Appendix B. Greenhouse Gas Reporting Program:

Reporting Requirements (as of July 9, 2015)

Subpart Reporting 

Threshold

Reporting and Verification

C—General 

Stationary 

Combustion

(§98.36)

25,000 

metric tons 

C02e/year

(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, or 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) If the total annual CO2 mass emissions measured by the CEMS consists entirely 

of non-biogenic CO2 (i.e., CO2from fossil fuel combustion plus, if applicable, CO2 from 

sorbent and/or process CO2), report the total annual CO2 mass emissions, expressed in 

metric tons. You are not required to report the combustion CO2 emissions by fuel type.

(ii) Report the total annual CO2 mass emissions measured by the CEMS. If this

total includes both biogenic and non-biogenic CO2, separately report the annual non-
biogenic CO2 mass emissions and the annual CO2 mass emissions from biomass 

combustion, each expressed in metric tons. You are not required to report the 

combustion CO2 emissions by fuel type.

(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 CH4 and 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)-(iii) [Reserved]

(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 CH4 and 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) [Reserved]

(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) 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 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.

(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 (incorporated by reference, see §98.7) and 

D6866-08 (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) The annual biogenic CO2 mass emissions from MSW combustion, in metric 

tons.

(xi) When ASTM methods D7459-08 (incorporated by reference, see §98.7) and 

D6866-08 (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 CO2emissions 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 CO2mass 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.

D—Electricity 

Generation

(§98.46)

All In The annual report shall comply with the data reporting requirements specified in 

§98.36(d)(1).

E—Adipic 

Acid 

Production 

(§98.56)

All In In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a) through (n) of this section at the 

facility level.

(a) Annual process N2O emissions from adipic acid production (metric tons).

(b)-(c) [Reserved]

(d) Annual process N2O emissions from adipic acid production facility that is sold 

or transferred off site (metric tons).

(e) Number of abatement technologies (if applicable).

(f) Types of abatement technologies used (if applicable).

(g) Abatement technology destruction efficiency for each abatement technology 

(percent destruction).

(h) Abatement utilization factor for each abatement technology (fraction of annual 

production that abatement technology is operating).

(i) Number of times in the reporting year that missing data procedures were 

followed to measure adipic acid production (months).

(j) If you conducted a performance test and calculated a site-specific emissions 

factor according to §98.53(a)(1), each annual report must also contain the information 

specified in paragraphs (j)(1) through (7) of this section for each adipic acid production 

unit.

(1) [Reserved]

(2) Test method used for performance test.

(3) [Reserved]
(4) N2O concentration per test run during performance test (ppm N2O).

(5) Volumetric flow rate per test run during performance test (dscf/hr).

(6) Number of test runs.

(7) Number of times in the reporting year that a performance test had to be 

repeated (number).

(k) If you requested Administrator approval for an alternative method of 

determining N2O emissions under §98.53(a)(2), each annual report must also contain 

the information specified in paragraphs (k)(1) through (4) of this section for each adipic 

acid production facility.

(1) Name of alternative method.

(2) Description of alternative method.

(3) Request date.

(4) Approval date.

(l) Fraction control factor for each abatement technology (percent of total 

emissions from the production unit that are sent to the abatement technology) if equation 

E-3c is used.

(m) If only cyclohexane is oxidized to produce adipic acid and the quantity is 

known, report the information specified in paragraph (m)(1) of this section. If materials 

other than cyclohexane are oxidized to produce adipic acid, report the information 

specified in paragraph (m)(2) of this section.

(1) Annual quantity of cyclohexane (tons) used to produce adipic acid.

(2) Annual quantity of cyclohexanone and cyclohexanol mixture (tons) used to 

produce adipic acid.

(n) Annual percent N2O emission reduction for all production units combined.

F—Aluminum 

Production 

(§98.66)

All In In addition to the information required by §98.3(c), you must report the following 

information at the facility level:

(a) [Reserved]

(b) Type of smelter technology used.

(c) The following PFC-specific information on an annual basis:

(1) Perfluoromethane emissions and perfluoroethane emissions from anode 

effects in all prebake and all Søderberg electrolysis cells combined.

(2) [Reserved]
(3) The last date when the smelter-specific-slope coefficients (or overvoltage 

emission factors) were measured.

(d) Method used to measure the frequency and duration of anode effects (or 

overvoltage).

(e) The following CO2-specific information for prebake cells:

(1) Annual anode consumption if using the method in §98.63(g).

(2) Annual CO2 emissions from the smelter.

(f) The following CO2-specific information for Søderberg cells:

(1) Annual paste consumption if using the method in §98.63(g).

(2) Annual CO2 emissions from the smelter.

(g) [Reserved]

(h) Exact data elements required will vary depending on smelter technology (e.g., 

point-feed prebake or Søderberg) and process control technology (e.g., Pechiney or 

other).

G—Ammonia 

Manufacturing 

(§98.76)

All In In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a) and (b) of this section, as applicable 

for each ammonia manufacturing process unit.

(a) If a CEMS is used to measure CO2 emissions, then you must report the 

relevant information required under §98.36 for the Tier 4 Calculation Methodology and 

the information in paragraphs (a)(1) and (2) of this section:

(1) Annual quantity of each type of feedstock consumed for ammonia 

manufacturing (scf of feedstock or gallons of feedstock or kg of feedstock).

(2) Method used for determining quantity of feedstock used.

(b) If a CEMS is not used to measure emissions, then you must report all of the 

following information in this paragraph (b):

(1) Annual CO2 process emissions (metric tons) for each ammonia manufacturing 

process unit.

(2) [Reserved]

(3) Method used for determining quantity of monthly feedstock used.

(4) Whether carbon content for each feedstock for month n is based on reports 

from the supplier or analysis of carbon content.

(5) If carbon content of feedstock for month n is based on analysis, the test 

method used.

(6) Sampling analysis results of carbon content of feedstock as determined for 

QA/QC of supplier data under §98.74(e).
(7)-(11) [Reserved]

(12) Annual urea production (metric tons) and method used to determine urea 

production.

(13) Annual CO2 emissions (metric tons) from the steam reforming of a 

hydrocarbon or the gasification of solid and liquid raw material at the ammonia 

manufacturing process unit used to produce urea and the method used to determine the 

CO2 consumed in urea production.

(14) Annual ammonia production (metric tons, sum of all process units reported 

within subpart G).

(15) Annual methanol production for each process unit (metric tons).

H– Cement 

Production

(§98.86)

All In In addition to the information required by §98.3(c), each annual report must contain the 

information specified in paragraphs (a) and (b) of this section, as appropriate.

(a) If a CEMS is used to measure CO2 emissions, then you must report under this 

subpart the relevant information required by §98.36(e)(2)(vi) and the information listed in 

this paragraph(a):

(1) Monthly clinker production from each kiln at the facility.

(2) Annual facility cement production.

(3) Number of kilns and number of operating kilns.

(b) If a CEMS is not used to measure CO2 emissions, then you must report the 

information listed in this paragraph (b) for each kiln:

(1) Kiln identification number.

(2) [Reserved]

(3) Annual cement production at the facility.

(4) Number of kilns and number of operating kilns.

(5)-(6) [Reserved]

(7) Method used to determine non-calcined CaO and non-calcined MgO in clinker.

(8) [Reserved]

(9) Method used to determine non-calcined CaO and non-calcined MgO in CKD.

(10) [Reserved]

(11) Quarterly kiln-specific CKD CO2 emission factors for each kiln (metric tons 

CO2/metric ton CKD produced).

(12) [Reserved]

(13) Name of raw kiln feed or raw material.

(14) Number of times missing data procedures were used to determine the following 

information:

(i) Clinker production (number of months).

(ii) Carbonate contents of clinker (number of months).

(iii) Non-calcined content of clinker (number of months).

(iv) CKD not recycled to kiln (number of quarters).

(v) Non-calcined content of CKD (number of quarters)

(vi) Organic carbon contents of raw materials (number of times).

(vii) Raw material consumption (number of months).

(15) Method used to determine the monthly clinker production from each kiln.

(16) Annual clinker production (metric tons).

(17) Annual average clinker CO2 emission factor for the facility, averaged across all kilns 

(metric tons CO2/metric ton clinker produced).

(18) Annual average CKD CO2 emission factor for the facility, averaged across all kilns 

(metric tons CO2/metric ton CKD produced).

I—Electronics 

Manufacturing

(§98.96)

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c), you must include in each annual 

report the following information for each electronics manufacturing facility:

(a) Annual manufacturing capacity of each fab at your facility used to determine the 

annual manufacturing capacity of your facility in Equation I-5 of this subpart.
(b) For facilities that manufacture semiconductors, the diameter of wafers manufactured 

at each fab at your facility (mm).

(c) Annual emissions, on a fab basis as described in paragraph (c)(1) through (5) of this 

section.

(1) When you use the procedures specified in §98.93(a) of this subpart, each fluorinated 

GHG emitted from each process type for which your fab is required to calculate 

emissions as calculated in Equations I-6 and I-7 of this subpart.

(2) Each fluorinated GHG emitted from each process type or process sub-type as 

calculated in Equations I-8 and I-9 of this subpart, as applicable.

(3) N2O emitted from all chemical vapor deposition processes and N2O emitted from the 

aggregate of other N2O-using manufacturing processes as calculated in Equation I-10 of 

this subpart.

(4) Each fluorinated heat transfer fluid emitted as calculated in Equation 1-16 of this 

subpart.

(5) When you use the procedures specified in §98.93(i) of this subpart, annual emissions 

of each fluorinated GHG, on a fab basis.

(d) The method of emissions calculation used in §98.93.

(e) Annual production in terms of substrate surface area (e.g., silicon, PV-cell, glass).

(f)-(l) [Reserved]

(m) For the fab-specific apportioning model used to apportion fluorinated GHG and N2O 

consumption under §98.94(c), the following information to determine it is verified in 

accordance with procedures in §98.94(c)(1) and (2):

(1) Identification of the quantifiable metric used in your fab-specific engineering model to 

apportion gas consumption for each fab, and/or an indication if direct measurements 

were used in addition to, or instead of, a quantifiable metric.

(2) The start and end dates selected under §98.94(c)(2)(i).

(3) Certification that the gas(es) you selected under §98.94(c)(2)(ii) for each fab 

corresponds to the largest quantity(ies) consumed, on a mass basis, of fluorinated GHG 

used at your fab during the reporting year for which you are required to apportion.

(4) The result of the calculation comparing the actual and modeled gas consumption 

under §98.94(c)(2)(iii) and (iv), as applicable.

(5) If you are required to apportion fluorinated GHG consumption between fabs as 

required by §98.94(c)(2)(v), certification that the gas(es) you selected under 

§98.94(c)(2)(ii) corresponds to the largest quantity(ies) consumed on a mass basis, of 

fluorinated GHG used at your facility during the reporting year for which you are required 

to apportion.

(n)-(o) [Reserved]
(p) Inventory and description of all abatement systems through which fluorinated GHGs 

or N2O flow at your facility and for which you are claiming destruction or removal 

efficiency, including:

(1) The number of abatement systems controlling emissions for each process sub-type, 

or process type, as applicable, for each gas used in the process sub-type or process 

type.

(2) The basis of the destruction or removal efficiency being used (default or site specific 

measurement according to §98.94(f)(4)(i)) for each process sub-type or process type 

and for each gas.

(q) For all abatement systems through which fluorinated GHGs or N2O flow at your 

facility, for which you are reporting controlled emissions, the following:

(1) Certification that all abatement systems at the facility have been installed, 

maintained, and operated in accordance with the site maintenance plan for abatement 

systems that is developed and maintained in your records as specified in §98.97(d)(9).

(2) If you use default destruction or removal efficiency values in your emissions 

calculations under §98.93(a), (b), or (i), certification that the site maintenance plan for 

abatement systems for which emissions are being reported contains manufacturer's 

recommendations and specifications for installation, operation, and maintenance for 

each abatement system.

(3) If you use default destruction or removal efficiency values in your emissions 

calculations under §98.93(a), (b), and/or (i), certification that the abatement systems for 

which emissions are being reported were specifically designed for fluorinated GHG or 

N2O abatement, as applicable. You must support this certification by providing 

abatement system supplier documentation stating that the system was designed for 

fluorinated GHG or N2O abatement, as applicable.

(4) For all stack systems for which you calculate fluorinated GHG emissions according to 

the procedures specified in §98.93(i)(3), certification that you have included and 

accounted for all abatement systems and any respective downtime in your emissions 

calculations under §98.93(i)(3).

(r) You must report an effective fab-wide destruction or removal efficiency value for each 

fab at your facility calculated using Equation I-26, I-27, and I-28 of this subpart, as 

appropriate.

(1) Use Equation I-27 of this subpart to calculate total unabated emissions, in metric tons 

CO2e, of all fluorinated GHG emitted from electronics manufacturing processes whose 

emissions of fluorinated GHG you calculated according to the default utilization and byproduct formation rate procedures in §98.93(a) or §98.93(i)(4). For each fluorinated GHG 

i in process j, use the same consumption (Cij), emission factors (1−Uij), and by-product 

formation rates (Bijk) to calculate unabated emissions as you used to calculate emissions 

in §98.93(a) or §98.93(i)(4).

(2) Use Equation I-28 to calculate total unabated emissions, in metric ton CO2e, of all 

fluorinated GHG emitted from electronics manufacturing processes whose emissions of 

fluorinated GHG you calculated according to the stack testing procedures in §98.93(i)(3). 

For each set of processes, use the same input gas consumption (Cif), input gas emission 

factors (EFif), by-product gas emission factors (EFkf), fractions of tools abated (aif and af), 

and destruction efficiencies (difand dkf) to calculate unabated emissions as you used to 

calculate emissions.
(s) Where missing data procedures were used to estimate inputs into the fluorinated heat 

transfer fluid mass balance equation under §98.95(b), the number of times missing data 

procedures were followed in the reporting year and the method used to estimate the 

missing data.

(t)-(v) [Reserved]

(w) If you elect to calculate fab-level emissions of fluorinated GHG using the stack test 

methods specified in §98.93(i), you must report the following in paragraphs (w)(1) and 

(2) for each stack system, in addition to the relevant data in paragraphs (a) through (v) of 

this section:

(1) The date of any stack testing conducted during the reporting year, and the identity of 

the stack system tested.

(2) An inventory of all stack systems from which process fluorinated GHG are emitted. 

For each stack system, indicate whether the stack system is among those for which 

stack testing was performed as per §98.93(i)(3) or not performed as per §98.93(i)(2).

(x) If the emissions you report under paragraph (c) of this section include emissions from 

research and development activities, as defined in §98.6, report the approximate 

percentage of total GHG emissions, on a metric ton CO2e basis, that are attributable to 

research and development activities, using the following ranges: less than 5 percent, 5 

percent to less than 10 percent, 10 percent to less than 25 percent, 25 percent to less 

than 50 percent, 50 percent and higher.

(y) If your semiconductor manufacturing facility emits more than 40,000 metric ton CO2e 

of GHG emissions, based on your most recently submitted annual report (beginning with 

the 2015 reporting year) as required in paragraph (c) of this section, from the electronics 

manufacturing processes subject to reporting under this subpart, you must prepare and 

submit a triennial (every 3 years) technology assessment report to the Administrator (or 

an authorized representative) that meets the requirements specified in paragraphs (y)(1) 

through (6) of this section. Any other semiconductor manufacturing facility may 

voluntarily submit this report to the Administrator.

(1) The first report must be submitted with the annual GHG emissions report that is due 

no later than March 31, 2017, and subsequent reports must be delivered every 3 years 

no later than March 31 of the year in which it is due.

(2) The report must include the information described in paragraphs (y)(2)(i) through (v) 

of this section.

(i) It must describe how the gases and technologies used in semiconductor 

manufacturing using 200 mm and 300 mm wafers in the United States have changed in 

the past 3 years and whether any of the identified changes are likely to have affected the 

emissions characteristics of semiconductor manufacturing processes in such a way that 

the default utilization and by-product formation rates or default destruction or removal 

efficiency factors of this subpart may need to be updated.

(ii) It must describe the effect on emissions of the implementation of new process 

technologies and/or finer line width processes in 200 mm and 300 mm technologies, the 

introduction of new tool platforms, and the introduction of new processes on previously 

tested platforms.

(iii) It must describe the status of implementing 450 mm wafer technology and the 

potential need to create or update default emission factors compared to 300 mm 

technology.
(iv) It must provide any utilization and by-product formation rates and/or destruction or 

removal efficiency data that have been collected in the previous 3 years that support the 

changes in semiconductor manufacturing processes described in the report.

(v) It must describe the use of a new gas, use of an existing gas in a new process type 

or sub-type, or a fundamental change in process technology.

(3) If, on the basis of the information reported in paragraph (y)(2) of this section, the 

report indicates that GHG emissions from semiconductor manufacturing may have 

changed from those represented by the default utilization and by-product formation rates 

in Tables I-3 or I-4, or the default destruction or removal efficiency values in Table I-16 of 

this subpart, the report must lay out a data gathering and analysis plan focused on the 

areas of potential change. The plan must describe the elements in paragraphs (y)(3)(i) 

and (ii).

(i) The testing of tools to determine the potential effect on current utilization and byproduct formation rates and destruction or removal efficiency values under the new

conditions.

(ii) A planned analysis of the effect on overall facility emissions using a representative 

gas-use profile for a 200 mm, 300 mm, or 450 mm fab (depending on which technology 

is under consideration).

(4) Multiple semiconductor manufacturing facilities may submit a single consolidated 3-

year report as long as the facility identifying information in §98.3(c)(1) and the 

certification statement in §98.3(c)(9) is provided for each facility for which the 

consolidated report is submitted.

(5) The Administrator will review the report received and determine whether it is 

necessary to update the default utilization rates and by-product formation rates in Tables 

I-3, I-4, I-11, and I-12 of this subpart and default destruction or removal efficiency values 

in Table I-16 of this subpart based on the following:

(i) Whether the revised default utilization and by-product formation rates and destruction 

or removal efficiency values will result in a projected shift in emissions of 10 percent or 

greater.

(ii) Whether new platforms, processes, or facilities that are not captured in current default 

utilization and by-product formation rates and destruction or removal efficiency values 

should be included in revised values.

(iii) Whether new data are available that could expand the existing data set to include 

new gases, tools, or processes not included in the existing data set (i.e. gases, tools, or 

processes for which no data are currently available).

(6) The Administrator will review the reports within 120 days and will notify you of a 

determination whether it is necessary to update any default utilization and by-product 

formation rates and/or destruction or removal efficiency values. If the Administrator 

determines it is necessary to update default utilization and by-product formation rates 

and/or destruction or removal efficiency values, you will then have 180 days from the 

date you receive notice of the determination to execute the data collection and analysis 

plan described in the report and submit those data to the Administrator.

Subpart K –

Ferroalloy 

production

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c), each annual report must contain the 

information specified in paragraphs (a) through (e) of this section, as applicable:
(§98.116) (a) Annual facility ferroalloy product production capacity (tons).

(b) If a CEMS is used to measure CO2 emissions, report the annual production for each 

ferroalloy product identified in §98.110, from each EAF (tons).

(c) Total number of EAFs at facility used for production of ferroalloy products.

(d) If a CEMS is used to measure CO2 emissions, then you must report under this 

subpart the relevant information required by §98.36 for the Tier 4 Calculation 

Methodology and the following information specified in paragraphs (d)(1) through (d)(3) 

of this section.

(1) Annual process CO2 emissions (in metric tons) from each EAF used for the 

production of any ferroalloy product identified in §98.110.

(2) Annual process CH4 emissions (in metric tons) from each EAF used for the 

production of any ferroalloy listed in Table K-1 of this subpart (metric tons).

(3) Identification number of each EAF.

(e) If a CEMS is not used to measure CO2 process emissions, and the carbon mass 

balance procedure is used to determine CO2 emissions according to the requirements in 

§98.113(b), then you must report the following information specified in paragraphs (e)(1) 

through (e)(7) of this section.

(1) Annual process CO2 emissions (in metric tons) from each EAF used for the 

production of any ferroalloy identified in §98.110 (metric tons).

(2) Annual process CH4 emissions (in metric tons) from each EAF used for the 

production of any ferroalloy listed in Table K-1 of this subpart.

(3) Identification number for each material.

(4)-(5) [Reserved]

(6) List the method used for the determination of carbon content for each material 

included for the calculation of annual process CO2 emissions for each EAF 

(e.g., supplier provided information, analyses of representative samples you collected).

(7) If you use the missing data procedures in §98.115(b), you must report how monthly 

mass of carbon-containing inputs and outputs with missing data was determined and the 

number of months the missing data procedures were used.

Subpart L –

Fluorinated 

Gas

Production

(§98.126)

25,000 

metric tons 

C02e/year

(a) All facilities. In addition to the information required by §98.3(c), you must report 

the information in paragraphs (a)(2) through (6) of this section according to the schedule 

in paragraph (a)(1) of this section, except as otherwise provided in paragraph (j) of this 

section or in §98.3(c)(4)(vii) and Table A-7 of subpart A of this part.

(1) Frequency of reporting under paragraph (a) of this section. The information in 

paragraphs (a)(2) through (6) of this section must be reported annually.

(2) Generically-identified process. For each production and transformation process 

at the facility, you must:
(i) Provide a number, letter, or other identifier for the process. This identifier must 

be consistent from year to year.

(ii) Indicate whether the process is a fluorinated gas production process, a 

fluorinated gas transformation process where no fluorinated GHG reactant is produced 

at another facility, or a fluorinated gas transformation process where one or more 

fluorinated GHG reactants are produced at another facility.

(iii) Indicate whether the process could be characterized as reaction, distillation, or 

packaging (include all that apply).

(iv) For each generically-identified process and each fluorinated GHG group, 

report the method(s) used to determine the mass emissions of that fluorinated GHG 

group from that process from vents (i.e., mass balance (for reporting years 2011, 2012, 

2013, and 2014 only), process-vent-specific emission factor, or process-vent-specific 

emission calculation factor).

(v) For each generically-identified process and each fluorinated GHG group, report 

the method(s) used to determine the mass emissions of that fluorinated GHG group from 

that process from equipment leaks, unless you used the mass balance method (for 

reporting years 2011, 2012, 2013, and 2014 only) for that process.

(3) Emissions from production and transformation processes, process level, 

multiple products. If your facility produces more than one fluorinated gas product, for 

each generically-identified process and each fluorinated GHG group, you must report the 

total GWP-weighted emissions of all fluorinated GHGs in that group from the process, in 

metric tons CO2e.

(4) Emissions from production and transformation processes, facility level, multiple 

products. If your facility produces more than one fluorinated gas product, you must report 

the information in paragraphs (a)(4)(i) and (ii) of this section, as applicable, for emissions 

from production and transformation processes.

(i) For each fluorinated GHG with emissions of 1,000 metric tons of CO2e or more 

from production and transformation processes, summed across the facility as a whole, 

you must report the total mass in metric tons of the fluorinated GHG emitted from 

production and transformation processes, summed across the facility as a whole. If the 

fluorinated GHG does not have a chemical-specific GWP in Table A-1 of subpart A, 

identify the fluorinated GHG group of which that fluorinated GHG is a member.

(ii) For all other fluorinated GHGs emitted from production and transformation 

processes, you must report the total GWP-weighted emissions from production and 

transformation processes of those fluorinated GHGs by fluorinated GHG group, summed 

across the facility as a whole, in metric tons of CO2e.

(5) Emissions from production and transformation processes, facility level, one 

product only. If your facility produces only one fluorinated gas product, aggregate and 

report the total GWP-weighted emissions from production and transformation processes 

of fluorinated GHGs by fluorinated GHG group for the facility as a whole, in metric tons 

of CO2e, with the following exception: Where emissions consist of a major fluorinated 

GHG constituent of a fluorinated gas product, and the product is sold or transferred to 

another person, report the total mass in metric tons of each fluorinated GHG that is 

emitted from production and transformation processes and that is a major fluorinated 

GHG constituent of the product. If the fluorinated GHG does not have a chemicalspecific GWP in Table A-1 of subpart A, identify the fluorinated GHG group of which that 

fluorinated GHG is a member.
(6) Effective destruction efficiency. For each generically-identified process, use 

Table L-1 of this subpart to report the range that encompasses the effective destruction 

efficiency, DEeffective, calculated for that process using Equation L-35 of this subpart. The 

effective destruction efficiency must be reported on a CO2e basis.

(b) Reporting for mass balance method for reporting years 2011, 2012, 2013, and 

2014. If you used the mass balance method to calculate emissions for any of the 

reporting years 2011, 2012, 2013, or 2014, you must conduct mass balance reporting for 

that reporting year. For processes whose emissions were determined using the mass 

balance method under the former §98.123(b), as included in paragraph 1 of Appendix A 

of this subpart, you must report the information listed in paragraphs (b)(1) and (b)(2) of 

this section for each process on an annual basis.

(1) If you calculated the relative and absolute errors under the former 

§98.123(b)(1), the overall absolute and relative errors calculated for the process under 

the former §98.123(b)(1), in metric tons CO2e and decimal fraction, respectively.

(2) The method used to estimate the total mass of fluorine in destroyed or 

recaptured streams (specify the former §98.123(b)(4) or (15), as included in paragraph 1 

of Appendix A of this subpart).

(c) Reporting for emission factor and emission calculation factor approach. For 

processes whose emissions are determined using the emission factor approach under 

§98.123(c)(3) or the emission calculation factor under §98.123(c)(4), you must report the 

following for each generically-identified process.

(1) [Reserved]

(2) [Reserved]

(3) For each fluorinated GHG group, the total GWP-weighted mass of all 

fluorinated GHGs in that group emitted from all process vents combined, in metric tons 

of CO2e.

(4) For each fluorinated GHG group, the total GWP-weighted mass of all 

fluorinated GHGs in that group emitted from equipment leaks, in metric tons of CO2e.

(d) Reporting for missing data. Where missing data have been estimated pursuant 

to §98.125, you must report:

(1) The generically-identified process for which the data were missing.

(2) The reason the data were missing, the length of time the data were missing, 

and the method used to estimate the missing data.

(3) Estimates of the missing data for all missing data associated with data 

elements required to be reported in this section.

(e) Reporting of destruction device excess emissions data. Each fluorinated gas 

production facility that destroys fluorinated GHGs must report the excess emissions that 

result from malfunctions of the destruction device, and these excess emissions must be 

reflected in the fluorinated GHG estimates in the former §98.123(b) as included in 

paragraph 1 of Appendix A of this subpart for the former mass balance method, and in 

§98.123(c). Such excess emissions would occur if the destruction efficiency was 

reduced due to the malfunction.
(f) Reporting of destruction device testing. By March 31, 2012 or by March 31 of 

the year immediately following the year in which it begins fluorinated GHG destruction, 

each fluorinated gas production facility that destroys fluorinated GHGs must submit a 

report containing the information in paragraphs (f)(1) through (f)(4) of this section. This 

report is one-time unless you make a change to the destruction device that would be 

expected to affect its destruction efficiencies.

(1) [Reserved]

(2) Chemical identity of the fluorinated GHG(s) used in the performance test 

conducted to determine destruction efficiency, including surrogates, and information on 

why the surrogate is sufficient to demonstrate the destruction efficiency for each 

fluorinated GHG, consistent with requirements in §98.124(g)(1), vented to the 

destruction device.

(3) Date of the most recent destruction device test.

(4) Name of all applicable Federal or State regulations that may apply to the 

destruction process.

(5) [Reserved]

(g) Reporting for destruction of previously produced fluorinated GHGs. Each 

fluorinated gas production facility that destroys fluorinated GHGs must report, separately 

from the fluorinated GHG emissions reported under paragraphs (b) or (c) of this section, 

the following for each previously produced fluorinated GHG destroyed:

(1) [Reserved]

(2) The mass of the fluorinated GHG emitted from the destruction device (metric 

tons).

(h) Reporting of emissions from venting of residual fluorinated GHGs from 

containers. Each fluorinated gas production facility that vents residual fluorinated GHGs 

from containers must report the following for each fluorinated GHG vented:

(1) The mass of the residual fluorinated GHG vented from containers annually 

(metric tons).

(2) [Reserved]

(i) Reporting of fluorinated GHG products of incomplete combustion (PICs) of 

fluorinated gases. Each fluorinated gas production facility that destroys fluorinated gases 

must submit a one-time report by June 30, 2011, that describes any measurements, 

research, or analysis that it has performed or obtained that relate to the formation of 

products of incomplete combustion that are fluorinated GHGs during the destruction of 

fluorinated gases. The report must include the methods and results of any measurement 

or modeling studies, including the products of incomplete combustion for which the 

exhaust stream was analyzed, as well as copies of relevant scientific papers, if available, 

or citations of the papers, if they are not. No new testing is required to fulfill this 

requirement.

