emissions sources listed in Sec.  98.232 (c)(21), (f)(5), (g)(3),
(h)(4), (i)(2), (i)(3), (i)(4), (i)(5), and (i)(6) on streams with gas
content greater than 10 percent CH4 plus CO2 by
weight. Emissions sources in streams with gas content less than or
equal to 10 percent CH4 plus CO2 by weight are
exempt from the requirements of this paragraph (r) and do not need to
be reported. Tubing systems equal to or less than one half inch
diameter are exempt from the requirements of paragraph (r) of this
section and do not need to be reported. You must calculate emissions
from all emission sources listed in this paragraph using Equation W-32A
of this section, except for natural gas distribution facility emission
sources listed in Sec.  98.232(i)(3). Natural gas distribution facility
emission sources listed in Sec.  98.232(i)(3) must calculate emissions
using Equation W-32B and according to paragraph (r)(6)(ii) of this
section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.075

Where:

Es,e,i = Annual volumetric emissions of GHGi
from the emission source type in standard cubic feet. The emission
source type may be a component (e.g. connector, open-ended line,
etc.), below grade metering-regulating station, below grade
transmission-distribution transfer station, distribution main, or
distribution service.
Es,MR,i = Annual volumetric emissions of GHGi
from all meter/regulator runs at above grade metering regulating
stations that are not above grade transmission-distribution transfer
stations or, when used to calculate emissions according to paragraph
(q)(9) of this section, the annual volumetric emissions of
GHGi from all meter/regulator runs at above grade
transmission-distribution transfer stations, in standard cubic feet.
Counte = Total number of the emission source type at the
facility. For onshore petroleum and natural gas production
facilities, average component counts are provided by major equipment
piece in Tables W-1B and Table W-1C of this subpart. Use average
component counts as appropriate for operations in Eastern and
Western U.S., according to Table W-1D of this subpart. Underground
natural gas storage facilities must count each component listed in
Table W-4 of this subpart. LNG storage facilities must count the
number of vapor recovery compressors. LNG import and export
facilities must count the number of vapor recovery compressors.
Natural gas distribution facilities must count: (1) The number of
distribution services by material type; (2) miles of distribution
mains by material type; and (3) number of below grade metering-
regulating stations, by pressure type; as listed in Table W-7 of
this subpart.
CountMR = Total number of meter/regulator runs at above
grade metering-regulating stations that are not above grade
transmission-distribution transfer stations or, when used to
calculate emissions according to paragraph (q)(9) of this section,
the total number of meter/regulator runs at above grade
transmission-distribution transfer stations.
EFs,e = Population emission factor for the specific
emission source type, as listed in Tables W-1A and W-4 through W-7
of this subpart. Use appropriate population emission factor for
operations in Eastern and Western U.S., according to Table W-1D of
this subpart.
EFs,MR,i = Meter/regulator run population emission factor
for GHGi based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic
feet of GHGi per operational hour of all meter/regulator
runs, as determined in Equation W-31.
GHGi = For onshore petroleum and natural gas production
facilities, concentration of GHGi, CH4, or
CO2, in produced natural gas as defined in paragraph
(u)(2) of this section; for onshore natural gas transmission
compression and underground natural gas storage, GHGi
equals 0.975 for CH4 and 1.1 x 10 -2 for
CO2; for LNG storage and LNG import and export equipment,
GHGi equals 1 for CH4 and 0 for
CO2; and for natural gas distribution, GHGi
equals 1 for CH4 and 1.1 x 10
-2CO2.
Te = Average estimated time that each emission source
type associated with the equipment leak emission was operational in
the calendar year, in hours, using engineering estimate based on
best available data.
Tw,avg = Average estimated time that each meter/regulator
run was operational in the calendar year, in hours per meter/
regulator run, using engineering estimate based on best available
data.

    (1) Calculate both CH4 and CO2 mass emissions
from volumetric emissions using calculations in paragraph (v) of this
section.
    (2) Onshore petroleum and natural gas production facilities must
use the appropriate default whole gas population emission factors
listed in Table W-1A of this subpart. Major equipment and components
associated with gas wells are considered gas service components in
reference to Table W-1A of this subpart and major natural gas equipment
in reference to Table W-1B of this subpart. Major equipment and
components associated with crude oil wells are considered crude service
components in reference to Table W-1A of this subpart and major crude
oil equipment in reference to Table W-1C of this subpart. Where
facilities conduct EOR operations the emissions factor listed in Table
W-1A of this subpart shall be used to estimate all streams of gases,
including recycle CO2 stream. The component count can be
determined using either of the calculation methods described in this
paragraph (r)(2). The same calculation method must be used for the
entire calendar year.
    (i) Component Count Method 1. For all onshore petroleum and natural
gas production operations in the facility perform the following
activities:
    (A) Count all major equipment listed in Table W-1B and Table W-1C
of this subpart. For meters/piping, use one meters/piping per well-pad.
    (B) Multiply major equipment counts by the average component counts
listed in Table W-1B and W-1C of this subpart for onshore natural gas
production and onshore oil production, respectively. Use the
appropriate factor in Table W-1A of this subpart for operations in
Eastern and Western U.S. according to the mapping in Table W-1D of this
subpart.
    (ii) Component Count Method 2. Count each component individually
for the facility. Use the appropriate factor in Table W-1A of this
subpart for operations in Eastern and Western U.S. according to the
mapping in Table W-1D of this subpart.
    (3) Underground natural gas storage facilities must use the
appropriate default total hydrocarbon population emission factors for
storage wellheads in gas service listed in Table W-4 of this subpart.
    (4) LNG storage facilities must use the appropriate default methane
population emission factor for LNG storage compressors in gas service
listed in Table W-5 of this subpart.
    (5) LNG import and export facilities must use the appropriate
default methane population emission factor for LNG terminal compressors
in gas

service listed in Table W-6 of this subpart.
    (6) Natural gas distribution facilities must use the appropriate
methane emission factors as described in paragraphs (r)(6)(i) and (ii)
of this section.
    (i) Below grade metering-regulating stations, distribution mains,
and distribution services must use the appropriate default methane
population emission factors listed in Table W-7 of this subpart. Below
grade transmission-distribution transfer stations must use the emission
factor for below grade metering-regulating stations.
    (ii) Above grade metering-regulating stations that are not above
grade transmission-distribution transfer stations must use the meter/
regulator run population emission factor calculated in Equation W-31.
Natural gas distribution facilities that do not have above grade
transmission-distribution transfer stations are not required to
calculate emissions for above grade metering-regulating stations and
are not required to report GHG emissions in Sec.  98.236(r)(2)(v).
    (s) * * *
    (2) Offshore production facilities that are not under BOEMRE
jurisdiction must use the most recent monitoring methods and
calculation methods published by BOEMRE referenced in 30 CFR 250.302
through 250.304 to calculate and report annual emissions (GOADS).
    (i) For any calendar year that does not overlap with the most
recent BOEMRE emissions study publication, you may report the most
recently reported emissions data submitted to demonstrate compliance
with this subpart of part 98, with emissions adjusted based on the
operating time for the facility relative to operating time in the
previous reporting period.
* * * * *
    (3) If BOEMRE discontinues or delays their data collection effort
by more than 4 years, then offshore reporters shall once in every 4
years use the most recent BOEMRE data collection and emissions
estimation methods to estimate emissions. These emission estimates
would be used to report emissions from the facility sources as required
in paragraph (s)(1)(i) of this section.
    (4) For either first or subsequent year reporting, offshore
facilities either within or outside of BOEMRE jurisdiction that were
not covered in the previous BOEMRE data collection cycle must use the
most recent BOEMRE data collection and emissions estimation methods
published by BOEMRE referenced in 30 CFR 250.302 through 250.304 to
calculate and report emissions.
    (t) GHG volumetric emissions using actual conditions. If equation
parameters in Sec.  98.233 are already determined at standard
conditions as provided in the introductory text in Sec.  98.233, which
results in volumetric emissions at standard conditions, then this
paragraph does not apply. Calculate volumetric emissions at standard
conditions as specified in paragraphs (t)(1) or (2) of this section,
with actual pressure and temperature determined by engineering
estimates based on best available data unless otherwise specified.
    (1) Calculate natural gas volumetric emissions at standard
conditions using actual natural gas emission temperature and pressure,
and Equation W-33 of this section for conversions of Ea,n or
conversions of FRa (whether sub-sonic or sonic).
[GRAPHIC] [TIFF OMITTED] TR25NO14.050

Where:

Es,n = Natural gas volumetric emissions at standard
temperature and pressure (STP) conditions in cubic feet, except
Es,n equals FRs,p for each well p when
calculating either subsonic or sonic flowrates under Sec.
98.233(g).
Ea,n = Natural gas volumetric emissions at actual
conditions in cubic feet, except Ea,n equals
FRa,p for each well p when calculating either subsonic or
sonic flowrates under Sec.  98.233(g).
Ts = Temperature at standard conditions
(60[emsp14][deg]F).
Ta = Temperature at actual emission conditions ([deg]F).
Ps = Absolute pressure at standard conditions (14.7
psia).
Pa = Absolute pressure at actual conditions (psia).
Za = Compressibility factor at actual conditions for
natural gas. You may use either a default compressibility factor of
1, or a site-specific compressibility factor based on actual
temperature and pressure conditions.

    (2) Calculate GHG volumetric emissions at standard conditions using
actual GHG emissions temperature and pressure, and Equation W-34 of
this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.051

Where:

Es,i = GHG i volumetric emissions at standard temperature
and pressure (STP) conditions in cubic feet.
Ea,i = GHG i volumetric emissions at actual conditions in
cubic feet.
Ts = Temperature at standard conditions
(60[emsp14][deg]F).
Ta = Temperature at actual emission conditions ([deg]F).
Ps = Absolute pressure at standard conditions (14.7
psia).
Pa = Absolute pressure at actual conditions (psia).
Za = Compressibility factor at actual conditions for GHG
i.

    You may use either a default compressibility factor of 1, or a
site-specific compressibility factor based on actual temperature and
pressure conditions.
* * * * *
    (u) GHG volumetric emissions at standard conditions. Calculate GHG
volumetric emissions at standard conditions as specified in paragraphs
(u)(1) and (2) of this section.
* * * * *
    (2) * * *
    (iii) GHG mole fraction in transmission pipeline natural gas that
passes through the facility for the onshore natural gas transmission
compression industry segment. You may use either a default 95 percent
methane and 1 percent carbon dioxide fraction for GHG mole fraction in
natural gas or

site specific engineering estimates based on best available data.
    (iv) GHG mole fraction in natural gas stored in the underground
natural gas storage industry segment. You may use either a default 95
percent methane and 1 percent carbon dioxide fraction for GHG mole
fraction in natural gas or site specific engineering estimates based on
best available data.
    (v) GHG mole fraction in natural gas stored in the LNG storage
industry segment. You may use either a default 95 percent methane and 1
percent carbon dioxide fraction for GHG mole fraction in natural gas or
site specific engineering estimates based on best available data.
    (vi) GHG mole fraction in natural gas stored in the LNG import and
export industry segment. For export facilities that receive gas from
transmission pipelines, you may use either a default 95 percent methane
and 1 percent carbon dioxide fraction for GHG mole fraction in natural
gas or site specific engineering estimates based on best available
data.
    (vii) GHG mole fraction in local distribution pipeline natural gas
that passes through the facility for natural gas distribution
facilities. You may use either a default 95 percent methane and 1
percent carbon dioxide fraction for GHG mole fraction in natural gas or
site specific engineering estimates based on best available data.
    (v) GHG mass emissions. Calculate GHG mass emissions in metric tons
by converting the GHG volumetric emissions at standard conditions into
mass emissions using Equation W-36 of this section.
[GRAPHIC] [TIFF OMITTED] TR25NO14.052

Where:

Massi = GHGi (either CH4,
CO2, or N2O) mass emissions in metric tons.
Es,i = GHGi (either CH4,
CO2, or N2O) volumetric emissions at standard
conditions, in cubic feet.
    [rho]i = Density of GHGi. Use 0.0526 kg/
ft\3\ for CO2 and N2O, and 0.0192 kg/ft\3\ for
CH4 at 60[emsp14][deg]F and 14.7 psia.

    (w) EOR injection pump blowdown. Calculate CO2 pump
blowdown emissions from each EOR injection pump system as follows:
    (1) Calculate the total injection pump system volume in cubic feet
(including pipelines, manifolds and vessels) between isolation valves.
* * * * *
    (3) Calculate the total annual CO2 emissions from each
EOR injection pump system using Equation W-37 of this section:
* * * * *
MassCO2 = Annual EOR injection pump system emissions in
metric tons from blowdowns.
N = Number of blowdowns for the EOR injection pump system in the
calendar year.
Vv = Total volume in cubic feet of EOR injection pump
system chambers (including pipelines, manifolds and vessels) between
isolation valves.
* * * * *
    (x) EOR hydrocarbon liquids dissolved CO2. Calculate CO2
emissions downstream of the storage tank from dissolved CO2
in hydrocarbon liquids produced through EOR operations as follows:
    (1) Determine the amount of CO2 retained in hydrocarbon
liquids after flashing in tankage at STP conditions. Annual samples of
hydrocarbon liquids downstream of the storage tank must be taken
according to methods set forth in Sec.  98.234(b) to determine
retention of CO2 in hydrocarbon liquids immediately
downstream of the storage tank. Use the annual analysis for the
calendar year.
    (2) * * *
* * * * *
    Shl = Amount of CO2 retained in
hydrocarbon liquids downstream of the storage tank, in metric tons
per barrel, under standard conditions.
* * * * *
    (z) * * *
    (1) If a fuel combusted in the stationary or portable equipment is
listed in Table C-1 of subpart C of this part, or is a blend containing
one or more fuels listed in Table C-1, calculate emissions according to
paragraph (z)(1)(i) of this section. If the fuel combusted is natural
gas and is of pipeline quality specification and has a minimum high
heat value of 950 Btu per standard cubic foot, use the calculation
method described in paragraph (z)(1)(i) of this section and you may use
the emission factor provided for natural gas as listed in Table C-1. If
the fuel is natural gas, and is not pipeline quality or has a high heat
value of less than 950 Btu per standard cubic feet, calculate emissions
according to paragraph (z)(2) of this section. If the fuel is field
gas, process vent gas, or a blend containing field gas or process vent
gas, calculate emissions according to paragraph (z)(2) of this section.
    (i) For fuels listed in Table C-1 or a blend containing one or more
fuels listed in Table C-1, calculate CO2, CH4,
and N2O emissions according to any Tier listed in subpart C
of this part. You must follow all applicable calculation requirements
for that tier listed in Sec.  98.33, any monitoring or QA/QC
requirements listed for that tier in Sec.  98.34, any missing data
procedures specified in Sec.  98.35, and any recordkeeping requirements
specified in Sec.  98.37.
    (ii) Emissions from fuel combusted in stationary or portable
equipment at onshore natural gas and petroleum production facilities
and at natural gas distribution facilities will be reported according
to the requirements specified in Sec.  98.236(z) and not according to
the reporting requirements specified in subpart C of this part.
    (2) * * *
    (iii) * * *
* * * * *
Va = Volume of gas sent to combustion unit in actual
cubic feet, during the year.
YCO2 = Mole fraction of CO2 constituent in gas
sent to combustion unit.
* * * * *
Yj = Mole fraction of gas hydrocarbon constituents j
(such as methane, ethane, propane, butane, and pentanes plus) in gas
sent to combustion unit.
* * * * *
YCH4 = Mole fraction of methane constituent in gas sent
to combustion unit.
* * * * *
    (vi) * * *
    [GRAPHIC] [TIFF OMITTED] TR25NO14.053

* * * * *
MassN2O = Annual N2O emissions from the
combustion of a particular type of fuel (metric tons).
Fuel = Annual mass or volume of the fuel combusted (mass or volume
per year, choose appropriately to be consistent with the units of
HHV).
HHV = Higher heating value of fuel, mmBtu/unit of fuel (in units
consistent with the fuel quantity combusted). For field gas or
process vent gas, you may use either a default higher heating value
of 1.235 x 10-3 mmBtu/scf or a site-specific higher
heating value. For natural gas that is not of pipeline quality or
that has a high heat value less than 950 Btu per standard cubic
foot, use a site-specific higher heating value.
* * * * *

0
6. Section 98.234 is amended by:
0
a. Revising paragraphs (a) introductory text, (d)(1), and (f);
0
b. Removing and reserving paragraph (g); and
0
c. Adding paragraph (h).
    The revisions and additions read as follows:

Sec.  98.234  Monitoring and QA/QC requirements.

* * * * *
    (a) You must use any of the methods described as follows in this
paragraph to conduct leak detection(s) of equipment leaks and through-
valve leakage from all source types listed in Sec.  98.233(k), (o), (p)
and (q) that occur during a calendar year.
* * * * *
    (d) * * *
    (1) A technician following manufacturer instructions shall conduct
measurements, including equipment manufacturer operating procedures and
measurement methods relevant to using a high volume sampler, including
positioning the instrument for complete capture of the equipment leak
without creating backpressure on the source.
* * * * *
    (f) Special reporting provisions for best available monitoring
methods in reporting year 2015--(1) Best available monitoring methods.
From January 1, 2015 to March 31, 2015, for a facility subject to this
subpart, you must use the calculation methodologies and equations in
Sec.  98.233 ``Calculating GHG Emissions'', but you may use the best
available monitoring method for any parameter for which it is not
reasonably feasible to acquire, install, and operate a required piece
of monitoring equipment by January 1, 2015 as specified in paragraphs
(f)(2) and (3) of this section. Starting no later than April 1, 2015,
you must discontinue using best available methods and begin following
all applicable monitoring and QA/QC requirements of this part, except
as provided in paragraph (f)(4) of this section. Best available
monitoring methods means any of the following methods:
    (i) Monitoring methods currently used by the facility that do not
meet the specifications of this subpart.
    (ii) Supplier data.
    (iii) Engineering calculations.
    (iv) Other company records.
    (2) Best available monitoring methods for well-related measurement
data. You may use best available monitoring methods for well-related
measurement data identified in paragraphs (f)(2)(i) and (ii) of this
section that cannot reasonably be measured according to the monitoring
and QA/QC requirements of this subpart.
    (i) If Calculation Method 1 for liquids unloading in Sec.
98.233(f)(1) was used in calendar year 2014 and will be used again in
calendar year 2015, the vented natural gas flow rate for any well in a
unique tubing diameter group and pressure group combination that has
not been previously measured.
    (ii) If using Equation W-10A of this subpart to determine natural
gas emissions from completions and workovers for representative wells,
the initial and average flowback rates (when using Calculation Method 1
in Sec.  98.233(g)(1)(i)) or pressures upstream and downstream of the
choke (when using Calculation Method 2 in Sec.  98.233(g)(1)(ii)) for
any well in a well type combination that has not been previously
measured.
    (3) Best available monitoring methods for emissions measurement.
You may use best available monitoring methods for sources listed in
paragraphs (f)(3)(i) and (ii) of this section if the required
measurement data cannot reasonably be obtained according to the
monitoring and QA/QC requirements of this part.
    (i) Centrifugal compressor as found measurements of manifolded
emissions from groups of centrifugal compressor sources according to
Sec.  98.233(o)(4) and (5), in onshore natural gas processing, onshore
natural gas transmission compression, underground natural gas storage,
LNG storage, and LNG import and export equipment as specified in Sec.
98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2).
    (ii) Reciprocating compressor as found measurements of manifolded
emissions from groups of reciprocating compressor sources according to
Sec.  98.233(p)(4) and (5), in onshore natural gas processing, onshore
natural gas transmission compression, underground natural gas storage,
LNG storage, and LNG import and export equipment as specified in Sec.
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1).
    (4) Requests for extension of the use of best available monitoring
methods beyond March 31, 2015. You may submit a request to the
Administrator to use one or more best available monitoring methods for
sources listed in paragraphs (f)(2) and (3) of this section beyond
March 31, 2015.
    (i) Timing of request. The extension request must be submitted to
EPA no later than January 31, 2015.
    (ii) Content of request. Requests must contain the following
information:
    (A) A list of specific source types and parameters for which you
are seeking use of best available monitoring methods.
    (B) For each specific source type for which you are requesting use
of best available monitoring methods, a description of the reasons that
the needed equipment could not be obtained and installed before April
1, 2015.
    (C) A description of the specific actions you will take to obtain
and install the equipment as soon as reasonably feasible and the
expected date by which the equipment will be installed and operating.
    (iii) Approval criteria. To obtain approval to use best available
monitoring methods after March 31, 2015, you must submit a request
demonstrating to the Administrator's satisfaction that it is not
reasonably feasible to acquire, install, and operate a required piece
of monitoring equipment by April 1, 2015. The use of best available
methods under paragraph (f) of this section will not be approved beyond
December 31, 2015.
* * * * *
    (h) For well venting for liquids unloading, if a monitoring period
other than the full calendar year is used to determine the cumulative
amount of time in hours of venting for each well (the term
``Tp'' in Equation W-7A and W-7B of Sec.  98.233) or the
number of unloading events per well (the term ``Vp'' in
Equations W-8 and W-9 of Sec.  98.233), then the monitoring period must
begin before February 1 of the reporting year and must not end before
December 1 of the reporting year. The end of one monitoring period must
immediately precede the start of the next monitoring period for the
next reporting year. All production days must be monitored and all
venting accounted for.

0
7. Section 98.235 is revised to read as follows:

Sec.  98.235  Procedures for estimating missing data.

    Except as specified in Sec.  98.233, whenever a value of a
parameter is unavailable for a GHG emission calculation required by
this subpart (including, but not limited to, if a measuring device
malfunctions during unit operation or activity data are not collected),
you must follow the procedures specified in paragraphs (a) through (i)
of this section, as applicable.
    (a) For stationary and portable combustion sources that use the
calculation methods of subpart C of this part, you must use the missing
data procedures in subpart C of this part.
    (b) For each missing value of a parameter that should have been
measured quarterly or more frequently using equipment including, but
not limited to, a continuous flow meter, composition analyzer,
thermocouple, or pressure gauge, you must substitute the arithmetic
average of the quality-assured values of that parameter immediately
preceding and immediately following the missing data incident. If the
``after'' value is not obtained by the end of the reporting year, you
may use the ``before'' value for the missing data substitution. If, for
a particular parameter, no quality-assured data are available prior to
the missing data incident, you must use the first quality-assured value
obtained after the missing data period as the substitute data value. A
value is quality-assured according to the procedures specified in Sec.
98.234.
    (c) For each missing value of a parameter that should have been
measured annually, you must repeat the estimation or measurement
activity for those sources as soon as possible, including in the
subsequent calendar year if missing data are not discovered until after
December 31 of the year in which data are collected, until valid data
for reporting are obtained. Data developed and/or collected in a
subsequent calendar year to substitute for missing data cannot be used
for that subsequent year's emissions estimation. Where missing data
procedures are used for the previous year, at least 30 days must
separate emissions estimation or measurements for the previous year and
emissions estimation or measurements for the current year of data
collection.
    (d) For each missing value of a parameter that should have been
measured biannually (every two years), you must conduct the estimation
or measurement activity for those sources as soon as possible in the
subsequent calendar year if the estimation or measurement was not made
in the appropriate year (first year of data collection and every two
years thereafter), until valid data for reporting are obtained. Data
developed and/or collected in a subsequent calendar year to substitute
for missing data cannot be used to alternate or postpone subsequent
biannual emissions estimations or measurements.
    (e) For the first 6 months of required data collection, facilities
that become newly subject to this subpart W may use best engineering
estimates for any data that cannot reasonably be measured or obtained
according to the requirements of this subpart.
    (f) For the first 6 months of required data collection, facilities
that are currently subject to this subpart W and that acquire new
sources from another facility that were not previously subject to this
subpart W may use best engineering estimates for any data related to
those newly acquired sources that cannot reasonably be measured or
obtained according to the requirements of this subpart.
    (g) Unless addressed in another paragraph of this section, for each
missing value of any activity data, you must substitute data value(s)
using the best available estimate(s) of the parameter(s), based on all
applicable and available process or other data (including, but not
limited to, processing rates, operating hours).
    (h) You must report information for all measured and substitute
values of a parameter, and the procedures used to substitute an
unavailable value of a parameter per the requirements in Sec.
98.236(bb).
    (i) You must follow recordkeeping requirements listed in Sec.
98.237(f).

0
8. Section 98.236 is revised to read as follows:

Sec.  98.236  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain reported emissions and related information
as specified in this section. Reporters that use a flow or volume
measurement system that corrects to standard conditions as provided in
the introductory text in Sec.  98.233 for data elements that are
otherwise required to be determined at actual conditions, report gas
volumes at standard conditions rather the gas volumes at actual
conditions and report the standard temperature and pressure used by the
measurement system rather than the actual temperature and pressure.
    (a) The annual report must include the information specified in
paragraphs (a)(1) through (8) of this section for each applicable
industry segment. The annual report must also include annual emissions
totals, in metric tons of each GHG, for each applicable industry
segment listed in paragraphs (a)(1) through (8) of this section, and
each applicable emission source listed in paragraphs (b) through (z) of
this section.
    (1) Onshore petroleum and natural gas production. For the
equipment/activities specified in paragraphs (a)(1)(i) through (xvii)
of this section, report the information specified in the applicable
paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified
in paragraph (b) of this section.
    (ii) Natural gas driven pneumatic pumps. Report the information
specified in paragraph (c) of this section.
    (iii) Acid gas removal units. Report the information specified in
paragraph (d) of this section.
    (iv) Dehydrators. Report the information specified in paragraph (e)
of this section.
    (v) Liquids unloading. Report the information specified in
paragraph (f) of this section.
    (vi) Completions and workovers with hydraulic fracturing. Report
the information specified in paragraph (g) of this section.
    (vii) Completions and workovers without hydraulic fracturing.
Report the information specified in paragraph (h) of this section.
    (viii) Onshore production storage tanks. Report the information
specified in paragraph (j) of this section.
    (ix) Well testing. Report the information specified in paragraph
(l) of this section.
    (x) Associated natural gas. Report the information specified in
paragraph (m) of this section.
    (xi) Flare stacks. Report the information specified in paragraph
(n) of this section.
    (xii) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
    (xiii) Reciprocating compressors. Report the information specified
in paragraph (p) of this section.
    (xiv) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
    (xv) EOR injection pumps. Report the information specified in
paragraph (w) of this section.
    (xvi) EOR hydrocarbon liquids. Report the information specified in
paragraph (x) of this section.
    (xvii) Combustion equipment. Report the information specified in
paragraph (z) of this section.
    (2) Offshore petroleum and natural gas production. Report the
information specified in paragraph (s) of this section.
    (3) Onshore natural gas processing. For the equipment/activities
specified

in paragraphs (a)(3)(i) through (vii) of this section, report the
information specified in the applicable paragraphs of this section.
    (i) Acid gas removal units. Report the information specified in
paragraph (d) of this section.
    (ii) Dehydrators. Report the information specified in paragraph (e)
of this section.
    (iii) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
    (iv) Flare stacks. Report the information specified in paragraph
(n) of this section.
    (v) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
    (vi) Reciprocating compressors. Report the information specified in
paragraph (p) of this section.
    (vii) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
    (4) Onshore natural gas transmission compression. For the
equipment/activities specified in paragraphs (a)(4)(i) through (vii) of
this section, report the information specified in the applicable
paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified
in paragraph (b) of this section.
    (ii) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
    (iii) Transmission storage tanks. Report the information specified
in paragraph (k) of this section.
    (iv) Flare stacks. Report the information specified in paragraph
(n) of this section.
    (v) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
    (vi) Reciprocating compressors. Report the information specified in
paragraph (p) of this section.
    (vii) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
    (5) Underground natural gas storage. For the equipment/activities
specified in paragraphs (a)(5)(i) through (vi) of this section, report
the information specified in the applicable paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified
in paragraph (b) of this section.
    (ii) Flare stacks. Report the information specified in paragraph
(n) of this section.
    (iii) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
    (iv) Reciprocating compressors. Report the information specified in
paragraph (p) of this section.
    (v) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
    (vi) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
    (6) LNG storage. For the equipment/activities specified in
paragraphs (a)(6)(i) through (v) of this section, report the
information specified in the applicable paragraphs of this section.
    (i) Flare stacks. Report the information specified in paragraph (n)
of this section.
    (ii) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
    (iii) Reciprocating compressors. Report the information specified
in paragraph (p) of this section.
    (iv) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
    (v) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
    (7) LNG import and export equipment. For the equipment/activities
specified in paragraphs (a)(7)(i) through (vi) of this section, report
the information specified in the applicable paragraphs of this section.
    (i) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
    (ii) Flare stacks. Report the information specified in paragraph
(n) of this section.
    (iii) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
    (iv) Reciprocating compressors. Report the information specified in
paragraph (p) of this section.
    (v) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
    (vi) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
    (8) Natural gas distribution. For the equipment/activities
specified in paragraphs (a)(8)(i) through (iii) of this section, report
the information specified in the applicable paragraphs of this section.
    (i) Combustion equipment. Report the information specified in
paragraph (z) of this section.
    (ii) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
    (iii) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
    (b) Natural gas pneumatic devices. You must indicate whether the
facility contains the following types of equipment: Continuous high
bleed natural gas pneumatic devices, continuous low bleed natural gas
pneumatic devices, and intermittent bleed natural gas pneumatic
devices. If the facility contains any continuous high bleed natural gas
pneumatic devices, continuous low bleed natural gas pneumatic devices,
or intermittent bleed natural gas pneumatic devices, then you must
report the information specified in paragraphs (b)(1) through (b)(4) of
this section.
    (1) The number of natural gas pneumatic devices as specified in
paragraphs (b)(1)(i) and (ii) of this section.
    (i) The total number of devices of each type, determined according
to Sec.  98.233(a)(1) and (2).
    (ii) If the reported value in paragraph (b)(1)(i) of this section
is an estimated value determined according to Sec.  98.233(a)(2), then
you must report the information specified in paragraphs (b)(1)(ii)(A)
through (C) of this section.
    (A) The number of devices of each type reported in paragraph
(b)(1)(i) of this section that are counted.
    (B) The number of devices of each type reported in paragraph
(b)(1)(i) of this section that are estimated (not counted).
    (C) Whether the calendar year is the first calendar year of
reporting or the second calendar year of reporting.
    (2) For each type of pneumatic device, the estimated average number
of hours in the calendar year that the natural gas pneumatic devices
reported in paragraph (b)(1)(i) of this section were operating in the
calendar year (``Tt'' in Equation W-1 of this subpart).
    (3) Annual CO2 emissions, in metric tons CO2,
for the natural gas pneumatic devices combined, calculated using
Equation W-1 of this subpart and Sec.  98.233(a)(4), and reported in
paragraph (b)(1)(i) of this section.
    (4) Annual CH4 emissions, in metric tons CH4,
for the natural gas pneumatic devices combined, calculated using
Equation W-1 of this subpart and Sec.  98.233(a)(4), and reported in
paragraph (b)(1)(i) of this section.
    (c) Natural gas driven pneumatic pumps. You must indicate whether
the facility has any natural gas driven pneumatic pumps. If the
facility contains any natural gas driven pneumatic pumps, then you must
report the information specified in paragraphs (c)(1) through (4) of
this section.
    (1) Count of natural gas driven pneumatic pumps.
    (2) Average estimated number of hours in the calendar year the
pumps were operational (``T'' in Equation W-2 of this subpart).

    (3) Annual CO2 emissions, in metric tons CO2,
for all natural gas driven pneumatic pumps combined, calculated
according to Sec.  98.233(c)(1) and (2).
    (4) Annual CH4 emissions, in metric tons CH4,
for all natural gas driven pneumatic pumps combined, calculated
according to Sec.  98.233(c)(1) and (2).
    (d) Acid gas removal units. You must indicate whether your facility
has any acid gas removal units that vent directly to the atmosphere, to
a flare or engine, or to a sulfur recovery plant. If your facility
contains any acid gas removal units that vent directly to the
atmosphere, to a flare or engine, or to a sulfur recovery plant, then
you must report the information specified in paragraphs (d)(1) and (2)
of this section.
    (1) You must report the information specified in paragraphs
(d)(1)(i) through (vi) of this section for each acid gas removal unit.
    (i) A unique name or ID number for the acid gas removal unit. For
the onshore petroleum and natural gas production industry segment, a
different name or ID may be used for a single acid gas removal unit for
each location it operates at in a given year.
    (ii) Total feed rate entering the acid gas removal unit, using a
meter or engineering estimate based on process knowledge or best
available data, in million cubic feet per year.
    (iii) The calculation method used to calculate CO2
emissions from the acid gas removal unit, as specified in Sec.
98.233(d).
    (iv) Whether any CO2 emissions from the acid gas removal
unit are recovered and transferred outside the facility, as specified
in Sec.  98.233(d)(11). If any CO2 emissions from the acid
gas removal unit were recovered and transferred outside the facility,
then you must report the annual quantity of CO2, in metric
tons CO2, that was recovered and transferred outside the
facility under subpart PP of this part.
    (v) Annual CO2 emissions, in metric tons CO2,
from the acid gas removal unit, calculated using any one of the
calculation methods specified in Sec.  98.233(d) and as specified in
Sec.  98.233(d)(10) and (11).
    (vi) Sub-basin ID that best represents the wells supplying gas to
the unit (for the onshore petroleum and natural gas production industry
segment only).
    (2) You must report information specified in paragraphs (d)(2)(i)
through (iii) of this section, applicable to the calculation method
reported in paragraph (d)(1)(iii) of this section, for each acid gas
removal unit.
    (i) If you used Calculation Method 1 or Calculation Method 2 as
specified in Sec.  98.233(d) to calculate CO2 emissions from
the acid gas removal unit, then you must report the information
specified in paragraphs (d)(2)(i)(A) and (B) of this section.
    (A) Annual average volumetric fraction of CO2 in the
vent gas exiting the acid gas removal unit.
    (B) Annual volume of gas vented from the acid gas removal unit, in
cubic feet.
    (ii) If you used Calculation Method 3 as specified in Sec.
98.233(d) to calculate CO2 emissions from the acid gas
removal unit, then you must report the information specified in
paragraphs (d)(2)(ii)(A) through (D) of this section.
    (A) Indicate which equation was used (Equation W-4A or W-4B).
    (B) Annual average volumetric fraction of CO2 in the
natural gas flowing out of the acid gas removal unit, as specified in
Equation W-4A or Equation W-4B of this subpart.
    (C) Annual average volumetric fraction of CO2 content in
natural gas flowing into the acid gas removal unit, as specified in
Equation W-4A or Equation W-4B of this subpart.
    (D) The natural gas flow rate used, as specified in Equation W-4A
of this subpart, reported as either total annual volume of natural gas
flow into the acid gas removal unit in cubic feet at actual conditions;
or total annual volume of natural gas flow out of the acid gas removal
unit, as specified in Equation W-4B of this subpart, in cubic feet at
actual conditions.
    (iii) If you used Calculation Method 4 as specified in Sec.
98.233(d) to calculate CO2 emissions from the acid gas
removal unit, then you must report the information specified in
paragraphs (d)(2)(iii)(A) through (L) of this section, as applicable to
the simulation software package used.
    (A) The name of the simulation software package used.
    (B) Natural gas feed temperature, in degrees Fahrenheit.
    (C) Natural gas feed pressure, in pounds per square inch.
    (D) Natural gas flow rate, in standard cubic feet per minute.
    (E) Acid gas content of the feed natural gas, in mole percent.
    (F) Acid gas content of the outlet natural gas, in mole percent.
    (G) Unit operating hours, excluding downtime for maintenance or
standby, in hours per year.
    (H) Exit temperature of the natural gas, in degrees Fahrenheit.
    (I) Solvent pressure, in pounds per square inch.
    (J) Solvent temperature, in degrees Fahrenheit.
    (K) Solvent circulation rate, in gallons per minute.
    (L) Solvent weight, in pounds per gallon.
    (e) Dehydrators. You must indicate whether your facility contains
any of the following equipment: Glycol dehydrators with an annual
average daily natural gas throughput greater than or equal to 0.4
million standard cubic feet per day, glycol dehydrators with an annual
average daily natural gas throughput less than 0.4 million standard
cubic feet per day, and dehydrators that use desiccant. If your
facility contains any of the equipment listed in this paragraph (e),
then you must report the applicable information in paragraphs (e)(1)
through (3).
    (1) For each glycol dehydrator that has an annual average daily
natural gas throughput greater than or equal to 0.4 million standard
cubic feet per day (as specified in Sec.  98.233(e)(1)), you must
report the information specified in paragraphs (e)(1)(i) through
(xviii) of this section for the dehydrator.
    (i) A unique name or ID number for the dehydrator. For the onshore
petroleum and natural gas production industry segment, a different name
or ID may be used for a single dehydrator for each location it operates
at in a given year.
    (ii) Dehydrator feed natural gas flow rate, in million standard
cubic feet per day, determined by engineering estimate based on best
available data.
    (iii) Dehydrator feed natural gas water content, in pounds per
million standard cubic feet.
    (iv) Dehydrator outlet natural gas water content, in pounds per
million standard cubic feet.
    (v) Dehydrator absorbent circulation pump type (e.g., natural gas
pneumatic, air pneumatic, or electric).
    (vi) Dehydrator absorbent circulation rate, in gallons per minute.
    (vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene
glycol (DEG), or ethylene glycol (EG)).
    (viii) Whether stripper gas is used in dehydrator.
    (ix) Whether a flash tank separator is used in dehydrator.
    (x) Total time the dehydrator is operating, in hours.
    (xi) Temperature of the wet natural gas, in degrees Fahrenheit.
    (xii) Pressure of the wet natural gas, in pounds per square inch
gauge.
    (xiii) Mole fraction of CH4 in wet natural gas.
    (xiv) Mole fraction of CO2 in wet natural gas.
    (xv) Whether any dehydrator emissions are vented to a vapor
recovery device.
    (xvi) Whether any dehydrator emissions are vented to a flare or
regenerator firebox/fire tubes. If any emissions are vented to a flare
or

regenerator firebox/fire tubes, report the information specified in
paragraphs (e)(1)(xvi)(A) through (C) of this section for these
emissions from the dehydrator.
    (A) Annual CO2 emissions, in metric tons CO2,
for the dehydrator, calculated according to Sec.  98.233(e)(6).
    (B) Annual CH4 emissions, in metric tons CH4,
for the dehydrator, calculated according to Sec.  98.233(e)(6).
    (C) Annual N2O emissions, in metric tons N2O,
for the dehydrator, calculated according to Sec.  98.233(e)(6).
    (xvii) Whether any dehydrator emissions are vented to the
atmosphere without being routed to a flare or regenerator firebox/fire
tubes. If any emissions are not routed to a flare or regenerator
firebox/fire tubes, then you must report the information specified in
paragraphs (e)(1)(xvii)(A) and (B) of this section for those emissions
from the dehydrator.
    (A) Annual CO2 emissions, in metric tons CO2,
for the dehydrator when not venting to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1), and, if
applicable, (e)(5).
    (B) Annual CH4 emissions, in metric tons CH4,
for the dehydrator when not venting to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1) and, if
applicable, (e)(5).
    (xviii) Sub-basin ID that best represents the wells supplying gas
to the dehydrator (for the onshore petroleum and natural gas production
industry segment only).
    (2) For glycol dehydrators with an annual average daily natural gas
throughput less than 0.4 million standard cubic feet per day (as
specified in Sec.  98.233(e)(2)), you must report the information
specified in paragraphs (e)(2)(i) through (v) of this section for the
entire facility.
    (i) The total number of dehydrators at the facility.
    (ii) Whether any dehydrator emissions were vented to a vapor
recovery device. If any dehydrator emissions were vented to a vapor
recovery device, then you must report the total number of dehydrators
at the facility that vented to a vapor recovery device.
    (iii) Whether any dehydrator emissions were vented to a control
device other than a vapor recovery device or a flare or regenerator
firebox/fire tubes. If any dehydrator emissions were vented to a
control device(s) other than a vapor recovery device or a flare or
regenerator firebox/fire tubes, then you must specify the type of
control device(s) and the total number of dehydrators at the facility
that were vented to each type of control device.
    (iv) Whether any dehydrator emissions were vented to a flare or
regenerator firebox/fire tubes. If any dehydrator emissions were vented
to a flare or regenerator firebox/fire tubes, then you must report the
information specified in paragraphs (e)(2)(iv)(A) through (D) of this
section.
    (A) The total number of dehydrators venting to a flare or
regenerator firebox/fire tubes.
    (B) Annual CO2 emissions, in metric tons CO2,
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this
section, calculated according to Sec.  98.233(e)(6).
    (C) Annual CH4 emissions, in metric tons CH4,
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this
section, calculated according to Sec.  98.233(e)(6).
    (D) Annual N2O emissions, in metric tons N2O,
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this
section, calculated according to Sec.  98.233(e)(6).
    (v) For dehydrator emissions that were not vented to a flare or
regenerator firebox/fire tubes, report the information specified in
paragraphs (e)(2)(v)(A) and (B) of this section.
    (A) Annual CO2 emissions, in metric tons CO2,
for emissions from all dehydrators reported in paragraph (e)(2)(i) of
this section that were not vented to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(2), (e)(4), and, if
applicable, (e)(5), where emissions are added together for all such
dehydrators.
    (B) Annual CH4 emissions, in metric tons CH4,
for emissions from all dehydrators reported in paragraph (e)(2)(i) of
this section that were not vented to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(2), (e)(4), and, if
applicable, (e)(5), where emissions are added together for all such
dehydrators.
    (3) For dehydrators that use desiccant (as specified in Sec.
98.233(e)(3)), you must report the information specified in paragraphs
(e)(3)(i) through (iii) of this section for the entire facility.
    (i) The same information specified in paragraphs (e)(2)(i) through
(iv) of this section for glycol dehydrators, and report the information
under this paragraph for dehydrators that use desiccant.
    (ii) Annual CO2 emissions, in metric tons
CO2, for emissions from all desiccant dehydrators reported
under paragraph (e)(3)(i) of this section that are not venting to a
flare or regenerator firebox/fire tubes, calculated according to Sec.
98.233(e)(3), (e)(4), and, if applicable, (e)(5), and summing for all
such dehydrators.
    (iii) Annual CH4 emissions, in metric tons
CH4, for emissions from all desiccant dehydrators reported
in paragraph (e)(3)(i) of this section that are not venting to a flare
or regenerator firebox/fire tubes, calculated according to Sec.
98.233(e)(3), (e)(4), and, if applicable, (e)(5), and summing for all
such dehydrators.
    (f) Liquids unloading. You must indicate whether well venting for
liquids unloading occurs at your facility, and if so, which methods (as
specified in Sec.  98.233(f)) were used to calculate emissions. If your
facility performs well venting for liquids unloading and uses
Calculation Method 1, then you must report the information specified in
paragraph (f)(1) of this section. If the facility performs liquids
unloading and uses Calculation Method 2 or 3, then you must report the
information specified in paragraph (f)(2) of this section.
    (1) For each sub-basin and well tubing diameter and pressure group
for which you used Calculation Method 1 to calculate natural gas
emissions from well venting for liquids unloading, report the
information specified in paragraphs (f)(1)(i) through (xii) of this
section. Report information separately for wells with plunger lifts and
wells without plunger lifts.
    (i) Sub-basin ID.
    (ii) Well tubing diameter and pressure group ID.
    (iii) Plunger lift indicator.
    (iv) Count of wells vented to the atmosphere for the sub-basin/well
tubing diameter and pressure group.
    (v) Percentage of wells for which the monitoring period used to
determine the cumulative amount of time venting was not the full
calendar year.
    (vi) Cumulative amount of time wells were vented (sum of
``Tp'' from Equation W-7A or W-7B of this subpart), in
hours.
    (vii) Cumulative number of unloadings vented to the atmosphere for
each well, aggregated across all wells in the sub-basin/well tubing
diameter and pressure group.
    (viii) Annual natural gas emissions, in standard cubic feet, from
well venting for liquids unloading, calculated according to Sec.
98.233(f)(1).
    (ix) Annual CO2 emissions, in metric tons
CO2, from well venting for liquids unloading, calculated
according to Sec.  98.233(f)(1) and (4).
    (x) Annual CH4 emissions, in metric tons CH4,
from well venting for liquids unloading, calculated according to Sec.
98.233(f)(1) and (4).
    (xi) For each well tubing diameter group and pressure group
combination, you must report the information specified in paragraphs
(f)(1)(xi)(A) through (E) of this section for each individual well not
using a plunger lift that was tested during the year.
    (A) API Well Number of tested well.

    (B) Casing pressure, in pounds per square inch absolute.
    (C) Internal casing diameter, in inches.
    (D) Measured depth of the well, in feet.
    (E) Average flow rate of the well venting over the duration of the
liquids unloading, in standard cubic feet per hour.
    (xii) For each well tubing diameter group and pressure group
combination, you must report the information specified in paragraphs
(f)(1)(xii)(A) through (E) of this section for each individual well
using a plunger lift that was tested during the year.
    (A) API Well Number.
    (B) The tubing pressure, in pounds per square inch absolute.
    (C) The internal tubing diameter, in inches.
    (D) Measured depth of the well, in feet.
    (E) Average flow rate of the well venting over the duration of the
liquids unloading, in standard cubic feet per hour.
    (2) For each sub-basin for which you used Calculation Method 2 or 3
(as specified in Sec.  93.233(f)) to calculate natural gas emissions
from well venting for liquids unloading, you must report the
information in (f)(2)(i) through (x) of this section. Report
information separately for each calculation method.
    (i) Sub-basin ID.
    (ii) Calculation method.
    (iii) Plunger lift indicator.
    (iv) Number of wells vented to the atmosphere.
    (v) Cumulative number of unloadings vented to the atmosphere for
each well, aggregated across all wells.
    (vi) Annual natural gas emissions, in standard cubic feet, from
well venting for liquids unloading, calculated according to Sec.
98.233(f)(2) or (3), as applicable.
    (vii) Annual CO2 emissions, in metric tons
CO2, from well venting for liquids unloading, calculated
according to Sec.  98.233(f)(2) or (3), as applicable, and Sec.
98.233(f)(4).
    (viii) Annual CH4 emissions, in metric tons
CH4, from well venting for liquids unloading, calculated
according to Sec.  98.233(f)(2) or (3), as applicable, and Sec.
98.233(f)(4).
    (ix) For wells without plunger lifts, the average internal casing
diameter, in inches.
    (x) For wells with plunger lifts, the average internal tubing
diameter, in inches.
    (g) Completions and workovers with hydraulic fracturing. You must
indicate whether your facility had any gas well completions or
workovers with hydraulic fracturing during the calendar year. If your
facility had gas well completions or workovers with hydraulic
fracturing during the calendar year, then you must report information
specified in paragraphs (g)(1) through (10) of this section, for each
sub-basin and well type combination. Report information separately for
completions and workovers.
    (1) Sub-basin ID.
    (2) Well type combination.
    (3) Number of completions or workovers in the sub-basin and well
type combination category.
    (4) Calculation method used.
    (5) If you used Equation W-10A to calculate annual volumetric total
gas emissions, then you must report the information specified in
paragraphs (g)(5)(i) and (ii) of this section.
    (i) Cumulative gas flowback time, in hours, from when gas is first
detected until sufficient quantities are present to enable separation,
and the cumulative flowback time, in hours, after sufficient quantities
of gas are present to enable separation (sum of ``Tp,i'' and
sum of ``Tp,s'' values used in Equation W-10A). You may
delay the reporting of this data element if you indicate in the annual
report that wildcat wells and/or delineation wells are the only wells
included in this number. If you elect to delay reporting of this data
element, you must report by the date specified in Sec.  98.236(cc) the
total number of hours of flowback from all wells during completions or
workovers and the API Well Number(s) for the well(s) included in the
number.
    (ii) For the measured well(s), the flowback rate, in standard cubic
feet per hour (average of ``FRs,p'' values used in Equation
W-12A). You may delay the reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that can be used for the measurement. If you
elect to delay reporting of this data element, you must report by the
date specified in Sec.  98.236(cc) the measured flowback rate during
well completion or workover and the API Well Number(s) for the well(s)
included in the measurement.
    (6) If you used Equation W-10B to calculate annual volumetric total
gas emissions, then you must report the information specified in
paragraphs (g)(6)(i) and (ii) of this section.
    (i) Vented natural gas volume, in standard cubic feet, for each
well in the sub-basin (``FVs,p'' in Equation W-10B).
    (ii) Flow rate at the beginning of the period of time when
sufficient quantities of gas are present to enable separation, in
standard cubic feet per hour, for each well in the sub-basin
(``FRp,i'' in Equation W-10B).
    (7) Annual gas emissions, in standard cubic feet
(``Es,n'' in Equation W-10A or W-10B).
    (8) Annual CO2 emissions, in metric tons CO2.
    (9) Annual CH4 emissions, in metric tons CH4.
    (10) If the well emissions were vented to a flare, then you must
report the total N2O emissions, in metric tons
N2O.
    (h) Completions and workovers without hydraulic fracturing. You
must indicate whether the facility had any gas well completions without
hydraulic fracturing or any gas well workovers without hydraulic
fracturing, and if the activities occurred with or without flaring. If
the facility had gas well completions or workovers without hydraulic
fracturing, then you must report the information specified in
paragraphs (h)(1) through (4) of this section, as applicable.
    (1) For each sub-basin with gas well completions without hydraulic
fracturing and without flaring, report the information specified in
paragraphs (h)(1)(i) through (vi) of this section.
    (i) Sub-basin ID.
    (ii) Number of well completions that vented gas directly to the
atmosphere without flaring.
    (iii) Total number of hours that gas vented directly to the
atmosphere during venting for all completions in the sub-basin category
(the sum of all ``Tp'' for completions that vented to the
atmosphere as used in Equation W-13B).
    (iv) Average daily gas production rate for all completions without
hydraulic fracturing in the sub-basin without flaring, in standard
cubic feet per hour (average of all ``Vp'' used in Equation
W-13B). You may delay reporting of this data element if you indicate in
the annual report that wildcat wells and/or delineation wells are the
only wells that can be used for the measurement. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec.  98.236(cc) the measured average daily gas production rate for
all wells during completions and the API Well Number(s) for the well(s)
included in the measurement.
    (v) Annual CO2 emissions, in metric tons CO2,
that resulted from completions venting gas directly to the atmosphere
(``Es,p'' from Equation W-13B for completions that vented
directly to the atmosphere, converted to mass emissions according to
Sec.  98.233(h)(1)).
    (vi) Annual CH4 emissions, in metric tons
CH4, that resulted from completions venting gas directly to
the atmosphere (``Es,p'' from Equation W-

13B for completions that vented directly to the atmosphere, converted
to mass emissions according to Sec.  98.233(h)(1)).
    (2) For each sub-basin with gas well completions without hydraulic
fracturing and with flaring, report the information specified in
paragraphs (h)(2)(i) through (vii) of this section.
    (i) Sub-basin ID.
    (ii) Number of well completions that flared gas.
    (iii) Total number of hours that gas vented to a flare during
venting for all completions in the sub-basin category (the sum of all
``Tp'' for completions that vented to a flare from Equation
W-13B).
    (iv) Average daily gas production rate for all completions without
hydraulic fracturing in the sub-basin with flaring, in standard cubic
feet per hour (the average of all ``Vp'' from Equation W-
13B). You may delay reporting of this data element if you indicate in
the annual report that wildcat wells and/or delineation wells are the
only wells that can be used for the measurement. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec.  98.236(cc) the measured average daily gas production rate for
all wells during completions and the API Well Number(s) for the well(s)
included in the measurement.
    (v) Annual CO2 emissions, in metric tons CO2,
that resulted from completions that flared gas calculated according to
Sec.  98.233(h)(2).
    (vi) Annual CH4 emissions, in metric tons
CH4, that resulted from completions that flared gas
calculated according to Sec.  98.233(h)(2).
    (vii) Annual N2O emissions, in metric tons
N2O, that resulted from completions that flared gas
calculated according to Sec.  98.233(h)(2).
    (3) For each sub-basin with gas well workovers without hydraulic
fracturing and without flaring, report the information specified in
paragraphs (h)(3)(i) through (iv) of this section.
    (i) Sub-basin ID.
    (ii) Number of workovers that vented gas to the atmosphere without
flaring.
    (iii) Annual CO2 emissions, in metric tons
CO2 per year, that resulted from workovers venting gas
directly to the atmosphere (``Es,wo'' in Equation W-13A for
workovers that vented directly to the atmosphere, converted to mass
emissions as specified in Sec.  98.233(h)(1)).
    (iv) Annual CH4 emissions, in metric tons CH4
per year, that resulted from workovers venting gas directly to the
atmosphere (``Es,wo'' in Equation W-13A for workovers that
vented directly to the atmosphere, converted to mass emissions as
specified in Sec.  98.233(h)(1)).
    (4) For each sub-basin with gas well workovers without hydraulic
fracturing and with flaring, report the information specified in
paragraphs (h)(4)(i) through (v) of this section.
    (i) Sub-basin ID.
    (ii) Number of workovers that flared gas.
    (iii) Annual CO2 emissions, in metric tons
CO2 per year, that resulted from workovers that flared gas
calculated as specified in Sec.  98.233(h)(2).
    (iv) Annual CH4 emissions, in metric tons CH4
per year, that resulted from workovers that flared gas, calculated as
specified in Sec.  98.233(h)(2).
    (v) Annual N2O emissions, in metric tons N2O
per year, that resulted from workovers that flared gas calculated as
specified in Sec.  98.233(h)(2).
    (i) Blowdown vent stacks. You must indicate whether your facility
has blowdown vent stacks. If your facility has blowdown vent stacks,
then you must report whether emissions were calculated by equipment or
event type or by using flow meters or a combination of both. If you
calculated emissions by equipment or event type for any blowdown vent
stacks, then you must report the information specified in paragraph
(i)(1) of this section considering, in aggregate, all blowdown vent
stacks for which emissions were calculated by equipment or event type.
If you calculated emissions using flow meters for any blowdown vent
stacks, then you must report the information specified in paragraph
(i)(2) of this section considering, in aggregate, all blowdown vent
stacks for which emissions were calculated using flow meters.
    (1) Report by equipment or event type. If you calculated emissions
from blowdown vent stacks by the seven categories listed in Sec.
98.233(i)(2), then you must report the equipment or event types and the
information specified in paragraphs (i)(1)(i) through (iii) of this
section for each equipment or event type. If a blowdown event resulted
in emissions from multiple equipment types, and the emissions cannot be
apportioned to the different equipment types, then you may report the
information in paragraphs (i)(1)(i) through (iii) of this section for
the equipment type that represented the largest portion of the
emissions for the blowdown event.
    (i) Total number of blowdowns in the calendar year for the
equipment or event type (the sum of equation variable ``N'' from
Equation W-14A or Equation W-14B of this subpart, for all unique
physical volumes for the equipment or event type).
    (ii) Annual CO2 emissions for the equipment or event
type, in metric tons CO2, calculated according to Sec.
98.233(i)(2)(iii).
    (iii) Annual CH4 emissions for the equipment or event
type, in metric tons CH4, calculated according to Sec.
98.233(i)(2)(iii).
    (2) Report by flow meter. If you elect to calculate emissions from
blowdown vent stacks by using a flow meter according to Sec.
98.233(i)(3), then you must report the information specified in
paragraphs (i)(2)(i) and (ii) of this section for the facility.
    (i) Annual CO2 emissions from all blowdown vent stacks
at the facility for which emissions were calculated using flow meters,
in metric tons CO2 (the sum of all CO2 mass
emission values calculated according to Sec.  98.233(i)(3), for all
flow meters).
    (ii) Annual CH4 emissions from all blowdown vent stacks
at the facility for which emissions were calculated using flow meters,
in metric tons CH4, (the sum of all CH4 mass
emission values calculated according to Sec.  98.233(i)(3), for all
flow meters).
    (j) Onshore production storage tanks. You must indicate whether
your facility sends produced oil to atmospheric tanks. If your facility
sends produced oil to atmospheric tanks, then you must indicate which
Calculation Method(s) you used to calculate GHG emissions, and you must
report the information specified in paragraphs (j)(1) and (2) of this
section as applicable. If you used Calculation Method 1 or Calculation
Method 2, and any atmospheric tanks were observed to have
malfunctioning dump valves during the calendar year, then you must
indicate that dump valves were malfunctioning and you must report the
information specified in paragraph (j)(3) of this section.
    (1) If you used Calculation Method 1 or Calculation Method 2 to
calculate GHG emissions, then you must report the information specified
in paragraphs (j)(1)(i) through (xiv) of this section for each sub-
basin and by calculation method.
    (i) Sub-basin ID.
    (ii) Calculation method used, and name of the software package used
if using Calculation Method 1.
    (iii) The total annual oil volume from gas-liquid separators and
direct from wells that is sent to applicable onshore production storage
tanks, in barrels. You may delay reporting of this data element if you
indicate in the annual report that wildcat wells and delineation wells
are the only wells in the sub-basin with oil production greater than or
equal to 10 barrels per day and flowing to gas-liquid separators or
direct to storage tanks. If you elect to delay reporting of this data
element, you must report by the date

specified in Sec.  98.236(cc) the total volume of oil from all wells
and the API Well Number(s) for the well(s) included in this volume.
    (iv) The average gas-liquid separator temperature, in degrees
Fahrenheit.
    (v) The average gas-liquid separator pressure, in pounds per square
inch gauge.
    (vi) The average sales oil or stabilized oil API gravity, in
degrees.
    (vii) The minimum and maximum concentration (mole fraction) of
CO2 in flash gas from onshore production storage tanks.
    (viii) The minimum and maximum concentration (mole fraction) of
CH4 in flash gas from onshore production storage tanks.
    (ix) The number of wells sending oil to gas-liquid separators or
directly to atmospheric tanks.
    (x) The number of atmospheric tanks.
    (xi) An estimate of the number of atmospheric tanks, not on well-
pads, receiving your oil.
    (xii) If any emissions from the atmospheric tanks at your facility
were controlled with vapor recovery systems, then you must report the
information specified in paragraphs (j)(1)(xii)(A) through (E) of this
section.
    (A) The number of atmospheric tanks that control emissions with
vapor recovery systems.
    (B) Total CO2 mass, in metric tons CO2, that
was recovered during the calendar year using a vapor recovery system.
    (C) Total CH4 mass, in metric tons CH4, that
was recovered during the calendar year using a vapor recovery system.
    (D) Annual CO2 emissions, in metric tons CO2,
from atmospheric tanks equipped with vapor recovery systems.
    (E) Annual CH4 emissions, in metric tons CH4,
from atmospheric tanks equipped with vapor recovery systems.
    (xiii) If any atmospheric tanks at your facility vented gas
directly to the atmosphere without using a vapor recovery system or
without flaring, then you must report the information specified in
paragraphs (j)(1)(xiii)(A) through (C) of this section.
    (A) The number of atmospheric tanks that vented gas directly to the
atmosphere without using a vapor recovery system or without flaring.
    (B) Annual CO2 emissions, in metric tons CO2,
that resulted from venting gas directly to the atmosphere.
    (C) Annual CH4 emissions, in metric tons CH4,
that resulted from venting gas directly to the atmosphere.
    (xiv) If you controlled emissions from any atmospheric tanks at
your facility with one or more flares, then you must report the
information specified in paragraphs (j)(1)(xiv)(A) through (D) of this
section.
    (A) The number of atmospheric tanks that controlled emissions with
flares.
    (B) Annual CO2 emissions, in metric tons CO2,
from atmospheric tanks that controlled emissions with one or more
flares.
    (C) Annual CH4 emissions, in metric tons CH4,
from atmospheric tanks that controlled emissions with one or more
flares.
    (D) Annual N2O emissions, in metric tons N2O,
from atmospheric tanks that controlled emissions with one or more
flares.
    (2) If you used Calculation Method 3 to calculate GHG emissions,
then you must report the information specified in paragraphs (j)(2)(i)
through (iii) of this section.
    (i) Report the information specified in paragraphs (j)(2)(i)(A)
through (F) of this section, at the basin level, for atmospheric tanks
where emissions were calculated using Calculation Method 3.
    (A) The total annual oil throughput that is sent to all atmospheric
tanks in the basin, in barrels. You may delay reporting of this data
element if you indicate in the annual report that wildcat wells and
delineation wells are the only wells in the sub-basin with oil
production less than 10 barrels per day and that send oil to
atmospheric tanks. If you elect to delay reporting of this data
element, you must report by the date specified in Sec.  98.236(cc) the
total annual oil throughput from all wells and the API Well Number(s)
for the well(s) included in this volume.
    (B) An estimate of the fraction of oil throughput reported in
paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the
basin that controlled emissions with flares.
    (C) An estimate of the fraction of oil throughput reported in
paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the
basin that controlled emissions with vapor recovery systems.
    (D) The number of atmospheric tanks in the basin.
    (E) The number of wells with gas-liquid separators (``Count'' from
Equation W-15 of this subpart) in the basin.
    (F) The number of wells without gas-liquid separators (``Count''
from Equation W-15 of this subpart) in the basin.
    (ii) Report the information specified in paragraphs (j)(2)(ii)(A)
through (D) of this section for each sub-basin with atmospheric tanks
whose emissions were calculated using Calculation Method 3 and that did
not control emissions with flares.
    (A) Sub-basin ID.
    (B) The number of atmospheric tanks in the sub-basin that did not
control emissions with flares.
    (C) Annual CO2 emissions, in metric tons CO2,
from atmospheric tanks in the sub-basin that did not control emissions
with flares, calculated using Equation W-15 of this subpart and
adjusted for vapor recovery, if applicable.
    (D) Annual CH4 emissions, in metric tons CH4,
from atmospheric tanks in the sub-basin that did not control emissions
with flares, calculated using Equation W-15 of this subpart and
adjusted for vapor recovery, if applicable.
    (iii) Report the information specified in paragraphs (j)(2)(iii)(A)
through (E) of this section for each sub-basin with atmospheric tanks
whose emissions were calculated using Calculation Method 3 and that
controlled emissions with flares.
    (A) Sub-basin ID.
    (B) The number of atmospheric tanks in the sub-basin that
controlled emissions with flares.
    (C) Annual CO2 emissions, in metric tons CO2,
from atmospheric tanks that controlled emissions with flares.
    (D) Annual CH4 emissions, in metric tons CH4,
from atmospheric tanks that controlled emissions with flares.
    (E) Annual N2O emissions, in metric tons N2O,
from atmospheric tanks that controlled emissions with flares.
    (3) If you used Calculation Method 1 or Calculation Method 2, and
any gas-liquid separator liquid dump values did not close properly
during the calendar year, then you must report the information
specified in paragraphs (j)(3)(i) through (iv) of this section for each
sub-basin.
    (i) The total number of gas-liquid separators whose liquid dump
valves did not close properly during the calendar year.
    (ii) The total time the dump valves on gas-liquid separators did
not close properly in the calendar year, in hours (sum of the
``Tn'' values used in Equation W-16 of this subpart).
    (iii) Annual CO2 emissions, in metric tons
CO2, that resulted from dump valves on gas-liquid separators
not closing properly during the calendar year, calculated using
Equation W-16 of this subpart.
    (iv) Annual CH4 emissions, in metric tons
CH4, that resulted from the dump valves on gas-liquid
separators not closing properly during the calendar year, calculated
using Equation W-16 of this subpart.
    (k) Transmission storage tanks. You must indicate whether your
facility

contains any transmission storage tanks. If your facility contains at
least one transmission storage tank, then you must report the
information specified in paragraphs (k)(1) through (3) of this section
for each transmission storage tank vent stack.
    (1) For each transmission storage tank vent stack, report the
information specified in (k)(1)(i) through (iv) of this section.
    (i) The unique name or ID number for the transmission storage tank
vent stack.
    (ii) Method used to determine if dump valve leakage occurred.
    (iii) Indicate whether scrubber dump valve leakage occurred for the
transmission storage tank vent according to Sec.  98.233(k)(2).
    (iv) Indicate if there is a flare attached to the transmission
storage tank vent stack.
    (2) If scrubber dump valve leakage occurred for a transmission
storage tank vent stack, as reported in paragraph (k)(1)(iii) of this
section, and the vent stack vented directly to the atmosphere during
the calendar year, then you must report the information specified in
paragraphs (k)(2)(i) through (v) of this section for each transmission
storage vent stack where scrubber dump valve leakage occurred.
    (i) Method used to measure the leak rate.
    (ii) Measured leak rate (average leak rate from a continuous flow
measurement device), in standard cubic feet per hour.
    (iii) Duration of time that the leak is counted as having occurred,
in hours, as determined in Sec.  98.233(k)(3) (may use best available
data if a continuous flow measurement device was used).
    (iv) Annual CO2 emissions, in metric tons
CO2, that resulted from venting gas directly to the
atmosphere, calculated according to Sec.  98.233(k)(1) through (4).
    (v) Annual CH4 emissions, in metric tons CH4,
that resulted from venting gas directly to the atmosphere, calculated
according to Sec.  98.233(k)(1) through (4).
    (3) If scrubber dump valve leakage occurred for a transmission
storage tank vent stack, as reported in paragraph (k)(1)(iii), and the
vent stack vented to a flare during the calendar year, then you must
report the information specified in paragraphs (k)(3)(i) through (vi)
of this section.
    (i) Method used to measure the leak rate.
    (ii) Measured leakage rate (average leak rate from a continuous
flow measurement device) in standard cubic feet per hour.
    (iii) Duration of time that flaring occurred in hours, as defined
in Sec.  98.233(k)(3) (may use best available data if a continuous flow
measurement device was used).
    (iv) Annual CO2 emissions, in metric tons
CO2, that resulted from flaring gas, calculated according to
Sec.  98.233(k)(5).
    (v) Annual CH4 emissions, in metric tons CH4,
that resulted from flaring gas, calculated according to Sec.
98.233(k)(5).
    (vi) Annual N2O emissions, in metric tons
N2O, that resulted from flaring gas, calculated according to
Sec.  98.233(k)(5).
    (l) Well testing. You must indicate whether you performed gas well
or oil well testing, and if the testing of gas wells or oil wells
resulted in vented or flared emissions during the calendar year. If you
performed well testing that resulted in vented or flared emissions
during the calendar year, then you must report the information
specified in paragraphs (l)(1) through (4) of this section, as
applicable.
    (1) If you used Equation W-17A to calculate annual volumetric
natural gas emissions at actual conditions from oil wells and the
emissions are not vented to a flare, then you must report the
information specified in paragraphs (l)(1)(i) through (vi) of this
section.
    (i) Number of wells tested in the calendar year.
    (ii) Average number of well testing days per well for well(s)
tested in the calendar year.
    (iii) Average gas to oil ratio for well(s) tested, in cubic feet of
gas per barrel of oil.
    (iv) Average flow rate for well(s) tested, in barrels of oil per
day. You may delay reporting of this data element if you indicate in
the annual report that wildcat wells and/or delineation wells are the
only wells that are tested. If you elect to delay reporting of this
data element, you must report by the date specified in Sec.  98.236(cc)
the measured average flow rate for well(s) tested and the API Well
Number(s) for the well(s) included in the measurement.
    (v) Annual CO2 emissions, in metric tons CO2,
calculated according to Sec.  98.233(l).
    (vi) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec.  98.233(l).
    (2) If you used Equation W-17A to calculate annual volumetric
natural gas emissions at actual conditions from oil wells and the
emissions are vented to a flare, then you must report the information
specified in paragraphs (l)(2)(i) through (vii) of this section.
    (i) Number of wells tested in the calendar year.
    (ii) Average number of well testing days per well for well(s)
tested in the calendar year.
    (iii) Average gas to oil ratio for well(s) tested, in cubic feet of
gas per barrel of oil.
    (iv) Average flow rate for well(s) tested, in barrels of oil per
day. You may delay reporting of this data element if you indicate in
the annual report that wildcat wells and/or delineation wells are the
only wells that are tested. If you elect to delay reporting of this
data element, you must report by the date specified in Sec.  98.236(cc)
the measured average flow rate for well(s) tested and the API Well
Number(s) for the well(s) included in the measurement.
    (v) Annual CO2 emissions, in metric tons CO2,
calculated according to Sec.  98.233(l).
    (vi) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec.  98.233(l).
    (vii) Annual N2O emissions, in metric tons
N2O, calculated according to Sec.  98.233(l).
    (3) If you used Equation W-17B to calculate annual volumetric
natural gas emissions at actual conditions from gas wells and the
emissions were not vented to a flare, then you must report the
information specified in paragraphs (l)(3)(i) through (v) of this
section.
    (i) Number of wells tested in the calendar year.
    (ii) Average number of well testing days per well for well(s)
tested in the calendar year.
    (iii) Average annual production rate for well(s) tested, in actual
cubic feet per day. You may delay reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that are tested. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec.  98.236(cc) the measured average annual production rate for
well(s) tested and the API Well Number(s) for the well(s) included in
the measurement.
    (iv) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec.  98.233(l).
    (v) Annual CH4 emissions, in metric tons CH4,
calculated according to Sec.  98.233(l).
    (4) If you used Equation W-17B to calculate annual volumetric
natural gas emissions at actual conditions from gas wells and the
emissions were vented to a flare, then you must report the information
specified in paragraphs (l)(4)(i) through (vi) of this section.
    (i) Number of wells tested in calendar year.
    (ii) Average number of well testing days per well for well(s)
tested in the calendar year.
    (iii) Average annual production rate for well(s) tested, in actual
cubic feet

per day. You may delay reporting of this data element if you indicate
in the annual report that wildcat wells and/or delineation wells are
the only wells that are tested. If you elect to delay reporting of this
data element, you must report by the date specified in Sec.  98.236(cc)
the measured average annual production rate for well(s) tested and the
API Well Number(s) for the well(s) included in the measurement.
    (iv) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec.  98.233(l).
    (v) Annual CH4 emissions, in metric tons CH4,
calculated according to Sec.  98.233(l).
    (vi) Annual N2O emissions, in metric tons
N2O, calculated according to Sec.  98.233(l).
    (m) Associated natural gas. You must indicate whether any
associated gas was vented or flared during the calendar year. If
associated gas was vented or flared during the calendar year, then you
must report the information specified in paragraphs (m)(1) through (8)
of this section for each sub-basin.
    (1) Sub-basin ID.
    (2) Indicate whether any associated gas was vented directly to the
atmosphere without flaring.
    (3) Indicate whether any associated gas was flared.
    (4) Average gas to oil ratio, in standard cubic feet of gas per
barrel of oil (average of the ``GOR'' values used in Equation W-18 of
this subpart).
    (5) Volume of oil produced, in barrels, in the calendar year during
the time periods in which associated gas was vented or flared (the sum
of ``Vp,q'' used in Equation W-18 of this subpart). You may
delay reporting of this data element if you indicate in the annual
report that wildcat wells and/or delineation wells are the only wells
from which associated gas was vented or flared. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec.  98.236(cc) the volume of oil produced for well(s) with
associated gas venting and flaring and the API Well Number(s) for the
well(s) included in the measurement.
    (6) Total volume of associated gas sent to sales, in standard cubic
feet, in the calendar year during time periods in which associated gas
was vented or flared (the sum of ``SG'' values used in Equation W-18 of
Sec.  98.233(m)). You may delay reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells from which associated gas was vented or flared. If you elect to
delay reporting of this data element, you must report by the date
specified in Sec.  98.236(cc) the measured total volume of associated
gas sent to sales for well(s) with associated gas venting and flaring
and the API Well Number(s) for the well(s) included in the measurement.
    (7) If you had associated gas emissions vented directly to the
atmosphere without flaring, then you must report the information
specified in paragraphs (m)(7)(i) through (iii) of this section for
each sub-basin.
    (i) Total number of wells for which associated gas was vented
directly to the atmosphere without flaring.
    (ii) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec.  98.233(m)(3) and (4).
    (iii) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec.  98.233(m)(3) and (4).
    (8) If you had associated gas emissions that were flared, then you
must report the information specified in paragraphs (m)(8)(i) through
(iv) of this section for each sub-basin.
    (i) Total number of wells for which associated gas was flared.
    (ii) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec.  98.233(m)(5).
    (iii) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec.  98.233(m)(5).
    (iv) Annual N2O emissions, in metric tons
N2O, calculated according to Sec.  98.233(m)(5).
    (n) Flare stacks. You must indicate if your facility contains any
flare stacks. You must report the information specified in paragraphs
(n)(1) through (12) of this section for each flare stack at your
facility, and for each industry segment applicable to your facility.
    (1) Unique name or ID for the flare stack. For the onshore
petroleum and natural gas production industry segment, a different name
or ID may be used for a single flare stack for each location where it
operates at in a given calendar year.
    (2) Indicate whether the flare stack has a continuous flow
measurement device.
    (3) Indicate whether the flare stack has a continuous gas
composition analyzer on feed gas to the flare.
    (4) Volume of gas sent to the flare, in standard cubic feet
(``Vs'' in Equations W-19 and W-20 of this subpart).
    (5) Fraction of the feed gas sent to an un-lit flare
(``Zu'' in Equation W-19 of this subpart).
    (6) Flare combustion efficiency, expressed as the fraction of gas
combusted by a burning flare.
    (7) Mole fraction of CH4 in the feed gas to the flare
(``XCH4'' in Equation W-19 of this subpart).
    (8) Mole fraction of CO2 in the feed gas to the flare
(``XCO2'' in Equation W-20 of this subpart).
    (9) Annual CO2 emissions, in metric tons CO2
(refer to Equation W-20 of this subpart).
    (10) Annual CH4 emissions, in metric tons CH4
(refer to Equation W-19 of this subpart).
    (11) Annual N2O emissions, in metric tons N2O
(refer to Equation W-40 of this subpart).
    (12) Indicate whether a CEMS was used to measure emissions from the
flare. If a CEMS was used to measure emissions from the flare, then you
are not required to report N2O and CH4 emissions
for the flare stack.
    (o) Centrifugal compressors. You must indicate whether your
facility has centrifugal compressors. You must report the information
specified in paragraphs (o)(1) and (2) of this section for all
centrifugal compressors at your facility. For each compressor source or
manifolded group of compressor sources that you conduct as found leak
measurements as specified in Sec.  98.233(o)(2) or (4), you must report
the information specified in paragraph (o)(3) of this section. For each
compressor source or manifolded group of compressor sources that you
conduct continuous monitoring as specified in Sec.  98.233(o)(3) or
(5), you must report the information specified in paragraph (o)(4) of
this section. Centrifugal compressors in onshore petroleum and natural
gas production are not required to report information in paragraphs
(o)(1) through (4) of this section and instead must report the
information specified in paragraph (o)(5) of this section.
    (1) Compressor activity data. Report the information specified in
paragraphs (o)(1)(i) through (xiv) of this section for each centrifugal
compressor located at your facility.
    (i) Unique name or ID for the centrifugal compressor.
    (ii) Hours in operating-mode.
    (iii) Hours in not-operating-depressurized-mode.
    (iv) Indicate whether the compressor was measured in operating-
mode.
    (v) Indicate whether the compressor was measured in not-operating-
depressurized-mode.
    (vi) Indicate which, if any, compressor sources are part of a
manifolded group of compressor sources.
    (vii) Indicate which, if any, compressor sources are routed to a
flare.
    (viii) Indicate which, if any, compressor sources have vapor
recovery.
    (ix) Indicate which, if any, compressor source emissions are
captured for fuel use or are routed to a thermal oxidizer.

    (x) Indicate whether the compressor has blind flanges installed and
associated dates.
    (xi) Indicate whether the compressor has wet or dry seals.
    (xii) If the compressor has wet seals, the number of wet seals.
    (xiii) Power output of the compressor driver (hp).
    (xiv) Indicate whether the compressor had a scheduled depressurized
shutdown during the reporting year.
    (2) Compressor source. (i) For each compressor source at each
compressor, report the information specified in paragraphs (o)(2)(i)(A)
through (C) of this section.
    (A) Centrifugal compressor name or ID. Use the same ID as in
paragraph (o)(1)(i) of this section.
    (B) Centrifugal compressor source (wet seal, isolation valve, or
blowdown valve).
    (C) Unique name or ID for the leak or vent. If the leak or vent is
connected to a manifolded group of compressor sources, use the same
leak or vent ID for each compressor source in the manifolded group. If
multiple compressor sources are released through a single vent for
which continuous measurements are used, use the same leak or vent ID
for each compressor source released via the measured vent. For a single
compressor using as found measurements, you must provide a different
leak or vent ID for each compressor source.
    (ii) For each leak or vent, report the information specified in
paragraphs (o)(2)(ii)(A) through (E) of this section.
    (A) Indicate whether the leak or vent is for a single compressor
source or manifolded group of compressor sources and whether the
emissions from the leak or vent are released to the atmosphere, routed
to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.
    (B) Indicate whether an as found measurement(s) as identified in
Sec.  98.233(o)(2) or (4) was conducted on the leak or vent.
    (C) Indicate whether continuous measurements as identified in Sec.
98.233(o)(3) or (5) were conducted on the leak or vent.
    (D) Report emissions as specified in paragraphs (o)(2)(ii)(D)(1)
and (2) of this section for the leak or vent. If the leak or vent is
routed to a flare, combustion, or vapor recovery, you are not required
to report emissions under this paragraph.
    (1) Annual CO2 emissions, in metric tons CO2.
    (2) Annual CH4 emissions, in metric tons CH4.
    (E) If the leak or vent is routed to flare, combustion, or vapor
recovery, report the percentage of time that the respective device was
operational when the compressor source emissions were routed to the
device.
    (3) As found measurement sample data. If the measurement methods
specified in Sec.  98.233(o)(2) or (4) are conducted, report the
information specified in paragraph (o)(3)(i) of this section. If the
calculation specified in Sec.  98.233(o)(6)(ii) is performed, report
the information specified in paragraph (o)(3)(ii) of this section.
    (i) For each as found measurement performed on a leak or vent,
report the information specified in paragraphs (o)(3)(i)(A) through (F)
of this section.
    (A) Name or ID of leak or vent. Use same leak or vent ID as in
paragraph (o)(2)(i)(C) of this section.
    (B) Measurement date.
    (C) Measurement method. If emissions were not detected when using a
screening method, report the screening method. If emissions were
detected using a screening method, report only the method subsequently
used to measure the volumetric emissions.
    (D) Measured flow rate, in standard cubic feet per hour.
    (E) For each compressor attached to the leak or vent, report the
compressor mode during which the measurement was taken.
    (F) If the measurement is for a manifolded group of compressor
sources, indicate whether the measurement location is prior to or after
comingling with non-compressor emission sources.
    (ii) For each compressor mode-source combination where a reporter
emission factor as calculated in Equation W-23 was used to calculate
emissions in Equation W-22, report the information specified in
paragraphs (o)(3)(ii)(A) through (D) of this section.
    (A) The compressor mode-source combination.
    (B) The compressor mode-source combination reporter emission
factor, in standard cubic feet per hour (EFs,m in Equation
W-23).
    (C) The total number of compressors measured in the compressor
mode-source combination in the current reporting year and the preceding
two reporting years (Countm in Equation W-23).
    (D) Indicate whether the compressor mode-source combination
reporter emission factor is facility-specific or based on all of the
reporter's applicable facilities.
    (4) Continuous measurement data. If the measurement methods
specified in Sec.  98.233(o)(3) or (5) are conducted, report the
information specified in paragraphs (o)(4)(i) through (iv) of this
section for each continuous measurement conducted on each leak or vent
associated with each compressor source or manifolded group of
compressor sources.
    (i) Name or ID of leak or vent. Use same leak or vent ID as in
paragraph (o)(2)(i)(C) of this section.
    (ii) Measured volume of flow during the reporting year, in million
standard cubic feet.
    (iii) Indicate whether the measured volume of flow during the
reporting year includes compressor blowdown emissions as allowed for in
Sec.  98.233(o)(3)(ii) and (o)(5)(iii).
    (iv) If the measurement is for a manifolded group of compressor
sources, indicate whether the measurement location is prior to or after
comingling with non-compressor emission sources.
    (5) Onshore petroleum and natural gas production. Centrifugal
compressors with wet seal degassing vents in onshore petroleum and
natural gas production must report the information specified in
paragraphs (o)(5)(i) through (iii) of this section.
    (i) Number of centrifugal compressors that have wet seal oil
degassing vents.
    (ii) Annual CO2 emissions, in metric tons
CO2, from centrifugal compressors with wet seal oil
degassing vents.
    (iii) Annual CH4 emissions, in metric tons
CH4, from centrifugal compressors with wet seal oil
degassing vents.
    (p) Reciprocating compressors. You must indicate whether your
facility has reciprocating compressors. You must report the information
specified in paragraphs (p)(1) and (2) of this section for all
reciprocating compressors at your facility. For each compressor source
or manifolded group of compressor sources that you conduct as found
leak measurements as specified in Sec.  98.233(p)(2) or (4), you must
report the information specified in paragraph (p)(3) of this section.
For each compressor source or manifolded group of compressor sources
that you conduct continuous monitoring as specified in Sec.
98.233(p)(3) or (5), you must report the information specified in
paragraph (p)(4) of this section. Reciprocating compressors in onshore
petroleum and natural gas production are not required to report
information in paragraphs (p)(1) through (4) of this section and
instead must report the information specified in paragraph (p)(5) of
this section.
    (1) Compressor activity data. Report the information specified in
paragraphs (p)(1)(i) through (xiv) of this section for each
reciprocating compressor located at your facility.

    (i) Unique name or ID for the reciprocating compressor.
    (ii) Hours in operating-mode.
    (iii) Hours in standby-pressurized-mode.
    (iv) Hours in not-operating-depressurized-mode.
    (v) Indicate whether the compressor was measured in operating-mode.
    (vi) Indicate whether the compressor was measured in standby-
pressurized-mode.
    (vii) Indicate whether the compressor was measured in not-
operating-depressurized-mode.
    (viii) Indicate which, if any, compressor sources are part of a
manifolded group of compressor sources.
    (ix) Indicate which, if any, compressor sources are routed to a
flare.
    (x) Indicate which, if any, compressor sources have vapor recovery.
    (xi) Indicate which, if any, compressor source emissions are
captured for fuel use or are routed to a thermal oxidizer.
    (xii) Indicate whether the compressor has blind flanges installed
and associated dates.
    (xiii) Power output of the compressor driver (hp).
    (xiv) Indicate whether the compressor had a scheduled depressurized
shutdown during the reporting year.
    (2) Compressor source. (i) For each compressor source at each
compressor, report the information specified in paragraphs (p)(2)(i)(A)
through (C) of this section.
    (A) Reciprocating compressor name or ID. Use the same ID as in
paragraph (p)(1)(i) of this section.
    (B) Reciprocating compressor source (isolation valve, blowdown
valve, or rod packing).
    (C) Unique name or ID for the leak or vent. If the leak or vent is
connected to a manifolded group of compressor sources, use the same
leak or vent ID for each compressor source in the manifolded group. If
multiple compressor sources are released through a single vent for
which continuous measurements are used, use the same leak or vent ID
for each compressor source released via the measured vent. For a single
compressor using as found measurements, you must provide a different
leak or vent ID for each compressor source.
    (ii) For each leak or vent, report the information specified in
paragraphs (p)(2)(ii)(A) through (E) of this section.
    (A) Indicate whether the leak or vent is for a single compressor
source or manifolded group of compressor sources and whether the
emissions from the leak or vent are released to the atmosphere, routed
to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.
    (B) Indicate whether an as found measurement(s) as identified in
Sec.  98.233(p)(2) or (4) was conducted on the leak or vent.
    (C) Indicate whether continuous measurements as identified in Sec.
98.233(p)(3) or (5) were conducted on the leak or vent.
    (D) Report emissions as specified in paragraphs (p)(2)(ii)(D)(1)
and (2) of this section for the leak or vent. If the leak or vent is
routed to flare, combustion, or vapor recovery, you are not required to
report emissions under this paragraph.
    (1) Annual CO2 emissions, in metric tons CO2.
    (2) Annual CH4 emissions, in metric tons CH4.
    (E) If the leak or vent is routed to flare, combustion, or vapor
recovery, report the percentage of time that the respective device was
operational when the compressor source emissions were routed to the
device.
    (3) As found measurement sample data. If the measurement methods
specified in Sec.  98.233(p)(2) or (4) are conducted, report the
information specified in paragraph (p)(3)(i) of this section. If the
calculation specified in Sec.  98.233(p)(6)(ii) is performed, report
the information specified in paragraph (p)(3)(ii) of this section.
    (i) For each as found measurement performed on a leak or vent,
report the information specified in paragraphs (p)(3)(i)(A) through (F)
of this section.
    (A) Name or ID of leak or vent. Use same leak or vent ID as in
paragraph (p)(2)(i)(C) of this section.
    (B) Measurement date.
    (C) Measurement method. If emissions were not detected when using a
screening method, report the screening method. If emissions were
detected using a screening method, report only the method subsequently
used to measure the volumetric emissions.
    (D) Measured flow rate, in standard cubic feet per hour.
    (E) For each compressor attached to the leak or vent, report the
compressor mode during which the measurement was taken.
    (F) If the measurement is for a manifolded group of compressor
sources, indicate whether the measurement location is prior to or after
comingling with non-compressor emission sources.
    (ii) For each compressor mode-source combination where a reporter
emission factor as calculated in Equation W-28 was used to calculate
emissions in Equation W-27, report the information specified in
paragraphs (p)(3)(ii)(A) through (D) of this section
    (A) The compressor mode-source combination.
    (B) The compressor mode-source combination reporter emission
factor, in standard cubic feet per hour (EFs,m in Equation
W-28).
    (C) The total number of compressors measured in the compressor
mode-source combination in the current reporting year and the preceding
two reporting years (Countm in Equation W-28).
    (D) Indicate whether the compressor mode-source combination
reporter emission factor is facility-specific or based on all of the
reporter's applicable facilities.
    (4) Continuous measurement data. If the measurement methods
specified in Sec.  98.233(p)(3) or (5) are conducted, report the
information specified in paragraphs (p)(4)(i) through (iv) of this
section for each continuous measurement conducted on each leak or vent
associated with each compressor source or manifolded group of
compressor sources.
    (i) Name or ID of leak or vent. Use same leak or vent ID as in
paragraph (p)(2)(i)(C) of this section.
    (ii) Measured volume of flow during the reporting year, in million
standard cubic feet.
    (iii) Indicate whether the measured volume of flow during the
reporting year includes compressor blowdown emissions as allowed for in
Sec.  98.233(p)(3)(ii) and (p)(5)(iii).
    (iv) If the measurement is for a manifolded group of compressor
sources, indicate whether the measurement location is prior to or after
comingling with non-compressor emission sources.
    (5) Onshore petroleum and natural gas production. Reciprocating
compressors in onshore petroleum and natural gas production must report
the information specified in paragraphs (p)(5)(i) through (iii) of this
section.
    (i) Number of reciprocating compressors.
    (ii) Annual CO2 emissions, in metric tons
CO2, from reciprocating compressors.
    (iii) Annual CH4 emissions, in metric tons
CH4, from reciprocating compressors.
    (q) Equipment leak surveys. If your facility is subject to the
requirements of Sec.  98.233(q), then you must report the information
specified in paragraphs (q)(1) and (2) of this section. Natural gas
distribution facilities with emission sources listed in Sec.
98.232(i)(1) must also report the information specified in paragraph
(q)(3) of this section.

    (1) You must report the information specified in paragraphs
(q)(1)(i) and (ii) of this section.
    (i) Except as specified in paragraph (q)(1)(ii) of this section,
the number of complete equipment leak surveys performed during the
calendar year.
    (ii) Natural gas distribution facilities performing equipment leak
surveys across a multiple year leak survey cycle must report the number
of years in the leak survey cycle.
    (2) You must indicate whether your facility contains any of the
component types listed in Sec.  98.232(d)(7), (e)(7), (f)(5), (g)(3),
(h)(4), or (i)(1), for your facility's industry segment. For each
component type that is located at your facility, you must report the
information specified in paragraphs (q)(2)(i) through (v) of this
section. If a component type is located at your facility and no leaks
were identified from that component, then you must report the
information in paragraphs (q)(2)(i) through (v) of this section but
report a zero (``0'') for the information required according to
paragraphs (q)(2)(iii), (iv), and (v) of this section.
    (i) Component type.
    (ii) Total number of the surveyed component type that were
identified as leaking in the calendar year (``xp'' in
Equation W-30 of this subpart for the component type).
    (iii) Average time the surveyed components are assumed to be
leaking and operational, in hours (average of ``Tp,z'' from
Equation W-30 of this subpart for the component type).
    (iv) Annual CO2 emissions, in metric tons
CO2, for the component type as calculated using Equation W-
30 (for surveyed components only).
    (v) Annual CH4 emissions, in metric tons CH4,
for the component type as calculated using Equation W-30 (for surveyed
components only).
    (3) Natural gas distribution facilities with emission sources
listed in Sec.  98.232(i)(1) must also report the information specified
in paragraphs (q)(3)(i) through (viii) and, if applicable, (q)(3)(ix)
of this section.
    (i) Number of above grade transmission-distribution transfer
stations surveyed in the calendar year.
    (ii) Number of meter/regulator runs at above grade transmission-
distribution transfer stations surveyed in the calendar year
(``CountMR,y'' from Equation W-31 of this subpart, for the
current calendar year).
    (iii) Average time that meter/regulator runs surveyed in the
calendar year were operational, in hours (average of
``Tw,y'' from Equation W-31 of this subpart, for the current
calendar year).
    (iv) Number of above grade transmission-distribution transfer
stations surveyed in the current leak survey cycle.
    (v) Number of meter/regulator runs at above grade transmission-
distribution transfer stations surveyed in current leak survey cycle
(sum of ``CountMR,y'' from Equation W-31 of this subpart,
for all calendar years in the current leak survey cycle).
    (vi) Average time that meter/regulator runs surveyed in the current
leak survey cycle were operational, in hours (average of
``Tw,y'' from Equation W-31 of this subpart, for all years
included in the leak survey cycle).
    (vii) Meter/regulator run CO2 emission factor based on
all surveyed transmission-distribution transfer stations in the current
leak survey cycle, in standard cubic feet of CO2 per
operational hour of all meter/regulator runs (``EFs,MR,i''
for CO2 calculated using Equation W-31 of this subpart).
    (viii) Meter/regulator run CH4 emission factor based on
all surveyed transmission-distribution transfer stations in the current
leak survey cycle, in standard cubic feet of CH4 per
operational hour of all meter/regulator runs (``EFs,MR,i''
for CH4 calculated using Equation W-31 of this subpart).
    (ix) If your natural gas distribution facility performs equipment
leak surveys across a multiple year leak survey cycle, you must also
report:
    (A) The total number of meter/regulator runs at above grade
transmission-distribution transfer stations at your facility
(``CountMR'' in Equation W-32B of this subpart).
    (B) Average estimated time that each meter/regulator run at above
grade transmission-distribution transfer stations was operational in
the calendar year, in hours per meter/regulator run
(``Tw,avg'' in Equation W-32B of this subpart).
    (C) Annual CO2 emissions, in metric tons CO2,
for all above grade transmission-distribution transfer stations at your
facility.
    (D) Annual CH4 emissions, in metric tons CH4,
for all above grade transmission-distribution transfer stations at your
facility.
    (r) Equipment leaks by population count. If your facility is
subject to the requirements of Sec.  98.233(r), then you must report
the information specified in paragraphs (r)(1) through (3) of this
section, as applicable.
    (1) You must indicate whether your facility contains any of the
emission source types required to use Equation W-32A of this subpart.
You must report the information specified in paragraphs (r)(1)(i)
through (v) of this section separately for each emission source type
required to use Equation W-32A of this subpart that is located at your
facility. Onshore petroleum and natural gas production facilities must
report the information specified in paragraphs (r)(1)(i) through (v) of
this section separately by component type, service type, and geographic
location (i.e., Eastern U.S. or Western U.S.).
    (i) Emission source type. Onshore petroleum and natural gas
production facilities must report the component type, service type and
geographic location.
    (ii) Total number of the emission source type at the facility
(``Counte'' in Equation W-32A of this subpart).
    (iii) Average estimated time that the emission source type was
operational in the calendar year, in hours (``Te'' in
Equation W-32A of this subpart).
    (iv) Annual CO2 emissions, in metric tons
CO2, for the emission source type.
    (v) Annual CH4 emissions, in metric tons CH4,
for the emission source type.
    (2) Natural gas distribution facilities must also report the
information specified in paragraphs (r)(2)(i) through (v) of this
section.
    (i) Number of above grade transmission-distribution transfer
stations at the facility.
    (ii) Number of above grade metering-regulating stations that are
not transmission-distribution transfer stations at the facility.
    (iii) Total number of meter/regulator runs at above grade metering-
regulating stations that are not above grade transmission-distribution
transfer stations (``CountMR'' in Equation W-32B of this
subpart).
    (iv) Average estimated time that each meter/regulator run at above
grade metering-regulating stations that are not above grade
transmission-distribution transfer stations was operational in the
calendar year, in hours per meter/regulator run (``Tw,avg''
in Equation W-32B of this subpart).
    (v) If your facility has above grade metering-regulating stations
that are not above grade transmission-distribution transfer stations
and your facility also has above grade transmission-distribution
transfer stations, you must also report:
    (A) Annual CO2 emissions, in metric tons CO2,
from above grade metering-regulating stations that are not above grade
transmission-distribution transfer stations.
    (B) Annual CH4 emissions, in metric tons CH4,
from above grade metering regulating stations that are not above grade
transmission-distribution transfer stations.

    (3) Onshore petroleum and natural gas production facilities must
also report the information specified in paragraphs (r)(3)(i) and (ii)
of this section.
    (i) Calculation method used.
    (ii) Onshore petroleum and natural gas production facilities must
report the information specified in paragraphs (r)(3)(ii)(A) and (B) of
this section, for each major equipment type, production type (i.e.,
natural gas or crude oil), and geographic location combination in
Tables W-1B and W-1C of this subpart.
    (A) An indication of whether the facility contains the major
equipment type.
    (B) If the facility does contain the equipment type, the count of
the major equipment type.
    (s) Offshore petroleum and natural gas production. You must report
the information specified in paragraphs (s)(1) through (3) of this
section for each emission source type listed in the most recent BOEMRE
study.
    (1) Annual CO2 emissions, in metric tons CO2.
    (2) Annual CH4 emissions, in metric tons CH4.
    (3) Annual N2O emissions, in metric tons N2O.
    (t) [Reserved]
    (u) [Reserved]
    (v) [Reserved]
    (w) EOR injection pumps. You must indicate whether CO2
EOR injection was used at your facility during the calendar year and if
any EOR injection pump blowdowns occurred during the year. If any EOR
injection pump blowdowns occurred during the calendar year, then you
must report the information specified in paragraphs (w)(1) through (8)
of this section for each EOR injection pump system.
    (1) Sub-basin ID.
    (2) EOR injection pump system identifier.
    (3) Pump capacity, in barrels per day.
    (4) Total volume of EOR injection pump system equipment chambers,
in cubic feet (``Vv'' in Equation W-37 of this subpart).
    (5) Number of blowdowns for the EOR injection pump system in the
calendar year.
    (6) Density of critical phase EOR injection gas, in kilograms per
cubic foot (``Rc'' in Equation W-37 of this subpart).
    (7) Mass fraction of CO2 in critical phase EOR injection
gas (``GHGCO2'' in Equation W-37 of this subpart).
    (8) Annual CO2 emissions, in metric tons CO2,
from EOR injection pump system blowdowns.
    (x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon
liquids were produced through EOR operations. If hydrocarbon liquids
were produced through EOR operations, you must report the information
specified in paragraphs (x)(1) through (4) of this section for each
sub-basin category with EOR operations.
    (1) Sub-basin ID.
    (2) Total volume of hydrocarbon liquids produced through EOR
operations in the calendar year, in barrels (``Vhl'' in
Equation W-38 of this subpart).
    (3) Average CO2 retained in hydrocarbon liquids
downstream of the storage tank, in metric tons per barrel under
standard conditions (``Shl'' in Equation W-38 of this
subpart).
    (4) Annual CO2 emissions, in metric tons CO2,
from CO2 retained in hydrocarbon liquids produced through
EOR operations downstream of the storage tank (``MassCO2''
in Equation W-38 of this subpart).
    (y) [Reserved]
    (z) Combustion equipment at onshore petroleum and natural gas
production facilities and natural gas distribution facilities. If your
facility is required by Sec.  98.232(c)(22) or (i)(7) to report
emissions from combustion equipment, then you must indicate whether
your facility has any combustion units subject to reporting according
to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section. If your
facility contains any combustion units subject to reporting according
to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section, then you must
report the information specified in paragraphs (z)(1) and (2) of this
section, as applicable.
    (1) Indicate whether the combustion units include: External fuel
combustion units with a rated heat capacity less than or equal to 5
million Btu per hour; or, internal fuel combustion units that are not
compressor-drivers, with a rated heat capacity less than or equal to 1
mmBtu/hr (or the equivalent of 130 horsepower). If the facility
contains external fuel combustion units with a rated heat capacity less
than or equal to 5 million Btu per hour or internal fuel combustion
units that are not compressor-drivers, with a rated heat capacity less
than or equal to 1 million Btu per hour (or the equivalent of 130
horsepower), then you must report the information specified in
paragraphs (z)(1)(i) and (ii) of this section for each unit type.
    (i) The type of combustion unit.
    (ii) The total number of combustion units.
    (2) Indicate whether the combustion units include: External fuel
combustion units with a rated heat capacity greater than 5 million Btu
per hour; internal fuel combustion units that are not compressor-
drivers, with a rated heat capacity greater than 1 million Btu per hour
(or the equivalent of 130 horsepower); or, internal fuel combustion
units of any heat capacity that are compressor-drivers. If your
facility contains: External fuel combustion units with a rated heat
capacity greater than 5 mmBtu/hr; internal fuel combustion units that
are not compressor-drivers, with a rated heat capacity greater than 1
million Btu per hour (or the equivalent of 130 horsepower); or internal
fuel combustion units of any heat capacity that are compressor-drivers,
then you must report the information specified in paragraphs (z)(2)(i)
through (vi) of this section for each combustion unit type and fuel
type combination.
    (i) The type of combustion unit.
    (ii) The type of fuel combusted.
    (iii) The quantity of fuel combusted in the calendar year, in
thousand standard cubic feet, gallons, or tons.
    (iv) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec.  98.233(z)(1) and (2).
    (v) Annual CH4 emissions, in metric tons CH4,
calculated according to Sec.  98.233(z)(1) and (2).
    (vi) Annual N2O emissions, in metric tons
N2O, calculated according to Sec.  98.233(z)(1) and (2).
    (aa) Each facility must report the information specified in
paragraphs (aa)(1) through (9) of this section, for each applicable
industry segment, by using best available data. If a quantity required
to be reported is zero, you must report zero as the value.
    (1) For onshore petroleum and natural gas production, report the
data specified in paragraphs (aa)(1)(i) and (ii) of this section.
    (i) Report the information specified in paragraphs (aa)(1)(i)(A)
through (C) of this section for the basin as a whole.
    (A) The quantity of gas produced in the calendar year from wells,
in thousand standard cubic feet. This includes gas that is routed to a
pipeline, vented or flared, or used in field operations. This does not
include gas injected back into reservoirs or shrinkage resulting from
lease condensate production.
    (B) The quantity of gas produced in the calendar year for sales, in
thousand standard cubic feet.
    (C) The quantity of crude oil and condensate produced in the
calendar year for sales, in barrels.
    (ii) Report the information specified in paragraphs (aa)(1)(ii)(A)
through (M) of this section for each unique sub-basin category.
    (A) State.
    (B) County.
    (C) Formation type.

    (D) The number of producing wells at the end of the calendar year
(exclude only those wells permanently taken out of production, i.e.,
plugged and abandoned) .
    (E) The number of producing wells acquired during the calendar
year.
    (F) The number of producing wells divested during the calendar
year.
    (G) The number of wells completed during the calendar year.
    (H) The number of wells permanently taken out of production (i.e.,
plugged and abandoned) during the calendar year.
    (I) Average mole fraction of CH4 in produced gas.
    (J) Average mole fraction of CO2 in produced gas.
    (K) If an oil sub-basin, report the average GOR of all wells, in
thousand standard cubic feet per barrel.
    (L) If an oil sub-basin, report the average API gravity of all
wells.
    (M) If an oil sub-basin, report average low pressure separator
pressure, in pounds per square inch gauge.
    (2) For offshore production, report the quantities specified in
paragraphs (aa)(2)(i) and (ii) of this section.
    (i) The total quantity of gas handled at the offshore platform in
the calendar year, in thousand standard cubic feet, including
production volumes and volumes transferred via pipeline from another
location.
    (ii) The total quantity of oil and condensate handled at the
offshore platform in the calendar year, in barrels, including
production volumes and volumes transferred via pipeline from another
location.
    (3) For natural gas processing, report the information specified in
paragraphs (aa)(3)(i) through (vii) of this section.
    (i) The quantity of natural gas received at the gas processing
plant in the calendar year, in thousand standard cubic feet.
    (ii) The quantity of processed (residue) gas leaving the gas
processing plant in the calendar year, in thousand standard cubic feet.
    (iii) The cumulative quantity of all NGLs (bulk and fractionated)
received at the gas processing plant in the calendar year, in barrels.
    (iv) The cumulative quantity of all NGLs (bulk and fractionated)
leaving the gas processing plant in the calendar year, in barrels.
    (v) Average mole fraction of CH4 in natural gas
received.
    (vi) Average mole fraction of CO2 in natural gas
received.
    (vii) Indicate whether the facility fractionates NGLs.
    (4) For natural gas transmission compression, report the quantity
specified in paragraphs (aa)(4)(i) through (v) of this section.
    (i) The quantity of gas transported through the compressor station
in the calendar year, in thousand standard cubic feet.
    (ii) Number of compressors.
    (iii) Total compressor power rating of all compressors combined, in
horsepower.
    (iv) Average upstream pipeline pressure, in pounds per square inch
gauge.
    (v) Average downstream pipeline pressure, in pounds per square inch
gauge.
    (5) For underground natural gas storage, report the quantities
specified in paragraphs (aa)(5)(i) through (iii) of this section.
    (i) The quantity of gas injected into storage in the calendar year,
in thousand standard cubic feet.
    (ii) The quantity of gas withdrawn from storage in the calendar
year, in thousand standard cubic feet.
    (iii) Total storage capacity, in thousand standard cubic feet.
    (6) For LNG import equipment, report the quantity of LNG imported
in the calendar year, in thousand standard cubic feet.
    (7) For LNG export equipment, report the quantity of LNG exported
in the calendar year, in thousand standard cubic feet.
    (8) For LNG storage, report the quantities specified in paragraphs
(aa)(8)(i) through (iii) of this section.
    (i) The quantity of LNG added into storage in the calendar year, in
thousand standard cubic feet.
    (ii) The quantity of LNG withdrawn from storage in the calendar
year, in thousand standard cubic feet.
    (iii) Total storage capacity, in thousand standard cubic feet.
    (9) For natural gas distribution, report the quantities specified
in paragraphs (aa)(9)(i) through (vii) of this section.
    (i) The quantity of natural gas received at all custody transfer
stations in the calendar year, in thousand standard cubic feet. This
value may include meter corrections, but only for the calendar year
covered by the annual report.
    (ii) The quantity of natural gas withdrawn from in-system storage
in the calendar year, in thousand standard cubic feet.
    (iii) The quantity of natural gas added to in-system storage in the
calendar year, in thousand standard cubic feet.
    (iv) The quantity of natural gas delivered to end users, in
thousand standard cubic feet. This value does not include stolen gas,
or gas that is otherwise unaccounted for.
    (v) The quantity of natural gas transferred to third parties such
as other LDCs or pipelines, in thousand standard cubic feet. This value
does not include stolen gas, or gas that is otherwise unaccounted for.
    (vi) The quantity of natural gas consumed by the LDC for
operational purposes, in thousand standard cubic feet.
    (vii) The estimated quantity of gas stolen in the calendar year, in
thousand standard cubic feet.
    (bb) For any missing data procedures used, report the information
in Sec.  98.3(c)(8) except as provided in paragraphs (bb)(1) and (2) of
this section.
    (1) For quarterly measurements, report the total number of quarters
that a missing data procedure was used for each data element rather
than the total number of hours.
    (2) For annual or biannual (once every two years) measurements, you
do not need to report the number of hours that a missing data procedure
was used for each data element.
    (cc) If you elect to delay reporting the information in paragraph
(g)(5)(i), (g)(5)(ii), (h)(1)(iv), (h)(2)(iv), (j)(1)(iii),
(j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), (l)(3)(iii), (l)(4)(iii), (m)(5),
or (m)(6) of this section, you must report the information required in
that paragraph no later than the date 2 years following the date
specified in Sec.  98.3(b) introductory text.

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9. Section 98.237 is amended by adding paragraph (f) to read as
follows:

Sec.  98.237  Records that must be retained.

* * * * *
    (f) For each time a missing data procedure was used, keep a record
listing the emission source type, a description of the circumstance
that resulted in the need to use missing data procedures, the missing
data provisions in Sec.  98.235 that apply, the calculation or analysis
used to develop the substitute value, and the substitute value.

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10. Section 98.238 is amended by:
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a. Adding a definition for ``Associated gas venting or flaring'' in
alphabetical order;
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b. Removing the definition for ``Component'';
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c. Adding definitions for ``Compressor mode'' and ``Compressor source''
in alphabetical order;
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d. Removing the definitions for ``Equipment leak'' and ``Equipment leak
detection'';
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