Appendix	C:		

Greenhouse	Gas	Reporting	Program:	Reporting	

Thresholds	and	Reporting	Requirements	
Page C‐1

Appendix C. Greenhouse Gas Reporting Program:  

Reporting Thresholds and Reporting Requirements

Subpart

Reporting

Threshold Reporting and Verification

C—General

Stationary

Combustion

(§98.30)

25,000 metric

tons C02e/year

Units that use the four tiers:

(1) Unit ID number.

(2) Code representing the type of unit.

(3) Maximum rated heat input capacity of the unit, in mmBtu/hr for boilers and process heaters only and relevant units of

measure for other combustion sources.

(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.

(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: the annual CO2mass emissions (including biogenic CO2), 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 as well as metric tons of biogenic CO2 emissions (if applicable).

(9) For a unit that uses Tier 4: total annual CO2mass emissions, expressed in metric tons, If the total annual CO2mass

emissions measured by the CEMS consists entirely of non‐biogenic CO2; total annual non‐biogenic CO2mass emissions and

the annual CO2mass emissions from biomass combustion, if this total includes both biogenic and non‐biogenic CO2mass

emissions measured by the CEMS (reporting by fuel type is not required); and estimate of the heat input from each type of

fuel listed in Table C–2 of subpart C that was combusted in the unit during the report year, and the annual CH4 and N2O

emissions for each of these fuels, 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 subpart C), expressed in metric tons.

(11) Verification data listed in 40 CFR 98.36(e) (see below).

(a) Tier 1 Calculation Methodology:

(i) Total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during the

reporting year, in short tons for solid fuels, gallons for liquid fuels and standard cubic feet for gaseous fuels, or, if

applicable, therms or mmBtu for natural gas.

(b) Tier 2 Calculation Methodology:

(i) 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, expressed in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels

(ii) The frequency of the HHV determinations (e.g., once a month, once per fuel lot).

(iii) 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, for each

calendar month in which HHV determination is required (the arithmetic average value for the month if multiple values are

obtained in a given month) as well as an indication whether each reported HHV is measured value or substitute data value.

(iv) If Equation C–2c of subpart C is used to calculate CO2 mass emissions: 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.

(c) Tier 3 Calculation Methodology:

(i) 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.

(ii) 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).

(iii) The carbon content (expressed as a decimal fraction for solid fuels, kg C per gallon for liquid fuels, and kg C per kg of

fuel for gaseous fuels) and, if applicable, gas molecular weight (expressed in units of kg per kg‐mole) values used in the

emission calculations (including both valid and substitute data values) (report the arithmetic average value for the month if

multiple values of a parameter are obtained in a given month).

(iv) The total number of valid carbon content determinations and, if applicable, molecular weight determinations made

during the reporting year, for each fuel type.

(v) The number of substitute data values used for carbon content and, if applicable, molecular weight used in the annual

GHG emissions calculations.

(vi) The annual average HHV, when measured HHV data, rather than a default HHV from Table C–1 of subpart C, are used

to calculate CH4 and N2O emissions for a Tier 3 unit, in accordance with §98.33(c)(1).

(vii) The value of the molar volume constant (MVC) used in Equation C–5 (if applicable).

(d) Tier 4 Calculation Methodology:

(i) The total number of source operating hours in the reporting year.

(ii) 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 subpart C (as applicable), in metric tons
Page C‐2

Subpart

Reporting

Threshold Reporting and Verification

C—General

Stationary

Combustion

(§98.30)

25,000 metric

tons C02e/year

Reporting alternatives for units using the four tiers (40 CFR 98.36(c)):

Aggregation of units  

(1) Group ID number, beginning with the prefix “GP”.

(2) The highest maximum rated heat input capacity of any unit in the group (mmBtu/hr).

(3) Each type of fuel combusted in the group of units during the reporting year.

(4) 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; 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, if the units burn both fossil fuels and biomass.

(5) 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).

(6) The methodology start date, for each fuel type.

(7) The methodology end date, for each fuel type.

(8) The calculated CO2 mass emissions (if any) from sorbent expressed in metric tons.

Monitored common stack or duct configuration

(1) Common stack or duct identification number, beginning with the prefix “CS”.

(2) Number of units sharing the common stack or duct.

(3) Combined maximum rated heat input capacity of the units sharing the common stack or duct (mmBtu/hr), only when all

of the units sharing the common stack are stationary fuel combustion units.

(4) Each type of fuel combusted in the units during the year.

(5) The methodology (tier) used to calculate the CO2 mass emissions.   

(6) The methodology start date.

(7) The methodology end date .

(8) An estimate of the heat input from each type of fuel listed in Table C–2 of subpart C that was combusted during the

report year in the units sharing the common stack or duct during the report year, and, for each of these fuels, 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.  

Common pipe configurations

(1) Common pipe identification number, beginning with the prefix “CP”.

(2) The highest maximum rated heat input capacity of any unit served by the common pipe (mmBtu/hr).

(3) The fuels combusted in the units during the reporting year.

(4) The methodology used to calculate the CO2 mass emissions.

(5) 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.

(6) 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.

(7) Methodology start date.

(8) Methodology end date.

(9) If a common liquid or gaseous fuel supply is shared between one or more large combustion units: attribute all of the

GHG emissions from combustion of the shared fuel to the large combustion unit(s) (provided that 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); 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; and the use of this reporting option is documented in the

Monitoring Plan required under §98.3(g)(5)).     
Page C‐3

Subpart

Reporting

Threshold Reporting and Verification

C—General

Stationary

Combustion

(§98.30)

25,000 metric

tons C02e/year

Units also subject to 40 CFR part 75:

(1) Unit or stack identification numbers that are reported under 40 CFR 75.64.

(2) Annual CO2 emissions at each monitored location, expressed in both short tons and metric tons.

(3) 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.

(4) 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.

(5) Identification of the Part 75 methodology used to determine the CO2mass emissions.

(6) Methodology start date.

(7) Methodology end date.

(8) Acid Rain Program indicator.

(9) Annual CO2mass 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)

(10) For units that use the alternative CO2mass emissions calculation methods provided in 40 CFR 98.33(a)(5): unit, stack,

or pipe ID numbers.

(11) For units that use methods specified in 40 CFR 98.33(a)(5)(i) and (ii): each type of fuel combusted in the unit during

the reporting year; methodology used to calculate the CO2mass emissions for each fuel type; methodology start date;

methodology end date; code or flag to indicate whether heat input is calculated according to appendix D to part 75  or 40

CFR 75.19 ; annual CO2 emissions at each monitored location, across all fuel types, expressed in metric tons of CO2e; annual

heat input from each type of fuel listed in Table C–2 of subpart C that was combusted during the reporting year, expressed

in mmBtu; annual CH4 and N2O emissions at each monitored location, from each fuel type listed in Table C–2 of subpart C

that was combusted during the reporting year (except as otherwise provided in 40 CFR 98.33(c)(4)(ii)(D)), expressed in

metric tons CO2e; annual CO2 mass emissions from the combustion of biomass, expressed in metric tons CO2e (except

where the reporting provisions of 40 CFR 98.3(c)(12)(i) through (c)(12)(iii) are implemented for the 2010 reporting year).

(12) For units that use methods specified in 40 CFR 98.33(a)(5)(iii) to monitor heat input year‐round: each type of fuel

combusted during the reporting year; methodology used to calculate the CO2 mass emissions; methodology start date;

methodology end date; code or flag to indicate that the heat input data is derived from CEMS measurements; total annual

CO2 emissions at each monitored location, expressed in metric tons of CO2e; annual heat input from each type of fuel listed

in Table C–2 of subpart C that was combusted during the reporting year, expressed in mmBtu; annual CH4 and N2O

emissions at each monitored location, from each fuel type listed in Table C–2 of subpart C that was combusted during the

reporting year (except as otherwise provided in 40 CFR 98.33(c)(4)(ii)(B)), expressed in metric tons CO2e; and annual CO2

mass emissions from the combustion of biomass, expressed in metric tons CO2e (except where the reporting provisions of

40 CFR 98.3(c)(12)(i) through (c)(12)(iii) are implemented for the 2010 reporting year).

D—Electricity

Generation

(§98.40)

All In (1) Unit or stack identification numbers that are reported under 40 CFR 75.64.

(2) Annual CO2 emissions at each monitored location, expressed in both short tons and metric tons.

(3) 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.

(4) 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.

(5) Identification of the Part 75 methodology used to determine the CO2 mass emissions.

(6) Methodology start date.

(7) Methodology end date.

(8) Acid Rain Program indicator.

(9) 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)
Page C‐4

Subpart

Reporting

Threshold Reporting and Verification

E—Adipic Acid

Production

(§98.50)

All In (1) Annual process N2O emissions from adipic acid production (metric tons).

(2) Annual adipic acid production (tons).

(3) Annual adipic acid production during which N2O abatement technology (located after the test point) is operating (tons).

(4) Annual process N2O emissions from adipic acid production facility that is sold or transferred off‐site (metric tons).  

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

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

(7) Abatement technology destruction efficiency for each abatement technology (percent destruction).

(8) Abatement utilization factor for each abatement technology (fraction of annual production that abatement technology

is operating).

(9) Number of times in the reporting year that missing data procedures were followed to measure adipic acid production

(months).

(10) 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.

If a performance test and site‐specific emissions factors were used:

(1) Emission factor (lb N2O/ton adipic acid).

(2) Test method used for performance test.

(3) Production rate per test run during performance test (tons/hr).

(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).

If approval was requested for an alternative method of calculating N2O concentration:

(1) Name of alternative method.

(2) Description of alternative method.

(3) Request date.

(4) Approval date.

F—Aluminum

Production

(§98.60)

All In (1) Annual aluminum production in metric tons.

(2) Type of smelter technology used.  

(3) The following PFC‐specific information on an annual basis: Perfluoromethane emissions and perfluoroethane emissions

from anode effects in all prebake and all Søderberg electolysis cells combined; Anode effect minutes per cell‐day (AE‐

mins/cell‐day), anode effect frequency (AE/cell‐day), anode effect duration (minutes). (Or anode effect overvoltage factor

((kg CF4/metric ton Al)/(mV/cell day)), potline overvoltage (mV/cell day), current efficiency (%)); Smelter‐specific slope

coefficients (or overvoltage emission factors) and the last date when the smelter‐specific‐slope coefficients (or overvoltage

emission factors) were measured.

(4) Method used to measure the frequency and duration of anode effects (or overvoltage).

(5) The following CO2‐specific information for prebake cells: Annual anode consumption and annual CO2 emissions from the

smelter.

(6) The following CO2‐specific information for Søderberg cells: Annual paste consumption and annual CO2 emissions from

the smelter.

(7) Smelter‐specific inputs to the CO2 process equations (e.g., levels of sulfur and ash) that were used in the calculation, on

an annual basis.  

(8) 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).
Page C‐5

Subpart

Reporting

Threshold Reporting and Verification

G—Ammonia

Manufacturing

(§98.70)

All In If a CEMS is used to measure CO2 emissions:

All relevant information required under 40 CFR 98.36 for the Tier 4 Calculation Methodology plus:

(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.

If a CEMS is not used to measure emissions:  

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

(2) Monthly quantity of each type of feedstock consumed for ammonia manufacturing for each ammonia processing unit

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

(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 petroleum coke as determined for QA/QC of supplier data under 98.74(e)

(7) If a facility uses gaseous feedstock, the carbon content of the gaseous feedstock, for month n, (kg C per kg of

feedstock).

(8) If a facility uses gaseous feedstock, the molecular weight of the gaseous feedstock (kg/kg‐mole).

(9) If a facility uses gaseous feedstock, the molar volume conversion factor of the gaseous feedstock (scf per kg‐mole).

(10) If a facility uses liquid feedstock, the carbon content of the liquid feedstock, for month n, (kg C per gallon of

feedstock).

(11) If a facility uses solid feedstock, the carbon content of the solid feedstock, for month n, (kg C per kg of feedstock).

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

(13) CO2 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.

H—Cement

Production

(§98.80)

All In If a CEMS is used to measure CO2 emissions:

All relevant information required under 40 CFR 98.37(e)(2)(vi) plus:

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

(2) Monthly cement production from each kiln at the facility.

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

If a CEMS is not used to measure CO2 emissions:  

(1) Kiln identification number.

(2) Monthly clinker production from each kiln.

(3) Annual cement production at the facility.

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

(5) Quarterly quantity of CKD not recycled to the kiln for each kiln at the facility.  

(6) Monthly fraction of total CaO, total MgO, non‐calcined CaO and non‐calcined MgO in clinker for each kiln (as wt‐

fractions).  

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

(8) Quarterly fraction of total CaO, total MgO, non‐calcined CaO and non‐calcined MgO in CKD not recycled to the kiln for

each kiln (as wt‐fractions).  

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

(10) Monthly kiln‐specific clinker CO2 emission factors for each kiln (metric tons CO2/metric ton clinker produced).  

(11) Quarterly kiln‐specific CKD CO2 emission factors for each kiln (metric tons CO2/metric ton CKD produced).  

(12) Annual organic carbon content of raw kiln feed or annual organic carbon content of each raw material (wt‐fraction,

dry basis).

(13) Annual consumption of raw kiln feed or annual consumption each raw material (dry basis).

(14) Number of times missing data procedures were used to determine: (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); and (vii) Raw material consumption (number of months).

(15) Method used to determine the monthly clinker production from each kiln reported under 40 CFR 98.86 (b)(2),

including monthly kiln‐specific clinker factors, if used.
Page C‐6

Subpart

Reporting

Threshold Reporting and Verification

I—Electronics

Manufacturing

(§98.90)

25,000 metric

tons C02e/year

(1) Annual manufacturing capacity of the facility as determined in Equation I–5 of subpart I.

(2) For facilities that manufacture semiconductors, the diameter of wafers manufactured at the facility (mm).

(3) Annual emissions of: (i) Each fluorinated GHG emitted from each process type for which the facility is required to

calculate emissions as calculated in Equations I–6 and I–7 of subpart I; (ii) Each fluorinated GHG emitted from each

individual recipe (including those in a set of similar recipes), or process sub‐type as calculated in Equations I–8 and I–9 of

subpart I, as applicable; (iii) N2O emitted from each chemical vapor deposition process and from other N2O‐using

manufacturing processes as calculated in Equation I–10 of subpart I; and (iv) Each fluorinated heat transfer fluid emitted as

calculated in Equation 1–16 of subpart I.

(4) The method of emissions calculation used in 40 CFR 98.93.

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

(6) When using factors for fluorinated GHG process utilization and by‐product formation rates other than the defaults

provided in Tables I–3, I–4, I–5, I–6, and I–7 to subpart I and/or N2O utilization factors other than the defaults provided in

Table I–8 to subpart I, report the following, as applicable: (i) The recipe‐specific utilization and by‐product formation rates

for each individual recipe (or set of similar recipes) and/or facility‐specific N2O utilization factors; (ii) For recipe‐specific

utilization and by‐product formation rates, the film or substrate that was etched/cleaned and the feature type that was

etched, as applicable; (iii) Certification that the recipes included in a set of similar recipes are similar, as defined in 40 CFR

98.98; (iv) Certification that the measurements for all reported recipe‐specific utilization and by‐product formation rates

and/or facility‐specific N2O utilization factors were made using the International SEMATECH #06124825A–ENG

(incorporated by reference, see 40 CFR 98.7), or the International SEMATECH #01104197A–XFR (incorporated by

reference, see 40 CFR 98.7) if measurements were made prior to January 1, 2007; (v) Source of the recipe‐specific

utilization and by‐product formation rates and/or facility‐specific‐N2O utilization factors; and (vi) Certification that the

conditions under which the measurements were made for facility‐specific N2O utilization factors are representative of the

facility's N2O emitting production processes.

