Page **1** of **60**

For the reasons stated in the preamble, title 40, chapter I, part 60, 70, 71, and 98 of the Code of the Federal Regulations is amended as follows: **PART 60 --**  **STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES**  1. The authority citation for part 60 continues to read as follows: Authority: 42 U.S.C. 7401, et seq. 2 . Part 60 is amended by adding subpart TTTT to read as follows: **Subpart TTTT Standards of Performance for Greenhouse Gas Emissi** **ons for Electric Generating Units** Sec. **Applicability** § 60.5508 What is the purpose of this subpart? § 60.5509 Am I subject to this subpart? **Emission Standards** § 60.5515 Which greenhouse gases are regulated by this subpart? § 60.5520 What CO 2 emissions standard must I meet? **General Compliance Requirements** § 60.5525 What are my general requirements for complying with

this subpart? **Monitoring and Compliance Determination Procedures** § 60.5535 How do I monitor and collect data to demonstrate

compliance? § 60.5540 How do I demonstrate compliance with my CO 2 emissions

standard and determine excess emissions? **Notifications, Reports, and Records**Page **2** of **60**

§ 60.5550 What notifications must I submit and when? § 60.5555 What reports must I submit and when? § 60.5560 What records must I maintain ? § 60.5565 In what form and how long must I keep my records? **Other Requirements and Information** § 60.5570 What parts of the General Provisions apply to my affected EGU ? § 60.5575 Who implements and enforces this subpart? § 60.5580 What definitions apply to this subpart? **Applicability §**  **60.5508 What is the purpose of this subpart?** This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a steam generating unit, IGCC, or a stationary combustion turbine that commences construction after January 8, 2014 or commences modification or reconstruction after June 18, 2014 . An affected steam generating unit, IGCC, or stationary combustion turb ine shall, for the purposes of this subpart, be referred to as an affected EGU. **§ 60.5509 Am I subject to this subpart?**  (a) Except as provided for in paragraph (b) of this section, the GHG standards included in this subpart appl y to any steam generating unit, IGCC, or stationary combustion turbine that commenced construction after January 8, 2014 or commenced modification or reconstruction after June 18, 2014 that meetsPage **3** of **60**

the relevant applicability conditions in paragraphs (a)(1) and (a)(2) of this section. (1) Has a base load rating greater than 260 GJ/h (250 MMBtu/h) of fossil fuel (either alone or in combination with any other fuel) , and (2) S erves a generator capable of selling greater than 25 MW of electricity to a util ity power distribution system . (b) You are not subject to the requirements of this subpart if your affected EGU meets any of the conditions specified in paragraphs (b)(1) through (b)(8 ) of this section. (1) Your EGU is a steam generating unit or IGCC that is currently and always has been subject to a federally enforceable permit condition limiting annual net - electric sales to no more than one - third o f its potential electric output or 219,000 MWh , whichever is gre ater . (2 ) Your EGU is capable of combusting 5 0 percent or more

non - fossil fuel and is also subject to a federally enforceable permit condition limiting the annual capacity factor for all fossil fuels combined of 10 percent (0.10) or less. (3) Your EGU is a combined heat and power unit that is subject to a federally enforceable permit condition limiting annual net - electric sales to no more than the product of the unit's net design efficiency and the unit's potential electric output or 219,000 MWh , whichever is greater .Page **4** of **60**

(4 ) Your EGU serves a generator along with other steam generating unit (s) , IGCC, or stationary combustion turbine (s) where the effective generation capacity (determined based on a prorated output of the base load rating of each ste am generating unit, IGCC , or stationary combustion turbine ) is 25 MW or less . (5) Your EGU is a municipal waste combustor that is subject to subpart Eb of this part. (6) Your EGU is a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part. (7) Your EGU is a steam generating unit(s) or IGCC that undergoes a modification resulting in an hourly increase in CO2 emissions (mass per hour) of 10 percent or less (2 significant figures) . Modified units that are not subject to the requirements of this subpart pursuant to this subsection continue to be existing units under section 111 with respect to CO2 emissions standards . (8 ) Your EGU is a stationary combustion turbine that is not capable of combusting natural gas (e.g., not connected to a natural gas pipeline ). **Emission Standards §**  **60.5515 Which**  **greenhouse gases are regulated by this subpart?** (a) The greenhouse gas regulated by this subpart is carbon dioxide (CO 2 ). (b) PSD and Title V Thresholds for Greenhouse Gases.Page **5** of **60**

(1) For the purposes of 40 CFR § 51.166(b)(49)(ii) , with respect to GHG emissions from affected facilities , the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, § 51.166(b)( 48) of this chapter . (2) For the purposes of 40 CFR § 52.21(b)(50)(ii) , with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 52.21(b)(49) of this chapter . (3) For the purposes of 40 CFR § 70.2 of this chapter , with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR § 70.2 of this chapter . (4) For the purposes of 40 CFR § 71.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutantPage **6** of **60**

that otherwise is "subject to regulation" as defined in 40 CFR § 71.2 of this chapter . **§ 60.5520 What CO** **2 emission standard must I meet?**  (a) For each affected EGU subject to this subpart, you must not discharge from the affected EGU any gases that contain CO 2 in excess of the applicable CO 2 emission standard specified in Table 1 or Table 2 of this subpart , consistent with paragraphs (b) and (c) of this section, as applicable . (b) Except as specified in paragraph (c) of the section, you must comply with the applicable gross energy output standard and your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable gross energy output standard . For the remainder of this subpart, where the term “gross or net energy output” is used, the term that applies to you is “gross energy output.” ( c ) As an alternate to meeting the requirements in paragraph (b) of this section, an owner or operator of a stationary combustion turbine may petition the Administrator in writing to comply with the alternate applicable net energy output standard . If the Administrator grants the petition , beginning on the date the Administrator grants the petition , the

source must comply with the applicable net energy output based standard included in this subpart. Your operating permit must include monitoring, recordkeeping, and reporting methodologiesPage **7** of **60**

based on the applicable net energy output standard . For the remainder of this subpart, where the term “gross or net energy output” is used, the term that applies to you is “net energy output.” Owners or operators complying with the net output based standard must petition the Administrator to switch back to complying with the gross energy output based standard . **General Compliance Requirements §**  **60.5525 What are my general requirements for complying with**  **this subpart?** Compliance with the applicable CO 2 emission standard of this subpart shall be determined on a 12

- operating month rolling average basis. See Tables 1

- 2 for the applicable CO 2 emission standards. (a) You must be in compliance with the emission standards in this subpart that apply to your affected EGU at all times. However, you must determine compliance with the emission standards only at the end of the applicable operating month, as provided in paragraph (a)(1) . (1) For each affected EGU subject to a CO 2 emissions standard based on a 12

- operating month rolling average, you must determine compliance monthly by calculating the average CO 2 emissions rate for the affected EGU at the end of the initial and each subsequent 12

