E—Adipic Acid
Production (§98.50)
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All In
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(1) Annual process N2O
emissions from adipic acid production (metric tons).
(2) Annual adipic acid
production (tons).
(3) Annual adipic acid
production during which N2O abatement technology is operating
(tons).
(4) Annual process N2O
emissions from adipic acid production facility that is sold or
transferred off-site (metric tons).
(5) Number of abatement
technologies (if applicable).
(6) Types of abatement
technology or technologies used (if applicable).
(7) Abatement technology
destruction efficiency for each abatement technology (percent
destruction).
(8) Abatement utilization
factor for each abatement technology (fraction of annual
production that abatement technology is operating).
(9) Number of times in the
reporting year that missing data procedures were followed to
measure adipic acid production (months).
If a performance test
and site-specific emissions factors were used:
(1)
Emission factor (lb N2O/ton adipic acid).
(2) Test method used for
performance test.
(3) Production rate per
test run during performance test (tons/hr).
(4) N2O concentration per
test run during performance test (ppm N2O).
(5) Volumetric flow rate
per test run during performance test (dscf/hr).
(6) Number of test runs.
(7) Number of times in the
reporting year that a performance test had to be repeated
(number).
If approval was
requested for an alternative method of calculating N2O
emissions:
(1) Name of alternative
method.
(2) Description of
alternative method.
(3) Request date.
(4)
Approval date.
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H—Cement Production
(§98.80)
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All In
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If a CEMS is used to
measure CO2 emissions:
All relevant information
required under 40 CFR 98.37(e)(2)(vi) for the Tier 4 Calculation
Methodology plus:
(1)
Monthly clinker production from each kiln at the facility.
(2)
Monthly cement production from each kiln at the facility.
(3)
Number of kilns and number of operating kilns.
If a CEMS is not used
to measure CO2 emissions:
(1)
Kiln identification number.
(2)
Monthly clinker production from each kiln.
(3)
Monthly cement production from each kiln.
(4)
Number of kilns and number of operating kilns.
(5)
Quarterly quantity of CKD not recycled to the kiln for each kiln
at the facility.
(6)
Monthly fraction of total CaO, total MgO, non-calcined CaO and
non-calcined MgO in clinker for each kiln (as wt-fractions).
(7)
Method used to determine non-calcined CaO and non-calcined MgO
in clinker.
(8)
Quarterly fraction of total CaO, total MgO, non-calcined CaO and
non-calcined MgO in CKD not recycled to the kiln for each kiln
(as wt-fractions).
(9)
Method used to determine non-calcined CaO and non-calcined MgO
in CKD.
(10)
Monthly kiln-specific clinker CO2 emission factors for each kiln
(metric tons CO2/metric ton clinker produced).
(11)
Quarterly kiln-specific CKD CO2 emission factors for each kiln
(metric tons CO2/metric ton CKD produced).
(12)
Annual organic carbon content of raw kiln feed or annual organic
carbon content of each raw material (wt-fraction, dry basis).
(13)
Annual consumption of raw kiln feed or annual consumption of
each raw material (dry basis).
(14)
Number of times missing data procedures were used to determine:
(i) Clinker production (number of months);
(ii)
Carbonate contents of clinker (number of months); (iii)
Non-calcined content of clinker (number of months); (iv) CKD not
recycled to kiln (number of quarters); (v) Non-calcined content
of CKD (number of quarters); (vi) Organic carbon contents of raw
materials (number of times); and (vii) Raw material consumption
(number of months).
(15)
Method used to determine the monthly clinker production from
each kiln reported under (b)(2) of this section, including
monthly kiln-specific clinker factors, if used.
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K—Ferroalloy
Production (§98.110)
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25,000 metric tons
C02e/year
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All:
(1) Total pounds of
synthetic fertilizer produced through and total nitrogen
contained in that fertilizer.
(2) Annual production for
each ferroalloy product identified in §98.110, from each
EAF (tons).
(3) Total number of EAFs
at facility used for production of ferroalloy products.
If a CEMS is used to
measure CO2 emissions:
All relevant information
required under 40 CFR 98.36 for the Tier 4 Calculation
Methodology plus:
(1)
Annual process CO2 emissions (in metric tons) from each EAF used
for the production of any ferroalloy product identified in
§98.110.
(2)
Annual process CH4 emissions (in metric tons) from each EAF used
for the production of any ferroalloy listed in Table K-1 of
subpart K (metric tons).
(3)
Identification each EAF.
If
a CEMS is not used to measure CO2 process emissions,:
(1)
Annual process CO2 emissions (in metric tons) from each EAF used
for the production of any ferroalloy product identified in
§98.110.
(2)
Annual process CH4 emissions (in metric tons) from each EAF used
for the production of any ferroalloy listed in Table K-1 of this
subpart (metric tons).
(3)
Identification number of each EAF.
(4)
Annual material quantity for each material included for the
calculation of annual process CO2 emissions for each EAF.
(5)
Annual average of the carbon content determinations for each
material included for the calculation of annual process CO2
emissions for each EAF (percent by weight, expressed as a
decimal fraction).
(6)
The method used for the determination of carbon content for each
material reported in paragraph (e)(5) of this section (e.g.,
supplier provided information, analyses of representative
samples you collected).
(7)
For missing data procedures: How monthly mass of
carbon-containing inputs and outputs with missing data was
determined and the number of months the missing data procedures
were used.
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N—Glass Production
(§98.140)
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25,000 metric tons
C02e/year
|
If a CEMS is used to
measure CO2 emissions:
All relevant information
required under 40 CFR 98.36 for the Tier 4 Calculation
Methodology plus:
(1) Annual quantity of
each carbonate-based raw material charged to each continuous
glass melting furnace and for all furnaces combined (tons).
(2) Annual quantity of
glass produced by each glass melting furnace and by all furnaces
combined (tons).
If a CEMS is not used
to determine CO2 emissions from continuous glass melting
furnaces, and process CO2 emissions are calculated according to
the procedures specified in §98.143(b):
(1) Annual process
emissions of CO2 (metric tons) for each continuous glass melting
furnace and for all furnaces combined.
(2) Annual quantity of
each carbonate-based raw material charged (tons) to each
continuous glass melting furnace and for all furnaces combined.
(3) Annual quantity of
glass produced (tons) from each continuous glass melting furnace
and from all furnaces combined.
(4) Carbonate-based
mineral mass fraction (percentage, expressed as a decimal) for
each carbonate-based raw material charged to a continuous glass
melting furnace.
