['Air Programs']
['Greenhouse Gases']
05/22/2023
Copyright 2024 J. J. Keller & Associate, Inc. For re-use options please contact copyright@jjkeller.com or call 800-558-5011.
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(a) In addition to the facility-level information required under §98.3, the annual GHG emissions report shall contain the unit-level or process-level data specified in paragraphs (b) through (f) of this section, as applicable, for each stationary fuel combustion source (e.g., individual unit, aggregation of units, common pipe, or common stack) except as otherwise provided in this paragraph (a). For the data specified in paragraphs (b)(9)(iii), (c)(2)(ix), (e)(2)(i), (e)(2)(ii)(A), (e)(2)(ii)(C), (e)(2)(ii)(D), (e)(2)(iv)(A), (e)(2)(iv)(C), (e)(2)(iv)(F), and (e)(2)(ix)(D) through (F) of this section, the owner or operator of a stationary fuel combustion source that does not meet the criteria specified in paragraph (f) of this section may elect either to report the data specified in this sentence in the annual report or to use verification software according to §98.5(b) in lieu of reporting these data. If you elect to use this verification software, you must use the verification software according to §98.5(b) for all of these data that apply to the stationary fuel combustion source.
(b) Units that use the four tiers. You shall report the following information for stationary combustion units that use the Tier 1, Tier 2, Tier 3, or Tier 4 methodology in §98.33(a) to calculate CO2 emissions, except as otherwise provided in paragraphs (c) and (d) of this section:
(1) The unit ID number.
(2) A code representing the type of unit.
(3) Maximum rated heat input capacity of the unit, in mmBtu/hr.
(4) Each type of fuel combusted in the unit during the report year.
(5) The methodology (i.e., tier) used to calculate the CO2 emissions for each type of fuel combusted (i.e., Tier 1, 2, 3, or 4).
(6) The methodology start date, for each fuel type.
(7) The methodology end date, for each fuel type.
(8) For a unit that uses Tiers 1, 2, and 3:
(i) The annual CO2 mass emissions (including biogenic CO2), and the annual CH4, and N2O mass emissions for each type of fuel combusted during the reporting year, expressed in metric tons of each gas and in metric tons of CO2e; and
(ii) Metric tons of biogenic CO2 emissions (if applicable).
(9) For a unit that uses Tier 4:
(i) For units that burn fossil fuels only, the annual CO2 emissions for all fuels combined. Reporting CO2 emissions by type of fuel is not required.
(ii) For units that burn both fossil fuels and biomass, the annual CO2 emissions from combustion of all fossil fuels combined and the annual CO2 emissions from combustion of all biomass fuels combined. Reporting CO2 emissions by type of fuel is not required.
(iii) An estimate of the heat input from each type of fuel listed in Table C-2 of this subpart that was combusted in the unit during the report year.
(iv) The annual CH4and N2O emissions for each type of fuel listed in Table C-2 of this subpart that was combusted in the unit during the report year, expressed in metric tons of each gas and in metric tons of CO2e.
(10) Annual CO2 emissions from sorbent (if calculated using Equation C–11 of this subpart), expressed in metric tons.
(11) If applicable, the plant code (as defined in §98.6).
(c) Reporting alternatives for units using the four Tiers. You may use any of the applicable reporting alternatives of this paragraph to simplify the unit-level reporting required under paragraph (b) of this section:
(1) Aggregation of units. If a facility contains two or more units (e.g., boilers or combustion turbines), each of which has a maximum rated heat input capacity of 250 mmBtu/hr or less, you may report the combined GHG emissions for the group of units in lieu of reporting GHG emissions from the individual units, provided that the use of Tier 4 is not required or elected for any of the units and the units use the same tier for any common fuels combusted. If this option is selected, the following information shall be reported instead of the information in paragraph (b) of this section:
(i) Group ID number, beginning with the prefix “GP”.
(ii) [Reserved]
(iii) Cumulative maximum rated heat input capacity of the group (mmBtu/hr). The cumulative maximum rated heat input capacity shall be determined as the sum of the maximum rated heat input capacities for all units in the group, excluding units less than 10 (mmBtu/hr).
(iv) The highest maximum rated heat input capacity of any unit in the group (mmBtu/hr).
(v) Each type of fuel combusted in the group of units during the reporting year.