- operating month period . (2) For each affected EGU subject to the CO 2 emissionsPage **8** of **60**

standard for multi

- fuel units, you must determine the total heat input in million Btu’s (MMBtu) from natural gas (HTIPng ) and the total heat input from all other fuels combined (HTIP o ) using one of the methods under § 60.5535(d)(2) . You must then use the following equation to determine the applicable emissions standard (EL) during the compliance period:

emission	standard = 120 x HTIP + (160 x HTIP ) Total	Heat	Input	from	All	Fuels Where: CO 2 emission standard = the emission standard during the

compliance period in units of lb/MMbtu . HTIPng = the heat input in MMBtu from natural gas during the

compliance pe riod. HTIP o = the heat input in MMBtu from all fuels other than

natural gas that were fired during the compliance period. 120 = allowable emission rate in lbs of CO2/MMBtu for heat

input derived from natural gas. 160 = allowable emission rate in lbs of CO2/MMBtu for heat

input derived from all fuels other than natural gas. (b) At all times you must operate and maintain each affected EGU , including associated equipment and monitoring equipment, in a manner consistent with safety and good airPage **9** of **60**

pollution control practice. The Administrator will determine if you are using consistent operation and maintenance procedures based on information available to the Administrator that may include, but is not limited to, fuel use records, monitoring results, review of operation and maintenance procedures and records, review of reports required by this subpart, and inspection of the EGU . (c) Within 30 days after the end of the initial compliance period (i.e., no more than 30 days after the first 12

- operating

month compliance period ), you must make an initial compliance determination for your affected EGU(s) with respect to the applicable emissions standard in Table 1 or Table 2 of this subpart, in accordance with the requirements in this subpart. The first operating month included in the initial 12

- operating month compliance period shall be determined as follows: (1) For an affected EGU that commences commercial operation (as defined in §72.2 of this chapter) on or after the effective date of this rule, the fir st month of the initial compliance period shall be the first operating month (as defined in §60.5580) after the calendar month in which emissions reporting is required to begin under: (i) §63.5555(c)(3)(i), for units subject to the Acid Rain Program; or ( ii) §63.5555(c)(3)(ii)(A), for units that are not in thePage **10** of **60**

Acid Rain Program. (2) For an affected EGU that has commenced commercial operation (as defined in §72.2 of this chapter) prior to the effective date of this rule: (i) If the date on which emissions reporting is required to begin under §75.64(a) of this chapter has passed prior to the effective date of this rule, emissions reporting shall begin according to §63.5555(c)(3)(i) (for Acid Rain program units), or according to §63.5555(c)(3)(ii)(B) (for unit s that are not subject to the Acid Rain Program). The first month of the initial compliance period shall be the first operating month (as defined in §60.5580) after the calendar month in which the rule becomes effective; or (ii) If the date on which emissi ons reporting is required to begin under §75.64(a) of this chapter occurs on or after the effective date of this rule, then the first month of the initial compliance period shall be the first operating month (as defined in §60.5580) after the calendar month in which emissions reporting is required to begin under §63.5555(c)(3)(ii)(A). (3) For a modified or reconstructed EGU that becomes subject to this subpart, the first month of the initial compliance period shall be the first operating month (as defined in §60.5580) after the calendar month in which emissions reporting is required to begin under §63.5555(c)(3)(iii).Page **11** of **60**

**Monitoring and Compliance Determination Procedures**  **§ 60.5535 How do I monitor and collect data to demonstrate**  **compliance?** (a) You must prepare a monitoring plan to quantify the hourly CO 2 mass emission rate (tons/hr), in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter. The electronic portion of the monitoring plan must be submitted using the ECMPS Client Tool and must be in place prior to reporting emissions data and/or the results of monitoring system certification tests under this subpart. The monitoring plan must be updated as necessary. Monitoring plan submittals must be made by the Designated Representative (DR), the Alternate DR, or a delegated agent of the DR (see §60.5555(c) ) . (b) You must determine the hourly CO 2 mass emissions in kilograms (kg) from your affected EGU(s) according to paragraphs (b)(1) through (5) of this section, or, if applicable, as provided in paragraph (c) of this section. (1) For an affected coal

- fired EGU or for an IGCC unit you must, and for all other affected EGUs you may, install, certify, operate, maintain, and calibrate a CO 2 conti nuous emission monitoring system (CEMS) to directly measure and record hourly average CO 2 concentrations in the affected EGU exhaust gases emitted to the atmosphere, and a flow monitoring system to measure hourly average stack gas flow rates, according toPage **12** of **60**

§ 75.10(a)(3)(i) of this chapter. As an alternative to direct measurement of CO 2 concentration, provided that your EGU does not use carbon separation (e.g., carbon capture and storage), you may use data from a certified oxygen (O 2 ) monitor to calculate hourly average CO 2 concentrations, in accordance with §75.10(a)(3)(iii) 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 system, according to § 75.11(b) of this chapter. Alternatively, you may either use an appropriate fuel

- specific default moisture value from §75.11(b) or submit a petition to the Administrator under §75.66 of this chapter for a site

specific default moisture value. (2) For each continuous 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 A and B to part 75 of this chapter. ( 3 ) You must use only unadjusted exhaust gas volumetric flow rates to determine the hourly CO 2 mass emissions rate from the affected EGU ; you must not apply the bias adjustment factors described in Section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data. ( 4 ) You must select an appropriate reference method to setup (characterize) the flow monitor and to perform the on

-Page **13** of **60**

going RATAs, in accordance with part 75 of this chapter. If you use a Type - S pitot tube or a pitot tube assembly for the flow RATAs, you must calibrate the pitot tube or pitot tube assembly; you may not use the 0.84 default Type

- S pitot tube coefficient specified in Method 2. ( 5 ) Calculate the hourly CO 2 mass emissions (kg) as described in paragraphs (a)(6)(i) through (iv) of this section. Perform this calculation only for “valid operating hours”, as defined in §60.5540(a)(1). (i) Begin with the hourly CO 2 mass emission rate (tons/hr), obtained either from Equation F

- 11 in Appendix F to part 75 of this chapter (if CO 2 concentration is measured on a wet basis), or by following the procedure in section 4.2 of Appendix F to part 75 of this chapter (if CO 2 concentration is measured on a dry basis). (ii) Next, multiply each hourly CO 2 mass emission rate by the EGU or stack operating time in hours (as defined in §72.2 of this chapter), to convert it to tons of CO 2. (iii) Finally, multiply the result from paragraph (b)(5)(ii) of this section by 909.1 to convert it from tons of CO 2 to kg. Round off to the nearest kg. (iv) The hourly CO 2 tons/hr values and EGU (or stack) operating times used to calculate CO 2 mass emissions are required to be recorded under §75.57(e) of this chapter and must bePage **14** of **60**

reported electronically under §75.64(a)(6). You must use these data to calculate the hourly CO 2 mass emissions. (c) If your affected EGU exclusively combusts liquid fuel and/or gaseous fuel as an alternative to complying with paragraph (b) of this section, you may determine the hourly CO 2 mass emissions according to paragraphs (c)(1) through (4) of this section. (1) You must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly EGU heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted. (2) For each measured hourly heat input rate, use Equation G- 4 in Appendix G to part 75 of this chapter to calculate the hourly CO 2 mass emission rate (tons/hr). 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. (3) For each “valid operating hour” (as defined in §60.5540(a) (1), multiply the hourly tons/h CO 2 mass emission rate from paragraph (c)(2) of this section by the EGU or stack operating time in hours (as defined in §72.2 of this chapter), to convert it to it to tons of CO 2 . Then, multiply the result byPage **15** of **60**

909.1 to convert from tons of CO 2 to kg. Round off to the nearest two significant figures . (4) The hourly CO 2 tons/h values and EGU (or stack) operating times used to calculate CO 2 mass emissions are required to be recorded under §75.57(e) of this chapter and must be reported electronically under §75.64(a)(6) You must use these data to calculate the hourly CO 2 mass emissions. (d) Consistent with § 60.5520, you must determine the basis of the emissions standard that applies to your affected source in accordance with either paragraph (d)(1) or (d)(2) , as applicable: (1) If you operate a s ource subject to an emissions standard established on an output basis (e.g., lbs of CO2 per gross or net MWh of energy output) , you must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record the hourly gross electric output or net electric output, as applicable, from the affected EGU(s) . These measurements must be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. For a combined heat and power ( CHP ) EGU , as defined in §60.5580 , you must also install, calibrate, maintain, and operate meters to continuously (i.e., hour

-by

-hour) determine and record the total useful thermal output . For process steam applications, you will need toPage **16** of **60**

install, calibrate, maintain, and operate meters to continuously determine and record the hourly steam flow rate, temperature, and pressure. Your plan shall ensure that you install, calibrate, maintain, and operate meters to record each component of the determination , hour

-by

-hour . (2) If you operate a source subject to an emissions standard established on a heat

- input basis (e.g., lbs of CO2 per MMBtu of heat input), you must determine the total heat input for each fuel fired during the compliance period in accordance with one of the following procedures: (i) Appendix D to Part 75 ; (ii) The procedures for monitoring heat input under of 40 CFR 60.107a(d); or (iii)The procedure for monitoring heat input under 40 CFR 98. 33(a)(2) or (a)(3). (e) Consistent with § 60.5520, if two or more affected EGUs serve a common electric generator, you must apportion the combined hourly gross or net energy output to the individual affected EGU s according to the fraction of the total steam load contributed by each EGU . Alternatively, if the EGU s are identical, you may apportion the combined hourly gross or net electrical load to the individual EGUs according to the fraction of the total heat input contributed by each EGU .Page **17** of **60**

(f) In accordance with § 60.13(g) and § 60.5520 , if two or more affected EGUs that implement the continuous emission monitoring provisions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard in Table 1 or Table 2 of this s ubpart , you may monitor the hourly CO 2 mass emissions at the common stack in lieu of monitoring each EGU separately. If you choose this option, the hourly gross or net energy output (electric, thermal, and/or mechanical, as applicable) must be the sum of the hourly loads for the individual affected EGUs and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter). If you attain compliance with the applicable emissions standard in § 60.5520 at the common stack, each affected EGU sharing the stack is in compliance. (g) In accordance with § 60.13(g ) and § 60.5520 if the exhaust gases from an affected EGU that implements the continuous emission monitoring provisions in paragraph (b) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly CO 2 mass emissions and the “stack operating time” (as defined in § 72.2 of this chapter) at each stack or duct separately. In this case, you must determine compliance with the applicable emissions standard in Table 1 orPage **18** of **60**

2 of this s ubpart by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the total gross or net energy output for the affected EGU . (h) Heat rate determination and design efficiency for combustion turbines . In accordance with xxxx , you must use an appropriate standard method published by a consensus

-based standards organization if such a method exist s or you may use an industry standard practice. Consensus

-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American S ociety of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB). ] Acceptable methods include [but are not limited to] the following testing and analytical methods: (1) ASME PTC 6

- 2004 Steam Turbines (incorporated by reference, see §60. 17 ). (2) ASME PTC 6S Procedures for Routine Performance Test of Steam Turbines (incorporated by reference, see §60.17) . (3) ASME PTC 6.2

- 2011 Steam Turbines in Combined Cycles (incorporated by reference, s ee §60.17) . (4) ASME PTC 22 Gas Turbines (incorporated by reference, see §60.17) .Page **19** of **60**

(5 ) ASME PTC 46 Overall Plant Performance (incorporated by reference, see §60.17). ( 6 ) ISO 2314:2009 Gas turbines

– acceptance tests (incorporated by reference, see §60.17) . (7 ) DIN 1943 Thermal Acceptance of steam turbines (incorporated by reference, see §60.17) . ( 8) IEC - 953

- 2 Rules for steam turbine thermal acceptance tests. Part 2: Method B

- Wide range of accuracy for various types and sizes of turbines (incorporated by re ference, see §60.17) . **§60.5540 How do I demonstrate compliance with my CO** **2 emissions**  **standard?** (a) In accordance with § 60.5520, t o demonstrate compliance with the applicable CO 2 emission standard in Table 1 or 2 of this subpart, for the initial and each subsequent 12

- operating month rolling average compliance period, you must follow the procedures in paragraphs (a)(1) through (a)(7) of this section to calculate the CO 2 mass emissions rate for your affected EGU(s) in units of the applicable emissions standard ( i.e., either kg/MWh or lb /MMBtu ). You must use the hourly CO 2 mass emissions and either the generati ng load data from §60.5535 (d)(1) or the heat input data from §60.5535 (d)(2) in the calculations.Page **20** of **60**

(1) Each compliance period shall include only “va lid operating hours” in the compliance period, i.e., operating hours for which: (i) “Valid data” (as defined in §60.5580) are obtained for all of the parameters used to determine the hourly CO 2 mass emissions (kg) and, if a heat input based standard appli es , all the parameters used to determine total heat input for the hour are also obtained ; and (ii) The corresponding hourly gross or net energy output value is also valid data ( Note : for hours with no useful output, zero is considered to be a valid value). (2) You must exclude operating hours in which: (i) The substitute data provisions of part 75 of this chapter are applied for any of the parameters used to determine the hourly CO 2 mass emissions or , if a heat input based standard applies, for any parameters used to determine the hourly heat input ; or ( ii) An exceedance of the full

- scale range of a continuous emission monitoring system occurs for any of the parameters used to determine the hourly CO 2 mass emissions or, if applicable, to determine the hourly heat input ; or (iii) The total gross or net energy output (P gross /net ) or, if applicable, the total heat input is unavailable.Page **21** of **60**

(3) For each compliance period , at least 95 percent of the operating hours in the compliance period must be valid operating hours, as defined in paragraph (a)(1) of this section. ( 4 ) You must calculate the total CO 2 mass emissions by summing the valid hourly CO 2 mass emissions values from §60.5535 for all of the valid operating hours in the compliance period. ( 5 ) Sources subject to output based standards. For each valid operating hour of the compliance period that was used in paragraph (a)( 4 ) of this section to calculate the total CO 2 mass emissions, you must determine P gross /net ( the corresponding hourly gross or net energy output in MWh ) according to the procedures in paragraphs (a)(3)(i) and (ii) of this section, as appropriate for the type of affected EGU(s) . For an operating hour in which

a valid CO 2 mass emissions value is determined according to paragraph (a)(1)(i) of this section, if there is no gross or net electrical output , but there is mechanical or useful thermal output, you must still determine the gross or net energy output for that hour. In addition, for an operating hour in which a valid CO 2 mass emissions value is determined according to paragraph (a)(1)(i) of this section, but there is no (i.e., zero) gross electrical, mechanical, or useful thermal output, you must us e that hour in the compliance determination . For hours or partial hours where the gross electric output is equalPage **22** of **60**

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 EGU using the following equation. All terms in the equation must be expressed in units of megawatt

-hours (MWh). To convert each hourly gross or net energy output ( Consistent with § 60.5520) value reported under part 75 of this chapter to MWh, multiply by the corresponding EGU or stack operating time.

/ = ( ) + ( ) + ( )

− ( ) TDF + [ ( ) + ( ) + ( ) ] Where: a P gross/net = In accordance with § 60.5520, gross or net energy

output of your affected EGU for each valid operating hour (as defined in 60.5540(a)(1)) in MWh. (Pe) ST = Electric energy output plus mechanical energy

output (if any) of steam turbines in MWh. (Pe) CT = Electric energy output plus mechanical energy

output (if any) o f stationary combustion turbine(s) in MWh. (Pe) IE = Electric energy output plus mechanical energy

output (if any) of your affected EGU’s integrated equipment that provides electricity or mechanical energy to the affected EGU or auxiliary equipmentPage **23** of **60** in MWh. (Pe) FW = Electric energy used to power boiler feedwater

pumps at steam generating units in MWh. Not applicable to stationary combustion turbines, IGCC EGUs, or EGUs complying with a net energy output based standard. (Pt) PS = Useful thermal output of steam (measured relative

to SATP conditions, as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected EGU. This is calculated using the equation specified in paragraph (a)(5)(ii) of this section in MWh. (Pt) HR = Non steam useful thermal output (measured

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

conditions, as applicable) from any integrated equipment is used for applications that do not generate additional steam, electricity, produce mechanical energy output, or enhance the performance of the affected EGU in MWh.Page **24** of **60**

T DF = Electric Transmission and Distribution Factor of

0.95 for a combined heat and power affected EGU where at least on an annual basis 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12

- operating month rolling average basis , or 1.0 for all other affected EGUs.

(ii) If applicable to your affected EGU (for example, for combined heat and power) , you must calculate (Pt) PS using the following equation: ( ) = ×

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

(lb)) for the operating hour. H = Enthalpy of the steam at measured temperature and

pressure (relative to SATP conditions or the energy in the condensate return line , as applicable) in Joules per kilogram (J/kg) (or Btu/lb). CF = Conversion factor of 3.6 x 10 9 J/MWh or 3.413 x 10 6Page **25** of **60** Btu/MWh.

( 6 ) Calculation of annual basis for standard. Sources complying with energy output

-based standards must calculate the basis (i.e., denominator) of their actual annual emission rate in accordance with paragraph (6)(i). Sources complying with heat input based standards must calculate the basis of their actual annual emission rate in accordance with paragraph (6)(ii). (i) In accordance with § 60.5520 if you are subject to an output based standard , you must calculate the total gross or net energy output for the affected EGU’s compliance peri od by summing the hourly gross or net energy output values for the affected EGU that you determined under paragraph (a)( 5 ) of this section for all of the valid operating hours in the applicable compliance period. (ii) If you are subject to a heat input bas ed standard, you must calculate the total heat input for each fuel fired during the compliance period. The calculation of total heat input for each individual fuel must include all valid operating hours and must also be consistent with any fuel

- specific procedures specified within your selected monitoring option under § 60.55 35(d)(2). ( 7 ) If you are subject to an output based standard, you must calculate the CO 2 mass emissions rate for the affectedPage **26** of **60**

EGU(s) (kg/MWh) by dividing the total CO 2 mass emissions value calculated according to the procedures in paragraph (a)( 4 ) of this section by the total gross or net energy output value calculated according to the procedures in paragraph (a)( 6 ) (i) of this section. Round off the result to two signif icant figures . If you are subject to a heat input based standard, you must calculate the CO2 mass emissions rate for the affected EGU(s) (lb /MMBtu) by dividing the total CO2 mass emissions value calculated according to the procedures in paragraph (a)(4) of this section by the total heat input calculated according to the procedures in paragraph (a)(6) (ii) of this section. Round off the result to two significant figures. (b) In accordance with § 60.5520, to demonstrate compliance with the applicable CO 2 emission standard, for the initial and each subsequent 12

- operating month compliance period, the CO 2 mass emissions rate for your affected EGU must be determined according to the procedures specified in paragraph (a)(1) through (7) of this section and must be less than or equal to the applicable CO 2 emissions standard in Table 1 , Table 2 , or the emissions standard calculated in accordance with § 60.5525(a)(2) of this subpart. **Notification, Reports, and Records §**  **60.5550 What notifications must I submit and when?**  (a) You must prepare and submit the notificationsPage **27** of **60**

specified in § 60.7(a)(1) and (a)(3) and § 60.19, as applicable to your affected EGU(s) (see Table 3 of this Subpart) . (b) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable to your affected EGUs . **§ 60.5555 What reports must I submit and**  **when ?**  (a) You must prepare and submit reports according to paragraphs (a) through (d) of this section, as applicable. (1) For affected EGUs that are required by § 60.5525 to conduct initial and on

- going compliance determinations on a 12

- operating month rolling average basis , you must submit electronic quarterly reports as follows. After you have accumulated the first 12

- operating months for the affected EGU , you must submit a report for the calendar quarter that includes the twelfth operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 days after the end of the quarter. (2) In each quarterly report you must include the following information, as applicable: (i) Each rolli ng average CO 2 mass emissions rate for which the last ( twelfth) operating month in a 12

- operating month compliance period falls within the calendar quarter. You must calculate each average CO 2 mass emissions rate for the compliance period according to the procedures in § 60.5540. You must reportPage **28** of **60**

the dates (month and year) of the first and twelfth 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

where your EGU violated the applicable CO 2 emission s tandard ; (iii) If one or more compliance periods end in the quarter and there are no violations for the affected EGU, you must include a statement indicating this in the report; ( iv ) The percentage of valid operating hours in each 12

