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Natural Gas STAR Methane Challenge Program
BMP Commitment Option Technical Document
Document last updated 14 July 2020
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Document Version
Introduction
Methane Challenge Program Reporting
Cost Recovery
Description of Emission Sources
Pneumatic Controllers
Fixed Roof, Atmospheric Pressure Hydrocarbon Liquid Storage Tanks
Equipment Leaks/Fugitive Emissions - Compressor Isolation and Blowdown Valves
Reciprocating Compressors - Rod Packing Vent
Centrifugal Compressors - Venting
Transmission Pipeline Blowdowns between Compressor Stations
Mains - Cast Iron and Unprotected Steel
Services - Cast Iron and Unprotected Steel
Distribution Pipeline Blowdowns
Excavation Damages
Non-Finalized Emission Sources
Appendix A: Segment and Facility Definitions
Onshore Production
Gathering and Boosting
Natural Gas Processing
Natural Gas Transmission & Underground Storage
Natural Gas Distribution
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Contents
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Document Version
This version of the Technical Document includes the following updates from the previously published
version:
• Addition of a new commitment option for Equipment Leaks from isolation and blowdown valves
at transmission compressor stations (pages 10-13).
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Annual reports will also provide partners an opportunity to report optional, qualitative information to
provide context for their progress each year.
For reporting purposes, the Methane Challenge Program will utilize the same segment and facility
definitions as Subpart W (see Appendix A). Data will be reported at the facility level. Annually, EPA will
compile the data collected and publicly release (on the Program website) all non-confidential data
submitted to the Methane Challenge Program5 to track the progress of individual Partner companies in
meeting their Program commitments.
EPA reserves the right to update the contents of this document at any time to maintain alignment with
GHGRP or Greenhouse Gas Inventory (GHGI) definitions and methodologies. Beginning in the second full
year of reporting for the program, EPA will send the Technical Document and Reporting Form for the
upcoming reporting year to all Methane Challenge Implementation Managers annually and highlight any
changes made.
Cost Recovery
Distribution companies charge rates that are typically approved by the utility's governing body (state
public utility commission (PUC), city council, utility board, etc.). EPA recognizes that Methane Challenge
Program partner commitments may be dependent on obtaining additional approval from regulators,
including cost recovery for steps taken to reduce methane emissions and meeting their Program
commitments. EPA encourages company efforts, including efforts to seek cost recovery if appropriate,
to make and fulfill Methane Challenge commitments.
5 The program only uses non-confidential data from Subpart W; additionally, all Methane Challenge supplemental data
must be non-confidential.
5
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Description of Emission Sources
Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting6
GHGRP
Natural gas-
actuated
controllers
with a bleed
rate greater
than 6 scf per
hour
Subpart W
Emission
Factor(EF)7
Actual count of high-bleed pneumatic controllers8
X
Average operating hours per high-bleed controller (hr/yr)
X
Total CH4 emissions from high-bleed controllers (mt CH4)
X
Number of high-bleed controllers claiming operational
exemptions
Rationale for operational exemption
6 Pneumatic device data for onshore production and gathering and boosting facilities are aggregated at the basin level
for reporting under Subpart W, which is equivalent to reporting at the facility level. Data for the transmission
compression and underground storage industry segments are aggregated at the facility level.
7 40 CFR 98.233(a)
8 This source is equivalent to GHGRP "pneumatic devices"
6
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Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting6
GHGRP
Natural gas-
actuated
controllers
with a bleed
rate less than
or equal to 6
scf per hour
Subpart W EF9
Actual count of low-bleed pneumatic controllers10
X
Average operating hours per low-bleed controller (hr/yr)
X
Total CH4 emissions from low-bleed controllers (mt CH4)
X
Voluntary
action to
reduce
methane
emissions
during the
reporting year
Difference in
emissions
before and after
mitigation11
Number of high-bleed controllers converted to low-bleed
Number of high-bleed controllers converted to zero emitting or
removed from service
Number of low bleed controllers converted to zero emitting or
removed from service
Emission reductions from voluntary action (mt CH4)
9 40 CFR 98.233(a)
10 This source is equivalent to GHGRP "pneumatic devices"
11 As calculated per the specified emission quantification methodologies for each source.
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Fixed Roof, Atmospheric Pressure Hydrocarbon Liquid Storage Tanks
Applicable Segments: Production, Gathering and Boosting
Source Description: Atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced
liquids from onshore petroleum and natural gas production and gathering and boosting facilities.
Mitigation Options:
• Route gas to a capture system (e.g. a vapor recovery unit or VRU) for beneficial use12 to achieve at
least a 95% reduction in methane emissions13, or
• Route gas to a flare or control device14 to achieve at least a 95% reduction in methane emissions.
Commitment Timeframe: Partners commit to implement the specified mitigation options for all sources
included in their commitment by their designated commitment achievement date, not to exceed five (5)
years from the commitment start date.
Reporting:
Emission Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting15
GHGRP
For gas-liquid separators or
gathering and boosting
non-separator equipment
(e.g., stabilizers, slug
Sub-Basin ID or county ID, as applicable depending on
the industry segment
X
Calculation method used
X
catchers) with annual
average daily throughput of
oil greater than or equal to
10 barrels per day, and for
wells flowing directly to
Subpart W
calculation
methods 1 or
Count of atmospheric tanks that vent directly to the
atmosphere
X
Count of atmospheric tanks with vapor recovery
system emission control measures
X
atmospheric storage tanks
without passing through a
separator with throughput
greater than or equal to 10
barrels per day:
2, adjusted as
needed for
vents routed
to VRU
(beneficial
Count of atmospheric tanks with flaring emission
control measures
X
Annual CH4 emissions from flashing in atmospheric
tanks venting directly to the atmosphere (mt CH4)
X
• Tanks venting to
atmosphere
use) or flare16
Annual CH4 emissions from flashing in atmospheric
tanks equipped with vapor recovery systems (mt CH4)
X
• Tanks routing gas to a
flare
• Tanks routing gas to
capture system for
beneficial use
Annual CH4 emissions from flashing in atmospheric
tanks that control emissions with flaring (mt CH4)
X
12 Beneficial use means routing natural gas for use such that the gas is not vented to the atmosphere or flared. This
includes natural gas reinjection, electricity generation, natural gas liquefaction, and natural gas sales.
13 May be used in conjunction with a vapor recovery tower.
14 Control device means any equipment used for oxidizing methane vapors. Such equipment includes, but is not limited
to, enclosed combustion devices, flares, boilers, and process heaters.
15 For reporting under Subpart W, atmospheric tank counts and emissions data are aggregated at the sub-basin level for
onshore production facilities, and at the county level for onshore gathering and boosting facilities.
16 40 CFR 98.233(j)(l); 40 CFR 98.233(j)(2)
8
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Emission Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting15
GHGRP
For hydrocarbon liquids
flowing to gas-liquid
separators or non-
separator equipment or
directly to atmospheric
storage tanks with
throughput of oil less than
10 barrels/day:
• Tanks venting to the
atmosphere
• Tanks with gas routed
to a flare
• Tanks with gas routed
to a capture system for
beneficial use
Subpart W
calculation
method 3,
adjusted as
needed for
vents routed
to VRU
(beneficial
use) or flare17
Sub-Basin ID or county ID, as applicable depending on
the industry segment
X
Count of tanks that vent directly to atmosphere
Count of tanks equipped with vapor recovery system
emission control measures
Count of tanks with flaring emission control measures
X
Annual CH4 emissions from venting direct to
atmosphere (mt CH4)
Annual CH4 emissions from flashing in tanks equipped
with vapor recovery systems (mt CH4)
Annual CH4 emissions from flashing in tanks that
control emissions with flaring (mt CH4)
X
Voluntary action to reduce
methane emissions during
the reporting year
Difference in
emissions
before and
after
mitigation18
Number of tanks routed to VRU or beneficial use
Number of tanks routed to flare or controls device
Emission reductions from voluntary action (mt CH4)
17 40 CFR 98.233(j)(3)
18 As calculated per the specified emission quantification methodologies for each source.
9
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Equipment Leaks/Fugitive Emissions - Compressor Isolation and Blowdown Valves
Applicable Segments: Transmission & Storage
Source Description: This commitment option addresses methane emissions at compressor stations from
leakage through compressor blowdown and isolation valves. For additional information on the emission
source and mitigation options, please review the Methane Challenge "Continuous Improvement"
document for this commitment: https://www.epa.gov/natural-gas-star-program/continuous-
improvement-document-equipment-leaks-compressor-valves.
Mitigation Options:
• Develop a compressor valve inspection, maintenance, and repair/replacement program
o Implement an annual isolation and blowdown valve-focused leak survey at all compressor
stations. Partners can measure the compressors as-found but are encouraged to work up to
a biannual survey, timing the surveys so both the isolation and blowdown valve can be
surveyed on each unit, each year
o Develop an isolation and blowdown valve enhanced maintenance plan
o Mitigate emissions from found leaks by any combination of the following:
¦ Implementing activities identified in the enhanced maintenance plan that lead to
emissions reductions, or
¦ Repairing or replacing valves where practical (e.g., considering budgetary
constraints, operating requirements and maintenance schedules).
Repair/replacement should be targeted as soon as practical, but in no more than
three years after identifying the leaking component, or
¦ Routing isolation and blowdown valve leakage to a capture system for beneficial use
to achieve at least a 95% reduction in methane emissions, or
¦ Routing isolation and blowdown valve leakage to flare or control device19 to achieve
at least a 95% reduction in methane emissions
Commitment Timeframe: Partners commit to implement the specified mitigation options for all sources
included in their commitment by their designated commitment achievement date, not to exceed five (5)
years from the commitment start date.
19 Control device means any equipment used for oxidizing methane vapors. Such equipment includes, but is not
limited to, enclosed combustion devices, flares, boilers, and process heaters.
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Facility-level Annual Reporting:
Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting
GHGRP
Individual
compressor
NA
Unique name or ID for the compressor
X
Compressor type (Reciprocating or Centrifugal)
X
Hours in operating-mode
X
Hours in standby-pressurized-mode
X
Hours in not-operating-depressurized-mode
X
Which, if any, compressor sources are part of a manifolded
group of compressor sources
X
Indicate all of the following that apply to blowdown valve and
isolation valve emissions from the compressor during the year:
Emissions are vented to the atmosphere
X
Emissions are routed to vapor recovery
X
Emissions are routed to flare
X
Emissions are captured for fuel use or routed to a thermal
oxidizer
X
Emissions are part of a manifolded group of compressor
sources
X
Compressor in not-operating-depressurized-mode all year
(Y/N)
X
Individual
components
on each
compressor
NA
Unique name or ID for the compressor
X
Unique name or ID for the individual vent to the atmosphere
X
Type of component [Isolation valve; Blowdown valve]20
X
Did you repair or replace this component during the calendar
year? [Repair; Replace; N/A]
If yes, date of repair or replacement
Did you implement an enhanced21 maintenance program on the
valve this year?
If yes, provide pertinent details on the maintenance
activity(ies)
20 Wet seals on centrifugal compressors and rod packing on reciprocating compressors are outside of the scope of
this commitment and will not be included in the reporting requirements for this commitment.
21 "Enhanced" maintenance refers to a data-driven approach that uses measurement to target certain valves for
maintenance and will likely go beyond "recommended" maintenance.
11
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Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting
GHGRP
As found
measurement
or continuous
measurement
of individual
compressor22,23,
24
Mode in which the compressor was operating when measured
(Operating; Standby-pressurized; Not-operating depressurized)
The measurement method used
X
Measurement date
X
Was this measurement taken before or after a mitigation action
was implemented during the calendar year (if applicable)
[Before; After; N/A]
Flow rate based on measurement type:
a. As found: Measured volumetric flow at standard conditions
(scfh)
X
b. Continuous: Measured volumetric flow at standard
conditions (MMscf)
X
Annual CH4 emissions (mt CH4)
X
Site-specific
EF25
Reporter EF (scfh)
X
Number of measured compressors (during the current year and
2 previous years) from which the reporter EF was developed
X
Annual CH4 emissions (mt CH4)
X
Leak inspection
and repair /
replacement
program
details
NA
Number of surveys at this facility during the calendar year
How many compressors at this facility were surveyed this year?
How many vents indicated valve leakage this year?
How many leaking isolation valves were repaired or replaced this
year?
How many leaking blowdown valves were repaired or replaced
this year?
How many leaking isolation valves were routed to a capture
system for beneficial use?
22 Under this Methane Challenge commitment, partners should report measurements from all surveys conducted
during the calendar year. The reporting form will be set up to accommodate this.
23 40 CFR 98.233(p)(l)(i)(A), (p)(2)(ii), (p)(6)(i), and (p)(ll)
24 40 CFR 98.233(p)(l)(ii), (p)(3), (p)(7), and (p)(ll)
25 The site-specific emissions factor approach is used when an as found measurement for the compressor is
conducted in standby-pressurized-mode or in not-operating-depressurized-mode during the year (and an as found
measurement is not conducted in operating mode). The site-specific emissions factor is developed from as found
measurements of individual rod packing vent emissions from other compressors during the same year and the 2
previous years. 40 CFR 98.233(p)(l)(i)(A), (p)(2)(ii), (p)(6), and (p)(ll).
12
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Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting
GHGRP
How many leaking blowdown valves were routed to a capture
system for beneficial use?
How many leaking isolation valves were routed to flare or
control device?
How many leaking blowdown valves were routed to flare or
control device?
If valves were repaired or replaced, use this space to provide any
pertinent details on the replacement/repaired valve's
performance, installation, and design considerations
Voluntary
action to
reduce
methane
emissions
during the
reporting year
Difference in
emissions
before and after
mitigation26
Has the inspection and maintenance program been rolled-out to
this facility? (Y/N)
Annual emissions reductions from voluntary action (mt CH4)
End-of-Commitment Report:
This emission source will have a special "end-of-commitment" report in which partners will submit an
analysis of their leak detection, maintenance, and repair/replacement program to inform future
commitments. Partners making this commitment should ensure they are tracking these data each year,
so they are able to prepare this report at the end of their commitment.
• Summary of "lessons learned"
• Analysis of leak counts and distribution
• Year-over-year leak changes, repair methods, and practices, including a discussion of the effects of
implementing the enhanced maintenance plan
• Equipment / valve-specific recommendations
• Maintenance plan results and costs
26 This should be calculated on a compressor-by-compressor basis, subtracting emissions after mitigation from
emissions before mitigation. Emissions after mitigation should be measured within 90 days of implementing the
mitigation action.
13
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Reciprocating Compressors - Rod Packing Vent
Applicable Segments: Gathering and Boosting, Processing, Transmission and Storage
Source Description: Reciprocating compressor means a piece of equipment that increases the pressure
of a process natural gas by positive displacement, employing linear movement of a shaft driving a piston
in a cylinder. Reciprocating compressor rod packing means a series of flexible rings in machined metal
cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount of
compressed natural gas that escapes to the atmosphere. Rod packing emissions typically occur around
the rings from slight movement of the rings in the cups as the rod moves, but can also occur through the
"nose gasket" around the packing case, between the packing cups, and between the rings and shaft. As
the rings wear, or if the fit between the rod packing rings and rod is too loose, more compressed natural
gas can escape.
Mitigation Options:
• Replace the reciprocating compressor rod packing every 26,000 hours of operation, or
• Replace the reciprocating compressor rod packing prior to every 36 months, or
• Route rod packing vent to a capture system for beneficial use to achieve at least a 95% reduction in
methane emissions, or
• Route rod packing vent to flare or control device27 to achieve at least a 95% reduction in methane
emissions.
Commitment Timeframe: Partners commit to implement the specified mitigation options for all sources
included in their commitment by their designated commitment achievement date, not to exceed five (5)
years from the commitment start date.
Reporting - Gathering and Boosting:
Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting
GHGRP
Reciprocating
compressors
Reciprocating
compressor
venting EF28
Number of reciprocating compressors
X
Annual CH4 emissions (mt CH4)
X
Each
reciprocating
compressor
NA
Is rod packing replacement occurring every 26,000 hours or 36
months (Y/N)
Date of last rod packing replacement
Number of operating hours since rod packing replacement
27 Control device means any equipment used for oxidizing methane vapors. Such equipment includes, but is not limited
to, enclosed combustion devices, flares, boilers, and process heaters.
28 40 CFR 98.233(p)(10)
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Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting
GHGRP
Voluntary
action to
reduce
methane
emissions
during the
reporting year
Difference in
emissions
before and after
mitigation29
Number of reciprocating compressors with rod packing vents
routed to VRU or beneficial use during reporting year
Number of reciprocating compressors with rod packing vents
routed to flare or control device during reporting year
Number of reciprocating compressors for which rod packing was
replaced during reporting year
Methodology used to quantify reductions
Emission reductions from voluntary action (mt CH4)
Reporting - Processing and Transmission and Storage:
Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting30
GHGRP
Unique name or ID for the reciprocating compressor
X
Hours in operating-mode
X
Hours in standby-pressurized-mode
X
Hours in not-operating-depressurized-mode
X
Is rod packing replacement occurring every 26,000 hours or 36
months (Y/N)
Date of last rod packing replacement
Number of operating hours since rod packing replacement
Each
NA
Which, if any, compressor sources are part of a manifolded
group of compressor sources
X
reciprocating
compressor
Indicate all of the following that apply to rod packing venting emissions
from the compressor during the year:
Emissions are vented to the atmosphere
X
Emissions are routed to vapor recovery
X
Emissions are routed to flare
X
Emissions are captured for fuel use or routed to a thermal
oxidizer
X
Emissions are part of a manifolded group of compressor
sources
X
Compressor in not-operating-depressurized-mode all year
(Y/N)
X
29 Partners can use a methodology of their choosing to calculate voluntary methane emission reductions from this source
and must specify what that methodology is.
30 Subpart W requires facilities to report certain information per compressor and other information per vent.
Information reported per individual compressor vent is also specific to that one compressor.
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Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting30
GHGRP
Reciprocating
compressor
rod packing
individual
atmospheric
vents
As found
measurement
or continuous
measurement
in operating
mode of
individual
compressor31,32
Unique name or ID for the compressor
X
Unique name or ID for the individual vent to the atmosphere
X
Flow rate based on measurement type:
a. As found: Measured volumetric flow at standard conditions
from the rod packing vent (scfh)
X
b. Continuous: Measured volumetric flow at standard
conditions from the rod packing vent (MMscf)
X
Annual CH4 emissions (mt CH4)
X
Site-specific
EF33
Unique name or ID for the compressor
X
Unique name or ID for the individual vent to the atmosphere
X
Reporter EF (scfh)
X
Number of measured compressors (during the current year and
2 previous years) from which the reporter EF was developed
X
Annual CH4 emissions (mt CH4)
X
Voluntary
action to
reduce
methane
emissions
during the
reporting year
Difference in
emissions
before and after
mitigation34
Number of reciprocating compressors with rod packing vents
routed to VRU or beneficial use during reporting year
Number of reciprocating compressors with rod packing vents
routed to flare or control device during reporting year
Number of reciprocating compressors for which rod packing
was replaced during reporting year
Emission reductions from voluntary action (mt CH4)
3140 CFR 98.233(p)(l)(i)(A), (p)(2)(ii), (p)(6)(i), and (p)(ll)
32 40 CFR 98.233(p)(l)(ii), (p)(3), (p)(7), and (p)(ll)
33 The site-specific emissions factor approach is used when an as found measurement for the compressor is conducted in
standby-pressurized-mode or in not-operating-depressurized-mode during the year (and an as found measurement is
not conducted in operating mode). The site-specific emissions factor is developed from as found measurements of
individual rod packing vent emissions from other compressors during the same year and the 2 previous years. 40 CFR
98.233(p)(l)(i)(A), (p)(2)(ii), (p)(6), and (p)(ll).
34 As calculated per the specified emission quantification methodologies for each source.
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Centrifugal Compressors - Venting
Applicable Segments: Gathering and Boosting, Processing, Transmission and Storage
Source Description: Centrifugal compressor means any equipment that increases the pressure of a
process natural gas by centrifugal action, employing rotating movement of the driven shaft. In wet seal
centrifugal compressors, high-pressure oil is used as a barrier against escaping gas in centrifugal
compressor shafts. Very little gas escapes through the oil barrier, but under high pressure, considerably
more gas is absorbed by the oil. The seal oil is purged of the absorbed gas (using heaters, flash tanks,
and degassing techniques) and recirculated; the centrifugal compressor wet seal degassing vent releases
emissions when the high-pressure oil barriers for centrifugal compressors are depressurized to release
absorbed natural gas. This source is focused on centrifugal compressors with wet seals.
Mitigation Options:
• Route wet seal degassing to a capture system for beneficial use to achieve at least a 95% reduction
in methane emissions, or
• Route wet seal degassing to flare or control device35 to achieve at least a 95% reduction in methane
emissions, or
• Convert wet seals to dry seals or use centrifugal compressors with dry seals.
Commitment Timeframe: Partners commit to implement the specified mitigation options for all sources
included in their commitment by their designated commitment achievement date, not to exceed five (5)
years from the commitment start date.
Reporting - Gathering and Boosting:
Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting
GHGRP
Centrifugal
compressors
Wet Seal Oil
Degassing Vent
EF36
Number of centrifugal compressors with wet seal oil
degassing vents
X
Annual CH4 emissions (mt CH4)
X
Centrifugal
compressors
with dry seals
NA
Number of centrifugal compressors with dry seals
35 Control device means any equipment used for oxidizing methane vapors. Such equipment includes, but is not limited
to, enclosed combustion devices, flares, boilers, and process heaters.
36 40 CFR 98.233(o)(10)
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Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting
GHGRP
Voluntary
action to
reduce
methane
emissions
during the
reporting year
Difference in
emissions
before and after
mitigation37
Number of wet seal compressor de-gassing vents routed to VRU
or beneficial use during reporting year
Number of wet seal compressor de-gassing vents routed to flare
or control device during reporting year
Number of wet seal compressors converted to dry seal38
Methodology used to quantify reductions
Emission reductions from voluntary action (mt CH4)
Reporting - Processing and Transmission & Storage:
Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting39
GHGRP
Each
centrifugal
compressor
with wet seals
NA
Unique name or ID for the compressor
X
Number of wet seals
X
Hours in operating mode
X
Which, if any, compressor sources are part of a manifolded
group of compressor sources
X
Indicate all of the following that apply to wet seal degassing
emissions from the compressor during the year:
Emissions are vented to the atmosphere
Emissions are routed to flare
X
Emissions are captured for fuel use or routed to a thermal
oxidizer
X
Emissions are routed to vapor recovery for beneficial use
other than as fuel
X
Compressor in not-operating-depressurized-mode all year
(Y/N)
X
Centrifugal
compressors
with dry seals
NA
Number of centrifugal compressors with dry seals
X
37 Partners can use a methodology of their choosing to calculate voluntary methane emission reductions from this source
and must specify what that methodology is.
38 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2016, Annex 3.6 (Table 3.6-2), Gas Processing,
https://www.epa.gov/sites/production/files/2018-04/2018 ghgi natural gas systems annex tables.xlsx
39 Subpart W requires facilities to report certain information per compressor and other information per vent.
Information reported per individual compressor vent is also specific to that one compressor.
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Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting39
GHGRP
Centrifugal
compressor
with wet seal
degassing
vented to the
atmosphere
As found or
continuous
measurement in
operating mode
of individual
compressor wet
seal degassing
vent40-41
Unique name or ID for the compressor
X
Unique name or ID for the individual vent to the atmosphere
X
Flow rate based on measurement type:
a. As found: Measured flow rate (scfh)
X
b. Continuous: Measured volume of flow during the reporting
year (MMscf)
X
Annual CH4 emissions (mt CH4)
X
Site-specific
EF42
Unique name or ID for the compressor
X
Unique name or ID for the individual vent to the atmosphere
X
Reporter EF (scfh)
X
Number of measured compressors (during the current year and
the 2 previous years) from which the reporter EF was developed
X
Annual CH4 emissions (mt CH4)
X
Voluntary
action to
reduce
methane
emissions
during the
reporting year
Difference in
emissions
before and after
mitigation43
Number of wet seal compressor de-gassing vents routed to VRU
or beneficial use during reporting year
Number of wet seal compressor de-gassing vents routed to flare
or control device during reporting year
Number of wet seal compressors converted to dry seal
Emission reductions from voluntary action (mt CH4)
40 40 CFR 98.233(o)(l)(i)(A), (o)(2)(ii), (o)(6)(i), and (o)(ll)
4140 CFR 98.233(o)(l)(ii), (o)(3), (o)(7), and (o)(ll)
42 The site-specific emissions factor approach is used when an as found measurement for the compressor is conducted in
not-operating-depressurized-mode during the year (and an as found measurement is not conducted in operating mode).
The site-specific emissions factor is developed from as found measurements of individual seal oil degassing vent
emissions from other compressors during the same year and the 2 previous years. 40 CFR 98.233(o)(l)(i)(A), (o)(2)(ii),
(°)(6), and (o)(ll)
43 As calculated per the specified emission quantification methodologies for each source.
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Transmission Pipeline Blowdowns between Compressor Stations
Applicable Segments: Transmission and Storage
Source Description: Blowdown means the release of gas from a pipeline or section of pipeline that
causes a reduction in system pressure or a complete depressurization.
Mitigation Options:
• Route gas to a compressor or capture system for beneficial use, or
• Route gas to a flare, or
• Route gas to a low-pressure system by taking advantage of existing piping connections between
high- and low-pressure systems, temporarily resetting or bypassing pressure regulators to reduce
system pressure prior to maintenance, or installing temporary connections between high and low-
pressure systems, or
• Utilize hot tapping, a procedure that makes a new pipeline connection while the pipeline remains in
service, flowing natural gas under pressure, to avoid the need to blow down gas.
Partners commit to maximize blowdown gas recovery and/or emission reductions through utilization of
one or more of these options to reduce methane emissions from non-emergency blowdowns by at least
50%^ from total potential emissions each year. Total potential emissions equals calculated emissions
from all planned maintenance activities in a calendar year45, assuming the pipeline is mechanically
evacuated or mechanically displaced using non-hazardous means down to atmospheric pressure and no
mitigation is used.46
Commitment Timeframe: Partners commit to achieve the specified annual reduction rate by their
designated commitment achievement date, not to exceed five (5) years from the commitment start
date, and maintain at least that rate moving forward.
44 Partners are encouraged to designate a higher reduction rate.
45 Total potential emissions amounts will likely be different each year.
46 The reference to atmospheric pressure is intended to assist in defining total potential emissions, not an indication that
companies must reduce pressure to atmospheric pressure for every blowdown.
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Reporting:
Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level GHGRP Reporting47
GHGRP
Pipeline
blowdowns
between
compressor
stations48
Subpart W
Method 1,
based on
volume,
temperature,
and pressure49
Total number of blowdowns per equipment or event type50
X
Total CH4 emissions (mt CH4) per equipment or event type
X
Subpart W
Method 2,
based on
measurement51
Total number of blowdowns
X
Total CH4 emissions (mt CH4)
X
Voluntary
action to
reduce
methane
emissions
during the
reporting
year
Difference in
potential and
actual
emissions52
Total number of blowdowns to which a BMP was applied
Number of blowdowns that routed gas to a:
Compressor or capture system for beneficial use
Flare53
Low-pressure system
Number of hot taps utilized that avoided the need to blowdown
gas to the atmosphere
Total potential emissions (mt CH4)
Emission reductions from voluntary action (mt CH4)
47 Under Calculation Method 1, Subpart W requires aggregated reporting of blowdown counts and emissions per
equipment or event type at the facility level. Under Calculation Method 2, Subpart W requires aggregated reporting of
the emissions per facility, but the number of blowdown events or number of stacks monitored is not reported. For
transmission pipeline facilities, Subpart W also requires reporting the total number of blowdown events and total
emissions aggregated over both methods at the state level.
48 Emergency blowdown events are not included in this source for the BMP Option.
49 98.233(i)(2), based on the volume of pipeline segment between isolation valves and the pressure and temperature of
the gas within the pipeline
50 Event types are as follows: pipeline integrity work (e.g., the preparation work of modifying facilities, ongoing
assessments, maintenance or mitigation), traditional operations or pipeline maintenance, equipment replacement or
repair (e.g., valves), pipe abandonment, new construction or modification of pipelines including commissioning and
change of service, operational precaution during activities (e.g. excavation near pipelines), and all other pipeline
segments with a physical volume greater than or equal to 50 ft3.
51 98.233(i)(3), based on the measurement of emissions using a flow meter.
52 As calculated per the specified emission quantification methodologies for each source.
53 98.233 (n) provides flaring quantification guidance.
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Mains - Cast Iron and Unprotected Steel
Applicable Segments: Distribution
Source Description: Distribution mains are natural gas distribution pipelines that serve as a common
source of supply for more than one service line.54 This source covers cast iron and unprotected steel
mains (steel mains without cathodic protection).
Mitigation Options:
• Replace cast iron mains with plastic or cathodically protected steel and replace or cathodically
protect unprotected steel mains, or
• Rehabilitate cast iron and unprotected steel pipes with plastic pipe inserts, also referred to as slip-
lining or u-liners, or cured-in-place liners:
o Slip-lining is a technique that involves the insertion of a plastic pipe into an existing pipe. The
new pipe is pushed or pulled into the host pipe.55 U-liners are high-density polyethylene (HDPE)
plastic piping and are manufactured in a "U" shape with diameter sizing specific to the host
pipe in need of repair. The liner is pulled through the host pipe and then reformed to a circular
shape after insertion using steam. This process is carried out without the need to trench and
results in a structurally sound HDPE plastic pipe fitted tightly within the pipe needing repair.56
PHMSA provides guidance related to inserting plastic pipe into a metal pipe,
o Cured-in place liners are pipe liners comprised of flexible tubing, jackets, elastomer skin, and
adhesive systems. These liners are installed into an existing metallic natural gas pipe in need of
rehabilitation. Cured-in place liners provide resistance to gas permeation and provide
resistance against damage caused by ground movement, internal corrosion, leaking joints,
pinholes, and chemical attacks.57
Partners commit to replace or rehabilitate cast iron and unprotected steel mains at the following
minimum annual rates (based on a partner's total inventory of cast iron and unprotected steel mains)
per the mitigation options listed above. Partners may choose to commit to higher rates than those
designated.
Tier
Inventory of Cast Iron58 and Unprotected
Steel Mains59
% Minimum Annual
Replacement/Repair
Tier 1
<500 miles
6.50%
Tier 2
500-1,000 miles
5%
Tier 3
1,001 -1,500 miles
3%
Tier 4
1,501 miles - 3000 miles
2%
Tier 5
>3000 miles
1.5%
54 http://primis.phmsa.dot.gov/comm/glossarv/index.htm?nocache=1606#Main
55 https://www.istt.com/main/task.guidelinedetail/id.113
56 http://www.astm.org/Standards/F1504.htm
57 http://www.astm.org/Standards/F2207.htm
58 Includes wrought iron.
59 Excluding cast iron and unprotected steel mains that have been rehabilitated using specified mitigation methods.
22
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Commitment Timeframe: Partners commit to achieve the specified annual replacement/rehabilitation
rate by their designated commitment achievement date, not to exceed five years from the commitment
start date, and maintain at least that rate moving forward. Commitments will be based on the Partner's
inventory of cast iron and unprotected steel mains as of January 1 of the year of their commitment60.
After achieving their specified rate, Partners can maintain that rate for a period of five years (e.g. if
replacement/rehabilitation actions result in a Partner's moving to a different mileage tier, they will not
automatically have to adopt that new rate). After five years, Partners will be requested to evaluate their
ability to commit to a higher rate. Partners can raise their committed rate at any time.
Reporting:
Emission Source
Quantification
Method61
Data Elements Collected via Facility-Level Reporting
GHGRP
Distribution mains -
cast iron - gas service
NA
Initial inventory of cast iron distribution mains as of
January 1 of the first year of current commitment (miles)62
Subpart W Cast
iron mains EF
Total miles of cast iron distribution mains
X
Annual CH4 emissions (mt CH4)
X
Distribution mains -
plastic - gas service
Subpart W
Plastic mains EF
Total miles of plastic distribution mains
X
Annual CH4 emissions (mt CH4)
X
Distribution mains -
protected steel - gas
service
Subpart W
Protected steel
mains EF
Total miles of protected steel distribution mains
X
Annual CH4 emissions (mt CH4)
X
Distribution mains -
unprotected steel -
gas service
Subpart W
Unprotected
steel mains EF
Initial inventory of unprotected steel distribution mains as
of January 1 of the first year of current commitment
(miles)63
Total miles of unprotected steel distribution mains
X
Annual CH4 emissions (mt CH4)
X
Distribution mains -
cast iron or
unprotected steel
with plastic liners or
inserts - gas service
Subpart W
Plastic mains EF
Total miles of cast iron or unprotected steel distribution
mains with Plastic Liners or Inserts*
Annual CH4 emissions* (mt CH4)
60 Excluding cast iron and unprotected steel mains that have been rehabilitated using specified mitigation methods.
61Based on comments received on the Continuous Improvement proposal published August 13, 2018, the Methane
Challenge Program will continue to use the Subpart W emission factors (40 CFR 98.233(r) and Table W-7) for the
Distribution Mains source for the 2017 reporting year. EPA will continue to evaluate the Methane Challenge reporting
methodology for this source for future reporting years.
62 For example, if a partner made a Mains commitment in March 2016 and submits a report for this commitment for the
first time in 2018, in their 2018 report they will include their inventory as of January 1, 2016. They will not need to report
this data element again for the March 2016 Mains commitment.
63 Ibid.
23
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Emission Source
Quantification
Method61
Data Elements Collected via Facility-Level Reporting
GHGRP
Voluntary action to
reduce methane
emissions during the
reporting year
Difference in
emissions
before and after
mitigation64
Miles of cast iron mains:
Replaced with plastic
Replaced with protected steel
Rehabilitated with plastic pipe inserts or cured-in-place
liners
Retired without replacement
Miles of unprotected steel mains:
Cathodically protected or replaced with protected steel
Rehabilitated with pipe inserts or cured-in-place liners
Replaced with plastic
Retired without replacement
Emission reductions from voluntary action (mt CH4)
*The reporting of this supplemental data may result in duplicate data for some facilities reporting into
Subpart W. The Methane Challenge Program will develop a process to reconcile any potential
duplications that occur.
64 As calculated per the specified emission quantification methodologies for each source.
24
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Services - Cast Iron and Unprotected Steel
Applicable Segments: Distribution
Source Description: A service line is a distribution line that transports gas from a common source of
supply to (1) a customer meter or the connection to a customer's piping, whichever is farther
downstream, or (2) the connection to a customer's piping if there is no customer meter. (A customer
meter is the meter that measures the transfer of gas from an operator to a consumer.)65 This source
covers cast iron and unprotected steel services.66
Mitigation Options:
• Replace unprotected steel and cast iron services with copper, plastic, or protected steel that meet
the manufacturing requirements and qualifications provided in 49 CFR Part 192, Subpart B67, or
• Rehabilitate cast iron and unprotected steel services with plastic pipe inserts or liners.
At a minimum, partners commit to replace or rehabilitate cast iron and unprotected steel services when
the main is replaced or rehabilitated. Partners would be encouraged to specify any additional targeted
replacement efforts beyond this practice. Due to the linkage with mains, this source is not eligible for a
stand-alone commitment, but can be selected as an optional addition for Partners that select the "Mains
- Cast Iron and Unprotected Steel" source category.
Commitment Timeframe: Partners commit to adopt the specified replacement or rehabilitation practice
by their designated commitment achievement date, not to exceed five (5) years from the commitment
start date, and maintain that practice moving forward.
Reporting:
Emission Source
Quantification
Method 68
Data Elements Collected via Facility-Level Reporting
GHGRP
Distribution
services - cast iron
- gas service
NA
Initial number of cast iron services as of January 1 of the
first year of current commitment69
Subpart W
Unprotected
steel services
EF70
Total number of cast iron services
Annual CH4 emissions (mt CH4)
Total number of copper services
X
65 http://primis.phmsa.dot.gov/comm/glossarv/index.htm?nocache=1606#ServiceLine
66 "Service Ts" are included in this source category.
67 http://www.ecfr.gov/cgi-bin/text-
idx?SID=06dfel0fe465d0eelb352dad32b2c248&mc=true&node=sp49.3.192.b&rgn=div6
68 Based on comments received on the Continuous Improvement proposal published August 13, 2018, the Methane
Challenge Program will continue to use the Subpart W emission factors (40 CFR 98.233(r) and Table W-7) for the
Distribution Services source for the 2017 reporting year. EPA will continue to evaluate the Methane Challenge reporting
methodology for this source for future reporting years.
69 For example, if a partner made a Services commitment in March 2016 and submits a report for this commitment for
the first time in 2018, in their 2018 report they will include their inventory as of January 1, 2016. They will not need to
report this data element again for the March 2016 Services commitment.
70 EPA is using the unprotected steel EF as a proxy quantification method for this source.
25
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Emission Source
Quantification
Method 68
Data Elements Collected via Facility-Level Reporting
GHGRP
Distribution
Subpart W
services - copper -
Copper services
Annual CH4 emissions (mt CH4)
X
gas service
EF
Distribution
services - plastic -
gas service
Subpart W Plastic
Total number of plastic services
X
services EF
Annual CH4 emissions (mt CH4)
X
Distribution
services -
Subpart W
Protected steel
Total number of protected steel services
X
protected steel -
gas service
services EF
Annual CH4 emissions (mt CH4)
X
Distribution
services -
Subpart W
Unprotected
steel services EF
Initial number of unprotected steel services as of January 1
of the first year of current commitment71
unprotected steel -
Total number of unprotected steel services
X
gas service
Annual CH4 emissions (mt CH4)
X
Distribution
services - cast Iron
or unprotected
Total number of cast iron or unprotected steel services
Subpart W Plastic
with plastic liners or inserts*
steel with plastic
services EF
liners or inserts -
Annual CH4 emissions* (mt CH4)
gas service
Number of cast iron services:
Replaced with plastic
Replaced with protected steel
Voluntary action to
reduce methane
Difference in
Replaced with copper
emissions before
Rehabilitated with plastic pipe inserts
emissions during
and after
Number of unprotected steel services:
the reporting year
mitigation72
Cathodically protected or replaced with protected steel
Replaced with plastic
Replaced with copper
Rehabilitated with plastic pipe inserts
Emission reductions from voluntary action (mt CH4)
*The reporting of this supplemental data may result in duplicate reporting for some facilities reporting into
GHGRP Subpart W. The Methane Challenge Program would develop a process to reconcile any potential
duplications that occur.
71 For example, if a partner made a Services commitment in March 2016 and submits a report for this commitment for
the first time in 2018, in their 2018 report they will include their inventory as of January 1, 2016. They will not need to
report this data element again for the March 2016 Services commitment.
72 As calculated per the specified emission quantification methodologies for each source.
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Applicable Segments: Distribution
Source Description: Blowdown means the release of gas from a pipeline or section of pipeline that
causes a reduction in system pressure or a complete depressurization.
Mitigation Options:
• Route gas to a compressor or capture system for beneficial use, or
• Route gas to a flare, or
• Route gas to a low-pressure system by taking advantage of existing piping connections between
high- and low-pressure systems, temporarily resetting or bypassing pressure regulators to reduce
system pressure prior to maintenance, or installing temporary connections between high and low-
pressure systems, or
• Utilize hot tapping, a procedure that makes a new pipeline connection while the pipeline remains in
service, flowing natural gas under pressure, to avoid the need to blow down gas, or
• Use stopoff/stopple equipment and fittings to reduce the length of pipe and the associated volume
of gas being blown down.
Partners commit to maximize blowdown gas recovery and/or emission reductions through utilization of
one or more of these options to reduce methane emissions from non-emergency blowdowns of
pipelines operating greater than 60 psi by at least 50%73 from total potential emissions each year. Total
potential emissions equal calculated emissions from all planned maintenance activities in a calendar
year74, assuming the pipeline is mechanically evacuated or mechanically displaced using non-hazardous
means down to atmospheric pressure and no mitigation is used.75
Commitment Timeframe: Partners commit to achieve the specified annual reduction rate by their
designated commitment achievement date, not to exceed five (5) years from the commitment start
date, and maintain at least that rate moving forward.
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73 Partners are encouraged to designate a higher reduction rate.
74 Total potential emissions amounts will likely be different each year.
75 The reference to atmospheric pressure is intended to assist in defining total potential emissions, not an indication that
companies must reduce pressure to atmospheric pressure for every blowdown.
27
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Reporting:
Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting
GHGRP
Distribution
Pipeline
Blowdowns76
Subpart W
calculation
method 1 or 2
77,78
Number of blowdowns
Total CH4 emissions (mt CH4)
Voluntary
action to
reduce
methane
emissions
during the
reporting year
Difference in
potential and
actual
emissions79
Number of blowdowns that routed gas to a:
Compressor or capture system for beneficial use
Flare80
Low-pressure system
Number of hot taps utilized that avoided the need to blowdown
gas to the atmosphere
Total potential emissions (mt CH4)
Emission reductions from voluntary action (mt CH4)
76 Emergency blowdown events and blowdowns of pipelines operating at 60 psi or less are not included in this source for
the BMP Option.
77 40 CFR 98.233(i)(2), based on the volume of pipeline segment between isolation valves and the pressure and
temperature of the gas within the pipeline.
78 40 CFR 98.233(i)(3), based on the measurement of emissions using a flow meter.
79 As calculated per the specified emission quantification methodologies for each source.
80 40 CFR 98.233 (n) provides flaring quantification guidance.
28
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Excavation Damages
Applicable Segments: Distribution
Source Description: Excavation damage may include damage to the external coating of the pipe, or
dents, scrapes, cuts, or punctures directly into the pipeline itself. Excavation damage often occurs when
required One-Call notifications are not made prior to beginning excavation, digging, or plowing
activities, or when calls are made but pipe is still damaged. When the location of underground facilities
is not properly determined, the excavator may inadvertently - and sometimes unknowingly - damage
the pipeline and its protective coating.81 This source covers both distribution mains and services.
Mitigation Options:
• Conduct incident analyses (e.g. by identifying whether excavation, locating, or One-Call practices
were not sufficient) to inform process improvements and reduce excavation damages, or
• Undertake targeted programs to reduce excavation damages and/or shorten time to shut-in when
damages do occur, including patrolling systems when construction activity is higher, excavator
education programs (811, call before you dig), identifying and implementing steps to minimize
repeat offenders, and stand-by efforts.
Partner companies' collection and reporting of data on all excavation damages is a significant part of this
commitment.82 Partners will use the collected data to set a company-specific goal for reducing
excavation damages and/or methane emissions from excavation damages.
Commitment Timeframe: Partners commit to reporting all data elements by their designated
commitment achievement date, not to exceed five (5) years from the commitment start date.
81 http://primis.phmsa.dot.gov/comm/FactSheets/FSExcavationDamage.htm
82 The program is not requesting quantification of emissions/reductions due to lack of a quantification methodology that
would result in consistent, comparable emissions calculations. EPA will evaluate adding quantification to this source in
the future should an acceptable methodology become available.
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Reporting:
Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting
GHGRP
Excavation
damages-
natural gas
distribution
network
NA
Total number of excavation damages
Total number of excavation damages per thousand locate calls
Total number of excavation damages per class location
(optional)
Total number of excavation damages by pipe material (steel, cast
iron, copper, plastic etc.) and part of system involved (main,
service, inside meter/regulator set, etc.)
Total number of excavation damages which resulted in a release
of natural gas
Total number of excavation damages which resulted in the
pipeline being shut down
Total number of excavation damages where the operator was
given prior notification of excavation activity
Total number of excavation damages by type that caused
excavation damage incidents83
Total number of excavation damages by apparent root cause84
Voluntary
action to
reduce
methane
emissions
during the
reporting
year
NA
Actions taken to minimize excavation damages/reduce methane
emissions from excavation damages
Company-specific goal for reducing excavation damages and/or
methane emissions from excavation damages (when available)
Progress in meeting company-specific goal (when available)
83 Contractor, Railroad, County, State, Developer, Utility, Farmer, Municipality, Occupant, Unknown/Other
84 One-Call Notification Practices, Locating Practices, or Excavation Practices Not Sufficient; One-Call Notification Center
Error; Abandoned Facility; Deteriorated Facility; Previous Damage; Other/Miscellaneous. Note - for a damage root
cause of "No Locate Call", please use the "One-Call Notification Practices Not Sufficient" category.
30
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Non-Finalized Emission Sources
At this time, EPA is not finalizing BMP commitment details for these sources. Details will be released as
soon as they are available.
Liquids Unloading
Pneumatic Pumps
Metering and Regulating (M&R) Stations/City Gates
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Appendix A: Segment and Facility Definitions
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Natural Gas Processing
For purposes of the Methane Challenge Program, natural gas processing means the separation of
natural gas liquids (NGLs) or non-methane gases from produced natural gas, or the separation of NGLs
into one or more component mixtures. Separation includes one or more of the following: forced
extraction of natural gas liquids, sulfur and carbon dioxide removal, fractionation of NGLs, or the
capture of C02 separated from natural gas streams. This segment also includes all residue gas
compression equipment owned or operated by the natural gas processing plant. This industry segment
includes processing plants that fractionate gas liquids, and processing plants that do not fractionate gas
liquids but have an annual average throughput of 25 MMscf per day or greater.
A natural gas processing facility for the purposes of reporting under the Methane Challenge is any
physical property, plant, building, structure, source, or stationary equipment in the natural gas
processing industry segment located on one or more contiguous or adjacent properties in actual
physical contact or separated solely by a public roadway or other public right-of-way and under common
ownership or common control, that emits or may emit any greenhouse gas. Operators of military
installations may classify such installations as more than a single facility based on distinct and
independent functional groupings within contiguous military properties.
Natural Gas Transmission & Underground Storage
For purposes of the Methane Challenge Program, BMP option, natural gas transmission compression
and natural gas transmission pipelines are both included in the 'Natural Gas Transmission &
Underground Natural Gas Storage' segment.
Onshore natural gas transmission compression means any stationary combination of compressors that
move natural gas from production fields, natural gas processing plants, or other transmission
compressors through transmission pipelines to natural gas distribution pipelines, LNG storage facilities,
or into underground storage. In addition, a transmission compressor station includes equipment for
liquids separation, and tanks for the storage of water and hydrocarbon liquids. Residue (sales) gas
compression that is part of onshore natural gas processing plants are included in the onshore natural
gas processing segment and are excluded from this segment.
Onshore natural gas transmission pipeline means all natural gas pipelines that are a Federal Energy
Regulatory Commission rate-regulated Interstate pipeline, a state rate-regulated Intrastate pipeline, or a
pipeline that falls under the "Hinshaw Exemption" as referenced in section 1(c) of the Natural Gas Act,
15 I.S.C. 717-717(w)(1994).
Underground natural gas storage means subsurface storage, including depleted gas or oil reservoirs and
salt dome caverns that store natural gas that has been transferred from its original location for the
primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas);
natural gas underground storage processes and operations (including compression, dehydration and
flow measurement, and excluding transmission pipelines); and all the wellheads connected to the
compression units located at the facility that inject and recover natural gas into and from the
underground reservoirs
A natural gas transmission compression facility or underground natural gas storage facility for the
purposes of reporting under the Methane Challenge is any physical property, plant, building, structure,
source, or stationary equipment in the natural gas transmission compression industry segment or
underground natural gas storage industry segment located on one or more contiguous or adjacent
properties in actual physical contact or separated solely by a public roadway or other public right-of-way
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and under common ownership or common control, that emits or may emit any greenhouse gas.
Operators of military installations may classify such installations as more than a single facility based on
distinct and independent functional groupings within contiguous military properties.
An onshore natural gas transmission pipeline facility for the purpose of reporting under the Methane
Challenge is the total U.S. mileage of natural gas transmission pipelines owned or operated by an
onshore natural gas transmission pipeline owner or operator. If an owner or operator has multiple
pipelines in the United States, the facility is considered the aggregate of those pipelines, even if they are
not interconnected.
Natural Gas Distribution
For purposes of the Methane Challenge Program, natural gas distribution means the distribution
pipelines and metering and regulating equipment at metering-regulating stations that are operated by a
Local Distribution Company (LDC) within a single state that is regulated as a separate operating company
by a public utility commission or that is operated as an independent municipally-owned distribution
system. This segment excludes customer meters and regulators, infrastructure, and pipelines (both
interstate and intrastate) delivering natural gas directly to major industrial users and farm taps
upstream of the local distribution company inlet.
A natural gas distribution facility for the purposes of reporting under the Methane Challenge is the
collection of all distribution pipelines and metering-regulating stations that are operated by an LDC
within a single state that is regulated as a separate operating company by a public utility commission or
that are operated as an independent municipally-owned distribution system.
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