### From: Culligan, Kevin Sent: Friday, May 30, 2014 10:04 PM To: 'Higgins, Cortney' Subject: FW: revised reg text TSD

In my checking, it looks like I had not sent this version.

<< Reg Text TSD 28 May 2014 (Proposed Applicability).docx >> << Reg Text TSD 28 May 2014 (Broad Applicability).docx >>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-2013-0603) Date: June, 2014 Subject: Amended Regulatory Text (Proposed Applicability)

Amended Regulatory Text

On January 8, 2014, the EPA proposed amendments (79 FR 1430) to the regulatory text of subparts Da and KKKK to include greenhouse gas (GHG) standards for new electric generatingunits (EGUs). As an alternative to amending proposed subparts Da and KKKK, the EPA coproposed creating a new subpart TTTT to include the proposed GHG standards. We intend to finalize the proposed amendments for modified and reconstructed EGUs following the approach finalized in the new source proposal published on January 8, 2014. For example, if the new source requirements are included in subparts Da and KKKK, the proposed requirements in this proposal would be added to those amendments.

To facilitate understanding the amendments being proposed in this proposal and allow interested persons to see how the proposed amendments for modified and reconstructed sources relate to the amendments from January 8, 2014 for newly constructed sources, the following document uses track changes to demonstrate the GHG standards for the proposed standards for modified and reconstructed EGUs on top of the regulatory text proposed on January 8, 2014.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 speci fied in paragraph (b) of this section. (1) Construction commenced after January 8, 20 14 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 th e purpose of supplying more than one-third of its potential electric output capacity and more than 219,000 MWh as net electric sales on an annual basis; (ii) The affected facility combusts fossil fuel fo r more than 10.0 percent of the heat input during any 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 system for sale on an annual basis. (2) Modification or reconstruction commenced after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], and the affected facility was constructed for the purpose of supplying more than one-third of its potential electric output and more than 219,000 MWh as net-electric sales on an annual basis, (b) The following EGUs are not subject to this section: (1) The proposed Wolverine EGU project described in Permit to Install No. 317-07 issued by the Michigan Department of Environm ental Quality, Air Quality Division, effective June 29, 2011 (as revised July 12, 2011). (2) The proposed Washington County EGU project described in Air Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, eff ective April 8, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014. (3) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment, effective December 16, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014. (c) As owner or operator of an affected facility subject to this section, you shall not cause to be discharged into the atmosphere from the affected facility any gases that contain CO 2 in excess of the emissions limit specified in this paragraph

. (1) As owner or operator of an affected facility for whic h 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; or Deleted: construction commenced after [DATE OF PUBLICATION IN THE FEDERAL REGISTER], and the affected facility

Deleted: and

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.

Deleted: 2

Comment [FC1]: Modification and reconstruction applicability does not include “and supplies” or fossil fuel use Comment [FC2]: Could delete since covered in the general applicability – keep to facilitate using “net electric sales” Comment [FC3]: Changing terminology to “netelectric sales” so “net-electric output” can be used in the definition of “net energy output” when determining the emission rate.

Deleted: limitation Comment [FC4]: Use consistent terminology – either “limit” or “standard”

Deleted: either paragraphs (c)(1) or (c)(2) of

Deleted: section

Deleted: (1 Comment [FC5]: For references purposes, in Table 4 of the January 8, 2014, proposal (79 FR 1430) the approximate net output based standard that corresponds to an 1,100 lb CO2/MWh-gross standard is 1,400 lb CO2/MWh-netPage **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 reconstruction commenced after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], you shall not cause to be discharged into the atmosphere from the affected facility any gases that contain CO 2 in excess of the emissions limit specified in para graph (c)(2)(i) or (c)(2)(ii) of this section. (i) If the design rated capacity of your affected facility is 590 MW (2,000 MMBtu/h) or less, 950 kg CO 2 /MWh of net energy output (2,100 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 (1,900 lb CO 2 /MWh) on a 12-operating month rolling average basis. (3) As owner or operator of an affected f acility for which modification commenced after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], you shall not cause to be discharged into the atmosphere from th e affected facility any 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-specific12-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 years 2002 through the most recent full calendar year the affected facility was operating prior to the modification using either recorded net output em ission 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 Ad ministrator or delegated authority shall approve the use of alternate data sources. The equivalent net output-based standard shall be calculated from gross output-based data assuming a 7.5 percent auxiliary (i.e., parasitic) load (i.e., the best annual value is divided by 0.925); (B) If the design rated capacity of your affected facility is 590 MW (2,000 MMBtu/h) or less, 950 kg CO 2 /MWh of net energy output (2,100 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 (1,900 lb CO 2 /MWh) on a 12-operating month rolling average basis. (ii) If the facility is subject to an approved CA A section 111(d) plan (state or federal) at the time of the modification, a site-s pecific 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 systems to identify applicable energy efficiency projects that you will implement at the affected facility to impr ove the affected facility ’s operating performance. You must maintain a copy of the most recent energy assessment report. The energy assessment Deleted: 2

Comment [FC6]: Since facility is not subject to 111(d) there is no CAA section 111(d) authority.

Could we just use generic “implementing authority” – should it be defined?Page **4** of **46**

must include at a minimum the elements in paragr aphs (c)(3)(ii)(A) through (c)(3)(ii)(C) of this section.(A) A visual inspection of the facility to identify steam leaks or ot her sources of reduced efficiency, (B) A review of available engineering pl ans and facility operation and maintenance procedures and logs, and (C) A comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, and the time frame for recouping those investments. (d) You must make compliance determinations at the end of each operating month, as provided in paragraphs (d)(1) and (d)(2) of this section. For the purpose of this section, operating month means a calendar month during which any fossil fuel is combusted in the affected facility. (1) If you 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 compliance. (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 days after accumulating the required number of operating months for the compliance period with which you have elected to comply (i.e., 12-operating months or 84-operating months). The first operating month included in this compliance period is the month in which emissions reporting is required to begin under § 75.64(a) of this chapter. (f) You must monitor and collect data to demonstrate compliance with the CO 2 emissions limit according to the requirements in paragraphs (f)(1) through (4) of this section. (1) You must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter. (2) You must measure the hourly 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, oper ate, maintain, and calibrate a CO 2 continuous emission monitoring system (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 system according to §75.10(a)(3)(i) of this chapter. If you measure CO 2 concentration on a dry basis, you must also inst all, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to §75.11(b) of this chapter. (ii) For each monitoring system used to determine the 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. (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 met hod sampling locations prior to the initial setup Deleted: elect

Deleted: comply with the

Deleted: limitation in paragraph (c)(1) of this section

Deleted: elect

Deleted: comply with the

Deleted: limitation in paragraph (c)(2) of this section

Deleted: limitation

Deleted: limitationPage **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 each dimens ion (i.e., depth and width) at three or more distinct locations and average the results. If the flow rate monitor or reference method sampling site is relocated, you must repeat these measurements at the new location. (iv) You can only use unadjusted exhaust ga s volumetric flow rates to determine the hourly CO 2 mass emissions from the affected facility; you must not apply the bias adjustment factors described in section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data. (v) If you choose to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube asse mbly. You must not use th e default Type-S pitot tube coefficient. (vi) If two or more affected facilities share a common exhaust gas stack and are subject to the same 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 ra ther 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 paragraph (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 determinations 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 nu mber of watt meters to continuously measure and record the gross or net electric output from the affected facility

. These measurements must be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. You must also meet the requirements specified in paragraphs (f)(4)(i) and (ii) of this section, as applicable. (i) If your affected facility is a combined heat and power unit as defined in § 60.42Da, you must also install, calibrate, maintain, a nd 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, Deleted: limitation

Deleted:
,

Deleted: you must Comment [FC7]: Additional requirement for consistent accuracy

Deleted: recovered

Deleted: energy Comment [FC8]: Soliciting comment on requirements for consistent accuracy of steam measurementsPage **6** of **46**

and pressure. If your affected fac ility has a direct mechanical driv e 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 th at you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination. (ii) If two or more affected facilities have steam generating units that serve a common electric generator, you must apportion the combined hourly gross or net electric output to each individual affected facility using a plan approved by the Administrator (e.g., using steam load or heat input to each affected facility). Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination. (g) You must demonstrate compliance with the 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 calculation 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 para meters 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 any of the parameters in the calculation. For the compliance determination calculation, you must obtain valid hourly values for a minimum of 95 percent of the operating hours in the applicable compliance period. (ii) You must calculate the total 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 hourly gross or net energy output using the appropriate definitions in § 60.42Da and paragraph (k) of this section and using the procedure specified in paragraphs (g)(3)(iii)(A) through (D) of this section. (A) Calculate P gross /net for your affected facility using the following equation:

ܲ

௚௥௢௦௦/௡௘௧ = ሺ ܲ݁ ሻ ௌ் ൅ ሺ ܲ݁ ሻ ஼் ൅ ሺ ܲ݁ ሻ ூா െ ሺܲ݁ሻ ிௐ T ൅ 	0.75 ൈ ሾ ሺ ܲݐ ሻ ௉ௌ ൅ ሺ ܲݐ ሻ ுோ ൅ ሺ ܲݐ ሻ ூா ሿ

Where:

P gross /net = Gross or net energy output of your affected facility in megawatt-hours ( MWh ). (Pe) ST = Electric energy output plus mechanic al energy output (if any) of steam turbines in MWh. Deleted: limitation

Deleted: ܲ ௚௥௢௦௦

Deleted: a Comment [FC9]: Technical corrections included throughout

Deleted: in

Deleted:

.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 mechanic al energy output (if any) of your affected facility’s integrated equipment that provides electricity or mechanical energy to the affected facility or auxiliary equipment in MWh. (Pe) FW = Electric energy used to power boiler feedwater pumps at steam generating units in MWh. This term is no t 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 electricity, produce mechanical energy output, or enhance the performance of the affected facility. This term is calculated using the equation specified in paragraph (g)(3)(iii)(B) of this section in MWh. (Pt) HR = Non steam useful 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 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, prod uce 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 mech anical output and 20.0 percent of the total gross or net energy output consists of useful thermal output on a rolling 3 year basis.
T = 1.0 for all other affected facilities.

(B) If applicable to your affected facility, calculate (Pt) PS using the following equation:

ሺܲݐሻ ௉ௌ ൌ ܳ ௠ ൈ 	ܪ 3.6	 ൈ	 10 ଽ 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). Comment [FC10]: Feedwater pumps already accounted for in net output calculation

Deleted: energy
Deleted: ISO Comment [FC11]: Standard ambient temperature and pressure are a better approximation of the energy in condensate/makeup water than ISO conditions

Deleted: Hourly

Deleted: energy
Deleted: ISO

Deleted: from heat recovery

Deleted: energy
Deleted: ISO

Deleted: provides thermal energy to

Deleted: or auxiliary equipment

Deleted: energy

Deleted: ISOPage **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 hourly 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 hourly CO 2 mass emissions are determined for a common stack, you must determine the hourly gross or net energy output (electric, thermal, and/or mechanical, as applicable) by summing the hourly loads for the individual affected facility and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter). (iv) You must calculate the total gross or net energy output by summing the hourly gross or net energy output values for the affected facility determined from paragraph (g)(1)(iii) of this section for all of the operating hours in the applicable compliance period. (v) You must calculate the 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 para graph (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 aff ected facility, then your affected facility is in compliance with the CO 2 emissions limit . If 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 affect ed facility is greater than the CO 2 emissions limit in paragraph (c) of this section appli cable 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 your affected facility. (3) You must submit electronic quarterly reports according to the requirements specified in paragraphs (h)(3)(i) through (iii) of this section. (i) Initially, after you have accumulated the required number of operating months for the CO 2 emission limit compliance period that you have chosen to comply with (i.e., 12-operating months or 84-operating months), you must subm it a report for the calendar quarter that includes the final (12th- or 84th) operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter no later than 30 days after the end of the quarter. Deleted: gross CO 2 emissions for that hour

Comment [FC12]: During periods of startup/shutdown where the facility is not generating power and “purchasing” power to run the facility net electricity is negative. There periods will be counted as zero and not negative.

Deleted: limitation

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Deleted: limitationPage **9** of **46**

(ii) In each quarterly 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) Any months in the calendar quarter that you are not counting as operating months. (C) For each operating month in the calendar quarter, the corresponding average CO 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 emission rates in that period divided by the total number of operating hours in that period , multiplied by 100 percent). (E) Any operating months in the calendar quarter with excess CO 2 emissions. (iii) In the final quarterly report of each calendar year you must include the following: (A) Net electric output sold to an el ectric grid over the calendar year; and (B) The potential electric output of the facility. (iv) You must submit each electronic re port using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool pr ovided by the Clean Air Markets Division in the EPA Office of Atmospheric Programs. (4) You must meet all applicable reporting re quirements and submit reports as required under subpart G of part 75 of this chapter. (5) If your affected unit uses geologic sequ estration to meet the applicable emissions limit, you must report in accordance with the requirements of 40 CFR part 98, subpart PP and either: (i) if injection occurs onsite, report in accordance with the requirements of 40 CFR part 98, subpart RR, or (ii) if injection occurs offsite, transfer the captured CO 2 to a facility or facilities that reports in accordance with the requirements of 40 CFR part 98, subpart RR. (i) For each affected electric utility stream generating unit, you must maintain records according to paragraphs (i)(1) through (i)(8) of this section. (1) You must comply with the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter. (2) You must maintain records of the calcula tions 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 cal culations you performed to determine the percentage of valid CO 2 mass emission rates in each compliance period. Deleted: limitation

Deleted: limitationsPage **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 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record except those records required to demonstrate compliance with an 84-operating month compliance period. You must maintain records required to demonstrate compliance with an 84-operating month compliance period for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. (8) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart. (j) PSD and Title V Thresholds for Gree nhouse Gases. (1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG em issions from new affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48). (2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from new affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49). (3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from new affected facilities, the “pollutant that is subject to any standard promulga ted under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 70.2. (4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from new affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 71.2. (k) For purposes of this section, the following definitions apply: Gross energy output means: (i) Except as provided under paragraph (ii) of this definition, for electric utility steam generating units, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) minus any electricity used to power the feedwater pumps plus 75 percent of the useful thermal output ; (ii) For electric utility steam generating unit combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on a rolling 3 year basis, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine( s), combustion turbine(s), and gas expanders) Deleted: limitation

Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application); Comment [FC13]: Redundant with definition of useful thermal outputPage **11** of **46**

minus any electricity used to power the feedwate r pumps, that difference divided by 0.95, plus 75 percent of the useful thermal output ; (iii) Except as provided under paragraph ( iv ) 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 co mbined 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 mechanic al 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 any integrated equipment that provides electricity or useful thermal output to either the affected facility or auxiliary equi pment. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the facility during operation.
Net-electric sales means: (i) Except as provided under paragraph (ii) of this definition, the gross electric sales to the utility power distribution system minus purchased power, or (ii) For combined heat and power facilities wh ere at least 20.0 percen t of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output, the gross electric sales to the utility power distribution system minus purch ased 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 output from the affected facility plus 75 percent of the useful thermal output; or (ii) For combined heat and power facilities wh ere at least 20.0 percen t 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 Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application);

Deleted: ii

Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application);

Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application);

Deleted: output Comment [FC14]: Use “net-electric sales” so we don’t have to use “for applicability purposes” and “for compliance purposes” for net electric output.

