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EA 2017-02 May 2, 2017
UNDERSTANDING UPDATES TO THE EPA INVENTORY OF GREENHOUSE GAS EMISSIONS FROM NATURAL GAS SYSTEMS
INTRODUCTION
Natural gas is a fuel of choice for consumers because of its low cost, efficient end uses, and
environmental attributes. This domestically produced and abundant energy source is poised to
serve as a foundation fuel for the US economy for years to come. This potential has focused
public attention on the environmental footprint of energy production, transportation,
distribution, and use.
Efficient natural gas technologies serve as low-cost, low-emission options for building energy
needs, home comfort, industrial processes, and electricity generation. Furthermore, natural gas
is a low-carbon fuel relative to coal and oil; natural gas results in less carbon dioxide for the
same amount of beneficial energy. A better understanding of methane emissions released from
production and delivery systems will further clarify how the use of natural gas may deliver
greater environmental benefits.
The Environmental Protection Agency (EPA) made further updates to its estimates of methane
emissions in its Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2015 that it
released in April 2017. The Inventory incorporates new data available from studies on emissions
as well as the EPA’s own Greenhouse Gas Reporting Program (GHGRP).
The Inventory reveals once again that natural gas distribution systems have a small emissions
footprint shaped by a declining trend. Distribution systems owned and operated by local natural
gas utilities emit only 0.1 percent of produced natural gas. These annual emissions declined 75
percent from 1990 to 2015 even as natural gas utility companies added nearly 600,000 miles of
pipeline to serve 19 million more customers, increases of 37 and 35 percent increase
respectively.
This exceptional record can be traced to safety as the top priority for gas utilities who continue
to be vigilant and deeply committed to systematically upgrading infrastructure through risk-
based integrity management programs. As companies and the country continue to modernize
the natural gas infrastructure base and connect homes and businesses, there will be new
opportunities to achieve low-cost carbon emissions reductions by leveraging this existing
infrastructure and the nation’s natural gas resource.
2
Figure 1 Methane Emissions from Natural Gas Distribution Systems
(Million Metric Tons CO2e)
Source: Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2015
Environmental Protection Agency
KEY FINDINGS
Annual methane emissions from natural gas distribution systems declined 75 percent
from 1990 to 2015.
The natural gas emissions rate of production from distribution systems is now less than
0.1 percent.
Industry wide the natural gas emissions as a rate of production (the “leakage rate”)
increased to 1.2 percent—a level still well below even the most stringent thresholds for
immediate climate benefits achieved through coal to natural gas switching.
The ratio of methane emissions per unit of natural gas produced has declined
continuously during the past two and a half decades, dropping 46 percent since 1990.
Total methane emissions from all natural gas systems have declined 16 percent from
1990 to 2015.
Methane emissions economy-wide represent 10 percent of all greenhouse gas emissions
in the United States. Along with natural gas systems, methane emission sources include
enteric fermentation and manure management (livestock), landfills, coal mining
petroleum systems, wastewater treatment, and others.
RECALCULATIONS IN THE 2017 INVENTORY
Each year EPA receives new information and data with which it uses to revise and
recalculate emissions estimates. Sources of information include a formal public
comment period, data from the EPA Greenhouse Gas Reporting Program (GHGRP), and
new field studies.
The sum of revisions to natural gas system calculated estimates showed a decrease in
methane emissions relative to the last year’s Inventory (2016 edition) from 176 million
metric tons of carbon dioxide equivalent (MMTe) to 163 MMTe, a decline of 8 percent.
0
10
20
30
40
50
1990 2005 2011 2012 2013 2014 2015
Down 75%
since 1990
3
The sum of revisions to combined oil and natural gas systems decreased methane
emissions from these sectors from 244 MMTe to 202 MMTe.
