(a) Your State plan must include monitoring for affected EGUs that is no less stringent than what is described in (a)(1) through (9) of this section.

(1) The owner or operator of an affected EGU (or group of affected EGUs that share a monitored common stack) that is required to meet standards of performance must prepare a monitoring plan in accordance with the applicable provisions in 40 CFR 75.53(g) and (h), unless such a plan is already in place under another program that requires CO2 mass emissions to be monitored and reported according to 40 CFR part 75.

(2) For rate-based standards of performance, only “valid operating hours,”, i.e., full or partial unit (or stack) operating hours for which:

(i) “Valid data” (as defined in § 60.5880b) are obtained for all of the parameters used to determine the hourly CO2 mass emissions (lbs). For the purposes of this subpart, substitute data recorded under part 75 of this chapter are not considered to be valid data; data obtained from flow monitoring bias adjustments are not considered to be valid data; and data provided or not provided from monitoring instruments that have not met the required frequency for relative accuracy audit testing are not considered to be valid data and

(ii) The corresponding hourly gross energy output value is also valid data (Note: For operating hours with no useful output, zero is considered to be a valid value).

(3) For rate-based standards of performance, the owner or operator of an affected EGU must measure and report the hourly CO2 mass emissions (lbs) from each affected unit using the procedures in paragraphs (a)(3)(i) through (vi) of this section, except as otherwise provided in paragraph (a)(4) of this section.

(i) The owner or operator of an affected EGU must install, certify, operate, maintain, and calibrate a CO2 continuous emissions monitoring system (CEMS) to directly measure and record CO2 concentrations in the affected EGU exhaust gases emitted to the atmosphere and an exhaust gas flow rate monitoring system according to 40 CFR 75.10(a)(3)(i). As an alternative to direct measurement of CO2 concentration, provided that the affected EGU does not use carbon separation (e.g., carbon capture and storage (CCS)), the owner or operator of an affected EGU may use data from a certified oxygen (O2) monitor to calculate hourly average CO2 concentrations, in accordance with 40 CFR 75.10(a)(3)(iii). However, when an O2 monitor is used this way, it only quantifies the combustion CO2; therefore, if the EGU is equipped with emission controls that produce non-combustion CO2 (e.g., from sorbent injection), this additional CO2 must be accounted for, in accordance with section 3 of appendix G to part 75 of this chapter. If CO2 concentration is measured on a dry basis, the owner or operator of the affected EGU must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to 40 CFR 75.11(b). Alternatively, the owner or operator of an affected EGU may either use an appropriate fuel-specific default moisture value from 40 CFR 75.11(b) or submit a petition to the Administrator under 40 CFR 75.66 for a site-specific default moisture value.

(ii) For each “valid operating hour” (as defined in paragraph (a)(2) of this section), calculate the hourly CO2 mass emission rate (tons/hr), either from Equation F-11 in appendix F to 40 CFR part 75 (if CO2 concentration is measured on a wet basis), or by following the procedure in section 4.2 of appendix F to 40 CFR part 75 (if CO2 concentration is measured on a dry basis).

(iii) Next, multiply each hourly CO2 mass emission rate by the EGU or stack operating time in hours (as defined in 40 CFR 72.2), to convert it to tons of CO2. Multiply the result by 2,000 lbs/ton to convert it to lbs.

(iv) The hourly CO2 tons/hr values and EGU (or stack) operating times used to calculate CO2 mass emissions are required to be recorded under 40 CFR 75.57(e) and must be reported electronically under 40 CFR 75.64(a)(6), if required by a State plan. The owner or operator must use these data, or equivalent data, to calculate the hourly CO2 mass emissions.

(v) Sum all of the hourly CO2 mass emissions values from paragraph (a)(3)(ii) of this section.

(vi) For each continuous monitoring system used to determine the CO2 mass emissions from an affected EGU, the monitoring system must meet the applicable certification and quality assurance procedures in 40 CFR 75.20 and appendices A and B to 40 CFR part.

(4) The owner or operator of an affected EGU that exclusively combusts liquid fuel and/or gaseous fuel may, as an alternative to complying with paragraph (a)(3) of this section, determine the hourly CO2 mass emissions according to paragraphs (a)(4)(i) through (a)(4)(vi) of this section.

(i) Implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly EGU heat input rates (MMBtu/hr), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted. The fuel flow meter(s) used to measure the hourly fuel flow rates must meet the applicable certification and quality-assurance requirements in sections 2.1.5 and 2.1.6 of appendix D to 40 CFR part 75 (except for qualifying commercial billing meters). The fuel GCV must be determined in accordance with section 2.2 or 2.3 of appendix D to 40 CFR part 75, as applicable.

(ii) For each measured hourly heat input rate, use Equation G-4 in appendix G to 40 CFR part 75 to calculate the hourly CO2 mass emission rate (tons/hr).

(iii) For each “valid operating hour” (as defined in paragraph (a)(2) of this section), multiply the hourly tons/hr CO2 mass emission rate from paragraph (a)(4)(ii) of this section by the EGU or stack operating time in hours (as defined in 40 CFR 72.2), to convert it to tons of CO2. Then, multiply the result by 2,000 lbs/ton to convert it to lbs.

