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pdfAppendix A
Table A-1 Reporting Thresholds and Reporting Requirements
Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
C—General Stationary Fuel Combustion Sources (§ 98.30). See ICR section 4(b)(i).
D—Electricity
See reporting requirements for stationary combustion
25,000 metric tons; all All facilities
Generation
facilities subject to the
(§98.40)
Acid Rain Program or
CAIR
Stationary combustion
See reporting requirements for stationary combustion
E—Adipic Acid All in
Production
(a) Annual N2O emissions from adipic acid production in metric tons.
Production
(b) Annual adipic acid production capacity (in metric tons).
(§98.50)
(c) Annual adipic acid production, in units of metric tons of adipic acid produced.
(d) Number of facility operating hours in calendar year.
(e) Emission rate factor used (lb N2O/ton adipic acid).
(f) Abatement technology used (if applicable).
(g) Abatement technology efficiency (percent destruction).
(h) Abatement utilization factor (percent of time that abatement system is operating).
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Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
F—Aluminum
Production
(§98.60)
All in
Stationary combustion
Production
See reporting requirements for stationary combustion
(a) Annual aluminum production in metric tons.
(b) Type of smelter technology used.
(c) The following PFC‐specific information on an annual basis:
(1) Perfluoromethane emissions and perfluoroethane emissions from anode effects in all prebake
and all Søderberg electolysis cells combined.
(2) Anode effect minutes per cell‐day, anode effect frequency (AE/cell‐day), anode effect duration
(minutes).
(3) Smelter‐specific slope coefficient and the last date when the smelter‐specific‐slope coefficient
was measured.
(d) Method used to measure the frequency and duration of anode effects.
(e) The following CO2‐specific information for prebake cells on an annual basis:
(1) Total anode consumption.
(2) Total CO2 emissions from the smelter.
(f) The following CO2‐specific information for Søderberg cells on an annual basis:
(1) Total paste consumption.
(2) Total CO2 emissions from the smelter.
(g) 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.
(h) Exact data elements required will vary depending on smelter technology
(e.g., point‐feed prebake or Søderberg).
G—Ammonia
Manufacturing
(§98.70)
All in
Stationary combustion
Production
See reporting requirements for stationary combustion
(a) Annual CO2 emissions from ammonia manufacturing process (metric tons);
(b) Total quantity of feedstock consumed for ammonia manufacturing; and
(c) Monthly analyses of carbon content for each feedstock used in ammonia manufacturing (kg
carbon/kg of feedstock).
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Subpart
Reporting Threshold 1
Source Category
H—Cement
Production
(§98.80)
All in
Fuel combustion at kilns See reporting requirements for stationary combustion
and any other Stationary
combustion unit
Production
I—Electronics
Manufacturing
(§98.90)
Stationary combustion
Production capacity
Semiconductors: 1,078 Production
m2 silicon
MEMs: 4,358 m2 silicon
LCDs: 235,737 m2 LCD
PVs: 728,014 m2 PV‐
Cell
J—Ethanol
Production
(§98.100)
25,000 metric tons
C02e/year
Onsite stationary
combustion
Onsite landfills
Onsite wastewater
treatment
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Reporting and Verification
(a) The total combined CO2 emissions from all kilns at the facility (in metric tons).
(b) Annual clinker production (tons).
(c) Number of kilns.
(d) Annual CKD production (in metric tons).
(e) Total annual fraction of CKD recycled to the kilns (as a percentage).
(f) Annual weighted average carbonate composition (by carbonate).
(g) Annual weighted average fraction of calcination achieved (for each carbonate, percent).
(h) Site‐specific emission factor (metric tons CO2/metric ton clinker produced).
(i) Organic carbon content of the raw material (percent).
(j) Annual consumption of raw material (metric tons)
(k) Facilities that use CEMS must also comply with the data reporting requirements specified in
§98.36(d)(iv).
See reporting requirements for stationary combustion
(a) Emissions of each GHG emitted from all plasma etching processes, all chamber cleaning, all
chemical vapor deposition processes, and all heat transfer fluid use, respectively.
(b) The method, mass of input F‐GHG gases, and emission factors used for estimating F‐GHG
emissions.
(c) Production in terms of substrate surface area (e.g., silicon, PV‐cell, LCD).
(d) Factors used for gas process utilization and by‐product formation, and the source and
uncertainty for each factor.
(e) The verified DRE and its uncertainty for each abatement device used, if you have verified the DRE
pursuant to §98.94(c).
(f) Fraction of each gas fed into each process type with abatement devices.
(g) Description of abatement devices, including the number of devices of each manufacturer and
model.
(h) For heat transfer fluid emissions, inputs in the mass‐balance equation.
(i) Example calculations for F‐GHG, N2O, and heat transfer fluid emissions.
(j) Estimate of the overall uncertainty in the emissions estimate.
See reporting requirements for stationary combustion
See reporting requirements for landfills
See reporting requirements for wastewater treatment
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Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
K—Ferroalloy
Production
(§98.110)
25,000 metric tons
C02e/year
Stationary combustion
Production
See reporting requirements for stationary combustion
(a) Annual CO2 emissions from each electric arc furnace used for ferroalloy production, in metric
tons and the method used to estimate these emissions.
(b) Annual CH4 emissions from each electric arc furnaces used for the production of any ferroalloy
listed in Table K‐1 of this subpart.
(c) Facility ferroalloy product production capacity (metric tons).
(d) Annual facility production quantity for each ferroalloy product (metric tons).
(d) Number of facility operating hours in calendar year.
(f) If you use the carbon balance procedure, report for each carbon‐containing input and output
material consumed or used (other than fuel), the information specified in paragraphs (g)(1)and (2) of
this section.
(1) Annual material quantity (in metric tons).
(2) Annual average of the monthly carbon content determinations for each material and the method
used for the determination (e.g., supplier provided information, analyses of representative samples
you collected).
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Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
L—Fluorinated 25,000 metric tons
Greenhouse Gas C02e/year
Production
(§98.120)
Stationary combustion
Production
See reporting requirements for stationary combustion
(a) For each production process at the facility, report: (1) Total mass of fluorinated GHG produced in
metric tons, by chemical; (2) Total mass of reactant fed into the production process in metric tons,
by chemical; (3) Total mass of each reactant permanently removed from production process in
metric tons, by chemical; (4) Total mass of fluorinated GHG product removed from production
process and destroyed,
(5) Mass of each by‐product generated; (6) Mass of each by‐product destroyed at the facility; (7)
Mass of each by‐product recaptured and sent off‐site for destruction; (8) Mass of each by‐product
recaptured for other purposes; (9) Mass of each fluorinated GHG emitted.
(b) Where missing data have been estimated pursuant to §98.125, report:
(1) Reason the data were missing, length of time the data were missing, method used to estimate
the missing data, & estimates of those data.
(2) Where the missing data have been estimated pursuant to §98.125(a)(3), report the rationale for
the methods used to estimate the missing data & why the methods specified in §98.125(a)(1) and
(a)(2) would lead to a significant under‐ or overestimate of the parameter(s).
(c) For each fluorinated GHG production facility that destroys fluorinated GHGs, report results
of annual fluorinated GHG conc. measurements at outlet of destruction device, including:
(1) Flow rate of fluorinated GHG being fed into destruction device in kg/hr.
(2) Concentration (mass fraction) of fluorinated GHG at outlet of destruction device.
(3) Flow rate at outlet of destruction device in kg/hr.
(4) Emission rate calculated from paragraphs(c)(2)&(c)(3) of this section in kg/hr.
(d) A fluorinated GHG production facility that destroys fluorinated GHGs shall submit a
one‐time report containing the following information:
(1) Destruction efficiency (DE) of each destruction unit.
(2) Test methods used to determine the destruction efficiency.
(3) Methods used to record the mass of fluorinated GHG destroyed.
(4) Chemical identity of fluor. GHG(s) used in performance test conducted to determine DE.
(5) Name of all applicable federal or state regs that may apply to destruction process.
(6) If any process changes affect unit destruction efficiency or methods used to record mass
of fluorinated GHG destroyed, a revised report must be submitted to reflect the changes. The
revised report must be submitted to EPA within 60 days of the change.
M—Food
Processing
(§98.130)
Onsite stationary
combustion
Onsite landfills
Onsite wastewater
treatment
See reporting requirements for stationary combustion
25,000 metric tons
C02e/year
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See reporting requirements for landfills
See reporting requirements for wastewater treatment
Page A-5
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Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
N—Glass
Production
(§98.140)
25,000 metric tons
C02e/year
Stationary combustion
Production
See reporting requirements for stationary combustion
For each continuous glass melting furnace, retain:
(a) Annual process emissions of CO2, in metric tons/yr.
(b) Annual quantity of each carbonate‐based raw material charged, in metric tons/yr.
(c) Annual quantity of glass produced, in metric tons/yr.
(d) If process CO2 emissions are calculated based on data provided by the raw material supplier
according to §98.143(a)(1), the carbonate‐based mineral mass fraction (as percent) for each
carbonate‐based raw material charged to a continuous glass melting furnace.
Stationary combustion
Production facilities
See reporting requirements for stationary combustion.
(a) For each HCFC‐22 production facility, report:
(1) The mass of HCFC‐22 produced in metric tons.
(2) The mass of reactants fed into the process in metric tons of reactant.
(3) 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.
(4) The method for tracking startups, shutdowns, and malfunctions and HFC‐23
generation/emissions during these events.
(5) 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.
(6) The total mass of the HFC‐23 generated in metric tons.
(7) The mass of any HFC‐23 packaged for sale in metric tons.
(8) The mass of any HFC‐23 sent off site for destruction in metric tons.
(9) The mass of HFC‐23 emitted in metric tons.
(10) The mass of HFC‐23 emitted from equipment leaks in metric tons.
(11) The mass of HFC‐23 emitted from process vents in metric tons.
O—HCFC‐22
All in
Production and
HFC‐23
Destruction
(§98.150)
(b) Where missing data have been estimated pursuant to §98.155, the designated
representative of the HCFC‐22 production facility or HCF‐23 destruction facility shall 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.
(1) Where the missing data have been estimated pursuant to §98.155(a)(3), the designated
representative shall also report the rationale for the methods used to estimate the missing
data and why the methods specified in §98.155(a)(1) and (2) would probably lead to a
significant under‐ or overestimate of the parameter(s).
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Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
O—HCFC‐22
Production and
HFC‐23
Destruction
(§98.150) (Cont.)
(1) If HFC‐23
destruction facility is
also an HCFC‐22
production facility: all
in
(2) If HFC‐23
destruction facility is
not also an HCFC‐22
prodcution facility:
25,000 metric tons
C02e/year
HFC‐23 destruction
facilities
Report the following:
(1) The mass of HFC‐23 fed into the thermal oxidizer.
(2) The mass of HFC‐23 destroyed.
(3) The mass of HFC‐23 emitted from the thermal oxidizer.
Report the results of the facility’s annual HFC‐23 concentration measurements at the outlet of the
destruction device, including:
(1) The flow rate of HFC‐23 being fed into the destruction device in kg/hr,
(2) The concentration (mass fraction) of HFC‐23 at the outlet of the destruction device,
(3) The flow rate at the outlet of the destruction device in kg/hr, and
(4) The emission rate calculated from (c)(2) and (3) in kg/hr.
Destruction facility shall also submit a one‐time report including:
(1) The destruction unit's destruction efficiency (DE),
(2) The methods used to determine the unit’s 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, and
(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.
P—Hydrogen
Production
(§98.160)
25,000 metric tons
C02e/year
Stationary combustion
Production
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See reporting requirements for stationary combustion
For each process unit, report:
(a) Facilities that use CEMS must comply with the procedures specified in §98.36(a)(1)(iv).
(b) Annual total consumption of feedstock for hydrogen production; annual total of hydrogen
produced; and annual total of ammonia produced, if applicable.
(c) Monthly analyses of carbon content for each feedstock used in hydrogen production (kg
carbon/kg of feedstock).
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Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
Q—Iron & Steel 25,000 metric tons
Production
C02e/year
(§98.170)
Stationary combustion
Production
R—Lead
Production
(§98.180)
25,000 metric tons
C02e/year
Stationary combustion
Production
See reporting requirements for stationary combustion
Report the following information for coke pushing and for each taconite indurating furnace; basic
oxygen furnace; non‐recovery coke oven battery; sinter process; EAF; argon‐oxygen decarburization
vessel; and direct reduction furnace, as applicable:
(a) Annual CO2 emissions by calendar quarters;
(b) Annual total for all process inputs and outputs when the carbon balance is used for specific
processes by calendar quarters (short tons);
(c) Annual production quantity (in metric tons) for taconite pellets, coke, sinter, iron, and raw steel
by calendar quarters;
(d) Production capacity (in tons per year) for the production of taconite pellets, coke, sinter, iron,
and raw steel;
(e) Annual operating hours for taconite furnaces, coke oven batteries, sinter production, blast
furnaces, direct reduced iron furnaces, and electric arc furnaces; and
(f) Site‐specific emission factor for all process units for which the site‐specific emission factor
approach is used.
(g) Facilities using CEMs must follow reporting requirements in §98.36(d)(iv)
See reporting requirements for stationary combustion
(a) Total annual CO2 emissions from each smelting furnace operated at your facility for lead
production (metric tons and the method used to estimate emissions).
(b) Facility lead product production capacity (metric tons).
(c) Annual facility production quantity (metric tons).
(d) Number of facility operating hours in calendar year.
(e) For each carbon‐containing input material consumed or used (other than fuel), report:
(1) Annual material quantity (in metric tons); and
(2) Annual weighted average carbon content determined for material and the method used for the
determination (e.g., supplier provided information, analyses of representative samples you
collected).
S—Lime
Manufacturing
(§98.190)
All in
Stationary combustion
Production
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See reporting requirements for stationary combustion
(a) For each lime kiln, record:
(1) Annual CO2 process emissions;
(2) Annual lime production (in metric tons);
(3) Annual lime production capacity (in metric tons) per facility;
(4) All monthly emission factors, and;
(5) Number of operating hours in calendar year
(b) Facilities that use CEMS must also comply with the recordkeeping requirements specified
in §98.37.
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Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
T—Magnesium 25,000 metric tons
Production
C02e/year
(§98.200)
Stationary combustion
Production
See reporting requirements for stationary combustion
(a) Total GHG emissions for your facility by gas in metric tons and CO2e;
(b) Type of production process (e.g., primary, secondary, die casting);
(c) Magnesium production amount in metric tons for each process type;
(d) Cover gas flow rate and composition;
(e) Amount of CO2 used as a carrier gas during the reporting period;
(f) For any missing data, you must report the length of time the data were missing, the method used
to estimate emissions in their absence, and the quantity of emissions thereby estimated;
(g) The facility’s cover gas usage rate; and
(h) 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 consumption).
(i) A description of any new melt protection technologies adopted to account for reduced GHG
emissions in any given year.
U—Misc. Uses of
Carbonate (§
98.210)
Production
(a) Annual CO2 emissions from miscellaneous carbonate use (in metric tons);
(b) Annual carbonate consumption (by carbonate type in tons);
(c) Annual fraction calcinations ; and
(d) Average annual mass fraction of carbonate‐based mineral in carbonate‐based raw material by
carbonate type.
Stationary combustion
Production
See reporting requirements for stationary combustion
For each nitric acid production line, report annual N2O process emissions and
(a) Annual nitric acid production capacity (metric tons);
(b) Annual nitric acid production (metric tons);
(c) Number of operating hours in the calendar year (hours);
(d) Emission factor(s) used (lb N2O/ton of nitric acid produced);
(e) Type of nitric acid process used;
(f) Abatement technology used (if applicable);
(g) Abatement utilization factor (percent of time that abatement system is operating); and
(h) Abatement technology efficiency.
V—Nitric Acid
Production
(§98.220)
All in
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Page A-9
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Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
W—Oil &
Natural Gas
Systems
(§98.230)
25,000 metric tons
C02e/year
Stationary combustion
Production
See reporting requirements for stationary combustion
(a) Annual emissions reported separately for each of the operations listed in (a)(1) through (6) of this
paragraph. Within each operation, emissions from each source type must be reported in the
aggregate. For example, an underground natural gas storage facility with multiple reciprocating
compressors must report emissions from all reciprocating compressors as an aggregate number.
(1) Offshore petroleum and natural gas production facilities.
(2) Onshore natural gas processing facilities.
(3) Onshore natural gas transmission compression facilities.
(4) Underground natural gas storage facilities.
(5) Liquefied natural gas storage facilities.
(6) Liquefied natural gas import and export facilities.
(b) Emissions reported separately for standby equipment.
(c) Emissions calculated for these sources shall assume no CO2 capture and transfer offsite.
(d) Activity data for each aggregated source type level for which emissions are being reported.
(e) Engineering estimate of total component count.
(f) Total number of compressors and average operating hours per year for compressors for each
operation listed in paragraphs (a)(1) through (6) of this section.
(g) Minimum, maximum and average throughput for each operation listed in paragraphs (a)(1)
through (6) of this section.
(h) Specification of the type of any control device used, including flares, for any source type
listed in 98.232(a).
(i) For offshore petroleum and natural gas production facilities, the number of connected wells,
and whether they are producing oil, gas, or both.
(j) Detection and measurement instruments used.
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Page A-10
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Subpart
Reporting Threshold 1
X—Petrochemic All in
al Production
(§98.240)
Source Category
Reporting and Verification
Stationary combustion
Onsite wastewater
treatment
Production
See reporting requirements for stationary combustion
See reporting requirements for onsite wastewater treatment
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(a) Facilities using the mass balance methodology in §98.243(a)(2) must report the information
specified in paragraphs (a)(1) through (9) of this section for each type of petrochemical produced,
reported by process unit.
(1) Identification of the petrochemical process.
(2) Annual CO2 emissions calculated using Equation X‐4 of this subpart.
(3) Methods used to determine feedstock and product flows and carbon contents.
(4) Number of actual and substitute data points for each measured parameter.
(5) Annual quantity of each feedstock consumed.
(6) Annual quantity of each product and byproduct produced, including all products from integrated
processes that are part of the petrochemical production source category.
(7) Each carbon content measurement for each feedstock, product, and byproduct.
(8) All calculations, measurements, equipment calibrations, certifications, and other information
used to assess the uncertainty in emission estimates and the underlying volumetric flow rates, mass
flow rates, and carbon contents of feedstocks and products.
(9) Identification of any combustion units that burned process off‐gas.
(b) Each facility that uses CEMS to determine emissions from process vents must report the
verification data specified in §98.36(d)(1)(iv).
Page A-11
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Subpart
Reporting Threshold 1
Source Category
Y—Petroleum
Refineries
(§98.250)
All in
Stationary combustion
See reporting requirements for stationary combustion
Non‐merchant hydrogen See reporting requirements for hydrogen production
production
Onsite landfills
See reporting requirements for landfills
Onsite wastewater
See reporting requirements for onsite wastewater treatment
treatment
Catalytic cracking units, (1) The unit ID number (if applicable);
traditional fluid coking (2) A description of the type of unit (fluid catalytic cracking unit, thermal catalytic cracking unit,
units, catalytic reforming traditional fluid coking unit, catalytic reforming unit, sulfur recovery plant, or coke calcining unit);
units, sulfur recovery
(3) Maximum rated throughput of the unit, in bbl/stream day, metric tons sulfur produced/stream
plants, sour gas sent off‐ day, or metric tons coke calcined/stream day, as applicable;
site for sulfur recovery (4) The calculated CO2, CH4, and N2O annual emissions for each unit, expressed in metric tons of
operations, on‐site sulfur each pollutant emitted; and
recovery plants, and coke (5) A description of the method used to calculate the CO2 emissions for each unit (e.g., reference
section and equation number).
calcining units
Reporting and Verification
Fluid coking units of the (1) The unit ID number (if applicable);
flexicoking type
(2) A description of the type of unit;
(3) Maximum rated throughput of the unit, in bbl/stream day;
(4) Indicate whether the GHG emissions from the low heat value gas are accounted for in subpart C
of this part or §98.253(c); and
(5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit, also report
the calculated annual CO2, CH4, and N2O emissions for each unit, expressed in metric
tons of each pollutant emitted.
Asphalt blowing
operations
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(1) The unit ID number (if applicable);
(2) The quantity of asphalt blown;
(3) The type of control device used to reduce methane (and other organic) emissions from the unit;
and
(4) The calculated annual CO2, CH4, and N2O emissions for each unit, expressed in metric tons of
each pollutant emitted.
Page A-12
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Subpart
Reporting Threshold 1
Y—Petroleum All in
Refineries
(§98.250) (Cont.)
Source Category
Reporting and Verification
All other process vents
subject to §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; and
(4) The calculated annual CO2, CH4, and N2O emissions for each unit, expressed in metric tons of
each pollutant emitted.
Equipment leaks, storage (1) The total quantity (in million bbl) of crude oil plus the quantity of intermediate products received
tanks, uncontrolled
from off‐site that are processed at the facility in the reporting year.
(2) The method used to calculate equipment leak emissions and the calculated, cumulative CH4
blowdown systems,
delayed coking units, and emissions (in metric tons of each pollutant emitted) for all equipment leak sources;
(3) The cumulative annual CH4 emissions (in metric tons of each pollutant emitted) for all storage
loading operations
tanks, except for those used to process unstabilized crude oil;
(4) The quantity of unstabilized crude oil received during the calendar year and the cumulative CH4
emissions (in metric tons of each pollutant emitted) for storage tanks used to process unstabilized
crude oil;
(5) The cumulative annual CH4 emissions (in metric tons of each pollutant emitted) for uncontrolled
blowdown systems.
