EF = Fuel-specific default CO2 emission factor, from
Table C-1 of this subpart (kg CO2/mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric
tons.

    (3) Tier 3 Calculation Methodology. Calculate the annual
CO2 mass emissions for each fuel by using either Equation
C3, C4, or C5 of this section, as appropriate.
    (i) For a solid fuel, use Equation C-3 of this section.
    [GRAPHIC] [TIFF OMITTED] TR30OC09.008

Where:

CO2 = Annual CO2 mass emissions from the
combustion of the specific solid fuel (metric tons).
Fuel = Annual mass of the solid fuel combusted, from company records
as defined in Sec.  98.6 (short tons).
CC = Annual average carbon content of the solid fuel (percent by
weight, expressed as a decimal fraction, e.g., 95% = 0.95). The
annual average carbon content shall be determined using the same
procedures as specified for HHV in paragraph (a)(2)(ii) of this
section.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.91 = Conversion factor from short tons to metric tons.

    (ii) For a liquid fuel, use Equation C-4 of this section.
    [GRAPHIC] [TIFF OMITTED] TR30OC09.009

Where:

CO2 = Annual CO2 mass emissions from the
combustion of the specific liquid fuel (metric tons).
Fuel = Annual volume of the liquid fuel combusted (gallons). The
volume of fuel combusted must be measured directly, using fuel flow
meters calibrated according to Sec.  98.3(i). Fuel billing meters
may be used for this purpose. Tank drop measurements may also be
used.
CC = Annual average carbon content of the liquid fuel (kg C per
gallon of fuel). The annual average carbon content shall be
determined using the same procedures as specified for HHV in
paragraph (a)(2)(ii) of this section.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.

    (iii) For a gaseous fuel, use Equation C-5 of this section.
    [GRAPHIC] [TIFF OMITTED] TR30OC09.010

Where:

CO2 = Annual CO2 mass emissions from
combustion of the specific gaseous fuel (metric tons).
Fuel = Annual volume of the gaseous fuel combusted (scf). The volume
of fuel combusted must be measured directly, using fuel flow meters
calibrated according to Sec.  98.3(i). Fuel billing meters may be
used for this purpose.
CC = Annual average carbon content of the liquid fuel (kg C per
gallon of fuel). The annual average carbon content shall be
determined using the same procedures as specified for HHV in
paragraph (a)(2)(ii) of this section.
MW = Annual average molecular weight of the gaseous fuel (kg/kg-
mole). The annual average carbon content shall be determined using
the same procedures as specified for HHV in paragraph (a)(2)(ii) of
this section.
MVC = Molar volume conversion factor (849.5 scf per kg-mole at
standard conditions, as defined in Sec.  98.6).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.

    (iv) Fuel flow meters that measure mass flow rates may be used for
liquid fuels, provided that the fuel density is used to convert the
readings to volumetric flow rates. The density shall be measured at the
same frequency as the carbon content, using ASTM D1298-99 (Reapproved
2005) ``Standard Test Method for Density, Relative Density (Specific
Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum
Products by Hydrometer Method'' (incorporated by reference, see Sec.
98.7).
    (v) The following default density values may be used for fuel oil,
in lieu of using the ASTM method in paragraph (a)(3)(iv) of this
section: 6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/gal
for No. 6 oil.
    (4) Tier 4 Calculation Methodology. Calculate the annual
CO2 mass emissions from all fuels combusted in a unit, by
using quality-assured data from continuous emission monitoring systems
(CEMS).
    (i) This methodology requires a CO2 concentration
monitor and a stack gas volumetric flow rate monitor, except as
otherwise provided in paragraph (a)(4)(iv) of this section. Hourly
measurements of CO2 concentration and stack gas flow rate
are converted to CO2 mass emission rates in metric tons per
hour.
    (ii) When the CO2 concentration is measured on a wet
basis, Equation C-6 of this section is used to calculate the hourly
CO2 emission rates:
[GRAPHIC] [TIFF OMITTED] TR30OC09.011

Where:

CO2 = CO2 mass emission rate (metric tons/hr).
CCO2 = Hourly average CO2 concentration (%
CO2).
Q = Hourly average stack gas volumetric flow rate (scfh).
5.18 x 10-7 = Conversion factor (metric tons/scf/%
CO2).

    (iii) If the CO2 concentration is measured on a dry
basis, a correction for the stack gas moisture content is required. You
shall either continuously monitor the stack gas moisture content as
described in Sec.  75.11(b)(2) of this chapter or, for certain types of
fuel, use a default moisture percentage from Sec.  75.11(b)(1) of this
chapter. For each unit operating hour, a moisture correction must be
applied to Equation C-6 of this section as follows:
[GRAPHIC] [TIFF OMITTED] TR30OC09.012

Where:

CO2* = Hourly CO2 mass emission rate,
corrected for moisture (metric tons/hr).
CO2 = Hourly CO2 mass emission rate from
Equation C-6 of this section, uncorrected (metric tons/hr).
%H2O = Hourly moisture percentage in the stack gas
(measured or default value, as appropriate).

    (iv) An oxygen (O2) concentration monitor may be used in
lieu of a CO2 concentration monitor to determine the hourly
CO2 concentrations, in accordance with Equation F-14a or F-
14b (as applicable) in appendix F to 40 CFR part 75, if the effluent
gas stream monitored by the CEMS consists solely of combustion products
(i.e., no process CO2 emissions are mixed with the
combustion products) and if only fuels that are listed in Table 1 in
section 3.3.5 of appendix F to 40 CFR part 75 are combusted in the
unit. If the O2 monitoring option is selected, the F-factors
used in Equations F-14a and F-14b shall be determined according to
section 3.3.5 or section 3.3.6 of appendix F to 40 CFR part 75, as
applicable. If Equation F-14b is used, the hourly moisture percentage
in the stack gas shall be either a measured value in accordance with
Sec.  75.11(b)(2) of this chapter, or, for certain types of fuel, a
default moisture value from Sec.  75.11(b)(1) of this chapter.
    (v) Each hourly CO2 mass emission rate from Equation C-6
or C-7 of this section is multiplied by the operating time to convert
it from metric tons per hour to metric tons. The operating time is the
fraction of the hour during which fuel is combusted (e.g., the unit
operating time is 1.0 if the unit operates for the whole hour and is
0.5 if the unit operates for 30 minutes in the hour). For common stack
configurations, the operating time is the fraction of the hour during
which effluent gases flow through the common stack.
    (vi) The hourly CO2 mass emissions are then summed over
each calendar quarter and the quarterly totals are summed to determine
the annual CO2 mass emissions.
    (vii) If both biomass and fossil fuel are combusted during the
year, determine and report the biogenic CO2 mass emissions
separately, as described in paragraph (e) of this section.
    (5) Alternative methods for units with continuous monitoring
systems. Units not subject to the Acid Rain Program that report data to
EPA according to 40 CFR part 75 may use the alternative methods in this
paragraph in lieu of using any of the four calculation methodology
tiers.
    (i) For a unit that combusts only natural gas and/or fuel oil, is
not subject to the Acid Rain Program, monitors and reports heat input
data year-round according to appendix D to 40 CFR part

