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## Fellner, Christian From: Hutson, Nick Sent: Thursday, December 19, 2013 2:52 PM To: Fellner, Christian Subject: Please docket - FW: Revised (RLSO) versions of regulatory text Attachments: EO 12866 EGU GHG NSPS 2060-AQ91 NPRM 20130628 REGTEXT_083013.docx; EO 12866 EGU GHG NSPS 2060-AQ91 NPRM 20130628 REGTEXT_083013x.pdf

From: Hutson, Nick Sent: Friday, August 30, 2013 5:38 PM To: Frey, Nathan J. Cc: Culligan, Kevin; Wayland, Robertj; Tsirigotis, Peter Subject: Revised (RLSO) versions of regulatory text



### Revised regulatory text is attached.

From: Hutson, Nick Sent: Friday, August 30, 2013 5:36 PM To: 'Frey, Nathan J.' Cc: Culligan, Kevin; Wayland, Robertj; Tsirigotis, Peter Subject: Revised (RLSO) versions of preamble; EPA response



### Nathan Attached to this email are three files: (1) A PDF version of the redline changes to the preamble (2) A MSWord version of the redline changes to the preamble (3) An updated ‘EPA Response’ to the Interagency Comments
In emails immediately following this one, I will send versions of the

... (1) Revised regulatory language (2) Revised RIA chapters; and (3) A DRAFT version of a TSD entitled “ Fossil Fuel
‐ Fired Boiler and IGCC EGU Projects Under Development: Status and Approach”

We have made many changes in response to comments from OMB and the Interagency Workgroup. We are still considering some comments. Those are noted in the text and in the EPA Response. We can continue to discuss specific comments and other aspects of the package once you have had the opportunity to see the edits in these revised versions.
Have a nice holiday and a relaxing time off next week. Regards, Nick2 

### Nick Hutson, PhD Energy Strategies Group U.S. Environmental Protection Agency Research Triangle Park, NC 27711 (919) 541

