animal population, as described in Sec.  98.363(a)(1) and (2), below
those listed in Table JJ-1 do not need to report under this rule. A
facility with an annual animal population that exceeds those listed in
Table JJ-1 should conduct a more thorough analysis to determine
applicability.
    (2) (i) If a facility has more than one animal group present (e.g.,
swine and poultry), the facility must determine if they are required to
report by calculating the combined animal group factor (CAGF) using
equation JJ-1:
[GRAPHIC] [TIFF OMITTED] TR30OC09.137

Where:

CAGF = Combined Animal Group Factor
AAAPAG,Facility = Average annual animal population at the
facility, by animal group
APTL AG = Animal population threshold level, as specified
in Table JJ-1 of this section

    (ii) If the calculated CAGF for a facility is less than 1, the
facility is not required to report under this rule. If the CAGF is
equal to or greater than 1, the facility must use more detailed
applicability tables and tools to determine if they are required to
report under this rule.
    (b) A manure management system (MMS) is a system that stabilizes
and/or stores livestock manure, litter, or manure wastewater in one or
more of the following system components: Uncovered anaerobic lagoons,
liquid/slurry systems with and without crust covers (including but not
limited to ponds and tanks), storage pits, digesters, solid manure
storage, dry lots (including feedlots), high-rise houses for poultry
production (poultry without litter), poultry production with litter,
deep bedding systems for cattle and swine, manure composting, and
aerobic treatment.
    (c) This source category does not include system components at a
livestock facility that are unrelated to the stabilization and/or
storage of manure such as daily spread or pasture/range/paddock systems
or land application activities or any method of manure utilization that
is not listed in Sec.  98.360(b).
    (d) This source category does not include manure management
activities located off site from a livestock facility or off-site
manure composting operations.

Sec.  98.361  Reporting threshold.

    Livestock facilities must report GHG emissions under this subpart
if the facility meets the reporting threshold as defined in 98.360(a)
above, contains a manure management system as defined in 98.360(b)
above, and meets the requirements of Sec.  98.2(a)(1).

Sec.  98.362  GHGs to report.

    (a) Livestock facilities must report annual aggregate
CH4 and N2O emissions for the following MMS
components at the facility:
    (1) Uncovered anaerobic lagoons.
    (2) Liquid/slurry systems (with and without crust covers, and
including but not limited to ponds and tanks).
    (3) Storage pits.
    (4) Digesters, including covered anaerobic lagoons.
    (5) Solid manure storage.
    (6) Dry lots, including feedlots.
    (7) High-rise houses for poultry production (poultry without
litter)
    (8) Poultry production with litter.
    (9) Deep bedding systems for cattle and swine.
    (10) Manure composting.
    (11) Aerobic treatment.
    (b) A livestock facility that is subject to this rule only because
of emissions from manure management system components is not required
to report emissions from subparts C through PP (other than subpart JJ)
of this part.
    (c) A livestock facility that is subject to this part because of
emissions from source categories described in subparts C through PP of
this part is not required to report emissions under subpart JJ of this
part unless emissions from manure management systems are 25,000 metric
tons CO2e per year or more.

Sec.  98.363  Calculating GHG emissions.

    (a) For all manure management system components listed in 98.360(b)
except digesters, estimate the annual CH4 emissions and sum
for all the components to obtain total emissions from the manure
management system for all animal types using Equation JJ-1.

[GRAPHIC] [TIFF OMITTED] TR30OC09.138

Where:

MMSC = Manure management systems component.
TVSAT = Total volatile solids excreted by animal type,
calculated using Equation JJ-3 of this section (kg/day).
VSMMSC = Fraction of the total manure for each animal
type that is managed in MMS component MMSC, assumed to be equivalent
to the fraction of VS in each MMS component.
VSss = Volatile solids removal through solid separation;
if solid separation occurs prior to the MMS component, use a default
value from Table JJ-4 of this section; if no solid separation
occurs, this value is set to 0.
(B0)AT = Maximum CH4-producing
capacity for each animal type, as specified in Table JJ-2 of this
section (m\3\ CH4/kg VS).
MCFMMSC = CH4 conversion factor for the MMS
component, as specified in Table JJ-5 of this section (decimal).
[GRAPHIC] [TIFF OMITTED] TR30OC09.139

Where:

TVSAT = Daily total volatile solids excreted per animal
type (kg/day).
PopulationAT = Average annual animal population
contributing manure to the manure management system by animal type
(head) (see description in Sec.  98.363(a)(i) and (ii) below).
TAMAT = Typical animal mass for each animal type, using
either default values in Table JJ-2 of this section or farm-specific
data (kg/head).
VSAT = Volatile solids excretion rate for each animal
type, using default values in Table JJ-2 or JJ-3 of this section (kg
VS/day/1000 kg animal mass).

    (1) Average annual animal populations for static populations (e.g.,
dairy cows, breeding swine, layers) must be estimated by performing an
animal inventory or review of facility records once each reporting
year.
    (2) Average annual animal populations for growing populations (meat
animals such as beef and veal cattle, market swine, broilers, and
turkeys) must be estimated each year using the average number of days
each animal is kept at the facility and the number of animals produced
annually, and an equation similar or equal to Equation JJ-4 below,
adapted from Equation 10.1 in 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, Volume 4, Chapter 10.
[GRAPHIC] [TIFF OMITTED] TR30OC09.140

Where:

PopulationAT = Average annual animal population (by
animal type).
Days onsiteAT = Average number of days the animal is kept
at the facility, by animal type.
NAPAAT = Number of animals produced annually, by animal
type.

    (b) For each digester, calculate the total amount of CH4
emissions, and then sum the emissions from all digesters, as shown in
Equation JJ-5 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.141

Where:

CH4 EmissionsAD = CH4 emissions
from anaerobic digestion (metric tons/yr).
AD = Number of anaerobic digesters at the manure management
facility.
CH4C = CH4 flow to digester combustion device,
calculated using Equation JJ-6 of this section (metric tons
CH4/yr).
CH4D = CH4 destruction at digesters,
calculated using Equation JJ-11 of this section (metric tons
CH4/yr) .
CH4L = Leakage at digesters calculated using Equation JJ-
12 of this section (metric tons CH4/yr).

    (1) For each digester, calculate the annual CH4 flow to
the combustion device (CH4C) using Equation JJ-6 of this
section. A fully integrated system that directly reports the quantity
of CH4 flow to the digester combustion device requires only
summing the results of all monitoring periods for a given year to
obtain CH4C.
[GRAPHIC] [TIFF OMITTED] TR30OC09.142

Where:

CH4C = CH4 flow to digester combustion device
(metric tons CH4/yr).
V = Average annual volumetric flow rate, calculated in Equation JJ-7
of this subsection (cubic feet CH4/yr).
C = Average annual CH4 concentration of digester gas,
calculated in Equation JJ-8 of this section (%, wet basis).
0.0423 = Density of CH4 lb/scf (at 520 [deg]R or 60
[deg]F and 1 atm).

T = Average annual temperature at which flow is measured, calculated
in Equation JJ-9 of this section ([deg]R).
P = Average annual pressure at which flow is measured, calculated in
Equation JJ-10 of this section (atm).

    (2) For each digester, calculate the average annual volumetric flow
rate, CH4 concentration of digester gas, temperature, and
pressure at which flow are measured using Equations JJ-7 through JJ-10
of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.143

Where:

V = Average annual volumetric flow rate (cubic feet CH4/
yr).
OD = Operating days, number of days per year that that the digester
was operating (days/yr).
Vn = Daily average volumetric flow rate for day n, as
determined from daily monitoring as specified in Sec.  98.364
(acfm).
[GRAPHIC] [TIFF OMITTED] TR30OC09.144

Where:

C = Average annual CH4 concentration of digester gas (%,
wet basis).
OD = Operating days, number of days per year that the digester was
operating (days/yr).
Cn = Average daily CH4 concentration of
digester gas for day n, as determined from daily monitoring as
specified in Sec.  98.364 (%, wet basis).
[GRAPHIC] [TIFF OMITTED] TR30OC09.145

Where:

T = Average annual temperature at which flow is measured ([deg]R).
OD = Operating days, number of days per year that the digester was
operating (days/yr).
Tn = Temperature at which flow is measured for day
n([deg]R).
[GRAPHIC] [TIFF OMITTED] TR30OC09.146

Where:

P = Average annual pressure at which flow is measured (atm).
OD = Operating days, number of days per year that the digester was
operating (days/yr).
Pn = Pressure at which flow is measured for day n (atm).

    (3) For each digester, calculate the CH4 destruction at
the digester combustion device using Equation JJ-11 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.147

Where:

CH4D = CH4 destruction at digester combustion
device (metric tons/yr).
CH4C = Annual quantity of CH4 flow to digester
combustion device, as calculated in Equation JJ-6 of this section
(metric tons CH4).
DE = CH4 destruction efficiency from flaring or burning
in engine (lesser of manufacturer's specified destruction efficiency
and 0.99). If the gas is transported off-site for destruction, use
DE = 1.
OH = Number of hours combustion device is functioning in reporting
year.
Hours = Hours in reporting year.

    (4) For each digester, calculate the CH4 leakage using
Equation JJ-12 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.148

Where:

CH4L = Leakage at digesters (metric tons/yr).
CH4C = Annual quantity of CH4 flow to digester
combustion device, as calculated in Equation JJ-6 of this section
(metric tons CH4).
CE = CH4 collection efficiency of anaerobic digester, as
specified in Table JJ-6 of this section (decimal).

    (c) For each MMS component, estimate the annual N2O
emissions and sum for all MMS components to obtain total emissions from
the manure management system for all animal types using Equation JJ-13
of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.149

Where:

Nex AT = Daily total nitrogen excreted per animal type,
calculated using Equation JJ-14 of this section (kg N/day).
Nex,MMSC = Fraction of the total manure for each animal
type that is managed in MMS component MMSC, assumed to be equivalent
to the fraction of Nex in each MMS component.
Nss = Nitrogen removal through solid separation; if solid
separation occurs prior to the MMS component, use a default value
from Table JJ-4 of this

section; if no solid separation occurs, this value is set to 0.
EFMMSC = Emission factor for MMS component, as specified
in Table JJ-7 of this section (kg N2O-N/kg N).
[GRAPHIC] [TIFF OMITTED] TR30OC09.150

Where:

Nex AT = Total nitrogen excreted per animal type (kg/
day).
PopulationAT = Average annual animal population
contributing manure to the manure management system by animal type
(head) (see description in Sec.  98.363(a)(i) and (ii)).
TAMAT = Typical animal mass by animal type, using either
default values in Table JJ-2 of this section or farm-specific data
(kg/head).
NAT = Nitrogen excretion rate by animal type, using
default values in Tables JJ-2 or JJ-3 of this section (kg N/day/1000
kg animal mass).

    (d) Estimate the annual total facility emissions using Equation JJ-
15 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.151

Where:

CH4 emissionsMMS = From Equation JJ-2 of this
section.
CH4 emissionsAD = From Equation JJ-5 of this
section.
21 = Global Warming Potential of CH4.
Direct N2O emissions = From Equation JJ-13 of this
section.
310 = Global Warming Potential of N2O.

Sec.  98.364  Monitoring and QA/QC requirements.