75, but is not required by the applicable 40 CFR part 75 program to
report CO2 mass emissions data, calculate the annual
CO2 mass emissions for the purposes of this part as follows:
    (A) Use the hourly heat input data from appendix D to 40 CFR part
75, together with Equation G-4 in appendix G to 40 CFR part 75 to
determine the hourly CO2 mass emission rates, in units of
tons/hr;
    (B) Use Equations F-12 and F-13 in appendix F to 40 CFR part 75 to
calculate the quarterly and cumulative annual CO2 mass
emissions, respectively, in units of short tons; and
    (C) Divide the cumulative annual CO2 mass emissions
value by 1.1 to convert it to metric tons.
    (ii) For a unit that combusts only natural gas and/or fuel oil, is
not subject to the Acid Rain Program, monitors and reports heat input
data year-round according to 40 CFR 75.19 of this chapter but is not
required by the applicable 40 CFR part 75 program to report
CO2 mass emissions data, calculate the annual CO2
mass emissions for the purposes of this part as follows:
    (A) Calculate the hourly CO2 mass emissions, in units of
short tons, using Equation LM-11 in 40 CFR 75.19(c)(4)(iii).
    (B) Sum the hourly CO2 mass emissions values over the
entire reporting year to obtain the cumulative annual CO2
mass emissions, in units of short tons.
    (C) Divide the cumulative annual CO2 mass emissions
value by 1.1 to convert it to metric tons.
    (iii) For a unit that is not subject to the Acid Rain Program, uses
flow rate and CO2 (or O2) CEMS to report heat
input data year-round according to 40 CFR part 75, but is not required
by the applicable 40 CFR part 75 program to report CO2 mass
emissions data, calculate the annual CO2 mass emissions as
follows:
    (A) Use Equation F-11 or F-2 (as applicable) in appendix F to 40
CFR part 75 to calculate the hourly CO2 mass emission rates
from the CEMS data. If an O2 monitor is used, convert the
hourly average O2 readings to CO2 using Equation
F-14a or F-14b in appendix F to 40 CFR part 75 (as applicable), before
applying Equation F-11 or F-2.
    (B) Use Equations F-12 and F-13 in appendix F to 40 CFR part 75 to
calculate the quarterly and cumulative annual CO2 mass
emissions, respectively, in units of short tons.
    (C) Divide the cumulative annual CO2 mass emissions
value by 1.1 to convert it to metric tons.
    (D) If both biomass and fossil fuel are combusted during the year,
determine and report the biogenic CO2 mass emissions
separately, as described in paragraph (e) of this section.
    (b) Use of the four tiers. Use of the four tiers of CO2
emissions calculation methodologies described in paragraph (a) of this
section is subject to the following conditions, requirements, and
restrictions:
    (1) The Tier 1 Calculation Methodology:
    (i) May be used for any fuel listed in Table C-1 of this subpart
that is combusted in a unit with a maximum rated heat input capacity of
250 mmBtu/hr or less.
    (ii) May be used for MSW in a unit of any size that does not
produce steam, if the use of Tier 4 is not required.
    (iii) May be used for solid, gaseous, or liquid biomass fuels in a
unit of any size provided that the fuel is listed in Table C-1 of this
subpart.
    (iv) May not be used if you routinely perform fuel sampling and
analysis for the fuel high heat value (HHV) or routinely receive the
results of HHV sampling and analysis from the fuel supplier at the
minimum frequency specified in Sec.  98.34(a), or at a greater
frequency. In such cases, Tier 2 shall be used.
    (2) The Tier 2 Calculation Methodology:
    (i) May be used for the combustion of any type of fuel in a unit
with a maximum rated heat input capacity of 250 mmBtu/hr or less
provided that the fuel is listed in Table C-1 of this subpart.
    (ii) May be used in a unit with a maximum rated heat input capacity
greater than 250 mmBtu/hr for the combustion of pipeline quality
natural gas and distillate fuel oil.
    (iii) May be used for MSW in a unit of any size that produces
steam, if the use of Tier 4 is not required.
    (3) The Tier 3 Calculation Methodology:
    (i) May be used for a unit of any size that combusts any type of
fuel listed in Table C-1 of this subpart (except for MSW), unless the
use of Tier 4 is required.
    (ii) Shall be used for a unit with a maximum rated heat input
capacity greater than 250 mmBtu/hr that combusts any type of fuel
listed in Table C-1 of this subpart (except MSW), unless either of the
following conditions apply:
    (A) The use of Tier 1 or 2 is permitted, as described in paragraphs
(b)(1)(iii) and (b)(2)(ii) of this section.
    (B) The use of Tier 4 is required.
    (iii) Shall be used for a fuel not listed in Table C-1 of this
subpart if the fuel is combusted in a unit with a maximum rated heat
input capacity greater than 250 mmBtu/hr provided that both of the
following conditions apply:
    (A) The use of Tier 4 is not required.
    (B) The fuel provides 10% or more of the annual heat input to the
unit or, if Sec.  98.36(c)(3) applies, to a group of units served by
common supply pipe.
    (4) The Tier 4 Calculation Methodology:
    (i) May be used for a unit of any size, combusting any type of
fuel.
    (ii) Shall be used if the unit meets all six of the conditions
specified in paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(F) of this
section:
    (A) The unit has a maximum rated heat input capacity greater than
250 mmBtu/hr, or if the unit combusts municipal solid waste and has a
maximum rated input capacity greater than 250 tons per day of MSW.
    (B) The unit combusts solid fossil fuel or MSW, either as a primary
or secondary fuel.
    (C) The unit has operated for more than 1,000 hours in any calendar
year since 2005.
    (D) The unit has installed CEMS that are required either by an
applicable Federal or State regulation or the unit's operating permit.
    (E) The installed CEMS include a gas monitor of any kind or a stack
gas volumetric flow rate monitor, or both and the monitors have been
certified, either in accordance with the requirements of 40 CFR part
75, part 60 of this chapter, or an applicable State continuous
monitoring program.
    (F) The installed gas or stack gas volumetric flow rate monitors
are required, either by an applicable Federal or State regulation or by
the unit's operating permit, to undergo periodic quality assurance
testing in accordance with either appendix B to 40 CFR part 75,
appendix F to 40 CFR part 60, or an applicable State continuous
monitoring program.
    (iii) Shall be used for a unit with a maximum rated heat input
capacity of 250 mmBtu/hr or less and for a unit that combusts municipal
solid waste with a maximum rated input capacity of 250 tons of MSW per
day or less, if the unit meets all of the following three conditions:
    (A) The unit has both a stack gas volumetric flow rate monitor and
a CO2 concentration monitor.
    (B) The unit meets the conditions specified in paragraphs
(b)(4)(ii)(B) through (b)(4)(ii)(D) of this section.
    (C) The CO2 and stack gas volumetric flow rate monitors
meet the conditions specified in paragraphs (b)(4)(ii)(E) and
(b)(4)(ii)(F) of this section.

    (5) The Tier 4 Calculation Methodology shall be used beginning on:
    (i) January 1, 2010, for a unit that is required to report
CO2 mass emissions beginning on that date, if all of the
monitors needed to measure CO2 mass emissions have been
installed and certified by that date.
    (ii) January 1, 2011, for a unit that is required to report
CO2 mass emissions beginning on January 1, 2010, if all of
the monitors needed to measure CO2 mass emissions have not
been installed and certified by January 1, 2010. In this case, you may
use Tier 2 or Tier 3 to report GHG emissions for 2010.
    (6) You may elect to use any applicable higher tier for one or more
of the fuels combusted in a unit. For example, if a 100 mmBtu/hr unit
combusts natural gas and distillate fuel oil, you may elect to use Tier
1 for natural gas and Tier 3 for the fuel oil, even though Tier 1 could
have been used for both fuels. However, for units that use either the
Tier 4 or the alternative calculation methodology specified in
paragraph (a)(5) of this section, CO2 emissions from the
combustion of all fuels shall be based solely on CEMS measurements.
    (c) Calculation of CH4 and N2O emissions from stationary combustion
sources. You must calculate annual CH4 and N2O
mass emissions only for units that are required to report
CO2 emissions using the calculation methodologies of this
subpart and for only those fuels that are listed in Table C-2 of this
subpart.
    (1) Use Equation C-8 of this section to estimate CH4 and
N2O emissions for any fuels for which you use the Tier 1 or
Tier 3 calculation methodologies for CO2. Use the same
values for fuel combustion that you use for the Tier 1 or Tier 3
calculation.
[GRAPHIC] [TIFF OMITTED] TR30OC09.013

Where:

CH4 or N2O = Annual CH4 or
N2O emissions from the combustion of a particular type of
fuel (metric tons).
Fuel = Mass or volume of the fuel combusted, either from company
records or directly measured by a fuel flow meter, as applicable
(mass or volume per year).
HHV = Default high heat value of the fuel from Table C-1 of this
subpart (mmBtu per mass or volume).
EF = Fuel-specific default emission factor for CH4 or
N2O, from Table C-2 of this subpart (kg CH4 or
N2O per mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric
tons.

    (2) Use Equation C-9a of this section to estimate CH4
and N2O emissions for any fuels for which you use the Tier 2
Equation C-2a of this section to estimate CO2 emissions. Use
the same values for fuel combustion and HHV that you use for the Tier 1
or Tier 3 calculation.
[GRAPHIC] [TIFF OMITTED] TR30OC09.014

Where:

CH4 or N2O = Annual CH4 or
N2O emissions from the combustion of a particular type of
fuel (metric tons).
Fuel = Mass or volume of the fuel combusted during the reporting
year.
HHV = High heat value of the fuel, averaged for all valid
measurements for the reporting year (mmBtu per mass or volume).
EF = Fuel-specific default emission factor for CH4 or
N2O, from Table C-2 of this subpart (kg CH4 or
N2O per mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric
tons.

    (3) Use Equation C-9b of this section to estimate CH4
and N2O emissions for any fuels for which you use Equation
C-2c of this section to calculate the CO2 emissions. Use the
same values for steam generation and the ratio ``B'' that you use for
Equation C-2c.
[GRAPHIC] [TIFF OMITTED] TR30OC09.015

Where:

CH4 or N2O = Annual CH4 or
N2O emissions from the combustion of a solid fuel (metric
tons).
Steam = Total mass of steam generated by solid fuel combustion
during the reporting year (lb steam).
B = Ratio of the boiler's maximum rated heat input capacity to its
design rated steam output (mmBtu/lb steam).
EF = Fuel-specific emission factor for CH4 or
N2O, from Table C-2 of this subpart (kg CH4 or
N2O per mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric
tons.

    (4) Use Equation C-10 of this section for units in the Acid Rain
Program, units that monitor and report heat input on a year-round basis
according to 40 CFR part 75, and units that use the Tier 4 Calculation
Methodology.
[GRAPHIC] [TIFF OMITTED] TR30OC09.016

Where:

CH4 or N2O = Annual CH4 or
N2O emissions from the combustion of a particular type of
fuel (metric tons).
(HI)A = Cumulative annual heat input from the fuel,
derived from the electronic data reports required under Sec.  75.64
of this chapter or, for Tier 4 units, from the best available
information as described in paragraph (c)(4)(ii) of this section
(mmBtu).
EF = Fuel-specific emission factor for CH4 or
N2O, from Table C-2 of this section (kg CH4 or
N2O per mmBtu).
0.001 = Conversion factor from kg to metric tons.

    (i) If only one type of fuel listed in Table C-2 of this subpart is
combusted during normal operation, substitute the cumulative annual
heat input from combustion of the fuel into Equation C-10 of this
section to calculate the annual CH4 or N2O
emissions.

    (ii) If more than one type of fuel listed in Table C-2 of this
subpart is combusted during normal operation, use Equation C-10 of this
section separately for each type of fuel. If flow rate and diluent gas
monitors are used to measure the unit heat input, use the best
available information (e.g., fuel feed rate measurements, fuel heating
values, engineering analysis) to estimate the annual heat input from
each type of fuel.
    (5) When multiple fuels are combusted during the reporting year,
sum the fuel-specific results from Equations C-8, C-9a, C-9b, or C-10
of this section (as applicable) to obtain the total annual
CH4 and N2O emissions, in metric tons.
    (d) Calculation of CO2 from sorbent.
    (1) When a unit is a fluidized bed boiler, is equipped with a wet
flue gas desulfurization system, or uses other acid gas emission
controls with sorbent injection, use Equation C-11 of this section to
calculate the CO2 emissions from the sorbent, if those
CO2 emissions are not monitored by CEMS:
[GRAPHIC] [TIFF OMITTED] TR30OC09.017

Where:

CO2 = CO2 emitted from sorbent for the
reporting year (metric tons).
S = Limestone or other sorbent used in the reporting year, from
company records (short tons).
R = 1.00, the calcium-to-sulfur stoichiometric ratio.
MWCO2 = Molecular weight of carbon dioxide (44).
MWS = Molecular weight of sorbent (100 if calcium
carbonate).
0.91 = Conversion factor from short tons to metric tons.

    (2) The annual CO2 mass emissions for the unit shall be
the sum of the CO2 emissions from the combustion process and
the CO2 emissions from the sorbent.
    (e) CO2 emissions from combustion of biomass. Use the procedures of
this paragraph (e) to estimate biogenic CO2 emissions from
units that combust a combination of biomass and fossil fuels. Reporting
of CO2 emissions from combustion of biomass is required only
for those biomass fuels listed in Table C-1 of this section, unless
emissions are measured using CEMS.
    (1) If CEMS are not used to measure CO2, use Equation C-
1 of this subpart to calculate the annual CO2 mass emissions
from the combustion of biomass (except MSW) for a unit of any size.
Determine the mass of biomass combusted using one of the following
procedures in this paragraph (e)(1), as appropriate.
    (i) Use company records.
    (ii) Follow the procedures in paragraph (e)(5) of this section.
    (iii) For premixed fuels that contain biomass and fossil fuels
(e.g., mixtures containing biodiesel), use best available information
to determine the mass of biomass fuels and document the procedure used
in the GHG Monitoring Plan required by Sec.  98.3(g)(5).
    (2) If a CO2 CEMS (or a surrogate O2 monitor)
and a stack gas flow rate monitor are used to determine the annual
CO2 mass emissions either according to 40 CFR part 75, the
Tier 4 Calculation Methodology, or the alternative calculation
methodology specified in paragraph (a)(5)(iii); and if both fossil fuel
and biomass (except for MSW) are combusted in the unit during the
reporting year, you may use the following procedure to determine the
annual biogenic CO2 mass emissions. If MSW is combusted in
the unit, follow the procedures in paragraph (e)(3) of this section.
    (i) For each operating hour, use Equation C-12 of this section to
determine the volume of CO2 emitted.
[GRAPHIC] [TIFF OMITTED] TR30OC09.018

Where:

VCO2h = Hourly volume of CO2 emitted (scf).
(%CO2)h = Hourly average CO2
concentration, measured by the CO2 concentration monitor,
or, if applicable, calculated from the hourly average O2
concentration (%CO2).
Qh = Hourly average stack gas volumetric flow rate,
measured by the stack gas volumetric flow rate monitor (scfh).
th = Source operating time (decimal fraction of the hour
during which the source combusts fuel, i.e., 1.0 for a full
operating hour, 0.5 for 30 minutes of operation, etc.).
100 = Conversion factor from percent to a decimal fraction.

    (ii) Sum all of the hourly VCO2h values for the
reporting year, to obtain Vtotal, the total annual volume of
CO2 emitted.
    (iii) Calculate the annual volume of CO2 emitted from
fossil fuel combustion using Equation C-13 of this section. If two or
more types of fossil fuel are combusted during the year, perform a
separate calculation with Equation C-13 of this section for each fuel
and sum the results.
[GRAPHIC] [TIFF OMITTED] TR30OC09.019

Where:

Vff = Annual volume of CO2 emitted from
combustion of a particular fossil fuel (scf).
Fuel = Total quantity of the fossil fuel combusted in the reporting
year, from company records, as defined in Sec.  98.6 (lb for solid
fuel, gallons for liquid fuel, and scf for gaseous fuel).
Fc = Fuel-specific carbon based F-factor, either a
default value from Table 1 in section 3.3.5 of appendix F to 40 CFR
part 75 or a site-specific value determined under section 3.3.6 of
appendix F to 40 CFR part 75 (scf CO2/mmBtu).
HHV = High heat value of the fossil fuel, from fuel sampling and
analysis (annual average value in Btu/lb for solid fuel, Btu/gal for
liquid fuel and Btu/scf for gaseous fuel, sampled as specified
(e.g., monthly, quarterly, semi-annually, or by lot) in Sec.
98.34(a)(2)). The average HHV shall be calculated according to the
requirements of paragraph (a)(2)(ii) of this section.
10\6\ = Conversion factor, Btu per mmBtu.

    (iv) Subtract Vff from Vtotal to obtain
Vbio, the annual volume of CO2 from the
combustion of biomass. If a CEMS is being used to measure the combined
combustion and process emissions from a unit that is subject to another
subpart of part 98, then also subtract CO2 process emissions
from Vtotal to determine Vbio. The CO2
process emissions must be calculated according to the requirements of
the applicable subpart.

    (v) Calculate the biogenic percentage of the annual CO2
emissions,expressed as a decimal fraction, using Equation C-14 of this
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.020

    (vi) Calculate the annual biogenic CO2 mass emissions,
in metric tons, by multiplying the results obtained from Equation C-14
of this section by the annual CO2 mass emissions in metric
tons, as determined:
    (A) Under paragraph (a)(4)(vi) of this section, for units using the
Tier 4 Calculation Methodology.
    (B) Under paragraph (a)(5)(iii)(B) of this section, for units using
the alternative calculation methodology specified in paragraph
(a)(5)(iii).
    (C) From the electronic data report required under Sec.  75.64 of
this chapter, for units in the Acid Rain Program and other units using
CEMS to monitor and report CO2 mass emissions according to
40 CFR part 75. However, before calculating the annual biogenic
CO2 mass emissions, multiply the cumulative annual
CO2 mass emissions by 0.91 to convert from short tons to
metric tons.
    (3) For a unit that combusts MSW, the annual biogenic
CO2 emissions shall be calculated using the procedures in
this paragraph (e)(3).
    (i) If the Tier 1 or Tier 2 Calculation Methodology is used to
quantify CO2 mass emissions:
    (A) Use Equation C-1 or C-2c of this subpart, as appropriate, to
calculate the annual CO2 mass emissions from MSW combustion.
    (B) Determine the relative proportions of biogenic and non-biogenic
CO2 emissions on a quarterly basis using the method
specified in Sec.  98.34(d).
    (C) Determine the annual biogenic CO2 mass emissions
from MSW combustion by multiplying the annual CO2 mass
emissions by the annual average biogenic decimal fraction obtained from
Sec.  98.34(d).
    (ii) If the unit uses Tier 4 to quantify CO2 emissions:
    (A) Follow the procedures in paragraphs (e)(2)(i) and (ii) of this
section, to determine Vtotal.
    (B) If any fossil fuel was combusted during the year, follow the
procedures in paragraph (e)(2)(iii) of this section, to determine
Vff.
    (C) Subtract Vff from Vtotal, to obtain
VMSW, the annual volume of CO2 emissions from MSW
combustion.
    (D) Determine the annual volume of biogenic CO2
emissions (Vbio) from MSW combustion as follows. Multiply
the annual volume of CO2 emissions from MSW combustion
(VMSW) by the annual average biogenic decimal fraction
obtained from ASTM D6866-08 and ASTM D7459-08.
    (E) Calculate the biogenic percentage of the annual CO2
emissions from the unit, using Equation C-14 of this section. For the
purposes of this calculation, the term ``Vbio'' in the
numerator of Equation C-14 of this section shall be the results of the
calculation performed under paragraph (e)(3)(ii)(D) of this section.
    (F) Calculate the annual biogenic CO2 mass emissions
according to paragraph (e)(2)(vi)(A) of this section.
    (4) As an alternative to the procedures in paragraph (e)(2) of this
section, use ASTM Methods D7459-08 and D6866-08 to determine the
biogenic portion of the annual CO2 emissions, as described
in Sec.  98.34(e). If this option is selected, the results of each
determination shall be expressed as a decimal fraction (e.g., 0.30, if
30 percent of the CO2 is biogenic), and the values shall be
averaged over the reporting year. The annual biogenic CO2
mass emissions shall be calculated by multiplying the the total annual
CO2 mass emissions by the annual average biogenic fraction
obtained from ASTM D6866-08 and ASTM D7459-08.
    (5) If Equation C-1 of this section is selected to calculate the
annual biogenic mass emissions for wood, wood waste, or other solid
biomass-derived fuel, Equation C-15 of this section may be used to
quantify biogenic fuel consumption, provided that all of the required
input parameters are accurately quantified. Similar equations and
calculation methodologies based on steam generation and boiler
efficiency may be used, provided that they are documented in the GHG
Monitoring Plan required by Sec.  98.3(g)(5).
[GRAPHIC] [TIFF OMITTED] TR30OC09.021

Where:

(Fuel)p = Quantity of biomass consumed during the
measurement period ``p'' (tons/year or tons/month, as applicable).
H = Average enthalpy of the boiler steam for the measurement period
(Btu/lb).
S = Total boiler steam production for the measurement period (lb/
month or lb/year, as applicable).
(HI)nb = Heat input from co-fired fossil fuels and non-
biomass-derived fuels for the measurement period, based on company
records of fuel usage and default or measured HHV values (Btu/month
or Btu/year, as applicable).
(HHV)bio = Default or measured high heat value of the
biomass fuel (Btu/lb).
(Eff)bio = Percent efficiency of biomass-to-energy
conversion, expressed as a decimal fraction.
2000 = Conversion factor (lb/ton).

Sec.  98.34  Monitoring and QA/QC requirements.

    The CO2 mass emissions data for stationary fuel
combustion sources shall be monitored as follows:
    (a) For the Tier 2 Calculation Methodology:
    (1) All fuel samples shall be taken at a location in the fuel
handling system that provides a sample representative of the fuel
combusted. The fuel sampling and analysis may be performed by either
the owner or operator or the supplier of the fuel.
    (2) The minimum required frequency of the HHV sampling and analysis
for each type of fuel is specified in this paragraph. When the
specified frequency is based on a specified time period (i.e., weekly,
monthly, quarterly, or semiannually), fuel sampling and analysis is
required only for those periods in which the unit operates.
    (i) For natural gas, semiannual sampling and analysis is required
(i.e., twice in a calendar year, with consecutive samples taken at
least four months apart).
    (ii) For coal and fuel oil, analysis of at least one representative
sample from each fuel lot is required. For the purposes of this
section, a fuel lot is defined as a shipment or delivery of a single
fuel (e.g., ship load, barge load, group of trucks, group of railroad
cars, etc.).
    (iii) For liquid fuels other than fuel oil, for fossil fuel-derived
gaseous fuels, and for biogas; sampling and analysis is required at
least once per calendar quarter. To the extent practicable, consecutive
quarterly samples shall be taken at least 30 days apart.
    (iv) For solid fuels other than coal and MSW, weekly sampling is
required to

obtain composite samples, which are then analyzed monthly.
    (3) If different types of fuel (e.g., different ranks of coal or
different grades of fuel oil) are blended prior to combustion, use one
of the following procedures in this paragraph.
    (i) Use a weighted HHV value in the emission calculations, based on
the relative proportions of each fuel in the blend.
    (ii) Take a representative sample of the blend and analyze it for
HHV.
    (4) If, for a particular type of fuel, HHV sampling and analysis is
performed more often than the minimum frequency specified in paragraph
(a)(2) of this section, the results of all valid fuel analyses shall be
used in the GHG emission calculations.
    (5) If, for a particular type of fuel, valid HHV values are
obtained at less than the minimum frequency specifed in paragraph
(a)(2) of this section, appropriate substitute data values shall be
used in the emissions calculations, in accordance with missing data
procedures of Sec.  98.35.
    (6) Use any applicable fuel sampling and analysis methods in this
paragraph (a)(6) to determine the high heat values. Alternatively, for
gaseous fuels, the HHV may be calculated using chromatographic analysis
together with standard heating values of the fuel constituents,
provided that the gas chromatograph is operated, maintained, and
calibrated according to the manufacturer's instructions.
    (i) ASTM D4809-06 Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method)
(incorporated by reference, see Sec.  98.7).
    (ii) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat
of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter
(incorporated by reference, see Sec.  98.7).
    (iii) ASTM D1826-94 (Reapproved 2003) Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter (incorporated by reference, see Sec.  98.7).
    (iv) ASTM D3588-98 (Reapproved 2003) Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels (incorporated by reference, see Sec.  98.7).
    (v) ASTM D4891-89 (Reapproved 2006) Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion (incorporated by reference, see Sec.  98.7).
    (vi) GPA Standard 2172-09 Calculation of Gross Heating Value,
Relative Density, Compressibility and Theoretical Hydrocarbon Liquid
Content for Natural Gas Mixtures for Custody Transfer (incorporated by
reference, see Sec.  98.7).
    (vii) GPA Standard 2261-00, Analysis for Natural Gas and Similar
Gaseous Mixtures by Gas Chromatography (incorporated by reference, see
Sec.  98.7).
    (viii) ASTM D5865-07a, Standard Test Method for Gross Calorific
Value of Coal and Coke (incorporated by reference, see Sec.  98.7).
    (b) For the Tier 3 Calculation Methodology:
    (1) Calibrate each oil and gas flow meter according to Sec.
98.3(i) and the provisions of this paragraph (b).
    (i) Perform calibrations using any of the test methods and
procedures in this paragraph (b)(1)(i):
    (A) An applicable flow meter test method listed in paragraphs
(b)(4)(i) through (b)(4)(viii) of this section.
    (B) The calibration procedures specified by the flow meter
manufacturer.
    (C) An industry-accepted or industry standard calibration practice.
    (ii) In addition to the initial calibration required by Sec.
98.3(i), recalibrate each fuel flow meter (except for qualifying
billing meters under paragraph (b)(1)(iii) of this section) either
annually, at the minimum frequency specified by the manufacturer, or at
the interval specified by the industry consensus standard practice
used.
    (iii) Fuel billing meters are exempted from the initial and ongoing
calibration requirements of this paragraph, provided that the fuel
supplier and the unit combusting the fuel do not have any common owners
and are not owned by subsidiaries or affiliates of the same company.
    (iv) For the initial calibration of an orifice, nozzle, or venturi
meter; in-situ calibration of the transmitters is sufficient. A primary
element inspection (PEI) shall be performed at least once every three
years.
    (v) For the continuously-operating units and processes described in
Sec.  98.3(i)(6), the required flow meter recalibrations and, if
necessary, the PEIs may be postponed until the next scheduled
maintenance outage.
    (vi) If a mixture of fuels is transported by a common pipe (e.g.,
still gas and supplementary natural gas), you must either separately
meter each of the fuels prior to mixing using flow meters calibrated
according to Sec.  98.3(i), or use flow meters calibrated according to
Sec.  98.3(i) to measure the mixed fuel at the common pipe and to
separately meter an appropriate subset of the fuels prior to mixing. If
the latter option is chosen, quantify the fuels that are not measured
prior to mixing by subtracting out the fuels measured prior to mixing
from the fuel measured at the common pipe.
    (2) Oil tank drop measurements (if used to determine liquid fuel
use volume) shall be performed according to any an appropriate method
published by a consensus-based standards organization (e.g., the
American Petroleum Institute).
    (3) The carbon content and, if applicable, molecular weight of the
fuels shall be determined according to the procedures in this paragraph
(b)(3).
    (i) All fuel samples shall be taken at a location in the fuel
handling system that provides a sample representative of the fuel
combusted. The fuel sampling and analysis may be performed by either
the owner or operator or by the supplier of the fuel.
    (ii) At a minimum, fuel samples shall be collected at the frequency
specified in this paragraph. When sampling is required at a specified
time interval (e.g., weekly, monthly, quarterly, or semiannually), fuel
sampling and analysis is required for only those specified periods in
which the unit operates.
    (A) For natural gas, semiannual sampling and analysis is required
(i.e., twice in a calendar year, with consecutive samples taken at
least four months apart).
    (B) For coal and fuel oil, analysis of at least one representative
sample from each fuel lot is required. For the purposes of this
section, a fuel lot is defined as a shipment or delivery of a single
fuel (e.g., ship load, barge load, group of trucks, group of railroad
cars, etc.).
    (C) For other liquid fuels other than fuel oil, for fossil fuel-
derived gaseous fuels, and for biogas; sampling and analysis is
required at least once per calendar quarter. To the extent practicable,
consecutive quarterly samples shall be taken at least 30 days apart.
    (D) For solid fuels other than coal, weekly sampling is required to
obtain composite samples, which are then analyzed monthly.
    (E) For gaseous fuels other than natural gas and biogas (e.g.,
refinery gas), daily sampling and analysis to determine the carbon
content and molecular weight of the fuel is required if the necessary
equipment is in place to make these measurements. Otherwise, weekly
sampling and analysis shall be performed.
    (iii) If, for a particular type of fuel, sampling and analysis for
carbon content and molecular weight is performed more often than the

minimum frequency specified in paragraph (b)(3) of this section, the
results of all valid fuel analyses shall be used in the GHG emission
calculations.
    (iv) If, for a particular type of fuel, sampling and analysis for
carbon content and molecular weight is performed at less than the
minimum frequency specified in paragraph (b)(3) of this section,
appropriate substitute data values shall be used in the emissions
calculations, in accordance with the missing data procedures of Sec.
98.35.
    (v) The procedures of paragraph (a)(3) of this section apply to
carbon content and molecular weight determinations.
    (4) Use any applicable standard method from the following list to
quality assure the data from each fuel flow meter.
    (i) AGA Report No. 3, Orifice Metering of Natural Gas and Other
Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty
Guidelines (1990) and Part 2: Specification and Installation
Requirements (2000) (incorporated by reference, see Sec.  98.7).
    (ii) AGA Transmission Measurement Committee Report No. 7,
Measurement of Gas by Turbine Meters (2006) (incorporated by reference,
see Sec.  98.7).
    (iii) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec.
98.7).
    (iv) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by
Turbine Meters (incorporated by reference, see Sec.  98.7).
    (v) ASME MFC-5M-1985 (Reaffirmed 1994), Measurement of Liquid Flow
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters
(incorporated by reference, see Sec.  98.7).
    (vi) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters (incorporated by reference, see Sec.  98.7).
    (vii) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow
by Means of Critical Flow Venturi Nozzles (incorporated by reference,
see Sec.  98.7).
    (viii) ASME MFC-9M-1988 (Reaffirmed 2001), Measurement of Liquid
Flow in Closed Conduits by Weighing Method (incorporated by reference,
see Sec.  98.7).
    (5) Use any applicable methods from the following list to determine
the carbon content and molecular weight (for gaseous fuel) of the fuel.
Alternatively, the results of chromatographic analysis of the fuel may
be used, provided that the gas chromatograph is operated, maintained,
and calibrated according to the manufacturer's instructions.
    (i) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas
by Gas Chromatography (incorporated by reference, see Sec.  98.7).
    (ii) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis
of Reformed Gas by Gas Chromatography (incorporated by reference, see
Sec.  98.7).
    (iii) ASTM D2502-04 (Reapproved 2002) Standard Test Method for
Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum
Oils from Viscosity Measurements (incorporated by reference, see Sec.
98.7).
    (iv) ASTM D2503-92 (Reapproved 2007) Standard Test Method for
Relative Molecular Mass (Relative Molecular Weight) of Hydrocarbons by
Thermoelectric Measurement of Vapor Pressure (incorporated by
reference, see Sec.  98.7).
    (v) 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
Sec.  98.7).
    (vi) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants (incorporated by reference, see Sec.
98.7).
    (vii) ASTM D5373-08 Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples
of Coal (incorporated by reference, see Sec.  98.7).
    (c) For the Tier 4 Calculation Methodology, the CO2 and
flow rate monitors must be certified prior to the applicable deadline
specified in Sec.  98.33(b)(5).
    (1) For initial certification, you may use any one of the following
three procedures in this paragraph.
    (i) Sec.  75.20(c)(2) and (4) and appendix A to 40 CFR part 75.
    (ii) The calibration drift test and relative accuracy test audit
(RATA) procedures of Performance Specification 3 in appendix B to part
60 (for the CO2 concentration monitor) and Performance
Specification 6 in appendix B to part 60 (for the continuous emission
rate monitoring system (CERMS)).
    (iii) The provisions of an applicable State continuous monitoring
program.
    (2) If an O2 concentration monitor is used to determine
CO2 concentrations, the applicable provisions of 40 CFR part
75, 40 CFR part 60, or an applicable State continuous monitoring
program shall be followed for initial certification and on-going
quality assurance, and all required RATAs of the monitor shall be done
on a percent CO2 basis.
    (3) For ongoing quality assurance, follow the applicable procedures
in either appendix B to 40 CFR part 75, appendix F to 40 CFR part 60,
or an applicable State continuous monitoring program. If appendix F to
40 CFR part 60 is selected for on-going quality assurance, perform
daily calibration drift assessments for both the CO2 monitor
(or surrogate O2 monitor) and the flow rate monitor, conduct
cylinder gas audits of the CO2 concentration monitor in
three of the four quarters of each year (except for non-operating
quarters), and perform annual RATAs of the CO2 concentration
monitor and the CERMS.
    (4) For the purposes of this part, the stack gas volumetric flow
rate monitor RATAs required by appendix B to 40 CFR part 75 and the
annual RATAs of the CERMS required by appendix F to 40 CFR part 60 need
only be done at one operating level, representing normal load or normal
process operating conditions, both for initial certification and for
ongoing quality assurance.
    (5) If, for any source operating hour, quality assured data are not
obtained with a CO2 monitor (or surrogate O2
monitor), flow rate monitor, or (if applicable) moisture monitor, use
appropriate substitute data values in accordance with the missing data
provisions of Sec.  98.35.
    (d) When municipal solid waste (MSW) is combusted in a unit,
determine the biogenic portion of the CO2 emissions from MSW
combustion using ASTM D6866-08 Standard Test Methods for Determining
the Biobased Content of Solid, Liquid, and Gaseous Samples Using
Radiocarbon Analysis (incorporated by reference, see Sec.  98.7) and
ASTM D7459-08 Standard Practice for Collection of Integrated Samples
for the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon
Dioxide Emitted from Stationary Emissions Sources (incorporated by
reference, see Sec.  98.7). Perform the ASTM D7459-08 sampling and the
ASTM D6866-08 analysis at least once in every calendar quarter in which
MSW is combusted in the unit. Collect each gas sample during normal
unit operating conditions while MSW is the only fuel being combusted
for at least 24 consecutive hours or for as long as is necessary to
obtain a sample large enough to meet the specifications of ASTM D6866-
08. Separate CO2 emissions into the biogenic and non-
biogenic fraction using the average proportion of biogenic emissions of
all samples analyzed during the reporting year. Express the results as
a decimal fraction (e.g., 0.30, if 30 percent of the CO2
from MSW combustion is biogenic). If there is a

common fuel source of MSW that feeds multiple units at the facility,
performing the testing at only one of the units is sufficient.
    (e) For units that use CEMS to measure the total CO2
mass emissions and combust a combination of biogenic fuels (other than
MSW) with a fossil fuel, ASTM D6866-08 and ASTM D7459-08 may be used to
determine the biogenic portion of the CO2 emissions. Perform
the ASTM D7459-08 sampling and the ASTM D6866-08 analysis at least once
in every calendar quarter in which biogenic and non-biogenic fuels are
co-fired in the unit. The relative proportions of the biogenic and non-
biogenic fuels during the sampling shall be representative of the
average fuel blend for a typical operating year. Collect each gas
sample using ASTM D7459-08 during normal unit operation for at least 24
consecutive hours or for as long as is necessary to obtain a sample
large enough to meet the specifications of ASTM D6866-08.
    (f) Whenever company records are used in the calculation of
CO2 emissions, the records required under Sec.  98.3(g)
shall include both the company records and an explanation of how those
records are used to estimate the following parameters:
    (1) Fuel consumption, when the Tier 1 and Tier 2 Calculation
Methodologies are used.
    (2) Fuel consumption, when solid fuel is combusted and the Tier 3
Calculation Methodology is used.
    (3) Fossil fuel consumption when Sec.  98.33(e) applies to a unit
that uses CEMS to quantify CO2 emissions and that combusts
both fossil and biomass fuels.
    (4) Sorbent usage, when Sec.  98.33(d) applies.
    (5) Quantity of steam generated by a unit when Sec.  98.33(a)(2)
applies.
    (6) Biogenic fuel consumption under Sec.  98.33(e)(5).
    (g) As part of the GHG Monitoring Plan required under Sec.
98.3(g)(5), you must document the procedures used to ensure the
accuracy of the estimates of fuel usage, sorbent usage, steam
production, and boiler efficiency (as applicable) in paragraph (f) of
this section, including but not limited to calibration of weighing
equipment, fuel flow meters, steam flow meters, and other measurement
devices. The estimated accuracy of measurements made with these devices
shall also be recorded, and the technical basis for these estimates
shall be provided.

Sec.  98.35  Procedures for estimating missing data.

    Whenever a quality-assured value of a required parameter is
unavailable (e.g., if a CEMS malfunctions during unit operation or if a
required fuel sample is not taken), a substitute data value for the
missing parameter shall be used in the calculations.
    (a) For all units subject to the requirements of the Acid Rain
Program, and all other stationary combustion units subject to the
requirements of this part that monitor and report emissions and heat
input data in accordance with 40 CFR part 75, the missing data
substitution procedures in 40 CFR part 75 shall be followed for
CO2 concentration, stack gas flow rate, fuel flow rate, high
heating value, and fuel carbon content.
    (b) For units that use the Tier 1, Tier 2, Tier 3, and Tier 4
Calculation Methodologies, perform missing data substitution as follows
for each parameter:
    (1) For each missing value of the high heating value, carbon
content, or molecular weight of the fuel, substitute the arithmetic
average of the quality-assured values of that parameter immediately
preceding and immediately following the missing data incident. If the
``after'' value has not been obtained by the time that the GHG
emissions report is due, you may use the ``before'' value for missing
data substitution or the best available estimate of the parameter,
based on all available process data (e.g., electrical load, steam
production, operating hours). If, for a particular parameter, no
quality-assured data are available prior to the missing data incident,
the substitute data value shall be the first quality-assured value
obtained after the missing data period.
    (2) For missing records of CO2 concentration, stack gas
flow rate, percent moisture, fuel usage, and sorbent usage, the
substitute data value shall be the best available estimate of the
parameter, based on all available process data (e.g., electrical load,
steam production, operating hours, etc.). You must document and retain
records of the procedures used for all such estimates.

Sec.  98.36  Data reporting requirements.

    (a) In addition to the facility-level information required under
Sec.  98.3, the annual GHG emissions report shall contain the unit-
level or process-level emissions data in paragraphs (b) through (d) of
this section (as applicable) and the emissions verification data in
paragraph (e) of this section.
    (b) Units that use the four tiers. You shall report the following
information for stationary combustion units that use the Tier 1, Tier
2, Tier 3, or Tier 4 methodology in Sec.  98.33(a) to calculate
CO2 emissions, except as otherwise provided in paragraphs
(c) and (d) of this section:
    (1) The unit ID number.
    (2) A code representing the type of unit.
    (3) Maximum rated heat input capacity of the unit, in mmBtu/hr for
boilers and process heaters only and relevant units of measure for
other combustion sources.
    (4) Each type of fuel combusted in the unit during the report year.
    (5) The tier used to calculate the CO2 emissions for
each type of fuel combusted (i.e., Tier 1, 2, 3, or 4).
    (6) For a unit that uses Tiers 1, 2, and 3; the CO2,
CH4, and N2O emissions for each type of fuel
combusted, expressed in metric tons of each gas and in metric tons of
CO2e.
    (7) For a unit that uses Tier 4:
    (i) For units that burn fossil fuels only, the annual
CO2 emissions for all fuels combined. Reporting
CO2 emissions by type of fuel is not required.
    (ii) For units that burn both fossil fuels and biomass, the annual
CO2 emissions from combustion of all fossil fuels combined
and the annual CO2 emissions from combustion of all biomass
fuels combined. Reporting CO2 emissions by type of fuel is
not required.
    (iii) Annual CH4 and N2O emissions for each
type of fuel combusted expressed in metric tons of each gas and in
metric tons of CO2e.
    (8) Annual CO2 emissions from sorbent (if calculated
using Equation C-11 of this subpart), expressed in metric tons.
    (9) Annual GHG emissions from all fossil fuels burned in the unit
(i.e., the sum of the CO2, CH4, and
N2O emissions), expressed in metric tons of CO2e.
    (10) Customer meter number for units that combust natural gas.
    (c) Reporting alternatives for units using the four Tiers. You may
use any of the applicable reporting alternatives of this paragraph to
simplify the unit-level reporting required under paragraph (b) of this
section:
    (1) Aggregation of units. If a facility contains two or more units
(e.g., boilers or combustion turbines), each of which has a maximum
rated heat input capacity of 250 mmBtu/hr or less, you may report the
combined GHG emissions for the group of units in lieu of reporting GHG
emissions from the individual units, provided that the use of Tier 4 is
not required or elected for

any of the units and the units use the same tier for any common fuels
combusted. If this option is selected, the following information shall
be reported instead of the information in paragraph (b) of this
section:
    (i) Group ID number, beginning with the prefix ``GP''.
    (ii) An identification number for each unit in the group.
    (iii) Cumulative maximum rated heat input capacity of the group
(mmBtu/hr).
    (iv) The highest maximum rated heat input capacity of any unit in
the group (mmBtu/hr).
    (v) Each type of fuel combusted in the group of units during the
reporting year.
    (vi) Annual CO2, CH4, and N2O mass
emissions aggregated for each type of fuel combusted in the group of
units during the year, expressed in metric tons of each gas and in
metric tons of CO2e. If any of the units burn both fossil
fuels and biomass, report also the annual CO2 emissions from
combustion of all fossil fuels combined and annual CO2
emissions from combustion of all biomass fuels combined, expressed in
metric tons.
    (vii) The tier used to calculate the CO2 mass emissions
for each type of fuel combusted in the units (i.e., Tier 1, Tier 2, or
Tier 3).
    (viii) The calculated CO2 mass emissions (if any) from
sorbent.
    (ix) Annual GHG emissions from all fossil fuels burned in the group
(i.e., the sum of the CO2, CH4, and
N2O emissions), expressed in metric tons of CO2e.
    (2) Monitored common stack or duct configurations. When the flue
gases from two or more stationary combustion units at a facility are
discharged through a common stack or duct before exiting to the
atmosphere and if CEMS are used to continuously monitor CO2
mass emissions at the common stack or duct according to the Tier 4
Calculation Methodology, you may report the combined emissions from the
units sharing the common stack or duct, in lieu of separately reporting
the GHG emissions from the individual units. The following information
shall be reported instead of the information in paragraph (b) of this
section:
    (i) Common stack or duct identification number, beginning with the
prefix ``CS''.
    (ii) Identification numbers of the units sharing the common stack
or duct.
    (iii) Maximum rated heat input capacity of each unit sharing the
common stack or duct (mmBtu/hr).
    (iv) Each type of fuel combusted in the units during the year.
    (v) The methodology used to calculate the CO2 mass
emissions, i.e., Tier 4.
    (vi) If the any of the units burn both fossil fuels and biomass,
annual CO2 mass emissions, annual CO2 emissions
from combustion of fossil fuels, and annual CO2 emissions
from combustion of biomass measured at the common stack or duct,
expressed in metric tons.
    (vii) The annual CH4 and N2O emissions from
the units sharing the common stack or duct, expressed in metric tons of
each gas and in metric tons of CO2e.
    (viii) Annual GHG emissions from all fossil fuels burned in the
group (i.e., the sum of the CO2, CH4, and
N2O emissions), expressed in metric tons of CO2e.
    (3) Common pipe configurations. When two or more liquid-fired or
gaseous-fired stationary combustion units at a facility combust the
same type of fuel and the fuel is fed to the individual units through a
common supply line or pipe, you may report the combined emissions from
the units served by the common supply line, in lieu of separately
reporting the GHG emissions from the individual units, provided that
the total amount of fuel combusted by the units is accurately measured
at the common pipe or supply line using a fuel flow meter that is
calibrated in accordance with Sec.  98.34(a). If a portion of the fuel
measured at the common pipe is diverted to a chemical or industrial
process where it is used but not combusted, you may subtract the
diverted fuel from the fuel measured at the common pipe prior to
performing the GHG emissions calculations, provided that the amount of
fuel diverted is also measured with a calibrated flow meter per Sec.
98.3(i). If the common pipe option is selected, the applicable tier
shall be used based on the maximum rated heat input capacity of the
largest unit served by the common pipe configuration. The 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) Maximum rated heat input capacity of each 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 CH4 and N2O emissions from the
units served by the common pipe, expressed in metric tons of each gas
and in metric tons of CO2e.
    (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.
    (d) Units subject to 40 CFR part 75.
    (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, you shall report the following unit-level information:
    (i) Unit or stack identification numbers. Use exact same unit,
common stack, or multiple stack identification numbers that represent
the monitored locations (e.g., 1, 2, CS001, MS1A, etc.) that are
reported under Sec.  75.64 of this chapter.
    (ii) Annual CO2, CH4, and N2O
emissions at each monitored location, expressed in metric tons of
CO2e.
    (iii) Identification of the Part 75 methodology used to determine
the CO2 mass emissions.
    (2) For units that use the alternative CO2 mass
emissions calculation methods for units with continuous monitoring
systems provided in Sec.  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, or multiple stack identification numbers that represent the
monitored locations (e.g., 1, 2, CS001, MS1A, etc.) that are reported
under Sec.  75.64 of this chapter.
    (ii) For units that use the alternative methods specified in Sec.
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 or 40 CFR 75.19:
    (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) A code or flag to indicate whether heat input is calculated
according to appendix D to 40 CFR part 75 or 40 CFR 75.19.
    (D) Annual CO2, CH4, and N2O
emissions at each monitored location, across all fuel types, expressed
in metric tons of CO2e.
    (iii) For units with continuous monitoring systems that use the
alternative method for units with continuous monitoring systems in
Sec.  98.33(a)(5)(iii) to monitor heat input year-round according to 40
CFR part 75:
    (A) Fuel combusted during the reporting year.

    (B) Methodology used to calculate the CO2 mass
emissions.
    (C) A code or flag to indicate that the heat input data is derived
from CEMS measurements.
    (D) The total annual CO2, CH4, and
N2O emissions at each monitored location, expressed in
metric tons of CO2e.
    (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 Sec.  98.33(a)(5).
    (iii) Are not in the Acid Rain Program, but are required monitor
and report CO2 mass emissions and heat input data year-
round, in accordance with 40 CFR part 75.
    (2) For stationary combustion sources using the Tier 1, Tier 2,
Tier 3, and Tier 4 Calculation Methodologies in Sec.  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
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, in mmBtu per short ton
for solid fuels, mmBtu per gallon for liquid fuels, and mmBtu per scf
for gaseous fuels. Specify the date on which each fuel sample was
taken. Indicate whether each HHV is a measured value of 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 the 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.
    (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 the 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). 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.
    (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 Sec.  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).
    (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, 40 CFR part 60, 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 Sec.  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,

[[Continued on page 56409]]

]

[[pp. 56409-56458]] Mandatory Reporting of Greenhouse Gases

[[Continued from page 56408]]

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, 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 Sec.  98.33(e)(4)(ii), if CEMS are used to measure
CO2 emissions.
    (D) The annual volume of biogenic CO2 emissions from MSW
combustion, in metric tons.
    (xi) When ASTM methods D7459-08 and D6866-08 are used to determine
the biogenic portion of the annual CO2 emissions from a unit
that co-fires biogenic (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 Sec.  98.33(a)(2)(iii) or to quantify solid fuel usage under
Sec.  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.

Sec.  98.37  Records that must be retained.

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

Sec.  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 to Subpart C of Part 98--Default CO2 Emission Factors and High
                  Heat Values for Various Types of Fuel
------------------------------------------------------------------------
                                  Default high heat       Default CO2
           Fuel type                    value           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.         1.028 x 10-3                       53.02
 Average).
------------------------------------------------------------------------
      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
Still Gas.....................  0.143                              66.72
Kerosene......................  0.135                              75.20
Liquefied petroleum gases       0.092                              62.98
 (LPG).
Propane.......................  0.091                              61.46
Propylene.....................  0.091                              65.95
Ethane........................  0.096                              62.64
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 fuels       mmBtu/short ton        kg CO2/mmBtu
            (solid)
------------------------------------------------------------------------
Municipal Solid Waste \1\.....  9.95                                90.7
Tires.........................  26.87                              85.97
------------------------------------------------------------------------
   Fossil fuel-derived fuels          mmBtu/scf           kg CO2/mmBtu
           (gaseous)
------------------------------------------------------------------------
Blast Furnace Gas.............  0.092 x 10-3                      274.32
Coke Oven Gas.................  0.599 x 10-3                       46.85
------------------------------------------------------------------------
     Biomass fuels--solid          mmBtu/short ton        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\ Allowed only for units that do not generate steam and use Tier 1.

 Table C-2 to Subpart C of Part 98--Default CH4 and N2O Emission Factors
                        for Various Types of Fuel
------------------------------------------------------------------------
                              Default CH4 emission  Default N2O emission
          Fuel type              factor (kg CH4/       factor (kg N2O/
                                     mmBtu)                mmBtu)
------------------------------------------------------------------------
Coal and Coke (All fuel       1.1 x 10-2            1.6 x 10-03
 types in Table C-1).
Natural Gas.................  1.0 x 10-03           1.0 x 10-04
Petroleum (All fuel types in  3.0 x 10-03           6.0 x 10-04
 Table C-1).
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     3.2 x 10-02           4.2 x 10-03
 fuel types in Table C-1).
Biogas......................  3.2 x 10-03           6.3 x 10-04
Biomass Fuels--Liquid (All    1.1 x 10-03           1.1 x 10-04
 fuel types in Table C-1).
------------------------------------------------------------------------
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 1g
  of CH4/MMBtu.
\1\ Allowed only for units that do not generate steam and use Tier 1.

Table C-2 to Subpart C--Default CH4 and N2O Emission Factors for Various
                              Types of Fuel
------------------------------------------------------------------------
                              Default CH4 emission  Default N2O emission
          Fuel type              factor (kg CH4/       factor (kg N2O/
                                     mmBtu)                mmBtu)
------------------------------------------------------------------------
Coal and Coke (All fuel       1.1 x 10-2            1.6 x 10-03
 types in Table C-1).
Natural Gas.................  1.0 x 10-03           1.0 x 10-04

Petroleum (All fuel types in  3.0 x 10-03           6.0 x 10-04
 Table C-1).
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     3.2 x 10-02           4.2 x 10-03
 fuel types in Table C-1).
Biogas......................  3.2 x 10-03           6.3 x 10-04
Biomass Fuels--Liquid (All    1.1 x 10-03           1.1 x 10-04
 fuel types in Table C-1).
------------------------------------------------------------------------
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

Sec.  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 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 Sec.  98.6.

Sec.  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 Sec.  98.2(a)(1).

Sec.  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.

Sec.  98.43  Calculating GHG emissions.

    Continue to monitor and report CO2 mass emissions as
required under Sec.  75.13 or section 2.3 of apppendix G to 40 CFR part
75, and Sec.  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
Sec.  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 Sec.  98.33(c).

Sec.  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.

Sec.  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.

Sec.  98.46  Data reporting requirements.

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

Sec.  98.47  Records that must be retained.

    You shall comply with the recordkeeping requirements of Sec. Sec.
98.3(g) and 98.37.

Sec.  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 E--Adipic Acid Production

Sec.  98.50  Definition of source category.

    The adipic acid production source category consists of all adipic
acid production facilities that use oxidation to produce adipic acid.

Sec.  98.51  Reporting threshold.

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

Sec.  98.52  GHGs to report.

    (a) You must report N2O process emissions at the
facility level.
    (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
following the requirements of subpart C.

Sec.  98.53  Calculating GHG emissions.

    (a) You must determine annual N2O emissions from adipic
acid production 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 paragraphs (b)
through (h) 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 conduct the test on the waste gas stream from the
nitric acid oxidation step of the process using the methods specified
in Sec.  98.54(b) through (d).
    (2) You must conduct the performance test under normal process
operating conditions and without using N2O abatement
technology.
    (3) You must measure the adipic acid production rate during the
test and calculate the production rate for the test period in metric
tons per hour.
    (c) You must determine an N2O emissions factor to use in
Equation E-2 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 a facility-specific emissions factor
according to Equation E-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.022

Where:

EFN2O = Average facility-specific N2O
emissions factor (lb N2O generated/ton adipic acid
produced).
CN2O = N2O concentration per text run during
the performance test (ppm N2O).
1.14 x 10-7 = Conversion factor (lb/dscf-ppm
N2O).
Q = Volumetric flow rate of effluent gas per test run during the
performance test (dscf/hr).
P = Production rate per test run during the performance test (tons
adipic acid produced/hr).
n = Number of test runs.

    (d) If applicable, you must determine the destruction efficiency
for each N2O abatement technology used at your facility
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
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 used at your facility. The
abatement factor is calculated for each adipic acid facility according
to Equation E-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.023

Where:

AFN = Abatement factor of N2O abatement
technology (fraction of annual production that abatement technology
is operating).
Pa Abate = Annual adipic acid production during which
N2O abatement was used.
Pa = Total annual adipic acid production (ton acid
produced).

    (f) You must determine the annual amount of adipic acid produced
and the annual adipic acid production during which N2O
abatement is operating.
    (g) You must calculate annual adipic acid production process
emissions of N2O by multiplying the emissions factor
(determined using Equation E-1 of this section) by the total annual
adipic acid production and accounting for N2O abatement,
according to Equation E-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.024

Where:

N2O = Annual N2O mass emissions from adipic
acid production (metric tons).
EFN2O = Facility-specific N2O emissions factor
(lb N2O generated/ton adipic acid produced).
Pa = Annual adipic acid produced (tons).
DFN = Destruction efficiency of N2O abatement
technology N (abatement device destruction efficiency, percent of
N2O removed from air stream).
AFN = Abatement factor of N2O abatement
technology N (fraction of annual production abatement technology is
operating).
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies.

    (h) You must determine the amount of process N2O
emissions that is sold or transferred off site (if applicable). You can
determine the amount using existing process flow meters and
N2O analyzers.

Sec.  98.54  Monitoring and QA/QC requirements.

    (a) You must conduct a new performance test and calculate a new
facility-specific emissions factor according to the frequency specified
in paragraphs (a)(1) through (a)(3) of this section.
    (1) Conduct the performance test annually.
    (2) Conduct the performance test when your adipic acid production
process is changed either by altering the ratio of cyclohexanone to
cyclohexanol or by installing abatement equipment.
    (3) If you requested Administrator approval for an alternative
method of determining N2O concentration under Sec.
98.53(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, Measurement of Vapor Phase Organic and
Inorganic Emissions by Extractive Fourier

Transform Infrared (FTIR) Spectroscopy in 40 CFR part 63, Appendix A;
    (2) ASTM D6348-03 Standard Test Method for Determination of Gaseous
Compounds by Extractive Direct Interface Fourier Transform Infrared
(FTIR) Spectroscopy (incorporated by reference, see Sec.  98.7); or
    (3) An equivalent method, with Administrator approval.
    (c) You must determine the production rate(s) during the
performance test according to paragraph (c)(1) or (c)(2) of this
section.
    (1) Direct measurement (such as using flow meters or weigh scales).
    (2) Existing plant procedures used for accounting purposes.
    (d) You must conduct all required performance tests according to
the methods in Sec.  98.54(b) 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
emissions 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.
    (3) The production rate(s) during the performance test and how each
production rate was determined.
    (e) You must determine the monthly adipic acid production quantity
and the monthly adipic acid production during which N2O
abatement technology is operating according to the methods in
paragraphs (c)(1) or (c)(2) of this section.
    (f) You must determine the annual adipic acid production quantity
and the annual adipic production quantity during which N2O
abatement technology is operating by summing the respective monthly
adipic acid production quantities.

Sec.  98.55  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 monthly adipic acid production, the
substitute data shall be the best available estimate based on all
available process data or data used for accounting purposes (such as
sales records).
    (b) For missing values related to the performance test, including
emission factors, production rate, and N2O concentration,
you must conduct a new performance test according to the procedures in
Sec.  98.54 (a) through (d).

Sec.  98.56  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (k) of this section at the facility level:
    (a) Annual process N2O emissions from adipic acid
production (metric tons).
    (b) Annual adipic acid production (tons).
    (c) Annual adipic acid production during which N2O
abatement technology is operating (tons).
    (d) Annual process N2O emissions from adipic acid
production facility that is sold or transferred off site (metric tons).
    (e) Number of abatement technologies (if applicable).
    (f) Types of abatement technologies used (if applicable).
    (g) Abatement technology destruction efficiency for each abatement
technology (percent destruction).
    (h) Abatement utilization factor for each abatement technology
(fraction of annual production that abatement technology is operating).
    (i) Number of times in the reporting year that missing data
procedures were followed to measure adipic acid production (months).
    (j) If you conducted a performance test and calculated a site-
specific emissions factor according to Sec.  98.53(a)(1), each annual
report must also contain the information specified in paragraphs (j)(1)
through (j)(7) of this section for each adipic acid production
facility.
    (1) Emissions factor (lb N2O/ton adipic acid).
    (2) Test method used for performance test.
    (3) Production rate per test run during performance test (tons/hr).
    (4) N2O concentration per test run during performance
test (ppm N2O).
    (5) Volumetric flow rate per test run during performance test
(dscf/hr).
    (6) Number of test runs.
    (7) Number of times in the reporting year that a performance test
had to be repeated (number).
    (k) If you requested Administrator approval for an alternative
method of determining N2O concentration under Sec.
98.53(a)(2), each annual report must also contain the information
specified in paragraphs (k)(1) through (k)(4) of this section for each
adipic acid production facility.
    (1) Name of alternative method.
    (2) Description of alternative method.
    (3) Request date.
    (4) Approval date.

Sec.  98.57  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must
retain the records specified in paragraphs (a) through (h) of this
section at the facility level:
    (a) Annual adipic acid production capacity (tons).
    (b) Records of significant changes to process.
    (c) Number of facility operating hours in calendar year.
    (d) Documentation of how accounting procedures were used to
estimate production rate.
    (e) Documentation of how process knowledge was used to estimate
abatement technology destruction efficiency.
    (f) Performance test reports of N2O emissions.
    (g) Measurements, records and calculations used to determine
reported parameters.
    (h) Documentation of the procedures used to ensure the accuracy of
the measurements of all reported parameters, including but not limited
to, calibration of weighing equipment, flow meters, and other
measurement devices. The estimated accuracy of measurements made with
these devices must also be recorded, and the technical basis for these
estimates must be provided.

Sec.  98.58  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

Sec.  98.60  Definition of the source category.

    (a) A primary aluminum production facility manufactures primary
aluminum using the Hall-H[eacute]roult manufacturing process. The
primary aluminum manufacturing process comprises the following
operations:
    (1) Electrolysis in prebake and S[oslash]derberg cells.
    (2) Anode baking for prebake cells.
    (b) This source category does not include experimental cells or
research and development process units.

Sec.  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 Sec.  98.2(a)(1) or (a)(2).

Sec.  98.62  GHGs to report.

    You must report:
    (a) Perfluoromethane (CF4), and perfluoroethane
(C2F6) emissions from anode effects in all
prebake and S[oslash]derberg electolysis cells.
    (b) CO2 emissions from anode consumption during
electrolysis in all prebake and S[oslash]derberg electolysis 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.

Sec.  98.63  Calculating GHG emissions.

    (a) The annual value for PFC emissions shall be estimated from the
sum of monthly values using Equation F-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.025

Where:

EPFC = Annual PFC emissions from aluminum production
(metric tons PFC).
Em = 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 S[oslash]derberg electolysis cell.
[GRAPHIC] [TIFF OMITTED] TR30OC09.026

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.
[GRAPHIC] [TIFF OMITTED] TR30OC09.027

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.
[GRAPHIC] [TIFF OMITTED] TR30OC09.028

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.
    (d) Calculate and report under this subpart the process
CO2 emissions by operating and maintaining CEMS according to
the Tier 4 Calculation Methodology in Sec.  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:
[GRAPHIC] [TIFF OMITTED] TR30OC09.029

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 S[oslash]derberg cells you must calculate CO2
emissions using Equation F-6 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.030

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 S[oslash]derberg 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.
[GRAPHIC] [TIFF OMITTED] TR30OC09.031

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.
[GRAPHIC] [TIFF OMITTED] TR30OC09.032

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 Sec.  98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of this part (General Stationary
Fuel Combustion Sources).

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

Sec.  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 method per Equation F-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.033

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 = S[oslash]derberg technology specific emission
factor (1.7 metric tons CO2/metric ton Al produced).
MPs = Metal production from S[oslash]derberg process
(metric tons Al).

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

Sec.  98.66  Data reporting requirements.

    In addition to the information required by Sec.  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 S[oslash]derberg electolysis 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
S[oslash]derberg 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 S[oslash]derberg) and process
control technology (e.g., Pechiney or other).

Sec.  98.67  Records that must be retained.

    In addition to the information required by Sec.  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 S[oslash]derberg electolysis 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
S[oslash]derberg 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 S[oslash]derberg) and process
control technology (e.g., Pechiney or other).

Sec.  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 of Part 98--Slope and Overvoltage Coefficients for the Calculation of PFC Emissions From
                                               Aluminum Production
----------------------------------------------------------------------------------------------------------------
                                                                     CF4 slope          CF4
                                                                    coefficient     overvoltage       Weight
                                                                     [(kg CF4/      coefficient   fraction C2F6/
                           Technology                             metric ton Al)/    [(kg CF4/    CF4 [(kg C2F6/
                                                                  (AE-Mins/cell-  metric ton Al)/    kg CF4)]
                                                                       day)]           (mV)]
----------------------------------------------------------------------------------------------------------------
CWPB............................................................           0.143            1.16           0.121
SWPB............................................................           0.272            3.65           0.252
VSS.............................................................           0.092              NA           0.053
HSS.............................................................           0.099              NA           0.085
----------------------------------------------------------------------------------------------------------------

 Table F-2 to Subpart F of Part 98--Default Data Sources for Parameters
                         Used for CO2 Emissions
------------------------------------------------------------------------
            Parameter                           Data source
------------------------------------------------------------------------
            CO2 Emissions from Prebake Cells (CWPB and SWPB)
------------------------------------------------------------------------
MP: metal production (metric tons  Individual facility records.
 Al).
NAC: net annual prebaked anode     Individual facility records.
 consumption per metric ton Al
 (metric tons C/metric tons Al).
Sa: sulfur content in baked anode  2.0.
 (percent weight).
Asha: ash content in baked anode   0.4.
 (percent weight).
------------------------------------------------------------------------
         CO2 Emissions from S[oslash]derberg Cells (VSS and HSS)
------------------------------------------------------------------------
MP: metal production (metric tons  Individual facility records.
 Al).
PC: annual paste consumption       Individual facility records.
 (metric ton/metric ton Al).
CSM: annual emissions of           HSS: 4.0.
 cyclohexane soluble matter (kg/   VSS: 0.5.
 metric ton Al).
BC: binder content of paste        Dry Paste: 24.
 (percent weight).                 Wet Paste: 27.
Sp: sulfur content of pitch        0.6.
 (percent weight).
Ashp: ash content of pitch         0.2.
 (percent weight).

Hp: hydrogen content of pitch      3.3.
 (percent weight).
Sc: sulfur content in calcined     1.9.
 coke (percent weight).
Ashc: ash content in calcined      0.2.
 coke (percent weight).
CD: carbon in skimmed dust from    0.01.
 S[oslash]derberg cells (metric
 ton C/metric ton Al).
------------------------------------------------------------------------
       CO2 Emissions from Pitch Volatiles Combustion (VSS and HSS)
------------------------------------------------------------------------
GA: initial weight of green        Individual facility records.
 anodes (metric tons).
Hw: annual hydrogen content in     0.005 x GA.
 green anodes (metric tons).
BA: annual baked anode production  Individual facility records.
 (metric tons).
WT: annual waste tar collected     (a) 0.005 x GA.
 (metric tons).
(a) Riedhammer furnaces..........  (b) insignificant.
(b) all other furnaces...........
------------------------------------------------------------------------
    CO2 Emissions From Bake Furnace Packing Materials (CWPB and SWPB)
------------------------------------------------------------------------
PCC: annual packing coke           0.015.
 consumption (metric tons/metric
 ton baked anode).
BA: annual baked anode production  Individual facility records.
 (metric tons).
Spc: sulfur content in packing     2.
 coke (percent weight).
Ashpc: ash content in packing      2.5.
 coke (percent weight).
------------------------------------------------------------------------

Subpart G--Ammonia Manufacturing

Sec.  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.

Sec.  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 Sec.  98.2(a)(1) or (2).

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

Sec.  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 Sec.  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)(6) 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:
[GRAPHIC] [TIFF OMITTED] TR30OC09.034

Where:

CO2,G = Annual CO2 emissions arising from
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:

[GRAPHIC] [TIFF OMITTED] TR30OC09.035

Where:

CO2,L = Annual CO2 emissions arising from
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:
[GRAPHIC] [TIFF OMITTED] TR30OC09.036

Where:

CO2,S = Annual CO2 emissions arising from
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.
[GRAPHIC] [TIFF OMITTED] TR30OC09.037

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.
[GRAPHIC] [TIFF OMITTED] TR30OC09.038

Where:

CO2 = Annual combined CO2 emissions from all
ammonia processing units (metric tons).
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:
[GRAPHIC] [TIFF OMITTED] TR30OC09.039

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 Sec.  98.33(a)(4) and all associated requirements for
Tier 4 in subpart C of this part.

Sec.  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 Sec.  98.7).
    (2) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis
of Reformed Gas by Gas Chromatography (incorporated by reference, see
Sec.  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 Sec.  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 Sec.  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
Sec.  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 Sec.
98.7).
    (7) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate
Analysis of Coal and Coke (incorporated by reference, see Sec.  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 Sec.  98.7).
    (d) Calibrate all oil and gas flow meters (except for gas billing
meters) and perform oil tank measurements according to the monitoring
and QA/QC requirements for the Tier 3 methodology in Sec.  98.34(b).
    (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) 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.

Sec.  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 Sec.  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.

Sec.  98.76  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraphs (a)
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 Sec.
98.37(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