In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraphs (a)
or (b) of this section, as applicable.
    (a) If a CEMS is used to measure CO2 emissions according
to the requirements in Sec.  98.183(a) or (b)(1), then you must report
under this subpart the relevant information required by Sec.  98.36 and
the information specified in paragraphs (a)(1) through (a)(4) of this
section.
    (1) Identification number of each smelting furnace.
    (2) Annual lead product production capacity (tons).
    (3) Annual production for each lead product (tons).
    (4) Total number of smelting furnaces at facility used for lead
production.
    (b) If a CEMS is not used to measure CO2 emissions, and
you measure CO2 emissions according to the requirements in
Sec.  98.183(b)(2)(i) and (b)(2)(ii), then you must report the
information specified in paragraphs (b)(1) through (b)(9) of this
section.
    (1) Identification number of each smelting furnace. (2) Annual
process CO2 emissions (in metric tons) from each smelting
furnace as determined by Equation R-1 of this subpart.
    (3) Annual lead product production capacity for the facility and
each smelting furnace(tons).
    (4) Annual production for each lead product (tons).
    (5) Total number of smelting furnaces at facility used for
production of lead products reported in paragraph (b)(4) of this
section.
    (6) Annual material quantity for each material used for the
calculation of annual process CO2 emissions using Equation
R-1 of this subpart for each smelting furnace (tons).
    (7) Annual average of the carbon content determinations for each
material used for the calculation of annual process CO2
emissions using Equation R-1 of this subpart for each smelting furnace.
    (8) List the method used for the determination of carbon content
for each material reported in paragraph (b)(7) of this section (e.g.,
supplier provided information, analyses of representative samples you
collected).
    (9) If you use the missing data procedures in Sec.  98.185(b), you
must report how the monthly mass of carbon-containing materials with
missing data was determined and the number of months the missing data
procedures were used.

Sec.  98.187  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), each annual
report must contain the information specified in paragraphs (a) through
(c) of this section, as applicable to the smelting furnaces at your
facility.
    (a) If a CEMS is used to measure combined process and combustion
CO2 emissions according to the requirements in Sec.
98.183(a) or (b)(1), then you must retain the records required for the
Tier 4 Calculation Methodology in Sec.  98.37 and the information
specified in paragraphs (a)(1) through (a)(3) of this section.
    (1) Monthly smelting furnace production quantity for each lead
product (tons).
    (2) Number of smelting furnace operating hours each month.
    (3) Number of smelting furnace operating hours in calendar year.
    (b) If the carbon mass balance procedure is used to determine
process CO2 emissions according to the requirements in Sec.
98.183(b)(2)(i) and (b)(2)(ii), then you must retain under this subpart
the records specified in paragraphs (b)(1) through (b)(5) of this
section.
    (1) Monthly smelting furnace production quantity for each lead
product (tons).
    (2) Number of smelting furnace operating hours each month.
    (3) Number of smelting furnace operating hours in calendar year.
    (4) Monthly material quantity consumed, used, or produced for each
material included for the calculations of annual process CO2
emissions using Equation R-1 of this subpart (tons).
    (5) Average carbon content determined and records of the supplier
provided information or analyses used for the determination for each
material included for the calculations of annual process CO2
emissions using Equation R-1 of this subpart.
    (c) 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, including documentation of any
materials excluded from Equation R-1 of this subpart that contribute
less than 1 percent of the total carbon into or out of the process. You
also must document the procedures used to ensure the accuracy of the
measurements of materials fed, charged, or placed in an smelting
furnace 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.

Sec.  98.188  Definitions.

    All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.

Subpart S--Lime Manufacturing

Sec.  98.190  Definition of the source category.

    (a) Lime manufacturing plants (LMPs) engage in the manufacture of a
lime product (e.g., calcium oxide, high-calcium quicklime, calcium
hydroxide, hydrated lime, dolomitic quicklime, dolomitic hydrate, or
other products) by calcination of limestone, dolomite, shells or other
cacareous substances as defined in 40 CFR 63.7081(a)(1).
    (b) This source category includes all LMPs unless the LMP is
located at a kraft pulp mill, soda pulp mill, sulfite pulp mill, or
only processes sludge containing calcium carbonate from water softening
processes. The lime manufacturing source category consists of marketed
and non-marketed lime manufacturing facilities.
    (c) Lime kilns at pulp and paper manufacturing facilities must
report emissions under subpart AA of this part (Pulp and Paper
Manufacturing).

Sec.  98.191  Reporting threshold.

    You must report GHG emissions under this subpart if your facility
is a lime manufacturing plant as defined in Sec.  98.190 and the
facility meets the requirements of either Sec.  98.2(a)(1) or (a)(2).

Sec.  98.192  GHGs to report.

    You must report:
    (a) CO2 process emissions from lime kilns.
    (b) CO2 emissions from fuel combustion at lime kilns.
    (c) N2O and CH4 emissions from fuel
combustion at each lime kiln. You must report these emissions under 40
CFR part 98, subpart C (General Stationary Fuel Combustion Sources).
    (d) CO2, N2O, and CH4 emissions
from each stationary fuel combustion unit other than lime kilns. You
must report these emissions under 40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).
    (e) CO2 collected and transferred off site under 40 CFR
part 98, following the requirements of subpart PP of this part
(Suppliers of Carbon Dioxide (CO2)).

Sec.  98.193  Calculating GHG emissions.

    You must calculate and report the annual process CO2
emissions from all lime kilns combined using the procedure in
paragraphs (a) and (b) of this section.
    (a) If all lime kilns meet the conditions specified in Sec.
98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under
this subpart the combined process and combustion CO2
emissions by operating and maintaining a CEMS to measure CO2
emissions according to the Tier 4 Calculation Methodology specified in
Sec.  98.33(a)(4) and all associated requirements for Tier 4 in subpart
C of this part (General Stationary Fuel Combustion Sources).
    (b) If CEMS are not required to be used to determine CO2
emissions from all lime kilns under paragraph (a) of this section, then
you must calculate and report the process and combustion CO2
emissions from the lime kilns by using the procedures in either
paragraph (b)(1) or (b)(2) of this section.
    (1) Calculate and report under this subpart the combined process
and combustion CO2 emissions by operating and maintaining a
CEMS to measure CO2 emissions from all lime kilns according
to the Tier 4 Calculation Methodology specified in Sec.  98.33(a)(4)
and all associated requirements for Tier 4 in subpart C of this part
(General Stationary Fuel Combustion Sources).
    (2) Calculate and report process and combustion CO2
emissions separately using the procedures specified in paragraphs
(b)(2)(i) through (b)(2)(v) of this section.
    (i) You must calculate a monthly emission factor for each type of
lime produced using Equation S-1 of this section. Calcium oxide and
magnesium oxide content must be analyzed monthly for each lime type:
[GRAPHIC] [TIFF OMITTED] TR30OC09.073

Where:

EFLIME,i,n = Emission factor for lime type i, for month n
(metric tons CO2/ton lime).
SRCaO = Stoichiometric ratio of CO2 and CaO
for calcium carbonate [see Table S-1 of this subpart] (metric tons
CO2/metric tons CaO).
SRMgO = Stoichiometric ratio of CO2 and MgO
for magnesium carbonate (See Table S-1 of this subpart) (metric tons
CO2/metric tons MgO).
CaOi,n = Calcium oxide content for lime type i, for month
n, determined according to Sec.  98.194(c) (metric tons CaO/metric
ton lime).
MgOi,n = Magnesium oxide content for lime type i, for
month n, determined according to Sec.  98.194(c) (metric tons MgO/
metric ton lime).
2000/2205 = Conversion factor for metric tons to tons.

(ii) You must calculate a monthly emission factor for each type of
byproduct/waste sold (including lime kiln dust) using Equation S-2 of
this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.074

Where:

EFLKD,i,n = Emission factor for sold lime byproduct/waste
type i, for month n (metric tons CO2/ton lime byproduct).
SRCaO = Stoichiometric ratio of CO2 and CaO
for calcium carbonate (see Table S-1 of this subpart((metric tons
CO2/metric tons CaO).
SRMgO = Stoichiometric ratio of CO2 and MgO
for magnesium carbonate (See Table S-1 of this subpart) (metric tons
CO2/metric tons MgO).
CaOLKD,i,n = Calcium oxide content for sold lime
byproduct/waste type i, for month n (metric tons CaO/metric ton
lime).
MgOLKD,i,n = Magnesium oxide content for sold lime
byproduct/waste type i, for month n (metric tons MgO/metric ton
lime).
2000/2205 = Conversion factor for metric tons to tons.

    (iii) You must calculate the annual CO2 emissions from
each type of byproduct/waste that is not sold (including lime kiln dust
and scrubber sludge) using Equation S-3 of this section:

[GRAPHIC] [TIFF OMITTED] TR30OC09.075

Where:

Ewaste,i = Annual CO2 emissions for unsold
lime byproduct/waste type i (metric tons CO2).
SRCaO = Stoichiometric ratio of CO2 and CaO
for calcium carbonate (see Table S-1 of this subpart) (metric tons
CO2/metric tons CaO).
SRMgO = Stoichiometric ratio of CO2 and MgO
for magnesium carbonate (See Table S-1 of this subpart) (metric tons
CO2/metric tons MgO).
CaOwaste,i = Calcium oxide content for unsold lime
byproduct/waste type i (metric tons CaO/metric ton lime).
MgOwaste,i = Magnesium oxide content for unsold lime
byproduct/waste type i (metric tons MgO/metric ton lime).
Mwaste,i = Annual weight or mass of unsold byproducts/
wastes for lime type i (tons).
2000/2205 = Conversion factor for metric tons to tons.

    (iv) You must calculate annual CO2 process emissions for
all kilns using Equation S-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.076

Where:

ECO2 = Annual CO2 process emissions from lime
production from all kilns (metric tons/year).
EFLIME,i,n = Emission factor for lime type i, in calendar
month n (metric tons CO2/ton lime) from Equation S-1 of
this section.
MLIME,i,n = Weight or mass of lime type i in calendar
month n (tons).
EFLKD,i,n = Emission factor of byproducts/wastes sold for
lime type i in calendar month n, (metric tons CO2/ton
byproduct/waste) from Equation S-2 of this section.
MLKD,i,n = Monthly weight or mass of byproducts/waste
sold (such as lime kiln dust, LKD) for lime type i in calendar month
n (tons).
Ewaste,i = Annual CO2 emissions for unsold
lime byproduct/waste type i (metric tons CO2) from
Equation S-3 of this section.
t = Number of lime types
b = Number of byproducts/wastes sold
z = Number of byproducts/wastes not sold

    (v) Calculate and report under subpart C of this part (General
Stationary Fuel Combustion Sources) the combustion CO2
emissions from each lime kiln according to the applicable requirements
in subpart C.

Sec.  98.194  Monitoring and QA/QC requirements.

    (a) You must determine the total quantity of each product type of
lime and each calcined byproduct/waste (such as lime kiln dust) that is
sold. The quantities of each should be directly measured monthly with
the same plant instruments used for accounting purposes, including but
not limited to, calibrated weigh feeders, rail or truck scales, and
barge measurements. The direct measurements of each lime product shall
be reconciled annually with the difference in the beginning of and end
of year inventories for these products, when measurements represent
lime sold.
    (b) You must determine the annual quantity of each calcined
byproduct/waste generated that is not sold by either direct measurement
using the same instruments identified in paragraph (a) of this section
or by using a calcined byproduct/waste generation rate.
    (c) You must determine the chemical composition (percent total CaO
and percent total MgO) of each type of lime and each type of calcined
byproduct/waste sold according to paragraph (c)(1) or (c)(2) of this
section. You must determine the chemical composition of each type of
lime on a monthly basis. You must determine the chemical composition
for each type of calcined byproduct/waste that is not sold on an annual
basis.
    (1) ASTM C25-06 Standard Test Methods for Chemical Analysis of
Limestone, Quicklime, and Hydrated Lime (incorporated by reference--see
Sec.  98.7).
    (2) The National Lime Association's CO2 Emissions
Calculation Protocol for the Lime Industry English Units Version,
February 5, 2008 Revision-National Lime Association (incorporated by
reference--see Sec.  98.7).
    (d) You must use the analysis of calcium oxide and magnesium oxide
content of each lime product collected during the same month as the
production data in monthly calculations.
    (e) You must follow the quality assurance/quality control
procedures (including documentation) in National Lime Association's
CO2 Emissions Calculation Protocol for the Lime Industry
English Units Version, February 5, 2008 Revision--National Lime
Association (incorporated by reference--see Sec.  98.7).

Sec.  98.195  Procedures for estimating missing data.

    For the procedure in Sec.  98.193(b)(2), a complete record of all
measured parameters used in the GHG emissions calculations is required
(e.g., oxide content, quantity of lime products, etc.). Therefore,
whenever a quality-assured value of a required parameter is
unavailable, a substitute data value for the missing parameter shall be
used in the calculations as specified in paragraphs (a) or (b) of this
section. You must document and keep records of the procedures used for
all such estimates.
    (a) For each missing value of the quantity of lime produced (by
lime type), and quantity of byproduct/waste produced and sold, the
substitute data value shall be the best available estimate based on all
available process data or data used for accounting purposes.
    (b) For missing values related to the CaO and MgO content, you must
conduct a new composition test according to the standard methods in
Sec.  98.194 (c)(1) or (c)(2).

Sec.  98.196  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraphs (a)
or (b) of this section, as applicable.
    (a) If a CEMS is used to measure CO2 emissions, then you
must report under this subpart the relevant information required by
Sec.  98.36 and the information listed in paragraphs (a)(1) through
(a)(8) of this section.
    (1) Method used to determine the quantity of lime sold.
    (2) Method used to determine the quantity of lime byproduct/waste
sold.
    (3) Beginning and end of year inventories for each lime product.
    (4) Beginning and end of year inventories for lime byproducts/
wastes.

    (5) Annual amount of lime byproduct/waste sold, by type (tons).
    (6) Annual amount of lime product sold, by type (tons).
    (7) Annual amount of lime byproduct/waste not sold, by type (tons).
    (8) Annual amount of lime product not sold, by type (tons).
    (b) If a CEMS is not used to measure CO2 emissions, then
you must report the information listed in paragraphs (b)(1) through
(b)(17) of this section.
    (1) Annual CO2 process emissions from all kilns combined
(metric tons).
    (2) Monthly emission factors for each lime type.
    (3) Monthly emission factors for each sold byproduct/waste by lime
type.
    (4) Standard method used (ASTM or NLA testing method) to determine
chemical compositions of each lime type and lime byproduct/waste type.
    (5) Monthly results of chemical composition analysis of each lime
product and byproduct/waste sold.
    (6) Annual results of chemical composition analysis of each type of
lime byproduct/waste not sold.
    (7) Method used to determine the quantity of lime sold.
    (8) Monthly amount of lime product sold, by type (tons).
    (9) Method used to determine the quantity of lime byproduct/waste
sold.
    (10) Monthly amount of lime byproduct/waste sold, by type (tons).
    (11) Annual amount of lime byproduct/waste not sold (tons).
    (12) Monthly mass of each lime type produced (tons).
    (13) Beginning and end of year inventories for each lime product.
    (14) Beginning and end of year inventories for lime byproducts/
wastes.
    (15) Annual lime production capacity (tons) per facility.
    (16) Number of times in the reporting year that missing data
procedures were followed to measure lime production (months) or the
chemical composition of lime products sold (months).
    (17) Indicate whether CO2 was used on-site (i.e. for use
in a purification process). If CO2 was used on-site, provide
the information in paragraphs (b)(17)(i) and (b)(17)(ii) of this
section.
    (i) The annual amount of CO2 captured for use in the on-
site process.
    (ii) The method used to determine the amount of CO2
captured.

Sec.  98.197  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must
retain the records specified in paragraphs (a) and (b) of this section.
    (a) Annual operating hours in calendar year.
    (b) Records of all analyses (e.g. chemical composition of lime
products, by type) and calculations conducted.

Sec.  98.198  Definitions.

    All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.

 Table S-1 to Subpart S of Part 98--Basic Parameters for the Calculation
                 of Emission Factors for Lime Production
------------------------------------------------------------------------
                                                         Stoichiometric
                       Variable                              ratio
------------------------------------------------------------------------
SRCaO................................................             0.7848
SRMgO................................................             1.0918
------------------------------------------------------------------------

Subpart T--[Reserved]

Subpart U--Miscellaneous Uses of Carbonate

Sec.  98.210  Definition of the source category.

    (a) This source category includes any equipment that uses
carbonates listed in Table U-1 in manufacturing processes that emit
carbon dioxide. Table U-1 includes the following carbonates: limestone,
dolomite, ankerite, magnesite, siderite, rhodochrosite, or sodium
carbonate. Facilities are considered to emit CO2 if they
consume at least 2,000 tons per year of carbonates heated to a
temperature sufficient to allow the calcination reaction to occur.
    (b) This source category does not include equipment that uses
carbonates or carbonate containing minerals that are consumed in the
production of cement, glass, ferroalloys, iron and steel, lead, lime,
phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium
hydroxide, or zinc.
    (c) This source category does not include carbonates used in
sorbent technology used to control emissions from stationary fuel
combustion equipment. Emissions from carbonates used in sorbent
technology are reported under 40 CFR 98, subpart C (Stationary Fuel
Combustion Sources).

Sec.  98.211  Reporting threshold.

    You must report GHG emissions from miscellaneous uses of carbonate
if your facility uses carbonates as defined in Sec.  98.210 of this
subpart and the facility meets the requirements of either Sec.
98.2(a)(1) or (a)(2).

Sec.  98.212  GHGs to report.

    You must report CO2 process emissions from all
miscellaneous carbonate use at your facility as specified in this
subpart.

Sec.  98.213  Calculating GHG emissions.

    You must determine CO2 process emissions from carbonate
use in accordance with the procedures specified in either paragraphs
(a) or (b) of this section.
    (a) Calculate the process emissions of CO2 using
calcination fractions with Equation U-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.077

Where:

ECO2 = Annual CO2 mass emissions from
consumption of carbonates (metric tons).
Mi = Annual mass of carbonate type i consumed (tons).
EFi = Emission factor for the carbonate type i, as
specified in Table U-1 to this subpart, metric tons CO2/
metric ton carbonate consumed.
Fi = Fraction calcination achieved for each particular
carbonate type i (decimal fraction). As an alternative to measuring
the calcination fraction, a value of 1.0 can be used.
n = Number of carbonate types.
2000/2205 = Conversion factor to convert tons to metric tons.

(b) Calculate the process emissions of CO2 using actual mass
of output carbonates with Equation U-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.078

Where:

ECO2 = Annual CO2 mass emissions from
consumption of carbonates (metric tons).
Mk = Annual mass of input carbonate type k (tons).
EFk = Emission factor for the carbonate type k, as
specified in Table U-1 of this subpart (metric tons CO2/
metric ton carbonate input).
Mj = Annual mass of output carbonate type j (tons).
EFj = Emission factor for the output carbonate type j, as
specified in Table U-1 of this subpart (metric tons CO2/
metric ton carbonate input).
m = Number of input carbonate types.
n = Number of output carbonate types.

Sec.  98.214  Monitoring and QA/QC requirements.

    (a) The annual mass of carbonate consumed (for Equation U-1 of this
subpart) or carbonate inputs (for Equation U-2 of this subpart) must be
determined annually from monthly measurements using the same plant
instruments used for accounting purposes including purchase records or
direct measurement, such as weigh hoppers or weigh belt feeders.
    (b) The annual mass of carbonate outputs (for Equation U-2 of this
subpart) must be determined annually from monthly measurements using
the same plant instruments used for accounting purposes including
purchase records or direct measurement, such as weigh hoppers or belt
weigh feeders.
    (c) If you follow the procedures of Sec.  98.213(a), as an
alternative to assuming a calcination fraction of 1.0, you can
determine on an annual basis the calcination fraction for each
carbonate consumed based on sampling and chemical analysis using a
suitable method such as using an x-ray fluorescence standard method or
other enhanced industry consensus standard method published by an
industry consensus standard organization (e.g., ASTM, ASME, etc.).

Sec.  98.215  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data
value for the missing parameter shall be used in the calculations as
specified in paragraph (b) of this section. You must document and keep
records of the procedures used for all such estimates.
    (b) For each missing value of monthly carbonate consumed, monthly
carbonate output, or monthly carbonate input, the substitute data value
must be the best available estimate based on the all available process
data or data used for accounting purposes.

Sec.  98.216  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (g) of this section at the facility level, as applicable.
    (a) Annual CO2 emissions from miscellaneous carbonate
use (metric tons).
    (b) Annual mass of each carbonate type consumed (tons).
    (c) Measurement method used to determine the mass of carbonate.
    (d) Method used to calculate emissions.
    (e) If you followed the calculation method of Sec.
98.213(b)(1)(i), you must report the information in paragraphs (e)(1)
through (e)(3) of this section.
    (1) Annual carbonate consumption by carbonate type (tons).
    (2) Annual calcination fractions used in calculations.
    (3) If you determined the calcination fraction, indicate which
standard method was used.
    (f) If you followed the calculation method of Sec.
98.213(b)(1)(ii), you must report the information in paragraphs (f)(1)
and (f)(2) of this section.
    (1) Annual carbonate input by carbonate type (tons).
    (2) Annual carbonate output by carbonate type (tons).
    (g) Number of times in the reporting year that missing data
procedures were followed to measure carbonate consumption, carbonate
input or carbonate output (months).

Sec.  98.217  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must
retain the records specified in paragraphs (a) through (d) of this
section:
    (a) Monthly carbonate consumption (by carbonate type in tons).
    (b) You must document the procedures used to ensure the accuracy of
the monthly measurements of carbonate consumption, carbonate input or
carbonate output including, but not limited to, calibration of weighing
equipment and other measurement devices.
    (c) Records of all analyses conducted to meet the requirements of
this rule.
    (d) Records of all calculations conducted.

Sec.  98.218  Definitions.

    All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.

   Table U-1 to Subpart U of Part 98--CO2 Emission Factors for Common
                               Carbonates
------------------------------------------------------------------------
                                                                 CO2
                                                               emission
                                                                factor
                  Mineral name--carbonate                     (tons CO2/
                                                                 ton
                                                              carbonate)
------------------------------------------------------------------------
Limestone--CaCO3...........................................      0.43971
Magnesite--MgCO3...........................................      0.52197
Dolomite--CaMg(CO3)2.......................................      0.47732
Siderite--FeCO3............................................      0.37987
Ankerite--Ca(Fe, Mg, Mn)(CO3)2.............................      0.47572
Rhodochrosite--MnCO3.......................................      0.38286
Sodium Carbonate/Soda Ash--Na2CO3..........................      0.41492
------------------------------------------------------------------------

Subpart V--Nitric Acid Production

Sec.  98.220  Definition of source category.

    A nitric acid production facility uses one or more trains to
produce weak nitric acid (30 to 70 percent in strength). A nitric acid
train produces weak nitric acid through the catalytic oxidation of
ammonia.

Sec.  98.221  Reporting threshold.

    You must report GHG emissions under this subpart if your facility
contains a nitric acid train and the facility meets the requirements of
either Sec.  98.2(a)(1) or (a)(2).

Sec.  98.222  GHGs to report.

    (a) You must report N2O process emissions from each
nitric acid production train as required by this subpart.
    (b) You must report under subpart C of this part (General
Stationary Fuel Combustion Sources) the emissions of CO2,
CH4, and N2O from each stationary combustion unit
by following the requirements of subpart C.

Sec.  98.223  Calculating GHG emissions.

    (a) You must determine annual N2O process emissions from
each nitric acid train according to paragraphs (a)(1) or (a)(2) of this
section.
    (1) Use a site-specific emission factor and production data
according to paragraphs (b) through (h) of this section.
    (2) Request Administrator approval for an alternative method of
determining N2O emissions according to paragraphs (a)(2)(i)
and (a)(2)(ii) of this section.
    (i) You must submit the request within 45 days following
promulgation of this subpart or within the first 30 days of each
subsequent reporting year.
    (ii) If the Administrator does not approve your requested
alternative method within 150 days of the end of the reporting year,
you must determine the N2O emissions factor for the current

reporting period using the procedures specified in paragraph (a)(1) of
this section.
    (b) You must conduct an annual performance test according to
paragraphs (b)(1) through (b)(3) of this section.
    (1) You must measure N2O emissions from the absorber
tail gas vent for each nitric acid train using the methods specified in
Sec.  98.224(b) through (d).
    (2) You must conduct the performance test under normal process
operating conditions and without using N2O abatement
technology (if applicable).
    (3) You must measure the production rate during the performance
test and calculate the production rate for the test period in metric
tons (100 percent acid basis) per hour.
    (c) You must determine an N2O emissions factor to use in
Equation V-3 of this section according to paragraphs (c)(1) or (c)(2)
of this section.
    (1) You may request Administrator approval for an alternative
method of determining N2O concentration according to the
procedures in paragraphs (a)(2)(i) and (a)(2)(ii) of this section.
Alternative methods include the use of N2O CEMs.
    (2) Using the results of the performance test in paragraph (b) of
this section, you must calculate an average site-specific emission
factor for each nitric acid train ``t'' according to Equation V-1 of
this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.079

Where:

EFN2Ot = Average site-specific N2O emissions
factor for nitric acid train ``t'' (lb N2O generated/ton
nitric acid produced, 100 percent acid basis).
CN2O = N2O concentration for each test run
during the performance test (ppm N2O).
1.14 x 10-7 = Conversion factor (lb/dscf-ppm
N2O).
Q = Volumetric flow rate of effluent gas for each test run during
the performance test (dscf/hr).
P = Production rate for each test run during the performance test
(tons nitric acid produced per hour, 100 percent acid basis).
n = Number of test runs.

    (d) If applicable, you must determine the destruction efficiency
for each N2O abatement technology according to paragraphs
(d)(1), (d)(2), or (d)(3) of this section.
    (1) Use the manufacturer's specified destruction efficiency.
    (2) Estimate the destruction efficiency through process knowledge.
Examples of information that could constitute process knowledge include
calculations based on material balances, process stoichiometry, or
previous test results provided the results are still relevant to the
current vent stream conditions. You must document how process knowledge
(if applicable) was used to determine the destruction efficiency.
    (3) Calculate the destruction efficiency by conducting an
additional performance test on the emissions stream following the
N2O abatement technology.
    (e) If applicable, you must determine the abatement factor for each
N2O abatement technology. The abatement factor is calculated
for each nitric acid train according to Equation V-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.080

Where:

AFN t = Abatement factor of N2O abatement
technology at nitric acid train ``t'' (fraction of annual production
that abatement technology is operating).
Pa t = Total annual nitric acid production from nitric
acid train ``t'' (ton acid produced, 100 percent acid basis).
Pa t Abate = Annual nitric acid production from nitric
acid train ``t'' during which N2O abatement was used (ton
acid produced, 100 percent acid basis).