(vi) Annual CO2 mass emissions and annual CH4, and N2O mass emissions, aggregated for each type of fuel combusted in the group of units during the report year, expressed in metric tons of each gas and in metric tons of CO2e. If any of the units burn both fossil fuels and biomass, report also the annual CO2 emissions from combustion of all fossil fuels combined and annual CO2 emissions from combustion of all biomass fuels combined, expressed in metric tons.
(vii) The methodology (i.e., tier) used to calculate the CO2 mass emissions for each type of fuel combusted in the units (i.e., Tier 1, Tier 2, or Tier 3).
(viii) The methodology start date, for each fuel type.
(ix) The methodology end date, for each fuel type.
(x) The calculated CO2 mass emissions (if any) from sorbent expressed in metric tons.
(xi) If applicable, the plant code (as defined in §98.6).
(2) Monitored common stack or duct configurations. When the flue gases from two or more stationary fuel combustion units at a facility are combined together in a common stack or duct before exiting to the atmosphere and if CEMS are used to continuously monitor CO2 mass emissions at the common stack or duct according to the Tier 4 Calculation Methodology, you may report the combined emissions from the units sharing the common stack or duct, in lieu of separately reporting the GHG emissions from the individual units. This monitoring and reporting alternative may also be used when process off-gases or a mixture of combustion products and process gases are combined together in a common stack or duct before exiting to the atmosphere. Whenever the common stack or duct monitoring option is applied, the following information shall be reported instead of the information in paragraph (b) of this section:
(i) Common stack or duct identification number, beginning with the prefix “CS”.
(ii) Number of units sharing the common stack or duct. Report "1" when the flue gas flowing through the common stack or duct includes combustion products and/or process off-gases, and all of the effluent comes from a single unit (e.g., a furnace, kiln, petrochemical production unit, or smelter).
(iii) Combined maximum rated heat input capacity of the units sharing the common stack or duct (mmBtu/hr). This data element is required only when all of the units sharing the common stack are stationary fuel combustion units.
(iv) Each type of fuel combusted in the units during the year.
(v) The methodology (tier) used to calculate the CO2 mass emissions, i.e., Tier 4.
(vi) The methodology start date.
(vii) The methodology end date.
(viii) Total annual CO2 mass emissions measured by the CEMS, expressed in metric tons. If any of the units burn both fossil fuels and biomass, separately report the annual non-biogenic CO2 mass emissions ( i.e., CO2 from fossil fuel combustion plus, if applicable, CO2 from sorbent and/or process CO2) and the annual CO2 mass emissions from biomass combustion, each expressed in metric tons.
(ix) An estimate of the heat input from each type of fuel listed in Table C-2 of this subpart that was combusted in the units sharing the common stack or duct during the report year.
(x) For each type of fuel listed in Table C-2 of this subpart that was combusted during the report year in the units sharing the common stack or duct during the report year, the annual CH4and N2O mass emissions from the units sharing the common stack or duct, expressed in metric tons of each gas and in metric tons of CO2e.
(xi) If applicable, the plant code (as defined in §98.6).
(3) Common pipe configurations. When two or more stationary combustion units at a facility combust the same type of liquid or gaseous fuel and the fuel is fed to the individual units through a common supply line or pipe, you may report the combined emissions from the units served by the common supply line, in lieu of separately reporting the GHG emissions from the individual units, provided that the total amount of fuel combusted by the units is accurately measured at the common pipe or supply line using a fuel flow meter, or, for natural gas, the amount of fuel combusted may be obtained from gas billing records. For Tier 3 applications, the flow meter shall be calibrated in accordance with §98.34(b). If a portion of the fuel measured (or obtained from gas billing records) at the main supply line is diverted to either: A flare; or another stationary fuel combustion unit (or units), including units that use a CO2 mass emissions calculation method in part 75 of this chapter; or a chemical or industrial process (where it is used as a raw material but not combusted), and the remainder of the fuel is distributed to a group of combustion units for which you elect to use the common pipe reporting option, you may use company records to subtract out the diverted portion of the fuel from the fuel measured (or obtained from gas billing records) at the main supply line prior to performing the GHG emissions calculations for the group of units using the common pipe option. If the diverted portion of the fuel is combusted, the GHG emissions from the diverted portion shall be accounted for in accordance with the applicable provisions of this part. When the common pipe option is selected, the applicable tier shall be used based on the maximum rated heat input capacity of the largest unit served by the common pipe configuration, except where the applicable tier is based on criteria other than unit size. For example, if the maximum rated heat input capacity of the largest unit is greater than 250 mmBtu/hr, Tier 3 will apply, unless the fuel transported through the common pipe is natural gas or distillate oil, in which case Tier 2 may be used, in accordance with §98.33(b)(2)(ii). As a second example, in accordance with §98.33(b)(1)(v), Tier 1 may be used regardless of unit size when natural gas is transported through the common pipe, if the annual fuel consumption is obtained from gas billing records in units of therms or mmBtu. When the common pipe reporting option is selected, the following information shall be reported instead of the information in paragraph (b) of this section:
(i) Common pipe identification number, beginning with the prefix “CP”.