Table 1 Methane Emissions by Inventory Release Edition
Methane emissions in 2014 Inventory,
2016 edition
Inventory, 2017
edition
Change
Field Production 109 108 -1%
Processing 24 11 -54%
Transmission and Storage 32 32 0%
Distribution 11 11 1%
Natural Gas Total 176 163 -8%
Petroleum Field Operations 67 42 -37%
Oil and Gas Total 244 205 -16%
Source: Inventory of U.S. Greenhouse Gas Emissions and Sinks
Emissions from the production segment, which includes gathering and boosting
facilities, were revised down from 109.0 MMTe in the prior inventory to 108.2 MMTe for
2015.
The processing stage emissions estimates underwent significant revision as EPA
incorporated new data from the GHGRP and a field study. The combined impact of
revisions to processing segment emissions (2014 data), compared to the previous
Inventory, is a decrease in methane emissions from 24.0 to 11.1 MMTe.
No methodological changes were made to the transmission and storage segment in the
2017 Inventory. However, EPA included estimates of emissions released from the Aliso
Canyon storage field in California pro-rated for 2015, which added 2.0 MMTe of
emissions to the transmission and storage stage, about 6 percent of total emissions for
this segment.
The distribution stage underwent no methodological changes. Updates to data resulted
in a small increase in calculated emissions of less than 0.001 MMTe, or 0.1 percent.
Other major sources of methane saw significant revisions in this year’s update. Methane
from landfills was revised downward 21%; petroleum systems (field operations) revised
downward 37%.
SUMMARY AND ANALYSIS OF EPA INVENTORY
For two decades, the Environmental Protection Agency (EPA) has developed and published
estimates of greenhouse gas (GHG) emissions in its annual Inventory of U.S. Greenhouse Gas
Emissions and Sinks (referenced throughout as the Inventory). It is the most comprehensive
assessment of U.S. greenhouse gas emissions available.
4
The Inventory covers all major and minor greenhouse gases, including carbon dioxide (CO2),
methane, nitrous oxides, and lesser gases. EPA reports all emissions in units of CO2-equivalence
(CO2e) by weighting different air emissions by their respective global warming potentials to
account for varying levels of radiative forcing of each gas relative to CO2 over a 100-year time
horizon. For methane, the EPA uses a global warming potential of 25, consistent with UNFCCC
reporting guidelines.1
Figure 2 U.S. Greenhouse Gas Emissions
(Million Metric Tons CO2e)
Source: EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2015
In 2015, United States greenhouse gas emissions totaled 6,587 million metric tons of carbon
dioxide equivalent (MMTe), down 2.3 percent from 2014 and down 9.9 percent from 2005.
Carbon dioxide from fossil fuel combustion accounts for the vast majority of annual GHG
emissions, constituting 82 percent of the total GHG.
Total CO2 emissions from fossil fuel combustion equaled 5,050 MMTe in 2015, which is 12
percent below 2005 levels. Petroleum combustion accounts for the largest amount of energy-
related CO2 emissions with a 43 percent share. Natural gas, for the first time, ranked second
among the fossil fuels in this category at 29 percent, followed by coal at 28 percent.
1 United Nations Framework Convention on Climate Change. The EPA uses a global warming potential of 25 for methane in accordance with the International Panel on Climate Change (IPCC) national inventory reporting guidelines. Higher global warming potentials have been published in the literature, including in fifth Assessment Reports from the IPCC. Using these higher factors would increase the contribution of methane to total greenhouse gases relative to CO2. Nevertheless, given the overwhelming contribution of CO2 emissions in the natural gas life cycle, even a significant upward change in methane’s global warming potential would not undermine the GHG benefits of using natural gas relative to other fossil energy sources.
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2,000
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1990 2005 2011 2012 2013 2014 2015
CO₂ CH4 N2O Other GHGs
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Figure 3 Share of carbon dioxide emissions from fossil fuel combustion 2015
Source: EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2015
Because the natural gas share of fossil fuel consumption has increased relative to coal, and given
the lower carbon emissions per unit of energy relative to coal, overall CO2 emissions since 2005
have trended downward.
Figure 4 Sources of Methane Emissions 2015
Source: EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2015
Methane is the second largest contributor to greenhouse gas emissions after CO2. Major
economic sectors that produce methane emissions are agricultural processes including livestock
management and rice cultivation, landfills, petroleum production, coal mining and natural gas
systems. Other major contributors include landfills, petroleum production, and coal mining. In
Coal28%
Natural Gas29%
Petroleum43%
0 50 100 150 200
Incineration of WasteIron and Steel Production & Metallurgical…
Silicon Carbide Production and…
Ferroalloy ProductionInternational Bunker FuelsPetrochemical Production
Field Burning of Agricultural Residues
Mobile CombustionComposting
Abandoned Underground Coal Mines
Stationary Combustion
Rice CultivationWastewater Treatment
Petroleum Systems
Coal MiningManure Management
LandfillsNatural Gas Systems
Enteric Fermentation
MMT CO2 Eq.
< 0.5< 0.5< 0.5< 0.5< 0.5< 0.5< 0.5
10%
Methane as a Portion of All Emissions
6
2015, methane emissions were 655 MMTe and accounted for 10 percent of all U.S. GHG
emissions.
Nitrous oxide (N2O) is the third largest contributor and results primarily from agricultural soil
management and mobile and stationary combustion. N2O emissions accounted for 6 percent of
total GHGs in 2015. Other GHGs include hydrofluorocarbons (HFCs), perfluorocarbons (PFCs),
and sulfur hexafluoride (SF6). Emissions of these gases together account for 3 percent of total
U.S. GHG.
Natural Gas System Methane Emissions
The U.S. natural gas system is comprised of thousands of wells and drilling rigs, well completion
equipment, numerous processing facilities, trillions of cubic feet of underground storage
capacity, millions of meters, and an extensive transmission and distribution network comprised
of 2.5 million miles of pipeline. The EPA categorizes this system into four stages: natural gas
field production, processing, transmission and storage, and distribution. Methane and, to a
lesser extent, CO2 are the two principal GHGs related to the operation of natural gas systems.
By the categorical conventions used in the Inventory, natural gas systems represent the second
largest source category for methane in the United States, constituting 24 percent of all methane
released, just behind Enteric Fermentation. In 2015, natural gas system methane emissions
equaled 162.4 MMTe or 2.5 percent of total U.S. greenhouse gases.
The largest share of natural gas system methane emissions stems from field production, which
accounts for 66 percent. Processing accounts for 7 percent; transmission and storage stage 21
percent; and distribution at 7 percent. Historical emissions for natural gas systems are listed in
Table 2.
Table 2 Methane Emissions from Natural Gas Systems
(million metric tons CO2e)
Source: EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2015
Natural gas system performance has improved significantly during the past two decades. New
control technologies and better industry practices have contributed to significant emissions
reductions, even as annual natural gas production and consumption have hit record highs. Since
1990, absolute methane emissions have declined 16 percent, even as gross natural gas
withdrawals climbed 53 percent.
1990 2005 2011 2012 2013 2014 20151990 -
2015
Field Production 70.6 95.2 104.5 106.9 106.3 108.2 106.6 51%
Processing 21.3 11.7 10.1 10.1 10.9 11.1 11.1 -48%
Transmission and Storage 58.6 30.7 28.8 27.9 30.8 32.0 33.7 -42%
Distribution 43.5 22.1 11.1 11.3 11.2 11.2 11.0 -75%
Total 194.1 159.7 154.5 156.2 159.2 162.5 162.4 -16%
7
Distribution System Methane Emissions
Natural gas distribution systems, owned and operated by natural gas utilities, deliver natural gas
to consumers through an extensive infrastructure comprised of 2.2 million miles of pipeline,
compressor stations, meter and regulating facilities, and other related equipment. Gas utilities
serve predominantly households and businesses and about 30 percent of natural gas volumes
consumed for electricity generation. In 2015, natural gas utilities delivered 58 percent of all
natural gas consumed across the country.
The distribution stage, which includes the regular operation and maintenance of natural gas
systems along with emissions releases from accidents, account for 7 percent of estimated
emissions from the whole natural gas industry. Categories of distribution emission sources
include leaks from natural gas pipelines, meters and regulators (M&R) stations, customer
meters, upsets (mishaps such as excavation damage), and releases during routine maintenance.
Gas utility companies reduce methane emissions each year through voluntary measures and are
reported to the EPA through its Natural Gas STAR program.
Overall, emissions from distribution systems have been improving even as the size of the system
has grown significantly. Methane emissions from distribution systems were 11.0 MMTe in 2015,
a decline of 75 percent from 1990 levels. This drop occurred even as the industry added 300,000
miles of distribution mains and an additional 300,000 miles of service lines (approximately
600,000 miles total) to serve 19 million more customers, a 37 and 35 percent increase in
pipeline mileage and customers respectively.
Table 3 Net and Potential Methane Emission Estimates from the Natural Gas Distribution Stag
and Reductions from the Natural STAR Program 2015
kt MMTe Share
Pipeline leaks* 231 5.8 48%
Meter/Regulator (City Gates)* 43 1.1 9%
Customer Meters 134 3.4 28%
Routine Maintenance 6 0.1 1%
Upsets 67 1.7 14%
Voluntary Reductions -41 -1.0
Net Emissions 439 11.0
Source: EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2015, Annex 3
Part A, Table A-148
*These values represent net emissions for these sources
Table 3 summarizes the breakdown in distribution methane emissions by source category. The
majority of distribution emissions are from pipeline leaks and meter/regulator operation.
Slightly less than half, 48 percent, of distribution system methane emissions are associated with
pipeline leaks, and 9 percent result from the operation of gas meter and regulators at city gates,
8
which connects the transmission system with the distribution network. Customer meters
account for 28 percent. Upsets and routine maintenance together comprise 14 percent.2
The historical reductions in this sector are the result of gas utility upgrades to distribution
infrastructure, improved leak surveys, and modernized designs. Pipeline networks have been
expanded and replaced with modern materials such as protected steel and plastics. Additionally,
operators have made significant upgrades and rebuilds to equipment at M&R stations.
Figure 5 reproduces the EPA estimates for pipeline leaks using EPA emission factors for pipeline
main and activity (mileage) data from the Department of Transportation. The same figure shows
the increasing trend in miles of installed main and the simultaneous decreasing trend in
emissions from main pipeline. It illustrates the nation’s natural gas utility industry’s expanding
service territory with a declining environmental footprint.
Figure 5 Pipeline Replacement Lowers Emissions
Source: AGA chart and calculations using data from
EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2015
The number of miles of installed main has increased 35 percent since 1990 and totaled 1.28
million miles in 2015. Even with this growth in distribution main pipe, estimated methane
emissions from pipeline leaks declined 75 percent during this period, a consequence of
increased removal of unprotected steel and cast iron pipe and replaced with plastic and
protected steel.3
2 Pipeline leaks are typically classified by the severity of the leak and the location to determine whether it represents an actionable condition for immediate repair. Grade 1 leaks require prompt action to protect life and property. Grade 2 leaks should be repaired within a set amount to time, typically on the order of one year. Grade 3 leaks are flagged to be reevaluated during survey schedules or until the leak is regraded or no longer results in a reading. 3 Estimated emissions are calculated using the new methodology employed in the 2016 Inventory and represent net emissions which reflect Gas STAR reductions. For the 2015 GHGI and previous inventories, estimates were potential emissions and did not reflect gas STAR reductions.
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015
Thousand Miles of Main
Million Metric Tons CO2 equivalent
Estimated Emissions from Main Pipe Installed Main Pipe
9
Unprotected steel and cast iron main pipeline emissions declined 10.4 MMTe from 1990 to
2015. Emissions from plastic main declined nearly 1 MMTe. Protected steel main emissions
increased 0.5 MMTe.
This exceptional record is because safety is the top priority for gas utilities who continue to be
vigilant and committed to systematically upgrading infrastructure through risk-based integrity
management programs. Today, there is a growing effort to accelerate the replacement of
pipelines no longer fit for service. Thirty-nine states and the District of Columbia have some
form of accelerated infrastructure replacement program or policy, which is helping reduce
emissions. It is because of these continuing efforts to modernize infrastructure and to enhance
pipeline safety that natural gas emissions from distribution are expected to continue to decline.
SUMMARY OF REVISIONS The EPA made substantial updates to its estimates of methane emissions in the Inventory of
U.S. Greenhouse Gases and Sinks: 1990-2015 using new data available from the EPA
Greenhouse Gas Reporting Program (GHGRP) and new studies.
Figure 6 Summary of Revisions to Natural Gas System Methane Estimates 2013
(MMT CO2e)4
Source: EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2013 (April 2015)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2014 (April 2016)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2015 (April 2017)
Environmental Protection Agency
4 Additional information on revisions to all oil and gas sector estimates may be found at: https://www3.epa.gov/climatechange/ghgemissions/usinventoryreport/natural-gas-systems.html
10
Updates to the distribution stage methodology resulted in a 66 percent or 22 MMTe downward
revision for methane emissions for year-end 2013, which is the most recent year that appears in
all three editions of the Inventory and thus data revisions can be compared (Figure 6). The
significant decline is due to the use of lower emissions factors for pipeline leaks and M&R
stations reported in a Washington State University study.5 Additional discussion follows in the
next section.
Estimates for field production increased 126 percent between the 2015 Inventory edition and
the 2017 Inventory edition due to the use of newly available data. EPA expanded its universe of
gathering stations, which were not included in prior inventories, following a new field study.6
Gathering facilities constituted the largest change with respect to the upward revision in field
production methane emissions. EPA used newly available data submitted annually under
subpart W of the Greenhouse Gas Reporting Program, which was used to develop activity factors
(counts per well) for in-line heaters, separators, dehydrators, compressors, meters/piping,
pneumatic pumps, and pneumatic controllers. In total, year-end 2013 estimates for production
emissions were revised upward by 59 MMTe.
Key data sources for the transmission and storage stage were updated as well, resulting in a 43
percent downward revision in emissions. EPA used a new field study on transmission and
storage to revise the activity data and emission factors for transmission and storage non-
compressor fugitive emissions.7 Estimated emissions for reciprocating compressors and
centrifugal compressors (wet seals) at transmission stations were revised downward and
constituted most the reductions. Overall emissions from this stage for year-end 2013 were
revised down by 24 MMTe.
New data collected through the EPA GHGRP for emissions from the processing stage were
incorporated into that segment’s methane emissions estimates in the 2017 Inventory. The net
result was a 52 percent decline in 2013 methane emissions relative to the 2015 Inventory.
The overall result was a 1.1 percent or 2 MMTe upward revision in 2013 methane emissions from
all natural gas systems relative to the 2015 Inventory.
Discussion of the Distribution Stage Revisions
The distribution segment emissions sources are categorized as meter and regulator stations,
pipeline leaks, customer meters, routine maintenance, and upsets. Estimates of emissions are
calculated using average emissions factors for specific source categories multiplied by the
activity data for that source.
5 Lamb et. al. “Direct Measurements Show Decreasing Methane Emissions from Natural Gas Local Distribution Systems in the United States.” 2015. http://pubs.acs.org/doi/abs/10.1021/es505116p 6 Marchese et. al. “Methane Emissions from United States Natural Gas Gathering and Processing.” 2015. http://pubs.acs.org/doi/abs/10.1021/acs.est.5b02275 7 Zimmerle, et. al. “Methane Emissions from the Natural Gas Transmission and Storage System in the United States.” July 2015. http://pubs.acs.org/doi/abs/10.1021/acs.est.5b01669
11
A number of emission factors and activity data sources were revised in the 2016 Inventory
edition to better account for substantial new data available on emissions from natural gas
distribution systems.
EPA incorporated new data and emission factors from a Washington State University study
published in 2015 (Lamb et. al.), which provides a more robust and current data set than the
prior 1992 GRI/EPA study, upon which prior inventory estimates were based. The research
team led by WSU reported a national sampling program from 13 natural gas utility systems that
resulted in direct measurements of 230 underground pipeline leaks and 229 metering and
regulating facilities. These measurements formed the basis for new emission factors for these
sources which are now used in the revised estimates of methane emissions from natural gas
distribution systems.