(7) Annual gas consumption for each fluorinated GHG and N2O as calculated in Equation I–11 of subpart I, including where

the facility used less than 50 kg of a particular fluorinated GHG or N2O during the reporting year. For all fluorinated GHGs

and N2O used at the facility for which emissions have not calculated using Equations I–6, I–7, I–8, I–9, and I–10 of subpart I,

the chemical name of the GHG used, the annual consumption of the gas, and a brief description of its use.

(8) All inputs used to calculate gas consumption in Equation I–11 of subpart I, for each fluorinated GHG and N2O used.

(9) Disbursements for each fluorinated GHG and N2O during the reporting year, as calculated using Equation I–12 of

subpart I.

(10) All inputs used to calculate disbursements for each fluorinated GHG and N2O used in Equation I–12 of subpart I,

including all facility‐wide gas‐specific heel factors used for each fluorinated GHG and N2O. If the facility used less than 50 kg

of a particular fluorinated GHG during the reporting year, facility‐wide gas‐specific heel factors do not need to be reported

for those gases.

(11) Annual amount of each fluorinated GHG consumed for each recipe, process sub‐type, or process type, as appropriate,

and the annual amount of N2O consumed for each chemical vapor deposition and other electronics manufacturing

production processes, as calculated using Equation I–13 of subpart I.

(12) All apportioning factors used to apportion fluorinated GHG and N2O consumption.

(13) For the facility‐specific apportioning model used to apportion fluorinated GHG and N2O consumption under 40 CFR

98.94(c), the following information to determine it is verified in accordance with procedures in 40 CFR 98.94(c)(1) and (2):

(i) Identification of the quantifiable metric used in the facility‐specific engineering model to apportion gas consumption; (ii)

The start and end dates selected under 40 CFR 98.94(c)(2)(i); (iii) Certification that the gases selected under 40 CFR

98.94(c)(2)(ii) correspond to the largest quantities consumed on a mass basis, at the facility in the reporting year for the

plasma etching process type and the chamber cleaning process type; and (iv) The result of the calculation comparing the

actual and modeled gas consumption under 40 CFR 98.94(c)(2)(iii).

(14) Fraction of each fluorinated GHG or N2O fed into a recipe, process sub‐type, or process type that is fed into tools

connected to abatement systems.

(15) Fraction of each fluorinated GHG or N2O destroyed or removed in abatement systems connected to process tools

where recipe, process sub‐type, or process type j is used, as well as all inputs and calculations used to determine the inputs

for Equation I–14 of subpart I.

(16) Inventory and description of all abatement systems through which fluorinated GHGs or N2O flow at the facility,

including the number of devices of each manufacturer, model numbers, manufacturer claimed fluorinated GHG and N2O

destruction or removal efficiencies, if any, and records of destruction or removal efficiency measurements over their in‐use

lives. The inventory of abatement systems must describe the tools with model numbers and the recipe(s), process sub‐

type, or process type for which these systems treat exhaust.

(17) For each abatement system through which fluorinated GHGs or N2O flow at the facility, for which controlled emissions

are reported, the following: (i) Certification that each abatement system has been installed, maintained, and operated in

accordance with manufacturers' specifications; (ii) All inputs and results of calculations made accounting for the uptime of

abatement systems used during the reporting year, in accordance with Equations I–14 and I–15 of subpart I; (iii) The

default destruction or removal efficiency value or properly measured destruction or removal efficiencies for each

abatement system used in the reporting year; (iv) Where the default destruction or removal efficiency value is used to

report controlled emissions, certification that the abatement systems for which emissions are being reported were

specifically designed for fluorinated GHG and N2O abatement. Support this certification by providing abatement system

supplier documentation stating that the system was designed for fluorinated GHG and N2O abatement; (v) Where properly

measured destruction or removal efficiencies or class averages of destruction or removal efficiencies are used, the

following must also be reported: (a) A description of the class, including the abatement system manufacturer and model

number and the fluorinated GHG(s) and N2O in the effluent stream; (b) The total number of systems in that class for the

reporting year; (c) The total number of systems for which destruction or removal efficiency was properly measured in that  
Page C‐7

Subpart

Reporting

Threshold Reporting and Verification

I—Electronics

Manufacturing

(§98.90)

25,000 metric

tons C02e/year

class for the reporting year; (d) A description of the calculation used to determine the class average, including all inputs to

the calculation; (e) A description of the method used for randomly selecting class members for testing.

(18) For fluorinated heat transfer fluid emissions, inputs to the fluorinated heat transfer fluid mass balance equation,

Equation I–16 of subpart I, for each fluorinated heat transfer fluid used.

(19) Where missing data procedures were used to estimate inputs into the fluorinated heat transfer fluid mass balance

equation under 40 CFR 98.95(b), the number of times missing data procedures were followed in the reporting year, the

method used to estimate the missing data, and the estimates of those data.

(20) A brief description of each “best available monitoring method” used according to 40 CFR 98.94(a), the parameter

measured or estimated using the method, and the time period during which the “best available monitoring method” was

used.

(21) For each fluorinated heat transfer fluid used, whether the emission estimate includes emissions from all applications

or from only the applications specified in the definition of fluorinated heat transfer fluids in 40 CFR 98.98.

(22) For reporting year 2012 only, the date on which monitoring emissions of fluorinated heat transfer fluids began whose

vapor pressure falls below 1 mm Hg absolute at 25 °C. This is either January 1, 2012 or March 23, 2012.

K—Ferroalloy

Production

(§98.110)

25,000 metric

tons C02e/year

All:  

(a) Annual facility ferroalloy product production capacity (tons).

(b) Annual production for each ferroalloy product identified in 40 CFR 98.110, from each EAF (tons).

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

If a CEMS is used to measure CO2 emissions:  

All relevant information required under 40 CFR 98.37(e)(2)(vi) for the Tier 4 Calculation Methodology plus:

(1) Annual process CO2 emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K‐

1 of subpart K.

(2) Annual process CH4 emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K‐

1 of subpart K (metric tons).

(3) Identification each EAF.  

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 40 CFR 98.113(b):

(1) Annual process CO2 emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K‐

1 of subpart K (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 subpart K (metric tons).

(3) Identification number for each material.

(4) Annual material quantity for each material included for the calculation of annual process CO2 emissions for each EAF.

(5) Annual average of the carbon content determinations for each material included for the calculation of annual process

CO2 emissions for each EAF (percent by weight, expressed as a decimal fraction).

(6) The method used for the determination of carbon content for each material reported in paragraph (e)(5) of this section

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

(7) For missing data procedures: 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.  
Page C‐8

Subpart

Reporting

Threshold Reporting and Verification

L—Fluorinated

Gas Production

(§98.120)

25,000 metric

tons C02e/year

All:  

(1) Frequency of reporting under paragraph (a) of this section. The information in paragraphs (a)(2), (5), and (6) of this

section must be reported annually. The information in paragraphs (a)(3) and (4) of this section must be reported once by

March 31, 2012 for each process and operating scenarios that operates between December 31, 2010 and December 31,

2011. For other processes and operating scenarios, the information in paragraphs (a)(3) and (4) of this section must be

reported once by March 31 of the year following the year in which the process or operating scenario commences or

recommences.

(2) Report the total mass in metric tons of each fluorinated GHG emitted from: (i) Each fluorinated gas production process

and all fluorinated gas production processes combined; (ii) Each fluorinated gas transformation process that is not part of a

fluorinated gas production process and all such fluorinated gas transformation processes combined, except report

separately fluorinated GHG emissions from transformation processes where a fluorinated GHG reactant is produced at

another facility; (iii) Each fluorinated gas destruction process that is not part of a fluorinated gas production process or a

fluorinated gas transformation process and all such fluorinated gas destruction processes combined; and (iv) Venting of

residual fluorinated GHGs from containers returned from the field.

(3) The chemical identities of the contents of the stream(s) (including process, emissions, and destroyed streams) analyzed

under the initial scoping speciation of fluorinated GHG at 40 CFR 98.124(a), by process.

(4) The location and function of the stream(s) (including process streams, emissions streams, and destroyed streams) that

were analyzed under the initial scoping speciation of fluorinated GHG at 40 CFR 98.124(a), by process.

(5) The method used to determine the mass emissions of each fluorinated GHG, i.e., mass balance, process‐vent‐specific

emission factor, or process‐vent‐specific emission calculation factor, for each process and process vent at the facility. For

processes for which the process‐vent‐specific emission factor or process‐vent‐specific emission calculation factor are used,

report the method used to estimate emissions from equipment leaks.

(6) The chemical formula and total mass produced of the fluorinated gas product in metric tons, by chemical and process.

For mass balance approach: For processes whose emissions are determined using the mass‐balance approach under 40

CFR 98.123(b), report the information listed in (1) through (13) for each process on an annual basis. Identify and separately

report fluorinated GHG emissions from transformation processes where the fluorinated GHG reactants are produced at

another facility. If using an element other than fluorine in the mass‐balance equation pursuant to 40 CFR 98.123(b)(3),

substitute that element for fluorine in the reporting requirements of this paragraph.

(1) If calculating the relative and absolute errors under 98.123(b)(1), the absolute and relative errors calculated under

paragraph 40 CFR 98.123(b)(1), as well as the data (including quantities and their accuracies and precisions) used in these

calculations.

(2) The balanced chemical equation that describes the reaction used to manufacture the fluorinated GHG product and

each fluorinated GHG transformation product.

(3) The mass and chemical formula of each fluorinated GHG reactant emitted from the process in metric tons.

(4) The mass and chemical formula of the fluorinated GHG product emitted from the process in metric tons.

(5) The mass and chemical formula of each fluorinated GHG by‐product emitted from the process in metric tons.

(6) The mass and chemical formula of each fluorine‐containing reactant that is fed into the process (metric tons).

(7) The mass and chemical formula of each fluorine‐containing product produced by the process (metric tons).

(8) If using 40 CFR 98.123(b)(4) to estimate the total mass of fluorine in destroyed or recaptured streams, report: (i) The

mass and chemical formula of each fluorine‐containing product that is removed from the process and fed into the

destruction device (metric tons); (ii) The mass and chemical formula of each fluorine‐containing by‐product that is

removed from the process and fed into the destruction device (metric tons); (iii) The mass and chemical formula of each

fluorine‐containing reactant that is removed from the process and fed into the destruction device (metric tons); (iv) The

mass and chemical formula of each fluorine‐containing by‐product that is removed from the process and recaptured

(metric tons); and (v) The demonstrated destruction efficiency of the destruction device for each fluorinated GHG fed into

the device from the process in greater than trace concentrations (fraction).

(9) If using 40 CFR 98.123(b)(15) to estimate the total mass of fluorine in destroyed or recaptured streams: (i) The mass of

fluorine in each stream that is fed into the destruction device (metric tons); (ii) The mass of fluorine that is recaptured

(metric tons); and (iii) The weighted average destruction efficiency of the destruction device calculated for each stream

under 40 CFR 98.123(b)(16).

(10) The fraction of the mass emitted that consists of each fluorine‐containing reactant.

(11) The fraction of the mass emitted that consists of the fluorine‐containing product.

(12) The fraction of the mass emitted that consists of each fluorine‐containing by‐product.

(13) The method used to estimate the total mass of fluorine in destroyed or recaptured streams (specify 40 CFR

98.123(b)(4) or (15)).

For emission factor and emission calculation factor approach. For processes whose emissions are determined using the

emission factor approach under 40 CFR 98.123(c)(3) or the emission calculation factor under 40 CFR 98.123(c)(4), report

the following for each process. Fluorinated GHG emissions from transformation processes where the fluorinated GHG

reactants are produced at another facility must be identified and reported separately from other fluorinated GHG

emissions.

(1) The identity and quantity of the process activity used to estimate emissions (e.g., tons of product produced or tons of

reactant consumed).

(2) The site‐specific, process‐vent‐specific emission factor(s) or emission calculation factor for each process vent.

(3) The mass of each fluorinated GHG emitted from each process vent (metric tons).

(4) The mass of each fluorinated GHG emitted from equipment leaks (metric tons).

For missing data: Where missing data have been estimated pursuant to 40 CFR 98.125, report 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.
Page C‐9

Subpart

Reporting

Threshold Reporting and Verification

L—Fluorinated

Gas Production

(§98.120)

25,000 metric

tons C02e/year

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 would be

reflected in the fluorinated GHG estimates in 40 CFR 98.123(b) and (c). Such excess emissions would occur if the

destruction efficiency was reduced due to the malfunction.

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 making a

change to the destruction device that would be expected to affect its destruction efficiencies.

(1) Destruction efficiency (DE) of each destruction device for each fluorinated GHG whose destruction the facility reflects in

40 CFR 98.123, in accordance with 40 CFR 98.124(g)(1)(i) through (iv).

(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 40 CFR 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) If making a change to the destruction device that would be expected to affect its destruction efficiencies, submit a

revised report that reflects the changes, including the revised destruction efficiencies measured for the device under 40

CFR 98.124(g)(2)(ii), by March 31 of the year that immediately follows the change.

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) The mass of the fluorinated GHG fed into the destruction device.

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

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 each container size and type annually (tons).

(2) If applicable, the heel factor calculated for each container size and type.

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.

N—Glass

Production

(§98.140)

25,000 metric

tons C02e/year

If a CEMS is used to measure CO2 emissions:

All relevant information required under 40 CFR 98.36 for the Tier 4 Calculation Methodology plus:

(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).

If a CEMS is not used to determine CO2 emissions from continuous glass melting furnaces, and process CO2 emissions are

calculated according to the procedures specified in 40 CFR 98.143(b):

(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 each continuous glass melting furnace and for

all furnaces combined.

(3) Annual quantity of glass produced (tons) from each continuous glass melting furnace and from all furnaces combined.

(4) Carbonate‐based mineral mass fraction (percentage, expressed as a decimal) for each carbonate‐based raw material

charged to a continuous glass melting furnace.

(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, including (i) Date of test; (ii) Method(s) and any variations used in the

analyses; and (iii) Mass fraction of each sample analyzed;

(6) The fraction of calcination achieved (percentage, expressed as a decimal) for each carbonate‐based raw material, if a

value other than 1.0 is used to calculate process mass emissions of CO2.

(7) Method used to determine 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).  
Page C‐10

Subpart

Reporting

Threshold Reporting and Verification

O—HCFC‐22

Production and

HFC‐23

Destruction

(§98.150)

HCFC‐22: All In

HFC‐23

destruction

processes that

are not

collocated

with a HCFC‐

22 production

and that

destroy more

than 2.14

metric tons

HFC‐23 per

year: All In

HCFC‐22 production facilities

At the facility level:

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

(2) Loss Factor used to account for the loss of HCFC– 22 upstream of the measurement.  

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

(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) Annual mass of the HFC‐23 generated in metric tons.  

(8) Annual mass of any HFC‐23 sent off site for sale in metric tons.  

(9) Annual mass of any HFC‐23 sent off site for destruction in metric tons.

(10) Mass of HFC‐23 in storage at the beginning and end of the year, in metric tons.

(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.

HFC‐23 destruction facilities

(1) Annual mass of HFC‐23 fed into the destruction device.

(2) Annual mass of HFC‐23 destroyed.

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

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 HFC–23 concentration measured pursuant to 40 CFR 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 revised destruction efficiency calculated

under 40 CFR 98.154(l) and the values used to calculate it, specifying whether 40 CFR 98.154(l)(1) or 40 CFR 98.154(l)(2)

has been used for the calculation. Specifically, the facility shall report the following:

(i) The flow rate of HFC‐23 being fed into the destruction device in kg/hr.

(ii) The concentration (mass fraction) of HFC‐23 at the outlet of the destruction device.

(iii) The flow rate at the outlet of the destruction device in kg/hr.

(iv) The emission rate calculated from (ii) and (iii) above in kg/hr.

(iv) Destruction efficiency (DE) calculated from paragraphs (i) and (iv) of this section.

Plus a one‐time report including the following information:

(1) Destruction efficiency (DE).  

(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.
Page C‐11

Subpart

Reporting

Threshold Reporting and Verification

P—Hydrogen

Production

(§98.160)

25,000 metric

tons C02e/year

If a CEMS is used to measure CO2 emissions:

All relevant information required under 40 CFR 98.3(c) for the Tier 4 Calculation Methodology plus:

(1) Unit identification number and annual CO2 emissions.

(2) Annual quantity of hydrogen produced (metric tons) for each process unit and for all units combined.  

(3) Annual quantity of ammonia produced (metric tons), if applicable (metric tons) for each process unit and for all units

combined.  

If a CEMS is not used to measure CO2 emissions:

(1) Unit identification number and annual CO2 emissions.  

(2) Monthly consumption of each fuel and feedstock used for hydrogen production and its type (scf of gaseous fuels and

feedstocks, gallons of liquid fuels and feedstocks, kg of solid fuels and feedstocks).  

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

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

(5) Monthly analyses of carbon content for each fuel and feedstock used in hydrogen production (kg carbon/kg of gaseous

and solid fuels and feedstocks, (kg carbon per gallon of liquid fuels and feedstocks).  

(6) Monthly analyses of the molecular weight of gaseous fuels and feedstocks (kg/kg‐mole) used, if any.

All:

(1) Quantity of CO2 collected and transferred off site in either gas, liquid, or solid forms, following the requirements of

subpart PP of this part.  

(2) Annual quantity of carbon other than CO2 collected and transferred off site in either gas, liquid, or solid forms (kg

carbon).

Q—Iron & Steel

Production

(§98.170)

25,000 metric

tons C02e/year

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:

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

(2) Annual production quantity (in metric tons) for taconite pellets, coke, sinter, iron, and raw steel.

If a CEMS is used to measure CO2 emissions: All relevant information required under 40 CFR 98.36 for the Tier 4

Calculation Methodology

If a CEMS is not used to measure CO2 emissions: An indication for each of whether for each process whether the

emissions were determined using the carbon mass balance method in 40 CFR 98.173(b)(1) or the site‐specific emission

factor method in 40 CFR 98.173(b)(2).

If the carbon mass balance method in 40 CFR 98.173(b)(1)  is used to determine CO2 emissions:

(1) The carbon content of each process input and output used to determine CO2 emissions.

(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) The annual volume of gaseous fuel (reported separately for each type in standard cubic feet), the annual volume of

liquid fuel (reported separately for each type in gallons), and the annual mass (in metric tons) of each other process inputs

and outputs used to determine CO2 emissions.

(4) The molecular weight of gaseous fuels.

(5) For the missing data procedures in 40 CFR 98.175(b): 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.  

If the site‐specific emission factor method 40 CFR 98.173(b)(2) is used to determine CO2 emissions:

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

(2) The average hourly feed or production rate (as applicable) during the test (in metric tons per hour).

(3) The site‐specific emission factor (in metric tons of CO2 per metric ton of feed or production, as applicable).

(4) The annual feed or production rate (as applicable) used to estimate annual CO2 emissions (in metric tons).

All:

(1) The annual amount of coal charged to the coke ovens (in metric tons).

(2) For flares burning coke oven gas or blast furnace gas, the information specified in 40 CFR 98.256(e) of subpart Y

(Petroleum Refineries) of this part.
Page C‐12

Subpart

Reporting

Threshold Reporting and Verification

R—Lead

Production

(§98.180)

25,000 metric

tons C02e/year

If a CEMS is used to measure CO2 emissions according to the requirements in 40 CFR 98.183(a) or (b)(1):

All relevant information required under 40 CFR 98.36 for the Tier 4 Calculation Methodology plus:

(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.

If a CEMS is not used to measure CO2 emissions and measuring CO2 emissions according to the requirements in 40 CFR

98.183(b)(2)(i) and (b)(2)(ii):

(1) Identification number of each smelting furnace.

(2) Annual process CO2 emissions (in metric tons) from each smelting furnace as determined by Eq. R‐1 of subpart R.

(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 (4).  

(6) Annual material quantity for each material used for the calculation of annual process CO2 emissions using Eq. R‐1 of

subpart R for each smelting furnace (tons).

(7) Annual average of the carbon content determinations for each material used for the calculation of annual process CO2

emissions using Eq. R‐1 of subpart R for each smelting furnace.

(8) The method used for the determination of carbon content for each material reported in (7) (e.g., supplier provided

information, analyses of representative samples).  

(9) For the missing data procedures in 40 CFR 98.185(b): How the monthly mass of carbon‐containing materials with

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

S—Lime

Manufacturing

(§98.190)

All In If a CEMS is used to measure CO2 emissions:

All relevant information required under 40 CFR 98.36 for the Tier 4 Calculation Methodology plus:

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

(2) Method used to determine the quantity of calcined lime byproduct/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/wastes sold, by type.  

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

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

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

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

If a CEMS is not used to measure CO2 emissions:  

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

(2) Monthly emission factors for each lime type produced.

(3) Monthly emission factors for each calcined byproduct/waste by lime type that is sold.

(4) Standard method used (ASTM or NLA testing method) to determine chemical compositions of each lime type produced

and each calcined lime byproduct/waste type.

(5) Monthly results of chemical composition analysis of each lime product produced and calcined byproduct/waste sold.

(6) Annual results of chemical composition analysis of each type of lime byproduct/waste not sold.

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

(8) Monthly amount of lime product sold, by type (tons).

(9) Method used to determine the quantity of calcined lime byproduct/waste sold.

(10) Monthly amount of calcined lime byproduct/waste sold, by type (tons).

(11) Annual amount of calcined lime byproduct/waste that is not sold, by type (tons).  

(12) Monthly weight or mass of each lime type produced (tons).  

(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/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 CO2was used on‐site, provide: (i) The

annual amount of CO2 captured for use in the on‐site process; and (ii) The method used to determine the amount of CO2

captured.

T—Magnesium

Production

(§98.200)

25,000 metric

tons C02e/year

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

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

(3) 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.

(4) Cover and carrier gas flow rate (e.g., standard cubic feet per minute) for each production unit and composition in

percent by volume.

(5) For any missing data, 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.

(6) The annual cover gas usage rate for the facility for each cover gas, excluding the carrier gas (kg gas/metric ton Mg).

(7) 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).

(8) A description of any new melt protection technologies adopted to account for reduced or increased GHG emissions in

any given year.
Page C‐13

Subpart

Reporting

Threshold Reporting and Verification

U—Misc. Uses of

Carbonate

(§98.210)

25,000 metric

tons C02e/year

(1) Annual CO2 emissions from miscellaneous carbonate use (metric tons).

(2) Annual mass of each carbonate type consumed (tons).

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

(4) Method used to calculate emissions.  

(5) For the calculation method of 40 CFR 98.213(b)(1)(i): (i) Annual carbonate consumption by carbonate type (tons); (ii)

Annual calcination fractions used in calculations; (iii) The standard method that was used to determine the calcinations

fraction, if applicable.

(6) For the calculation method of 40 CFR 98.213(b)(1)(ii): (i) Annual carbonate input by carbonate type (tons) and

(ii) Annual carbonate output by carbonate type (tons).  

(7) Number of times in the reporting year that missing data procedures were followed to measure carbonate consumption,

carbonate input or carbonate output (months).
Page C‐14

Subpart

Reporting

Threshold Reporting and Verification

V—Nitric Acid

Production

(§98.220)

All In (1) Train identification number.

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

(3) Annual nitric acid production from each nitric acid train (tons, 100 percent acid basis).

(4) Annual nitric acid production from each nitric acid train during which N2O abatement technology is operating (ton acid

produced, 100 percent acid basis)

(5) Annual nitric acid production from the nitric acid facility (tons, 100 percent acid basis).

(6) Number of nitric acid trains.

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

(8) Abatement technologies used (if applicable).  

(9) Abatement technology destruction efficiency for each abatement technology (percent destruction).

(10) Abatement utilization factor for each abatement technology (fraction of annual production that abatement

technology is operating).

(11) Type of nitric acid process used for each nitric acid train (low, medium, high, or dual pressure).

(12) Number of times in the reporting year that missing data procedures were followed to measure nitric acid production

(months).

(13) If a performance test was conducted and site‐specific emissions factor was calculated: (i) Emission factor calculated

for each nitric acid train (lb N2O/ ton nitric acid, 100 percent acid basis); (ii) Test method used for performance test; (iii)

Production rate per test run during performance test (tons nitric acid produced/hr, 100 percent acid basis); (iv) N2O

concentration per test run during performance test (ppm N2O); (v) Volumetric flow rate per test run during performance

test (dscf/hr); (vi) Number of test runs during performance test; (vii) Number of times in the reporting year that a

performance test had to be repeated (number).

(14) If approval was requested for an alternative method of determining N2O concentration under 40 CFR 98.223(a)(2),: (i)

Name of alternative method; (ii) Description of alternative method; (iii) Request date; and (iv) Approval date.

(15) Fraction control factor for each abatement technology (percent of total emissions from the production unit that are

sent to the abatement technology) if equation V–3c is used.
Page C‐15

Subpart

Reporting

Threshold Reporting and Verification

W—Petroleum

and Natural Gas

Systems

(§98.230)

25,000 metric

tons C02e/year

Report annual emissions in metric tons of CO2e for each GHG separately for each of these industry segments:

(1) Onshore petroleum and natural gas production.

(2) Offshore petroleum and natural gas production.

(3) Onshore natural gas processing.

(4) Onshore natural gas transmission compression.

(5) Underground natural gas storage.

(6) LNG storage.

(7) LNG import and export.

(8) Natural gas distribution.

For offshore petroleum and natural gas production, report emissions of CH4, CO2, and N2O as applicable to the source

type (in metric tons CO2e per year at standard conditions) individually for all of the emissions source types listed in the

most recent BOEMRE study.

For onshore petroleum and natural gas production, report the best available estimate of API gravity, best available

estimate of gas to oil ratio, and best available estimate of average low pressure separator pressure for each oil sub‐basin

category. For onshore petroleum and natural gas production and natural gas distribution combustion emissions, report the

following: (i) Cumulative number of external fuel combustion units with a rated heat capacity equal to or less than 5

mmBtu/hr, by type of unit; (ii) Cumulative number of external fuel combustion units with a rated heat capacity larger than

5 mmBtu/hr, by type of unit; (iii) Report annual CO2, CH4, and N2O emissions from external fuel combustion units with a

rated heat capacity larger than 5 mmBtu/hr, expressed in metric tons CO2e for each gas, by type of unit; (iv) Cumulative

volume of fuel combusted in external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by fuel

type; (v) Cumulative number of internal fuel combustion units, not compressor‐drivers, with a rated heat capacity equal to

or less than 1 mmBtu/hr or 130 horsepower, by type of unit; (vi) Report annual CO2, CH4, and N2O emissions from internal

combustion units greater than 1mmBtu/hr, expressed in metric tons CO2e for each gas, by type of unit; (vii) Cumulative

volume of fuel combusted in internal combustion units with a rated heat capacity larger than 1 mmBtu/hr or 130

horsepower, by fuel type; (d) Report annual throughput as determined by engineering estimate based on best available

data for each industry segment listed in paragraphs (a)(1) through (a)(8) of this section.

For natural gas pneumatic devices, report the following: (i) Actual count and estimated count separately of natural gas

pneumatic high bleed devices as applicable; (ii) Actual count and estimated count separately of natural gas pneumatic low

bleed devices as applicable; (iii) Actual count and estimated count separately of natural gas pneumatic intermittent bleed

devices as applicable; (iv) Report annual CO2 and CH4 emissions at the facility level, expressed in metric tons CO2e for each

gas, for each of the following pieces of equipment: high bleed pneumatic devices; intermittent bleed pneumatic devices;

low bleed pneumatic devices.

For natural gas driven pneumatic pumps, report: (i) Count of natural gas driven pneumatic pumps; and (ii) Report annual

CO2 and CH4 emissions at the facility level, expressed in metric tons CO2e for each gas, for all natural gas driven pneumatic

pumps combined.

For each acid gas removal unit, report: (i) Total throughput off 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; (ii) For Calculation Methodology

1 and Calculation Methodology 2 of 40 CFR 98.233(d), annual average fraction of CO2 content in the vent from the acid gas

removal unit; (iii) For Calculation Methodology 3 of 40 CFR 98.233(d), annual average volume fraction of CO2 content of

natural gas into and out of the acid gas removal unit; (iv) Report the annual quantity of CO2, expressed in metric tons CO2e,

that was recovered from the AGR unit and transferred outside the facility, under subpart PP of this part; (v) Report annual

CO2 emissions for the AGR unit, expressed in metric tons CO2e; (vi) For the onshore natural gas processing industry

segment only, report a unique name or ID number for the AGR unit; and (vii) An indication of which calculation

methodology was used for the AGR.