‐ 2968 hutson.nick@epa.gov***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 1 of 52 For the reasons stated in the preamble, title 40, chapter I, part 60, 70, 71, and 98 of the Code of the Federal Regulations is proposed to be amended as follows: **PART 60-- [AMENDED]**  **STANDARDS OF PERFORMANCE FOR NEW STATIONARY**
**SOURCES** 1. The authority citation for part 60 continues to read as follows: Authority: 42 U.S.C. 7401, et seq. **Subpart Da-— [Amended]**  **Standards of Performance for Electric Utility Steam Generating Units**  2. Section 60.46Da is revised added to read as follows: **§ §**  **60.46Da Standards for carbon dioxide (CO 2**  **)** (a) Your electric utility steam generating unit or IGCC electric utility steam generating unit is subject to this section if construction commenced on or after [ INSERT DATE OF
FINAL RULE PUBLICATION IN THE FEDERAL REGISTER], and the affected facility meets the conditions specified in paragraph (a) (1) and (a) (2) of this sub section, except as specified in paragraph (b) of this section. (1) The affected facility burns fossil fuel for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 2 of 52 (2) The affected facility supplies more than one-third ofits potential electric output and more than 219,000 MWh netelectrical output to a utility power distribution system for sale. (b) The following EGUs are not subject to this section: (1) The proposed Wolverine EGU project described in Permit to Install No. 317-07 issued by the Michigan Department of Environmental Quality, Air Quality Division, effective June 29, 2011 (as revised July 12, 2011). (2) The proposed Washington County EGU project described in Air Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, effective April 8, 2010, provided that a complete request for an applicability determination for the project has been submitted to [INSERT APPROPRIATE EPA CONTACT INFORMATION] no later than 120 days after [ DATE OF FINAL RULE PUBLICATION IN THE FEDERAL
REGISTER INSERT DATE OF FEDERAL REGISTER PUBLICATION ] and EPA determines that construction had not commenced for NSPS purposes as of [ DATE OF FINAL RULE PUBLICATION IN THE FEDERAL
REGISTER INSERT DATE OF PUBLICATION FOR 111(a)( 2) PURPOSES ]. (3) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3 of 52 effective December 16, 2010, provided that a complete request for an applicability determination for the project has been submitted to [INSERT APPROPRIATE EPA CONTACT INFORMATION] no later than 120 days after [ DATE OF FINAL RULE PUBLICATION IN THE
FEDERAL REGISTER INSERT DATE OF FEDERAL REGISTER PUBLICATION ] and EPA determines that construction had not commenced for NSPS purposes as of [ DATE OF FINAL RULE PUBLICATION IN THE FEDERAL
REGISTER INSERT DATE OF PUBLICATION FOR 111(a)(2) PURPOSES ]. (c) No As owner or operator of an affected facility subject to this section , you shall not cause to be discharged into the atmosphere from the affected facility any gases that contain CO 2 in excess of the emissions limitation specified in either paragraph (c) (1) or (c) (2) of this sub section. (1) 450 500 kilograms (kg) of CO 2 per megawatt-hour (MWh) of gross energy output ( 1, 000 1,100 lb CO 2 /MWh) on a 12-operating month rolling average basis; or (2) 480 kg of CO 2 per MWh of gross energy output (1,050 lb
CO 2 /MWh) on a 60-operating month rolling average basis. (d) Your affected facility must be in compliance at all times with the applicable CO 2 emission limitation in paragraph (c) of this section for which you have elected to comply. However, c C ompliance determinations are only to be made at the end of each operating month, as provided in paragraphs (d) (1)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 4 of 52
and (d) (2) of this subs s ection. For the purpose of this section, operating month means a calendar month during which any fossil fuel is combusted in an affected facility at any time. (1) If you elect to comply with the CO 2 emissions limitation in paragraph (c)(1) of this section, you must determine compliance monthly by calculating the average CO 2 emissions rate for the affected facility at the end of each preceding 12- operating month period. (2) If you elect to comply with the CO 2 emissions limitation in paragraph (c)(2) of this section, you must determine compliance monthly by calculating the average CO 2 emissions rate for the affected facility at the end of each preceding 60- operating month period. (e) You must conduct an initial CO 2 emissions limitation determination for your affected facility within 30 days after the required number of operating months for the CO 2 emission s limitation operating month compliance period that you have elected to comply with have been accumulated (i.e., 12-operating months or 60-operating months ) . The first operating month included in this compliance period is the month in which emissions reporting is required to begin under § § 75.64(a) of this chapter part .***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 5 of 52 (f) You must monitor and collect data to demonstrate compliance with the CO 2 emissions limitation according to the requirements specified in paragraphs (f)(1) through (4) of this section. (1) You must prepare a monitoring plan in accordance with the applicable provisions in § § § 75.53(g) and (h) of this chapter part . (2) You must measure the hourly CO 2 mass emissions from each affected facility using the procedures specified in paragraphs (f)(2)(i) through (vii) of this section, except as provided in paragraph (3) of this section. (i) You must install, certify, operate, maintain, and calibrate a CO 2 continuous emission monitoring system (CEMS) to directly measure and record CO 2 concentrations in the exhaust gases from your affected facility that are vented to the atmosphere and an exhaust gas flow rate monitoring system according to § § 75.10(a)(3)(i) of this chapter part . If CO 2 concentration is measured on a dry basis, you must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to § § 75.11(b) of this chapter part . (ii) For each monitoring system used to determine the CO 2 mass emissions, you must meet the applicable certification and***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 6 of 52 quality assurance procedures in § § 75.20 of this chapter part and appendices B and D to part 75 of this chapter part . (iii) You must use a laser device to measure each exhaust gas stack or duct dimensions at the flow monitor and the reference method sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, make three determinations of the diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, make three measurements of each dimension at three or more distinct locations (i.e., depth and width) and average the results. If the flow rate monitor or reference method sampling site is relocated, repeat these measurements at the new location. (iv) Only unadjusted exhaust gas volumetric flow rates can be used to determine the hourly CO 2 mass emissions from the affected facility; the bias adjustment factors described in Section 7.6.5 of Appendix A to part 75 of this chapter part cannot be applied to the exhaust gas flow rate data. (v) If you elect to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube assembly. Use of the default Type-S pitot tube coefficient is not permitted.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 7 of 52 (vi) If two or more affected facilities share a common exhaust gas stack and are subject to the same CO 2 emissions limitation in paragraph (c) of this section, you may monitor the hourly CO 2 mass emissions at the common exhaust gas stack in place of monitoring each affected facility separately. (vii) If the exhaust gases from the affected facilities are vented to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly CO 2 mass emissions and the “stack operating time” (as defined in § § 72.2 of this chapter part ) at each stack or duct separately. (3) You must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record the gross electrical output from the affected facility, and you must meet the requirements specified in paragraphs (f)(4)(i) and (ii) of this section, as applicable. (i) If your affected facility is a combined heat and power unit as defined in § § 60.42Da of this subpart, you must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful recovered thermal energy. For process steam applications, you will need to install, calibrate, maintain, and operate meters to continuously***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 8 of 52 determine and record this information includes steam flow rate, temperature, and pressure. If the combined heat and power unit has a direct mechanical drive application, you must submit a plan to the Administrator or delegated authority for approval of how gross energy output will be determined , ensuring you, install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination.
. (ii) If two or more affected facilities steam generating units serve a common electrical generator, you must apportion the combined hourly gross electrical output to each individual affected facility using a plan approved by the Administrator (e.g., using steam load or heat input to each affected facility ). ), ensuring you, install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination. (g) You must demonstrate compliance with the CO 2 emissions limitation using the procedures specified in paragraphs (g)(1) and (2) of this section. (1) You must calculate the CO 2 mass emissions output-based rate for your affected facility using the hourly CO 2 mass emissions and gross energy output data determined and recorded according to the procedures specified in paragraph (f) of this section for each operating hour in the applicable operating***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 9 of 52 month compliance period for the CO 2 emissions limitation (i.e., 12-operating months or 60-operating months), and the calculation procedures specified in paragraphs (g)(1)(i) through (v) of this section. (i) Use only operating hours in the operating month compliance period for which quality-assured data are obtained for all parameters used to determine the hourly CO 2 mass emissions. No operating hours in which the substitute data provisions of part 75 of this chapter part are used for any of those parameters are to be included 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 operating month compliance period for the CO 2 emissions limitation applicable to the affected facility. (ii) Calculate the total CO 2 mass emissions by summing all of the valid hourly CO 2 mass emissions values determined for the applicable operating month compliance period interval. In a case for which exhaust gases from the affected facility are vented to the atmosphere through multiple stacks or ducts, the total CO 2 mass emissions for the affected facility is calculated by summing the total CO 2 mass emissions determined from each of the individual stacks or ducts.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 10 of 52 (iii) For each operating hour of the operating month compliance period used in paragraph (g)(1)(ii) of this section to calculate the total CO 2 mass emissions, determine the affected facility’s corresponding hourly gross energy output using the appropriate definition in § § 60.42Da of this subpart for your affected facility. For an operating hour in which there is no gross electrical load, but there is mechanical or useful thermal output, you must still determine the gross energy output for that hour. In the case for which hourly CO 2 mass emissions are determined for a common stack, then the hourly gross energy output (electrical, thermal, and/or mechanical, as applicable) is determined by summing the hourly loads for the individual affected facility and the operating time is expressed as “stack operating hours” (as defined in § § 72.2 of this chapter part ). (iv) Calculate the total gross energy output by summing the hourly gross energy output values for the affected facility determined from paragraph (g)(1)(iii) of this section for all of the operating hours in the applicable operating month compliance period interval.
(v) Calculate the CO 2 mass emissions output-based rate for the applicable operating month compliance period interval by dividing the total CO 2 mass emissions value from paragraph***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 11 of 52 (g)(1)(ii) of this section by the total gross energy output value from paragraph (g)(1)(iv) of this section. (2) Compliance with the CO 2 emissions limitation 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 output-based rate for your affected facility determined in paragraph (g)(1) of this section. (i) If the CO 2 mass emissions output-based rate for the your affected facility is less than or equal to the CO 2 emissions limitation in paragraph (c) of this section applicable to your affected facility, then the your affected facility is determined to be in compliance with the CO 2 emissions limitation. If compliance with the CO 2 emissions limitation is attained at a common stack for two or more affected facilities subject to the
same CO 2 emissions limitation, each affected facility sharing the stack is in compliance with the CO 2 emissions limitation considered to be in compliance
. (ii) If the CO 2 mass emissions output-based rate for the affected facility is greater than the CO 2 emissions limitation in paragraph (c) of this section applicable to your affected facility, then the affected facility has is determined to have