    (f) You must determine the annual amount of nitric acid produced
and the annual amount of nitric acid produced while each N2O
abatement technology is operating from each nitric acid train (100
percent basis).
    (g) You must calculate N2O emissions for each nitric
acid train by multiplying the emissions factor (determined in Equation
V-1 of this section) by the annual nitric acid production and
accounting for N2O abatement, according to Equation V-3 of
this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.081

Where:

EN2Ot = N2O mass emissions per year for nitric
acid train ``t'' (metric tons).
EFN2Ot = Average site-specific N2O emissions
factor for nitric acid train ``t'' (lb N2O generated/ton
acid produced, 100 percent acid basis).
Pa t = Annual nitric acid production from the train ``t''
(ton acid produced, 100 percent acid basis).
DFN t = Destruction efficiency of N2O
abatement technology N that is used on nitric acid train ``t''
(percent of N2O removed from air stream).
AFN t = Abatement factor of N2O abatement
technology for nitric acid train ``t'' (fraction of annual
production that abatement technology is operating).
2204.63 = Conversion factor (lb/metric ton).
z = Number of different N2O abatement technologies.

    (h) You must determine the annual nitric acid production emissions
combined from all nitric acid trains at your facility using Equation V-
4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.082

Where:

N2O = Annual process N2O emissions from nitric
acid production facility (metric tons).
EN2Ot = N2O mass emissions per year for nitric
acid train ``t'' (metric tons).
m = Number of nitric acid trains.

Sec.  98.224  Monitoring and QA/QC requirements.

    (a) You must conduct a new performance test and calculate a new
site-specific emissions factor according to a test plan as specified in
paragraphs (a)(1) through (a)(3) of this section.
    (1) Conduct the performance test annually.
    (2) Conduct the performance test when your nitric acid production
process is changed, specifically when abatement equipment is installed.
    (3) If you requested Administrator approval for an alternative
method of determining N2O concentration under Sec.
98.223(a)(2), you must conduct the performance test if your request has
not been approved by the Administrator within 150 days of the end of
the reporting year in which it was submitted.
    (b) You must measure the N2O concentration during the
performance test using one of the methods in paragraphs (b)(1) through
(b)(3) of this section.
    (1) EPA Method 320 at 40 CFR part 63, appendix A, Measurement of
Vapor Phase Organic and Inorganic Emissions by Extractive Fourier
Transform Infrared (FTIR) Spectroscopy.
    (2) ASTM D6348-03 Standard Test Method for Determination of Gaseous
Compounds by Extractive Direct Interface Fourier Transform Infrared
(FTIR) Spectroscopy (incorporated by reference in Sec.  98.7).
    (3) An equivalent method, with Administrator approval.
    (c) You must determine the production rate(s) (100 percent basis)
from each nitric acid train during the performance test according to
paragraphs (c)(1) or (c)(2) of this section.
    (1) Direct measurement of production and concentration (such as
using flow meters, weigh scales, for production and concentration
measurements).
    (2) Existing plant procedures used for accounting purposes (i.e.
dedicated tank-level and acid concentration measurements).
    (d) You must conduct all performance tests in conjunction with the
applicable EPA methods in 40 CFR part 60, appendices A-1 through A-4.
Conduct three emissions test runs of 1 hour each. All QA/QC procedures
specified in the reference test methods and any associated performance
specifications apply. For each test, the facility must prepare an
emission factor determination report that must include the items in
paragraphs (d)(1) through (d)(3) of this section.
    (1) Analysis of samples, determination of emissions, and raw data.
    (2) All information and data used to derive the emissions
factor(s).
    (3) The production rate during each test and how it was determined.
    (e) You must determine the monthly nitric acid production and the
monthly nitric acid production during which N2O abatement
technology is operating from each nitric acid train according to the
methods in paragraphs (c)(1) or (c)(2) of this section.
    (f) You must determine the annual nitric acid production and the
annual nitric acid production during which N2O abatement
technology is operating for each train by summing the respective
monthly nitric acid production quantities.

Sec.  98.225  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data
value for the missing parameter shall be used in the calculations as
specified in paragraphs (a) and (b) of this section.
    (a) For each missing value of nitric acid production, the
substitute data shall be the best available estimate based on all
available process data or data used for accounting purposes (such as
sales records).
    (b) For missing values related to the performance test, including
emission factors, production rate, and N2O concentration,
you must conduct a new performance test according to the procedures in
Sec.  98.224 (a) through (d).

Sec.  98.226  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (o) of this section for each nitric acid production train.
    (a) Train identification number.
    (b) Annual process N2O emissions from each nitric acid
train (metric tons).
    (c) Annual nitric acid production from each nitric acid train
(tons, 100 percent acid basis).
    (d) Annual nitric acid production from each nitric acid train
during which N2O abatement technology is operating (ton acid
produced, 100 percent acid basis).
    (e) Annual nitric acid production from the nitric acid facility
(tons, 100 percent acid basis).
    (f) Number of nitric acid trains.
    (g) Number of abatement technologies (if applicable).
    (h) Abatement technologies used (if applicable).
    (i) Abatement technology destruction efficiency for each abatement
technology (percent destruction).
    (j) Abatement utilization factor for each abatement technology
(fraction of annual production that abatement technology is operating).
    (k) Type of nitric acid process used for each nitric acid train
(low, medium, high, or dual pressure).
    (l) Number of times in the reporting year that missing data
procedures were followed to measure nitric acid production (months).
    (m) If you conducted a performance test and calculated a site-
specific emissions factor according to Sec.  98.223(a)(1), each annual
report must also contain the information specified in paragraphs (m)(1)
through (m)(7) of this section for each nitric acid production
facility.
    (1) Emission factor calculated for each nitric acid train (lb
N2O/ton nitric acid, 100 percent acid basis).
    (2) Test method used for performance test.
    (3) Production rate per test run during performance test (tons
nitric acid produced/hr, 100 percent acid basis).
    (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 during performance test.
    (7) Number of times in the reporting year that a performance test
had to be repeated (number).
    (n) If you requested Administrator approval for an alternative
method of determining N2O concentration under Sec.
98.223(a)(2), each annual report must also contain the information
specified in paragraphs (n)(1) through (n)(4) of this section for each
nitric acid production facility.
    (1) Name of alternative method.
    (2) Description of alternative method.
    (3) Request date.
    (4) Approval date.
    (o) Total pounds of synthetic fertilizer produced through and total
nitrogen contained in that fertilizer.

Sec.  98.227  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must
retain the records specified in paragraphs (a) through (g) of this
section for each nitric acid production facility:

    (a) Records of significant changes to process.
    (b) Documentation of how process knowledge was used to estimate
abatement technology destruction efficiency (if applicable).
    (c) Performance test reports.
    (d) Number of operating hours in the calendar year for each nitric
acid train (hours).
    (e) Annual nitric acid permitted production capacity (tons).
    (f) Measurements, records, and calculations used to determine
reported parameters.
    (g) Documentation of the procedures used to ensure the accuracy of
the measurements of all reported parameters, including but not limited
to, calibration of weighing equipment, flow meters, 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.

Sec.  98.228  Definitions.

    All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.

Subpart W--[Reserved]

Subpart X--Petrochemical Production

Sec.  98.240  Definition of the source category.

    (a) The petrochemical production source category consists of all
processes that produce acrylonitrile, carbon black, ethylene, ethylene
dichloride, ethylene oxide, or methanol, except as specified in
paragraphs (b) through (f) of this section. The source category
includes processes that produce the petrochemical as an intermediate in
the onsite production of other chemicals as well as processes that
produce the petrochemical as an end product for sale or shipment
offsite.
    (b) A process that produces a petrochemical as a byproduct is not
part of the petrochemical production source category.
    (c) A facility that makes methanol, hydrogen, and/or ammonia from
synthesis gas is part of the petrochemical source category if the
annual mass of methanol produced exceeds the individual annual mass
production levels of both hydrogen recovered as product and ammonia.
The facility is part of subpart P of this part (Hydrogen Production) if
the annual mass of hydrogen recovered as product exceeds the individual
annual mass production levels of both methanol and ammonia. The
facility is part of subpart G of this part (Ammonia Manufacturing) if
the annual mass of ammonia produced exceeds the individual annual mass
production levels of both hydrogen recovered as product and methanol.
    (d) A direct chlorination process that is operated independently of
an oxychlorination process to produce ethylene dichloride is not part
of the petrochemical production source category.
    (e) A process that produces bone black is not part of the
petrochemical source category.
    (f) A process that produces a petrochemical from bio-based
feedstock is not part of the petrochemical production source category.

Sec.  98.241  Reporting threshold.

    You must report GHG emissions under this subpart if your facility
contains a petrochemical process as specified in Sec.  98.240, and the
facility meets the requirements of either Sec.  98.2(a)(1) or (2).

Sec.  98.242  GHGs to report.

    You must report the information in paragraphs (a) through (c) of
this section:
    (a) CO2 CH4, and N2O process
emissions from each petrochemical process unit. Process emissions
include CO2 generated by reaction in the process and by
combustion of process off-gas in stationary combustion units and
flares.
    (1) If you comply with Sec.  98.243(b) or (d), report under this
subpart the calculated CO2, CH4, and
N2O emissions for each stationary combustion source and
flare that burns any amount of petrochemical process off-gas.
    (2) If you comply with Sec.  98.243(c), report under this subpart
the calculated CO2 emissions for each petrochemical process
unit.
    (b) CO2, CH4, and N2O combustion
emissions from stationary combustion units and flares.
    (1) If you comply with Sec.  98.243(b) or (d), report these
emissions from stationary combustion units that are associated with
petrochemical process units and burn only supplemental fuel under
subpart C of this part (General Stationary Fuel Combustion Sources) by
following the requirements of subpart C.
    (2) If you comply with Sec.  98.243(c), report CO2,
CH4, and N2O combustion emissions under subpart C
of this part (General Stationary Fuel Combustion Sources) by following
the requirements of subpart C only for the combustion of supplemental
fuel. Determine the applicable Tier in subpart C of this part (General
Stationary Fuel Combustion Sources) based on the maximum rated heat
input capacity of the stationary combustion source.
    (c) CO2 captured. You must report the mass of
CO2 captured under, subpart PP of this part (Suppliers of
Carbon Dioxide (CO2) by following the requirements of
subpart PP.

Sec.  98.243  Calculating GHG emissions.

    (a) If you route all process vent emissions and emissions from
combustion of process off-gas to one or more stacks and use CEMS on
each stack to measure CO2 emissions (except flare stacks),
then you must determine process-based GHG emissions in accordance with
paragraph (b) of this section. Otherwise, determine process-based GHG
emissions in accordance with the procedures specified in paragraph (c)
or (d) of this section.
    (b) Continuous emission monitoring system (CEMS). Route all process
vent emissions and emissions from combustion of process off-gas to one
or more stacks and determine CO2 emissions from each stack
(except flare stacks) according to the Tier 4 Calculation Methodology
requirements in subpart C of this part. For each stack (except flare
stacks) that includes emissions from combustion of petrochemical
process off-gas, calculate CH4 and N2O emissions
in accordance with subpart C of this part (use the Tier 3 methodology
and emission factors for ``Petroleum'' in Table C-2 of subpart C of
this part). For each flare, calculate CO2, CH4,
and N2O emissions using the methodology specified in Sec.
98.253(b)(1) through (b)(3).
    (c) Mass balance for each petrochemical process unit. Calculate the
emissions of CO2 from each process unit, for each calendar
month as described in paragraphs (c)(1) through (c)(5) of this section.
    (1) For each gaseous and liquid feedstock and product, measure the
volume or mass used or produced each calendar month with a flow meter
by following the procedures specified in Sec.  98.244(b)(2).
Alternatively, for liquids, you may calculate the volume used or
collected in each month based on measurements of the liquid level in a
storage tank at least once per month (and just prior to each change in
direction of the level of the liquid) following the procedures
specified in Sec.  98.244(b)(3). Fuels used for combustion purposes are
not considered to be feedstocks.
    (2) For each solid feedstock and product, measure the mass used or
produced each calendar month by following the procedures specified in
Sec.  98.244(b)(1).
    (3) Collect a sample of each feedstock and product at least once
per month and determine the carbon content of each

sample according to the procedures in Sec.  98.244(b)(4).
Alternatively, you may use the results of analyses conducted by a fuel
or feedstock supplier, provided the sampling and analysis are conducted
at least once per month using any of the procedures specified in Sec.
98.244(b)(4). If multiple valid carbon content measurements are made
during the monthly measurement period, average them arithmetically.
    (4) If you determine that the monthly average concentration of a
specific compound in a feedstock or product is greater than 99.5
percent by volume (or mass for liquids and solids), then as an
alternative to the sampling and analysis specified in paragraph (c)(3)
of this section, you may calculate the carbon content assuming 100
percent of that feedstock or product is the specific compound during
periods of normal operation. You must maintain records of any
determination made in accordance with this paragraph (c)(4) along with
all supporting data, calculations, and other information. This
alternative may not be used for products during periods of operation
when off-specification product is produced. You must reevaluate
determinations made under this paragraph (c)(4) after any process
change that affects the feedstock or product composition. You must keep
records of the process change and the corresponding composition
determinations. If the feedstock or product composition changes so that
the average monthly concentration falls below 99.5 percent, you are no
longer permitted to use this alternative method.
    (5) Calculate the CO2 mass emissions for each
petrochemical process unit using Equations X-1 through X-4 of this
section.
    (i) Gaseous feedstocks and products. Use Equation X-1 of this
section to calculate the net annual carbon input or output from gaseous
feedstocks and products. Note that the result will be a negative value
if there are no gaseous feedstocks in the process but there are gaseous
products.
[GRAPHIC] [TIFF OMITTED] TR30OC09.083

Where:

Cg = Annual net contribution to calculated emissions from
carbon (C) in gaseous materials (kilograms/year, kg/yr).
(Fgf)i,n = Volume of gaseous feedstock i
introduced in month ``n'' (standard cubic feet, scf).
(CCgf)i,n = Average carbon content of the
gaseous feedstock i for month ``n'' (kg C per kg of feedstock).
(MWf)i = Molecular weight of gaseous feedstock
i (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at
standard conditions).
(Pgp)i,n = Volume of gaseous product i
produced in month ``n'' (scf).
(CCgp)i,n = Average carbon content of gaseous
product i, including streams containing CO2 recovered for
sale or use in another process, for month ``n'' (kg C per kg of
product).
(MWp)i = Molecular weight of gaseous product i
(kg/kg-mole).
j = Number of feedstocks.
k = Number of products.

    (ii) Liquid feedstocks and products. Use Equation X-2 of this
section to calculate the net carbon input or output from liquid
feedstocks and products. Note that the result will be a negative value
if there are no liquid feedstocks in the process but there are liquid
products.
[GRAPHIC] [TIFF OMITTED] TR30OC09.084

Where:

Cl = Annual net contribution to calculated emissions from
carbon in liquid materials, including liquid organic wastes (kg/yr).
(Flf)i,n = Volume or mass of liquid feedstock
i introduced in month ``n'' (gallons or kg).
(CClf)i,n = Average carbon content of liquid
feedstock i for month ``n'' (kg C per gallon or kg of feedstock).
(Plp)i,n = Volume or mass of liquid product i
produced in month ``n'' (gallons or kg).
(CClp)i,n = Average carbon content of liquid
product i, including organic liquid wastes, for month ``n'' (kg C
per gallon or kg of product).
j = Number of feedstocks.
k = Number of products.

    (iii) Solid feedstocks and products. Use Equation X-3 of this
section to calculate the net annual carbon input or output from solid
feedstocks and products. Note that the result will be a negative value
if there are no solid feedstocks in the process but there are solid
products.

[GRAPHIC] [TIFF OMITTED] TR30OC09.085

Where:

Cs = Annual net contribution to calculated emissions from
carbon in solid materials (kg/yr).
(Fsf)i,n = Mass of solid feedstock i
introduced in month ``n'' (kg).
(CCsf)i,n = Average carbon content of solid
feedstock i for month ``n'' (kg C per kg of feedstock).
(Psp)i,n = Mass of solid product i produced in
month ``n'' (kg).
(CCsp)i,n = Average carbon content of solid
product i in month ``n'' (kg C per kg of product).
j = Number of feedstocks.
k = Number of products.

    (iv) Annual emissions. Use the results from Equations X-1 through
X-3 of this section, as applicable, in Equation X-4 of this section to
calculate annual CO2 emissions.

[GRAPHIC] [TIFF OMITTED] TR30OC09.086

Where:

CO2 = Annual CO2 mass emissions from process
operations and process off-gas combustion (metric tons/year).
0.001 = Conversion factor from kg to metric tons.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of carbon (C) (kg/kg-mole).

    (d) Optional combustion methodology for ethylene production
processes. For any ethylene production process, calculate
CO2 emissions from combustion of fuel that contains ethylene
process off-gas using the Tier 3 or Tier 4 methodology in subpart C of
this part, and calculate CH4 and N2O emissions
using the applicable procedures in Sec.  98.33(c) (use the emission
factors for ``Petroleum'' in Table C-2 of subpart C of this part
(General Stationary Fuel Combustion Sources)). You are not required to
use the same Tier for each stationary combustion unit that burns
ethylene process off-gas. For each flare, calculate CO2,
CH4, and N2O emissions using the methodology
specified in Sec.  98.253(b)(1) through (b)(3).

Sec.  98.244  Monitoring and QA/QC requirements.

    (a) If you use CEMS to determine emissions from process vents, you
must comply with the procedures specified in Sec.  98.34(c).
    (b) If you use the mass balance methodology in Sec.  98.243(c), use
the procedures specified in paragraphs (b)(1) through (b)(4) of this
section to determine feedstock and product flows and carbon contents.
    (1) Operate and maintain belt scales or other weighing devices as
described in Specifications, Tolerances, and Other Technical
Requirements For Weighing and Measuring Devices NIST Handbook 44 (2009)
(incorporated by reference, see Sec.  98.7) or follow procedures
specified by the measurement device manufacturer. Calibrate the
measurement device according to the procedures specified by the method,
the procedures specified by the manufacturer, or Sec.  98.3(i).
Recalibrate either biennially or at the minimum frequency specified by
the manufacturer.
    (2) Operate and maintain all flow meters for gas and liquid
feedstocks and products by following the procedures in Sec.  98.3(i)
and using any of the flow meter methods specified in paragraphs
(b)(2)(i) through (b)(2)(xv) of this section, as applicable, use a
standard method published by a consensus-based standards organization
(e.g., ASTM, API, etc.), or follow procedures specified by the flow
meter manufacturer or Sec.  98.3(i). Recalibrate each flow meter either
biennially or at the minimum frequency specified by the manufacturer.
    (i) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec.
98.7).
    (ii) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by
Turbine Meters (incorporated by reference, see Sec.  98.7).
    (iii) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters
(incorporated by reference, see Sec.  98.7).
    (iv) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters (incorporated by reference, see Sec.  98.7).
    (v) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles (incorporated by reference, see
Sec.  98.7).
    (vi) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow
in Closed Conduits by Weighing Method (incorporated by reference, see
Sec.  98.7).
    (vii) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of
Coriolis Mass Flowmeters (incorporated by reference, see Sec.  98.7).
    (viii) ASME MFC-14M-2003 (Reaffirmed 2008), Measurement of Fluid
Flow Using Small Bore Precision Orifice Meters (incorporated by
reference, see Sec.  98.7).
    (ix) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits
with Electromagnetic Flowmeters (incorporated by reference, see Sec.
98.7).
    (x) ASME MFC-18M-2001 (Reaffirmed 2006), Measurement of Fluid Flow
Using Variable Area Meters (incorporated by reference, see Sec.  98.7).
    (xi) ASME MFC-22-2007 Measurement of Liquid by Turbine Flowmeters
(incorporated by reference, see Sec.  98.7).
    (xii) AGA Report No. 3: Orifice Metering of Natural Gas and Other
Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty
Guidelines (1990), Part 2: Specification and Installation Requirements
(2000) (incorporated by reference, see Sec.  98.7).
    (xiii) AGA Transmission Measurement Committee Report No. 7:
Measurement of Natural Gas by Turbine Meter (2006)/February
(incorporated by reference, see Sec.  98.7).
    (xiv) AGA Report No. 11: Measurement of Natural Gas by Coriolis
Meter (2003) (incorporated by reference, see Sec.  98.7).
    (xv) ISO 8316: Measurement of Liquid Flow in Closed Conduits--
Method by Collection of the Liquid in a Volumetric Tank (1987-10-01)
First Edition (incorporated by reference, see Sec.  98.7).
    (3) Perform tank level measurements (if used to determine feedstock
or product flows) according to any standard method published by a
consensus-based standards organization (e.g., ASTM, API, etc.) or
follow procedures specified by the measurement device manufacturer or
Sec.  98.3(i). Calibrate the measurement devices prior to the effective
date of the rule, and recalibrate either biennially or at the minimum
frequency specified by the manufacturer or Sec.  98.3(i).
    (4) Use any of the standard methods specified in paragraphs
(b)(4)(i) through (b)(4)(x) of this section, as applicable, to
determine the carbon content or composition of feedstocks and products
and the average molecular weight of gaseous feedstocks and products.
Calibrate instruments in accordance with the method and as specified in
paragraphs (b)(4)(i) through (b)(4)(x), as applicable. For coal used as
a feedstock, the samples for carbon content determinations shall be
taken at a location that is representative of the coal feedstock used
during the corresponding monthly period. For carbon black products,
samples shall be taken of each grade or type of product produced during
the monthly period. Samples of coal feedstock or carbon black product
for carbon content determinations may be either grab samples collected
and analyzed monthly or a composite of samples collected more
frequently and analyzed monthly. Analyses conducted in accordance with
methods specified in paragraphs (b)(4)(i) through (b)(4)(x) of this
section may be performed by the owner or operator, by an indpendent
laboratory, or by the supplier of a feedstock.
    (i) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas
by Gas Chromatography (incorporated by reference, see Sec.  98.7).
    (ii) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling
of Process Vents With a Portable Gas

Chromatograph (incorporated by reference, see Sec.  98.7).
    (iii) ASTM D2505-88(Reapproved 2004)e1 Standard Test Method for
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity
Ethylene by Gas Chromatography (incorporated by reference, see Sec.
98.7).
    (iv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography
(incorporated by reference, see Sec.  98.7).
    (v) ASTM D3176-89 (Reapproved 2002) Standard Practice Method for
Ultimate Analysis of Coal and Coke (incorporated by reference, see
Sec.  98.7).
    (vi) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants (incorporated by reference, see Sec.
98.7).
    (vii) ASTM D5373-08 Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples
of Coal (incorporated by reference, see Sec.  98.7).
    (viii) Methods 8031, 8021, or 8015 in ``Test Methods for Evaluating
Solid Waste, Physical/Chemical Methods,'' EPA Publication No. SW-846,
Third Edition, September 1986, as amended by Update I, November 15,
1992.
    (ix) Method 18 at 40 CFR part 60, appendix A-6.
    (x) Performance Specification 9 in 40 CFR part 60, appendix B for
continuous online gas analyzers. The 7-day calibration error test
period must be completed prior to the effective date of the rule.

Sec.  98.245  Procedures for estimating missing data.

    For missing feedstock flow rates, product flow rates, and carbon
contents, use the same procedures as for missing flow rates and carbon
contents for fuels as specified in Sec.  98.35.

Sec.  98.246  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraphs (a),
(b), or (c) of this section, as appropriate for each process unit.
    (a) If you use the mass balance methodology in Sec.  98.243(c), you
must report the information specified in paragraphs (a)(1) through
(a)(10) of this section for each type of petrochemical produced,
reported by process unit.
    (1) The petrochemical process unit ID number or other appropriate
descriptor.
    (2) The type of petrochemical produced, names of other products,
and names of carbon-containing feedstocks.
    (3) Annual CO2 emissions calculated using Equation X-4
of this subpart.
    (4) Each of the monthly volume, mass, and carbon content values
used in Equations X-1 through X-3 of this subpart (i.e., the directly
measured values, substitute values, or the calculated values based on
other measured data such as tank levels or gas composition) and the
molecular weights for gaseous feedstocks and products used in Equation
X-1 of this subpart. Indicate whether you used the alternative to
sampling and analysis specified in Sec.  98.243(c)(4).
    (5) Annual quantity of each type of petrochemical produced from
each process unit (metric tons).
    (6) Name of each method listed in Sec.  98.244 used to determine a
measured parameter (or description of manufacturer's recommended
method).
    (7) The dates and summarized results (e.g., percent calibration
error) of the calibrations of each measurement device.
    (8) Identification of each combustion unit that burned both process
off-gas and supplemental fuel.
    (9) If you comply with the alternative to sampling and analysis
specified in Sec.  98.243(c)(4), the amount of time during which off-
specification product was produced, the volume or mass of off-
specification product produced, and if applicable, the date of any
process change that reduced the composition to less than 99.5 percent.
    (10) You may elect to report the flow and carbon content of
wastewater, and you may elect to report the carbon content of
hydrocarbons in fugitive emissions and in process vents that are not
controlled with a combustion device. These values may be estimated
based on engineering analyses. These values are not to be used in the
mass balance calculation.
    (b) If you use CEMS to measure CO2 emissions in
accordance with Sec.  98.243(b), then you must report the relevant
information required under Sec.  98.36 for the Tier 4 Calculation
Methodology and the information listed in paragraphs (b)(1) through
(b)(6) of this section.
    (1) For CEMS used on stacks for stationary combustion units, report
the relevant information required under Sec.  98.36 for the Tier 4
calculation methodology.
    (2) For CEMS used on stacks that are not used for stationary
combustion units, report the information required under Sec.
98.36(e)(2)(vi) and (vii).
    (3) The petrochemical process unit ID or other appropriate
descriptor, and the type of petrochemical produced.
    (4) The CO2 emissions from each stack and the combined
CO2 emissions from all stacks (except flare stacks) that
handle process vent emissions and emissions from stationary combustion
units that burn process off-gas for the petrochemical process unit. If
a stationary combustion source serves multiple petrochemical process
units or units other than the petrochemical process unit, estimate
based on engineering judgment the fraction of fuel energy and emissions
attributable to each petrochemical process unit.
    (5) The CH4 and N2O emissions from each stack
and the combined CH4 and N2O emissions from all
stationary combustion units that burn process off-gas from the
petrochemical process unit, the cumulative annual heat input used in
Equation C-10 in Sec.  98.33(c) of this subpart, and the annual flow of
each fuel on which this heat input is based.
    (6) ID or other appropriate descriptor of each stationary
combustion unit that burns process off-gas.
    (7) Information listed in Sec.  98.256(e) of subpart Y of this part
for each flare that burns process off-gas.
    (8) Annual quantity of each type of petrochemical produced from
each process unit (metric tons).
    (c) If you comply with the combustion methodology specified in
Sec.  98.243(d), you must report under this subpart the information
listed in paragraphs (c)(1) through (c)(4) of this section.
    (1) For each stationary combustion unit that burns ethylene process
off-gas (or group of stationary sources with a common pipe), the
relevant information listed in Sec.  98.36 for the selected Tier 3 or
Tier 4 methodology. If a stationary combustion source serves multiple
ethylene process units or units other than the ethylene process unit,
estimate based on engineering judgment the fraction of fuel energy and
emissions attributable to each ethylene process unit.
    (2) Information listed in Sec.  98.256(e) for each flare that burns
ethylene process off-gas.
    (3) Name and annual quantity of each feedstock.
    (4) Annual quantity of each type of petrochemical produced from
each process unit (metric tons).

Sec.  98.247  Records that must be retained.

    In addition to the recordkeeping requirements in Sec.  98.3(g), you
must retain the records specified in paragraphs (a) through (c) of this
section, as applicable.
    (a) If you comply with the CEMS measurement methodology in Sec.
98.243(b), then you must retain under this subpart the records required
for the Tier 4 Calculation Methodology in Sec.  98.37.

    (b) If you comply with the mass balance methodology in Sec.
98.243(c), then you must retain records of the information listed in
paragraphs (b)(1) through (b)(3) of this section.
    (1) Results of feedstock or product composition determinations
conducted in accordance with Sec.  98.243(c)(4).
    (2) 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 Sec.  98.243(c)(4) for determining
carbon content of feedstock or product.
    (3) A part of the monitoring plan required under Sec.  98.3(g)(5),
record the estimated accuracy of measurement devices and the technical
basis for these estimates.
    (c) If you comply with the combustion methodology in Sec.
98.243(d), then you must retain under this subpart the records required
for the Tier 3 and/or Tier 4 Calculation Methodologies in Sec.  98.37.

Sec.  98.248  Definitions.

    Except as specified in this section, all terms used in this subpart
have the same meaning given in the Clean Air Act and subpart A of this
part.
    Product, as used in Sec.  98.243, means each of the following
carbon-containing outputs from a process: the petrochemical, recovered
byproducts, and liquid organic wastes that are not incinerated onsite.
Product does not include process vent emissions, fugitive emissions, or
wastewater.

Subpart Y--Petroleum Refineries

Sec.  98.250  Definition of source category.

    (a) A petroleum refinery is any facility engaged in producing
gasoline, gasoline blending stocks, naphtha, kerosene, distillate fuel
oils, residual fuel oils, lubricants, or asphalt (bitumen) through
distillation of petroleum or through redistillation, cracking, or
reforming of unfinished petroleum derivatives, except as provided in
paragraph (b) of this section.
    (b) For the purposes of this subpart, facilities that distill only
pipeline transmix (off-spec material created when different
specification products mix during pipeline transportation) are not
petroleum refineries, regardless of the products produced.
    (c) This source category consists of the following sources at
petroleum refineries: Catalytic cracking units; fluid coking units;
delayed coking units; catalytic reforming units; coke calcining units;
asphalt blowing operations; blowdown systems; storage tanks; process
equipment components (compressors, pumps, valves, pressure relief
devices, flanges, and connectors) in gas service; marine vessel, barge,
tanker truck, and similar loading operations; flares; sulfur recovery
plants; and non-merchant hydrogen plants (i.e., hydrogen plants that
are owned or under the direct control of the refinery owner and
operator).

Sec.  98.251  Reporting threshold.

    You must report GHG emissions under this subpart if your facility
contains a petroleum refineries process and the facility meets the
requirements of either Sec.  98.2(a)(1) or (a)(2).

Sec.  98.252  GHGs to report.

    You must report:
    (a) CO2, CH4, and N2O combustion
emissions from stationary combustion units and from each flare.
Calculate and report these emissions under subpart C of this part
(General Stationary Fuel Combustion Sources) by following the
requirements of subpart C, except for CO2 emissions from
combustion of refinery fuel gas. For CO2 emissions from
combustion of fuel gas, use either equation C-5 in subpart C of this
part or the Tier 4 methodology in subpart C of this part. You may
aggregate units, monitor common stacks, or monitor common (fuel) pipes
as provided in Sec.  98.36(c) when calculating and reporting emissions
from stationary combustion units.
    (b) CO2, CH4, and N2O coke burn-
off emissions from each catalytic cracking unit, fluid coking unit, and
catalytic reforming unit under this subpart.
    (c) CO2 emissions from sour gas sent off site for sulfur
recovery operations under this subpart. You must follow the calculation
methodologies from Sec.  98.253(f) and the monitoring and QA/QC
methods, missing data procedures, reporting requirements, and
recordkeeping requirements of this subpart.
    (d) CO2 process emissions from each on-site sulfur
recovery plant under this subpart.
    (e) CO2, CH4, and N2O emissions
from each coke calcining unit under this subpart.
    (f) CO2 and CH4 emissions from asphalt
blowing operations under this subpart.
    (g) CH4 emissions from equipment leaks, storage tanks,
loading operations, delayed coking units, and uncontrolled blowdown
systems under this subpart.
    (h) CO2, CH4, and N2O emissions
from each process vent not specifically included in paragraphs (a)
through (g) of this section under this subpart.
    (i) CO2 and CH4 emissions from non-merchant
hydrogen production under this subpart. You must follow the calculation
methodologies, monitoring and QA/QC methods, missing data procedures,
reporting requirements, and recordkeeping requirements of subpart P of
this part.

Sec.  98.253  Calculating GHG emissions.

    (a) Calculate GHG emissions required to be reported in Sec.
98.252(b) through (i) using the applicable methods in paragraphs (b)
through (n) of this section.
    (b) For flares, calculate GHG emissions according to the
requirements in paragraphs (b)(1) through (b)(3) of this section.
    (1) Calculate the CO2 emissions according to the
applicable requirements in paragraphs (b)(1)(i) through (b)(1)(iii) of
this section.
    (i) Flow measurement. If you have a continuous flow monitor on the
flare, you must use the measured flow rates when the monitor is
operational and the flow rate is within the calibrated range of the
measurement device to calculate the flare gas flow. If you do not have
a continuous flow monitor on the flare and for periods when the monitor
is not operational or the flow rate is outside the calibrated range of
the measurement device, you must use engineering calculations, company
records, or similar estimates of volumetric flare gas flow.
    (ii) Heat value or carbon content measurement. If you have a
continuous higher heating value monitor or gas composition monitor on
the flare or if you monitor these parameters at least weekly, you must
use the measured heat value or carbon content value in calculating the
CO2 emissions from the flare using the applicable methods in
paragraphs (b)(1)(ii)(A) and (b)(1)(ii)(B).
    (A) If you monitor gas composition, calculate the CO2
emissions from the flare using Equation Y-1 of this section. If daily
or more frequent measurement data are available, you must use daily
values when using Equation Y-1 of this section; otherwise, use weekly
values.

[GRAPHIC] [TIFF OMITTED] TR30OC09.087

Where:

CO2 = Annual CO2 emissions for a specific fuel
type (metric tons/year).
0.98 = Assumed combustion efficiency of a flare.
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
n = Number of measurement periods. The minimum value for n is 52
(for weekly measurements); the maximum value for n is 366 (for daily
measurements during a leap year).
p = Measurement period index.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
(Flare)p = Volume of flare gas combusted during
measurement period (standard cubic feet per period, scf/period). If
a mass flow meter is used, measure flare gas flow rate in kg/period
and replace the term ``(MW)p/MVC'' with ``1''.
(MW)p = Average molecular weight of the flare gas
combusted during measurement period (kg/kg-mole). If measurements
are taken more frequently than daily, use the arithmetic average of
measurement values within the day to calculate a daily average.
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
(CC)p = Average carbon content of the flare gas combusted
during measurement period (kg C per kg flare gas). If measurements
are taken more frequently than daily, use the arithmetic average of
measurement values within the day to calculate a daily average.

    (B) If you monitor heat content but do not monitor gas composition,
calculate the CO2 emissions from the flare using Equation Y-
2 of this section. If daily or more frequent measurement data are
available, you must use daily values when using Equation Y-2 of this
section; otherwise, use weekly values.
[GRAPHIC] [TIFF OMITTED] TR30OC09.088

Where:

CO2 = Annual CO2 emissions for a specific fuel
type (metric tons/year).
0.98 = Assumed combustion efficiency of a flare.
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
n = Number of measurement periods. The minimum value for n is 52
(for weekly measurements); the maximum value for n is 366 (for daily
measurements during a leap year).
p = Measurement period index.
(Flare)p = Volume of flare gas combusted during
measurement period (million (MM) scf/period). If a mass flow meter
is used, you must also measure molecular weight and convert the mass
flow to a volumetric flow as follows: Flare[MMscf] = 0.000001 x
Flare[kg] x MVC/(MW)p, where MVC is the molar volume
conversion factor (849.5 scf/kg-mole) and (MW)p is the
average molecular weight of the flare gas combusted during
measurement period (kg/kg-mole).
(HHV)p = Higher heating value for the flare gas combusted
during measurement period (British thermal units per scf, Btu/scf =
MMBtu/MMscf). If measurements are taken more frequently than daily,
use the arithmetic average of measurement values within the day to
calculate a daily average.
EmF = Default CO2 emission factor of 60 kilograms
CO2/MMBtu (HHV basis).
    (iii) Alternative to heat value or carbon content measurements. If
you do not measure the higher heating value or carbon content of the
flare gas at least weekly, determine the quantity of gas discharged to
the flare separately for periods of routine flare operation and for
periods of start-up, shutdown, or malfunction, and calculate the
CO2 emissions as specified in paragraphs (b)(1)(iii)(A)
through (b)(1)(iii)(C) of this section.
    (A) For periods of start-up, shutdown, or malfunction, use
engineering calculations and process knowledge to estimate the carbon
content of the flared gas for each start-up, shutdown, or malfunction
event exceeding 500,000 scf/day.
    (B) For periods of normal operation, use the average heating value
measured for the fuel gas for the heating value of the flare gas. If
heating value is not measured, the heating value may be estimated from
historic data or engineering calculations.
    (C) Calculate the CO2 emissions using Equation Y-3 of
this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.089

Where:

CO2 = Annual CO2 emissions for a specific fuel
type (metric tons/year).
0.98 = Assumed combustion efficiency of a flare.
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
FlareNorm = Annual volume of flare gas combusted during
normal operations from company records, (million (MM) standard cubic
feet per year, MMscf/year).
HHV = Higher heating value for fuel gas or flare gas from company
records (British thermal units per scf, Btu/scf = MMBtu/MMscf).
EmF = Default CO2 emission factor for flare gas of 60
kilograms CO2/MMBtu (HHV basis).
n = Number of start-up, shutdown, and malfunction events during the
reporting year exceeding 500,000 scf/day.
p = Start-up, shutdown, and malfunction event index.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
(FlareSSM)p = Volume of flare gas combusted
during indexed start-up, shutdown, or malfunction event from
engineering calculations, (scf/event).
(MW)p = Average molecular weight of the flare gas, from
the analysis results or engineering calculations for the event (kg/
kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
(CC)p = Average carbon content of the flare gas, from
analysis results or engineering calculations for the event (kg C per
kg flare gas).

    (2) Calculate CH4 using Equation Y-4 of this section.

[GRAPHIC] [TIFF OMITTED] TR30OC09.090

Where:

CH4 = Annual methane emissions from flared gas (metric
tons CH4/year).
CO2 = Emission rate of CO2 from flared gas
calculated in paragraph (b)(1) of this section (metric tons/year).
EmFCH4 = Default CH4 emission factor for
``PetroleumProducts'' from Table C-2 of subpart C of this part
(General Stationary Fuel Combustion Sources) (kg CH4/
MMBtu).
EmF = Default CO2 emission factor for flare gas of 60 kg
CO2/MMBtu (HHV basis).
0.02/0.98 = Correction factor for flare combustion efficiency.
16/44 = Correction factor ratio of the molecular weight of
CH4 to CO2.
fCH4 = Weight fraction of carbon in the flare gas prior
to combustion that is contributed by methane from measurement values
or engineering calculations (kg C in methane in flare gas/kg C in
flare gas); default is 0.4.

    (3) Calculate N2O emissions using Equation Y-5 of this
section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.091

Where:

N2O = Annual nitrous oxide emissions from flared gas
(metric tons N2O/year).
CO2 = Emission rate of CO2 from flared gas
calculated in paragraph (b)(1) of this section (metric tons/year).
EmFN2O = Default N2O emission factor for
``PetroleumProducts'' from Table C-2 of subpart C of this part
(General Stationary Fuel Combustion Sources) (kg N2O/
MMBtu).
EmF = Default CO2 emission factor for flare gas of 60 kg
CO2/MMBtu (HHV basis).

    (c) For catalytic cracking units and traditional fluid coking
units, calculate the GHG emissions using the applicable methods
described in paragraphs (c)(1) through (c)(5) of this section.
    (1) If you operate and maintain a CEMS that measures CO2
emissions according to subpart C of this part (General Stationary Fuel
Combustion Sources), you must calculate and report CO2
emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this
section. Other catalytic cracking units and traditional fluid coking
units must either install a CEMS that complies with the Tier 4
Calculation Methodology in subpart C of this part (General Stationary
Combustion Sources), or follow the requirements of paragraphs (c)(2) or
(3) of this section.
    (i) Calculate CO2 emissions by following the Tier 4
Calculation Methodology specified in Sec.  98.33(a)(4) and all
associated requirements for Tier 4 in subpart C of this part (General
Stationary Fuel Combustion Sources).
    (ii) If a CO boiler or other post-combustion device is used, you
must also calculate the CO2 emissions from the fuel fired to
the CO boiler or post-combustion device using the applicable methods
for stationary combustion units in subpart C of this part. Calculate
the process emissions from the catalytic cracking unit or fluid coking
unit as the difference in the CO2 CEMS emissions and the
calculated combustion emissions associated with the CO boiler.
    (2) For catalytic cracking units and fluid coking units with rated
capacities greater than 10,000 barrels per stream day (bbls/sd) that do
not use a continuous CO2 CEMS for the final exhaust stack,
you must continuously or no less frequently than hourly monitor the
O2, CO2, and (if necessary) CO concentrations in
the exhaust stack from the catalytic cracking unit regenerator or fluid
coking unit burner prior to the combustion of other fossil fuels and
calculate the CO2 emissions according to the requirements of
paragraphs (c)(2)(i) through (c)(2)(iii) of this section:
    (i) Calculate the CO2 emissions from each catalytic
cracking unit and fluid coking unit using Equation Y-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.092

Where:

CO2 = Annual CO2 mass emissions (metric tons/
year).
Qr = Volumetric flow rate of exhaust gas from the fluid
catalytic cracking unit regenerator or fluid coking unit burner
prior to the combustion of other fossil fuels (dry standard cubic
feet per hour, dscfh).
%CO2 = Hourly average percent CO2
concentration in the exhaust gas stream from the fluid catalytic
cracking unit regenerator or fluid coking unit burner (percent by
volume--dry basis).
%CO = Hourly average percent CO concentration in the exhaust gas
stream from the fluid catalytic cracking unit regenerator or fluid
coking unit burner (percent by volume--dry basis). When there is no
post-combustion device, assume %CO to be zero.
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).
n = Number of hours in calendar year.

    (ii) Either continuously monitor the volumetric flow rate of
exhaust gas from the fluid catalytic cracking unit regenerator or fluid
coking unit burner prior to the combustion of other fossil fuels or
calculate the volumetric flow rate of this exhaust gas stream using
Equation Y-7 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.093

Where:

Qr = Volumetric flow rate of exhaust gas from the fluid
catalytic cracking unit regenerator or fluid coking unit burner
prior to the combustion of other fossil fuels (dscfh).
Qa = Volumetric flow rate of air to the fluid catalytic
cracking unit regenerator or fluid coking unit burner, as determined
from control room instrumentation (dscfh).
Qoxy = Volumetric flow rate of oxygen enriched air to the
fluid catalytic cracking unit regenerator or fluid coking unit
burner as determined from control room instrumentation (dscfh).

%O2 = Hourly average percent oxygen concentration in
exhaust gas stream from the fluid catalytic cracking unit
regenerator or fluid coking unit burner (percent by volume--dry
basis).
%Ooxy = O2 concentration in oxygen enriched
gas stream inlet to the fluid catalytic cracking unit regenerator or
fluid coking unit burner based on oxygen purity specifications of
the oxygen supply used for enrichment (percent by volume--dry
basis).
%CO2 = Hourly average percent CO2
concentration in the exhaust gas stream from the fluid catalytic
cracking unit regenerator or fluid coking unit burner (percent by
volume--dry basis).
%CO = Hourly average percent CO concentration in the exhaust gas
stream from the fluid catalytic cracking unit regenerator or fluid
coking unit burner (percent by volume--dry basis). When no auxiliary
fuel is burned and a continuous CO monitor is not required under 40
CFR part 63 subpart UUU, assume %CO to be zero.

    (iii) If you have a CO boiler that uses auxiliary fuels or combusts
materials other than catalytic cracking unit or fluid coking unit
exhaust gas, you must determine the CO2 emissions resulting
from the combustion of these fuels or other materials following the
requirements in subpart C and report those emissions by following the
requirements of subpart C of this part.
    (3) For catalytic cracking units and fluid coking units with rated
capacities of 10,000 barrels per stream day (bbls/sd) or less that do
not use a continuous CO2 CEMS for the final exhaust stack,
comply with the requirements in paragraph (c)(3)(i) of this section or
paragraphs (c)(3)(ii) and (c)(3)(iii) of this section, as applicable.
    (i) If you continuously or no less frequently than daily monitor
the O2, CO2, and (if necessary) CO concentrations
in the exhaust stack from the catalytic cracking unit regenerator or
fluid coking unit burner prior to the combustion of other fossil fuels,
you must calculate the CO2 emissions according to the
requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this
section, except that daily averages are allowed and the summation can
be performed on a daily basis.
    (ii) If you do not monitor at least daily the O2,
CO2, and (if necessary) CO concentrations in the exhaust
stack from the catalytic cracking unit regenerator or fluid coking unit
burner prior to the combustion of other fossil fuels, calculate the
CO2 emissions from each catalytic cracking unit and fluid
coking unit using Equation Y-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.094

Where:

CO2 = Annual CO2 mass emissions (metric tons/
year).
Qunit = Annual throughput of unit from company records
(barrels (bbls) per year, bbl/yr).
CBF = Coke burn-off factor from engineering calculations (kg coke
per barrel of feed); default for catalytic cracking units = 7.3;
default for fluid coking units = 11.
0.001 = Conversion factor (metric ton/kg).
CC = Carbon content of coke based on measurement or engineering
estimate (kg C per kg coke); default = 0.94.
44/12 = Ratio of molecular weight of CO2 to C (kg
CO2 per kg C).

    (iii) If you have a CO boiler that uses auxiliary fuels or combusts
materials other than catalytic cracking unit or fluid coking unit
exhaust gas, you must determine the CO2 emissions resulting
from the combustion of these fuels or other materials following the
requirements in subpart C of this part (General Stationary Fuel
Combustion Sources) and report those emissions by following the
requirements of subpart C of this part.
    (4) Calculate CH4 emissions using either unit specific
measurement data, a unit-specific emission factor based on a source
test of the unit, or Equation Y-9 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.095

Where:

CH4 = Annual methane emissions from coke burn-off (metric
tons CH4/year).
CO2 = Emission rate of CO2 from coke burn-off
calculated in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), (g)(1), or
(g)(2) of this section, as applicable (metric tons/year).
EmF1 = Default CO2 emission factor for
petroleum coke from Table C-1 of subpart C of this part (General
Stationary Fuel Combustion Sources) (kg CO2/MMBtu).
EmF2 = Default CH4 emission factor for
``PetroleumProducts'' from Table C-2 of subpart C of this part
(General Stationary Fuel Combustion Sources) (kg CH4/
MMBtu).

    (5) Calculate N2O emissions using either unit specific
measurement data, a unit-specific emission factor based on a source
test of the unit, or Equation Y-10 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.096

Where:

N2O = Annual nitrous oxide emissions from coke burn-off
(mt N2O/year).
CO2 = Emission rate of CO2 from coke burn-off
calculated in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), (g)(1), or
(g)(2) of this section, as applicable (metric tons/year).
EmF1 = Default CO2 emission factor for
petroleum coke from Table C-1 of subpart C of this part (General
Stationary Fuel Combustion Sources) (kg CO2/MMBtu).
EmF3 = Default N2O emission factor for
``PetroleumProducts'' from Table C-2 of subpart C of this part (kg
N2O/MMBtu).

    (d) For fluid coking units that use the flexicoking design, the GHG
emissions from the resulting use of the low value fuel gas must be
accounted for only once. Typically, these emissions will be accounted
for using the methods described in subpart C of this part (General
Stationary Fuel Combustion Sources). Alternatively, you may use the
methods in paragraph (c) of this section provided that you do not
otherwise account for the subsequent combustion of this low value fuel
gas.
    (e) For catalytic reforming units, calculate the CO2
emissions using the applicable methods described in paragraphs (e)(1)
through (e)(3) of this section and calculate the CH4 and
N2O emissions using the methods described in paragraphs
(c)(4) and (c)(5) of this section, respectively.
    (1) If you operate and maintain a CEMS that measures CO2
emissions according to subpart C of this part (General Stationary Fuel
Combustion Sources), you must calculate CO2 emissions as
provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other
catalytic reforming units must either install a CEMS that complies with
the Tier 4 Calculation Methodology in subpart C of this part, or follow
the requirements of paragraph (e)(2) or (e)(3) of this section.
    (2) If you continuously or no less frequently than daily monitor
the O2, CO2, and (if necessary) CO concentrations
in the exhaust stack from the catalytic reforming unit catalyst
regenerator prior to the combustion of other fossil fuels, you must
calculate the CO2 emissions according to the requirements of
paragraphs (c)(2)(i) through (c)(2)(iii) of this section.

    (3) Calculate CO2 emissions from the catalytic reforming
unit catalyst regenerator using Equation Y-11 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.097

Where:

CO2 = Annual CO2 emissions (metric tons/year).
CBQ = Coke burn-off quantity per regeneration cycle from
engineering estimates (kg coke/cycle).
n = Number of regeneration cycles in the calendar year.
CC = Carbon content of coke based on measurement or engineering
estimate (kg C per kg coke); default = 0.94.
44/12 = Ratio of molecular weight of CO2 to C (kg
CO2 per kg C).
0.001 = Conversion factor (metric ton/kg).

    (f) For on-site sulfur recovery plants, calculate and report
CO2 process emissions from sulfur recovery plants according
to the requirements in paragraphs (f)(1) through (f)(5) of this
section. Combustion emissions from the sulfur recovery plant (e.g.,
from fuel combustion in the Claus burner or the tail gas treatment
incinerator) must be reported under subpart C of this part (General
Stationary Fuel Combustion Sources). For the purposes of this subpart,
the sour gas stream for which monitoring is required according to
paragraphs (f)(2) through (f)(5) of this section is not considered a
fuel.
    (1) If you operate and maintain a CEMS that measures CO2
emissions according to subpart C of this part, you must calculate
CO2 emissions under this subpart by following the Tier 4
Calculation Methodology specified in Sec.  98.33(a)(4) and all
associated requirements for Tier 4 in subpart C of this part (General
Stationary Fuel Combustion Sources). You must monitor fuel use in the
Claus burner, tail gas incinerator, or other combustion sources that
discharge via the final exhaust stack from the sulfur recovery plant
and calculate the combustion emissions from the fuel use according to
subpart C of this part. Calculate the process emissions from the sulfur
recovery plant as the difference in the CO2 CEMS emissions
and the calculated combustion emissions associated with the sulfur
recovery plant final exhaust stack. Other sulfur recovery plants must
either install a CEMS that complies with the Tier 4 Calculation
Methodology in subpart C, or follow the requirements of paragraphs
(f)(2) through (f)(5) of this section.
    (2) Flow measurement. If you have a continuous flow monitor on the
sour gas feed to the sulfur recovery plant, you must use the measured
flow rates when the monitor is operational to calculate the sour gas
flow rate. If you do not have a continuous flow monitor on the sour gas
feed to the sulfur recovery plant, you must use engineering
calculations, company records, or similar estimates of volumetric sour
gas flow.
    (3) Carbon content. If you have a continuous gas composition
monitor capable of measuring carbon content on the sour gas feed to the
sulfur recovery plant or if you monitor gas composition for carbon
content on a routine basis, you must use the measured carbon content
value. Alternatively, you may develop a site-specific carbon content
factor using limited measurement data or engineering estimates or use
the default factor of 0.20.
    (4) Calculate the CO2 emissions from each sulfur
recovery plant using Equation Y-12 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.098

Where:

CO2 = Annual CO2 emissions (metric tons/year).
FSG = Volumetric flow rate of sour gas feed (including
sour water stripper gas) to the sulfur recovery plant (scf/year).
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
MFC = Mole fraction of carbon in the sour gas to the
sulfur recovery plant (kg-mole C/kg-mole gas); default = 0.20.
0.001 = Conversion factor, kg to metric tons.

    (5) If tail gas is recycled to the front of the sulfur recovery
plant and the recycled flow rate and carbon content is included in the
measured data under paragraphs (f)(2) and (f)(3) of this section,
respectively, then the annual CO2 emissions calculated in
paragraph (f)(4) of this section must be corrected to avoid double
counting these emissions. You may use engineering estimates to perform
this correction or assume that the corrected CO2 emissions
are 95 percent of the uncorrected value calculated using Equation Y-12
of this section.
    (g) For coke calcining units, calculate GHG emissions according to
the applicable provisions in paragraphs (g)(1) through (g)(3) of this
section.
    (1) If you operate and maintain a CEMS that measures CO2
emissions according to subpart C of this part, you must calculate and
report CO2 emissions under this subpart by following the
Tier 4 Calculation Methodology specified in Sec.  98.33(a)(4) and all
associated requirements for Tier 4 in subpart C of this part (General
Stationary Fuel Combustion Sources). You must monitor fuel use in the
coke calcining unit that discharges via the final exhaust stack from
the coke calcining unit and calculate the combustion emissions from the
fuel use according to subpart C of this part. Calculate the process
emissions from the coke calcining unit as the difference in the
CO2 CEMS emissions and the calculated combustion emissions
associated with the coke calcining unit final exhaust stack. Other coke
calcining units must either install a CEMS that complies with the Tier
4 Calculation Methodology in subpart C of this part, or follow the
requirements of paragraph (g)(2) of this section.
    (2) Calculate the CO2 emissions from the coke calcining
unit using Equation Y-13 of this section.

[GRAPHIC] [TIFF OMITTED] TR30OC09.099

Where:

CO2 = Annual CO2 emissions (metric tons/year).
Min = Annual mass of green coke fed to the coke calcining
unit from facility records (metric tons/year).
CCGC = Average mass fraction carbon content of green coke
from facility measurement data (metric ton carbon/metric ton green
coke).
Mout = Annual mass of marketable petroleum coke produced
by the coke calcining unit from facility records (metric tons
petroleum coke/year).
Mdust = Annual mass of petroleum coke dust collected in
the dust collection system of the coke calcining unit from facility
records (metric ton petroleum coke dust/year).
CCMPC = Average mass fraction carbon content of
marketable petroleum coke produced by the coke calcining unit from
facility measurement data (metric ton carbon/metric ton petroleum
coke).
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).

    (3) For all coke calcining units, use the CO2 emissions
from the coke calcining unit calculated in paragraphs (g)(1) or (g)(2),
as applicable, and calculate CH4 using the methods described
in paragraph (c)(4) of this section and N2O emissions using
the methods described in paragraph (c)(5) of this section.
    (h) For asphalt blowing operations, calculate GHG emissions
according to the requirements in paragraph (j) of this section or
according to the applicable provisions in paragraphs (h)(1) and (h)(2)
of this section.
    (1) For uncontrolled asphalt blowing operations or asphalt blowing
operations controlled by vapor scrubbing, calculate CO2 and
CH4 emissions using Equations Y-14 and Y-15 of this section,
respectively.
[GRAPHIC] [TIFF OMITTED] TR30OC09.100

Where:

CO2 = Annual CO2 emissions from uncontrolled
asphalt blowing (metric tons CO2/year).
QAB = Quantity of asphalt blown (million barrels per
year, MMbbl/year).
EFAB,CO2 = Emission factor for CO2 from
uncontrolled asphalt blowing from facility-specific test data
(metric tons CO2/MMbbl asphalt blown); default = 1,100.
[GRAPHIC] [TIFF OMITTED] TR30OC09.101

Where:

CH4 = Annual methane emissions from uncontrolled asphalt
blowing (metric tons CH4/year).
QAB = Quantity of asphalt blown (million barrels per
year, MMbbl/year).
EFAB,CH4 = Emission factor for CH4 from
uncontrolled asphalt blowing from facility-specific test data
(metric tons CH4/MMbbl asphalt blown); default = 580.

    (2) For asphalt blowing operations controlled by thermal oxidizer
or flare, calculate CO2 and CH4 emissions using
Equations Y-16 and Y-17 of this section, respectively, provided these
emissions are not already included in the flare emissions calculated in
paragraph (b) of this section or in the stationary combustion unit
emissions required under subpart C of this part (General Stationary
Fuel Combustion Sources).
[GRAPHIC] [TIFF OMITTED] TR30OC09.102

Where:

CO2 = Annual CO2 emissions from controlled
asphalt blowing (metric tons CO2/year).
0.98 = Assumed combustion efficiency of thermal oxidizer or flare.
QAB = Quantity of asphalt blown (MMbbl/year).
CEFAB = Carbon emission factor from asphalt blowing from
facility-specific test data (metric tons C/MMbbl asphalt blown);
default = 2,750.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
[GRAPHIC] [TIFF OMITTED] TR30OC09.103

Where:

CH4 = Annual methane emissions from controlled asphalt
blowing (metric tons CH4/year).
0.02 = Fraction of methane uncombusted in thermal oxidizer or flare
based on assumed 98% combustion efficiency.
QAB = Quantity of asphalt blown (million barrels per
year, MMbbl/year).
EFAB,CH4 = Emission factor for CH4 from
uncontrolled asphalt blowing from facility-specific test data
(metric tons CH4/MMbbl asphalt blown); default = 580.

    (i) For delayed coking units, calculate the CH4
emissions from the depressurization of the coking unit vessel (i.e.,
the ``coke drum'') to atmosphere using either of the methods provided
in paragraphs (i)(1) or (i)(2), provided no water or steam is added to
the vessel once it is vented to the atmosphere. You must use the method
in paragraph (i)(1) of this section if you add water or steam to the
vessel after it is vented to the atmosphere.
    (1) Use the process vent method in paragraph (j) of this section
and also calculate the CH4 emissions from the subsequent
opening of the vessel for coke cutting operations using Equation Y-18
of this section. If you have coke drums or vessels of different
dimensions, use Equation Y-18 for each set of coke drums or vessels of
the same size and sum the resultant emissions across each set of coke
drums or vessels to calculate the CH4 emissions for all
delayed coking units.
[GRAPHIC] [TIFF OMITTED] TR30OC09.104

Where:

CH4 = Annual methane emissions from the delayed coking
unit vessel opening (metric ton/year).
N = Cumulative number of vessel openings for all delayed coking unit
vessels of the same dimensions during the year.
H = Height of coking unit vessel (feet).
PCV = Gauge pressure of the coking vessel when opened to
the atmosphere prior to coke cutting or, if the alternative method
provided in paragraph (i)(2) of this section is used, gauge pressure
of the coking vessel when depressurization gases are first routed to
the atmosphere (pounds per square inch gauge, psig).
14.7 = Assumed atmospheric pressure (pounds per square inch, psi).
fvoid = Volumetric void fraction of coking vessel prior
to steaming (cf gas/cf of vessel); default = 0.6.
D = Diameter of coking unit vessel (feet).
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
MFCH4 = Mole fraction of methane in coking vessel gas
(kg-mole CH4/kg-mole gas, wet basis); default value is
0.01.
0.001 = Conversion factor (metric ton/kg).

    (2) Calculate the CH4 emissions from the
depressurization vent and subsequent opening of the vessel for coke
cutting operations using Equation Y-18 of this section and the pressure
of the coking vessel when the depressurization gases are first routed
to the atmosphere. If you have coke drums or vessels of different
dimensions, use Equation Y-18 for each set of coke drums or vessels of
the same size and sum the resultant emissions across each set of coke
drums or vessels to calculate the CH4 emissions for all
delayed coking units.
    (j) For each process vent not covered in paragraphs (a) through (i)
of this section that can be reasonably expected to contain greater than
2 percent by volume CO2 or greater than 0.5 percent by
volume of CH4 or greater than 0.01 percent by volume (100
parts per million) of N2O, calculate GHG emissions using the
Equation Y-19 of this section. You must use Equation Y-19 of this
section for catalytic reforming unit depressurization and purge vents
when methane is used as the purge gas or if you elected this method as
an alternative to the methods in paragraphs (h)(1) or (h)(2) of this
section.

[GRAPHIC] [TIFF OMITTED] TR30OC09.105

Where:

Ex = Annual emissions of each GHG from process vent
(metric ton/yr).
N = Number of venting events per year.
P = Index of venting events.
(VR)p = Average volumetric flow rate of process gas
during the event (scf per hour).
(MFx)p = Mole fraction of GHG x in process
vent during the event (kg-mol of GHG x/kg-mol vent gas).
MWx = Molecular weight of GHG x (kg/kg-mole); use 44 for
CO2 or N2O and 16 for CH4.
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
(VT)p = Venting time for the event, (hours).
0.001 = Conversion factor (metric ton/kg).

    (k) For uncontrolled blowdown systems, you must either use the
methods for process vents in paragraph (j) of this section or calculate
CH4 emissions using Equation Y-20 of this section. Blowdown
systems where the uncondensed gas stream is routed to a flare or
similar control device is considered to be controlled and is not
required to estimate emissions under this paragraph (k).

[GRAPHIC] [TIFF OMITTED] TR30OC09.106

Where:

CH4 = Methane emission rate from blowdown systems (mt
CH4/year).
QRef = Quantity of crude oil plus the quantity of
intermediate products received from off site that are processed at
the facility (MMbbl/year).
EFBD = Methane emission factor for uncontrolled blown
systems (scf CH4/MMbbl); default is 137,000.
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).

    (l) For equipment leaks, calculate CH4 emissions using
the method specified in either paragraph (l)(1) or (l)(2) of this
section.
    (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 Equipment Leak Emissions
Estimates (EPA-453/R-95-017, NTIS PB96-175401).
    (2) Use Equation Y-21 of this section.

    [GRAPHIC] [TIFF OMITTED] TR30OC09.107

Where:

CH4 = Annual methane emissions from equipment leaks
(metric tons/year).
NCD = Number of atmospheric crude oil distillation
columns at the facility.
NPU1 = Cumulative number of catalytic cracking units,
coking units (delayed or fluid), hydrocracking, and full-range
distillation columns (including depropanizer and debutanizer
distillation columns) at the facility.
NPU2 = Cumulative number of hydrotreating/hydrorefining
units, catalytic reforming units, and visbreaking units at the
facility.
NH2 = Total number of hydrogen plants at the facility.
NFGS = Total number of fuel gas systems at the facility.

    (m) For storage tanks, except as provided in paragraph (m)(3) of
this section, calculate CH4 emissions using the applicable
methods in paragraphs (m)(1) and (m)(2) of this section.
    (1) For storage tanks other than those processing unstabilized
crude oil, you must either calculate CH4 emissions from
storage tanks that have a vapor-phase methane concentration of 0.5
volume percent or more using tank-specific methane composition data
(from measurement data or product knowledge) and the AP-42 emission

estimation methods provided in Section 7.1 of the AP-42: ``Compilation
of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area
Sources'', including TANKS Model (Version 4.09D) or similar programs,
or estimate CH4 emissions from storage tanks using Equation
Y-22 of this section.

[GRAPHIC] [TIFF OMITTED] TR30OC09.108

Where:

CH4 = Annual methane emissions from storage tanks (metric
tons/year).
0.1 = Default emission factor for storage tanks (metric ton
CH4/MMbbl).
QRef = Quantity of crude oil plus the quantity of
intermediate products received from off site that are processed at
the facility (MMbbl/year).

    (2) For storage tanks that process unstabilized crude oil,
calculate CH4 emissions from the storage of unstabilized
crude oil using either tank-specific methane composition data (from
measurement data or product knowledge) and direct measurement of the
gas generation rate or by using Equation Y-23 of this section.

[GRAPHIC] [TIFF OMITTED] TR30OC09.109

Where:

CH4 = Annual methane emissions from storage tanks (metric
tons/year).
Qun = Quantity of unstabilized crude oil received at the
facility (MMbbl/year).
[Delta]P = Pressure differential from the previous storage pressure
to atmospheric pressure (pounds per square inch, psi).
MFCH4 = Mole fraction of CH4 in vent gas from
the unstabilized crude oil storage tank from facility measurements
(kg-mole CH4/kg-mole gas); use 0.27 as a default if
measurement data are not available.
995,000 = Correlation Equation factor (scf gas per MMbbl per psi).
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).

    (3) You do not need to calculate CH4 emissions from
storage tanks that meet any of the following descriptions:
    (i) Units permanently attached to conveyances such as trucks,
trailers, rail cars, barges, or ships;
    (ii) Pressure vessels designed to operate in excess of 204.9
kilopascals and without emissions to the atmosphere;
    (iii) Bottoms receivers or sumps;
    (iv) Vessels storing wastewater; or
    (v) Reactor vessels associated with a manufacturing process unit.
    (n) For crude oil, intermediate, or product loading operations for
which the equilibrium vapor-phase concentration of methane is 0.5
volume percent or more, calculate CH4 emissions from loading
operations using product-specific, vapor-phase methane composition data
(from measurement data or process knowledge) and the emission
estimation procedures provided in Section 5.2 of the AP-42:
``Compilation of Air Pollutant Emission Factors, Volume 1: Stationary
Point and Area Sources.'' For loading operations in which the
equilibrium vapor-phase concentration of methane is less than 0.5
volume percent, you may assume zero methane emissions.

Sec.  98.254  Monitoring and QA/QC requirements.

    (a) Fuel flow meters, gas composition monitors, and heating value
monitors associated with stationary combustion sources must follow the
monitoring and QA/QC requirements in Sec.  98.34.
    (b) All flow meters, gas composition monitors, and heating value
monitors that are used to provide data for the GHG emissions
calculations in this subpart for sources other than stationary
combustion sources shall be calibrated according to the procedures in
the applicable methods specified in paragraphs (c) through (e) of this
section, the procedures specified by the manufacturer, or Sec. Sec.
98.3(i). Recalibrate each flow meter either biennially (every two
years) or at the minimum frequency specified by the manufacturer.
Recalibrate each gas composition monitor and heating value monitor
either annually or at the minimum frequency specified by the
manufacturer.
    (c) For flare or sour gas flow meters, operate and maintain the
flow meter using any of the following methods, a method published by a
consensus-based standards organization (e.g., ASTM, API, etc.) or
follow the procedures specified by the flow meter manufacturer. Flow
meters must have a rated accuracy of  5 percent or lower.
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec.
98.7).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by
Turbine Meters (incorporated by reference, see Sec.  98.7).
    (3) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters (incorporated by reference, see Sec.  98.7).
    (4) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles (incorporated by reference, see
Sec.  98.7).
    (5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of
Coriolis Mass Flowmeters (incorporated by reference, see Sec.  98.7).
    (6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore
Precision Orifice Meters (incorporated by reference, see Sec.  98.7).
    (7) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable Area
Meters (incorporated by reference, see Sec.  98.7).
    (8) AGA Report No. 11 Measurement of Natural Gas by Coriolis Meter
(2003) (incorporated by reference, see Sec.  98.7).
    (d) Determine flare gas composition using any of the following
methods.
    (1) Method 18 at 40 CFR part 60, appendix A-6.
    (2) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas
by Gas Chromatography (incorporated by reference, see Sec.  98.7).
    (3) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis
of Reformed Gas by Gas Chromatography (incorporated by reference, see
Sec.  98.7).
    (4) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous
Mixtures by Gas Chromatography (incorporated by reference, see Sec.
98.7).
    (5) UOP539-97 Refinery Gas Analysis by Gas Chromatography
(incorporated by reference, see Sec.  98.7).
    (e) Determine flare gas higher heating value using any of the
following methods.
    (1) ASTM D4809-06 Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method)
(incorporated by reference, see Sec.  98.7).
    (2) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter
(incorporated by reference, see Sec.  98.7).
    (3) ASTM D1826-94 (Reapproved 2003) Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter (incorporated by reference, see Sec.  98.7).

[[Continued on page 56459]]

]

[[pp. 56459-56508]] Mandatory Reporting of Greenhouse Gases

[[Continued from page 56458]]

    (4) ASTM D3588-98 (Reapproved 2003) Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels (incorporated by reference, see Sec.  98.7).
    (5) ASTM D4891-89 (Reapproved 2006) Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion (incorporated by reference, see Sec.  98.7).
    (f) For exhaust gas flow meters used to comply with the
requirements in Sec.  98.253(c)(2)(ii), install, operate, calibrate,
and maintain exhaust gas flow meter according to the requirements in 40
CFR 63.1572(c) or according to the following requirements.
    (1) Locate the flow meter(s) and other necessary equipment such as
straightening vanes in a position that provides representative flow;
reduce swirling flow or abnormal velocity distributions due to upstream
and downstream disturbances.
    (2) Use a flow rate meter with an accuracy within  5
percent.
    (3) Use a continuous monitoring system capable of correcting for
the temperature, pressure, and moisture content to output flow in dry
standard cubic feet (standard conditions as defined in Sec.  98.6).
    (4) Install, operate, and maintain each continuous monitoring
system according to the manufacturer's specifications and requirements.
    (g) For exhaust gas CO2/CO/O2 composition
monitors used to comply with the requirements in Sec.  98.253(c)(2),
install, operate, calibrate, and maintain exhaust gas composition
monitors according to the requirements in 40 CFR 60.105a(b)(2) or 40
CFR 63.1572(a) or according to the manufacturer's specifications and
requirements.
    (h) Determine the mass of petroleum coke as required by Equation Y-
13 of this subpart using mass measurement equipment meeting the
requirements for commercial weighing equipment as described in
Specifications, Tolerances, and Other Technical Requirements For
Weighing and Measuring Devices, NIST Handbook 44 (2009) (incorporated
by reference, see Sec.  98.7). Calibrate the measurement device
according to the procedures specified by the method, the procedures
specified by the manufacturer, or Sec.  98.3(i). Recalibrate either
biennially or at the minimum frequency specified by the manufacturer.
    (i) Determine the carbon content of petroleum coke as required by
Equation Y-13 of this subpart using any one of the following methods.
Calibrate the measurement device according to procedures specified by
the method or procedures specified by the measurement device
manufacturer.
    (1) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate
Analysis of Coal and Coke (incorporated by reference, see Sec.  98.7).
    (2) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants (incorporated by reference, see Sec.
98.7).
    (3) ASTM D5373-08 Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples
of Coal (incorporated by reference, see Sec.  98.7).
    (j) Determine the quantity of petroleum process streams using
company records. These quantities include the quantity of asphalt
blown, quantity of crude oil plus the quantity of intermediate products
received from off site, and the quantity of unstabilized crude oil
received at the facility.
    (k) The owner or operator shall document the procedures used to
ensure the accuracy of the estimates of fuel usage, gas composition,
and 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.
    (l) All CO2 CEMS and flow rate monitors used for direct
measurement of GHG emissions must comply with the QA procedures in
Sec.  98.34(c).

Sec.  98.255  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG
emissions calculations is required (e.g., concentrations, flow rates,
fuel heating values, carbon content values). Therefore, whenever a
quality-assured value of a required parameter is unavailable (e.g., if
a CEMS malfunctions during unit operation or if a required fuel sample
is not taken), a substitute data value for the missing parameter shall
be used in the calculations.
    (a) For stationary combustion sources, use the missing data
procedures in subpart C of this part.
    (b) For each missing value of the heat content, carbon content, or
molecular weight of the fuel, substitute the arithmetic average of the
quality-assured values of that parameter immediately preceding and
immediately following the missing data incident. If the ``after'' value
is not obtained by the end of the reporting year, you may use the
``before'' value for the missing data substitution. 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.
    (c) For missing CO2, CO, O2, CH4,
or N2O concentrations, gas flow rate, and percent moisture,
the substitute data values shall be the best available estimate(s) of
the parameter(s), based on all available process data (e.g., processing
rates, operating hours, etc.). The owner or operator shall document and
keep records of the procedures used for all such estimates.
    (d) For hydrogen plants, use the missing data procedures in subpart
P of this part.

Sec.  98.256   Data reporting requirements.

    In addition to the reporting requirements of Sec.  98.3(c), you
must report the information specified in paragraphs (a) through (q) of
this section.
    (a) For combustion sources, follow the data reporting requirements
under subpart C of this part (General Stationary Fuel Combustion
Sources).
    (b) For hydrogen plants, follow the data reporting requirements
under subpart P of this part (Hydrogen Production).
    (c) [Reserved]
    (d) [Reserved]
    (e) For flares, owners and operators shall report:
    (1) The flare ID number (if applicable).
    (2) A description of the type of flare (steam assisted, air-
assisted).
    (3) A description of the flare service (general facility flare,
unit flare, emergency only or back-up flare).
    (4) The calculated CO2, CH4, and
N2O annual emissions for each flare, expressed in metric
tons of each pollutant emitted.
    (5) A description of the method used to calculate the
CO2 emissions for each flare (e.g., reference section and
equation number).
    (6) If you use Equation Y-1 of this subpart, the annual volume of
flare gas combusted (in scf/year) and the annual average molecular
weight (in kg/kg-mole) and carbon content of the flare gas (in kg
carbon per kg flare gas).
    (7) If you use Equation Y-2 of this subpart, the annual volume of
flare gas combusted (in million (MM) scf/year) and the annual average
higher heating value of the flare gas (in MMBtu per MMscf).
    (8) If you use Equation Y-3 of this subpart, the annual volume of
flare gas combusted (in MMscf/year) during

normal operations, the annual average higher heating value of the flare
gas (in MMBtu/MMscf), the number of SSM events exceeding 500,000 scf/
day, and the volume of gas flared (in scf/event) and the average
molecular weight (in kg/kg-mole) and carbon content of the flare gas
(in kg carbon per kg flare) for each SSM event over 500,000 scf/day.
    (9) The fraction of carbon in the flare gas contributed by methane
used in Equation Y-4 of this subpart and the basis for its value.
    (f) For catalytic cracking units, traditional fluid coking units,
and catalytic reforming units, owners and operators shall report:
    (1) The unit ID number (if applicable).
    (2) A description of the type of unit (fluid catalytic cracking
unit, thermal catalytic cracking unit, traditional fluid coking unit,
or catalytic reforming unit).
    (3) Maximum rated throughput of the unit, in bbl/stream day.
    (4) The calculated CO2, CH4, and
N2O annual emissions for each unit, expressed in metric tons
of each pollutant emitted.
    (5) A description of the method used to calculate the
CO2 emissions for each unit (e.g., reference section and
equation number).
    (6) If you use a CEMS, the relevant information required under
Sec.  98.36(e)(2)(vi) for the Tier 4 Calculation Methodology, the
CO2 annual emissions as measured by the CEMS (unadjusted to
remove CO2 combustion emissions associated with a CO boiler,
if present) and the process CO2 emissions as calculated
according to Sec.  98.253(c)(1)(ii). Report the CO2 annual
emissions associated with fuel combustion under subpart C of this part
(General Stationary Fuel Combustion Sources).
    (7) If you use Equation Y-6 of this subpart, the annual average
exhaust gas flow rate, %CO2, and %CO.
    (8) If you use Equation Y-7 of this subpart, the annual average
flow rate of inlet air and oxygen-enriched air, %O2,
%Ooxy, %CO2, and %CO.
    (9) If you use Equation Y-8 of this subpart, the coke burn-off
factor, annual throughput of unit, and the average carbon content of
coke and the basis for the value.
    (10) Indicate whether you use a measured value, a unit-specific
emission factor, or a default emission factor for CH4
emissions. If you use a unit-specific emission factor for
CH4, report the units of measure for the unit-specific
factor, the activity data for calculating emissions (e.g., if the
emission factor is based on coke burn-off rate, the annual quantity of
coke burned), and the basis for the factor.
    (11) Indicate whether you use a measured value, a unit-specific
emission factor, or a default emission factor for N2O
emissions. If you use a unit-specific emission factor for
N2O, report the units of measure for the unit-specific
factor, the activity data for calculating emissions (e.g., if the
emission factor is based on coke burn-off rate, the annual quantity of
coke burned), and the basis for the factor.
    (12) If you use Equation Y-11 of this subpart, the number of
regeneration cycles during the reporting year, the average coke burn-
off quantity per cycle, and the average carbon content of the coke.
    (g) For fluid coking unit of the flexicoking type, the owner or
operator shall report:
    (1) The unit ID number (if applicable).
    (2) A description of the type of unit.
    (3) Maximum rated throughput of the unit, in bbl/stream day.
    (4) Indicate whether the GHG emissions from the low heat value gas
are accounted for in subpart C of this part or Sec.  98.253(c).
    (5) If the GHG emissions for the low heat value gas are calculated
at the flexicoking unit, also report the calculated annual
CO2, CH4, and N2O emissions for each
unit, expressed in metric tons of each pollutant emitted, and the
applicable equation input parameters specified in paragraphs (f)(7)
through (f)(11) of this section.
    (h) For sulfur recovery plants and for emissions from sour gas sent
off-site for sulfur recovery, the owner and operator shall report:
    (1) The plant ID number (if applicable).
    (2) Maximum rated throughput of each independent sulfur recovery
plant, in metric tons sulfur produced/stream day.
    (3) The calculated CO2 annual emissions for each sulfur
recovery plant, expressed in metric tons. The calculated annual
CO2 emissions from sour gas sent off-site for sulfur
recovery, expressed in metric tons.
    (4) If you use Equation Y-12 of this subpart, the annual volumetric
flow to the sulfur recovery plant (in scf/year) and the annual average
mole fraction of carbon in the sour gas (in kg-mole C/kg-mole gas).
    (5) If you recycle tail gas to the front of the sulfur recovery
plant, indicate whether the recycled flow rate and carbon content are
included in the measured data under Sec.  98.253(f)(2) and (3).
Indicate whether a correction for CO2 emissions in the tail
gas was used in Equation Y-12. If so, then report the value of the
correction, the annual volume of recycled tail gas (in scf/year) and
the annual average mole fraction of carbon in the tail gas (in kg-mole
C/kg-mole gas). Indicate whether you used the default (95%) or a unit
specific correction, and if used, report the approach used.
    (6) If you use a CEMS, the relevant information required under
Sec.  98.36(e)(2)(vi) for the Tier 4 Calculation Methodology, the
CO2 annual emissions as measured by the CEMS and the annual
process CO2 emissions calculated according to Sec.
98.253(f)(1). Report the CO2 annual emissions associated
with fuel combustion subpart C of this part (General Stationary Fuel
Combustion Sources).
    (i) For coke calcining units, the owner and operator shall report:
    (1) The unit ID number (if applicable).
    (2) Maximum rated throughput of the unit, in metric tons coke
calcined/stream day.
    (3) The calculated CO2, CH4, and
N2O annual emissions for each unit, expressed in metric tons
of each pollutant emitted.
    (4) A description of the method used to calculate the
CO2 emissions for each unit (e.g., reference section and
equation number).
    (5) If you use Equation Y-13 of this subpart, annual mass and
carbon content of green coke fed to the unit, the annual mass and
carbon content of marketable coke produced, and the annual mass of coke
dust collected in dust collection systems.
    (6) If you use a CEMS, the relevant information required under
Sec.  98.36(e)(2)(vi) for the Tier 4 Calculation Methodology, the
CO2 annual emissions as measured by the CEMS and the annual
process CO2 emissions calculated according to Sec.
98.253(g)(1). Report the CO2 annual emissions associated
with fuel combustion under subpart C of this part (General Stationary
Fuel Combustion Sources).