EPA incorporated the Lamb et. al. emission factors into its recalculations for pipeline leaks from
main and service lines and meter and regulator stations. Lamb et. al. emission factors were used
for the years 2011 to 2014. For the years between 1992 and 2011, a linear interpolation between
the 1992 GRI/EPA and the Lamb et. al. emission factors for each source category.
EPA also revised both emissions factors and activity data for customer meters, which as a
category is subdivided into residential and commercial, the later incorporating industrial
meters. Lamb et. al did not examine emissions from customer meters. Instead, EPA
incorporated the results of a 2009 Gas Technology Institute Study and a Clearstone report.8,9
EPA revised the activity data for customer meters by using data on customer counts reported by
the Energy Information Administration from its EIA-176 survey. The effect was a modest
increase in emissions.
EPA made no changes to the emission factors for routine maintenance or mishaps categories. A
summary of the changes to the distribution stage emission factors can be found in Table 4 (next
page).
Finally, EPA sought to include estimates to account for methane released from the Aliso Canyon
natural gas storage field leak that began in the fall of 2015. EPA included estimates of emissions
released from the Aliso Canyon based on official estimates developed by the California Air
Resources Board and pro-rated for 2015. The additional emissions, which totaled 2.0 MMTe,
were added to the transmission and storage stage and accounted for about 6 percent of total
emissions for this segment.
8 Gas Technology Institute and Innovative Environmental Solutions, Field Measurement Program to Improve Uncertainties for Key Greenhouse Gas Emission Factors for Distribution Sources, November 2009. GTI Project Number 20497. OTD Project Number 7.7.b. 9 Clearstone Engineering, Development of Updated Emission Factors for Residential Meters, May 2011
12
Table 4
Emission Factors for the Natural Gas Distribution Stage
Source: EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2015
2015 EPA
Inventory
(Old)
2017 EPA
Inventory
(New)
Percent
ChangeUnits
Pipeline Leaks*
Mains—Cast Iron 238.70 60.09 -75% Mscf/mile-yrc,bb
Mains—Unprotected steel 110.19 44.72 -59% Mscf/mile-yrc,bb
Mains—Protected steel 3.07 5.02 64% Mscf/mile-yrc,bb
Mains—Plastic 9.91 1.5 -85% Mscf/mile-yrc,bb
Services—Unprotected steel 1.70 0.75 -56% Mscf/servicec,bb
Services Protected steel 0.18 0.07 -61% Mscf/servicec,bb
Services—Plastic 0.01 0.01 0% Mscf/servicec,bb
Services—Copper 0.25 0.25 0% Mscf/serviceb
Meter/Regulator (City Gates)*
M&R >300 179.80 12.7 -93% scfh/stationc,d,bb
M&R 100-300 95.60 5.9 -94% scfh/stationc,d,bb
M&R <100 4.31 4.31 0% scfh/stationb
Reg >300 161.90 5.15 -97% scfh/stationc,d,bb
R-Vault >300 1.30 0.3 -77% scfh/stationc,d,bb
Reg 100-300 40.50 0.85 -98% scfh/stationc,d,bb
R-Vault 100-300 0.18 0.3 67% scfh/stationc,d,bb
Reg 40-100 1.04 0.97 -7% scfh/stationc,d,bb
R-Vault 40-100 0.09 0.3 233% scfh/stationc,d,bb
Reg <40 0.13 0.13 0% scfh/stationb
Customer Meters
Residential 143.27 77.31 -46% scfy/meterb,c
Commercial/Industry 47.90 505.4 955% scfy/meterb,c
Routine Maintenance
Pressure Relief Valve Releases 0.05 0.05 0% Mscf/mileb
Pipeline Blowdown 0.10 0.1 0% Mscfy/mileb
Upsets
Mishaps 1.59 1.59 0% Mscfy/mileb
b EPA/GRI (1996), Methane Emissions from the Natural Gas Industry
c EPA (2016d)
d 2014 GHGRP – Subpart W data
f EIA (2015d, 2015e, 2015f) – Number of Consumers (Residential, Commercial, and Industrial)
bb Emission factors represent actual emissions and can be used to calculate emissions directly.