- operating month compliance period described in paragraph (a)(1)(i) of this section (i.e., the total number of valid operating hours (as defined in §60.5540(a)(1)) in that period divided by the total number of operating hours in that period, multiplied by 100 percent); (v) Consistent with § 60.5520, the CO 2 emissions standard (as identified in Table 1 or 2 ) with which your affected EGU must comply ; and ( vi ) Consistent with § 60.5520, an indication whether or not the hourly gross or net energy output (P gross /net ) values used in the compliance determinations are based solely upon gross electrical load.Page **29** of **60**

(3) In the final quarterly report of each calendar year, you must include the following: (i) Consistent with § 60.5520, gross energy output or net energy output so ld to an electric grid over the 4 quarters of the calendar year ; and (ii) The potential electric output of the EGU . (b) You must submit all electronic reports required under paragraph (a) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of EPA. (c) (1) For affected EGUs under this subpart that are also subject to the Acid Rain Program, you must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter. (2) For affected EGU s under this subpart that are not in the Acid Rain Program, you must also meet the reporting requirements and submit reports as required under subpart G of part 75 of this chapter , to the extent that those requirements and reports provide applicable data for the compliance demonstrations required under this subpart. (3) (i) For all newly

- constructed affected EGUs under this subpart that are also subje ct to the Acid Rain Program, you must begin submitting the quarterly electronic emissions reportsPage **30** of **60**

described in paragraph (c)(1) of this section in accordance with §75.64(a), i.e., beginning with data recorded on and after the earlier of: (A) The date of p rovisional certification, as defined in §75.20(a)(3) of this chapter; or (B) 180 days after the date on which the EGU commences commercial operation (as defined in §72.2 of this chapter). (ii) For newly

- constructed affected EGUs under this subpart that are not subject to the Acid Rain Program, you must begin submitting the quarterly electronic reports described in paragraph (c)(2) of this section, beginning with data recorded on and after: (A) The date on which reporting is required to begin under §75.64 (a), if that date occurs on or after the effective date of this rule; or (B) The effective date of this rule, if the date on which reporting would ordinarily be required to begin under §75.64(a) has passed prior to the effective date of this rule. (iii) For reconstructed or modified units, reporting of emissions data shall begin at the date on which the EGU becomes an affected unit under this subpart, provided that the ECMPS Client Tool is able to receive and process net energy output data on that date. Otherwise, emissions data reporting shall be on a gross energy output basis until the date that the ClientPage **31** of **60**

Tool is first able to receive and process net energy output data. (4) If any required monitoring system has not been provisionally certif ied by the applicable date on which emissions data reporting is required to begin under paragraph (c)(3) of this section, the maximum (or in some cases, minimum) potential value for the parameter measured by the monitoring system shall be reported until the required certification testing is successfully completed, in accordance with §75.4(j) of this chapter, §75.37(b) of this chapter, or section 2.4 of appendix D to part 75 of this chapter (as applicable). Operating hours in which CO 2 mass emission rates a re calculated using maximum potential values are not “valid operating hours” (as defined in §60.5540(a)(1)), and shall not be used in the compliance determinations under §60.5540. (d) For affected EGU s subject to the Acid Rain Program, the reports required under paragraphs (a) and (c)(1) of this section shall be submitted by: (1) The person appointed as the Designated Representative (DR) under §72.20 of this chapter; or (2) The person appointed as the Alternate Designated Representative (ADR) under §72.22 o f this chapter; or (3) A person (or persons) authorized by the DR or ADR under §72.26 of this chapter to make the required submissions.Page **32** of **60**

(e) For affected EGU s that are not subject to the Acid Rain Program, the owner or operator shall appoint a DR and (optional) an ADR to submit the reports required under paragraphs (a) and (c)(2) of this section. The DR and ADR must register with the Clean Air Markets Division (CAMD) Business System. The DR may delegate the authority to make the required submissions to one or more persons. ( f ) If your affected EGU captures CO 2 to meet the applicable emission limit, you must report in accordance with the requirements of 40 CFR Part 98 Subpart PP and either: (1) Report in accordance with the requirements of 40 CFR Part 98 subpart RR , if injection occurs on

- site , or (2) T ransfer the captured CO 2 to an EGU or facilit y that reports in accordance with the requirements of 40 CFR Part 98 subpart RR , if injection occurs off

- site . (3 ) Transfer the captured CO 2 to a facility that has received an innovat ive technology waiver from EPA pursuant to paragraph (g) of this section. (g) Any person may request the Administrator to issue a waiver of the requirement that captured CO 2 from an affected EGU be transferred to a facility reporting under 40 CFR Part 98 subpart RR. To receive a waiver, the applicant must demonstrate to the Administrator that its technology will store captured CO 2 as effectively as geologic sequestration, and that the proposedPage **33** of **60**

technology will not cause or contribute to an unreasonable risk to public health, welfare, or safety. In making this determination, the Administrator shall consider (among other factors) operating history of the technology, whether the technology will increase emissions or other releases of any pollutant other than CO 2 , and permanence of the CO 2 storage. The Administrator may test the system itself, or require the applicant to perform any tests considered by the Administrator to be necessary to show the technology’s effectiveness, safety, and ability to store captured CO 2 without release. The Administrator may grant conditional approval of a technology, the approval conditioned on monitoring and reporting of operations. The Administrator may also withdraw approval of the waiver on evidence of releases of CO 2 or other pollutants. The Administrator will provide notice to the public of any application under this provision, and provide public notice of any proposed action on a petition be fore the Administrator takes final action. **§ 60.5560 What records must**  **I maintain?** (a) You must maintain records of the information you used to demonstrate compliance with this subpart as specified in § 60.7 (b) and (f). (b) (1) For affected EGUs subject to the Acid Rain Program, you must follow the applicable recordkeeping requirements andPage **34** of **60**

maintain records as required under subpart F of part 75 of this chapter. (2) For affected EGU s that are not subject to the Acid Rain Program, you must also foll ow the recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter , to the extent that those records provide applicable data for the compliance determinations required under this subpart. Regardless of the prior sentence, at a minimum, the following records must be kept, as applicable to the types of continuous monitoring systems used to demonstrate compliance under this subpart: (i) Monitoring plan records under §75.53(g) and (h) of this chapter; (ii) Operating parameter records under §75.57(b)(1) through (b)(4) of this chapter; (iii) The records under §75.57(c)(2) of this chapter, for stack gas volumetric flow rate; (iv) The records under §75.57(c)(3) for continuous moisture monitoring systems; (v) The records under §75.57(e)(1), except for paragraph (e)(1)(x), for CO 2 concentration monitoring systems or O 2 monitors used to calculate CO 2 concentration; (vi) The records under §75.58(c)(1), paragraphs (c)(1)(i), (c)(1)(ii), and (c)(1)(viii) through (c)(1)(xiv), for oil flowPage **35** of **60**

meters; (vii) The records under §75.58(c)(4), paragraphs (c)(4)(i), (c)(4)(ii), (c)(4)(iv), (c)(4)(v), and (c)(4)(vii) through (c)(4)(xi), for gas flow meters; (viii) The quality