(ii) Cumulative maximum rated heat input capacity of the units served by the common pipe (mmBtu/hr). The cumulative maximum rated heat input capacity shall be determined as the sum of the maximum rated heat input capacities for all units served by the common pipe, excluding units less than 10 (mmBtu/hr).
(iii) The highest maximum rated heat input capacity of any unit served by the common pipe (mmBtu/hr).
(iv) The fuels combusted in the units during the reporting year.
(v) The methodology used to calculate the CO2 mass emissions (i.e., Tier 1, Tier 2, or Tier 3).
(vi) If the any of the units burns both fossil fuels and biomass, the annual CO2 mass emissions from combustion of all fossil fuels and annual CO2 emissions from combustion of all biomass fuels from the units served by the common pipe, expressed in metric tons.
(vii) Annual CO2 mass emissions and annual CH4 and N2O emissions from each fuel type for the units served by the common pipe, expressed in metric tons of each gas and in metric tons of CO2e.
(viii) Annual GHG emissions from all fossil fuels burned in units served by the common pipe (i.e., the sum of the CO2, CH4, and N2O emissions), expressed in metric tons of CO2e.
(viii) Methodology start date
(ix) Methodology end date
(x) If applicable, the plant code (as defined in §98.6).
(4) The following alternative reporting option applies to facilities at which a common liquid or gaseous fuel supply is shared between one or more large combustion units, such as boilers or combustion turbines (including units subject to subpart D of this part and other units subject to part 75 of this chapter) and small combustion sources, including, but not limited to, space heaters, hot water heaters, and lab burners. In this case, you may simplify reporting by attributing all of the GHG emissions from combustion of the shared fuel to the large combustion unit(s), provided that:
(i) The total quantity of the fuel combusted during the report year in the units sharing the fuel supply is measured, either at the "gate" to the facility or at a point inside the facility, using a fuel flow meter, billing meter, or tank drop measurements (as applicable);
(ii) On an annual basis, at least 95 percent (by mass or volume) of the shared fuel is combusted in the large combustion unit(s), and the remainder is combusted in the small combustion sources. Company records may be used to determine the percentage distribution of the shared fuel to the large and small units; and
(iii) The use of this reporting option is documented in the Monitoring Plan required under §98.3(g)(5). Indicate in the Monitoring Plan which units share the common fuel supply and the method used to demonstrate that this alternative reporting option applies. For the small combustion sources, a description of the types of units and the approximate number of units is sufficient.
(d) Units subject to part 75 of this chapter.
(1) For stationary combustion units that are subject to subpart D of this part, you shall report the following unit-level information:
(i) Unit or stack identification numbers. Use exact same unit, common stack, common pipe, or multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) that are reported under §75.64 of this chapter.
(ii) Annual CO2 emissions at each monitored location, expressed in both short tons and metric tons. Separate reporting of biogenic CO2 emissions under §98.3(c)(4)(ii) and §98.3(c)(4)(iii)(A) is optional only for the 2010 reporting year, as provided in §98.3(c)(12).
(iii) Annual CH4 and N2O emissions at each monitored location, for each fuel type listed in Table C-2 that was combusted during the year (except as otherwise provided in §98.33(c)(4)(ii)(B)), expressed in metric tons of CO2e.
(iv) The total heat input from each fuel listed in Table C-2 that was combusted during the year (except as otherwise provided in §98.33(c)(4)(ii)(B)), expressed in mmBtu.
(v) Identification of the Part 75 methodology used to determine the CO2 mass emissions.
(vi) Methodology start date.
(vii) Methodology end date.