Deleted: on a calendar year basis Comment [FC15]: Not necessary since time frame specific directly in text.

Deleted: on a calendar year basis.

Comment [FC16]: Net electric output does not account for supplying electric power to other EGUs.For example, a simple cycle combustion turbine colocated with a coal-fired EGU would not be able to say it was supplying power to coal-fired EGU to offset auxiliary power requirements of the coal-fired EGU.

Comment [FC17]: Soliciting comment on 100% thermal creditPage **12** of **46**

net electric or mechanical output from the affected facility divided by 0.95, plus 75 percent of the useful thermal output. Potential electric output means: (i) Either 33 percent or the design net elect ric output efficiency, at the election of the owner/operator of the affected facility, (ii) Multiplied by the maximum design heat in put capacity of the steam generating unit, (Btu/h) (iii) Divided by 3,413 Btu/KWh, (iv) Divided by 1,000 kWh/MWh, and (v) Multiplied by 8,760 h/yr. (vi) For example, a 35 percent efficient steam generating unit with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 310,000 MWh 12 month potential electric output capacity. Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb. Steam generating unit means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to either the boiler or auxiliary equipment. Useful thermal output means the thermal energy made available for use in any heating application (e.g., steam delivered to an industrial process for a heating application, including thermal cooling applications) that is not used fo r 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 ener gy used to reduce fuel moisture is considered useful thermal output). Useful thermal output for affected facilities with no condensate return (or other thermal energy input to the affected facility) or where measuring the energy in the condensate (or other thermal energy input to the affected facility) would not meaningfully impact the emission rate calculation is measured agai nst the energy in the thermal output at SATP conditions. Affected facilities with meaningful en ergy in the condensate return (or other thermal energy input to the affected facility) must measur e the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output. Comment [FC18]: More representative than ISO of emergy content of makeup water and ISO conditions includes relative humidity that could unnecessarily complicate the calculations of useful thermal output

Formatted: Indent: First line: 0.5"

Comment [FC19]: Thermal energy used for coal drying is considered useful thermal output – could be done offsite by a separate thermal source and would not be included in the calculation. Comment [FC20]: Changing from ISO conditions since SATP is closer to makeup water conditions (50 Btu/lb instead of 30 Btu/lb).Page **13** of **46**

Subpart KKKK -— Standards of Performance for Stationary Combustion Turbines 3. Section 60.4305 is amended by adding paragraph (c) to read as follows: § 60.4305 Does this subpart apply to my stationary combustion turbine?
* * * * * (c) For purposes of regulation of greenhouse gases, the applicable provisions of this subpart affect your stationary combustion turb ine if it meets the applicability conditions in paragraphs (c)(1) through (c)(5) of this section. (1) Commenced construction after January 8, 2014 or it commenced reconstruction or modification after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] ; (2) Has a design heat input to the turbine engine greater than 73 MW (250 MMBtu/h); (3) Combusts fossil fuel for more than 10.0 percent of the heat input during any 3 consecutive calendar years. (4) Combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis; and (5) Was constructed for the purpose of supplying, and supplies, one-third or more of its potential electric output and more than 219,000 MWh net-electrical output to a utility distribution system on a 3 year rolling average basis.
4. Section 60.4315 is revised to read as follows: § 60.4315 What pollutants are regulated by this subpart? (a) The pollutants regulated by this subpart are nitrogen oxides (NO X ), sulfur dioxide (SO 2 ), and greenhouse gases. (b)(1) The greenhouse gases regulated by this subpart consist of carbon dioxide (CO 2 ). (2) PSD and Title V Thresholds for Green house Gases. (i) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GH G emissions from affected stationary combustion turbine, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporat e, 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, th e “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 any 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 by adding paragraph (c) to read as follows: § 60.4333 What are my general requirements for complying with this subpart?
* * * * * (c) If you own or operate an affected stationary combustion turbine subject to a CO 2 emissions standard in §60.4326, you must make compliance determinations on a 12-operating month rolling average basis, and you must de termine 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 emissions from each affected stationary combustion turbine using the procedures in paragraphs (b)(1) through (5) of this section, except as provided in paragraph (c) of this section. (1) You must install, certify, ope rate, maintain, and calibrate a CO 2 continuous emission monitoring system (CEMS) to directly measure and record CO 2 concentrations in the stationary combustion turbine exhaust gase s emitted to the atmosphere an d an exhaust gas flow rate monitoring system according to § 75.10(a)(3)(i) of this chapter. If you measure CO 2 concentration on a dry basis, you must also inst all, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to § 75.11(b) of this chapter. (2) For each monitoring system that you use to determine the 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 met hod sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, you must make measure of the diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, you must measure each dimension (i.e., de pth 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 **46**

(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 apply the bias adjustment factors described in section 7. 6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data. (5) If you chose to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube asse mbly. You must not use th e default Type-S pitot tube coefficient. (c) As an alternative to comp lying with paragraph (b) of th is 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 specified in paragraphs (c)(1) and (2) of this section. (1) You must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted. (2) You may determine site-specific carbon-based F-factors (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 nu mber of watt meters to continuously measure and record the gross electric output from the affected stationary combustion turbine. These measurements must be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. If the affected stationary combustion turbine is a CHP stationary combustion turbine, you must also install, calibrate, maintain, and operate meters to continuously determin e and record the total useful thermal output . For process steam applications, y ou will need to install, calibrate, maintain, and operate meters to continuously determine and record steam flow rate, temperature, and pressure. If the affected stationary combustion turbine has a direct mechanical drive application, you must submit a plan to the Administrator or delegated authority for approval of how gross energy output will be determined. Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination. (e) If two or more affected stationary combustion turbines serve a common electric generator, you must apportion the combined hourly gross output to the individual stationary combustion turbines using a plan approved by th e Administrator (e.g., using steam load or heat input to each affected stationary combustion turbine). Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination. (f) In accordance with § 60.13(g), if two or more stationary combustion turbines that implement the continuous emission monitoring provi sions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard under § 60.4326, you may monitor the hourly CO 2 mass emissions at the common stack in lieu of monitoring each stationary combustion turbine se parately. If you choose this option, the hourly gross load (electric, thermal, and/or mechanical, as applicable) must be the sum of the hourly loads for the Deleted: recovered

Deleted: energyPage **16** of **46**

individual stationary combustion turbines and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter). If you attain compliance with the applicable emissions standard in § 60.4326 at the common stack, each stationary combustion turbine sharing the stack is in compliance. (g) In accordance with § 60.13(g), if the exhaust gases from a stationary combustion turbine that implements the continuous emission monitoring provisions in paragraph (b) of this section are emitted to the atmosphere through mul tiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you chose to monitor in the ducts), you must monitor the hourly 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 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 by the total gross output for the unit.
8. Section 60.4374 is added under undesignated center heading “Monitoring” to read as follows: § 60.4374 How do I demonstrate compliance with my 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 hourly 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 affected stationary combustion turbine, and the calculation procedures in paragraphs (a)(1) through (a)(5) of this section. (1) You must only use operating hours in the compliance period for the compliance determination calculation for which you obtained valid data for all parameters you used to determine the hourly 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 this chapter for any 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 hourly gross output (P gross ) by applying the appropriate definitions in §§ 60.4420 and 60.4421 of this subpart and according to the procedures specified in paragraphs (a)(3)(i) and (iv) of this section . (i) Calculate P gross for your affected stationary combustion turbine using the following equation:

ܲ ௚௥௢௦௦ = ሺܲ݁ሻ ஼் ൅ 	 ሺܲ݁ሻ ௌ் ൅ 	 ሺܲ݁ሻ ூா T ൅ 	0.75 ൈ ሾ ሺ ܲݐ ሻ ௉ௌ ൅ ሺ ܲݐ ሻ ுோ ൅ ሺ ܲݐ ሻ ூா ሿ

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 mechanic al energy output (if any) of steam turbines in MWh. (Pe) IE = Electric energy output plus mechanic al 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 applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, enhance the performance of the affected facility. This is calculated 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, prod uce mechanical energy output, or enhance the performance 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 electric or direct mechanical output and 20.0 percent of the total gross energy output consists of useful therma l output on a rolling 3 year basis.
T = 1.0 for all other affected stationary combustion turbines.

(ii) If applicable to your affected stat ionary combustion turb ine, calculate (Pt) PS using the following equation:

ሺܲݐሻ ௉ௌ ൌ ܳ ௠ ൈ 	ܪ 3.6	 ൈ	 10 ଽ 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). Deleted: in

Deleted:

.

Deleted: energy
Deleted: ISO

Deleted: Calculated

Deleted: energy
Deleted: ISO

Deleted: energy
Deleted: ISO

Deleted: provides input to

Deleted: or auxiliary equipment

Deleted: energy

Deleted: ISOPage **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 you 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 applicable) by summing the hourly gross energy output you determined for each of your individual affected stationary combustion turbines that vent to the common stack; and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter). (4) You must calculate the total gross output for the affected stationary combustion turbine’s compliance period by summing the hourly gross output values for the affected stationary combustion turbine determined from paragraph (a)(2) of this section for all of the operating hours in the applicable compliance period. (5) You must calculate the 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 requirements of paragraph (a)(2) of this sec tion 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 affect ed 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 ap plicable to the affected stationary combustion turbine, then your affected stationary combustion turbine has excess CO 2 emissions. 9. Section 60.4375 is amended by revising the section heading to read as follows: § 60.4375 What reports must I submit to comply with my 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 notifi cations 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 st ationary 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 ro lling average basis for the standard in § 60.4326, you must submit electronic quarterly reports as follows. After you have accumulated the first 12-operating months for the affected stationary combustion turbine,Page **19** of **46**

you must submit a report for the calendar quarter that includes the 12th -operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 days after the end of the quarter. (2) In each quarterly report, you must include the following information, as applicable: (i) Each rolling average CO 2 mass emissions rate for whic h 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 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; (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 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 2 of this subpart) with which your affected stationary combustion turbine is complying. (3) The final quarterly report of each calendar year must contain the following: (i) Net electric output sold to an electric grid over the 4 quarters of the calendar year; and (ii) The potential electric output of the stationary combustion turbine. (c) You must submit all electronic reports re quired under paragraph (b) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Offi ce of Atmospheric Programs of the EPA. (d) You must meet all applicable reporting re quirements 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 info rmation 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 calculati ons 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 sitespecific 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 year(s) as required by this subpart.
12. Section 60.4395 is revised to read as follows: § 60.4395 When must I submit my reports? All of your reports required under § 60.7(c) must be postmarked by the 30th day after the end of each 6-month period, except as specified in § 60.4376
13. Section 60.4421 is added to read as follows: § 60.4421 What definitions with respect to 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 ISO conditions using the higher heating value of the fuel (heat input from duct burners is not included).
Excess emissions means a specified averaging period over which either: (1) The 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 any associated steam turbine(s) or integrated equipment plus any useful thermal output 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). Deleted: ISOPage **21** of **46**

(2) For a CHP stationary combustion turbine wh ere at least 20.0 percent of the total gross energy output consists of electric or direct mechan ical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on a rolling 3-year basis, the sum of the gross electric or direct mechan ical output from both the combustion turbine engine and any associated steam turbine(s) divided by 0.95 plus any useful thermal output measured relative to 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 system minus purchased power; or (2) For combined heat and power facilities wh ere at least 20.0 percent of the total gross energy output consists of electric or direct mechan ical output and at least 20.0 percent of the total gross energy output consists of useful thermal ou tput on a 3 calendar year rolling average basis, the gross electric sales to the utility power distribution system minus purchased power of the thermal host facility or facilities ; and (3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads are included when calculating net-electric sales. Net-electric output means: the amount of gross generation a generator produces, as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and transformer losses as m easured 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 wh ere at least 20.0 percen t of the total gross energy output consists of electric or direct mechan ical output and at least 20.0 percent of the total gross energy output consists of useful thermal outp ut on a rolling 3 year basis, the net electric or mechanical output from both the combustion turbine engine and any associated steam turbine(s) or integrated equipment divided by 0.95, plus 75 percent of the useful thermal output

. Operating month means a calendar month during which any fuel is combusted in the affected stationary combustion turbine. Potential electric output means 33 percent or the design electric output efficiency on a net output basis (at the election of the owner/operator of the affected facility) multiplied by the base load rating (expressed in MMBtu/h) of the stat ionary combustion turbine, multiplied by 10 6 Btu/MMBtu, divided by 3,413 Btu/KWh, divide d by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 percent efficient stationary combustion turbine with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 310,000 MWh 12-month potential electric output capacity). Deleted: ISO

Deleted: output

Deleted: on a 3 calendar year rolling average basis

Deleted: on a three calendar year rolling average basisPage **22** of **46**

Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb. Stationary combustion turbine means all equipment, including but not limited to the combustion turbine engine, the fuel, air, lubrica tion and exhaust gas systems, control systems, heat recovery system, steam turbine, fuel compressor, heater, and/or pump, post-combustion emission control technology, and any ancillary components a nd sub-components plus any integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustion turbine is not self propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. Useful thermal output means the thermal energy made available for use in any heating application (e.g., steam delivered to an industrial process for a heating application, including thermal cooling applications) that is not used fo r 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 ener gy used to reduce fuel moisture is considered useful thermal output). Useful thermal output for affected facilities with no condensate return (or other thermal energy input to the affected facility) or where measuring the energy in the condensate (or other thermal energy input to the affected facility) would not meaningfully impact the emission rate calculation is measured agai nst the energy in the thermal output at SATP conditions. Affected facilities with meaningful en ergy in the condensate return (or other thermal energy input to the affected facility) must measur e 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 Di oxide 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 average Deleted: to

Deleted: to

Deleted: 850MMBtu

Deleted: 850MMBtuPage **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 Information Yes § 60.10 State authority Yes

§ 60.11 Compliance with standards and maintenance requirements No

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

§ 60.18 General control device requirements No

§ 60.19 General notification and reporting requirements Yes Deleted: to

Deleted: toPage **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 I subject to this subpart?