- assurance records under §75.59(a) of this chapter, paragraphs (a)(1 ) through (a)(12) and (a)(15), for CEMS; (ix) The quality

- assurance records under §75.59(a) of this chapter, paragraphs (b)(1) through (b)(4), for fuel flow meters; and (x) Records of data acquisition and handling system (DAHS) verification under §75.59(e) of this chapter. (c) You must keep records of the calculations you performed to determine the hourly and total CO 2 mass emissions ( tons ) for: (1) Each operating month (for all affected EGU s); (2) Each compliance period, including, each 12

- operating month compliance period. (d) Consistent with § 60.5520 , you must keep records of the applicable data recorded and calculations performed that you used to determine your affected EGU’s gross or net energy output for each operating month. (e) You must keep records of the calculations you performed to determine the percentage of valid CO 2 mass emission rates in each compliance period.Page **36** of **60**

(f) You must keep records of the calculations you performed to assess compliance with each applicable CO 2 mass emissions standard in Table 1 or 2 of this s ubpart . (g) You must keep records of the calculations you performed to determine any site

- specific carbon

-based F

- factors you used in the emissions calculations (if applicable). **§ 60.5565 In what form and how long must I kee** **p my records?** (a) Your records must be in a form suitable and readily available for expeditious review. (b) You must maintain each record for 3 years after the date of conclusion of each compliance period . (c) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. Records that are accessible from a central location by a computer or other means that instantly provide access at the site meet this requirement. You may maintain the records off site for the remaining year(s) as required by this subpart. **Other Requirements and Information §**  **60.5570 What parts of the General Provisions apply to my**  **affected EGU** **?** Notwithstanding any other provision of this chapter, certain parts of the General Provisions in § 60.1 through 60.19, listed in Table 3 to this subpart, do not apply to your affectedPage **37** of **60**

EGU . **§ 60.5575 Who implements and enforces this**  **subpart?** (a) This subpart can be implemented and enforced by the EPA, or a delegated authority such as your state, local, or tribal agency. If the Administrator has delegated authority to your state, local, or tribal agency, then that agency (as well as the EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your state, local, or tribal agency. (b) In delegating implementation and enforcement authority of this subpart to a state, local, or tribal agency, the Administrator retains the authorities listed in paragraphs (b)(1) through (5) of this section and does not transfer them to the state, local, or tribal agency. In addition, the EPA retains oversight of this subpart and can take enforcement actions, as appropriate. (1) Approval of alternatives to the emission standards. (2) Approval of major alternatives to test methods. (3) Approval of major alternatives to monitoring. (4) Approval of major alternatives to re cordkeeping and reporting. (5) Performance test and data reduction waivers under § 60.8(b).Page **38** of **60**

**§ 60.5580 What definitions apply to this subpart?**  As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in subpart A (General Provisions of this part). Annual capacity factor means the ratio between the actual heat input to an EGU during a calendar year and the potential heat input to the EGU had it been operated for 8,760 hours during a calendar year at the base load rating . Base load rating means the maximum amount of heat input (fuel) that an EGU can combust on a steady state basis, as determined by the physical design and characteristi cs of the EGU at ISO conditions. For a stationary combustion turbine, base load rating includes the heat input from duct burners. Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference,

see § 60.17), coal refuse, and petroleum coke. Synthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to solvent

- refined coal, gasified coal (not meeting the definition of natural gas), coal

- oil mixtures, and coal

-water mixtures are included in this definition for the purposes of this subpart. Coal refuse means waste products of coal mining, physical coal cleaning, and coal preparation operations ( e.g. culm, gob,Page **39** of **60**

etc.) containing coal, matrix material, clay, and other organic and inorganic material. Combined cycle unit means an electric generating unit that

uses a stationary combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat recovery steam generating unit (HRSG) to generate additional electricity. Combined heat and power unit or CHP unit , (also known as “cogeneration”) means an electric generating unit that that use a steam- generating unit or stationary combustion turbine to simultaneously produce both electric (or mechanical) and useful thermal output from the same primary energy source. Design efficiency means the rated overall net efficiency (e.g., electric plus thermal output) on a lower heating value basis of the EGU at the base load rating and ISO conditions . Distillate oil means fuel oils that comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17); diesel fuel oil numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see § 60.17); kerosene, as defined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see § 60.17); biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see § 60.17);Page **40** of **60**

or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference,

see § 60.17). Electric Generating units or EGU means any steam generating unit, IGCC unit, or stationary combustion turbine that is subject to this rule (i.e., meets the applicability criteria) Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat. Gaseous fuel means any fuel that is present as a gas at ISO conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke

- oven gas, synthet ic gas, and gasified coal. Gross energy output means: (1) For stationary combustion turbines and IGCC, the gross electric or direct mechanical output from both the EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) plus 100 percent of the useful thermal output . (2) For steam generating units, the gross electric or mechanical output from the affected EGU(s) (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps plus 100 percent of the useful thermal output ;Page **41** of **60**

(3) For combined heat and power facilitie s where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and 20.0 percent of the total gross energy output consists of useful thermal output on a 12

- operat i ng month rolling average basis, the gross el ectric or mechanical output from the affected EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps (the electric auxiliary load of boiler feedwater pumps is not applicable to IGCC facilities), that difference divided by 0.95, plus 100 percent of the useful thermal output . Heat recovery steam generating unit (HRSG) means an EGU in which hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used with or without duct burners. Integrated gasification combined cycle unit or IGCC means a combined cycle stationary combustion turbine that is designed to burn fuels containing 50 percent (by heat input) or more solid

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

- derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the EGU during operation.Page **42** of **60**

ISO conditions means 288 Kelvin (15 o C), 60 percent relative humidity and 101.3 kilopascals pressure. Liquid fuel means any fuel that is present as a liquid at ISO conditions and includes, but is not limited to, distillate oil and residual oil. Mechanical output means the useful mechanical energy that is not used to operate the affected EGU(s) , generate electricity and/or thermal energy, or to enhance the performance of the affected EGU . Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by 745.7 then dividing by 1,000,00 0. Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal

- derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable CO 2 content or heating value. Net -electric sales meansPage **43** of **60**

(1) The gross electric sales to the utility power distribution system minus purchased power; or (2) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on an annual basis , the gross electric sales to the utility power distribution system minus purchased power of the thermal host EGU or facilities . (3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads are included when calculating net

- electric sales. (4) Electric sales that that result from a grid emergency are not included when calculating net

- electric sales . Net -electric output means: the amount of gross generation the generator(s) produces (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)), as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale). Net energy output means:Page **44** of **60**

(i) Except as provided under paragraph (ii) of this definition, the net electric or mechanical output from the affected EGU plus 100 percent of the useful thermal output; or (ii) For combined heat and power facilities where at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12

- operating month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output; Oil means crude oil or petroleum or a fuel derived from crude oil or petroleum, including distillate and residual oil, and gases derived from solid oil