(6) The total number of delayed coking units at the facility, the number of delayed coking drums per
unit, the dimensions and annual number of coke‐cutting cycles for each drum, and the cumulative
annual CH4 emissions (in metric tons of each pollutant emitted) for delayed coking units.
(7) The quantity and types of materials loaded 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.
(8) 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.
(9) The cumulative annual CH4 emissions (in metric tons of each pollutant emitted) for
loading operations.
Overall Facility
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If you have a CEMS that measures CO2 emissions but that is not required to be used for reporting
GHG emissions under this subpart (i.e., a CO2 CEMS on a process heater stack but the combustion
emissions are calculated based on the fuel gas consumption), you must identify the emission source
that has the CEMS and report the CO2 emissions as measured by the CEMS for that emissions
source.
Page A-13
March 2009
Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
Z—Phosphoric All in
Acid Production
(§98.260)
Stationary combustion
Production
See reporting requirements for stationary combustion
(a) Annual phosphoric acid production by origin of the phosphate rock (in metric tons);
(b) Annual phosphoric acid production by concentration of phosphoric acid produced (metric tons).
(c) Annual phosphoric acid production capacity;
(d) Annual arithmetic average percent inorganic carbon in phosphate rock from batch records;
(e) Annual average phosphate rock consumption from monthly measurement records (in metric
tons).
AA—Pulp and
Paper
Manufacturing
(§98.270)
Stationary combustion
Onsite landfills
Onsite wastewater
treatment
Production
See reporting requirements for stationary combustion
See reporting requirements for landfills
See reporting requirements for onsite wastewater treatment
Stationary combustion
Production
See reporting requirements for stationary combustion
(a) Annual CO2 and CH4 emissions from all silicon carbide production processes combined (in metric
tons);
(b) Annual production of silicon carbide (in metric tons);
(c) Annual capacity of silicon carbide production (in metric tons);
(d) Annual operating hours; and
(e) Quarterly facility‐specific emission factors.
BB—Silicon
Carbide
Production
(§98.280)
25,000 metric tons
C02e/year
All in
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(a) Annual emissions of CO2, biogenic CO2, CH4, and N2O presented by calendar quarter;
(b) Total consumption of all biomass fuels by calendar quarter;
(c) Total annual quantity of spent liquor solids fired at the facility by calendar quarter;
(d) Total annual steam purchases; and
(e) Total annual quantities of makeup chemicals (carbonates) used.
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March 2009
Subpart
Reporting Threshold 1
Source Category
CC—Soda Ash
Manufacturing
(§98.290)
All in
Fuel combustion at each See reporting requirements for stationary combustion
kiln and from each
stationary combustion
unit
For each soda ash
(a) Annual CO2 process emissions (metric tons);
manufacturing line
(b) Number of soda ash manufacturing lines;
(c) Annual soda ash production (metric tons) and annual soda ash production capacity;
(d) Annual consumption of trona from monthly measurements (metric tons);
(e) Fractional purity (i.e., inorganic carbon content) of trona or soda ash (by daily measurements and
by monthly average) depending on the components used in Equation CC‐2 or CC‐3 of this subpart);
and
(f) Number of operating hours in calendar year.
DD—Sulfur
Hexafluoride
(SF6) from
Electrical
Equipment
(§98.300)
17,820 lbs (7,838 kg) Electric power system
(Total nameplate
capacity of SF6 and PFC
containing equipment
in the system)
EE—Titanium
Dioxide
Production
(§98.310)
All in
Stationary combustion
Production
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Reporting and Verification
Report the following information for each electric power system, by chemical:
(a) Nameplate capacity of equipment containing SF6 and nameplate capacity of equipment
containing each PFC:
(1) Existing as of the beginning of the year.
(2) New during the year.
(3) Retired during the year.
(b) Transmission miles (length of lines carrying voltages at or above 34.5 kV).
(c) SF6 and PFC sales and purchases.
(d) SF6 and PFC sent off site for destruction.
(e) SF6 and PFC sent off site to be recycled.
(f) SF6 and PFC returned from off site after recycling.
(g) SF6 and PFC stored in containers at the beginning and end of the year.
(h) SF6 and PFC with or inside new equipment purchased in the year.
(i) SF6 and PFC with or inside equipment sold to other entities.
(j) SF6 and PFC returned to suppliers.
See reporting requirements for stationary combustion
For each titanium dioxide production line:
(a) Annual CO2 emissions (metric tons);
(b) Annual consumption of calcined petroleum coke (metric tons);
(c) Annual production of titanium dioxide (metric tons);
(e) Annual production capacity of titanium dioxide (metric tons); and
(f) Annual operating hours for each titanium dioxide process line.
Page A-15
March 2009
Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
FF—Undergroun All active underground Stationary combustion
d Coal Mines
coal mines for which Production
(§98.320)
CH4 from the
ventilation system is
sampled quarterly by
MSHA (or on a more
frequent basis)
See reporting requirements for stationary combustion
(a) Quarterly volumetric flow rate measurement results for all ventilation systems, including date
and location of measurement.
(b) Quarterly CH4 concentration measurement results for all ventilation systems, including date and
location of measurement.
(c) Quarterly CEMS volumetric flow data used to calculate CH4 liberated from degasification systems
(summed from daily data).
(d) Quarterly CEMS CH4 concentration data used to calculate CH4 liberated from degasification
systems (average from daily data).
(e) Quarterly CH4 destruction at ventilation and degasification systems.
(f) Dates in reporting period where active ventilation of mining operations is taking place.
(g) Dates in reporting period when continuous monitoring equipment is not properly functioning.
(h) Quarterly averages of temperatures and pressures at the time and at the conditions for which all
measurements are made.
(i) Quarterly CH4 liberated from each ventilation well or shaft, and from each degasification system
(this includes degasification systems deployed before, during, or after mining operations are
conducted in a mine area).
(j) Quarterly CH4 emissions (net) from each ventilation well or shaft, and from each
degasification system (this includes degasification systems deployed before, during,
or after mining operations are conducted in a mine area).
(k) Quarterly CO2 emissions from onsite destruction of coal mine gas CH4, where the
gas is not a fuel input for energy generation or use.
GG—Zinc
Production
(§98.330)
See reporting requirements for stationary combustion
For each Waelz kiln or electrothermic furnace:
(a) Annual CO2 emissions in metric tons, and the method used to estimate emissions.
(b) Annual zinc product production capacity (in metric tons).
(c) Total number of Waelz kilns and electrothermic furnaces at the facility.
(d) Number of facility operating hours in calendar year.
(e) If you use the carbon input procedure, report for each carbon‐containing input material
consumed or used (other than fuel) report:
(1) Annual material quantity (in metric tons); and
(2) Annual average of the monthly carbon content determinations for each material and the method
used for the determination (e.g., supplier provided information, analyses of representative samples
you collected).
25,000 metric tons
C02e/year
Stationary combustion
Production
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Page A-16
March 2009
Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
HH—Landfills
(§98.340)
25,000 metric tons
C02e/year of
generation
Stationary combustion
Production (As required
by related source
methodology)
See reporting requirements for stationary combustion
(a) Waste disposal for each year of landfilling. (b) Method for estimating waste disposal. (c) Waste
composition, if available, in percentage categorized as (1) municipal, (2) construction and
demolition, (3) biosolids or biological sludges, (4) industrial, inorganic, (5) industrial, organic, (6)
other, or more refined categories, such as those for which k rates are available in Table HH‐1 of this
subpart. (d) Method for estimating waste composition. (e) Fraction of CH4 in landfill gas based on
measured values if the landfill has a gas collection system or a default. (f) Oxidation fraction used in
the calculations. (g) Degradable organic carbon (DOC) used in the calculations. (h) Decay rate (k)
used in the calculations. (i) Fraction of DOC dissimilated used in the calculations.(j) Methane
correction factor used in the calculations. (k) Annual methane generation and methane emissions
(metric tons/year) according to the methodologies in §98.343(c)(1) through (3). Landfills with gas
collection system must separately report methane generation and emissions according to the
methodologies in
§98.343(c)(3)(i) and (ii) and indicate which values are calculated using the methodologies in
§98.343(c)(ii). (l) Landfill design capacity. (m) Estimated year of landfill closure. (n) Total
volumetric flow of landfill gas for landfills with gas collection systems. (o) CH4
concentration of landfill gas for landfills with gas collection systems. (p) Monthly average
temperature at which flow is measured for landfills with gas collection systems. (q) Monthly
average pressure at which flow is measured for landfills with gas collection systems. (r)
Destruction efficiency used for landfills with gas collection systems. (s) Methane destruction
for landfills with gas collection systems (total annual, metric tons/year). (t) Estimated gas
collection system efficiency for landfills with gas collection systems. (u) Methodology for
estimating gas collection system efficiency for landfills with gas collection systems. (v)
Cover system description. (w) Number of wells in gas collection system. (x) Acreage and
quantity of waste covered by intermediate cap. (y) Acreage and quantity of waste covered by
final cap. (z) Total CH4 generation from landfills. (aa) Total CH4 emissions from landfills.
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Page A-17
March 2009
Subpart
Reporting Threshold 1
II—Wastewater N/A
(§98.350)
Source Category
Reporting and Verification
Stationary combustion
Production (As required
by related source
methodology)
See reporting requirements for stationary combustion
(a) Type of wastewater treatment system.
(b) Percent of wastewater treated at each system component.
(c) COD.
(d) Influent flow rate.
(e) B0.
(f) MCF.
(g) Methane emissions.
(h) Type of oil/water separator (petroleum refineries).
(i) Emissions factor for the type of separator (petroleum refineries).
(j) Carbon fraction in NMVOC (petroleum refineries).
(k) CO2 emissions (petroleum refineries).
(l) Total volumetric flow of digester gas (facilities with anaerobic digesters).
(m) CH4 concentration of digester gas (facilities with anaerobic digesters).
(n) Temperature at which flow is measured (facilities with anaerobic digesters).
(o) Pressure at which flow is measured (facilities with anaerobic digesters).
(p) Destruction efficiency used (facilities with anaerobic digesters).
(q) Methane destruction (facilities with anaerobic digesters).
(r) Fugitive methane (facilities with anaerobic digesters).
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Page A-18
March 2009
Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
JJ—Manure
Management
(§98.360)
25,000 metric tons
C02e/year of
generation
Stationary combustion
Production (As required
by related source
methodology)
See reporting requirements for stationary combustion
For each management system component, report the following:
(a) Type(s) of manure management system.
(b) Animal population (by animal type).
(c) Monthly total volatile solids content of excreted manure.
(d) Percent of manure handled in each manure management system component.
(e) B0 value used.
(f) Methane conversion factor used.
(g) Average animal mass (for each type of animal).
(h) Monthly nitrogen content of excreted manure.
(i) N2O emission factor selected.
(j) CH4 emissions.
(k) N2O emissions.
(l) Total annual volumetric biogas flow (for systems with digesters).
(m) Average annual CH4 concentration (for systems with digesters).
(n) Temperature at which gas flow is measured (for systems with digesters).
(o) Pressure at which gas flow is measured (for systems with digesters).
(p) Destruction efficiency used (for systems with digesters).
(q) Methane destruction (for systems with digesters).
(r) Methane generation from the digesters.
Coal mine owner or
operator
For each coal mine:
(1) The name and MSHA ID number of the mine.
(2) The name of the operating company.
(3) Annual CO2 emissions.
(4) By rank, the total annual quantity in tons of coal produced.
(5) The annual weighted carbon content of the coal as calculated according to §98.373.
(6) If Method 1 was used to determine CO2 mass emissions, you must report daily mass fraction of
carbon in coal measured by ultimate analysis and daily amount of coal supplied.
(7) If Method 2 was used to determine CO2 mass emissions, you must report:
(i) All of the data used to construct the carbon vs. Btu/lb correlation graph;
(ii) Slope of the correlation line; and
(iii) The R‐squared (R2) value of the correlation.
(8) If Method 3 was used to determine CO2 mass emissions, you must report daily GCV of coal
measured by proximate analysis and daily amount of coal supplied.
KK—Suppliers of All in
Coal (§98.370)
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Page A-19
March 2009
Subpart
Reporting Threshold 1
KK—Suppliers of All in
Coal (§98.370)
(Cont.)
Source Category
Reporting and Verification
Coal importers
Report the following information at the corporate level:
(1) The total annual quantity in tons of coal imported into the U.S. by the importer, by rank, and
country of origin.
(2) Annual CO2 emissions.
(3) The annual weighted carbon content of the coal as calculated according to §98.373.
(4) If Method 1 was used to determine CO2 mass emissions, you must report mass fraction of carbon
in coal per shipment measured by ultimate analysis and amount of coal supplied per shipment.
(5) If Method 2 was used to determine CO2 mass emissions, you must report:
(i) All of the data used to construct the carbon vs. Btu/lb correlation graph;
(ii) Slope of the correlation line; and
(iii) The R‐squared (R2) value of the correlation.
(6) If Method 3 was used to determine CO2 mass emissions, you must report GCV in coal per
shipment measured by proximate analysis and amount of coal supplied per shipment.
Coal exporters
Report the following information at the corporate level:
(1) The total annual quantity in tons of coal exported from the U.S. by rank and by coal producing
company and mine.
(2) Annual CO2 emissions.
(3) The annual weighted carbon content of the coal as calculated according to §98.373.
(4) If Method 1 was used to determine CO2 mass emissions, you must report mass fraction of carbon
in coal per shipment measured by ultimate analysis and amount of coal supplied per shipment.
(5) If Method 2 was used to determine CO2 mass emissions, you must report:
(i) All of the data used to construct the carbon vs. Btu/lb correlation graph;
(ii) Slope of the correlation line; and
(iii) The R‐sqaured (R2) value of the correlation.
(6) If Method 3 was used to determine CO2 mass emissions, you must report GCV in coal per
shipment measured by proximate analysis and amount of coal supplied per shipment.
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Page A-20
March 2009
Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
KK—Suppliers of All in
Coal (§98.370)
(Cont.)
Waste coal reclaimers
Report the following information for each reclamation facility:
(1) By rank, the total annual quantity in tons of waste coal produced.
(2) Mine and state of origin if waste coal is reclaimed from mines that are no longer operating.
(3) Annual CO2 emissions.
(4) The annual weighted carbon content of the coal as calculated according to §98.373.
(5) If Method 1 was used to determine CO2 mass emissions, you must report mass fraction of carbon
in coal per shipment measured by ultimate analysis and amount of coal supplied per shipment.
(6) If Method 2 was used to determine CO2 mass emissions, you must report:
(i) All of the data used to construct the carbon vs. Btu/lb correlation graph;
(ii) Slope of the correlation line; and
(iii) The R‐squared (R2) value of the correlation.
(7) If Method 3 was used to determine CO2 mass emissions, you must report GCV in coal per
shipment measured by proximate analysis and amount of coal supplied per shipment.
LL—Suppliers of All in
Coal‐based
Liquid Fuels
(§98.380)
Producers
(1) The total annual volume of each coal‐based liquid supplied to the economy (in standard barrels).
(2) The total annual CO2 emissions in metric tons associated with each coal‐based liquid supplied to
the economy, calculated according to §98.383(a).
Importers
(1) The total annual volume of each imported coal‐based liquid (in standard barrels).
(2) The total annual CO2 emissions in metric tons associated with each imported coal‐based liquid,
calculated according to §98.383(a).
(1) The total annual volume of each exported coal‐based liquid (in standard barrels).
(2) The total annual CO2 emissions in metric tons associated with each exported coal‐based liquid,
calculated according to §98.383(a).
Exporters
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Page A-21
March 2009
Subpart
Reporting Threshold 1
MM—Suppliers All in
of Petroleum
Products
(§98.390)
Source Category
Reporting and Verification
Refiners
(1) CO2 emissions in metric tons for each petroleum product and natural gas liquid (ex refinery gate),
calculated according to §98.393(a) or (g).
(2) CO2 emissions in metric tons for each petroleum product or natural gas liquid that enters the
refinery annually as a feedstock to be further refined or otherwise used onsite, calculated according
to §98.393(b) or (g).
(3) CO2 emissions in metric tons from each type of biomass feedstock co‐processed with petroleum
feedstocks, calculated according to §98.393(c).
(4) The total sum of CO2 emissions from all products, calculated according to §98.393(d).
(5) The total volume of each petroleum product and natural gas liquid associated with the CO2
emissions reported in paragraphs (1) and (2), seperately, and the volume of the biomass‐based
component of each petroleum product reported in this paragraph that was produced by blending a
petroleum‐based product with a biomass‐based product. If a determination cannot be made
whether the material is a petroleum product or a natural gas liquid, it shall be reported as a
petroleum product.
(6) The total volume of any biomass co‐processed with a petroleum product associated
with the CO2 emissions reported in paragraph (3).
(7) The measured density and/or mass carbon share for any petroleum product or natural
gas liquid for which CO2 emissions were calculated using Calculation Methodology 2 of this
subpart, along with the selected method from §98.394(c) and the calculated EF.
(8) The total volume of each distillate fuel oil product or feedstock reported in paragraph
(5) that contains less than 15 ppm sulfur content and is free from marker
solvent yellow 124 and dye solvent red 164.
(9) All of the following information for all crude oil feedstocks used at the refinery:
(i) Batch volume (in standard barrels). (ii) API gravity of the batch. (iii) Sulfur
content of the batch. (iv) Country of origin of the batch.
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Page A-22
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Subpart
Reporting Threshold 1
MM—Suppliers All in
of Petroleum
Products
(§98.390) (Cont.)
Source Category
Reporting and Verification
Importers
Report the following information at the corporate level:
(1) CO2 emissions in metric tons for each imported petroleum product and natural gas liquid,
calculated according to §98.393(a).
(2) Total sum of CO2 emissions, calculated according to §98.393(e).
(3) The total volume of each imported petroleum product and natural gas liquid associated with the
CO2 emissions reported in paragraph (1) of this section as well as the volume of the biomass‐based
component of each petroleum product reported in this paragraph that was produced by blending a
petroleum‐based product with a biomass‐based product. If you cannot determine whether the
material is a petroleum product or a natural gas liquid, you shall report it as a petroleum product.
(4) The measured density and/or mass carbon share for any imported petroleum product or natural
gas liquid for which CO2 emissions were calculated using Calculation Methodology 2 of this subpart,
along with the selected method from §98.394(c) and the calculated EF.
(5) The total volume of each distillate fuel oil product reported in paragraph (1) of this section that co
dye solvent red 164.
Exporters
Report the following information at the corporate level:
(1) CO2 emissions in metric tons for each exported petroleum product and natural gas liquid,
calculated according to §98.393(a).
(2) Total sum of CO2 emissions, calculated according to §98.393(e).
(3) The total volume of each exported petroleum product and natural gas liquid associated with the
CO2 emissions reported in paragraph (1) of this section as well as the volume of the biomass‐based
component of each petroleum product reported in this paragraph that was produced by blending a
petroleum‐based product with a biomass‐based product. If you cannot determine whether the
material is a petroleum product or a natural gas liquid, you shall report it as a petroleum product.
(4) The measured density and/or mass carbon share for any petroleum product or natural gas liquid
for which CO2 emissions were calculated using Calculation Methodology 2 of this section, along with
the selected method from §98.394(c) and the calculated EF.
(5) The total volume of each distillate fuel oil product reported in paragraph (1) that contains less than
dye solvent red 164.
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Page A-23
March 2009
Subpart
Reporting Threshold 1
NN—Suppliers of All in
Natural Gas and
Natural Gas
Liquids (§98.400)
Source Category
Reporting and Verification
Natural gas processing
plants
(1) The total annual quantity in barrels of NGLs produced for sale or delivery on behalf of others in
the following categories: propane, natural butane, ethane, and isobutane, and all other bulk NGLs
as a single category; and
(2) The total annual CO2 mass emissions associated with the volumes in paragraph (1) and calculated
in accordance with §98.403.
Local distribution
companies
(1) The total annual volume in Mcf of natural gas received by the local distribution company for
redelivery to end users on the local distribution company’s distribution system.
(2) The total annual CO2 mass emissions associated with the volumes in paragraph (1) and calculated
in accordance with §98.403.
(3) The total natural gas volumes received for redelivery to downstream gas transmission pipelines
and other local distribution companies.
(4) The name and EPA and EIA identification code of each individual covered facility, and the name
and EIA identification code of any other end‐user for which the local gas distribution company
delivered greater than or equal to 460,000 Mcf during the calendar year, and the total natural gas
volumes actually delivered to each of these end‐users.
(5) The annual volume in Mcf 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 and
Instructions.
(i) residential consumers.
(ii) commercial consumers.
(iii) industrial consumers.
(iv) electricity generating facilities.
(6) The total annual CO2 mass emissions associated with the volumes in paragraph (5) and
calculated in accordance with §98.403.
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Page A-24
March 2009
Subpart
Reporting Threshold 1
OO—Suppliers All in
of Industrial
Greenhouse
Gases (§98.410)
Source Category
Reporting and Verification
Fluorinated GHG or
(1) Total mass in metric tons of each fluorinated GHG or nitrous oxide produced at that facility.
nitrous oxide production (2) Total mass in metric tons of each fluorinated GHG or nitrous oxide transformed at that facility.
facility
(3) Total mass in metric tons of each fluorinated GHG destroyed at that facility.
(4) Total mass in metric tons of any fluorinated GHG or nitrous oxide sent to another facility for
transformation.
(5) Total mass in metric tons of any fluorinated GHG sent to another facility for destruction.
(6) Total mass in metric tons of each reactant fed into the production process.
(7) Total mass in metric tons of each non‐GHG reactant and by‐product permanently removed from
the process.
(8) Mass of used product added back into the production process (e.g., for reclamation).
(9) 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.
(10) Names and addresses of facilities to which any fluorinated GHGs were sent for destruction, and
the quantities (metric tons) of nitrous oxide and of each fluorinated
GHG that were sent to each for destruction.