    (a) Perform an annual animal inventory or review of facility
records (for static populations) or population calculation (for growing
populations) to determine the average annual animal population for each
animal type (see description in Sec.  98.363(a)(1) and (2)).
    (b) Perform an analysis on your operation to determine the fraction
of total manure by weight for each animal type that is managed in each
on-site manure management system component. If your system changes from
previous reporting periods, you must reevaluate the fraction of total
manure managed in each system component.
    (c) The CH4 concentration of gas from digesters must be
determined using ASTM D1946-90 (Reapproved 2006) Standard Practice for
Analysis of Reformed Gas by Gas Chromatography (incorporated by
reference see Sec.  98.7). All gas composition monitors shall be
calibrated prior to the first reporting year for biogas methane and
carbon dioxide content using ASTM D1946-90 (Reapproved 2006) Standard
Practice for Analysis of Reformed Gas by Gas Chromatography
(incorporated by reference see Sec.  98.7)and recalibrated either
annually or at the minimum frequency specified by the manufacturer,
whichever is more frequent, or whenever the error in the midrange
calibration check exceeds  10 percent. All monitors shall
be maintained as specified by the manufacturer.
    (d) All temperature and pressure monitors must be calibrated using
the procedures and frequencies specified by the manufacturer. All
equipment (temperature and pressure monitors) shall be maintained as
specified by the manufacturer.
    (e) For digesters with gas collection systems, install, operate,
maintain, and calibrate a gas flow meter capable of measuring the
volumetric flow rate to provide data for the GHG emissions
calculations, using the applicable methods specified in paragraphs
(e)(1) through (e)(6) of this section or as specified by the
manufacturer.
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec.
98.7).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by
Turbine Meters (incorporated by reference, see Sec.  98.7).
    (3) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters (incorporated by reference, see Sec.  98.7).
    (4) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles (incorporated by reference, see
Sec.  98.7).
    (5) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore
Precision Orifice Meters (incorporated by reference, see Sec.  98.7).
    (6) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area
Meters (incorporated by reference, see Sec.  98.7).
    (f) If applicable, the owner or operator shall document the
procedures used to ensure the accuracy of gas flow rate, gas
composition, temperature, and pressure measurements. These procedures
include, but are not limited to, calibration of fuel flow meters and
other measurement devices. The estimated accuracy of measurements made
with these devices shall also be recorded, and the technical basis for
these estimates shall be provided.
    (g) Each gas flow meter shall be calibrated prior to the first
reporting year and recalibrated either annually or at the minimum
frequency specified by the manufacturer, whichever is more frequent.
Each gas flow meter must have a rated accuracy of  5
percent or lower and be capable of correcting for the temperature and
pressure and, if the gas composition monitor determines CH4
concentration on a dry basis, moisture content.

Sec.  98.365  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter
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, according to the requirements in paragraph (b) of
this section.
    (b) For missing gas flow rates or CH4 content data, the
substitute data value shall be the arithmetic average of the quality-
assured values of that parameter immediately preceding and immediately
following the missing data incident. If, for a particular parameter, no
quality-assured data are available prior to the missing data incident,
the substitute data value shall be the first quality-assured value
obtained after the missing data period.

Sec.  98.366  Data reporting requirements.

    (a) In addition to the information required by Sec.  98.3(c), each
annual report must contain the following information:

    (1) List of manure management system components at the facility.
    (2) Fraction of manure from each animal type that is handled in
each manure management system component.
    (3) Average annual animal population (for each animal type) for
static populations or the results of Equation JJ-4 for growing
populations.
    (4) Average number of days that growing animals are kept at the
facility (for each animal type).
    (5) The number of animals produced annually for growing populations
(for each animal type).
    (6) Typical animal mass (for each animal type).
    (7) Total facility emissions (results of Equation JJ-15).
    (8) CH4 emissions from manure management system
components listed in Sec.  98.360(b), except digesters (results of
Equation JJ-2).
    (9) VS value used (for each animal type).
    (10) B0 value used (for each animal type).
    (11) Methane conversion factor used for each MMS component.
    (12) Average ambient temperature used to select each methane
conversion factor.
    (13) N2O emissions (results of Equation JJ-13).
    (14) N value used for each animal type.
    (15) N2O emission factor selected for each MMS
component.
    (b) Facilities with anaerobic digesters must also report:
    (1) CH4 emissions from anaerobic digesters (results of
Equation JJ-5).
    (2) CH4 flow to the digester combustion device for each
digester (results of Equation JJ-6, or value from fully integrated
monitoring system as described in 98.363(b)).
    (3) CH4 destruction for each digester (results of
Equation JJ-11).
    (4) CH4 leakage for each digester (results of Equation
JJ-12).
    (5) Total annual volumetric biogas flow for each digester (results
of Equation JJ-7).
    (6) Average annual CH4 concentration for each digester
(results of Equation JJ-8).
    (7) Average annual temperature at which gas flow is measured for
each digester (results of Equation JJ-9).
    (8) Average annual gas flow pressure at which gas flow is measured
for each digester (results of Equation JJ-10).
    (9) Destruction efficiency used for each digester.
    (10) Number of days per year that each digester was operating.
    (11) Collection efficiency used for each digester.

Sec.  98.367  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must
retain the calibration records for all monitoring equipment, including
the method or manufacturer's specification used for calibration.

Sec.  98.368  Definitions.

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

 Table JJ-1 to Subpart JJ of Part 98--Animal Population Threshold Level
    Below Which Facilities Are Not Required To Report Emissions Under
                             Subpart JJ 1,2
------------------------------------------------------------------------
                                                          Average annual
                                                              animal
                      Animal group                          population
                                                            (Head) \3\
------------------------------------------------------------------------
Beef....................................................          29,300
Dairy...................................................           3,200
Swine...................................................          34,100
Poultry:
    Layers..............................................         723,600
    Broilers............................................      38,160,000
    Turkeys.............................................       7,710,000
------------------------------------------------------------------------
\1\ The threshold head populations in this table were calculated using
  the most conservative assumptions (high VS and N values, maximum
  ambient temperatures, and the application of an uncertainty factor) to
  ensure that facilities at or near the 25,000 metric ton CO2e threshold
  level were not excluded from reporting.
\2\ For facilities with more than one animal group present refer to Sec.
    98.360 (2) to estimate the combined animal group factor (CAGF),
  which is used to determine if a facility may be required to report.
\3\ For all animal groups except dairy, the average annual animal
  population represents the total number of animals present at the
  facility. For dairy facilities, the average annual animal population
  represents the number of mature dairy cows present at the facility
  (note that heifers and calves were included in the emission estimates
  for dairy facilities using the assumption that the average annual
  animal population of heifers and calves at dairy facilities are equal
  to 30 percent of the mature dairy cow average annual animal
  population, therefore the average annual population for dairy
  facilities should not include heifers and calves, only dairy cows).

                         Table JJ-2 to Subpart JJ of Part 98--Waste Characteristics Data
----------------------------------------------------------------------------------------------------------------
                                                                                Maximum
                                                       Volatile solids                                methane
                                    Typical animal   excretion rate  (kg     Nitrogen excretion     generation
            Animal type               mass  (kg)    VS/day/1000 kg animal   rate  (kg N/day/1000   potential, Bo
                                                            mass)             kg animal mass)      (m\3\ CH4/kg
                                                                                VS added)
----------------------------------------------------------------------------------------------------------------
Dairy Cows........................             604  See Table JJ-3.......  See Table JJ-3.......            0.24
Dairy Heifers.....................             476  See Table JJ-3.......  See Table JJ-3.......            0.17
Dairy Calves......................             118  6.41.................  0.30.................            0.17
Feedlot Steers....................             420  See Table JJ-3.......  See Table JJ-3.......            0.33
Feedlot heifers...................             420  See Table JJ-3.......  See Table JJ-3.......            0.33
Market Swine <60 lbs..............              16  8.80.................  0.60.................            0.48
Market Swine 60-119 lbs...........              41  5.40.................  0.42.................            0.48
Market Swine 120-179 lbs..........              68  5.40.................  0.42.................            0.48
Market Swine >180 lbs.............              91  5.40.................  0.42.................            0.48
Breeding Swine....................             198  2.60.................  0.24.................            0.48

Feedlot Sheep.....................              25  9.20.................  0.42.................            0.36
Goats.............................              64  9.50.................  0.45.................            0.17
Horses............................             450  10.00................  0.30.................            0.33
Hens >/= 1 yr.....................             1.8  10.09................  0.83.................            0.39
Pullets...........................             1.8  10.09................  0.62.................            0.39
Other Chickens....................             1.8  10.80................  0.83.................            0.39
Broilers..........................             0.9  15.00................  1.10.................            0.36
Turkeys...........................             6.8  9.70.................  0.74.................            0.36
----------------------------------------------------------------------------------------------------------------

                  Table JJ-3 to Subpart JJ of Part 98--State-Specific Volatile Solids (VS) and Nitrogen (N) Excretion Rates for Cattle
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  Volatile solids excretion rate (kg VS/day/  Nitrogen excretion rate (kg VS/day/1000 kg
                                                                             1000 kg animal mass)                            animal mass)
                              State                              ---------------------------------------------------------------------------------------
                                                                    Dairy      Dairy     Feedlot    Feedlot     Dairy      Dairy     Feedlot    Feedlot
                                                                     cows     heifers     steer     heifers      cows     heifers     steer     heifers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama.........................................................       8.40       8.35       4.27       4.74       0.50       0.46       0.36       0.38
Alaska..........................................................       7.30       8.35       4.15       4.58       0.45       0.46       0.35       0.37
Arizona.........................................................      10.37       8.35       3.91       4.27       0.58       0.46       0.33       0.34
Arkansas........................................................       7.59       8.35       3.98       4.35       0.46       0.46       0.33       0.35
California......................................................      10.02       8.35       3.96       4.33       0.56       0.46       0.33       0.34
Colorado........................................................      10.25       8.35       3.97       4.34       0.58       0.46       0.33       0.35
Connecticut.....................................................       9.22       8.35       4.41       4.93       0.53       0.46       0.37       0.40
Delaware........................................................       8.63       8.35       4.19       4.64       0.51       0.46       0.35       0.37
Florida.........................................................       8.90       8.35       4.15       4.58       0.52       0.46       0.35       0.37
Georgia.........................................................       9.07       8.35       4.18       4.63       0.53       0.46       0.35       0.37
Hawaii..........................................................       7.00       8.35       4.15       4.58       0.44       0.46       0.35       0.37
Idaho...........................................................      10.11       8.35       4.03       4.42       0.57       0.46       0.34       0.35
Illinois........................................................       9.07       8.35       4.15       4.59       0.52       0.46       0.35       0.37
Indiana.........................................................       9.38       8.35       3.98       4.35       0.54       0.46       0.33       0.35
Iowa............................................................       9.46       8.35       3.93       4.28       0.54       0.46       0.33       0.34
Kansas..........................................................       9.63       8.35       3.97       4.35       0.55       0.46       0.33       0.35
Kentucky........................................................       7.89       8.35       4.20       4.65       0.48       0.46       0.35       0.37
Louisiana.......................................................       7.39       8.35       4.07       4.48       0.45       0.46       0.34       0.36
Maine...........................................................       8.99       8.35       4.07       4.47       0.52       0.46       0.34       0.36
Maryland........................................................       9.02       8.35       4.05       4.45       0.52       0.46       0.34       0.35
Massachusetts...................................................       8.63       8.35       4.15       4.58       0.51       0.46       0.35       0.37
Michigan........................................................      10.05       8.35       4.00       4.38       0.57       0.46       0.34       0.35
Minnesota.......................................................       9.17       8.35       3.89       4.24       0.53       0.46       0.33       0.34
Mississippi.....................................................       8.19       8.35       4.14       4.57       0.49       0.46       0.35       0.37
Missouri........................................................       8.02       8.35       4.08       4.49       0.48       0.46       0.34       0.36
Montana.........................................................       9.03       8.35       4.23       4.69       0.52       0.46       0.36       0.38
Nebraska........................................................       9.09       8.35       3.98       4.35       0.53       0.46       0.33       0.35
Nevada..........................................................       9.65       8.35       4.07       4.48       0.55       0.46       0.34       0.36
New Hampshire...................................................       9.44       8.35       3.94       4.30       0.54       0.46       0.33       0.34
New Jersey......................................................       8.51       8.35       3.98       4.36       0.50       0.46       0.33       0.35
New Mexico......................................................      10.34       8.35       3.88       4.22       0.58       0.46       0.32       0.33
New York........................................................       9.42       8.35       3.75       4.05       0.54       0.46       0.31       0.32
North Carolina..................................................       9.38       8.35       4.20       4.65       0.55       0.46       0.35       0.37
North Dakota....................................................       8.40       8.35       3.88       4.22       0.50       0.46       0.32       0.34
Ohio............................................................       9.01       8.35       3.96       4.33       0.52       0.46       0.33       0.34
Oklahoma........................................................       8.58       8.35       3.98       4.35       0.50       0.46       0.33       0.35
Oregon..........................................................       9.40       8.35       4.06       4.46       0.54       0.46       0.34       0.36
Pennsylvania....................................................       9.26       8.35       3.98       4.35       0.53       0.46       0.33       0.35
Rhode Island....................................................       8.94       8.35       4.36       4.87       0.52       0.46       0.37       0.39
South Carolina..................................................       9.05       8.35       4.15       4.58       0.53       0.46       0.35       0.37
South Dakota....................................................       9.45       8.35       4.01       4.39       0.54       0.46       0.34       0.35
Tennessee.......................................................       8.60       8.35       4.48       5.02       0.51       0.46       0.38       0.40
Texas...........................................................       9.51       8.35       3.95       4.32       0.54       0.46       0.33       0.34
Utah............................................................       9.70       8.35       3.88       4.22       0.55       0.46       0.32       0.34
Vermont.........................................................       9.03       8.35       4.10       4.52       0.52       0.46       0.34       0.36
Virginia........................................................       9.02       8.35       3.98       4.35       0.53       0.46       0.33       0.35
Washington......................................................      10.36       8.35       4.07       4.47       0.58       0.46       0.34       0.36
West Virginia...................................................       8.13       8.35       4.65       5.25       0.48       0.46       0.40       0.42
Wisconsin.......................................................       9.34       8.35       3.95       4.31       0.54       0.46       0.33       0.34