excess CO 2 emissions.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 12 of 52 (h) You must prepare and submit notifications and reports according to paragraphs (h)(1) through (4) of this section. (1) You must prepare and submit the notifications specified in § § § 60.7(a)(1) and (a)(3) and § § 60.19 of this part, as applicable to your affected facility. (2) You must prepare and submit notifications specified in § § 75.61 of this ch apter part , as applicable to your affected facility. (3) You must submit electronic quarterly reports according to the requirements specified in paragraphs (h)(3)(i) through (iii) of this section. (i) Initially, after the required number of operating months for the CO 2 emission limitation operating month compliance period that you have elected to comply with have been accumulated (i.e., 12-operating months or 60-operating months), a report for the calendar quarter that includes the twelfth 12th- (or sixtieth) operating month must be submitted no later than 30 days after the end of that quarter. Thereafter, a report for each subsequent calendar quarter must be submitted no later than 30 days after the end of the quarter. (ii) Each quarterly report must include the information specified in paragraphs (h)(3)(ii)(A) th r ough (E) of this section.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 13 of 52 (A) Identification of the CO 2 emission limitation operating month compliance period with which you have elected to comply. (B) Identification of any months in the calendar quarter that are not operating months. (C) For each operating month in the calendar quarter, the corresponding average CO 2 mass emissions output-based rate for the applicable operating month compliance period interval, as determined according to paragraph (g) of this section. (D) Percentage of valid CO 2 mass emission rates in each operating month 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) Identification of any operating months in the calendar quarter with excess CO 2 emissions. (iii) The final quarterly report of each calendar year must contain the following: (A) Gross electric output sold to an electric grid over the 4 quarters of the calendar year; and (B) The potential electric output of the facility. (iv) Each electronic report must be submitted using the Emissions Collection and Monitoring Plan System (ECMPS) Client***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 14 of 52 Tool provided by the Clean Air Markets Division in the EPA Office of Atmospheric Programs. (4) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter part . (5) Any affected unit that employs geologic sequestration to meet the applicable emission limit must report 40 CFR Part 98 Subpart PP and either: (i) if injection occurs onsite, report under 40 CFR Part 98 subpart RR, or (ii) if injection occurs offsite, transfer the captured CO2 to a facility or facilities that reports under 40 CFR Part 98 subpart RR. (i) For each affected electric utility stream generating unit, you must maintain records according to paragraphs (i)(1) through (i) (8) of this section. (1) You must comply with the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter part . (2) You must maintain records of the calculations performed to determine the total CO 2 mass emissions for each operating month, and averages for each operating month compliance period Formatted: Line spacing: Double***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 15 of 52 interval (i.e., 12-operating months or 60-operating months, as applicable to the CO 2 emissions limitations). (3) You must maintain records of the applicable data recorded and calculations performed used to determine the gross energy output for each operating month. (4) You must maintain records of the calculations performed to determine the percentage of valid CO 2 mass emission rates in each operating month compliance period. (5) You must maintain records of the calculations performed to assess compliance with each applicable CO 2 emissions limitation in paragraph (c) of this section. (6) Your records must be in a form suitable and readily available for expeditious review. (7) You must maintain each record for 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record except those records required to demonstrate compliance with a 60-operating month compliance period. You must maintain records required to demonstrate compliance with a 60-operating month compliance period for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. (8) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 16 of 52 maintenance, corrective action, report, or record, according to § § 60.7. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart. (j) PSD and Thresholds for Greenhouse Gases. (1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from new EGUs, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48). (2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from new EGUs, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49). (3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from new electric utility generating units, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 17 of 52 that otherwise is "subject to regulation" as defined in 40 CFR 70.2. (4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from new electric utility generating units, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 71.2. (k) For purposes of this section, the following definitions apply: Gross energy output means: (1) For electric utility steam generating units constructed, reconstructed, or modified after May 3, 2011, the gross electrical or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) minus any electricity used to power the feedwater pumps plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process); (2) For combined heat and power facilities constructed, reconstructed, or modified after May 3, 2011, where at least***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 18 of 52 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross useful energy output consists of thermal output, the gross electrical or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) divided by 0.95 minus any electricity used to power the feedwater pumps plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( i.e., steam delivered to an industrial process); (3) For a IGCC electric utility generating unit constructed, reconstructed, or modified after May 3, 2011, the gross useful work performed is the gross electrical or mechanical output from the unit plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( i.e., steam delivered to an industrial process). Integrated gasification combined cycle electric utility steam generating unit or IGCC electric utility steam generating unit means an electric utility combined cycle gas turbine facility Comment [CRB1]: Check against 4K***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 19 of 52 that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas plus any integrated equipment that provides electricity or useful thermal output to either the turbine engine and heat recovery steam generator or to power auxiliary equipment
. . The Administrator may waive the 50 percent solidderived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the unit during operation. Net-electric output means (1) the The gross electric sales to the utility power distribution system minus purchased power on a calendar year basis, or (2) For combined heat and power facilities where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross useful energy output consists of thermal output, net-electric output means the gross electric sales to the utility power distribution system minus purchased power of the thermal host facilit y ies or facilities on a calendar year basis.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 20 of 52 Potential electrical output capacity means 33 percent or the design net electric output efficiency time the maximum design heat input capacity of the steam generating unit, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr (e.g. , a 35 percent efficient steam generating unit with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 3 10,000 06,420 MWh 12 month potential electrical output capacity). For electric utility combined cycle gas turbines the potential electrical output capacity is determined on the basis of the fossil-fuel firing capacity of the steam generator exclusive of the heat input and electrical power contribution by the gas turbine. Steam generating unit for facilities constructed, reconstructed, or modified before May 4, 2011, means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (inclu ding fossil

- fuel

fired steam generators associated with combined cycle gas turbines; nuclear steam generators are not included). For units constructed, reconstructed, or modified after May 3, 2011, steam generating unit means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossil-fuel-fired steam generators associated with combined cycle gas turbines; nuclear steam generators are not included) plus any***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 21 of 52 integrated equipment that provides electricity or useful thermal output to either the boiler or to power auxiliary equipment.

* * * * * **Subpart KKKK-—** Standards of Performance for Stationary Combustion Turbines **[Amended]** 3. Section 60.4315 is revised to read as follows:

**§ §**  **60.4315 What pollutants are regulated by this subpart?** (a) The pollutants regulated by this subpart are nitrogen oxides (NO X ), sulfur dioxide (SO 2 ), and greenhouse gas es . (b)(1) The greenhouse gas regulated by this subpart is carbon dioxide (CO 2 ). (2) PSD and Thresholds for Greenhouse Gases. (i) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from new EGUs, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48). (ii) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from new EGUs, the “pollutant that***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 22 of 52 is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49). (iii) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from new electric utility generating units, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 70.2. (iv) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from new electric utility generating units, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 71.2. 4. Section 60. 4325 4326 is added to read as follows:

**§ §**  **60. 4325**  **4326 What CO**  **2 emissions standard must I meet?**  For each affected EGU subject to this subpart, you must not discharge from the EGU into the atmosphere any gases that contain CO 2 in excess of the applicable CO 2 emissions standard specified in Table 2 to this subpart. Each CO 2 emissions standard has a minimum of two significant digits.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 23 of 52 5. Section 60.4333 is amended by adding paragraph ( g c ) to read as follows:
**§ §**  **60.4333 What are my general requirements for complying with this subpart?** 

* * * * * ( g c ) If you own or operate a stationary combustion turbine subject to a CO 2 emissions standard in § § 60. 4325 4326 , compliance determinations are to be made on a 12-operating month rolling average, you must determine compliance monthly by calculating the average CO 2 emissions rate for the affected EGU at the end of each preceding 12-operating month period.

6. Section 60.4373 is added to read as follows:

**§ §**  **60.4373 How do I monitor and collect data to demonstrate compliance with my 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 part . (b) You must measure the hourly CO 2 mass emissions from each affected EGU using the procedures specified in paragraphs (b)(1) through (5) of this section, except as provided in paragraph (c) of this section. (1) You must install, certify, operate, maintain, and calibrate a CO 2 continuous emission monitoring system (CEMS) to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 24 of 52 directly measure and record CO 2 concentrations in the EGU exhaust gases vented to the atmosphere and an exhaust gas flow rate monitoring system according to § § 75.10(a)(3)(i) of this chapter part . If CO 2 concentration is measured on a dry basis, you must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to § § 75.11(b) of this chapter part . (2) 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 part and appendices B and D to part 75 of this chapter part . (3) You must use a laser device to measure each exhaust gas stack or duct dimensions at the flow monitor and the reference method sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, make three determinations of the diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, make three measurements of each dimension at three or more distinct locations (i.e., depth and width) and average the results. If the flow rate monitor or reference method sampling site is relocated, repeat these measurements at the new location. (4) Only unadjusted exhaust gas volumetric flow rates can be used to determine the hourly CO 2 mass emissions from the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 25 of 52 affected EGU; the bias adjustment factors described in Section 7.6.5 of Appendix A to part 75 of this chap ter part cannot be applied to the exhaust gas flow rate data. (5) If you elect to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube assembly. Use of the default Type-S pitot tube coefficient is not permitted. (c) As an alternative to complying with paragraph (b) of this section, you may determine the hourly CO 2 mass emissions by using Equation G-4 in appendix G to part 75 of this chapter part 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 part to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted. (2) You may determine site-specific carbon-based F-factors using Equation F-7b in section 3.3.6 of appendix F to part 75 of this chapter part , 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 watt***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 26 of 52 a sufficient number of watt meter (and meters ) to continuously measure and record the gross electrical output from the affected EGU. If the affected EGU is a CHP EGU, you must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful recovered thermal energy. For process steam applications, you will need to install, calibrate, maintain, and operate meters to continuously determine and record steam flow rate, temperature, and
pressure. For steam this information includes flow rate, temperature, and pressure. If the CHP EGU has a direct mechanical drive application, you must submit a plan to the Administrator or delegated authority for approval of how gross energy output will be determined , ensuring you, install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination.
. (e) If two or more affected EGUs serve a common electrical generator, you must apportion the combined hourly gross output to the individual EGUs using a plan approved by the Administrator (e.g., using steam load or heat input to each affected EGU) , ensuring you, install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination
. (f) In accordance with § § 60.13(g), if two or more EGUs that implement the continuous emission monitoring provisions in***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 27 of 52 paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard under § § 60. 4325 4326 , you may monitor the hourly CO 2 mass emissions at the common stack in lieu of monitoring each EGU separately. If this option is chosen, the hourly gross load (electrical, thermal, and/or mechanical, as applicable) shall be the sum of the hourly loads for the individual EGUs and the operating time shall be expressed as “stack operating hours” (as defined in § § 72.2 of this chapter part ). If compliance with the applicable emissions standard in § § 60. 4325 4326 is attained at the common stack, each EGU sharing the stack is considered to be in compliance. (g) In accordance with § § 60.13(g), if the exhaust gases from an EGU that implements the continuous emission monitoring provisions in paragraph (b) of this section are vented to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly CO 2 mass emissions and the “stack operating time” (as defined in § § 72.2 of this chapter part ) at each stack or duct separately. In this case, compliance with the applicable emissions standard in § § 60. 4325 4326 is determined by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the total gross output for the unit.

7. Section 60.4374 is added to read as follows:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 28 of 52 **§ §**  **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 output-based rate for your affected EGU by using the hourly CO 2 mass emissions and total gross output data determined and recorded according to the procedures specified in § § 60.4373 for each operating hour in the applicable operating month compliance period for the CO 2 emissions standard applicable to the affected EGU, and the calculation procedures specified in paragraphs (a)(1) through (a)(5) of this section. (1) Only operating hours in the operating month compliance period are used for the compliance determination calculation for which quality-assured data are obtained for all parameters used to determine the hourly CO 2 mass emissions. No operating hours in which the substitute data provisions of part 75 of this chapter part are used for any of those parameters are to be included 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 operating month compliance period for the CO 2 emissions standard applicable to the affected EGU. (2) Calculate the total CO 2 mass emissions for the affected EGU’s operating month compliance period by summing the hourly CO 2 mass emissions values for the affected EGU determined to be***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 29 of 52 valid according to the conditions specified in paragraph (a)(1) of this section for all of the operating hours in the applicable operating month compliance period. (3) For each operating hour of the operating month compliance period used in paragraph (a)(2) of this section to calculate the total CO 2 mass emissions, determine the affected EGU’s corresponding hourly gross output according to the procedures specified in paragraphs (a)(3)(i) and (ii) of this section, as appropriate for the type of stationary combustion turbine or steam generating unit used for the EGU. For an operating hour in which there is no gross electrical load, but there is mechanical or useful thermal output, you must still determine the gross output for that hour. (i) The gross output of a stationary combustion turbine with respect to CO 2 emissions is determined as specified in paragraphs (a)(3)(i)(A) and (B) of this section. (A) The gross electrical and mechanical output from the stationary combustion turbine plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( e.g. , steam delivered to an industrial process); or (B) For a CHP EGU where at least 20.0 percent of the total gross useful energy output consists of electric or direct***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 30 of 52 mechanical output and at least 20.0 percent of the total gross useful energy output consists of useful thermal output on an three calendar year rolling average basis, the gross electrical and mechanical output from the stationary combustion turbine facility divided by 0.95 plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process). (ii) Gross output of a steam generating unit with respect
to CO 2 emissions is determined as specified in paragraphs (a)(3)(ii)(A) and (B) of this section. (A) The gross electrical and mechanical output from the steam generating unit minus any electricity used to power the feedwater pumps plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( e.g. , steam delivered to an industrial process); or (B) For a CHP EGU where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross useful energy output consists of useful thermal output on an three calendar year rolling average basis, the difference of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 31 of 52 gross electrical and mechanical output from the affected steam generating unit minus any electricity used to power the feedwater pumps divided by 0.95 plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process). (4) Calculate the total gross output for the affected EGU’s compliance period by summing the hourly gross output values for the affected EGU determined from paragraph (a)(2) of this section for all of the operating hours in the applicable compliance period. (5) Calculate the CO 2 mass emissions output-based rate for the affected EGU by dividing the total CO 2 mass emissions value from paragraph (a)(2) of this section by the total gross output value from paragraph (a)(4) of this section. (b) If the CO 2 mass emissions output-based rate for the affected EGU determined according to the procedures specified in paragraph (a) of this section is less than or equal to the CO 2 emissions standard in Table 2 of this subpart applicable to the EGU, then the affected EGU is determined to be in compliance with the emissions standard. If the average CO 2 mass emissions rate is greater than the CO 2 emissions standard in Table 2 of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 32 of 52 this subpart applicable to the EGU, then the affected EGU is determined to have has excess CO 2 emissions. 8. Section 60.4375 is amended by revising the section heading to read as follows:

**§ §**  **60.4375 What reports must I submit to comply with my NO x**  **and**
**SO 2**  **emissions limits?**

* * * * *

9. Section 60.4376 is added to read as follows:

**§ §**  **60.4376 What notifications and reports must I submit to comply with my CO**  **2 emissions standard?**  (a)(1) You must prepare and submit the notifications specified in § § § 60.7(a)(1) and (a)(3) and § § 60.19, as applicable to your affected EGU. (2) You must prepare and submit notifications specified in § § 75.61 of this chapter part , as applicable to your affected
EGU. (b) You must prepare and submit reports according to paragraphs (b) through (d) of this section, as applicable. (1) For EGUs that are required, pursuant to § § § 60.4333 ( g c ), to conduct initial and on-going compliance determinations on a 12-operating month rolling average basis with respect to the standard in § § 60. 4325 4326 you must submit electronic***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 33 of 52 quarterly reports as follows. After the first 12-operating months have been accumulated for the EGU, a report for the calendar quarter that includes the twelfth 12th- operating month shall be submitted no later than 30 days after the end of that quarter. Thereafter, a report for each subsequent calendar quarter shall be submitted, no later than 30 days after the end of the quarter. (2) Each quarterly report shall include the following information, as applicable: (i) Each rolling average CO 2 mass emissions rate for which the last ( twelfth 12th ) operating month in a 12-operating month compliance period falls within the calendar quarter. Calculate each average CO 2 mass emissions rate according to § § § 60.4374. Report the dates (month and year) of the first 1st and twelfth 12th- operating months in each compliance period for which a CO 2 mass emissions rate calculation is performed. If there are no compliance periods that end in the quarter, include a statement to that effect; (ii) Identification of each operating month in the calendar quarter with excess CO 2 emissions. If one or more compliance periods end in the quarter; (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)(1)(i) of this section (i.e.,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 34 of 52 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) Indication of which compliance option is being followed under § § 60. 4325 4326
. (3) The final quarterly report of each calendar year must contain the following: (i) Gross electric output sold to an electric grid over the 4 quarters of the calendar year; and (ii) The potential electric output of the facility. (c) All electronic reports required under paragraph (b) of this section shall be submitted using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of the EPA. (d) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter part . 10. Section 60.4390 is amended by revising the section heading to read as follows:

**§ §**  **60.4390 What records must I maintain to comply with my NO x**  **and**
**SO 2**  **emissions limits?**

* * * * ****E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 35 of 52 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 your information used to demonstrate compliance with this subpart as specified in § § 60.7 (b) and (f). (b) You must follow the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter part . (c) You must keep records of the calculations 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 used to determine your affected EGU’s gross output for each operating month. (e) You must keep records of the calculations performed to determine the percentage of valid CO 2 mass emission rates in each compliance period. (f) You must keep records of the calculations performed to assess compliance with each applicable CO 2 mass emissions standard in § § 60. 4325 4326
.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 36 of 52 (g) You must keep records of the calculations performed to determine any site-specific carbon-based F-factors used in the emissions calculations (if applicable). (h)(1) Your records must be in a form suitable and readily available for expeditious review. (2) You must keep each record for 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record to demonstrate compliance with a 12- operating month emissions standard. (3) You must keep each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § § 60.7. You may keep the records off site and electronically for the remaining year(s) as required by this subpart.

12. Section 60.4395 is amended to read as follows:

**§ §**  **60.4395 When must I submit my reports?**

Consistent with § § 60.7(c), all reports required under § § 60.7(c) must be postmarked by the 30th day following the end of each 6-month period, except as specified in § § 60.4376
13. Section 60.4421 is added to read as follows:

**§ §**  **60.4421 What definitions with respect to CO 2**  **emissions apply to this subpart?**  Base load rating means 100 percent of the manufacturer's design***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 37 of 52 heat input capacity of the combustion turbine engine at ISO conditions using the higher heating value of the fuel (heat input from duct burners is not included). Electric generating unit or EGU means any steam electric generating unit or stationary combustion turbine that generates electricity. Excess emissions means a specified averaging period over which either : (1) t T he NO X , CO 2 or SO 2 emissions rate are higher than the applicable emissions standard in § § 60.4320, § § 60. 4325 4326 or § § 60.4330; or (2) t T he total sulfur content of the fuel being combusted in the affected facility or the SO 2 emissions exceeds the standard specified in § § 60.4330; or (3) t T he recorded value of a particular monitored parameter, including ration of water or steam to fuel, is outside the acceptable range specified in the parameter monitoring plan for the affected unit. Gross useful energy output means: (1) For simple cycle and combined cycle combustion turbines, the gross useful work performed is the gross electrical or direct mechanical output from both the combustion turbine engine and any associated steam turbine(s).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 38 of 52 (2) For a CHP combustion turbine, the gross useful work performed is the gross electrical or direct mechanical output from both the combustion turbine engine and any associated steam turbine(s) (divide by 0.95) plus any useful thermal output measured relative to ISO conditions (except for GHG calculations in § § 60.4374 as only 75 percent credit is given) that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( i.e. , steam delivered to an industrial process). Heat recovery steam generating unit (HRSG) means a unit where the hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used with or without duct burners. Integrated gasification combined cycle electric utility steam generating unit (IGCC) means an electric utility steamgenerating unit that burns solid-derived fuels in a combinedcycle combustion turbine plus any integrated equipment that provides electricity or useful thermal output to either the turbine engine and HRSG or to power auxiliary equipment. No solid fuel is directly combusted in the unit during operation. Net-electric output means:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 39 of 52 (1) The gross electric sales to the utility power distribution system minus purchased power on a three calendar year rolling average basis; or (2) For combined heat and power facilities where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross useful energy output consists of useful thermal output on a 3 calendar year rolling average basis, netelectric output means the gross electric sales to the utility power distribution system minus purchased power of the thermal host facility or facilities on a three calendar year rolling average basis. Operating month means a calendar month during which any fuel is combusted in the EGU at any time. Potential electric output means 33 percent or the design electric output efficiency on a net output basis times the maximum design heat input capacity (expressed in MMBtu/h) of the steam generating unit, multiplied by 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 EGU with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 306,420 310,000 MWh 12

- month potential electrical output capacity). Stationary combustion turbine means all equipment, including but Comment [CRB2]: ?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 40 of 52 not limited to the combustion turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems, heat recovery system, steam turbine, fuel compressor, heater, and/or pump, post-combustion emission control technology, and any ancillary components and sub-components plus any integrated equipment that provides electricity or useful thermal output to either the boiler or to power auxiliary equipment. Stationary means that the combustion turbine is not self propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to either the boiler or to power auxiliary equipment. System emergency means any abnormal system condition that requires immediate automatic or manual action to prevent or limit loss of transmission facilities or generators that could adversely affect the reliability of the power system.

* * * * *

14. Table 2 to Subpart KKKK of Part 60 is added to read as
follows: **Table 2 to Subpart KKKK of Part 60 – EGU CO 2**  **Emission Standards** Formatted: Font: Bold***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 41 of 52 **Affected EGU CO 2**  **Emission Standard** Stationary combustion turbine that has a design heat input to the turbine engine of greater than 250 MW (850MMBtu/h), that burns fossil fuel for more than 10.0 percent of the average annual heat input during a 3 year rolling average basis, combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and supplies one-third or more of its potential electric outputand more than 219,000 MWh netelectrical output to a utility distribution system 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 (850MMBtu/h), that burns fossil fuel for more than 10.0 percent of the average annual heat input during a 3 year rolling average basis, combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and that supplies one-third or more of its potential electric outputand more than 219,000 MWh netelectrical output to a utility distribution system 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

15. Table 3 to Subpart KKKK of Part 60 is added to read s as follows:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 42 of 52 Table 3 to Subpart KKKK of Part 60 – Applicability of Subpart A General Provisions to EGU 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 Additional terms defined in § § 60.4420 § § 60.3 Units and Abbreviations Yes § § 60.4 Address Yes

§ § 60.5 Determination of construction or modification Yes

§ § 60.6 Review of plans Yes

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

§ § 60.11 Compliance with standards and maintenance requirements No

§ § 60.12 Circumvention Yes § § 60.13 Monitoring requirements Yes
§ § 60.14 Modification No § § 60.15 Reconstruction N o § § 60.16 Priority list No***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 43 of 52

§ § 60.17 Incorporations by reference Yes

§ § 60.18 General control device requirements No

§ § 60.19 General notification and reporting requirements Yes

**PART 70— [AMENDED]**  STATE OPERATING PERMIT PROGRAMS 16. The authority citation for part 70 continues to read as follows: **Authority** : 42 U.S.C. 7401 et seq. 17. Section 70.2 is amended a. By adding a new definition of “ Greenhouse gases ,” b. By adding new paragraph (4) to the definition of “Regulated pollutants (for presumptive fee calculation),” and c. By revising paragraph (1) to the definition of “ Subject to regulation. ” The revision and additions read as follows: by adding new paragraph (4) to the definition of “ Regulated pollutants (for presumptive fee calculation )” to read as follows: **§ §**  **70.2 Definitions.**
* * * * * Greenhouse gases (GHGs) means the air pollutant defined in § 86.1818-12(a) of this chapter as the aggregate group of six Formatted: Indent: First line: 0.5"

Formatted: Indent: First line: 0.5"***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 44 of 52 greenhouse gases: carbon dioxide, nitrous oxide, methane, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride

. * * * * * Regulated pollutant (for presumptive fee calculation), which is used only for purposes of § 70.9(b)(2), means any “regulated air pollutant” except the following:
* * * * * (1) Carbon monoxide; (2) Any pollutant that is a regulated air pollutant solely because it is a Class I or I I substance to a standard promulgated under or established by title VI of the Act; or (3) Any pollutant that is a regulated air pollutant solely because it is subject to a standard or regulation under section 112(r) of the Act; (4) Greenhouse gases.
* * * * * Subject to regulation * * * (1) Greenhouse gases shall not be subject to regulation unless, as of July 1, 2011, the GHG emissions are at a stationary source emitting or having the potential to emit 100,000 tpy CO 2 equivalent emissions.
* * * * * Formatted: FR Paragraph, Line spacing: single Formatted: Font:

Formatted: No underline Formatted: Indent: First line: 0.5"

Formatted: Font: Italic, Underline***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 45 of 52 18. Section 70.9 is amended by revising paragraph (b)(2)(i), and by adding a new paragraph (b)(2)(v)) to read as follows: **§ 70.9 Fee determination and certification.**
* * * * * (b) * * * (2)(i) The Administrator will presume that the fee schedule meets the requirements of paragraph (b)(1) of this section if it would result in the collection and retention of an amount not less than $25 per year [as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) of this section] times the total tons of the actual emissions of each regulated pollutant (for presumptive fee calculation) emitted from part 70 sources and the any GHG cost adjustment required under paragraph (b)(2)(v) of this section.
* * * * * (v) GHG cost adjustment. The amount calculated in paragraph (b)(2)(i) of this section shall be increased by the GHG cost adjustment determined as follows: For each activity identified in the following table, multiply the number of activities performed by the permitting authority by the burden hours per activity, and then calculate a total number of burden hours for all activities. Next, multiply the burden hours by the Formatted: Font: Not Italic, Underline***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 46 of 52 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 Preparing a permit application (add GHG to a non

- GHG permit) Modification due to GHG Modification to address GHG in a non-GHG permit Address GHG at permit renewal 43 40 9 7 10 4

* * * * * **PART 71— [AMENDED]**  FEDERAL OPERATING PERMIT PROGRAMS 19. The authority citation for part 71 continues to read as follows: **Authority** : 42 U.S.C. 7401 et seq. 20. Section 71.2 is amended: a. By adding a new definition of “Greenhouse gases,” b. By adding a new paragraph (4) to the definition of “Regulated pollutant (for fee calculation),” and c. By revising paragraph (1) of the definition of “Subject to regulation.” The revisions and additions read as follows: is proposed to be amended by adding new paragraph (4) to the definition of “ Regulated pollutant (for fee calculation )” to read as follows: Formatted: Left***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 47 of 52 **§ 71.2 Definitions.**
* * * * * Greenhouse gases (GHGs) means the air pollutant defined in § 86.1818-12(a) of this chapter as the aggregate group of six greenhouse gases: carbon dioxide, nitrous oxide, methane, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride

. * * * * * Regulated pollutant (for fee calculation) , which is used only for purposes of § 71.9(c), means any “ regulated air pollutant ” except the following: (1) Carbon monoxide; (2) Any pollutant that is a regulated air pollutant solely because it is a Class I or II substance to a standard promulgated under or established by title VI of the Act; or (3) Any pollutant that is a regulated air pollutant solely because it is subject to a standard or regulation under section 112(r) of the Act;
* * * * * (4) Greenhouse gases.
* * * * * Subject to regulation * * * (1) Greenhouse gases shall not be subject to regulation unless, as of July 1, 2011, the GHG emissions are at a Formatted: Indent: First line: 0.5"

Formatted: Font: Not Italic, Underline Formatted: Indent: First line: 0.5" Formatted: Font: Italic, Underline

Formatted: Normal, Indent: First line: 0", Don't adjust space between Latin and Asian text, Don't adjust space between Asian text and numbers***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 48 of 52 stationary source emitting or having the potential to emit 100,000 tpy CO 2 equivalent emissions.
* * * * * 21. Section 71.9 is amended by : a. By revising paragraph (c)(1) and adding new paragraphs (c)(1)(i) and (c)(1)(ii), b. By revising paragraph (c)(2)(i) and adding new paragraphs (c)(2)(i)(A) and (c)(2)(i)(B), c. By revising paragraphs (c)(3) and (c)(4), and d. By adding a new paragraph (c)(8).

a. By r evising paragraph © (1) , b. By revising paragraph © (2)

c . By adding a new paragraph © (8). The revisions and additions read as follows: **§ 71.9 Fee determination and certification.**
* * * * * (c) * * * Establishment of fee schedule
. (1) For part 71 programs that are administered by EPA, each part 71 source shall pay an annual fee which is the sum of: (i) $32 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive emissions; and***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 49 of 52 (ii) A a ny GHG fee adjustment required under paragraph (c) © (8) of this section. (2) For part 71 programs that are fully delegated pursuant to § 71.10: (i) Where the EPA has not suspended its part 71 fee collection pursuant to paragraph (c) © (2)(ii) of this section, the annual fee for each part 71 source shall be the sum of: (A) $24 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive emissions; and (B) A a ny GHG fee 49 a djust t ment required under paragraph (c)(8) of this section. (ii) Where the delegate State collects fees from part 71 sources under State law which are sufficient to fund the delegated part 71 program, the EPA may suspend its collection of part 71 fees. The specific terms and condi tions regarding the suspension of fee collection will be addressed in the applicable delegation agreement pursuant to § 71.10.
* * * * * (4) For programs that are delegated in part, the fee shall be computed using the following formula: Formatted: Indent: First line: 0"

Formatted: Indent: First line: 0.5"***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 50 of 52 Cost per ton=( E ×32)+( D ×24)+[(1

− E

− D )×$ C ]

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

− E

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

Activity S et fee GHG completeness determination (for initial permit or updated application Preparing a permit application (add GHG to a non - GHG permit) GHG evaluation for a permit M m odification or related permit action due to GHG Modification to address GHG in a non

- GHG $2,236 $2,08 0 $ 364 468 $ 208 520 Formatted: FR Paragraph, Indent: First line: 0", Line spacing: single***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 51 of 52 permit GHG evaluation at Address GHG at permit renewal

* * * * *

**PART 98— [AMENDED]**  **MANDATORY GREENHOUSE GAS REPORTING**
22. The authority citation for part 98 continues is revised to read as follows: Authority: 42 U.S.C. 7401-7671q. **Subpart PP—[AMENDED]**
23. Section 98.426 is amended by adding paragraph (h) to read as follows: § § 98.426 Data reporting requirements.
* * * * * (h) If you capture a CO 2 stream from an electricity generating unit that is subject to subpart D of this part and transfer CO 2 to any facilities that are subject to subpart RR of this part, you must: (1) Report the facility identification number associated with the annual GHG report for the subpart D facility, (2) Report each facility identification number associated with the annual GHG reports for each subpart RR facility to which CO 2 is transferred, and Formatted: Tab stops: 0.5", Left

Formatted: Tab stops: 0.5", List tab + Not at 1"

Formatted: Subscript***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 52 of 52 (3) Report the annual quantity of CO 2 in metric tons that is transferred to each subpart RR facility. 24. Section 98.427 is amended by adding paragraph (d) to read as follows: § § 98.427 Records that must be retained.
* * * * * (d) Facilities subject to § § 98.426(h) must retain records of CO 2 in metric tons that is transferred to each subpart RR facility.