(viii) Acid Rain Program indicator.
(ix) Annual CO2 mass emissions from the combustion of biomass, expressed in metric tons of CO2e, except where the reporting provisions of §§98.3(c)(12)(i) through (c)(12)(iii) are implemented for the 2010 reporting year.
(x) If applicable, the plant code (as defined in §98.6).
(2) For units that use the alternative CO2 mass emissions calculation methods provided in §98.33(a)(5), you shall report the following unit-level information:
(i) Unit, stack, or pipe ID numbers. Use exact same unit, common stack, common pipe, or multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) that are reported under §75.64 of this chapter.
(ii) For units that use the alternative methods specified in §98.33(a)(5)(i) and (ii) to monitor and report heat input data year-round according to appendix D to part 75 of this chapter or §75.19 of this chapter:
(A) Each type of fuel combusted in the unit during the reporting year.
(B) The methodology used to calculate the CO2 mass emissions for each fuel type.
(C) Methodology start date.
(D) Methodology end date.
(E) A code or flag to indicate whether heat input is calculated according to appendix D to part 75 of this chapter or §75.19 of this chapter.
(F) Annual CO2 emissions at each monitored location, across all fuel types, expressed in metric tons of CO2e.
(G) Annual heat input from each type of fuel listed in Table C-2 of this subpart that was combusted during the reporting year, expressed in mmBtu.
(H) Annual CH4 and N2O emissions at each monitored location, from each fuel type listed in Table C-2 of this subpart that was combusted during the reporting year (except as otherwise provided in §98.33(c)(4)(ii)(D)), expressed in metric tons CO2e.
(I) Annual CO2 mass emissions from the combustion of biomass, expressed in metric tons CO2e, except where the reporting provisions of §§98.3(c)(12)(i) through (c)(12)(iii) are implemented for the 2010 reporting year.
(J) If applicable, the plant code (as defined in §98.6).
(iii) For units with continuous monitoring systems that use the alternative method for units with continuous monitoring systems in §98.33(a)(5)(iii) to monitor heat input year-round according to part 75 of this chapter:
(A) Each type of fuel combusted during the reporting year.
(B) Methodology used to calculate the CO2 mass emissions.
(C) Methodology start date.
(D) Methodology end date.
(E) A code or flag to indicate that the heat input data is derived from CEMS measurements.
(F) The total annual CO2 emissions at each monitored location, expressed in metric tons of CO2e.
(G) Annual heat input from each type of fuel listed in Table C-2 of this subpart that was combusted during the reporting year, expressed in mmBtu.
(H) Annual CH4 and N2O emissions at each monitored location, from each fuel type listed in Table C-2 of this subpart that was combusted during the reporting year (except as otherwise provided in §98.33(c)(4)(ii)(B)), expressed in metric tons CO2e.
(I) Annual CO2 mass emissions from the combustion of biomass, expressed in metric tons CO2e, except where the reporting provisions of §§98.3(c)(12)(i) through (c)(12)(iii) are implemented for the 2010 reporting year.
(J) If applicable, the plant code (as defined in §98.6).
(e) Verification data. You must keep on file, in a format suitable for inspection and auditing, sufficient data to verify the reported GHG emissions. This data and information must, where indicated in this paragraph (e), be included in the annual GHG emissions report.
(1) The applicable verification data specified in this paragraph (e) are not required to be kept on file or reported for units that meet any one of the three following conditions:
(i) Are subject to the Acid Rain Program.
(ii) Use the alternative methods for units with continuous monitoring systems provided in §98.33(a)(5).
(iii) Are not in the Acid Rain Program, but are required to monitor and report CO2 mass emissions and heat input data year-round, in accordance with part 75 of this chapter.
(2) For stationary combustion sources using the Tier 1, Tier 2, Tier 3, and Tier 4 Calculation Methodologies in §98.33(a) to quantify CO2 emissions, the following additional information shall be kept on file and included in the GHG emissions report, where indicated:
(i) For the Tier 1 Calculation Methodology, report:
(A) The total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during the reporting year, in short tons for solid fuels, gallons for liquid fuels and standard cubic feet for gaseous fuels, or, if applicable, therms or mmBtu for natural gas.
(B) If applicable, the moisture content used to calculate the wood and wood residuals wet basis HHV for use in Equations C-1 and C-8 of this subpart, in percent.