- derived fuels (not meeting the definition of natural gas). Operating month means a calendar month during which any fuel is combusted in the affected EGU at any time. Petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, distillate and residual oil. Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 oF)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb . Potential electric output means 33 percent or the designPage **45** of **60**

efficiency , whichever is greater, multiplied by the base load rating (expressed in MMBtu/h) of the EGU , 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 EGU with a 100 MW (341 MMBtu/h) fossil fuel heat input capacity would have a 310,000 MWh 12 month potential electric output capacity). Solid fuel means any fuel that has a definite shape and volume, has no tendency to flow or disperse under moderate stress, and is not liquid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, and pulverized solid fuels. Stationary combustion turbine means all equipment, including but not limited to the turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, post

- combustion emission control technology, and any ancillary components and sub

components comprising any simple cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system plus any integrated equipment that provides el ectricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustionPage **46** of **60**

turbine is not self

-propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. If a stationary combustion turbine burns any solid fuel directly it is considered a steam generating unit. Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected EGU(s) or auxiliary equipment. Useful thermal output means the thermal energy made available for use in any heating application ( e .g., steam delivered to an industrial process for a heating application, including thermal cooling applications) that is not used for electric generation, mechanical output at the affected EGU, to directly enhance the performance of the affected EGU (e.g., economizer output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered useful thermal output) , or to supply energy to a pollution control device at the affected EGU . Useful thermal output for affected EGU(s) with no condensate return (or other thermal energy input to the affected EGU(s)) or where measuring the energy in the condensate (or other thermal energy input to the affected EGU(s)) would not meaningfully impact the emission rate calculat ion is measuredPage **47** of **60**

against the energy in the thermal output at SATP conditions. Affected EGU(s) with meaningful energy in the condensate return (or other thermal energy input to the affected EGU ) must measure the energy in the condensate and subtract that ene rgy relative to SATP conditions from the measured thermal output. System emergency means any abnormal system condition that the Regional Transmission Organizations (RTO), Independent System Operators (ISO) or control area Administrator determines requires immediate automatic or manual action to prevent or limit loss of transmission faci lities or generators that could adversely affect the reliability of the power system and therefore call for maximum generation resources to operate in the affected area, or for the specific affected facility to operate to avert loss of load. Valid data means quality

- assured data generated by continuous monitoring systems that are installed, operated, and maintained according to part 75 of this chapter. For CEMS, the initial certification requirements in §75.20 of this chapter and appendix A to part 75 of this chapter must be met before quality

- assured data are reported under this subpart; for on

going quality assurance, the daily, quarterly, and semiannual/annual test requirements in sections 2.1, 2.2, and 2.3 of appendix B to part 75 of this chapter must be met and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 ofPage **48** of **60**

appendix B to part 75 of this chapter apply. For fuel flow meters, the initial certification requirements in section 2.1.5 of appendix D to part 75 of this chapter must be met before quality

- assured data are reported under this subpart (except for qualifying commercial billing meters under section 2.1.4.2 of appendix D), and for on

- going quality assurance, the provisions in section 2.1.6 of appendix D to part 75 of this chapter apply (except for qualifying commercial billing meters ). Violation means a specified averaging period over which the CO 2 emissions rate is higher than the applicable emissions standard located in Table 1 or Table 2 of this subpart .Page **49** of **60**

**Table 1 of Subpart TTTT of Part 60**  **– CO** **2 Emission Standards for**  **Affected Steam Generating Units and Integrated Gasification Combined Cycle**  **F acilities that Commenced Construction after**  **January 8, 2014 and Reconstruction or Modification after June 18, 2014**  **(net energy**  **output -** **based standards are only applicable to affected**  **units subject to a federally**  **enforceable permit**  **condition limiting GHG emissions on a net**  **energy output basi** **s) Note: numerical values**  **of 1,000 or greater have a minimum of**  **3 significant figures**  **and numerical values**  **of less than 1,000 have** 

**a minimum of 2**  **significant figures Affected**  **EGU CO** **2 Emission Standard**  Newly constructed steam generating unit or integrated gas ification combined cycle (IGCC) 640 kg CO 2 /MWh of gross energy output (1,400 lb CO 2 /MWh) Reconstructed steam generating unit or IGCC that has base load rating of 2,100 GJ/h (2,000 MMBtu/h) or less 91 0 kg of CO 2 per MWh of gross energy output (2,000 lb CO 2 /MWh) Reconstructed steam generating unit or IGCC EGU that has a base load rating greater than 2,100 GJ/h (2,000 MMBtu/h) 82 0 kg of CO 2 per MWh of gross energy output (1,800 lb CO 2 /MWh) Modified steam generating or IGCC unit A unit

- specific emission limit determined by the unit’s best historical annual CO 2 emission rate (from 2002 to the date of the modification); the emission limit will be no lower than: 1. 1,800 lb CO 2 /MWh

- gross for units with a base load rating greater than 2,000 MMBtu/h ; or 2. 2,000 lb CO 2 /MWh

- gross for units with a base load rating of 2,000 MMBtu/h or less .Page **50** of **60**

**Table 2**  **of Subpart TTTT of Part 60 –**  **CO 2**  **Emission Standards f** **or Affected**  **Stationary Combustion Turbines that Commenced**  **Construction after January 8, 2014 and Reconstruction after June**  **18, 2014 (net energy outp** **ut -** **based standards are only applicable to affected**  **units subject to a federally**  **enforceable permit**  **condition limiting GHG emissions on a net energy output basi s)**  **Note: numerical values of 1,000 or greater**  **have a minimum of 3**  **significant figures and**  **numerical values of less than 1,000**  **have**

**a minimum of 2**  **significant figures Affected**  **EGU CO** **2 Emission Standard** 1 Newly constructed or reconstructed s tationary combustion turbine that supplies more than the design efficiency times the potential electric output as net

- electric sales on a 3 year rolling average basis and combusts more than 90% natural gas on a heat input basis on a 12

- operating month rolling average basis. 45 0 kg of CO 2 per MWh of gross energy output (1,000 lb CO 2 /MWh) ; or 4 7 0 kilograms (kg) of CO 2 per megawatt -hour (MWh) of net energy output (1,030 lb/MWh)

Newly constructed or reconstructed stationary combustion turbine that supplies one

- third or the design efficiency, whichever is greater, of its potential electric output or less as net

electric sales on a 3 year rolling average basis and combusts more than 90% natural gas on a heat input basis on a 12

- operating month rolling average basis. 50 kg CO2 per gigajoule (GJ) of heat input ( 120 lb CO2/MMBtu )

Stationary combustion turbine that combusts 90% or less natural gas on a heat input basis on a 12

- operating month rolling average basis. 69 kg CO2/GJ of heat input ( 160 lb/MMBtu )

1 See procedures for establishing and revising the compliance option under § 60.5520.Page **51** of **60**

**Table 3**  **to Subpart TTTT of Part 60 –**  **Applicability of Subpart A**  **General Provisions to Subpart TTTT General**  **Provisions citation**  **Subject of**