(5) Results of all tests
used to verify the carbonate-based mineral mass fraction for
each carbonate-based raw material charged to a continuous glass
melting furnace, including (i) Date of test; (ii) Test method(s)
and any variations used in the analyses; and (iii) Mass fraction
of each sample analyzed;
(6) The fraction of
calcination achieved (percentage, expressed as a decimal) for
each carbonate-based raw material, if a value other than 1.0 is
used to calculate process mass emissions of CO2.
(7) Method used to
determine fraction of calcination
(8) Total number of
continuous glass melting furnaces.
(9)
The number of times in the reporting year that missing data
procedures were followed to measure monthly quantities of
carbonate-based raw materials or mass fraction of the
carbonate-based minerals for any continuous glass melting
furnace (months).
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O—HCFC-22 Production
and HFC-23 Destruction (§98.150)
|
HCFC-22: All In
HFC-23 destruction
processes that are not collocated with HCFC-22 production and
that destroy more than 2.14 metric tons HFC-23 per year: All In
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Production facilities
At the facility level:
(1) Annual mass of HCFC-22
produced in metric tons.
(2) Annual Loss Factor
used to account for the loss of HCFC– 22 upstream of the
measurement.
(3) Annual mass of
reactants fed into the process in metric tons of reactant.
(4) The mass (in metric
tons) of materials other than HCFC-22 and HFC-23 (i.e.,
unreacted reactants, HCl and other by-products) that occur in
more than trace concentrations and that are permanently removed
from the process.
(5) The method for
tracking startups, shutdowns, and malfunctions and HFC-23
generation/emissions during these events.
(6) The names and
addresses of facilities to which any HFC-23 was sent for
destruction, and the quantities of HFC-23 (metric tons) sent to
each.
(7) Annual mass of the
HFC-23 generated in metric tons.
(8) Annual mass of any
HFC-23 sent off site for sale in metric tons.
(9) Annual mass of any
HFC-23 sent off site for destruction in metric tons.
(10) Annual masses of
HFC-23 in storage at the beginning and end of the year, in
metric tons.
(11) Annual mass of HFC-23
emitted in metric tons.
(12) Annual mass of HFC-23
emitted from equipment leaks in metric tons.
(13) Annual mass of HFC-23
emitted from process vents in metric tons.
HFC-23
destruction facilities
(1)
Annual
mass
of HFC-23 fed into the destruction device.
(2)
Annual
mass
of HFC-23 destroyed.
(3)
Annual
mass
of HFC-23 emitted from the destruction device.
Plus
the concentration (mass fraction) of HFC-23 measured at the
outlet of the destruction device during of the facility’s
annual HFC-23 concentration measurements at the outlet of the
device.
Plus
the following information, if facilities calculate the emission
rate and DE of the destruction device under §98.154(l)(2)
(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.
(4)
Emission rate (in kg/hr) calculated from (d)(2) and (d)(3) of
this section.
(5)
Destruction efficiency (DE) calculated from paragraphs (d)(1)
and (d)(4) of this section.
Plus
a one-time report by March 31, 2011 or within 60 days of
commencing HFC-23 destruction, including the following
information:
(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.
(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.
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P—Hydrogen
Production (§98.160)
|
25,000 metric tons
C02e/year
|
If a CEMS is used to
measure CO2 emissions:
All relevant information
required under 40 CFR 98.36 for the Tier 4 Calculation
Methodology plus:
(1) Unit identification
number and annual CO2 emissions.
(2) Annual quantity of
hydrogen produced (metric tons) for each process unit and for
all units combined.
(3) Annual quantity of
ammonia produced (metric tons), if applicable (metric tons) for
each process unit and for all units combined.
If a CEMS is not used
to measure CO2 emissions:
(1) Unit identification
number and annual CO2 emissions.
(2) Monthly consumption of
each fuel and feedstock used for hydrogen production and its
type (scf of gaseous fuels and feedstocks, gallons of liquid
fuels and feedstocks, kg of solid fuels and feedstocks).
(3) Annual quantity of
hydrogen produced (metric tons).
(4) Annual quantity of
ammonia produced, if applicable (metric tons).
(5) Monthly analyses of
carbon content for each fuel and feedstock used in hydrogen
production (kg carbon /kg of gaseous and solid fuels and
feedstocks, (kg carbon per gallon of liquid fuels and
feedstocks).
(6) Monthly analyses of
the molecular weight of gaseous fuels and feedstocks
(kg/kg-mole) used, if any.
All:
(1) Quantity of CO2
collected and transferred off site in either gas, liquid, or
solid forms, following the requirements of subpart PP of this
part.
(2)
Annual quantity of carbon other than CO2 collected and
transferred off site in either gas, liquid, or solid forms (kg
carbon).
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Q—Iron & Steel
Production (§98.170)
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25,000 metric tons
C02e/year
|
Each coke pushing
operation; taconite indurating furnace; basic oxygen furnace;
non-recovery coke oven battery; sinter process; EAF;
decarburization vessel; direct reduction furnace, and flare
burning coke oven gas or blast furnace gas::
(1)
Unit identification number and annual CO2 emissions (in metric
tons) .
(2) Annual production
quantity (in metric tons) for taconite pellets, coke, sinter,
iron, and raw steel.
(3) The annual amount
of coal charged to the coke ovens (in metric tons).
If a CEMS is used to
measure CO2 emissions: All
relevant information required under 40 CFR 98.36 for the Tier 4
Calculation Methodology
If a CEMS is not used
to measure CO2 emissions:
An indication for each of whether for each process whether the
emissions were determined using the carbon mass balance method
in §98.173(b)(1) or the site-specific emission factor
method in §98.173(b)(2).
If the carbon mass
balance method is used to determine CO2 emissions:
(1) The carbon content of
each process input and output used to determine CO2 emissions.
(2) Whether the carbon
content was determined from information from the supplier or by
laboratory analysis, and if by laboratory analysis, the test
method used.
(3) The annual volume of
each type of gaseous fuel (reported separately for each type in
standard cubic feet), the annual volume of each type of liquid
fuel (reported separately for each type in gallons), and the
annual mass (in metric tons) of each other process inputs and
outputs used to determine CO2 emissions.
(4) The molecular weight
of gaseous fuels.
(5) For the missing data
procedures in §98.175(b): How the monthly mass for each
process input or output with missing data was determined and the
number of months the missing data procedures were used.