(ii) For the Tier 2 Calculation Methodology, report:
(A) The total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during each month of the reporting year. Express the quantity of each fuel combusted during the measurement period in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels.
(B) The frequency of the HHV determinations (e.g., once a month, once per fuel lot).
(C) The high heat values used in the CO2 emissions calculations for each type of fuel combusted during the reporting year, in mmBtu per short ton for solid fuels, mmBtu per gallon for liquid fuels, and mmBtu per scf for gaseous fuels. Report a HHV value for each calendar month in which HHV determination is required. If multiple values are obtained in a given month, report the arithmetic average value for the month.
(D) If Equation C-2c of this subpart is used to calculate CO2 mass emissions, report the total quantity (i.e., pounds) of steam produced from MSW or solid fuel combustion during each month of the reporting year, and the ratio of the maximum rate heat input capacity to the design rated steam output capacity of the unit, in mmBtu per lb of steam.
(E) For each HHV used in the CO2 emissions calculations for each type of fuel combusted during the reporting year, indicate whether the HHV is a measured value or a substitute data value.
(iii) For the Tier 2 Calculation Methodology, keep records of the methods used to determine the HHV for each type of fuel combusted and the date on which each fuel sample was taken, except where fuel sampling data are received from the fuel supplier. In that case, keep records of the dates on which the results of the fuel analyses for HHV are received.
(iv) For the Tier 3 Calculation Methodology, report:
(A)The quantity of each type of fuel combusted in the unit or group of units(as applicable) during each month of the reporting year, in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels.
(B) The frequency of carbon content and, if applicable, molecular weight determinations for each type of fuel for the reporting year (e.g., daily, weekly, monthly, semiannually, once per fuel lot).
(C) The carbon content and, if applicable, gas molecular weight values used in the emission calculations (including both valid and substitute data values). For each calendar month of the reporting year in which carbon content and, if applicable, molecular weight determination is required, report a value of each parameter. If multiple values of a parameter are obtained in a given month, report the arithmetic average value for the month. Express carbon content as a decimal fraction for solid fuels, kg C per gallon for liquid fuels, and kg C per kg of fuel for gaseous fuels. Express the gas molecular weights in units of kg per kg-mole.
(D) The total number of valid carbon content determinations and, if applicable, molecular weight determinations made during the reporting year, for each fuel type.
(E) The number of substitute data values used for carbon content and, if applicable, molecular weight used in the annual GHG emissions calculations.
(F) The annual average HHV, when measured HHV data, rather than a default HHV from Table C-1 of this subpart, are used to calculate CH4 and N2O emissions for a Tier 3 unit, in accordance with §98.33(c)(1).
(G) The value of the molar volume constant (MVC) used in Equation C-5 (if applicable).
(v) For the Tier 3 Calculation Methodology, keep records of the following:
(A) For liquid and gaseous fuel combustion, the dates and results of the initial calibrations and periodic recalibrations of the required fuel flow meters.
(B) For fuel oil combustion, the method from §98.34(b) used to make tank drop measurements (if applicable).
(C) The methods used to determine the carbon content and (if applicable) the molecular weight of each type of fuel combusted.
(D) The methods used to calibrate the fuel flow meters).
(E) The date on which each fuel sample was taken, except where fuel sampling data are received from the fuel supplier. In that case, keep records of the dates on which the results of the fuel analyses for carbon content and (if applicable) molecular weight are received.
(vi) For the Tier 4 Calculation Methodology, report:
(A) The total number of source operating hours in the reporting year.
(B) The cumulative CO2 mass emissions in each quarter of the reporting year, i.e., the sum of the hourly values calculated from Equation C–6 or C–7 of this subpart (as applicable), in metric tons.
(C) For CO2 concentration, stack gas flow rate, and (if applicable) stack gas moisture content, the percentage of source operating hours in which a substitute data value of each parameter was used in the emissions calculations.
(vii) For the Tier 4 Calculation Methodology, keep records of:
(A) Whether the CEMS certification and quality assurance procedures of part 75 of this chapter, part 60 of this chapter, or an applicable State continuous monitoring program were used.
(B) The dates and results of the initial certification tests of the CEMS.
(C) The dates and results of the major quality assurance tests performed on the CEMS during the reporting year, i.e., linearity checks, cylinder gas audits, and relative accuracy test audits (RATAs).