Wyoming.........................................................       9.29       8.35       4.17       4.61       0.53       0.46       0.35       0.37
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Table JJ-4 to Subpart JJ of Part 98--Volatile Solids and Nitrogen
                    Removal through Solids Separation
------------------------------------------------------------------------
                                    Volatile solids    Nitrogen removal
    Type of solids separation      removal (decimal)       (decimal)
------------------------------------------------------------------------
Gravity.........................                0.60                0.60
Mechanical:
    Stationary Screen...........                0.20                0.10
    Vibrating Screen............                0.15                0.15
    Screw Press.................                0.25                0.15
    Centrifuge..................                0.50                0.25
    Roller drum.................                0.25                0.15
    Belt press/screen...........                0.50                0.30
------------------------------------------------------------------------

BILLING CODE 6560-50-P

[GRAPHIC] [TIFF OMITTED] TR30OC09.192

BILLING CODE 6560-50-C

     Table JJ-6 to Subpart JJ of Part 98--Collection Efficiencies of
                           Anaerobic Digesters
------------------------------------------------------------------------
                                                              Methane
      Anaerobic digester type            Cover type         collection
                                                            efficiency
------------------------------------------------------------------------
Covered anaerobic lagoon (biogas    Bank to bank,                  0.975
 capture).                           impermeable.
                                    Modular, impermeable            0.70
Complete mix, fixed film, or plug   Enclosed Vessel.....            0.99
 flow digester.
------------------------------------------------------------------------

 Table JJ-7 to Subpart JJ of Part 98--Nitrous Oxide Emission Factors (kg
                            N2O-N/kg Kjdl N)
------------------------------------------------------------------------
                                                                 N2O
             Manure management system component                emission
                                                                factor
------------------------------------------------------------------------
Uncovered anaerobic lagoon.................................            0
Liquid/Slurry (with crust cover)...........................        0.005
Liquid/Slurry (without crust cover)........................            0
Storage pits...............................................        0.002
Digesters..................................................            0
Solid manure storage.......................................        0.005
Dry lots (including feedlots)..............................         0.02
High-rise house for poultry (poultry without litter).......        0.001
Poultry production with litter.............................        0.001
Deep bedding for cattle and swine (active mix).............         0.07
Deep bedding for cattle and swine (no mix).................         0.01
Manure Composting (in vessel)..............................        0.006
Manure Composting (intensive)..............................          0.1
Manure Composting (passive)................................         0.01
Manure Composting (static).................................        0.006
Aerobic Treatment (forced aeration)........................        0.005
Aerobic Treatment (natural aeration).......................         0.01
------------------------------------------------------------------------

Subpart KK--[Reserved]

Subpart LL--Suppliers of Coal-based Liquid Fuels

Sec.  98.380  Definition of the source category.

    This source category consists of producers, importers, and
exporters of products listed in Table MM-1 of subpart MM that are coal-
based (coal-to-liquid products).
    (a) A producer is the owner or operator of a coal-to-liquids
facility. A coal-to-liquids facility is any facility engaged in
converting coal into liquid products using a process involving
conversion of coal into gas and then into liquids (e.g., Fischer-
Tropsch) or conversion of coal directly into liquids (i.e., direct
liquefaction).
    (b) An importer or exporter shall have the same meaning given in
Sec.  98.6.

Sec.  98.381  Reporting threshold.

    Any supplier of coal-to-liquid products who meets the requirements
of Sec.  98.2(a)(4) must report GHG emissions.

Sec.  98.382  GHGs to report.

    You must report the CO2 emissions that would result from
the complete combustion or oxidation of fossil-fuel products (besides
coal or crude oil) that you produce, use as feedstock, import, or
export during the calendar year. Additionally, producers must report
CO2 emissions that would result from the complete combustion
or oxidation of any biomass co-processed with fossil fuel-based
feedstocks.

Sec.  98.383  Calculating GHG emissions.

    You must follow the calculation methodologies of Sec.  98.393 as if
they applied to the appropriate coal-to-liquid product supplier (i.e.,
calculation methodologies for refiners apply to producers of coal-to-
liquid products and calculation methodologies for importers and
exporters of petroleum products apply to importers and exporters of
coal-to-liquid products).
    (a) In calculation methodologies in Sec.  98.393 for petroleum
products or petroleum-based products, suppliers of coal-to-liquid
products shall also include coal-to-liquid products.
    (b) In calculation methodologies in Sec.  98.393 for non-crude
feedstocks or non-crude petroleum feedstocks, producers of coal-to-
liquid products shall also include coal-to-liquid products that enter
the facility to be further processed or otherwise used on site.
    (c) In calculation methodologies in Sec.  98.393 for petroleum
feedstocks, suppliers of coal-to-liquid products shall also include
coal and coal-to-liquid products that enter the facility to be further
processed or otherwise used on site.

Sec.  98.384  Monitoring and QA/QC requirements.

    You must follow the monitoring and QA/QC requirements in Sec.
98.394 as if they applied to the appropriate coal-to-liquid product
supplier. Any monitoring and QA/QC requirement for petroleum products
in Sec.  98.394 also applies to coal-to-liquid products.

Sec.  98.385  Procedures for estimating missing data.

    You must follow the procedures for estimating missing data in Sec.
98.395 as if they applied to the appropriate coal-to-liquid product
supplier. Any procedure for estimating missing data for petroleum
products in Sec.  98.395 also applies to coal-to-liquid products.

Sec.  98.386  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), the
following requirements apply:
    (a) Producers shall report the following information for each coal-
to-liquid facility:
    (1) For each product listed in Table MM-1 of subpart MM of this
part that enters the coal-to-liquid facility to be further processed or
otherwise used on site, report the annual quantity in metric tons or
barrels by each quantity measurement standard method or other industry
standard practice used. For natural gas liquids, quantity shall reflect
the individual components of the product.
    (2) For each product listed in Table MM-1 of subpart MM of this
part that enters the coal-to-liquid facility to be further processed or
otherwise used on site, report the total annual quantity in metric tons
or barrels. For natural gas liquids, quantity shall reflect the
individual components of the product.
    (3) For each feedstock reported in paragraph (a)(2) that was
produced by blending a fossil fuel-based product with a biomass-based
product, report the percent of the volume reported in paragraph (a)(2)
of this section that is fossil fuel-based.
    (4) Each standard method or other industry standard practice used
to measure each quantity reported in paragraph (a)(1) of this section.
    (5) For each product (leaving the coal-to-liquid facility) listed
in Table MM-1 of subpart MM of this part, report the annual quantity in
metric tons or barrels by each quantity measurement standard method or
other industry standard practice used. For natural gas liquids,
quantity shall reflect the individual components of the product.
    (6) For each product (leaving the coal-to-liquid facility) listed
in Table MM-1 of subpart MM of this part, report the total annual
quantity in metric tons or barrels. For natural gas liquids, quantity
shall reflect the individual components of the product.
    (7) For each product reported in paragraph (a)(6) of this section
that was produced by blending a fossil fuel-based

product with a biomass-based product, report the percent of the volume
reported in paragraph (a)(6) of this section that is fossil fuel-based.
    (8) Each standard method or other industry standard practice used
to measure each quantity reported in paragraph (a)(5) of this section.
    (9) For every feedstock reported in paragraph (a)(2) of this
section for which Calculation Methodology 2 of subpart MM of this part
was used to determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor.
    (10) For every non-solid feedstock reported in paragraph (a)(2) of
this section for which Calculation Methodology 2 of subpart MM of this
part was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (11) For every product reported in paragraph (a)(6) of this section
for which Calculation Methodology 2 of this subpart was used to
determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor.
    (12) For every non-solid product reported in paragraph (a)(6) of
this section for which Calculation Methodology 2 of subpart MM of this
part was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (13) For each specific type of biomass that enters the coal-to-
liquid facility to be co-processed with fossil fuel-based feedstock to
produce a product reported in paragraph (a)(6) of this section, report
the annual quantity in metric tons or barrels by each quantity
measurement standard method or other industry standard practice used.
    (14) For each specific type of biomass that enters the coal-to-
liquid facility to be co-processed with fossil fuel-based feedstock to
produce a product reported in paragraph (a)(6) of this section, report
the total annual quantity in metric tons or barrels.
    (15) Each standard method or other industry standard practice used
to measure each quantity reported in paragraph (a)(3) of this section.
    (16) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each feedstock reported in
paragraph (a)(2) of this section, calculated according to Sec.
98.393(b) or (h).
    (17) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each product (leaving the
coal-to-liquid facility) reported in paragraph (a)(6) of this section,
calculated according to Sec.  98.393(a) or (h).
    (18) Annual CO2 emissions in metric tons that would
result from the complete combustion or oxidation of each type of
biomass feedstock co-processed with fossil fuel-based feedstocks
reported in paragraph (a)(3) of this section, calculated according to
Sec.  98.393(c).
    (19) Annual CO2 emissions that would result from the
complete combustion or oxidation of all products, calculated according
to Sec.  98.393(d).
    (20) Annual quantity of bulk NGLs in metric tons or barrels
received for processing during the reporting year.
    (b) In addition to the information required by Sec.  98.3(c), each
importer shall report all of the following information at the corporate
level:
    (1) For each product listed in Table MM-1 of subpart MM of this
part, report the annual quantity in metric tons or barrels by each
quantity measurement standard method or other industry standard
practice used. For natural gas liquids, quantity shall reflect the
individual components of the product.
    (2) For each product listed in Table MM-1 of subpart MM of this
part, report the total annual quantity in metric tons or barrels. For
natural gas liquids, quantity shall reflect the individual components
of the product as listed in Table MM-1 of subpart MM of this part.
    (3) For each product reported in paragraph (b)(2) of this section
that was produced by blending a fossil fuel-based product with a
biomass-based product, report the percent of the volume reported in
paragraph (b)(2) of this section that is fossil fuel-based.
    (4) Each standard method or other industry standard practice used
to measure each quantity reported in paragraph (b)(1) of this section.
    (5) For each product reported in paragraph (b)(2) of this section
for which Calculation Methodology 2 of this subpart used was used to
determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c)
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons.
    (6) For each non-solid product reported in paragraph (b)(2) of this
section for which Calculation Methodology 2 of this subpart was used to
determine an emissions factor, report:
    (i) The density test results in metric tons ber barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each imported product
reported in paragraph (b)(2) of this section, calculated according to
Sec.  98.393(a).
    (8) The total sum of CO2 emissions that would result
from the complete combustion or oxidation of all imported products,
calculated according to Sec.  98.393(e).
    (c) In addition to the information required by Sec.  98.3(c), each
exporter shall report all of the following information at the corporate
level:
    (1) For each product listed in Table MM-1 of subpart MM of this
part, report the annual quantity in metric tons or barrels by each
quantity measurement standard method or other industry standard
practice used. For natural gas liquids, quantity shall reflect the
individual components of the product.
    (2) For each product listed in table MM-1 of subpart MM of this
part, report the total annual quantity in metric tons or barrels. For
natural gas liquids, quantity shall reflect the individual components
of the product.
    (3) For each product reported in paragraph (c)(2) of this section
that was produced by blending a fossil fuel-based product with a
biomass-based product, report the percent of the volume reported in
paragraph (c)(2) of this section that is fossil fuel-based.
    (4) Each standard method or other industry standard practice used
to measure each quantity reported in paragraph (c)(1) of this section.
    (5) For each product reported in paragraph (c)(2) of this section
for which Calculation Methodology 2 of this subpart was used to
determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c).

    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons.
    (6) For each non-solid product reported in paragraph (c)(2) of this
section for which Calculation Methodology 2 of this subpart used was
used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each exported product
reported in paragraph (c)(2) of this section, calculated according to
Sec.  98.393(a).
    (8) Total sum of CO2 emissions that would result from
the complete combustion or oxidation of all exported products,
calculated according to Sec.  98.393(e).

Sec.  98.387  Records that must be retained.

    You must retain records according to the requirements in Sec.
98.397 as if they applied to the appropriate coal-to-liquid product
supplier (e.g., retaining copies of all reports submitted to EPA under
Sec.  98.386 and records to support information contained in those
reports). Any records for petroleum products that are required to be
retained in Sec.  98.397 are also required for coal-to-liquid products.

Sec.  98.388  Definitions.

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

Subpart MM--Suppliers of Petroleum Products

Sec.  98.390  Definition of the source category.

    This source category consists of petroleum refineries and importers
and exporters of petroleum products and natural gas liquids as listed
in Table MM-1 of this subpart.
    (a) A petroleum refinery for the purpose of this subpart is any
facility engaged in producing petroleum products through the
distillation of crude oil.
    (b) A refiner is the owner or operator of a petroleum refinery.
    (c) Importer has the same meaning given in Sec.  98.6 and includes
any entity that imports petroleum products or natural gas liquids as
listed in Table MM-1 of this subpart. Any blender or refiner of refined
or semi-refined petroleum products shall be considered an importer if
it otherwise satisfies the aforementioned definition.
    (d) Exporter has the same meaning given in Sec.  98.6 and includes
any entity that exports petroleum products or natural gas liquids as
listed in Table MM-1 of this subpart. Any blender or refiner of refined
or semi-refined petroleum products shall be considered an exporter if
it otherwise satisfies the aforementioned definition.

Sec.  98.391  Reporting threshold.

    Any supplier of petroleum products who meets the requirements of
Sec.  98.2(a)(4) must report GHG emissions.

Sec.  98.392  GHGs To report.

    Suppliers of petroleum products must report the CO2
emissions that would result from the complete combustion or oxidation
of each petroleum product and natural gas liquid produced, used as
feedstock, imported, or exported during the calendar year.
Additionally, refiners must report CO2 emissions that would
result from the complete combustion or oxidation of any biomass co-
processed with petroleum feedstocks.

Sec.  98.393  Calculating GHG emissions.

    (a) Calculation for individual products produced, imported, or
exported.
    (1) Except as provided in paragraph (h) of this section, any
refiner, importer, or exporter shall calculate CO2 emissions
from each individual petroleum product and natural gas liquid using
Equation MM-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.152

Where:

CO2i = Annual CO2 emissions that would result
from the complete combustion or oxidation of each petroleum product
or natural gas liquid ``i'' (metric tons).
Producti = Annual volume of product ``i'' produced,
imported, or exported by the reporting party (barrels). For
refiners, this volume only includes products ex refinery gate. For
natural gas liquids, volumes shall reflect the individual components
of the product as listed in Table MM-1 of this subpart.
EFi = Product-specific CO2 emission factor
(metric tons CO2 per barrel).

    (2) In the event that an individual petroleum product is
produced as a solid rather than liquid any refiner, importer, or
exporter shall calculate CO2 emissions using Equation MM-
1 of this section.

Where:

CO2i = Annual CO2 emissions that would result
from the complete combustion or oxidation of each petroleum product
``i'' (metric tons).
Producti = Annual mass of product ``i'' produced,
imported, or exported by the reporting party (metric tons). For
refiners, this mass only includes products ex refinery gate.
EFi = Product-specific CO2 emission factor
(metric tons CO2 per metric ton of product).

    (b) Calculation for individual products that enter a refinery as a
non-crude feedstock.
    (1) Except as provided in paragraph (h) of this section, any
refiner shall calculate CO2 emissions from each non-crude
feedstock using Equation MM-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.153

Where:

CO2j = Annual CO2 emissions that would result
from the complete combustion or oxidation of each non-crude
feedstock ``j'' (metric tons).
Feedstockj = Annual volume of a petroleum product or
natural gas liquid ``j'' that enters the refinery to be further
refined or otherwise used on site (barrels). For natural gas
liquids, volumes shall reflect the individual components of the
product as listed in table MM-1 of this subpart.
EFj = Feedstock-specific CO2 emission factor
(metric tons CO2 per barrel).

    (2) In the event that a non-crude feedstock enters a refinery as a
solid rather than liquid, the refiner shall calculate CO2
emissions using Equation MM-2 of this section.

Where:

CO2j = Annual CO2 emissions that would result
from the complete combustion or oxidation of each non-crude
feedstock ``j'' (metric tons).
Feedstockj = Annual mass of a petroleum product ``j''
that enters the refinery to be further refined or otherwise used on
site (metric tons).
EFj = Feedstock-specific CO2 emission factor
(metric tons CO2 per metric ton of feedstock).

    (c) Calculation for biomass co-processed with petroleum feedstocks.
    (1) Refiners shall calculate CO2 emissions from each
type of biomass that enters a refinery and is co-processed with
petroleum feedstocks using Equation MM-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.154

Where:

CO2m = Annual CO2 emissions that would result
from the complete combustion or oxidation of each type of biomass
``m'' (metric tons).
Biomassm = Annual volume of a specific type of biomass
that enters the refinery and is co-processed with petroleum
feedstocks to produce a petroleum product reported under paragraph
(a) of this section (barrels).

EFm = Biomass-specific CO2 emission factor
(metric tons CO2 per barrel).

    (2) In the event that biomass enters a refinery as a solid rather
than liquid and is co-processed with petroleum feedstocks, the refiner
shall calculate CO2 emissions from each type of biomass
using Equation MM-3 of this section.

Where:

CO2m = Annual CO2 emissions that would result
from the complete combustion or oxidation of each type of biomass
``m'' (metric tons).
Biomassm = Total annual mass of a specific type of
biomass that enters the refinery to be co-processed with petroleum
feedstocks to produce a petroleum product reported under paragraph
(a) of this section (metric tons).
EFm = Biomass-specific CO2 emission factor
(metric tons CO2 per metric ton of biomass).

    (d) Summary calculation for refinery products. Refiners shall
calculate annual CO2 emissions from all products using
Equation MM-4 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.155

Where:

CO2r = Annual CO2 emissions that would result
from the complete combustion or oxidation of all petroleum products
and natural gas liquids (ex refinery gate) minus non-crude
feedstocks and any biomass to be co-processed with petroleum
feedstocks.
CO2i = Annual CO2 emissions that would result
from the complete combustion or oxidation of each petroleum product
or natural gas liquid ``i'' (metric tons).
CO2j = Annual CO2 emissions that would result
from the complete combustion or oxidation of each non-crude
feedstock ``j'' (metric tons).
CO2m = Annual CO2 emissions that would result
from the complete combustion or oxidation of each type of biomass
``m'' (metric tons).

    (e) Summary calculation for importer and exporter products.
Importers and exporters shall calculate annual CO2 emissions
from all petroleum products and natural gas liquids imported or
exported, respectively, using Equations MM-1 and MM-5 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.156

Where:

CO2i = Annual CO2 emissions that would result
from the complete combustion or oxidation of each petroleum product
or natural gas liquid ``i'' (metric tons).
CO2x = Annual CO2 emissions that would result
from the complete combustion or oxidation of all petroleum products
and natural gas liquids.

    (f) Emission factors for petroleum products and natural gas
liquids. The emission factor (EFi,j) for each petroleum
product and natural gas liquid shall be determined using either of the
calculation methods described in paragraphs (f)(1) or (f)(2) of this
section. The same calculation method must be used for the entire
quantity of the product for the reporting year. For refiners, the
quantity of a product that enters a refinery (i.e., a non-crude
feedstock) is considered separate from the quantity of a product ex
refinery gate.
    (1) Calculation Method 1. For solid products, use the default
carbon share factor (i.e., percent carbon by mass) in column B of Table
MM-1 of this subpart for the appropriate product. For all other
products, use the default CO2 emission factor listed in
column C of Table MM-1 of this subpart for the appropriate product.
    (2) Calculation Method 2.
    (i) For solid products, develop emission factors according to
Equation MM-6 of this section using a value of 1 for density and direct
measurements of carbon share according to methods set forth in Sec.
98.394(c). For all other products, develop emission factors according
to Equation MM-6 of this section using direct measurements of density
and carbon share according to methods set forth in Sec.  98.394(c).
[GRAPHIC] [TIFF OMITTED] TR30OC09.157

Where:

EFi,j = Emission factor of the petroleum product or
natural gas liquid (metric tons CO2 per barrel or per
metric ton of product).
Density = Density of the petroleum product or natural gas liquid
(metric tons per barrel for non-solid products, 1 for solid
products).
Carbon share = Percent of total mass that carbon represents in the
petroleum product or natural gas liquid, expressed as a fraction
(e.g., 75% would be expressed as 0.75 in the above equation).
44/12 = Conversion factor for carbon to carbon dioxide.

    (ii) If you use a standard method that involves gas chromatography
to determine the percent mass of each component in a product, calculate
the product's carbon share using Equation MM-7 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.158

Where:

Carbon Share = Percent of total mass that carbon represents in the
petroleum product or natural gas liquid.
%Composition i* * *n = Percent of total mass that each molecular
component in the petroleum product or natural gas liquid represents
as determined by the procedures in the selected standard method.
%Massi* * *n = Percent of total mass that carbon
represents in each molecular component of the petroleum product or
natural gas liquid.

    (g) Emission factors for biomass co-processed with petroleum
feedstocks. Refiners shall use the most appropriate default
CO2 emission factor (EFm) for biomass in Table
MM-2 of this subpart to calculate CO2 emissions in paragraph
(c) of this section.
    (h) Special procedures for blended biomass-based fuels. In the
event that some portion of a petroleum product is biomass-based and was
not derived by co-processing biomass and petroleum feedstocks together
(i.e., the petroleum product was produced by blending a

petroleum-based product with a biomass-based fuel), the reporting party
shall calculate emissions for the petroleum product according to one of
the methods in paragraphs (h)(1) through (h)(4) of this section, as
appropriate.
    (1) A reporter using Calculation Methodology 1 to determine the
emission factor of a petroleum product shall calculate the
CO2 emissions associated with that product using Equation
MM-8 of this section in place of Equation MM-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.159

Where:

CO2i = Annual CO2 emissions that would result
from the complete combustion or oxidation of each petroleum product
``i'' (metric tons).
Producti = Annual volume of each petroleum product ``i''
produced, imported, or exported by the reporting party (barrels).
For refiners, this volume only includes products ex refinery gate.
EFi = Petroleum product-specific CO2 emission
factor (metric tons CO2 per barrel) from Table MM-1 of
this subpart.
%Voli = Percent volume of product ``i'' that is
petroleum-based, including 2.5% of the volume of any ethanol product
blended into a petroleum-based product to represent the denaturant
in that ethanol product, expressed as a fraction (e.g., 75% would be
expressed as 0.75 in the above equation).

    (2) A refinery using Calculation Methodology 1 of this subpart to
determine the emission factor of a non-crude petroleum feedstock shall
calculate the CO2 emissions associated with that feedstock
using Equation MM-9 of this section in place of Equation MM-2 of this
section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.160

Where:

CO2j = Annual CO2 emissions that would result
from the complete combustion or oxidation of each non-crude
feedstock ``j'' (metric tons).
Feedstockj = Annual volume of each petroleum product
``j'' that enters the refinery as a feedstock to be further refined
or otherwise used on site (barrels).
EFj = Non-crude petroleum feedstock-specific
CO2 emission factor (metric tons CO2 per
barrel).
%Volj = Percent volume of feedstock ``j'' that is
petroleum-based, including 2.5% of the volume of any ethanol product
blended with the petroleum-based product to represent the denaturant
in that ethanol product, expressed as a fraction (e.g., 75% would be
expressed as 0.75 in the above equation).

    (3) A reporter using Calculation Methodology 2 of this subpart to
determine the emission factor of a petroleum product must calculate the
CO2 emissions associated with that product using Equation
MM-10 of this section in place of Equation MM-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.161

Where:

CO2i = Annual CO2 emissions that would result
from the complete combustion or oxidation of each product ``i''
(metric tons).
Producti = Annual volume of each petroleum product ``i''
produced, imported, or exported by the reporting party (barrels).
For refiners, this volume only includes products ex refinery gate.
EFi = Product-specific CO2 emission factor
(metric tons CO2 per barrel).
EFm = Default CO2 emission factor from Table
MM-2 of this subpart that most closely represents the component of
product ``i'' that is biomass-based.
%Volm = Percent volume of petroleum product ``i'' that is
biomass-based, not including 2.5% of the volume of any ethanol
product blended with the petroleum-based product, which represents
the denaturant in that ethanol product, expressed as a fraction
(e.g., 75% would be expressed as 0.75 in the above equation).

    (4) A refiner using Calculation Methodology 2 of this subpart to
determine the emission factor of a non-crude petroleum feedstock must
calculate the CO2 emissions associated with that feedstock
using Equation MM-11 of this section in place of Equation MM-2 of this
section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.162

Where:

CO2j = Annual CO2 emissions that would result
from the complete combustion or oxidation of each non-crude
feedstock ``j'' (metric tons).
Feedstockj = Annual volume of each petroleum product
``j'' that enters the refinery to be further refined or otherwise
used on site (barrels).
EFj = Feedstock-specific CO2 emission factor
(metric tons CO2 per barrel).
EFm = Default CO2 emission factor from Table
MM-2 of this subpart that most closely represents the component of
petroleum product ``j'' that is biomass-based.
%Volm = Percent volume of non-crude feedstock ``j'' that
is biomass-based, not including 2.5% of the volume of any ethanol
product blended with the petroleum-based product, which represents
the denaturant in that ethanol product, expressed as a fraction
(e.g., 75% would be expressed as 0.75 in the above equation).

Sec.  98.394  Monitoring and QA/QC requirements.

    (a) Determination of quantity.
    (1) The quantity of petroleum products, natural gas liquids,
biomass, and crude oil shall be determined as follows:
    (i) Where an appropriate standard method published by a consensus-
based standards organization exists, such a method shall be used.
Consensus-based

standards organizations include, but are not limited to, the following:
ASTM International, the American National Standards Institute (ANSI),
the American Gas Association (AGA), the American Society of Mechanical
Engineers (ASME), the American Petroleum Institute (API), and the North
American Energy Standards Board (NAESB).
    (ii) Where no appropriate standard method developed by a consensus-
based standards organization exists, industry standard practices shall
be followed.
    (iii) For products that are liquid at 60 degrees Fahrenheit and one
standard atmosphere, all measurements of quantity shall be temperature-
adjusted and pressure-adjusted to these conditions. For all other
products, reporters shall use appropriate standard conditions specified
in the standard method; if temperature and pressure conditions are not
specified in the standard method or if a reporter uses an industry
standard practice to determine quantity, the reporter shall use
appropriate standard conditions according to established industry
practices.
    (2) All measurement equipment (including, but not limited to, flow
meters and tank gauges) used for compliance with this subpart shall be
appropriate for the standard method or industry standard practice
followed under paragraph (a)(1)(i) or (a)(1)(ii) of this section.
    (b) Equipment Calibration.
    (1) All measurement equipment shall be calibrated prior to its
first use for reporting under this subpart, using an appropriate
standard method published by a consensus based standards organization
or according to the equipment manufacturer's directions.
    (2) Measurement equipment shall be recalibrated at the minimum
frequency specified by the standard method used or by the equipment
manufacturer's directions.
    (c) Procedures for Calculation Methodology 2 of this subpart.
    (1) Reporting parties shall collect one sample of each petroleum
product or natural gas liquid on any day of each calendar month of the
reporting year in which the quantity of that product was measured in
accordance with the requirements of this subpart. For example, if a
given product was measured as entering the refinery continuously
throughout the reporting year, twelve samples of that product shall be
collected over the reporting year, one on any day of each calendar
month of that year. If a given product was only measured from April 15
through June 10 of the reporting year, a refiner would collect three
samples during that year, one during each of the calendar months of
April, May and June on a day when the product was measured as either
entering or exiting the refinery. Each sample shall be collected using
an appropriate standard method published by a consensus-based standards
organization.
    (2) Mixing and handling of samples shall be performed using an
appropriate standard method published by a consensus-based standards
organization.
    (3) Density measurement.
    (i) For all products that are not solid, reporters shall test for
density using an appropriate standard method published by a consensus-
based standards organization.
    (ii) The density value for a given petroleum product shall be
generated by either making a physical composite of all of the samples
collected for the reporting year and testing that single sample or by
measuring the individual samples throughout the year and defining the
representative density value for the sample set by numerical means,
i.e., a mathematical composite. If a physical composite is chosen as
the option to obtain the density value, the reporter shall submit each
of the individual samples collected during the reporting year to the
laboratory responsible for generating the composite sample.
    (iii) For physical composites, the reporter shall handle the
individual samples and the laboratory shall mix them in accordance with
an appropriate standard method published by a consensus-based standards
organization.
    (iv) All measurements of density shall be temperature-adjusted and
pressure-adjusted to the conditions assumed for determining the
quantities of the product reported under this subpart.
    (4) Carbon share measurement.
    (i) Reporters shall test for carbon share using an appropriate
standard method published by a consensus-based standards organization.
    (ii) If a standard method that involves gas chromatography is used
to determine the percent mass of each component in a product, the
molecular formula for each component shall be obtained from the
information provided in the standard method and the atomic mass of each
element in a given molecular component shall be obtained from the
periodic table of the elements.
    (iii) The carbon share value for a given petroleum product shall be
generated by either making a physical composite of all of the samples
collected for the reporting year and testing that single sample or by
measuring the individual samples throughout the year and defining the
representative carbon share value for the sample set by numerical
means, i.e., a mathematical composite. If a physical composite is
chosen as the option to obtain the carbon share value, the reporter
shall submit each of the individual samples collected during the
reporting year to the laboratory responsible for generating the
composite sample.
    (iv) For physical composites, the reporter shall handle the
individual samples and the laboratory shall mix them in accordance with
an appropriate standard method published by a consensus-based standards
organization.
    (d) Measurement of API gravity and sulfur content of crude oil.
    (1) Samples of each batch of crude oil shall be taken according to
an appropriate standard method published by a consensus-based standards
organization.
    (2) Samples shall be handled according to an appropriate standard
method published by a consensus-based standards organization.
    (3) API gravity shall be measured using an appropriate standard
method published by a consensus-based standards organization.
    (4) Sulfur content shall be measured using an appropriate standard
method published by a consensus-based standards organization.
    (5) All measurements shall be temperature-adjusted and pressure-
adjusted to the conditions assumed for determining the quantities of
crude oil reported under this subpart.

Sec.  98.395  Procedures for estimating missing data.

    (a) Determination of quantity. Whenever the quality assurance
procedures in Sec.  98.394(a) cannot be followed to measure the
quantity of one or more petroleum products, natural gas liquids, types
of biomass, feedstocks, or crude oil batches during any period (e.g.,
if a meter malfunctions), the following missing data procedures shall
be used:
    (1) For quantities of a product that are purchased or sold, a
period of missing data shall be substituted using a reporter's
established procedures for billing purposes in that period as agreed to
by the party selling or purchasing the product.
    (2) For quantities of a product that are not purchased or sold but
of which the custody is transferred, a period of missing data shall be
substituted using a reporter's established procedures for tracking
purposes in that period as agreed to by the party involved in custody
transfer of the product.

    (b) Determination of emission factor. Whenever any of the
procedures in Sec.  98.394(c) cannot be followed to develop an emission
factor for any reason, Calculation Methodology 1 of this subpart must
be used in place of Calculation Methodology 2 of this subpart for the
entire reporting year.
    (c) Determination of API gravity and sulfur content of crude oil.
For missing data on sulfur content or API gravity, the substitute data
value shall be the arithmetic average of the quality-assured values of
API gravity or sulfur content in the batch preceding and the batch
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 values for API gravity
and sulfur content obtained from the batch after the missing data
period.

Sec.  98.396  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), the
following requirements apply:
    (a) Refiners shall report the following information for each
facility:
    (1) For each petroleum product or natural gas liquid listed in
table MM-1 of this subpart that enters the refinery to be further
refined or otherwise used on site, report the annual quantity in metric
tons or barrels by each quantity measurement standard method or other
industry standard practice used. For natural gas liquids, quantity
shall reflect the individual components of the product.
    (2) For each petroleum product or natural gas liquid listed in
Table MM-1 of this subpart that enters the refinery to be further
refined or otherwise used on site, report the annual quantity in metric
tons or barrels. For natural gas liquids, quantity shall reflect the
individual components of the product.
    (3) For each feedstock reported in paragraph (a)(2) of this section
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph
(a)(2) of this section that is petroleum-based.
    (4) Each standard method or other industry standard practice used
to measure each quantity reported in paragraph (a)(1) of this section.
    (5) For each petroleum product and natural gas liquid (ex refinery
gate) listed in Table MM-1 of this subpart, report the annual quantity
in metric tons or barrels by each quantity measurement standard method
or other industry standard practice used. For natural gas liquids,
quantity shall reflect the individual components of the product.
    (6) For each petroleum product and natural gas liquid (ex refinery
gate) listed in Table MM-1 of this subpart, report the annual quantity
in metric tons or barrels. For natural gas liquids, quantity shall
reflect the individual components of the product.
    (7) For each product reported in paragraph (a)(6) of this section
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph
(a)(6) of this section that is petroleum-based.
    (8) Each standard method or other industry standard practice used
to measure each quantity reported in paragraph (a)(5) of this section.
    (9) For every feedstock reported in paragraph (a)(2) of this
section for which Calculation Methodology 2 of this subpart was used to
determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c)
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percentmass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons.
    (10) For every non-solid feedstock reported in paragraph (a)(2) of
this section for which Calculation Methodology 2 of this subpart was
used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (11) For every petroleum product and natural gas liquid reported in
paragraph (a)(6) of this section for which Calculation Methodology 2 of
this subpart was used to determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percentmass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons
CO2 per barrel or per metric ton of product.
    (12) For every non-solid petroleum product and natural gas liquid
reported in paragraph (a)(6) for which Calculation Method 2 was used to
determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (13) For each specific type of biomass that enters the refinery to
be co-processed with petroleum feedstocks to produce a petroleum
product reported in paragraph (a)(6) of this section, report the annual
quantity in metric tons or barrels by each quantity measurement
standard method or other industry standard practice used.
    (14) For each specific type of biomass that enters the refinery to
be co-processed with petroleum feedstocks to produce a petroleum
product reported in paragraph (a)(6) of this section, report the annual
quantity in metric tons or barrels.
    (15) Each standard method or other industry standard practice used
to measure each quantity reported in paragraph (a)(13) of this section.
    (16) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each petroleum product and
natural gas liquid (ex refinery gate) reported in paragraph (a)(6) of
this section, calculated according to Sec.  98.393(a) or (h).
    (17) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each feedstock reported in
paragraph (a)(2) of this section, calculated according to Sec.
98.393(b) or (h).
    (18) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each type of biomass
feedstock co-processed with petroleum feedstocks reported in paragraph
(a)(13) of this section, calculated according to Sec.  98.393(c).
    (19) The sum of CO2 emissions that would result from the
complete combustion or oxidation of all products, calculated according
to Sec.  98.393(d).
    (20) All of the following information for all crude oil feedstocks
used at the refinery:
    (i) Batch volume in barrels.
    (ii) API gravity of the batch at the point of entry at the
refinery.
    (iii) Sulfur content of the batch at the point of entry at the
refinery.
    (iv) Country of origin of the batch, if known.
    (21) The quantity of bulk NGLs in metric tons or barrels received
for processing during the reporting year.
    (b) In addition to the information required by Sec.  98.3(c), each
importer shall report all of the following information at the corporate
level:
    (1) For each petroleum product and natural gas liquid listed in
Table MM-1 of this subpart, report the annual quantity in metric tons
or barrels by each quantity measurement standard method or other
industry standard practice used. For natural gas liquids,

quantity shall reflect the individual components of the product.
    (2) For each petroleum product and natural gas liquid listed in
Table MM-1 of this subpart, report the annual quantity in metric tons
or barrels. For natural gas liquids, quantity shall reflect the
individual components of the product as listed in Table MM-1 of this
subpart.
    (3) For each product reported in paragraph (b)(2) of this section
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph
(b)(2) of this section that is petroleum-based.
    (4) Each standard method or other industry standard practice used
to measure each quantity reported in paragraph (b)(1) of this section.
    (5) For each product reported in paragraph (b)(2) of this section
for which Calculation Methodology 2 of this subpart used was used to
determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons
CO2 per barrel or per metric ton of product.
    (6) For each non-solid product reported in paragraph (b)(2) of this
section for which Calculation Methodology 2 of this subpart was used to
determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each imported petroleum
product and natural gas liquid reported in paragraph (b)(2) of this
section, calculated according to Sec.  98.393(a).
    (8) The sum of CO2 emissions that would result from the
complete combustion oxidation of all imported products, calculated
according to Sec.  98.393(e).
    (c) In addition to the information required by Sec.  98.3(c), each
exporter shall report all of the following information at the corporate
level:
    (1) For each petroleum product and natural gas liquid listed in
Table MM-1 of this subpart, report the annual quantity in metric tons
or barrels by each quantity measurement standard method or other
industry standard practice used. For natural gas liquids, quantity
shall reflect the individual components of the product.
    (2) For each petroleum product and natural gas liquid listed in
Table MM-1 of this subpart, report the annual quantity in metric tons
or barrels. For natural gas liquids, quantity shall reflect the
individual components of the product.
    (3) For each product reported in paragraph (c)(2) of this section
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph
(c)(2) of this section that is petroleum based.
    (4) Each standard method or other industry standard practice used
to measure each quantity reported in paragraph (c)(1) of this section.
    (5) For each product reported in paragraph (c)(2) of this section
for which Calculation Methodology 2 of this subpart was used to
determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percentmass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons
CO2 per barrel or per metric ton of product.
    (6) For each non-solid product reported in paragraph (c)(2) of this
section for which Calculation Methodology 2 of this subpart used was
used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of for each exported
petroleum product and natural gas liquid reported in paragraph (c)(2)
of this section, calculated according to Sec.  98.393(a).
    (8) The sum of CO2 emissions that would result from the
complete combustion or oxidation of all exported products, calculated
according to Sec.  98.393(e).

Sec.  98.397  Records that must be retained.

    (a) All reporters shall retain copies of all reports submitted to
EPA under Sec.  98.396. In addition, all reporters shall maintain
sufficient records to support information contained in those reports,
including but not limited to information on the characteristics of
their feedstocks and products.
    (b) Reporters shall maintain records to support quantities that are
reported under this subpart, including records documenting any
estimations of missing data and the number of calendar days in the
reporting year for which substitute data procedures were followed. For
all quantities of petroleum products, natural gas liquids, biomass, and
feedstocks, reporters shall maintain metering, guaging, and other
records normally maintained in the course of business to document
product and feedstock flows including the date of initial calibration
and the frequency of recalibration for the measurement equipment used
    (c) Reporters shall retain laboratory reports, calculations and
worksheets used to estimate the CO2 emissions of the
quantities of petroleum products, natural gas liquids, biomass, and
feedstocks reported under this subpart.
    (d) Reporters shall maintain laboratory reports, calculations and
worksheets used in the measurement of density and carbon share for any
petroleum product or natural gas liquid for which CO2
emissions were calculated using Calculation Methodology 2.
    (e) Reporters shall maintain laboratory reports, calculations and
worksheets used in the measurement of API gravity and sulfur content
for every crude oil batch reported under this subpart.
    (f) Estimates of missing data shall be documented and records
maintained showing the calculations.
    (g) Reporters described in this subpart shall also retain all
records described in Sec.  98.3(g).

Sec.  98.398  Definitions.

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

   Table MM-1 to Subpart MM of Part 98--Default Factors for Petroleum
                  Products and Natural Gas Liquids 1 2
------------------------------------------------------------------------
                                                              Column C:
                                    Column A:    Column B:     emission
                                     density       carbon       factor
             Products                (metric    share (% of    (metric
                                    tons/bbl)      mass)      tons CO2/
                                                                 bbl)
------------------------------------------------------------------------
Finished Motor Gasoline
------------------------------------------------------------------------
Conventional--Summer
    Regular......................       0.1181        86.66       0.3753
    Midgrade.....................       0.1183        86.63       0.3758
    Premium......................       0.1185        86.61       0.3763
Conventional--Winter
    Regular......................       0.1155        86.50       0.3663
    Midgrade.....................       0.1161        86.55       0.3684
    Premium......................       0.1167        86.59       0.3705
Reformulated--Summer
    Regular......................       0.1167        86.13       0.3686
    Midgrade.....................       0.1165        86.07       0.3677
    Premium......................       0.1164        86.00       0.3670
Reformulated--Winter
    Regular......................       0.1165        86.05       0.3676
    Midgrade.....................       0.1165        86.06       0.3676
    Premium......................       0.1166        86.06       0.3679
Gasoline--Other..................       0.1185        86.61       0.3763
------------------------------------------------------------------------
Blendstocks
------------------------------------------------------------------------
CBOB--Summer
    Regular......................       0.1181        86.66       0.3753
    Midgrade.....................       0.1183        86.63       0.3758
    Premium......................       0.1185        86.61       0.3763
CBOB--Winter
    Regular......................       0.1155        86.50       0.3663
    Midgrade.....................       0.1161        86.55       0.3684
    Premium......................       0.1167        86.59       0.3705
RBOB--Summer
    Regular......................       0.1167        86.13       0.3686
    Midgrade.....................       0.1165        86.07       0.3677
    Premium......................       0.1164        86.00       0.3670
RBOB--Winter
    Regular......................       0.1165        86.05       0.3676
    Midgrade.....................       0.1165        86.06       0.3676
    Premium......................       0.1166        86.06       0.3679
Blendstocks--Other...............       0.1185        86.61       0.3763
------------------------------------------------------------------------
Oxygenates
------------------------------------------------------------------------
Methanol.........................       0.1268        37.48       0.1743
GTBA.............................       0.1257        64.82       0.2988
MTBE.............................       0.1181        68.13       0.2950
ETBE.............................       0.1182        70.53       0.3057
TAME.............................       0.1229        70.53       0.3178
DIPE.............................       0.1156        70.53       0.2990
------------------------------------------------------------------------
Distillate Fuel Oil
------------------------------------------------------------------------
Distillate No. 1
    Ultra Low Sulfur.............       0.1346        86.40       0.4264
    Low Sulfur...................       0.1346        86.40       0.4264
    High Sulfur..................       0.1346        86.40       0.4264
Distillate No. 2
    Ultra Low Sulfur.............       0.1342        87.30       0.4296
    Low Sulfur...................       0.1342        87.30       0.4296
    High Sulfur..................       0.1342        87.30       0.4296
Distillate Fuel Oil No. 4........       0.1452        86.47       0.4604
Residual Fuel Oil No. 5 (Navy           0.1365        85.67       0.4288
 Special)........................
Residual Fuel Oil No. 6 (a.k.a.         0.1528        84.67       0.4744
 Bunker C).......................
Kerosene-Type Jet Fuel...........       0.1294        86.30       0.4095
Kerosene.........................       0.1346        86.40       0.4264
Diesel--Other....................       0.1452        86.47       0.4604
------------------------------------------------------------------------
Petrochemical Feedstocks
------------------------------------------------------------------------

    Naphthas (< 401 [deg]F)......       0.1158        84.11       0.3571
    Other Oils (> 401 [deg]F)....       0.1390        87.30       0.4450
------------------------------------------------------------------------
Unfinished Oils
------------------------------------------------------------------------
Heavy Gas Oils...................       0.1476        85.80       0.4643
Residuum.........................       0.1622        85.70       0.5097
------------------------------------------------------------------------
Other Petroleum Products and Natural Gas Liquids
------------------------------------------------------------------------
Aviation Gasoline................       0.1120        85.00       0.3490
Special Naphthas.................       0.1222        84.76       0.3798
Lubricants.......................       0.1428        85.80       0.4492
Waxes............................       0.1285        85.30       0.4019
Petroleum Coke...................       0.1818        92.28       0.6151
Asphalt and Road Oil.............       0.1634        83.47       0.5001
Still Gas........................       0.1405        77.70       0.4003
Ethane...........................       0.0866        79.89       0.2537
Ethylene.........................       0.0903        85.63       0.2835
Propane..........................       0.0784        81.71       0.2349
Propylene........................       0.0803        85.63       0.2521
Butane...........................       0.0911        82.66       0.2761
Butylene.........................       0.0935        85.63       0.2936
Isobutane........................       0.0876        82.66       0.2655
Isobutylene......................       0.0936        85.63       0.2939
Pentanes Plus....................       0.1055        83.63       0.3235
Miscellaneous Products...........       0.1380        85.49       0.4326
------------------------------------------------------------------------
\1\ In the case of products blended with some portion of biomass-based
  fuel, the carbon share in Table MM-1 of this subpart represents only
  the petroleum-based components.
\2\ Products that are derived entirely from biomass should not be
  reported, but products that were derived from both biomass and a
  petroleum product (i.e., co-processed) should be reported as the
  petroleum product that it most closely represents.

 Table MM-2 to Subpart MM of Part 98--Default Factors for Biomass-Based
                            Fuels and Biomass
------------------------------------------------------------------------
                                                              Column C:
                                    Column A:    Column B:     Emission
                                     Density       Carbon       factor
  Biomass-based fuel and biomass     (metric    share (% of    (metric
                                    tons/bbl)      mass)      tons CO2/
                                                                 bbl)
------------------------------------------------------------------------
Ethanol (100%)...................       0.1267        52.14       0.2422
Biodiesel (100%, methyl ester)...       0.1396        77.30       0.3957
Rendered Animal Fat..............       0.1333        76.19       0.3724
Vegetable Oil....................       0.1460        76.77       0.4110
------------------------------------------------------------------------

Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids

Sec.  98.400  Definition of the source category.

    This supplier category consists of natural gas liquids
fractionators and local natural gas distribution companies.
    (a) Natural gas liquids fractionators are installations that
fractionate natural gas liquids (NGLs) into their consitutent liquid
products (ethane, propane, normal butane, isobutane or pentanes plus)
for supply to downstream facilities.
    (b) Local Distribution Companies (LDCs) are companies that own or
operate distribution pipelines, not interstate pipelines or intrastate
pipelines, that physically deliver natural gas to end users and that
are regulated as separate operating companies by State public utility
commissions or that operate as independent municipally-owned
distribution systems.
    (c) This supply category does not consist of the following
facilities:
    (1) Field gathering and boosting stations.
    (2) Natural gas processing plants that separate NGLs from natural
gas and produce bulk or y-grade NGLs but do not fractionate these NGLs
into their constituent products.
    (3) Facilities that meet the definition of refineries and report
under subpart MM of this part.
    (4) Facilities that meet the definition of petrochemical plants and
report under subpart X of this part.

Sec.  98.401  Reporting threshold.

    Any supplier of natural gas and natural gas liquids that meets the
requirements of Sec.  98.2(a)(4) must report GHG emissions.

Sec.  98.402  GHGs to report.

    (a) NGL fractionators must report the CO2 emissions that
would result from the complete combustion or oxidation of the annual
quantity of ethane, propane, normal butane, isobutane, and pentanes

plus that is produced and sold or delivered to others.
    (b) LDCs must report the CO2 emissions that would result
from the complete combustion or oxidation of the annual volumes of
natural gas provided to end-users on their distribution systems.

Sec.  98.403  Calculating GHG emissions.