(iv) The hourly CO2 tons/hr values and EGU (or stack) operating times used to calculate CO2 mass emissions are required to be recorded under 40 CFR 75.57(e) and must be reported electronically under 40 CFR 75.64(a)(6), if required by a State plan. You must use these data, or equivalent data, to calculate the hourly CO2 mass emissions.

(v) Sum all of the hourly CO2 mass emissions values (lb) from paragraph (a)(4)(iii) of this section.

(vi) The owner or operator of an affected EGU may determine site-specific carbon-based F-factors (Fc) using Equation F-7b in section 3.3.6 of appendix F to 40 CFR part 75 and may use these Fc values in the emissions calculations instead of using the default Fc values in the Equation G-4 nomenclature.

(5) For rate-based standards, the owner or operator of an affected EGU (or group of affected units that share a monitored common stack) must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record on an hourly basis gross electric output. Measurements must be performed using 0.2 accuracy class electricity metering instrumentation and calibration procedures as specified under ANSI No. C12.20-2010 (incorporated by reference, see § 60.17). Further, the owner or operator of an affected EGU that is a combined heat and power facility must install, calibrate, maintain, and operate equipment to continuously measure and record on an hourly basis useful thermal output and, if applicable, mechanical output, which are used with gross electric output to determine gross energy output. The owner or operator must use the following procedures to calculate gross energy output, as appropriate for the type of affected EGU(s).

(i) Determine Pgross/net the hourly gross or net energy output in MWh. For rate-based standards, perform this calculation only for valid operating hours (as defined in paragraph (a)(2) of this section). For mass-based standards, perform this calculation for all unit (or stack) operating hours, i.e., full or partial hours in which any fuel is combusted.

(ii) If there is no net electrical output, but there is mechanical or useful thermal output, either for a particular valid operating hour (for rate-based applications), or for a particular operating hour (for mass-based applications), the owner or operator of the affected EGU must still determine the net energy output for that hour.

(iii) For rate-based applications, if there is no (i.e., zero) gross electrical, mechanical, or useful thermal output for a particular valid operating hour, that hour must be used in the compliance determination. For hours or partial hours where the gross electric output is equal to or less than the auxiliary loads, net electric output shall be counted as zero for this calculation.

(iv) Calculate Pgross/net for your affected EGU (or group of affected EGUs that share a monitored common stack) using the following equation. All terms in the equation must be expressed in units of MWh. To convert each hourly gross or net energy output value reported under 40 CFR part 75 to MWh, multiply by the corresponding EGU or stack operating time.

Equation 1 to Paragraph (a)(5)(iv) Where: PGROSS/NET = Gross or net energy output of your affected EGU for each valid operating hour (as defined in 60.5860b(a)(2)) in MWh. (PE)ST = Electric energy output plus mechanical energy output (if any) of steam turbines in MWh. (PE)CT = Electric energy output plus mechanical energy output (if any) of stationary combustion turbine(s) in MWh. (PE)IE = Electric energy output plus mechanical energy output (if any) of your affected egu's integrated equipment that provides electricity or mechanical energy to the affected EGU or auxiliary equipment in MWh. (PE)A = Electric energy used for any auxiliary loads in MWh. (PT)PS = Useful thermal output of steam (measured relative to SATP conditions, as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected EGU. This is calculated using the equation specified in paragraph (a)(5)(V) of this section in MWh. (PT)HR = Non-steam useful thermal output (measured relative to SATP conditions, as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected EGU in MWh. (PT)IE = Useful thermal output (relative to SATP conditions, as applicable) from any integrated equipment is used for applications that do not generate additional steam, electricity, produce mechanical energy output, or enhance the performance of the affected EGU in MWh. TDF = Electric transmission and distribution factor of 0.95 for a combined heat and power affected egu where at least on an annual basis 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and 20.0 percent of the total gross or net energy output consist of useful thermal output on a 12-operating month rolling average basis, or 1.0 for all other affected EGUs.

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

Equation 2 to Paragraph (a)(5)(v) Where: QM = Measured steam flow in kilograms (KG) (or pounds (LBS)) for the operating hour. H = Enthalpy of the steam at measured temperature and pressure (relative to SATP conditions or the energy in the condensate return line, as applicable) in joules per kilogram (J/KG) (or BTU/LB). CF = Conversion factor of 3.6 × 10 9 J/MWH or 3.413 × 10 6 BTU/MWh.

(vi) For rate-based standards, sum all of the values of Pgross/net for the valid operating hours (as defined in paragraph (a)(2) of this section). Then, divide the total CO2 mass emissions for the valid operating hours from paragraph (a)(3)(v) or (a)(4)(v) of this section, as applicable, by the sum of the Pgross/net values for the valid operating hours to determine the CO2 emissions rate (lb/gross or net MWh).

(6) In accordance with § 60.13(g), if two or more affected EGUs implementing the continuous emissions monitoring provisions in paragraph (a)(3) of this section share a common exhaust gas stack and are subject to the same emissions standard, the owner or operator may monitor the hourly CO2 mass emissions at the common stack in lieu of monitoring each EGU separately. If an owner or operator of an affected EGU chooses this option, the hourly gross or net electric output for the common stack must be the sum of the hourly gross or net electric output of the individual affected EGUs and the operating time must be expressed as “stack operating hours” (as defined in 40 CFR 72.2).

(7) In accordance with § 60.13(g), if the exhaust gases from an affected EGU implementing the continuous emissions monitoring provisions in paragraph (a)(3) 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), the hourly CO2 mass emissions and the “stack operating time” (as defined in 40 CFR 72.2) at each stack or duct must be monitored separately. In this case, the owner or operator of an affected EGU must determine compliance with an applicable emissions standard by summing the CO2 mass emissions measured at the individual stacks or ducts and dividing by the gross or net energy output for the affected EGU.

(8) Consistent with § 60.5775b, if two or more affected EGUs serve a common electric generator, you must apportion the combined hourly gross or net energy output to the individual affected EGUs according to the fraction of the total steam load contributed by each EGU. Alternatively, if the EGUs are identical, you may apportion the combined hourly gross or net electrical load to the individual EGUs according to the fraction of the total heat input contributed by each EGU.

(9) The owner or operator of an affected EGU must measure and report monthly fuel usage for each affected source subject to standards of performance with the information in paragraphs (a)(9)(i) through (iii) of this section:

(i) The calendar month during which the fuel was used;

(ii) Each type of fuel used during the calendar month of the compliance period; and

(iii) Quantity of each type of fuel combusted in each calendar month in the compliance period with units of measure.

(b) Your State plan must require the owner or operator of each affected EGU covered by your State plan to maintain the records, for at least 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record.

(1) The owner or operator of an affected EGU must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, whichever is latest, according to § 60.7. The owner or operator of an affected EGU may maintain the records off site and electronically for the remaining year(s).

(2) The owner or operator of an affected EGU must keep all of the following records, in a form suitable and readily available for expeditious review:

(i) All documents, data files, and calculations and methods used to demonstrate compliance with an affected EGU's standard of performance under § 60.5775b.

(ii) Copies of all reports submitted to the State under paragraph (b) of this section.

(iii) Data that are required to be recorded by 40 CFR part 75 subpart F.

(c) Your State plan must require the owner or operator of an affected EGU covered by your State plan to include in a report submitted to you the information in paragraphs (c)(1) through (3) of this section.

(1) Owners or operators of an affected EGU must include in the report all hourly CO2 emissions, for each affected EGU (or group of affected EGUs that share a monitored common stack).

(2) For rate-based standards, each report must include:

(i) The hourly CO2 mass emission rate values (tons/hr) and unit (or stack) operating times, (as monitored and reported according to part 75 of this chapter), for each valid operating hour;

(ii) The gross or net electric output and the gross or net energy output (Pgross/net) values for each valid operating hour;

(iii) The calculated CO2 mass emissions (lb) for each valid operating hour;

(iv) The sum of the hourly gross or net energy output values and the sum of the hourly CO2 mass emissions values, for all of the valid operating hours; and

(v) The calculated CO2 mass emission rate (lbs/gross or net MWh).

(3) For each affected EGU the report must also include the applicable standard of performance and demonstration that it met the standard of performance. An owner or operator must also include in the report the affected EGU's calculated emission performance as a CO2 emission rate in units of the standard of performance.

(d) The owner or operator of an affected EGU must follow any additional requirements for monitoring, recordkeeping and reporting in a State plan that are required under § 60.5740b if applicable.

(e) If an affected EGU captures CO2 to meet the applicable standard of performance, the owner or operator must report in accordance with the requirements of 40 CFR part 98 subpart PP and either:

(1) Report in accordance with the requirements of 40 CFR part 98, subpart RR, or subpart VV, if injection occurs on-site;

(2) Transfer the captured CO2 to a facility that reports in accordance with the requirements of 40 CFR part 98, subpart RR, or subpart VV, if injection occurs off-site; or

(3) Transfer the captured CO2 to a facility that has received an innovative technology waiver from the EPA pursuant to paragraph (f) of this section.

(f) Any person may request the Administrator to issue a waiver of the requirement that captured CO2 from an affected EGU be transferred to a facility reporting under 40 CFR part 98, subpart RR, or subpart VV. To receive a waiver, the applicant must demonstrate to the Administrator that its technology will store captured CO2 as effectively as geologic sequestration, and that the proposed technology will not cause or contribute to an unreasonable risk to public health, welfare, or safety. In making this determination, the Administrator shall consider (among other factors) operating history of the technology, whether the technology will increase emissions or other releases of any pollutant other than CO2, and permanence of the CO2 storage. The Administrator may test the system or require the applicant to perform any tests considered by the Administrator to be necessary to show the technology's effectiveness, safety, and ability to store captured CO2 without release. The Administrator may grant conditional approval of a technology, with the approval conditioned on monitoring and reporting of operations. The Administrator may also withdraw approval of the waiver on evidence of releases of CO2 or other pollutants. The Administrator will provide notice to the public of any application under this provision and provide public notice of any proposed action on a petition before the Administrator takes final action.