Emission Standards

§ 60.5515 What 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

§ 60.5550 What notifications must I submit and when? § 60.5555 What reports must I submit and when? § 60.5560 What records must I maintain? § 60.5565 In what form and how long must I keep my records?

Other Requirements and Information

§ 60.5570 What parts of the General Provisions apply to my affected facility? § 60.5575 Who implements and enforces this subpart? § 60.5580 What definitions apply to this subpart?

Applicability § 60.5508 What is the purpose of this subpart? This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a steam generating unit, IGCC, or a stationary combustion turbine that commences construction after January 8, 2014 or commences modification or reconstruction after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]. Deleted: Utilit y Comment [FC21]: Make consistent

Deleted: 60.5530 Affirmative defense for violation of emission standards during malfunction¶

Deleted: [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 st ationary combustion turbine that commenced construction after January 8, 2014 or commenced modification or rec onstruction 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 IGCC 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), comb usts fossil fuel for more than 10.0 percent of the average annual heat input during a 3 year roll ing 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-electric output to a util ity distribution system on an annual basis. (2) A steam generating unit or IGCC that commenced modification or reconstruction after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] 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) and was constructed for the purpose of supplying one-third or more of its potential electric output and more th an 219,000 MWh net-electric output to a utility distribution system 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 year rolling average basis, combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and was constructed for the purpose of supplying, and supplies, one-third or more of its potential electric output and more than 219,000 MWh net-electrical output to a utility distribu tion system on a 3 year rolling average basis. (b) You are not subject to the requirements of th is 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 Environm ental Quality, Air Quality Division, effective June 29, 2011 (as revised July 12, 2011). (2) The proposed Washington County EGU project described in Air Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, eff ective April 8, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014. (3) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment, effective December 16, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014. (4) Your affected facility is a municipal wast e combustor unit that is subject to subpart Eb of this part. (5) Your affected facility is a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part.
Emission Standards Deleted: commences

Deleted: (2Page **27** of **46**

§ 60.5515 What 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 Green house Gases. (1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GH G emissions from aff ected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48). (2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is 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 52.21(b)(49). (3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that othe rwise is "subject to regulation" as defined in 40 CFR 70.2. (4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 71.2. § 60.5520 What CO 2 emissions standard must I meet? (a) For each affected facility subject to this subpart, you must not discharge from the affected facility any 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 complying with the standards sp ecified 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 paragrap h 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 ow ner/operator may elect to comply with a sitespecific 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 years 2002 through the most recent full calendar year the affected facility was operating prior to the modification using either recorded net output emission rate data or gross electrical output and 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. The equivalent net output-based standard shall be calculated from gross output-based data assuming a 7.5 percent auxilia ry (i.e., parasitic) load (i.e., th e best annual value is divided by 0.925); or Deleted: stack into the atmosphere

Deleted: of this subpart.Page **28** of **46**

(2) If the affected facility is subject to an approved CAA section 111(d) plan (state or federal) at the time of the modification, a s ite-specific 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 systems to identify applicable energy efficiency projects that you will implement at the affected facility to improve the affected facility’s operating performance. You must maintain a copy of the most recent energy assessment report. The energy assessment must include at a minimum the elements in paragraphs (b)(2)(i) through (b)(2)(iii) of this section. (i) A visual inspection of the facility to identify steam leaks or other sources of reduced efficiency, (ii) A review of available engineering pl ans and facility operation and maintenance procedures and logs, and (iii) A comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, and the time frame for recouping those investments. General Compliance Requirements § 60.5525 What are my general requirements for complying with this subpart? (a) You must be in compliance with the emissi on standards in this subpart that apply to your affected facility at all times. However, you must make a compliance determination only at the end of the applicable operating month, as provided in paragraphs (a)(1) and (2) of this section. (1) For each affected facility subject to a CO 2 emissions standard based on a 12-operating month rolling average, you must determine co mpliance monthly by 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 monthly 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, including associated equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practice. The Administrator will determ ine if you are using consistent operation and maintenance procedures based on information ava ilable to the Administrator that may include, but is not limited to, fuel use records, monitori ng results, review of operation and maintenance procedures and r ecords, review of reports required by this subpart, and inspection of the facility. (c) You must conduct an initial compliance determination for your affected facility for the applicable emissions standard in § 60.5520, according to the requirements in this subpart, within 30 days after the end of the initial compliance period for the CO 2 emissions standards applicable to your affected facility (i.e., 12-ope rating 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? Deleted: § 60.5530 Affirmative defense for violation of emission standards during malfunction.¶ In response to an action to enforce the standards set forth in § 60.5520, you may assert an affirmative defense to a claim for civil penalties for violations of such standards that are caused by malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be assessed if you fail to meet your burden of proving all of the requirements in the affirmative defense. The affirmative defense shall not be available for claims for injunctive relief.¶ (a) Assertion of affirmative defense. To establish the affirmative defense in any action to enforce such a standard, you must timely meet the reporting requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that:¶ (1) The violation:¶ (i) Was caused by a sudden, infrequent, and unavoidable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner; and¶ (ii) Could not have been prevented through careful planning, proper design or better operation and maintenance practices; ¶ (iii) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; ¶ (iv) Was not part of a recurring pattern indicative of inadequate design, operation, or maintenance; ¶ (2) Repairs were made as expeditiously as possible when the violation occurred; ¶ (3) The frequency, amount and duration of the violation (including any bypass) were minimized to the maximum extent practicable; ¶ (4) If the violation resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage;¶ (5) All possible steps were taken to minimize the impact of the violation on ambient air quality, the environment, and human health; ¶ (6) All emissions monitoring and control systems were kept in operation if at all possible, consistent with safety and good air pollution control practices; ¶ (7) All of the actions in response to the violation were documented by properly signed, contemporaneous operating logs; ¶ (8) At all times, the affected source was operated in a manner consistent with good practices for minimizing emissions; and¶ (9) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the violation resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of any emissions that were the result of the malfunction.¶ (b) Report. The owner or operator seeking to assert an affirmative defense shall submit a written report ... [1] Comment [FC22]: As discussed in the preamble,

we are not including a regulatory affirmative defense to civil penalties for violations caused by malfunctions in light of the recent decision in NRDC

v. EPA, No. 10

‐ 1371 (D.C. Cir. April 18, 2014) 2014 U.S. App. LEXIS 7281 (vacating affirmative defense provisions in Section 112(d) rule establishing emission standards for Portland cement kilns).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, ope rate, maintain, and calibrate a CO 2 continuous emission monitoring system (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 system 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, mainta in, and calibrate a continuous moisture monitoring system, according to § 75.11(b) of this chapter. (2) For each monitoring system you use to determine the 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 met hod sampling locations prior to the initial setup (characterization) of the flow monitor. For circ ular 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 m onitor or reference method sampling site is relocated, you must repeat these measurements at the new location. (4) You must use only unadjusted exhaust gas volumetric flow rates to determine the hourly CO 2 mass emissions from the affected facility; you must not apply the bias adjustment factors described in section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data. (5) If you choose to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube asse mbly. You must not use th e default Type-S pitot tube coefficient. (c) If your affected facility exclusively combus ts 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 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-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 nu mber of watt meters to continuously measure and record the gross or net electric output from the affected facility.Page **30** of **46**

These measurements must be performed using 0. 2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. If the affected facility is a CHP facility, you must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful 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 se rve a common electric generator, you must apportion the combined hourly gross or net output to the individual af fected facilities using a plan approved by the Administrator (e.g., using st eam load or heat input to each affected EGU). Your plan shall ensure that you install, calibra te, 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. If you choose this option, the hourly gross or net load (electric, thermal, and/or mechanical, as applicable) must be the sum of th e 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 operati ng time” (as defined in § 72.2 of this chapter) at each stack or duct separately. In this case, you must determine compliance with the applicable emissions standard in § 60.5520 by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the total gross or net output for the affected facility. §60.5540 How do I demonstrate compliance with my CO 2 emissions standard and determine excess emissions? (a) You must calculate the CO 2 mass emissions rate for your affected facility by 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 procedures in paragraphs (a)(1) through (a)(5) of this section. (1) You can only use operating hours in the compliance period for the compliance determination calculation if valid data are obtained for all parameters you used to determine the hourly CO 2 mass emissions and the gross or net output data are used for the compliance determination calculation. You must not include operating hours in which you used the substitute Comment [FC23]: Additional requirement for consistent accuracy

Deleted: recovered

Deleted: energy Comment [FC24]: Requesting comment on requirements for consistent accuracy of steam measurementsPage **31** of **46**

data provisions of part 75 of this chapter for any of those parameters in the calculation. For the compliance determination calculation, you must obtain valid hourly 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 calculate 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 section to calculate the total CO 2 mass emissions, you must dete rmine the affected facility’s corresponding hourly gross or net output according to the procedures in paragraphs (a)(3)(i) and (ii) of this section, as appropriate for the type of affected facility. For an operating hour in which there is no gross or net electric load, but there is mechanical or useful thermal output, you must still determine the gross or net output for that hour. In additio n, 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:

ܲ

௚௥௢௦௦/௡௘௧ = ሺ ܲ݁ ሻ ௌ் ൅ ሺ ܲ݁ ሻ ஼் ൅ ሺ ܲ݁ ሻ ூா െ ሺܲ݁ሻ ிௐ T ൅ 	0.75 ൈ ሾ ሺ ܲݐ ሻ ௉ௌ ൅ ሺ ܲݐ ሻ ுோ ൅ ሺ ܲݐ ሻ ூா ሿ

Where: a

P gross /net = Gross or net energy output of your affected facility in megawatt-hours ( MWh ). (Pe) ST = Electric energy output plus mechanic al 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 mechanic al energy output (if any) of your affected facility’s integrated equipment that provides electricity or mechanical energy to the affected facility or auxiliary equipment in MWh. (Pe) FW = Electric energy used to power boiler feedwater pumps at steam generating units in MWh. Not applicable to stationary combustion turbines
, 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 electricity, produce mechanical energy output, or enhance the performance of the affected facility. This is calculated 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) from Comment [FC25]: During periods of startup/shutdown where the facility is not generating power and “purchasing” power to run the facility net electricity is negative. There periods will be counted as zero and not negative.

Deleted: ܲ ௚௥௢௦௦

Deleted: in

Deleted:

.

Deleted: or Comment [FC26]: Feedwater pump energy use already accounted for when calculating net output.

Deleted: energy
Deleted: ISO Comment [FC27]: Standard ambient temperature and pressure are a better approximation of the energy in condensate/makeup water than ISO conditions.

Deleted: Calculated

Deleted: Hourly

Deleted: energy
Deleted: ISO

Deleted: energy
Deleted: ISOPage **32** of **46**

any integrated equipment that is used for applications that do not generate additional steam, electricity, prod uce 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 mech anical output and 20.0 percent of the total gross or net energy output consists of useful thermal output on a rolling 3 year basis.
T = 1.0 for all other affected facilities.

(ii) If applicable to your affected facility, you must calculate (Pt) PS using the following equation:
ሺܲݐሻ ௉ௌ ൌ ܳ ௠ ൈ 	ܪ 3.6	 ൈ	 10 ଽ 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 the 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 facility 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 the 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 your 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) Deleted: provides thermal energy to

Deleted: or auxiliary equipment

Deleted: energy

Deleted: ISOPage **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 chapter, as applicable to your affected facility. § 60.5555 What reports must I submit and when? (a) You must prepare and submit reports according to paragraphs (a) through (d) of this section, as applicable. (1) For affected facilities that are required by § 60.5525 to conduct initial and on-going compliance determinations on a 12- or 84-operating month rolling average basis for the standard in § 60.5520 you must submit electronic quarterly reports as follows. After you have accumulated the first 12-operating months for the affected facility (or, the first 84-operating months for an affected facility electing to comply with the 84 -operating month standard), you must submit a report for the calendar quarter that includes the twelfth (or eighty-fourth) operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 days after the end of the quarter. (2) In each quarterly report you must include the following information, as applicable: (i) Each rolling average CO 2 mass emissions rate for which the last (12th or eightyfourth) operating month in a 12- or 84-operating month compliance period falls within the calendar quarter. You must calculate each average CO 2 mass emissions rate according to the procedures in § 60.5540. You must report the dates (month and year) of the first and twelfth (or eighty-fourth) operating months in each compliance period for which you performed a 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; (iii) 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 peri od divided 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 calendar year, you must include the following: (i) Gross electric output sold to an electric grid over the 4 quarters of the calendar year; and (ii) The potential electric output of the facility. (b) You must submit all electronic reports re quired 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 Of fice of Atmospheric Programs of EPA. (c) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter.Page **34** of **46**

(d) If your affected unit employs geologic se questration to meet th e applicable emission limit, you must report in accordance with the requirements of 40 CFR part 98, subpart PP and either: (1) if injection occurs onsite, report in accordance with the requirements of 40 CFR part 98, subpart RR, or (2) if injection occurs offsite, transfer the captured CO 2 to a facility or facilities that reports in accordance with the requirements of 40 CFR part 98, subpart RR. § 60.5560 What records must I maintain? (a) You must maintain records of the info rmation 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 calculati ons 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 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 § 60.5520.(g) You must keep records of the calculations you performed to determine any sitespecific carbon-based F-factors you used in the emissions calculations (if applicable). § 60.5565 In what form and how long must I keep my records? (a) Your records must be in a form suitable and readily available for expeditious review. (b) You must maintain each record for 5 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record except those records required to demonstrate compliance with an 84-operating month compliance period. You must maintain records required to demonstrate compliance with an 84-operating month compliance period for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. (c) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart. Other Requirements and Information § 60.5570 What parts of the General Provisions apply to my affected facility?Page **35** of **46**

Notwithstanding any other provision of this chapter, certain parts of the General Provisions in §§ 60.1 through 60.19, listed in Table 2 of this subpart, do not apply to your affected facility. § 60.5575 Who implements and enforces this subpart? (a) This subpart can be implemented and enforced by the EPA, or a delegated authority such as your state, local, or tribal agency. If the Administrator has delegated authority to your state, local, or tribal agency, then that agency (as well as the EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your state, local, or tribal agency. (b) In delegating implementation and enforcement authority of this subpart to a state, local, or tribal agency, the Administrator reta ins 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 alte rnatives 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 define d 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 determ ined by the physical design and characteristics of the steam generating unit at ISO 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 ISO conditions (heat input from duct burners is not included).
Coal means all solid fuels classified as anthr acite, 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 mi xtures, and coal-water mixtures are included in this definition for the purposes of this subpart.
Coal refuse means waste products of coal mining, physical coal cleaning, and coal preparation operations ( e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material. Combined cycle facility means an electric generating unit that uses a stationary combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat recovery steam generating unit to generate additional electricity. Combined heat and power facility or CHP facility , ( also known as “cogeneration”) means Deleted: Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding.¶

Deleted: baseloadPage **36** of **46**

an electric generating unit that that use a steam-g enerating 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 by reference, see § 60.17); diesel fuel oil numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see § 60.17); kerosene, as defined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see § 60.17); biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see § 60.17); or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see § 60.17).
Excess emissions means a specified averaging period over which the 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, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
Gaseous fuel means any fuel that is present as a gas at ISO conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal. Gross energy output means: (1) For stationary combustion turbines and IG CC facilities, the gross electric or direct mechanical output from both the unit (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) plus 75 percent of the useful thermal output

. (2) For electric utility steam generating uni ts, the gross electric or mechanical output from the affected facility (including, but not lim ited to, output from stea m turbine(s), combustion turbine(s), and gas expander(s)) minus any electrici ty used to power the feedwater pumps plus 75 percent of the useful thermal output ; (3) For combined heat and power facilities wh ere at least 20.0 percent of the total gross energy output consists of electric or direct mech anical output and 20.0 percent of the total gross energy output consists of useful thermal output on a rolling 3 year basis, the gross electric or mechanical output from the affected facility (i ncluding, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander (s)) minus any electricity used to power the feedwater pumps (the electric auxiliary load of boiler feedwater pumps is not applicable to IGCC facilities), that difference divided by 0.95, plus 75 percent of the useful thermal output

. 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 gene rating units can be used with or without duct burners. Integrated gasification combined cycle facility or IGCC facility means a combined cycle stationary combustion turbine that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas. The Administrator may waive the 50 percent solid-derived fuel require ment during periods of the gasification system Deleted: energy

Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application).

Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application);

Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application).Page **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 IS O conditions and includes, but is not limited to, distillate oil and residual oil. Mechanical output means the useful mechanical energy that is not used to operate the affected facility, generate electricity and/or thermal energy, or to enhance the performance of the affected facility. Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000. Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value.
Net-electric sales means: (1) The gross electric sales to the utility power distribution system minus purchased power; or (2) For combined heat and power facilities wh ere at least 20.0 percent of the total gross energy output consists of electric or direct mechan ical output and at least 20.0 percent of the total gross energy output consists of useful thermal ou tput, the gross electric sa les to the utility power distribution system minus pur chased 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 output means: the amount of gross generation the generator(s) produces (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)), as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale). Net energy output means: (i) Except as provided under paragraph (ii) of this definition, the net electric or mechanical output from the affected facility plus 75 percent of the useful thermal output; or (ii) For combined heat and power facilities wh ere at least 20.0 percen t of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a rolling 3 year basis, the net electric or mechanical output from the affected facility divided by 0.95, plus 75 percent of the useful thermal output; Deleted: output

Deleted: on a three calendar year rolling average basis

Deleted: on a 3 calendar year rolling average basis

Deleted: on a three calendar year rolling average basis.

Deleted: 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). ¶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 h eat input capacity (expr essed 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 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 li quid 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 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb. Stationary combustion turbine means all equipment, including but not limited to the turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery syst em, fuel compressor, heater, and/or pump, postcombustion emission control technology, and an y ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system plus any integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustion turbine is not self propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. If a statio nary 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 genera tors are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected facility or auxiliary equipment. Useful thermal output means the thermal energy made available for use in any heating application ( e .g., steam delivered to an industrial process for a heating application, including thermal cooling applications ) that is not used for electric generation, mechanical output at the affected facility, or to directly enhance the performance of the affected facility (e.g., economizer output is not useful thermal output , but thermal energy used to reduce fuel moisture is considered useful thermal output). Useful thermal output for affected facilities with no condensate return (or other thermal energy input to the affected facility) or where measuring the energy in the condensate (or other thermal energy input to the affected facility) would not meaningfully impact the emission rate calculation is measured against the energy in the thermal output at SATP conditions. Affected facilities with meaningful energy in the condensate return (or other thermal energy input to the affected facility) must measur e the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output. Comment [FC28]: Deleted oil since it is used in EGU NESHAP, and added petroleum since it is used in the EGU NSPS.

Deleted: industrial or commercial process, or used in any

Deleted: or cooling

Deleted: , i.

Deleted: ., total thermal energy made available

Deleted: processes and

Deleted: other than

Deleted: . Thermal

Deleted: for this subpart means the energy in recovered

Deleted: ISO

Deleted: ¶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 tu rbine 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 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. Deleted: to

Deleted: 850MMBtu

Deleted: 850MMBtu

Deleted: ).

Deleted: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 PUBLICATION 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). 510 kg of CO 2 per MWh of gross output (1,100 lb CO 2 /MWh) on a 12-operating month rolling average

Stationary combustion tu rbine that has a base load rating heat input to the turbine engine of greater than 250 MW (850 MMBtu/h). 460 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. 950 kg of CO 2 per MWh of net energy output (2,100 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). 860 kg of CO 2 per MWh of net energy output (1,900 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 ti me of the modification or m odified 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. Deleted: Table 2 toPage **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 Information Yes § 60.10 State authority Yes

§ 60.11 Compliance with standards and maintenance requirements No

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

§ 60.18 General control device requirements No

§ 60.19 General notification and reporting requirements Yes Formatted: Space After: 0 ptPage **42** of **46**

PART 70 — STATE OPERATING PERMIT PROGRAMS 17. The authority citation for part 70 continues to read as follows: Authority : 42 U.S.C. 7401, et seq.
18. Section 70.2 is amended: a. By adding in alphabetical order the definition of “Greenhouse gases,” b. By revising the introductory text, removing “or” from the end of paragraph (2), adding “or” to the end of paragraph (3), and adding paragraph (4) to the definition of “Regulated pollutant (for presumptive fee calculation),” and c. By revising paragraph (1) to the definition of “Subject to regulation

. ”
The revision and additions read as follows: § 70.2 Definitions.
* * * * * Greenhouse gases (GHGs) means the air pollutant defined in § 86.1818-12(a) of this chapter as the aggregate group of six greenhouse gases: carbon dioxide, nitrous oxide, methane, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride.
* * * * * Regulated pollutant (for presumptive fee calculation), which is used only for purposes of § 70.9(b)(2), means any regulated ai r pollutant except the following:
* * * (4) Greenhouse gases.
* * * * * Subject to regulation * * * (1) Greenhouse gases shall not be subject to regulation unless, as of July 1, 2011, the GHG emissions are at a stationary source emitting or having the potential to emit 100,000 tpy CO 2 equivalent emissions.
* * * * * 19. Section 70.9 is amended by revising paragraph (b)(2)(i), and by adding paragraph (b)(2)(v) to read as follows: § 70.9 Fee determination and certification.
* * * * * (b) * * * (2)(i) The Administrator will presume that th e fee schedule meets the requirements of paragraph (b)(1) of this section if it would result in the collection and retention of an amount not less than $25 per year [as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) of this section] times the total tons of the actual emissions of each regulated pollutant (for presumptive fee calculation) emitted from part 70 sources and any GHG cost adjustment required under paragraph (b)(2)(v) of this section.Page **43** of **46**

* * * * * (v) GHG cost adjustment. The amount calculate d 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 th e average cost of staff time, including wages, employee benefits and overhead. Activity Burden hours per activity GHG completeness determination (for initial permit or updated application)

GHG evaluation for a modification or related permit action

GHG evaluation at permit renewal 43

7

10

* * * * *
PART 71 — FEDERAL OPERATING PERMIT PROGRAMS 20. The authority citation for part 71 continues to read as follows: Authority : 42 U.S.C. 7401, et seq.
21. Section 71.2 is amended: a. By adding in alphabetical order the definition of “Greenhouse gases,” b. By removing “or” from the end of paragraph (2), adding “or” to the end of paragraph (3), and adding paragraph (4) to the definition of “Regulated pollutant (for fee calculation),” and c. By revising paragraph (1) of the definition of “Subject to regulation.”
The revisions and additions read as follows: § 71.2 Definitions.
* * * * * Greenhouse gases (GHGs) means the air pollutant defined in § 86.1818-12(a) of this chapter as the aggregate group of six greenhouse gases: carbon dioxide, nitrous oxide, methane, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride.
* * * * * Regulated pollutant (for fee calculation)

, which is used only for purposes of § 71.9(c), means any “regulated air pollutant” except the following:Page **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 em issions of each regulated pollutant (for fee calculation) emitted from the source , including fugitive emissions; and (B) Any GHG fee adjustment required under paragraph (c)(8) of this section.
* * * * * (3) For part 71 programs that are administered by EPA with contractor assistance, the per ton fee shall vary depending on the extent of contractor involvement and the cost to EPA of contractor assistance. The EPA shall establish a pe r ton fee that is based on the contractor costs for the specific part 71 program that is bein g administered, using the following formula: Cost per ton=( E ×32)+[(1

− E )×$ C ]
Where E represents EPA's proportion of total effo rt (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 tr acking costs. In addition, each part 71 source shall pay a GHG fee adjustment for each activity as required under paragraph (c)(8) of this section. (4) For programs that are delegated in part, the fee shall be computed using the following formula: Cost per ton=( E ×32)+( D ×24)+[(1

− E

− D )×$ C ]
Where E and D represent, respectively, the EPA and delegate agency proportions of total effort (expressed as a percentage of total effort) needed to administer the part 71 program, 1

− E

− D represents the contractor's effort, and C represents the contractor assistance cost on a per ton basis. C shall be computed using the formula for contractor assistance cost found in paragraph (c)(3) of this section and shall be zero if contract or assistance is not utilized. In addition, each part 71 source shall pay a GHG fee adjustment for each activity as required under paragraph (c)(8) of this section.
* * * * * (8) GHG fee adjustment . The annual fee shall be increased by a GHG fee adjustment for any source that has initiated an activity listed in the following table since the fee was last paid. The GHG fee adjustment shall be equal to the set fee provided in the table for each activity that has been initiated since the fee was last paid:

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

GHG evaluation for a permit modification or related permit action

GHG evaluation at permit renewal $2,236

$364

$520

* * * * *
PART 98 — MANDATORY GREENHOUSE GAS REPORTING 23. The authority citation for part 98 is revised to read as follows: Authority: 42 U.S.C. 7401-7671q. Subpart PP—Suppliers of Carbon Dioxide 24. Section 98.426 is amended by adding paragraph (h) to read as follows:Page **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 subj ect to subpart RR of this part, you must: (1) Report the facility identification number a ssociated with the annual GHG report for the facility that is subject to subpart D of this part, (2) Report each facility identification number associated with the annual GHG reports for each facility that is subject to subpart RR of this part to which 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 by adding paragraph (d) to read as follows: § 98.427 Records that must be retained.
* * * * * (d) Facilities subject to § 98. 426(h) must retain records of CO 2 in metric tons that is transferred to each facility that is subject to subpart RR of this part.Page 28: [1] Deleted Fellner, Christian 5/28/2014 3:57:00 PM 

## § 60.5530 Affirmative defense for violation of emission standards du ring malfunction. In response to an action to enforce the sta ndards set forth in § 60.5520, you may assert an affirmative defense to a claim for civil penalties for violations of such standards that are caused by malfunction, as defined at 40 CFR 60.2. Appropria te penalties may be a ssessed if you fail to meet your burden of proving a ll of the requirements in the affi rmative defense. The affirmative defense shall not be available fo r claims for injunctive relief. (a) Assertion of affirmative defense. To esta blish the affirmative defense in any action to enforce such a standard, you must timely meet th e reporting requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that: (1) The violation: (i) Was caused by a sudden, infrequent, and unavoidable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner; and (ii) Could not have been prevented thr ough careful planning, prope r design or better operation and maintenance practices; (iii) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; (iv) Was not part of a recu rring pattern indicative of in adequate design, operation, or maintenance; (2) Repairs were made as e xpeditiously as possible when the violation occurred; (3) The frequency, amount and duration of the violation (includi ng any bypass) were minimized to the maximu m extent practicable; (4) If the violation resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life , personal injury, or severe property damage; (5) All possible steps were taken to minimize the impact of the vi olation on ambient air quality, the environment, and human health; (6) All emissions monitoring a nd control systems were kept in operation if at all possible, consistent with safety a nd good air pollution c ontrol practices; (7) All of the actions in response to the vi olation were documented by properly signed, contemporaneous operating logs; (8) At all times, the affected source was operated in a manner consistent with good practices for minimizing emissions; and (9) A written root cause analysis has been prep ared, the purpose of which is to determine, correct, and eliminate th e primary causes of the malfunction a nd the violation resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of any emissions that were th e result of the malfunction. (b) Report. The owner or operator seeking to assert an affirmative defense shall submit a written report to the Administrat or to demonstrate, with all necessary supporting documentation, that it has met the requir ements set forth in paragraph (a) of this section. This affirmative defense

## report is due after the initial occurrence of the exceedance of the standard in § 60.5520, and on the same quarterly reporting schedule as in § 60.5555 (which may be the e nd of any applicable averaging period). If such quarter ly report is due less than 45 days after the initial occurrence of the violation, the affirmative defense report ma y be included in the fo llowing quarterly report required in § 60.5555(a).Page **1** of **43**

MEMORANDUM

From: Office of Air Quality Planning and Standards U.S. Environmental Protection Agency To: EGU NSPS Docket (EPA-HQ-OAR-2013-0603) Date: June, 2014 Subject: Amended Regulatory Text (Broad Applicability)

Amended Regulatory Text

On January 8, 2014, the EPA proposed amendments (79 FR 1430) to the regulatory text of subparts Da and KKKK to include greenhouse gas (GHG) standards for new electric generatingunits (EGUs). As an alternative to amending proposed subparts Da and KKKK, the EPA coproposed creating a new subpart TTTT to include the proposed GHG standards. We intend to finalize the proposed amendments for modified and reconstructed EGUs following the approach finalized in the new source proposal published on January 8, 2014. For example, if the new source requirements are included in subparts Da and KKKK and use the applicability described in detail in docket item EPA-HQ-OAR-2013-0495- 0062, the proposed requirements in this proposal would be added to those amendments.

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

In addition, in docket item EPA-HQ-OAR-2013-0495-0062 of the January 8, 2014, proposal, the EPA elaborated upon the request for comment included in the preamble on whether the general applicability of the proposed standards should be broadened and based on design characteristics instead of design characteristics and operating parameters. Under this approach, a GHG emission standard would apply during periods when certa in conditions are met and no numerical GHG emission standard would apply during periods when one or more of those conditions are not met. In other words, although there would be no numeri cal emission limit, the facility would remain subject to the standard of performance. The trac k changes of the proposed amendments in this proposal include this expanded applicability approach. This broad applicability approach could have implications for the corresponding 111(d) rulemaking since it would include non-natural gas-fired and low capacity factor stationary combustion would be included in the 111(b) applicability.Page **2** of **43**

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 the facility was constructed for the purpose of supplying and supplies more than one-third of its potential electric output capacity and more than 219,000 MWh as net electric sales on an annual basis; or (2) Modification or reconstruction commenced after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] , and the affected facility was constructed for the purpose of supplying more than one-third of its potential electric output and more than 219,000 MWh as net-electric sales on an annual basis, (b) The following EGUs are not subject to this section: (1) The proposed Wolverine EGU project described in Permit to Install No. 317-07 issued by the Michigan Department of Environm ental Quality, Air Quality Division, effective June 29, 2011 (as revised July 12, 2011). (2) The proposed Washington County EGU project described in Air Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, eff ective April 8, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014. (3) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment, effective December 16, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014. (c) As owner or operator of an affected facility subject to this section, you shall not cause to be discharged into the atmosphere from the affected facility any gases that contain CO 2 in excess of the emissions limit specified in this paragraph. (1) As owner or operator of an affected facility for which construction commenced after January 8, 2014, you shall not cause to be discharged into the atmosphere from the affected facility any gases that contain CO 2 in excess of the emissions limit specified in paragraph (c)(1)(i), (c)(1) (ii), or (c)(1) (iii) 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; ( 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 ; or (iii) If the affected facility combusts fossil fu el for 10.0 percent or less of the heat input during any 3 consecutive calendar year s no numerical emission standard. (2) As owner or operator of an affected facility for which reconstruction commenced after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], you shall not cause to be discharged into the atmosphere from the affected facility any gases that contain CO 2 Deleted: c

Comment [FC1]: Modification and reconstruction applicability does not include “and supplies” Comment [FC2]: Could delete since covered in the general applicability – keep to facilitate using “net electric sales” Comment [FC3]: Changing terminology to “netelectric sales” so “net-electric output” can be used in the definition of “net energy output” when determining the emission rate.

Deleted: meets the conditions specified in paragraphs (a)(1) and (a)(2) of this section, except as specified in paragraph (b) of this section.

Deleted: (1) The affected facility combusts fossil fuel for more than 10.0 percent of the heat input during any 3 consecutive calendar years Comment [FC4]: Move to standards sections with “no emission standard” to be consistent with subpart TTTT new source proposal in docket item EPA-HQ-OAR-2013-0495-0062 (error in subpart Da regulatory text)

Deleted: .¶ (2) The affected facility supplies more than one-third of its potential electric output and more than 219,000 MWh net-electric output to a utility power distribution system for sale on an annual basis.¶

Deleted: ation Comment [FC5]: Use consistent terminology – either “limit” or “standard”

Deleted: either

Deleted: s (c)(1) or (c)(2) of this section

Deleted: or Comment [FC6]: For references purposes, in Table 4 of the January 8, 2014, proposal (79 FR 1430) the approximate net output based standard that corresponds to an 1,100 lb CO2/MWh-gross standard is 1,400 lb CO2/MWh-net

Deleted: 2

Deleted:

.Page **3** of **43**

in excess of the emissions limit specified in paragr aph (c)(2)(i), (c)(2)(ii), or (c)(2)(iii) of this section. (i) If the design rated capacity of your affected facility is 590 MW (2,000 MMBtu/h) or less, 950 kg CO 2 /MWh of net energy output (2,100 lb CO 2 /MWh) on a 12-operating month rolling average basis; (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 (1,900 lb CO 2 /MWh) on a 12-operating month rolling average basis; or (iii) If the affected facility combusts fossil fu el for 10.0 percent or less of the heat input during any 3 consecutive calendar year s no numerical emission standard. (3) As owner or operator of an affected f acility for which modification commenced after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], you shall not cause to be discharged into the atmosphere from the affected facility any gases that contain 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-specific12-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 years 2002 through the most recent full calendar year the affected facility was operating prior to the modification using either recorded net output em ission 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 Ad ministrator or delegated authority shall approve the use of alternate data sources. The equivalent net output-based standard shall be calculated from gross output-based data assuming a 7.5 percent auxiliary (i.e., parasitic) load (i.e., the best annual value is divided by 0.925); (B) If the design rated capacity of your affected facility is 590 MW (2,000 MMBtu/h) or less, 950 kg CO 2 /MWh of net energy output (2,100 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 (1,900 lb CO 2 /MWh) on a 12-operating month rolling average basis. (ii) If the facility is subject to an approved CA A section 111(d) plan (state or federal) at the time of the modification, a site-s pecific 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 systems to identify applicable energy efficiency projects that you will implement at the affected facility to impr ove the affected facility ’s operating performance. You must maintain a copy of the most recent energy assessment report. The energy assessment must include at a minimum the elements in paragr aphs (c)(3)(ii)(A) through (c)(3)(ii)(C) of this Comment [FC7]: Soliciting comment on an appropriate numerical standard.

Comment [FC8]: Since facility is not subject to 111(d) there is no CAA section 111(d) authority.

Could we just use generic “implementing authority” – should it be defined?Page **4** of **43**

section.(A) A visual inspection of the facility to identify steam leaks or ot her sources of reduced efficiency, (B) A review of available engineering pl ans and facility operation and maintenance procedures and logs, and (C) A comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, and the time frame for recouping those investments. (d) You must make compliance determinations at the end of each operating month, as provided in paragraphs (d)(1) and (d)(2) of this section. For the purpose of this section, operating month means a calendar month during which any fossil fuel is combusted in the affected facility. (1) If you 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 compliance. (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 days after accumulating the required number of operating months for the compliance period with which you have elected to comply (i.e., 12-operating months or 84-operating months). The first operating month included in this compliance period is the month in which emissions reporting is required to begin under § 75.64(a) of this chapter. (f) You must monitor and collect data to demonstrate compliance with the CO 2 emissions limit according to the requirements in paragraphs (f)(1) through (4) of this section. (1) You must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter. (2) You must measure the hourly 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, oper ate, maintain, and calibrate a CO 2 continuous emission monitoring system (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 system according to §75.10(a)(3)(i) of this chapter. If you measure CO 2 concentration on a dry basis, you must also inst all, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to §75.11(b) of this chapter. (ii) For each monitoring system used to determine the 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. (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 met hod sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, you must make measurements of the Deleted: ¶

Deleted: elect to comply with the

Deleted: ation in paragraph (c)(1) of this section

Deleted: elect to comply with the

Deleted: ation in paragraph (c)(2) of this section

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diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, you must make measurements of each dimens ion (i.e., depth and width) at three or more distinct locations and average the results. If the flow rate monitor or reference method sampling site is relocated, you must repeat these measurements at the new location. (iv) You can only use unadjusted exhaust ga s volumetric flow rates to determine the hourly CO 2 mass emissions from the affected facility; you must not apply the bias adjustment factors described in section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data. (v) If you choose to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube asse mbly. You must not use th e default Type-S pitot tube coefficient. (vi) If two or more affected facilities share a common exhaust gas stack and are subject to the same 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 ra ther 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 paragraph (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 determinations 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 nu mber of watt meters to continuously measure and record the gross or net electric output from the affected facility

. These measurements must be performed using 0. 2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. 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, you must also install, calibrate, maintain, a nd 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, and pressure. If your affected fac ility has a direct mechanical driv e application, you must submit Deleted: ation

Deleted:

,

Comment [FC9]: Additional requirement for consistent accuracy

Deleted: and

Deleted: y

Deleted: recovered

Deleted: energy Comment [FC10]: Soliciting comment on requirements for consistent accuracy of steam measurementsPage **6** of **43**

a plan to the Administrator or delegated authority for approval of how gross or net energy output will be determined. Your plan shall ensure th at you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination. (ii) If two or more affected facilities have steam generating units that serve a common electric generator, you must apportion the combined hourly gross or net electric output to each individual affected facility using a plan approved by the Administrator (e.g., using steam load or heat input to each affected facility). Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination. (g) You must demonstrate compliance with the 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 calculation 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 para meters 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 any of the parameters in the calculation. For the compliance determination calculation, you must obtain valid hourly values for a minimum of 95 percent of the operating hours in the applicable compliance period. (ii) You must calculate the total 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 hourly gross or net energy output using the appropriate definitions in § 60.42Da and paragraph (k) of this section and using the procedure specified in paragraphs (g)(3)(iii)(A) through (D) of this section. (A) Calculate P gross /net for your affected facility using the following equation:

ܲ

௚௥௢௦௦ /௡௘௧ = ሺ ܲ݁ ሻ ௌ் ൅ ሺ ܲ݁ ሻ ஼் ൅ ሺ ܲ݁ ሻ ூா െ ሺܲ݁ሻ ிௐ T ൅ 	0.75 ൈ ሾ ሺ ܲݐ ሻ ௉ௌ ൅ ሺ ܲݐ ሻ ுோ ൅ ሺ ܲݐ ሻ ூா ሿ

Where:

P gross /net = Gross or net energy output of your affected facility in megawatt-hours ( MWh )

. (Pe) ST = Electric energy output plus mechanic al energy output (if any) of steam turbines in MWh. (Pe) CT = Electric energy output plus mechanical energy output (if any) of stationary Deleted: ation

Deleted: a Comment [FC11]: Technical corrections included throughout

Deleted: inPage **7** of **43**

combustion turbine(s) in MWh. (Pe) IE = Electric energy output plus mechanic al energy output (if any) of your affected facility’s integrated equipment that provides electricity or mechanical energy to the affected facility or auxiliary equipment in MWh. (Pe) FW = Electric energy used to power boiler feedwater pumps at steam generating units in MWh. This term is no t 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 electricity, produce mechanical energy output, or enhance the performance of the affected facility. This term is calculated using the equation specified in paragraph (g)(3)(iii)(B) of this section in MWh. (Pt) HR = 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 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, prod uce 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 mech anical output and 20.0 percent of the total gross or net energy output consists of useful thermal output on a rolling 3 year basis.
T = 1.0 for all other affected facilities.

(B) If applicable to your affected facility, calculate (Pt) PS using the following equation:
ሺܲݐሻ ௉ௌ ൌ ܳ ௠ ൈ 	ܪ 3.6	 ൈ	 10 ଽ 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).

(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 Comment [FC12]: Feedwater pumps already accounted for in net output calculation

Deleted: energy
Deleted: ISO Comment [FC13]: Standard ambient temperature and pressure are a better approximation of the energy in condensate/makeup water than ISO conditions

Deleted: Hourly u

Deleted: energy
Deleted: ISO

Deleted: from heat recovery

Deleted: energy
Deleted: ISO

Deleted: provides thermal energy to the affected facility or auxiliary equipment

Deleted: energy

Deleted: ISOPage **8** of **43**

that hour. In addition, for an operating hour in which there is no useful output, you must still determine the hourly 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 hourly CO 2 mass emissions are determined for a common stack, you must determine the hourly gross or net energy output (electric, thermal, and/or mechanical, as applicable) by summing the hourly loads for the individual affected facility and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter). (iv) You must calculate the total gross or net energy output by summing the hourly gross or net energy output values for the affected facility determined from paragraph (g)(1)(iii) of this section for all of the operating hours in the applicable compliance period. (v) You must calculate the 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 para graph (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 yo ur affected facility is in compliance with the CO 2 emissions limit. If 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 affect ed 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 your affected facility. (3) You must submit electronic quarterly reports according to the requirements specified in paragraphs (h)(3)(i) through (iii) of this section. (i) Initially, after you have accumulated the required number of operating months for the CO 2 emission limit compliance period that you have chosen to comply with (i.e., 12-operating months or 84-operating months), you must subm it a report for the calendar quarter that includes the final (12th- or 84th) operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter no later than 30 days after the end of the quarter. Deleted: gross

Comment [FC14]: During periods of startup/shutdown where the facility is not generating power and “purchasing” power to run the facility net electricity is negative. There periods will be counted as zero and not negative.