(11) Where missing data have been estimated pursuant to §98.415, the reason the data
were missing, the length of time the data were missing, the method used to estimate
the missing data, and the estimates of those data. Where the missing data have been
estimated pursuant to §98.415(a)(3), the report shall explain the rationale for the methods
used to estimate the missing data and why the methods specified in §98.415(a)(1) and
(a)(2) would lead to a significant under‐ or overestimate of the parameters.
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Page A-25
March 2009
Subpart
Reporting Threshold 1
OO—Suppliers 25,000 metric tons
of Industrial
C02e/year
Greenhouse
Gases (§98.410)
(Cont.)
Source Category
Reporting and Verification
Fluorinated GHG
(a) Report the results of the annual fluorinated GHG concentration measurements at the outlet of
production facilities that the destruction device, including:
destroy fluorinated GHGs (1) Flow rate of fluorinated GHG being fed into the destruction device in kg/hr.
(2) Concentration (mass fraction) of fluorinated GHG at the outlet of the destruction device.
(3) Flow rate at the outlet of the destruction device in kg/hr.
(4) Emission rate calculated from (a)(2) and (a)(3) in kg/hr.
(b) A fluorinated GHG production facility that destroys fluorinated GHGs shall submit a one‐time
report containing the following information:
(1) Destruction efficiency (DE) of each destruction unit.
(2) Test method 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 importers of
fluorinated GHGs or
nitrous oxide
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With the exception of transhipments and heels, bulk importers must submit an annual report that
summarizes their imports at the corporate level. For each import report:
(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG imported in bulk.
(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) 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 transforma
(9) If applicable, the names and addresses of the persons and facilities to which the nitrous oxide or fl
(metric tons) of nitrous oxide and of each fluorinated GHG that were sold or transferred to
each facility for destruction.
Page A-26
March 2009
Subpart
Reporting Threshold 1
Source Category
Reporting and Verification
OO—Suppliers 25,000 metric tons
of Industrial
C02e/year
Greenhouse
Gases (§98.410)
(Cont.)
Bulk exporter of
With the exception of transhipments and heels, bulk exporters must submit an annual report that
fluorinated GHGs or N2O summarizes their imports at the corporate level. For each export report:
(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) Quantity exported by chemical in metric tons of chemical;
(5) Commodity code of the fluorinated GHGs and nitrous oxide shipped;
(6) Date on which, and the port from which, fluorinated GHGs and nitrous oxide were exported from
the United States or its territories; and
(7) Country to which the fluorinated GHGs or nitrous oxide were exported.
PP—Suppliers of All in
Production
(a) Each facility with production process units or CO2 production wells must report the following
Carbon Dioxide
information:
(§98.420)
(1) Total annual mass in metric tons and the weighted average composition of the CO2 stream
captured, extracted, or transferred in either gas, liquid, or solid forms.
(2) Annual quantities in metric tons transferred to the following end use applications by end‐use, 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.
Importers and exporters (b) CO2 importers and exporters must report the information in paragraphs (a)(1) and (2) at the
corporate level.
1 Many facilities that would be affected by the proposed 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.
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Page A-27
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Table A-2 Recordkeepings Requirements
Subpart
Source Category
Recordkeeping (5 years unless otherwise noted)
C—General Stationary Fuel Combustion Sources (§ 98.30). See ICR section 4(b)(i).
D—Electricity
All facilities
See recordkeeping requirements for stationary combustion
Generation
(§98.40)
E—Adipic Acid Stationary combustion
See recordkeeping requirements for stationary combustion
Production
(a) Annual N2O emissions from adipic acid production in metric tons;
Production
(b) Annual adipic acid production capacity (in metric tons);
(§98.50)
(c) Annual adipic acid production, in units of metric tons of adipic acid produced;
(d) Number of facility operating hours in calendar year;
(e) Measurements, records and calculations used to determine the annual production rate; and
(f) Emission rate factor used and supporting test or calculation information including the annual emission rate factor determination report
specified in §98.54(c). This report must be available upon request.
F—Aluminum
Production
(§98.60)
Stationary combustion
Production
See recordkeeping requirements for stationary combustion
(a) Monthly aluminum production in metric tons.
(b) Type of smelter technology used.
(c) The following PFC‐specific information on a monthly basis:
(1) Perfluoromethane and perfluoroethane emissions from anode effects in each prebake and Søderberg electolysis cells.
(2) Anode effect minutes per cell‐day, anode effect frequency (AE/cell‐day), anode effect duration (minutes) from each prebake and Søderberg
eletolysis cells.
(3) Smelter‐specific slope coefficient and the last date when the smelter‐specific‐slope coefficient was measured.
(d) Method used to measure the frequency and duration of anode effects.
(e) The following CO2‐specific information for prebake cells on an annual basis:
(1) Total anode consumption.
(2) Total CO2 emissions from the smelter.
(f) The following CO2‐specific information for Søderberg cells on an annual basis:
(1) Total paste consumption.
(2) Total CO2 emissions from the smelter.
(g) 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.
(h) Exact data elements required will vary depending on smelter technology (e.g., point‐feed prebake or Søderberg).
G—Ammonia
Manufacturing
(§98.70)
Stationary combustion
Production
See recordkeeping requirements for stationary combustion
(a) Method used for determining quantity of feedstock used.
(b) Monthly analyses of carbon content for each feedstock used in ammonia manufacturing.
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Subpart
Source Category
Recordkeeping (5 years unless otherwise noted)
H—Cement
Production
(§98.80)
Fuel combustion at kilns See recordkeeping requirements for stationary combustion
and any other Stationary
combustion unit
Production
(a) Monthly carbonate consumption.
(b) Monthly clinker production (tons).
(c) Monthly CKD production (in metric tons).
(d) Total annual fraction of CKD recycled to the kiln (as a percentage).
(e) Monthly analysis of carbonate composition in clinker (by carbonate).
(f) Monthly analysis of fraction of calcination achieved for CKD and each carbonate.
(g) Monthly cement production.
(h) Documentation of calculated site‐specific clinker emission factor.
(i) Facilities that use CEMS must also comply with the recordkeeping requirements specified in §98.37.
I—Electronics
Manufacturing
(§98.90)
Stationary combustion
Production
J—Ethanol
Production
(§98.100)
Onsite stationary
combustion
Onsite landfills
Onsite wastewater
treatment
See recordkeeping requirements for stationary combustion
(a) Data used to estimate emissions including all spreadsheets and copies of calculations used to estimate emissions.
(b) Documentation for the values used for GHG utilization rates and by‐product emission factors, including documentation that these were
measured using the the International SEMATECH Manufacturing Initiative’s Guideline for Environmental Characterization of Semiconductor
Process Equipment.
(c) The date and results of the initial and any subsequent tests of emission control device DRE, including the following information:
(1) Dated certification, by the technician who made the measurement, that the dilution factor was determined using the tracer method.
(2) Dated certification, by the technician who made the measurement, that the DRE was calculated using the formula given in §98.94(c)(1)(iv).
(3) Documentation of the measured flows, concentrations and calculations used to calculate DF, relative precision (ε), and DRE.
(d) The date and results of the initial and any subsequent tests to determine process tool gas utilization and by‐product formation factors
See recordkeeping requirements for stationary combustion
See recordkeeping requirements for landfills
See recordkeeping requirements for wastewater treatment
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Subpart
Source Category
Recordkeeping (5 years unless otherwise noted)
K—Ferroalloy
Production
(§98.110)
Stationary combustion
Production
See recordkeeping requirements for stationary combustion
(a) Monthly facility production quantity for each ferroalloy product (in metric tons).
(b) Number of facility operating hours each month.
(c) If you use the carbon balance procedure, record for each carbon‐containing input and output material consumed or used (other than fuel),
the information specified in paragraphs (c)(1) and (2) of this section.
(1) Monthly material quantity (in metric tons); and
(2) Monthly average carbon content determined for material and records of the supplier provided information or analyses used for the
determination.
(d) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input
input and output to each electric arc furnace. You also must document the procedures used to ensure the accuracy of the measurements of
materials fed, charged, or placed in an affected unit including, but not limited to, calibration of weighing equipment and other measurement
devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates
must be provided.
(e) If you are required to calculate CH4 emissions for the electric arc furnace as specified in §98.113(c),
you must maintain records of the total amount of each alloy product produced for the specified reporting
period, and the appropriate alloy‐product specific emission factor used to calculate CH4 emissions.
See recordkeeping requirements for stationary combustion
(a)(1) Dated records of the data used to estimate the data reported under §§98.123 and 98.126 of this subpart, and
(a)(2) Dated records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, flowmeters, and volumetric and
density measures used to measure the quantities reported under this subpart, including the industry standards or manufacturer directions used
for calibration pursuant to §98.124(g) and (h).
L—Fluorinated Stationary combustion
Greenhouse Gas Production
Production
(§98.120)
(b) In addition to the data required by paragraph (a) of this section, the designated representative of a fluorinated GHG production facility that
destroys fluorinated GHGs shall keep records of test reports and other information documenting the facility’s one‐time destruction efficiency
report and annual destruction device outlet reports in §98.126(c) and (d).
M—Food
Processing
(§98.130)
N—Glass
Production
(§98.140)
Onsite stationary
combustion
Onsite landfills
Onsite wastewater
treatment
Stationary combustion
Production
See recordkeeping requirements for stationary combustion
See recordkeeping requirements for landfills
See recordkeeping requirements for wastewater treatment
See recordkeeping requirements for stationary combustion
(a) Total number of continuous glass melting furnaces.
(b) Monthly glass production rate for each continuous glass melting furnace.
(c) Monthly amount of each carbonate‐based raw material charged to each continuous glass melting furnace.
(d) If process CO2 emissions are calculated using data provided by the raw material supplier, retain:
(1) Data on carbonate‐based mineral mass fractions provided by the raw material supplier.
(2) 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.
(e) All other documentation used to support the reported GHG emissions.
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Subpart
Source Category
HCFC‐22 Production
O—HCFC‐22
Production and Facility
HFC‐23
Destruction
(§98.150)
HFC‐23 Destruction
Facility
P—Hydrogen
Production
(§98.160)
Q—Iron & Steel
Production
(§98.170)
Stationary combustion
Production
R—Lead
Production
(§98.180)
Stationary combustion
Production
Stationary combustion
Production
Recordkeeping (5 years unless otherwise noted)
(1) The data used to estimate HFC‐23 emissions.
(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements,
and and flowmeters used to measure the quantities reported under this rule, including the industry standards or manufacturer directions used
for calibration pursuant to §98.154 (o) and (p).
(1) Records documenting their one‐time and annual reports in §98.156(c), (d), and (e).
(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements,
and flowmeters used to measure the quantities reported under this subpart, including the industry standards or manufacturer directions used
for calibration pursuant to §98.154(o) and (p).
See recordkeeping requirements for stationary combustion
(a) For all CEMS, compliance with the CEMS recordkeeping requirements in §93.37.
(b) Monthly analyses of carbon content for each feedstock used in hydrogen production.
See recordkeeping requirements for stationary combustion
(a) Annual CO2 emissions as measured or determined for each calendar quarter;
(b) Monthly total for all process inputs and outputs for each calendar quarter when the carbon balance is used for specific processes;
(c) Monthly analyses of carbon content for each calendar quarter when the carbon balance is used for specific processes;
(d) Site‐specific emission factor for all process units for which the site‐specific emission factor approach is used;
(e) Annual production quantity for taconite pellets, coke, sinter, iron, and raw steel with records for each calendar quarter; and
(f) Facilities must keep records that include a detailed explanation of how company records or measurements are used to determine all sources
of carbon input and output and the metric tons of coal charged to the coke ovens (e.g., weigh belts, a combination of measuring volume and
bulk density). The owner or operator also must document the procedures used to ensure the accuracy of the measurements of fuel usage
including, but not limited to, calibration of weighing equipment, fuel flow meters, coal usage including, but not limited to, calibration of
weighing equipment and other measurement devices.
The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these
estimates must be provided.
See recordkeeping requirements for stationary combustion
(a) Monthly facility production quantity for each lead product (in metric tons).
(b) Number of facility operating hours each month.
(c) For each carbon‐containing input material consumed or used (other than fuel) record:
(1) Monthly material quantity (in metric tons); and
(2) Monthly average carbon content determined for material and records of the supplier provided information or analyses used for the
determination.
(d) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input
to each smelting furnace. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged,
or placed in an affected unit including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated
accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
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Subpart
Source Category
Recordkeeping (5 years unless otherwise noted)
S—Lime
Manufacturing
(§98.190)
Stationary combustion
Production
See recordkeeping requirements for stationary combustion
For each lime kiln:
(1) Annual calcined by‐products/waste products (by lime type summed from monthly data.
(2) Lime production (by lime type) per month (metric tons).
(3) Calculation of emission factors.
(4) Results of chemical composition analysis (by lime product) per month.
(5) Monthly correction factors for by‐products/waste products for each kiln.
T—Magnesium
Production
(§98.200)
Stationary combustion
Production
See recordkeeping requirements for stationary combustion
(a) Check‐out and weigh‐in sheets and procedures for cylinders;
(b) Accuracy certifications and calibration records for scales;
(c) Residual gas amounts in cylinders sent back to suppliers; and
(d) Invoices for gas purchases and sales.
U—Misc. Uses of Production
Carbonate
(§98.210)
(a) Records of monthly carbonate consumption (by carbonate type). You must also document the procedures used to ensure the accuracy of
monthly carbonate consumption.
(b) Annual chemical analysis of mass fraction of carbonate‐based mineral in carbonate‐based raw material by carbonate type.
(c) You must keep a record of all carbonate purchases and deliveries.
V—Nitric Acid
Production
(§98.220)
See recordkeeping requirements for stationary combustion
For each nitric acid production line:
(a) Records of significant changes to process;
(b) Annual test reports of N2O emissions; and
(c) Calculations of the site‐specific emissions factor.
Stationary combustion
Production
W—Oil & Natural Stationary combustion
Production
Gas Systems
(§98.230)
See recordkeeping requirements for stationary combustion
(a) Dates on which measurements were conducted.
(b) Results of all emissions detected, whether quantification was made pursuant to §98.234(k) and measurements.
(c) Calibration reports for detection and measurement instruments used.
(d) Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions.
X—Petrochemica Stationary combustion
Onsite wastewater
l Production
treatment
(§98.240)
Production
See recordkeeping requirements for stationary combustion
See recordkeeping requirements for onsite wastewater treatment
(a) The CEMS recordkeeping requirements in §98.37, if you operate a CEMS on process vents.
(b) Results of feedstock or product composition determinations conducted in accordance with §98.243(a)(2)(iv).
(c) Start and end times and calculated carbon contents for time periods when off‐specification product is produced, if you comply with the
alternative methodology in §98.243(a)(2)(iv) for determining carbon content of feedstock or product.
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Subpart
Source Category
Stationary combustion
Non‐merchant hydrogen
production
Onsite landfills
Onsite wastewater
treatment
Production
Z—Phosphoric Stationary combustion
Acid Production Production
(§98.260)
Y—Petroleum
Refineries
(§98.250)
Recordkeeping (5 years unless otherwise noted)
See recordkeeping requirements for stationary combustion
See recordkeeping requirements for hydrogren production
See recordkeeping requirements for landfills
See recordkeeping requirements for onsite wastewater treatment
Retain records of all parameters monitored under §98.255 (Procedures for estimating missing data)
See recordkeeping requirements for stationary combustion
For each wet‐process phosphoric acid production facility:
(a) Total annual CO2 emissions from all wet‐process phosphoric acid process lines (in metric tons);
(b) Phosphoric acid production (by origin of the phosphate rock) and concentration;
(c) Phosphoric acid production capacity (in metric tons/year);
(d) Number of wet‐process phosphoric acid process lines;
(e) Monthly phosphate rock consumption (by origin of phosphate rock);
(f) Measurements of percent inorganic carbon in phosphate rock for each batch consumed for phosphoric acid production;
(g) Records of all phosphate rock purchases and/or deliveries (if vertically integrated with a mine); and
(h) Documentation of the procedures used to ensure the accuracy of monthly phosphate rock consumption
See recordkeeping requirements for stationary combustion
(a) GHG emission estimates (including separate estimates of biogenic CO2) by calendar quarter for each emissions source listed under
§98.270(b) of this subpart;
(b) Monthly total consumption of all biomass fuels for each biomass combustion unit;
(c) Monthly analyses of spent pulping liquor HHV for each chemical recovery furnace at kraft and soda facilities;
(d) Monthly analyses of spent pulping liquor carbon content for each chemical recovery combustion unit at a sulfite or semichemical pulp
facility;
(e) Monthly quantities of spent liquor solids fired in each chemical recovery furnace and chemical recovery combustion unit;
(f) Monthly and annual steam purchases;
(g) Monthly and annual steam production for each biomass combustion unit;
(h) Monthly quantities of makeup chemicals used
AA—Pulp and
Paper
Manufacturing
(§98.270)
Stationary combustion
Production
BB—Silicon
Carbide
Production
(§98.280)
Stationary combustion
Production
CC—Soda Ash
Manufacturing
(§98.290)
Fuel combustion at each See recordkeeping requirements for stationary combustion
kiln and from each
stationary combustion
unit
For each soda ash
(a) Monthly production of soda ash (metric tons);
manufacturing line
(b) Monthly consumption of trona (metric tons);
(c) Daily analyses for inorganic carbon content of trona or soda ash (as fractional purity), depending on the components used in Equation CC‐2
or CC‐3 of this subpart; and
(d) Number of operating hours in calendar year.
See recordkeeping requirements for stationary combustion
(a) Annual consumption of petroleum coke (in metric tons);
(b) Quarterly analyses of carbon content for consumed coke (averaged to an annual basis); and
(c) Quarterly facility‐specific emission factor calculations.
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Subpart
Source Category
Recordkeeping (5 years unless otherwise noted)
DD—Sulfur
Hexafluoride
(SF6) from
Electrical
Equipment
(§98.300)
Electric power system
Retain records of the information reported and listed in §98.306.
EE—Titanium
Dioxide
Production
(§98.310)
Stationary combustion
Production
See recordkeeping requirements for stationary combustion
(a) Monthly production of titanium dioxide (metric tons);
(b) Production capacity of titanium dioxide (metric tons);
(c) Records of all calcined petroleum coke purchases;
(d) Records of monthly calcined petroleum coke consumption (metric tons); and
(e) Annual operating hours for each titanium dioxide process line.
FF—Undergroun Stationary combustion
Production
d Coal Mines
(§98.320)
See recordkeeping requirements for stationary combustion
(a) Calibration records for all monitoring equipment.
(b) Records of gas sales.
(c) Logbooks of parameter measurements.
(d) Laboratory analyses of samples.
GG—Zinc
Production
(§98.330)
Stationary combustion
Production
See recordkeeping requirements for stationary combustion
(a) Monthly facility production quantity for each zinc product (in metric tons).
(b) Number of facility operating hours each month.
(c) Annual production quantity for each zinc product (in metric tons).
(d) If you use the carbon input procedure, record for each carbon‐containing input material consumed or used (other than fuel), the
information specified in paragraphs (d)(1) and (2) of this section.
(1) Monthly material quantity (in metric tons).
(2) Monthly average carbon content determined for material and records of the supplier provided information or analyses used for the
determination.
(e) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input
to each Waelz kiln or electrothermic furnace, as applicable to your facility. You also must document the procedures used to ensure the
accuracy of the measurements of materials fed, charged, or placed in an affected unit including, but not limited to, calibration of weighing
equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and
the technical basis for these estimates must be provided.
HH—Landfills
(§98.340)
II—Wastewater
(§98.350)
Stationary combustion
Production
Stationary combustion
Production
See recordkeeping requirements for stationary combustion
Calibration records for all monitoring equipment
See recordkeeping requirements for stationary combustion
Calibration records for all monitoring equipment.
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Subpart
Source Category
Recordkeeping (5 years unless otherwise noted)
Stationary combustion
JJ—Manure
Production
Management
KK—Suppliers of All facilities
Coal (§98.370)
See recordkeeping requirements for stationary combustion
Calibration records for all monitoring equipment.
(a) A complete record of all measured parameters used in the reporting of fuel quantities, including all sample results and documentation to
support quantities that are reported under this part.
(b) Records documenting all calculations of missing data.
(c) Calculations and worksheets used to estimate the CO2 emissions.
(d) Calibration records of any instruments used onsite and calibration records of scales or other equipment used to weigh coal.
LL—Suppliers of All facilities
Coal‐based Liquid
Fuels (§98.380)
Reporters shall retain copies of all reports submitted to EPA. Reporters shall maintain records to support volumes that are reported under this
part, including records documenting any calculation of substitute measured data. Reporters shall also retain calculations and worksheets used
to estimate the CO2 equivalent of the volumes reported under this part. These records shall be retained for five (5) years similar to 40 CFR part
80 fuels compliance reporting program.
MM—Suppliers All facilities
of Petroleum
Products
(§98.390)
(a) Any reporter described in §98.391 shall retain copies of all reports submitted to EPA under §98.396. In addition, any reporter under this
subpart shall maintain sufficient records to support information contained in those reports, including but not limited to information on the
characteristics of their feedstocks and products.
(b) Reporters shall maintain records to support volumes that are reported under this part, including records documenting any estimations of
missing metered data. For all volumes of petroleum products, natural gas liquids, biomass, and feedstocks, reporters shall maintain meter and
other records normally maintained in the course of business to document product and feedstock flows.
(c) Reporters shall also retain laboratory reports, calculations and worksheets used to estimate the CO2 emissions of the volumes reported
under this part.
(d) Estimates of missing data shall be documented and records maintained showing the calculations.
