(vi) Annual CH4 emissions, in metric tons
CH4, for the natural gas pneumatic devices combined for
which emissions were calculated using Equation W-1B of this subpart and
Sec.  98.233(a)(6).
    (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 (6) of
this section. If a pump was vented directly to the atmosphere for part
of the year and routed to a flare, combustion, or vapor recovery system
during another part of the year, then include the pump in each of the
counts specified in paragraphs (c)(1) through (3) of this section.
    (1) Count of natural gas driven pneumatic pumps vented directly to
the atmosphere at any point during the year.
    (2) Count of natural gas driven pneumatic pumps routed to a flare,
combustion, or vapor recovery system at any point during the year.
    (3) Total count of natural gas driven pneumatic pumps at the
facility.
    (4) Average estimated number of hours in the calendar year that
natural gas driven pneumatic pumps that vented directly to atmosphere
were in service (i.e., supplied with natural gas) (``T'' in Equation W-
2 of this subpart).
    (5) Annual CO2 emissions, in metric tons CO2,
for all natural gas driven pneumatic pumps vented directly to the
atmosphere combined, calculated according to Sec.  98.233(c)(1) and
(2).
    (6) Annual CH4 emissions, in metric tons CH4,
for all natural gas driven pneumatic pumps vented directly to the
atmosphere combined, calculated according to Sec.  98.233(c)(1) and
(2).
    (d) * * *
    (1) * * *
    (iii) The calculation method used to calculate CO2
emissions from the acid gas removal unit, as specified in Sec.
98.233(d). If the AGR vent was routed to a flare and comingled with
emissions from other sources and you continuously monitor the flow rate
and/or composition, select ``Routed to a flare [Sec.
98.233(d)(12)(ii)]'' as the calculation method.
* * * * *
    (2) * * *
    (iii) * * *
    (L) Solvent type, from one of the following options:
SelexolTM, Rectisol[supreg], PurisolTM, Fluor
SolventSM, BenfieldTM, 20 wt% MEA, 30 wt% MEA, 40
wt% MDEA, 50 wt% MDEA, and other.
    (iv) If the AGR vent was routed to a flare, then you must report
the unique name or ID for the flare stack to which the AGR vent is
routed.
    (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 and glycol dehydrators with an
annual average daily natural gas throughput less than 0.4 million
standard cubic feet per day. 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) of this
section.
    (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 (xix)
of this section for the dehydrator.
* * * * *
    (viii) Whether stripping gas is used in dehydrator.
    (A) If stripping gas is used in the dehydrator, type of stripping
gas used (dry natural gas, flash gas, nitrogen/inert gas, other).
    (B) If stripping gas is used in the dehydrator, average flow rate
of stripping gas in standard cubic feet per minute.
* * * * *
    (xi) Temperature of the wet natural gas at the absorber inlet, in
degrees Fahrenheit.

    (xii) Pressure of the wet natural gas at the absorber inlet, in
pounds per square inch gauge.
* * * * *
    (xv) Sub-basin ID that best represents the wells supplying gas to
the dehydrator (for the onshore petroleum and natural gas production
industry segment only) or name of the county that best represents the
equipment supplying gas to the dehydrator (for the onshore petroleum
and natural gas gathering and boosting industry segment only).
    (xvi) If a flash tank separator is used in the dehydrator, then you
must report the information specified in paragraphs (e)(1)(xvi)(A)
through (I) of this section for the emissions from the flash tank vent.
    (A) Flash tank vent gas flow rate in standard cubic feet per hour.
    (B) Flow-weighted average mole fraction of CO2 in flash
tank vent gas (``XCO2'' in Equation W-20 of this subpart if
the flash tank vent gas is routed to a flare).
    (C) Flow-weighted average mole fraction of CH4 in flash
tank vent gas (``XCH4'' in Equation W-19 of this subpart if
the flash tank vent gas is routed to a flare).
    (D) Whether any flash gas emissions are vented directly to the
atmosphere, routed to a flare, routed to the regenerator firebox/fire
tubes, routed to a vapor recovery system, used as stripping gas, or any
combination.
    (E) Annual CO2 emissions, in metric tons CO2,
from the flash tank when not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1)(iv), and, if
applicable, (e)(1)(vi)(A).
    (F) Annual CH4 emissions, in metric tons CH4,
from the flash tank when not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1)(iv) and, if
applicable, (e)(1)(vi)(A).
    (G) Annual CO2 emissions, in metric tons CO2,
that resulted from routing flash gas to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1)(v) and, if
applicable, (e)(1)(vi)(B).
    (H) Annual CH4 emissions, in metric tons CH4,
that resulted from routing flash gas to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1)(v) and, if
applicable, (e)(1)(vi)(B).
    (I) Annual N2O emissions, in metric tons N2O,
that resulted from routing flash gas to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1)(v) and, if
applicable, (e)(1)(vi)(B).
    (xvii) If flash tank emissions were routed to a flare, then you
must report the information specified in paragraphs (e)(1)(xvii)(A)
through (G) of this section for the flared emissions from the flash
tank vent.
    (A) Indicate whether the flare was monitored with a CEMS in
accordance with Sec.  98.233(n)(8). If a CEMS was used, then paragraphs
(e)(1)(xvi)(H) and (I) and (e)(1)(xvii)(B) through (G) of this section
do not apply.
    (B) Indicate whether all gas from the flash tank was measured using
a continuous flow monitor.
    (C) Indicate whether all gas from the flash tank was measured with
a continuous gas composition analyzer.
    (D) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
    (E) Total volume of gas from the flash tank to a flare, in standard
cubic feet (``Vs'' in Equations W-19 and W-20 of this
subpart).
    (F) Fraction of total flared gas from the flash tank routed to an
un-lit flare (``Zu'' in Equation W-19 of this subpart).
    (G) Average flare combustion efficiency, expressed as a fraction of
gas from the flash tank combusted by a burning flare.
    (xviii) Report the information specified in paragraphs
(e)(1)(xviii)(A) through (I) of this section for the emissions from the
dehydrator still vent.
    (A) Still vent gas flow rate in standard cubic feet per hour.
    (B) Flow-weighted average mole fraction of CO2 in still
vent gas (``XCO2'' in Equation W-20 of this subpart if the
flash tank vent gas is routed to a flare).
    (C) Flow-weighted average mole fraction of CH4 in still
vent gas (``XCH4'' in Equation W-19 of this subpart if the
flash tank vent gas is routed to a flare).
    (D) Whether any still vent emissions are vented directly to the
atmosphere, routed to a flare, routed to the regenerator firebox/fire
tubes, or routed to a vapor recovery system.
    (E) Annual CO2 emissions, in metric tons CO2,
from the still vent when not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1)(iv), and, if
applicable, (e)(1)(vi)(A).
    (F) Annual CH4 emissions, in metric tons CH4,
from the still vent when not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1)(iv) and, if
applicable, (e)(1)(vi)(A).
    (G) Annual CO2 emissions, in metric tons CO2,
that resulted from routing still vent gas to a flare or regenerator
firebox/fire tubes, calculated according to Sec.  98.233(e)(1)(v) and,
if applicable, (e)(1)(vi)(B).
    (H) Annual CH4 emissions, in metric tons CH4,
that resulted from routing still vent gas to a flare or regenerator
firebox/fire tubes, calculated according to Sec.  98.233(e)(1)(v) and,
if applicable, (e)(1)(vi)(B).
    (I) Annual N2O emissions, in metric tons N2O,
that resulted from routing still vent gas to a flare or regenerator
firebox/fire tubes, calculated according to Sec.  98.233(e)(1)(v) and,
if applicable, (e)(1)(vi)(B).
    (xix) If emissions from the still vent were routed to a flare, then
you must report the information specified in paragraphs (e)(1)(xix)(A)
through (G) of this section for the flared emissions from the still
vent.
    (A) Indicate whether the flare was monitored with a CEMS in
accordance with Sec.  98.233(n)(8). If a CEMS was used, then paragraphs
(e)(1)(xviii)(H) and (I) and (e)(1)(xix)(B) through (G) of this section
do not apply.
    (B) Indicate whether all gas from the still vent was measured using
a continuous flow monitor.
    (C) Indicate whether all gas from the still vent was measured with
a continuous gas composition analyzer.
    (D) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
    (E) Total volume of gas from the still vent to a flare, in standard
cubic feet (``Vs'' in Equations W-19 and W-20 of this
subpart).
    (F) Fraction of total flared gas from the still vent routed to an
un-lit flare (``Zu'' in Equation W-19 of this subpart).
    (G) Average flare combustion efficiency, expressed as a fraction of
gas from the still vent combusted by a burning flare.
    (2) You must report the information specified in paragraphs
(e)(2)(i) through (v) of this section for all glycol dehydrators with
an annual average daily natural gas throughput greater than 0 million
standard cubic feet per day and less than 0.4 million standard cubic
feet per day (as specified in Sec.  98.233(e)(2)) at the facility.
    (i) The total number of dehydrators at the facility.
    (ii) Whether any dehydrator emissions were routed to a vapor
recovery system. If any dehydrator emissions were routed to a vapor
recovery system, then you must report the total number of dehydrators
at the facility that routed to a vapor recovery system.

    (iii) Whether any dehydrator emissions were routed to a control
device other than a vapor recovery system or a flare or regenerator
firebox/fire tubes. If any dehydrator emissions were routed to a
control device(s) other than a vapor recovery system 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 routed to each type of control device.
    (iv) Whether any dehydrator emissions were routed to a flare or
regenerator firebox/fire tubes. If any dehydrator emissions were routed
to a flare or regenerator firebox/fire tubes, then you must report the
information specified in paragraphs (e)(2)(iv)(A) through (L) of this
section.
    (A) The total number of dehydrators routed to a flare or
regenerator firebox/fire tubes.
    (B) Indicate whether all gas from the dehydrators routed to flares
was measured using a continuous flow monitor.
    (C) Indicate whether all gas from the dehydrators routed to flares
was measured with a continuous gas composition analyzer.
    (D) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
    (E) Total volume of gas from dehydrators to a flare, in standard
cubic feet (``Vs'' in Equations W-19 and W-20 of this
subpart).
    (F) Fraction of total flared gas from the dehydrators routed to un-
lit flares (``Zu'' in Equation W-19 of this subpart).
    (G) Average flare combustion efficiency, expressed as a fraction of
gas from the dehydrators combusted by a burning flare.
    (H) Flow-weighted average mole fraction of CH4 in gas
from the dehydrators routed to a flare (``XCH4'' in Equation
W-19 of this subpart).
    (I) Flow-weighted average mole fraction of CO2 in gas
from the dehydrators routed to a flare (``XCO2'' in Equation
W-20 of this subpart).
    (J) 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)(5) and, if applicable,
(e)(4)(ii).
    (K) 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)(5) and, if applicable,
(e)(4)(ii).
    (L) 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)(5) and, if applicable,
(e)(4)(ii).
    (v) For dehydrator emissions that were not routed 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 routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(2) and, if
applicable, (e)(4)(i), 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 routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(2) and, if
applicable, (e)(4)(i), where emissions are added together for all such
dehydrators.
* * * * *
    (f) * * *
    (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 by unloading type
combination.
* * * * *
    (iii) Unloading type combination (with or without plunger lifts,
automated or manual unloading).
* * * * *
    (xi) * * *
    (F) Unloading type (automated or manual).
    (xii) * * *
    (F) Unloading type (automated or manual).
    (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 paragraphs (f)(2)(i) through (xii) of this section.
Report information separately for each calculation method and unloading
type combination.
* * * * *
    (iii) Unloading type combination (with or without plunger lifts,
automated or manual unloadings).
* * * * *
    (ix) Average flow-line rate of gas (average of ``SFRp''
from Equation W-8 or W-9 of this subpart, as applicable), at standard
conditions in cubic feet per hour.
    (x) Cumulative amount of time that wells were left open to the
atmosphere during unloading events (sum of ``HRp,q'' from
Equation W-8 or W-9 of this subpart, as applicable), in hours.
    (xi) For wells without plunger lifts, the information in paragraphs
(f)(2)(xi)(A) through (C) of this section.
    (A) Average internal casing diameter (average of ``CDp''
from Equation W-8 of this subpart), in inches.
    (B) Average well depth (average of ``WDp'' from Equation
W-8 of this subpart), in feet.
    (C) Average shut-in pressure, surface pressure, or casing pressure
(average of ``SPp'' from Equation W-8 of this subpart), in
pounds per square inch absolute.
    (xii) For wells with plunger lifts, the information in paragraphs
(f)(2)(xii)(A) through (C) of this section.
    (A) Average internal tubing diameter (average of ``TDp''
from Equation W-9 of this subpart), in inches.
    (B) Average tubing depth (average of ``WDp'' from
Equation W-9 of this subpart), in feet.
    (C) Average flow line pressure (average of ``SPp'' from
Equation W-9 of this subpart), in pounds per square inch absolute.
    (g) * * *
    (10) If the well emissions were routed to a flare, then you must
report the information specified in paragraphs (g)(10)(i) through (xi)
of this section.
    (i) Indicate whether the total emissions reported under paragraphs
(g)(8) and (9) of this section include vented emissions during the
initial flowback period.
    (ii) Indicate whether the flare was monitored with a CEMS in
accordance with Sec.  98.233(n)(8). If a CEMS was used, then paragraph
(g)(9) and paragraphs (g)(10)(iii) through (xi) of this section do not
apply.
    (iii) Indicate whether all of the gas from completions and
workovers was measured using continuous flow monitors.
    (iv) Indicate whether all of the gas streams from completions and
workovers were measured with continuous gas composition analyzers.
    (v) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
    (vi) Total volume of gas from completions and workovers to all
flares, in standard cubic feet (``Vs'' in Equations W-19 and
W-20 of this subpart).
    (vii) Fraction of total flared gas from completions and workovers
routed to

un-lit flares (``Zu'' in Equation W-19 of this subpart).
    (viii) Average flare combustion efficiency, expressed as a fraction
of gas from completions and workovers combusted by a burning flare.
    (ix) Flow-weighted average mole fraction of CH4 in gas
from completions and workovers routed to flares (``XCH4'' in
Equation W-19 of this subpart).
    (x) Flow-weighted average mole fraction of CO2 in gas
from completions and workovers routed to flares (``XCO2'' in
Equation W-20 of this subpart).
    (xi) Total N2O emissions, in metric tons N2O.
    (h) * * *
    (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 (xvi) of this section.
* * * * *
    (v) Indicate whether the flare was monitored with a CEMS in
accordance with Sec.  98.233(n)(8). If a CEMS was used, then paragraphs
(h)(2)(vi) through (xii), (xiv), and (xv) of this section do not apply.
    (vi) Indicate whether all of the gas from completions was measured
using continuous flow monitors.
    (vii) Indicate whether all of the gas streams from completions were
measured with continuous gas composition analyzers.
    (viii) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
    (ix) Total volume of gas from completions to all flares, in
standard cubic feet (``Vs'' in Equations W-19 and W-20 of
this subpart).
    (x) Fraction of total flared gas from completions routed to un-lit
flares (``Zu'' in Equation W-19 of this subpart).
    (xi) Average flare combustion efficiency, expressed as a fraction
of gas from completions combusted by a burning flare.
    (xii) Flow-weighted average mole fraction of CH4 in gas
from completions routed to flares (``XCH4'' in Equation W-19
of this subpart).
    (xiii) Flow-weighted average mole fraction of CO2 in gas
from completions routed to flares (``XCO2'' in Equation W-20
of this subpart).
    (xiv) Annual CO2 emissions, in metric tons
CO2, that resulted from completions that flared gas
calculated according to Sec.  98.233(h)(2).
    (xv) Annual CH4 emissions, in metric tons
CH4, that resulted from completions that flared gas
calculated according to Sec.  98.233(h)(2).
    (xvi) Annual N2O emissions, in metric tons
N2O, that resulted from completions that flared gas
calculated according to Sec.  98.233(h)(2).
* * * * *
    (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 (xiv) of this section.
* * * * *
    (iii) Indicate whether the flare was monitored with a CEMS in
accordance with Sec.  98.233(n)(8). If a CEMS was used, then paragraphs
(h)(4)(iv) through (x), (xii), and (xiii) of this section do not apply.
    (iv) Indicate whether all of the gas from workovers was measured
using continuous flow monitors.
    (v) Indicate whether all of the gas streams from workovers were
measured with continuous gas composition analyzers.
    (vi) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
    (vii) Total volume of gas from workovers to all flares, in standard
cubic feet (``Vs'' in Equations W-19 and W-20 of this
subpart).
    (viii) Fraction of total flared gas from workovers routed to un-lit
flares (``Zu'' in Equation W-19 of this subpart).
    (ix) Average flare combustion efficiency, expressed as a fraction
of gas from workovers combusted by a burning flare.
    (x) Flow-weighted average mole fraction of CH4 in gas
from workovers routed to flares (``XCH4'' in Equation W-19
of this subpart).
    (xi) Flow-weighted average mole fraction of CO2 in gas
from workovers routed to flares (``XCO2'' in Equation W-20
of this subpart).
    (xii) 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).
    (xiii) 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).
    (xiv) 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) * * *
    (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)(iv) for onshore natural gas processing, onshore natural
gas transmission compression, LNG import and export equipment, or
onshore petroleum and natural gas gathering and boosting industry
segments, 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. If you calculated emissions from
blowdown vent stacks by the eight categories listed in Sec.
98.233(i)(2)(iv) for the onshore natural gas transmission pipeline
segment, then you must report the pipeline segments or event types and
the information specified in paragraphs (i)(1)(i) through (iii) of this
section for each ``equipment or event type'' (i.e., category). If a
blowdown event resulted in emissions from multiple categories, and the
emissions cannot be apportioned to the different categories, then you
may report the information in paragraphs (i)(1)(i) through (iii) of
this section for the ``equipment or event type'' (i.e., category) that
represented the largest portion of the emissions for the blowdown
event.
* * * * *
    (j) Onshore production and onshore petroleum and natural gas
gathering and boosting storage tanks. You must indicate whether your
facility sends hydrocarbon produced liquids to atmospheric tanks. If
your facility sends hydrocarbon produced liquids 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 of Sec.  98.233(j), 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 must report the information specified in paragraph
(j)(3) of this section.
    (1) If you used Calculation Method 1 or Calculation Method 2 of
Sec.  98.233(j) to calculate GHG emissions, then you must report the
information specified in paragraphs (j)(1)(i) through (xvi) of this
section for each sub-basin (for onshore production) or county (for
onshore petroleum and natural gas gathering and

boosting) and by calculation method. Onshore petroleum and natural gas
gathering and boosting facilities do not report the information
specified in paragraph (j)(1)(ix) of this section.
    (i) Sub-basin ID (for onshore production) or county name (for
onshore petroleum and natural gas gathering and boosting).
    (ii) Calculation method used, and name of the software package used
if using Calculation Method 1.
    (iii) The total annual hydrocarbon liquids volume from gas-liquid
separators and direct from wells or non-separator equipment that is
sent to applicable onshore production and onshore petroleum and natural
gas gathering and boosting storage tanks, in barrels. You may delay
reporting of this data element for onshore production if you indicate
in the annual report that wildcat wells and delineation wells are the
only wells in the sub-basin with hydrocarbon liquids 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
paragraph (cc) of this section the total volume of hydrocarbon liquids
from all wells and the well ID number(s) for the well(s) included in
this volume.
    (iv) The average gas-liquid separator or non-separator equipment
temperature, in degrees Fahrenheit.
    (v) The average gas-liquid separator or non-separator equipment
pressure, in pounds per square inch gauge.
    (vi) The average sales oil or stabilized hydrocarbon liquids API
gravity, in degrees.
    (vii) The flow-weighted average concentration (mole fraction) of
CO2 in flash gas from onshore production and onshore natural
gas gathering and boosting storage tanks (calculated as the sum of all
products of the concentration of CO2 in the flash gas for
each storage tank times the throughput for that storage tank, divided
by the sum of all throughputs from storage tanks) (``XCO2''
in Equation W-20 of this subpart if the flash gas is routed to a
flare).
    (viii) The flow-weighted average concentration (mole fraction) of
CH4 in flash gas from onshore production and onshore natural gas
gathering and boosting storage tanks (calculated as the sum of all
products of the concentration of CH4 in the flash gas for
each storage tank times the throughput for that storage tank, divided
by the sum of all throughputs from storage tanks) (``XCH4''
in Equation W-19 of this subpart and ``Y1'' in Equation W-20
of this subpart if the flash gas is routed to a flare).
    (ix) The number of wells sending hydrocarbon liquids to gas-liquid
separators or directly to atmospheric tanks.
    (x) Count of atmospheric tanks specified in paragraphs (j)(1)(x)(A)
through (D) of this section.
    (A) The number of atmospheric tanks.
    (B) The number of atmospheric tanks that vented gas directly to the
atmosphere and did not control emissions using a vapor recovery system
or one or more flares at any point during the reporting year.
    (C) The number of atmospheric tanks that routed emissions to vapor
recovery and/or one or more flares at any point during the reporting
year.
    (D) The number of atmospheric tanks in paragraph (j)(1)(x)(C) of
this section that had an open or unseated thief hatch at some point
during the year while the tank was also routing emissions to a vapor
recovery system and/or a flare.
    (xi) For the atmospheric tanks at your facility identified in
paragraph (j)(1)(x)(B) of this section, you must report the information
specified in paragraphs (j)(1)(xi)(A) and (B) of this section.
    (A) Annual CO2 emissions, in metric tons CO2,
that resulted from venting gas directly to the atmosphere, calculated
according to Sec.  98.233(j)(1) and (2).
    (B) Annual CH4 emissions, in metric tons CH4,
that resulted from venting gas directly to the atmosphere, calculated
according to Sec.  98.233(j)(1) and (2).
    (xii) For the atmospheric tanks at your facility identified in
paragraph (j)(1)(x)(C) of this section, you must report the information
specified in paragraphs (j)(1)(xii)(A) through (N) of this section.
    (A) Annual CO2 emissions, in metric tons CO2,
that resulted from venting gas directly to the atmosphere, calculated
according to Sec.  98.233(j)(1), (2), and (4).
    (B) Annual CH4 emissions, in metric tons CH4,
that resulted from venting gas directly to the atmosphere, calculated
according to Sec.  98.233(j)(1), (2), and (4).
    (C) Indicate whether the flare was monitored with a CEMS in
accordance with Sec.  98.233(n)(8). If a CEMS was used, then paragraphs
(j)(1)(xii)(D) through (K), (M), and (N) of this section do not apply.
    (D) Indicate whether all of the gas from the atmospheric tanks in
the applicable sub-basin or county and subject to this paragraph
(j)(1)(xii) was measured using a continuous flow monitor.
    (E) Indicate whether all of the gas from the atmospheric tanks in
the applicable sub-basin or county and subject to this paragraph
(j)(1)(xii) was measured with a continuous gas composition analyzer.
    (F) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
    (G) Total volume of gas from the atmospheric tanks in the
applicable sub-basin or county and subject to this paragraph
(j)(1)(xii) that was routed to a flare, in standard cubic feet
(``Vs'' in Equations W-19 and W-20 of this subpart).
    (H) Fraction of total flared gas from the atmospheric tanks in the
applicable sub-basin or county and subject to this paragraph
(j)(1)(xii) that was routed to un-lit flares (``Zu'' in
Equation W-19 of this subpart).
    (I) Average flare combustion efficiency, expressed as a fraction of
gas from the atmospheric tanks in the applicable sub-basin or county
and subject to this paragraph (j)(1)(xii) combusted by a burning flare.
    (J) Annual CO2 emissions, in metric tons CO2,
from flares used to control emissions, calculated according to Sec.
98.233(j)(5).
    (K) Annual CH4 emissions, in metric tons CH4,
from flares used to control emissions, calculated according to Sec.
98.233(j)(5).
    (L) Annual N2O emissions, in metric tons N2O,
from flares used to control emissions, calculated according to Sec.
98.233(j)(5).
    (M) Total CO2 mass, in metric tons CO2, that
was recovered during the calendar year using a vapor recovery system.
    (N) Total CH4 mass, in metric tons CH4, that
was recovered during the calendar year using a vapor recovery system.
    (xiii) For the atmospheric tanks at your facility identified in
paragraph (j)(1)(x)(D) of this section, the total volume of gas vented
through open or unseated thief hatches, in scf, during periods while
the tanks were also routing emissions to vapor recovery systems and/or
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 (E) of this section, at the basin level, for atmospheric tanks
where emissions were calculated using Calculation Method 3 of Sec.
98.233(j).
    (A) The total annual hydrocarbon liquids throughput that is sent to
all atmospheric tanks in the basin, in

barrels. You may delay reporting of this data element for onshore
production if you indicate in the annual report that wildcat wells and
delineation wells are the only wells in the sub-basin with hydrocarbon
liquids production less than 10 barrels per day and that send
hydrocarbon liquids 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 hydrocarbon liquids throughput
from all wells and the well ID number(s) for the well(s) included in
this volume.
    (B) An estimate of the fraction of hydrocarbon liquids 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 hydrocarbon liquids 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 total number of separators, wells, or non-separator
equipment (``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 (for onshore production)
or county (for onshore petroleum and natural gas gathering and
boosting) with atmospheric tanks whose emissions were calculated using
Calculation Method 3 of Sec.  98.233(j) and that either did not control
emissions with flares or that used flares to control emissions from
less than half the annual hydrocarbon liquids received.
    (A) Sub-basin ID (for onshore production) or county name (for
onshore petroleum and natural gas gathering and boosting).
    (B) The number of atmospheric tanks in the sub-basin (for onshore
production) or county (for onshore petroleum and natural gas gathering
and boosting) that did not control emissions with flares and for which
emissions were calculated using Calculation Method 3.
    (C) Annual CO2 emissions, in metric tons CO2,
from atmospheric tanks in the sub-basin (for onshore production) or
county (for onshore petroleum and natural gas gathering and boosting)
that did not control emissions with flares, calculated using Equation
W-15 of Sec.  98.233(j) and adjusted using the requirements described
in Sec.  98.233(j)(4), if applicable.
    (D) Annual CH4 emissions, in metric tons CH4,
from atmospheric tanks in the sub-basin (for onshore production) or
county (for onshore petroleum and natural gas gathering and boosting)
that did not control emissions with flares, calculated using Equation
W-15 of Sec.  98.233(j) and adjusted using the requirements described
in Sec.  98.233(j)(4), if applicable.
    (iii) Report the information specified in paragraphs (j)(2)(iii)(A)
through (N) of this section for each sub-basin (for onshore production)
or county (for onshore petroleum and natural gas gathering and
boosting) with atmospheric tanks whose emissions were calculated using
Calculation Method 3 of Sec.  98.233(j) and that used flares to control
emissions from at least half the annual hydrocarbon liquids received.
    (A) Sub-basin ID (for onshore production) or county name (for
onshore petroleum and natural gas gathering and boosting).
    (B) The number of atmospheric tanks in the sub-basin (for onshore
production) or county (for onshore petroleum and natural gas gathering
and boosting) that controlled emissions with flares and for which
emissions were calculated using Calculation Method 3.
    (C) Indicate whether the flare was monitored with a CEMS in
accordance with Sec.  98.233(n)(8). If a CEMS was used, then paragraphs
(j)(2)(iii)(D) through (K), (M), and (N) of this section do not apply.
    (D) Indicate whether all of the gas from the atmospheric tanks in
the applicable sub-basin or county and subject to this paragraph
(j)(2)(iii) was measured using a continuous flow monitor.
    (E) Indicate whether all of the gas from the atmospheric tanks in
the applicable sub-basin or county and subject to this paragraph
(j)(2)(iii) was measured with a continuous gas composition analyzer.
    (F) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
    (G) Total volume of gas from the atmospheric tanks in the
applicable sub-basin or county and subject to this paragraph
(j)(2)(iii) that was routed to a flare, in standard cubic feet
(``Vs'' in Equations W-19 and W-20 of this subpart).
    (H) Fraction of total flared gas from the atmospheric tanks in the
applicable sub-basin or county and subject to this paragraph
(j)(2)(iii) that was routed to un-lit flares (``Zu'' in
Equation W-19 of this subpart).
    (I) Average flare combustion efficiency, expressed as a fraction of
gas from the atmospheric tanks in the applicable sub-basin or county
and subject to this paragraph (j)(2)(iii) combusted by a burning flare.
    (J) Flow-weighted average mole fraction of CH4 in gas
from the atmospheric tanks in the applicable sub-basin or county and
subject to this paragraph (j)(2)(iii) and routed to a flare
(``XCH4'' in Equation W-19 of this subpart).
    (K) Flow-weighted average mole fraction of CO2 in gas
from the atmospheric tanks in the applicable sub-basin or county and
subject to this paragraph (j)(2)(iii) and routed to a flare
(``XCO2'' in Equation W-20 of this subpart).
    (L) Annual CO2 emissions, in metric tons CO2,
from atmospheric tanks that controlled emissions with flares,
calculated according to Sec.  98.233(j)(5) and adjusted using the
requirements described in Sec.  98.233(j)(4), if applicable.
    (M) Annual CH4 emissions, in metric tons CH4,
from atmospheric tanks that controlled emissions with flares,
calculated according to Sec.  98.233(j)(5) and adjusted using the
requirements described in Sec.  98.233(j)(4), if applicable.
    (N) Annual N2O emissions, in metric tons N2O,
from atmospheric tanks that controlled emissions with flares,
calculated according to Sec.  98.233(j)(5).
    (3) * * *
    (ii) The total time the dump valves on gas-liquid separators did
not close properly in the calendar year, in hours (sum of the
``Tdv'' values used in Equation W-16 of this subpart).
* * * * *
    (k) * * *
    (1) * * *
    (ii) Indicate if there is a flare attached to the transmission
storage tank vent stack.
    (iii) Method used to determine if dump valve leakage occurred.
    (iv) Indicate whether scrubber dump valve leakage occurred for the
transmission storage tank vent according to Sec.  98.233(k)(2) or Sec.
98.233(k)(5).
    (2) If scrubber dump valve leakage occurred for a transmission
storage tank vent stack, as reported in paragraph (k)(1)(iv) 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.
* * * * *

    (3) If scrubber dump valve leakage occurred for a transmission
storage tank vent stack, as reported in paragraph (k)(1)(iv) of this
section, and the vent stack routed to a flare during the calendar year,
then you must report the information specified in paragraphs (k)(3)(i)
through (iii) of this section.
    (i) Indicate whether leak rate was determined using a continuous
flow measurement device for the duration of the time that flaring
occurred or if an annual measurement was conducted in accordance with
paragraph (k)(1)(ii) of this section.
    (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).
    (l) * * *
    (1) If you used Equation W-17A of Sec.  98.233 to calculate annual
volumetric natural gas emissions at actual conditions from oil wells
and the emissions are not routed to a flare, then you must report the
information specified in paragraphs (l)(1)(i) through (vii) of this
section.
* * * * *
    (2) If you used Equation W-17A of Sec.  98.233 to calculate annual
volumetric natural gas emissions at actual conditions from oil wells
and the emissions are routed to a flare, then you must report the
information specified in paragraphs (l)(2)(i) through (xvii) of this
section. All reported data elements should be specific to the wells for
which Equation W-17A of Sec.  98.233 was used and for which well
testing emissions were routed to flares.
* * * * *
    (vi) Indicate whether the flare was monitored with a CEMS in
accordance with Sec.  98.233(n)(8). If a CEMS was used, then paragraphs
(l)(2)(vii) through (xiv), (xvi), and (xvii) of this section do not
apply.
    (vii) Indicate whether all of the gas from well testing routed to
flares was measured using continuous flow monitors.
    (viii) Indicate whether all of the gas streams from well testing
routed to flares were measured with continuous gas composition
analyzers.
    (ix) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
    (x) Total volume of gas from well testing routed to all flares, in
standard cubic feet (``Vs'' in Equations W-19 and W-20 of
this subpart).
    (xi) Fraction of total flared gas from well testing routed to un-
lit flares (``Zu'' in Equation W-19 of this subpart).
    (xii) Average flare combustion efficiency, expressed as a fraction
of gas from well testing combusted by a burning flare.
    (xiii) Flow-weighted average mole fraction of CH4 in gas
from well testing routed to flares (``XCH4'' in Equation W-
19 of this subpart).
    (xiv) Flow-weighted average mole fraction of CO2 in gas
from well testing routed to flares (``XCO2'' in Equation W-
20 of this subpart).
    (xv) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec.  98.233(l).
    (xvi) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec.  98.233(l).
    (xvii) Annual N2O emissions, in metric tons N2O,
calculated according to Sec.  98.233(l).
    (3) If you used Equation W-17B of Sec.  98.233 to calculate annual
volumetric natural gas emissions at actual conditions from gas wells
and the emissions were not routed to a flare, then you must report the
information specified in paragraphs (l)(3)(i) through (vi) of this
section.
* * * * *
    (4) If you used Equation W-17B of Sec.  98.233 to calculate annual
volumetric natural gas emissions at actual conditions from gas wells
and the emissions were routed to a flare, then you must report the
information specified in paragraphs (l)(4)(i) through (xvi) of this
section. All reported data elements should be specific to the wells for
which Equation W-17B of Sec.  98.233 was used and for which well
testing emissions were routed to flares.
* * * * *
    (v) Indicate whether the flare was monitored with a CEMS in
accordance with Sec.  98.233(n)(8). If a CEMS was used, then paragraphs
(l)(4)(vi) through (xiii), (xv), and (xvi) of this section do not
apply.
    (vi) Indicate whether all of the gas from well testing routed to
flares was measured using continuous flow monitors.
    (vii) Indicate whether all of the gas streams from well testing
routed to flares were measured with continuous gas composition
analyzers.
    (viii) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
    (ix) Total volume of gas from well testing routed to all flares, in
standard cubic feet (``Vs'' in Equations W-19 and W-20 of
this subpart).
    (x) Fraction of total flared gas from well testing routed to un-lit
flares (``Zu'' in Equation W-19 of this subpart).
    (xi) Average flare combustion efficiency, expressed as a fraction
of gas from well testing combusted by a burning flare.
    (xii) Flow-weighted average mole fraction of CH4 in gas
from well testing routed to flares (``XCH4'' in Equation W-
19 of this subpart).
    (xiii) Flow-weighted average mole fraction of CO2 in gas
from well testing routed to flares (``XCO2'' in Equation W-
20 of this subpart).
    (xiv) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec.  98.233(l).
    (xv) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec.  98.233(l).
    (xvi) Annual N2O emissions, in metric tons
N2O, calculated according to Sec.  98.233(l).
    (m) * * *
    (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). Do not report the GOR if you vented or flared associated
gas and used a continuous flow monitor to determine the total volume of
associated gas vented or routed to the flare in the sub-basin (i.e., if
you did not use Equation W-18 for any wells with associated gas venting
or flaring emissions in the sub-basin).
    (5) Volume of oil produced, in barrels, in the calendar year only
during the time periods in which associated gas was vented or flared
(the sum of ``Vp,q'' used in Equation W-18 of Sec.  98.233).
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 well ID number(s) for
the well(s) included in the measurement. Do not report the volume of
oil produced if you vented or flared associated gas and used a
continuous flow monitor to determine the total volume of associated gas
vented or routed to the flare in the sub-basin (i.e., if you did not
use Equation W-18 for any wells with associated gas venting or flaring
emissions in the sub-basin).

    (6) Total volume of associated gas sent to sales, in standard cubic
feet, in the calendar year only 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 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 paragraph (cc) of this section the
measured total volume of associated gas sent to sales for well(s) with
associated gas venting and flaring and the well ID number(s) for the
well(s) included in the measurement. Do not report the volume of gas
sent to sales if you vented or flared associated gas and used a
continuous flow monitor to determine the total volume of associated gas
vented or routed to the flare in the sub-basin (i.e., if you did not
use Equation W-18 for any wells with associated gas venting or flaring
emissions in the sub-basin).
    (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 (viii) of this section for
each sub-basin.
    (i) Total number of wells for which associated gas was vented
directly to the atmosphere without flaring and a list of their well ID
numbers.
    (ii) Indicate whether all of the associated gas volume vented in
the sub-basin was measured using continuous flow monitors.
    (iii) Indicate whether all associated gas streams vented in the
sub-basin were measured with continuous gas composition analyzers.
    (iv) Total volume of associated gas vented in the sub-basin, in
standard cubic feet.
    (v) Flow-weighted average mole fraction of CH4 in
associated gas vented in the sub-basin.
    (vi) Flow-weighted average mole fraction of CO2 in
associated gas vented in the sub-basin.
    (vii) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec.  98.233(m)(3) and (4).
    (viii) 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
(xiii) of this section for each sub-basin.
    (i) Total number of wells for which associated gas was flared and a
list of their well ID numbers.
    (ii) Indicate whether the flare was monitored with a CEMS in
accordance with Sec.  98.233(n)(8). If a CEMS was used, then paragraphs
(m)(8)(iii) through (x), (xii), and (xiii) of this section do not
apply.
    (iii) Indicate whether all of the associated gas volume routed to
flares in the sub-basin was measured using continuous flow monitors.
    (iv) Indicate whether all associated gas streams routed to flares
in the sub-basin were measured with continuous gas composition
analyzers.
    (v) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
    (vi) Total volume of associated gas routed to all flares in the
sub-basin, in standard cubic feet (``Vs'' in Equations W-19
and W-20 of this subpart).
    (vii) Fraction of total flared associated gas in the sub-basin
routed to un-lit flares (``Zu'' in Equation W-19 of this
subpart).
    (viii) Average flare combustion efficiency, expressed as a fraction
of associated gas combusted by a burning flare.
    (ix) Flow-weighted average mole fraction of CH4 in
associated gas routed to flares in the sub-basin (``XCH4''
in Equation W-19 of this subpart).
    (x) Flow-weighted average mole fraction of CO2 in
associated gas routed to flares in the sub-basin (``XCO2''
in Equation W-20 of this subpart).
    (xi) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec.  98.233(m)(5).
    (xii) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec.  98.233(m)(5).
    (xiii) Annual N2O emissions, in metric tons
N2O, calculated according to Sec.  98.233(m)(5).
    (n) Flare stacks. You must indicate if your facility has any flare
stacks to which emissions are routed from miscellaneous flared sources
(i.e., sources other than those subject to Sec.  98.233(e), (g), (h),
(j), (l), or (m), as applicable for the industry segment). If you have
any miscellaneous flared sources, you must report the information
specified in paragraph (n)(1) of this section for each flare used to
control emissions from such sources. Additionally, for each flare at
your facility, regardless of the source(s) controlled, you must report
the information specified in paragraph (n)(2) of this section.
    (1) For each flare stack used to control miscellaneous flared
sources, you must report the information specified in paragraph
(n)(1)(i) through (xiv) of this section.
    (i) Unique name or ID for the flare stack. For the onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting industry segments, 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.
    (ii) Indicate whether the flare stack has a continuous flow
measurement device.
    (iii) Indicate whether the flare stack has a continuous gas
composition analyzer on feed gas to the flare.
    (iv) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
    (v) Estimated fraction of total volume flared that was received
from another facility solely for flaring (e.g., gas separated from
liquid at a production facility that is routed to a flare that is
assigned to an onshore petroleum and natural gas gathering and boosting
facility).
    (vi) Volume of gas from miscellaneous flared sources sent to the
flare, in standard cubic feet (``Vs'' in Equations W-19 and
W-20 of this subpart).
    (vii) Fraction of the feed gas sent to an un-lit flare
(``Zu'' in Equation W-19 of this subpart).
    (viii) Flare combustion efficiency, expressed as the fraction of
gas combusted by a burning flare.
    (ix) Flow-weighted average mole fraction of CH4 in the
feed gas from miscellaneous flared sources to the flare
(``XCH4'' in Equation W-19 of this subpart).
    (x) Flow-weighted average mole fraction of CO2 in the
feed gas from miscellaneous flared sources to the flare
(``XCO2'' in Equation W-20 of this subpart).
    (xi) Annual CO2 emissions, in metric tons CO2
(refer to Equation W-20 of this subpart). If gas from an acid gas
removal unit is routed to the flare, then the CO2 emissions
to report should exclude the CO2 emissions reported under
paragraph (d)(1)(v) of this section to prevent double counting of
emissions.
    (xii) Annual CH4 emissions, in metric tons
CH4 (refer to Equation W-19 of this subpart).
    (xiii) Annual N2O emissions, in metric tons
N2O (refer to Equation W-40 of this subpart).
    (xiv) Indicate whether a CEMS was used to measure emissions from
the flare. If a CEMS was used to measure emissions from the flare, then
the information specified in paragraphs

(n)(1)(ii) through (x), (xii), and (xiii) of this section do not apply
for that flare; report only the CO2 emissions as specified
in paragraph (n)(1)(xi) of this section.
    (2) For each flare stack at your facility, you must report the
information specified in paragraphs (n)(2)(i) through (ix) of this
section.
    (i) Unique name or ID for the flare stack.
    (ii) Indicate each emission source type that routed emissions to
the flare stack during the reporting year (i.e., dehydrator vents, well
venting during completions and workovers with hydraulic fracturing, gas
well venting during completions and workovers without hydraulic
fracturing, onshore production and onshore petroleum and natural gas
gathering and boosting storage tanks, well testing venting and flaring,
associated gas venting and flaring, miscellaneous flared sources).
    (iii) Total volume of gas routed to the flare.
    (iv) Indicate the type of flare (i.e., open ground-level flare,
enclosed ground-level flare, open elevated flare, or enclosed elevated
flare).
    (v) Indicate the type of flare assist (i.e., unassisted, air-
assisted with single speed fan/blower, air-assisted with dual speed
fan/blower, air-assisted with variable speed fan/blower, steam-
assisted, or pressure-assisted).
    (vi) Indicate whether the flare has a continuous pilot or
autoigniter.
    (vii) If the flare has a continuous pilot, indicate whether the
presence of flame is continuously monitored.
    (viii) If the flare has a continuous pilot and the presence of a
flame is not continuously monitored, indicate how periods when the
pilot is not lit are identified (i.e., assumed pilot is always lit,
assumed pilot was unlit for a fixed number of hours or fraction of
operating hours, visual observations of flare flame, other (specify)).
    (ix) Estimated fraction of the total volume routed to the flare
when it was not lit.
    (o) * * *
    (1) Compressor activity data. Report the information specified in
paragraphs (o)(1)(i) through (x) of this section, as applicable, 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 standby-pressurized-mode.
    (iv) Hours in not-operating-depressurized-mode.
    (v) If you conducted volumetric emission measurements as specified
in Sec.  98.233(o)(1):
    (A) Indicate whether the compressor was measured in operating-mode.
    (B) Indicate whether the compressor was measured in standby-
pressurized-mode.
    (C) Indicate whether the compressor was measured in not-operating-
depressurized-mode.
    (vi) Indicate whether the compressor has blind flanges installed
and associated dates.
    (vii) Indicate whether the compressor has wet or dry seals.
    (viii) If the compressor has wet seals, the number of wet seals.
    (ix) If the compressor has dry seals, the number of dry seals.
    (x) Power output of the compressor driver (hp).
    (2) * * *
    (i) * * *
    (B) Centrifugal compressor source (wet seal, dry seal, isolation
valve, or blowdown valve).
* * * * *
    (ii) * * *
    (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, or vapor recovery.
* * * * *
    (5) * * *
    (i) Report the following activity data.
    (A) Total number of centrifugal compressors at the facility.
    (B) Number of centrifugal compressors that have wet seals.
    (C) Number of centrifugal compressors that have atmospheric wet
seal oil degassing vents (i.e., wet seal oil degassing vents where the
emissions are released to the atmosphere rather than being routed to
flares, combustion, or vapor recovery).
    (ii) Annual CO2 emissions, in metric tons
CO2, from centrifugal compressors with atmospheric wet seal
oil degassing vents.
    (iii) Annual CH4 emissions, in metric tons
CH4, from centrifugal compressors with atmospheric wet seal
oil degassing vents.
    (p) * * *
    (1) Compressor activity data. Report the information specified in
paragraphs (p)(1)(i) through (vii) of this section, as applicable, 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) If you conducted volumetric emission measurements as specified
in Sec.  98.233(p)(1):
    (A) Indicate whether the compressor was measured in operating-mode.
    (B) Indicate whether the compressor was measured in standby-
pressurized-mode.
    (C) Indicate whether the compressor was measured in not-operating-
depressurized-mode.
    (vi) Indicate whether the compressor has blind flanges installed
and associated dates.
    (vii) Power output of the compressor driver (hp).
    (2) * * *
    (ii) * * *
    (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, or vapor recovery.
* * * * *
    (3) * * *
    (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.
* * * * *
    (5) * * *
    (i) Report the following activity data.
    (A) Total number of reciprocating compressors at the facility.
    (B) Number of reciprocating compressors that have rod packing
emissions vented to the atmosphere (i.e., rod packing vents where the
emissions are released to the atmosphere rather than being routed to
flares, combustion, or vapor recovery).
    (ii) Annual CO2 emissions, in metric tons
CO2, from reciprocating compressors with rod packing
emissions vented to the atmosphere.
    (iii) Annual CH4 emissions, in metric tons
CH4, from reciprocating compressors with rod packing
emissions vented to the atmosphere.
    (q) * * *
    (1) You must report the information specified in paragraphs
(q)(1)(i) through (vii) of this section.
* * * * *
    (iii) Except for natural gas distribution facilities, indicate
whether any of the leak detection surveys used in calculating emissions
per Sec.  98.233(q)(2) were conducted for compliance with any of the
standards in paragraphs (q)(1)(iii)(A) through (E) of this section.
Report the indication per facility, not per component type, and
indicate all that apply for the facility.

    (A) The well site or compressor station fugitive emissions
standards in Sec.  60.5397a of this chapter.
    (B) The well site or compressor station fugitive emissions
standards in part 60, subpart OOOOb of this chapter.
    (C) The well site or compressor station fugitive emissions
standards in an applicable approved state plan or applicable Federal
plan in part 62 of this chapter.
    (D) The standards for equipment leaks at onshore natural gas plants
in part 60, subpart OOOOb of this chapter.
    (E) The standards for equipment leaks at onshore natural gas plants
in an applicable approved state plan or applicable Federal plan in part
62 of this chapter.
* * * * *
    (vi) Report whether emissions were calculated using Calculation
Method 1 (leaker factor emission calculation methodology) and/or using
Calculation Method 2 (leaker measurement methodology).
    (vii) For facilities in onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and
boosting, report the number of major equipment (as listed in Table W-
1A) by service type for which leak detection surveys were conducted and
emissions calculated according to Sec.  98.233(q).
    (2) You must indicate whether your facility contains any of the
component types subject to or complying with Sec.  98.233(q) that are
listed in Sec.  98.232(c)(21), (d)(7), (e)(7) or (8), (f)(5), through
(8), (g)(4), (g)(6) or (7), (h)(5), (h)(7) or (8), (i)(1), or (j)(10)
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)(ii) through (v) of
this section. If you used Calculation Method 1 (leaker factor emission
calculation methodology) for some complete leak surveys and used
Calculation Method 2 (leaker measurement methodology) for some complete
leak surveys, you must report the information specified in paragraphs
(q)(2)(i) through (v) of this section separately for component surveys
using Calculation Method 1 and Calculation Method 2.
    (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 or the number of
leaks measured for the specified component type according to the
provisions in Sec.  98.233(q)(3)(i)).
    (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 or average
duration of leaks for the specified component type determined according
to the provisions in Sec.  98.233(q)(3)(ii)).
    (iv) Annual CO2 emissions, in metric tons
CO2, for the component type as calculated using Equation W-
30 or Sec.  98.233(q)(3)(vi) (for surveyed components only).
    (v) Annual CH4 emissions, in metric tons CH4,
for the component type as calculated using Equation W-30 or Sec.
98.233(q)(3)(vi) (for surveyed components only).
* * * * *
    (r) * * *
    (1) You must indicate whether your facility contains any of the
emission source types required to use Equation W-32A of Sec.  98.233.
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 that is located at your facility.
Onshore petroleum and natural gas production facilities and onshore
petroleum and natural gas gathering and boosting facilities must report
the information specified in paragraphs (r)(1)(i) through (v)
separately by equipment type and service type.
    (i) Emission source type. Onshore petroleum and natural gas
production facilities and onshore petroleum and natural gas gathering
and boosting facilities must report the equipment type and service
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 BOEM
study.
* * * * *
    (y) Other large release events. You must indicate whether there
were any other large release events from your facility during the
reporting year. If there were any other large release events, you must
report the total number of other large release events from your
facility that occurred during the reporting year and, for each other
large release event, report the information specified in paragraphs
(y)(1) through (8) of this section.
    (1) Unique release event identification number (e.g., Event 1,
Event 2).
    (2) The approximate start date, start time, and duration (in hours)
of the release event.
    (3) A general description of the event. Include:
    (i) Identification of the equipment involved in the release.
    (ii) A description of how the release occurred, from one of the
following categories: fire/explosion, gas well blowout, oil well
blowout, gas well release, oil well release, pressure relief, large
leak, and other (specify).
    (iii) A description of the technology or method used to identify
the release.
    (iv) An indication of whether the release was identified under the
provisions of part 60, subpart OOOOb of this chapter or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter.
    (v) An indication of whether a portion of the natural gas released
was combusted during the release, and if so, the fraction of the
natural gas released that was estimated to be combusted.
    (4) The total volume of gas released during the event in standard
cubic feet.
    (5) The volume fraction of CO2 in the gas released
during the event.
    (6) The volume fraction of CH4 in the gas released
during the event.
    (7) Annual CO2 emissions, in metric tons CO2,
from the release event.
    (8) Annual CH4 emissions, in metric tons CH4,
from the release event.
    (z) Combustion equipment at onshore petroleum and natural gas
production facilities, onshore petroleum and natural gas gathering and
boosting facilities, and natural gas distribution facilities. If your
facility is required by Sec.  98.232(c)(22), (i)(7), or (j)(12) to
report emissions from combustion equipment, then you must indicate
whether your facility has any combustion units subject to reporting
according to paragraph (a)(1)(xix), (a)(8)(i), or (a)(9)(xiii) of this
section. If your facility contains any combustion units subject to
reporting according to paragraph (a)(1)(xix), (a)(8)(i), or
(a)(9)(xiii) of this section, then you must report the information
specified in paragraphs (z)(1) and (2) of this section, as applicable.
* * * * *
    (2) * * *
    (i) The type of combustion unit. For internal fuel combustion units
of any heat capacity that are compressor-drivers, you must also specify
the design class as: 2-stroke lean-burn, 4-

stroke lean-burn, 4-stroke rich-burn, or other.
* * * * *
    (iv) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec.  98.233(z)(1) through (3).
    (v) Annual CH4 emissions, in metric tons CH4,
calculated according to Sec.  98.233(z)(1) through (3).
    (vi) Annual N2O emissions, in metric tons
N2O, calculated according to Sec.  98.233(z)(1) through (3).
    (aa) * * *
    (3) For natural gas processing, if your facility fractionates NGLs
and also reports as a supplier to subpart NN of this part, you must
report the information specified in paragraphs (aa)(3)(ii) and
(aa)(3)(v) through (viii) of this section. Otherwise, report the
information specified in paragraphs (aa)(3)(i) through (viii) of this
section.
    (i) The quantity of natural gas received at the gas processing
plant for processing in the calendar year, in thousand standard cubic
feet.
* * * * *
    (viii) Indicate whether the facility reports as a supplier to
subpart NN of this part.
* * * * *
    (10) For onshore petroleum and natural gas gathering and boosting
facilities, report the quantities specified in paragraphs (aa)(10)(i)
through (vi) of this section.
* * * * *
    (v) The number of compressor stations in the facility.
    (vi) The number of centralized oil production sites in the
facility.
    (11) * * *
    (ii) The quantity of natural gas withdrawn from underground natural
gas storage and LNG storage (regasification) facilities owned and
operated by the onshore natural gas transmission pipeline owner or
operator that are not subject to this subpart in the calendar year, in
thousand standard cubic feet.
    (iii) The quantity of natural gas added to underground natural gas
storage and LNG storage (liquefied) facilities owned and operated by
the onshore natural gas transmission pipeline owner or operator that
are not subject to this subpart 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) and the procedures used to substitute an
unavailable value of a parameter, except as provided in paragraphs
(bb)(1) and (2) of this section.
* * * * *
    (cc) If you elect to delay reporting the information in paragraph
(g)(5)(i) or (ii), (g)(5)(iii)(A) or (B), (h)(1)(iv), (h)(2)(iv),
(j)(1)(iii), (j)(2)(i)(A), (l)(1)(v), (l)(2)(v), (l)(3)(iv),
(l)(4)(iv), or (m)(5) or (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.
0
60. Amend Sec.  98.238 by:
0
a. Adding a definition for ``Centralized oil production site'' in
alphabetical order;
0
b. Revising the definitions for ``Compressor mode'' and ``Compressor
source'';
0
c. Adding a definition for ``Compressor station'' in alphabetical
order;
0
d. Removing the second definition for ``Facility with respect to
natural gas distribution for purposes of reporting under this subpart
and for the corresponding subpart A requirements'';
0
e. Revising the definitions for ``Flare stack emissions'' and ``Forced
extraction of natural gas liquids''; and
0
f. Adding definitions for ``Other large release event,'' ``Routed to
combustion'', ``Well blowout'', and ``Well release'' in alphabetical
order.
    The additions and revisions read as follows:

Sec.  98.238  Definitions.

* * * * *
    Centralized oil production site means any permanent combination of
one or more hydrocarbon liquids storage tanks located on one or more
contiguous or adjacent properties that does not also contain a
permanent combination of one or more compressors that are part of the
onshore petroleum and natural gas gathering and boosting facility that
gathers hydrocarbon liquids from multiple well-pads.
* * * * *
    Compressor mode means the operational and pressurized status of a
compressor. For both centrifugal compressors and reciprocating
compressors, ``mode'' refers to either: Operating-mode, standby-
pressurized-mode, or not-operating-depressurized-mode.
    Compressor source means the source of certain venting or leaking
emissions from a centrifugal or reciprocating compressor. For
centrifugal compressors, ``source'' refers to blowdown valve leakage
through the blowdown vent, unit isolation valve leakage through an open
blowdown vent without blind flanges, wet seal oil degassing vents, and
dry seal vents. For reciprocating compressors, ``source'' refers to
blowdown valve leakage through the blowdown vent, unit isolation valve
leakage through an open blowdown vent without blind flanges, and rod
packing emissions.
    Compressor station means any permanent combination of one or more
compressors located on one or more contiguous or adjacent properties
that are part of the onshore petroleum and natural gas gathering and
boosting facility that move natural gas at increased pressure through
gathering pipelines or into or out of storage.
* * * * *
    Flare stack emissions means CO2 in gas routed to a
flare, CO2 from partial combustion of hydrocarbons in gas
routed to a flare, CH4 emissions resulting from the
incomplete combustion of hydrocarbons in gas routed to a flare, and
N2O resulting from operation of a flare.
    Forced extraction of natural gas liquids means removal of ethane or
higher carbon number hydrocarbons existing in the vapor phase in
natural gas, by removing ethane or heavier hydrocarbons derived from
natural gas into natural gas liquids by means of a forced extraction
process. Forced extraction processes include but are not limited to
refrigeration, absorption (lean oil), cryogenic expander, and
combinations of these processes. Forced extraction does not include
natural gas dehydration, the collection or gravity separation of water
or hydrocarbon liquids from natural gas at ambient temperature or
heated above ambient temperatures, the condensation of water or
hydrocarbon liquids through passive reduction in pressure or
temperature, a Joule-Thomson valve, a dew point depression valve, or an
isolated or standalone Joule-Thomson skid.
* * * * *
    Other large release event means an unplanned, unexpected, and
uncontrolled release to the atmosphere of gas, liquids, or mixture
thereof, from wells and/or other equipment that result in emissions for
which there are no methodologies in Sec.  98.233 to appropriately
estimate these emissions. Other large release events include, but are
not limited to, well blowouts, well releases, pressure relief valve
releases from process equipment other than onshore production and
onshore petroleum and natural gas gathering and boosting storage tanks,
and releases that occur as a result of an accident, equipment rupture,
fire, or explosion. Other large release events also include failure of
equipment or equipment components such that a single equipment leak or
release has emissions that exceed the emissions calculated for

that source using applicable methods in Sec.  98.233 by the threshold
in Sec.  98.233(y).
* * * * *
    Routed to combustion means, for onshore petroleum and natural gas
production facilities, natural gas distribution facilities, and onshore
petroleum and natural gas gathering and boosting facilities, that
emissions are routed to stationary or portable fuel combustion
equipment specified in Sec.  98.232(c)(22), (i)(7), or (j)(12), as
applicable. For all other industry segments in this subpart, routed to
combustion means that emissions are routed to a stationary fuel
combustion unit subject to subpart C of this part (General Stationary
Fuel Combustion Sources).
* * * * *
    Well blowout means a complete loss of well control for a long
duration of time resulting in an emissions release.
* * * * *
    Well release means a short duration of uncontrolled emissions
release from a well followed by a period of controlled emissions
release in which control techniques were successfully implemented.
* * * * *
0
61. Revise table W-1A to subpart W of part 98 to read as follows:

 Table W-1A to Subpart W of Part 98--Default Whole Gas Emission Factors
 for Onshore Petroleum and Natural Gas Production Facilities and Onshore
       Petroleum and Natural Gas Gathering and Boosting Facilities
------------------------------------------------------------------------
  Onshore petroleum and natural gas production
and onshore petroleum and natural gas gathering   Emission factor (scf/
                  and boosting                       hour/component)
------------------------------------------------------------------------
Population Emission Factors--Pneumatic Device Vents and Pneumatic Pumps,
                             Gas Service \1\
------------------------------------------------------------------------
Continuous Low Bleed Pneumatic Device Vents \2\                      6.8
Continuous High Bleed Pneumatic Device Vents                        21.2
 \2\...........................................
Intermittent Bleed Pneumatic Device Vents \2\..                      8.8
Pneumatic Pumps \3\............................                     13.3
------------------------------------------------------------------------
        Population Emission Factors--Major Equipment, Gas Service
------------------------------------------------------------------------
Wellhead.......................................                     0.59
Separator......................................                     0.84
Meters/Piping..................................                      2.8
Compressor.....................................                       10
Acid Gas Removal Unit..........................                      2.4
Dehydrator.....................................                      3.1
Heater Treater.................................                     0.12
Storage Vessel.................................                     0.85
------------------------------------------------------------------------
       Population Emission Factors--Major Equipment, Crude Service
------------------------------------------------------------------------
Wellhead.......................................                     0.14
Separator......................................                     0.43
Meters/Piping..................................                      2.5
Compressor.....................................                       10
Acid Gas Removal Unit..........................                      2.4
Dehydrator.....................................                      3.1
Heater Treater.................................                     0.35
Storage Vessel.................................                     0.56
------------------------------------------------------------------------
  Population Emission Factors--Gathering Pipelines by Material Type \4\
------------------------------------------------------------------------
Protected Steel................................                     0.91
Unprotected Steel..............................                      8.0
Plastic/Composite..............................                     0.27
Cast Iron......................................                      8.2
------------------------------------------------------------------------
\1\ For multi-phase flow that includes gas, use the gas service emission
  factors.
\2\ Emission factor is in units of ``scf/hour/device.''
\3\ Emission factor is in units of ``scf/hour/pump.''
\4\ Emission factors are in units of ``scf/hour/mile of pipeline.''

Table W-1B to Subpart W of Part 98--Default Average Component Counts
for Major Onshore Natural Gas Production Equipment and Onshore
Petroleum and Natural Gas Gathering and Boosting Equipment for
Reporting Year 2022 and Prior Reporting Years

0
62. Revise the table heading for table W-1B to subpart W of part 98 to
read as set forth above.

Table W-1C to Subpart W of Part 98--Default Average Component Counts
for Major Crude Oil Production Equipment for Reporting Year 2022 and
Prior Reporting Years

0
63. Revise the table heading for table W-1C to subpart W of part 98 to
read as set forth above.

Table W-1D to Subpart W of Part 98--Designation of Eastern and Western
U.S. for Reporting Year 2022 and Prior Reporting Years

0
64. Revise the table heading for table W-1D to subpart W of part 98 to
read as set forth above.
0
65. Revise table W-1E to subpart W of part 98 to read as follows:

 Table W-1E to Subpart W of Part 98--Default Whole Gas Leaker Emission Factors for Onshore Petroleum and Natural
                   Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting
----------------------------------------------------------------------------------------------------------------
                                                                   Emission factor (scf/hour/component)
                                                        --------------------------------------------------------
                                                           If you survey      If you survey      If you survey
                  Equipment components                    using method 21    using method 21    using any of the
                                                          as specified in    as specified in    methods in Sec.
                                                                Sec.               Sec.          98.234(a)(1),
                                                          98.234(a)(2)(i)    98.234(a)(2)(ii)     (3), or (5)
----------------------------------------------------------------------------------------------------------------
                            Leaker Emission Factors--All Components, Gas Service \1\
----------------------------------------------------------------------------------------------------------------
Valve..................................................                4.9                3.5                 16
Flange.................................................                4.1                2.2                 11
Connector (other)......................................                1.3                0.8                7.9
Open-Ended Line \2\....................................                2.8                1.9                 10
Pressure Relief Valve..................................                4.5                2.8                 13
Pump Seal..............................................                3.7                1.4                 23
Other \3\..............................................                4.5                2.8                 15
----------------------------------------------------------------------------------------------------------------
                              Leaker Emission Factors--All Components, Oil Service
----------------------------------------------------------------------------------------------------------------
Valve..................................................                3.2                2.2                9.2
Flange.................................................                2.7                1.4                 11
Connector (other)......................................                1.0                0.6                9.1
Open-Ended Line........................................                1.6                1.1                6.6
Pump \4\...............................................                3.7                2.6                 15
Other \3\..............................................                3.1                2.0                2.9
----------------------------------------------------------------------------------------------------------------
\1\ For multi-phase flow that includes gas, use the gas service emission factors.
\2\ The open-ended lines component type includes blowdown valve and isolation valve leaks emitted through the
  blowdown vent stack for centrifugal and reciprocating compressors.
\3\ ``Others'' category includes any equipment leak emission point not specifically listed in this table, as
  specified in Sec.   98.232(c)(21) and (j)(10).
\4\ The pumps component type in oil service includes agitator seals.

0
66. Remove table W-2 to subpart W of part 98 and add table W-2A and
table W-2B to subpart W of part 98 in numerical order to read as
follows:

  Table W-2A to Subpart W of Part 98--Default Total Hydrocarbon Leaker Emission Factors for Onshore Natural Gas
                                                   Processing
----------------------------------------------------------------------------------------------------------------
                                                                   Emission factor (scf/hour/component)
                                                        --------------------------------------------------------
                                                           If you survey      If you survey      If you survey
         Onshore natural gas processing plants            using method 21    using method 21    using any of the
                                                          as specified in    as specified in    methods in Sec.
                                                                Sec.               Sec.          98.234(a)(1),
                                                          98.234(a)(2)(i)    98.234(a)(2)(ii)     (3), or (5)
----------------------------------------------------------------------------------------------------------------
                           Leaker Emission Factors--Compressor Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\..............................................              14.84               9.51                 61
Connector..............................................               5.59               3.58                 23
Open-Ended Line........................................              17.27              11.07                 71
Pressure Relief Valve..................................              39.66              25.42                163
Meter..................................................              19.33              12.39                 79
Other \2\..............................................                4.1               2.63                 17
----------------------------------------------------------------------------------------------------------------
                         Leaker Emission Factors--Non-Compressor Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\..............................................               6.42               4.12                 26
Connector..............................................               5.71               3.66                 23
Open-Ended Line........................................              11.27               7.22                 46
Pressure Relief Valve..................................               2.01               1.29                8.2
Meter..................................................               2.93               1.88                 12
Other \2\..............................................                4.1               2.63                 17
----------------------------------------------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Other includes any potential equipment leak emission point in gas service that is not specifically listed in
  this table.

    Table W-2B to Subpart W of Part 98--Default Whole Gas Population
           Emission Factors for Onshore Natural Gas Processing
------------------------------------------------------------------------
                                                        Emission factor
   Population emission factors--gas service onshore     (scf whole gas/
                natural gas processing                    hour/device)
------------------------------------------------------------------------
Continuous Low Bleed Pneumatic Device Vents..........                6.8
Continuous High Bleed Pneumatic Device Vents.........               32.4
Intermittent Bleed Pneumatic Device Vents............                2.3
------------------------------------------------------------------------

0
67. Revise table W-3A to subpart W of part 98 to read as follows:

  Table W-3A to Subpart W of Part 98--Default Total Hydrocarbon Leaker Emission Factors for Onshore Natural Gas
                                            Transmission Compression
----------------------------------------------------------------------------------------------------------------
                                                                   Emission factor (scf/hour/component)
                                                        --------------------------------------------------------
                                                           If you survey      If you survey      If you survey
      Onshore natural gas transmission compression        using method 21    using method 21    using any of the
                                                          as specified in    as specified in    methods in Sec.
                                                                Sec.               Sec.          98.234(a)(1),
                                                          98.234(a)(2)(i)    98.234(a)(2)(ii)     (3), or (5)
----------------------------------------------------------------------------------------------------------------
                           Leaker Emission Factors--Compressor Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\..............................................              14.84               9.51                 61
Connector..............................................               5.59               3.58                 23
Open-Ended Line........................................              17.27              11.07                 71
Pressure Relief Valve..................................              39.66              25.42                163
Meter or Instrument....................................              19.33              12.39                 79
Other \2\..............................................                4.1               2.63                 17
----------------------------------------------------------------------------------------------------------------
                         Leaker Emission Factors--Non-Compressor Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\..............................................               6.42               4.12                 26
Connector..............................................               5.71               3.66                 23
Open-Ended Line........................................              11.27               7.22                 46
Pressure Relief Valve..................................               2.01               1.29                8.2
Meter or Instrument....................................               2.93               1.88                 12
Other \2\..............................................                4.1               2.63                 17
----------------------------------------------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Other includes any potential equipment leak emission point in gas service that is not specifically listed in
  this table, as specified in Sec.   98.232(e)(8).

0
68. Revise the table heading and table W-3B to subpart W of part 98 to
read as follows:

    Table W-3B to Subpart W of Part 98--Default Whole Gas Population
    Emission Factors for Onshore Natural Gas Transmission Compression
------------------------------------------------------------------------
                                                        Emission factor
   Population emission factors--gas service onshore     (scf whole gas/
         natural gas transmission compression             hour/device)
------------------------------------------------------------------------
Continuous Low Bleed Pneumatic Device Vents..........                6.8
Continuous High Bleed Pneumatic Device Vents.........               32.4
Intermittent Bleed Pneumatic Device Vents............                2.3
------------------------------------------------------------------------

0
69. Revise table W-4A to subpart W of part 98 to read as follows:

  Table W-4A to Subpart W of Part 98--Default Total Hydrocarbon Leaker Emission Factors for Underground Natural
                                                   Gas Storage
----------------------------------------------------------------------------------------------------------------
                                                                   Emission factor (scf/hour/component)
                                                        --------------------------------------------------------
                                                           If you survey      If you survey      If you survey
            Underground natural gas storage               using method 21    using method 21    using any of the
                                                          as specified in    as specified in    methods in Sec.
                                                                Sec.               Sec.          98.234(a)(1),
                                                          98.234(a)(2)(i)    98.234(a)(2)(ii)     (3), or (5)
----------------------------------------------------------------------------------------------------------------
                              Leaker Emission Factors--Storage Station, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\..............................................              14.84               9.51                 61
Connector (other)......................................               5.59               3.58                 23
Open-Ended Line........................................              17.27              11.07                 71
Pressure Relief Valve..................................              39.66              25.42                163
Meter and Instrument...................................              19.33              12.39                 79
Other \2\..............................................                4.1               2.63                 17
----------------------------------------------------------------------------------------------------------------
                             Leaker Emission Factors--Storage Wellheads, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\..............................................                4.5                3.2                 18
Connector (other than flanges).........................                1.2                0.7                4.9
Flange.................................................                3.8                2.0                 16
Open-Ended Line........................................                2.5                1.7                 10
Pressure Relief Valve..................................                4.1                2.5                 17
Other \2\..............................................                4.1                2.5                 17
----------------------------------------------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Other includes any potential equipment leak emission point in gas service that is not specifically listed in
  this table, as specified in Sec.   98.232(f)(6) and (8).

0
70. Revise the table heading and table W-4B to subpart W of part 98 to
read as follows:

 Table W-4B to Subpart W of Part 98--Default Population Emission Factors
                   for Underground Natural Gas Storage
------------------------------------------------------------------------
                                                  Emission factor (scf/
        Underground natural gas storage              hour/component)
------------------------------------------------------------------------
  Total Hydrocarbon Population Emission Factors--Storage Wellheads, Gas
                                 Service
------------------------------------------------------------------------
Connector......................................                     0.01
Valve..........................................                      0.1
Pressure Relief Valve..........................                     0.17
Open-Ended Line................................                     0.03
------------------------------------------------------------------------
  Whole Gas Population Emission Factors--Other Components, Gas Service
------------------------------------------------------------------------
Continuous Low Bleed Pneumatic Device Vents \1\                      6.8
Continuous High Bleed Pneumatic Device Vents                        32.4
 \1\...........................................
Intermittent Bleed Pneumatic Device Vents \1\..                      2.3
------------------------------------------------------------------------
\1\ Emission Factor is in units of ``scf whole gas/hour/device.''

0
71. Revise table W-5A to subpart W of part 98 to read as follows:

   Table W-5A to Subpart W of Part 98--Default Methane Leaker Emission Factors for Liquefied Natural Gas (LNG)
                                                     Storage
----------------------------------------------------------------------------------------------------------------
                                                                   Emission factor (scf/hour/component)
                                                        --------------------------------------------------------
                                                           If you survey      If you survey      If you survey
                      LNG storage                         using method 21    using method 21    using any of the
                                                          as specified in    as specified in    methods in Sec.
                                                                Sec.               Sec.          98.234(a)(1),
                                                          98.234(a)(2)(i)    98.234(a)(2)(ii)     (3), or (5)
----------------------------------------------------------------------------------------------------------------
                          Leaker Emission Factors--LNG Storage Components, LNG Service
----------------------------------------------------------------------------------------------------------------
Valve..................................................               1.19               0.23                4.9
Pump Seal..............................................               4.00               0.73                 16
Connector..............................................               0.34               0.11                1.4
Other \1\..............................................               1.77               0.99                7.3
----------------------------------------------------------------------------------------------------------------
                          Leaker Emission Factors--LNG Storage Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \2\..............................................              14.84               9.51                 61
Connector..............................................               5.59               3.58                 23
Open-Ended Line........................................              17.27              11.07                 71
Pressure Relief Valve..................................              39.66              25.42                163
Meter and Instrument...................................              19.33              12.39                 79
Other \3\..............................................                4.1               2.63                 17
----------------------------------------------------------------------------------------------------------------
\1\ ``Other'' equipment type for components in LNG service should be applied for any equipment type other than
  connectors, pumps, or valves.
\2\ Valves include control valves, block valves and regulator valves.
\3\ ``Other'' equipment type for components in gas service should be applied for any equipment type other than
  valves, connectors, flanges, open-ended lines, pressure relief valves, and meters and instruments, as
  specified in Sec.   98.232(g)(6) and (7).

0
72. Revise table W-6A to subpart W of part 98 to read as follows:

 Table W-6A to Subpart W of Part 98--Default Methane Leaker Emission Factors for LNG Import and Export Equipment
----------------------------------------------------------------------------------------------------------------
                                                                   Emission factor (scf/hour/component)
                                                        --------------------------------------------------------
                                                           If you survey      If you survey      If you survey
            LNG import and export equipment               using method 21    using method 21    using any of the
                                                          as specified in    as specified in    methods in Sec.
                                                                Sec.               Sec.          98.234(a)(1),
                                                          98.234(a)(2)(i)    98.234(a)(2)(ii)     (3), or (5)
----------------------------------------------------------------------------------------------------------------
                         Leaker Emission Factors--LNG Terminals Components, LNG Service
----------------------------------------------------------------------------------------------------------------
Valve..................................................               1.19               0.23                4.9
Pump Seal..............................................               4.00               0.73                16.
Connector..............................................               0.34               0.11                1.4
Other \1\..............................................               1.77               0.99                7.3
----------------------------------------------------------------------------------------------------------------
                         Leaker Emission Factors--LNG Terminals Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \2\..............................................              14.84               9.51                 61
Connector..............................................               5.59               3.58                 23
Open-Ended Line........................................              17.27              11.07                 71
Pressure Relief Valve..................................              39.66              25.42                163
Meter and Instrument...................................              19.33              12.39                 79
Other \3\..............................................                4.1               2.63                 17
----------------------------------------------------------------------------------------------------------------
\1\ ``Other'' equipment type for components in LNG service should be applied for any equipment type other than
  connectors, pumps, or valves.
\2\ Valves include control valves, block valves and regulator valves.
\3\ ``Other'' equipment type for components in gas service should be applied for any equipment type other than
  valves, connectors, flanges, open-ended lines, pressure relief valves, and meters and instruments, as
  specified in Sec.   98.232(h)(7) and (8).

0
73. Revise table W-7 to subpart W of part 98 to read as follows:

   Table W-7 to Subpart W of Part 98--Default Total Hydrocarbon Leaker
           Emission Factors for Onshore Natural Gas Processing
------------------------------------------------------------------------
                                    Emission factor (scf/hour/component)
                                   -------------------------------------
                                      If you survey      If you survey
     Natural gas distribution        using method 21    using any of the
                                     as specified in    methods in Sec.
                                           Sec.          98.234(a)(1),
                                     98.234(a)(2)(i)      (3), or (5)
------------------------------------------------------------------------
  Leaker Emission Factors--Transmission-Distribution Transfer Station1
                         Components, Gas Service
------------------------------------------------------------------------
Connector.........................               1.69                6.7
Block Valve.......................              0.557                2.3
Control Valve.....................               9.34                 38
Pressure Relief Valve.............               0.27                1.1
Orifice Meter.....................              0.212               0.87
Regulator.........................              0.772                3.2
Open-ended Line...................             26.131                107
------------------------------------------------------------------------
\1\ Excluding customer meters.

0
74. Add table W-8 to subpart W of part 98 to read as follows:

 Table W-8 to Subpart W of Part 98--Default Methane Population Emission
                  Factors for Natural Gas Distribution
------------------------------------------------------------------------
                                                  Emission factor  (scf/
            Natural gas distribution                 hour/component)
------------------------------------------------------------------------
Population Emission Factors--Below Grade Transmission-Distribution
 Transfer Station Components and Below Grade Metering-Regulating
 Station1 Components, Gas Service \2\
------------------------------------------------------------------------
Below Grade T-D Transfer Station...............                     0.30
Below Grade M&R Station........................                     0.30
------------------------------------------------------------------------
Population Emission Factors--Distribution Mains, Gas Service \3\
------------------------------------------------------------------------
Unprotected Steel..............................                      1.2
Protected Steel................................                      2.3
Plastic........................................                     0.45
Cast Iron......................................                      2.8
------------------------------------------------------------------------
Population Emission Factors--Distribution Services, Gas Service \4\
------------------------------------------------------------------------
Unprotected Steel..............................                    0.086
Protected Steel................................                   0.0077
Plastic........................................                   0.0016
Copper.........................................                     0.03
------------------------------------------------------------------------
\1\ Excluding customer meters.
\2\ Emission Factor is in units of ``scf/hour/station.''
\3\ Emission Factor is in units of ``scf/hour/mile.''
\4\ Emission Factor is in units of ``scf/hour/number of services.''

0
75. Add table W-9 to subpart W of part 98 in numerical order to read as
follows:

 Table W-9 to Subpart W of Part 98--Default Methane Emission Factors for
                  Natural Gas-Fired Compressor-Drivers
------------------------------------------------------------------------
                                              Emission factor (kg CH4/
   Compressor-driver engine design class               mmBtu)
------------------------------------------------------------------------
2-stroke lean-burn........................                         0.658
4-stroke lean-burn........................                         0.522
4-stroke rich-burn........................                         0.045
------------------------------------------------------------------------

Subpart X--Petrochemical Production

0
76. Amend Sec.  98.243 by revising paragraphs (b)(3) and (d)(5) to read
as follows:

Sec.  98.243  Calculating GHG emissions.

* * * * *
    (b) * * *
    (3) For each flare, calculate CO2, CH4, and
N2O emissions using the methodology specified in Sec.
98.253(b).
* * * * *
    (d) * * *
    (5) For each flare, calculate CO2, CH4, and
N2O emissions using the methodology specified in Sec.
98.253(b).
0
77. Amend Sec.  98.244 by revising paragraph (b)(4)(iii) to read as
follows:

Sec.  98.244  vMonitoring and QA/QC requirements.

* * * * *
    (b) * * *
    (4) * * *
    (iii) ASTM D2505-88 (Reapproved 2004)e1 Standard Test Method for
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity
Ethylene

by Gas Chromatography (incorporated by reference, see Sec.  98.7).
* * * * *
0
78. Amend Sec.  98.246 by revising paragraphs (a) introductory text,
(a)(2) and (5), (a)(13) and (15), (b)(7) and (8), (c) introductory
text, and (c)(3) and (4) and adding paragraph (c)(6) to read as
follows:

Sec.  98.246  Data reporting requirements.

* * * * *
    (a) If you use the mass balance methodology in Sec.  98.243(c), you
must report the information specified in paragraphs (a)(1) through (15)
of this section for each type of petrochemical produced, reported by
process unit.
* * * * *
    (2) The type of petrochemical produced.
* * * * *
    (5) Annual quantity of each type of petrochemical produced from
each process unit (metric tons). If you are electing to consider the
petrochemical process unit to be the entire integrated ethylene
dichloride/vinyl chloride monomer process, the portion of the total
amount of EDC produced that is used in VCM production may be a measured
quantity or an estimate that is based on process knowledge and best
available data. The portion of the total amount of EDC produced that is
not utilized in VCM production must be measured in accordance with
Sec.  98.244(b)(2) or (3). Sum the amount of EDC used in the production
of VCM plus the amount of separate EDC product to report as the total
quantity of EDC petrochemical from an integrated EDC/VCM petrochemical
process unit.
* * * * *
    (13) Name and annual quantity (in metric tons) of each product
included in Equations X-1, X-2, and X-3 of Sec.  98.243. If you are
electing to consider the petrochemical process unit to be the entire
integrated ethylene dichloride/vinyl chloride monomer process, the
reported quantity of EDC product should include only that which was not
used in the VCM process.
* * * * *
    (15) For each gaseous feedstock or product for which the volume was
used in Equation X-1, report the annual average molecular weight of the
measurements or determinations, conducted according to Sec.
98.243(c)(3) or (4). Report the annual average molecular weight in
units of kg per kg mole.
    (b) * * *
    (7) Information listed in Sec.  98.256(e) of subpart Y of this part
for each flare that burns process off-gas. Additionally, provide
estimates based on engineering judgment of the fractions of the total
CO2, CH4 and N2O emissions that are
attributable to combustion of off-gas from the petrochemical process
unit(s) served by the flare.
    (8) Annual quantity of each type of petrochemical produced from
each process unit (metric tons).
* * * * *
    (c) If you comply with the combustion methodology specified in
Sec.  98.243(d), you must report under this subpart the information
listed in paragraphs (c)(1) through (c)(6) of this section.
* * * * *
    (3) Information listed in Sec.  98.256(e) of subpart Y of this part
for each flare that burns ethylene process off-gas. Additionally,
provide estimates based on engineering judgment of the fractions of the
total CO2, CH4 and N2O emissions that
are attributable to combustion of off-gas from the ethylene process
unit(s) served by the flare.
    (4) Name and annual quantity of each carbon-containing feedstock
(metric tons).
* * * * *
    (6) Name and annual quantity (in metric tons) of each product
produced in each process unit.

Subpart Y--Petroleum Refineries

0
79. Amend Sec.  98.253 by:
0
a. Revising paragraph (b) introductory text, paragraph (c) introductory
text, and paragraph (e) introductory text;
0
b. Revising Equation Y-18b in paragraph (i)(2);
0
c. Revising parameters ``Mwater'' and ``Hwater'' of Equation Y-18b in
paragraph (i)(2);
0
d. Adding parameter ``fcoke'' to Equation Y-18b in paragraph (i)(2);
and
0
e. Revising parameter ``Msteam'' of Equation Y-18f in paragraph (i)(5).
    The revisions and addition read as follows:

Sec.  98.253  Calculating GHG emissions.

* * * * *
    (b) For flares, calculate GHG emissions according to the
requirements in paragraphs (b)(1) through (3) of this section. All gas
discharged through the flare stack must be included in the flare GHG
emissions calculations with the exception of the following, which may
be excluded as applicable: (1) gas used for the flare pilots, and (2)
if using the calculation method in paragraph (b)(1)(iii) of this
section, the gas released during start-up, shutdown, or malfunction
events of 500,000 scf/day or less.
* * * * *
    (c) For catalytic cracking units and traditional fluid coking
units, calculate the GHG emissions from coke burn-off using the
applicable methods described in paragraphs (c)(1) through (c)(5) of
this section.
* * * * *
    (e) For catalytic reforming units, calculate the CO2
emissions from coke burn-off using the applicable methods described in
paragraphs (e)(1) through (e)(3) of this section and calculate the
CH4 and N2O emissions using the methods described
in paragraphs (c)(4) and (c)(5) of this section, respectively.
* * * * *
    (i) * * *
    (2) * * *
    [GRAPHIC] [TIFF OMITTED] TP21JN22.051

* * * * *
Mwater = Mass of water in the delayed coking unit vessel
at the end of the cooling cycle just prior to atmospheric venting or
draining (metric tons/cycle).
* * * * *
Hwater = Typical distance from the bottom of the coking
unit vessel to the top of the water level at the end of the cooling
cycle just prior to atmospheric venting or draining (feet) from
company records or engineering estimates.
fcoke = Fraction of the coke-filled bed that is covered
by water at the end of the cooling cycle just prior to atmospheric
venting or draining. Use 1 if the water fully covers coke-filled
portion of the coke drum.
* * * * *
    (5) * * *
* * * * *
Msteam = Mass of steam generated and released per
decoking cycle (metric tons/cycle) as determined in paragraph (i)(4)
of this section.
* * * * *
0
80. Amend Sec.  98.254 by revising paragraph (d) introductory text and

paragraph (e) introductory text to read as follows:

Sec.  98.254  Monitoring and QA/QC requirements.

* * * * *
    (d) Except as provided in paragraph (g) of this section, determine
gas composition and, if required, average molecular weight of the gas
using any of the following methods. Alternatively, the results of
chromatographic or direct mass spectrometer analysis of the gas may be
used, provided that the gas chromatograph or mass spectrometer is
operated, maintained, and calibrated according to the manufacturer's
instructions; and the methods used for operation, maintenance, and
calibration of the gas chromatograph or mass spectrometer are
documented in the written Monitoring Plan for the unit under Sec.
98.3(g)(5).
* * * * *
    (e) Determine flare gas higher heating value using any of the
following methods. Alternatively, the results of chromatographic
analysis of the gas may be used, provided that the gas chromatograph is
operated, maintained, and calibrated according to the manufacturer's
instructions; and the methods used for operation, maintenance, and
calibration of the gas chromatograph are documented in the written
Monitoring Plan for the unit under Sec.  98.3(g)(5).
* * * * *
0
81. Amend Sec.  98.256 by revising paragraph (k)(6) to read as follows:

Sec.  98.256  Data reporting requirements.

* * * * *
    (k) * * *
    (6) The basis for the typical dry mass of coke in the delayed
coking unit vessel at the end of the coking cycle (mass measurements
from company records or calculated using Equation Y-18a of this
subpart). If you use mass measurements from company records to
determine the typical dry mass of coke in the delayed coking unit
vessel at the end of the coking cycle, you must also report:
    (i) Internal height of delayed coking unit vessel (feet) for each
delayed coking unit.
    (ii) Typical distance from the top of the delayed coking unit
vessel to the top of the coke bed (i.e., coke drum outage) at the end
of the coking cycle (feet) from company records or engineering
estimates for each delayed coking unit.
* * * * *
0
82. Amend Sec.  98.257 by:
0
a. Revising paragraphs (b)(45), (46), and (53); and
0
b. Removing and reserving paragraphs (b)(54), (55), and (56).
    The revisions read as follows:

Sec.  98.257  Records that must be retained.

* * * * *
    (b) * * *
    (45) Mass of water in the delayed coking unit vessel at the end of
the cooling cycle prior to atmospheric venting or draining (metric ton/
cycle) (Equations Y-18b and Y-18e in Sec.  98.253) for each delayed
coking unit.
    (46) Typical distance from the bottom of the coking unit vessel to
the top of the water level at the end of the cooling cycle just prior
to atmospheric venting or draining (feet) from company records or
engineering estimates (Equation Y-18b in Sec.  98.253) for each delayed
coking unit.
* * * * *
    (53) Fraction of the coke-filled bed that is covered by water at
the end of the cooling cycle just prior to atmospheric venting or
draining (Equation Y-18b in Sec.  98.253) for each delayed coking unit.
* * * * *

Subpart BB--Silicon Carbide Production

0
83. Amend Sec.  98.286 by revising the introductory text and adding
paragraph (c) to read as follows:

Sec.  98.286  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraph (a)
or (b) of this section, and paragraph (c) of this section, as
applicable for each silicon carbide production facility.
* * * * *
    (c) If methane abatement technology is used at the silicon carbide
production facility, you must report the information in paragraphs
(c)(1) through (3) of this section. Upon reporting this information
once in an annual report, you are not required to report this
information again unless the information changes during a reporting
year, in which case, the reporter must include any updates in the
annual report for the reporting year in which the change occurred.
    (1) Type of methane abatement technology used on each silicon
carbide process unit or production furnace, and date of installation
for each.
    (2) Methane destruction efficiency for each methane abatement
technology (percent destruction). You must either use the
manufacturer's specified destruction efficiency or the destruction
efficiency determined via a performance test. If you report the
destruction efficiency determined via a performance test, you must also
report the test method that was used during the performance test.
    (3) Percentage of annual operating hours that methane abatement
technology was in use for all silicon carbide process units or
production furnaces combined.
0
84. Amend Sec.  98.287 by revising the introductory text and adding
paragraph (d) to read as follows:

Sec.  98.287  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must
retain the records specified in paragraphs (a) through (d) of this
section for each silicon carbide production facility.
* * * * *
    (d) Records of all information reported as required under Sec.
98.286(c).

Subpart DD--Electrical Transmission and Distribution Equipment Use

0
85. Amend Sec.  98.300 by revising paragraphs (a) introductory text and
(a)(3) and (7) to read as follows:

Sec.  98.300  Definition of the source category.

    (a) The electrical transmission and distribution equipment use
source category consists of all electric transmission and distribution
equipment and servicing inventory insulated with or containing
fluorinated GHGs, including but not limited to sulfur hexafluoride
(SF6) and perfluorocarbons (PFCs), used within an electric
power system. Electric transmission and distribution equipment and
servicing inventory includes, but is not limited to:
* * * * *
    (3) Switchgear, including closed-pressure and hermetically sealed-
pressure switchgear and gas-insulated lines containing fluorinated
GHGs, including but not limited to SF6 and PFCs.
* * * * *
    (7) Other containers of fluorinated GHG, including but not limited
to SF6 and PFCs.
* * * * *
0
86. Revise Sec.  98.301 to read as follows:

Sec.  98.301  Reporting threshold.

    (a) You must report GHG emissions under this subpart if you are an
electric power system as defined in Sec.  98.308 and your facility
meets the requirements of Sec.  98.2(a)(1). To calculate total annual
GHG emissions for comparison to the 25,000 metric ton CO2e per year
emission threshold in Table A-3, you must calculate emissions of each
fluorinated GHG, including but not limited to SF6 and PFCs,
and then sum the emissions of each fluorinated GHG

resulting from the use of electrical transmission and distribution
equipment for threshold applicability purposes using Equation DD-1 of
this subpart.
[GRAPHIC] [TIFF OMITTED] TP21JN22.052

Where:

E = Annual emissions for threshold applicability purposes (metric
tons CO2e).
NCEPS,j = the total nameplate capacity of insulating gas j-
containing equipment (excluding hermetically sealed-pressure
equipment) located within the facility plus the total nameplate
capacity of insulting gas j-containing equipment (excluding
hermetically sealed-pressure equipment) that is not located within
the facility but is under common ownership or control
GHGi,w = The weight fraction of fluorinated GHG i in insulating gas
j in the gas insulated equipment included in the total nameplate
capacity NCEPS,j, expressed as a decimal fraction. If
fluorinated GHG i is not part of a gas mixture, use a value of 1.0.
GWPi = Gas-appropriate GWP as provided in Table A-1 to subpart A of
this part.
EF = Emission factor for electrical transmission and distribution
equipment (lbs emitted/lbs nameplate capacity). For all gases, use
an emission factor or 0.1.
i = Fluorinated GHG contained in the electrical transmission and
distribution equipment.
0.000453592 = Conversion factor from lbs to metric tons.

    (b) A facility other than an electric power system that is subject
to this part because of emissions from any other source category listed
in Table A-3 or A-4 in subpart A of this part is not required to report
emissions under subpart DD of this part unless the total estimated
emissions from fluorinated gas, including but not limited to SF6 and
PFCs, containing equipment located at the facility, as calculated in
Equation DD-2 for comparison to the 25,000 metric ton CO2e per year
emission threshold in Table A-3 meets or exceeds 25,000 tons CO2e.
[GRAPHIC] [TIFF OMITTED] TP21JN22.053

Where:

E = Annual emissions for threshold applicability purposes (metric
tons CO2e).
NCother,j = For a facility other than an electric power system, the
total nameplate capacity of insulating gas j containing equipment
(excluding hermetically sealed-pressure equipment) located within
the facility
GHGi,w = The weight fraction of fluorinated GHG i in insulating gas
j in the gas insulated equipment included in the total nameplate
capacity NCother,j, expressed as a decimal fraction. If fluorinated
GHG i is not part of a gas mixture, use a value of 1.0.
GWPi = Gas-appropriate GWP as provided in Table A-1 to subpart A of
this part.
EF = Emission factor for electrical transmission and distribution
equipment (lbs emitted/lbs nameplate capacity). For all gases, use
an emission factor or 0.1.
i = Fluorinated GHG contained in the electrical transmission and
distribution equipment.
0.000453592 = Conversion factor from lbs to metric tons.

0
87. Revise Sec.  98.302 to read as follows:

Sec.  98.302  GHGs to report.

    You must report emissions of each fluorinated GHG, including but
not limited to SF6 and PFC, from your facility (including
emissions from fugitive equipment leaks, installation, servicing,
equipment decommissioning and disposal, and from storage cylinders)
resulting from the transmission and distribution servicing inventory
and equipment listed in Sec.  98.300(a). For acquisitions of equipment
containing or insulated with fluorinated GHG, you must report emissions
from the equipment after the title to the equipment is transferred to
the electric power transmission or distribution entity.
0
88. Revise Sec.  98.303 to read as follows:

Sec.  98.303  Calculating GHG emissions.

    (a) Mass-balance approach. Calculate the annual emissions of each
fluorinated GHG (including but not limited to SF6 and PFC)
using the mass-balance approach in Equation DD-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.054

Where:

User Emissionsi = Emissions of fluorinated GHG i from the
facility (pounds).
GHGi,w = The weight fraction of fluorinated GHG i in
insulating gas j if insulating gas j is a gas mixture, expressed as
a decimal fraction. If fluorinated GHG i is not part of a gas
mixture, use a value of 1.0.