Deleted: ation

Deleted: ation

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Deleted: ation

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(ii) In each quarterly 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) Any months in the calendar quarter that you are not counting as operating months. (C) For each operating month in the calendar quarter, the corresponding average CO 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 emission rates in that period divided by the total number of operating hours in that period , multiplied by 100 percent). (E) Any operating months in the calendar quarter with excess CO 2 emissions. (iii) In the final quarterly report of each calendar year you must include the following: (A) Net electric output sold to an el ectric grid over the calendar year; and (B) The potential electric output of the facility. (iv) You must submit each electronic re port using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool pr ovided by the Clean Air Markets Division in the EPA Office of Atmospheric Programs. (4) You must meet all applicable reporting re quirements and submit reports as required under subpart G of part 75 of this chapter. (5) If your affected unit uses geologic sequ estration to meet the applicable emissions limit, you must report in accordance with the requirements of 40 CFR part 98, subpart PP and either: (i) if injection occurs onsite, report in accordance with the requirements of 40 CFR part 98, subpart RR, or (ii) if injection occurs offsite, transfer the captured CO 2 to a facility or facilities that reports in accordance with the requirements of 40 CFR part 98, subpart RR. (i) For each affected electric utility stream generating unit, you must maintain records according to paragraphs (i)(1) through (i)(8) of this section. (1) You must comply with the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter. (2) You must maintain records of the calcula tions 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 cal culations you performed to determine the percentage of valid CO 2 mass emission rates in each compliance period. Deleted: ation

Deleted: ationPage **10** of **43**

(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 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record except those records required to demonstrate compliance with an 84-operating month compliance period. You must maintain records required to demonstrate compliance with an 84-operating month compliance period for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. (8) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart. (j) PSD and Title V Thresholds for Gree nhouse Gases. (1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG em issions from new affected facilities, the “pollutant that is subject to the standard pr omulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48). (2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from new affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49). (3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from new affected facilities, the “pollutant that is subject to any standard promulga ted under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 70.2. (4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from new affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 71.2. (k) For purposes of this section, the following definitions apply: Gross energy output means: (i) Except as provided under paragraph (ii) of this definition, for electric utility steam generating units, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) minus any electricity used to power the feedwater pumps plus 75 percent of the useful thermal output; (ii) For electric utility steam generating unit combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on a rolling 3 year basis, the gross electric or mechanic al output from the affected facility (including, but not limited to, output from steam turbine( s), combustion turbine(s), and gas expanders) Deleted: ation

Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application Comment [FC15]: Redundant with definition of useful thermal output

Deleted: )Page **11** of **43**

minus any electricity used to power the feedwate r 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 co mbined 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 mechanic al 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 any integrated equipment that provides electricity or useful thermal output to either the affected facility or auxiliary equi pment. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the facility during operation.
Net-electric sales means: (i) Except as provided under paragraph (ii) of this definition, the gross electric sales to the utility power distribution system minus purchased power, or (ii) For combined heat and power facilities wh ere at least 20.0 percen t of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output, the gross electric sales to the utility power distribution system minus purch ased 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 output from the affected facility plus 75 percent of the useful thermal output; or (ii) For combined heat and power facilities wh ere at least 20.0 percen t 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 Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application)

Deleted: i

Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application)

Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application)

Deleted: ;

Deleted: output Comment [FC16]: Use “net-electric sales” so we don’t have to use “for applicability purposes” and “for compliance purposes” for net electric output.

Deleted: on a calendar year basis Comment [FC17]: Not necessary since time frame specific directly in text.

Deleted: on a calendar year basis

Deleted:

. Comment [FC18]: Net electric output does not account for supplying electric power to other EGUs.For example, a simple cycle combustion turbine colocated with a coal-fired EGU would not be able to say it was supplying power to coal-fired EGU to offset auxiliary power requirements of the coal-fired EGU.

Comment [FC19]: Soliciting comment on 100% thermal creditPage **12** of **43**

net electric or mechanical output from the affected facility divided by 0.95, plus 75 percent of the useful thermal output. Potential electric output means: (i) Either 33 percent or the design net elect ric output efficiency, at the election of the owner/operator of the affected facility, (ii) Multiplied by the maximum design heat input capacity of the steam generating unit, (Btu/h) (iii) Divided by 3,413 Btu/KWh, (iv) Divided by 1,000 kWh/MWh, and (v) Multiplied by 8,760 h/yr. (vi) For example, a 35 percent efficient steam generating unit with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 310,000 MWh 12 month potential electric output capacity. Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb. Steam generating unit means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to either the boiler or auxiliary equipment. Useful thermal output means the thermal energy made available for use in any heating application (e.g., steam delivered to an industrial process for a heating application, including thermal cooling applications) that is not used fo r 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 ener gy used to reduce fuel moisture is considered useful thermal output). Useful thermal output for affected facilities with no condensate return (or other thermal energy input to the affected facility) or where measuring the energy in the condensate (or other thermal energy input to the affected facility) would not meaningfully impact the emission rate calculation is measured agai nst the energy in the thermal output at SATP conditions. Affected facilities with meaningful en ergy in the condensate return (or other thermal energy input to the affected facility) must measur e the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output. Comment [FC20]: More representative than ISO of emergy content of makeup water and ISO conditions includes relative humidity that could unnecessarily complicate the calculations of useful thermal output

Comment [FC21]: Thermal energy used for coal drying is considered useful thermal output – could be done offsite by a separate thermal source and would not be included in the calculation. Comment [FC22]: Changing from ISO conditions since SATP is closer to makeup water conditions (50 Btu/lb instead of 30 Btu/lb).Page **13** of **43**

Subpart KKKK -— Standards of Performance for Stationary Combustion Turbines 3. Section 60.4305 is amended by adding paragraph (c) to read as follows: § 60.4305 Does this subpart apply to my stationary combustion turbine?

* * * * * (c) For purposes of regulation of greenhouse gases, the applicable provisions of this subpart affect your stationary combustion turbine if it serves a generator capable of selling greater than 25 MW to a utility power distribution system and commenced construction after January 8, 2014 or it commenced reconstruction or modi fication after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER].
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 regulated by this subpart consist of carbon dioxide (CO 2 ). (2) PSD and Title V Thresholds for Green house Gases. (i) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GH G emissions from affected stationary combustion turbine, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporat e, 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, th e “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.
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 any 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 by adding paragraph (c) to read as follows: Comment [FC23]: Added to avoid covering industrial units not connected to a generator being subject to “no emision standard.” If covered by 111(b), even with no emission standard, they would be included in the 111(d) state plan.Page **14** of **43**

§ 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 de termine 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 emissions from each affected stationary combustion turbine using the procedures in paragraphs (b)(1) through (5) of this section, except as provided in paragraph (c) of this section. (1) You must install, certify, ope rate, maintain, and calibrate a CO 2 continuous emission monitoring system (CEMS) to directly measure and record CO 2 concentrations in the stationary combustion turbine exhaust gase s emitted to the atmosphere an d an exhaust gas flow rate monitoring system according to § 75.10(a)(3)(i) of this chapter. If you measure CO 2 concentration on a dry basis, you must also inst all, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to § 75.11(b) of this chapter. (2) For each monitoring system that you use to determine the 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 met hod sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, you must make measure of the diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, you must measure each dimension (i.e., de pth and width) at three or more distinct locations and average the results. If the flow rate monitor or reference method sampling site is relocated, you must repeat these measurements at the new location. (4) You must use unadjusted exhaust gas volumetric flow rates only to determine the hourly CO 2 mass emissions from the affected stationary combustion turbine; you must not apply the bias adjustment factors described in section 7. 6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data. (5) If you chose to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube asse mbly. You must not use th e default Type-S pitot tube coefficient. (c) As an alternative to comp lying with paragraph (b) of th is section, you may determinePage **15** of **43**

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 (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 nu mber of watt meters to continuously measure and record the gross electric output from the affected stationary combustion turbine. These measurements must be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. If the affected stationary combustion turbine is a CHP stationary combustion turbine, you must also install, calibrate, maintain, and operate meters to continuously determin e and record the total useful thermal output . For process steam applications, y ou will need to install, calibrate, maintain, and operate meters to continuously determine and record steam flow rate, temperature, and pressure. If the affected stationary combustion turbine has a direct mechanical drive application, you must submit a plan to the Administrator or delegated authority for approval of how gross energy output will be determined. Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination. (e) If two or more affected stationary combustion turbines serve a common electric generator, you must apportion the combined hourly gross output to the individual stationary combustion turbines using a plan approved by th e Administrator (e.g., using steam load or heat input to each affected stationary combustion turbine). Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination. (f) In accordance with § 60.13(g), if two or more stationary combustion turbines that implement the continuous emission monitoring provi sions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard under § 60.4326, you may monitor the hourly CO 2 mass emissions at the common stack in lieu of monitoring each stationary combustion turbine se parately. If you choose this option, the hourly gross load (electric, thermal, and/or mechanical, as applicable) must be the sum of the hourly loads for the individual stationary combustion turbines and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter). If you attain compliance with the applicable emissions standard in § 60.4326 at the common stack, each stationary combustion turbine sharing the stack is in compliance. (g) In accordance with § 60.13(g), if the exhaust gases from a stationary combustion turbine that implements the continuous emission monitoring provisions in paragraph (b) of this section are emitted to the atmosphere through mul tiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you chose to monitor in the ducts), you must monitor the hourly 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 determine compliance with the Deleted: recovered

Deleted: energyPage **16** of **43**

applicable emissions standard in § 60.4326 by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the total gross output for the unit.
8. Section 60.4374 is added under undesignated center heading “Monitoring” to read as follows: § 60.4374 How do I demonstrate compliance with my 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 hourly 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 affected stationary combustion turbine, and the calculation procedures in paragraphs (a)(1) through (a)(5) of this section. (1) You must only use operating hours in the compliance period for the compliance determination calculation for which you obtained valid data for all parameters you used to determine the hourly 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 this chapter for any 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 hourly gross output (P gross ) by applying the appropriate definitions in §§ 60.4420 and 60.4421 of this subpart and according to the procedures specified in paragraphs (a)(3)(i) and (iv) of this section . (i) Calculate P gross for your affected stationary combustion turbine using the following equation:

ܲ ௚௥௢௦௦ = ሺܲ݁ሻ ஼் ൅ 	 ሺܲ݁ሻ ௌ் ൅ 	 ሺܲ݁ሻ ூா T ൅ 	0.75 ൈ ሾ ሺ ܲݐ ሻ ௉ௌ ൅ ሺ ܲݐ ሻ ுோ ൅ ሺ ܲݐ ሻ ூா ሿ

Where:

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 mechanic al energy output (if any) of steam turbines in MWh. (Pe) IE = Electric energy output plus mechanic al 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. Deleted: inPage **17** of **43**

(Pt) PS = Useful thermal output of steam ( relative to SATP conditions , as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, enhance the performance of the affected facility. 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, prod uce mechanical energy output, or enhance the performance 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 electric or direct mechanical output and 20.0 percent of the total gross energy output consists of useful therma l output on a rolling 3 year basis.
T = 1.0 for all other affected stationary combustion turbines.

(ii) If applicable to your affected stat ionary combustion turbine, calculate (Pt) PS using the following equation:
ሺܲݐሻ ௉ௌ ൌ ܳ ௠ ൈ 	ܪ 3.6	 ൈ	 10 ଽ 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). (iii) You must determine the hourly gross energy output for each operating hour in which there is no electric output, but there is mechanical output or useful thermal output. In addition you must determine the hourly gross 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 applicable) by summing the hourly gross energy output you determined for each of your individual affected stationary combustion turbines that vent to the common stack; and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter). Deleted: energy
Deleted: ISO

Deleted: C

Deleted: energy
Deleted: ISO

Deleted: energy
Deleted: ISO

Deleted: provides input to the affected facility or auxiliary equipment

Deleted: energy

Deleted: ISOPage **18** of **43**

(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 appli cable 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 requirements of paragraph (a)(2) of this section by the total gross output value as calculated according to the requirements of paragraph (a)(4) of this section. (b) If the CO 2 mass emissions rate for the affect ed 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 ap plicable to the affected stationary combustion turbine, then your affected stationary combustion turbine has excess CO 2 emissions. 9. Section 60.4375 is amended by revising the section heading to read as follows: § 60.4375 What reports must I submit to comply with my 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 notifi cations 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 st ationary 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 ro lling average basis for the standard in § 60.4326, you must submit electronic quarterly reports as follows. After you have accumulated the first 12-operating months for the affected stationary combustion turbine, you must submit a report for the calendar quarter that includes the 12th-o perating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 days after the end of the quarter. (2) In each quarterly report, you must include the following information, as applicable: (i) Each rolling average CO 2 mass emissions rate for whic h 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 compliance periods that end in the quarter, you must include a statement to that effect;Page **19** of **43**

(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 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 2 of this subpart) with which your affected stationary combustion turbine is complying. (3) The final quarterly report of each calendar year must contain the following: (i) Net electric output sold to an electric grid over the 4 quarters of the calendar year; and (ii) The potential electric output of the stationary combustion turbine. (c) You must submit all electronic reports re quired under paragraph (b) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Offi ce of Atmospheric Programs of the EPA. (d) You must meet all applicable reporting re quirements 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 info rmation 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 calculati ons 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 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. (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 sitespecific 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.Page **20** of **43**

(2) You must keep each record for 5 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record to demonstrate compliance with a 12-operating month emissions standard. (3) You must keep each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may keep the records off site and electronically for the remaining year(s) as required by this subpart.
12. Section 60.4395 is revised to read as follows: § 60.4395 When must I submit my reports? All of your reports required under § 60.7(c) must be postmarked by the 30th day after the end of each 6-month period, except as specified in § 60.4376
13. Section 60.4421 is added to read as follows: § 60.4421 What definitions with respect to 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 ISO conditions using the higher heating value of the fuel (heat input from duct burners is not included).
Excess emissions means a specified averaging period over which either: (1) The 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 any associated steam turbine(s) or integrated equipment plus any useful thermal output 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). (2) For a CHP stationary combustion turbine wh ere at least 20.0 percent of the total gross energy output consists of electric or direct mechan ical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on a rolling 3-year basis, the sum of the gross electric or direct mechan ical output from both the combustion turbine engine and any associated steam turbine(s) divided by 0.95 plus any useful thermal output measured relative to 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: Deleted: ISO

Deleted: ISO

Deleted: outputPage **21** of **43**

(1) The gross electric sales to the utility power distribution system minus purchased power; or (2) For combined heat and power facilities wh ere at least 20.0 percent of the total gross energy output consists of electric or direct mechan ical output and at least 20.0 percent of the total gross energy output consists of useful thermal ou tput on a 3 calendar year rolling average basis, the gross electric sales to the utility power distribution system minus purchased power of the thermal host facility or facilities ; and (3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads are included when calculating net-electric sales. Net-electric output means: the amount of gross generation a generator produces, as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and transformer losses as m easured 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 wh ere at least 20.0 percen t of the total gross energy output consists of electric or direct mechan ical output and at least 20.0 percent of the total gross energy output consists of useful thermal outp ut on a rolling 3 year basis, the net electric or mechanical output from both the combustion turbine engine and any associated steam turbine(s) or integrated equipment divided by 0.95, plus 75 percent of the useful thermal output. Operating month means a calendar month during which any fuel is combusted in the affected stationary combustion turbine. Potential electric output means 33 percent or the design electric output efficiency on a net output basis (at the election of the owner/operator of the affected facility) multiplied by the base load rating (expressed in MMBtu/h) of the stat ionary combustion turbine, multiplied by 10 6 Btu/MMBtu, divided by 3,413 Btu/KWh, divide d by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 percent efficient stationary combustion turbine with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 310,000 MWh 12-month potential electric output capacity). Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb. Stationary combustion turbine means all equipment, including but not limited to the combustion turbine engine, the fuel, air, lubrica tion and exhaust gas systems, control systems, heat recovery system, steam turbine, fuel compressor, heater, and/or pump, post-combustion emission control technology, and any ancillary components a nd sub-components plus any integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustion turbine is not self propelled or intended to be propelled while performing its function. It may, Deleted: on a 3 calendar year rolling average basis