(e) Reporters described in this subpart shall also retain all records described in §98.3(g).
NN—Suppliers of All facilities
Natural Gas and
Natural Gas
Liquids (§98.400)
(a) Records of all daily meter readings and documentation to support volumes of natural gas and NGLs that are reported under this part.
(b) Records documenting any estimates of missing metered data.
(c) Calculations and worksheets used to estimate CO2 emissions for the volumes reported under this part.
(d) Records related to the large end‐users identified in §98.406(b)(4).
(e) Records relating to measured Btu content or carbon content.
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Subpart
Source Category
OO—Suppliers of Fluroinated GHG
production facility
Industrial
Greenhouse
Gases (§98.410)
Recordkeeping (5 years unless otherwise noted)
(a) Fluorinated GHG production facility shall retain the following records:
(1) Dated records of the data used to estimate the data reported under §98.416, and
(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, flowmeters, and volumetric and density
measures used to measure the quantities reported under this subpart, including the industry standards or manufacturer directions used for
calibration pursuant to §98.414(j) and (k).
(b) In addition to the data required by paragraph (a) of this section, fluorinated GHG production facility that destroys fluorinated GHGs shall
keep records of test reports and other information documenting the facility’s one‐time destruction efficiency report and annual destruction
device outlet reports in §98.416(b) and (c).
Bulk importer of
(1) A copy of the bill of lading for the import;
fluorinated GHGs or N2O (2) The invoice for the import; and
(3) The U.S. Customs entry form.
(1) A copy of the bill of lading for the export; and
Bulk exporter of
fluorinated GHGs or N2O (2) The invoice for the import
Facilities that import
containers with a
fluorinated GHG or N2O
heel
PP—Suppliers of Facility containing
Carbon Dioxide production process units
(§98.420)
CO2 production well
facility
Facilities that import or
export CO2
Keep records of the amount brought into the US that document that the residual amount in each shipment is less than 10% of the volume of
container and will:
(1) Remain in the container and be included in a future shipment;
(2) Be recovered and transformed; or
(3) Be recovered and destroyed.
Quarterly records of captured and transferred CO2 streams and composition.
Quarterly records of the mass flow of the extracted and transferred CO2 stream and composition.
Quarterly records of the mass flow and composition of CO2 streams imported or exported.
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Appendix B
Table B-1 Calculating GHG Emissions
Subpart
Source Category
C—General Stationary fuel
Stationary Fuel combustion
Combustion
Sources (§
98.30)
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Freq of Measurement
CO2 ‐ Tier 1 N/A ‐ default emissions factor
Calculate annually using: mass or volume of fuel combusted (from company
records)
Comments
Tier 1 used for any unit with a max rated
heat input capacity of 250 mmBtu/hr or
less. May also be used to calculate the
biogenic CO2 emissions from a unit of any
size that combusts wood, wood waste, or
other solid biomass‐derived fuels.
CO2 ‐ Tier 2 N/A ‐ default emissions factor
Calculate annually using: mass or volume of fuel combusted, high heat value of fuel Tier 2 used for any unit with a max rated
heat input capacity of 250 mmBtu/hr or
for measurement period, number of required heat content measurements
less
(frequency of measurements depends on fuel; see 98.34(c) for requirements)
For municipal solid waste (MSW) combustion, calculate annually using: total mass
of steam generated by MSW combustion during the reporting period and ratio of
design heat input to its design rated steam output
CO2 ‐ Tier 3 N/A
Calculate annually for solid, liquid, and gaseous fuels using: fuel carbon content & Tier 3 used for any affected unit size
quantity (volume or mass) of fuel combusted (determined at same frequency of
combusting any type of fuel
high heat value measurements see 98.35(d) for requirements); determine carbon
content monthly, but for other gaseous fuels (e.g., refinery gas, process gas, etc.),
daily sampling and analysis is required to determine carbon content & molecular
weight of the fuel
Note: For natural gas combustion, CO2 mass emissions are calculated only for
those months in which natural gas is combusted during the reporting year. For the
combustion of other gaseous fuels (e.g., refinery gas, process gas), CO2 mass
emissions are calculated only for those days on which the gaseous fuel is
combusted during the reporting year
CO2 ‐ Tier 4 N/A ‐ CEMS required
Calculate annually. If CO2 conc measured on a wet basis: hourly average of CO2
conc & stack gas volumetric flow rate. If measured on a dry basis must also use the
hourly moisture % in stack gas to correct the measurement; sum hourly emissions
over entire calander year for annual emissions
Note: An oxygen (O2) monitor may be used in lieu of a CO2 monitor to determine
the hourly CO2 concentrations if the effluent gas stream monitored by the CEMS
consists solely of combustion products, and if only fuels that are listed in Table 1 in
section 3.3.5 of appendix F to part 75 are combusted in the unit(s).
CH4, N2O
Calculate annually using: mass or volume of the fuel combusted (from company
records); high heat value (measured or default)
For MSW combustion, calculate annually using: total mass of steam generated by
MSW combustion during the reporting year and ratio of the boiler’s design heat
input to its design rated steam output
N/A ‐ default emissions factor
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Page B-1
Tier 4 may be used for a unit of any size,
combusting any type of fuel; must be used
if unit has a maximum rated heat input
capacity greater than 250 mmBtu/hr, or if
unit combusts MSW & has maximum
capacity greater than 250 tons per day of
MSW. Additional conditions under which
Tier 4 must be used are specified in the
rule.
March 2009
Subpart
Source Category
C—General Unit w/ sorbent
Stationary Fuel injection
Combustion
Sources (§
98.30) (Cont.)
GHGs
CO2
Fuel(s) combusted CO2
= biomass
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Freq of Measurement
N/A
Calculate annually using: limestore or other sorbent used in report year
N/A ‐ CEMS optional
Comments
Used if unit is: fluidized bed boiler;
equipped with a wet flue gas
desulfurization system; or uses other acid
gas emission controls with sorbent
injection. Calc used only if GHG emissions
from sorbent are not monitored by CEMS
If facility doesn't use CEMS and if the
Calculate annually using:
If Tier 4 is not used and there is no MSW: mass or volume of fuel per year.
biogenic fuel consists of wood and/or
If CEMS or Tier 4 is used, and there is no MSW: hourly volume of CO2 emitted
wood waste and/or other biomass‐derived
(calculated with inputs: hourly CO2 conc, hourly stack gas volumetric flow rate,
solid fuels (no MSW), use Tier 1
source operating time); total quantity of fossil fuel combusted in report year; and methodology
gross calorific value of fuel.
If there is MSW: quarterly determination of relative proportions of biogenic and
non‐biogenic CO2; use the same inputs as for other biomass fuel types.
D—Electricity Electric generating units (EGUs) ‐ calculate annual CO2, N2O, CH4 emissions using methods in subpart C
Generation (§
98.40)
E—Adipic Acid Stationary Combustion unit that uses a carbon‐based fuel ‐ calculate CO2, NO2, CH4 emissions using requirements of subpart C
Production (§ Production
N2O
facility‐specific (ss) emission factor, Calculate annually using: total adipic acid production at the facility
98.50)
calculated annually (annual
performance test, 3 test runs of 1
hour each) using N2O concentration,
volumetric flow rate of effluent gas,
and production rate (can be
determined through sales records,
or through direct measurement
using flow meters or weigh scales)
Draft Final ICR for the Proposed GHG Reporting Rule –
DO NOT CITE, QUOTE, OR DISTRIBUTE
Page B-2
Must conduct a new performance test
whenever the production rate is changed
by more than 10%
March 2009
Subpart
Source Category
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Freq of Measurement
F—Aluminum Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Production (§ Production
CF4
N/A
Anode effect minutes per cell‐day (measured monthly), total Al production
98.60)
(measured monthly), slope coefficient (measured at least every 36 months)
Anode
consumption
Comments
Calculate emissions from anode effects
from each Prebake and Søderberg
electolysis cell
C2F6
N/A
CF4 emissions from aluminum production (calculated monthly)
CO2
N/A
(1) For prebake cells ‐ calculate annually using: total Al production, net prebaked Note: there are emission calculations for
anode consumption, sulfur and ash content in baked anodes;
prebake cell and for Søderberg cells
(2) For Søderberg cells ‐ calculate annually using: total Al production, paste
consumption, emissions of cyclohexane soluble matter, binder content of paste,
sulfur, ash, and hydrogen content in pitch, sulfur and ash content in calcined coke,
carbon in skimmed dust from Søderberg.
Anoke baking of
Prebake cells
CO2 from N/A
Calculate annually using: initial weight and hydrogen content of green anodes,
pitch
baked anode production, waste tar collected
volatiles
CO2 from N/A
Calculate annually using: packing coke consumption, baked anode production,
bake
sulfur and ash content in packing coke. Frequency of measurement for each
parameter is not specified at this time.
furnace
packing
material
G—Ammonia Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Manufacturing Different fuels used for combustion and feedstock (i.e. fuel combustion has not been accounted for in feedstock emissions calculations) or the combustion emissions exhausted through a stack
(§ 98.70)
CO2 collected and used onsite or transferred offsite ‐ calculate CO2 emissions using requirements for suppliers of CO2 (subpart PP)
Production
CO2
N/A ‐ CEMS optional (if use CEMS,
calculate CO2 emissions using Tier 4
Calculation Methodology of subpart
C)
Calculate annually using: volume/mass and carbon content of gaseous/liquid/solid
feedstock (measured continuously using a flow meter) used in a month. For liquid
and solid feed stock also use CO2 captured or recovered for use in urea or
production in calculation. All inputs are calculated monthly.
H—Cement Fuel combustion at kilns and any other stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Production (§ If CEMS used to measure process‐related emissions from facility ‐ calculate CO2 emissions using Tier 4 Calculation Methodology of subpart C
98.80)
Clinker production CO2
ss emission factor; calculated using Calculate annually using: quantity of clinker production (measured monthly), plant
CaO & MgO content of Clinker, non‐ specific fraction of calcined material in cement kiln dust (CKD) not recycled to the
carbonate CaO & MgO content of kiln (measured quarterly) and quantity CKD discarded (measured quarerly).
Clinker (calculated monthly)
Note: A default factor of 1.0 (assumes that 100% of all carbonates in CKD is
calcined) may be used in place of the ss factor
Raw materials
N/A
Draft Final ICR for the Proposed GHG Reporting Rule –
DO NOT CITE, QUOTE, OR DISTRIBUTE
Emissions from gaseous, liquid, and solid
fuel and/or feedstock are calculated
separately (using similar formulas) and
then added together
Total annual CO2 emissions = sum of
annual CO2 emissions from the production
of each clinker and emissions from raw
materials
Organic carbon content of raw material (determined monthly by an off‐site
laboratory analysis) and annual amount of raw materials used.
Page B-3
March 2009
Subpart
Source Category
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Comments
Freq of Measurement
I—Electronics Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Manufacturing Etching and
F‐GHG
N/A ‐ default emissions factor
Calculate annually using: gas consumption, process utilization rate for gas, fraction F‐GHG reported depends on product type
(§ 98.90)
chamber cleaning
of input gas used in process w/abatement devices, fraction of input gas destroyed (see Table 1 in this subpart); facilities
in abatement devices connected to process. Must also calculated by‐product gas w/abatement devices must verify the
emissions using inputs: kg gas created as a by‐product in process per kg of input destruction or reoval efficiency of the
gas consumed in process, gas consumption, fraction of gas used in process
equipment
w/abatement devices, fraction of gas destroyed in abatement devices connected
to process
Total annual emissions = sum of input and
by‐product emissions from each etch
process and each cleaning process.
NO2
N/A
Calculate annually using: consumption of N2O
Facilities that use F‐GHG
heat transfer fluids
N/A
Calculate annually using: inventory of heat transfer fluid (HTF) at end of previous
reporting period, net purchases of HTF, total nameplate capacity of installed HTF
equipment & retired HTF equip, inventory of HTF at end of period, amount HTF
recovered and sent offsite. When consumption of gases is estimated by monitoring
changes in container mass & inventories use inputs: inventory of gas stored in
cylinders at the beginning & end of year, acquisitions of gas during year,
disbursement of gas during period.
Onsite stationary combustion ‐ calculate CO2, N20, and CH4 emissions according to the requirements of subpart C
J—Ethanol
Production (§ Onsite landfills ‐ calculate CH4 emissions according to the requirements for landfills (subpart HH)
98.100)
Onsite wastewater treatment ‐ calculate CO2 and CH4 emissions according to the requirements for wastewater treatment (subpart II)
K—Ferroalloy Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Production (§ If CEMS used to measure CO2 emissions for electric arc furnace subject to GHG reporting ‐ calculate emissions according to requirements of subpart C
98.110)
N/A
Calculate annually using: mass & carbon content of reducing agent, carbon
Calculate emissions from each EAF
Electric arc furnace CO2
(EAF) ‐ ferroally
electrode consumed in EAF, ore, flux material, alloy product, and non‐product
separately and sum to find total CO2
production
outgoing material. Determine mass of each solid carbon‐containing input & output emissions
material monthly by direct measurement or calculations using process operating
information. Determine average carbon content of each input and output material
monthly using info from supplier or analysis of a representative sample. For each
input material for which the carbon content is not provided by your material
supplier, carbon content of the material must be analyzed by independent certified
laboratory annually.
EAF ‐ ferrosilicon or CH4
N/A ‐ default emissions factor
Calculate annually using: mass of alloy product produced in electric arc furnace
Calculate emissions from each EAF
silicon metals
separately and sum to find total CH4
production
emissions
Draft Final ICR for the Proposed GHG Reporting Rule –
DO NOT CITE, QUOTE, OR DISTRIBUTE
Page B-4
March 2009
Subpart
Source Category
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Freq of Measurement
L—Fluorinated Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Greenhouse Production
Fluorinated N/A
Calculate monthly using: total mass of each fluorinated GHG emitted from the
Gas
GHGs
production process (estimated daily using: mass of fluor GHG produced, mass of
Production
(mass)
reactant that is consumed in process, concentration (mass fraction) of fluor GHG
(§98.120)
product in destroyed wastes, mass of wastes removed from the process and
Comments
destroyed, and yield loss related to byproducts.) The total mass of the reactant
consumed in process is estimated daily using: mass of reactant fed into the
production process and mass of reactant permanently removed from the
production process. The total mass of the wastes removed from the process and
destroyed is estimated using: mass of wastes removed from the process and fed
into the destruction device and Destruction Efficiency of the destruction device
(fraction). Yield loss related to byproduct for production is calculated daily using
the mass of byproduct generated by production process. If by‐product is
responsible for yield loss in production process and occurs in any process stream in
more than trace concentrations, the mass of by‐product generated is calculated
daily using: concentration (mass fraction) and mass flow of the byproduct
stream. If by‐product is responsible for yield loss, is a fluorinated GHG,
occurs in any process stream in more than trace concentrations, and is
not completely recaptured or completely destroyed, the mass of
by‐product emitted is calculated daily using: mass of by‐product
generated, concentration (mass fraction) of by‐product in stream of
destroyed wastes and in stream of recaptural material, mass of wastes
removed from production process and destroyed, mass removed from
production process, number of streams of destroyed waste, and number
of streams of recaptured materials.
Onsite stationary combustion ‐ calculate CO2, N20, and CH4 emissions according to the requirements of subpart C
M—Food
Processing (§ Onsite landfills ‐ calculate CH4 emissions according to the requirements for landfills (subpart HH)
98.130)
Onsite wastewater treatment ‐ calculate CH4 emissions according to the requirements for wastewater treatment (subpart II)
Stationary combustion unit ‐ fuel combustion at each continuous glass melting furnace and at any other on‐site stationary fuel combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to
N—Glass
Production (§ If CEMS used to measure CO2 emissions ‐ calculate emissions according to requirements of subpart C
98.140)
Production
CO2
N/A ‐ default emissions factor
Calculate annually using: number of carbonate‐based raw materials charged to
Calculate emissions from each continuous
furnace, mass fraction of carbonate‐based mineral in carbonate‐based raw
glass melting furance separately and sum
material (from supplier or use default value), mass of carbonate‐based raw
to determine total emissions
material charged to furnace, fraction of calcination achieved for carboate‐based
raw material (calculate or use default value).
Draft Final ICR for the Proposed GHG Reporting Rule –
DO NOT CITE, QUOTE, OR DISTRIBUTE
Page B-5
March 2009
Subpart
O—HCFC‐22
Production
and HFC‐23
Destruction (§
98.150)
Source Category
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Freq of Measurement
Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions using requirements in subpart C
Comments
HCFC‐22 production HFC‐23
processes and HFC‐ (mass)
23 destruction
processes
N/A
Calculate annually using: mass HFC‐23 emitted from equipment leaks (calculated
annually using emissions tests that measure: fraction HFC‐23 by weight in the
stream(s) in the equipment, number of hours in year during which equipment
contained HFC‐23, applicable leak rate for each source of equipment type and
service, number of sources of equipment type and service with screening values
less than 10,000 ppmv as determined according to §98.154(h)), mass HFC‐23
emitted from process vents (calculated monthly using: HFC‐23 emission rate from
the process vents during the period of the most recent emissions test (emissions
test conducted annually), HCFC‐22 production rate during the period and during
the most recent test), and mass HFC‐23 emitted from thermal oxidizer (calculated
annually using: mass HFC‐23 fed into destruction device (measured daily) &
destruction efficiency of the destruction device)
Facilities that don't HFC‐23
(mass)
use a thermal
oxidizer or have a
thermal oxidizer
that is not directly
connected to the
HCFC‐22 production
equipment
N/A
Calculate annually using: mass HFC‐23 generated annually , mass HFC‐23 packaged See next two row for methods used to
for sale annually (measured daily), mass HFC‐23 sent off‐site for destruction
calculate the mass of HFC‐23 generated
(measured daily), mass HFC‐23 destroyed on‐site
annually
Facility measures total mass N/A
of HFC‐23
mass flow of
combined stream generated
(HFC‐23 + other
product)
N/A
Facility measures
production of only
the other product
(either HCFC‐22 or
HCl)
HFC‐23 destruction HFC‐23
facilities
(mass)
N/A
Production
N/A ‐ CEMS optional (if used see
requirements in subpart C)
Calculate annually using: fraction HFC‐23 by weight in HFC‐23/other product
stream (measured daily), mass flow of HFC‐23/other product stream (measured
continuously using a flow meter), number of conc & flow measurements for the
year
Calculate annually using: fraction of HFC‐23 and of HCFC‐22 by weight in HCFC‐
22/HFC‐23 stream (measured daily), mass of HCFC‐22 produced (measured daily
using inputs: mass HCFC‐22 coming out of production process (measured daily),
mass of HCFC‐22 added to production process upstream, (measured daily)),
number of conc & mass measurement periods for the year
All HCFC‐22 production facilities shall
account for HFC‐23 generation and
emissions that occur as a result of
startups, shutdowns, and malfunctions,
either recording HFC‐23 generation and
emissions during these events, or
documenting that these events do not
result in significant HFC‐23 generation
and/or emissions.
This is NOT a GHG calculation, these
calculations are used to find the mass of
HFC‐23 generated annually, which are
used in the calculation for HFC‐23 (mass)
emissions for facilities that do not use a
thermal oxidizer
Calculate annually using: mass HFC‐23 fed into destruction device (measured daily) Estimates of the mass of HFC‐23 destroyed
must account for any temporary
& mass of HFC‐23 destroyed (calculated using inputs: mass HFC‐23 fed into
reductions in the destruction efficiency
destruction device (measured daily) & destruction efficiency of the destruction
that result from any startups, shutdowns,
device)
or malfunctions of the destruction device
P—Hydrogen Combustion of fuels in each hydrogen production unit and any other stationary combustion units ‐ calculate CO2, NO2, & CH4 emissions using requirements in subpart C
Production (§ CO2 collected and used onsite or transferred offsite ‐ calculate CO2 emissions using requirements for suppliers of CO2 (subpart PP)
98.160)
If CEMS used to measure CO2 mass emissions ‐ calculate CO2 emissions using Tier 4 Calculation Methodology of subpart C
CO2
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Calculate annually using: mass/volume of gaseous/liquid feedstock (measured
continuously using a flow meter) and solid feedstock (obtained from company
records) and carbon content in feedstock (monthly).
Page B-6
March 2009
Subpart
Source Category
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Comments
Freq of Measurement
Stationary combustion unit ‐ calculate CO2, CH4, and NO2 emissions according to requirements of subpart C. Stationary combustion units include, but are not limited to, by‐product recovery coke
Q—Iron &
Steel
If CEMS used to measure CO2 emissions ‐ calculate emissions according to requirements of subpart C
Production (§ Taconite indurating CO2 ‐
For each process input and output other
N/A
Calculate annually using: mass/volume & carbon content (CC) of
98.170)
furnaces
solid/liquid/gaseous fuel combusted, mass & CC of greenball (taconite) pellets fed than fuels, sample each process input and
Carbon
output weekly and prepare a monthly
to the furnace & fired pellets produced by the furnace (all inputs measured
balance
composite sample for carbon analysis
monthly)
Basic oxygen
N/A
Calculate annually using: mass & carbon content (CC) of molten iron, ferrous scrap, (analysis performed by certified,
independent lab). Calculate the mass
process furnaces
flux materials, and carbonaceous materials charged to furnace; mass & CC of
emissions rate of CO2 in each calendar
molten steel & slag produced by furnace (all inputs measured monthly)
month for each process. The calculations
Non‐recovery coke
N/A
Calculate annually using: mass & carbon content of coal charged to the battery & are based on the monthly mass of inputs
and outputs to each process and the
oven batteries
coke produced by the battery (all inputs measured monthly)
respective weight fraction of carbon. If
facility has a process input or output that
Sinter processes
N/A
Calculate annually using: volume & carbon content (CC) of gaseous fuel
combusted; mass & CC of sinter feed material and of sinter pellets produced (all contains carbon that is not included in the
equations, account for the carbon and
inputs measured monthly)
mass rate of that process input or output
Electric arc furances
N/A
Calculate annually using: mass of direct reduced iron, carbon content (CC) of
in your calculations.
(EAFs)
molten iron, mass & avrg CC of ferrous scrap, flux materials, and carbonaceous
materials charged to furace, mass & avrg CC of carbon electrode consumed and of
molten steel & slag produced by furance (all inputs measured monthly)
Argon‐oxygen
decarburization
vessels
Direct reduction
furnaces
N/A
N/A
Draft Final ICR for the Proposed GHG Reporting Rule –
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Calculate annually using: mass of molten steel charged to the vessel carbon
content (CC) of molten steel before decarburization and avrg CC of molten steel
after decarburization
Calculate annually using: volume & avrg carbon content (CC) of gaseous fuel, mass
& CC of iron ore/iron ore pellets fed to the furnace, mass & CC of carbonaceous
materials and other materials charged to the furnace; mass & CC of iron & non‐
metallic materials produced (all inputs measured monthly)
Page B-7
March 2009
Subpart
Source Category
Q—Iron &
Coke pushing
Steel
process
Production (§
98.170) (Cont.)
GHGs
CO2 ‐ ss
emission
factor
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Freq of Measurement
Calculate annually using total amount of feed or production for reporting period.
ss emission factor, calculate
annually using a performance test
that measures: CO2 conc,
volumetric flow rate (either the feed
rate of materials into the process or
the production rate during the test),
and moisture % in stack gas.
Conduct annual performance test
for 9 hours or 9 complete
production cycles; measure inputs
hourly.
Comments
For the furnace exhaust from basic oxygen
furnaces, EAFs, argon‐oxygen
decarburization vessels, and direct
reduction furnaces, sample furnace
exhaust for at 9 complete production
cycles that start furnace is being charged
and end after steel or iron and slag have
been tapped. For EAFs that produce both
carbon steel and stainless or specialty (low
carbon) steel, develop an emission factor
for the production of both types of steel.
For taconite indurating furnaces, non‐
recovery coke batteries, and sinter
processes, sample for at least 9 hours.
Conduct new performance test & calculate
new ss EF if any changes at the facility
alter the energy efficiency/carbon content
of fuel or feed by more than 10%
R—Lead
Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Production (§ If CEMS used to measure CO2 emissions ‐ calculate emissions according to requirements of subpart C
98.180)
Calculate emissions from each smelting
Production
CO2
N/A
Caclulate annually using: mass and carbon content of: lead ore charged to the
smelting furnace, lead scrap charged to the furnace, flux materials, carbonaceous furance separately and sum to determine
materials, and any other materials charged to the furnace. All inputs are measured total emissions
monthly. Determine the carbon content of all inputs listed above using information
provided by your material supplier. If not provided by supplier, the carbon content
must be analyzed by an independent certified laboratory each month using test
methods (and their QA/QC procedures) in §98.7 of subpart A.
Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
S—Lime
Manufacturing If CEMS used to measure CO2 emissions ‐ calculate emissions according to requirements of subpart C
(§ 98.190)
Production
CO2
ss emission factor, calculated
Calculate annually using: correction factor for byproduct/waste products (calculate Calculate emissions and ss emission factor
annually using: CaO and MgO
monthly using: weight of lime kiln dust (LKD) not recycled to kiln, weight of LKD
for each kiln based on the type of lime
content (determined by an off‐site produced at kiln, fraction of original carbonate in LKD, fraction of calcination of
produced at the kiln, sum emissions from
lab every month)
original carbonate in LKD); weight/mass of lime; number of lime types produced at each kiln to determine total emissions
kiln. All inputs measured monthly.
Draft Final ICR for the Proposed GHG Reporting Rule –
DO NOT CITE, QUOTE, OR DISTRIBUTE
Page B-8
March 2009
Subpart
Source Category
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Freq of Measurement
Onsite combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
T—Magnesiu
m Production Production
(§ 98.200)
U—Misc. Uses Production
of Carbonate
(§ 98.210)
SF6, HFC‐
N/A
134a, FK 5‐1‐
12, CO2,
other
fluorinated
GHGs
Option 1: Measure by monitoring changes in container masses and inventories,
calculate annually using: inventory of cover gas or carrier gas stored in cylinders or
other containers at beginning & end of period, acquisitions of cover gas or carrier
gas, disbursements of cover gas or carrier gas to sources or locations outside the
facility.
Option 2: Measure by monitoring changes in mass of indiv containers as their
contents are used, calculate annually using: mass of contents of cylinder at
beginning & end of period.
CO2
Calculate annually using: mass of carbonate consumed (can be determined from
purchase records or by direct weight measurement using the same plant
instruments used for accounting purposes), [Comment: This information is
requried in the data reporting requirements but not in the GHG emissions
calculation section] , fraction calcination achieved (can calculate annually based on
sampling & analysis by certified lab or use default of 1.0)
N/A ‐ default emissions factor
V—Nitric Acid Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Production (§ Production
N2O
ss emission factor, calculated
Calculate annually for each nitric acid production line using: total production rate
98.220)
annually for each nitric acid
for the year, destruction factor of N2O abatement technology (percent of N2O
production line using: N20
removed from air stream), and abatement factor of N2O abatement technology
concentration, flow rate of effluent (percent of year that abatement technology was used)
gas, production rate (performance
test, 3 test runs of 1 hour each)
W—Oil &
Stationary combustion unit ‐ calculate CO2, NO2, CH4 emissions using requirements in subpart C
Natural Gas Process facilities
CH4 and
Calculate using: natural gas volumetric fugitive emissions at standard conditions
Systems (§
CO2
(calculated differently depending on the source, see source categories below) and
98.230)
volumetric
mole % of GHG in the natural gas (mole % is the annual average mole % for each
Acid gas removal
vent stacks
fugitive
emissions
CH4 and
CO2 mass
fugitive
emissions
Fugitive
emissions
Comments
Must conduct a new performance test
whenever the production rate is changed
by more than 10%
Equation A
facility and is specific to the source category)
N/A
Draft Final ICR for the Proposed GHG Reporting Rule –
DO NOT CITE, QUOTE, OR DISTRIBUTE
Calculate using: GHG volumetric fugitive emissions at standard conditions (from
equation A), density of GHG
Equation B
Calculate annually using: natural gas feed temperature, pressure, and flow rate;
acid gas content of feed natural gas and outlet natural gas; unit operating hours,
exit temperature of natural gas; solvent pressure, temperature, circulation rate,
and weight. Note: if the acid gas removal unit is capturing CO2 and transferring it
offsite calculate emissions using requirements for industrial greenhouse gas
suppliers (subpart OO)
Use simulation software package to
calculate emissions
Page B-9
March 2009
Subpart
Source Category
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Freq of Measurement
W—Oil &
Natural gas driven Natural gas N/A
Calculate annually using: natural gas driven pneumatic pump gas emission (from
Natural Gas pneumatic pump
fugitive
manufacturer), volume of liquid pumped annually. If manufactured data not
Systems (§
emissions
available conduct one time measurement using high volume sampler or calibrated
98.230) (Cont.)
bag for each pump.
Natural gas driven Natural gas N/A
Calculate annually using: natural gas driven pnematic valve actuator natural gas
pneumatic manual fugitive
emission (provided by manufacturer) and number of times the pneumatic device
valve actuator
emissions
was actuated in a way that vented natural gas to the atmosphere through the
Natural gas driven Natural gas N/A
fugitive
pneumatic valve
emissions
bleed device
Blowdown vent
stacks
N/A
Dehydrator vent
Fugitive
emissions
N/A
Flare stack
Fugitive
emissions
N/A
Storage tank
CH4 and
N/A
CO2
volumetric
fugitive
emissions
Compressor wet
seal degassing
vents
Natural gas N/A
fugitive
emissions
Draft Final ICR for the Proposed GHG Reporting Rule –
DO NOT CITE, QUOTE, OR DISTRIBUTE
Comments
Use volumetric natural gas fugitive
emissions to calculate CH4 & CO2
volumetric & mass fugitive emissions (see
equations A & B above)
Use volumetric natural gas fugitive
emissions to calculate CH4 & CO2
volumetric & mass fugitive emissions (see
Use volumetric natural gas fugitive
emissions to calculate CH4 & CO2
volumetric & mass fugitive emissions (see
Calculate annually using: number of blowdowns for equipment in year, volume of equations A & B above)
blowdown equipment chambers; use equation B above to determine nautral gas
volumetric fugitive emissions
Calculate annually using: feed natural gas flow rate & water content, outlet natural Use simulation software package to
gas water content, absorbent circulation rate, use of stripping natural gas and of calculate emissions
flash tank separator, wet natural gas temperature, pressure, and composition
Calculate annually using: pneumatic device bleed rate (from manufacturer); if
manufacturing data not available conduct one time measurement using high
volume sampler or calibrated bag for each pneumatic device
Use volumetric fugitive emissions to
Calculate annually. GHG emissions: volume of natural gas sent to flare stack, %
natural gas combusted by flare, conc of GHG in flare gas (quarterly sample taken calculate CH4 & CO2 mass fugitive
from flow velocity measuring device), conc of natural gas hydrocarbon
emissions (see equation B above)
constituents. GHG volumetric fugitive emissions: natural gas volumetric fugitive
emissions at actual conditions, temperature, pressure.
Use volumetric fugitive emissions to
Calculate annually using: mole percent of a particular GHG in the hydrocarbon
calculate CH4 & CO2 mass fugitive
vapors and hydrocarbon vapor volumetric fugitive emissions at standard
emissions (see equation B above)
conditions. Calculate hydrocarbon vapor volumetric fugitive emissions at actual
conditions using: storage tank total annual throughput and measured hydrocarbon
vapor emissions rate per throughput (measured using test period of one complete
production cycle). Use this number, temperature at actual emission conditions, and
absolute pressure at ambient conditions to convert to emissions at standard
condition.
Calculate annually using volume of natural gas sent to vent from velocity
measurement in §98.234 (j) using manufacturer’s manual for the specific meter
used to measure velocity. Use this number, temperature at actual emission
conditions, and absolute pressure at ambient conditions to convert to emissions at
standard condition.
Page B-10
Use volumetric natural gas fugitive
emissions to calculate CH4 & CO2
volumetric & mass fugitive emissions (see
equations A & B above)
March 2009
Subpart
Source Category
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Freq of Measurement
X—Petrochem Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
ical Production CO2 captured ‐ calculate CO2 emissions using requirements for suppliers of CO2 (subpart PP)
(§ 98.240)
Onsite wastewater treatment ‐ calculate CH4 emissions according to the requirements for wastewater treatment (subpart II)
Petrochemical
process
CO2 ‐ Mass N/A ‐ CEMS optional (if use CEMS,
balance
calculate CO2 emissions using Tier 4
Calculation Methodology of subpart
C)
Comments
Calculate weekly using: mass/volume and carbon content of: solid, liquid &
gaseous feedstock introduced & solid, liquid & gaseous product produced [solid
feedstock take grab samples weekly or composite samples analyzed weekly;
measure volume of gaseous & liquid feedstock & product continuously with flow
meter; alternatively facility can demonstrate to administrator that average conc is
always > 99.5% by submitted data, calcs & other supporting info to administrator,
if approved facility may assume carbon content = 100%)
Y—Petroleum Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Refineries (§ Sour gas sent off‐site for sulfur recovery operations ‐ calculate CO2 emissions according to requirements for on‐site sulfur recovery plants in this subpart
98.250)
On‐site landfills ‐ calculate CH4 emissions according to the requirements for landfills (subpart HH)
On‐site wastewater treatment ‐ calculate CH4 and CO2 emissions according to the requirements for wastewater treatment (subpart II)
Non‐merchant hydrogen production ‐ calculate CO2 and CH4 emissions according to the requirements for hydrogen production (subpart P)
If CEMS used to measure CO2 emissions for flares, catalytic cracking units, fluid coking units, or coke calcining units ‐ calculate emissions according to requirements of subpart C
Flares ‐ calculate CH4 and NO2 emissions according to requirements of subpart C
Flares
CO2
CH4, N2O
Catalytic cracking CO2
units & traditional
fluid coking units
CH4, N2O
N/A ‐ default emissions factor
N/A
N/A
N/A ‐ default emissions factor
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Calculate annually using: volume of flare gas combusted during normal operations
(from company records), higher heating value for refinery fuel or flare gas (from
company records), number of start‐up, shutdown, and malfunction events during
the reporting year, volume of flare gas combusted during a start‐up, shutdown, or
malfunctions (from engineering calculations), average carbon content of the
gaseous fuel, from the fuel analysis results or engineering calculations for the
shutdown/malfunction event
Calculate emissions according to the requirements of subpart C
If facility has a continuous flow monitor,
high heating value monitor, or carbon
content monitor on the flare or if facility
measures these parameters daily must use
these values when calculating CO2
emissions
Calculate annually using: volumetric flow rate of exhaust gas, hourly avrg % CO2 If a CO boiler or other post‐combustion
concentration in exhaust gas stream, hourly avrg % CO concentration in exhaust device is used, calculate the GHG
emissions from the fuel fired to the CO
gas stream
boiler or post‐combustion device
Note: If facility doesn't continuously monitor flow rate of exhaust gas, must
calculate using flow rate of air to unit, flow rate of O2 enriched air to unit, O2 conc. according to the requirements of subpart
in gas stream inlet to unit, hourly average % O2, CO, & CO2 in exhaust gas stream C
from unit. If using post‐combustion device calculate emissions using method for
combustion sources and report separately
Calculate annually using: emission rate of CO2 from coke burn‐off
Page B-11
March 2009
Subpart
Source Category
GHGs
Y—Petroleum Catalytic reforming CO2
Refineries (§ units
98.250) (Cont.)
On‐site sulfur
recovery plants
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Comments
Freq of Measurement
N/A
Calculate annually using: quantity of coke burn‐off per regeneration cycle, number Facilities can also calculate emissions using
of regeneration cycles in calendar year, site‐specific fraction carbon content of
methods for catalytic cracking units &
produced coke (use default value if ss is unavailable)
traditional fluid coking units
CH4, N2O
N/A ‐ default emissions factor
Calculate annually using: emission rate of CO2 from calcinating reforming units
CO2
N/A ‐ CEMS optional (if use CEMS,
calculate CO2 emissions using
requirements of subpart C)
Calculate annually using: flow rate of sour gas feed, mole fraction of carbon in the If facility has a continuous flow and/or
sour gas to the sulfur recovery plant (use default factor or develop ss factor)
carbon content monitor on the sour gas
feed to the sulfur recovery plant, must use
the measured flow rates when the
monitor is operational to calculate the
sour gas flow rate and/or carbon content
value
N/A
Calculate annually using: mass of green coke fed to unit, mass of marketable
Calculate the CO2 emissions for any
petroleum coke produced by unit, and mass of petroleum coke dust collected in auxiliary fuel fired to the calcining unit
the dust collection system of unit (all from facility records); avrg mass fraction
using the applicable methods according to
carbon content of green coke and avrg mass fraction carbon content of marketable requirements of subpart C
petroleum coke produced by unit
Coke calcining units CO2
CH4, N2O
N/A ‐ default emissions factor
Calculate annually using: CO2 emissions from coke calcining unit
N/A ‐ default emissions factor
Calculate annually using: quantity of asphalt blown
Must use emission factor from facility
specific test data, if available
N/A ‐ default emissions factor
Calculate annually using: quantity of asphalt blown
Only calculate CO2 emissions if they are
not included in flare emissions
Delayed coking unit CH4
‐ subsequent
openings of vessel
N/A
Calculate annually using: total number of vessel openings, height/diameter of
coking unit vessel
Calculate CH4 emissions from
depressurization of coking unit vessel to
atmosphere using method for "all other
process vents"
All other process
vents
N/A
Calculate annually using: number of venting events per year, flow rate of process
vent, venting time (hours per event)
Used also for catalytic reforming unit
depressurization and purge vents when
methane is used as purge gas
N/A ‐ default emissions factor
Calculate annually using: quantity of crude oil, quantity of intermediate off‐site
products processed at the facility
Facilities also have the option of the
method used for other process vents (§
98.253(j))
Uncontrolled
CH4
asphalt blowing
operations
Controlled asphalt CO2
blowing
CO2, N20,
CH4
Uncontrolled
CH4
blowdown systems
Draft Final ICR for the Proposed GHG Reporting Rule –
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Page B-12
March 2009
Subpart
Source Category
Y—Petroleum Equipment leaks
Refineries (§
98.250) (Cont.)
GHGs
CH4
Storage tanks ‐ do CH4
not process
unstabilized crude
oil
CH4
Storage tanks ‐
process
unstabilized crude
oil
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Freq of Measurement
N/A
Calculate using either (1) or (2) below:
(1) Use process‐specific methane composition data (from measurement data or
process knowledge) and any of the emission estimation procedures provided in the
Protocol for Equuipiment Leak Emissions Estimates (EPA‐453/R‐95‐017, NTIS PB96‐
175401).
(2) Calculate annually using: number of atmospheric crude oil distillation columns;
number of catalytic cracking units, coking units (delayed or fluid), hydrocracking,
and full‐range distillation columns (including depropanizer and debutanizer
distillation columns); number of hydrotreating/hydrorefining units, catalytic
reforming units, and visbreaking units at the facility; and the total number of
hydrogen plants and fuel gas systems at the facility
Comments
N/A ‐ default emissions factor
Calculate annually using: quantity of crude oil, quantity of intermediate products
received from off‐site that are processed at the facility
N/A
Calculate annually using: quantity of unstabilized crude oil received at the facility, Facilities can also calculate CH4 emissions
presure differential, mole fraction of CH4 in vent gas from facility measurements (if from the storage of unstabilized crude oil
available)
using either tank‐specific methane
composition data (from measurement
data or product knowledge) and direct
measurement of the gas generation rate
Crude oil,
CH4
N/A
Calculate annually using: product‐specific vapor‐phase methane composition data
intermediate, or
product loading
operations
Z—Phosphoric Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Acid
If CEMS used to measure CO2 emissions ‐ calculate emissions according to requirements of subpart C
Production (§ Production
CO2
N/A
Calculate annually using: inorganic carbon content of the batch of phosphate rock
98.260)
used (measured monthly), mass of phosphate consumed (measured monthly), and
number of months during which the process line operates
Draft Final ICR for the Proposed GHG Reporting Rule –
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Page B-13
Facilities can also use tank‐specific
methane data and the TANKS model to
estimate CH4 emissions
If equilibrium vapor‐phase CH4 conc. Is
less than 0.5 volume %, report zero CH4
emissions
Calculate emissions from each wet‐
process phosphoric acid prod line
separately and sum to get total emissions
March 2009
Subpart
Source Category
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Comments
Freq of Measurement
AA—Pulp and On‐site stationary fuel combustion units (boilers, gas turbines, thermal oxiders, and other sources) ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Paper
Onsite landfills ‐ calculate CH4 emissions according to the requirements for landfills (subpart HH)
Manufacturing Onsite wastewater treatment ‐ calculate CH4 emissions according to the requirements for wastewater treatment (subpart II)
(§ 98.270)
Chemical recovery Fossil‐fuel based CO2 ‐ direct measurement using Teir 1 methodology for stationary combustion sources in subpart C
furnace located at a Fossil‐fuel based CH4, N20 ‐ direct measurement of fossil fuels consumed, default HHV, and default emissions factors and convert to metric tons of CO2 equivalent according to
kraft or soda facility Biogenic
N/A ‐ default emissions factor
Calculate annually using: mass of spent liquor solids combusted (measured
CH4 and N2O emissions must be
CO2, CH4,
N20
Chemical recovery
combustion unit
located at a sulfite
or stand‐alone
semichemical
facility
monthly), high heat value of the spent liquor solids for the month (site‐specific)
calculated as the sum of emissions from
combustion of fossil fuels and combustion
of biomass in spent liquor solids.
CO2 emissions from fossil fuels ‐ Direct measurement of fossil fuels consumed and default emissions factors according to the Tier 1 methodology for stationary combustion
CH4 and N20 from fossil fuels ‐ Direct measurement of fossil fuels consumed, default HHV, and default emissions factors and convert to metric tons of CO2 equivalent according
Biogenic
CO2
N/A
Calculate annually using: mass of spent liquor solids (measured monthly), carbon
content of spent liquor solids (from monthly fuel analysis results)
Biomass CH4, N20 ‐ calculate emissions using equation used for kraft facilities and default factors in Table AA‐1 and convert the CH4 or N2O emissions to metric tons of CO2
Lime kiln located at CO2 emissions from fossil fuels ‐ Direct measurement of fossil fuels consumed and default HHV and default emissions factors, according to the Tier 1 methodology for stationary
kraft or soda facility CH4 and N20 from fossil fuels ‐ Direct measurement of fossil fuels consumed, default HHV, and default emissions factors and convert to metric tons of CO2 equivalent according
Biogenic CO2 ‐ calculate emissions from conversion of CaCO3 to CaO as part of the chemical recovery furnace biogenic CO2 estimates
Makeup chemical CO2
N/A
Calculate annually using: make‐up quantity of CaCO3 and of Na2CO3 used
use
Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
BB—Silicon
Carbide
If CEMS used to measure CO2 emissions ‐ calculate CO2 emissions using Tier 4 Calculation Methodology of subpart C
Production (§ Production
CO2
ss emission factor calculated
Calculate annually using: petcoke consumption (measured quarterly)
98.280)
quarterly using: carbon content (CC)
of petcoke for the quarter based on
reports from the supplier or by
quarterly measurement of the CC by
off‐site lab
CH4
N/A ‐ default emissions factor
Calculate annually using: petcoke consumption (measured quarterly), and number
of quarters.