(j) Special provisions for reporting years 2011, 2012, and 2013 only. For reporting 

years 2011, 2012, and 2013, the owner or operator of a facility must comply with 

paragraphs (j)(1), (j)(2), and (j)(3) of this section.
(1) Timing. The owner or operator of a facility is not required to report the data 

elements at §98.3(c)(4)(iii) and paragraphs (a)(2), (a)(3), (a)(4), (a)(6), (b), (c), (d), (e), 

(f), (g), and (h) of this section until the later of March 31, 2015 or the date set forth for 

that data element at §98.3(c)(4)(vii) and Table A-7 of Subpart A of this part.

(2) Excess emissions. Excess emissions of fluorinated GHGs resulting from 

destruction device malfunctions must be reflected in the reported facility-wide CO2e 

emissions but are not required to be reported separately.

(3) Calculation and reporting of CO2e. You must report the total fluorinated GHG 

emissions covered by this subpart, expressed in metric tons of CO2e. This includes 

emissions from all fluorinated gas production processes, all fluorinated gas 

transformation processes that are not part of a fluorinated gas production process, all 

fluorinated gas destruction processes that are not part of a fluorinated gas production 

process or a fluorinated gas transformation process, and venting of residual fluorinated 

GHGs from containers returned from the field. To convert fluorinated GHG emissions to 

CO2e for reporting under this section, use Equation A-1 of §98.2. For fluorinated GHGs 

whose GWPs are not listed in Table A-1 of Subpart A of this part, use either the default 

GWP specified below or your best estimate of the GWP based on the information 

described in §98.123(c)(1)(vi)(A)(3). Use of quantitative structure activity relationships 

(QSARs) is an acceptable method for determining GWPs in situations where pure 

standards of the “target” fluorinated GHG are not available, the “target” fluorinated GHG 

cannot be isolated from gas streams, and FTIR spectra for the impurities are not 

available.

(i) If you choose to use a default GWP rather than your best estimate of the GWP 

for fluorinated GHGs whose GWPs are not listed in Table A-1 of Subpart A of this part, 

use a default GWP of 10,000 for fluorinated GHGs that are fully fluorinated GHGs and 

use a default GWP of 2000 for other fluorinated GHGs.

(ii) Provide the total annual emissions across fluorinated GHGs for the entire 

facility, in metric tons of CO2e, that were calculated using the default GWP of 2000.

(iii) Provide the total annual emissions across fluorinated GHGs for the entire 

facility, in metric tons of CO2e, that were calculated using the default GWP of 10,000.

(iv) Provide the total annual emissions across fluorinated GHGs for the entire 

facility, in metric tons of CO2e, that were calculated using your best estimate of the 

GWP.

(k) Submission of complete reporting year 2011, 2012, and 2013 GHG reports. By 

March 31, 2015, you must submit annual GHG reports for reporting years 2011, 2012, 

and 2013 that contain the information specified in paragraphs (a) through (i) of this 

section. The reports must calculate CO2e using the GWPs in Table A-1 of subpart A of 

this part (as in effect on January 1, 2015). Prior submission of partial reports for these 

reporting years under paragraph (j) of this section does not affect your obligation to 

submit complete reports under this paragraph.

Subpart N –

Glass 

Production

(§98.146)

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a) and (b) of this section, as applicable.

(a) If a CEMS is used to measure CO2 emissions, then you must report under this 

subpart the relevant information required under §98.36 for the Tier 4 Calculation 

Methodology and the following information specified in paragraphs (a)(1) and (2) of this 

section:
(1) Annual quantity of each carbonate-based raw material charged to each 

continuous glass melting furnace and for all furnaces combined (tons).

(2) Annual quantity of glass produced by each glass melting furnace and by all 

furnaces combined (tons).

(b) If a CEMS is not used to determine CO2 emissions from continuous glass 

melting furnaces, and process CO2emissions are calculated according to the procedures 

specified in §98.143(b), then you must report the following information as specified in 

paragraphs (b)(1) through (b)(9) of this section:

(1) Annual process emissions of CO2 (metric tons) for each continuous glass 

melting furnace and for all furnaces combined.

(2) Annual quantity of each carbonate-based raw material charged (tons) to all 

furnaces combined.

(3) Annual quantity of glass produced (tons) from each continuous glass melting 

furnace and from all furnaces combined.

(4) [Reserved]

(5) Results of all tests used to verify the carbonate-based mineral mass fraction for 

each carbonate-based raw material charged to a continuous glass melting furnace, as 

specified in paragraphs (b)(5)(i) through (b)(5)(iii) of this section.

(i) Date of test.

(ii) Method(s) and any variations used in the analyses.

(iii) Mass fraction of each sample analyzed.

(6) [Reserved]

(7) Method used to determine decimal fraction of calcination.

(8) Total number of continuous glass melting furnaces.

(9) The number of times in the reporting year that missing data procedures were 

followed to measure monthly quantities of carbonate-based raw materials or mass 

fraction of the carbonate-based minerals for any continuous glass melting furnace 

(months).

Subpart O –

HCFC-22 

Production 

and HFC-23 

Destruction

(§98.156)

HCFC-22: 

All In

HFC-23 

destruction 

processes 

that are not 

collocated 

with a 

HCFC-22 

production 

and that 

destroy more 

(a) In addition to the information required by §98.3(c), the HCFC-22 production 

facility shall report the following information at the facility level:

(1) Annual mass of HCFC-22 produced in metric tons.

(2) [Reserved]

(3) Annual mass of reactants fed into the process in metric tons of reactant.
than 2.14 

metric tons 

HFC-23 per 

year: All In

(4) The mass (in metric tons) of materials other than HCFC-22 and HFC-23 (i.e., 

unreacted reactants, HCl and other by-products) that occur in more than trace 

concentrations and that are permanently removed from the process.

(5) The method for tracking startups, shutdowns, and malfunctions and HFC-23 

generation/emissions during these events.

(6) The names and addresses of facilities to which any HFC-23 was sent for 

destruction, and the quantities of HFC-23 (metric tons) sent to each.

(7)-(10) [Reserved]

(11) Annual mass of HFC-23 emitted in metric tons.

(12) Annual mass of HFC-23 emitted from equipment leaks in metric tons.

(13) Annual mass of HFC-23 emitted from process vents in metric tons.

(b) In addition to the information required by §98.3(c), facilities that destroy HFC23 shall report the following for each HFC-23 destruction process:

(1)-(2) [Reserved]

(3) Annual mass of HFC-23 emitted from the destruction device.

(c) Each HFC-23 destruction facility shall report the concentration (mass fraction) 

of HFC-23 measured at the outlet of the destruction device during the facility's annual 

HFC-23 concentration measurements at the outlet of the device. If the concentration of 

HFC-23 is below the detection limit of the measuring device, report the detection limit 

and that the concentration is below the detection limit.

(d) If the HFC-23 concentration measured pursuant to §98.154(l) is greater than 

that measured during the performance test that is the basis for the destruction efficiency 

(DE), the facility shall report the following:

(1) [Reserved]

(2) Concentration (mass fraction) of HFC-23 at the outlet of the destruction device.

(3) Flow rate at the outlet of the destruction device in kg/hr.

(4) Emission rate (in kg/hr) calculated from paragraphs (d)(2) and (d)(3) of this 

section.

(5) [Reserved]

(e) By March 31, 2011 or within 60 days of commencing HFC-23 destruction, HFC23 destruction facilities shall submit a one-time report including the following information 

for each destruction process:

(1) [Reserved]

(2) The methods used to determine destruction efficiency.
(3) The methods used to record the mass of HFC-23 destroyed.

(4) The name of other relevant federal or state regulations that may apply to the 

destruction process.

(5) If any changes are made that affect HFC-23 destruction efficiency or the 

methods used to record volume destroyed, then these changes must be reflected in a 

revision to this report. The revised report must be submitted to EPA within 60 days of the 

change

Subpart P –

Hydrogen 

Production

(§98.166)

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a) or (b) of this section, as appropriate, 

and paragraphs (c) through (e) of this section:

(a) If a CEMS is used to measure CO2 emissions, then you must report the 

relevant information required under §98.36 for the Tier 4 Calculation Methodology and 

the following information in this paragraph (a):

(1) Unit identification number and annual CO2 emissions.

(2) Annual quantity of hydrogen produced (metric tons) for each process unit.

(3) Annual quantity of ammonia produced (metric tons), if applicable, for each 

process unit.

(b) If a CEMS is not used to measure CO2 emissions, then you must report the 

following information for each hydrogen production process unit:

(1) Unit identification number and annual CO2 emissions.

(2) [Reserved]

(3) Annual quantity of hydrogen produced (metric tons).

(4) Annual quantity of ammonia produced, if applicable (metric tons).

(5)-(6) [Reserved]

(7) Name and annual quantity (metric tons) of each carbon-containing fuel and 

feedstock.

(c) Quantity of CO2 collected and transferred off site in either gas, liquid, or solid 

forms, following the requirements of subpart PP of this part.

(d) Annual quantity of carbon other than CO2 collected and transferred off site in 

either gas, liquid, or solid forms (kg carbon).

(e) Annual methanol production (metric tons) for each process unit.

Subpart Q –

Iron and Steel 

Production

(§98.176)

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c), each annual report must 

contain the information required in paragraphs (a) through (h) of this section for each 

coke pushing operation; taconite indurating furnace; basic oxygen furnace; non-recovery 

coke oven battery; sinter process; EAF; decarburization vessel; direct reduction furnace; 

and flare burning coke oven gas or blast furnace gas. For reporting year 2010, the 

information required in paragraphs (a) through (h) of this section is not required for 

decarburization vessels that are not argon-oxygen decarburization vessels. For reporting 
year 2011 and each subsequent reporting year, the information in paragraphs (a) 

through (h) of this section must be reported for all decarburization vessels.

(a) Unit identification number and annual CO2 emissions (in metric tons).

(b) If a CEMS is used to measure CO2 emissions, then you must report the annual 

production quantity for the production unit (in metric tons) for taconite pellets, coke, 

sinter, iron, and raw steel.

(c) If a CEMS is used to measure CO2 emissions, then you must report the 

relevant information required under §98.36 for the Tier 4 Calculation Methodology.

(d) If a CEMS is not used to measure CO2 emissions, then you must report for 

each process whether the emissions were determined using the carbon mass balance 

method in §98.173(b)(1) or the site-specific emission factor method in §98.173(b)(2).

(e) If you use the carbon mass balance method in §98.173(b)(1) to determine 

CO2 emissions, you must, except as provided in §98.174(b)(4), report the following 

information for each process:

(1) [Reserved]

(2) Whether the carbon content was determined from information from the supplier 

or by laboratory analysis, and if by laboratory analysis, the method used.

(3)-(4) [Reserved]

(5) If you used the missing data procedures in §98.175(b), you must report how 

the monthly mass for each process input or output with missing data was determined 

and the number of months the missing data procedures were used.

(6) The information specified in paragraphs (e)(6)(i) through (vi) of this section 

aggregated for all process units for which CO2 emissions were determined using the 

mass balance method in §98.173(b)(1), except as provided in §98.174(b)(4).

(i) The annual mass (metric tons) of all gaseous, liquid, and solid fuels (combined) 

used in process units for which CO2 emissions were determined using Equations Q-1 

through Q-7 of §98.173, calculated as specified in Equation Q-9 of this section.

(ii) The annual mass (metric tons) of all non-fuel material inputs (combined) 

specified in Equations Q-1 through Q-7 of §98.173, calculated as specified in Equation 

Q-10 of this section.

(iii) The annual mass (metric tons) of all solid and liquid products and byproducts 

(combined) specified in Equations Q-1 through Q-7 of §98.173, calculated as specified in 

Equation Q-11 of this section.

(iv) The weighted average carbon content of all gaseous, liquid, and solid fuels 

(combined) included in Equation Q-9 of this section, calculated as specified in Equation 

Q-12 of this section.

(v) The weighted average carbon content of all non-fuel inputs to all process units 

(combined) included in Equation Q-10 of this section, calculated as specified in Equation 

Q-13 of this section.
(vi) The weighted average carbon content of all solid and liquid products and 

byproducts from all process units (combined) included in Equation Q-11 of this section, 

calculated as specified in Equation Q-14 of this section.

(f) If you used the site-specific emission factor method in §98.173(b)(2) to 

determine CO2 emissions, you must report the following information for each process:

(1) The measured average hourly CO2 emission rate during the test (in metric tons 

per hour).

(2)-(4) [Reserved]

(g) [Reserved]

(h) For flares burning coke oven gas or blast furnace gas, the information specified 

in §98.256(e) of subpart Y (Petroleum Refineries) of this part.

Subpart R –

Lead 

Production

(§98.186)

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a) or (b) of this section, as applicable.

(a) If a CEMS is used to measure CO2 emissions according to the requirements in 

§98.183(a) or (b)(1), then you must report under this subpart the relevant information 

required by §98.36 and the information specified in paragraphs (a)(1) through (a)(4) of 

this section.

(1) Identification number of each smelting furnace.

(2) Annual lead product production capacity (tons).

(3) Annual production for each lead product (tons).

(4) Total number of smelting furnaces at facility used for lead production.

(b) If a CEMS is not used to measure CO2 emissions, and you measure 

CO2 emissions according to the requirements in §98.183(b)(2)(i) and (b)(2)(ii), then you 

must report the information specified in paragraphs (b)(1) through (b)(9) of this section.

(1) Identification number of each smelting furnace. (2) Annual process 

CO2 emissions (in metric tons) from each smelting furnace as determined by Equation R1 of this subpart.

(3) Annual lead product production capacity for the facility and each smelting 

furnace(tons).

(4) Annual production for each lead product (tons).

(5) Total number of smelting furnaces at facility used for production of lead 

products reported in paragraph (b)(4) of this section.

(6)-(7) [Reserved]

(8) List the method used for the determination of carbon content for each material 

used for the calculation of annual process CO2 emissions using Equation R-1 of §98.183 
for each smelting furnace (e.g., supplier provided information, analyses of representative 

samples you collected).

(9) If you use the missing data procedures in §98.185(b), you must report how the 

monthly mass of carbon-containing materials with missing data was determined and the 

number of months the missing data procedures were used.

Subpart S –

Lime 

Production

(§98.196)

All In In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a) or (b) of this section, as applicable.

(a) If a CEMS is used to measure CO2 emissions, then you must report under this 

subpart the relevant information required by §98.36 and the information listed in 

paragraphs (a)(1) through (8) of this section.

(1) Method used to determine the quantity of lime that is produced and quantity of 

lime that is sold.

(2) Method used to determine the quantity of calcined lime byproduct or waste 

sold.

(3) Beginning and end of year inventories for each lime product that is produced, 

by type.

(4) Beginning and end of year inventories for calcined lime byproducts or wastes 

sold, by type.

(5) Annual amount of calcined lime byproduct or waste sold, by type (tons).

(6) Annual amount of lime product sold, by type (tons).

(7) Annual amount of calcined lime byproduct or waste that is not sold, by type 

(tons).

(8) Annual amount of lime product not sold, by type (tons).

(b) If a CEMS is not used to measure CO2 emissions, then you must report the 

information listed in paragraphs (b)(1) through (18) of this section.

(1) Annual CO2 process emissions from all lime kilns combined (metric tons).

(2)-(3) [Reserved]

(4) Standard method used (ASTM or NLA testing method) to determine chemical 

compositions of each lime type produced and each calcined lime byproduct or waste 

type.

(5)-(6) [Reserved]

(7) Method used to determine the quantity of lime produced and/or lime sold.

(8) [Reserved]

(9) Method used to determine the quantity of calcined lime byproduct or waste 

sold.
(10)-(12) [Reserved]

(13) Beginning and end of year inventories for each lime product that is produced.

(14) Beginning and end of year inventories for calcined lime byproducts or wastes 

sold.

(15) Annual lime production capacity (tons) per facility.

(16) Number of times in the reporting year that missing data procedures were 

followed to measure lime production (months) or the chemical composition of lime 

products sold (months).

(17) Indicate whether CO2 was used on-site (i.e. for use in a purification process). 

If CO2 was used on-site, provide the information in paragraphs (b)(17)(i) and (ii) of this 

section.

(i) The annual amount of CO2 captured for use in the on-site process.

(ii) The method used to determine the amount of CO2 captured.

(18) Annual quantity (tons) of lime product sold, by type.

Subpart T –

Magnesium 

Production

(§98.206)

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c), each annual report must include 

the following information at the facility level:

(a) Emissions of each cover or carrier gas in metric tons.

(b) Types of production processes at the facility (e.g., primary, secondary, die 

casting).

(c) Amount of magnesium produced or processed in metric tons for each process 

type. This includes the output of primary and secondary magnesium production 

processes and the input to magnesium casting processes.

(d) Cover and carrier gas flow rate (e.g., standard cubic feet per minute) for each 

production unit and composition in percent by volume.

(e) For any missing data, you must report the length of time the data were missing 

for each cover gas or carrier gas, the method used to estimate emissions in their 

absence, and the quantity of emissions thereby estimated.

(f) The annual cover gas usage rate for the facility for each cover gas, excluding 

the carrier gas (kg gas/metric ton Mg).

(g) If applicable, an explanation of any change greater than 30 percent in the 

facility's cover gas usage rate (e.g.,installation of new melt protection technology or leak 

discovered in the cover gas delivery system that resulted in increased emissions).

(h) A description of any new melt protection technologies adopted to account for 

reduced or increased GHG emissions in any given year.

Subpart U –

Miscellaneous 

Uses of 

Carbonate

(§98.216)

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a) through (g) of this section at the 

facility level, as applicable.

(a) Annual CO2 emissions from miscellaneous carbonate use (metric tons).
(b) [Reserved]

(c) Measurement method used to determine the mass of carbonate.

(d) Method used to calculate emissions.

(e) If you followed the calculation method of §98.213(b)(1)(i), you must report the 

information in paragraphs (e)(1) through (e)(3) of this section.

(1)-(2) [Reserved]

(3) If you determined the calcination fraction, indicate which standard method was 

used.

(f) [Reserved]

(g) Number of times in the reporting year that missing data procedures were 

followed to measure carbonate consumption, carbonate input or carbonate output 

(months).

Subpart V –

Nitric Acid 

Production

(§98.226)

All In In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a) through (q) of this section.

(a) Nitric Acid train identification number.

(b) Annual process N2O emissions from each nitric acid train (metric tons).

(c) [Reserved]

(d) [Reserved]

(e) Annual nitric acid production from the nitric acid facility (tons, 100 percent acid 

basis).

(f) Number of nitric acid trains.

(g) Number of different N2O abatement technologies per nitric acid train “t”.

(h) Abatement technologies used (if applicable).

(i) [Reserved]

(j) [Reserved]

(k) Type of nitric acid process used for each nitric acid train (low, medium, high, or 

dual pressure).

(l) Number of times in the reporting year that missing data procedures were 

followed to measure nitric acid production (months).

(m) If you conducted a performance test and calculated a site-specific emissions 

factor according to §98.223(a)(1), each annual report must also contain the information 

specified in paragraphs (m)(1) through (7) of this section.
(1) [Reserved]

(2) Test method used for performance test.

(3)-(6) [Reserved]

(7) Number of times in the reporting year that a performance test had to be 

repeated (number).

(n) If you requested Administrator approval for an alternative method of 

determining N2O emissions under §98.223(a)(2), each annual report must also contain 

the information specified in paragraphs (n)(1) through (4) of this section.

(1) Name of alternative method.

(2) Description of alternative method.

(3) Request date.

(4) Approval date.

(o) [Reserved]

(p) [Reserved]

(q) Annual percent N2O emission reduction for all nitric acid trains combined.

Subpart W –

Petroleum and 

Natural Gas 

Systems

(§98.236)

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c), each annual report must 

contain reported emissions and related information as specified in this section. Reporters 

that use a flow or volume measurement system that corrects to standard conditions as 

provided in the introductory text in §98.233 for data elements that are otherwise required 

to be determined at actual conditions, report gas volumes at standard conditions rather 

the gas volumes at actual conditions and report the standard temperature and pressure 

used by the measurement system rather than the actual temperature and pressure.

(a) The annual report must include the information specified in paragraphs (a)(1) 

through (8) of this section for each applicable industry segment. The annual report must 

also include annual emissions totals, in metric tons of each GHG, for each applicable 

industry segment listed in paragraphs (a)(1) through (8) of this section, and each 

applicable emission source listed in paragraphs (b) through (z) of this section.

(1) Onshore petroleum and natural gas production. For the equipment/activities 

specified in paragraphs (a)(1)(i) through (xvii) of this section, report the information 

specified in the applicable paragraphs of this section.

(i) Natural gas pneumatic devices. Report the information specified in paragraph 

(b) of this section.

(ii) Natural gas driven pneumatic pumps. Report the information specified in 

paragraph (c) of this section.

(iii) Acid gas removal units. Report the information specified in paragraph (d) of 

this section.

(iv) Dehydrators. Report the information specified in paragraph (e) of this section.
(v) Liquids unloading. Report the information specified in paragraph (f) of this 

section.

(vi) Completions and workovers with hydraulic fracturing. Report the information 

specified in paragraph (g) of this section.

(vii) Completions and workovers without hydraulic fracturing. Report the 

information specified in paragraph (h) of this section.

(viii) Onshore production storage tanks. Report the information specified in 

paragraph (j) of this section.

(ix) Well testing. Report the information specified in paragraph (l) of this section.

(x) Associated natural gas. Report the information specified in paragraph (m) of 

this section.

(xi) Flare stacks. Report the information specified in paragraph (n) of this section.

(xii) Centrifugal compressors. Report the information specified in paragraph (o) of 

this section.

(xiii) Reciprocating compressors. Report the information specified in paragraph (p) 

of this section.

(xiv) Equipment leaks by population count. Report the information specified in 

paragraph (r) of this section.

(xv) EOR injection pumps. Report the information specified in paragraph (w) of this 

section.

(xvi) EOR hydrocarbon liquids. Report the information specified in paragraph (x) of 

this section.

(xvii) Combustion equipment. Report the information specified in paragraph (z) of 

this section.

(2) Offshore petroleum and natural gas production. Report the information 

specified in paragraph (s) of this section.

(3) Onshore natural gas processing. For the equipment/activities specified in 

paragraphs (a)(3)(i) through (vii) of this section, report the information specified in the 

applicable paragraphs of this section.

(i) Acid gas removal units. Report the information specified in paragraph (d) of this 

section.

(ii) Dehydrators. Report the information specified in paragraph (e) of this section.

(iii) Blowdown vent stacks. Report the information specified in paragraph (i) of this 

section.

(iv) Flare stacks. Report the information specified in paragraph (n) of this section.
(v) Centrifugal compressors. Report the information specified in paragraph (o) of 

this section.

(vi) Reciprocating compressors. Report the information specified in paragraph (p) 

of this section.

(vii) Equipment leak surveys. Report the information specified in paragraph (q) of 

this section.

(4) Onshore natural gas transmission compression. For the equipment/activities 

specified in paragraphs (a)(4)(i) through (vii) of this section, report the information 

specified in the applicable paragraphs of this section.

(i) Natural gas pneumatic devices. Report the information specified in paragraph 

(b) of this section.

(ii) Blowdown vent stacks. Report the information specified in paragraph (i) of this 

section.

(iii) Transmission storage tanks. Report the information specified in paragraph (k) 

of this section.

(iv) Flare stacks. Report the information specified in paragraph (n) of this section.

(v) Centrifugal compressors. Report the information specified in paragraph (o) of 

this section.

(vi) Reciprocating compressors. Report the information specified in paragraph (p) 

of this section.

(vii) Equipment leak surveys. Report the information specified in paragraph (q) of 

this section.

(5) Underground natural gas storage. For the equipment/activities specified in 

paragraphs (a)(5)(i) through (vi) of this section, report the information specified in the 

applicable paragraphs of this section.

(i) Natural gas pneumatic devices. Report the information specified in paragraph 

(b) of this section.

(ii) Flare stacks. Report the information specified in paragraph (n) of this section.

(iii) Centrifugal compressors. Report the information specified in paragraph (o) of

this section.

(iv) Reciprocating compressors. Report the information specified in paragraph (p) 

of this section.

(v) Equipment leak surveys. Report the information specified in paragraph (q) of 

this section.

(vi) Equipment leaks by population count. Report the information specified in 

paragraph (r) of this section.
(6) LNG storage. For the equipment/activities specified in paragraphs (a)(6)(i) 

through (v) of this section, report the information specified in the applicable paragraphs 

of this section.

(i) Flare stacks. Report the information specified in paragraph (n) of this section.

(ii) Centrifugal compressors. Report the information specified in paragraph (o) of 

this section.

(iii) Reciprocating compressors. Report the information specified in paragraph (p) 

of this section.

(iv) Equipment leak surveys. Report the information specified in paragraph (q) of 

this section.

(v) Equipment leaks by population count. Report the information specified in 

paragraph (r) of this section.

(7) LNG import and export equipment. For the equipment/activities specified in 

paragraphs (a)(7)(i) through (vi) of this section, report the information specified in the 

applicable paragraphs of this section.

(i) Blowdown vent stacks. Report the information specified in paragraph (i) of this 

section.

(ii) Flare stacks. Report the information specified in paragraph (n) of this section.

(iii) Centrifugal compressors. Report the information specified in paragraph (o) of 

this section.

(iv) Reciprocating compressors. Report the information specified in paragraph (p) 

of this section.

(v) Equipment leak surveys. Report the information specified in paragraph (q) of 

this section.

(vi) Equipment leaks by population count. Report the information specified in 

paragraph (r) of this section.

(8) Natural gas distribution. For the equipment/activities specified in paragraphs 

(a)(8)(i) through (iii) of this section, report the information specified in the applicable 

paragraphs of this section.

(i) Combustion equipment. Report the information specified in paragraph (z) of this 

section.

(ii) Equipment leak surveys. Report the information specified in paragraph (q) of 

this section.

(iii) Equipment leaks by population count. Report the information specified in 

paragraph (r) of this section.

(b) Natural gas pneumatic devices. You must indicate whether the facility contains 

the following types of equipment: Continuous high bleed natural gas pneumatic devices, 

continuous low bleed natural gas pneumatic devices, and intermittent bleed natural gas 

pneumatic devices. If the facility contains any continuous high bleed natural gas 
pneumatic devices, continuous low bleed natural gas pneumatic devices, or intermittent 

bleed natural gas pneumatic devices, then you must report the information specified in 

paragraphs (b)(1) through (b)(4) of this section.

(1) The number of natural gas pneumatic devices as specified in paragraphs 

(b)(1)(i) and (ii) of this section.

(i) The total number of devices of each type, determined according to 

§98.233(a)(1) and (2).

(ii) If the reported value in paragraph (b)(1)(i) of this section is an estimated value 

determined according to §98.233(a)(2), then you must report the information specified in 

paragraphs (b)(1)(ii)(A) through (C) of this section.

(A) The number of devices of each type reported in paragraph (b)(1)(i) of this 

section that are counted.

(B) The number of devices of each type reported in paragraph (b)(1)(i) of this 

section that are estimated (not counted).

(C) Whether the calendar year is the first calendar year of reporting or the second 

calendar year of reporting.

(2) For each type of pneumatic device, the estimated average number of hours in 

the calendar year that the natural gas pneumatic devices reported in paragraph (b)(1)(i) 

of this section were operating in the calendar year (“Tt” in Equation W-1 of this subpart).

(3) Annual CO2 emissions, in metric tons CO2, for the natural gas pneumatic 

devices combined, calculated using Equation W-1 of this subpart and §98.233(a)(4), and 

reported in paragraph (b)(1)(i) of this section.

(4) Annual CH4 emissions, in metric tons CH4, for the natural gas pneumatic 

devices combined, calculated using Equation W-1 of this subpart and §98.233(a)(4), and 

reported in paragraph (b)(1)(i) of this section.

(c) Natural gas driven pneumatic pumps. You must indicate whether the facility 

has any natural gas driven pneumatic pumps. If the facility contains any natural gas 

driven pneumatic pumps, then you must report the information specified in paragraphs 

(c)(1) through (4) of this section.

(1) Count of natural gas driven pneumatic pumps.

(2) Average estimated number of hours in the calendar year the pumps were 

operational (“T” in Equation W-2 of this subpart).

(3) Annual CO2 emissions, in metric tons CO2, for all natural gas driven pneumatic 

pumps combined, calculated according to §98.233(c)(1) and (2).

(4) Annual CH4 emissions, in metric tons CH4, for all natural gas driven pneumatic 

pumps combined, calculated according to §98.233(c)(1) and (2).

(d) Acid gas removal units. You must indicate whether your facility has any acid 

gas removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur 

recovery plant. If your facility contains any acid gas removal units that vent directly to the 
atmosphere, to a flare or engine, or to a sulfur recovery plant, then you must report the 

information specified in paragraphs (d)(1) and (2) of this section.

(1) You must report the information specified in paragraphs (d)(1)(i) through (vi) of 

this section for each acid gas removal unit.

(i) A unique name or ID number for the acid gas removal unit. For the onshore 

petroleum and natural gas production industry segment, a different name or ID may be 

used for a single acid gas removal unit for each location it operates at in a given year.

(ii) Total feed rate entering the acid gas removal unit, using a meter or engineering 

estimate based on process knowledge or best available data, in million cubic feet per 

year.

(iii) The calculation method used to calculate CO2 emissions from the acid gas 

removal unit, as specified in §98.233(d).

(iv) Whether any CO2 emissions from the acid gas removal unit are recovered and 

transferred outside the facility, as specified in §98.233(d)(11). If any CO2 emissions from 

the acid gas removal unit were recovered and transferred outside the facility, then you 

must report the annual quantity of CO2, in metric tons CO2, that was recovered and 

transferred outside the facility under subpart PP of this part.

(v) Annual CO2 emissions, in metric tons CO2, from the acid gas removal unit, 

calculated using any one of the calculation methods specified in §98.233(d) and as 

specified in §98.233(d)(10) and (11).

(vi) Sub-basin ID that best represents the wells supplying gas to the unit (for the 

onshore petroleum and natural gas production industry segment only).

(2) You must report information specified in paragraphs (d)(2)(i) through (iii) of this 

section, applicable to the calculation method reported in paragraph (d)(1)(iii) of this 

section, for each acid gas removal unit.

(i) If you used Calculation Method 1 or Calculation Method 2 as specified in 

§98.233(d) to calculate CO2 emissions from the acid gas removal unit, then you must 

report the information specified in paragraphs (d)(2)(i)(A) and (B) of this section.

(A) Annual average volumetric fraction of CO2 in the vent gas exiting the acid gas 

removal unit.

(B) Annual volume of gas vented from the acid gas removal unit, in cubic feet.

(ii) If you used Calculation Method 3 as specified in §98.233(d) to calculate 

CO2 emissions from the acid gas removal unit, then you must report the information 

specified in paragraphs (d)(2)(ii)(A) through (D) of this section.

(A) Indicate which equation was used (Equation W-4A or W-4B).

(B) Annual average volumetric fraction of CO2 in the natural gas flowing out of the 

acid gas removal unit, as specified in Equation W-4A or Equation W-4B of this subpart.

(C) Annual average volumetric fraction of CO2 content in natural gas flowing into 

the acid gas removal unit, as specified in Equation W-4A or Equation W-4B of this 

subpart.
(D) The natural gas flow rate used, as specified in Equation W-4A of this subpart, 

reported as either total annual volume of natural gas flow into the acid gas removal unit 

in cubic feet at actual conditions; or total annual volume of natural gas flow out of the 

acid gas removal unit, as specified in Equation W-4B of this subpart, in cubic feet at 

actual conditions.

(iii) If you used Calculation Method 4 as specified in §98.233(d) to calculate 

CO2 emissions from the acid gas removal unit, then you must report the information 

specified in paragraphs (d)(2)(iii)(A) through (L) of this section, as applicable to the 

simulation software package used.

(A) The name of the simulation software package used.

(B) Natural gas feed temperature, in degrees Fahrenheit.

(C) Natural gas feed pressure, in pounds per square inch.

(D) Natural gas flow rate, in standard cubic feet per minute.

(E) Acid gas content of the feed natural gas, in mole percent.

(F) Acid gas content of the outlet natural gas, in mole percent.

(G) Unit operating hours, excluding downtime for maintenance or standby, in hours 

per year.

(H) Exit temperature of the natural gas, in degrees Fahrenheit.

(I) Solvent pressure, in pounds per square inch.

(J) Solvent temperature, in degrees Fahrenheit.

(K) Solvent circulation rate, in gallons per minute.

(L) Solvent weight, in pounds per gallon.

(e) Dehydrators. You must indicate whether your facility contains any of the 

following equipment: Glycol dehydrators with an annual average daily natural gas 

throughput greater than or equal to 0.4 million standard cubic feet per day, glycol 

dehydrators with an annual average daily natural gas throughput less than 0.4 million 

standard cubic feet per day, and dehydrators that use desiccant. If your facility contains 

any of the equipment listed in this paragraph (e), then you must report the applicable 

information in paragraphs (e)(1) through (3).

(1) For each glycol dehydrator that has an annual average daily natural gas 

throughput greater than or equal to 0.4 million standard cubic feet per day (as specified 

in §98.233(e)(1)), you must report the information specified in paragraphs (e)(1)(i) 

through (xviii) of this section for the dehydrator.

(i) A unique name or ID number for the dehydrator. For the onshore petroleum and 

natural gas production industry segment, a different name or ID may be used for a single 

dehydrator for each location it operates at in a given year.

(ii) Dehydrator feed natural gas flow rate, in million standard cubic feet per day, 

determined by engineering estimate based on best available data.
(iii) Dehydrator feed natural gas water content, in pounds per million standard 

cubic feet.

(iv) Dehydrator outlet natural gas water content, in pounds per million standard 

cubic feet.

(v) Dehydrator absorbent circulation pump type (e.g., natural gas pneumatic, air 

pneumatic, or electric).

(vi) Dehydrator absorbent circulation rate, in gallons per minute.

(vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene glycol (DEG), or 

ethylene glycol (EG)).

(viii) Whether stripper gas is used in dehydrator.

(ix) Whether a flash tank separator is used in dehydrator.

(x) Total time the dehydrator is operating, in hours.

(xi) Temperature of the wet natural gas, in degrees Fahrenheit.

(xii) Pressure of the wet natural gas, in pounds per square inch gauge.

(xiii) Mole fraction of CH4 in wet natural gas.

(xiv) Mole fraction of CO2 in wet natural gas.

(xv) Whether any dehydrator emissions are vented to a vapor recovery device.

(xvi) Whether any dehydrator emissions are vented to a flare or regenerator 

firebox/fire tubes. If any emissions are vented to a flare or regenerator firebox/fire tubes, 

report the information specified in paragraphs (e)(1)(xvi)(A) through (C) of this section for 

these emissions from the dehydrator.

(A) Annual CO2 emissions, in metric tons CO2, for the dehydrator, calculated 

according to §98.233(e)(6).

(B) Annual CH4 emissions, in metric tons CH4, for the dehydrator, calculated 

according to §98.233(e)(6).

(C) Annual N2O emissions, in metric tons N2O, for the dehydrator, calculated 

according to §98.233(e)(6).

(xvii) Whether any dehydrator emissions are vented to the atmosphere without 

being routed to a flare or regenerator firebox/fire tubes. If any emissions are not routed 

to a flare or regenerator firebox/fire tubes, then you must report the information specified 

in paragraphs (e)(1)(xvii)(A) and (B) of this section for those emissions from the 

dehydrator.

(A) Annual CO2 emissions, in metric tons CO2, for the dehydrator when not venting 

to a flare or regenerator firebox/fire tubes, calculated according to §98.233(e)(1), and, if 

applicable, (e)(5).
(B) Annual CH4 emissions, in metric tons CH4, for the dehydrator when not venting 

to a flare or regenerator firebox/fire tubes, calculated according to §98.233(e)(1) and, if 

applicable, (e)(5).

(xviii) Sub-basin ID that best represents the wells supplying gas to the dehydrator 

(for the onshore petroleum and natural gas production industry segment only).

(2) For glycol dehydrators with an annual average daily natural gas throughput 

less than 0.4 million standard cubic feet per day (as specified in §98.233(e)(2)), you 

must report the information specified in paragraphs (e)(2)(i) through (v) of this section for 

the entire facility.

(i) The total number of dehydrators at the facility.

(ii) Whether any dehydrator emissions were vented to a vapor recovery device. If 

any dehydrator emissions were vented to a vapor recovery device, then you must report 

the total number of dehydrators at the facility that vented to a vapor recovery device.

(iii) Whether any dehydrator emissions were vented to a control device other than 

a vapor recovery device or a flare or regenerator firebox/fire tubes. If any dehydrator 

emissions were vented to a control device(s) other than a vapor recovery device or a 

flare or regenerator firebox/fire tubes, then you must specify the type of control device(s) 

and the total number of dehydrators at the facility that were vented to each type of 

control device.

(iv) Whether any dehydrator emissions were vented to a flare or regenerator 

firebox/fire tubes. If any dehydrator emissions were vented to a flare or regenerator 

firebox/fire tubes, then you must report the information specified in paragraphs 

(e)(2)(iv)(A) through (D) of this section.

(A) The total number of dehydrators venting to a flare or regenerator firebox/fire 

tubes.

(B) Annual CO2 emissions, in metric tons CO2, for the dehydrators reported in 

paragraph (e)(2)(iv)(A) of this section, calculated according to §98.233(e)(6).

(C) Annual CH4 emissions, in metric tons CH4, for the dehydrators reported in 

paragraph (e)(2)(iv)(A) of this section, calculated according to §98.233(e)(6).

(D) Annual N2O emissions, in metric tons N2O, for the dehydrators reported in 

paragraph (e)(2)(iv)(A) of this section, calculated according to §98.233(e)(6).

(v) For dehydrator emissions that were not vented to a flare or regenerator 

firebox/fire tubes, report the information specified in paragraphs (e)(2)(v)(A) and (B) of 

this section.

(A) Annual CO2 emissions, in metric tons CO2, for emissions from all dehydrators 

reported in paragraph (e)(2)(i) of this section that were not vented to a flare or 

regenerator firebox/fire tubes, calculated according to §98.233(e)(2), (e)(4), and, if 

applicable, (e)(5), where emissions are added together for all such dehydrators.

(B) Annual CH4 emissions, in metric tons CH4, for emissions from all dehydrators 

reported in paragraph (e)(2)(i) of this section that were not vented to a flare or 

regenerator firebox/fire tubes, calculated according to §98.233(e)(2), (e)(4), and, if 

applicable, (e)(5), where emissions are added together for all such dehydrators.
(3) For dehydrators that use desiccant (as specified in §98.233(e)(3)), you must 

report the information specified in paragraphs (e)(3)(i) through (iii) of this section for the 

entire facility.

(i) The same information specified in paragraphs (e)(2)(i) through (iv) of this 

section for glycol dehydrators, and report the information under this paragraph for 

dehydrators that use desiccant.

(ii) Annual CO2 emissions, in metric tons CO2, for emissions from all desiccant 

dehydrators reported under paragraph (e)(3)(i) of this section that are not venting to a 

flare or regenerator firebox/fire tubes, calculated according to §98.233(e)(3), (e)(4), and, 

if applicable, (e)(5), and summing for all such dehydrators.

(iii) Annual CH4 emissions, in metric tons CH4, for emissions from all desiccant 

dehydrators reported in paragraph (e)(3)(i) of this section that are not venting to a flare 

or regenerator firebox/fire tubes, calculated according to §98.233(e)(3), (e)(4), and, if 

applicable, (e)(5), and summing for all such dehydrators.

(f) Liquids unloading. You must indicate whether well venting for liquids unloading 

occurs at your facility, and if so, which methods (as specified in §98.233(f)) were used to 

calculate emissions. If your facility performs well venting for liquids unloading and uses 

Calculation Method 1, then you must report the information specified in paragraph (f)(1) 

of this section. If the facility performs liquids unloading and uses Calculation Method 2 or 

3, then you must report the information specified in paragraph (f)(2) of this section.

(1) For each sub-basin and well tubing diameter and pressure group for which you 

used Calculation Method 1 to calculate natural gas emissions from well venting for 

liquids unloading, report the information specified in paragraphs (f)(1)(i) through (xii) of 

this section. Report information separately for wells with plunger lifts and wells without 

plunger lifts.

(i) Sub-basin ID.

(ii) Well tubing diameter and pressure group ID.

(iii) Plunger lift indicator.

(iv) Count of wells vented to the atmosphere for the sub-basin/well tubing diameter 

and pressure group.

(v) Percentage of wells for which the monitoring period used to determine the 

cumulative amount of time venting was not the full calendar year.

(vi) Cumulative amount of time wells were vented (sum of “Tp” from Equation W-7A 

or W-7B of this subpart), in hours.

(vii) Cumulative number of unloadings vented to the atmosphere for each well, 

aggregated across all wells in the sub-basin/well tubing diameter and pressure group.

(viii) Annual natural gas emissions, in standard cubic feet, from well venting for 

liquids unloading, calculated according to §98.233(f)(1).

(ix) Annual CO2 emissions, in metric tons CO2, from well venting for liquids 

unloading, calculated according to §98.233(f)(1) and (4).
(x) Annual CH4 emissions, in metric tons CH4, from well venting for liquids 

unloading, calculated according to §98.233(f)(1) and (4).

(xi) For each well tubing diameter group and pressure group combination, you 

must report the information specified in paragraphs (f)(1)(xi)(A) through (E) of this 

section for each individual well not using a plunger lift that was tested during the year.

(A) API Well Number of tested well.

(B) Casing pressure, in pounds per square inch absolute.

(C) Internal casing diameter, in inches.

(D) Measured depth of the well, in feet.

(E) Average flow rate of the well venting over the duration of the liquids unloading, 

in standard cubic feet per hour.

(xii) For each well tubing diameter group and pressure group combination, you 

must report the information specified in paragraphs (f)(1)(xii)(A) through (E) of this 

section for each individual well using a plunger lift that was tested during the year.

(A) API Well Number.

(B) The tubing pressure, in pounds per square inch absolute.

(C) The internal tubing diameter, in inches.

(D) Measured depth of the well, in feet.

(E) Average flow rate of the well venting over the duration of the liquids unloading, 

in standard cubic feet per hour.

(2) For each sub-basin for which you used Calculation Method 2 or 3 (as specified 

in §93.233(f)) to calculate natural gas emissions from well venting for liquids unloading, 

you must report the information in (f)(2)(i) through (x) of this section. Report information 

separately for each calculation method.

(i) Sub-basin ID.

(ii) Calculation method.

(iii) Plunger lift indicator.

(iv) Number of wells vented to the atmosphere.

(v) Cumulative number of unloadings vented to the atmosphere for each well, 

aggregated across all wells.

(vi) Annual natural gas emissions, in standard cubic feet, from well venting for 

liquids unloading, calculated according to §98.233(f)(2) or (3), as applicable.

(vii) Annual CO2 emissions, in metric tons CO2, from well venting for liquids 

unloading, calculated according to §98.233(f)(2) or (3), as applicable, and §98.233(f)(4).
(viii) Annual CH4 emissions, in metric tons CH4, from well venting for liquids 

unloading, calculated according to §98.233(f)(2) or (3), as applicable, and §98.233(f)(4).

(ix) For wells without plunger lifts, the average internal casing diameter, in inches.

(x) For wells with plunger lifts, the average internal tubing diameter, in inches.

(g) Completions and workovers with hydraulic fracturing. You must indicate 

whether your facility had any gas well completions or workovers with hydraulic fracturing 

during the calendar year. If your facility had gas well completions or workovers with 

hydraulic fracturing during the calendar year, then you must report information specified 

in paragraphs (g)(1) through (10) of this section, for each sub-basin and well type 

combination. Report information separately for completions and workovers.

(1) Sub-basin ID.

(2) Well type combination.

(3) Number of completions or workovers in the sub-basin and well type 

combination category.

(4) Calculation method used.

(5) If you used Equation W-10A to calculate annual volumetric total gas emissions, 

then you must report the information specified in paragraphs (g)(5)(i) and (ii) of this 

section.

(i) Cumulative gas flowback time, in hours, from when gas is first detected until 

sufficient quantities are present to enable separation, and the cumulative flowback time, 

in hours, after sufficient quantities of gas are present to enable separation (sum of “Tp,i” 

and sum of “Tp,s” values used in Equation W-10A). You may delay the reporting of this 

data element if you indicate in the annual report that wildcat wells and/or delineation 

wells are the only wells included in this number. If you elect to delay reporting of this 

data element, you must report by the date specified in §98.236(cc) the total number of 

hours of flowback from all wells during completions or workovers and the API Well 

Number(s) for the well(s) included in the number.

(ii) For the measured well(s), the flowback rate, in standard cubic feet per hour 

(average of “FRs,p” values used in Equation W-12A). You may delay the reporting of this 

data element if you indicate in the annual report that wildcat wells and/or delineation 

wells are the only wells that can be used for the measurement. If you elect to delay 

reporting of this data element, you must report by the date specified in §98.236(cc) the 

measured flowback rate during well completion or workover and the API Well Number(s) 

for the well(s) included in the measurement.

(6) If you used Equation W-10B to calculate annual volumetric total gas emissions, 

then you must report the information specified in paragraphs (g)(6)(i) and (ii) of this 

section.

(i) Vented natural gas volume, in standard cubic feet, for each well in the sub-basin 

(“FVs,p” in Equation W-10B).

(ii) Flow rate at the beginning of the period of time when sufficient quantities of gas 

are present to enable separation, in standard cubic feet per hour, for each well in the 

sub-basin (“FRp,i” in Equation W-10B).
(7) Annual gas emissions, in standard cubic feet (“Es,n” in Equation W-10A or W10B).

(8) Annual CO2 emissions, in metric tons CO2.

(9) Annual CH4 emissions, in metric tons CH4.

(10) If the well emissions were vented to a flare, then you must report the total N2O 

emissions, in metric tons N2O.

(h) Completions and workovers without hydraulic fracturing. You must indicate 

whether the facility had any gas well completions without hydraulic fracturing or any gas 

well workovers without hydraulic fracturing, and if the activities occurred with or without 

flaring. If the facility had gas well completions or workovers without hydraulic fracturing, 

then you must report the information specified in paragraphs (h)(1) through (4) of this 

section, as applicable.

(1) For each sub-basin with gas well completions without hydraulic fracturing and 

without flaring, report the information specified in paragraphs (h)(1)(i) through (vi) of this 

section.

(i) Sub-basin ID.

(ii) Number of well completions that vented gas directly to the atmosphere without 

flaring.

(iii) Total number of hours that gas vented directly to the atmosphere during 

venting for all completions in the sub-basin category (the sum of all “Tp” for completions 

that vented to the atmosphere as used in Equation W-13B).

(iv) Average daily gas production rate for all completions without hydraulic 

fracturing in the sub-basin without flaring, in standard cubic feet per hour (average of all 

“Vp” used in Equation W-13B). You may delay reporting of this data element if you 

indicate in the annual report that wildcat wells and/or delineation wells are the only wells 

that can be used for the measurement. If you elect to delay reporting of this data 

element, you must report by the date specified in §98.236(cc) the measured average 

daily gas production rate for all wells during completions and the API Well Number(s) for 

the well(s) included in the measurement.

(v) Annual CO2 emissions, in metric tons CO2, that resulted from completions 

venting gas directly to the atmosphere (“Es,p” from Equation W-13B for completions that 

vented directly to the atmosphere, converted to mass emissions according to 

§98.233(h)(1)).

(vi) Annual CH4 emissions, in metric tons CH4, that resulted from completions 

venting gas directly to the atmosphere (“Es,p” from Equation W-13B for completions that 

vented directly to the atmosphere, converted to mass emissions according to 

§98.233(h)(1)).

(2) For each sub-basin with gas well completions without hydraulic fracturing and 

with flaring, report the information specified in paragraphs (h)(2)(i) through (vii) of this 

section.

(i) Sub-basin ID.

(ii) Number of well completions that flared gas.
(iii) Total number of hours that gas vented to a flare during venting for all 

completions in the sub-basin category (the sum of all “Tp” for completions that vented to 

a flare from Equation W-13B).

(iv) Average daily gas production rate for all completions without hydraulic 

fracturing in the sub-basin with flaring, in standard cubic feet per hour (the average of all 

“Vp” from Equation W-13B). You may delay reporting of this data element if you indicate 

in the annual report that wildcat wells and/or delineation wells are the only wells that can 

be used for the measurement. If you elect to delay reporting of this data element, you 

must report by the date specified in §98.236(cc) the measured average daily gas 

production rate for all wells during completions and the API Well Number(s) for the 

well(s) included in the measurement.

(v) Annual CO2 emissions, in metric tons CO2, that resulted from completions that 

flared gas calculated according to §98.233(h)(2).

(vi) Annual CH4 emissions, in metric tons CH4, that resulted from completions that 

flared gas calculated according to §98.233(h)(2).

(vii) Annual N2O emissions, in metric tons N2O, that resulted from completions that 

flared gas calculated according to §98.233(h)(2).

(3) For each sub-basin with gas well workovers without hydraulic fracturing and 

without flaring, report the information specified in paragraphs (h)(3)(i) through (iv) of this 

section.

(i) Sub-basin ID.

(ii) Number of workovers that vented gas to the atmosphere without flaring.

(iii) Annual CO2 emissions, in metric tons CO2 per year, that resulted from 

workovers venting gas directly to the atmosphere (“Es,wo” in Equation W-13A for 

workovers that vented directly to the atmosphere, converted to mass emissions as 

specified in §98.233(h)(1)).

(iv) Annual CH4 emissions, in metric tons CH4 per year, that resulted from 

workovers venting gas directly to the atmosphere (“Es,wo” in Equation W-13A for 

workovers that vented directly to the atmosphere, converted to mass emissions as 

specified in §98.233(h)(1)).

(4) For each sub-basin with gas well workovers without hydraulic fracturing and 

with flaring, report the information specified in paragraphs (h)(4)(i) through (v) of this 

section.

(i) Sub-basin ID.

(ii) Number of workovers that flared gas.

(iii) Annual CO2 emissions, in metric tons CO2 per year, that resulted from 

workovers that flared gas calculated as specified in §98.233(h)(2).

(iv) Annual CH4 emissions, in metric tons CH4 per year, that resulted from 

workovers that flared gas, calculated as specified in §98.233(h)(2).
(v) Annual N2O emissions, in metric tons N2O per year, that resulted from 

workovers that flared gas calculated as specified in §98.233(h)(2).

(i) Blowdown vent stacks. You must indicate whether your facility has blowdown 

vent stacks. If your facility has blowdown vent stacks, then you must report whether 

emissions were calculated by equipment or event type or by using flow meters or a 

combination of both. If you calculated emissions by equipment or event type for any 

blowdown vent stacks, then you must report the information specified in paragraph (i)(1) 

of this section considering, in aggregate, all blowdown vent stacks for which emissions 

were calculated by equipment or event type. If you calculated emissions using flow 

meters for any blowdown vent stacks, then you must report the information specified in 

paragraph (i)(2) of this section considering, in aggregate, all blowdown vent stacks for 

which emissions were calculated using flow meters.

(1) Report by equipment or event type. If you calculated emissions from blowdown 

vent stacks by the seven categories listed in §98.233(i)(2), then you must report the 

equipment or event types and the information specified in paragraphs (i)(1)(i) through (iii) 

of this section for each equipment or event type. If a blowdown event resulted in 

emissions from multiple equipment types, and the emissions cannot be apportioned to 

the different equipment types, then you may report the information in paragraphs (i)(1)(i) 

through (iii) of this section for the equipment type that represented the largest portion of 

the emissions for the blowdown event.

(i) Total number of blowdowns in the calendar year for the equipment or event type 

(the sum of equation variable “N” from Equation W-14A or Equation W-14B of this 

subpart, for all unique physical volumes for the equipment or event type).

(ii) Annual CO2 emissions for the equipment or event type, in metric tons CO2, 

calculated according to §98.233(i)(2)(iii).

(iii) Annual CH4 emissions for the equipment or event type, in metric tons CH4, 

calculated according to §98.233(i)(2)(iii).

(2) Report by flow meter. If you elect to calculate emissions from blowdown vent 

stacks by using a flow meter according to §98.233(i)(3), then you must report the 

information specified in paragraphs (i)(2)(i) and (ii) of this section for the facility.

(i) Annual CO2 emissions from all blowdown vent stacks at the facility for which 

emissions were calculated using flow meters, in metric tons CO2 (the sum of all 

CO2 mass emission values calculated according to §98.233(i)(3), for all flow meters).

(ii) Annual CH4 emissions from all blowdown vent stacks at the facility for which 

emissions were calculated using flow meters, in metric tons CH4, (the sum of all 

CH4 mass emission values calculated according to §98.233(i)(3), for all flow meters).

(j) Onshore production storage tanks. You must indicate whether your facility 

sends produced oil to atmospheric tanks. If your facility sends produced oil to 

atmospheric tanks, then you must indicate which Calculation Method(s) you used to 

calculate GHG emissions, and you must report the information specified in paragraphs 

(j)(1) and (2) of this section as applicable. If you used Calculation Method 1 or 

Calculation Method 2, and any atmospheric tanks were observed to have malfunctioning 

dump valves during the calendar year, then you must indicate that dump valves were 

malfunctioning and you must report the information specified in paragraph (j)(3) of this 

section.
(1) If you used Calculation Method 1 or Calculation Method 2 to calculate GHG 

emissions, then you must report the information specified in paragraphs (j)(1)(i) through 

(xiv) of this section for each sub-basin and by calculation method.

(i) Sub-basin ID.

(ii) Calculation method used, and name of the software package used if using 

Calculation Method 1.

(iii) The total annual oil volume from gas-liquid separators and direct from wells 

that is sent to applicable onshore production storage tanks, in barrels. You may delay 

reporting of this data element if you indicate in the annual report that wildcat wells and 

delineation wells are the only wells in the sub-basin with oil production greater than or 

equal to 10 barrels per day and flowing to gas-liquid separators or direct to storage 

tanks. If you elect to delay reporting of this data element, you must report by the date 

specified in §98.236(cc) the total volume of oil from all wells and the API Well Number(s) 

for the well(s) included in this volume.

(iv) The average gas-liquid separator temperature, in degrees Fahrenheit.

(v) The average gas-liquid separator pressure, in pounds per square inch gauge.

(vi) The average sales oil or stabilized oil API gravity, in degrees.

(vii) The minimum and maximum concentration (mole fraction) of CO2 in flash gas 

from onshore production storage tanks.

(viii) The minimum and maximum concentration (mole fraction) of CH4 in flash gas 

from onshore production storage tanks.

(ix) The number of wells sending oil to gas-liquid separators or directly to 

atmospheric tanks.

(x) The number of atmospheric tanks.

(xi) An estimate of the number of atmospheric tanks, not on well-pads, receiving 

your oil.

(xii) If any emissions from the atmospheric tanks at your facility were controlled 

with vapor recovery systems, then you must report the information specified in 

paragraphs (j)(1)(xii)(A) through (E) of this section.

(A) The number of atmospheric tanks that control emissions with vapor recovery 

systems.

(B) Total CO2 mass, in metric tons CO2, that was recovered during the calendar 

year using a vapor recovery system.

(C) Total CH4 mass, in metric tons CH4, that was recovered during the calendar 

year using a vapor recovery system.

(D) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks equipped 

with vapor recovery systems.
(E) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks equipped 

with vapor recovery systems.

(xiii) If any atmospheric tanks at your facility vented gas directly to the atmosphere 

without using a vapor recovery system or without flaring, then you must report the 

information specified in paragraphs (j)(1)(xiii)(A) through (C) of this section.

(A) The number of atmospheric tanks that vented gas directly to the atmosphere 

without using a vapor recovery system or without flaring.

(B) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas 

directly to the atmosphere.

(C) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas 

directly to the atmosphere.

(xiv) If you controlled emissions from any atmospheric tanks at your facility with 

one or more flares, then you must report the information specified in paragraphs 

(j)(1)(xiv)(A) through (D) of this section.

(A) The number of atmospheric tanks that controlled emissions with flares.

(B) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks that 

controlled emissions with one or more flares.

(C) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks that 

controlled emissions with one or more flares.

(D) Annual N2O emissions, in metric tons N2O, from atmospheric tanks that 

controlled emissions with one or more flares.

(2) If you used Calculation Method 3 to calculate GHG emissions, then you must 

report the information specified in paragraphs (j)(2)(i) through (iii) of this section.

(i) Report the information specified in paragraphs (j)(2)(i)(A) through (F) of this 

section, at the basin level, for atmospheric tanks where emissions were calculated using 

Calculation Method 3.

(A) The total annual oil throughput that is sent to all atmospheric tanks in the 

basin, in barrels. You may delay reporting of this data element if you indicate in the 

annual report that wildcat wells and delineation wells are the only wells in the sub-basin 

with oil production less than 10 barrels per day and that send oil to atmospheric tanks. If 

you elect to delay reporting of this data element, you must report by the date specified in 

§98.236(cc) the total annual oil throughput from all wells and the API Well Number(s) for 

the well(s) included in this volume.

(B) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) of 

this section sent to atmospheric tanks in the basin that controlled emissions with flares.

(C) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) of 

this section sent to atmospheric tanks in the basin that controlled emissions with vapor 

recovery systems.

(D) The number of atmospheric tanks in the basin.
(E) The number of wells with gas-liquid separators (“Count” from Equation W-15 of 

this subpart) in the basin.

(F) The number of wells without gas-liquid separators (“Count” from Equation W15 of this subpart) in the basin.

(ii) Report the information specified in paragraphs (j)(2)(ii)(A) through (D) of this 

section for each sub-basin with atmospheric tanks whose emissions were calculated 

using Calculation Method 3 and that did not control emissions with flares.

(A) Sub-basin ID.

(B) The number of atmospheric tanks in the sub-basin that did not control 

emissions with flares.

(C) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks in the subbasin that did not control emissions with flares, calculated using Equation W-15 of this 

subpart and adjusted for vapor recovery, if applicable.

(D) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks in the subbasin that did not control emissions with flares, calculated using Equation W-15 of this 

subpart and adjusted for vapor recovery, if applicable.

(iii) Report the information specified in paragraphs (j)(2)(iii)(A) through (E) of this 

section for each sub-basin with atmospheric tanks whose emissions were calculated 

using Calculation Method 3 and that controlled emissions with flares.

(A) Sub-basin ID.

(B) The number of atmospheric tanks in the sub-basin that controlled emissions 

with flares.

(C) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks that 

controlled emissions with flares.

(D) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks that 

controlled emissions with flares.

(E) Annual N2O emissions, in metric tons N2O, from atmospheric tanks that 

controlled emissions with flares.

(3) If you used Calculation Method 1 or Calculation Method 2, and any gas-liquid 

separator liquid dump values did not close properly during the calendar year, then you 

must report the information specified in paragraphs (j)(3)(i) through (iv) of this section for 

each sub-basin.

(i) The total number of gas-liquid separators whose liquid dump valves did not 

close properly during the calendar year.

(ii) The total time the dump valves on gas-liquid separators did not close properly 

in the calendar year, in hours (sum of the “Tn” values used in Equation W-16 of this 

subpart).
(iii) Annual CO2 emissions, in metric tons CO2, that resulted from dump valves on 

gas-liquid separators not closing properly during the calendar year, calculated using 

Equation W-16 of this subpart.

(iv) Annual CH4 emissions, in metric tons CH4, that resulted from the dump valves 

on gas-liquid separators not closing properly during the calendar year, calculated using 

Equation W-16 of this subpart.

(k) Transmission storage tanks. You must indicate whether your facility contains 

any transmission storage tanks. If your facility contains at least one transmission storage 

tank, then you must report the information specified in paragraphs (k)(1) through (3) of 

this section for each transmission storage tank vent stack.

(1) For each transmission storage tank vent stack, report the information specified 

in (k)(1)(i) through (iv) of this section.

(i) The unique name or ID number for the transmission storage tank vent stack.

(ii) Method used to determine if dump valve leakage occurred.

(iii) Indicate whether scrubber dump valve leakage occurred for the transmission 

storage tank vent according to §98.233(k)(2).

(iv) Indicate if there is a flare attached to the transmission storage tank vent stack.

(2) If scrubber dump valve leakage occurred for a transmission storage tank vent 

stack, as reported in paragraph (k)(1)(iii) of this section, and the vent stack vented 

directly to the atmosphere during the calendar year, then you must report the information 

specified in paragraphs (k)(2)(i) through (v) of this section for each transmission storage 

vent stack where scrubber dump valve leakage occurred.

(i) Method used to measure the leak rate.

(ii) Measured leak rate (average leak rate from a continuous flow measurement 

device), in standard cubic feet per hour.

(iii) Duration of time that the leak is counted as having occurred, in hours, as 

determined in §98.233(k)(3) (may use best available data if a continuous flow 

measurement device was used).

(iv) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas 

directly to the atmosphere, calculated according to §98.233(k)(1) through (4).

(v) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas 

directly to the atmosphere, calculated according to §98.233(k)(1) through (4).

(3) If scrubber dump valve leakage occurred for a transmission storage tank vent 

stack, as reported in paragraph (k)(1)(iii), and the vent stack vented to a flare during the 

calendar year, then you must report the information specified in paragraphs (k)(3)(i) 

through (vi) of this section.

(i) Method used to measure the leak rate.

(ii) Measured leakage rate (average leak rate from a continuous flow measurement 

device) in standard cubic feet per hour.
(iii) Duration of time that flaring occurred in hours, as defined in §98.233(k)(3) (may 

use best available data if a continuous flow measurement device was used).

(iv) Annual CO2 emissions, in metric tons CO2, that resulted from flaring gas, 

calculated according to §98.233(k)(5).

(v) Annual CH4 emissions, in metric tons CH4, that resulted from flaring gas, 

calculated according to §98.233(k)(5).

(vi) Annual N2O emissions, in metric tons N2O, that resulted from flaring gas, 

calculated according to §98.233(k)(5).

(l) Well testing. You must indicate whether you performed gas well or oil well 

testing, and if the testing of gas wells or oil wells resulted in vented or flared emissions 

during the calendar year. If you performed well testing that resulted in vented or flared 

emissions during the calendar year, then you must report the information specified in 

paragraphs (l)(1) through (4) of this section, as applicable.

(1) If you used Equation W-17A to calculate annual volumetric natural gas 

emissions at actual conditions from oil wells and the emissions are not vented to a flare, 

then you must report the information specified in paragraphs (l)(1)(i) through (vi) of this 

section.

(i) Number of wells tested in the calendar year.

(ii) Average number of well testing days per well for well(s) tested in the calendar 

year.

(iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil.

(iv) Average flow rate for well(s) tested, in barrels of oil per day. You may delay 

reporting of this data element if you indicate in the annual report that wildcat wells and/or 

delineation wells are the only wells that are tested. If you elect to delay reporting of this 

data element, you must report by the date specified in §98.236(cc) the measured 

average flow rate for well(s) tested and the API Well Number(s) for the well(s) included 

in the measurement.

(v) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(l).

(vi) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(l).

(2) If you used Equation W-17A to calculate annual volumetric natural gas 

emissions at actual conditions from oil wells and the emissions are vented to a flare, 

then you must report the information specified in paragraphs (l)(2)(i) through (vii) of this 

section.

(i) Number of wells tested in the calendar year.

(ii) Average number of well testing days per well for well(s) tested in the calendar 

year.

(iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil.

(iv) Average flow rate for well(s) tested, in barrels of oil per day. You may delay 

reporting of this data element if you indicate in the annual report that wildcat wells and/or 

delineation wells are the only wells that are tested. If you elect to delay reporting of this 
data element, you must report by the date specified in §98.236(cc) the measured 

average flow rate for well(s) tested and the API Well Number(s) for the well(s) included 

in the measurement.

(v) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(l).

(vi) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(l).

(vii) Annual N2O emissions, in metric tons N2O, calculated according to §98.233(l).

(3) If you used Equation W-17B to calculate annual volumetric natural gas 

emissions at actual conditions from gas wells and the emissions were not vented to a 

flare, then you must report the information specified in paragraphs (l)(3)(i) through (v) of 

this section.

(i) Number of wells tested in the calendar year.

(ii) Average number of well testing days per well for well(s) tested in the calendar 

year.

(iii) Average annual production rate for well(s) tested, in actual cubic feet per day. 

You may delay reporting of this data element if you indicate in the annual report that 

wildcat wells and/or delineation wells are the only wells that are tested. If you elect to 

delay reporting of this data element, you must report by the date specified in §98.236(cc) 

the measured average annual production rate for well(s) tested and the API Well 

Number(s) for the well(s) included in the measurement.

(iv) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(l).

(v) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(l).

(4) If you used Equation W-17B to calculate annual volumetric natural gas 

emissions at actual conditions from gas wells and the emissions were vented to a flare, 

then you must report the information specified in paragraphs (l)(4)(i) through (vi) of this 

section.

(i) Number of wells tested in calendar year.

(ii) Average number of well testing days per well for well(s) tested in the calendar 

year.

(iii) Average annual production rate for well(s) tested, in actual cubic feet per day. 

You may delay reporting of this data element if you indicate in the annual report that 

wildcat wells and/or delineation wells are the only wells that are tested. If you elect to 

delay reporting of this data element, you must report by the date specified in §98.236(cc) 

the measured average annual production rate for well(s) tested and the API Well 

Number(s) for the well(s) included in the measurement.

(iv) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(l).

(v) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(l).

(vi) Annual N2O emissions, in metric tons N2O, calculated according to §98.233(l).

(m) Associated natural gas. You must indicate whether any associated gas was 

vented or flared during the calendar year. If associated gas was vented or flared during 
the calendar year, then you must report the information specified in paragraphs (m)(1) 

through (8) of this section for each sub-basin.

(1) Sub-basin ID.

(2) Indicate whether any associated gas was vented directly to the atmosphere 

without flaring.

(3) Indicate whether any associated gas was flared.

(4) Average gas to oil ratio, in standard cubic feet of gas per barrel of oil (average 

of the “GOR” values used in Equation W-18 of this subpart).

(5) Volume of oil produced, in barrels, in the calendar year during the time periods 

in which associated gas was vented or flared (the sum of “Vp,q” used in Equation W-18 of 

this subpart). You may delay reporting of this data element if you indicate in the annual 

report that wildcat wells and/or delineation wells are the only wells from which associated 

gas was vented or flared. If you elect to delay reporting of this data element, you must 

report by the date specified in §98.236(cc) the volume of oil produced for well(s) with 

associated gas venting and flaring and the API Well Number(s) for the well(s) included in 

the measurement.

(6) Total volume of associated gas sent to sales, in standard cubic feet, in the 

calendar year during time periods in which associated gas was vented or flared (the sum 

of “SG” values used in Equation W-18 of §98.233(m)). You may delay reporting of this 

data element if you indicate in the annual report that wildcat wells and/or delineation 

wells from which associated gas was vented or flared. If you elect to delay reporting of 

this data element, you must report by the date specified in §98.236(cc) the measured 

total volume of associated gas sent to sales for well(s) with associated gas venting and 

flaring and the API Well Number(s) for the well(s) included in the measurement.

(7) If you had associated gas emissions vented directly to the atmosphere without 

flaring, then you must report the information specified in paragraphs (m)(7)(i) through (iii) 

of this section for each sub-basin.

(i) Total number of wells for which associated gas was vented directly to the 

atmosphere without flaring.

(ii) Annual CO2 emissions, in metric tons CO2, calculated according to 

§98.233(m)(3) and (4).

(iii) Annual CH4 emissions, in metric tons CH4, calculated according to 

§98.233(m)(3) and (4).

(8) If you had associated gas emissions that were flared, then you must report the 

information specified in paragraphs (m)(8)(i) through (iv) of this section for each subbasin.

(i) Total number of wells for which associated gas was flared.

(ii) Annual CO2 emissions, in metric tons CO2, calculated according to 

§98.233(m)(5).

(iii) Annual CH4 emissions, in metric tons CH4, calculated according to 

§98.233(m)(5).
(iv) Annual N2O emissions, in metric tons N2O, calculated according to 

§98.233(m)(5).

(n) Flare stacks. You must indicate if your facility contains any flare stacks. You 

must report the information specified in paragraphs (n)(1) through (12) of this section for 

each flare stack at your facility, and for each industry segment applicable to your facility.

(1) Unique name or ID for the flare stack. For the onshore petroleum and natural 

gas production industry segment, a different name or ID may be used for a single flare 

stack for each location where it operates at in a given calendar year.

(2) Indicate whether the flare stack has a continuous flow measurement device.

(3) Indicate whether the flare stack has a continuous gas composition analyzer on 

feed gas to the flare.

(4) Volume of gas sent to the flare, in standard cubic feet (“Vs” in Equations W-19 

and W-20 of this subpart).

(5) Fraction of the feed gas sent to an un-lit flare (“Zu” in Equation W-19 of this 

subpart).

(6) Flare combustion efficiency, expressed as the fraction of gas combusted by a 

burning flare.

(7) Mole fraction of CH4 in the feed gas to the flare (“XCH4” in Equation W-19 of this 

subpart).

(8) Mole fraction of CO2 in the feed gas to the flare (“XCO2” in Equation W-20 of this 

subpart).

(9) Annual CO2 emissions, in metric tons CO2 (refer to Equation W-20 of this 

subpart).

(10) Annual CH4 emissions, in metric tons CH4 (refer to Equation W-19 of this 

subpart).

(11) Annual N2O emissions, in metric tons N2O (refer to Equation W-40 of this 

subpart).

(12) Indicate whether a CEMS was used to measure emissions from the flare. If a 

CEMS was used to measure emissions from the flare, then you are not required to report 

N2O and CH4 emissions for the flare stack.

(o) Centrifugal compressors. You must indicate whether your facility has 

centrifugal compressors. You must report the information specified in paragraphs (o)(1) 

and (2) of this section for all centrifugal compressors at your facility. For each 

compressor source or manifolded group of compressor sources that you conduct as 

found leak measurements as specified in §98.233(o)(2) or (4), you must report the 

information specified in paragraph (o)(3) of this section. For each compressor source or 

manifolded group of compressor sources that you conduct continuous monitoring as 

specified in §98.233(o)(3) or (5), you must report the information specified in paragraph 

(o)(4) of this section. Centrifugal compressors in onshore petroleum and natural gas 

production are not required to report information in paragraphs (o)(1) through (4) of this 

section and instead must report the information specified in paragraph (o)(5) of this 

section.
(1) Compressor activity data. Report the information specified in paragraphs 

(o)(1)(i) through (xiv) of this section for each centrifugal compressor located at your 

facility.

(i) Unique name or ID for the centrifugal compressor.

(ii) Hours in operating-mode.

(iii) Hours in not-operating-depressurized-mode.

(iv) Indicate whether the compressor was measured in operating-mode.

(v) Indicate whether the compressor was measured in not-operatingdepressurized-mode.

(vi) Indicate which, if any, compressor sources are part of a manifolded group of 

compressor sources.

(vii) Indicate which, if any, compressor sources are routed to a flare.

(viii) Indicate which, if any, compressor sources have vapor recovery.

(ix) Indicate which, if any, compressor source emissions are captured for fuel use 

or are routed to a thermal oxidizer.

(x) Indicate whether the compressor has blind flanges installed and associated 

dates.

(xi) Indicate whether the compressor has wet or dry seals.

(xii) If the compressor has wet seals, the number of wet seals.

(xiii) Power output of the compressor driver (hp).

(xiv) Indicate whether the compressor had a scheduled depressurized shutdown 

during the reporting year.

(2) Compressor source. (i) For each compressor source at each compressor, 

report the information specified in paragraphs (o)(2)(i)(A) through (C) of this section.

(A) Centrifugal compressor name or ID. Use the same ID as in paragraph (o)(1)(i) 

of this section.

(B) Centrifugal compressor source (wet seal, isolation valve, or blowdown valve).

(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a 

manifolded group of compressor sources, use the same leak or vent ID for each 

compressor source in the manifolded group. If multiple compressor sources are released 

through a single vent for which continuous measurements are used, use the same leak 

or vent ID for each compressor source released via the measured vent. For a single 

compressor using as found measurements, you must provide a different leak or vent ID 

for each compressor source.
(ii) For each leak or vent, report the information specified in paragraphs (o)(2)(ii)(A) 

through (E) of this section.

(A) Indicate whether the leak or vent is for a single compressor source or 

manifolded group of compressor sources and whether the emissions from the leak or 

vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal 

oxidizer), or vapor recovery.

(B) Indicate whether an as found measurement(s) as identified in §98.233(o)(2) or 

(4) was conducted on the leak or vent.

(C) Indicate whether continuous measurements as identified in §98.233(o)(3) or 

(5) were conducted on the leak or vent.

(D) Report emissions as specified in paragraphs (o)(2)(ii)(D)(1) and (2) of this 

section for the leak or vent. If the leak or vent is routed to a flare, combustion, or vapor 

recovery, you are not required to report emissions under this paragraph.

(1) Annual CO2 emissions, in metric tons CO2.

(2) Annual CH4 emissions, in metric tons CH4.

(E) If the leak or vent is routed to flare, combustion, or vapor recovery, report the 

percentage of time that the respective device was operational when the compressor 

source emissions were routed to the device.

(3) As found measurement sample data. If the measurement methods specified in 

§98.233(o)(2) or (4) are conducted, report the information specified in paragraph (o)(3)(i) 

of this section. If the calculation specified in §98.233(o)(6)(ii) is performed, report the 

information specified in paragraph (o)(3)(ii) of this section.

(i) For each as found measurement performed on a leak or vent, report the 

information specified in paragraphs (o)(3)(i)(A) through (F) of this section.

(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph 

(o)(2)(i)(C) of this section.

(B) Measurement date.

(C) Measurement method. If emissions were not detected when using a screening 

method, report the screening method. If emissions were detected using a screening 

method, report only the method subsequently used to measure the volumetric emissions.

(D) Measured flow rate, in standard cubic feet per hour.

(E) For each compressor attached to the leak or vent, report the compressor mode 

during which the measurement was taken.

(F) If the measurement is for a manifolded group of compressor sources, indicate 

whether the measurement location is prior to or after comingling with non-compressor 

emission sources.

(ii) For each compressor mode-source combination where a reporter emission 

factor as calculated in Equation W-23 was used to calculate emissions in Equation W22, report the information specified in paragraphs (o)(3)(ii)(A) through (D) of this section.
(A) The compressor mode-source combination.

(B) The compressor mode-source combination reporter emission factor, in 

standard cubic feet per hour (EFs,m in Equation W-23).

(C) The total number of compressors measured in the compressor mode-source 

combination in the current reporting year and the preceding two reporting years 

(Countm in Equation W-23).

(D) Indicate whether the compressor mode-source combination reporter emission 

factor is facility-specific or based on all of the reporter's applicable facilities.

(4) Continuous measurement data. If the measurement methods specified in 

§98.233(o)(3) or (5) are conducted, report the information specified in paragraphs 

(o)(4)(i) through (iv) of this section for each continuous measurement conducted on each 

leak or vent associated with each compressor source or manifolded group of compressor 

sources.

(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph 

(o)(2)(i)(C) of this section.

(ii) Measured volume of flow during the reporting year, in million standard cubic 

feet.

(iii) Indicate whether the measured volume of flow during the reporting year 

includes compressor blowdown emissions as allowed for in §98.233(o)(3)(ii) and 

(o)(5)(iii).

(iv) If the measurement is for a manifolded group of compressor sources, indicate 

whether the measurement location is prior to or after comingling with non-compressor 

emission sources.

(5) Onshore petroleum and natural gas production. Centrifugal compressors with 

wet seal degassing vents in onshore petroleum and natural gas production must report 

the information specified in paragraphs (o)(5)(i) through (iii) of this section.

(i) Number of centrifugal compressors that have wet seal oil degassing vents.

(ii) Annual CO2 emissions, in metric tons CO2, from centrifugal compressors with 

wet seal oil degassing vents.

(iii) Annual CH4 emissions, in metric tons CH4, from centrifugal compressors with 

wet seal oil degassing vents.

(p) Reciprocating compressors. You must indicate whether your facility has 

reciprocating compressors. You must report the information specified in paragraphs 

(p)(1) and (2) of this section for all reciprocating compressors at your facility. For each 

compressor source or manifolded group of compressor sources that you conduct as 

found leak measurements as specified in §98.233(p)(2) or (4), you must report the 

information specified in paragraph (p)(3) of this section. For each compressor source or 

manifolded group of compressor sources that you conduct continuous monitoring as 

specified in §98.233(p)(3) or (5), you must report the information specified in paragraph 

(p)(4) of this section. Reciprocating compressors in onshore petroleum and natural gas 

production are not required to report information in paragraphs (p)(1) through (4) of this 

section and instead must report the information specified in paragraph (p)(5) of this 

section.
(1) Compressor activity data. Report the information specified in paragraphs 

(p)(1)(i) through (xiv) of this section for each reciprocating compressor located at your 

facility.

(i) Unique name or ID for the reciprocating compressor.

(ii) Hours in operating-mode.

(iii) Hours in standby-pressurized-mode.

(iv) Hours in not-operating-depressurized-mode.

(v) Indicate whether the compressor was measured in operating-mode.

(vi) Indicate whether the compressor was measured in standby-pressurized-mode.

(vii) Indicate whether the compressor was measured in not-operatingdepressurized-mode.

(viii) Indicate which, if any, compressor sources are part of a manifolded group of 

compressor sources.

(ix) Indicate which, if any, compressor sources are routed to a flare.

(x) Indicate which, if any, compressor sources have vapor recovery.

(xi) Indicate which, if any, compressor source emissions are captured for fuel use 

or are routed to a thermal oxidizer.

(xii) Indicate whether the compressor has blind flanges installed and associated 

dates.

(xiii) Power output of the compressor driver (hp).

(xiv) Indicate whether the compressor had a scheduled depressurized shutdown 

during the reporting year.

(2) Compressor source. (i) For each compressor source at each compressor, 

report the information specified in paragraphs (p)(2)(i)(A) through (C) of this section.

(A) Reciprocating compressor name or ID. Use the same ID as in paragraph 

(p)(1)(i) of this section.

(B) Reciprocating compressor source (isolation valve, blowdown valve, or rod 

packing).

(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a 

manifolded group of compressor sources, use the same leak or vent ID for each 

compressor source in the manifolded group. If multiple compressor sources are released 

through a single vent for which continuous measurements are used, use the same leak 

or vent ID for each compressor source released via the measured vent. For a single 

compressor using as found measurements, you must provide a different leak or vent ID 

for each compressor source.
(ii) For each leak or vent, report the information specified in paragraphs (p)(2)(ii)(A) 

through (E) of this section.

(A) Indicate whether the leak or vent is for a single compressor source or 

manifolded group of compressor sources and whether the emissions from the leak or 

vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal 

oxidizer), or vapor recovery.

(B) Indicate whether an as found measurement(s) as identified in §98.233(p)(2) or 

(4) was conducted on the leak or vent.

(C) Indicate whether continuous measurements as identified in §98.233(p)(3) or 

(5) were conducted on the leak or vent.

(D) Report emissions as specified in paragraphs (p)(2)(ii)(D)(1) and (2) of this 

section for the leak or vent. If the leak or vent is routed to flare, combustion, or vapor 

recovery, you are not required to report emissions under this paragraph.

(1) Annual CO2 emissions, in metric tons CO2.

(2) Annual CH4 emissions, in metric tons CH4.

(E) If the leak or vent is routed to flare, combustion, or vapor recovery, report the 

percentage of time that the respective device was operational when the compressor 

source emissions were routed to the device.

(3) As found measurement sample data. If the measurement methods specified in 

§98.233(p)(2) or (4) are conducted, report the information specified in paragraph (p)(3)(i) 

of this section. If the calculation specified in §98.233(p)(6)(ii) is performed, report the 

information specified in paragraph (p)(3)(ii) of this section.

(i) For each as found measurement performed on a leak or vent, report the 

information specified in paragraphs (p)(3)(i)(A) through (F) of this section.

(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph 

(p)(2)(i)(C) of this section.

(B) Measurement date.

(C) Measurement method. If emissions were not detected when using a screening 

method, report the screening method. If emissions were detected using a screening 

method, report only the method subsequently used to measure the volumetric emissions.

(D) Measured flow rate, in standard cubic feet per hour.

(E) For each compressor attached to the leak or vent, report the compressor mode 

during which the measurement was taken.

(F) If the measurement is for a manifolded group of compressor sources, indicate 

whether the measurement location is prior to or after comingling with non-compressor 

emission sources.

(ii) For each compressor mode-source combination where a reporter emission 

factor as calculated in Equation W-28 was used to calculate emissions in Equation W27, report the information specified in paragraphs (p)(3)(ii)(A) through (D) of this section
(A) The compressor mode-source combination.

(B) The compressor mode-source combination reporter emission factor, in 

standard cubic feet per hour (EFs,m in Equation W-28).

(C) The total number of compressors measured in the compressor mode-source 

combination in the current reporting year and the preceding two reporting years 

(Countm in Equation W-28).

(D) Indicate whether the compressor mode-source combination reporter emission 

factor is facility-specific or based on all of the reporter's applicable facilities.

(4) Continuous measurement data. If the measurement methods specified in 

§98.233(p)(3) or (5) are conducted, report the information specified in paragraphs 

(p)(4)(i) through (iv) of this section for each continuous measurement conducted on each 

leak or vent associated with each compressor source or manifolded group of compressor 

sources.

(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph 

(p)(2)(i)(C) of this section.

(ii) Measured volume of flow during the reporting year, in million standard cubic 

feet.

(iii) Indicate whether the measured volume of flow during the reporting year 

includes compressor blowdown emissions as allowed for in §98.233(p)(3)(ii) and 

(p)(5)(iii).

(iv) If the measurement is for a manifolded group of compressor sources, indicate 

whether the measurement location is prior to or after comingling with non-compressor 

emission sources.

(5) Onshore petroleum and natural gas production. Reciprocating compressors in 

onshore petroleum and natural gas production must report the information specified in 

paragraphs (p)(5)(i) through (iii) of this section.

(i) Number of reciprocating compressors.

(ii) Annual CO2 emissions, in metric tons CO2, from reciprocating compressors.

(iii) Annual CH4 emissions, in metric tons CH4, from reciprocating compressors.

(q) Equipment leak surveys. If your facility is subject to the requirements of 

§98.233(q), then you must report the information specified in paragraphs (q)(1) and (2) 

of this section. Natural gas distribution facilities with emission sources listed in 

§98.232(i)(1) must also report the information specified in paragraph (q)(3) of this 

section.

(1) You must report the information specified in paragraphs (q)(1)(i) and (ii) of this 

section.

(i) Except as specified in paragraph (q)(1)(ii) of this section, the number of 

complete equipment leak surveys performed during the calendar year.
(ii) Natural gas distribution facilities performing equipment leak surveys across a 

multiple year leak survey cycle must report the number of years in the leak survey cycle.

(2) You must indicate whether your facility contains any of the component types 

listed in §98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), or (i)(1), for your facility's industry 

segment. For each component type that is located at your facility, you must report the 

information specified in paragraphs (q)(2)(i) through (v) of this section. If a component 

type is located at your facility and no leaks were identified from that component, then you 

must report the information in paragraphs (q)(2)(i) through (v) of this section but report a 

zero (“0”) for the information required according to paragraphs (q)(2)(iii), (iv), and (v) of 

this section.

(i) Component type.

(ii) Total number of the surveyed component type that were identified as leaking in 

the calendar year (“xp” in Equation W-30 of this subpart for the component type).

(iii) Average time the surveyed components are assumed to be leaking and 

operational, in hours (average of “Tp,z” from Equation W-30 of this subpart for the 

component type).

(iv) Annual CO2 emissions, in metric tons CO2, for the component type as 

calculated using Equation W-30 (for surveyed components only).

(v) Annual CH4 emissions, in metric tons CH4, for the component type as 

calculated using Equation W-30 (for surveyed components only).

(3) Natural gas distribution facilities with emission sources listed in §98.232(i)(1) 

must also report the information specified in paragraphs (q)(3)(i) through (viii) and, if 

applicable, (q)(3)(ix) of this section.

(i) Number of above grade transmission-distribution transfer stations surveyed in 

the calendar year.

(ii) Number of meter/regulator runs at above grade transmission-distribution 

transfer stations surveyed in the calendar year (“CountMR,y” from Equation W-31 of this 

subpart, for the current calendar year).

(iii) Average time that meter/regulator runs surveyed in the calendar year were 

operational, in hours (average of “Tw,y” from Equation W-31 of this subpart, for the 

current calendar year).

(iv) Number of above grade transmission-distribution transfer stations surveyed in 

the current leak survey cycle.

(v) Number of meter/regulator runs at above grade transmission-distribution 

transfer stations surveyed in current leak survey cycle (sum of “CountMR,y” from Equation 

W-31 of this subpart, for all calendar years in the current leak survey cycle).

(vi) Average time that meter/regulator runs surveyed in the current leak survey 

cycle were operational, in hours (average of “Tw,y” from Equation W-31 of this subpart, 

for all years included in the leak survey cycle).

(vii) Meter/regulator run CO2 emission factor based on all surveyed transmissiondistribution transfer stations in the current leak survey cycle, in standard cubic feet of 
CO2 per operational hour of all meter/regulator runs (“EFs,MR,i” for CO2calculated using 

Equation W-31 of this subpart).

(viii) Meter/regulator run CH4 emission factor based on all surveyed transmissiondistribution transfer stations in the current leak survey cycle, in standard cubic feet of 

CH4 per operational hour of all meter/regulator runs (“EFs,MR,i” for CH4calculated using 

Equation W-31 of this subpart).

(ix) If your natural gas distribution facility performs equipment leak surveys across 

a multiple year leak survey cycle, you must also report:

(A) The total number of meter/regulator runs at above grade transmissiondistribution transfer stations at your facility (“CountMR” in Equation W-32B of this 

subpart).

(B) Average estimated time that each meter/regulator run at above grade 

transmission-distribution transfer stations was operational in the calendar year, in hours 

per meter/regulator run (“Tw,avg” in Equation W-32B of this subpart).

(C) Annual CO2 emissions, in metric tons CO2, for all above grade transmissiondistribution transfer stations at your facility.

(D) Annual CH4 emissions, in metric tons CH4, for all above grade transmissiondistribution transfer stations at your facility.

(r) Equipment leaks by population count. If your facility is subject to the 

requirements of §98.233(r), then you must report the information specified in paragraphs 

(r)(1) through (3) of this section, as applicable.

(1) You must indicate whether your facility contains any of the emission source 

types required to use Equation W-32A of this subpart. You must report the information 

specified in paragraphs (r)(1)(i) through (v) of this section separately for each emission 

source type required to use Equation W-32A of this subpart that is located at your 

facility. Onshore petroleum and natural gas production facilities must report the 

information specified in paragraphs (r)(1)(i) through (v) of this section separately by 

component type, service type, and geographic location (i.e., Eastern U.S. or Western 

U.S.).

(i) Emission source type. Onshore petroleum and natural gas production facilities 

must report the component type, service type and geographic location.

(ii) Total number of the emission source type at the facility (“Counte” in Equation 

W-32A of this subpart).

(iii) Average estimated time that the emission source type was operational in the 

calendar year, in hours (“Te” in Equation W-32A of this subpart).

(iv) Annual CO2 emissions, in metric tons CO2, for the emission source type.

(v) Annual CH4 emissions, in metric tons CH4, for the emission source type.

(2) Natural gas distribution facilities must also report the information specified in 

paragraphs (r)(2)(i) through (v) of this section.

(i) Number of above grade transmission-distribution transfer stations at the facility.
(ii) Number of above grade metering-regulating stations that are not transmissiondistribution transfer stations at the facility.

(iii) Total number of meter/regulator runs at above grade metering-regulating 

stations that are not above grade transmission-distribution transfer stations (“CountMR” in 

Equation W-32B of this subpart).

(iv) Average estimated time that each meter/regulator run at above grade 

metering-regulating stations that are not above grade transmission-distribution transfer 

stations was operational in the calendar year, in hours per meter/regulator run (“Tw,avg” in 

Equation W-32B of this subpart).

(v) If your facility has above grade metering-regulating stations that are not above 

grade transmission-distribution transfer stations and your facility also has above grade 

transmission-distribution transfer stations, you must also report:

(A) Annual CO2 emissions, in metric tons CO2, from above grade meteringregulating stations that are not above grade transmission-distribution transfer stations.

(B) Annual CH4 emissions, in metric tons CH4, from above grade metering 

regulating stations that are not above grade transmission-distribution transfer stations.

(3) Onshore petroleum and natural gas production facilities must also report the 

information specified in paragraphs (r)(3)(i) and (ii) of this section.

(i) Calculation method used.

(ii) Onshore petroleum and natural gas production facilities must report the 

information specified in paragraphs (r)(3)(ii)(A) and (B) of this section, for each major 

equipment type, production type (i.e., natural gas or crude oil), and geographic location 

combination in Tables W-1B and W-1C of this subpart.

(A) An indication of whether the facility contains the major equipment type.

(B) If the facility does contain the equipment type, the count of the major 

equipment type.

(s) Offshore petroleum and natural gas production. You must report the 

information specified in paragraphs (s)(1) through (3) of this section for each emission 

source type listed in the most recent BOEMRE study.

(1) Annual CO2 emissions, in metric tons CO2.

(2) Annual CH4 emissions, in metric tons CH4.

(3) Annual N2O emissions, in metric tons N2O.

(t) [Reserved]

(u) [Reserved]

(v) [Reserved]

(w) EOR injection pumps. You must indicate whether CO2 EOR injection was used 

at your facility during the calendar year and if any EOR injection pump blowdowns 

occurred during the year. If any EOR injection pump blowdowns occurred during the 
calendar year, then you must report the information specified in paragraphs (w)(1) 

through (8) of this section for each EOR injection pump system.

(1) Sub-basin ID.

(2) EOR injection pump system identifier.

(3) Pump capacity, in barrels per day.

(4) Total volume of EOR injection pump system equipment chambers, in cubic feet 

(“Vv” in Equation W-37 of this subpart).

(5) Number of blowdowns for the EOR injection pump system in the calendar year.

(6) Density of critical phase EOR injection gas, in kilograms per cubic foot (“Rc” in 

Equation W-37 of this subpart).

(7) Mass fraction of CO2 in critical phase EOR injection gas (“GHGCO2” in Equation 

W-37 of this subpart).

(8) Annual CO2 emissions, in metric tons CO2, from EOR injection pump system 

blowdowns.

(x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon liquids were 

produced through EOR operations. If hydrocarbon liquids were produced through EOR 

operations, you must report the information specified in paragraphs (x)(1) through (4) of 

this section for each sub-basin category with EOR operations.

(1) Sub-basin ID.

(2) Total volume of hydrocarbon liquids produced through EOR operations in the 

calendar year, in barrels (“Vhl” in Equation W-38 of this subpart).

(3) Average CO2 retained in hydrocarbon liquids downstream of the storage tank, 

in metric tons per barrel under standard conditions (“Shl” in Equation W-38 of this 

subpart).

(4) Annual CO2 emissions, in metric tons CO2, from CO2 retained in hydrocarbon 

liquids produced through EOR operations downstream of the storage tank (“MassCO2” in 

Equation W-38 of this subpart).

(y) [Reserved]

(z) Combustion equipment at onshore petroleum and natural gas production 

facilities and natural gas distribution facilities. If your facility is required by §98.232(c)(22) 

or (i)(7) to report emissions from combustion equipment, then you must indicate whether 

your facility has any combustion units subject to reporting according to paragraphs 

(a)(1)(xvii) or (a)(8)(i) of this section. If your facility contains any combustion units subject 

to reporting according to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section, then you must 

report the information specified in paragraphs (z)(1) and (2) of this section, as applicable.

(1) Indicate whether the combustion units include: External fuel combustion units 

with a rated heat capacity less than or equal to 5 million Btu per hour; or, internal fuel 

combustion units that are not compressor-drivers, with a rated heat capacity less than or 

equal to 1 mmBtu/hr (or the equivalent of 130 horsepower). If the facility contains 

external fuel combustion units with a rated heat capacity less than or equal to 5 million 
Btu per hour or internal fuel combustion units that are not compressor-drivers, with a 

rated heat capacity less than or equal to 1 million Btu per hour (or the equivalent of 130 

horsepower), then you must report the information specified in paragraphs (z)(1)(i) and 

(ii) of this section for each unit type.

(i) The type of combustion unit.

(ii) The total number of combustion units.

(2) Indicate whether the combustion units include: External fuel combustion units 

with a rated heat capacity greater than 5 million Btu per hour; internal fuel combustion 

units that are not compressor-drivers, with a rated heat capacity greater than 1 million 

Btu per hour (or the equivalent of 130 horsepower); or, internal fuel combustion units of 

any heat capacity that are compressor-drivers. If your facility contains: External fuel 

combustion units with a rated heat capacity greater than 5 mmBtu/hr; internal fuel 

combustion units that are not compressor-drivers, with a rated heat capacity greater than 

1 million Btu per hour (or the equivalent of 130 horsepower); or internal fuel combustion 

units of any heat capacity that are compressor-drivers, then you must report the 

information specified in paragraphs (z)(2)(i) through (vi) of this section for each 

combustion unit type and fuel type combination.

(i) The type of combustion unit.

(ii) The type of fuel combusted.

(iii) The quantity of fuel combusted in the calendar year, in thousand standard 

cubic feet, gallons, or tons.

(iv) Annual CO2 emissions, in metric tons CO2, calculated according to 

§98.233(z)(1) and (2).

(v) Annual CH4 emissions, in metric tons CH4, calculated according to 

§98.233(z)(1) and (2).

(vi) Annual N2O emissions, in metric tons N2O, calculated according to 

§98.233(z)(1) and (2).

(aa) Each facility must report the information specified in paragraphs (aa)(1) 

through (9) of this section, for each applicable industry segment, by using best available 

data. If a quantity required to be reported is zero, you must report zero as the value.

(1) For onshore petroleum and natural gas production, report the data specified in 

paragraphs (aa)(1)(i) and (ii) of this section.

(i) Report the information specified in paragraphs (aa)(1)(i)(A) through (C) of this 

section for the basin as a whole.

(A) The quantity of gas produced in the calendar year from wells, in thousand 

standard cubic feet. This includes gas that is routed to a pipeline, vented or flared, or 

used in field operations. This does not include gas injected back into reservoirs or 

shrinkage resulting from lease condensate production.

(B) The quantity of gas produced in the calendar year for sales, in thousand 

standard cubic feet.
(C) The quantity of crude oil and condensate produced in the calendar year for 

sales, in barrels.

(ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through (M) of this 

section for each unique sub-basin category.

(A) State.

(B) County.

(C) Formation type.

(D) The number of producing wells at the end of the calendar year (exclude only 

those wells permanently taken out of production, i.e., plugged and abandoned) .

(E) The number of producing wells acquired during the calendar year.

(F) The number of producing wells divested during the calendar year.

(G) The number of wells completed during the calendar year.

(H) The number of wells permanently taken out of production (i.e., plugged and 

abandoned) during the calendar year.

(I) Average mole fraction of CH4 in produced gas.

(J) Average mole fraction of CO2 in produced gas.

(K) If an oil sub-basin, report the average GOR of all wells, in thousand standard 

cubic feet per barrel.

(L) If an oil sub-basin, report the average API gravity of all wells.

(M) If an oil sub-basin, report average low pressure separator pressure, in pounds 

per square inch gauge.

(2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) 

and (ii) of this section.

(i) The total quantity of gas handled at the offshore platform in the calendar year, in 

thousand standard cubic feet, including production volumes and volumes transferred via 

pipeline from another location.

(ii) The total quantity of oil and condensate handled at the offshore platform in the 

calendar year, in barrels, including production volumes and volumes transferred via 

pipeline from another location.

(3) For natural gas processing, report the information specified in paragraphs 

(aa)(3)(i) through (vii) of this section.

(i) The quantity of natural gas received at the gas processing plant in the calendar 

year, in thousand standard cubic feet.
(ii) The quantity of processed (residue) gas leaving the gas processing plant in the 

calendar year, in thousand standard cubic feet.

(iii) The cumulative quantity of all NGLs (bulk and fractionated) received at the gas 

processing plant in the calendar year, in barrels.

(iv) The cumulative quantity of all NGLs (bulk and fractionated) leaving the gas 

processing plant in the calendar year, in barrels.

(v) Average mole fraction of CH4 in natural gas received.

(vi) Average mole fraction of CO2 in natural gas received.

(vii) Indicate whether the facility fractionates NGLs.

(4) For natural gas transmission compression, report the quantity specified in 

paragraphs (aa)(4)(i) through (v) of this section.

(i) The quantity of gas transported through the compressor station in the calendar 

year, in thousand standard cubic feet.

(ii) Number of compressors.

(iii) Total compressor power rating of all compressors combined, in horsepower.

(iv) Average upstream pipeline pressure, in pounds per square inch gauge.

(v) Average downstream pipeline pressure, in pounds per square inch gauge.

(5) For underground natural gas storage, report the quantities specified in 

paragraphs (aa)(5)(i) through (iii) of this section.

(i) The quantity of gas injected into storage in the calendar year, in thousand 

standard cubic feet.

(ii) The quantity of gas withdrawn from storage in the calendar year, in thousand 

standard cubic feet.

(iii) Total storage capacity, in thousand standard cubic feet.

(6) For LNG import equipment, report the quantity of LNG imported in the calendar 

year, in thousand standard cubic feet.

(7) For LNG export equipment, report the quantity of LNG exported in the calendar 

year, in thousand standard cubic feet.

(8) For LNG storage, report the quantities specified in paragraphs (aa)(8)(i) 

through (iii) of this section.

(i) The quantity of LNG added into storage in the calendar year, in thousand 

standard cubic feet.

(ii) The quantity of LNG withdrawn from storage in the calendar year, in thousand 

standard cubic feet.
(iii) Total storage capacity, in thousand standard cubic feet.

(9) For natural gas distribution, report the quantities specified in paragraphs 

(aa)(9)(i) through (vii) of this section.

(i) The quantity of natural gas received at all custody transfer stations in the 

calendar year, in thousand standard cubic feet. This value may include meter 

corrections, but only for the calendar year covered by the annual report.

(ii) The quantity of natural gas withdrawn from in-system storage in the calendar 

year, in thousand standard cubic feet.

(iii) The quantity of natural gas added to in-system storage in the calendar year, in 

thousand standard cubic feet.

(iv) The quantity of natural gas delivered to end users, in thousand standard cubic 

feet. This value does not include stolen gas, or gas that is otherwise unaccounted for.

(v) The quantity of natural gas transferred to third parties such as other LDCs or 

pipelines, in thousand standard cubic feet. This value does not include stolen gas, or gas 

that is otherwise unaccounted for.

(vi) The quantity of natural gas consumed by the LDC for operational purposes, in 

thousand standard cubic feet.

(vii) The estimated quantity of gas stolen in the calendar year, in thousand 

standard cubic feet.

(bb) For any missing data procedures used, report the information in §98.3(c)(8) 

except as provided in paragraphs (bb)(1) and (2) of this section.

(1) For quarterly measurements, report the total number of quarters that a missing 

data procedure was used for each data element rather than the total number of hours.

(2) For annual or biannual (once every two years) measurements, you do not need 

to report the number of hours that a missing data procedure was used for each data 

element.

(cc) If you elect to delay reporting the information in paragraph (g)(5)(i), (g)(5)(ii), 

(h)(1)(iv), (h)(2)(iv), (j)(1)(iii), (j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), (l)(3)(iii), (l)(4)(iii), (m)(5), or 

(m)(6) of this section, you must report the information required in that paragraph no later 

than the date 2 years following the date specified in §98.3(b) introductory text.

Subpart X –

Petrochemical 

Production

(§98.246)

All In In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a), (b), or (c) of this section, as 

appropriate for each process unit.

(a) If you use the mass balance methodology in §98.243(c), you must report the 

information specified in paragraphs (a)(1) through (13) of this section for each type of 

petrochemical produced, reported by process unit.

(1) The petrochemical process unit ID number or other appropriate descriptor.

(2) The type of petrochemical produced, names of products, and names of carboncontaining feedstocks.
(3) Annual CO2 emissions calculated using Equation X-4 of this subpart.

(4) The temperature (in °F) at which the gaseous feedstock and product volumes 

used in Equation X-1 of §98.243 were determined.

(5) Annual quantity of each type of petrochemical produced from each process unit 

(metric tons).

(6) For each feedstock and product, provide the information specified in 

paragraphs (a)(6)(i) through (a)(6)(iii) of this section.

(i) Name of each method used to determine carbon content or molecular weight in 

accordance with §98.244(b)(4);

(ii) Description of each type of device (e.g., flow meter, weighing device) used to 

determine flow or mass in accordance with §98.244(b)(1) through (3).

(iii) Identification of each method (i.e., method number, title, or other description) 

used to determine flow or mass in accordance with §98.244(b)(1) through (3).

(7) [Reserved]

(8) Identification of each combustion unit that burned both process off-gas and 

supplemental fuel, including combustion units that are not part of the petrochemical 

process unit.

(9) The number of days during which off-specification product was produced if the 

alternative to sampling and analysis specified in §98.243(c)(4) is used for a product, and, 

if applicable, the date of any process change that reduced the monthly average 

composition to less than 99.5 percent for each product or feedstock for which you 

comply with the alternative to sampling and analysis specified in §98.243(c)(4).

(10) You may elect to report the flow and carbon content of wastewater, and you 

may elect to report the annual mass of carbon released in fugitive emissions and in 

process vents that are not controlled with a combustion device. These values may be 

estimated based on engineering analyses. These values are not to be used in the mass 

balance calculation.

(11) If you determine carbon content or composition of a feedstock or product 

using a method under §98.244(b)(4)(xv)(B), report the information listed in paragraphs 

(a)(11)(i) through (a)(11)(iii) of this section. Include the information in paragraph (a)(11)(i) 

of this section in each annual report. Include the information in paragraphs (a)(11)(ii) and 

(a)(11)(iii) of this section only in the first applicable annual report, and provide any 

changes to this information in subsequent annual reports.

(i) Name or title of the analytical method.

(ii) A copy of the method. If the method is a modification of a method listed in 

§§98.244(b)(4)(i) through (xiv), you may provide a copy of only the sections that differ 

from the listed method.

(iii) An explanation of why an alternative to the methods listed in §§98.244(b)(4)(i) 

through (xiv) is needed.
(12) Name and annual quantity (in metric tons) of each carbon-containing 

feedstock included in Equations X-1, X-2, and X-3 of §98.243.

(13) Name and annual quantity (in metric tons) of each product included in 

Equations X-1, X-2, and X-3.

(b) If you measure emissions in accordance with §98.243(b), then you must report 

the information listed in paragraphs (b)(1) through (10) of this section.

(1) The petrochemical process unit ID or other appropriate descriptor, and the type 

of petrochemical produced.

(2) For CEMS used on stacks that include emissions from stationary combustion 

units that burn any amount of off-gas from the petrochemical process, report the relevant 

information required under §98.36(c)(2) and (e)(2)(vi) for the Tier 4 calculation 

methodology. Sections 98.36(c)(2)(ii) and (c)(2)(ix) do not apply for the purposes of this 

subpart.

(3) For CEMS used on stacks that do not include emissions from stationary 

combustion units, report the information required under §98.36(b)(6), (b)(7), and 

(e)(2)(vi).

(4) For each CEMS monitoring location that meets the conditions in paragraph 

(b)(2) or (3) of this section, provide an estimate based on engineering judgment of the 

fraction of the total CO2 emissions that results from CO2 directly emitted by the 

petrochemical process unit plus CO2 generated by the combustion of off-gas from the 

petrochemical process unit.

(5) For each CEMS monitoring location that meets the conditions in paragraph 

(b)(2) of this section, report the CH4and N2O emissions expressed in metric tons of each 

gas. For each CEMS monitoring location, provide an estimate based on engineering 

judgment of the fraction of the total CH4 and N2O emissions that is attributable to 

combustion of off-gas from the petrochemical process unit.

(6) [Reserved]

(7) Information listed in §98.256(e) of subpart Y of this part for each flare that 

burns process off-gas.

(8) Annual quantity of each type of petrochemical produced from each process unit 

(metric tons).

(9) Name and annual quantity (in metric tons) of each carbon-containing 

feedstock.

(10) Name and annual quantity (in metric tons) of each product.

(c) If you comply with the combustion methodology specified in §98.243(d), you 

must report under this subpart the information listed in paragraphs (c)(1) through (c)(5) 

of this section.

(1) The ethylene process unit ID or other appropriate descriptor.

(2) For each stationary combustion unit that burns ethylene process off-gas (or 

group of stationary sources with a common pipe), except flares, the relevant information 

listed in §98.36 for the applicable Tier methodology. For each stationary combustion unit 

or group of units (as applicable) that burns ethylene process off-gas, provide an estimate 
based on engineering judgment of the fraction of the total emissions that is attributable to 

combustion of off-gas from the ethylene process unit.

(3) Information listed in §98.256(e) of subpart Y of this part for each flare that 

burns ethylene process off-gas.

(4) Name and annual quantity of each feedstock (metric tons).

(5) Annual quantity of ethylene produced from each process unit (metric tons).

Subpart Y –

Petroleum 

Refineries

(§98.256)

All In In addition to the reporting requirements of §98.3(c), you must report the 

information specified in paragraphs (a) through (q) of this section.

(a) For combustion sources, follow the data reporting requirements under subpart 

C of this part (General Stationary Fuel Combustion Sources).

(b) For hydrogen plants, follow the data reporting requirements under subpart P of 

this part (Hydrogen Production).

(c)-(d) [Reserved]

(e) For flares, owners and operators shall report:

(1) The flare ID number (if applicable).

(2) A description of the type of flare (steam assisted, air-assisted).

(3) A description of the flare service (general facility flare, unit flare, emergency 

only or back-up flare).

(4) The calculated CO2, CH4, and N2O annual emissions for each flare, expressed 

in metric tons of each pollutant emitted.

(5) A description of the method used to calculate the CO2 emissions for each flare 

(e.g., reference section and equation number).

(6) If you use Equation Y-1a of §98.253, an indication of whether daily or weekly 

measurement periods are used, the annual volume of flare gas combusted (in scf/year) 

and the annual average molecular weight (in kg/kg-mole), and annual average carbon 

content of the flare gas (in kg carbon per kg flare gas).

(7) If you use Equation Y-1b of §98.253, an indication of whether daily or weekly 

measurement periods are used, the annual volume of flare gas combusted (in scf/year), 

the annual average CO2 concentration (volume or mole percent), the number of carbon 

containing compounds other than CO2 in the flare gas stream, and for each of the 

carbon containing compounds other than CO2 in the flare gas stream:

(i) The annual average concentration of the compound (volume or mole percent).

(ii) [Reserved]

(8) If you use Equation Y-2 of this subpart, an indication of whether daily or weekly 

measurement periods are used, the annual volume of flare gas combusted (in million 

(MM) scf/year), the annual average higher heating value of the flare gas (in 

mmBtu/mmscf), and an indication of whether the annual volume of flare gas combusted 
and the annual average higher heating value of the flare gas were determined using 

standard conditions of 68 °F and 14.7 psia or 60 °F and 14.7 psia.

(9) If you use Equation Y-3 of §98.253, the number of SSM events exceeding 

500,000 scf/day.

(10) The basis for the value of the fraction of carbon in the flare gas contributed by 

methane used in Equation Y-4 of §98.253.

(f) For catalytic cracking units, traditional fluid coking units, and catalytic reforming 

units, owners and operators shall report:

(1) The unit ID number (if applicable).

(2) A description of the type of unit (fluid catalytic cracking unit, thermal catalytic 

cracking unit, traditional fluid coking unit, or catalytic reforming unit).

(3) Maximum rated throughput of the unit, in bbl/stream day.

(4) The calculated CO2, CH4, and N2O annual emissions for each unit, expressed 

in metric tons of each pollutant emitted.

(5) A description of the method used to calculate the CO2 emissions for each unit 

(e.g., reference section and equation number).

(6) If you use a CEMS, the relevant information required under §98.36 for the Tier 

4 Calculation Methodology, the CO2 annual emissions as measured by the CEMS 

(unadjusted to remove CO2 combustion emissions associated with additional units, if 

present) and the process CO2 emissions as calculated according to §98.253(c)(1)(ii). 

Report the CO2annual emissions associated with sources other than those from the coke 

burn-off in accordance with the applicable subpart (e.g., subpart C of this part in the case 

of a CO boiler).

(7) If you use Equation Y-6 of §98.253, the annual average exhaust gas flow rate, 

%CO2, and %CO.

(8) If you use Equation Y-7a of this subpart, the annual average flow rate of inlet 

air and oxygen-enriched air, %O2, %Ooxy, %CO2, and %CO.

(9) If you use Equation Y-7b of this subpart, the annual average flow rate of inlet 

air and oxygen-enriched air, %N2,oxy, and %N2,exhaust.

(10) If you use Equation Y-8 of §98.253, the basis for the value of the average 

carbon content of coke.

(11) Indicate whether you use a measured value, a unit-specific emission factor, or 

a default for CH4 emissions. If you use a unit-specific emission factor for CH4, report the 

basis for the factor.

(12) Indicate whether you use a measured value, a unit-specific emission factor, or 

a default emission factor for N2O emissions. If you use a unit-specific emission factor for 

N2O, report the basis for the factor.
(13) If you use Equation Y-11 of §98.253, the number of regeneration cycles or 

measurement periods during the reporting year and the average coke burn-off quantity 

per cycle or measurement period.

(g) For fluid coking unit of the flexicoking type, the owner or operator shall report:

(1) The unit ID number (if applicable).

(2) A description of the type of unit.

(3) Maximum rated throughput of the unit, in bbl/stream day.

(4) Indicate whether the GHG emissions from the low heat value gas are 

accounted for in subpart C of this part or §98.253(c).

(5) If the GHG emissions for the low heat value gas are calculated at the 

flexicoking unit, also report the calculated annual CO2, CH4, and N2O emissions for each 

unit, expressed in metric tons of each pollutant emitted, and the applicable equation 

input parameters specified in paragraphs (f)(7) through (f)(13) of this section.

(h) For on-site sulfur recovery plants and for emissions from sour gas sent off-site 

for sulfur recovery, the owner and operator shall report:

(1) The plant ID number (if applicable).

(2) For each on-site sulfur recovery plant, the maximum rated throughput (metric 

tons sulfur produced/stream day), a description of the type of sulfur recovery plant, and 

an indication of the method used to calculate CO2 annual emissions for the sulfur 

recovery plant (e.g., CO2 CEMS, Equation Y-12, or process vent method in §98.253(j)).

(3) The calculated CO2 annual emissions for each on-site sulfur recovery plant, 

expressed in metric tons. The calculated annual CO2 emissions from sour gas sent offsite for sulfur recovery, expressed in metric tons.

(4) [Reserved]

(5) If you recycle tail gas to the front of the sulfur recovery plant, indicate whether 

the recycled flow rate and carbon content are included in the measured data under 

§98.253(f)(2) and (3). Indicate whether a correction for CO2 emissions in the tail gas was 

used in Equation Y-12 of §98.253. If so, then report:

(i) Indicate whether you used the default (95 percent) or a unit specific correction, 

and if a unit-specific correction was used, report the value of the correction and the 

approach used.

(ii) If the following data are not used to calculate the recycling correction factor, 

report the information specified in paragraphs (h)(5)(ii)(A) through (B) of this section.

(A) The annual volume of recycled tail gas (in scf/year) only.

(B) The annual average mole fraction of carbon in the tail gas (in kg-mole C/kgmole gas).

(6) If you use a CEMS, the relevant information required under §98.36 for the Tier 

4 Calculation Methodology, the CO2 annual emissions as measured by the CEMS and 

the annual process CO2 emissions calculated according to §98.253(f)(1). Report the 
CO2 annual emissions associated with fuel combustion in accordance with subpart C of 

this part (General Stationary Fuel Combustion Sources).

(7) If you use the process vent method in §98.253(j) for a non-Claus sulfur 

recovery plant, the relevant information required under paragraph (l)(5) of this section.

(i) For coke calcining units, the owner and operator shall report:

(1) The unit ID number (if applicable).

(2) Maximum rated throughput of the unit, in metric tons coke calcined/stream day.

(3) The calculated CO2, CH4, and N2O annual emissions for each unit, expressed 

in metric tons of each pollutant emitted.

(4) A description of the method used to calculate the CO2 emissions for each unit 

(e.g., reference section and equation number).

(5) If you use Equation Y-13 of §98.253, an indication of whether coke dust is 

recycled to the unit (e.g., all dust is recycled, a portion of the dust is recycled, or none of 

the dust is recycled).

(6) If you use a CEMS, the relevant information required under §98.36 for the Tier 

4 Calculation Methodology, the CO2 annual emissions as measured by the CEMS and 

the annual process CO2 emissions calculated according to §98.253(g)(1).

(7) Indicate whether you use a measured value, a unit-specific emission factor or a 

default emission factor for CH4emissions. If you use a unit-specific emission factor for 

CH4, report the basis for the factor.

(8) Indicate whether you use a measured value, a unit-specific emission factor, or 

a default emission factor for N2O emissions. If you use a unit-specific emission factor for 

N2O, report the basis for the factor.

(j) For asphalt blowing operations, the owner or operator shall report:

(1) The unit ID number (if applicable).

(2) [Reserved]

(3) The type of control device used to reduce methane (and other organic) 

emissions from the unit.

(4) The calculated annual CO2 and CH4 emissions for each unit, expressed in 

metric tons of each pollutant emitted.

(5) If you use Equation Y-14 of §98.253, the basis for the CO2 emission factor 

used.

(6) If you use Equation Y-15 of §98.253, the basis for the CH4 emission factor 

used.

(7) If you use Equation Y-16a of §98.253, the basis for the carbon emission factor 

used.
(8) If you use Equation Y-16b of §98.253, the basis for the CO2 emission factor 

used and the basis for the carbon emission factor used.

(9) If you use Equation Y-17 of §98.253, the basis for the CH4 emission factor 

used.

(10) If you use Equation Y-19 of this subpart, the relevant information required 

under paragraph (l)(5) of this section.

(k) For delayed coking units, the owner or operator shall report:

(1) The cumulative annual CH4 emissions (in metric tons of CH4) for all delayed 

coking units at the facility.

(2) A description of the method used to calculate the CH4 emissions for each unit 

(e.g., reference section and equation number).

(3) The total number of delayed coking units at the facility; the total number of 

delayed coking drums at the facility; and, for each coke drum or vessel, the typical drum 

outage (i.e. the unfilled distance from the top of the drum, in feet).

(4) For each set of coking drums that are the same dimensions, the number of 

coking drums in the set, and the mole fraction of methane in coking gas (in kg-mole 

CH4/kg-mole gas, wet basis).

(5) The basis for the volumetric void fraction of the coke vessel prior to steaming 

and the basis for the mole fraction of methane in the coking gas.

(6) If you use Equation Y-19 of this subpart, the relevant information required 

under paragraph (l)(5) of this section for each set of coke drums or vessels of the same 

size.

(l) For each process vent subject to §98.253(j), the owner or operator shall report:

(1) The vent ID number (if applicable).

(2) The unit or operation associated with the emissions.

(3) The type of control device used to reduce methane (and other organic) 

emissions from the unit, if applicable.

(4) The calculated annual CO2, CH4, and N2O emissions for each vent, expressed 

in metric tons of each pollutant emitted.

(5) The annual volumetric flow discharged to the atmosphere (in scf), and an 

indication of the measurement or estimation method, annual average mole fraction of 

each GHG above the concentration threshold or otherwise required to be reported and 

an indication of the measurement or estimation method, and for intermittent vents, the 

number of venting events and the cumulative venting time.

(m) For uncontrolled blowdown systems, the owner or operator shall report:

(1) An indication of whether the uncontrolled blowdown emission are reported 

under §98.253(k) or §98.253(j) or a statement that the facility does not have any 

uncontrolled blowdown systems.
(2) The cumulative annual CH4 emissions (in metric tons of CH4) for uncontrolled 

blowdown systems.

(3) For uncontrolled blowdown systems reporting under §98.253(k), the basis for 

the value of the methane emission factor used for uncontrolled blowdown systems.

(4) For uncontrolled blowdown systems reporting under §98.253(j), the relevant 

information required under paragraph (l)(5) of this section.

(n) For equipment leaks, the owner or operator shall report:

(1) The cumulative CH4 emissions (in metric tons of each pollutant emitted) for all 

equipment leak sources.

(2) The method used to calculate the reported equipment leak emissions.

(3) The number of each type of emission source listed in Equation Y-21 of this 

subpart at the facility.

(o) For storage tanks, the owner or operator shall report:

(1) The cumulative annual CH4 emissions (in metric tons of CH4) for all storage 

tanks, except for those used to process unstabilized crude oil.

(2) For storage tanks other than those processing unstabilized crude oil:

(i) The method used to calculate the reported storage tank emissions for storage 

tanks other than those processing unstabilized crude (i.e., either AP 42, Section 7.1 

(incorporated by reference, see §98.7), or Equation Y-22 of this section).

(ii) [Reserved]

(3) The cumulative CH4 emissions (in metric tons of CH4) for storage tanks used to 

process unstabilized crude oil or a statement that the facility did not receive any 

unstabilized crude oil during the reporting year.

(4) For storage tanks that process unstabilized crude oil:

(i) The method used to calculate the reported unstabilized crude oil storage tank 

emissions.

(ii)-(iv) [Reserved]

(v) The basis for the mole fraction of CH4 in vent gas from unstabilized crude oil 

storage tanks.

(vi) If you did not use Equation Y-23, the tank-specific methane composition data 

and the annual gas generation volume (scf/yr) used to estimate the cumulative 

CH4 emissions for storage tanks used to process unstabilized crude oil.

(5)-(7) [Reserved]

(p) For loading operations, the owner or operator shall report:
(1) The cumulative annual CH4 emissions (in metric tons of each pollutant emitted) 

for loading operations.

(2) The types of materials loaded that have an equilibrium vapor-phase 

concentration of methane of 0.5 volume percent or greater, and the type of vessel 

(barge, tanker, marine vessel, etc.) in which each type of material is loaded.

(3) The type of control system used to reduce emissions from the loading of 

material with an equilibrium vapor-phase concentration of methane of 0.5 volume 

percent or greater, if any (submerged loading, vapor balancing, etc.).

(q) Name of each method listed in §98.254 or a description of manufacturer's 

recommended method used to determine a measured parameter.

Subpart Z –

Phosphoric 

Acid 

Production

(§98.266)

All In In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a) through (f) of this section.

(a) Annual phosphoric acid production, by origin of the phosphate rock (tons).

(b) Annual phosphoric acid production capacity (tons).

(c) Annual arithmetic average percent inorganic carbon or carbon dioxide in 

phosphate rock from monthly records (percent by weight, expressed as a decimal 

fraction).

(d) Annual phosphate rock consumption from monthly measurement records by 

origin (tons).

(e) If you use a CEMS to measure CO2 emissions, then you must report the 

information in paragraphs (e)(1) and (e)(2) of this section.

(1) The identification number of each wet-process phosphoric acid process line.

(2) The annual CO2 emissions from each wet-process phosphoric acid process line 

(metric tons) and the relevant information required under 40 CFR 98.36 (e)(2)(vi) for the 

Tier 4 Calculation Methodology.

(f) If you do not use a CEMS to measure emissions, then you must report the 

information in paragraphs (f)(1) through (9) of this section.

(1) Identification number of each wet-process phosphoric acid process line.

(2) Annual CO2 emissions from each wet-process phosphoric acid process line 

(metric tons) as calculated by either Equation Z-1a or Equation Z-1b of this subpart.

(3) Annual phosphoric acid permitted production capacity (tons) for each wetprocess phosphoric acid process line (metric tons).

(4) Method used to estimate any missing values of inorganic carbon content or 

carbon dioxide content of phosphate rock for each wet-process phosphoric acid process 

line.

(5) [Reserved]

(6) [Reserved]
(7) Number of wet-process phosphoric acid process lines.

(8) Number of times missing data procedures were used to estimate phosphate 

rock consumption (months), inorganic carbon contents of the phosphate rock (months), 

and CO2 contents of the phosphate rock (months).

(9) Annual process CO2 emissions from phosphoric acid production facility (metric 

tons).

Subpart AA –

Pulp and 

Paper 

Manufacturing

(§98.276)

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c) and the applicable information 

required by §98.36, each annual report must contain the information in paragraphs (a) 

through (l) of this section as applicable:

(a) Annual emissions of CO2, biogenic CO2, CH4, biogenic CH4 N2O, and biogenic 

N2O (metric tons per year).

(b) [Reserved]

(c) Basis for determining the annual mass of the spent liquor solids combusted 

(whether based on T650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by 

reference, see §98.7) or an online measurement system).

(d) [Reserved]

(e) The default emission factor for CO2, CH4, or N2O, used in Equation AA-1 of this 

subpart (kg CO2, CH4, or N2O per mmBtu).

(f)-(i) [Reserved]

(j) Annual steam purchases (pounds of steam per year).

(k) Total annual production of unbleached virgin chemical pulp produced onsite 

during the reporting year in air-dried metric tons per year. This total annual production 

value is the sum of all kraft, semichemical, soda, and sulfite pulp produced onsite, prior 

to bleaching, through all virgin pulping lines. Do not include mechanical pulp or 

secondary fiber repulped for paper production in the virgin pulp production total.

(l) For each pulp mill lime kiln, report the information specified in paragraphs (l)(1) 

and (2) of this section.

(1) The quantity of calcium oxide (CaO) produced (metric tons).

(2) The percent of annual heat input, individually for each fossil fuel type.

Subpart BB –

Silicon

Carbide 

Production

(§98.286)

All In In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a) or (b) of this section, as applicable for 

each silicon carbide production facility.

(a) If a CEMS is used to measure process CO2 emissions, you must report under 

this subpart the relevant information required for the Tier 4 Calculation Methodology in 

§98.36 and the information listed in this paragraph (a):

(1) Annual consumption of petroleum coke (tons).

(2) Annual production of silicon carbide (tons).
(3) Annual production capacity of silicon carbide (tons).

(b) If a CEMS is not used to measure process CO2 emissions, you must report the 

information in paragraph (b)(1) through (8) of this section for all silicon carbide process 

units or production furnaces combined:

(1) [Reserved]

(2) Annual production of silicon carbide (tons).

(3) Annual production capacity of silicon carbide (tons).

(4) [Reserved]

(5) Whether carbon content of the petroleum coke is based on reports from the 

supplier or through self measurement using applicable ASTM standard method.

(6) [Reserved]

(7) Sampling analysis results for carbon content of consumed petroleum coke as 

determined for QA/QC of supplier data under §98.284(d) (percent by weight expressed 

as a decimal fraction).

(8) Number of times in the reporting year that missing data procedures were 

followed to measure the carbon contents of petroleum coke (number of months) and 

petroleum coke consumption (number of months).

Subpart CC –

Soda Ash 

Manufacturing

(§98.296)

All In In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a) or (b) of this section, as appropriate 

for each soda ash manufacturing facility.

(a) If a CEMS is used to measure CO2 emissions, then you must report under this 

subpart the relevant information required under §98.36 and the following information in 

this paragraph (a):

(1) Annual consumption of trona or liquid alkaline feedstock for each 

manufacturing line (tons).

(2) Annual production of soda ash for each manufacturing line (tons).

(3) Annual production capacity of soda ash for each manufacturing line (tons).

(4) Identification number of each manufacturing line.

(b) If a CEMS is not used to measure CO2 emissions, then you must report the 

information listed in this paragraph (b):

(1) Identification number of each manufacturing line.

(2) Annual process CO2 emissions from each soda ash manufacturing line (metric 

tons).

(3) Annual production of soda ash for each manufacturing line (tons).
(4) Annual production capacity of soda ash for each manufacturing line (tons).

(5)-(7) [Reserved]

(8) Whether CO2 emissions for each manufacturing line were calculated using a 

trona input method as described in Equation CC-1 of this subpart, a soda ash output 

method as described in Equation CC-2 of this subpart, or a site-specific emission factor 

method as described in Equations CC-3 through CC-5 of this subpart.

(9) Number of manufacturing lines located used to produce soda ash.

(10) If you produce soda ash using the liquid alkaline feedstock process and use 

the site-specific emission factor method (§98.293(b)(3)) to estimate emissions then you 

must report the following relevant information for each manufacturing line or stack:

(i) Stack gas volumetric flow rate during performance test (dscfm).

(ii) Hourly CO2 concentration during performance test (percent CO2).

(iii) CO2 emission factor (metric tons CO2/metric tons of process vent flow from 

mine water stripper/evaporator).

(iv) CO2 mass emission rate during performance test (metric tons/hour).

(v) Average process vent flow from mine water stripper/evaporator during 

performance test (pounds/hour).

(vi) Annual process vent flow rate from mine water stripper/evaporator (thousand 

pounds/hour).

(11) Number of times missing data procedures were used and for which parameter 

as specified in this paragraph (b)(11):

(i) Trona or soda ash (number of months).

(ii) Inorganic carbon contents of trona or soda ash (weeks).

(iii) Process vent flow rate from mine water stripper/evaporator (number of 

months).

Subpart DDElectrical 

Transmission 

and 

Distribution 

Equipment 

Use

(§98.306)

Electrical 

transmission 

and 

distribution 

equipment 

use at 

facilities 

where the 

total 

nameplate 

capacity of 

SF6and PFC 

containing 

equipment 

exceeds 

In addition to the information required by §98.3(c), each annual report must 

contain the following information for each electric power system, by chemical:

(a) Nameplate capacity of equipment (pounds) containing SF6 and nameplate 

capacity of equipment (pounds) containing each PFC:

(1) Existing at the beginning of the year (excluding hermetically sealed-pressure 

switchgear).

(2) New during the year (all SF6-insulated equipment, including hermetically 

sealed-pressure switchgear).
17,820 

pounds

(3) Retired during the year (all SF6-insulated equipment, including hermetically 

sealed-pressure switchgear).

(b) Transmission miles (length of lines carrying voltages above 35 kilovolt).

(c) Distribution miles (length of lines carrying voltages at or below 35 kilovolt).

(d) Pounds of SF6 and PFC stored in containers, but not in energized equipment, 

at the beginning of the year.

(e) Pounds of SF6 and PFC stored in containers, but not in energized equipment, 

at the end of the year.

(f) Pounds of SF6 and PFC purchased in bulk from chemical producers or 

distributors.

(g) Pounds of SF6 and PFC purchased from equipment manufacturers or 

distributors with or inside equipment, including hermetically sealed-pressure switchgear.

(h) Pounds of SF6 and PFC returned to facility after off-site recycling.

(i) Pounds of SF6 and PFC in bulk and contained in equipment sold to other 

entities.

(j) Pounds of SF6 and PFC returned to suppliers.

(k) Pounds of SF6 and PFC sent off-site for recycling.

(l) Pounds of SF6 and PFC sent off-site for destruction.

Subpart EE –

Titanium 

Dioxide 

Production

(§98.316)

All In In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a) or (b) of this section, as applicable for 

each titanium dioxide production line.

(a) If a CEMS is used to measure CO2 emissions, then you must report the 

relevant information required under §98.36(e)(2)(vi) for the Tier 4 Calculation 

Methodology and the following information in this paragraph (a).

(1) Identification number of each process line.

(2) Annual consumption of calcined petroleum coke (tons).

(3) Annual production of titanium dioxide (tons).

(4) Annual production capacity of titanium dioxide (tons).

(5) Annual production of carbon-containing waste (tons), if applicable.

(b) If a CEMS is not used to measure CO2 emissions, then you must report the 

information listed in this paragraph (b):

(1) Identification number of each process line.
(2) Annual CO2 emissions from each chloride process line (metric tons/year).

(3) Annual consumption of calcined petroleum coke for each process line (tons).

(4) Annual production of titanium dioxide for each process line (tons).

(5) Annual production capacity of titanium dioxide for each process line (tons).

(6) [Reserved]

(7) Annual production of carbon-containing waste for each process line (tons), if 

applicable.

(8) Monthly production of titanium dioxide for each process line (tons).

(9) [Reserved]

(10) Whether monthly carbon content of the petroleum coke is based on reports 

from the supplier or through self measurement using applicable ASTM standard 

methods.

(11) Carbon content for carbon-containing waste for each process line (percent by 

weight expressed as a decimal fraction).

(12) If carbon content of petroleum coke is based on self measurement, the ASTM 

standard methods used.

(13) Sampling analysis results of carbon content of petroleum coke as determined 

for QA/QC of supplier data under §98.314(d) (percent by weight expressed as a decimal 

fraction).

(14) Number of separate chloride process lines located at the facility.

(15) The number of times in the reporting year that missing data procedures were 

followed to measure the carbon contents of petroleum coke (number of months); 

petroleum coke consumption (number of months); carbon-containing waste generated 

(number of months); and carbon contents of the carbon-containing waste (number of 

times during year).

Subpart FF –

Underground 

Coal Mines

(§98.326)

Underground 

coal mines 

liberating 

36,500,000 

actual cubic 

feet of CH4 

or more per 

year

In addition to the information required by §98.3(c), each annual report must 

contain the following information for each mine:

(a) Quarterly CH4 liberated from each ventilation monitoring point, (metric tons 

CH4).

(b) Weekly CH4 liberated from each degasification system monitoring point (metric 

tons CH4).

(c) Quarterly CH4 destruction at each ventilation and degasification system 

destruction device or point of offsite transport (metric tons CH4).

(d) Quarterly CH4 emissions (net) from all ventilation and degasification systems 

(metric tons CH4).
(e) Quarterly CO2 emissions from on-site destruction of coal mine gas CH4, where 

the gas is not a fuel input for energy generation or use (e.g., flaring) (metric tons CO2).

(f) Quarterly volumetric flow rate for each ventilation monitoring point and units of 

measure (scfm or acfm), date and location of each measurement, and method of 

measurement (quarterly sampling or continuous monitoring), used in Equation FF-1 of 

this subpart.

(g) Quarterly CH4 concentration for each ventilation monitoring point, dates and 

locations of each measurement and method of measurement (sampling or continuous 

monitoring).

(h) Weekly volumetric flow rate used to calculate CH4 liberated from degasification 

systems and units of measure (acfm or scfm), and method of measurement (sampling or 

continuous monitoring), used in Equation FF-3 of this subpart.

(i) Quarterly CH4 concentration (%) used to calculate CH4 liberated from 

degasification systems and if the data is based on CEMS or weekly sampling.

(j) Weekly volumetric flow rate used to calculate CH4 destruction for each 

destruction device and each point of offsite transport, and units of measure (acfm or 

scfm).

(k) Weekly CH4 concentration (%) used to calculate CH4 flow to each destruction 

device and each point of offsite transport (C).

(l) Dates in quarterly reporting period where active ventilation of mining operations 

is taking place.

(m) Dates in quarterly reporting period where degasification of mining operations is 

taking place.

(n) Dates in quarterly reporting period when continuous monitoring equipment is 

not properly functioning, if applicable.

(o) Temperatures (°R), pressure (atm), moisture content, and the moisture 

correction factor (if applicable) used in Equation FF-1 and FF-3 of this subpart; and the 

gaseous organic concentration correction factor, if Equation FF-9 was required.

(p) For each destruction device, a description of the device, including an indication 

of whether destruction occurs at the coal mine or off-site. If destruction occurs at the 

mine, also report an indication of whether a back-up destruction device is present at the 

mine, the annual operating hours for the primary destruction device, the annual 

operating hours for the back-up destruction device (if present), and the destruction 

efficiencies assumed (percent).

(q) A description of the gas collection system (manufacturer, capacity, and number 

of wells) the surface area of the gas collection system (square meters), and the annual 

operating hours of the gas collection system.

(r) Identification information and description for each well, shaft, and vent hole, 

including paragraphs (r)(1) through (r)(3) of this section:

(1) Indication of whether the well, shaft, or vent hole is monitored individually, or as 

part of a centralized monitoring point. Note which method (sampling or continuous 

monitoring) was used.
(2) Start date and close date of each well, shaft, and vent hole.

(3) Number of days the well, shaft, or vent hole was in operation during the 

reporting year.

(s) For each centralized monitoring point, identification of the wells and shafts 

included in the point. Note which method (sampling or continuous monitoring) was used.

(t) Mine Safety and Health Administration (MSHA) identification for this coal mine.

Subpart GG –

Zinc 

Production

(§98.336)

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c), each annual report must 

contain the information specified in paragraphs (a) or (b) of this section, as applicable, 

for each Waelz kiln or electrothermic furnace.

(a) If a CEMS is used to measure CO2 emissions, then you must report under this 

subpart the relevant information required for the Tier 4 Calculation Methodology in 

§98.36 and the information listed in this paragraph (a):

(1) Annual zinc product production capacity (tons).

(2) Annual production quantity for each zinc product (tons).

(3) Annual facility production quantity for each zinc product (tons).

(4) Number of Waelz kilns at each facility used for zinc production.

(5) Number of electrothermic furnaces at each facility used for zinc production.

(b) If a CEMS is not used to measure CO2 emissions, then you must report the 

information listed in this paragraph (b):

(1) Identification number and annual process CO2 emissions from each individual 

Waelz kiln or electrothermic furnace (metric tons).

(2) Annual zinc product production capacity (tons).

(3) Annual production quantity for each zinc product (tons).

(4) Number of Waelz kilns at each facility used for zinc production.

(5) Number of electrothermic furnaces at each facility used for zinc production.

(6) [Reserved]

(7) [Reserved]

(8) Whether carbon content of each carbon-containing input material charged to 

each kiln or furnace is based on reports from the supplier or through self measurement 

using applicable ASTM standard method.

(9) If carbon content of each carbon-containing input material charged to each kiln 

or furnace is based on self measurement, the ASTM Standard Test Method used.

(10) [Reserved]
(11) Whether carbon content of the carbon electrode used in each furnace is 

based on reports from the supplier or through self measurement using applicable ASTM 

standard method.

(12) If carbon content of carbon electrode used in each furnace is based on self 

measurement, the ASTM standard method used.

(13) If you use the missing data procedures in §98.335(b), you must report how 

the monthly mass of carbon-containing materials with missing data was determined and 

the number of months the missing data procedures were used.

Subpart HH –

Municipal 

Solid Waste 

Landfills

(§98.346)

Municipal 

solid waste 

landfills that 

generate 

CH4 in 

amounts 

equivalent to 

25,000 

metric tons 

CO2e or 

more per 

year

In addition to the information required by §98.3(c), each annual report must 

contain the following information for each landfill.

(a) A classification of the landfill as “open” (actively received waste in the reporting 

year) or “closed” (no longer receiving waste), the year in which the landfill first started 

accepting waste for disposal, the last year the landfill accepted waste (for open landfills, 

enter the estimated year of landfill closure), the capacity (in metric tons) of the landfill, an 

indication of whether leachate recirculation is used during the reporting year and its 

typical frequency of use over the past 10 years (e.g., used several times a year for the 

past 10 years, used at least once a year for the past 10 years, used occasionally but not 

every year over the past 10 years, not used), an indication as to whether scales are 

present at the landfill, and the waste disposal quantity for each year of landfilling 

required to be included when using Equation HH-1 of this subpart (in metric tons, wet 

weight).

(b) Method for estimating reporting year and historical waste disposal quantities, 

reason for its selection, and the range of years it is applied. For years when waste 

quantity data are determined using the methods in §98.343(a)(3), report separately the 

quantity of waste determined using the methods in §98.343(a)(3)(i) and the quantity of 

waste determined using the methods in §98.343(a)(3)(ii). For historical waste disposal 

quantities that were not determined using the methods in §98.343(a)(3), provide the 

population served by the landfill for each year the Equation HH-2 of this subpart is 

applied, if applicable, or, for open landfills using Equation HH-3 of this subpart, provide 

the value of landfill capacity (LFC) used in the calculation.

(c) Waste composition for each year required for Equation HH-1 of this subpart, in 

percentage by weight, for each waste category listed in Table HH-1 to this subpart that is 

used in Equation HH-1 of this subpart to calculate the annual modeled CH4 generation.

(d) For each waste type used to calculate CH4 generation using Equation HH-1 of 

this subpart, you must report:

(1) Degradable organic carbon (DOC) and fraction of DOC dissimilated (DOCF) 

values used in the calculations.

(2) Decay rate (k) value used in the calculations.

(e) Fraction of CH4 in landfill gas (F), an indication of whether the fraction of 

CH4 was determined based on measured values or the default value, and the methane 

correction factor (MCF) used in the calculations. If an MCF other than the default of 1 is 

used, provide an indication of whether active aeration of the waste in the landfill was 

conducted during the reporting year, a description of the aeration system, including 

aeration blower capacity, the fraction of the landfill containing waste affected by aeration, 

the total number of hours during the year the aeration blower was operated, and other 

factors used as a basis for the selected MCF value.

(f) The surface area of the landfill containing waste (in square meters), 

identification of the type of cover material used (as either organic cover, clay cover, sand 
cover, or other soil mixtures). If multiple cover types are used, the surface area 

associated with each cover type.

(g) The modeled annual methane generation rate for the reporting year (metric 

tons CH4) calculated using Equation HH-1 of this subpart.

(h) For landfills without gas collection systems, the annual methane emissions 

(i.e., the methane generation, adjusted for oxidation, calculated using Equation HH-5 of 

this subpart), reported in metric tons CH4, the oxidation fraction used in the calculation, 

and an indication of whether passive vents and/or passive flares (vents or flares that are 

not considered part of the gas collection system as defined in §98.6) are present at this 

landfill.

(i) For landfills with gas collection systems, you must report:

(1) Total volumetric flow of landfill gas collected for destruction for the reporting 

year (cubic feet at 520 °R or 60 degrees Fahrenheit and 1 atm).

(2) Annual average CH4 concentration of landfill gas collected for destruction 

(percent by volume).

(3) Monthly average temperature and pressure for each month at which flow is 

measured for landfill gas collected for destruction, or statement that temperature and/or 

pressure is incorporated into internal calculations run by the monitoring equipment.

(4) An indication as to whether flow was measured on a wet or dry basis, an 

indication as to whether CH4concentration was measured on a wet or dry basis, and if 

required for Equation HH-4 of this subpart, monthly average moisture content for each 

month at which flow is measured for landfill gas collected for destruction.

(5) An indication of whether destruction occurs at the landfill facility, off-site, or 

both. If destruction occurs at the landfill facility, also report for each measurement 

location the number of destruction devices associated with that measurement location 

and the annual operating hours and the destruction efficiency (percent) for each 

destruction device associated with that measurement location.

(6) Annual quantity of recovered CH4 (metric tons CH4) calculated using Equation 

HH-4 of this subpart for each measurement location.

(7) A description of the gas collection system (manufacturer, capacity, and number 

of wells), the surface area (square meters) and estimated waste depth (meters) for each 

area specified in Table HH-3 to this subpart, the estimated gas collection system 

efficiency for landfills with this gas collection system, the annual operating hours of the 

gas collection system for each measurement location, and an indication of whether 

passive vents and/or passive flares (vents or flares that are not considered part of the 

gas collection system as defined in §98.6) are present at the landfill.

(8) Methane generation corrected for oxidation calculated using Equation HH-5 of 

this subpart, reported in metric tons CH4, and the oxidation fraction used in the 

calculation.

(9) Methane generation (GCH4) value used as an input to Equation HH-6 of this 

subpart. Specify whether the value is modeled (GCH4 from HH-1 of this subpart) or 

measured (R from Equation HH-4 of this subpart).
(10) Methane generation corrected for oxidation calculated using Equation HH-7 of 

this subpart, reported in metric tons CH4, and the oxidation fraction used in the 

calculation.

(11) Methane emissions calculated using Equation HH-6 of this subpart, reported 

in metric tons CH4, and the oxidation fraction used in the calculation.

(12) Methane emissions calculated using Equation HH-8 of this subpart, reported 

in metric tons CH4, and the oxidation fraction used in the calculation.

Subpart II –

Industrial 

Wastewater 

Management

(§98.356)

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c), each annual report must 

contain the following information for each wastewater treatment system.

(a) A description or diagram of the industrial wastewater treatment system, 

identifying the processes used to treat industrial wastewater and industrial wastewater 

treatment sludge. Indicate how the processes are related to each other and identify the 

anaerobic processes. Provide a unique identifier for each anaerobic process, indicate 

the average depth in meters of each anaerobic lagoon, and indicate whether biogas 

generated by each anaerobic process is recovered. The anaerobic processes must be 

identified as:

(1) Anaerobic reactor.

(2) Anaerobic deep lagoon (depth more than 2 meters).

(3) Anaerobic shallow lagoon (depth less than 2 meters).

(4) Anaerobic sludge digester.

(b) For each anaerobic wastewater treatment process (reactor, deep lagoon, or 

shallow lagoon) you must report:

(1) Weekly average COD or BOD5 concentration of wastewater entering each 

anaerobic wastewater treatment process, for each week the anaerobic process was 

operated.

(2) Volume of wastewater entering each anaerobic wastewater treatment process 

for each week the anaerobic process was operated.

(3) Maximum CH4 production potential (B0) used as an input to Equation II-1 or II-2 

of this subpart, from Table II-1 to this subpart.

(4) Methane conversion factor (MCF) used as an input to Equation II-1 or II-2 of 

this subpart, from Table II-1 to this subpart.

(5) Annual mass of CH4 generated by each anaerobic wastewater treatment 

process, calculated using Equation II-1 or II-2 of this subpart.

(c) For each anaerobic wastewater treatment process from which biogas is not 

recovered, you must report the annual CH4 emissions, calculated using Equation II-3 of 

this subpart.

(d) For each anaerobic wastewater treatment process and anaerobic sludge 

digester from which some biogas is recovered, you must report:
(1) Annual quantity of CH4 recovered from the anaerobic process calculated using 

Equation II-4 of this subpart.

(2) Total weekly volumetric biogas flow for each week (up to 52 weeks/year) that 

biogas is collected for destruction.

(3) Weekly average CH4 concentration for each week that biogas is collected for 

destruction.

(4) Weekly average biogas temperature for each week at which flow is measured 

for biogas collected for destruction, or statement that temperature is incorporated into 

monitoring equipment internal calculations.

(5) Whether flow was measured on a wet or dry basis, whether CH4 concentration 

was measured on a wet or dry basis, and if required for Equation II-4 of this subpart, 

weekly average moisture content for each week at which flow is measured for biogas

collected for destruction, or statement that moisture content is incorporated into 

monitoring equipment internal calculations.

(6) Weekly average biogas pressure for each week at which flow is measured for 

biogas collected for destruction, or statement that pressure is incorporated into 

monitoring equipment internal calculations.

(7) CH4 collection efficiency (CE) used in Equation II-5 of this subpart.

(8) Whether destruction occurs at the facility or off-site. If destruction occurs at the 

facility, also report whether a back-up destruction device is present at the facility, the 

annual operating hours for the primary destruction device, the annual operating hours for 

the back-up destruction device (if present), the destruction efficiency for the primary 

destruction device, and the destruction efficiency for the back-up destruction device (if 

present).

(9) For each anaerobic process from which some biogas is recovered, you must 

report the annual CH4 emissions, as calculated by Equation II-6 of this subpart.

(e) The total mass of CH4 emitted from all anaerobic processes from which biogas 

is not recovered (calculated in Equation II-3 of this subpart) and from all anaerobic 

processes from which some biogas is recovered (calculated in Equation II-6 of this 

subpart) using Equation II-7 of this subpart.

Subpart JJ –

Manure 

Management

(§98.366)

Manure 

management 

systems with 

combined 

CH4 and N2O 

emissions in 

amounts 

equivalent to 

25,000 

metric tons 

CO2e or 

more per 

year

(a) In addition to the information required by §98.3(c), each annual report must 

contain the following information:

(1) List of manure management system components at the facility.

(2) Fraction of manure from each animal type that is handled in each manure 

management system component.

(3) Average annual animal population (for each animal type) for static populations 

or the results of Equation JJ-4 for growing populations.

(4) Average number of days that growing animals are kept at the facility (for each 

animal type).
(5) The number of animals produced annually for growing populations (for each 

animal type).

(6) Typical animal mass (for each animal type).

(7) Total facility emissions (results of Equation JJ-15).

(8) CH4 emissions from manure management system components listed in 

§98.360(b), except digesters (results of Equation JJ-2).

(9) VS value used (for each animal type).

(10) B0 value used (for each animal type).

(11) Methane conversion factor used for each MMS component.

(12) Average ambient temperature used to select each methane conversion factor.

(13) N2O emissions (results of Equation JJ-13).

(14) N value used for each animal type.

(15) N2O emission factor selected for each MMS component.

(b) Facilities with anaerobic digesters must also report:

(1) CH4 emissions from anaerobic digesters (results of Equation JJ-5).

(2) CH4 flow to the digester combustion device for each digester (results of 

Equation JJ-6, or value from fully integrated monitoring system as described in 

98.363(b)).

(3) CH4 destruction for each digester (results of Equation JJ-11).

(4) CH4 leakage for each digester (results of Equation JJ-12).

(5) Total annual volumetric biogas flow for each digester (results of Equation JJ-7).

(6) Average annual CH4 concentration for each digester (results of Equation JJ-8).

(7) Average annual temperature at which gas flow is measured for each digester 

(results of Equation JJ-9).

(8) Average annual gas flow pressure at which gas flow is measured for each 

digester (results of Equation JJ-10).

(9) Destruction efficiency used for each digester.

(10) Number of days per year that each digester was operating.

(11) Collection efficiency used for each digester.
Subpart LL –

Suppliers of 

Coal-Based 

Liquid Fuels

(§98.386)

Producers of 

coal-to-liquid 

products: All 

in

Importers & 

Exporters: 

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c), the following requirements 

apply:

(a) Producers shall report the following information for each coal-to-liquid facility:

(1) [Reserved]

(2) For each product listed in Table MM-1 of subpart MM of this part that enters the 

coal-to-liquid facility to be further processed or otherwise used on site, report the total 

annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the 

individual components of the product.

(3) For each feedstock reported in paragraph (a)(2) of this section that was 

produced by blending a fossil fuel-based product with a biomass-based product, report 

the percent of the volume reported in paragraph (a)(2) of this section that is fossil fuelbased (excluding any denaturant that may be present in any ethanol product).

(4) Each standard method or other industry standard practice used to measure 

each quantity reported in paragraph (a)(2) of this section.

(5) [Reserved]

(6) For each product (leaving the coal-to-liquid facility) listed in Table MM-1 of 

subpart MM of this part, report the total annual quantity in metric tons or barrels. For 

natural gas liquids, quantity shall reflect the individual components of the product. Those 

products that enter the facility, but are not reported in (a)(2), shall not be reported under 

this paragraph.

(7) For each product reported in paragraph (a)(6) of this section that was produced 

by blending a fossil fuel-based product with a biomass-based product, report the percent 

of the volume reported in paragraph (a)(6) of this section that is fossil fuel-based 

(excluding any denaturant that may be present in any ethanol product).

(8) Each standard method or other industry standard practice used to measure 

each quantity reported in paragraph (a)(6) of this section.

(9) For every feedstock reported in paragraph (a)(2) of this section for which 

Calculation Methodology 2 of subpart MM of this part was used to determine an 

emissions factor, report:

(i) The number of samples collected according to §98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric 

ton of product.

(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for 

which Calculation Methodology 2 of subpart MM of this part was used to determine an 

emissions factor, report:
(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(11) For every product reported in paragraph (a)(6) of this section for which 

Calculation Methodology 2 of this subpart was used to determine an emissions factor, 

report:

(i) The number of samples collected according to §98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or metric ton 

of product.

(12) For every non-solid product reported in paragraph (a)(6) of this section for 

which Calculation Method 2 of subpart MM of this part was used to determine an 

emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(13) [Reserved]

(14) For each specific type of biomass that enters the coal-to-liquid facility to be 

co-processed with fossil fuel-based feedstock to produce a product reported in 

paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels.

(15) Each standard method or other industry standard practice used to measure 

each quantity reported in paragraph (a)(14) of this section.

(16) The CO2 emissions in metric tons that would result from the complete 

combustion or oxidation of each feedstock reported in paragraph (a)(2) of this section 

that were calculated according to §98.393(b) or (h).

(17) The CO2 emissions in metric tons that would result from the complete 

combustion or oxidation of each product (leaving the coal-to-liquid facility) reported in 

paragraph (a)(6) of this section that were calculated according to §98.393(a) or (h).

(18) Annual CO2 emissions in metric tons that would result from the complete 

combustion or oxidation of each type of biomass feedstock co-processed with fossil fuelbased feedstocks reported in paragraph (a)(14) of this section, calculated according to 

§98.393(c).

(19) Annual CO2 emissions that would result from the complete combustion or 

oxidation of all products, calculated according to §98.393(d).

(20) Annual quantity of bulk NGLs in metric tons or barrels received for processing 

during the reporting year.
(b) In addition to the information required by §98.3(c), each importer shall report all 

of the following information at the corporate level:

(1) [Reserved]

(2) For each product listed in Table MM-1 of subpart MM of this part, report the 

total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall 

reflect the individual components of the product as listed in Table MM-1 of subpart MM 

of this part.

(3) For each product reported in paragraph (b)(2) of this section that was produced 

by blending a fossil fuel-based product with a biomass-based product, report the percent 

of the volume reported in paragraph (b)(2) of this section that is fossil fuel-based 

(excluding any denaturant that may be present in any ethanol product).

(4) Each standard method or other industry standard practice used to measure 

each quantity reported in paragraph (b)(2) of this section.

(5) For each product reported in paragraph (b)(2) of this section for which 

Calculation Methodology 2 of this subpart used was used to determine an emissions 

factor, report:

(i) The number of samples collected according to §98.394(c)

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2 emissions factor in metric tons per barrel or per metric ton 

of product.

(6) For each non-solid product reported in paragraph (b)(2) of this section for 

which Calculation Methodology 2 of this subpart was used to determine an emissions 

factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(7) The CO2 emissions in metric tons that would result from the complete 

combustion or oxidation of each imported product reported in paragraph (b)(2) of this 

section, calculated according to §98.393(a).

(8) The total sum of CO2 emissions that would result from the complete 

combustion or oxidation of all imported products, calculated according to §98.393(e).

(c) In addition to the information required by §98.3(c), each exporter shall report all 

of the following information at the corporate level:

(1) [Reserved]
(2) For each product listed in table MM-1 of subpart MM of this part, report the total 

annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the 

individual components of the product.

(3) For each product reported in paragraph (c)(2) of this section that was produced 

by blending a fossil fuel-based product with a biomass-based product, report the percent 

of the volume reported in paragraph (c)(2) of this section that is fossil fuel-based 

(excluding any denaturant that may be present in any ethanol product).

(4) Each standard method or other industry standard practice used to measure 

each quantity reported in paragraph (c)(2) of this section.

(5) For each product reported in paragraph (c)(2) of this section for which 

Calculation Methodology 2 of this subpart was used to determine an emissions factor, 

report:

(i) The number of samples collected according to §98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric 

ton of product.

(6) For each non-solid product reported in paragraph (c)(2) of this section for which 

Calculation Methodology 2 of this subpart used was used to determine an emissions 

factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(7) The CO2 emissions in metric tons that would result from the complete 

combustion or oxidation of each exported product reported in paragraph (c)(2) of this 

section, calculated according to §98.393(a).

(8) Total sum of CO2 emissions that would result from the complete combustion or 

oxidation of all exported products, calculated according to §98.393(e).

(d) Blended feedstock and products. (1) Producers, exporters, and importers must 

report the following information for each blended product and feedstock where emissions 

were calculated according to §98.393(i):

(i) Volume or mass of each blending component.

(ii) The CO2 emissions in metric tons that would result from the complete 

combustion or oxidation of each blended feedstock or product, using Equation MM-12 or 

Equation MM-13 of §98.393.

(iii) Whether it is a blended feedstock or a blended product.

(2) For a product that enters the facility to be further refined or otherwise used on 

site that is a blended feedstock, producers must meet the reporting requirements of 
paragraph (a)(2) of this section by reflecting the individual components of the blended 

feedstock.

(3) For a product that is produced, imported, or exported that is a blended product, 

producers, importers, and exporters must meet the reporting requirements of paragraphs 

(a)(6), (b)(2), and (c)(2) of this section, as applicable, by reflecting the individual 

components of the blended product.

Subpart MM –

Suppliers of 

Petroleum 

Products

(§98.396)

(A) All 

petroleum 

refineries 

that distill 

crude oil.

(B) Importers 

of an annual 

quantity of 

petroleum 

products and 

natural gas 

liquids that is 

equivalent to 

25,000 

metric tons 

CO2e or 

more.

(C) 

Exporters of 

an annual 

quantity of 

petroleum 

products and 

natural gas 

liquids that is 

equivalent to 

25,000 

metric tons 

CO2e or 

more.

In addition to the information required by §98.3(c), the following requirements 

apply:

(a) Refiners shall report the following information for each facility:

(1) [Reserved]

(2) For each petroleum product or natural gas liquid listed in Table MM-1 of this 

subpart that enters the refinery to be further refined or otherwise used on site, report the 

annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the 

individual components of the product.

(3) For each feedstock reported in paragraph (a)(2) of this section that was 

produced by blending a petroleum-based product with a biomass-based product, report 

the percent of the volume reported in paragraph (a)(2) of this section that is petroleumbased (excluding any denaturant that may be present in any ethanol product).

(4)-(5) [Reserved]

(6) For each petroleum product and natural gas liquid (ex refinery gate) listed in 

Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For 

natural gas liquids, quantity shall reflect the individual components of the product. 

Petroleum products and natural gas liquids that enter the refinery, but are not reported in 

(a)(2), shall not be reported under this paragraph.

(7) For each product reported in paragraph (a)(6) of this section that was produced 

by blending a petroleum-based product with a biomass-based product, report the 

percent of the volume reported in paragraph (a)(6) of this section that is petroleumbased (excluding any denaturant that may be present in any ethanol product).

(8) [Reserved]

(9) For every feedstock reported in paragraph (a)(2) of this section for which 

Calculation Method 2 of this subpart was used to determine an emissions factor, report:

(i) The number of samples collected according to §98.394(c)

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric 

ton of product.
(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for 

which Calculation Method 2 of this subpart was used to determine an emissions factor, 

report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(11) For every petroleum product and natural gas liquid reported in paragraph 

(a)(6) of this section for which Calculation Method 2 of this subpart was used to 

determine an emissions factor, report:

(i) The number of samples collected according to §98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric 

ton of product.

(12) For every non-solid petroleum product and natural gas liquid reported in 

paragraph (a)(6) for which Calculation Method 2 was used to determine an emissions 

factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(13) [Reserved]

(14) For each specific type of biomass that enters the refinery to be co-processed 

with petroleum feedstocks to produce a petroleum product reported in paragraph (a)(6) 

of this section, report the annual quantity in metric tons or barrels.

(15) [Reserved]

(16) The CO2 emissions in metric tons that would result from the complete 

combustion or oxidation of each petroleum product and natural gas liquid (ex refinery 

gate) reported in paragraph (a)(6) of this section that were calculated according to 

§98.393(a) or (h).

(17) The CO2 emissions in metric tons that would result from the complete 

combustion or oxidation of each feedstock reported in paragraph (a)(2) of this section 

that were calculated according to §98.393(b) or (h).

(18) The CO2 emissions in metric tons that would result from the complete 

combustion or oxidation of each type of biomass feedstock co-processed with petroleum 

feedstocks reported in paragraph (a)(14) of this section, calculated according to 

§98.393(c).
(19) The sum of CO2 emissions that would result from the complete combustion or 

oxidation of all products, calculated according to §98.393(d).

(20) For all crude oil that enters the refinery, report the annual quantity in barrels.

(21) The quantity of bulk NGLs in metric tons or barrels received for processing 

during the reporting year. Report only quantities of bulk NGLs not reported in (a)(2) of 

this section.

(22) Volume of crude oil in barrels that you injected into a crude oil supply or 

reservoir.

(b) In addition to the information required by §98.3(c), each importer shall report all 

of the following information at the corporate level:

(1) [Reserved]

(2) For each petroleum product and natural gas liquid listed in Table MM-1 of this 

subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, 

quantity shall reflect the individual components of the product.

(3) For each product reported in paragraph (b)(2) of this section that was produced 

by blending a petroleum-based product with a biomass-based product, report the 

percent of the volume reported in paragraph (b)(2) of this section that is petroleumbased (excluding any denaturant that may be present in any ethanol product).

(4) [Reserved]

(5) For each product reported in paragraph (b)(2) of this section for which 

Calculation Method 2 of this subpart used was used to determine an emissions factor, 

report:

(i) The number of samples collected according to §98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric 

ton of product.

(6) For each non-solid product reported in paragraph (b)(2) of this section for 

which Calculation Method 2 of this subpart was used to determine an emissions factor, 

report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(7) The CO2 emissions in metric tons that would result from the complete 

combustion or oxidation of each imported petroleum product and natural gas liquid 

reported in paragraph (b)(2) of this section, calculated according to §98.393(a).
(8) The sum of CO2 emissions that would result from the complete combustion 

oxidation of all imported products, calculated according to §98.393(e).

(c) In addition to the information required by §98.3(c), each exporter shall report all 

of the following information at the corporate level:

(1) [Reserved]

(2) For each petroleum product and natural gas liquid listed in Table MM-1 of this 

subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, 

quantity shall reflect the individual components of the product.

(3) For each product reported in paragraph (c)(2) of this section that was produced 

by blending a petroleum-based product with a biomass-based product, report the 

percent of the volume reported in paragraph (c)(2) of this section that is petroleum based 

(excluding any denaturant that may be present in any ethanol product).

(4) [Reserved]

(5) For each product reported in paragraph (c)(2) of this section for which 

Calculation Method 2 of this subpart was used to determine an emissions factor, report:

(i) The number of samples collected according to §98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percentmass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric 

ton of product.

(6) For each non-solid product reported in paragraph (c)(2) of this section for which 

Calculation Method 2 of this subpart used was used to determine an emissions factor, 

report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(7) The CO2 emissions in metric tons that would result from the complete 

combustion or oxidation of for each exported petroleum product and natural gas liquid 

reported in paragraph (c)(2) of this section, calculated according to §98.393(a).

(8) The sum of CO2 emissions that would result from the complete combustion or 

oxidation of all exported products, calculated according to §98.393(e).

(d) Blended non-crude feedstock and products. (1) Refineries, exporters, and 

importers must report the following information for each blended product and non-crude 

feedstock where emissions were calculated according to §98.393(i):

(i) Volume or mass of each blending component.
(ii) The CO2 emissions in metric tons that would result from the complete 

combustion or oxidation of each blended non-crude feedstock or product, using Equation 

MM-12 or Equation MM-13 of this section.

(iii) Whether it is a blended non-crude feedstock or a blended product.

(2) For a product that enters the refinery to be further refined or otherwise used on 

site that is a blended non-crude feedstock, refiners must meet the reporting 

requirements of paragraph (a)(2) of this section by reflecting the individual components 

of the blended non-crude feedstock.

(3) For a product that is produced, imported, or exported that is a blended product, 

refiners, importers, and exporters must meet the reporting requirements of paragraphs 

(a)(6), (b)(2), and (c)(2) of this section, as applicable, by reflecting the individual 

components of the blended product.

Subpart NN –

Suppliers of 

Natural Gas 

and Natural 

Gas Liquids

(§98.406)

(A) All 

fractionators.

(B) Local 

natural gas 

distribution 

companies 

that deliver 

460,000 

thousand 

standard 

cubic feet or 

more of 

natural gas 

per year.

(a) In addition to the information required by §98.3(c), the annual report for each 

NGL fractionator covered by this rule shall contain the following information.

(1) Annual quantity (in barrels) of each NGL product supplied to downstream 

facilities in the following product categories: ethane, propane, normal butane, isobutane, 

and pentanes plus.

(2) Annual quantity (in barrels) of each NGL product received from other NGL 

fractionators in the following product categories: ethane, propane, normal butane, 

isobutane, and pentanes plus.

(3) Annual volumes in Mscf of natural gas received for processing.

(4) Annual quantities (in barrels) of y-grade, o-grade, and other bulk NGLs:

(i) Received.

(ii) Supplied to downstream users that are not fractionated by the reporter.

(5) Annual quantity (in barrels) of propane that the NGL fractionator odorizes at the 

facility and delivers to others.

(6) Annual CO2 emissions (metric tons) that would result from the complete 

combustion or oxidation of the quantities in paragraphs (a)(1) and (a)(2) of this section, 

calculated in accordance with §98.403(a) and (c)(1).

(7) Annual CO2 mass emissions (metric tons) that would result from the 

combustion or oxidation of fractionated NGLs supplied less the quantity received from 

other fractionators, calculated in accordance with §98.403(c)(2). If the calculated value is 

negative, the reporter shall report the value as zero.

(8) The specific industry standard used to measure each quantity reported in 

paragraph (a)(1) of this section.

(9) If the NGL fractionator developed reporter-specific EFs or HHVs, report the 

following for each product type:
(i) The specific industry standard(s) used to develop reporter-specific higher 

heating value(s) and/or emission factor(s), pursuant to §98.404(b)(2) and (c)(3).

(ii) The developed HHV(s).

(iii) The developed EF(s).

(b) In addition to the information required by §98.3(c), the annual report for each 

LDC shall contain the following information.

(1) Annual volume in Mscf of natural gas received by the LDC at its city gate 

stations for redelivery on the LDC's distribution system, including for use by the LDC.

(2) Annual volume in Mscf of natural gas placed into storage or liquefied and 

stored (Fuel1 in Equation NN-5a).

(3) Annual volume in Mscf of natural gas withdrawn from on-system storage and 

annual volume in Mscf of vaporized liquefied natural gas (LNG) withdrawn from storage 

for delivery on the distribution system (Fuel2 in Equation NN-5a).

(4) [Reserved]

(5) Annual volume in Mscf of natural gas that bypassed the city gate(s) and was 

supplied through the LDC distribution system. This includes natural gas from producers 

and natural gas processing plants from local production, or natural gas that was 

vaporized upon receipt and delivered, and any other source that bypassed the city gate 

(Fuelz in Equation NN-5b).

(6) Annual volume in Mscf of natural gas delivered to downstream gas 

transmission pipelines and other local distribution companies.

(7) Annual volume in Mscf of natural gas delivered by the LDC to each large enduser as defined in §98.403(b)(2)(i) of this section.

(8) The total annual CO2 mass emissions (metric tons) associated with the 

volumes in paragraphs (b)(1) through (b)(7) of this section, calculated in accordance with 

§98.403(a) and (b)(1) through (b)(3).

(9) Annual CO2 emissions (metric tons) that would result from the complete 

combustion or oxidation of the annual supply of natural gas to end-users registering less 

than 460,000 Mscf, calculated in accordance with §98.403(b)(4). If the calculated value 

is negative, the reporter shall report the value as zero.

(10) The specific industry standard used to develop the volume reported in 

paragraph (b)(1) of this section.

(11) If the LDC developed reporter-specific EFs or HHVs, report the following:

(i) The specific industry standard(s) used to develop reporter-specific higher 

heating value(s) and/or emission factor(s), pursuant to §98.404 (b)(2) and (c)(3).

(ii) The developed HHV(s).

(iii) The developed EF(s).
(12) The customer name, address, and meter number of each large end-user 

reported in paragraph (b)(7) of this section. Additionally, report whether the quantity of 

natural gas reported in paragraph (b)(7) of this section is the total quantity delivered to a 

large end-user's facility, or the quantity delivered to a specific meter located at the 

facility.

(i) If known, report the EIA identification number of each LDC customer.

(ii) [Reserved]

(13) The annual volume in Mscf of natural gas delivered by the local distribution 

company to each of the following end-use categories. For definitions of these categories, 

refer to EIA Form 176 (Annual Report of Natural Gas and Supplemental Gas Supply & 

Disposition) and Instructions.

(i) Residential consumers.

(ii) Commercial consumers.

(iii) Industrial consumers.

(iv) Electricity generating facilities.

(c) Each reporter shall report the number of days in the reporting year for which 

substitute data procedures were used for the following purpose:

(1) To measure quantity.

(2) To develop HHV(s).

(3) To develop EF(s).

Subpart OO –

Suppliers of 

Industrial 

Greenhouse 

Gases

(§98.416)

Producers: 

All in

Importers & 

Exporters 

with annual 

bulk imports 

or exports of 

N2O, 

fluorinated 

GHG, and 

CO2that in 

combination 

are 

equivalent to 

25,000 

metric tons 

CO2e or 

more.

In addition to the information required by §98.3(c), each annual report must 

contain the following information:

(a) Each fluorinated GHG or nitrous oxide production facility shall report the 

following information:

(1) Mass in metric tons of each fluorinated GHG or nitrous oxide produced at that 

facility by process, except for amounts that are captured solely to be shipped off site for 

destruction.

(2) Mass in metric tons of each fluorinated GHG or nitrous oxide transformed at 

that facility, by process.

(3) Mass in metric tons of each fluorinated GHG that is destroyed at that facility 

and that was previously produced as defined at §98.410(b). Quantities to be reported 

under this paragraph (a)(3) of this section include but are not limited to quantities that 

are shipped to the facility by another facility for destruction and quantities that are 

returned to the facility for reclamation but are found to be irretrievably contaminated and 

are therefore destroyed.

(4) [Reserved]

(5) Total mass in metric tons of each fluorinated GHG or nitrous oxide sent to 

another facility for transformation.
(6) Total mass in metric tons of each fluorinated GHG sent to another facility for 

destruction, except fluorinated GHGs that are not included in the mass produced in 

§98.413(a) because they are removed from the production process as by-products or 

other wastes. Quantities to be reported under this paragraph (a)(6) could include, for 

example, fluorinated GHGs that are returned to the facility for reclamation but are found 

to be irretrievably contaminated and are therefore sent to another facility for destruction.

(7) Total mass in metric tons of each fluorinated GHG that is sent to another facility 

for destruction and that is not included in the mass produced in §98.413(a) because it is 

removed from the production process as a byproduct or other waste.

(8)-(9) [Reserved]

(10) Mass in metric tons of any fluorinated GHG or nitrous oxide fed into the 

transformation process, by process.

(11) Mass in metric tons of each fluorinated GHG that is fed into the destruction 

device and that was previously produced as defined at §98.410(b). Quantities to be 

reported under this paragraph (a)(11) of this section include but are not limited to 

quantities that are shipped to the facility by another facility for destruction and quantities 

that are returned to the facility for reclamation but are found to be irretrievably 

contaminated and are therefore destroyed.

(12) Mass in metric tons of each fluorinated GHG or nitrous oxide that is measured 

coming out of the production process, by process.

(13) Mass in metric tons of each used fluorinated GHGs or nitrous oxide added 

back into the production process (e.g., for reclamation), including returned heels in 

containers that are weighed to measure the mass in §98.414(a), by process.

(14) Names and addresses of facilities to which any nitrous oxide or fluorinated 

GHGs were sent for transformation, and the quantities (metric tons) of nitrous oxide and 

of each fluorinated GHG that were sent to each for transformation.

(15) Names and addresses of facilities to which any fluorinated GHGs were sent 

for destruction, and the quantities (metric tons) of each fluorinated GHG that were sent 

to each for destruction.

(16) Where missing data have been estimated pursuant to §98.415, the reason the 

data were missing, the length of time the data were missing, the method used to 

estimate the missing data, and the estimates of those data.

(b) By March 31, 2011 or within 60 days of commencing fluorinated GHG 

destruction, whichever is later, a fluorinated GHG production facility or importer that 

destroys fluorinated GHGs shall submit a one-time report containing the following 

information for each destruction process:

(1) Destruction efficiency (DE).

(2) Methods used to determine the destruction efficiency.

(3) Methods used to record the mass of fluorinated GHG destroyed.

(4) Chemical identity of the fluorinated GHG(s) used in the performance test 

conducted to determine DE.
(5) Name of all applicable federal or state regulations that may apply to the 

destruction process.

(6) If any process changes affect unit destruction efficiency or the methods used to 

record mass of fluorinated GHG destroyed, then a revised report must be submitted to 

reflect the changes. The revised report must be submitted to EPA within 60 days of the 

change.

(c) Each bulk importer of fluorinated GHGs or nitrous oxide shall submit an annual 

report that summarizes its imports at the corporate level, except for shipments including 

less than twenty-five kilograms of fluorinated GHGs or nitrous oxide, transshipments, 

and heels that meet the conditions set forth at §98.417(e). The report shall contain the 

following information for each import:

(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG imported 

in bulk, including each fluorinated GHG constituent of the fluorinated GHG product that 

makes up between 0.5 percent and 100 percent of the product by mass.

(2) Total mass in metric tons of nitrous oxide and each fluorinated GHG imported 

in bulk and sold or transferred to persons other than the importer for use in processes 

resulting in the transformation or destruction of the chemical.

(3) Date on which the fluorinated GHGs or nitrous oxide were imported.

(4) Port of entry through which the fluorinated GHGs or nitrous oxide passed.

(5) Country from which the imported fluorinated GHGs or nitrous oxide were 

imported.

(6) Commodity code of the fluorinated GHGs or nitrous oxide shipped.

(7) Importer number for the shipment.

(8) Total mass in metric tons of each fluorinated GHG destroyed by the importer.

(9) If applicable, the names and addresses of the persons and facilities to which 

the nitrous oxide or fluorinated GHGs were sold or transferred for transformation, and 

the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sold 

or transferred to each facility for transformation.

(10) If applicable, the names and addresses of the persons and facilities to which 

the fluorinated GHGs were sold or transferred for destruction, and the quantities (metric 

tons) of each fluorinated GHG that were sold or transferred to each facility for 

destruction.

(d) Each bulk exporter of fluorinated GHGs or nitrous oxide shall submit an annual 

report that summarizes its exports at the corporate level, except for shipments including 

less than twenty-five kilograms of fluorinated GHGs or nitrous oxide, transshipments, 

and heels. The report shall contain the following information for each export:

(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG exported 

in bulk.

(2) Names and addresses of the exporter and the recipient of the exports.
(3) Exporter's Employee Identification Number.

(4) Commodity code of the fluorinated GHGs and nitrous oxide shipped.

(5) Date on which, and the port from which, fluorinated GHGs and nitrous oxide 

were exported from the United States or its territories.

(6) Country to which the fluorinated GHGs or nitrous oxide were exported.

(e) By March 31, 2011, or within 60 days of commencing fluorinated GHG 

production, whichever is later, a fluorinated GHG production facility shall submit a onetime report describing the following information:

(1) The method(s) by which the producer in practice measures the mass of 

fluorinated GHGs produced, including the instrumentation used (Coriolis flowmeter, other 

flowmeter, weigh scale, etc.) and its accuracy and precision.

(2) The method(s) by which the producer in practice estimates the mass of 

fluorinated GHGs fed into the transformation process, including the instrumentation used 

(Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision.

(3) The method(s) by which the producer in practice estimates the fraction of 

fluorinated GHGs fed into the transformation process that is actually transformed, and 

the estimated precision and accuracy of this estimate.

(4) The method(s) by which the producer in practice estimates the masses of 

fluorinated GHGs fed into the destruction device, including the method(s) used to 

estimate the concentration of the fluorinated GHGs in the destroyed material, and the 

estimated precision and accuracy of this estimate.

(5) The estimated percent efficiency of each production process for the fluorinated 

GHG produced.

(f) By March 31, 2011, all fluorinated GHG production facilities shall submit a onetime report that includes the concentration of each fluorinated GHG constituent in each 

fluorinated GHG product as measured under §98.414(n). If the facility commences 

production of a fluorinated GHG product that was not included in the initial report or 

performs a repeat measurement under §98.414(n) that shows that the identities or 

concentrations of the fluorinated GHG constituents of a fluorinated GHG product have 

changed, then the new or changed concentrations, as well as the date of the change, 

must be reflected in a revision to the report. The revised report must be submitted to 

EPA by the March 31st that immediately follows the measurement under §98.414(n).

(g) Isolated intermediates that are produced and transformed at the same facility 

are exempt from the reporting requirements of this section.

(h) Low-concentration constituents are exempt from the reporting requirements of 

this section.

Subpart PP –

Suppliers of 

Carbon 

Dioxide

(§98.426)

Producers: 

All in

Bulk 

importers & 

exporters 

with annual 

In addition to the information required by §98.3(c) of subpart A of this part, the 

annual report shall contain the following information, as applicable:

(a) If you use Equation PP-1 of this subpart, report the following information for 

each mass flow meter or CO2 stream that delivers CO2 to containers:
bulk imports 

or exports of 

N2O, 

fluorinated 

GHG, and 

CO2that in 

combination 

are 

equivalent to 

25,000 

metric tons 

CO2e or 

more

(1) Annual mass in metric tons of CO2.

(2) Quarterly mass in metric tons of CO2.

(3) Quarterly concentration of the CO2 stream.

(4) The standard used to measure CO2 concentration.

(5) The location of the flow meter in your process chain in relation to the points of 

CO2 stream capture, dehydration, compression, and other processing.

(b) If you use Equation PP-2 of this subpart, report the following information for 

each volumetric flow meter or CO2stream that delivers CO2 to containers:

(1) Annual mass in metric tons of CO2.

(2) Quarterly volume in standard cubic meters of CO2.

(3) Quarterly concentration of the CO2 stream in volume or weight percent.

(4) Report density as follows:

(i) Quarterly density of the CO2 stream in metric tons per standard cubic meter if 

you report the concentration of the CO2 stream in paragraph (b)(3) of this section in 

weight percent.

(ii) Quarterly density of CO2 in metric tons per standard cubic meter if you report 

the concentration of the CO2 stream in paragraph (b)(3) of this section in volume 

percent.

(5) The method used to measure density.

(6) The standard used to measure CO2 concentration.

(7) The location of the flow meter in your process chain in relation to the points of 

CO2 stream capture, dehydration, compression, and other processing.

(c) For the aggregated annual mass of CO2 emissions calculated using Equation 

PP-3a or PP-3b, report the following:

(1) If you use Equation PP-3a of this subpart, report the annual CO2 mass in metric 

tons from all flow meters and CO2 streams that deliver CO2 to containers.

(2) If you use Equation PP-3b of this subpart, report:

(i) The total annual CO2 mass through main flow meter(s) in metric tons.

(ii) The total annual CO2 mass through subsequent flow meter(s) in metric tons.

(iii) The total annual CO2 mass supplied in metric tons.

(iv) The location of each flow meter in relation to the point of segregation.
(d) If you use Equation PP-4 of this subpart, report at the corporate level the 

annual mass of CO2 in metric tons in all CO2 containers that are imported or exported.

(e) Each reporter shall report the following information:

(1) The type of equipment used to measure the total flow of the CO2 stream or the 

total mass or volume in CO2containers.

(2) The standard used to operate and calibrate the equipment reported in (e)(1) of 

this section.

(3) The number of days in the reporting year for which substitute data procedures 

were used for the following purpose:

(i) To measure quantity.

(ii) To measure concentration.

(iii) To measure density.

(f) Report the aggregated annual quantity of CO2 in metric tons that is transferred 

to each of the following end use applications, if known:

(1) Food and beverage.

(2) Industrial and municipal water/wastewater treatment.

(3) Metal fabrication, including welding and cutting.

(4) Greenhouse uses for plant growth.

(5) Fumigants (e.g., grain storage) and herbicides.

(6) Pulp and paper.

(7) Cleaning and solvent use.

(8) Fire fighting.

(9) Transportation and storage of explosives.

(10) Injection of carbon dioxide for enhanced oil and natural gas recovery that is 

covered by subpart UU of this part.

(11) Geologic sequestration of carbon dioxide that is covered by subpart RR of this 

part.

(12) Research and development.

(13) Other.

(g) Each production process unit that captures a CO2 stream for purposes of 

supplying CO2 for commercial applications or in order to sequester or otherwise inject it 
underground when custody of the CO2 is maintained shall report the percentage of that 

stream, if any, that is biomass-based during the reporting year.

Subpart QQ –

Importers and 

Exporters of 

Fluorinated 

Greenhouse 

Gases 

Contained in 

Pre-Charged 

Equipment or 

Closed-Cell 

Foams

(§98.436)

Importers 

and 

exporters of 

an annual 

quantity of 

fluorinated 

greenhouse 

gases 

contained in 

pre-charged 

equipment or 

closed-cell 

foams that is 

equivalent to 

25,000 

metric tons 

CO2e or 

more.

(a) Each importer of fluorinated GHGs contained in pre-charged equipment or 

closed-cell foams must submit an annual report that summarizes its imports at the 

corporate level, except for transshipments, as specified:

(1) Total mass in metric tons of each fluorinated GHG imported in pre-charged 

equipment or closed-cell foams.

(2) For each type of pre-charged equipment with a unique combination of charge 

size and charge type, the identity of the fluorinated GHG used as a refrigerant or 

electrical insulator, charge size (holding charge, if applicable), and number imported.

(3) For closed-cell foams that are imported inside of equipment, the identity of the 

fluorinated GHG contained in the foam, the mass of the fluorinated GHG contained in the 

foam in each piece of equipment, and the number of pieces of equipment imported with 

each unique combination of mass and identity of fluorinated GHG within the closed-cell 

foams.

(4) For closed cell-foams that are not imported inside of equipment, the identity of 

the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg 

fluorinated GHG/cubic foot), and the volume of foam imported (cubic feet) for each type 

of closed-cell foam with a unique combination of fluorinated GHG density and identity.

(5) Dates on which the pre-charged equipment or closed-cell foams were 

imported.

(6) If the importer does not know the identity and mass of the fluorinated GHGs 

within the closed-cell foam, the importer must report the following:

(i) Total mass in metric tons of CO2e of the fluorinated GHGs imported in closedcell foams.

(ii) For closed-cell foams that are imported inside of equipment, the mass of the 

fluorinated GHGs in CO2e contained in the foam in each piece of equipment and the 

number of pieces of equipment imported for each equipment type.

(iii) For closed-cell foams that are not imported inside of equipment, the density in 

CO2e of the fluorinated GHGs in the foam (kg CO2e/cubic foot) and the volume of foam 

imported (cubic feet) for each type of closed-cell foam.

(iv) Dates on which the closed-cell foams were imported.

(v) Name of the foam manufacturer for each type of closed-cell foam where the 

identity and mass of the fluorinated GHGs is unknown.

(vi) Certification that the importer was unable to obtain information on the identity 

and mass of the fluorinated GHGs within the closed-cell foam from the closed-cell foam 

manufacturer or manufacturers.

(b) Each exporter of fluorinated GHGs contained in pre-charged equipment or 

closed-cell foams must submit an annual report that summarizes its exports at the 

corporate level, except for transshipments, as specified:

(1) Total mass in metric tons of each fluorinated GHG exported in pre-charged 

equipment or closed-cell foams.
(2) For each type of pre-charged equipment with a unique combination of charge 

size and charge type, the identity of the fluorinated GHG used as a refrigerant or 

electrical insulator, charge size (including holding charge, if applicable), and number 

exported.

(3) For closed-cell foams that are exported inside of equipment, the identity of the 

fluorinated GHG contained in the foam in each piece of equipment, the mass of the 

fluorinated GHG contained in the foam in each piece of equipment, and the number of 

pieces of equipment exported with each unique combination of mass and identity of 

fluorinated GHG within the closed-cell foams.

(4) For closed-cell foams that are not exported inside of equipment, the identity of 

the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg 

fluorinated GHG/cubic foot), and the volume of foam exported (cubic feet) for each type 

of closed-cell foam with a unique combination of fluorinated GHG density and identity.

(5) Dates on which the pre-charged equipment or closed-cell foams were 

exported.

(6) If the exporter does not know the identity and mass of the fluorinated GHG 

within the closed-cell foam, the exporter must report the following:

(i) Total mass in metric tons of CO2e of the fluorinated GHGs exported in closedcell foams.

(ii) For closed-cell foams that are exported inside of equipment, the mass of the 

fluorinated GHGs in CO2e contained in the foam in each piece of equipment and the 

number of pieces of equipment imported for each equipment type.

(iii) For closed-cell foams that are not exported inside of equipment, the density in 

CO2e of the fluorinated GHGs in the foam (kg CO2 e/cubic foot) and the volume of foam 

imported (cubic feet) for each type of closed-cell foam.

(iv) Dates on which the closed-cell foams were exported.

(v) Name of the foam manufacturer for each type of closed-cell foam where the 

identity and mass of the fluorinated GHGg is unknown.

(vi) Certification that the exporter was unable to obtain information on the identity 

and mass of the fluorinated GHGs within the closed-cell foam from the closed-cell foam 

manufacturer or manufacturers.

Subpart RR –

Geologic 

Sequestration 

of Carbon 

Dioxide

(§98.446)

All in In addition to the information required by §98.3(c), report the information listed in 

this section.

(a) If you receive CO2 by pipeline, report the following for each receiving flow 

meter:

(1) The total net mass of CO2 received (metric tons) annually.

(2) If a volumetric flow meter is used to receive CO2 report the following unless you 

reported yes to paragraph (a)(4) of this section:

(i) The volumetric flow through a receiving flow meter at standard conditions (in 

standard cubic meters) in each quarter.
(ii) The volumetric flow through a receiving flow meter that is redelivered to another 

facility without being injected into your well (in standard cubic meters) in each quarter.

(iii) The CO2 concentration in the flow (volume percent CO2 expressed as a 

decimal fraction) in each quarter.

(3) If a mass flow meter is used to receive CO2 report the following unless you 

reported yes to paragraph (a)(4) of this section:

(i) The mass flow through a receiving flow meter (in metric tons) in each quarter.

(ii) The mass flow through a receiving flow meter that is redelivered to another 

facility without being injected into your well (in metric tons) in each quarter.

(iii) The CO2 concentration in the flow (weight percent CO2 expressed as a decimal 

fraction) in each quarter.

(4) If the CO2 received is wholly injected and not mixed with any other supply of 

CO2, report whether you followed the procedures in §98.444(a)(4).

(5) The standard or method used to calculate each value in paragraphs (a)(2) 

through (a)(3) of this section.

(6) The number of times in the reporting year for which substitute data procedures 

were used to calculate values reported in paragraphs (a)(2) through (a)(3) of this section.

(7) Whether the flow meter is mass or volumetric.

(8) A numerical identifier for the flow meter.

(b) If you receive CO2 in containers, report:

(1) The mass (in metric tons) or volume at standard conditions (in standard cubic 

meters) of contents in containers received in each quarter.

(2) The concentration of CO2 of contents in containers (volume or wt. percent 

CO2 expressed as a decimal fraction) in each quarter.

(3) The mass (in metric tons) or volume (in standard cubic meters) of contents in 

containers that is redelivered to another facility without being injected into your well in 

each quarter.

(4) The net mass of CO2 received (in metric tons) annually.

(5) The standard or method used to calculate each value in paragraphs (b)(1), 

(b)(2), and (b)(3) of this section.

(6) The number of times in the reporting year for which substitute data procedures 

were used to calculate values reported in paragraphs (b)(1) and (b)(2) of this section.

(c) If you use more than one receiving flow meter, report the total net mass of 

CO2 received (metric tons) through all flow meters annually.

(d) The source of the CO2 received according to the following categories:
(1) CO2 production wells.

(2) Electric generating unit.

(3) Ethanol plant.

(4) Pulp and paper mill.

(5) Natural gas processing.

(6) Gasification operations.

(7) Other anthropogenic source.

(8) Discontinued enhanced oil and gas recovery project.

(9) Unknown.

(e) Report the date that you began collecting data for calculating total amount 

sequestered according to §98.448(a)(7) of this subpart.

(f) Report the following. If the date specified in paragraph (e) of this section is 

during the reporting year for this annual report, report the following starting on the date 

specified in paragraph (e) of this section.

(1) For each injection flow meter (mass or volumetric), report:

(i) The mass of CO2 injected (metric tons) annually.

(ii) The CO2 concentration in flow (volume or weight percent CO2 expressed as a 

decimal fraction) in each quarter.

(iii) If a volumetric flow meter is used, the volumetric flow rate at standard 

conditions (in standard cubic meters) in each quarter.

(iv) If a mass flow meter is used, the mass flow rate (in metric tons) in each 

quarter.

(v) A numerical identifier for the flow meter.

(vi) Whether the flow meter is mass or volumetric.

(vii) The standard used to calculate each value in paragraphs (f)(1)(ii) through 

(f)(1)(iv) of this section.

(viii) The number of times in the reporting year for which substitute data 

procedures were used to calculate values reported in paragraphs (f)(1)(ii) through 

(f)(1)(iv) of this section.

(ix) The location of the flow meter.

(2) The total CO2 injected (metric tons) in the reporting year as calculated in 

Equation RR-6 of this subpart.
(3) For CO2 emissions from equipment leaks and vented emissions of CO2, report 

the following:

(i) The mass of CO2 emitted (in metric tons) annually from equipment leaks and 

vented emissions of CO2 from equipment located on the surface between the flow meter 

used to measure injection quantity and the injection wellhead.

(ii) The mass of CO2 emitted (in metric tons) annually from equipment leaks and 

vented emissions of CO2 from equipment located on the surface between the production 

wellhead and the flow meter used to measure production quantity.

(4) For each separator flow meter (mass or volumetric), report:

(i) CO2 mass produced (metric tons) annually.

(ii) CO2 concentration in flow (volume or weight percent CO2 expressed as a 

decimal fraction) in each quarter.

(iii) If a volumetric flow meter is used, volumetric flow rate at standard conditions 

(standard cubic meters) in each quarter.

(iv) If a mass flow meter, mass flow rate (metric tons) in each quarter.

(v) A numerical identifier for the flow meter.

(vi) Whether the flow meter is mass or volumetric.

(vii) The standard used to calculate each value in paragraphs (f)(4)(ii) through 

(f)(4)(iv) of this section.

(viii) The number of times in the reporting year for which substitute data 

procedures were used to calculate values reported in paragraphs (f)(4)(ii) through 

(f)(4)(iv) of this section.

(5) The entrained CO2 in produced oil or other fluid divided by the CO2 separated 

through all separators in the reporting year (weight percent CO2 expressed as a decimal 

fraction) used as the value for X in Equation RR-9 of this subpart and as determined 

according to your EPA-approved MRV plan.

(6) Annual CO2 produced in the reporting year as calculated in Equation RR-9 of 

this subpart.

(7) For each leakage pathway through which CO2 emissions occurred, report:

(i) A numerical identifier for the leakage pathway.

(ii) The CO2 (metric tons) emitted through that pathway in the reporting year.

(8) Annual CO2 mass emitted (metric tons) by surface leakage in the reporting year 

as calculated by Equation RR-10 of this subpart.

(9) Annual CO2 (metric tons) sequestered in subsurface geologic formations in the 

reporting year as calculated by Equation RR-11 or RR-12 of this subpart.
(10) Cumulative mass of CO2 (metric tons) reported as sequestered in subsurface 

geologic formations in all years since the well or group of wells became subject to 

reporting requirements under this subpart.

(11) Date that the most recent MRV plan was approved by EPA and the MRV plan 

approval number that was issued by EPA.

(12) An annual monitoring report that contains the following components:

(i) A narrative history of the monitoring efforts conducted over the previous 

calendar year, including a listing of all monitoring equipment that was operated, its 

period of operation, and any relevant tests or surveys that were conducted.

(ii) A description of any changes to the monitoring program that you concluded 

were not material changes warranting submission of a revised MRV plan under 

§98.448(d).

(iii) A narrative history of any monitoring anomalies that were detected in the 

previous calendar year and how they were investigated and resolved.

(iv) A description of any surface leakages of CO2, including a discussion of all 

methodologies and technologies involved in detecting and quantifying the surface 

leakages and any assumptions and uncertainties involved in calculating the amount of 

CO2 emitted.

(13) If a well is permitted under the Underground Injection Control program, for 

each injection well, report:

(i) The well identification number used for the Underground Injection Control 

permit.

(ii) The Underground Injection Control permit class.

(14) If an offshore well is not subject to the Safe Drinking Water Act, for each

injection well, report any well identification number and any identification number used 

for the legal instrument authorizing geologic sequestration.

Subpart SS –

Electrical 

Equipment 

Manufacture 

or 

Refurbishment

(§98.456)

Total annual 

purchases of 

SF6and 

PFCs that 

exceed 

23,000 

pounds

In addition to the information required by §98.3(c), each annual report must 

contain the following information for each chemical at the facility level:

(a) Pounds of SF6 and PFCs stored in containers at the beginning of the year.

(b) Pounds of SF6 and PFCs stored in containers at the end of the year.

(c) Pounds of SF6 and PFCs purchased in bulk.

(d) Pounds of SF6 and PFCs returned by equipment users with or inside 

equipment.

(e) Pounds of SF6 and PFCs returned to site from off site after recycling.

(f) Pounds of SF6 and PFCs inside new equipment delivered to customers.
(g) Pounds of SF6 and PFCs delivered to equipment users in containers.

(h) Pounds of SF6 and PFCs returned to suppliers.

(i) Pounds of SF6 and PFCs sent off site for destruction.

(j) Pounds of SF6 and PFCs sent off site to be recycled.

(k) The nameplate capacity of the equipment, in pounds, delivered to customers 

with SF6 or PFCs inside, if different from the quantity in paragraph (f) of this section.

(l) A description of the engineering methods and calculations used to determine 

emissions from hoses or other flow lines that connect the container to the equipment that 

is being filled.

(m) The values for EFci of Equation SS-5 of this subpart for each hose and valve 

combination and the associated valve fitting sizes and hose diameters.

(n) The total number of fill operations for each hose and valve combination, or, 

FCi of Equation SS-5 of this subpart.

(o) If the mass of SF6 or the PFC disbursed to customers in new equipment over 

the period p is determined according to the methods required in §98.453(h), report the 

mean value of nameplate capacity in pounds for each make, model, and group of 

conditions.

(p) If the mass of SF6 or the PFC disbursed to customers in new equipment over 

the period p is determined according to the methods required in §98.453(h), report the 

number of samples and the upper and lower bounds on the 95 percent confidence 

interval for each make, model, and group of conditions.

(q) Pounds of SF6 and PFCs used to fill equipment at off-site electric power 

transmission or distribution locations, or MF, of Equation SS-6 of this subpart.

(r) Pounds of SF6 and PFCs used to charge the equipment prior to leaving the 

electrical equipment manufacturer or refurbishment facility, or MC, of Equation SS-6 of 

this subpart.

(s) The nameplate capacity of the equipment, in pounds, installed at off-site 

electric power transmission or distribution locations used to determine emissions from 

installation, or NI, of Equation SS-6 of this subpart.

(t) For any missing data, you must report the reason the data were missing, the 

parameters for which the data were missing, the substitute parameters used to estimate 

emissions in their absence, and the quantity of emissions thereby estimated.

Subpart TT—

Industrial 

Waste 

Landfills

(§98.466)

25,000 

metric tons 

C02e/year

In addition to the information required by §98.3(c), each annual report must 

contain the following information for each landfill.

(a) Report the following general landfill information:

(1) A classification of the landfill as “open” (actively received waste in the reporting 

year) or “closed” (no longer receiving waste).
(2) The year in which the landfill first started accepting waste for disposal.

(3) The last year the landfill accepted waste (for open landfills, enter the estimated 

year of landfill closure).

(4) The capacity (in metric tons) of the landfill.

(5) An indication of whether leachate recirculation is used during the reporting year 

and its typical frequency of use over the past 10 years (e.g., used several times a year 

for the past 10 years, used at least once a year for the past 10 years, used occasionally 

but not every year over the past 10 years, not used).

(b) Report the following waste characterization and modeling information:

(1) The number of waste steams (including “Other Industrial Solid Waste (not 

otherwise listed)” and “Inerts”) for which Equation TT-1 of this subpart is used to 

calculate modeled CH4 generation.

(2) A description of each waste stream (including the types of materials in each 

waste stream) for which Equation TT-1 of this subpart is used to calculate modeled 

CH4 generation.

(3) The fraction of CH4 in the landfill gas, F, (volume fraction, dry basis, corrected 

to 0% oxygen) for the reporting year and an indication as to whether this was the default 

value or a value determined through measurement data.

(4) The methane correction factor (MCF) value used in the calculations. If an MCF 

value other than the default of 1 is used, provide a description of the aeration system, 

including aeration blower capacity, the fraction of the landfill containing waste affected by 

the aeration, the total number of hours during the year the aeration blower was operated, 

and other factors used as a basis for the selected MCF value.

(5) For each waste stream, the decay rate (k) value used in the calculations.

(c) Report the following historical waste information:

(1) [Reserved]

(2) For each waste stream identified in paragraph (b) of this section, the method(s) 

for estimating historical waste disposal quantities and the range of years for which each 

method applies.

(3) For each waste stream identified in paragraph (b) of this section for which 

Equation TT-2 of this subpart is used, provide:

(i) [Reserved]

(ii) The year of the data used in Equation TT-2 of §98.463 for the waste disposal 

quantity and production quantity, for each year used in Equation TT-2 to calculate the 

average waste disposal factor (WDF).

(iii) [Reserved]

(4) If Equation TT-4a of this subpart is used, provide:
(i) The value of landfill capacity (LFC).

(ii) YrData.

(iii) YrOpen.

(5) If Equation TT-4b of this subpart is used, provide:

(i) WIP (i.e., the quantity of waste in-place at the start of the reporting year from 

design drawings or engineering estimates (metric tons) or, for closed landfills for which 

waste in-place quantities are not available, the landfill's design capacity).

(ii) The cumulative quantity of waste placed in the landfill for the years for which 

disposal quantities are available from company record or from Equation TT-3 of this part.

(iii) YrLast.

(iv) YrOpen.

(v) NYrData.

(d) For each year of landfilling starting with the “Start Year” (S) and each year 

thereafter up to the current reporting year, report the following information:

(1) The calendar year for which the following data elements apply.

(2) The quantity of waste (WX) disposed of in the landfill (metric tons, wet weight) 

for the specified year for each waste stream identified in paragraph (b) of this section.

(3) For each waste stream, the degradable organic carbon (DOCX) value (mass 

fraction) for the specified year and an indication as to whether this was the default value 

from Table TT-1 to this subpart, a measured value using a 60-day anaerobic 

biodegradation test as specified in §98.464(b)(4)(i), or a value based on total and volatile 

solids measurements as specified in §98.464(b)(4)(ii). If DOCX was determined by a 60-

day anaerobic biodegradation test, specify the test method used.

(e) Report the following information describing the landfill cover material:

(1) The type of cover material used (as either organic cover, clay cover, sand 

cover, or other soil mixtures).

(2) For each type of cover material used, the surface area (in square meters) at 

the start of the reporting year for the landfill sections that contain waste and that are 

associated with the selected cover type.

(f) The modeled annual methane generation (GCH4) for the reporting year (metric 

tons CH4) calculated using Equation TT-1 of this subpart.

(g) For landfills without gas collection systems, provide:

(1) The annual methane emissions (i.e., the methane generation (MG), adjusted 

for oxidation, calculated using Equation TT-6 of this subpart), reported in metric tons 

CH4.
(2) An indication of whether passive vents and/or passive flares (vents or flares 

that are not considered part of the gas collection system as defined in §98.6) are present 

at this landfill.

(h) For landfills with gas collection systems, in addition to the reporting 

requirements in paragraphs (a) through (f) of this section, provide:

(1) The annual methane generation, adjusted for oxidation, calculated using 

Equation TT-6 of this subpart, reported in metric tons CH4.

(2) The oxidation factor used in Equation TT-6 of this subpart.

(3) All information required under 40 CFR 98.346(i)(1) through (7) and 40 CFR 

98.346(i)(9) through (12).

Subpart UU –

Injection of 

Carbon 

Dioxide

(§98.476)

All In If you are subject to this part and report under this subpart, you are not required to 

report the information in §98.3(c)(4) for this subpart. In addition to the information 

required by §98.3(c)(1) through §98.3(c)(3) and by §98.3(c)(5) through §98.3(c)(9), you 

must report the information listed in this section.

(a) If you receive CO2 by pipeline, report the following for each receiving flow 

meter:

(1) The total net mass of CO2 received (metric tons) annually.

(2) If a volumetric flow meter is used to receive CO2:

(i) The volumetric flow through a receiving flow meter at standard conditions (in 

standard cubic meters) in each quarter.

(ii) The volumetric flow through a receiving flow meter that is redelivered to another 

facility without being injected into your well (in standard cubic meters) in each quarter.

(iii) The CO2 concentration in the flow (volume percent CO2 expressed as a 

decimal fraction) in each quarter.

(3) If a mass flow meter is used to receive CO2:

(i) The mass flow through a receiving flow meter (in metric tons) in each quarter.

(ii) The mass flow through a receiving flow meter that is redelivered to another 

facility without being injected into your well (in metric tons) in each quarter.

(iii) The CO2 concentration in the flow (weight percent CO2 expressed as a decimal 

fraction) in each quarter.

(4) The standard or method used to calculate each value in paragraphs (a)(2) 

through (a)(3) of this section.

(5) The number of times in the reporting year for which substitute data procedures 

were used to calculate values reported in paragraphs (a)(2) through (a)(3) of this section.

(6) Whether the flow meter is mass or volumetric.

(b) If you receive CO2 in containers, report:
(1) The mass (in metric tons) or volume at standard conditions (in standard cubic 

meters) of contents in containers in each quarter.

(2) The concentration of CO2 of contents in containers (volume or weight percent 

CO2 expressed as a decimal fraction) in each quarter.

(3) The mass (in metric tons) or volume (in standard cubic meters) of contents in 

containers that is redelivered to another facility without being injected into your well in 

each quarter.

(4) The net total mass of CO2 received (in metric tons) annually.

(5) The standard or method used to calculate each value in paragraphs (b)(1), 

(b)(2), and (b)(3) of this section.

(6) The number of times in the reporting year for which substitute data procedures 

were used to calculate values reported in paragraphs (b)(1) and (b)(2) of this section.

(c) If you use more than one receiving flow meter, report the net total mass of 

CO2 received (metric tons) through all flow meters annually.

(d) The source of the CO2 received according to the following categories:

(1) CO2 production wells.

(2) Electric generating unit.

(3) Ethanol plant.

(4) Pulp and paper mill.

(5) Natural gas processing.

(6) Gasification operations.

(7) Other anthropogenic source.

(8) Discontinued enhanced oil and gas recovery project.

(9) Unknown.

(e) Report the following:

(1) Whether the facility received a Research and Development project exemption 

from reporting under 40 CFR part 98, subpart RR, for this reporting year. If you received 

an exemption, report the start and end dates of the exemption approved by EPA.

(2) Whether the facility includes a well or group of wells where a CO2 stream was 

injected into subsurface geologic formations to enhance the recovery of oil during this 

reporting year.

(3) Whether the facility includes a well or group of wells where a CO2 stream was 

injected into subsurface geologic formations to enhance the recovery of natural gas 

during this reporting year.
(4) Whether the facility includes a well or group of wells where a CO2 stream was 

injected into subsurface geologic formations for acid gas disposal during this reporting 

year.

(5) Whether the facility includes a well or group of wells where a CO2 stream was 

injected for a purpose other than those listed in paragraphs (e)(1) through (4) of this 

section. If you injected CO2 for another purpose, report the purpose of the injection.