Deleted: on a three calendar year rolling average basis

Deleted:

.Page **22** of **43**

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 fo r 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 ener gy used to reduce fuel moisture is considered useful thermal output). Useful thermal output for affected facilities with no condensate return (or other thermal energy input to the affected facility) or where measuring the energy in the condensate (or other thermal energy input to the affected facility) would not meaningfully impact the emission rate calculation is measured agai nst the energy in the thermal output at SATP conditions. Affected facilities with meaningful en ergy in the condensate return (or other thermal energy input to the affected facility) must measur e the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output.Page **23** of **43**

14. Table 2 of Subpart KKKK of Part 60 is added to read as follows:
Table 2 of Subpart KKKK of Part 60 – Carbon Di oxide 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), that combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and where netelectric sales consist of more than one-third of its potential electric output and more than 219,000 MWh on a 3 year rolling average basis. 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), that combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and where netelectric sales consist of more than one-third of its potential electric output and more than 219,000 MWh on a 3 year rolling average basis.. 500 kg of CO 2 per MWh of gross output (1,100 lb CO 2 /MWh) on a 12-operating month rolling average

Stationary combustion tu rbine that either has a design heat input to the turbine engine of 73 MW (250 MMBtu/h) or less, that combusts 90% or less natural gas on a heat input basis on a 3 year rolling average basis, or where netelectric sales consist of one-third or less of its potential electric output or 219,000 MWh or less on a 3 year rolling average basis. No emission standard Deleted: to

Deleted: to

Deleted: that supplies

Deleted: net-electric output to a utility distribution system

Deleted: that supplies

Deleted: net-electric output to a utility distribution system

Deleted: that supplies

Deleted: net-electric output to a utility distribution systemPage **24** of **43**

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 Information Yes § 60.10 State authority Yes

§ 60.11 Compliance with standards and maintenance requirements No

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

§ 60.18 General control device requirements No

§ 60.19 General notification and reporting requirements Yes Deleted: to

Deleted: toPage **25** of **43**

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 I subject to this subpart?

Emission Standards

§ 60.5515 What 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

§ 60.5550 What notifications must I submit and when? § 60.5555 What reports must I submit and when? § 60.5560 What records must I maintain? § 60.5565 In what form and how long must I keep my records?

Other Requirements and Information

§ 60.5570 What parts of the General Provisions apply to my affected facility? § 60.5575 Who implements and enforces this subpart? § 60.5580 What definitions apply to this subpart?

Applicability § 60.5508 What is the purpose of this subpart? This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a steam generating unit, IGCC, or a stationary combustion turbine that commences construction after January 8, 2014 or commences modification or reconstruction after [INS ERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]. Deleted: Utilit y Comment [FC24]: Make consistent

Deleted: § 60.5530 Affirmative defense for violation of emission standards during malfunction¶Page **26** of **43**

§ 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 serves a generator capable of selling greater than 25 MW t o a utility power distribution system and that commences construction after January 8, 2014 or commences modification or reconstruction after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]. (b) You are not subject to the requirements of th is 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 Environm ental Quality, Air Quality Division, effective June 29, 2011 (as revised July 12, 2011). (2) The proposed Washington County EGU project described in Air Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, eff ective April 8, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014. (3) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment, effective December 16, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014. (4) Your affected facility is a municipal wast e combustor unit that is subject to subpart Eb of this part. (5) Your affected facility is a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part.
Emission Standards § 60.5515 What greenhouse gases are regulated by this subpart? (a) The greenhouse gas regulated by this subpart is carbon dioxide (CO 2 ). (b) PSD and Title V Thresholds for Green house Gases. (1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GH G emissions from aff ected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48). (2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is 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 52.21(b)(49). (3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 70.2. Comment [FC25]: Add to avoid covering large industrial units that to not generate sufficient electricity to be subject to the 219,000 MWh requirement. If covered by 111(b), even with no emission standard, they would be included in the 111(d) state plan.Page **27** of **43**

(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 any 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 complying with the standards sp ecified 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 paragrap h 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 ow ner/operator may elect to comply with a sitespecific 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 years 2002 through the most recent full calendar year the affected facility was operating prior to the modification using either recorded net output emission rate data or gross electrical output and 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. The equivalent net output-based standard shall be calculated from gross output-based data assuming a 7.5 percent auxilia ry (i.e., parasitic) load (i.e., th e best annual value is divided by 0.925); or (2) If the affected facility is subject to an approved CAA section 111(d) plan (state or federal) at the time of the modification, a s ite-specific 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 systems to identify applicable energy efficiency projects that you will implement at the affected facility to improve the affected facility’s operating performance. You must maintain a copy of the most recent energy assessment report. The energy assessment must include at a minimum the elements in paragraphs (b)(2)(i) through (b)(2)(iii) of this section. (i) A visual inspection of the facility to identify steam leaks or other sources of reduced efficiency, (ii) A review of available engineering pl ans and facility operation and maintenance procedures and logs, and (iii) A comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, and the time frame for recouping those investments. General Compliance Requirements § 60.5525 What are my general requirements for complying with this subpart? Deleted: stack into the atmospherePage **28** of **43**

(a) You must be in compliance with the emissi on standards in this subpart that apply to your affected facility at all times. However, you must make a compliance determination only at the end of the applicable operating month, as provided in paragraphs (a)(1) and (2) of this section. (1) For each affected facility subject to a CO 2 emissions standard based on a 12-operating month rolling average, you must determine co mpliance monthly by 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 monthly 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, including associated equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practice. The Administrator will determ ine if you are using consistent operation and maintenance procedures based on information ava ilable to the Administrator that may include, but is not limited to, fuel use records, monitori ng results, review of operation and maintenance procedures and r ecords, review of reports re quired by this subpart, and inspection of the facility. (c) You must conduct an initial compliance determination for your affected facility for the applicable emissions standard in § 60.5520, according to the requirements in this subpart, within 30 days after the end of the initial compliance period for the CO 2 emissions standards applicable to your affected facility (i.e., 12-ope rating 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? (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, ope rate, maintain, and calibrate a CO 2 continuous emission monitoring system (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 system 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, mainta in, and calibrate a continuous moisture monitoring system, according to § 75.11(b) of this chapter. (2) For each monitoring system you use to determine the 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 met hod sampling locations prior to the initial setup (characterization) of the flow monitor. For circ ular stacks, you must measure the diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, you must Deleted: § 60.5530 Affirmative defense for violation of emission standards during malfunction Comment [FC26]: As discussed in the preamble,

we are not including a regulatory affirmative defense to civil penalties for violations caused by malfunctions in light of the recent decision in NRDC

v. EPA, No. 10

‐ 1371 (D.C. Cir. April 18, 2014) 2014 U.S. App. LEXIS 7281 (vacating affirmative defense provisions in Section 112(d) rule establishing emission standards for Portland cement kilns).

Deleted: .¶ In response to an action to enforce the standards set forth in § 60.5520, you may assert an affirmative defense to a claim for civil penalties for violations of such standards that are caused by malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be assessed if you fail to meet your burden of proving all of the requirements in the affirmative defense. The affirmative defense shall not be available for claims for injunctive relief.¶ (a) Assertion of affirmative defense. To establish the affirmative defense in any action to enforce such a standard, you must timely meet the reporting requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that:¶ (1) The violation:¶ (i) Was caused by a sudden, infrequent, and unavoidable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner; and¶ (ii) Could not have been prevented through careful planning, proper design or better operation and maintenance practices; ¶ (iii) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; ¶ (iv) Was not part of a recurring pattern indicative of inadequate design, operation, or maintenance; ¶ (2) Repairs were made as expeditiously as possible when the violation occurred; ¶ (3) The frequency, amount and duration of the violation (including any bypass) were minimized to the maximum extent practicable; ¶ (4) If the violation resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage;¶ (5) All possible steps were taken to minimize the impact of the violation on ambient air quality, the environment, and human health; ¶ (6) All emissions monitoring and control systems were kept in operation if at all possible, consistent with safety and good air pollution control practices; ¶ (7) All of the actions in response to the violation were documented by properly signed, contemporaneous operating logs; ¶ (8) At all times, the affected source was operated in a manner consistent with good practices for minimizing emissions; and¶ (9) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the violation resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of any emissions that were the result of the malfunction.¶ ... [1]Page **29** of **43**

measure each dimension (i.e., depth and width) at three or more distinct locations and average the results. If the flow rate m onitor or reference method sampling site is relocated, you must repeat these measurements at the new location. (4) You must use only unadjusted exhaust gas volumetric flow rates to determine the hourly CO 2 mass emissions from the affected facility; you must not apply the bias adjustment factors described in section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data. (5) If you choose to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube asse mbly. You must not use th e default Type-S pitot tube coefficient. (c) If your affected facility exclusively combus ts 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 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-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 nu mber of watt meters to continuously measure and record the gross or net electric output from th e affected facility. These measurements must be performed using 0. 2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. If the affected facility is a CHP facility, you must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful 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 se rve a common electric generator, you must apportion the combined hourly gross or net output to the individual affected facilities using a plan approved by the Administrator (e.g., using st eam load or heat input to each affected EGU). Your plan shall ensure that you install, calibra te, 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 Comment [FC27]: Additional requirement for consistent accuracy

Deleted: recovered

Deleted: energy Comment [FC28]: Requesting comment on requirements for consistent accuracy of steam measurementsPage **30** of **43**

separately. If you choose this option, the hourly gross or net load (electric, thermal, and/or mechanical, as applicable) must be the sum of th e 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 operati ng time” (as defined in § 72.2 of this chapter) at each stack or duct separately. In this case, you must determine compliance with the applicable emissions standard in § 60.5520 by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the total gross or net output for the affected facility. §60.5540 How do I demonstrate compliance with my CO 2 emissions standard and determine excess emissions? (a) You must calculate the CO 2 mass emissions rate for your affected facility by 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 procedures in paragraphs (a)(1) through (a)(5) of this section. (1) You can only use operating hours in the compliance period for the compliance determination calculation if valid data are obtained for all parameters you used to determine the hourly CO 2 mass emissions and the gross or net output data are used for the compliance determination calculation. You must not include operating hours in which you used the substitute data provisions of part 75 of this chapter for any of those parameters in the calculation. For the compliance determination calculation, you must obtain valid hourly 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 calculate 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 section to calculate the total CO 2 mass emissions, you must dete rmine the affected facility’s corresponding hourly gross or net output according to the procedures in paragraphs (a)(3)(i) and (ii) of this section, as appropriate for the type of affected facility. For an operating hour in which there is no gross or net electric load, but there is mechanical or useful thermal output, you must still determine the gross or net output for that hour. In additio n, 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:

ܲ

௚௥௢௦௦ /௡௘௧ = ሺ ܲ݁ ሻ ௌ் ൅ ሺ ܲ݁ ሻ ஼் ൅ ሺ ܲ݁ ሻ ூா െ ሺܲ݁ሻ ிௐ T ൅ 	0.75 ൈ ሾ ሺ ܲݐ ሻ ௉ௌ ൅ ሺ ܲݐ ሻ ுோ ൅ ሺ ܲݐ ሻ ூா ሿ Comment [FC29]: During periods of startup/shutdown where the facility is not generating power and “purchasing” power to run the facility net electricity is negative. There periods will be counted as zero and not negative.Page **31** of **43**

Where: a

P gross /net = Gross or net energy output of your affected facility in megawatt-hours ( MWh )

. (Pe) ST = Electric energy output plus mechanic al 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 mechanic al energy output (if any) of your affected facility’s integrated equipment that provides electricity or mechanical energy to the affected facility or auxiliary equipment in MWh. (Pe) FW = Electric energy used to power boiler feedwater pumps at steam generating units in MWh. Not applicable to stationary combustion turbines
, 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 electricity, produce mechanical energy output, or enhance the performance 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) from any integrated equipment that is used for applications that do not generate additional steam, electricity, prod uce 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 mech anical output and 20.0 percent of the total gross or net energy output consists of useful thermal output on a rolling 3 year basis.
T = 1.0 for all other affected facilities.

(ii) If applicable to your affected facility, you must calculate (Pt) PS using the following equation:
ሺܲݐሻ ௉ௌ ൌ ܳ ௠ ൈ 	ܪ 3.6	 ൈ	 10 ଽ Where: Deleted: in

Deleted: or Comment [FC30]: Feedwater pump energy use already accounted for when calculating net output.

Deleted: energy
Deleted: ISO Comment [FC31]: Standard ambient temperature and pressure are a better approximation of the energy in condensate/makeup water than ISO conditions.

Deleted: C

Deleted: Hourly

Deleted: energy
Deleted: ISO

Deleted: energy
Deleted: ISO

Deleted: provides thermal energy to the affected facility or auxiliary equipment

Deleted: energyPage **32** of **43**

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 the 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 facility 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 the 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 your 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) and 60.19, as applicable to your affected facility. (b) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable to your affected facility. § 60.5555 What reports must I submit and when? (a) You must prepare and submit reports according to paragraphs (a) through (d) of this section, as applicable. (1) For affected facilities that are required by § 60.5525 to conduct initial and on-going compliance determinations on a 12- or 84-operating month rolling average basis for the standard in § 60.5520 you must submit electronic quarterly reports as follows. After you have accumulated the first 12-operating months for the affected facility (or, the first 84-operating months for an affected facility electing to comply with the 84 -operating month standard), you must submit a report for the calendar quarter that includes the twelfth (or eighty-fourth) operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 days after the end of the quarter. (2) In each quarterly report you must include the following information, as applicable: (i) Each rolling average CO 2 mass emissions rate for which the last (12th or eightyfourth) operating month in a 12- or 84-operating month compliance period falls within the Deleted: ISOPage **33** of **43**

calendar quarter. You must calculate each average CO 2 mass emissions rate according to the procedures in § 60.5540. You must report the dates (month and year) of the first and twelfth (or eighty-fourth) operating months in each compliance period for which you performed a 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; (iii) 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 peri od divided 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 calendar year, you must include the following: (i) Gross electric output sold to an electric grid over the 4 quarters of the calendar year; and (ii) The potential electric output of the facility. (b) You must submit all electronic reports re quired 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 Of fice of Atmospheric Programs of EPA. (c) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter. (d) If your affected unit employs geologic se questration to meet th e applicable emission limit, you must report in accordance with the requirements of 40 CFR part 98, subpart PP and either: (1) if injection occurs onsite, report in accordance with the requirements of 40 CFR part 98, subpart RR, or (2) if injection occurs offsite, transfer the captured CO 2 to a facility or facilities that reports in accordance with the requirements of 40 CFR part 98, subpart RR. § 60.5560 What records must I maintain? (a) You must maintain records of the info rmation 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 calculati ons 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.Page **34** of **43**

(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 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 § 60.5520.(g) You must keep records of the calculations you performed to determine any sitespecific carbon-based F-factors you used in the emissions calculations (if applicable). § 60.5565 In what form and how long must I keep my records? (a) Your records must be in a form suitable and readily available for expeditious review. (b) You must maintain each record for 5 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record except those records required to demonstrate compliance with an 84-operating month compliance period. You must maintain records required to demonstrate compliance with an 84-operating month compliance period for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. (c) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart. Other Requirements and Information § 60.5570 What parts of the General Provisions apply to my affected facility? Notwithstanding any other provision of this chapter, certain parts of the General Provisions in §§ 60.1 through 60.19, listed in Table 2 of this subpart, do not apply to your affected facility. § 60.5575 Who implements and enforces this subpart? (a) This subpart can be implemented and enforced by the EPA, or a delegated authority such as your state, local, or tribal agency. If the Administrator has delegated authority to your state, local, or tribal agency, then that agency (as well as the EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your state, local, or tribal agency. (b) In delegating implementation and enforcement authority of this subpart to a state, local, or tribal agency, the Administrator reta ins 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 alte rnatives to monitoring.Page **35** of **43**

(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 define d 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 determ ined by the physical design and characteristics of the steam generating unit at ISO 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 ISO conditions (heat input from duct burners is not included).
Coal means all solid fuels classified as anthr acite, 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 mi xtures, and coal-water mixtures are included in this definition for the purposes of this subpart.
Coal refuse means waste products of coal mining, physical coal cleaning, and coal preparation operations ( e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material. Combined cycle facility means an electric generating unit that uses a stationary combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat recovery steam generating unit to generate additional electricity. Combined heat and power facility or CHP facility , ( also known as “cogeneration”) means an electric generating unit that that use a steam-g enerating 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 by reference, see § 60.17); diesel fuel oil numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see § 60.17); kerosene, as defined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see § 60.17); biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see § 60.17); or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see § 60.17).
Excess emissions means a specified averaging period over which the 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, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
Gaseous fuel means any fuel that is present as a gas at ISO conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and Deleted: Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding.¶

Deleted: energyPage **36** of **43**

gasified coal. Gross energy output means: (1) For stationary combustion turbines and IG CC facilities, the gross electric or direct mechanical output from both the unit (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) plus 75 percent of the useful thermal output. (2) For electric utility steam generating uni ts, the gross electric or mechanical output from the affected facility (including, but not lim ited to, output from stea m turbine(s), combustion turbine(s), and gas expander(s)) minus any electrici ty used to power the feedwater pumps plus 75 percent of the useful thermal output; (3) For combined heat and power facilities wh ere at least 20.0 percent of the total gross energy output consists of electric or direct mech anical output and 20.0 percent of the total gross energy output consists of useful thermal output on a rolling 3 year basis, the gross electric or mechanical output from the affected facility (i ncluding, 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, pl us 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 gene rating units can be used with or without duct burners. Integrated gasification combined cycle facility or IGCC facility means a combined cycle facility that has a design heat input greater th an 73 MW (250MMBtu/h) heat input of fossil fuel (either alone or in combination with any other fuel), was constructed for the purpose of supplying one-third or more of its potential electric output and more than 219,000 MWh for netelectric sales on an annual basis, and is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas plus any integrated equipment that provides electricity or useful th ermal output to either the affected facility or auxiliary equipment. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system constr uction, 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 IS O conditions and includes, but is not limited to, distillate oil and residual oil. Mechanical output means the useful mechanical energy that is not used to operate the affected facility, generate electricity and/or thermal energy, or to enhance the performance of the affected facility. Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000. Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application)

Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application)

Deleted: measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application)

Formatted: Underline

Deleted: supplies

Deleted: net-electric output to a utility distribution systemPage **37** of **43**

20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value.
Net-electric sales means: (1) The gross electric sales to the utility power distribution system minus purchased power; or (2) For combined heat and power facilities wh ere at least 20.0 percent of the total gross energy output consists of electric or direct mechan ical output and at least 20.0 percent of the total gross energy output consists of useful thermal ou tput, the gross electric sa les to the utility power distribution system minus pur chased 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 output means: the amount of gross generation the generator(s) produces (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)), as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale). Net energy output means: (i) Except as provided under paragraph (ii) of this definition, the net electric or mechanical output from the affected facility plus 75 percent of the useful thermal output; or (ii) For combined heat and power facilities wh ere at least 20.0 percen t of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a rolling 3 year basis, the net electric or mechanical output from the affected facility divided by 0.95, plus 75 percent of the useful thermal output; Operating month means a calendar month during which any fuel is combusted in the affected facility at any time.
Petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, distillate and residual oil. Potential electric output means 33 percent or the design electric output efficiency on a net output basis multiplied by the maximum design h eat input capacity (exp ressed 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 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 li quid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, and pulverized solid fuels. Deleted: output

Deleted: on a three calendar year rolling average basis

Deleted: on a 3 calendar year rolling average basis

Deleted: on a three calendar year rolling average basis

Deleted:

.

Deleted: 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). Comment [FC32]: Deleted oil since it is used in EGU NESHAP, and added petroleum since it is used in the EGU NSPS.

Deleted: ¶Page **38** of **43**

Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb. Stationary combustion turbine means all equipment, including but not limited to the turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery syst em, fuel compressor, heater, and/or pump, postcombustion emission control technology, and any ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system plus any integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustion turbine is not self propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. If a statio nary 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) that 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) and that was constructed for the purpose of supplying one-third or more of its potential electric output and more than 219,000 MWh as net-electric sales an annual basis plus any integrated equipment that provides electricity or useful thermal output to the affected facility or auxiliary equipment. Useful thermal output means the thermal energy made available for use in any 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 ener gy used to reduce fuel moisture is considered useful thermal output)

. Useful t hermal output for affected facilities with no condensate return (or other thermal energy input to the affected facility) or where measuring the energy in the condensate (or other thermal energy input to the affected facility) would not meaningfully impact the emission rate calculation is measured agai nst the energy in the thermal output at SATP conditions. Affected facilities with meaningful en ergy in the condensate return (or other thermal energy input to the affected facility) must measur e the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output.

. Deleted: supplies

Deleted: net-electric output to a utility distribution system on

Deleted: industrial or commercial process, or used in any

Deleted: or cooling

Deleted:

, Deleted: i.e., total thermal energy made available for processes and applications other than

Deleted: T

Deleted: this subpart means the energy in recovered thermal output measured against the energy in the thermal output at ISO conditions

Deleted: ¶Page **39** of **43**

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 tu rbine that has a base load rating heat input to the turbine engine of greater than 250 MW (850 MMBtu/h), that combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and where net-electric sales consist of more than one-third of its potential electric output and more than 219,000 MWh on a 3 year rolling average basis. 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), that combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and where net-electric sales consist of more than one-third of its po tential electric output and more than 219,000 MWh on a 3 year rolling average basis. 500 kg of CO 2 per MWh of gross output (1,100 lb CO 2 /MWh) on a 12-operating month rolling average

Stationary combustion tu rbine that either has a design heat input to the turbine engine of 73 MW (250 MMBtu/h) or less, that combusts 90% or less natural gas on a heat input basis on a 3 year rolling average basis, or where net-electric sales consist of one-third or less of its potential electric output or 219,000 MWh or less on a 3 year rolling average basis. No emission standard

Steam generating unit that burns fossil fuel for more than 10.0 percent of the heat input during a 3 year rolling average basis. 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 that burn s fossil fuel for more than 10.0 percent of the heat input during a 3 year rolling average basis. 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- Deleted: to

Deleted: that supplies

Deleted: net-electric output to a utility distribution system

Deleted: that supplies

Deleted: net-electric output to a utility distribution system

Comment [FC33]: Moved with table so the standards are grouped together by type of facility.

Deleted: average annual

Deleted: average annualPage **40** of **43**

operating month rolling average basis.

Steam generating unit or IGCC facility that burns fossil fuel for 10.0 percent or less of the heat input during a 3 year rolling average basis. No emission standard Deleted: Stationary combustion turbine that either has a design heat input to the turbine engine of 73 MW (250 MMBtu/h) or less , that combusts 90% or less natural gas on a heat input basis on a 3 year rolling average basis, or that supplies one-third or less of its potential electric output or 219,000 MWh or less net-electric output to a utility distribution system on a 3 year rolling average basis.

Deleted: No emission standard

Deleted: average annualPage **41** of **43**

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 PUBLICATION 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), that combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and where net-electric sales consist of more than one-third of its po tential electric output and more than 219,000 MWh on a 3 year rolling average basis. 510 kg of CO 2 per MWh of gross output (1,100 lb CO 2 /MWh) on a 12-operating month rolling average

Stationary combustion tu rbine that has a base load rating heat input to the turbine engine of greater than 250 MW (850 MMBtu/h), that combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and where net-electric sales consist of more than one-third of its po tential electric output and more than 219,000 MWh on a 3 year rolling average basis. 460 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 tu rbine that either has a design heat input to the turbine engine of 73 MW (250 MMBtu/h) or less, that combusts 90% or less natural gas on a heat input basis on a 3 year rolling average basis, or where net-electric sales consist of one-third or less of its potential electric output or 219,000 MWh or less on a 3 year rolling average basis. No emission standard

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 and that burns fossil fuel for more than 10.0 percent of the heat input during a 3 year rolling average basis. 950 kg of CO 2 per MWh of net energy output (2,100 lb CO 2 /MWh) on a 12-operating month rolling average basis;

Steam generating unit or IGCC facility that 860 kg of CO 2 per MWh of net energy output

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 ti me of the modification or m odified 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. Comment [FC34]: Redundant with the 25 MW generator general applicability criterion.

Comment [FC35]: Soliciting comment on potential complications of having electric sales criteria on a different time frame than the emission standard averaging period

Comment [FC36]: Redundant with the 25 MW generator general applicability criterion Comment [FC37]: Soliciting comment on an appropriate emission standard

Comment [FC38]: Soliciting comment on potential complications of having fuel use criterion on a different time frame than the emission standard averaging periodPage **42** of **43**

has a design heat input greater than 590 MW (2,000 MMBtu/h) and that burns fossil fuel for more than 10.0 percent of the heat input during a 3 year rolling average basis. (1,900 lb CO 2 /MWh) on a 12-operating month rolling average basis;

Steam generating unit or IGCC facility that burns fossil fuel for 10.0 percent or less of the heat input during a 3 year rolling average basis. No emission standardPage **43** of **43**

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

General Provisions citation Subject of citation Applies to subpart TTTT Explanation

§ 60.1 Applicability Yes § 60.2 Definitions Yes Additional terms defined in § 60.5580 § 60.3 Units and Abbreviations Yes § 60.4 Address Yes

§ 60.5 Determination of construction or modification Yes

§ 60.6 Review of plans Yes

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

§ 60.11 Compliance with standards and maintenance requirements No

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

§ 60.18 General control device requirements No

§ 60.19 General notification and reporting requirements Yes Deleted: 2

Deleted: toPage 28: [1] Deleted Fellner, Christian 5/28/2014 1:39:00 PM



## . In response to an action to enforce the sta ndards set forth in § 60.5520, you may assert an affirmative defense to a claim for civil penalties for violations of such standards that are caused by malfunction, as defined at 40 CFR 60.2. Appropria te penalties may be a ssessed if you fail to meet your burden of proving a ll of the requirements in the affi rmative defense. The affirmative defense shall not be available fo r claims for injunctive relief. (a) Assertion of affirmative defense. To esta blish the affirmative defense in any action to enforce such a standard, you must timely meet th e reporting requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that: (1) The violation: (i) Was caused by a sudden, infrequent, and unavoidable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner; and (ii) Could not have been prevented thr ough careful planning, prope r design or better operation and maintenance practices; (iii) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; (iv) Was not part of a recu rring pattern indicative of in adequate design, operation, or maintenance; (2) Repairs were made as e xpeditiously as possible when the violation occurred; (3) The frequency, amount and duration of the violation (includi ng any bypass) were minimized to the maximu m extent practicable; (4) If the violation resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life , personal injury, or severe property damage; (5) All possible steps were taken to minimize the impact of the vi olation on ambient air quality, the environment, and human health; (6) All emissions monitoring a nd control systems were kept in operation if at all possible, consistent with safety a nd good air pollution c ontrol practices; (7) All of the actions in response to the vi olation were documented by properly signed, contemporaneous operating logs; (8) At all times, the affected source was operated in a manner consistent with good practices for minimizing emissions; and (9) A written root cause analysis has been prep ared, the purpose of which is to determine, correct, and eliminate th e primary causes of the malfunction a nd the violation resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of any emissions that were th e result of the malfunction. (b) Report. The owner or operator seeking to assert an affirmative defense shall submit a written report to the Administrat or to demonstrate, with all necessary supporting documentation, that it has met the requir ements set forth in paragraph (a) of this section. This affirmative defense

## report is due after the initial occurrence of the exceedance of the standard in § 60.5520, and on the same quarterly reporting schedule as in § 60.5555 (which may be the end of any applicable averaging period). If such quarter ly report is due less than 45 days after the initial occurrence of the violation, the affirmative defense report ma y be included in the fo llowing quarterly report required in § 60.5555(a).