For dehydrators, report: (i) For each Glycol dehydrator with a throughput greater than or equal to 0.4 MMscfd, report the

following: (A) Glycol dehydrator feed natural gas flow rate in MMscfd, determined by engineering estimate based on best

available data; (B) Glycol dehydrator absorbent circulation pump type; (C) Whether stripper gas is used in glycol

dehydrator; (D) Whether a flash tank separator is used in glycol dehydrator; (E) Type of absorbent; (F) Total time the glycol

dehydrator is operating in hours; (G) Temperature, in degrees Fahrenheit and pressure, in psig, of the wet natural gas; (H)

Concentration of CH4 and CO2 in wet natural gas; (I) What vent gas controls are used; (J) For each glycol dehydrator, report

annual CO2 and CH4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO2e for

each gas; (K) For each glycol dehydrator, report annual CO2, CH4, and N2O emissions that resulted from flaring process gas

from the dehydrator, expressed in metric tons CO2e for each gas, (L) For the onshore natural gas processing industry

segment only, report a unique name or ID number for glycol dehydrator; (ii) For all glycol dehydrators with a throughput

less than 0.4 MMscfd, report the following: (A) Count of glycol dehydrators; (B) Which vent gas controls are used; (C)

Report annual CO2 and CH4 emissions at the facility level that resulted from venting gas directly to the atmosphere,

expressed in metric tons CO2e for each gas, combined for all glycol dehydrators with annual average daily throughput of

less than 0.4 MMscfd; and (D) Report annual CO2, CH4, and N2O emissions at the facility level that resulted from the flaring

of process gas, expressed in metric tons CO2e for each gas, combined for all glycol dehydrators with annual average daily

throughput of less than 0.4 MMscfd; and (iii) For absorbent desiccant dehydrators, report the following: (A) Count of

desiccant dehydrators; (B) Report annual CO2 and CH4 emissions at the facility level, expressed in metric tons CO2e for each

gas, for all absorbent desiccant dehydrators combined.
Page C‐16

Subpart

Reporting

Threshold Reporting and Verification

W—Petroleum

and Natural Gas

Systems

(§98.230)

25,000 metric

tons C02e/year

For well venting for liquids unloading: report: (i) For Calculation Methodology 1, report the following for each tubing

diameter group and pressure group combination within each sub‐basin category: (A) Count of wells vented to atmosphere

for liquids unloading; (B) Count of plunger lifts. Whether the selected well from the tubing diameter and pressure group

combination had a plunger lift (yes/no); (C) Cumulative number of unloadings vented to the atmosphere; (D) Average flow

rate of the measured well venting in cubic feet per hour; (E) Internal casing diameter or internal tubing diameter in inches,

where applicable, and well depth of each well, in feet, selected to represent emissions in that tubing size and pressure

combination; (F) Casing pressure, in psia, of each well selected to represent emissions in that tubing size group and

pressure group combination that does not have a plunger lift; (G) Tubing pressure, in psia, of each well selected to

represent emissions in a tubing size group and pressure group combination that has plunger lift; (H) Report annual CO2

and CH4 emissions in metric tons CO2e for each gas; (ii) For Calculation Methodologies 2 and 3, report the following for

each sub‐basin category: (A) Count of wells vented to the atmosphere for liquids unloading; (B) Count of plunger lifts; (C)

Cumulative number of unloadings vented to the atmosphere; (D) Average internal casing diameter, in inches, of each well,

where applicable; and (E) Report annual CO2 and CH4 emissions, expressed in metric tons CO2e for each GHG gas.

For well completions and workovers, report the following for each sub‐basin category: (i) For gas well completions and

workovers with hydraulic fracturing by sub‐basin and well type (horizontal or vertical) combination, report the following:

(A) Total count of completions in calendar year; (B) When using Equation W–10A, measured flow rate of backflow during

well completion in standard cubic feet per hour; (C) Total count of workovers in calendar year that flare gas or vent gas to

the atmosphere; (D) When using Equation W–10A, measured flow rate of backflow during well workover in standard cubic

feet per hour; (E) When using Equation W–10A, total number of days of backflow from all wells during completions; (F)

When using Equation W–10A, total number of days of backflow from all wells during workovers; (G) Report number of

completions employing purposely designed equipment that separates natural gas from the backflow and the amount of

natural gas, in standard cubic feet, recovered using engineering estimate based on best available; (H) Report number of

workovers employing purposely designed equipment that separates natural gas from the backflow and the amount of

natural gas, in standard cubic feet, recovered using engineering estimate based on best available data; (I) Annual CO2 and

CH4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO2e for each gas; and

(J) Annual CO2, CH4, and N2O emissions that resulted from flares, expressed in metric tons CO2e for each gas; and (ii) For

gas well completions and workovers without hydraulic fracturing: (A) Total count of completions in calendar year; (B) Total

count of workovers in calendar year that flare gas or vent gas to the atmosphere; (C) Total number of days of gas venting

to the atmosphere during backflow for completion; (D) Annual CO2 and CH4 emissions that resulted from venting gas

directly to the atmosphere, expressed in metric tons CO2e for each gas; and (E) Annual CO2, CH4, and N2O emissions that

resulted from flares, expressed in metric tons CO2e for each gas.

For blowdown vent stack emission source: report the following: (i) For each unique physical volume that is blown down

more than once during the calendar year, report the following: (A) Total number of blowdowns for each unique physical

volume in the calendar year; (B) Annual CO2 and CH4 emissions, for each unique physical blowdown volume, expressed in

metric tons CO2e for each gas; (C) A unique name or ID number for the unique physical volume; (ii) For all unique volumes

that are blown down once during the calendar year, report the following: (A) Total number of blowdowns for all unique

physical volumes in the calendar year; (B) Annual CO2 and CH4 emissions from all unique physical volumes as an aggregate

per facility, expressed in metric tons CO2e for each gas.
Page C‐17

Subpart

Reporting

Threshold Reporting and Verification

W—Petroleum

and Natural Gas

Systems

(§98.230)

25,000 metric

tons C02e/year

For gas emitted from produced oil sent to atmospheric tanks: (i) For wellhead gas‐liquid separator with oil throughput

greater than or equal to 10 barrels per day, using Calculation Methodology 1 and 2 of 40 CFR 98.233(j), report the

following by sub‐basin category, unless otherwise specified: (A) Number of wellhead separators sending oil to atmospheric

tanks; (B) Estimated average separator temperature, in degrees Fahrenheit, and estimated average pressure, in psig; (C)

Estimated average sales oil stabilized API gravity, in degrees; (D) Count of hydrocarbon tanks at well pads; (E) Best estimate

of count of stock tanks not at well pads receiving oil; (F) Total volume of oil from all wellhead separators sent to tank(s) in

barrels per year; (G) Count of tanks with emissions control measures, either vapor recovery system or flaring, for tanks at

well pads; (H) Best estimate of count of stock tanks assumed to have emissions control measures not at well pads,

receiving oil; (I) Range of concentrations of flash gas, CH4 and CO2; (J) Annual CO2 and CH4 emissions that resulted from

venting gas to the atmosphere, expressed in metric tons CO2e for each gas, for all wellhead gas‐liquid separators or

storage tanks using Calculation Methodology 1, and for all wellhead gas‐liquid separators or storage tanks using

Calculation Methodology 2 of 40 CFR 98.233(j); (K) Annual CO2 and CH4 gas quantities that were recovered, expressed in

metric tons CO2e for each gas, for all wellhead gas‐liquid separators or storage tanks using Calculation Methodology 1, and

for all wellhead gas‐liquid separators or storage tanks using Calculation Methodology 2 of 40 CFR 98.233(j); (L) Annual

CO2,CH4,and N2O emissions that resulted from flaring gas, expressed in metric tons CO2e for each gas, for all wellhead gas‐

liquid separators or storage tanks using Calculation Methodology 1, and for all wellhead gas‐liquid separators or storage

tanks using Calculation Methodology 2 of 40 CFR 98.233(j); (ii) For wells with oil production greater than or equal to 10

barrels per day, using Calculation Methodology 3 and 4 of 40 CFR 98.233(j), report the following by sub‐basin category: (A)

Total volume of sales oil from all wells in barrels per year; (B) Total number of wells sending oil directly to tanks; (C) Total

number of wells sending oil to separators off the well pads; (D) Sales oil API gravity range for wells in (c)(8)(ii)(B) and

(c)(8)(ii)(C) of this section, in degrees; (E) Count of hydrocarbon tanks on wellpads; (F) Count of hydrocarbon tanks, both on

and off well pads assumed to have emissions control measures: either vapor recovery system or flaring of tank vapors; (G)

Annual CO2 and CH4 emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO2e for each

gas, at the sub‐basin level for Calculation Methodology 3 or 4 of 40 CFR 98.233(j); (H) Annual CO2 and CH4 gas quantities

that were recovered, expressed in metric tons CO2e for each gas, at the sub‐basin level for Calculation Methodology 3 or 4

of 40 CFR 98.233(j); (I) Annual CO2,CH4,and N2O emissions that resulted from flaring gas, expressed in metric tons CO2e

for each gas, at the sub‐basin level for Calculation Methodology 3 and 4 of 40 CFR 98.233(j); (iii) For wellhead gas‐liquid

separators and wells with throughput less than 10 barrels per day, using Calculation Methodology 5 of 40 CFR 98.233(j)

Equation W–15 of 40 CFR 98.233, report the following: (A) Number of wellhead separators; (B) Number of wells without

wellhead separators; (C) Total volume of oil production in barrels per year; (D) Best estimate of fraction of production sent

to tanks with assumed control measures: either vapor recovery system or flaring of tank vapors; (E) Count of hydrocarbon

tanks on well pads; (F) Annual CO2 and CH4 emissions that resulted from venting gas to the atmosphere, expressed in

metric tons CO2e for each gas, at the sub‐basin level for Calculation Methodology 5 of 40 CFR 98.233(j); (G) Annual CO2

and CH4 gas quantities that were recovered, expressed in metric tons CO2e for each gas, at the sub‐basin level for

Calculation Methodology 5 of 40 CFR 98.233(j); (H) Annual CO2,CH4,and N2O emissions that resulted from flaring gas,

expressed in metric tons CO2e for each gas, at the sub‐basin level for Calculation Methodology 5 of 40 CFR 98.233(j); (iv) If

wellhead separator dump valve is functioning improperly during the calendar year, report the following: (A) Count of

wellhead separators that dump valve factor is applied; (B) Annual CO2 and CH4 emissions that resulted from venting gas to

the atmosphere, expressed in metric tons CO2e for each gas, at the sub‐basin level for improperly functioning dump valves.

For transmission tank emissions identified using optical gas imaging instrument or acoustic leak detection of scrubber

dump valves: report the following: (i) For each vent stack, report annual CO2 and CH4 emissions that resulted from venting

gas directly to the atmosphere, expressed in metric tons CO2e for each gas; (ii) For each transmission storage tank, report

annual CO2, CH4, and N2O emissions that resulted from flaring process gas from the transmission storage tank, expressed in

metric tons CO2e for each gas; (iii) A unique name or ID number for the vent stack monitored according to 40 CFR

98.233(k).

For well testing venting and flaring, report the following: (i) Number of wells tested per basin in calendar year; (ii) Average

gas to oil ratio for each basin; (iii) Average number of days the well is tested in a basin; (iv) Report annual CO2 and CH4

emissions at the facility level, expressed in metric tons CO2e for each gas, emissions from well testing venting; (v) Report

annual CO2,CH4,and N2O emissions at the facility level, expressed in metric tons CO2e for each gas, emissions from well

testing flaring.

For associated natural gas venting and flaring: report the following for each basin: (i) Number of wells venting or flaring

associated natural gas in a calendar year; (ii) Average gas to oil ratio for each basin; (iii) Report annual CO2 and CH4

emissions at the facility level, expressed in metric tons CO2e for each gas, emissions from associated natural gas venting;

(iv) Report annual CO2,CH4,and N2O emissions at the facility level, expressed in metric tons CO2e for each gas, emissions

from associated natural gas flaring.

For flare stacks: report the following for each flare: (i) Whether flare has a continuous flow monitor; (ii) Volume of gas sent

to flare in cubic feet per year; (iii) Percent of gas sent to un‐lit flare determined by engineering estimate and process

knowledge based on best available data and operating records; (iv) Whether flare has a continuous gas analyzer; (v) Flare

combustion efficiency; (vi) Report uncombusted CH4 emissions, in metric tons CO2e; (vii) Report uncombusted CO2

emissions, in metric tons CO2e ); (viii) Report combusted CO2 emissions, in metric tons CO2e ; (ix) Report N2O emissions, in

metric tons CO2e; (x) For the natural gas processing industry segment, a unique name or ID number for the flare stack; (xi)

In the case that a CEMS is used to measure CO2 emissions for the flare stack, indicate that a CEMS was used in the annual

report and report the combusted CO2 and uncombusted CO2 as a combined number.
Page C‐18

Subpart

Reporting

Threshold Reporting and Verification

W—Petroleum

and Natural Gas

Systems

(§98.230)

25,000 metric

tons C02e/year

For each centrifugal compressor: (i) For compressors with wet seals in operational mode, report the following for each

degassing vent: (A) Number of wet seals connected to the degassing vent; (B) Fraction of vent gas recovered for fuel or

sales or flared; (C) Annual throughput in million scf, use an engineering calculation based on best available data; (D) Type

of meters used for making measurements; (E) Reporter emission factor for wet seal oil degassing vents in cubic feet per

hour; (F) Total time the compressor is operating in hours; (G) Report seal oil degassing vent emissions for compressors

measured and for compressors not measured; (ii) For wet and dry seal centrifugal compressors in operating mode, report

the following: (A) Total time in hours the compressor is in operating mode; (B) Reporter emission factor for blowdown

vents in cubic feet per hour; (C) Report blowdown vent emissions when in operating mode. (iii) For wet and dry seal

centrifugal compressors in not operating, depressurized mode, report the following: (A) Total time in hours the

compressor is in shutdown, depressurized mode; (B) Reporter emission factor for isolation valve emissions in shutdown,

depressurized mode in cubic feet per hour; (C) Report the isolation valve leakage emissions in not operating, depressurized

mode in cubic feet per hour; (iv) Report total annual compressor emissions from all modes of operation; (v) For centrifugal

compressors in onshore petroleum and natural gas production refer to Equation W–25 of 40 CFR 98.233), report the

following: (A) Count of compressors; (B) Report emissions collectively.

For reciprocating compressors: (i) For reciprocating compressors rod packing emissions with or without a vent in operating

mode, report the following: (A) Annual throughput in million scf, use an engineering calculation based on best available

data; (B) Total time in hours the reciprocating compressor is in operating mode; (C) Report rod packing emissions for

compressors measured and for compressors not measured; (ii) For reciprocating compressors blowdown vents not

manifold to rod packing vents, in operating and standby pressurized mode , report the following: (A) Total time in hours

the compressor is in standby, pressurized mode; (B) Reporter emission factor for blowdown vents in cubic feet per hour;

(C) Report blowdown vent emissions when in operating and standby pressurized modes; (iii) For reciprocating compressors

in not operating, depressurized mode, report the following: (A) Total time the compressor is in not operating,

depressurized mode; (B) Reporter emission factor for isolation valve emissions in not operating, depressurized mode in

cubic feet per hour; (C) Report the isolation valve leakage emissions in not operating, depressurized mode; (iv) Report total

annual compressor emissions from all modes of operation; (v) For reciprocating compressors in onshore petroleum and

natural gas production, report the following: (A) Count of compressors; (B) Report emissions collectively.

For each component type (major equipment type for onshore production) that uses emission factors for estimating

emissions: (i) For equipment leaks found in each leak survey, report the following: (A) Total count of leaks found in each

complete survey listed by date of survey and each component type for which there is a leaker emission factor in Tables W–

2, W–3, W–4, W–5, W–6, and W–7 of subpart W; (B) For onshore natural gas processing, range of concentrations of

CH4and CO2; (C) Annual CO2 and CH4 emissions, in metric tons CO2e for each gas, by component type.

For local distribution companies: report the following: (i) Total number of above grade T–D transfer stations in the facility;

(ii) Number of years over which all T–D transfer stations will be monitored at least once; (iii) Number of T–D stations

monitored in calendar year; (iv) Total number of below grade T–D transfer stations in the facility; (v) Total number of

above grade metering‐regulating stations (this count will include above grade T–D transfer stations) in the facility; (vi) Total

number of below grade metering‐regulating stations (this count will include below grade T–D transfer stations) in the

facility; (vii) [Reserved]; (viii) Leak factor for meter/regulator run developed in Equation W–32 of 40 CFR 98.233; (ix)

Number of miles of unprotected steel distribution mains; (x) Number of miles of protected steel distribution mains; (xi)

Number of miles of plastic distribution mains; (xii) Number of miles of cast iron distribution mains; (xiii) Number of

unprotected steel distribution services; (xiv) Number of protected steel distribution services; (xv) Number of plastic

distribution services; (xvi) Number of copper distribution services; (xvii) Annual CO2 and CH4 emissions, in metric tons CO2e

for each gas, from all above grade T–D transfer stations combined; (xviii) Annual CO2 and CH4 emissions, in metric tons

CO2e for each gas, from all below grade T–D transfer stations combined; (xix) Annual CO2 and CH4 emissions, in metric tons

CO2e for each gas, from all above grade metering‐regulating stations (including T–D transfer stations) combined; (xx)

Annual CO2 and CH4 emissions, in metric tons CO2e for each gas, from all below grade metering‐regulating stations

(including T–D transfer stations) combined; (xxi) Annual CO2 and CH4 emissions, in metric tons CO2e for each gas, from all

distribution mains combined; and (xxii) Annual CO2 and CH4 emissions, in metric tons CO2e for each gas, from all

distribution services combined.

For each EOR injection pump blowdown: report the following: (i) Pump capacity, in barrels per day; (ii) Volume of critical

phase gas between isolation valves; (iii) Number of blowdowns per year; (iv) Critical phase EOR injection gas density; (v)

For each EOR pump, report annual CO2 and CH4 emissions, expressed in metric tons CO2e for each gas.

For EOR hydrocarbon liquids dissolved CO2 for each sub‐basin category: report the following: (i) Volume of crude oil

produced in barrels per year; (ii) Amount of CO2 retained in hydrocarbon liquids in metric tons per barrel, under standard

conditions; and (iii) Report annual CO2 emissions at the sub‐basin level, expressed in metric tons CO2e.
Page C‐19

Subpart

Reporting

Threshold Reporting and Verification

X—Petrochemical

Production

(§98.240)

All In For mass balance:

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 other products, and names of carbon‐containing feedstocks.

(3) Annual CO2 emissions calculated using Equation X‐4 of subpart X.

(4) Each of the monthly volume, mass, and carbon content values used in Equations X‐1 through X‐3 (i.e., the directly

measured values, substitute values, or the calculated values based on other measured data such as tank levels or gas

composition), the molecular weights for gaseous feedstocks and products used in Equation X‐1, and the temperature (in

°F) at which the gaseous feedstock and product volumes used in Equation X–1 of subpart X were determined. Plus an

indication of whether alternative sampling analysis was used.  

(5) Annual quantity of each type of petrochemical produced from each process unit (metric tons).

(6) Name of each method listed in 40 CFR 98.244 used to determine a measured parameter (or description of

manufacturer’s recommended method).

(7)Identification of each combustion unit that burned both process off‐gas and supplemental fuel.

(8) For the alternative to sampling and analysis: The amount of time during which off‐specification product was produced,

the volume or mass of off‐specification product produced, and if applicable, the date of any process change that reduced

the composition to less than 99.5 percent.

(9) Respondents may elect to report the flow and carbon content of wastewater and 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.

(10) If carbon content or composition of a feedstock or product is determined using a method under 40 CFR

98.244(b)(4)(xv)(B), report the following 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 40 CFR 98.244(b)(4)(i) through (xiv), 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 40 CFR 98.244(b)(4)(i) through (xii) is

needed.

If emissions are measured in accordance with 40 CFR 98.243(b):  

(1) The petrochemical process unit ID or other appropriate descriptor, and the type of petrochemical produced.

(2) For CEMS used on stacks for stationary combustion units, report the relevant information required under 40 CFR 98.36

for the Tier 4 calculation methodology. Section 98.36(b)(9)(iii) does not apply for the purposes of subpart X.

(3) For CEMS used on stacks that are not used for stationary combustion units, report the information required under 40

CFR 98.36(e)(2)(vi).

(2) The combined CO2 emissions from each stack and the combined CO2 emissions from all stacks (except flare stacks) that

handle process vent emissions and emissions from stationary combustion units that burn process off‐gas for the

petrochemical process unit. For each stationary combustion unit (or group of combustion units monitored with a single

CO2CEMS) that burns petrochemical 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 petrochemical process unit.

(3) For stationary combustion units that burn process off‐gas from the petrochemical process unit, report the information

related to CH4 and N2O emissions as specified in paragraphs (b)(5)(i) through (b)(5)(iv) of this section.

(4) ID or other appropriate descriptor of each stationary combustion unit that burns process off‐gas.

(5) Information listed in 40 CFR 98.256(e) of subpart Y for each flare that burns process off‐gas.

(6) Annual quantity of each type of petrochemical produced from each process unit (metric tons).  

For the combustion methodology (40 CFR 98.243(d)):

(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 40 CFR 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 40 CFR 98.256(e) of subpart Y for each flare that burns ethylene process off‐gas.

(4) Name and annual quantity of each feedstock.

(5) Annual quantity of each type of petrochemical produced from each process unit (metric tons).
Page C‐20

Subpart

Reporting

Threshold Reporting and Verification

Y—Petroleum

Refineries  

(§98.250)

All In Combustion Sources: See reporting requirements for General Stationary Fuel Combustion Sources (subpart C).

Hydrogen plants : See reporting requirements for Hydrogen Production (subpart P).

Flares:

(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 Equation Y‐1a of subpart Y was used: 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), the molar

volume conversion factor (in scf/kg‐mole), and annual average carbon content of the flare gas (in kg carbon per kg flare

gas).  

(7) If Equation Y‐1b of subpart Y was used: an indication of whether daily or weekly measurement periods are used, the

annual volume of flare gas combusted (in scf/year), the molar volume conversion factor (in scf/kg‐mole), 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) and (ii) The carbon mole number of the compound

(moles carbon per mole compound).

(8) If Equation Y‐2 of subpart Y was used: 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 Equation Y‐3 of subpart Y was used: The annual volume of flare gas combusted (in MMscf/year) during normal

operations, the annual average higher heating value of the flare gas (in MMBtu/MMscf), the number of SSM events

exceeding 500,000 scf/day, and the volume of gas flared (in scf/event) and the average molecular weight (in kg/kg‐mole),

the molar volume conversion factor (in scf/kg‐mole), and carbon content of the flare gas (in kg carbon per kg flare) for

each SSM event over 500,000 scf/day.  

(9) The fraction of carbon in the flare gas contributed by methane used in Equation Y‐4 of subpart Y and the basis for its

value.

For catalytic cracking units, traditional fluid coking units, and catalytic reforming units:

(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 a CEMS was used: the relevant information required under 40 CFR 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 40 CFR 98.253(c)(1)(ii). Respondents

must report the CO2 annual emissions associated with sources other than those from the coke burn‐off in the applicable

subpart (e.g., subpart C of this part in the case of a CO boiler).  

(7) If Equation Y‐6 of subpart Y was used: The annual average exhaust gas flow rate, %CO2, %CO, and the molar volume

conversion factor (in scf/kg‐mole).

(8) If Equation Y‐7a of subpart Y was used: The annual average flow rate of inlet air and oxygen‐enriched air, %O2, %Ooxy,

%CO2, and %CO.  

(9) If Equation Y‐7b of subpart Y was used: The annual average flow rate of inlet air and oxygen‐enriched air, %N2,oxy, and

%N2,exhaust.

(10) If Equation Y‐8 of subpart Y was used: The coke burn‐off factor, annual throughput of unit, and the average carbon

content of coke and the basis for the value.

(11) An indication of whether a measured value, a unit‐specific emission factor, or default emission factor was used for CH4

emissions. If unit‐specific emission factors for CH4 are used, respondents must report the the unit‐specific emission factor

for CH4, units of measure for the unit‐specific factor, the activity data for calculating emissions (e.g., if the emission factor

is based on coke burn‐off rate, the annual quantity of coke burned), and the basis for the factor.

(12) An indication of whether a measured value, a unit‐specific emission factor, or default emission factor was used for

N2O emissions. If a unit‐specific emission factor was used: The unit‐specific emission factor for N2O, The units of measure

for the unit‐specific factor, the activity data for calculating emissions (e.g., if the emission factor is based on coke burn‐off

rate, the annual quantity of coke burned), and the basis for the factor.  

(13) If Equation Y‐11 of subpart Y was used: The number of regeneration cycles or measurement periods during the

reporting year, the average coke burn‐off quantity per cycle or measurement period, and the average carbon content of

the coke.  
Page C‐21

Subpart

Reporting

Threshold Reporting and Verification

Y—Petroleum

Refineries  

(§98.250)

(continued)

All in Fluid coking unit of the flexicoking type:

(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 40 CFR

98.253(c).  

(5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit: 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 (7) through (13) above.  

For sulfur recovery plants and emissions from sour gas sent off‐site for sulfur recovery:

(1) The plant ID number (if applicable).

(2) Maximum rated throughput of each independent sulfur recovery plant, in 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 40 CFR 98.253(j)).

(3) The calculated CO2 annual emissions for each sulfur recovery plant, expressed in metric tons. Plus the calculated annual

CO2 emissions from sour gas sent off‐site for sulfur recovery, expressed in metric tons.

(4) If Equation Y‐12 of subpart Y was used: The annual volumetric flow to the sulfur recovery plant (in scf/year), the molar

volume conversion factor (in scf/kg‐mole), and the annual average mole fraction of carbon in the sour gas (in kg‐mole

C/kg‐mole gas).

(5) If tail gas is recycled to the front of the sulfur recovery plant: An indication of whether the recycled flow rate and

carbon content are included in the measured data under 40 CFR 98.253(f)(2) and (3). Also an indication of whether a

correction for CO2 emissions in the tail gas was used in Equation Y‐12. If so, then respondents must report the value of the

correction, the annual volume of recycled tail gas (in scf/year), and the annual average mole fraction of carbon in the tail

gas (in kg‐mole C/kg‐mole gas). Respondents must also indicate whether they used the default (95%) or a unit specific

correction, and if used, report the approach used.

(6) For a CEMS: the relevant information required under 40 CFR 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 40 CFR

98.253(f)(1). Plus the CO2 annual emissions associated with the process emissions calculated according to 40 CFR

98.253(f)(1). Plus the CO2 annual emissions associated with fuel combustion under 40 CFR 98, subpart C.

(7) If the process vent method is used in 40 CFR 98.253(j) for a non‐Claus sulfur recovery plant, the relevant information

required under paragraph (l)(5) of this section.

For coke calcining units:

(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 Equation Y‐13 of subpart Y is used: Annual mass and carbon content of green coke fed to the unit, the annual mass

and carbon content of marketable coke produced, the annual mass of coke dust collected in dust collection systems, and

and 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 a CEMS is used: the relevant information required under 40 CFR 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 40 CFR

98.253(g)(1).

(7) An indication of whether a measured value, a unit‐specific emission factor or a default for CH4 emissions was used. If a

unit‐specific emission factor for CH4, is used: the unit‐specific emission factor for CH4, the units of measure for the unit‐

specific factor, the activity data for calculating emissions (e.g., if the emission factor is based on coke burn‐off rate, the

annual quantity of coke burned), and the basis for the factor.

(8) An indication of whether a measured value, a unit‐specific emission factor, or a default emission factor was used for

N2O emissions. If a unit‐specific emission factor for N2O is used, report the unit‐specific emission factor for N2O, the units

of measure for the unit‐specific factor, the activity data for calculating emissions (e.g., if the emission factor is based on

coke burn‐off rate, the annual quantity of coke burned), and the basis for the factor.

For asphalt blowing operations:

(1) The unit ID number (if applicable).

(2) The quantity of asphalt blown (in million bbl) at the unit in the reporting year.

(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 Equation Y‐14 of subpart Y is used: The CO2 emission factor used and the basis for the value.  

(6) If Equation Y‐15 of subpart Y is used: The CH4 emission factor used and the basis for the value.

(7) If Equation Y‐16 of subpart Y is used: The carbon emission factor used and the basis for the value.  

(8) If Equation Y‐16b of subpart Y is used: The CO2 emission factor used and the basis for its value and the carbon emission

factor used and the basis for its value.

(9) If Equation Y‐17 of subpart Y is used: The CH4 emission factor used and the basis for the value.
Page C‐22

Subpart

Reporting

Threshold Reporting and Verification

Y—Petroleum

Refineries  

(§98.250)

(continued)

All in For delayed coking units:

(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 dimensions, the typical gauge pressure of the coking drum when first vented to the

atmosphere, typical void fraction, the typical drum outage (i.e. the unfilled distance from the top of the drum, in feet), the

molar volume conversion factor (in scf/kg‐mole), and annual number of coke‐cutting cycles.

(4) For each set of coking drums that are the same dimensions: the number of coking drums in the set, the height and

diameter of the coke drums (in feet), the cumulative number of vessel openings for all delayed coking drums in the set, the

typical venting pressure (in psig), void fraction (in cf gas/cf of vessel), and the mole fraction of methane in coking gas (in

kg‐mole CF4/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.

For process vents subject to 40 CFR 98.253(j):

(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, the molar volume conversion factor (in scf/kg‐

mole), and for intermittent vents, the number of venting events and the cumulative venting time.

For uncontrolled blowdown systems:

(1) An indication of whether the uncontrolled blowdown emission are reported under 40 CFR 98.253(k) or 40 CFR 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 40 CFR 98.253(k), the total quantity (in million bbl) of crude oil

plus the quantity of intermediate products received from off site that are processed at the facility in the reporting year,

the methane emission factor used for uncontrolled blowdown systems, the basis for the value, and the molar volume

conversion factor (in scf/kg‐mole).

(4) For uncontrolled blowdown systems reporting under 40 CFR 98.253(j), the relevant information required under

paragraph (l)(5) of this section.

For equipment leaks:

(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 at the facility.

For storage tanks:

(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 40 CFR 98.7), or Equation Y–22 of this section) and (ii) The total quantity (in MMbbl) of

crude oil plus the quantity of intermediate products received from off site that are processed at the facility in the reporting

year.

(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) The quantity of unstabilized crude oil received during the calendar year (in MMbbl), (iii) The

average pressure differential (in psi), (iv) The molar volume conversion factor (in scf/kg‐mole), (v) The average mole

fraction of CH4 in vent gas from unstabilized crude oil storage tanks and the basis for the mole fraction, and (vi) If Equation

Y‐23 was not used, the tank‐specific methane composition data and the gas generation rate data used to estimate the

cumulative CH4 emissions for storage tanks used to process unstabilized crude oil.

(5) The method used to calculate the reported storage tank emissions for storage tanks processing unstabilized crude oil.

(6) The quantity of unstabilized crude oil received during the calendar year (in MMbbl), the average pressure differential

(in psi), and the mole fraction of CH4 in vent gas from the unstabilized crude oil storage tank, and the basis for the mole

fraction.

(7) The tank‐specific methane composition data and the gas generation rate data, if Equation Y–23 was not used.

For loading operations:

(1) The cumulative annual CH4 emissions (in metric tons of each pollutant emitted) for loading operations.  

(2) The quantity and types of materials loaded by vessel type (barge, tanker, marine vessel, etc.) that have an equilibrium

vapor‐phase concentration of methane of 0.5 volume percent or greater, and the type of vessels in which the 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.).
Page C‐23

Subpart

Reporting

Threshold Reporting and Verification

Y—Petroleum

Refineries  

(§98.250)

(continued)

All in For all: Name of each method listed in 40 CFR 98.254 or a description of the manufacturer’s recommended method used

determine a measured parameter.

Z—Phosphoric

Acid Production

(§98.260)

All In All:

(1) Annual phosphoric acid production by origin (as listed in Table Z‐1 to subpart Z) of the phosphate rock (tons).

(2) Annual phosphoric acid permitted production capacity (tons).

(3) Annual arithmetic average percent inorganic carbon or carbon dioxide in phosphate rock from monthly records

(percent by weight, expressed as a decimal fraction).

(4) Annual phosphate rock consumption from monthly measurement records by origin (as listed in Table Z‐1 to subpart Z)

(tons).

If a CEMS is used to measure CO2 emissions:  

(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.

If a CEMS is not used to measure CO2 emissions:

(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 Eq. Z‐1a

or Equation Z‐1b of subpart Z.

(3) Annual phosphoric acid permitted production capacity (tons) for each wet‐process phosphoric acid process line (metric

tons).

(4) Method used to estimate any missing values of inorganic carbon or carbon dioxide content of phosphate rock for each

wet‐process phosphoric acid process line.

(5) Monthly inorganic carbon content of phosphate rock for each wet‐process phosphoric acid process line for which

Equation Z‐1a is used (percent by weight, expressed as a decimal fraction), or CO2 (percent by weight, expressed as a

decimal fraction) for which Equation Z‐1b is used.

(6) Monthly mass of phosphate rock consumed by origin, (as listed in Table Z‐1 to subpart Z) in production for each wet‐

process phosphoric acid process line (tons).

(7) Number of wet‐process phosphoric acid process lines.

(8) Number of times missing data procedures were used to estimate phosphate rock consumption (months) and inorganic

carbon contents of the phosphate rock (months).

(9) Annual process CO2 emissions from phosphoric acid production facility (metric tons).

AA—Pulp and

Paper

Manufacturing

(§98.270)

25,000 metric

tons

C02e/year

(1) Annual emissions of CO2, biogenic CO2, CH4, biogenic CH4N2O, and biogenic N2O (metric tons per year).

(2) Annual quantities fossil fuels by type used in chemical recovery furnaces and chemical recovery combustion units in

short tons for solid fuels, gallons for liquid fuels and scf for gaseous fuels.

(3) Annual mass of the spent liquor solids combusted (short tons per year), and 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 40 CFR 98.7) or an online measurement system).

(4) The high heat value (HHV) of the spent liquor solids used in Equation AA‐1 of subpart AA (mmBtu per kilogram).

(5) The default or site‐specific emission factor for CO2, CH4, or N2O, used in Equation AA‐1 of subpart AA (kg CO2, CH4, or

N2O per mmBtu).

(6) The carbon content (CC) of the spent liquor solids, used in equation AA‐2 of subpart AA (percent by weight, expressed

as a decimal fraction, e.g., 95% = 0.95).

(7) Annual quantities of fossil fuels by type used in pulp mill lime kilns in short tons for solid fuels, gallons for liquid fuels

and scf for gaseous fuels.

(8) Make‐up quantity of CaCO3 used for the reporting year (metric tons per year) used in Equation AA‐3 of subpart AA.  

(9) Make‐up quantity of Na2CO3 used for the reporting year (metric tons per year) used in Equation AA‐3 of subpart AA.

(10) Annual steam purchases (pounds of steam per year).

(11) Annual production of pulp and/or paper products produced (metric tons).

BB—Silicon

Carbide

Production

(§98.280)

All In If a CEMS is used to measure CO2 emissions:

All relevant information required under 40 CFR 98.36 for the Tier 4 Calculation Methodology plus:

(1) Annual consumption of petroleum coke (tons).  

(2) Annual production of silicon carbide (tons).

(3) Annual production capacity of silicon carbide (tons).

If a CEMS is not used to measure process CO2 emissions:

(1) Monthly consumption of petroleum coke (tons).  

(2) Annual production of silicon carbide (tons).

(3) Annual production capacity of silicon carbide (tons).

(4) Carbon content factor of petroleum coke from the supplier or as measured by the applicable method in 98.284(c) for

each month (percent by weight expressed as a decimal fraction).

(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) CO2 emissions factor calculated for each month (metric tons CO2/metric ton of petroleum coke consumed).

(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).
Page C‐24

Subpart

Reporting

Threshold Reporting and Verification

CC—Soda Ash

Manufacturing

(§98.290)

All in If a CEMS is used to measure CO2 emissions:

All relevant information required under 40 CFR 98.36 plus:

(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.

If a CEMS is not used to measure CO2 emissions:  

(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) Monthly consumption of trona or liquid alkaline feedstock for each manufacturing line (tons).

(6) Monthly production of soda ash for each manufacturing line (tons).

(7) Inorganic carbon content factor of trona or soda ash (depending on use of Eq. CC‐1 or CC‐2) as measured by the

applicable method in 40 CFR 98.294(b) or (c) for each month (percent by weight expressed as a decimal fraction).

(8) Whether CO2 emissions for each manufacturing line were calculated using a trona input method as described in

Equation CC‐1, a soda ash output method as described in Equation CC‐2, or a site‐specific emission factor method as

described in Equations CC‐3 through CC‐5.

(9) Number of manufacturing lines located used to produce soda ash.

(10) For soda ash produced using the liquid alkaline feedstock process, if the site‐specific emission factor method is used to

estimate emissions: (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 stripper/evaporator (thousand pounds/hour); and (vii) Annual operating hours for each manufacturing line used

to produce soda ash using liquid alkaline feedstock (hours).

(11) Number of times missing data procedures were used and for which of the following parameters: (i) Trona or soda ash

(number of months); (ii) Inorganic carbon contents of trona or soda ash (weeks); or (iii) Process vent flow rate from mine

water stripper/evaporator (number of months)

DD – Electrical

Transmission and

Distribution

Equipment Use

(§98.300)

Electrical

transmission

and

distribution

equipment

use at facilities

where the

total

nameplate

capacity of

SF6and PFC

containing

equipment

exceeds

17,820 pounds

(1) Nameplate capacity of equipment (pounds) containing SF6and nameplate capacity of equipment (pounds) containing

each PFC: (i) Existing at the beginning of the year (excluding hermetically sealed‐pressure switchgear); (ii) New during the

year (all SF6‐insulated equipment, including hermetically sealed‐pressure switchgear); and (iii) Retired during the year (all

SF6‐insulated equipment, including hermetically sealed‐pressure switchgear).

(2) Transmission miles (length of lines carrying voltages above 35 kilovolt).

(3) Distribution miles (length of lines carrying voltages at or below 35 kilovolt).

(4) Pounds of SF6and PFC stored in containers, but not in energized equipment, at the beginning of the year.

(5) Pounds of SF6 and PFC stored in containers, but not in energized equipment, at the end of the year.

(6) Pounds of SF6and PFC purchased in bulk from chemical producers or distributors.

(7) Pounds of SF6and PFC purchased from equipment manufacturers or distributors with or inside equipment, including

hermetically sealed‐pressure switchgear.

(8) Pounds of SF6and PFC returned to facility after off‐site recycling.

(9) Pounds of SF6and PFC in bulk and contained in equipment sold to other entities.

(10) Pounds of SF6and PFC returned to suppliers.

(11) Pounds of SF6and PFC sent off‐site for recycling.

(12) Pounds of SF6and PFC sent off‐site for destruction.
Page C‐25

Subpart

Reporting

Threshold Reporting and Verification

EE—Titanium

Dioxide

Production

(§98.310)

All In If a CEMS is used to measure CO2 emissions:

All relevant information required under 40 CFR 98.37(e)(2)(vi) for the Tier 4 Calculation Methodology plus:

(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 (tones).

(5) Annual production of carbon‐containing waste (tons), if applicable.

If a CEMS is not used to measure CO2 emissions:  

(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) Calcined petroleum coke consumption for each process line for each month (tons).

(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) Monthly carbon content factor of petroleum coke (percent by weight expressed as a decimal fraction).

(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 40 CFR

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).

FF – Underground

Coal Mines

(§98.320)

Underground

coal mines

liberating

36,500,000

actual cubic

feet of CH4 or

more per year

(1) Quarterly CH4 liberated from each ventilation monitoring point (CH4Vm), (metric tons CH4).

(2) Weekly CH4 liberated from each degasification system monitoring point (metric tons CH4).

(3) Quarterly CH4 destruction at each ventilation and degasification system destruction device or point of offsite transport

(metric tons CH4).

(4) Quarterly CH4 emissions (net) from all ventilation and degasification systems (metric tons CH4).

(5) 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).

(6) Quarterly volumetric flow rate for each ventilation monitoring point (scfm), date and location of each measurement,

and method of measurement (quarterly sampling or continuous monitoring), used in Equation FF–1 of subpart FF.

(7) Quarterly CH4 concentration for each ventilation monitoring point, dates and locations of each measurement and

method of measurement (sampling or continuous monitoring).

(8) Weekly volumetric flow rate used to calculate CH4 liberated from degasification systems (cfm) and method of

measurement (sampling or continuous monitoring), used in Equation FF–3 of subpart FF.

(9) Quarterly CEMS CH4 concentration (%) used to calculate CH4 liberated from degasification systems (average from daily

data), or quarterly CH4 concentration data based on results from weekly sampling data).

(10) Weekly volumetric flow rate used to calculate CH4 destruction for each destruction device and each point of offsite

transport (cfm).

(11) Weekly CH4 concentration (%) used to calculate CH4 flow to each destruction device and each point of offsite

transport.

(12) Dates in quarterly reporting period where active ventilation of mining operations is taking place.

(13) Dates in quarterly reporting period where degasification of mining operations is taking place.

(14) Dates in quarterly reporting period when continuous monitoring equipment is not properly functioning, if applicable.

(15) Temperatures (°R), pressure (atm), and moisture content used in Equation FF–1 and FF–3 of subpart FF, and the

gaseous organic concentration correction factor, if Equation FF–9 was required.

(16) 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).

(17) 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.

(18) Identification information and description for each well and shaft, indication of whether the well or shaft is monitored

individually, or as part of a centralized monitoring point. Note which method (sampling or continuous monitoring) was

used.

(19) For each centralized monitoring point, identification of the wells and shafts included in the point. Note which method

(sampling or continuous monitoring) was used.
Page C‐26

Subpart

Reporting

Threshold Reporting and Verification

GG—Zinc

Production

(§98.330)

25,000 metric

tons C02e/year

If a CEMS is used to measure CO2 emissions:

All relevant information required under 40 CFR 98.36 for the Tier 4 Calculation Methodology plus:

(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.

If a CEMS is not used to measure CO2 emissions:

(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) Annual mass of each carbon‐containing input material charged to each kiln or furnace (including zinc bearing material,

flux materials (e.g., limestone, dolomite), carbon electrode, and other carbonaceous materials (e.g., coal, coke) (tons).

(7) Carbon content of each carbon‐containing input material charged to each kiln or furnace (including zinc bearing

material, flux materials, and other carbonaceous materials) from the annual carbon analysis or from information provided

by the material supplier for each kiln or furnace (percent by weight, expressed as a decimal fraction).

(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 Method used.

(10) Carbon content of the carbon electrode used in each furnace from the annual carbon analysis or from information

provided by the material supplier (percent by weight, expressed as a decimal fraction).

(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) For the missing data procedures in 40 CFR 98.335(b): How the monthly mass of carbon‐containing materials with

missing data was determined and the number of months the missing data procedures were used.
Page C‐27

Subpart

Reporting

Threshold Reporting and Verification

HH—Landfills

(§98.340)

Municipal

solid waste

landfills that

generate CH4

in amounts

equivalent to

25,000 metric

tons CO2e or

more per year

All:

(1) 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 subpart HH (in

metric tons, wet weight).  

(2) 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 40 CFR 98.343(a)(3), report

separately the quantity of waste determined using the methods in 40 CFR 98.343(a)(3)(i) and the quantity of waste

determined using the methods in 40 CFR 98.343(a)(3)(ii). For historical waste disposal quantities that were not determined

using the methods in 40 CFR 98.343(a)(3), provide the population served by the landfill for each year the Equation HH–2 of

subpart HH is applied, if applicable, or, for open landfills using Equation HH–3 of subpart HH, provide the value of landfill

capacity (LFC) used in the calculation.

(3) Waste composition for each year required for Equation HH–1 of subpart HH, in percentage by weight, for each waste

category listed in Table HH–1 to subpart HH that is used in Equation HH–1 of subpart HH to calculate the annual modeled

CH4 generation.

(4) For each waste type used to calculate CH4 generation using Equation HH‐1 of subpart HH: Degradable organic carbon

(DOC), methane correction factor (MCF), and fraction of DOC dissimilated (DOCF) values used in the calculations. If an MCF

value 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 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) Fraction of CH4 in landfill gas (F) and an indication of whether the fraction of CH4 was determined based on measured

values or the default value.  

(6) 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.  

(7) The modeled annual methane generation rate for the reporting year (metric tons CH4) calculated using Equation HH‐1

of subpart HH.

(8) For landfills without gas collection systems, the annual methane emissions (i.e., the methane generation, adjusted for

oxidation, calculated using Equation HH‐5 of subpart HH), reported in metric tons CH4, 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

40 CFR 98.6) are present at this landfill.

For landfills with gas collection systems:  

(1) Total volumetric flow of landfill gas collected for destruction for the reporting year (cubic feet at 520°R or 60°F and 1

atm).

(2) Annual average CH4 concentration of landfill gas collected for destruction (percent by volume).  

(3) Monthly average temperature 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 CH4 concentration

was measured on a wet or dry basis, and if required for Equation HH–4 of subpart HH, 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 or off‐site. If destruction occurs at the landfill facility:

An indication of whether a back‐up destruction device is present at the landfill, the annual operating hours for the primary

destruction device, the annual operating hours for the back‐up destruction device (if present), and the destruction

efficiency used (percent).  

(6) Annual quantity of recovered CH4 (metric tons CH4) calculated using Equation HH‐4 of subpart HH.  

(7) A description of the gas collection system (manufacture, capacity, number of number of wells), the surface area (square

meters) and estimated waste depth (meters) for each area specified in Table HH‐3 of subpart HH, the estimated gas

collection system efficiency for landfills with this gas collection system, the annual operating hours of the gas collection

system, 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 40 CFR 98.6) are present at the landfill.  

(8) Methane generation corrected for oxidation calculated using Equation HH‐5 of subpart HH, reported in metric tons CH4.

(9) Methane generation (GCH4) value used as an input to HH‐6 of subpart HH. Specify whether the value is modeled (GCH4

from HH‐1) or measured (R from Eq. HH‐4).

(10) Methane generation corrected for oxidation calculated using Equation HH‐7 of subpart HH, reported in metric tons

CH4.

(11) Methane emissions calculated using Equation HH‐6 of subpart HH, reported in metric tons CH4; and  

(12) Methane emissions calculated using Equation HH‐8 of subpart HH, reported in metric tons CH4.
Page C‐28

Subpart

Reporting

Threshold Reporting and Verification

II—Industrial

Wastewater

Treatment

(§98.350)

25,000 metric

tons C02e/year

All:

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.

The total mass of CH4 emitted from all anaerobic processes from which biogas is not recovered (calculated in Equation II–3

of subpart II) and from all anaerobic processes from which some biogas is recovered (calculated in Equation II–6 of subpart

II) using Equation II–7 of subpart II.

For each anaerobic wastewater treatment process (reactor, deep lagoon, or shallow lagoon):

(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 subpart II, from Table II–1 to subpart

II.

(4) Methane conversion factor (MCF) used as an input to Equation II–1 or II–2 of subpart II, from Table II–1 to subpart II.

(5) Annual mass of CH4 generated by each anaerobic wastewater treatment process, calculated using Equation II–1 or II–2

of subpart II.

For each anaerobic wastewater treatment process from which biogas is not recovered, report the annual CH4 emissions,

calculated using Equation II–3 of subpart II.

For each anaerobic wastewater treatment process and anaerobic sludge digester from which some biogas is recovered:

(1) Annual quantity of CH4 recovered from the anaerobic process calculated using Equation II–4 of subpart II.

(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 subpart II, 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 subpart II.

(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, report the annual CH4 emissions, as calculated by

Equation II–6 of subpart II.
Page C‐29

Subpart

Reporting

Threshold Reporting and Verification

JJ—Manure

Management

(§98.360)

Manure

management

systems with

combined CH4

and N2O

emissions in

amounts

equivalent to

25,000 metric

tons CO2e or

more per year

All:

(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‐14).

(8) CH4 emissions from manure management system components listed in 40 CFR 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.  

For facilities with anaerobic digesters:

(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 40 CFR 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.
Page C‐30

Subpart

Reporting

Threshold Reporting and Verification

LL—Suppliers of

Coal‐based Liquid

Fuels (§98.380)

Producers of

coal‐to‐liquid

products:  All

in

Importers &

Exporters:

25,000 metric

tons

C02e/year

Producers (for each coal‐to‐liquid facility):

(1) For each product listed in table MM‐1 that enters the coal‐to‐liquid facility to be further processed or otherwise used

on site: The annual quantity in metric tons or barrels by each quantity measurement standard method or other industry

standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(2) For each product listed in table MM‐1 that enters the coal‐to‐liquid facility to be further processed or otherwise used

on site: The total annual quantity in metric tons or barrels. For natural gas liquids, quantity must reflect the individual

components of the product.

(3) For each feedstock reported in (2) that was produced by blending a fossil fuel‐based product with a biomass‐based

product: The percent of the volume reported in (2) 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 (1).

(5) For each product (leaving the coal‐to‐liquid facility) listed in table MM‐1: The annual quantity in metric tons or barrels

by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity

shall reflect the individual components of the product. Those products that enter the facility, but are not reported in (1),

shall not be reported under this paragraph.

(6) For each product (leaving the coal‐to‐liquid facility) listed in table MM‐1: The total annual quantity in metric tons or

barrels. For natural gas liquids, quantity must reflect the individual components of the product. Those products that enter

the facility, but are not reported in (2), shall not be reported under this paragraph.

(7) For each product reported in (6) that was produced by blending a fossil fuel‐based product with a biomass‐based

product: The percent of the volume reported in (6) 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 (5).  

(9) For every feedstock reported in (2) for which Calculation Method 2 of subpart MM was used to determine an emissions

factor: (i) The number of samples collected according to 40 CFR 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; and (v) The calculated CO2

emissions factor.

(10) For every non‐solid feedstock reported in (2) for which Calculation Method 2 of subpart MM was used to determine

an emissions factor: (i) The density test results in metric tons per barrel, and (ii) The standard method used to test density.

(11) For every product reported in (6) for which Calculation Method 2 of subpart MM was used to determine an emissions

factor: (i) The number of samples collected according to 40 CFR 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; and (v) The calculated CO2

emissions factor.

(12) For every non‐solid product reported in (6) for which Calculation Method 2 of subpart MM was used to determine an

emissions factor: (i) The density test results in metric tons per barrel, and (ii) The standard method used to test density.  

(13) 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 (6): The annual quantity in metric tons or barrels by each quantity

measurement standard method or other industry standard practice used.

(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 (6): The total annual quantity in metric tons or barrels.

(15) Each standard method or other industry standard practice used to measure each quantity reported in (3).  

(16) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of each feedstock

reported in (2), calculated according to 40 CFR 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 (6), calculated according to 40 CFR 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 fuel‐based feedstocks reported in (3), calculated according to 40 CFR 98.393(c).

(19) Annual CO2 emissions that would result from the complete combustion or oxidation of all products, calculated

according to 40 CFR 98.393(d).

(20) Annual quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year.
Page C‐31

Subpart

Reporting

Threshold Reporting and Verification

LL—Suppliers of

Coal‐based Liquid

Fuels (§98.380)

(continued)

Producers of

coal‐to‐liquid

products:  All

in

Importers &

Exporters:

25,000 metric

tons

C02e/year

Importers (at the corporate level):

(1) For each product listed in table MM‐1 of subpart MM: The annual quantity in metric tons or barrels by each quantity

measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the

individual components of the product.

(2) For each product listed in table MM‐1 of subpart MM: 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.

(3) For each product reported in (2) that was produced by blending a fossil fuel‐based product with a biomass‐based

product: The percent of the volume reported in (2) 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 (1).

(5) For each product reported in (2) for which Calculation Method 2 of subpart MM was used to determine an emissions

factor:  (i) The number of samples collected according to 40 CFR 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; and (v) The calculated

CO2 emissions factor in metric tons.

(6) For each non‐solid product reported in (2) for which Calculation Method 2 of subpart MM was used to determine an

emissions factor: (i) The density test results in metric tons per barrel, and (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 (2), calculated according to 40 CFR 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 40 CFR 98.393(e).

Exporters (at the corporate level):

(1) For each product listed in table MM‐1: The annual quantity in metric tons or barrels by each quantity measurement

standard method or other industry standard practice used. For natural gas liquids, quantity must reflect the individual

components of the product.

(2) For each product listed in table MM‐1: The total annual quantity in metric tons or barrels. For natural gas liquids,

quantity must reflect the individual components of the product.

(3) For each product reported in (2) that was produced by blending a fossil fuel‐based product with a biomass‐based

product: The percent of the volume reported in (2) 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 (1).  

(5) For each product reported in (2) for which Calculation Method 2 of subpart MM was used to determine an emissions

factor: (i) The number of samples collected according to 40 CFR 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; and (v) The calculated CO2

emissions factor in metric tons.

(6) For each non‐solid product reported in (2) for which Calculation Method 2 of subpart MM was used to determine an

emissions factor: (i) The density test results in metric tons per barrel, and (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 (2), calculated according to 40 CFR 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 40 CFR 98.393(e).

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 40 CFR 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 40 CFR 98.393; and (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 paragraphs (a)(1) and (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)(5), (a)(6), (b)(1), (b)(2), (c)(1), and (c)(2) of this section, as

applicable, by reflecting the individual components of the blended product.
Page C‐32

Subpart

Reporting

Threshold Reporting and Verification

MM—Suppliers

of Petroleum

Products

(§98.390)

(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.

Refiners:

(1) For each petroleum product or natural gas liquid listed in table MM‐1 that enters the refinery to be further refined or

otherwise used on site: The annual quantity in metric tons or barrels by each quantity measurement standard method or

other industry standard practice used. For natural gas liquids, shall reflect the individual components of the product.

(2) For each petroleum product or natural gas liquid listed in table MM‐1 that enters the refinery to be further refined or

otherwise used on site: 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 (2) that was produced by blending a petroleum‐based product with a biomass‐based

product: The percent of the volume reported in (2) that is petroleum‐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 (1).

(5) For each petroleum product and natural gas liquid (ex refinery gate) listed in table MM‐1: The annual quantity in metric

tons or barrels by each quantity measurement standard method or other industry standard practice used. 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 (1), shall not be reported under this paragraph.

(6) For each petroleum product and natural gas liquid (ex refinery gate) listed in table MM‐1 of subpart MM: 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 (2), shall not be reported under

this paragraph.

(7) For each product reported in (6) that was produced by blending a petroleum‐based product with a biomass‐based

product: The percent of the volume reported in (6) that is petroleum‐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 (5).  

(9) For every feedstock reported in (2) for which Calculation Method 2 of subpart MM was used to determine an emissions

factor: (i) The number of samples collected according to 40 CFR 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; and (v) The calculated CO2

emissions factor in metric tons.

(10) For every non‐solid feedstock reported in (2) for which Calculation Method 2 of subpart MM was used to determine

an emissions factor: (i) The density test results in metric tons per barrel and (ii) The standard method used to test density.

(11) For every petroleum product and natural gas liquid reported in (6) for which Calculation Method 2 of subpart MM was

used to determine an emissions factor: (i) The number of samples collected according to 40 CFR 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; and (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 (6) for which Calculation Method

2 of subpart MM was used to determine an emissions factor: (i) The density test results in metric tons per barrel and (ii)

The standard method used to test density.

(13) For each specific type of biomass that enters the refinery to be co‐processed with petroleum feedstocks to produce a

petroleum product reported in (6): The annual quantity in metric tons or barrels by each quantity measurement standard

method or other industry standard practice used.

(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 (6): The annual quantity in metric tons or barrels.

(15) Each standard method or other industry standard practice used to measure each quantity reported in (13).  

(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 (6).  

(17) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of each feedstock

reported in (2) that were calculated according to 40 CFR 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 (13), calculated according to 40 CFR 98.393(c).

(19) The sum of CO2 emissions that would result from the complete combustion or oxidation of all products, calculated

according to 40 CFR 98.393(d).

(20) All of the following information for all crude oil feedstocks used at the refinery: (i) Batch volume in barrels; (ii)

Weighted average API gravity of the batch at the point of entry at the refinery; (iii) Weighted average sulfur content of the

batch at the point of entry at the refinery; (iv) Country of origin, of the batch, if known and data in (v) and (vi) are

unknown; (v) EIA crude stream code and crude stream name of the batch, if known; and (vi) Generic name for the crude

stream and the appropriate EIA two‐letter country or state and production area code of the batch, if known and no

appropriate EIA crude stream code exists.

(21) The quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year.

(22) Volume of crude oil in barrels injected into a crude oil supply or reservoir. A volume of crude oil that entered the

refinery, but was not reported in paragraphs (2) or (20), shall not be reported under this paragraph.

(23) Special provisions for 2010. For reporting year 2010 only, a refiner that knows the information under a specific tier of

the batch definition in 40 CFR 98.398, but does not have the necessary data collection and management in place to readily

report this information, can use the next most appropriate tier of the batch definition for reporting batch information

under paragraph 98.396(a)(20).
Page C‐33

Subpart

Reporting

Threshold Reporting and Verification

MM—Suppliers

of Petroleum

Products

(§98.390)

(continued)

(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.

Importers (at the corporate level):

(1) For each petroleum product and natural gas liquid listed in table MM‐1: The annual quantity in metric tons or barrels by

each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity

shall reflect the individual components of the product.

(2) For each petroleum product and natural gas liquid listed in table MM‐1: The annual quantity in metric tons or barrels.

For natural gas liquids, quantity must reflect the individual components of the product as listed in table MM‐1 of subpart

MM.

(3) For each product reported in (2) that was produced by blending a petroleum‐based product with a biomass‐based

product: The percent of the volume reported in (2) that is petroleum‐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 (1).

(5) For each product reported in (2) for which Calculation Method 2 of subpart MM was used to determine an emissions

factor: (i) The number of samples collected according to 40 CFR 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; and (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 (2) for which Calculation Method 2 of subpart MM was used to determine an

emissions factor: (i) The density test results in metric tons per barrel and (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 (2), calculated according to 40 CFR 98.393(a).

(8) The sum of CO2 emissions that would result from the complete combustion or oxidation of all imported products,

calculated according to 40 CFR 98.393(e).

Exporters (at the corporate level):

(1) For each petroleum product and natural gas liquid listed in table MM‐1 of subpart MM: The annual quantity in metric

tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas

liquids, quantity shall reflect the individual components of the product.

(2) For each petroleum product and natural gas liquid listed in table MM‐1 of subpart MM: 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 (2) that was produced by blending a petroleum‐based product with a biomass‐based

product: The percent of the volume reported in (2) that is petroleum 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 (1).  

(5) For each product reported in (2) for which Calculation Method 2 of subpart MM was used to determine an emissions

factor: (i) The number of samples collected according to 40 CFR 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; and (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 (2) for which Calculation Method 2 of subpart MM used was used to determine

an emissions factor: (i) The density test results in metric tons per barrel and (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

petroleum product and natural gas liquid reported in (2), calculated according to 40 CFR 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 40 CFR 98.393(e).

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 40 CFR 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 subpart MM; and (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 paragraphs (a)(1) and (a)(2) of 40 CFR 98.396 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)(5), (a)(6), (b)(1), (b)(2), (c)(1), and (c)(2) of 40 CFR 98.396, as

applicable, by reflecting the individual components of the blended product.
Page C‐34

Subpart

Reporting

Threshold Reporting and Verification

NN—Suppliers of

Natural Gas and

Natural Gas

Liquids (§98.400)

(A) All

fractionators.

(B) Local

natural gas

distribution

companies

that deliver

460,000

thousand

standard cubic

feet or more

of natural gas

per year.

For each NGL fractionator:

(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 categories:

ethane, propane, normal butane, isobutane, and pentanes plus.

(3) Annual volumes in Mscf of natural gas received for processing.

(4) Annual quantity (in barrels) of y‐grade, bulk NGLs received from others for fractionation.  

(5) Annual quantity (in barrels) of propane that the NGL fractionator odorizes at the facility and delivers to others.  

(6) Annual CO2 emissions (in metric tons) that would result from the complete combustion or oxidation of the quantities in

(1) and (2), calculated in accordance with 40 CFR 98.403(a) and (c)(1).  

(7) Annual CO2mass emissions (metric tons) that would result from the combustion or oxidation of fractionated NGLs

supplied less the quantity received by other fractionators, calculated in accordance with 40 CFR 98.403(c)(2).

(8) The specific industry standard used to measure each quantity reported in (1).

(9) If the NGL fractionator developed reporter‐specific EFs or HHVs: (i) The specific industry standard(s) used to develop

reporter‐specific higher heating value(s) and/or emission factor(s), pursuant to 40 CFR 98.404(b)(2) and (c)(3); (ii) The

developed HHV(s); and (iii) The developed EF(s).  

Local distribution companies:

(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.

(3) Annual volume in Mscf of vaporized liquefied natural gas (LNG) produced at on‐system vaporization facilities for

delivery on the distribution system that is not accounted for in (1).

(4) Annual volume in Mscf of natural gas withdrawn from on‐system storage (that is not delivered to the city gate) for

delivery to on the distribution system.  

(5) Annual volume in Mscf of natural gas delivered directly to LDC systems from producers or natural gas processing plants

from local production.

(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 LDC to each meter registering supply equal to or greater than

460,000 Mcsf during the calendar year.

(8) The total annual CO2 mass emissions (metric tons) associated with the volumes in (1) ‐ (7), calculated in accordance

with 40 CFR 98.403.

(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 Mcsf, calculated in accordance with 40 CFR 98.403(b)(4).

(10) The specific industry standard used to develop the volume reported in (1).

(11) If the LDC developed reporter‐specific EFs or HHVs: (i) The specific industry standard(s) used to develop reporter‐

specific higher heating value(s) and/or emission factor(s), pursuant to 40 CFR 98.404(b)(2) and (c)(3); (ii) The developed

HHV(s); and (iii) The developed EF(s).

(12) The customer name, address, and meter number of each meter reading used to report in (7). If known, the EIA

identification number of each LDC customer.

(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; and

(iv) Electricity generating facilities.

All: Each reporter must report the number of days in the reporting year that substitute data procedures were used for the

following purpose: (i) To measure quantity; (ii) To develop HHV(s); and (iii) To develop EF(s).
Page C‐35

Subpart

Reporting

Threshold Reporting and Verification

OO—Suppliers of

Industrial

Greenhouse

Gases (§98.410)  

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.

Each fluorinated GHG or nitrous oxide production facility:

(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 40 CFR 98.410(b). Quantities to be reported 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) Total mass in metric tons of each fluorinated GHG or nitrous oxide sent to another facility for transformation.

(5) 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 40 CFR 98.413(a) because they are removed from the production process as by‐

products or other wastes. Quantities to be reported 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.

(6) 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 40 CFR 98.413(a) because it is removed from the production process as a byproduct or other

waste.

(8) Mass in metric tons of any fluorinated GHG or nitrous oxide fed into the transformation process, by process.

(9) Mass in metric tons of each fluorinated GHG fed into the destruction device and that was previously produced as

defined at 40 CFR 98.410(b). Quantities to be reported 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.

(10) Mass in metric tons of each fluorinated GHG or nitrous oxide that is measured coming out of the production process,

by process.

(11) Mass in metric tons of each fluorinated GHG 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.

(12) 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.

(13) 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.

(14) Where missing data have been estimated pursuant to 40 CFR 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.  

Fluorinated GHG production facilities that destroy fluorinated GHGs (one‐time report) 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.

Bulk importer of fluorinated GHGs or N2O :

For each import (except for shipments including less than 25 kilograms of fluorinated GHGs or nitrous oxide,

transshipments, and heels that meet the conditions set forth at 98.417(e)):

(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 perfecnt 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.
Page C‐36

Subpart

Reporting

Threshold Reporting and Verification

OO—Suppliers of

Industrial

Greenhouse

Gases (§98.410)

(cont’d)

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.

Bulk exporter of fluorinated GHGs or N2O:

For each export (except for shipments including less than 25 kilograms of fluorinated GHGs or nitrous oxide,

transshipments, and heels):

(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.

A fluorinated GHG production facility must submit a one‐time report within 60 days of commencing fluorinated GHG

production describing:

(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.

PP—Suppliers of

Carbon Dioxide

(CO2) (§98.420)

Producers:  All

in

Bulk 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

Facilities that use Equation PP‐1 of 40 CFR 98.423:

For each mass flow meter or CO2 stream that delivers CO2 to containers:

(1) Annual mass in metric tons of the 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 the process chain in relation to the points of CO2 stream capture, dehydration,

compression, and other processing.

Facilities that use Equation PP‐2 of 40 CFR 98.423:

For each volumetric flow meter or CO2 stream 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 CO2 in metric tons per standard cubic meter if reporting the

concentration of the CO2 stream in (3) and (ii) Quarterly density of the CO2 stream in metric tons per standard cubic meter

if reporting the concentration of the CO2 stream in (3) 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 the process chain in relation to the points of CO2 stream capture, dehydration,

compression, and other processing.

Facilities that use Equation PP‐3a or PP‐3b of 40 CFR 98.423 for calculating the aggregated annual mass of CO2

emissions:

(1) If Equation PP‐3a is used, Annual CO2 mass in metric tons from all flow meters and CO2 streams that deliver CO2 to

containers.

(2) If Equation PP–3b is used, report: (i) The total annual CO2mass through main flow meter(s) in metric tons; (ii) The total

annual CO2mass through subsequent flow meter(s) in metric tons; (iii) The total annual CO2mass supplied in metric tons;

and (iv) The location of each flow meter in relation to the point of segregation.

Facilities that use Equation PP‐4 of 40 CFR 98.423:

1) Annual mass of CO2in metric tons in all CO2 containers imported or exported at the corporate level.

All:

(1) The type of equipment used to measure the total flow of the CO2 stream or the total mass or volume in CO2 containers.

(2) The standard used to operate and calibrate the equipment reported in (1).

(3) The number of days in the reporting year for which substitute data procedures were used for the following purposes: (i)

To measure quantity; (ii) To measure concentration; and (iii) To measure density.

(4) The aggregated annual quantity of CO2 in metric tons that is transferred to each of the following end use applications, if

known: (i) Food and beverage; (ii) Industrial and municipal water/wastewater treatment; (iii) Metal fabrication, including

welding and cutting; (iv) Greenhouse uses for plant growth; (v) Fumigants (e.g., grain storage) and herbicides; (vi) Pulp and

paper; (vii) Cleaning and solvent use; (viii) Fire fighting, (ix) Transportation and storage of explosives; (x) Enhanced oil and

natural gas recovery; (xi) Long‐term storage (sequestration); (xii) Research and development; (xiii) Other.

(5) 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.
Page C‐37

Subpart

Reporting

Threshold Reporting and Verification

Subpart QQ—

Importers and

Exporters of

Fluorinated

Greenhouse

Gases Contained

in Pre‐Charged

Equipment or

Closed‐Cell

Foams

(§98.430)

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.

Each importer of fluorinated GHGs contained in pre‐charged equipment or closed‐cell foams:

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 appliances, the identity of the fluorinated GHG contained in the foam

in each appliance, the mass of the fluorinated GHG contained in the foam in each appliance, and the number of appliances

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 appliances, 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 closed‐cell foams; (ii)

For closed‐cell foams that are imported inside of appliances, the mass of the fluorinated GHGs in CO2 e contained in the

foam in each appliance and the number of appliances imported for each type of appliance; (iii) For closed‐cell foams that

are not imported inside of appliances, the mass 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; and (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.

Each exporter of fluorinated GHGs contained in pre‐charged equipment of closed‐cell foams:

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 appliances, the identity of the fluorinated GHG contained in the foam

in each appliance, the mass of the fluorinated GHG contained in the foam in each appliance, and the number of appliances

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 appliances, 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 closed‐cell foams.

(ii) For closed‐cell foams that are exported inside of appliances, the mass of the fluorinated GHGs in CO2e contained in the

foam in each appliance and the number of appliances imported for each type of appliance.

(iii) For closed‐cell foams that are not exported inside of appliances, the mass 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 exported.

(v) Name of the foam manufacturer for each type of closed‐cell foam where the identity and mass of the fluorinated GHG

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.
Page C‐38

Subpart

Reporting

Threshold Reporting and Verification

Subpart RR—

Geologic

Sequestration of

Carbon Dioxide

(§98.440)

All in If CO2 is received by pipeline:

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 reporting yes to paragraph (4): (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

the 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 reporting yes to (4): (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 the 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 the procedures in 40

CFR 98.444(a)(4) were followed.

(5) The standard or method used to calculate each value in (2) through (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 (2) through (3) of this section.

(7) Whether the flow meter is mass or volumetric.

(8) A numerical identifier for the flow meter.

If CO2 is received in containers:

(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 the 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 (1) and (2).

(6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported

in (1) and (2).

If more than one receiving flow meter is used: The total net mass of CO2 received (metric tons) through all flow meters

annually.

All:

(1) The source of the CO2 received according to the following categories: (i) CO2 production wells; (ii) Electric generating

unit; (iii) Ethanol plant; (iv) Pulp and paper mill; (v) Natural gas processing; (vi) Gasification operations; (vii) Other

anthropogenic source; (viii) Discontinued enhanced oil and gas recovery project; (ix) Unknown.

(2) The date that data collection began for calculating total amount sequestered according to 40 CFR 98.448(a)(7) of 40

CFR 98.

(3) If the date specified in (2) is during the reporting year for this annual report, report the following starting on the date

specified in (2):  

(a) For each injection flow meter (mass or volumetric): (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 (ii) through (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 (ii) through (iv) of this section; (ix) The location of the flow meter.

The total CO2 injected (metric tons) in the reporting year as calculated in Equation RR–6 of subpart RR.

(b) For CO 2emissions 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 and (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.

(c) For each separator flow meter (mass or volumetric): (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 (ii) through (iv); and (viii) The number of times in the reporting year for which substitute data procedures were

used to calculate values reported in(ii) through (iv).

(d) 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 subpart RR and as

determined according to the EPA‐approved MRV plan.

(e) Annual CO2 produced in the reporting year as calculated in Equation RR–9 of subpart RR.

(f) For each leakage pathway through which CO2 emissions occurred: (i) A numerical identifier for the leakage pathway and

(ii) The CO2 (metric tons) emitted through that pathway in the reporting year.

(g) Annual CO2mass emitted (metric tons) by surface leakage in the reporting year as calculated by Equation RR–10 of

subpart RR.
Page C‐39

Subpart

Reporting

Threshold Reporting and Verification

Subpart RR—

Geologic

Sequestration of

Carbon Dioxide

(§98.440)

(cont’d)

All In (h) Annual CO2 (metric tons) sequestered in subsurface geologic formations in the reporting year as calculated by Equation

RR–11 or RR–12 of subpart RR.

(i) 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 subpart RR.

(j) Date that the most recent MRV plan was approved by EPA and the MRV plan approval number that was issued by EPA.

(k) 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 were concluded to not be material changes warranting submission of a revised MRV plan under 40 CFR

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; and (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.

(l) If a well is permitted under the Underground Injection Control program, for each injection well: (i) The well

identification number used for the Underground Injection Control permit and  (ii) The Underground Injection Control

permit class.

(m) 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.
Page C‐40

Subpart

Reporting

Threshold Reporting and Verification

Subpart SS—

Electrical

Equipment

Manufacture or

Refurbishment

(§98.450)

total annual

purchases of

SF6and PFCs

that exceed

23,000 pounds

All:

For each chemical at the facility level:

(1) Pounds of SF6 and PFCs stored in containers at the beginning of the year.

(2) Pounds of SF6 and PFCs stored in containers at the end of the year.

(3) Pounds of SF6 and PFCs purchased in bulk.

(4) Pounds of SF6 and PFCs returned by equipment users with or inside equipment.

(5) Pounds of SF6 and PFCs returned to site from off site after recycling.

(6) Pounds of SF6 and PFCs inside new equipment delivered to customers.

(7) Pounds of SF6 and PFCs delivered to equipment users in containers.

(8) Pounds of SF6 and PFCs returned to suppliers.

(9) Pounds of SF6 and PFCs sent off site for destruction.

(10) Pounds of SF6 and PFCs sent off site to be recycled.

(11) The nameplate capacity of the equipment, in pounds, delivered to customers with SF6or PFCs inside, if different from

the quantity in paragraph (6) of this section.

(12) 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.

(13) The values for EFC for each hose and valve combination and the associated valve fitting sizes and hose diameters.

(14) The total number of fill operations for each hose and valve combination, or, FCi  of Equation SS–5 of subpart SS.

(15) The mean value for each make, model, and group of conditions if the mass of SF6 or the PFC disbursed to customers in

new equipment over the period p is determined by assuming that it is equal to the equipment's nameplate capacity or, in

cases where equipment is shipped with a partial charge, equal to its partial shipping charge.

(16) The number of samples and the upper and lower bounds on the 95 percent confidence interval for each make, model,

and group of conditions if the mass of SF6 or the PFC disbursed to customers in new equipment over the period p is

determined by assuming that it is equal to the equipment's nameplate capacity or, in cases where equipment is shipped

with a partial charge, equal to its partial shipping charge.

(17) 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 subpart SS.

(18) 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 subpart SS.

(19) 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 subpart SS.

(20) For any missing data, 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.
Page C‐41

Subpart

Reporting

Threshold Reporting and Verification

TT—Industrial

Waste Landfills

(§98.460)

25,000 metric

tons C02e/year

All:

(a) 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) Waste characterization and modeling information:

(1) The number of waste steams (including “Other Industrial Solid Waste (not otherwise listed)”) for which Equation TT–1

of subpart TT 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

subpart TT 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.

(c) For each waste stream identified in (b):

(1) The decay rate (k) value used in the calculations.

(2) The method(s) for estimating historical waste disposal quantities and the range of years for which each method applies.

(3) If Equation TT–2 of subpart TT is used: (i) The total number of years (N) for which disposal and production data are both

available; (ii) The year, the waste disposal quantity and production quantity for each year used in Equation TT–2 of subpart

TT to calculate the average waste disposal factor (WDF); and (iii) The average waste disposal factor (WDF) calculated for

the waste stream.

(4) If Equation TT–4 of subpart TT is used: (i) The value of landfill capacity (LFC); (ii) YrData; and (iii) YrOpen.

(d) For each year of landfilling starting with the “Start Year” (S) and each year thereafter up to the current reporting year:

(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 (b).

(3) 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 subpart TT, a measured value using a 60‐day anaerobic biodegradation test as

specified in 40 CFR 98.464(b)(4)(i), or a value based on total and volatile solids measurements as specified in 40 CFR

98.464(b)(4)(ii). If DOCXwas 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 subpart TT.

(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 subpart TT), 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 40 CFR 98.6) are present at this landfill.  

(h) For landfills with gas collection systems, in addition to the reporting requirements in (a) through (f), report according to

40 CFR 98.346(i).
Page C‐42

Subpart

Reporting

Threshold Reporting and Verification

UU—Injection of

Carbon Dioxide

(§98.470)

All In If subject to this part and report under subpart UU, the facility is not required to report the information in 40 CFR

98.3(c)(4) for subpart UU. Report the information required by 40 CFR 98.3(c)(1) through 40 CFR 98.3(c)(3) and by 40 CFR

98.3(c)(5) through 40 CFR 98.3(c)(9), plus the information below.

If CO2 is received by pipeline, 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 the well (in standard cubic meters) in each quarter; and (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

the well (in metric tons) in each quarter; and (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 (2) through (3).

(5) The number of times in the reporting year for which substitute data procedures were used to calculate values reported

in paragraphs (2) through (3).

(6) Whether the flow meter is mass or volumetric.

If CO2 is received in containers:

(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 the 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 (1) and (2) of this section.

(6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported

in (1) and (2).

If more than one receiving flow meter is used:  

The net total mass of CO2 received (metric tons) through all flow meters annually.

All:

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.

Note: Many facilities that would be affected by the rule emit GHGs from multiple sources. The facility must assess every source category that could potentially

apply to each when determining if a threshold has been exceeded. If the threshold is exceed for any source category, the facility must report emissions from all

source categories, including those source categories that do not exceed the applicable threshold.