**citation Applies to**  **subpart TTTT**  **Explanation** § 60.1 Applicability Yes § 60.2 Definitions Yes Additional terms defined in § 60.5580 § 60.3 Units and

Abbreviations Yes

§ 60.4 Address Yes Does not apply to information reported electronically through ECMPS. Duplicate submittals are not required. § 60.5 Determination of

construction or modification Yes § 60.6 Review of plans Yes

§ 60.7 Notification and

Recordkeeping Yes Only the requirements to submit the notification s in 60.7(a)(1) and (a)(3) and to keep records of malfunctions in §60.7(b), if applicable § 60.8 Performance tests No § 60.9 Availability of

Information Yes § 60.10 State authority Yes § 60.11 Compliance with

standards and maintenance requirements No § 60.12 Circumvention Yes § 60.13 Monitoring

requirements No All monitoring is done according to Part 75Page **52** of **60**

§ 60.14 Modification No § 60.15 Reconstruction No § 60.16 Priority list No § 60.17 Incorporations by

reference Yes § 60.18 General control

device requirements No

§ 60.19 General

notification and reporting requirements Yes Does not apply to notifications under §75.61 or to information reported through ECMPS.Page **53** of **60**

**PART 70 —**  **STATE OPERATING PERMIT PROGRAMS** 3 . The authority citation for part 70 continues to read as follows: **Authority** : 42 U.S.C. 7401 et seq. 4 . Section 70.2 is amended by revising the introductory text, removing “or” from the end of paragraph (2), adding “or” to the end of paragraph (3), and adding paragraph (4) to the definition of “Regulated pollutant (for presumptive fee calculation).” The revision and additions read as follows: **§ 70.2 Definitions.** 

* * * * * Regulated pollutant (for presumptive fee calculation) , which is used only for purposes of § 70.9(b)(2), means any regulated air pollutant except the following:

* * * * * (4) Greenhouse gases.

* * * * * 5 . Section 70.9 is amended by revising paragraph (b)(2)(i), and by adding paragraph (b)(2)(v) to read as follows: **§ 70.9**  **Fee determination and certification.**

* * * * * (b) * * * (2)(i) The Administrator will presume that the fee schedulePage **54** of **60**

meets the requirements of paragraph (b)(1) of this section if it would result in the collection and retention of an amount not less than $25 per year [as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) of this section] times the total tons of the actual emissions of each regulated pollutant (for presumptive fee calculat ion) emitted from part 70 sources and any GHG cost adjustment required under paragraph (b)(2)(v) of this section.

* * * * * (v) GHG cost adjustment . The amount calculated in paragraph (b)(2)(i) of this section shall be increased by the GHG cost adjustment determined as follows: For each activity identified in the following table, multiply the number of activities performed by the permitting authority by the burden hours per activity, and then calculate a total number of burden hours for all activities. Next, multiply the burden hours by the average cost of staff time, including wages, employee benefits and overhead. Activity Burden hours per activity GHG completeness determination (for initial permit or updated application) GHG evaluation for a permit modification or related permit action 43

7Page **55** of **60**

GHG evaluation at permit renewal 10

* * * * * **PART 71 —**  **FEDERAL OPERATING PERMIT PROGRAMS** 6 . The authority citation for part 71 continues to read as follows: **Authority** : 42 U.S.C. 7401 et seq. 7. Section 71.2 is amended by removing “or” from the end of paragraph (2), adding “or” to the end of paragraph (3), and adding paragraph (4) to the definition of “Regulated pollutant (for fee calculation).” The revisions and additions read as follows: **§ 71.2**  **Definitions.**

* * * * * Regulated pollutant (for fee calculation), which is used only for purposes of § 71.9(c), means any “ regulated air pollutant ” except the following:

* * * * * (4) Greenhouse gases.

* * * * * 8. Section 71.9 is amended by:

a. Revising paragraphs (c)(1), (c)(2)(i), (c)(3), and (c)(4), and b. Adding paragraph (c)(8). The revisions and additions read as follows:Page **56** of **60**

**§ 71.9**  **Permit fees .** 

* * * * * (c) * * * (1) For part 71 programs that are administered by EPA, each part 71 source shall pay an annual fee which is the sum of: (i) $32 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitte d 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 calculat ion) emitted from the source, including fugitive emissions; and (B) Any GHG fee adjustment required under paragraph (c)(8) of this section.Page **57** of **60**

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

- E represents the contractor's effort, and C represents the contractor assistance cost on a per ton basis. C shall be computed by using the following formula: C =[ B + T + N ] divided by 12,300,000 Where B represents the base cost (contractor costs), where T represents travel costs, and where N represents nonpersonnel data management and tracking costs. In addition, each part 71 source shall pay a GHG fee adjustment for each activity as required under paragraph (c)(8) of this section. (4) For programs that are delegated in part, the fee shall be computed using the following formula: Cost per ton=( E ×32)+( D ×24)+[(1 − E − D )×$ C ]Page **58** of **60**

Where E and D represent, respectively, the EPA and delegate agency proportions of total effort (expressed as a percentage of total effort) needed to administer the part 71 program, 1 − E − D represents the contractor's effort, and C represents the contractor assistance cost on a per ton basis. C shall be computed using the formula for contractor assistance cost found in paragraph (c)(3) of this section and shall be zero if contractor assistance is not utilized. In addition, each part 71 source shall pay a GHG fee adjustment for each activity as required under paragraph (c)(8) of this section.

* * * * * (8) GHG fee adjustment . The annual fee shall be increased by a GHG fee adjustment for any source that has initiated an activity listed in the following table since the fee was last paid. The GHG fee adjustment shall be equal to the set fee provided in the table for each activity that has been initiated since the fee was last paid:

Activity Set fee GHG completeness determination (for initial permit or updated application) GHG evaluation for a permit modification or related permit action GHG evaluation at permit renewal $2,236 $364 $520Page **59** of **60**

* * * * * **PART 98 —**  **MANDATORY GREENHOUSE GAS REPORTING** 9. The authority citation for part 98 is revised to read as follows: Authority: 42 U.S.C. 7401

- 7671q. **Subpart PP**

**— Suppliers of Carbon Dioxide**  10. Section 98.426 is amended by adding paragraph (h) to read as follows: § 98.426 Data reporting requirements.

* * * * * (h) If you capture a CO 2 stream from an electricity generating unit that is subject to subpart D of this part and transfer CO2 to any facilities that are subject to subpart RR of this part, you must: (1) Report the facility identification number associated with the annual GHG report for the subpart D facility, (2) Report each facility identification number associated with the annual GHG reports for each subpart RR facility to which CO2 is transferred, and (3) Report the annual quantity of CO2 in metric tons that is transferred to each subpart RR facility. 11. Section 98.427 is amended by adding paragraph (d) to read as follows: § 98.427 Records that must be retained.Page **60** of **60**

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