    (a) LDCs and fractionators shall, for each individual product
reported under this part, calculate the estimated CO2
emissions that would result from the complete combustion or oxidation
of the products supplied using either of Calculation Methodology 1 or 2
of this subpart:
    (1) Calculation Methodology 1. NGL fractionators shall estimate
CO2 emissions that would result from the complete combustion
or oxidation of the product(s) supplied using Equation NN-1 of this
section. LDCs shall estimate CO2 emissions that would result
from the complete combustion or oxidation of the product received at
the city gate using Equation NN-1. For each product, use the default
value for higher heating value and CO2 emission factor in
Table NN-1 of this subpart. Alternatively, for each product, a
reporter-specific higher heating value and CO2 emission
factor may be used, in place of one or both defaults provided they are
developed using methods outlined in Sec.  98.404. For each product, you
must use the same volume unit throughout the equation.
[GRAPHIC] [TIFF OMITTED] TR30OC09.163

Where:

CO2i = Annual CO2 mass emissions that would
result from the combustion or oxidation of each product ``h'' for
redelivery to all recipients (metric tons).
Fuel = Total annual volume of product ``h'' supplied (volume per
year, in Mscf for natural gas and bbl for NGLs).
HHV = Higher heating value of product ``h'' supplied (MMBtu/Mscf or
MMBtu/bbl).
EFh = CO2 emission factor of product ``h'' (kg
CO2/MMBtu).
1 x 10-3 = Conversion factor from kilograms to metric
tons (MT/kg).

    (2) Calculation Methodology 2. NGL fractionators shall estimate
CO2 emissions that would result from the complete combustion
or oxidation of the product(s) supplied using Equation NN-2 of this
section. LDCs shall estimate CO2 emissions that would result
from the complete combustion or oxidation of the product received at
the city gate using Equation NN-2. For each product, use the default
CO2 emission factor found in Table NN-2 of this subpart.
Alternatively, for each product, a reporter-specific CO2
emission factor may be used in place of the default factor, provided it
is developed using methods outlined in Sec.  98.404. For each product,
you must use the same volume unit throughout the equation.

[GRAPHIC] [TIFF OMITTED] TR30OC09.164

Where:

CO2i = Annual CO2 mass emissions that would
result from the combustion or oxidation of each product ``h''
(metric tons)
Fuel = Total annual volume of product ``h'' supplied (bbl or Mscf
per year)
EFh = CO2 emission factor of product ``h'' (MT
CO2/bbl, or MT CO2/Mscf)

    (b) Each LDC shall follow the procedures below.
    (1) For natural gas that is received for redelivery to downstream
gas transmission pipelines and other local distribution companies, use
eEquation NN-3 of this section and the default values for the
CO2 emission factors found in Table NN-2 of this subpart.
Alternatively, reporter-specific CO2 emission factors may be
used, provided they are developed using methods outlined in Sec.
98.404.
[GRAPHIC] [TIFF OMITTED] TR30OC09.165

Where:

CO2j = Annual CO2 mass emissions that would
result from the combustion or oxidation of natural gas for
redelivery to transmission pipelines or other LDCs (metric tons).
Fuel = Total annual volume of natural gas supplied (Mscf per year).
EF = Fuel-specific CO2 emission factor (MT
CO2/Mscf).

    (2)(i) For natural gas delivered to each meter registering a supply
equal to or greater than 460,000 Mscf per year, use Equation NN-4 of
this section and the default values for the CO2 emission
factors found in Table NN-2 of this subpart.
    (ii) Alternatively, reporter-specific CO2 emission
factors may be used, provided they are developed using methods outlined
in Sec.  98.404.
[GRAPHIC] [TIFF OMITTED] TR30OC09.166

Where:

CO2k = Annual CO2 mass emissions that would
result from the combustion or oxidation of natural gas received by
end-users that receive a supply equal to or greater than 460,000
Mscf per year (metric tons).
Fuel = Total annual volume of natural gas supplied (Mscf per year).
EF = Fuel-specific CO2 emission factor (MT
CO2/Mscf).

    (3) For natural gas received by the LDC at the city gate that is
injected into on-system storage, and/or liquefied and stored, use
Equation NN-5 of this section and the default value for the
CO2 emission factors found in Table NN-2 of this subpart.
Alternatively, a reporter-specific CO2 emission factor may
be used, provided it is developed using methods outlined in Sec.
98.404.
[GRAPHIC] [TIFF OMITTED] TR30OC09.167

Where:

CO2l = Annual CO2 mass emissions that would
result from the combustion or oxidation of the net natural gas that
is liquefied and/or stored and not used for deliveries by the LDC
within the reported year (metric tons).
Fuel1 = Total annual volume of natural gas received by
the LDC at the city gate and stored on-system or liquefied and
stored in the reportng year (Mscf per year).
Fuel2 = Total annual volume of natural gas that is used
for deliveries in the reporting year that was not otherwise
accounted for in Equation NN-1 or NN-2 of this section (Mscf per
year). This primarily includes natural gas previously stored on-
system or liquefied and stored that is removed from storage and used
for deliveries to customers or other LDCs by the LDC within the
reporting year. This also includes natural gas that bypassed the
city gate and was delivered directly to LDC systems from producers
or natural gas processing plants from local production.
EF = Fuel-specific CO2 emission factor (MT
CO2/Mscf).

    (4) Calculate the total CO2 emissions that would result
from the complete combustion or oxidation of the annual supply of
natural gas to end-users using Equation NN-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.168

Where:

CO2 = Annual CO2 mass emissions that would
result from the combustion or oxidation of natural gas delivered to
LDC customers not covered in paragraph (b)(2) of this section
(metric tons).
CO2i = Annual CO2 mass emissions that would
result from the combustion or oxidation of natural gas received at
the city gate as calculated in paragraph (a)(1) or (a)(2) of this
section (metric tons).
CO2j = Annual CO2 mass emissions that would
result from the combustion or oxidation of natural gas delivered to
transmission pipelines or other LDCs as calculated in paragraph
(b)(1) of this section (metric tons).
CO2k = Annual CO2 mass emissions that would
result from the combustion or oxidation of natural gas received by
end-users that receive a supply equal to or greater than 460,000
Mscf per year as calculated in paragraph (b)(2) of this section
(metric tons).
CO2l = Annual CO2 mass emissions that would
result from the combustion or oxidation of natural gas received by
the LDC and liquefied and/or stored but not used for deliveries
within the reported year as calculated in paragraph (b)(3) of this
section (metric tons).

    (c) Each NGL fractionator shall follow the following procedures.
    (1)(i) For fractionated NGLs received by the reporter from other
NGL fractionators, you shall use Equation NN-7 of this section and the
default values for the CO2 emission factors found in Table
NN-2 of this subpart.
    (ii) Alternatively, reporter-specific CO2 emission
factors may be used, provided they are developed using methods outlined
in Sec.  98.404.
[GRAPHIC] [TIFF OMITTED] TR30OC09.169

Where:

CO2m = Annual CO2 mass emissions that would
result from the combustion or oxidation of each fractionated NGL
product ``g'' received from other fractionators (metric tons).
Fuelg = Total annual volume of each NGL product ``g''
received (bbls).
EF = Fuel-specific CO2 emission factor (MT
CO2/bbl).

    (2) Calculate the total CO2 equivalent emissions that
would result from the combustion or oxidation of fractionated NGLs
supplied less the quantity received by other fractionators using
Equation NN-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.170

Where:

CO2 = Annual CO2 mass emissions that would
result from the combustion or oxidation of fractionated NGLs
delivered to customers or on behalf of customers (metric tons).
CO2i = Annual CO2 mass emissions that would
result from the combustion or oxidation of fractionated NGLs
delivered to all customers as calculated in paragraph (a)(1) or
(a)(2) of this section (metric tons).
CO2m = Annual CO2 mass emissions that would
result from the combustion or oxidation of fractionated NGLs
received from other fractionators and calculated in paragraph (c)(1)
of this section (metric tons).

Sec.  98.404  Monitoring and QA/QC requirements.

    (a) Determination of quantity.
    (1) NGL fractionators and LDCs shall determine the quantity of NGLs
and natural gas using methods in common use in the industry for billing
purposes as audited under existing Sarbanes Oxley regulationn.
    (i) Where an appropriate standard method published by a consensus-
based standards organization exists, such a method shall be used.
Consensus-based standards organizations include, but are not limited
to, the following: ASTM International, the American National Standards
Institute (ANSI), the American Gas Association (AGA), the American
Society of Mechanical Engineers (ASME), the American Petroleum
Institute (API), and the North American Energy Standards Board (NAESB).
    (ii) Where no appropriate standard method developed by a consensus-
based standards organization exists, industry standard practices shall
be followed.
    (2) NGL fractionators and LDCs shall base the minimum frequency of
the product quantity measurements, to be summed to the annual quantity
reported, on the reporter's standard practices for commercial
operations.
    (i) For NGL fractionators the minimum frequency of measurements
shall be the measurements taken at custody transfers summed to the
annual reportable volume.
    (ii) For natural gas the minimum frequency of measurement shall be
based on the LDC's standard measurement schedules used for billing
purposes and summed to the annual reportable volume.
    (3) NGL fractionators shall use measurement for NGLs at custody
tranfer meters or at such meters that are used to determine the NGL
product slate delivered from the fractionation facility.
    (4) If a NGL fractionator supplies a product not listed in Table
NN-1 of this subpart that is a mixture or blend of two or more products
listed in Tables NN-1 and NN-2 of this subpart, the NGL fractionator
shall report the quantities of the constituents of the mixtures or
blends separately.
    (5) For an LDC using Equation NN-1 or NN-2 of this subpart, the
point(s) of measurement for the natural gas volume supplied shall be
the LDC city gate meter(s).
    (i) If the LDC makes its own quantity measurements according to
established business practices, its own measurements shall be used.
    (ii) If the LDC does not make its own quantity measurements
according to established business practices, it shall use its
delivering pipeline invoiced measurements for natural gas deliveries to
the LDC city gate, used in determining daily system sendout.
    (6) An LDC using Equation NN-3 of this subpart shall measure
natural gas at the custody transfer meters.
    (7) An LDC using Equation NN-4 of this subpart shall measure
natural gas at the customer meters. The reporter shall consider the
volume delivered through a single particluar meter at a single
particular location as the volume delivered to an individual end-user.
    (8) An LDC using Equation NN-5 of this subpart shall measure
natural gas as follows:

    (i) Fuel1 shall be measured at the on-system storage
injection meters and/or at the meters measuring natural gas to be
liquefied.
    (ii) Fuel2 shall be measured at the meters used for
measuring on-system storage withdrawals and/or LNG vaporization
injection. If Fuel2 is from a source other than storage, the
appropriate meter shall be used to measure the quantity.
    (9) An LDC shall measure all natural gas under the following
standard industry temperature and pressure conditions: Cubic foot of
gas at a temperature of 60 degrees Fahrenheit and at an absolute
pressure of fourteen and seventy-three hundredths (14.73) pounds per
square inch.
    (b) Determination of higher heating values (HHV).
    (1) When a reporter uses the default HHV provided in this section
to calculate Equation NN-1 of this subpart, the appropriate value shall
be taken from Table NN-1 of this subpart.
    (2) When a reporter uses a reporter-specific HHV to calculate
Equation NN-1 of this subpart, an appropriate standard test published
by a consensus-based standards organization shall be used. Consensus-
based standards organizations include, but are not limited to, the
following: AGA and GPA.
    (i) If an LDC makes its own HHV measurements according to
established business practices, then its own measurements shall be
used.
    (ii) If an LDC does not make its own measurements according to
established business practices, it shall use its delivering pipeline
measurements.
    (c) Determination of emission factor (EF).
    (1) When a reporter used the default EF provided in this section to
calculate Equation NN-1 of this subpart, the appropriate value shall be
taken from Table NN-1 of this subpart.
    (2) When a reporter used the default EF provided in this section to
calculate Equation NN-2, NN-3, NN-4, NN-5, or NN-7 of this subpart, the
appropriate value shall be taken from Table NN-2 of this subpart.
    (3) When a reporter uses a reporter-specific EF, the reporter shall
use an appropriate standard method published by a consensus-based
standards organization to conduct compositional analysis necessary to
determine reporter-specific CO2 emission factors. Consensus-
based standards organizations include, but are not limited to, the
following: AGA and GPA.
    (d) Equipment Calibration.
    (1) Equipment used to measure quantities in Equations NN-1, NN-2,
and NN-5 of this subpart shall be calibrated prior to its first use for
reporting under this subpart, using a suitable standard method
published by a consensus based standards organization or according to
the equipment manufacturer's directions.
    (2) Equipment used to measure quantities in Equations NN-1, NN-2,
and NN-5 of this subpart shall be recalibrated at the frequency
specified by the standard method used or by the manufacturer's
directions.

Sec.  98.405  Procedures for estimating missing data.

    (a) Whenever a quality-assured value of the quantity of natural gas
liquids or natural gas supplied during any period is unavailable (e.g.,
if a flow meter malfunctions), a substitute data value for the missing
quantity measurement must be used in the calculations according to
paragraphs (b) and (c) of this section.
    (b) Determination of quantity.
    (1) NGL fractionators shall substitute meter records provided by
pipeline(s) for all pipeline receipts of NGLs; by manifests for
deliveries made to trucks or rail cars; or metered quantities accepted
by the entities purchasing the output from the fractionator whether by
pipeline or by truck or rail car. In cases where the metered data from
the receiving pipeline(s) or purchasing entities are not available,
fractionators may substitute estimates based on contract quantities
required to be delivered under purchase or delivery contracts with
other parties.
    (2) LDCs shall either substitute their delivering pipeline metered
deliveries at the city gate or substitute nominations and scheduled
delivery quantities for the period when metered values of actual
deliveries are not available.
    (c) Determination of HHV and EF.
    (1) Whenever an LDC that makes its own HHV measurements according
to established business practices cannot follow the quality assurance
procedures for developing a reporter-specific HHV, as specified in
Sec.  98.404, during any period for any reason, the reporter shall use
either its delivering pipeline measurements or the default HHV provided
in Table NN-1 of this part for that period.
    (2) Whenever an LDC that does not make its own HHV measurements
according to established business practices or an NGL fractionator
cannot follow the quality assurance procedures for developing a
reporter-specific HHV, as specified in Sec.  98.404, during any period
for any reason, the reporter shall use the default HHV provided in
Table NN-1 of this part for that period.
    (3) Whenever a NGL fractionator cannot follow the quality assurance
procedures for developing a reporter-specific HHV, as specified in
Sec.  98.404, during any period for any reason, the NGL fractionator
shall use the default HHV provided in Table NN-1 of this part for that
period.
    (4) Whenever a reporter cannot follow the quality assurance
procedures for developing a reporter-specific EF, as specified in Sec.
98.404, during any period for any reason, the reporter shall use the
default EF provided in Sec.  98.408 for that period.

Sec.  98.406  Data reporting requirements.

    (a) In addition to the information required by Sec.  98.3(c), the
annual report for each NGL fractionator covered by this rule shall
contain the following information.
    (1) Annual quantity (in barrels) of each NGL product supplied to
downstream facilities in the following product categories: ethane,
propane, normal butane, isobutane, and pentanes plus.
    (2) Annual quantity (in barrels) of each NGL product received from
other NGL fractionators in the following product categories: ethane,
propane, normal butane, isobutane, and pentanes plus.
    (3) Annual volumes in Mscf of natural gas received for processing.
    (4) Annual quantity (in barrels) of y-grade, bulk NGLs received
from others for fractionation.
    (5) Annual quantity (in barrels) of propane that the NGL
fractionator odorizes at the facility and delivers to others.
    (6) Annual CO2 emissions (metric tons) that would result
from the complete combustion or oxidation of the quantities in
paragraphs (b)(1) and (b)(2) of this section, calculated in accordance
with Sec.  98.403(a) and (c)(1).
    (7) Annual CO2 mass emissions (metric tons) that would
result from the combustion or oxidation of fractionated NGLs supplied
less the quantity received by other fractionators, calculated in
accordance with Sec.  98.403(c)(2).
    (8) The specific industry standard used to measure each quantity
reported in paragraph (a)(1) of this section.
    (9) If the LNG fractionator developed reporter-specific EFs or
HHVs, report the following:
    (i) The specific industry standard(s) used to develop reporter-
specific higher heating value(s) and/or emission factor(s), pursuant to
Sec.  98.404(b)(2) and (c)(3).
    (ii) The developed HHV(s).
    (iii) The developed EF(s).

    (b) In addition to the information required by Sec.  98.3(c), the
annual report for each LDC shall contain the following information.
    (1) Annual volume in Mscf of natural gas received by the LDC at its
city gate stations for redelivery on the LDC's distribution system,
including for use by the LDC.
    (2) Annual volume in Mscf of natural gas placed into storage.
    (3) Annual volume in Mscf of vaporized liquefied natural gas (LNG)
produced at on-system vaporization facilities for delivery on the
distribution system that is not accounted for in paragraph (b)(1) of
this section.
    (4) Annual volume in Mscf of natural gas withdrawn from on-system
storage (that is not delivered to the city gate) for delivery on the
distribution system.
    (5) Annual volume in Mscf of natural gas delivered directly to LDC
systems from producers or natural gas processing plants from local
production.
    (6) Annual volume in Mscf of natural gas delivered to downstream
gas transmission pipelines and other local distribution companies.
    (7) Annual volume in Mscf of natural gas delivered by LDC to each
meter registering supply equal to or greater than 460,000 Mcsf during
the calendar year.
    (8) The total annual CO2 mass emissions (metric tons)
associated with the volumes in paragraphs (b)(1) through (b)(7) of this
section, calculated in accordance with Sec.  98.403(a) and (b)(1)
through (b)(3).
    (9) Annual CO2 emissions (metric tons) that would result
from the complete combustion or oxidation of the annual supply of
natural gas to end-users registering less than 460,000 Mcsf, calculated
in accordance with Sec.  98.403(b)(4).
    (10) The specific industry standard used to develop the volume
reported in paragraph (b)(1) of this section.
    (11) If the LDC developed reporter-specific EFs or HHVs, report the
following:
    (i) The specific industry standard(s) used to develop reporter-
specific higher heating value(s) and/or emission factor(s), pursuant to
Sec.  98.404 (b)(2) and (c)(3).
    (ii) The developed HHV(s).
    (iii) The developed EF(s).
    (12) The customer name, address, and meter number of each meter
reading used to report in paragraph (b)(7) of this section.
    (i) If known, report the EIA identification number of each LDC
customer.
    (ii) [Reserved]
    (13) The annual volume in Mscf of natural gas delivered by the
local distribution company to each of the following end-use categories.
For definitions of these categories, refer to EIA Form 176 (Annual
Report of Natural Gas and Supplemental Gas Supply & Disposition) and
Instructions.
    (i) Residential consumers.
    (ii) Commercial consumers.
    (iii) Industrial consumers.
    (iv) Electricity generating facilities.
    (c) Each reporter shall report the number of days in the reporting
year for which substitute data procedures were used for the following
purpose:
    (1) To measure quantity.
    (2) To develop HHV(s).
    (3) To develop EF(s).

Sec.  98.407  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), each
annual report must contain the following information:
    (a) Records of all daily meter readings and documentation to
support volumes of natural gas and NGLs that are reported under this
part.
    (b) Records documenting any estimates of missing metered data and
showing the calculations of the values used for the missing data.
    (c) Calculations and worksheets used to estimate CO2
emissions for the volumes reported under this part.
    (d) Records related to the large end-users identified in Sec.
98.406(b)(6).
    (e) Records relating to measured Btu content or carbon content
showing specific industry standards used to develop reporter-specific
higher heating values and emission factors.
    (f) Records of such audits as required by Sarbanes Oxley
regulations on the accuracy of measurements of volumes of natural gas
and NGLs delivered to customers or on behalf of customers.

Sec.  98.408  Definitions.

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

  Table NN-1 to Subpart NN of Part 98--Default Factors for Calculation
                      Methodology 1 of This Subpart
------------------------------------------------------------------------
                                                             Default CO2
                                      Default high heating     emission
                Fuel                      value factor       factor  (kg
                                                              CO2/MMBtu)
------------------------------------------------------------------------
Natural Gas........................  1.027 MMBtu/Mscf......        53.02
Propane............................  3.836 MMBtu/bbl.......        63.02
Normal butane......................  4.326 MMBtu/bbl.......        64.93
Ethane.............................  3.082 MMBtu/bbl.......        59.58
Isobutane..........................  3.974 MMBtu/bbl.......        65.08
Pentanes plus......................  4.620 MMBtu/bbl.......        66.90
------------------------------------------------------------------------

     Table NN-2 to Subpart NN of Part 98--Lookup Default Values for
                Calculation Methodology 2 of This Subpart
------------------------------------------------------------------------
                                                             Default CO2
                                                               emission
                Fuel                          Unit            value  (MT
                                                              CO2/Unit)
------------------------------------------------------------------------
Natural Gas........................  Mscf..................     0.054452
Propane............................  Barrel................     0.241745
Normal butane......................  Barrel................     0.280887
Ethane.............................  Barrel................     0.183626
Isobutane..........................  Barrel................     0.258628

Pentanes plus......................  Barrel................     0.309078
------------------------------------------------------------------------

Subpart OO--Suppliers of Industrial Greenhouse Gases

Sec.  98.410  Definition of the source category.

    (a) The industrial gas supplier source category consists of any
facility that produces a fluorinated GHG or nitrous oxide, any bulk
importer of fluorinated GHGs or nitrous oxide, and any bulk exporter of
fluorinated GHGs or nitrous oxide.
    (b) To produce a fluorinated GHG means to manufacture a fluorinated
GHG from any raw material or feedstock chemical. Producing a
fluorinated GHG includes the manufacture of a fluorinated GHG for use
in a process that will result in its transformation either at or
outside of the production facility. Producing a fluorinated GHG also
includes the creation of a fluorinated GHG (with the exception of HFC-
23) that is captured and shipped off site for any reason, including
destruction. Producing a fluorinated GHG does not include the reuse or
recycling of a fluorinated GHG, the creation of HFC-23 during the
production of HCFC-22, or the creation of by-products that are released
or destroyed at the production facility.
    (c) To produce nitrous oxide means to produce nitrous oxide by
thermally decomposing ammonium nitrate (NH4NO3).
Producing nitrous oxide does not include the reuse or recycling of
nitrous oxide or the creation of by-products that are released or
destroyed at the production facility.

Sec.  98.411  Reporting threshold.

    Any supplier of industrial greenhouse gases who meets the
requirements of Sec.  98.2(a)(4) must report GHG emissions.

Sec.  98.412  GHGs to report.

    You must report the GHG emissions that would result from the
release of the nitrous oxide and each fluorinated GHG that you produce,
import, export, transform, or destroy during the calendar year.

Sec.  98.413  Calculating GHG emissions.

    (a) Calculate the total mass of each fluorinated GHG or nitrous
oxide produced annually, except for amounts that are captured solely to
be shipped off site for destruction, by using Equation OO-1 of this
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.171

P = Mass of fluorinated GHG or nitrous oxide produced annually.
Pp = Mass of fluorinated GHG or nitrous oxide produced
over the period ``p''.

    (b) Calculate the total mass of each fluorinated GHG or nitrous
oxide produced over the period ``p'' by using Equation OO-2 of this
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.172

Where:

Pp = Mass of fluorinated GHG or nitrous oxide produced
over the period ``p'' (metric tons).
Op = Mass of fluorinated GHG or nitrous oxide that is
measured coming out of the production process over the period p
(metric tons).
Up = Mass of used fluorinated GHG or nitrous oxide that
is added to the production process upstream of the output
measurement over the period ``p'' (metric tons).

    (c) Calculate the total mass of each fluorinated GHG or nitrous
oxide transformed by using Equation OO-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.173

Where:

T = Mass of fluorinated GHG or nitrous oxide transformed annually
(metric tons).

FT = Mass of fluorinated GHG fed into the transformation
process annually (metric tons).
ET = The fraction of the fluorinated GHG or nitrous oxide
fed into the transformation process that is transformed in the process
(metric tons).

    (d) Calculate the total mass of each fluorinated GHG destroyed by
using Equation OO-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.174

Where: