§98.33(b)(1)(v), Tier 1 may be used regardless of unit size when
natural gas is transported through the common pipe, if the annual fuel
consumption is obtained from gas billing records in units of therms.
When the common pipe reporting option is selected, Tthe following
information shall be reported instead of the information in paragraph
(b) of this section:

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

(ii)  The identification numbers of the units served by the common pipe.

(iii)  The highest mMaximum rated heat input capacity of eachany unit
served by the common pipe (mmBtu/hr).

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

(v)  The methodology used to calculate the CO2 mass emissions (i.e.,
Tier 1, Tier 2, or Tier 3).

(vi)  If the any of the units burns both fossil fuels and biomass, the
annual CO2 mass emissions from combustion of all fossil fuels and annual
CO2 emissions from combustion of all biomass fuels from the units served
by the common pipe, expressed in metric tons.

(vii)  Annual CO2, mass emissions and annual CH4 and N2O emissions from
each fuel type for the units served by the common pipe, expressed in
metric tons of each gas and in metric tons of CO2e.

(viii)  Methodology start date

(ix)  Methodology end date

(viii)  Annual GHG emissions from all fossil fuels burned in units
served by the common pipe (i.e., the sum of the CO2, CH4, and N2O
emissions), expressed in metric tons of CO2e.

(4)  The following alternative reporting option applies to situations
where a common liquid or gaseous fuel supply is shared between one or
more large combustion units, such as boilers or combustion turbines
(including units subject to subpart D of this part); and small
combustion sources on-site, including but not limited to space heaters
and hot water heaters.  In this case, you may simplify reporting by
attributing all of the GHG emissions from combustion of the shared fuel
to the large combustion unit(s), provided that:

(i)  The total quantity of the fuel combusted during the report year in
the units sharing the fuel supply is measured, either at the “gate”
to the facility  or at a point inside the facility, using a fuel flow
meter, billing meter, or tank drop measurements (as applicable);

(ii)  On an annual basis, at least 95 percent (by mass or volume) of the
shared fuel is combusted in the large combustion unit(s), and the
remainder is combusted in the small combustion sources.  Company records
may be used to determine the percentage distribution of the shared fuel
to the large and small units; and

(iii)  The use of this reporting option is documented in the Monitoring
Plan required under §98.3(g)(5).   Indicate in the Monitoring Plan
which units share the common fuel supply and the method used to
demonstrate that this alternative reporting option applies.  For the
small combustion sources on-site, a description of the types of units
and the approximate number of units is sufficient.

(d)  Units subject to 40 CFR part 75 of this chapter.

(1)  For stationary combustion units that are either subject to the Acid
Rain Program or not in the Acid Rain Program but monitor and report CO2
mass emissions year-round according to 40 CFR part 75 subject to subpart
D of this part, you shall report the following unit-level information:

(i)  Unit or stack identification numbers.  Use exact same unit, common
stack, common pipe, or multiple stack identification numbers that
represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.)
that are reported under §75.64 of this chapter.

(ii)  Annual CO2 emissions at each monitored location, expressed in both
short tons and metric tons.  Reporting of biogenic CO2 emissions under
§98.3(c)(4)(ii) and §98.3(c)(4)(iii)(A) is optional.  Subpart D units
are not required to report biogenic CO2 emissions under
§§98.3(c)(4)(ii) and (c)(4)(iii)(A).

(iiiii)  Annual CO2, CH4, and N2O emissions at each monitored location,
for each fuel type listed in Table C-2 that was combusted during the
year (except as otherwise provided in §98.33(c)(4)(ii)(B)), expressed
in metric tons of CO2e.

(iv)  The total heat input from each fuel listed in Table C-2 that was
combusted during the year (except as otherwise provided in
§98.33(c)(4)(ii)(B)), expressed in mmBtu.

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

(vi)  Methodology start date.

(vii)  Methodology end date.

(viii)  Acid Rain Program indicator.

(ix)  Annual CO2 mass emissions from the combustion of biomass,
expressed in metric tons of CO2e (optional).

(2)  For units that use the alternative CO2 mass emissions calculation
methods for units with continuous monitoring systems provided in
§98.33(a)(5), you shall report the following unit-level information:

(i)  Unit, stack, or pipe ID numbers.  Use exact same unit, common
stack, common pipe, or multiple stack identification numbers that
represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.)
that are reported under §75.64 of this chapter.

(ii)  For units that use the alternative methods specified in
§98.33(a)(5)(i) and (ii) to monitor and report heat input data
year-round according to appendix D to 40 CFR part 75 of this chapter or
40 CFR §75.19 of this chapter:

(A)  Each type of fuel combusted in the unit during the reporting year.

(B)  The methodology used to calculate the CO2 mass emissions for each
fuel type.

(C)  Methodology start date.

(D)  Methodology end date.

(EC)  A code or flag to indicate whether heat input is calculated
according to appendix D to 40 CFR part 75 of this chapter or 40 CFR
§75.19 of this chapter.

(DF)  Annual CO2, CH4, and N2O emissions at each monitored location,
across all fuel types, expressed in metric tons of CO2e.

(G)  Annual heat input from each type of fuel listed in Table C-2 of
this subpart that was combusted during the reporting year, expressed in
mmBtu.

(H)  Annual CH4 and N2O emisions at each monitored location, from each
fuel type listed in Table C-2 of this subpart that was combusted during
the reporting year (except as otherwise provided in
§98.33(c)(4)(ii)(D)), expressed in metric tons CO2e.

(I)  Annual CO2 mass emissions from the combustion of biomass, expressed
in metric tons CO2e (optional).

(iii)  For units with continuous monitoring systems that use the
alternative method for units with continuous monitoring systems in
§98.33(a)(5)(iii) to monitor heat input year-round according to 40 CFR
part 75 of this chapter:

(A)  Each type of Ffuel combusted during the reporting year.

(B)  Methodology used to calculate the CO2 mass emissions.

(C)  Methodology start date.

(D)  Methodology end date.

(EC)  A code or flag to indicate that the heat input data is derived
from CEMS measurements.

(FD)  The total annual CO2, CH4, and N2O emissions at each monitored
location, expressed in metric tons of CO2e.

(G)  Annual heat input from each type of fuel listed in Table C-2 of
this subpart that was combusted during the reporting year, expressed in
mmBtu.

(H)  Annual CH4 and N2O emisions at each monitored location, from each
fuel type listed in Table C-2 of this subpart that was combusted during
the reporting year (except as otherwise provided in
§98.33(c)(4)(ii)(B)), expressed in metric tons CO2e.

(I)  Annual CO2 mass emissions from the combustion of biomass, expressed
in metric tons CO2e (optional).

(e)  Verification data.  You must keep on file, in a format suitable for
inspection and auditing, sufficient data to verify the reported GHG
emissions.  This data and information must, where indicated in this
paragraph (e), be included in the annual GHG emissions report.

(1)  The applicable verification data specified in this paragraph (e)
are not required to be kept on file or reported for units that meet any
one of the three following conditions:

(i)  Are subject to the Acid Rain Program.

(ii)  Use the alternative methods for units with continuous monitoring
systems provided in §98.33(a)(5).

(iii)  Are not in the Acid Rain Program, but are required to monitor and
report CO2 mass emissions and heat input data year-round, in accordance
with 40 CFR part 75 of this chapter.

(2)  For stationary combustion sources using the Tier 1, Tier 2, Tier 3,
and Tier 4 Calculation Methodologies in §98.33(a) to quantify CO2
emissions, the following additional information shall be kept on file
and included in the GHG emissions report, where indicated:

(i)  For the Tier 1 Calculation Methodology, report the total quantity
of each type of fuel combusted in the unit or group of aggregated units
(as applicable) during the reporting year, in short tons for solid
fuels, gallons for liquid fuels and standard cubic feet or, if
applicable, therms for gaseous fuels.

(ii)  For the Tier 2 Calculation Methodology, report:

(A)  The total quantity of each type of fuel combusted in the unit or
group of aggregated units (as applicable) during each month of the
reporting year.  Express the quantity of each fuel combusted during the
measurement period in  short tons for solid fuels, gallons for liquid
fuels, and scf for gaseous fuels.

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

(C)  The high heat values used in the CO2 emissions calculations for
each type of fuel combusted during the reporting year, in mmBtu per
short ton for solid fuels, mmBtu per gallon for liquid fuels, and mmBtu
per scf for gaseous fuels.  Report a HHV value for each calendar month
in which HHV determination is required.  If multiple values are obtained
in a given month, report the arithmetic average value for the month.
Specify the date on which each fuel sample was taken. Indicate whether
each reported HHV is a measured value ofor a substitute data value.

(D)  If Equation C-2c of this subpart is used to calculate CO2 mass
emissions, report the total quantity (i.e., pounds) of steam produced
from MSW or solid fuel combustion during each month of the reporting
year, and the ratio of the maximum rate heat input capacity to the
design rated steam output capacity of the unit, in mmBtu per lb of
steam.

(iii)  For the Tier 2 Calculation Methodology, keep records of the
methods used to determine the HHV for each type of fuel combusted and
the date on which each fuel sample was taken, except where fuel sampling
data are received from the fuel supplier.  In that case, keep records of
the dates on which the results of the fuel analyses for HHV are
received.

(iv)  For the Tier 3 Calculation Methodology, report:

(A)  The quantity of each type of fuel combusted in the unit or group of
units (as applicable) during each month of the reporting year, in short
tons for solid fuels, gallons for liquid fuels, and scf for gaseous
fuels.

(B)  The frequency of carbon content and, if applicable, molecular
weight determinations for each type of fuel for the reporting year
(e.g., daily, weekly, monthly, semiannually, once per fuel lot).

(C)  The carbon content and, if applicable, gas molecular weight values
used in the emission calculations (including both valid and substitute
data values).  For each calendar month of the reporting year in which
carbon content and, if applicable, molecular weight determination is
required, report a value of each parameter.  If multiple values of a
parameter are obtained in a given month, report the arithmetic average
value for the month.Report all measured values if the fuel is sampled
monthly or less frequently.  Otherwise, for daily and weekly sampling,
report monthly average values determined using the calculation
procedures in Equation C-2b for each variable.  Express carbon content
as a decimal fraction for solid fuels, kg C per gallon for liquid fuels,
and kg C per kg of fuel for gaseous fuels.  Express the gas molecular
weights in units of kg per kg-mole.

(D)  The total number of valid carbon content determinations and, if
applicable, molecular weight determinations made during the reporting
year, for each fuel type.

(E)  The number of substitute data values used for carbon content and,
if applicable, molecular weight used in the annual GHG emissions
calculations.

(F)  The annual average HHV, when measured HHV data, rather than a
default HHV from Table C-1 of this subpart, are used to calculate CH4
and N2O emissions for a Tier 3 unit, in accordance with §98.33(c)(1).

(v)  For the Tier 3 Calculation Methodology, keep records of the
following:

(A)  For liquid and gaseous fuel combustion, the dates and results of
the initial calibrations and periodic recalibrations of the required
fuel flow meters.

(B)  For fuel oil combustion, the method from §98.34(b) used to make
tank drop measurements (if applicable).

(C)  The methods used to determine the carbon content for each type of
fuel combusted.

(D)  The methods used to calibrate the fuel flow meters).

(E)  The date on which each fuel sample was taken, except where fuel
sampling data are received from the fuel supplier.  In that case, keep
records of the dates on which the results of the fuel analyses for
carbon content and (if applicable) molecular weight are received.

(vi)  For the Tier 4 Calculation Methodology, report:

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

(B)  The cumulative CO2 mass emissions in each quarter of the reporting
year, i.e., the sum of the hourly values calculated from Equation C-6 or
C-7 of this subpart (as applicable), in metric tons.

(C)  For CO2 concentration, stack gas flow rate, and (if applicable)
stack gas moisture content, the percentage of source operating hours in
which a substitute data value of each parameter was used in the
emissions calculations.

(vii)  For the Tier 4 Calculation Methodology, keep records of:

(A)  Whether the CEMS certification and quality assurance procedures of
40 CFR part 75 of this chapter, 40 CFR part 60 of this chapter, or an
applicable State continuous monitoring program were used.

(B)  The dates and results of the initial certification tests of the
CEMS.

(C)  The dates and results of the major quality assurance tests
performed on the CEMS during the reporting year, i.e., linearity checks,
cylinder gas audits, and relative accuracy test audits (RATAs).

(viii)  If CO2 emissions that are generated from acid gas scrubbing with
sorbent injection are not captured using CEMS, report:

(A)  The total amount of sorbent used during the report year, in short
tons.

(B)  The molecular weight of the sorbent.

(C)  The ratio (“R”) in Equation C-11 of this subpart.

(ix)  For units that combust both fossil fuel and biomass, when CEMS are
used to quantify the annual CO2 emissions and biogenic CO2 is determined
according to §98.33(e)(2), you shall report the following additional
information, as applicable:

(A)   The annual volume of CO2 emitted from the combustion of all fuels,
i.e., Vtotal, in scf.

(B)  The annual volume of CO2 emitted from the combustion of fossil
fuels, i.e., Vff, in scf.  If more than one type of fossil fuel was
combusted, report the combustion volume of CO2 for each fuel separately
as well as the total.

(C)  The annual volume of CO2 emitted from the combustion of biomass,
i.e., Vbio, in scf.

(D)  The carbon-based F-factor used in Equation C-13 of this subpart,
for each type of fossil fuel combusted, in scf CO2 per mmBtu.

(E)  The annual average HHV value used in Equation C-13 of this subpart,
for each type of fossil fuel combusted, in Btu/lb, Btu/gal, or Btu/scf,
as appropriate.

(F)  The total quantity of each type of fossil fuel combusted during the
reporting year, in lb, gallons, or scf, as appropriate.

(G)  Annual biogenic CO2 mass emissions, in metric tons.

(x)  When ASTM methods D7459-08 and D6866-08 are used to determine the
biogenic portion of the annual CO2 emissions from MSW combustion, as
described in §98.34(d), report:

(A)  The results of each quarterly sample analysis, expressed as a
decimal fraction (e.g., if the biogenic fraction of the CO2 emissions
from MSW combustion is 30 percent, report 0.30).

(B)  Annual combined biomass and fossil fuel  CO2 emissions from MSW
combustion, in metric tons of CO2e.

(C)  The quantities Vff, Vtotal, and VMSW from §98.33(e)(4)(ii), if
CEMS are used to measure CO2 emissions.

(BD)  The annual volume of biogenic CO2 mass emissions from MSW
combustion, in metric tons.

(xi)  When ASTM methods D7459-08 and D6866-08 are used in accordance
with §98.34(e) to determine the biogenic portion of the annual CO2
emissions from a unit that co-fires biogenic fuels (or partly-biogenic
fuels, including tires if you are electing to report biogenic CO2
emissions from tire combustion) (other than MSW) and non-biogenic fuels,
you shall report the results of each quarterly sample analysis,
expressed as a decimal fraction (e.g., if the biogenic fraction of the
CO2 emissions is 30 percent, report 0.30).

(3)  Within 30 days of receipt of a written request from the
Administrator, you shall submit explanations of the following:

(i)  An explanation of how company records are used to quantify fuel
consumption, if the Tier 1 or Tier 2 Calculation Methodology is used to
calculate CO2 emissions.

(ii)  An explanation of how company records are used to quantify fuel
consumption, if solid fuel is combusted and the Tier 3 Calculation
Methodology is used to calculate CO2 emissions.

(iii)  An explanation of how sorbent usage is quantified.

(iv)  An explanation of how company records are used to quantify fossil
fuel consumption in units that uses CEMS to quantify CO2 emissions and
combusts both fossil fuel and biomass.

(v)  An explanation of how company records are used to measure steam
production, when it is used to calculate CO2 mass emissions under
§98.33(a)(2)(iii) or to quantify solid fuel usage under §98.33(c)(3).

(4)  Within 30 days of receipt of a written request from the
Administrator, you shall submit the verification data and information
described in paragraphs (e)(2)(iii), (e)(2)(v), and (e)(2)(vii) of this
section.

§98.37  Records That Must be Retained.

In addition to the requirements of §98.3(g), you must retain the
applicable records specified in §§98.34(f) and (g), 98.35(b), and
98.36(e).

§98.38  Definitions.

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

Table C-1 toof Subpart C—Default CO2 Emission Factors and High Heat
Values for Various Types of Fuel

Fuel Type	Default High Heat Value	Default CO2 Emission Factor

Coal and coke	mmBtu/short ton	kg CO2 /mmBtu

Anthracite	25.09	103.54

Bituminous	24.93	93.40

Subbituminous	17.25	97.02

Lignite	14.21	96.36

Coke	24.80	102.04

Mixed (Commercial sector)	21.39	95.26

Mixed (Industrial coking)	26.28	93.65

Mixed (Industrial sector)	22.35	93.91

Mixed (Electric Power sector)	19.73	94.38

Natural gas	mmBtu/scf	kg CO2 /mmBtu

Pipeline (Weighted U.S. Average)	1.028 x 10-3	53.02

Petroleum products	mmBtu/gallon	kg CO2 /mmBtu

Distillate Fuel Oil No. 1	0.139	73.25

Distillate Fuel Oil No. 2	0.138	73.96

Distillate Fuel Oil No. 4	0.146	75.04

Residual Fuel Oil No. 5	0.140	72.93

Residual Fuel Oil No. 6	0.150	75.10

Waste OilStill Gas	0.1350.143	74.0066.72

Kerosene	0.135	75.20

Liquefied petroleum gases (LPG)	0.092	62.98

Propane	0.091	61.46

Propylene	0.091	65.95

Ethane	0.096	62.64

Ethanol  	0.084	68.44

Ethylene	0.100	67.43

Isobutane	0.097	64.91

Isobutylene	0.103	67.74

Butane	0.101	65.15

Butylene	0.103	67.73

Naphtha (<401 deg F)	0.125	68.02

Natural Gasoline	0.110	66.83

Other Oil (>401 deg F)	0.139	76.22

Pentanes Plus	0.110	70.02

Petrochemical Feedstocks	0.129	70.97

Petroleum Coke	0.143	102.41

Special Naphtha	0.125	72.34

Unfinished Oils	0.139	74.49

Heavy Gas Oils	0.148	74.92

Lubricants	0.144	74.27

Motor Gasoline	0.125	70.22

Aviation Gasoline	0.120	69.25

Kerosene-Type Jet Fuel	0.135	72.22

Asphalt and Road Oil	0.158	75.36

Crude Oil	0.138	74.49

Fossil Fuel-derived Other fuels (solid)	mmBtu/short ton	kg CO2 /mmBtu

Municipal Solid Waste1	9.951	90.7

Tires	26.87	85.97

Plastics	38.00	75.00

Petroleum Coke	30.00	102.41

Fossil Fuel-derived Other fuels (gaseous)	mmBtu/scf	kg CO2 /mmBtu

Blast Furnace Gas	0.092 x 10-3	274.32

Coke Oven Gas	0.599 x 10-3	46.85

Propane Gas	2.516 x 10-3	61.46

Fuel Gas2	1.388 x 10-3	59.00

Biomass fuels - solid	mmBtu/short Tton	kg CO2 /mmBtu

Wood and Wood Residuals	15.38	93.80

Agricultural Byproducts	8.25	118.17

Peat	8.00	111.84

Solid Byproducts	25.83	105.51

Biomass fuels - gaseous	mmBtu/scf	kg CO2 /mmBtu

Biogas (Captured methane)	0.841 x 10-3	52.07

Biomass fuels - liquid	mmBtu/gallon	kg CO2 /mmBtu

Ethanol (100%) 	0.084	68.44

Biodiesel (100%) 	0.128	73.84

Rendered Animal Fat 	0.125	71.06

Vegetable Oil 	0.120	81.55

1 Use of this default HHV is Aallowed only for units that combust MSW,
do not generate steam, and are allowed to use Tier 1.

2 Reporters subject to subpart X of this part that are complying with
§98.243(d) or subpart Y of this part may only use the default HHV and
the default CO2 emission factor for fuel gas combustion under the
conditions prescribed in §98.243(d)(2)(i) and (d)(2)(ii) and
§98.252(a)(1) and (a)(2), respectively. Otherwise, Tier 3 (Equation
C-5) or Tier 4 must be used.

Table C-2 of Subpart C—Default CH4 and N2O Emission Factors for
Various Types of Fuel.

Fuel Type	Default CH4 Emission Factor (kg CH4 /mmBtu)	Default N2O
Emission Factor (kg N2O/mmBtu)

Coal and Coke (All fuel types in Table C-1)	1.1 x 10-2	1.6 x 10-03

Natural Gas	1.0 x 10-03	1.0 x 10-04

Petroleum (All fuel types in Table C-1)	3.0 x 10-03	6.0 x 10-04

Municipal Solid Waste 	3.2 x 10-02	4.2 x 10-03

Tires	3.2 x 10-02	4.2 x 10-03

Blast Furnace Gas	2.2 x 10-05	1.0 x 10-04

Coke Oven Gas	4.8 x 10-04	1.0 x 10-04

Biomass Fuels - Solid (All fuel types in Table C-1)	3.2 x 10-02	4.2 x
10-03

Biogas	3.2 x 10-03	6.3 x 10-04

Biomass Fuels – Liquid (All fuel types in Table C-1)	1.1 x 10-03	1.1 x
10-04

Note:  Those employing this table are assumed to fall under the IPCC
definitions of the “Energy Industry” or “Manufacturing Industries
and Construction”.  In all fuels except for coal the values for these
two categories are identical.  For coal combustion, those who fall
within the IPCC “Energy Industry” category may employ a value of 1 g
of CH4/MMBtu.

1Allowed only for units that do not generate steam and use Tier 1.

Table C-2 toof Subpart C—Default CH4 and N2O Emission Factors for
Various Types of Fuel.

Fuel Type	Default CH4 Emission Factor (kg CH4 /mmBtu)	Default N2O
Emission Factor (kg N2O/mmBtu)

Coal and Coke (All fuel types in Table C-1)	1.1 x 10-02	1.6 x 10--0303

Natural Gas	1.0 x 10-03	1.0 x 10--0404

Petroleum (All fuel types in Table C-1)	3.0 x 10-03	6.0 x 10--0404

Municipal Solid Waste 	3.2 x 10-02	4.2 x 10--0303

Tires	3.2 x 10-02	4.2 x 10--0303

Blast Furnace Gas	2.2 x 10-05	1.0 x 10--0404

Coke Oven Gas	4.8 x 10-04	1.0 x 10--0404

Biomass Fuels - Solid (All fuel types in Table C-1)	3.2 x 10-02	4.2 x
10--0303

Biogas	3.2 x 10-03	6.3 x 10--0404

Biomass Fuels – Liquid (All fuel types in Table C-1)	1.1 x 10-03	1.1 x
10--0404

Note:  Those employing this table are assumed to fall under the IPCC
definitions of the “Energy Industry” or “Manufacturing Industries
and Construction”.  In all fuels except for coal the values for these
two categories are identical.  For coal combustion, those who fall
within the IPCC “Energy Industry” category may employ a value of 1 g
of CH4/MMBtu.

Subpart D—Electricity Generation

§98.40  Definition of the source category.

(a)  The electricity generation source category comprises electricity
generating units that are subject to the requirements of the Acid Rain
Program and any other electricity generating units that are required to
monitor and report to EPA CO2 mass emissions year-round according to 40
CFR part 75.

(b)  This source category does not include portable equipment, emergency
equipment, or emergency generators, as defined in §98.6.

§98.41  Reporting threshold.

You must report GHG emissions under this subpart if your facility
contains one or more electricity generating units and the facility meets
the requirements of §98.2(a)(1).

§98.42  GHGs to report.

(a)  For each electricity generating unit that is subject to the
requirements of the Acid Rain Program or is otherwise required to
monitor and report to EPA CO2 emissions year-round according to 40 CFR
part 75, you must report under this subpart the annual mass emissions of
CO2, N2O, and CH4 by following the requirements of this subpart.

(b)  For each electricity generating unit that is not subject to the
Acid Rain Program or otherwise required to monitor and report to EPA CO2
emissions year-round according to 40 CFR part 75, you must report under
subpart C of this part (General Stationary Fuel Combustion Sources) the
emissions of CO2, CH4, and N2O by following the requirements of subpart
C.

(c)  For each stationary fuel combustion unit that does not generate
electricity, you must report under subpart C of this part (General
Stationary Fuel Combustion Sources) the emissions of CO2, CH4, and N2O
by following the requirements of subpart C of this part.

§98.43  Calculating GHG emissions.

Continue to monitor and report CO2 mass emissions as required under
§75.13 or section 2.3 of apppendix G to 40 CFR part 75, and §75.64.
Calculate CO2, CH4, and N2O emissions as follows:

(a)  Convert the cumulative annual CO2 mass emissions reported in the
fourth quarter electronic data report required under §75.64 from units
of short tons to metric tons.  To convert tons to metric tons, divide by
1.1023.

(b)  Calculate and report annual CH4 and N2O mass emissions under this
subpart by following the applicable method specified in §98.33(c).

§98.44  Monitoring and QA/QC requirements

Follow the applicable quality assurance procedures for CO2 emissions in
appendices B, D, and G to 40 CFR part 75.

§98.45  Procedures for estimating missing data.

Follow the applicable missing data substitution procedures in 40 CFR
part 75 for CO2 concentration, stack gas flow rate, fuel flow rate, high
heating value, and fuel carbon content.

§98.46  Data reporting requirements.

The annual report shall comply with the data reporting requirements
specified in §98.36(d)(1)(b) and, if applicable, §98.36(c)(2) or
(c)(3).

§98.47  Records that must be retained.

You shall comply with the recordkeeping requirements of §§98.3(g) and
98.37.  Records retained under §75.57(h) of this chapter for missing
data events satisfy the recordkeeping requirements of §98.3(g)(4) for
those same events.

§98.48  Definitions.

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

Subpart F—Aluminum Production

§98.60  Definition of the source category.

(a)  A primary aluminum production facility manufactures primary
aluminum using the Hall-Héroult manufacturing process.  The primary
aluminum manufacturing process comprises the following operations:

(1)  Electrolysis in prebake and Søderberg cells.

(2)  Anode baking for prebake cells.

(b)  This source category does not include experimental cells or
research and development process units.

§98.61  Reporting threshold.

You must report GHG emissions under this subpart if your facility
contains an aluminum production process and the facility meets the
requirements of either §98.2(a)(1) or (a)(2).

§98.62  GHGs to report.

You must report:

(a)  Perfluoromethane (CF4), and perfluoroethane (C2F6) emissions from
anode effects in all prebake and Søderberg electrolysis cells.

(b)  CO2 emissions from anode consumption during electrolysis in all
prebake and Søderberg electrolysis cells.

(c)  CO2 emissions from on-site anode baking.

(d)  You must report under subpart C of this part (General Stationary
Fuel Combustion Sources) the emissions of CO2, N2O, and CH4 emissions
from each stationary fuel combustion unit by following the requirements
of subpart C.

§98.63  Calculating GHG emissions.

(a)  The annual value of each PFC compound (CF4, C2F6)for PFC emissions
shall be estimated from the sum of monthly values using Equation F-1 of
this section:

 	(Eq. F-1)

Where:

EPFC	=	Annual emissions of each PFC compoundPFC emissions from aluminum
production (metric tons PFC).

Em	=	Emissions of the individual PFC compound PFC emissions from
aluminum production for the month “m” (metric tons PFC).

(b)  Use Equation F-2 of this section to estimate CF4 emissions from
anode effect duration or Equation F-3 of this section to estimate CF4
emissions from overvoltage, and use Equation F-4 of this section to
estimate C2F6 emissions from anode effects from each prebake and
Søderberg electrolysis cell.

	ECF4 = SCF4 × AEM × MP × 0.001	(Eq. F-2)

Where:

ECF4	=	Monthly CF4 emissions from aluminum production (metric tons CF4).

SCF4	=	The slope coefficient ((kg CF4/metric ton
Al)/(AE-Mins/cell-day)).

AEM	=	The anode effect minutes per cell-day (AE-Mins/cell-day).

MP	=	Metal production (metric tons Al), 	where AEM and MP are calculated
monthly.

	ECF4 = EFCF4 × MP × 0.001	(Eq. F-3)

Where:

ECF4	=	Monthly CF4 emissions from aluminum production (metric tons CF4).

EFCF4	=	The overvoltage emission factor (kg CF4/metric ton Al).

MP	=	Metal production (metric tons Al), where MP is calculated monthly.

	EC2F6 = ECF4 × FC2F6/CF4 × 0.001	(Eq. F-4)

Where:

EC2F6	=	Monthly C2F6 emissions from aluminum production (metric tons
C2F6).

ECF4	=	CF4 emissions from aluminum production(kg CF4).

FC2F6/CF4	=	The weight fraction of C2F6/CF4 (kg C2F6/kg CF4).

0.001	=	Conversion factor from kg to metric tons, where ECF4 is
calculated monthly.

(c)  You must calculate and report the annual process CO2 emissions from
anode consumption during electrolysis and anode baking of prebake cells
using either the procedures in paragraph (d) of this section, or the
procedures in paragraphs (e) and (f) of this section, or the procedures
in paragraph (g) of this section.

(d)  Calculate and report under this subpart the process CO2 emissions
by operating and maintaining CEMS according to the Tier 4 Calculation
Methodology in §98.33(a)(4) and all associated requirements for Tier 4
in subpart C of this part (General Stationary Fuel Combustion Sources).

(e)  Use the following procedures to calculate CO2 emissions from anode
consumption during electrolysis:

(1)  For Prebake cells: you must calculate CO2 emissions from anode
consumption using Equation F-5 of this section:

ECO2 = NAC × MP ×([100 – Sa– Asha] / 100) × (44/12)	(Eq. F-5)

Where:

ECO2	=	Annual CO2 emissions from prebaked anode consumption (metric tons
CO2).

NAC	=	Net annual prebaked anode consumption per metric ton Al (metric
tons C/metric tons Al).

MP	=	Annual metal production (metric tons Al).

Sa	=	Sulfur content in baked anode (percent weight).

Asha	=	Ash content in baked anode(percent weight).

44/12	=	Ratio of molecular weights, CO2 to carbon.

(2)  For Søderberg cells you must calculate CO2 emissions using
Equation F-6 of this section:

ECO2 = (PC × MP – [CSM × MP] / 1000 – BC / 100 × PC ×

MP × [Sp + Ashp + Hp] / 100 – [100 - BC] / 100 × PC × MP ×

	[Sc + Ashc] / 100 – MP × CD) × (44/12)	(Eq. F-6)

Where:

ECO2	=	Annual CO2 emissions from paste consumption (metric ton CO2).

PC	=	Annual paste consumption (metric ton/metric ton Al).

MP	=	Annual metal production (metric ton Al).

CSM	=	Annual emissions of cyclohexane soluble matter (kg/metric ton Al).

BC	=	Binder content of paste (percent weight).

Sp	=	Sulfur content of pitch (percent weight).

Ashp	=	Ash content of pitch (percent weight).

Hp 	=	Hydrogen content of pitch (percent weight).

Sc 	=	Sulfur content in calcined coke (percent weight).

Ashc	=	Ash content in calcined coke (percent weight).

CD	=	Carbon in skimmed dust from Søderberg cells (metric ton C/metric
ton Al).

44/12	=	Ratio of molecular weights, CO2 to carbon.

(f)  Use the following procedures to calculate CO2 emissions from anode
baking of prebake cells:

(1)  Use Equation F-7 of this section to calculate emissions from pitch
volatiles combustion.

	ECO2PV = (GA – Hw – BA – WT) × (44/12)	(Eq. F-7)

Where:

ECO2PV	=	Annual CO2 emissions from pitch volatiles combustion (metric
tons CO2).

GA	=	Initial weight of green anodes (metric tons).

Hw	=	Annual hydrogen content in green anodes (metric tons).

BA	=	Annual baked anode production (metric tons).

WT	=	Annual waste tar collected (metric tons).

44/12	=	Ratio of molecular weights, CO2 to carbon.

(2)  Use Equation F-8 of this section to calculate emissions from bake
furnace packing material.

ECO2PC = 	PCC × BA × ([100 – Spc – Ashpc] / 100) × (44/12)	(Eq.
F-8)

Where:

ECO2PC	=	Annual CO2 emissions from bake furnace packing material (metric
tons CO2).

PCC	=	Annual packing coke consumption (metric tons/metric ton baked
anode).

BA	=	Annual baked anode production (metric tons).

Spc	=	Sulfur content in packing coke (percent weight).

Ashpc	=	Ash content in packing coke (percent weight).

44/12	=	Ratio of molecular weights, CO2 to carbon.

(g)  If process CO2 emissions from anode consumption during electrolysis
or anode baking of prebake cells are vented through the same stack as
any combustion unit or process equipment that reports CO2 emissions
using a CEMS that complies with the Tier 4 Calculation Methodology in
subpart C of this part (General Stationary Fuel Combustion Sources),
then the calculation methodology in paragraphs (d) and (e) of this
section shall not be used to calculate those process emissions.  The
owner or operation shall report under this subpart the combined stack
emissions according to the Tier 4 Calculation Methodology in
§98.33(a)(4) and all associated requirements for Tier 4 in subpart C of
this part (General Stationary Fuel Combustion Sources).

§98.64  Monitoring and QA/QC requirements.

(a)  Effective one year after publication of the rule for smelters with
no prior measurement or effective three years after publication for
facilities with historic measurements, the smelter-specific slope
coefficients, overvoltage emission factors, and wieight fractions used
in Equations F-2, F-3, and F-4 of this subpart must be measured in
accordance with the recommendations of the EPA/IAI Protocol for
Measurement of Tetrafluoromethane (CF4) and Hexafluoroethane (C2F6)
Emissions from Primary Aluminum Production (2008), except the minimum
frequency of measurement shall be every 10 years unless a change occurs
in the control algorithm that affects the mix of types of anode effects
or the nature of the anode effect termination routine.  Facilities which
operate at less than 0.2 anode effect minutes per cell day or operate
with less than 1.4mV anode effect overvoltage can use either
smelter-specific slope coefficients or the technology specific default
values in Table F-1 of this subpart.

(b)  The minimum frequency of the measurement and analysis is annually
except as follows: Monthly – anode effect minutes per cell day (or
anode effect overvoltage and current efficiency), production

(i)  Monthly for anode effect minutes per cell day (or anode effect
overvoltage and current efficiency).

(ii)  Monthly for aluminum production.

(iii)  Smelter-specific slope coefficients, overvoltage emission
factors, and weight fractions according to paragraph (a) of this
section.

(c)  Sources may use either smelter-specific values from annual
measurements of parameters needed to complete the equations in §98.63
(e.g., sulfur, ash, and hydrogen contents) or the default values shown
in Table F-2 of this subpart.

§98.65  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 (e.g., if a meter malfunctions
during unit operation or if a required sample measurement is not taken),
a substitute data value for the missing parameter shall be used in the
calculations, according to the following requirements:

(a)  Where anode or paste consumption data are missing, CO2 emissions
can be estimated from aluminum production using Tier 1 methodper
Equation F-8 of this section.

	ECO2 = EFp x MPp + EFs x MPs	(Eq. F-8)

Where:

ECO2	=	CO2 emissions from anode and/or paste consumption, metric tons
CO2.

EFp	=	Prebake technology specific emission factor (1.6 metric tons
CO2/metric ton aluminum produced).

MPp	=	Metal production from prebake process (metric tons Al).

EFs	=	Søderberg technology specific emission factor (1.7 metric tons
CO2/metric ton Al produced).

MPs	=	Metal production from Søderberg process (metric tons Al).

(b)  For other parameters, use the average of the two most recent data
points after the missing data.

§98.66  Data reporting requirements.

In addition to the information required by §98.3(c), you must report
the following information at the facility level:

(a)  Annual aluminum production in metric tons.

(b)  Type of smelter technology used.

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

(1)  Perfluoromethane emissions and perfluoroethane emissions from anode
effects in all prebake and all Søderberg electrolysis cells combined.

(2)  Anode effect minutes per cell-day (AE-mins/cell-day), anode effect
frequency (AE/cell-day), anode effect duration (minutes). (Or anode
effect overvoltage factor ((kg CF4/metric ton Al)/(mV/cell day)),
potline overvoltage (mV/cell day), current efficiency (%).)

(3)  Smelter-specific slope coefficients (or overvoltage emission
factors) and the last date when the smelter-specific-slope coefficients
(or overvoltage emission factors) were measured.

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

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

(1)  Annual anode consumption.

(2)  Annual CO2 emissions from the smelter.

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

(1)  Annual paste consumption.

(2)  Annual CO2 emissions from the smelter.

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

(h)  Exact data elements required will vary depending on smelter
technology (e.g., point-feed prebake or Søderberg) and process control
technology (e.g., Pechiney or other).

§98.67  Records that must be retained.

In addition to the information required by §98.3(g),  you must retain
the following records:

(a)  Monthly aluminum production in metric tons.

(b)  Type of smelter technology used.

(c)  The following PFC-specific information on a monthly basis:

(1)  Perfluoromethane and perfluoroethane emissions from anode effects
in prebake and Søderberg electrolysis cells.

(2)  Anode effect minutes per cell-day (AE-mins/cell-day), anode effect
frequency (AE/cell-day), anode effect duration (minutes). (Or anode
effect overvoltage factor ((kg CF4/metric ton Al)/(mV/cell day)),
potline overvoltage (mV/cell day), current efficiency (%).))

(3)  Smelter-specific slope coefficients and the last date when the
smelter-specific-slope coefficients were measured.

(d)  Method used to measure the frequency and duration of anode effects
(or to measure anode effect overvoltage and current efficiency).

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

(1)  Annual anode consumption.

(2)  Annual CO2 emissions from the smelter.

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

(1)  Annual paste consumption.

(2)  Annual CO2 emissions from the smelter.

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

(h)  Exact data elements required will vary depending on smelter
technology (e.g., point-feed prebake or Søderberg) and process control
technology (e.g., Pechiney or other).

§98.68  Definitions.

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

Table F-1 to Subpart F—Slope and Overvoltage Coefficients for the
Calculation of PFC Emissions from Aluminum Production

Technology	CF4 Slope Coefficient

[(kg CF4/metric ton Al)/(AE-Mins/cell-day)]	CF4 Overvoltage Coefficient

[(kg CF4/metric ton Al)/(mV)]	Weight Fraction C2F6/CF4

[(kg C2F6/kg CF4)]

Center Worked Prebake (CWPB)	0.143	1.16	0.121

Side Worked Prebake (SWPB)	0.272	3.65	0.252

Vertical Stud Søderberg (VSS)	0.092	NA	0.053

Horizontal Stud Søderberg (HSS)	0.099	NA	0.085

Table F-2 to Subpart F—Default Data Sources for Parameters Used for
CO2 Emissions

CO2 Emissions from Prebake Cells (CWPB and SWPB)

Parameter	Data Source

MP:  metal production (metric tons Al)	Individual facility records

NAC:  net annual prebaked anode consumption per metric ton Al (metric
tons C/metric tons Al)	Individual facility records

Sa: sulfur content in baked anode (percent weight)	2.0

Asha:  ash content in baked anode(percent weight)	0.4

CO2 Emissions from Søderberg Cells (VSS and HSS)

Parameter	Data Source

MP:  metal production (metric tons Al)	Individual facility records

PC:  annual paste consumption (metric ton/metric ton Al)	Individual
facility records

CSM: annual emissions of cyclohexane soluble matter (kg/metric ton Al)
HSS:  4.0

VSS:  0.5

BC:  binder content of paste (percent weight)	Dry Paste:  24

Wet Paste:  27

Sp:  sulfur content of pitch (percent weight)	0.6

Ashp:  ash content of pitch (percent weight)	0.2

Hp:  hydrogen content of pitch (percent weight)	3.3

Sc:  sulfur content in calcined coke (percent weight)	1.9

Ashc:  ash content in calcined coke (percent weight)	0.2

CD:  carbon in skimmed dust from Søderberg cells (metric ton C/metric
ton Al)	0.01

CO2 Emissions from Pitch Volatiles Combustion (VSS and HSSCWPB and SWPB)

Parameter	Data Source

GA:  initial weight of green anodes (metric tons)	Individual facility
records

Hw:  annual hydrogen content in green anodes (metric tons)	0.005 × GA

BA:  annual baked anode production (metric tons)	Individual facility
records

WT:  annual waste tar collected (metric tons)

(a)  Riedhammer furnaces

(b)  all other furnaces	(a)  0.005 × GA

(b)  insignificant

CO2 Emissions from Bake Furnace Packing Materials (CWPB and SWPB)

Parameter	Data Source

PCC:  annual packing coke consumption (metric tons/metric ton baked
anode)	0.015

BA:  annual baked anode production (metric tons)	Individual facility
records

Spc:  sulfur content in packing coke (percent weight)	2

Ashpc: ash content in packing coke (percent weight)	2.5

Subpart G—Ammonia Manufacturing

§98.70  Definition of Source Category.

The ammonia manufacturing source category comprises the process units
listed in paragraphs (a) and (b) of this section.

(a)  Ammonia manufacturing processes in which ammonia is manufactured
from a fossil-based feedstock produced via steam reforming of a
hydrocarbon.

(b)  Ammonia manufacturing processes in which ammonia is manufactured
through the gasification of solid and liquid raw material.

§98.71  Reporting threshold.

You must report GHG emissions under this subpart if your facility
contains an ammonia manufacturing process and the facility meets the
requirements of either §98.2(a)(1) or (2).

§98.72  GHGs to report.

You must report:

(a)  CO2 process emissions from steam reforming of a hydrocarbon or the
gasification of solid and liquid raw material, reported for each ammonia
manufacturing process unit following the requirements in of this subpart
(CO2 process emissions reported under this subpart may include CO2 that
is later consumed on-site for urea production, and therefore is not
released to the ambient air from the ammonia manufacturing process
unit).

(b)  CO2, CH4, and N2O emissions from each stationary fuel combustion
unit.  You must report these emissions under subpart C of this part
(General Stationary Fuel Combustion Sources), by following the
requirements of subpart C, except that for ammonia manufacturing
processes subpart C does not apply to any CO2 resulting from combustion
of the waste recycle stream (commonly referred to as the purge gas
stream).

(c)  CO2 emissions collected and transferred off site under subpart PP
(Suppliers of CO2), following the requirements of subpart PP.

§98.73  Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each
ammonia manufacturing process unit using the procedures in either
paragraph (a) or (b) of this section.

(a)  Calculate and report under this subpart the process CO2 emissions
by operating and maintaining CEMS according to the Tier 4 Calculation
Methodology specified in §98.33(a)(4) and all associated requirements
for Tier 4 in subpart C of this part (General Stationary Fuel Combustion
Sources).

(b)   Calculate and report under this subpart process CO2 emissions
using the procedures in paragraphs (b)(1) through (b)(65) of this
section for gaseous feedstock, liquid feedstock, or solid feedstock, as
applicable.

(1)  Gaseous feedstock.  You must calculate, from each ammonia
manufacturing unit, the CO2 process emissions from gaseous feedstock
according to Equation G-1 of this section:

 	(Eq. G-1)

Where:

CO2,G,k	=	Annual CO2 emissions arising from gaseous feedstock
consumption (metric tons).

Fdstkn	=	Volume of the gaseous feedstock used in month n (scf of
feedstock).

CCn	=	Carbon content of the gaseous feedstock, for month n, (kg C per kg
of feedstock), determined according to 98.74(c).

MW	=	Molecular weight of the gaseous feedstock (kg/kg-mole).

MVC 	=	Molar volume conversion factor (849.5 scf per kg-mole at standard
conditions).

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.001	=	Conversion factor from kg to metric tons.

k	=	Processing unit.

n	=	Number of month

(2)  Liquid feedstock.  You must calculate, from each ammonia
manufacturing unit, the CO2 process emissions from liquid feedstock
according to Equation G-2 of this section:

 	(Eq. G-2)

Where:

CO2,L,k 	=	Annual CO2 emissions arising from liquid feedstock
consumption (metric tons).

Fdstkn 	=	Volume of the liquid feedstock used in month n (gallons of
feedstock).

CCn 	=	Carbon content of the liquid feedstock, for month n, (kg C per
gallon of feedstock) determined according to 98.74(c).

44/12 	=	Ratio of molecular weights, CO2 to carbon.

0.001 	=	Conversion factor from kg to metric tons.

k	=	Processing unit.

n	=	Number of month

(3)  Solid feedstock.  You must calculate, from each ammonia
manufacturing unit, the CO2 process emissions from solid feedstock
according to Equation G-3 of this section:

 	(Eq. G-3)

Where:

CO2,S,k 	=	Annual CO2 emissions arising from solid feedstock consumption
(metric tons).

Fdstkn	=	Mass of the solid feedstock used in month n (kg of feedstock).

CCn 	=	Carbon content of the solid feedstock, for month n, (kg C per kg
of feedstock), determined according to 98.74(c).

44/12 	=	Ratio of molecular weights, CO2 to carbon.

0.001 	=	Conversion factor from kg to metric tons.

K	=	Processing unit.

n	=	Number of month.

(4)  You must calculate the annual process CO2 emissions from each
ammonia processing unit k at your facility summing emissions, as
applicable from Equation G-1, G-2, and G-3 of this section using
Equation G-4.

  CO2,G + CO2,S + CO2,L 	(Eq. G-4)

Where:

ECO2k	=	Annual CO2 emissions from each ammonia processing unit k (metric
tons).

k	=		Processing unit.

(5)  You must determine the combined CO2 emissions from all ammonia
processing units at your facility using Equation G-5 of this section.

 	(Eq. G-5)

Where:

CO2	=	Annual combined CO2 emissions from all ammonia processing units
(metric tons) (CO2 process emissions reported under this subpart may
include CO2 that is later consumed on-site for urea production, and
therefore is not released to the ambient air from the ammonia
manufacturing process unit(s)).

ECO2k	=	Annual CO2 emissions from each ammonia processing unit (metric
tons).

k	=		Processing unit.

n	=	Total number of ammonia processing units.

(6)  If applicable, ammonia manufacturing facilities that utilize the
waste recycle stream as a fuel must calculate emissions associated with
the waste stream for each ammonia process unit according to Equation G-6
of this section:

 	(Eq. G-6)

Where:

CO2	=	Annual CO2 contained in waste recycle stream (metric tons).

RecycleStreamn	=	Volume of the waste recycle stream in month n (scf).

CCn	=	Carbon content of the waste recycle stream, for month n, (kg C per
kg of waste recycle stream) determined according to 98.74(f).

MW	=	Molecular weight of the waste recycle stream (kg/kg-mole).

MVC 	=	Molar volume conversion factor (849.5 scf per kg-mole at standard
conditions).

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.001	=	Conversion factor from kg to metric tons.

n	=	Number of month

(c)  If GHG emissions from an ammonia manufacturing unit are vented
through the same stack as any combustion unit or process equipment that
reports CO2 emissions using a CEMS that complies with the Tier 4
Calculation Methodology in subpart C of this part (General Stationary
Fuel Combustion Sources), then the calculation methodology in paragraph
(b) of this section shall not be used to calculate process emissions.
The owner or operator shall report under this subpart the combined stack
emissions according to the Tier 4 Calculation Methodology in
§98.33(a)(4) and all associated requirements for Tier 4 in subpart C of
this part.

§98.74  Monitoring and QA/QC requirements.

(a)  You must continuously measure the quantity of gaseous or liquid
feedstock consumed using a flow meter.  The quantity of solid feedstock
consumed can be obtained from company records and aggregated on a
monthly basis.

(b)  You must document the procedures used to ensure the accuracy of the
estimates of feedstock consumption.

(c)  You must determine monthly carbon contents and the average
molecular weight of each feedstock consumed from reports from your
supplier. As an alternative to using supplier information on carbon
contents, you can also collect a sample of each feedstock on a monthly
basis and analyze the carbon content and molecular weight of the fuel
using any of the following methods listed in paragraphs (c)(1) through
(c)(8) of this section, as applicable.

(1)  ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by reference, see §98.7).

(2)  ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of
Reformed Gas by Gas Chromatography (incorporated by reference, see
§98.7).

(3)  ASTM D2502-04 (Reapproved 2002) Standard Test Method for Estimation
of Mean Relative Molecular Mass of Petroleum Oils from Viscosity
Measurements (incorporated by reference, see §98.7).

(4)  ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative
Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric
Measurement of Vapor Pressure (incorporated by reference, see §98.7).

(5)  ASTM D3238-95 (Reapproved 2005) Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of
Petroleum Oils by the n-d-M Method (incorporated by reference, see
§98.7).

(6)  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
§98.7).

(7)  ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate
Analysis of Coal and Coke (incorporated by reference, see §98.7).

(8)  ASTM D5373-08 Standard Methods for Instrumental Determination of
Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal
(incorporated by reference, see §98.7).

(d) Calibrate all oil and gas flow meters that are used to measure
liquid and gaseous feedstock volumes and flow rates (except for gas
billing meters) and perform oil tank measurements according to the
monitoring and QA/QC requirements for the Tier 3 methodology in
§98.34(b)(1).  Perform oil tank drop measurements (if used to quantify
feedstock volumes) according to §98.34(b)(2).

(e)  For quality assurance and quality control of the supplier data, on
an annual basis, you must measure the carbon contents of a
representative sample of the feedstocks consumed using the appropriate
ASTM Method as listed in  paragraphs (c)(1) through (c)(8) of this
section.

(f)  [Reserved]Facilities must continuously measure the quantity of
waste gas recycled using a flow meter, as applicable.  You must
determine the carbon content and the molecular weight of the waste
recycle stream by collecting a sample of each waste recycle stream on a
monthly basis and analyzing the carbon content using the appropriate
ASTM Method as listed in paragraphs (c)(1) through (c)(8) of this
section.

(g)  If CO2 from ammonia production is used to produce urea at the same
facility, you must determine the quantity of urea produced using methods
or plant instruments used for accounting purposes (such as sales
records).  You must document the procedures used to ensure the accuracy
of the estimates of urea produced.

§98.75  Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions
calculations is required.  Therefore, whenever the monitoring and
quality assurance procedures in §98.74 cannot be followed  (e.g., if a
meter malfunctions during unit operation), a substitute data value for
the missing parameter shall be used in the calculations following
paragraphs (a) and (b) of this section. You must document and keep
records of the procedures used for all such estimates.

(a)  For missing data on monthly carbon contents of feedstock or the
waste recycle stream, the substitute data value shall be the arithmetic
average of the quality-assured values of that carbon content in the
month preceding and the month immediately following the missing data
incident. If no quality-assured data are available prior to the missing
data incident, the substitute data value shall be the first
quality-assured value for carbon content obtained in the month after the
missing data period.

(b)  For missing feedstock supply rates or waste recycle stream used to
determine monthly feedstock consumption or monthly waste recycle stream
quantity, you must determine the best available estimate(s) of the
parameter(s), based on all available process data.

§98.76  Data reporting requirements.

In addition to the information required by §98.3(c), each annual report
must contain the information specified in paragraphs (a) and (b) of this
section, as applicable for each ammonia manufacturing process unit.

(a)  If a CEMS is used to measure CO2 emissions, then you must report
the relevant information required under §98.367(e)(2)(vi) for the Tier
4 Calculation Methodology and the following information in this
paragraph (a):

(1)  Annual quantity of each type of feedstock consumed for ammonia
manufacturing (scf of feedstock or gallons of feedstock or kg of
feedstock).

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

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

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

(2)  Monthly quantity of each type of feedstock consumed for ammonia
manufacturing for each ammonia processing unit (scf of feedstock or
gallons of feedstock or kg of feedstock).

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

(4)  Whether carbon content for each feedstock for month n is based on
reports from the supplier or analysis of carbon content.

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

(6)  Sampling analysis results of carbon content of petroleum
cokefeedstock as determined for QA/QC of supplier data under §98.74(e).

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

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

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

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

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

(12)  Annual CO2 emissions associated with the waste recycle stream for
each ammonia process unit (metric tons)

(13)  Carbon content of the waste recycle stream for month n for each
ammonia process unit (kg C per kg of waste recycle stream).

(14)  Volume of the waste recycle stream for month n for each ammonia
process unit (scf)

(15)  Method used for analyzing carbon content of waste recycle stream.

(1216)  Annual urea production (metric tons) and method used to
determine urea production.

(13)  CO2 from the steam reforming of a hydrocarbon or the gasification
of solid and liquid raw material at the ammonia manufacturing process
unit used to produce urea and the method used to determine the CO2
consumed in urea production.

(17)  Uses of urea produced, if known, such as but not limited to
fertilizer, animal feed, manufacturing of plastics or resins, and
pollution control technologies.

(c)  Total pounds of synthetic fertilizer produced through and total
nitrogen contained in that fertilizer.

§98.77  Records that must be retained.

In addition to the records required by §98.3(g), you must retain the
following records specified in paragraphs (a) and (b) of this section
for each ammonia manufacturing unit.

(a)  If a CEMS is used to measure emissions, retain records of all
feedstock purchases in addition to the requirements in §98.37 for the
Tier 4 Calculation Methodology.

(b)  If a CEMS is not used to measure process CO2 emissions, you must
also retain the records specified in paragraphs (b)(1) through (b)(2) of
this section:

(1)  Records of all analyses and calculations conducted for reported
data as listed in §98.76(b).

(2)  Monthly records of carbon content of feedstock from supplier and/or
all analyses conducted of carbon content.

§98.78  Definitions.

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

Subpart P—Hydrogen Production

§98.160  Definition of the source category.

(a)  A hydrogen production source category consists of facilities that
produce hydrogen gas sold as a product to other entities.

(b)  This source category comprises process units that produce hydrogen
by reforming, gasification, oxidation, reaction, or other
transformations of feedstocks.

(c)  This source category includes merchant hydrogen production
facilities located within a petroleum refinery if they are not owned by,
or under the direct control of, the refinery owner and operator.

§98.161  Reporting threshold.

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

§98.162  GHGs to report.

You must report:

(a)  CO2 process emissions from each hydrogen production process unit.

(b)  CO2, CH4 and N2O combustion emissions from each hydrogen production
process unit.  You must calculate and report these combustion emissions
under  subpart C of this part (General Stationary Fuel Combustion
Sources) by following the requirements of subpart C.

(c)  CO2, CH4, and N2O emissions from each stationary combustion unit
other than hydrogen production process units.  You must calculate and
report these emissions under subpart C of this part (General Stationary
Fuel Combustion Sources) by following the requirements of subpart C.

(d)  For CO2 collected and transferred off site, you must follow the
requirements of subpart PP of this part.

§98.163  Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each
hydrogen production process unit using the procedures specified in
either paragraph (a) or (b) of this section.

(a)  Continuous Emissions Montoring Systems (CEMS). Calculate and report
under this subpart the process CO2 emissions by operating and
maintaining CEMS according to the Tier 4 Calculation Methodology
specified in §98.33(a)(4) and all associated requirements for Tier 4 in
subpart C of this part (General Stationary Fuel Combustion Sources).

(b)  Fuel and feedstock material balance approach. Calculate and report
process CO2 emissions as the sum of the annual emissions associated with
each fuel and feedstock used for hydrogen production by following
paragraphs (b)(1) through (b)(3) of this section.

(1)  Gaseous fuel and feedstock.  You must calculate the annual CO2
process emissions from gaseous fuel and feedstock according to Equation
P-1 of this section:

 	(Eq. P-1)

Where:

CO2 	=	Annual CO2 process emissions arising from fuel and feedstock
consumption (metric tons/yr).

Fdstkn 	=	Volume of the gaseous fuel and feedstock used in month n (scf
(at standard conditions of 68 °F and atmospheric pressure) of fuel and
feedstock).

CCn 	=	Average carbon content of the gaseous fuel and feedstock, from
the results of one or more analyses for month n (kg carbon per kg of
fuel and feedstock).

MW	=	Molecular weight of the gaseous fuel and feedstock (kg/kg-mole).

MVC 	=	Molar volume conversion factor (849.5 scf per kg-mole at standard
conditions).

k 	=	Months in the year.

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.001	=	Conversion factor from kg to metric tons.

(2)  Liquid fuel and feedstock.  You must calculate the annual CO2
process emissions from liquid fuel and feedstock according to Equation
P-2 of this section:

  	(Eq. P-2)

Where:

CO2 	=	Annual CO2 emissions arising from fuel and feedstock consumption
(metric tons/yr).

Fdstkn	=	Volume of the liquid fuel and feedstock used in month n
(gallons of fuel and feedstock).

CCn 	=	Average carbon content of the liquid fuel and feedstock, from the
results of one or more analyses for month n (kg carbon per gallon of
fuel and feedstock).

k 	=	Months in the year.

44/12 	=	Ratio of molecular weights, CO2 to carbon.

0.001 	=	Conversion factor from kg to metric tons.

(3)  Solid fuel and feedstock.  You must calculate the annual CO2
process emissions from solid fuel and feedstock according to Equation
P-3 of this section:

 	(Eq.P-3)

Where:

CO2 	=	Annual CO2 emissions from fuel and feedstock consumption in
metric tons per month (metric tons/yr).

Fdstkn	=	Mass of solid fuel and feedstock used in month n (kg of fuel
and feedstock).

CCn 	=	Average carbon content of the solid fuel and feedstock, from the
results of one or more analyses for month n (kg carbon per kg of fuel
and feedstock).

k 	=	Months in the year.

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.001	=	Conversion factor from kg to metric tons.

(c)  If GHG emissions from a hydrogen production process unit are vented
through the same stack as any combustion unit or process equipment that
reports CO2 emissions using a CEMS that complies with the Tier 4
Calculation Methodology in subpart C of this part (General Stationary
Fuel Combustion Sources), then the calculation methodology in paragraph
(b) of this section shall not be used to calculate process emissions.
The owner or operator shall report under this subpart the combined stack
emissions according to the Tier 4 Calculation Methodology in
§98.33(a)(4) and all associated requirements for Tier 4 in subpart C of
this part (General Stationary Fuel Combustion Sources).

§98.164  Monitoring and QA/QC requirements.

The GHG emissions data for hydrogen production process units must be
quality-assured as specified in paragraphs (a) or (b) of this section,
as appropriate for each process unit:

(a)  If a CEMS is used to measure GHG emissions, then the facility must
comply with the monitoring and QA/QC procedures specified in §98.34(c).

(b)  If a CEMS is not used to measure GHG emissions, then you must:

(1)  Calibrate all oil and gas flow meters that are used to measure
liquid and gaseous feedstock volumes (except for gas billing meters),
solids weighing equipment, and oil tank drop measurements (if used to
determine liquid fuel and feedstock use volume) according to
thecalibration accuracy requirements in §98.3(i) of this part
monitoring and QA/QC requirements for the Tier 3 methodology in
§98.34(b)(1).  Perform oil tank drop measurements (if used to quantify
liquid fuel or feedstock consumption) according to §98.34(b)(2).
Calibrate all solids weighing equipment according to the procedures in
§98.3(i).

(2)  Determine the carbon content and the molecular weight annually of
standard gaseous hydrocarbon fuels and feedstocks having consistent
composition (e.g., natural gas). For other gaseous fuels and feedstocks
(e.g., biogas, refinery gas, or process gas), weekly sampling and
analysis is required to determine the carbon content and molecular
weight of the fuel and feedstock.

(3)  Determine the carbon content of fuel oil, naphtha, and other liquid
fuels and feedstocks at least monthly, except annually for standard
liquid hydrocarbon fuels and feedstocks having consistent composition,
or upon delivery for liquid fuels delivered by bulk transport (e.g., by
truck or rail).

(4)  Determine the carbon content of coal, coke, and other solid fuels
and feedstocks at least monthly, except annually for standard solid
hydrocarbon fuels and feedstocks having consistent composition, or upon
delivery for solid fuels delivered by bulk transport (e.g., by truck or
rail).

(5)  You must use the following applicable methods to determine the
carbon content for all fuels and feedstocks, and molecular weight of
gaseous fuels and feedstocks.

(i)  ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by reference, see §98.7).

(ii)  ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of
Reformed Gas by Gas Chromatography (incorporated by reference, see
§98.7).

(iii)  ASTM D2013-07 Standard Practice of Preparing Coal Samples for
Analysis (incorporated by reference, see §98.7).

(iv)  ASTM D2234/D2234M-07 Standard Practice for Collection of a Gross
Sample of Coal (incorporated by reference, see §98.7).

(v)  ASTM D2597-94 (Reapproved 2004) Standard Test Method for Analysis
of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and
Carbon Dioxide by Gas Chromatography (incorporated by reference, see
§98.7).

(vi)  ASTM D3176-89 (Reapproved 2002), Standard Practice for Ultimate
Analysis of Coal and Coke (incorporated by reference, see §98.7).

(vii)  ASTM D3238-95 (Reapproved 2005), Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of
Petroleum Oils by the n-d-M Method (incorporated by reference, see
§98.7).

(viii)  ASTM D4057-06 Standard Practice for Manual Sampling of Petroleum
and Petroleum Products (incorporated by reference, see §98.7).

(ix)  ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic
Sampling of Petroleum and Petroleum Products (incorporated by reference,
see §98.7).

(x)  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
§98.7).

(xi)  ASTM D5373-08 Standard Test Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal
(incorporated by reference, see §98.7).

(xii)  ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal
(incorporated by reference, see §98.7).

(xiii)  ASTM D6883-04 Standard Practice for Manual Sampling of
Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles
(incorporated by reference, see §98.7).

(xiv)  ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of
Coal (incorporated by reference, see §98.7).

(xv)  ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography
(incorporated by reference, see §98.7).

(xvi)  GPA 2261–00 Analysis for Natural Gas and Similar Gaseous
Mixtures by Gas Chromatography (incorporated by reference, see §98.7).

(xvii)  ISO 3170: Petroleum Liquids -- Manual sampling – Third Edition
(incorporated by reference, see §98.7).

(xviii)  ISO 3171: Petroleum Liquids -- Automatic pipeline sampling –
Second Edition (incorporated by reference, see §98.7).

(c)  For units using the calculation methodologies described in this
section, the records required under §98.3(g) must include both the
company records and a detailed explanation of how company records are
used to estimate the following:

(1)  Fuel and feedstock consumption, when solid fuel and feedstock is
combusted and a CEMS is not used to measure GHG emissions.

(2)  Fossil fuel consumption, when, pursuant to §98.33(e), the owner or
operator of a unit that uses CEMS to quantify CO2 emissions and that
combusts both fossil and biogenic fuels separately reports the biogenic
portion of the total annual CO2 emissions.

(3)  Sorbent usage, if the methodology in §98.33(d) is used to
calculate CO2 emissions from sorbent.

(d)  The owner or operator must document the procedures used to ensure
the accuracy of the estimates of fuel and feedstock usage and sorbent
usage (as applicable) in paragraph (b) of this section, including, but
not limited to, calibration of weighing equipment, fuel and feedstock
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.

§98.165  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 (e.g., if a meter malfunctions
during unit operation), a substitute data value for the missing
parameter must be used in the calculations as specified in paragraphs
(a), (b), and (c) of this section:

(a)  For each missing value of the monthly fuel and feedstock
consumption, the substitute data value must be the best available
estimate of the fuel and feedstock consumption, based on all available
process data (e.g., hydrogen production, electrical load, and operating
hours).  You must document and keep records of the procedures used for
all such estimates.

(b)  For each missing value of the carbon content or molecular weight of
the fuel and feedstock, the substitute data value must be the arithmetic
average of the quality-assured values of carbon contents or molecular
weight of the fuel and feedstock immediately preceding and immediately
following the missing data incident. If no quality-assured data on
carbon contents or molecular weight of the fuel and feedstock are
available prior to the missing data incident, the substitute data value
must be the first quality-assured value for carbon contents or molecular
weight of the fuel and feedstock obtained after the missing data period.
 You must document and keep records of the procedures used for all such
estimates.

(c)  For missing CEMS data, you must use the missing data procedures in
§98.35.

§98.166  Data reporting requirements.

In addition to the information required by §98.3(c), each annual report
must contain the information specified in paragraphs (a) or (b) of this
section, as appropriate:

(a)  If a CEMS is used to measure CO2 emissions, then you must report
the relevant information required under §98.36 for the Tier 4
Calculation Methodology and the following information in this paragraph
(a):

(1)  Unit identification number and annual CO2 process emissions.

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

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

(b)  If a CEMS is not used to measure CO2 emissions, then you must
report the following information for each hydrogen production process
unit:

(1)  Unit identification number and annual CO2 process emissions.

(2)  Monthly consumption of each fuel and feedstock used for hydrogen
production and its type (scf of gaseous fuels and feedstocks, gallons of
liquid fuels and feedstocks, kg of solid fuels and feedstocks).

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

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

(5)  Monthly analyses of carbon content for each fuel and feedstock used
in hydrogen production (kg carbon/kg of gaseous and solid fuels and
feedstocks, (kg carbon per gallon of liquid fuels and feedstocks).

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

(c)  Quarterly quantity of CO2 collected and transferred off site in
either gas, liquid, or solid forms (kg), following the requirements of
subpart PP of this part.

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

§98.167  Records that must be retained.

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

(a)  If a CEMS is used to measure CO2 emissions, then you must retain
under this subpart the records required for the Tier 4 Calculation
Methodology in §98.37.

(b)  If a CEMS is not used to measure CO2 emissions, then you must
retain records of all analyses and calculations conducted as listed in
§§98.166(b), (c), and (d).

§98.168  Definitions.

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

Subpart V—Nitric Acid Production

§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.

§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 §98.2(a)(1) or (a)(2).

§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.

§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 §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:

 	(Eq. V-1)

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).

1.14x10-7=	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.

 	(Eq. V-2)

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:

 	(Eq. V-3)

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:

 	(Eq. V-4)

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.

§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 §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 §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.

§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 §98.224
(a) through (d).

§98.226  Data reporting requirements.

In addition to the information required by §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 §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 §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.

§98.227  Records that must be retained.

In addition to the information required by §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.

§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 X—Petrochemical Production

§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 (fg) 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.

(g)  A process that solely distills or recycles waste solvent that
contains a petrochemical is not part of the petrochemical production
source category.

§98.241  Reporting threshold.

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

§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 §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.  If you comply with §98.243(b), also report under this
subpart the measured CO2 emissions from process vents routed to stacks
that are not associated with stationary combustion units.

(2)  If you comply with §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 §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 §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.

§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 N20 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, and either the
default high heat value for fuel gas in Table C-1 of subpart C of this
part or a calculated HHV, as allowed in Equation C-8 of subpart C of
this part).  For each flare, calculate CO2, CH4, and N2O emissions using
the methodology specified in §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 §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
§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
§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 §98.244(b)(4).  Alternatively, you may use the results of
analyses conducted by a fuel or feedstock supplier, provided the
sampling and analysis is conducted at least once per month using any of
the procedures specified in §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.

	(Eq. X-1)

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 68 °F and 14.7 pounds per square inch absolute or 836.6
scf/kg-mole at 60 °F and 14.7 pounds per square inch absolute).

(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.

 	(Eq. X-2)

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.

 	(Eq. X-3)

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.

 	(Eq. X-4)

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 each ethylene production process, calculate CO2 GHG emissions
from each combustion of unit that burns fuel that contains any off-gas
from the ethylene process as specified in paragraphs (d)(1) through
(d)(5) of this section.

(1)  Except as specified in paragraphs (d)(2) and (d)(5) of this
section, calculate CO2 emissions off-gas using the Tier 3 or Tier 4
methodology in subpart C of this part.,

(2)  You may use either Equation C-1 or Equation C-2a in subpart C of
this part to calculate CO2 emissions from combustion of any ethylene
process off-gas streams that meet either of the conditions in paragraphs
(d)(2)(i) or (d)(2)(ii) of this section (for any default values in the
calculation, use the defaults for fuel gas in Table C-1 of subpart C of
this part).  Follow the otherwise applicable procedures in subpart C to
calculate emissions from combustion of all other fuels in the combustion
unit.

(i)  The annual average flow rate of fuel gas (that contains ethylene
process off-gas) in the fuel gas line to the combustion unit, prior to
any split to individual burners or ports, does not exceed 345 standard
cubic feet per minute at 60°F and 14.7 pounds per square inch absolute,
and a flow meter is not installed at any point in the line supplying
fuel gas or an upstream common pipe. Calculate the annual average flow
rate using company records assuming total flow is evenly distributed
over 525,600 minutes per year.

(ii)  The combustion unit has a maximum rated heat input capacity of
less than 30 MMBtu/hr, and a flow meter is not installed at any point in
the line supplying fuel gas (that contains ethylene process off-gas) or
an upstream common pipe.

(3)  Except as specified in paragraph (d)(5) of this section, and
calculate CH4 and N2O emissions using the applicable procedures in
§98.33(c) for the same tier methodology that you used for calculating
CO2 emissions.

(i)  For all gaseous fuels that contain ethylene process off-gas, use
the emission factors for “Petroleum” in Table C-2 of subpart C of
this part (General Stationary Fuel Combustion Sources).

(ii)  For Tier 3, use either the default high heat value for fuel gas in
Table C-1 of subpart C of this part or a calculated HHV, as allowed in
Equation C-8 of subpart C of this part.

(4)  You are not required to use the same Tier for each stationary
combustion unit that burns ethylene process off-gas.

(5)  For each flare, calculate CO2, CH4, and N2O emissions using the
methodology specified in §98.253(b)(1) through (b)(3).

§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 §98.34(c).

(b)  If you use the mass balance methodology in §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, and calibrate 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 §98.7) or follow procedures specified
by the measurement device manufacturer.  You must Calibrate the
measurement device according to the procedures specified by the method,
the procedures specified by the manufacturer, or §98.3(i).
Rrecalibrate each weighing device at one of the following frequencies.
You may recalibrate either biennially (i.e., once every two years) or or
at the minimum frequency specified by the manufacturer.

(2)  Operate and maintain all flow meters used for gas and liquid
feedstocks and products according to the manufacturer’s recommended
procedures.  You must calibrate each of these flow meters according to
one of the following.  You may use either by following the procedures in
§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 an industry consensus standard method or  published by a
consensus-based standards organization (e.g., ASTM, API, etc.), or
follow procedures methods specified by the flow meter manufacturer or
§98.3(i).  Each flow meter must meet the applicable accuracy
specification in §98.3(i), except as otherwise specified in
§98.3(i)(4) through (i)(6).  RYou must recalibrate each flow meter
according to one of the following frequencies.  You may recalibrate
either biennially or, at the minimum frequency specified by the
manufacturer, or at the interval specified by the industry consensus
standard practice used.

(i)  ASME MFC–3M–2004 Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi (incorporated by reference, see §98.7).

(ii)  ASME MFC–4M–1986 (Reaffirmed 1997) Measurement of Gas Flow by
Turbine Meters (incorporated by reference, see §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 §98.7).

(iv)  ASME MFC–6M–1998 Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters (incorporated by reference, see §98.7).

(v)  ASME MFC–7M–1987 (Reaffirmed 1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles (incorporated by reference, see
§98.7).

(vi)  ASME MFC–9M–1988 (Reaffirmed 2001) Measurement of Liquid Flow
in Closed Conduits by Weighing Method (incorporated by reference, see
§98.7).

(vii)  ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis
Mass Flowmeters (incorporated by reference, see §98.7).

(viii)  ASME MFC-14M-2003 (Reaffirmed 2008), Measurement of Fluid Flow
Using Small Bore Precision Orifice Meters (incorporated by reference,
see §98.7).

(ix)  ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits
with Electromagnetic Flowmeters (incorporated by reference, see §98.7).

(x)  ASME MFC-18M-2001 (Reaffirmed 2006), Measurement of Fluid Flow
Using Variable Area Meters (incorporated by reference, see §98.7).

(xi)  ASME MFC-22-2007 Measurement of Liquid by Turbine Flowmeters
(incorporated by reference, see §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 §98.7).

(xiii)  AGA Transmission Measurement Committee Report No. 7:
Measurement of Natural Gas by Turbine Meter (2006)/February
(incorporated by reference, see §98.7).

(xiv)  AGA Report No. 11: Measurement of Natural Gas by Coriolis Meter
(2003) (incorporated by reference, see §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 §98.7).

(3)  You must pPerform tank level measurements (if used to determine
feedstock or product flows) according to one of the following methods.
You may use any standard method published by a consensus-based standards
organization (e.g., ASTM, API, etc.) or you may use industry standard
practice.or follow procedures specified by the measurement device
manufacturer or §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 §98.3(i).

(4)  Use any of the applicable standard methods specified in paragraphs
(b)(4)(i) through (b)(4)(xiii) 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)(xiii), 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)(xiii) of this section
may be performed by the owner or operator, by an independent 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 §98.7).

(ii)  ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling of
Process Vents With a Portable Gas Chromatograph (incorporated by
reference, see §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 §98.7).

(iv)  ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography
(incorporated by reference, see §98.7).

(v)  ASTM D3176-89 (Reapproved 2002) Standard Practice Method for
Ultimate Analysis of Coal and Coke (incorporated by reference, see
§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
§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 §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.

(xi)  ASTM D2593-93 (Reapproved 2009) Standard Test Method for Butadiene
Purity and Hydrocarbon Impurities by Gas Chromatography, (incorporated
by reference, see §98.7), effective as of January 1, 2010.

(xii)  An industry standard practice for carbon black feedstock oils and
carbon black products, effective as of January 1, 2010.

(xiii)  Modifications of existing analytical methods or other analytical
methods that are applicable to your process provided that the methods
listed in §98.244(b)(4)(i) through §98.244(b)(4)(xii) are not
appropriate because the relevant compounds cannot be detected, the
quality control requirements are not technically feasible, or use of the
method would be unsafe, effective as of January 1, 2010.

§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 §98.35.

§98.246  Data reporting requirements.

In addition to the information required by §98.3(c), each annual report
must contain the information specified in paragraphs (a), (b), or (c) of
this section, as appropriate for each process unit.

(a)  If you use the mass balance methodology in §98.243(c), you must
report the information specified in paragraphs (a)(1) through
(a)(10)(11) 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, and the temperture (in °F) at which the gaseous feedstock and
product volumes used in Equation X-1 of this subpart were determined.
Indicate whether you used the alternative to sampling and analysis
specified in §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 §98.244 used to determine a measured
parameter (or description of manufacturer’s recommended method).

(7)  [Reserved]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 §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 annual mass of carbon content of
hydrocarbons released in fugitive emissions and in process vents that
are not controlled with a combustion device.  These values may be
estimated based on engineering analyses.  These values are not to be
used in the mass balance calculation.

(11)  If you determine carbon content or composition of a feedstock or
product using a method under §98.244(b)(4)(xiii), report the
information listed in paragraphs (a)(11)(i) through (a)(11)(iii) of this
section.  Include the information in paragraph (a)(11)(i) of this
section in each annual report.  Include the information in paragraphs
(a)(11)(ii) and (a)(11)(iii) of this section only in the first
applicable annual report, and provide any changes to this information in
subsequent annual reports.

(i)  Name or title of the analytical method.

(ii)  A copy of the method.  If the method is a modification of a method
listed in §98.244(b)(4)(i) through (xii), you may provide a copy of
only the sections that differ from the listed method.

(iii)  An explanation of why an alternative to the methods listed in
§98.244(b)(4)(i) through (xii) is needed.

(b)  If you use CEMS to measure CO2 emissions in accordance with
§98.243(b), then you must report the relevant information required
under §98.36 for the Tier 4 Calculation Methodology and the information
listed in paragraphs (b)(1) through (b)(68) of this section.

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

(12)  For CEMS used on stacks for stationary combustion units, report
the relevant information required under §98.36 for the Tier 4
calculation methodology.  Section 98.36(b)(9)(iii) does not apply for
the purposes of this subpart.

(23)  For CEMS used on stacks that are not used for stationary
combustion units, report the information required under
§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 aFor each stationary combustion
unit (or group of combustion units monitored with a single CO2 CEMS)
that burns petrochemical process off-gassource serves multiple
petrochemical process units or units other than the petrochemical
process unit, provide an estimate based on engineering judgment of the
fraction of fuel energy andthe total emissions that is attributable to
combustion of off-gas from theeach petrochemical process unit.

(5)  For stationary combustion units that burn process off-gas from the
petrochemical process unit, report the information related to CH4 and
N2O emissions as specified in paragraphs (b)(5)(i) through (b)(5)(iv) of
this section.

(i)  The CH4 and N2O emissions from each stack that is monitored with a
CO2 CEMS, expressed in metric tons of each gas and in metric tons of
CO2e.  For each stack provide an estimate based on engineering judgment
of the fraction of the total emissions that is attributable to
combustion of off-gas from the petrochemical process unit.

(ii)  and tThe combined CH4 and N2O emissions from all stationary
combustion units, expressed in metric tons of each gas and in metric
tons of CO2e.

(iii)  The quantity of each type of fuel used in Equation C-8 in
§98.33(c) for each stationary combustion unit or group of units (as
applicable) during the reporting year, expressed in short tons for solid
fuels, gallons for liquid fuels, and scf for gaseous fuels.

(iv)  The HHV (either default or annual average from measured data) used
in Equation C-8 in §98.33(c) for each stationary combustion unit or
group of combustion units (as applicable) that burn process off-gas from
the petrochemical process unit, the cumulative annual heat input used in
Equation C-10 in §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 §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
§98.243(d), you must report under this subpart the information listed
in paragraphs (c)(1) through (c)(45) of this section.

(1)  The ethylene process unit ID or other appropriate descriptor.

(12)  For each stationary combustion unit that burns ethylene process
off-gas (or group of stationary sources with a common pipe), except
flares, the relevant information listed in §98.36 for the applicable
Tier selected Tier 3 or Tier 4 methodology.  If aFor each stationary
combustion unit or group of units (as applicable) that burns ethylene
process off-gas, provide ansource serves multiple ethylene process units
or units other than the ethylene process unit, estimate based on
engineering judgment of the fraction of fuel energy andthe total
emissions that is attributable to combustion of off-gas from the each
ethylene process unit.

(23)  Information listed in §98.256(e) of subpart Y of this part for
each flare that burns ethylene process off-gas.

(34)  Name and annual quantity of each feedstock.

(45)  Annual quantity of each type of petrochemicalethylene produced
from each process unit (metric tons).

§98.247  Records that must be retained.

In addition to the recordkeeping requirements in §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 §98.243(b),
then you must retain under this subpart the records required for the
Tier 4 Calculation Methodology in §98.37, records of the procedures
used to develop estimates of the fraction of total emissions
attributable to combustion of petrochemical process off-gas as required
in §98.246(b), and records of any annual average HHV calculations.

(b)  If you comply with the mass balance methodology in §98.243(c),
then you must retain records of the information listed in paragraphs
(b)(1) through (b)(34) of this section.

(1)  Results of feedstock or product composition determinations
conducted in accordance with §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 §98.243(c)(4) for determining carbon content
of feedstock or product.

(3)  A part of the monitoring plan required under §98.3(g)(5), record
the estimated accuracy of measurement devices and the technical basis
for these estimates.

(4) The dates and results (e.g., percent calibration error) of the
calibrations of each measurement device.

(c)  If you comply with the combustion methodology in §98.243(d), then
you must retain under this subpart the records required for the
applicable Tier 3 and/or Tier 4 Calculation Methodologies in §98.37.
If you comply with §98.243(d)(2), you must also keep records of the
annual average flow calculations.

§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 §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

§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).

§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 §98.2(a)(1) or (a)(2).

§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 from
stationary combustion units 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
eEquation C-5 in subpart C of this part or the Tier 4 methodology in
subpart C of this part, unless either of the conditions in paragraphs
(a)(1) or (2) of this section are met, in which case use either
Equations C-1 or C-2a in subpart C of this part.  For CH4 and N2O
emissions from combustion of fuel gas, use the applicable procedures in
§98.33(c) for the same tier methodology that was used for calculating
CO2 emissions.  (Use the default CH4 and N2O emission factors for
“Petroleum (All fuel types in Table C-1)” in Table C-2 of this part.
 For Tier 3, use either the default high heat value for fuel gas in
Table C-1 of subpart C of this part or a calculated HHV, as allowed in
Equation C-8 of subpart C of this part.)  You may aggregate units,
monitor common stacks, or monitor common (fuel) pipes as provided in
§98.36(c) when calculating and reporting emissions from stationary
combustion units.  Calculate and report the emissions from flares under
this subpart.

(1)  The annual average fuel gas flow rate in the fuel gas line to the
combustion unit, prior to any split to individual burners or ports, does
not exceed 345 standard cubic feet per minute at 60ºF and 14.7 pounds
per square inch absolute and either of the conditions in paragraph
(a)(1)(i) or (ii) of this section exist.  Calculate the annual average
flow rate using company records assuming total flow is evenly
distributed over 525,600 minutes per year.

(i)  A flow meter is not installed at any point in the line supplying
fuel gas or an upstream common pipe.

(ii)  The fuel gas line contains only vapors from loading or unloading,
waste or wastewater handling, and remediation activities that are
combusted in a thermal oxidizer or thermal incinerator.

(2)  The combustion unit has a maximum rated heat input capacity of less
than 30 MMBtu/hr and either of the following conditions exist:

(i)  A flow meter is not installed at any point in the line supplying
fuel gas or an upsteam common pipe; or

(ii)  The fuel gas line contains only vapors from loading or unloading,
waste or wastewater handling, and remediation activities that are
combusted in a thermal oxidizer or thermal incinerator.

(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 §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 CH4emissions from non-merchant hydrogen production process
units (not including hydrogen produced from catalytic reforming units)
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.

§98.253  Calculating GHG emissions.

(a)  Calculate GHG emissions required to be reported in §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 either Equation Y-1a or Equation Y-1b of this section.
If daily or more frequent measurement data are available, you must use
daily values when using Equation Y-1a or Equation Y-1b of this section;
otherwise, use weekly values.

 	(Eq.Y-1a)

Where: