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Natural Gas STAR Methane Challenge Program
BMP Commitment Option Technical Document
Document last updated 15 August 2018
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Contents
Document Version
Introduction
Methane Challenge Program Reporting
Cost Recovery
Description of Emission Sources
Pneumatic Controllers
Fixed Roof, Atmospheric Pressure Hydrocarbon Liquid Storage Tanks
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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The reporting elements outlined in this document apply to Reporting Year 2017 and correspond to v3.4
of the Methane Challenge BMP Commitment Option form. This version of the Technical Document
includes the following updates from the previously published version:
• Combines the two documents previously separated by segments (Onshore Production,
Processing, Gathering and Boosting, and Transmission and Storage in one, and Distribution in
another) into a single Technical Document;
• Fixes minor grammatical errors and improves the formatting of the document;
• Clarifies certain data elements to ensure complete reporting for distribution mains, including
adding the 'retired without replacement' field and the initial inventory of cast iron and
unprotected steel mains to properly calculate intended commitment progress; and
• Clarifies certain data elements to ensure complete reporting for distribution services, including
adding the initial inventory of cast iron and unprotected steel services to properly calculate
intended commitment progress.
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This document provides additional details to augment the Natural Gas STAR Methane Challenge
Program ("Methane Challenge") Best Management Practices (BMP) Commitment Framework and
Partnership Agreement documents released January 21, 2016.1 This document provides additional
information for each of the emission sources, including source descriptions, detail on mitigation options,
and Greenhouse Gas Reporting Program (GHGRP) and voluntary reporting data elements that would be
reported annually to the EPA to track partner progress. Where multiple mitigation options are listed,
Partners can choose to implement any combination of these throughout their operations to meet their
commitments.
Methane Challenge Program Reporting
The EPA will collect the following information from partner companies as part of annual reporting to
provide context for participation in the Program and facilitate annual tracking of progress:
• List of included facilities that report to Subpart W (GHGRP facility ID)
• List of included facilities not reporting to Subpart W (Methane Challenge facility ID2)
• List of facilities acquired/divested during the reporting year
In the following sections of this document, for each emission source, the "Reporting" table summarizes
the Data Elements the Methane Challenge Program will utilize to track partner company progress
towards their commitments, including the following information:
• Emission Source: For each Emission Source that a company has committed to address3, the
company will provide information on all occurrences of that source across company/unit operations.
Data collection will include both unmitigated sources and sources that have implemented mitigation
options (including supplementary information for those sources that have eliminated emissions
completely).
• Quantification Method: For most Emission Sources, there is a corresponding method or methods to
quantify methane emissions.
• Data Elements Collected via Facility-Level Reporting: The table lists data elements to be reported
by Partners, and indicates those already collected through GHGRP Subpart W reporting. Facilities
not already reporting to Subpart W would report Data Elements through a supplemental reporting
mechanism. Facilities already reporting to Subpart W would provide only supplemental data
elements through the supplemental reporting mechanism.
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, the EPA
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Introduction
1 The Methane Challenge Program: Best Management Practices (BMP) Framework document can be found on the
Natural Gas STAR website at https://www.epa.gov/natural-gas-star-program/methane-challenge-program-best-
management-practice-bmp-commitment-framework.
2 In the Methane Challenge module in e-GGRT, the system will auto-generate IDs for all non-GHGRP facilities created by
the partner's Implementation Manager (IM) or the IM's Delegates.
3 Partners will only provide supplemental data for sources for which they have made commitments.
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will compile the data collected and publicly release (on the Program website) all non-confidential data
submitted either to the Methane Challenge Program4 or through the GHGRP 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 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.
4 All Methane Challenge supplemental data must be non-confidential.
5
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Pneumatic Controllers
Applicable Segments: Production, Gathering and Boosting, Transmission and Storage
Source Description: Natural gas pneumatic controllers are automated instruments actuated by
pressurized natural gas used for maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature. Continuous bleed means a continuous flow of pneumatic supply natural gas
to the process control device (e.g. level control, temperature control, pressure control) where the
supply gas pressure is modulated by the process condition, and then flows to the valve controller where
the signal is compared with the process set-point to adjust gas pressure in the valve actuator. Pneumatic
controllers in this document are equivalent to pneumatic devices as defined in the GHGRP.
This source focuses on continuous high-bleed controllers (those with natural gas bleed rate greater than
6 standard cubic feet per hour). This source does not cover operational situations in which pneumatic
controllers with a bleed rate greater than 6 standard cubic feet (scf) per hour are required based on
functional needs, including but not limited to response time, safety and positive actuation. Partner
companies would track and report pneumatic controllers operating under these exceptions.
Intermittent bleed pneumatic controllers are not included in this source category.
Mitigation Options:
• Utilize natural gas-actuated pneumatic controllers with a continuous bleed rate less than or equal to
6 scf of gas per hour, or
• Utilize zero emitting controllers (e.g. instrument air, solar, electric, or mechanical controllers), or
• Remove natural gas pneumatics controllers from service with no replacement.
Commitment Timeframe: Partners commit to implement the specified mitigation options for all sources
included in their commitment (except those specifically exempted) by their designated commitment
achievement date, not to exceed five (5) years from the commitment start date.
Reporting:
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Description of Emission Sources
Emission Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting5
GHGRP
Natural gas-
actuated
controllers with
a bleed rate
greater than 6
scf per hour
Subpart W
Emission
Factor(EF)6
Actual count of high-bleed pneumatic controllers7
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
5 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.
6 40 CFR 98.233(a)
7 This source is equivalent to GHGRP "pneumatic devices"
6
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Emission Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting5
GHGRP
Natural gas-
actuated
controllers with
a bleed rate less
than or equal to
6 scf per hour
Subpart W EF8
Actual count of low-bleed pneumatic controllers9
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
mitigation10
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)
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8 40 CFR 98.233(a)
9 This source is equivalent to GHGRP "pneumatic devices"
10 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 use11 to achieve at
least a 95% reduction in methane emissions12, or
• Route gas to a flare or control device13 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 Reporting14
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 flare15
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
11 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.
12 May be used in conjunction with a vapor recovery tower.
13 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.
14 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.
15 40 CFR 98.233(j)(l); 40 CFR 98.233(j)(2)
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Emission Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting14
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 flare16
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
mitigation17
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)
16 40 CFR 98.233(j)(3)
17 As calculated per the specified emission quantification methodologies for each source.
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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 device18 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:
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Reciprocating Compressors - Rod Packing Vent
Applicable Segments: Gathering and Boosting, Processing, Transmission and Storage
Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting
GHGRP
Reciprocating
compressors
Reciprocating
compressor
venting EF19
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
18 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.
19 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
mitigation20
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 Reporting21
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
20 Partners can use a methodology of their choosing to calculate voluntary methane emission reductions from this source
and must specify what that methodology is.
21 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.
11
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Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting21
GHGRP
Reciprocating
compressor
rod packing
individual
atmospheric
vents
As found
measurement
or continuous
measurement
in operating
mode of
individual
compressor22,23
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
EF24
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
mitigation25
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)
22 40 CFR 98.233(p)(l)(i)(A), (p)(2)(ii), (p)(6)(i), and (p)(ll)
23 40 CFR 98.233(p)(l)(ii), (p)(3), (p)(7), and (p)(ll)
24 The site-specific emissions factor approach is used when anas 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).
25 As calculated per the specified emission quantification methodologies for each source.
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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 device26 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:
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Centrifugal Compressors - Venting
Applicable Segments: Gathering and Boosting, Processing, Transmission and Storage
Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting
GHGRP
Centrifugal
compressors
Wet Seal Oil
Degassing Vent
EF27
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
26 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.
27 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
mitigation28
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 seal29
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 Reporting30
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
28 Partners can use a methodology of their choosing to calculate voluntary methane emission reductions from this source
and must specify what that methodology is.
29 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
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.
14
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Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting30
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
vent31,32
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 flow rate (scfh)
X
b. Continuous: Measured volume of flow during the reporting
year (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
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
mitigation34
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)
3140 CFR 98.233(o)(l)(i)(A), (o)(2)(ii), (o)(6)(i), and (o)(ll)
32 40 CFR 98.233(o)(l)(ii), (o)(3), (o)(7), and (o)(ll)
33 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)
34 As calculated per the specified emission quantification methodologies for each source.
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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%35 from total potential emissions each year. Total potential emissions equals calculated emissions
from all planned maintenance activities in a calendar year36, assuming the pipeline is mechanically
evacuated or mechanically displaced using non-hazardous means down to atmospheric pressure and no
mitigation is used.37
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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Transmission Pipeline Blowdowns between Compressor Stations
Applicable Segments: Transmission and Storage
35 Partners are encouraged to designate a higher reduction rate.
36 Total potential emissions amounts will likely be different each year.
37 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.
16
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Reporting:
Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level GHGRP Reporting38
GHGRP
Pipeline
blowdowns
between
compressor
stations39
Subpart W
Method 1,
based on
volume,
temperature,
and pressure40
Total number of blowdowns per equipment or event type41
X
Total CH4 emissions (mt CH4) per equipment or event type
X
Subpart W
Method 2,
based on
measurement42
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
emissions43
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
Flare44
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)
38 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.
39 Emergency blowdown events are not included in this source for the BMP Option.
40 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
41 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.
42 98.233(i)(3), based on the measurement of emissions using a flow meter.
43 As calculated per the specified emission quantification methodologies for each source.
44 98.233 (n) provides flaring quantification guidance.
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Source Description: Distribution mains are natural gas distribution pipelines that serve as a common
source of supply for more than one service line.45 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.46 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.47
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.48
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 Iron49 and Unprotected
Steel Mains50
% 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%
45 http://primis.phmsa.dot.gov/comm/glossarv/index.htm?nocache=1606#Main
46 http://www.istt.com/guidelines/slip-lining
47 http://www.astm.org/Standards/F1504.htm
48 http://www.astm.org/Standards/F2207.htm
49 Includes wrought iron.
50 Excluding cast iron and unprotected steel mains that have been rehabilitated using specified mitigation methods.
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Mains - Cast Iron and Unprotected Steel
Applicable Segments: Distribution
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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 commitment51.
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:
M) (
Emission Source
Quantification
Method52
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)53
Cast iron mains
EF
Total miles of cast iron distribution mains
X
Annual CH4 emissions (mt CH4)
Distribution mains -
plastic - gas service
Plastic mains EF
Total miles of plastic distribution mains
X
Annual CH4 emissions (mt CH4)
Distribution mains -
protected steel - gas
service
Protected steel
mains EF
Total miles of protected steel distribution mains
X
Annual CH4 emissions (mt CH4)
Distribution mains -
unprotected steel -
gas service
Unprotected
steel mains EF
Initial inventory of unprotected steel distribution mains as
of January 1 of the first year of current commitment
(miles)54
Total miles of unprotected steel distribution mains
X
Annual CH4 emissions (mt CH4)
Distribution mains -
cast iron or
unprotected steel
with plastic liners or
inserts - gas service
Plastic mains EF
Total miles of cast iron or unprotected steel distribution
mains with Plastic Liners or Inserts*
Annual CH4 emissions* (mt CH4)
51 Excluding cast iron and unprotected steel mains that have been rehabilitated using specified mitigation methods.
52 The methodology (i.e., emission factors) used to calculate emissions and reductions for the Distribution Mains source
will be finalized pending completion of the Continuous Improvement proposal published August 13, 2018.
53 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.
54 Ibid.
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Emission Source
Quantification
Method52
Data Elements Collected via Facility-Level Reporting
GHGRP
Voluntary action to
reduce methane
emissions during the
reporting year
Difference in
emissions
before and after
mitigation55
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.
55 As calculated per the specified emission quantification methodologies for each source.
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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.)56 This source
covers cast iron and unprotected steel services.57
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 B58, 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 59
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 commitment60
Unprotected
steel services
EF61
Total number of cast iron services
Annual CH4 emissions (mt CH4)
Distribution
services - copper -
gas service
Copper services
EF
Total number of copper services
X
Annual CH4 emissions (mt CH4)
56 http://primis.phmsa.dot.gov/comm/glossarv/index.htm?nocache=1606#ServiceLine
57 "Service Ts" are included in this source category.
58 http://www.ecfr.gov/cgi-bin/text-
idx?SID=06dfel0fe465d0eelb352dad32b2c248&mc=true&node=sp49.3.192.b&rgn=div6
59 The methodology (i.e., emission factors) used to calculate emissions and reductions for the Distribution Services
source will be finalized pending completion of the Continuous Improvement proposal published 13 August 2018.
60 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.
61 EPA is using the unprotected steel EF as a proxy quantification method for this source.
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Services - Cast Iron and Unprotected Steel
Applicable Segments: Distribution
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Emission Source
Quantification
Method 59
Data Elements Collected via Facility-Level Reporting
GHGRP
Distribution
services - plastic -
gas service
Plastic services
EF
Total number of plastic services
X
Annual CH4 emissions (mt CH4)
Distribution
services -
protected steel -
gas service
Protected steel
services EF
Total number of protected steel services
X
Annual CH4 emissions (mt CH4)
Distribution
services -
unprotected steel -
gas service
Unprotected
steel services EF
Initial number of unprotected steel services as of January 1
of the first year of current commitment62
Total number of unprotected steel services
X
Annual CH4 emissions (mt CH4)
Distribution
services - cast Iron
or unprotected
steel with plastic
liners or inserts -
gas service
Plastic services
EF
Total number of cast iron or unprotected steel services
with plastic liners or inserts*
Annual CH4 emissions* (mt CH4)
Voluntary action to
reduce methane
emissions during
the reporting year
Difference in
emissions before
and after
mitigation63
Number of cast iron services:
Replaced with plastic
Replaced with protected steel
Replaced with copper
Rehabilitated with plastic pipe inserts
Number of unprotected steel services:
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.
62 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.
63 As calculated per the specified emission quantification methodologies for each source.
22
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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%64 from total potential emissions each year. Total
potential emissions equal calculated emissions from all planned maintenance activities in a calendar
year65, assuming the pipeline is mechanically evacuated or mechanically displaced using non-hazardous
means down to atmospheric pressure and no mitigation is used.66
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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Distribution Pipeline Blowdowns
64 Partners are encouraged to designate a higher reduction rate.
65 Total potential emissions amounts will likely be different each year.
66 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.
23
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Reporting:
Emission
Source
Quantification
Method
Data Elements Collected via Facility-Level Reporting
GHGRP
Distribution
Pipeline
Blowdowns67
Subpart W
calculation
method 1 or 2
68,69
Number of blowdowns
Total CH4 emissions (mt CH4)
Voluntary
action to
reduce
methane
emissions
during the
reporting year
Difference in
potential and
actual
emissions70
Number of blowdowns that routed gas to a:
Compressor or capture system for beneficial use
Flare71
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)
67 Emergency blowdown events and blowdowns of pipelines operating at 60 psi or less are not included in this source for
the BMP Option.
68 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.
69 40 CFR 98.233(i)(3), based on the measurement of emissions using a flow meter.
70 As calculated per the specified emission quantification methodologies for each source.
7140 CFR 98.233 (n) provides flaring quantification guidance.
24
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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.72 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.73 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.
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Excavation Damages
Applicable Segments: Distribution
72 http://primis.phmsa.dot.gov/comm/FactSheets/FSExcavationDamage.htm
73 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.
25
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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 incidents74
Total number of excavation damages by apparent root cause75
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)
74 Contractor, Railroad, County, State, Developer, Utility, Farmer, Municipality, Occupant, Unknown/Other
75 One-Call Notification Practices, Locating Practices, or Excavation Practices Not Sufficient; One-Call Notification Center
Error, Abandoned Facility, Deteriorated Facility, Previous Damage, Other/Miscellaneous
26
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Onshore Production
For purposes of the Methane Challenge Program, onshore petroleum and natural gas production means
all equipment on a single well-pad or associated with a single well-pad (including but not limited to
compressors, generators, dehydrators, storage vessels, engines, boilers, heaters, flares, separation and
processing equipment, and portable non-self-propelled equipment, which includes well drilling and
completion equipment, workover equipment, and leased, rented or contracted equipment) used in the
production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural
gas (including condensate). This equipment also includes associated storage or measurement vessels, all
petroleum and natural gas production equipment located on islands, artificial islands, or structures
connected by a causeway to land, an island, or an artificial island. Onshore petroleum and natural gas
production also means all equipment on or associated with a single enhanced oil recovery (EOR) well
pad using C02or natural gas injection.
A facility means all natural gas equipment on a single well-pad or associated with a single well-pad and
C02 EOR operations that are under common ownership or common control including leased, rented, or
contracted activities by an onshore natural gas production owner or operator and that are located in a
single hydrocarbon basin as defined in 40 CFR 98.238. Where a person or entity owns or operates more
than one well in a basin, then all onshore natural gas production equipment associated with all wells
that the person or entity owns or operates in the basin would be considered one facility.
Gathering and Boosting
For purposes of the Methane Challenge Program, onshore petroleum and natural gas gathering and
boosting means gathering pipelines and other equipment used to collect petroleum and/or natural gas
from onshore production gas or oil wells and used to compress, dehydrate, sweeten, or transport the
petroleum and/or natural gas to a natural gas processing facility, a natural gas transmission pipeline, or
a natural gas distribution pipeline. Gathering and boosting equipment includes, but is not limited to,
gathering pipelines, separators, compressors, acid gas removal units, dehydrators, pneumatic
devices/pumps, storage vessels, engines, boilers, heaters, and flares. Gathering and boosting equipment
does not include equipment reported under any other industry segment defined in subpart W.
Gathering pipelines operating on a vacuum and gathering pipelines with a gas to oil ratio (GOR) less than
300 standard cubic feet per stock tank barrel (scf/STB) are not included in this industry segment (oil here
refers to hydrocarbon liquids of all API gravities).
A gathering and boosting facility for purposes of reporting under Methane Challenge means all
gathering pipelines and other equipment located along those pipelines that are under common
ownership or common control by a gathering and boosting system owner or operator and that are
located in a single hydrocarbon basin as defined in 40 CFR 98.238. Where a person owns or operates
more than one gathering and boosting system in a basin (for example, separate gathering lines that are
not connected), then all gathering and boosting equipment that the person owns or operates in the
basin would be considered one facility. Any gathering and boosting equipment that is associated with a
single gathering and boosting system, including leased, rented, or contracted activities, is considered to
be under common control of the owner or operator of the gathering and boosting system that contains
the pipeline. The facility does not include equipment and pipelines that are part of any other industry
segment defined in subpart W.
28
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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
29
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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.
Document last updated 15 August 2018
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