If the site-specific
emission factor method is used to determine CO2 emissions:
(1) The measured average
hourly CO2 emission rate during the test(in metric tons per
hour).
(2) The average hourly
feed or production rate (as applicable) during the test (in
metric tons per hour).
(3) The site-specific
emission factor (in metric tons of CO2 per metric ton of feed or
production, as applicable).
(4)
The annual feed or production rate (as applicable) used to
estimate annual CO2 emissions (in metric tons).
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For flares burning coke
oven gas or blast furnace gas: All
relevant information specified in §98.256(e) of subpart Y
(Petroleum Refineries) of this part.
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S—Lime Manufacturing
(§98.190)
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All In
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If a CEMS is used to
measure CO2 emissions:
All relevant information
required under 40 CFR 98.37(e)(2)(vi) for the Tier 4 Calculation
Methodology plus:
(1) Method used to
determine the quantity of lime that is produced and sold.
(2) Method used to
determine the quantity of calcined lime byproduct/waste sold.
(3) Beginning and end of
year inventories for each lime product that is produced, by
type.
(4) Beginning and end of
year inventories for calcined lime byproducts/wastes sold, by
type.
(5) Annual amount of
calcined lime byproduct/waste sold, by type (tons).
(6) Annual amount of lime
product sold, by type (tons).
(7) Annual amount of
calcined lime byproduct/waste that is not sold, by type (tons).
(8) Annual amount of lime
product not sold, by type (tons).
If a CEMS is not used
to measure CO2 emissions:
(1) Annual CO2 process
emissions from all kilns combined (metric tons).
(2) Monthly emission
factors for each lime type produced.
(3) Monthly emission
factors for each calcined byproduct/waste by lime type that is
sold.
(4) Standard method
used (ASTM or NLA testing method) to determine chemical
compositions of each lime type produced and each calcined lime
byproduct/waste type.
(5) Monthly results of
chemical composition analysis of each type of lime product
produced and calcined byproduct/waste sold.
(6) Annual results of
chemical composition analysis of each type of lime
byproduct/waste that is not sold.
(7) Method used to
determine the quantity of lime produced and/or lime sold.
(8) Monthly amount of
lime product sold, by type (tons).
(9) Method used to
determine the quantity of calcined lime byproduct/waste sold.
(10) Monthly amount of
calcined lime byproduct/waste sold, by type (tons).
(11) Annual amount of
calcined lime byproduct/waste that is not sold, by type (tons).
(12)
Monthly weight or mass of each lime type produced (tons).
(13) Beginning and end of
year inventories for each lime product that is produced.
(14) Beginning and end of
year inventories for calcined lime byproducts/wastes sold.
(15)
Annual lime production capacity (tons) per facility.
(16)
Number of times in the reporting year that missing data
procedures were followed to measure lime production (months) or
the chemical composition of lime products sold
(months).
(17)
Indicate whether CO2 was used on-site (i.e. for use in a
purification process). If CO2 was used on-site, provide: (i) The
annual amount of CO2 captured for use in the on-site process;
and (ii) The method used to determine the amount of CO2
captured.
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V—Nitric Acid
Production (§98.220)
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All In
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All
(1) Train
identification number.
(2) Annual process N2O
emissions from each nitric acid train (metric tons).
(3) Annual nitric acid
production from each nitric acid train (tons, 100 percent acid
basis).
(4) Annual nitric acid
production from each nitric acid train during which N2O
abatement technology is operating (ton acid produced, 100
percent acid basis)
(5) Annual nitric acid
production from the nitric acid facility (tons, 100 percent acid
basis).
(6) Number of nitric acid
trains.
(7) Number of different
N2O
abatement technologies per nitric acid train “t”.
(8) Abatement technologies
used (if applicable).
(9) Abatement technology
destruction efficiency for each abatement technology (percent
destruction).
(10) Abatement utilization
factor for each abatement technology (fraction of annual
production that abatement technology is operating).
(11) Type of nitric acid
process used for each nitric acid train (single pressure or dual
pressure).
(12) Number of times in
the reporting year that missing data procedures were followed to
measure nitric acid production (months).
(13) If a performance test
was conducted and site-specific emissions factor was calculated
according to §98.223(a)(1): (i) Emission factor calculated
for each nitric acid train (lb N2O/ ton nitric acid, 100 percent
acid basis); (ii) Test method used for performance test; (iii)
Production rate per test run during performance test (tons
nitric acid produced/hr, 100 percent acid basis); (iv) N2O
concentration per test run during performance test (ppm N2O);
(v) Volumetric flow rate per test run during performance test
(dscf/hr); (vi) Number of test runs during performance test;
(vii) Number of times in the reporting year that a performance
test had to be repeated (number).
(14) If approval was
requested for an alternative method of determining N2O emissions
under §98.223(a)(2),: (i) Name of alternative method; (ii)
Description of alternative method; (iii) Request date; and (iv)
Approval date.
(15)
Total pounds of synthetic fertilizer produced through and total
nitrogen contained in that fertilizer.
|
Z—Phosphoric Acid
Production (§98.260)
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All In
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All:
(1) Annual phosphoric acid
production by origin (as listed in Table Z-1 to subpart Z) of
the phosphate rock (tons).
(2) Annual phosphoric acid
permitted production capacity (tons).
(3) Annual arithmetic
average percent inorganic carbon in phosphate rock from monthly
records (percent by weight, expressed as a decimal fraction).
(4) Annual phosphate rock
consumption from monthly measurement records by origin (as
listed in Table Z-1 to subpart Z) from monthly measurement
records (tons).
If a CEMS is used to
measure CO2 emissions:
All relevant information
required under 40 CFR 98.37(e)(2)(vi) for the Tier 4 Calculation
Methodology plus:
(1) The identification
number of each wet-process phosphoric acid process line.
(2) The annual CO2
emissions from each wet-process phosphoric acid process line
(metric tons) and the relevant information required under 40 CFR
98.36 (e)(2)(vi) for the Tier 4 Calculation Methodology.
If a CEMS is not used
to measure CO2 emissions:
(1) Identification number
of each wet-process phosphoric acid process line.
(2) Annual CO2 emissions
from each wet-process phosphoric acid process line (metric tons)
as calculated by Eq. Z-1 of subpart Z.
(3) Annual phosphoric acid
permitted production capacity for each wet-process phosphoric
acid process line (metric tons).
(4) Method used to
estimate any missing values of inorganic carbon content of
phosphate rock for each wet-process phosphoric acid process
line.
(5) Monthly inorganic
carbon content of phosphate rock for each wet-process phosphoric
acid process line (percent by weight, expressed as a decimal
fraction).
(6) Monthly mass of
phosphate rock consumed by origin, (as listed in Table Z-1 to
subpart Z) in production for each wet-process phosphoric acid
process line (tons).
(7) Number of wet-process
phosphoric acid process lines.
(8) Number of times
missing data procedures were used to estimate phosphate rock
consumption (months) and inorganic carbon contents of the
phosphate rock (months).
(9)
Annual process CO2
emissions from phosphoric acid production facility (metric
tons).
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CC—Soda Ash
Manufacturing (§98.290)
|
All in
|
If a CEMS is used to
measure CO2 emissions:
All relevant information
required under 40 CFR 98.37(e)(2)(vi) for the Tier 4 Calculation
Methodology plus:
(1) Annual consumption of
trona or liquid alkaline feedstock for each manufacturing line
(tons).
(2) Annual production of
soda ash for each manufacturing line (tons).
(3) Annual production
capacity of soda ash for each manufacturing line (tons).
(4) Identification number
of each manufacturing line.
If a CEMS is not used
to measure CO2 emissions:
(1) Annual process CO2
emissions from each soda ash manufacturing line (metric tons).
(2) Annual process CO2
emissions from each soda ash manufacturing line (metric tons).
(3) Annual production of
soda ash for
each manufacturing line (tons).
(4) Annual production
capacity of soda ash for each manufacturing line (tons).
(5) Monthly consumption of
trona or liquid alkaline feedstock for each manufacturing line
(tons).
(6) Monthly production of
soda ash (tons).
(7) Inorganic carbon
content factor of trona or soda ash (depending on use of Eq.
CC-1 or CC-2) as measured by the applicable method in 98.294(b)
or (c) for each month (percent by weight expressed as a decimal
fraction).
(8) Whether CO2 emissions
for each manufacturing line were calculated using a trona input
method as described in Equation CC-1, a soda ash output method
as described in Equation CC-2, or a site-specific emission
factor method as described in Equations CC-3 through CC-5.
(9) Number of
manufacturing lines located used to produce soda ash.
(10) For soda ash produced
using the liquid alkaline feedstock process, if the
site-specific emission factor method is used to estimate
emissions, report the following information for each
manufacturing line or stack: (i) Stack gas volumetric flow rate
during performance test (dscfm); (ii) Hourly CO2 concentration
during performance test (percent CO2); (iii) CO2 emission factor
(metric tons CO2/metric tons of process vent flow from mine
water stripper/evaporator); (iv) CO2 mass emission rate during
performance test (metric tons/hour); (v) Average process vent
flow from mine water stripper/evaporater during performance test
(pounds/hour); (vi) Annual process vent flow rate from mine
stripper/evaporator (thousand pounds/hour); and (vii) Annual
operating hours for each manufacturing line used to produce soda
ash using liquid alkaline feedstock (hours).
(11)
Number of times missing data procedures were used and for which
of the following parameters: (i) Trona or soda ash (number of
months); (ii) Inorganic carbon contents of trona or soda ash
(weeks); and (iii) Process vent flow rate from mine water
stripper/evaporator (number of months)
|
EE—Titanium Dioxide
Production (§98.310)
|
All In
|
If a CEMS is used to
measure CO2 emissions:
All relevant information
required under 40 CFR 98.37(e)(2)(vi) for the Tier 4 Calculation
Methodology plus:
(1) Identification number
of each process line.
(2) Annual consumption of
calcined petroleum coke (tons).
(3) Annual production of
titanium dioxide (tons).
(4) Annual production
capacity of titanium dioxide (tones).
(5) Annual production of
carbon-containing waste (tons), if applicable.
If a CEMS is not used
to measure CO2 emissions:
(1) Identification number
of each process line.
(2) Annual CO2 emissions
from each chloride process line (metric tons/year).
(3) Annual consumption of
calcined petroleum coke for each process line (tons).
(4) Annual production of
titanium dioxide for each process line (tons).
(5) Annual production
capacity of titanium dioxide for each process line (tons).
(6) Calcined petroleum
coke consumption for each process line for each month (tons).
(7) Annual production of
carbon-containing waste for each process line (tons), if
applicable.
(8) Monthly production of
titanium dioxide for each process line (tons).
(9) Monthly carbon content
factor of petroleum coke (percent by weight expressed as a
decimal fraction).
(10) Whether monthly
carbon content of the petroleum coke is based on reports from
the supplier or through self measurement using applicable ASTM
Standard Test Methods.
(11) Carbon content for
carbon-containing waste for each process line (percent by weight
expressed as a decimal fraction).
(12) If carbon content of
petroleum coke is based on self measurement, the ASTM Standard
Test Methods used.
(13) Sampling analysis
results of carbon content of petroleum coke as determined for
QA/QC of supplier data under 98.314(d) (percent by weight
expressed as a decimal fraction).
(14) Number of separate
chloride process lines located at the facility.
(15)
The number of times in the reporting year that missing data
procedures were followed to measure the carbon contents of
petroleum coke (number of months); petroleum coke consumption
(number of months); carbon-containing waste generated (number of
months); and carbon contents of the carbon-containing waste
(number of times during year).
|
GG—Zinc Production
(§98.330)
|
25,000 metric tons
C02e/year
|
If a CEMS is used to
measure CO2 emissions:
All relevant information
required under 40 CFR 98.36 for the Tier 4 Calculation
Methodology plus:
(1) Annual zinc product
production capacity (tons).
(2) Annual production
quantity for each zinc product (tons).
(3) Annual facility
production quantity for each zinc product (tons).
(4) Number of Waelz kilns
at each facility used for zinc production.
(5) Number of
electrothermic furnaces at each facility used for zinc
production.
If a CEMS is not used
to measure CO2 emissions:
(1) Identification number
and annual process CO2 emissions from each individual Waelz kiln
or electrothermic furnace (metric tons).
(2) Annual zinc product
production capacity (tons).
(3) Annual production
quantity for each zinc product (tons).
(4) Number of Waelz kilns
at each facility used for zinc production.
(5) Number of
electrothermic furnaces at each facility used for zinc
production.
(6) Annual mass of each
carbon-containing input material charged to each kiln or furnace
(including zinc bearing material, flux materials (e.g.,
limestone, dolomite), carbon electrode, and other carbonaceous
materials (e.g., coal, coke) (tons).
(7) Carbon content of each
carbon-containing input material charged to each kiln or furnace
(including zinc bearing material, flux materials, and other
carbonaceous materials) from the annual carbon analysis or from
information provided by the material supplier for each kiln or
furnace (percent by weight, expressed as a decimal fraction).
(8) Whether carbon content
of each carbon-containing input material charged to each kiln or
furnace is based on reports from the supplier or through self
measurement using applicable ASTM Standard Test Method.
(9) If carbon content of
each carbon-containing input material charged to each kiln or
furnace is based on self measurement, the ASTM Standard Test
Method used.
(10) Carbon content of the
carbon electrode used in each furnace from the annual carbon
analysis or
from information provided by the material supplier (percent by
weight, expressed as a decimal fraction).
(11) Whether carbon
content of the carbon electrode used in each furnace is based on
reports from the supplier or through self measurement using
applicable ASTM Standard Test Method.
(12) If carbon content of
carbon electrode used in each furnace is based on self
measurement, the ASTM Standard Test Method used.
(13)
For the missing data procedures in §98.335(b): How the
monthly mass of carbon-containing materials with missing data
was determined and the number of months the missing data
procedures were used.
|
HH—Landfills
(§98.340)
|
25,000 metric tons
C02e/year
|
(1) A classification of
the landfill as “open” (actively received waste in
the reporting year) or “closed” (no longer receiving
waste), the year in which the landfill first started accepting
waste for disposal, the last year the landfill accepted waste
(for open landfills, enter the estimated year of landfill
closure), the capacity (in metric tons) of the landfill, an
indication of whether leachate recirculation is used during the
reporting year and its typical frequency of use over the past 10
years (e.g., used several times a year for the past 10 years,
used at least once a year for the past 10 years, used
occasionally but not every year over the past 10 years, not
used), an indication as to whether scales are present at the
landfill, and the waste disposal quantity for each year of
landfilling required to be included when using Equation HH-1 of
this subpart (in metric tons, wet weight).
(2)
Method for estimating reporting year and historical waste
disposal quantities, reason for its selection, and the range of
years it is applied. For years when waste quantity data are
determined using the methods in §98.343(a)(3), report
separately the quantity of waste determined using the methods in
§98.343(a)(3)(i) and the quantity of waste determined using
the methods in §98.343(a)(3)(ii). For historical waste
disposal quantities that were not determined using the methods
in §98.343(a)(3), provide the population served by the
landfill for each year the Equation HH-2 of this subpart is
applied, if applicable, or, for open landfills using Equation
HH-3 of this subpart, provide the value of landfill capacity
(LFC) used in the calculation.
(3)
Waste composition for each year of landfilling, if available, in
percentage categorized as (a) Municipal.
(b)
Biosolids or biological sludges; (c) Other, or more refined
categories, such as those for which k rates are available in
Table HH-1 of this subpart, and the method or basis for
estimating waste composition.
(4)
For each waste type used to calculate CH4 generation using
Equation HH-1 of subpart H: (i) Degradable organic carbon (DOC),
methane correction
factor (MCF), and fraction of DOC dissimilated (DOCF)
values used and (ii) Decay rate (k) value used.
(5)
Fraction of CH4 in landfill gas (F) and an indication of whether
the fraction of CH4 was determined based on measured values or
the default value.
(6)
The surface area of the landfill containing waste (in square
meters), identification of the type of cover material used (as
either organic cover, clay cover, sand cover, or other soil
mixtures). If multiple cover types are used, the surface area
associated with each cover type.
(7)
The modeled annual methane generation rate for the reporting
year (metric tons CH4) calculated using Equation HH-1 of subpart
HH.
(8) For landfills without
gas collection systems, the annual methane emissions (i.e., the
methane generation, adjusted for oxidation, calculated using
Equation HH-5 of subpart HH), reported in metric tons CH4 and an
indication of whether passive vents and/or passive flares (vents
or flares that are not considered part of the gas collection
system as defined in §98.6) are present at this landfill.
For
landfills with gas collection systems:
(1)
Total volumetric flow of landfill gas collected for destruction
for the reporting year (cubic feet at 520°R or 60°F and
1 atm).
(2)
Annual average CH4 concentration of landfill gas collected for
destruction (percent by volume).
(3)
Monthly average temperature
and pressure for
each month at which flow is measured for landfill gas collected
for destruction, or statement that temperature and/or pressure
is incorporated into internal calculations run by the monitoring
equipment.
(4)
An indication as to whether flow was measured on a wet or dry
basis, an indication as to whether CH4
concntration was measured on a wet or dry basis, and if required
for Equation HH-4, monthly average moisture content for each
month at which flow is measured for landfill gas collected for
destruction .
(5)
An indication of whether destruction occurs at the landfill
facility or off-site. If destruction occurs at the landfill
facility: An indication of whether a back-up destruction device
is present at the landfill, the annual operating hours for the
primary destruction device, the annual operating hours for the
back-up destruction device (if present), and the destruction
efficiency used (percent).
(6)
Annual quantity of recovered CH4 (metric tons CH4) calculated
using Equation HH-4 of subpart HH.
(7)
A description of the gas collection system (manufacture,
capacity, number of number of wells, etc.), the surface area
(square meters) and estimated waste depth (meters) for each area
specified in Table HH-3 of subpart HH, the estimated gas
collection system efficiency for landfills with this gas
collection system, and the annual operating hours of the gas
collection system, and an indication of whether passive vents
and/or passive flares (vents or flares that are not considered
part of the gas collection system as defined in §98.6) are
present at the landfill..
(8)
Methane generation corrected for oxidation calculated using
Equation HH-5 of subpart HH, reported in metric tons CH4;
(9)
Methane generation (GCH4) value used as an input to HH-6.
Specify whether the value is modeled (GCH4 from HH-1) or
measured (R from Eq. HH-4)
(10)
Methane generation corrected for oxidation calculated using
Equation HH-7 of subpart HH, reported in metric tons CH4.
(11)
Methane emissions calculated using Equation HH-6 of subpart HH,
reported in metric tons CH4; and
(12)
Methane emissions calculated using Equation HH-8 of subpart HH,
reported in metric tons CH4.
|
LL—Suppliers of
Coal-based Liquid Fuels (§98.380)
|
Producers of
coal-to-liquid products: All in
Importers & Exporters:
25,000 metric tons C02e/year
|
Producers (for each
coal-to-liquid facility):
(1) For each product
listed in table MM-1 that enters the coal-to-liquid facility to
be further processed or otherwise used on site: The annual
quantity in metric tons or barrels by each quantity measurement
standard method or other industry standard practice used. For
natural gas liquids, quantity must reflect the individual
components of the product.
(2) For each product
listed in table MM-1 that enters the coal-to-liquid facility to
be further processed or otherwise used on site: The annual
quantity in metric tons or barrels. For natural gas liquids,
quantity must reflect the individual components of the product.
(3) For each feedstock
reported in (2) that was produced by blending a fossil
fuel-based product with a biomass-based product: The percent of
the volume reported in (2) that is fossil fuel-based.
(4) Each standard method
or other industry standard practice used to measure each
quantity reported in (1).
(5) For each product
(leaving the coal-to-liquid facility) listed in table MM-1: The
annual quantity in metric tons or barrels by each quantity
measurement standard method or other industry standard practice
used. For natural gas liquids, quantity must reflect the
individual components of the product. Those products that enter
the facility, but are not reported in (1), shall not be reported
under this paragraph.
(6) For each product
(leaving the coal-to-liquid facility) listed in table MM-1: The
annual quantity in metric tons or barrels. For natural gas
liquids, quantity must reflect the individual components of the
product. Those products that enter the facility, but are not
reported in (2), shall not be reported under this paragraph.
(7) For each product
reported in (6) that was produced by blending a fossil
fuel-based product with a biomass-based product: The percent of
the volume reported in (6) that is fossil fuel-based.
(8) Each standard method
or other industry standard practice used to measure each
quantity reported in (5).
(9) For every feedstock
reported in (2) for which Calculation Method 2 was used to
determine an emissions factor:
(i) The number of samples
collected according to §98.394(c); (ii) The sampling
standard method used; (iii) The carbon share test results in
percent mass; (iv) The standard method used to test carbon
share; and (v) The calculated CO2 emissions factor in metric
tons.
(10) For every non-solid
feedstock reported in (2) for which Calculation Method 2 was
used to determine an emissions factor: (i) The density test
results in metric tons per barrel and (ii) The standard method
used to test density.
(11) For every product
reported in (6) for which Calculation Method 2 was used to
determine an emissions factor: (i) The number of samples
collected according to §98.394(c); (ii) The sampling
standard method used; (iii) The carbon share test results in
percent mass; (iv) The standard method used to test carbon
share; and (v) The calculated CO2 emissions factor in metric
tons.
(12) For every non-solid
product reported in (6) for which Calculation Method 2 was used
to determine an emissions factor: (i) The density test results
in metric tons per barrel and (ii) The standard method used to
test density;
(13) For each specific
type of biomass that enters the coal-to-liquid facility to be
co-processed with fossil fuel-based feedstock to produce a
product reported in (6): The annual quantity in metric tons or
barrels by each quantity measurement standard method or other
industry standard practice used.
(14) For each specific
type of biomass that enters the coal-to-liquid facility to be
co-processed with fossil fuel-based feedstock to produce a
product reported in (6): The annual quantity in metric tons or
barrels.
(15) Each standard method
or other industry standard practice used to measure each
quantity reported in (12).
(16) The CO2 emissions in
metric tons that would result from the complete combustion or
oxidation of each feedstock reported in (2), calculated
according to §98.393(b) or (h).
(17) The CO2 emissions in
metric tons that would result from the complete combustion or
oxidation of each product (leaving the coal-to-liquid facility)
reported in (6), calculated according to §98.393(a) or (h).
(18) The CO2 emissions in
metric tons that would result from the complete combustion or
oxidation of each type of biomass feedstock co-processed with
fossil fuel-based feedstocks reported in (12), calculated
according to §98.393(c).
(19) The total sum of CO2
emissions that would result from the complete combustion or
oxidation of all products, calculated according to §98.393(d).
(20)
The total quantity of bulk NGLs in metric tons or barrels
received for processing during the reporting year.
|
Importers:
(1) For each product
listed in table MM-1 of subpart M: The annual quantity in metric
tons or barrels by each quantity measurement standard method or
other industry standard practice used. For natural gas liquids,
quantity must reflect the individual components of the product.
(2) For each product
listed in table MM-1 of subpart M: The annual quantity in metric
tons or barrels. For natural gas liquids, quantity must reflect
the individual components of the product as listed in table
MM-1.
(3) For each product
reported in (2) that was produced by blending a fossil
fuel-based product with a biomass-based product: The percent of
the volume reported in (2) that is fossil fuel-based.
(4) Each standard method
or other industry standard practice used to measure each
quantity reported in (1).
(5) For each product
reported in (2) for which Calculation Method 2 used was used to
determine an emissions factor:
(i) The number of samples
collected according to §98.394(c); (ii) The sampling
standard method used; (iii) The carbon share test results in
percent mass; (iv) The standard method used to test carbon
share; and (v) The calculated CO2 emissions factor in metric
tons.
(6) For each non-solid
product reported in (2) for which Calculation Method 2 was used
to determine an emissions factor: (i) The density test results
in metric tons per barrel and (ii) The standard method used to
test density.
(7) The CO2 emissions in
metric tons that would result from the complete combustion or
oxidation of each imported product reported in (2), calculated
according to §98.393(a).
(8)
The total sum of CO2 emissions that would result from the
complete combustion or oxidation of all imported products.
|
LL—Suppliers of
Coal-based Liquid Fuels (§98.380)
(continued)
|
Producers of
coal-to-liquid products: All in
Importers & Exporters:
25,000 metric tons C02e/year
|
Exporters:
(1) For each product
listed in table MM-1: The annual quantity in metric tons or
barrels by each quantity measurement standard method or other
industry standard practice used. For natural gas liquids,
quantity must reflect the individual components of the product.
(2) For each product
listed in table MM-1: The annual quantity in metric tons or
barrels. For natural gas liquids, quantity must reflect the
individual components of the product.
(3) For each product
reported in (2) that was produced by blending a fossil
fuel-based product with a biomass-based product: The percent of
the volume reported in (2) that is fossil fuel-based.
(4) Each standard method
or other industry standard practice used to measure each
quantity reported in (1).
(5) For each product
reported in (2) for which Calculation Method 2 was used to
determine an emissions factor: (i) The number of samples
collected according to §98.394(c); (ii) The sampling
standard method used; (iii) The carbon share test results in
percent mass; (iv) The standard method used to test carbon
share; and (v) The calculated CO2 emissions factor in metric
tons.
(6) For each non-solid
product reported in (2) for which Calculation Method 2 used was
used to determine an emissions factor: (i) The density test
results in metric tons per barrel and (ii) The standard method
used to test density;
(7) The CO2 emissions in
metric tons that would result from the complete combustion or
oxidation of each exported product reported in (2), calculated
according to §98.393(a).
(8)
Total sum of CO2 emissions that would result from the complete
combustion or oxidation of all exported products, calculated
according to §98.393(e).
|
MM—Suppliers of
Petroleum Products (§98.390)
|
Refiners: All in
Importers & Exporters:
25,000 metric tons
C02e/year
|
Refiners:
(1) For each petroleum
product or natural gas liquid listed in table MM-1 that enters
the refinery as a feedstock to be further refined or otherwise
used on site: The annual quantity in metric tons or barrels by
each quantity measurement standard method or other industry
standard practice used. For natural gas liquids, quantity must
reflect the individual components of the product.
(2) For each petroleum
product or natural gas liquid listed in table MM-1 that enters
the refinery to be further refined or otherwise used on site:
The annual quantity in metric tons or barrels. For natural gas
liquids, quantity must reflect the individual components of the
product.
(3) For each feedstock
reported in (2) that was produced by blending a petroleum-based
product with a biomass-based product: The percent of the volume
reported in (2) that is petroleum-based (excluding any
denaturant that may be present in any ethanol product).
(4) Each standard method
or other industry standard practice used to measure each
quantity reported in (1).
(5) For each petroleum
product and natural gas liquid (ex refinery gate) listed in
table MM-1: The annual quantity in metric tons or barrels by
each quantity measurement standard method or other industry
standard practice used. For natural gas liquids, quantity must
reflect the individual components of the product. Petroleum
products and natural gas liquids that enter the refinery, but
are not reported in (1), shall not be reported under this
paragraph.
(6) For each petroleum
product and natural gas liquid (ex refinery gate) listed in
table MM-1 of subpart MM: The annual quantity in metric tons or
barrels. For natural gas liquids, quantity must reflect the
individual components of the product. Petroleum products and
natural gas liquids that enter the refinery, but are not
reported in (2), shall not be reported under this paragraph.
(7) For each product
reported in (6) that was produced by blending a petroleum-based
product with a biomass-based product: The percent of the volume
reported in (6) that is petroleum-based (excluding any
denaturant that may be present in any ethanol product).
(8) Each standard method
or other industry standard practice used to measure each
quantity reported in (5).
(9) For every feedstock
reported in (2) for which Calculation Method 2 was used to
determine an emissions factor: (i) The number of samples
collected; (ii) The sampling standard method used; (iii) The
carbon share test results in percent mass; (iv) The standard
method used to test carbon share; and (v) The calculated CO2
emissions factor in metric tons.
(10) For every non-solid
feedstock reported in (2) for which Calculation Method 2 was
used to determine an emissions factor: (i) The carbon share test
results in percent mass and (ii) The standard method used to
test density/
(11) For every petroleum
product and natural gas liquid reported in (6) for which
Calculation Method 2 was used to determine an emissions factor:
(i) The number of samples collected; (ii) The sampling standard
method used;
(iii) The density test
results in metric tons per barrel; (iv) The standard method used
to test carbon share; and (v) The calculated CO2 emissions
factor in metric tons CO2 per barrel or per metric ton of
product.
(12) For every non-solid
petroleum product and natural gas liquid reported in paragraph
(a)(6) for which Calculation Method 2 was used to determine an
emissions factor: (i) The density test results in metric tons
per barrel and (ii) The standard method used to test density.
(13) For each specific
type of biomass that enters the refinery to be co-processed with
petroleum feedstocks to produce a petroleum product reported in
(6): The annual quantity in metric tons or barrels by each
quantity measurement standard method or other industry standard
practice used.
(14) For each specific
type of biomass that enters the refinery to be co-processed with
petroleum feedstocks to produce a petroleum product reported in
(6): The annual quantity in metric tons or barrels.
(15) Each standard method
or other industry standard practice used to measure each
quantity reported (13).
(16) The CO2 emissions in
metric tons that would result from the complete combustion or
oxidation of each petroleum product and natural gas liquid (ex
refinery gate) reported in (6).
(17) The CO2 emissions in
metric tons that would result from the complete combustion or
oxidation of each feedstock reported in (2).
(18) The CO2 emissions in
metric tons that would result from the complete combustion or
oxidation of each type of biomass feedstock co-processed with
petroleum feedstocks reported in (12).
(19) The sum of CO2
emissions that would result from the complete combustion or
oxidation of all products.
(20) All of the following
information for all crude oil feedstocks used at the refinery:
(i) Batch volume in barrels; (ii) Weighted average API gravity
of the batch at the point of entry at the refinery; (iii)
Weighted average sulfur content of the batch at the point of
entry at the refinery; and (iv) Country of origin of the batch,
if known.
(21)
The quantity of bulk NGLs in metric tons or barrels received for
processing during the reporting year.
|
MM—Suppliers of
Petroleum Products (§98.390)
(continued)
|
25,000 metric tons
C02e/year
|
Importers:
(1) For each petroleum
product and natural gas liquid listed in table MM-1: The annual
quantity in metric tons or barrels by each quantity measurement
standard method or other industry standard practice used. For
natural gas liquids, quantity must reflect the individual
components of the product.
(2) For each petroleum
product and natural gas liquid listed in table MM-1: The annual
quantity in metric tons or barrels. For natural gas liquids,
quantity must reflect the individual components of the product
as listed in table MM-1 of subpart MM.
(3) For each product
reported in (2) that was produced by blending a petroleum-based
product with a biomass-based product: The percent of the volume
reported in (2) that is petroleum-based (excluding any
denaturant that may be present in any ethanol product).
(4) Each standard method
or other industry standard practice used to measure each
quantity reported in (1).
(5) For each product
reported in (2) for which Calculation Method 2 used was used to
determine an emissions factor::
(i) The number of samples
collected according to §98.394(c); (ii) The sampling
standard method used; (iii) The carbon share test results in
percent mass; (iv) The standard method used to test carbon
share; and (v) The calculated CO2 emissions factor in metric
tons CO2 per barrel or per metric ton of product.
(6) For each non-solid
product reported in (2) for which Calculation Method 2 was used
to determine an emissions factor:
(i) The density test
results in metric tons per barrel and (ii) The standard method
used to test density.
(7) The CO2 emissions in
metric tons that would result from the complete combustion or
oxidation of each imported petroleum product and natural gas
liquid reported in (2), calculated according to §98.393(a).
(8)
The sum of CO2 emissions that would result from the complete
combustion or oxidation of all imported products, calculated
according to §98.393(e).
|
Exporters:
(1) For each petroleum
product and natural gas liquid listed in table MM-1 of subpart
MM: The annual quantity in metric tons or barrels by quantity
measurement standard method or other industry standard practice
used. For natural gas liquids, quantity must reflect the
individual components of the product.
(2) For each petroleum
product and natural gas liquid listed in table MM-1 of subpart
MM: The annual quantity in metric tons or barrels. For natural
gas liquids, quantity must reflect the individual components of
the product.
(3) For each product
reported in (2) that was produced by blending a petroleum-based
product with a biomass-based product: The percent of the volume
reported in (2) that is petroleum based (excluding any
denaturant that may be present in any ethanol product).
(4) Each standard method
or other industry standard practice used to measure each
quantity reported in (1).
(5) For each product
reported in (2) for which Calculation Method 2 was used to
determine an emissions factor: (i) The number of samples
collected according to §98.394(c); (ii) The sampling
standard method used; (iii) The carbon share test results in
percentmass; (iv) The standard method used to test carbon share;
and (v) The calculated CO2 emissions factor in metric tons CO2
per barrel or per metric ton of product.
(6) For each non-solid
product reported in (2) for which Calculation Method 2 used was
used to determine an emissions factor: (i) The density test
results in metric tons per barrel and (ii) The standard method
used to test density.
(7) The CO2 emissions in
metric tons that would result from the complete combustion or
oxidation of each exported petroleum product and natural gas
liquid reported in (2), calculated according to §98.393(a).
(8)
The sum of CO2 emissions that would result from the complete
combustion or oxidation of all exported products, calculated
according to §98.393(e).
|
Report the following
information for each blended product and non-crude feedstock, if
emissions are calculated according to §98.393(i):
(1) Volume or mass of
each blending component.
(2) The CO2
emissions in metric tons that would result from the complete
combustion or oxidation of each blended non-crude feedstock or
product, using Equation MM-12 or Equation MM-13 of this section.
(3) For a product that
enters the refinery to be further refined or otherwise used on
site that is a blended non-crude feedstock, refiners must meet
the reporting requirements of paragraphs (1) and (2) for
Importers by reflecting the individual components of the blended
non-crude feedstock.
(3)
For a product that is produced, imported, or exported that is a
blended product, refiners, importers, and exporters must meet
the reporting requirements of paragraphs (5) and (6) for
Importers and (1) and (2) for Exporters , (1), and (2) of this
section, as applicable, by reflecting the individual components
of the blended product.
|
NN—Suppliers of
Natural Gas and Natural Gas Liquids (§98.400)
|
All In
|
NGL fractionator:
(1) Annual quantity (in
barrels) of each NGL product supplied to downstream facilities
in the following categories: ethane, propane, normal butane,
isobutane, and pentanes plus.
(2) Annual quantity (in
barrels) of each NGL product received from other NGL
fractionators in the following categories: ethane, propane,
normal butane, isobutane, and pentanes plus.
(3) Annual volumes in Mscf
of natural gas received for processing.
(4) Annual quantity (in
barrels) of y-grade, bulk NGLs received from others for
fractionation.
(5) Annual quantity (in
barrels) of propane that the NGL fractionator odorizes at the
facility and delivers to others.
(6) Annual CO2 emissions
(in metric tons) that would result from the complete combustion
or oxidation of the volumes in (1) and (2).
(7) Annual CO2 mass
emissions (metric tons) that would result from the combustion or
oxidation of fractionated NGLs supplied less the quantity
received by other fractionators, calculated in accordance with
§98.403(c)(2).
(8) The specific industry
standard used to measure the quantities reported in (1).
(9)
If the NGL fractionator developed reporter-specific EFs or HHVs,
report the following for each product type: (i) The specific
industry standard(s) used to develop reporter-specific higher
heating value(s) and/or emission factor(s), pursuant to §98.404
(b)(2) and (c)(3); (ii) The developed HHV(s); and (iii) The
developed EF(s).
|
Local distribution
companies:
(1) Annual volume in Mscf
of natural gas received by the LDC at its city gate stations for
redelivery on the LDC’s distribution system, including for
use by the LDC.
(2) Annual volume in Mscf
of natural gas placed into storage.
(3) Annual volume in Mscf
of vaporized liquefied natural gas (LNG) produced at on-system
vaporization facilities for delivery on the distribution system
that is not accounted for in (1).
(4) Annual volume in Mscf
of natural gas withdrawn from on-system storage (that is not
delivered to the city gate) for delivery to on the distribution
system.
(5) Annual volume in Mscf
of natural gas delivered directly to LDC systems from producers
or natural gas processing plants from local production.
(6) Annual volume in Mscf
of natural gas delivered to downstream gas transmission
pipelines and other local distribution companies.
(7) Annual volume in Mscf
of natural gas delivered by LDC to each meter registering supply
equal to or greater than 460,000 Mcsf during the calendar year.
(8) Annual CO2 mass
emissions (metric tons) associated with the volumes in (1) - (7)
and calculated in accordance with §98.403.
(9) Annual CO2 emissions
(metric tons) that would result from the complete combustion or
oxidation of the annual supply of natural gas to end-users
registering less than 460,000 Mcsf, calculated in accordance
with §98.403(b)(4).
(10) The specific industry
standard used to develop the volume reported in (1).
(11) If the LDC developed
reporter-specific EFs or HHVs: (i) The specific industry
standard(s) used to develop reporter-specific higher heating
value(s) and/or emission factor(s), pursuant to §98.404
(b)(2) and (c)(3); (ii) The developed HHV(s); and (iii) The
developed EF(s).
(12) The customer name,
address, and meter number of each meter reading used to report
in (7). If known, the EIA identification number of each LDC
customer.
(13)
The annual volume in Mscf of natural gas delivered by the local
distribution company to each of the following end-use
categories: (i) Residential consumers; (ii) Commercial
consumers; (iii) Industrial consumers; and (iv) Electricity
generating facilities.
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All: Each
reporter must report the number of days in the reporting year
that substitute data procedures were used for the following
purpose: (i) To measure quantity; (ii) To develop HHV(s); and
(iii) To develop EF(s).
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