonstrate compliance with an 84

- operating month compliance period. You must m aintain records required to demonstrate compliance with an 84

- operating month compliance period for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. (c) You must maintain each record o n site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart. **Other Requirements and Information § 60.5570 What parts of the General Provisions apply to my affected facility?** Page **35** of **46**

Notwithstanding an y other provision of this chapter, certain parts of the General Provisions in § § 60.1 through 60.19, listed in Table 2 of this subpart, do not apply to your affected facility

. **§ 60.5575 Who implements and enforces this subpart?** (a) This subpart can be implemented and enforced by the EPA, or a delegated authority such as your state, local, or tribal agency . If the Administrat or 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 s tate, 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 tr ansfer them to the state, local, or tribal agency . In addition, the EPA retains oversight of this subpart and can take enforcement actions, as appropriate. (1) Approval of alternatives to the emission standards. (2) Approval of major alternatives to test methods. (3) Approval of major alternatives to monitoring. (4) Approval of major alternatives to recordkeeping and reporting. (5) Performance test and data reduction waivers under § 60.8(b). **§ 60.5580 What definitions apply to this subpart?** As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in subpart A (General Provisions of this part). Base load rating means the maximum amount of heat input (fuel) that a steam generating unit can combust on a steady state basis, as determined by the ph ys ical design and characteristics of the steam generating unit at I SO conditions. For a stationary combustion turbine, base load rating means 100 percent of the design heat input capacity of the simple cycle portion of the stationary combustion turbine at I SO conditions (heat input from duct burners is not included). Coal means all solid fuels classified as anthracite, bituminous, subbituminous , or lignite by the American Society

of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17), coal refuse, and petroleum coke. Sy nthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to so lvent

- 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, phy sical coal clean ing, and coal preparation operations ( e.g. culm, gob, etc.) containing coal, matrix material, clay , and other organic and inorganic material. Combined cycle facility means an electric generating unit that uses a stationary combustion turbine from which th e heat from the turbine exhaust gases is recovered b y a heat recovery steam generating unit to generate additional electricity. Combined heat and power facilit y or CHP facilit y , ( also known as “cogeneration”) meansPage **36** of **46**

an electric generating unit that that use a steam

- generating unit or stationary combustion turbine to simultaneously

produce both electric (or mechanical) and useful thermal output from the same primary energy source. Distillate oil means fuel oils that contain no more than 0.05 weight percent nitrogen and comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated b y 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 b y reference, see § 60.17); kerosene, as defined b y the American Societ y of Testing and Materials in ASTM D3699 (incorporated by reference, see § 60.17 ); biodiesel as defined b y the American Society of Testing and Materials in ASTM D6751 (incorporated b y reference, see § 60.17); or biodiesel blends as defined by the American Society

of Testing and Materials in ASTM D7467 (incorporated by reference, see § 60.17). Excess emissions means a specified averaging period over which the CO 2 emissions rate is higher than the applicable emissions standard located in Table 1 of this subpart

. Fossil fuel means natural gas, petroleum, coal, and any form of solid, liqui d, or gaseous fuel derived from such material for the purpose of creating useful heat. Gaseous fuel means an y fuel that is present as a gas at I SO conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke

- oven gas, synthetic gas, and gasified coal. Gross energy

output means: (1) For stationary

combustion turbines and IGCC facilities, the gross electric or direct mechanical output from both the unit (including, but not limited to, output from steam turbine(s), combus tion turbine(s), and gas expander(s)) plus 75 percent of the useful thermal output

. (2) For electric utility

steam generating units, the gross electric or mechanical output from the affected facility

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

used to power the feedwater pumps plus 75 percent of the useful thermal output ; (3) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and 20.0 percent of the total gross energy output consists of useful thermal output on a rolling 3 ye ar basis, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus an y el ectricity used to power the feedwater pumps (the electric auxiliary load of boiler feedwater pumps is not applicable to IGCC facilities), that difference divided by 0.95, plus 75 percent of the useful thermal output

. Heat recovery

steam generating unit (HRSG) means a unit in which hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used with or without duct burners. Integrated gasificati on combined cycle facility or IGCC facility means a combined cycle stationary combustion turbine that is designed to burn fuels containing 50 percent (by heat input) or more solid

- derived fuel not meeting the definition of natural gas. The Administrator may waive the 50 percent solid

- derived fuel requirement during periods of the gasification sy stemPage **37** of **46**

construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the unit during operation. ISO conditions means 288 Kelvin (15 o C), 60 percent relative humidity and 101.3 kilopascals pressure. Liquid fuel means any

fuel that is present as a liquid at I SO conditions and includes, but is not limited to, distillate oil and residual oil. Mechanical output means the useful mechanical energy that is not used to operate the affected facility , generate electricit y and/or thermal energy, or to enhance the performance of the affected facility . Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by

7 45.7 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 b y volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finall y, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal

- derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value. Net

- electric sales means : (1) The gross electric sales to the utility power distribution sy stem minus purchased power ; or (2) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy

output consists of useful thermal output , the gross electric sales to the utility powe r distribution sy stem minus purchased power of the thermal host facility or facilities ; and (3) Electricity

supplied to other facilities that produce electricity to offset auxiliary loads are included when calculating net

- electric sales. Net

- electric o utput 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 th e plant (i.e., auxiliary

loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment , other electricity needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale). Net energy

output means: (i) Except as provided under paragraph (ii ) of this definition, the net electric or mechanical output from the affected facility plus 75 percent of the useful thermal output; or (ii) For combined heat and power facilities where at least 20.0 percent of the total gross or net energy

output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a rolling 3 year basis, the net ele ctric or mechanical output from the affected facility divided by 0.95, plus 75 percent of the useful thermal output;Page **38** of **46**

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

at any time. Petroleum means crude oil or a fuel derived from crude oil, including , but not limited to, distillate and residual oil

. Potential electric output means 33 percent or the design electric output efficiency on a net output basis multiplied by the maximum design heat input capacity (expres sed in MMBtu/h) of the steam generating unit, multiplied by 10 6 Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/ yr (e.g., a 35 percent efficient affected facility with a 100 MW (341 MMBtu/h) fossil

- fuel heat input c apacit y would have a 310,000 MWh 12 month potential electric output capacity). Solid fuel means an y 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. Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F) ) and 10 0.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 5 0 Btu/lb. Stationary

combustion turbine means all equipment, including but not limited to the turbine engine, the fuel, air, lubrication and exhaust gas s ys tems, control s ys tems (except emissions control equipment), heat rec overy s ys tem, fuel compressor, heater, and/or pump, post

combustion emission control technology , and any ancillary components and sub

- components comprising an y simple cycle stationary combustion turbine, an y combined cycle combustion turbine, and an y combi ned heat and power combustion turbine based sy stem plus any integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery

s ys tem or auxiliary

equipment. Stationary

means that the combustion turbine is not self propelled or intended to be propelled while performing its function. It may , however, be mounted on a vehicle for portability . If a stationary combustion turbine burns any solid fuel directly it is considered a steam generating unit. Steam gene rating unit means an y furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected facility or aux iliary equipment. Useful thermal output means the thermal energy made available for use in any heating application ( e .g., steam delivered to an industrial process for a heating application , including thermal cooling applications ) that is not used for electric generation, mechanical output at the affected facility , or to directly enhance the performance of the affected facility (e.g., economizer output is not useful thermal output , but thermal energy used to reduce fuel moisture is considered useful thermal output)

. Useful thermal output for affected facilities with no condensate return (or other thermal energy

input to the affected facility) or where measuring the energy in the condensate (or other thermal energy input to the affected facility) would not meaningfull y impact the emission rate calculation is measured against the ene rgy in the thermal output at SATP conditions. Affected facilities with meaningful energy in the condensate return (or other thermal energy input to the affected facilit y) must measure the energy in the condensate and subtract that energy relative to SA TP conditions from the measured thermal output.Page **39** of **46**

**Table 1 of**  **Subpart TTTT of Part 60**

**– CO**  **2 Emission Standards**  **for Affected Facilities that Commenced Construction after January 8, 2014** 

**Note: all numerical values have a minimum of 2 significant figures Affected Facility**  **CO 2**  **Emission Standard** Stationary

combustion turbine that has a base load rating heat input to the turbine engine of greater than 250 MW ( 850 MMBtu/h)

. 450 kilograms (kg) of CO 2 per megawatt

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

- operating month rolling average
Stationary

combustion turbine that has a design heat input to the turbine engine greater than 73 MW (250 MMBtu/h) and equal to or less than 250 MW ( 850 MMBtu/h ).

. 500 kg of CO 2 per MWh of gross output (1,100 lb CO 2 /MWh) on a 12

- operating month rolling average Steam generating unit 500 kg of CO 2 per MWh of gross energy output (1,100 lb CO 2 /MWh) on a 12

- operating month rolling average basis;
or 480 kg of CO 2 per MWh of gross energy output (1,050 lb CO 2 /MWh) on an 84

- operating month rolling average basis. Integrated gasification combined cycle (IGCC) facility 500 kg of CO 2 per MWh of gross energy output (1,100 lb CO 2 /MWh) on a 12

- operating month rolli ng average basis;
or 480 kg of CO 2 per MWh of gross energy output (1,050 lb CO 2 /MWh) on an 84

- operating month rolling average basis.Page **40** of **46**

**Table 2**  **of Subpart TTTT of Part 60** 

**– CO**  **2 Emission Standards for Affected Facilities**  **( as**  **applicable )**  **1 that Commenced Reconstruction or Modification after [INSERT DATE OF**  **PUBLICAT I**  **ON IN THE FEDERAL REGISTER]** 

**Note: all numerical values have a minimum of 2 significant figures Affected Facility**  **CO 2**  **Emission Standard** Stationary

combustion turbine that has a design heat input to the turbine engine greater than 73 MW (250 MMBtu/h) and equal to or less than 250 MW (850 MMBtu/h )

. 51 0 kg of CO 2 per MWh of gross output (1,100 lb CO 2 /MWh) on a 12

- operating month rolling average
Stationary

combustion turbine that ha s a base load rating heat input to the turbine engine of greater than 250 MW (850 MMBtu/h)

. 46 0 kilograms (kg) of CO 2 per megawatt

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

- operating month rolling average
Steam generating unit or integrated gasification combined cycle (IGCC) facility that has a design heat input of 590 MW (2,000 MMBtu/h) or less. 95 0 kg of CO 2 per MWh of net energy output (2 , 1 00 lb CO 2 /MWh) on a 12

- operating month rolling average basis; Steam generating unit or IGCC facility that has a design heat input greater than 590 MW (2,000 MMBtu/h). 86 0 kg of CO 2 per MWh of net energy output (1, 9 00 lb CO 2 /MWh) on a 12

- operating month rolling average basis;

1 The emission standards in Table 2 are not applicable to modified steam generating units and IGCC facilities subject to an approved CAA section 111(d) plan at the time of the modification or modified steam generating units and IGCC facilities not subject to an approved CAA section 111(d) plan at the time of the modification that elect to comply with an emission standard based on historical operating data.Page **41** of **46**

**Table 3**  **of Subpart TTTT of Part 60** 

**– Applicability of Subpart A General Provisions to**  **Subpart TTTT General**  **Provisions citation**  **Subject of citation Applies to**  **subpart TTTT**  **Explanation**
§ 60.1 Applicability Yes § 60.2 Definitions Yes Additional terms defined in § 60.5580 § 60.3 Units and Abbreviations Yes § 60.4 Address Yes
§ 60.5 Determination of

construction or modification Yes
§ 60.6 Review of plans Yes
§ 60.7 Notification and

Recordkeeping Yes Only the requirements to submit the notification in § 60.7(a)(1) and (a)(3) § 60.8 Performance tests No § 60.9 Availability of In formation Yes § 60.10 State authority Yes

§ 60.11 Compliance with

standards and maintenance requirements No

§ 60.12 Circumvention Yes § 60.13 Monitoring requirements Yes § 60.14 Modification No § 60.15 Reconstruction No § 60.16 Priority list No § 60.17 In corporations by

reference Yes
§ 60.18 General control device

requirements No
§ 60.19 General notification and

reporting requirements YesPage **42** of **46**

**PART 70**

**— STATE**  **OPERATING PERMIT PROGRAMS** 17. The authorit y citation for part 70 continues to read as follows: **Authority** : 42 U.S.C. 7401, et seq

. 18. Section 70.2 is amended: a. By adding in alphabetical order the definition of “Greenhouse gases,” b. By revising the i ntroductory text, removing “or” from the end of paragraph (2), adding “or” to the end of paragraph (3), and adding paragraph (4) to the definition of “Regulated pollutant (for presumptive fee calculation),” and c. By revising paragraph (1) to the definiti on of “Subject to regulation

. ” The revision and additions read as follows: **§ 70.2 Definitions.**

* * * * * Greenhouse gases (GHGs) means the air pollutant defined in § 86.1818

- 12(a) of this chapter as the aggregate group of six greenhouse gases: carbon dioxide, nitrous oxide, methane, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride.

* * * * * Regulated pollutant (for presumpt ive fee calculation) , which is used onl y for purposes of § 70.9(b)(2), means an y regulated air pollutant except the following:

* * * (4) Greenhouse gases.

* * * * * Subject to regulation * * * (1) Greenhouse gases shall not be subject to regulation unl ess, as of July 1, 2011, the GHG emissions are at a stationary source emitting or having the potential to emit 100,000 tpy CO 2 equivalent emissions.

* * * * * 19. Section 70.9 is amended by revising paragraph (b)(2)(i), and by adding paragraph (b)(2)(v) t o 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 retentio n of an amount not less than $25 per ye ar [as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) of this section] times the total tons of the actual emissions of each regulated pollutant (for presumptive fee calculation) emitted from part 70 sources and any GHG cost adjustment required under paragraph (b)(2)(v) of this section.Page **43** of **46**

* * * * * (v) GHG cost adjustment . The amount calculated in paragraph (b)(2)(i) of this section shall be increased b y 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 b y the average cost of staff time, including wages, employee benefits and overhead. Activity Burden hours per activity GHG completeness determination (for initial permit or updated application)

GHG evaluation for a modification or related permit action

GHG evaluation at permit renewal 43

7

10

* * * * * **PART 71**

**— FEDERAL OPERATING PERMIT PROGRAMS**  20. The authorit y citation for part 71 continues to read as follows: **Authority** : 42 U.S.C. 7401, et seq

. 21. Section 71.2 is amended: a. By adding in alphabetical order the definition of “Greenhouse gases,” b. By removing “or” from the end of paragraph (2), adding “or” to the end of paragraph (3), and adding paragraph (4) to the definition of “Regulated pollutant (for fee calculation),” and c. By re vising paragraph (1) of the definition of “Subject to regulation.” The revisions and additions read as follows: **§ 71.2**  **Definitions.**

* * * * * Greenhouse gases (GHGs) means the air pollutant defined in § 86.1818

- 12(a) of this chapter as the aggregate grou p 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 an y “regulated air po llutant” except the following:Page **44** of **46**

* * * * * (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 CO 2 equivalent emissions.

* * * * * 22. Section 71.9 is amended by : a. Revising paragraphs (c)(1), (c)(2)(i), (c)(3), and (c)(4), and b. Adding paragraph (c)(8). The revisions and additions read as follows: **§ 71.9**  **Permit fees.** 

* * * * * (c) * * * (1) For part 71 programs that are administered by EPA, each part 71 source shall pay an annual fee which is the sum of: (i) $32 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive emissions; and (ii) Any GHG fee adjustment required under paragraph (c)(8) of this section. (2) * * * (i) Where the EPA has not suspended its part 71 fee collection pursuant to paragraph (c)(2)(ii) of this section, the annual fee for each part 71 source shall be the sum of: (A) $24 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section ) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive emissions; and (B) An y GHG fee adjustment required under paragraph (c)(8) of this section.

* * * * * (3) For part 71 programs that are administered by EPA with contractor assistance, the per ton fee shall vary

depending on the extent of contractor involvement and the cost to EPA of contractor assistance. The EPA shall establish a per ton fee that is based on the contractor costs for the specific part 71 program that is being administered, using the following formula: Cost per ton=( E ×32)+[(1 − E )×$ C ] Where E represents EPA's proportion of total effort (expressed as a percentage of total effort) needed to administer the part 71 program, 1

- E represents the contractor's effort, and C represents the contractor assistance cost on a per ton basis. C shall be computed by using the following formula:Page **45** of **46**

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 par agraph (c)(8) of this section. (4) For programs that are delegated in part, the fee shall be computed using the following formula: Cost per ton=( E ×32)+( D ×24)+[(1 − E − D )×$ C ] Where E and D represent, respectivel y, the EPA and delegate agency proport ions 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 formul a 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 th e set fee provided in the table for each activity that has been initiated since the fee was last paid:

Activity Set fee GHG completeness determination (for initial permit or updated application)

GHG evaluation for a permit modification or related permit action

GHG evaluation at permit renewal $2,236

$364

$520

* * * * * **PART 98**

**— MANDATORY GREENHOUSE GAS REPORTING**  23. The authorit y citation for part 98 is revised to read as follows: Authority : 42 U.S.C. 7401

- 7671q. **Subpart PP**

**— Suppliers of Carbon Dioxide**  24. Section 98.426 is amended b y adding paragraph (h) to read as follows:Page **46** of **46**

**§ 98.426 Data reporting requirements.**

* * * * * (h) If you capture a CO 2 stream from an electricity generating unit that is subject to subpart D of this part and transfer CO 2 to any facilities that are subject to subpart RR of this part, yo u must: (1) Report the facility

identification number associated with the annual GHG rep ort for the facility

that is subject to subpart D of this part, (2) Report each facility

identification number associated with the annual GHG reports for each facility

that is subject to subpart RR of this part to which CO 2 is transferred, and (3) Report the annual quantity of CO 2 in metric tons that is transferred to each facility that is subject to subpart RR of this part. 25. Section 98.427 is amended b y adding paragraph (d) to read as follows: **§ 98.427 Records that must be retained.**

* * * * * (d) Faci lities subject to § 98. 426(h) must retain records of CO 2 in metric tons that is transferred to each facility that is subject to subpart RR of this part.