CC—Soda Ash Fuel combustion at each kiln and from each stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Manufacturing If CEMS used to measure CO2 emissions ‐ calculate CO2 emissions using Tier 4 Calculation Methodology of subpart C
(§ 98.290)
Production
CO2
N/A
Calculate annually using: inorganic carbon content (measured daily) and mass
Calculate emissions from each calciner
(measured monthly) of trona input OR of soda ash output ratio to ton of CO2
(kiln) separately and sum to get total
emitted for each ton of trona OR natural soda ash produced
emissions
Draft Final ICR for the Proposed GHG Reporting Rule –
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Page B-14
March 2009
Subpart
Source Category
DD—Sulfur
Electric power
Hexafluoride system
(SF6) from
Electrical
Equipment
(§98.300)
GHGs
SF6, PFC
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Freq of Measurement
N/A
Calculate annually using: change in SF6/PFC inventory, purchased SF6/PFC,
disbursements of SF6/PFC, change in total nameplate capacity of equipment
EE—Titanium Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Dioxide
Production
CO2
N/A
(a) If CEMS used to measure CO2 emissions, calculate CO2 emissions using Tier 4
Production (§
Calculation Methodology of subpart C.
98.310)
(b) Calculate annually using: calcined petcoke consumption (measured monthly).
Comments
Calculate emissions from each chloride
process line separately and sum to get
total emissions
FF—Undergro Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
und Coal
Ventilation well or CH4
N/A
Calculate quarterly using: volumetric flow rate (average daily), CH4 concentration, Sum emissions from mine ventilation
Mines (§
shaft
temperature, and pressure of ventillation gas during active ventilation of mining systems, degasification systems, and
98.320)
operations
onsite combustion to get total CH4
Degasification
CH4
N/A
Calculate quarterly using: volumetric flow rate (average daily), CH4 concentration, emissions. If CH4 is destroyed, must use
system
temperature, and pressure of ventillation gas for the days in the quarter when the amount of CH4 collected for destruction
degasificatgion system is in operation and the continuous monitoring equipment is and destruction efficiency of destruction
equipment to calculate quantity of CH4
properly functioning.
Degasification or CO2
ventilation system
with on‐site coal
mine gas CH4
destruction
N/A
Calculate quarterly using: CH4 destroyed
GG—Zinc
Stationary combustion unit ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Production (§ Production
CO2
N/A
(a) If CEMS used to measure CO2 emissions, calculate emissions according to
98.330)
requirements of subpart C.
(b) Calculate annually using: mass and carbon content of: zinc bearing material
charged to the furnace, flux materials, carbon electrode consumed, and
carbonaceous materials. All inputs calculated monthly. If carbon content of input
above is not provided by material supplier, carbon content must be analyzed by
independent certified laboratory each month using test methods (and QA/QC
procedures) in §98.7 of subpart A.
Draft Final ICR for the Proposed GHG Reporting Rule –
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Page B-15
Calculate emissions for each individual
Waelz kiln or electrothermic furnace and
sum to get total emissions
March 2009
Subpart
Source Category
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Comments
Freq of Measurement
HH—Landfills Stationary combustion ‐ calculate CO2 emissions from the combustion of fuels in stationary combustion devices, including devices that combust landfill gas with other fuels (also include fuels used in
(§ 98.340)
Modeled CH4
CH4
N/A
Calculate annually using: quantity of waste disposed in the landfill in year X (Wx) This is not an emissions calculation. The
generation
Landfills with gas
collection systems
from facility records, CH4 generation potential (metric tons CH4/metric ton waste), annual modeled CH4 generation is used to
degradable organic carbon (fraction (metric tons C/metric ton waste)), fraction of calculate CH4 emissions for the three
DOC dissimilated, fraction by volume of CH4 in landfill gas. The annual quantity of landfill categories below
each type of waste disposed must be calculated as the sum of the daily quantities
For years when material‐specific waste
of waste (of that type) disposed. For both MSW and industrial landfills, you may
use the bulk waste parameters for a portion of your waste materials when using quantity data are available, and for
the material‐specific modeling approach for mixed waste streams that cannot be industrial waste landfills, calculate each
waste quantity type & sum CH4
designated to a specific material type.
(1) For industrial landfills, Wx in reporting years must be determined by direct mass generation rates for all waste types to
calculate the total modeled methane
measurement of waste entering the landfill using industrial scales. For previous
years where data are unavailable on waste disposal quantities, estimate using:
generation rate for the landfill.
average waste disposal factor (calculated using quantity of waste placed in the
industrial landfill and quantity of product produced in years for which disposal and
production data are available) and production quantity for facility.
(2) For years prior to reporting for which waste disposal quantities are not readily
available for MSW landfills, Wx shall be estimated using the estimated population
served by the landfill in each year, the values for national average per capita
waste disposal and fraction of generated waste disposed of in solid waste disposal
sites found in Table HH‐2.
CH4
N/A
Calculate the quantity of CH4 destroyed: Calculate annually using: quantity of CH4 Must calculate using both Method 1 and
recovered (calculate annually using: daily average volumetric flow rate, daily
Method 2
average CH4 concentration of landfill gas, density of CH4, and temperature and
pressure at which flow is measured). Additional inputs include oxidation fraction
and destruction efficiency.
Calculate CH4 emissions using both of 2 methods:
(1) Calculate annually using the modeled CH4 generation rate, the quantity of CH4
recovered, destruction efficiency, and soil oxidation factor
(2) Calculate annually using the quantity of CH4 recovered, collection efficiency
estimated at landfill (taking into account system coverage, operation, and cover
system materials) oxidation fraction, and destruction efficiency.
Landfills w/out gas CH4
collection systems
N/A
Calculate annually using: modeled CH4 generation rate, oxidation fraction
Draft Final ICR for the Proposed GHG Reporting Rule –
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Page B-16
March 2009
Subpart
Source Category
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Freq of Measurement
II—Wastewate Stationary combustion unit (and flares) ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
r (§ 98.350)
Anaerobic
CH4
N/A ‐ default emissions factor
Calculate annually using: volumetric flow rate of wastewater sent to an anaerobic
treatment systems
other than
digesters
Comments
treatment system and average monthly COD (both monitored weekly using 24‐
hour flow‐weighted composite sample), and maximum CH4 producing potential of
wastewater (can use default)
Petroleum refining CO2
facility w/ onsite
oil/water separator
N/A ‐ default emissions factor
Calculate annually using: volumetric flow rate of wastewater treated through
The flow should reflect the wasterwater
oil/water separator (monitor weekly) and carbon fraction in NMVOC (measured or treated in the oil/water separater
default).
Anaerobic digesters CH4
N/A
Calculate CH4 destroyed annually using: quantity of CH4 generated by the
anaerobic digester (calculated using: daily average volumetric flow rate, daily
average CH4 concentration of digester gas, and the pressure and temperature at
which flow is measured (measured daily)) and CH4 destruction efficiency from
flaring or burning in engine.
JJ—Manure Stationary combustion unit (and flares) ‐ calculate CO2, N2O, and CH4 emissions according to requirements of subpart C
Management All facilities other CH4
Collect samples monthly to determine TVS
N/A
Calculate CH4 emissions annually using: total volatile solids excreted by animal
(§ 98.360)
and TN concentration. Laboratory used
than digesters
type (calculated using:annual average animal population, typical animal mass,
should be certified for waste analysis for
average percent total volatile solids by animal type (determined from monthly
NPDES reporting.
manure monitoring), manure excretion rate (use default value or farm specific
data)), maximum CH4‐producing capacity (from Table JJ‐1), percent of manure that
Total emissions for facility = [CH4
is managed in each manure management system.
emissions + CH4 flow to digester
Anaerobic digesters CH4
N/A
Calculate CH4 flow to the combustion device annually using: average daily
combustion device – CH4 destruction of
volumetric flow rate, average daily CH4 concentration of digester gas,
digester + CH4 leakage of digester) x 1
temperature, and pressure. Calculate the amount of CH4 destroyed annually using:
metric ton/1000 kg x 21] + [direct N2O
CH4 flow to the comubtion device and CH4 destruction efficiency from flaring or
emissions x 1 metric ton/1000 kg x 310]
burning in engine. Calculate the CH4 leakage at digesters annually using: CH4
combusted by digester, CH4 collection efficiency of anaerobic digester (as specified
in Table JJ‐3).
All facilities
N2O
N/A ‐ default emissions factor
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Calculate annually using: total nitrogen excreted per animal type (calculated using:
annual average percent of nitrogen present in manure by animal type (as
determined from monthly manure monitoring), average annual animal population,
typical animal mass (using either the default values in Table JJ‐1 or a farm‐specific
value based on farm data), and manure excretion rate (using either a default value
from Table JJ‐1 or a farm‐specific value based on farm data)), percent of manure
that is managed in each manure management system, and an emission factor from
Table JJ‐4.
Page B-17
March 2009
Subpart
Source Category
GHGs
KK—Suppliers Coal mines ‐
CO2
of Coal
produce 100,000 or
(§98.370)
more short tons
coal annually
CO2
Coal mines ‐
produce less than
100,000 short tons
coal annually,
coal/coke
exporters,
coal/coke
importers, water
coal producers
LL—Suppliers
of Coal‐based
Liquid Fuels (§
98.380)
Coal‐to‐liquids
producers,
importers,
exporters
CO2
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Comments
Freq of Measurement
N/A ‐ default emission factor used in Calculate CO2 emissions annually using: mass and carbon content of the coal. The Facilities can chose Method 1 or Method
Method 3
carbon content of the coal is determined using one of the following methods: 2. A facility that does not satisfy the
Method 1: quantity of coal produced or quantity of coal in shipment and weighted monitoring criteria for Method 2 must use
avrg % carbon in coal (calculated using: mass fraction of carbon in coal and amount Method 1.
of coal supplied (both measured daily), the number of operating days per year, and
the total coal supplied during the year).
Facilities can chose Methods 1, 2, or 3.
Method 2: (1) calculate weighted annual average gross calorific value (GCV) of the Coal exporters: calculate carbon content
coal (using GCV or HHV of coal measured daily by proximate analysis (decimal
(CC) for each coal shipment using info on
value), amount of coal supplied (measured daily), total coal supplied during the
CC of exported coal provided by the
year); (2) establish statistical relationship between GCV and carbon content (CC) source mine, according to Method 1, 2, or
using procedure described in §98.374(f); (3) calculate estimated annual weighted 3. Coal importers: calculate CC for each
average of the mass fraction of carbon in the coal by applying the slope coefficient, coal shipment using Methods 1 or 2, or by
determined according to the requirements of §98.374(f)(4), to the weighted annual use of Method 3 in combination with mine‐
average GCV of
specific info from country of origin, or
the coal determined in step (1).
published CC values for coal of same rank
Method 3: (1) calculate weighted annual average gross calorific value (GCV)
from country of origin. Waste coal
of the coal (using GCV or HHV of coal measured daily by proximate analysis
reclaimers: calculate CC using Methods 1
(decimal value), amount of coal supplied (measured daily),
2, or 3.
total coal supplied during the year); and (2) identify estimated annual
Note: For importers, exporters, and waste
weighted average of the mass fraction of carbon in the coal from
coal reclaimers using Methods 1, 2, or 3,
Table KK‐1 using annual weighted GCV of coal from step (1).
measurements of each shipment can be
used in place of daily measurements
Can use site‐specific or default
emission factor. The site‐specific
emission factor is calculate using
density and percentage of total
mass that carbon represents for
each coal‐based liquid fuel.
Draft Final ICR for the Proposed GHG Reporting Rule –
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Calculate annually using: annual volume of a coal‐based liquid fuel and a CO2
emission factor determined using either Method 1 or Method 2: Method 1: Use
default emission factor listed in column C in Table MM‐1. Method 2: Use a site‐
specific CO2 emission factor calculated by multiplying the density by the carbon
content of the coal‐based liquid, where at least one of these parameters has been
measured uisng the methods specified in §98.394(c). Default values for carbon
content and density are included in Table MM‐1.
Page B-18
March 2009
Subpart
Source Category
GHGs
CO2
MM—Supplier Refiners ‐
s of Petroleum petroleum product
or natural gas liquid
Products (§
98.390)
Refiners ‐ non‐
CO2
crude petroleum
product and natural
gas liquid feedstock
Refiners ‐ biomass CO2
co‐processed with
petroleum
feedstocks
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Comments
Freq of Measurement
Default emissions factor (product Calculate emissions annually using: total annual volume produced by the reporting Total CO2 emissions for refiners =
specific, see tables in subpart MM) party (this volume only includes products ex refinery gate) and either a default or emissions from complete combustion or
oxidation of each petroleum product or
site‐specific emission factor.
or ss factor (calculated using:
density of petroleum product or
Calculated annually using: total annual volume of a petroleum product or natural natural gas liquid ‐ emissions from the
natural gas liquid or non‐crude
gas liquid that enters the refinery as a feedstock to be further refined or otherwise complete combustion or oxidation of each
feedstock and percent of total mass used on site (any waste feedstock that enters the refinery must also be included) non‐crude feedstock ‐ emissions from the
that carbon represents in petroleum and either a default or site‐specific emission factor.
complete combustion or oxidation of
biomass
product or natural gas liquid or non‐
crude feedstock). Refiners shall use Total annual volume of a specific type of biomass that enters the refinery to be co‐
the most appropriate default CO2 processed with petroleum feedstocks to produce a petroleum product and a
emission factor for biomass in Table default emission factor.
MM‐3 to calculate CO2 emissions.
Importers,
exporters
CO2
Calculate emissions from each individual petroleum product and natural gas liquid Total CO2 emissions for importers and
exporters = sum of emissions from the
annually using: total annual volume of product imported or exported by the
reporting party and either a default or site‐specific emission factor.
complete combustion or oxidation of all
petroleum products and natural gas liquids
All
CO2
In the event that some portion of a petroleum product or feedstock is biomass‐
based and was not derived by co‐processing biomass and petroleum feedstocks
together (i.e. the petroleum product or feedstock was produced by blending a
petroleum‐based product with a biomass‐based product), the reporting party shall
calculate emissions for the petroleum product or feedstock according to the
following methods in paragraph (1) or (2), as appropriate.
(a) If using default CO2 emission factors: (1) Use the annual volume of petroleum
product produced, imported, or exported (for refineries this includes only products
ex‐refinery gate), the percent volume of the product that is petroleum‐based, the
petroleum product‐specific default CO2 emission factor from Table MM‐1.
(2) Refineries may calculate the CO2 emissions associated with non‐crude
petroleum product using the annual volume of the petroleum product, the percent
volume of the product that is petroleum‐based, and the non‐crude petroleum
feedstock‐specific CO2 emission factor.
(b) If using site‐specific CO2 emission factors: (1) Use the annual volume of
petroleum product produced, imported, or exported (for refineries this includes
only products ex‐refinery gate), the percent volume of the product that is
petroleum‐based, the site‐specific petroleum product CO2 emission factor, and a
default CO2 emission factor from Table MM‐3 for the biomass. (2) Refineries may
calculate the CO2 emissions associated with non‐crude petroleum product using
the annual volume of the petroleum product, the percent volume of the product
that is petroleum‐based, the site‐specific CO2 emission factor for the non‐crude
petroleum product, and a default emission factor from Table MM‐3.
Draft Final ICR for the Proposed GHG Reporting Rule –
DO NOT CITE, QUOTE, OR DISTRIBUTE
Page B-19
March 2009
Subpart
Source Category
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Comments
Freq of Measurement
N/A ‐ default emissions factor (can Calculate annually the estimated CO2 equivalent emissions using either Method 1 Natural gas processing plants: report CO2
use facility‐ or company‐specific CO2 or 2:
emissions that would result from complete
emission factors, provided that they Method 1: Use the total annual volume of fuel or product, default factors from
combustion or oxidation of annual
are determined using industry
Table NN‐1 for the CO2 emission factor, and higher heat value of the fuel supplied. quantity of propane, butane, ethane,
standard practices)
Alternatively, reporter‐specific higher heating values and CO2 emission factors may isobutane and bulk NGLs sold or delivered
be used, provided they are developed using methods outlined in §98.404.
for use off site.
Local distribution companies: report CO2
Note: This calculation is used to find the annual potential CO2 mass emissions
from the combustion of fuel.
emissions that would result from complete
Method 2: Use the total annual volume of fuel or product supplied and the fuel‐
combustion or oxidation of annual
specific CO2 emission factors in Table NN‐1. Alternatively, reporter‐specific CO2
volumes of natural gas provided to end‐
emission factors may be used, provided they are developed using methods
users.
outlined in §98.404.
Note: This calculation is used to find the annual potential CO2 mass emissions from
the combustion of fuel.
NN—Suppliers All Suppliers
of Natural Gas (natural gas
and Natural processing plants
Gas Liquids (§ and local
98.400)
distribution
companies)
CO2
OO—Suppliers Fluroinated GHG
of Industrial production facility
Greenhouse
Gases (§
98.410)
Fluorinated N/A
GHG or N20
(mass)
Bulk importer and
exporter of
fluorinated GHGs or
N2O
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Calculate annually using: mass of each fluorinated GHG or nitrous oxide: (1)
produced at facility (calculated using the mass of each fluorinated GHG or nitrous
oxide produced and the mass of each fluorinated GHG or nitrous oxide added to
the production process upstream) , (2) transformed at facility (calculated using the
mass of each fluorinated GHG and nitrous oxide input to the transformation
process and the mass of residual, unreacted fluorinated GHG or nitrous oxide that
is permanently removed from the transfromation process), (3) destroyed at facility
(calculated using mass of fluorinated GHG input to the destruction device and the
destruction efficiency), and (4) sent to another facility for destruction (all
measured daily).
No calculation method provided. Importers and exporters measure fluorinated
GHGs and N2O imported or exported directly.
Page B-20
March 2009
Subpart
Source Category
GHGs
Calculating GHG Emissions
Info Needed for Emissions Factor &
Additional Info for GHG Calc & Freq of Measurement
Freq of Measurement
PP—Suppliers Production process CO2 (mass) N/A
Calculate quarterly (prior to purification, processing, or compressing) using:
units
of Carbon
average CO2 concentration in flow and quarterly mass flow rate.
Dioxide (§
CO2 production
98.420)
wells
Calculate quarterly using: average CO2 concentration in flow and quarterly mass
Facilities that
import or export
flow rate.
CO2
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Comments
If facility doesn't have a flow meter for
quantities captured or extracted, measure
quantities transferred off‐site using a flow
meter. In either case, sampling must be
If the importer of a CO2 stream does not
have mass flow meters installed to
measure the mass flow of gas imported,
the measurements shall be based on the
mass flow of the imported CO2 stream
transferred off site or used in on‐site
processes, as measured by mass flow
meters. If an exporter of a CO2 stream
does not have mass flow meters installed
to measure the mass flow exported, the
measurements shall be based on the mass
flow of the CO2 stream received for
export, as measured by mass flow meters.
In all cases, sampling on at least a
quarterly basis also must be conducted to
determine the composition of the CO2
stream.
March 2009
Table B-2 Procedures for Estimating Missing Data and QA/QC Requirements
Subpart
Source Category
All facilities
C—General
Stationary Fuel
Combustion
Sources
(§98.30)
Procedures for Estimating Missing Data
QA/QC
For units subject to the requirements of the Acid Rain Program, the
Tiers 1, 2, and 3: Document the procedures used to ensure accuracy of the estimates of
applicable missing data substitution procedures in part 75 are followed for fuel usage and/or sorbent usage (as applicable), the technical basis for these estimates,
CO2 concentration, stack gas flow rate, fuel flow rate, gross calorific value
and the accuracy of measurement devices.
(GCV), and fuel carbon content.
Tier 2: Follow the specified sampling and analysis methods to ensure the accuracy of high
For all units that are not subject to the requirements of the Acid Rain
heat value meaurements.
Program, when the Tier 1, Tier 2, Tier 3, or Tier 4 calculation is used,
Tier 3: All oil and gas flow meters (except for gas billing meters) shall be calibrated prior
use (1) and (2):
to the first year for which GHG emissions are reported under this part, using an
(1) For each missing value of the heat content, carbon content, or molecular applicable flow meter test method listed in §98.7 or the calibration procedures specified
weight of the fuel, and for each missing value of CO2 concentration and
by the flow meter manufacturer. Fuel flow meters shall be recalibrated either annually or
percent moisture, the substitute data value shall be the arithmetic average of at the minimum frequency specified by the manufacturer. Follow specified methods for
the quality‐assured values of that parameter immediately preceding and
oil tankdrop measurements, and carbon content sampling and analysis and molecular
immediately following the missing data incident. If, for a particular
weight determination.
parameter, no quality‐assured data are available prior to the missing data
Tier 4: Follow applicable QA procedures in in appendix B to part 75 of this chapter,
incident, the substitute data value shall be the first quality‐assured value
appendix F to part 60 of this chapter, or an applicable State continuous monitoring
obtained after the missing data period; and
program. If appendix F to part 60 of this chapter is selected for on‐going quality
(2) For missing records of stack gas flow rate, fuel usage, and sorbent usage, assurance, perform daily calibration drift (CD) assessments for both the CO2 and
the substitute data value shall be the best available estimate of
flow rate monitors, conduct cylinder gas audits of the CO2 concentration monitor
the flow rate, fuel usage, or sorbent consumption, based on all available
in three of the four quarters of each year (except for non‐operating quarters), and
perform annual RATAs of the CO2 concentration monitor and the CERMS. If O2
process data (e.g., steam production, electrical load, and operating
monitor is used, follow the applicable QA provisions of either part 75, part 60, or a
hours). The owner or operator shall document and keep records of the
procedures used for all such estimates.
State continuous monitoring program. Additional QA/QC is followed when sources
using Tier 4 combust biogenic fuels, including MSW.
D—Electricity
Generation
(§98.40)
E—Adipic Acid
Production
(§98.50)
All facilities
See requirements for stationary combustion
Stationary
combustion
Production
See requirements for stationary combustion
F—Aluminum Stationary
combustion
Production
Production
(§98.60)
A complete record of all measured parameters used in the GHG emissions
calculations is required.
All QA/QC procedures specified in the reference test methods and any associated
performance specifications apply. For each performance test facility must prepare an
emission factor determination report that includes: (1) analysis of samples, determination
of raw data; (2) all information and data used to derive the emissions factors; and (3) the
production rate during the test and how it was determined.
See requirements for stationary combustion
None specified. All QA/QC procedures specified in the reference test methods and any
A complete record of all measured parameters used in the GHG emissions
associated performance specifications apply.
calculations is required.
(a) Where anode or paste consumption data is missing, CO2 emissions can be
estimated from aluminum production using Tier 1 method (inputs required:
metal production from prebake process, metal production from Soderburg
process).
(b) For other parameters, use the average of the two most recent data
points.
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March 2009
Subpart
G—Ammonia
Manufacturing
(§98.70)
Source Category Procedures for Estimating Missing Data
See requirements for stationary combustion
Stationary
combustion
CO2 collected and See requirements for CO2 suppliers
used onsite or
transferred offsite
Production
H—Cement
Production
(§98.80)
QA/QC
All fuel flow meters and gas composition monitors shall be calibrated prior to the first
A complete record of all measured parameters used in the GHG emissions
reporting year, using a suitable method published by a consensus standards organization
calculations is required.
(a) For missing feedstock supply rates, use the lesser of the maximum supply (e.g., ASTM, ASME, API, AGA, or others). Alternatively, calibration procedures specified
rate that the unit is capable of processing or the maximum supply rate that by the flow meter manufacturer may be used. Fuel flow meters and gas composition
monitors shall be recalibrated either annually or at the minimum frequency specified by
the meter can measure.
(b) There are no missing data procedures for carbon content. A re‐test must the manufacturer, whichever is more frequent.
be performed if the data from any monthly measurements are determined to Document the procedures used to ensure the accuracy of the estimates of feedstock
be invalid.
consumption.
Fuel combustion See requirements for stationary combustion
at kilns and any
other Stationary
combustion unit
Production
If data on the carbonate content or organic carbon content analysis is
missing, facilities must undertake a new analysis.
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None specified. All QA/QC procedures specified in the reference test methods and any
associated performance specifications apply.
March 2009
Subpart
I—Electronics
Manufacturing
(§98.90)
Source Category
Stationary
combustion
Production
J—Ethanol
Production
(§98.100)
Onsite stationary See requirements for stationary combustion
combustion
Onsite landfills
Onsite
wastewater
treatment
Procedures for Estimating Missing Data
See requirements for stationary combustion
QA/QC
(a) For semiconductor facilities that have an annual capacity of greater than Estimating F‐GHG & N2O emissions from cleaning/etching:
10,500 m2 silicon, estimate missing site‐specific gas process utilization and by‐(1) Follow the QA/QC procedures in the International SEMATECH Manufacturing
Initiative’s Guideline for Environmental Characterization of Semiconductor Process
product formation using default factors from Tables I‐2 through I‐4 of this
subpart. However, use of these default factors shall be restricted to less than Equipment when estimating facility‐specific gas process utilization and by‐product gas
5 percent of the total facility emissions.
formation.
(b) For facilities using heat transfer fluids and missing data for one or more (2) Follow the QA/QC procedures in the EPA DRE measurement protocol when estimating
of the parameters in Equation I‐8, you shall estimate heat transfer fluid
abatement device DRE.
(3) Certify that abatement devices are maintained in accordance with manufacturer
emissions using the arithmetic average of the emission rates for the year
specified guidelines.
immediately preceding the period of missing data and the months
(4) Certify that gas consumption is tracked to a high degree of precision as part of normal
immediately following the period of missing data. Alternatively, you may
facility operations and that further QA/QC is not required.
estimate missing information using records from the heat transfer fluid
supplier. You shall document the method used and values estimated for all Estimating F‐GHG emissions from heat transfer fluid use:
missing data values.
(1) Review all inputs to Equation I‐4 to ensure that all inputs and outputs to the facility’s
(c) If the methods specified in paragraphs (a) and (b) of this section are likely system are accounted for.
to significantly under‐ or overestimate the value of the parameter during the (2) Do not enter negative inputs into the mass balance equation and ensure that no
period when data were missing (e.g., because the monitoring
negative emissions are calculated from the mass
failure was linked to a process disturbance that is likely to have
balance equation.
significantly increased the F‐GHG emission rate), you shall develop a
(3) Ensure that the beginning of year inventory matches the end of year inventory from
best estimate of the parameter, documenting the methods used, the
previous year. All flowmeters, scales, load cells, and volumetric and density
rationale behind them, and the reasons why the methods specified in
measures used to measure quantities that are to be reported under §98.92 and
paragraphs (a) and (b) of this section would lead to a significant under‐
§98.96 shall be calibrated using suitable NIST‐traceable standards and suitable
or overestimate of the parameter.
methods published by a consensus standards organization (e.g., ASTM, ASME,
ASHRAE, or others). Alternatively, calibration procedures specified by the
flowmeter, scale, or load cell manufacturer may be used. Calibration shall be
performed prior to the first reporting year. After the initial calibration, recalibration
shall be performed at least annually or at the minimum frequency specified by the
manufacturer, whichever is more frequent.
See requirements for landfills
See requirements for onsite wastewater treatment
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March 2009
Subpart
K—Ferroalloy
Production
(§98.110)
Source Category
Stationary
combustion
Production
Procedures for Estimating Missing Data
See requirements for stationary combustion
QA/QC
A complete record of all measured parameters used in the GHG emissions
None specified. All QA/QC procedures specified in the reference test methods and any
calculations is required.
associated performance specifications apply.
(a) For each missing value of the carbon content the substitute data value
shall be the arithmetic average of the quality‐assured values of that
parameter immediately preceding and immediately following the missing
data incident. If, for a particular parameter, no quality‐assured data are
available prior to the missing data incident, the substitute data value shall be
the first quality‐assured value obtained after the missing data period; and
(b) For missing records of the mass of carbon‐containing input or output
material consumption, the substitute data value shall be the best available
estimate of the mass of the input or output material. The owner or operator
shall document and keep records of the procedures used for all such
estimates.
(c) If you are required to calculate CH4 emissions for the electric arc furnace
as specified in §98.113(c), then you are required to have 100 percent of the
specified data for each reporting period.
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March 2009
Subpart
Source Category
L—Fluorinated Stationary
Greenhouse combustion
Gas Production Production
(§98.120)
M—Food
Processing
(§98.130)
N—Glass
Production
(§98.140)
Procedures for Estimating Missing Data
See requirements for stationary combustion
QA/QC
All flowmeters, scales, load cells, and volumetric and density measures used to measure
A complete record of all measured parameters used in the GHG emissions
calculations is required.
quantities that are to be reported under §98.126 shall be calibrated using suitable NIST‐
(1) For each missing value of the mass of fluorinated GHG produced, the
traceable standards and suitable methods published by a consensus standards
mass of reactants fed into the production process, the mass of reactants
organization (e.g., ASTM, ASME, ASHRAE, or others). Alternatively, calibration
permanently removed from the production process, the mass flow of process procedures specified by the flowmeter, scale, or load cell manufacturer may be used.
streams containing more than trace concentrations of by‐products that lead Calibration shall be performed prior to the first reporting year. After the initial
to yield losses, or the mass of wastes fed into the destruction device, the
calibration, recalibration shall be performed at least annually or at the minimum
substitute value of that parameter shall be a secondary mass measurement frequency specified by the manufacturer, whichever is more frequent. All gas
taken during the period the primary mass measurement was not available. chromatographs used to determine the concentration of fluorinated greenhouse gases in
For example, if the mass produced is usually measured with a flowmeter at process streams shall be calibrated at least monthly through analysis of certified
the inlet to the day tank and that flowmeter fails to meet an accuracy or
standards with known concentrations of the same chemical(s) in the same range(s)
precision test, malfunctions, or is rendered inoperable, then the mass
(fractions by mass) as the process samples. Calibration gases prepared from a high‐
produced may be estimated by calculating the change in volume in the day concentration certified standard using a gas dilution system that meets the requirements
tank and multiplying it by the density of the product.
specified in Test Method 205, 40 CFR Part 51, Appendix M may also
(2) For each missing value of fluorinated GHG concentration, the substitute be used.
data value shall be the arithmetic average of the
quality‐assured values of that parameter immediately preceding and
immediately following the missing data incident. If no quality‐assured
data are available prior to the missing data incident, the substitute
data value shall be the first quality‐assured value obtained after the
missing data period.
(3) If the methods specified in paragraphs (a)(1) and (a)(2) are likely to
significantly under‐ or overestimate the value of the parameter during
the period when data were missing, you shall develop a best estimate
of the parameter, documenting the methods used, the rationale behind
them, and the reasons why the methods specified in (a)(1) and (a)(2)
would lead to a significant under‐ or overestimate of the parameter.
Onsite stationary See requirements for stationary combustion
combustion
Onsite landfills
Onsite
wastewater
treatment
Stationary
combustion
Production
See requirements for landfills
See requirements for onsite wastewater treatment
See requirements for stationary combustion
(a) Missing data on the monthly amounts of carbonate‐based raw materials
charged to any continuous glass melting furnace shall be replaced by the
average of the data from the previous month and the following month for
each carbonate‐based raw material charged.
(b) Missing data on the mass fractions of carbonate‐based minerals in the
carbonate‐based raw materials shall be replaced using the assumption that
the mass fraction of each carbonate based mineral is 1.0.
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Page B-26
If use raw material supplier data to determine carbonate‐mineral mass, facility should
make its own measurements annually to verify the data. Such measurements shall be
based on sampling and chemical analysis conducted by a certified laboratory using a
suitable method published by a consensus standards organization (e.g., ASTM Method
D3682, Test Method for Major and Minor Elements in Coal and Coke Ash by Atomic
Absorption Method).
March 2009
Subpart
Source Category
O—HCFC‐22 All facilities
Production and
HFC‐23
Destruction
(§98.150)
P—Hydrogen Stationary
Production
combustion
Production
(§98.160)
Q—Iron &
Steel
Production
(§98.170)
Stationary
combustion
Production
Procedures for Estimating Missing Data
QA/QC
A complete record of all measured parameters used in the GHG emissions
All flowmeters, scales, and load cells used to measure quantities that are to be reported
calculations is required.
under section §98.156 of this subpart shall be calibrated using suitable NIST‐traceable
(1) For each missing value of the HFC‐23 or HCFC‐22 concentration, the
standards and suitable methods published by a consensus standards organization (e.g.,
substitute data value shall be the arithmetic average of the quality‐assured ASTM, ASME, ASHRAE, or others). Alternatively, calibration procedures specified by the
values of that parameter immediately preceding and immediately following flowmeter, scale, or load cell manufacturer may be used. Calibration shall be performed
the missing data incident. If, for a particular parameter, no quality‐assured prior to the first reporting year. After the initial calibration, recalibration shall be
data are available prior to the missing data incident, the substitute data value performed at least annually or at the minimum frequency specified by the manufacturer,
shall be the first quality‐assured value obtained after the missing data period. whichever is more frequent.
(2) For each missing value of the product stream mass flow or product mass, All gas chromatographs used to determine the concentration of HFC‐23 in process
the substitute value of that parameter shall be a secondary product
streams shall be calibrated at least monthly through analysis of certified standards (or of
measurement. If that measurement is taken significantly downstream of the calibration gases prepared from a high‐concentration certified standard using a gas
usual mass flow or mass measurement (e.g., at the shipping dock rather than dilution system that meets the requirements specified in Test Method 205, 40 CFR part
near the reactor), the measurement shall be multiplied by 1.015 to
51, appendix M) with known HFC‐23 concentrations that are in the same range (fractions
compensate for losses.
by mass) as the process samples.
(3) Notwithstanding paragraphs (a)(1) and (a)(2), if the owner or operator
has reason to believe that the methods specified in paragraphs (a)(1) and
(a)(2) are likely to significantly under‐ or overestimate the
value of the parameter during the period when data were missing (e.g.,
because the monitoring failure was linked to a process disturbance that
is likely to have significantly increased the HFC‐23 generation rate),
develop best estimate of the parameter, documenting the methods used,
the rationale behind them, and the reasons why the methods specified in
(a)(1) and (a)(2) would probably lead to a significant under‐ or
overestimate of the parameter.
See requirements for stationary combustion
A complete record of all measured parameters used in the GHG emissions
All fuel flow meters, gas composition monitors, and heating value monitors shall be
calculations is required.
calibrated prior to the first reporting year, using a suitable method published by a
(a) For missing feedstock supply rates, use the lesser of the maximum supply consensus standards organization (e.g., ASTM, ASME, API, AGA, or others). Alternatively,
rate that the unit is capable of processing or the maximum supply rate that calibration procedures specified by the flow meter manufacturer may be used. Fuel flow
the meter can measure.
meters, gas composition monitors, and heating value monitors shall be recalibrated
(b) There are no missing data procedures for carbon content. A re‐test must either annually or at the minimum frequency specified by the manufacturer. Document
be performed if the data from any monthly measurements are determined to the procedures used to ensure the accuracy of the estimates of feedstock consumption.
be invalid.
(c) Facilities that use CEMS must comply with the monitoring and QA/QC
procedures specified in §98.34(e).
See requirements for stationary combustion
There are no allowances for missing data for facilities that estimate emissions None specified. All QA/QC procedures specified in the reference test methods and any
using the carbon balance procedure or the site‐emission factor procedure, associated performance specifications apply.
and 100 percent data availability is required.
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March 2009
Subpart
R—Lead
Production
(§98.180)
Source Category
Stationary
combustion
Production
Stationary
S—Lime
Manufacturing combustion
Production
(§98.190)
Procedures for Estimating Missing Data
See requirements for stationary combustion
QA/QC
A complete record of all measured parameters used in the GHG emissions
None specified. All QA/QC procedures specified in the reference test methods and any
calculations is required.
associated performance specifications apply.
(a) For each missing value of the carbon content the substitute data value
shall be the arithmetic average of the quality‐assured values of that
parameter immediately preceding and immediately following the missing
data incident. If, for a particular parameter, no quality‐assured data are
available prior to the missing data incident, the substitute data value shall be
the first quality‐assured value obtained after the missing data period; and
(b) For missing records of the mass of carbon‐containing input material
consumption, the substitute data value shall be the best available estimate of
the mass of the input material. The owner or operator shall document and
keep records of the procedures used for all such estimates.
See requirements for stationary combustion
A complete record of all measured parameters used in the GHG emissions
Follow the quality assurance/quality control procedures (including documentation) in the
National Lime Association’s “CO2 Emissions Calculation Protocol for the Lime Industry‐
calculations is required.
(a) For each missing value of quantity of lime types, CaO and MgO content, English Units Version”, February 5, 2008 Revision (incorporated by reference‐see §98.7).
and quantity of LKD the substitute data value shall be the arithmetic average
of the quality‐assured values of that parameter immediately preceding and
immediately following the missing data incident. If, for a particular
parameter, no quality‐assured data are available prior to the missing data
incident, the substitute data value shall be the first quality‐assured value
obtained after the missing data period; and
(b) For missing records of mass of raw material consumption, the substitute
data value shall be the best available estimate of the mass of inputs. The
owner or operator shall document and keep records of the procedures used
for all such estimates.
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March 2009
Subpart
Source Category
T—Magnesium Stationary
Production
combustion
Production
(§98.200)
Procedures for Estimating Missing Data
See requirements for stationary combustion
QA/QC
A complete record of all measured parameters used in the GHG emission
calculations is required. Replace missing data on the consumption of cover
gases by multiplying magnesium production during the missing data period
by the average cover gas usage rate from the most recent period when
operating conditions were similar to those for the period for which the data
are missing. Calculate the usage rate for each cover gas using equation T‐5.
All flowmeters, scales, and load cells used to measure quantities that are to be reported
under this subpart shall be calibrated using suitable NIST‐traceable standards and
suitable methods published by a consensus standards organization (e.g., ASTM, ASME,
ASHRAE, or others). Alternatively, calibration procedures specified by the flowmeter,
scale, or load cell manufacturer may be used. Calibration shall be performed prior to the
first reporting year. After the initial calibration, recalibration shall be performed at least
annually or at the minimum frequency specified by the manufacturer, whichever is more
frequent.
Option 2:
(1) Track the identities and masses of containers leaving and entering storage with check‐
out and check‐in sheets and procedures. The masses of cylinders returning to storage
shall be measured immediately before the cylinders are put back into storage.
(2) Ensure that all the quantities required by equations T‐3 and T‐4 of this subpart have
been measured using scales or load cells with an accuracy of one percent of full scale or
better, accounting for the tare weights of the containers.
You may accept gas masses or weights provided by the gas supplier
(e.g., for the contents of cylinders containing new gas or for the heels remaining
in cylinders returned to the gas supplier); however, you remain responsible for the
accuracy of these masses or weights under this subpart.
U—Misc. Uses Production
of Carbonate (§
98.210)
A complete record of all measured parameters used in the GHG emissions
calculations is required. A re‐test must be performed if the data from any
measurements are determined to be invalid.
None specified. All QA/QC procedures specified in the reference test methods and any
associated performance specifications apply.
V—Nitric Acid Stationary
Production
combustion
Production
(§98.220)
See requirements for stationary combustion
W—Oil &
Natural Gas
Systems
(§98.230)
Stationary
combustion
Process facilities
A complete record of all measured parameters used in the GHG emissions
calculations is required.
All QA/QC procedures specified in the reference test methods and any associated
performance specifications apply. The report must include:
(1) Analysis of samples, determination of emissions, and raw data;
(2) All information and data used to derive the emissions factor; and
(3) The production rate during the test and how it was determined.
See requirements for stationary combustion
A complete record of all measured parameters used in the GHG emissions
calculations is required. If data are lost or an error occurs during annual
emissions measurements, you must repeat the measurement activity for
those sources until a valid measurement is obtained.
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None specified. All QA/QC procedures specified in the reference test methods and any
associated performance specifications apply.
March 2009
Subpart
X—Petrochemi
cal Production
(§98.240)
Source Category
Stationary
combustion
Onsite
wastewater
treatment
Production
Y—Petroleum Stationary
combustion
Refineries
Non‐merchant
(§98.250)
hydrogen
production
Onsite landfills
Onsite
wastewater
treatment
Production
Z—Phosphoric Stationary
Acid
combustion
Production
Production
(§98.260)
Procedures for Estimating Missing Data
See requirements for stationary combustion
QA/QC
See requirements for onsite wastewater treatment
(a) For missing feedstock flow rates, product flow rates, and carbon contents, CEMS: see requirements of subpart C
use the same procedures as for missing flow rates and carbon contents for Mass balance: document procedures used to ensure the accuracy of the measurements
fuels as specified in §98.35.
of the feedstock and product flows including, but not limited to, calibration of all
(b) For missing CO2 concentration, stack gas flow rate, and moisture content weighing equipment and other measurement devices. The estimated accuracy of
for CEMS on any process vent stack, follow the applicable procedures
measurements made with these devices shall be recorded, and the technical basis for
these estimates shall be recorded. All feedstock and product flow meters must be
specified in §98.35.
calibrated prior to the first reporting year, using any applicable method incorporated by
reference in §98.7(b)(1) through (6), (c)(1), (f)(3)(i) through (ii), or (g)(1). You should use
the flow meter accuracy test procedures in appendix D to part 75 of this chapter.
Alternatively, calibration procedures specified by the equipment manufacturer may be
used. Flow meters and gas composition monitors shall be recalibrated annually or at the
frequency specified by another applicable rule or the manufacturer, whichever is more
frequent.
See requirements for stationary combustion
See requirements for hydrogen production
See requirements for landfills
See requirements for onsite wastewater treatment
A complete record of all measured parameters used in the GHG emissions
calculations is required.
(a) For each missing value of the heat content, carbon content, or molecular
weight of the fuel, the substitute data value shall be the arithmetic average
of the quality‐assured values of that parameter immediately preceding and
immediately following the missing data incident. If, for a particular
parameter, no quality‐assured data are available prior to the missing data
incident, the substitute data value shall be the first quality‐assured value
obtained after the missing data period.
(b) For missing oil and gas flow rates, use the standard missing data
procedures in section 2.4.2 of appendix D to part 75 of this chapter.
(c) For missing CO2, CO, or O2, CH4, and N2O concentrations, stack gas flow
rate, and stack gas moisture content values, use the applicable initial missing
data procedures in §98.35 of subpart C.
See requirements for stationary combustion
All fuel flow meters, gas composition monitors, and/or heating value monitors that are
used to provide data for the GHG emissions calculations shall be calibrated prior to the
first reporting year, using a suitable method published by a consensus standards
organization (e.g., ASTM, ASME, API, AGA, etc.). Alternatively, calibration procedures
specified by the flow meter manufacturer may be used. Fuel flow meters, gas
composition monitors, and heating value monitors shall be recalibrated either annually or
at the minimum frequency specified by the manufacturer. Document the procedures
used to ensure the accuracy of the estimates of fuel usage, gas composition, and/or
heating value including, but not limited to, calibration of weighing equipment, fuel flow
meters, and other measurement devices. The estimated accuracy of measurements made
with these devices shall also be recorded, and the technical basis for these estimates shall
be provided. All CO2 CEMS and flow rate monitors used for direct measurement of GHG
emissions must comply with the QA procedures in §98.34(e).
A complete record of all measured parameters used in the GHG emissions
calculations is required. A re‐test must be performed if the data from the
measurement are determined to be unacceptable.
None specified. All QA/QC procedures specified in the reference test methods and any
associated performance specifications apply.
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Subpart
AA—Pulp and
Paper
Manufacturing
(§98.270)
Source Category
Stationary
combustion
Production
BB—Silicon
Carbide
Production
(§98.280)
Stationary
combustion
Production
Procedures for Estimating Missing Data
See requirements for stationary combustion
QA/QC
A complete record of all measured parameters used in the GHG emissions
calculations is required.
(a) There are no missing data procedures for measurements of heat content
and carbon content of spent pulping liquor. A re‐test must be performed if
the data from any monthly measurements are determined to be invalid.
(b) For missing spent pulping liquor flow rates, use the lesser value of either
the maximum fuel flow rate for the combustion unit, or the maximum flow
rate that the fuel flow meter can measure.
(c) For the use of makeup chemicals (carbonates), the substitute data value
shall be the best available estimate of makeup chemical consumption, based
on available data (e.g., past accounting records, production rates). The
owner or operator shall document and keep records of the procedures used
for all such estimates.
See requirements for stationary combustion
Each facility must keep records that include a detailed explanation of how company
records of measurements are used to estimate GHG emissions. The owner or operator
must also document the procedures used to ensure the accuracy of the measurements of
fuel and makeup chemical usage, including, but not limited to calibration of weighing
equipment, fuel flow meters, and other measurement devices. The estimated accuracy
of measurements made with these devices must be recorded and the technical basis for
these estimates must be provided. The procedures used to convert spent liquor flow
rates to units of mass (i.e., spent liquor solids firing rates) also must be documented.
Records must be made available upon request for verification of the calculations and
measurements. All QA/QC procedures specified in the reference test methods and any
associated performance specifications apply.
A complete record of all measured parameters used in the GHG emissions
None specified. All QA/QC procedures specified in the reference test methods and any
calculations is required. There are no missing value provisions for the carbon associated performance specifications apply.
content factor or coke consumption. A re‐test must be performed if the data
from the quarterly carbon content measurements are determined to be
unacceptable or not representative of typical operations.
CC—Soda Ash Fuel combustion See requirements for stationary combustion
Manufacturing at each kiln and
from each
(§98.290)
stationary
combustion unit
For each soda ash A re‐test must be performed if the data from the daily carbon content
measurements are determined to be unacceptable.
manufacturing
line
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Document the procedures used to ensure the accuracy of the monthly measurements of
trona consumed soda ash production. A complete record of all measured parameters
used in the GHG emissions calculations is required. All QA/QC procedures specified in the
reference test methods and any associated performance specifications apply.
March 2009
Subpart
DD—Sulfur
Hexafluoride
(SF6) from
Electrical
Equipment
(§98.300)
Source Category
Electric power
system
EE—Titanium Stationary
Dioxide
combustion
Production
Production
(§98.310)
Procedures for Estimating Missing Data
QA/QC
A complete record of all measured parameters used in the GHG emissions
(a) QA/QC methods for reviewing completeness and accuracy of reporting: (1) Review
calculations is required. Replace missing data, if needed, based on data from inputs to mass balance equation to ensure inputs and outputs to company’s system are
equipment with a similar nameplate capacity for SF6 and PFC, and from
all included. (2) Do not enter negative inputs and confirm that negative emissions are not
similar equipment repair, replacement, and maintenance operations.
calculated. However, decrease in SF6 inventory and nameplate capacity may be
calculated as negative numbers. (3) Ensure that beginning‐of‐year inventory matches end‐
of‐year inventory from the previous year. (4) Ensure that in addition to SF6 purchased
from bulk gas distributors, SF6 purchased from Original Equipment Manufacturers (OEM)
and SF6 returned to the facility from off‐site recycling are also accounted for among the
total additions.
(b) Ensure the following QA/QC methods are employed throughout the year: (1) Ensure
that cylinders returned to the gas supplier are consistently weighed on a scale that is
certified to be accurate and precise to within 1% of the true weight and is periodically
recalibrated per the manufacturer’s specifications.
Either measure residual gas (the amount of gas remaining in returned cylinders) or
have the gas supplier measure it. If the gas supplier weighs the residual gas, obtain
from the gas supplier a detailed monthly accounting, within 1%, of residual gas
amounts in the cylinders returned to the gas supplier. (2) Ensure that procedures
are in place and followed to track and weigh all cylinders as they are leaving and
entering storage. Cylinders shall be weighed on a scale that is certified to be
accurate to within 1% of the true weight and the scale shall be recalibrated at least
annually or at the minimum frequency specified by the manufacturer, whichever is
more frequent. All scales used to measure quantities that are to be reported under
§98.306 shall be calibrated using suitable NIST‐traceable standards and suitable
methods published by a consensus standards organization (e.g., ISWM, ISDA,
NCWM, or others). Alternatively, calibration procedures specified by the scale
manufacturer may be used. Calibration shall be performed prior to the first
reporting year. (3) Ensure all substations have provided information to the manager
compiling the emissions report (if it is not already handled through an electronic
inventory system).
See requirements for stationary combustion
A complete record of all measured parameters used in the GHG emissions
calculations is required.
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Document the procedures used to ensure the accuracy of monthly calcined petroleum
coke consumption.
March 2009
Subpart
FF—Undergrou
nd Coal Mines
(§98.320)
Source Category
Stationary
combustion
Production
GG—Zinc
Production
(§98.330)
Stationary
combustion
Production
Procedures for Estimating Missing Data
See requirements for stationary combustion
QA/QC
A complete record of all measured parameters used in the GHG emissions
calculations is required.
For each missing value of CH4 concentration, flow rate, temperature, and
pressure for ventilation and degassification systems, the substitute data
value shall be the arithmetic average of the quality‐assured values of that
parameter immediately preceding and immediately following the missing
data incident. If, for a particular parameter, no quality‐assured data are
available prior to the missing data incident, the substitute data value shall be
the first quality‐assured value obtained after the missing data period.
All fuel flow meters and gas composition monitors shall be calibrated prior to the first
reporting year, using a suitable method published by a consensus standards organization
(e.g., ASTM, ASME, API, AGA, MSHA, or others). Alternatively, calibration procedures
specified by the flow meter manufacturer may be used. Fuel flow meters, and gas
composition monitors shall be recalibrated either annually or at the minimum frequency
specified by the manufacturer or other applicable standards. All temperature and
pressure monitors must be calibrated using the procedures and frequencies specified by
the manufacturer.
Document the procedures used to ensure the accuracy of gas flow rate, gas composition,
temperature, and pressure measurements. Procedures include calibration fuel flow
meters, and other measurement devices. The estimated accuracy of measurements and
the technical basis for the estimated accuracy shall be recorded.
See requirements for stationary combustion
A complete record of all measured parameters used in the GHG emissions
None specified. All QA/QC procedures specified in the reference test methods and any
calculations is required.
associated performance specifications apply.
(a) For each missing value of the carbon content the substitute data value
shall be the arithmetic average of the quality‐assured values of that
parameter immediately preceding and immediately following the missing
data incident. If, for a particular parameter, no quality‐assured data are
available prior to the missing data incident, the substitute data value shall be
the first quality‐assured value obtained after the missing data period; and
(b) For missing records of the mass of carbon‐containing input material
consumption, the substitute data value shall be the best available estimate of
the mass of the input material. The owner or operator shall document and
keep records of the procedures used for all such estimates.
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March 2009
Subpart
Source Category
HH—Landfills Stationary
(§98.340)
combustion
Production (As
required by
related source
methodology)
II—Wastewater Stationary
combustion
(§98.350)
Production (As
required by
related source
methodology)
Procedures for Estimating Missing Data
See requirements for stationary combustion
QA/QC
All fuel flow meters and gas composition monitors shall be calibrated prior to the first
A complete record of all measured parameters used in the GHG emissions
calculations is required.
reporting year, using ASTM D1945‐03 (Reapproved 2006), Standard Test Method for
(1) For each missing value of the CH4 content, the substitute data value shall Analysis of natural Gas by Gas Chromatography; ASTM D1946‐90 (Reapproved 2006),
be the arithmetic average of the quality‐assured values of that parameter
Standard Practice for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891‐89
immediately preceding and immediately following the missing data incident. (Reapproved 2006, Standard Test Method for Heating Value of Gases in Natural Gas
If, for a particular parameter, no quality‐assured data are available prior to Range by Stoichiometric Combustion; or UOP539‐97 Refinery Gas Analysis by Gas
the missing data incident, the substitute data value shall be the first quality‐ Chromatrography (incorporated by reference, see §98.7).
assured value obtained after the missing data period.
Alternatively, calibration procedures specified by the flow meter manufacturer may be
(2) For missing gas flow rates, the substitute data value shall be the
used. Fuel flow meters, and gas composition monitors shall be recalibrated either
arithmetic average of the quality‐assured values of that parameter
annually or at the minimum frequency specified by the manufacturer. All temperature
immediately preceding and immediately following the missing data incident. and pressure monitors must be calibrated using the procedures and frequencies specified
If, for a particular parameter, no quality‐assured data are available prior to by the manufacturer. Document the procedures used to ensure the accuracy of the
the missing data incident, the substitute data value shall be the first quality‐ estimates of disposal quantities
assured value obtained after the missing data period.
and, if applicable, gas flow rate, gas composition, temperature, and pressure
(3) For missing daily waste disposal data for disposal in reporting years, the measurements. These procedures include, but are not limited to,
substitute value shall be the average daily waste disposal
calibration of weighing equipment, fuel flow meters, and other measurement devices.
quantity for that day of the week as measured on the week before
The estimated accuracy of measurements made with these devices shall
and week after the missing daily data.
also be recorded, and the technical basis for these estimates shall be provided.
See requirements for stationary combustion
A complete record of all measured parameters used in the GHG emissions
calculations is required.
(1) For each missing monthly value of COD or wastewater flow treated, the
substitute data value shall be the arithmetic average of the quality‐assured
values of those parameters for the weeks immediately preceding and
immediately following the missing data incident. For each missing value of
the CH4 content or gas flow rates, the substitute data value shall be the
arithmetic average of the quality‐assured values of that parameter
immediately preceding and immediately following the missing data incident.
(2) If, for a particular parameter, no quality‐assured data are available prior
to the missing data incident, the substitute data value shall be the first
quality‐assured value obtained after the missing data period.
Draft Final ICR for the Proposed GHG Reporting Rule –
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All flow meters must be calibrated using the procedures and frequencies specified by the
device manufacturer. All gas flow meters and gas composition monitors shall be
calibrated prior to the first reporting year, using a suitable method published by a
consensus standards organization (e.g., ASTM, ASME, API, AGA, or others). Alternatively,
calibration procedures specified by the flow meter manufacturer may be used. Gas flow
meters and gas composition monitors shall be recalibrated either annually or at the
minimum frequency specified by the manufacturer. All temperature and pressure
monitors must be calibrated using the procedures and frequencies specified by the device
manufacturer. Document the procedures used to ensure the accuracy of gas flow rate,
gas composition, temperature, and pressure measurements. These procedures include,
but are not limited to, calibration fuel flow meters and other measurement devices. The
estimated accuracy of measurements made with these devices shall also be recorded,
and the technical basis for these estimates shall be provided.
March 2009
Subpart
JJ—Manure
Management
(§98.360)
Source Category
Stationary
combustion
Production (As
required by
related source
methodology)
KK—Suppliers All facilities
of Coal
(§98.370)
LL—Suppliers All facilities
of Coal‐based
Liquid Fuels
(§98.380)
Procedures for Estimating Missing Data
See requirements for stationary combustion
QA/QC
A complete record of all measured parameters used in the GHG emissions
calculations is required.
For missing gas flow rates, volatile solids, or nitrogen or methane content
data, the substitute data value shall be the arithmetic average of the quality‐
assured values of that parameter immediately preceding and immediately
following the missing data incident. If, for a particular parameter, no quality‐
assured data are available prior to the missing data incident, the substitute
data value shall be the first quality‐assured value obtained after the missing
data period.
All temperature and pressure monitors must be calibrated using the procedures and
frequencies specified by the manufacturer. All gas flow meters and gas composition
monitors shall be calibrated prior to the first reporting year, using a suitable method
published by a consensus standards organization (e.g., ASTM, ASME, API, AGA, or others).
Alternatively, calibration procedures specified by the flow meter manufacturer may be
used. Gas flow meters and gas composition monitors shall be recalibrated either annually
or at the minimum frequency specified by the manufacturer.
If applicable, document the procedures used to ensure the accuracy of gas flow rate, gas
composition, temperature, and pressure measurements. These procedures include, but
are not limited to, calibration of fuel flow meters and other measurement devices. The
estimated accuracy of measurements made with these devices shall also be recorded,
and the technical basis for these estimates shall be provided.
A complete record of all measured parameters used in the GHG emissions
Each owner or operator using mechanical coal sampling systems shall perform quality
assurance and quality control according to ASTM D4702‐07 and ASTM D6518‐07.
calculations is required.
(b) Whenever a quality‐assured value for coal production during any time
period is unavailable, you must use the average of the parameter values
recorded immediately before and after the missing data period in the
calculations.
(c) Facilities using Calculation Method 1 of this section shall develop the
statistical relationship between GCV and carbon content according to
§98.274(e), and use this statistical relationship to estimate daily carbon
content for any day for which measured carbon content is not available.
(d) Facilities, importers and exporters using Calculation Method 2 or 3 shall
estimate the missing GCV values based on a weighted average value for the
previous seven days.
(e) Estimates of missing data shall be documented and records maintained
showing the calculations.
(a) A complete record of all measured parameters used in the reporting of All flow meters and product monitors shall be calibrated prior to the first reporting year,
fuel volumes and the calculations of CO2 mass emissions is required.
using a suitable method published by a consensus standards organization (e.g., ASTM,
(b) For coal‐to‐liquids facilities, the last quality assured reading shall be used. ASME, API, NAESB, or others). Alternatively, calibration procedures specified by the flow
If substantial variation in the flow rate is observed or if a quality assured
meter manufacturer may be used. Fuel flow meters shall be recalibrated either annually
measurement of quantity is unavailable for any other reason, the average of or at the minimum frequency specified by the manufacturer.
the last and the next quality assured reading shall be used to calculate a
Reporters shall take the following steps to ensure the quality and accuracy of the data
substitute measurement of quantity.
reported under these rules:
(c) Calculation of substitute data shall be documented and records
(1) for all volumes of coal‐based liquid fuels, reporters shall maintain meter and such
maintained showing the calculations.
other records as are normally maintained in the course of business to document fuel
flows;
(2) for all estimates of CO2 mass emissions, reporters shall maintain calculations and
worksheets used to calculate the emissions.
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Subpart
Source Category
MM—Suppliers All facilities
of Petroleum
Products
(§98.390)
Procedures for Estimating Missing Data
QA/QC
Whenever a metered or quality‐assured value of the quantity of petroleum All flow meters and tank gauges shall be calibrated prior to use for reporting, using a
products, natural gas liquids, biomass, or feedstocks during any period is
suitable method published by a consensus standards organization (e.g., ASTM, ASME, API,
unavailable, a substitute data value for the missing quantity measurement or NAESB). Alternatively, calibration procedures specified by the flow meter
shall be used in the calculations contained in §98.393.
manufacturer may be used. Product flow meters and tank gauges shall be recalibrated
(a) For marine‐imported and exported refined and semi‐refined products, the either annually or at the minimum frequency specified by the manufacturer, whichever is
reporting party shall attempt to reconcile any differences between ship and more frequent.
shore volume readings. If the reporting party is unable to reconcile the
readings, the higher of the two values shall be used for emission calculation
purposes.
(b) For pipeline imported and exported refined and semi‐refined products,
the last valid volume reading based on the company’s established procedures
for purposes of product tracking and billing shall be used. If the pipeline
experiences substantial variations in flow rate, the average of the last valid
volume reading and the next valid volume reading shall be used for emission
calculation purposes.
(c) For petroleum refineries, the last valid volume reading based on the
facility’s established procedures for purposes of product tracking
and billing shall be used. If substantial variation in the flow rate is
observed, the average of the last and the next valid volume reading
shall be used for emission calculation purposes.
NN—Suppliers All facilities
of Natural Gas
and Natural
Gas Liquids
(§98.400)
(a) A complete record of all measured parameters used in the reporting of All flow meters and product or fuel composition monitors shall be calibrated prior to the
fuel volumes and in the calculations of CO2 mass emissions is required.
first reporting year, using a suitable method published by the American Gas Association
Gas Measurement Committee reports on flow metering and heating value calculations
(b) For NGLs, natural gas processing plants shall substitute meter records
and the Gas Processors Association standards on measurement and heating value.
provided by pipeline(s) for all pipeline receipts of NGLs; by manifests for
deliveries made to trucks or rail cars; or metered quantities accepted by the Alternatively, calibration procedures specified by the flow meter manufacturer may be
entities purchasing the output from the processing plant whether by pipeline used. Fuel flow meters shall be recalibrated either annually or at the minimum frequency
or by truck or rail car. In cases where the metered data from the receiving specified by the manufacturer.
pipeline(s) or purchasing entities are not available, substitute estimates
based on contract quantities required to be delivered under purchase or
delivery contracts with other parties.
(c) Natural gas local distribution companies may substitute the metered
quantities from the delivering pipelines for all deliveries into the distribution
system. In cases where the pipeline metered delivery data are not available,
substitute their pipeline nominations and scheduled quantities for the period
when metered values of actual deliveries are not available.
(d) Estimates of missing data shall be documented and records
maintained showing the calculations of the values used for the
missing data.
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March 2009
Subpart
Source Category
OO—Suppliers All facilities
of Industrial
Greenhouse
Gases
(§98.410)
Procedures for Estimating Missing Data
QA/QC
A complete record of all measured parameters used in the GHG emissions
Facilities that destroy fluorinated GHGs shall account for any temporary reductions in the
calculations is required.
destruction efficiency that result from any startups, shutdowns, or malfunctions of the
(1) For each missing value of the mass produced, fed into the production
destruction device, including departures from the operating conditions defined in state or
process (for used material being reclaimed), fed into transformation
local permitting requirements and/or oxidizer manufacturer specifications. All
processes, fed into destruction devices, sent to another facility for
flowmeters, weigh scales, and combinations of volumetric and density measurements
that are used to measure or calculate quantities that are to be reported under this
transformation, or sent to another facility for destruction, the substitute
subpart shall be calibrated using suitable NIST‐traceable standards and suitable methods
value of that parameter shall be a secondary mass measurement.
published by a consensus standards organization (e.g., ASTM, ASME, ASHRAE, or others).
(2) For each missing value of fluorinated GHG concentration, except the
annual destruction device outlet concentration measurement specified in
Alternatively, calibration procedures specified by the flowmeter, scale, or load cell
§98.414(h), the substitute data value shall be the arithmetic average of the manufacturer may be used. Calibration shall be performed prior to the first reporting
year. After the initial calibration, recalibration shall be performed at least annually or at
quality‐assured values of that parameter immediately preceding and
the minimum frequency specified by the manufacturer, whichever is more frequent. All
immediately following the missing data incident. If, for a particular
parameter, no quality‐assured data are available prior to the missing data
gas chromatographs that are used to measure or calculate quantities that are to be report
incident, the substitute data value shall be the first quality‐assured value
shall be calibrated at least monthly through analysis of certified standards
obtained after the missing data period. There are no missing value
with known concentrations of the same chemical(s) in the same range(s)
allowances for the annual destruction device outlet concentration measureme (fractions by mass) as the process samples. Calibration gases prepared
from a high‐concentration certified standard using a gas dilution system
(3) Notwithstanding paragraphs (1) and (2), if the owner or
that meets the requirements specified in Test Method 205, 40 CFR Part 51,
operator has reason to believe that the methods specified in
paragraphs (1) and (2) are likely to significantly under‐ or
Appendix M may also be used.
overestimate the value of the parameter during the period when
data were missing, the designated representative shall develop his or her best
parameter, documenting the methods used, the rationale behind
them, and the reasons why the methods specified in (1) and (2)
would probably lead to a significant under‐ or overestimate of the
parameter. EPA may reject the alternative estimate and replace
it with an estimate based on the applicable method in paragraph
(1) or (2) if EPA does not agree with the rationale or method for
the alternative estimate.
PP—Suppliers All facilities
of Carbon
Dioxide
(§98.420)
(a) Missing quarterly monitoring data on mass flow of CO2 streams captured, (a) Mass flow meter calibrations must be NIST traceable.
extracted, imported, or exported shall be substituted with the greater of the (b) Methods to measure the composition of the carbon dioxide captured, extracted,
following values:
transferred, imported, or exported must conform to applicable chemical analytical
(1) Quarterly CO2 mass flow of gas transferred off site measured during the standards. Acceptable methods include U.S. Food and Drug Administration food‐grade
specifications for carbon dioxide (see 21 CFR 184.1250) and ASTM standard E‐1745‐95
current reporting year; or
(2) Quarterly or annual average values of the monitored CO2 mass flow from (2005).
the past calendar year.
(b) Missing monitoring data on the mass flow of the CO2 stream transferred
off site shall be substituted with the quarterly or annual average values from
off site transfers from the past calendar year.
(c) Missing data on composition of the CO2 stream captured, extracted,
transferred, imported, or exported may be substituted for with quarterly or
annual average values from the past calendar year.
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| File Type | application/pdf |
| File Modified | 2009-03-13 |
| File Created | 2009-03-13 |