(viii) If CO2 emissions that are generated from acid gas scrubbing with sorbent injection are not captured using CEMS, report:
(A) The total amount of sorbent used during the report year, in short tons.
(B) The molecular weight of the sorbent.
(C) The ratio (“R”) in Equation C–11 of this subpart.
(ix) For units that combust both fossil fuel and biomass, when biogenic CO2 is determined according to §98.33(e)(2), you shall report the following additional information, as applicable:
(A) The annual volume of CO2 emitted from the combustion of all fuels, i.e., Vtotal, in scf.
(B) The annual volume of CO2 emitted from the combustion of fossil fuels, i.e., Vff, in scf. If more than one type of fossil fuel was combusted, report the combustion volume of CO2 for each fuel separately as well as the total.
(C) The annual volume of CO2 emitted from the combustion of biomass, i.e., Vbio, in scf.
(D) The carbon-based F-factor used in Equation C–13 of this subpart, for each type of fossil fuel combusted, in scf CO2 per mmBtu.
(E) The annual average HHV value used in Equation C–13 of this subpart, for each type of fossil fuel combusted, in Btu/lb, Btu/gal, or Btu/scf, as appropriate.
(F) The total quantity of each type of fossil fuel combusted during the reporting year, in lb, gallons, or scf, as appropriate.
(G) Annual biogenic CO2 mass emissions, in metric tons.
(x) When ASTM methods D7459-08 and D6866-16 (both incorporated by reference, see §98.7) are used to determine the biogenic portion of the annual CO2 emissions from MSW combustion, as described in §98.34(d), report:
(A) The results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of the CO2 emissions from MSW combustion is 30 percent, report 0.30).
(B) Annual combined biomass and fossil fuel CO2 emissions from MSW combustion, in metric tons of CO2e.
(C) The quantities Vff, Vtotal, and VMSW from §98.33(e)(4)(ii), if CEMS are used to measure CO2 emissions.
(B) The annual volume of biogenic CO2 emissions from MSW combustion, in metric tons.
(xi) When ASTM methods D7459-08 and D6866-16 (both incorporated by reference, see §98.7) are used in accordance with §98.34(e) to determine the biogenic portion of the annual CO2 emissions from a unit that co-fires biogenic fuels (or partly-biogenic fuels, including tires if you are electing to report biogenic CO2 emissions from tire combustion) and non-biogenic fuels, you shall report the results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of the CO2 emissions is 30 percent, report 0.30).
(3) Within 30 days of receipt of a written request from the Administrator, you shall submit explanations of the following:
(i) An explanation of how company records are used to quantify fuel consumption, if the Tier 1 or Tier 2 Calculation Methodology is used to calculate CO2 emissions.
(ii) An explanation of how company records are used to quantify fuel consumption, if solid fuel is combusted and the Tier 3 Calculation Methodology is used to calculate CO2 emissions.
(iii) An explanation of how sorbent usage is quantified.
(iv) An explanation of how company records are used to quantify fossil fuel consumption in units that uses CEMS to quantify CO2 emissions and combusts both fossil fuel and biomass.
(v) An explanation of how company records are used to measure steam production, when it is used to calculate CO2 mass emissions under §98.33(a)(2)(iii) or to quantify solid fuel usage under §98.33(c)(3).
(4) Within 30 days of receipt of a written request from the Administrator, you shall submit the verification data and information described in paragraphs (e)(2)(iii), (e)(2)(v), and (e)(2)(vii) of this section.
(f) Each stationary fuel combustion source (e.g., individual unit, aggregation of units, common pipe, or common stack) subject to reporting under paragraph (b) or (c) of this section must indicate if both of the following two conditions are met:
(1) The stationary fuel combustion source contains at least one combustion unit connected to a fuel-fired electric generator owned or operated by an entity that is subject to regulation of customer billing rates by the public utility commission (excluding generators that are connected to combustion units that are subject to subpart D of this part).
(2) The stationary fuel combustion source is located at a facility for which the sum of the nameplate capacities for all electric generators specified in paragraph (f)(1) of this section is greater than or equal to 1 megawatt electric output.
[74 FR 56406, Oct. 30, 2009; 75 FR 79151, Dec. 17, 2010; 78 FR 71950, Nov. 29, 2013; 79 FR 63782, Oct. 24, 2014; 81 FR 89251, Dec. 9, 2016]
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