1 Activity data for 2014 available from source.
2 Ratios relating other factors for which activity data are available.
*The values in this table are net emissions for these sources.
a Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS)
aa Emission factors listed in this table are for potential emissions (unless otherwise indicated in a
13
CALCULATION OF METHANE EMISSIONS RATE OF PRODUCTION What do these levels of natural gas system methane emissions mean in the context of rapidly
growing production? The following analysis calculates an effective emissions rate of production
or the amount of methane released for each unit of natural gas produced at the wellhead. Many
groups use this metric as a benchmark for natural gas system performance. The calculation can
be made using EPA estimates for methane emissions from natural gas systems and statistics on
annual natural gas production volumes from the U.S. Energy Information Administration (EIA).
The section steps through these calculations to derive a value for the emissions rate of
production and examine how it has changed over time.
Using the EPA Inventory, natural gas systems released 6,497 kilotons of methane in 2015, which
is equivalent to 339 Bcf.10 This value includes emissions from natural gas wells only. Therefore,
it is appropriate to also account for methane emissions from petroleum production given that 20
percent of produced natural gas came from oil wells in 2015.
We attribute a portion of methane emissions from petroleum production to the natural gas value
chain based on the ratio of natural gas to other produced liquids and gases from oil wells.11 The
natural gas fraction of total energy content (oil plus natural gas) from oil wells was 25 percent in
2015.12 Applying this factor to total petroleum system methane emissions, we count 35 Bcf of
methane from petroleum production as attributable to the natural gas value chain.
Using EIA data for U.S. gross natural gas withdrawals of 32,985 Bcf in 2015 and assuming a
methane content of 90 percent for natural gas, we calculate:
339 𝐵𝑐𝑓 + 20 𝐵𝑐𝑓
32,985 𝐵𝑐𝑓∗
1
90%= 1.2%
The calculated emissions rate of 1.2 percent is far below earlier estimates of 2.2 to 2.4 percent
derived using data from prior EPA Inventories, and far below other studies that peg emissions
rate even higher.
10 Using 0.01917 kg CH4 per scf. 11 This analysis assigns a portion of petroleum system methane emissions from natural gas production out of oil wells to the natural gas system. This contribution is small compared with combustion-related CO2. Furthermore, these emissions should be considered an upper bound since it is not clear that the petroleum system methane emissions would not have occurred otherwise if marketable natural gas was not part of the oil well production. In many cases, the oil well would likely still be produced and the non-marketed natural gas would have been vented or flared, thus contributing to the petroleum system footprint and not the natural gas value chain. 12 Calculated using the gas fraction of total energy from oil wells. Gross natural gas withdrawal from oil wells was 5.9 Tcf in 2012. Crude oil production was 3.2 billion barrels. Energy equivalency conversions assumed: 1,030 cf / MMbtu for natural gas and 5.8 MMBtu / bbl.
14
Table 5 Historical Natural Gas Emissions Rate of Production
1990 2005 2011 2012 2013 2014 2015
2.2% 1.7% 1.4% 1.4% 1.3% 1.3% 1.2%
Source: EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2015
Energy Information Administration & AGA calculations
Applying this methodology using data from prior years, one can see that the emissions rate of
production has steadily decreased during the past two decades, down from 2.2 percent in 1990
(see Table 5).
Similarly, one can examine the methane emissions per unit of natural gas produced. Instead of a
percentage ratio, as shown previously, we calculate the kilograms of methane emissions released
per unit of gross natural gas withdrawals (including attribution of a portion of petroleum system
methane emissions). This ratio serves as a measure of the efficiency of natural gas production as
it relates to methane emissions.
During the past two decades, annual methane released from natural gas systems has declined as
production has risen. As Figure 7 shows, the ratio of these two values, methane emissions per
unit of natural gas produced, has declined continuously during the past two and a half decades,
dropping 46 percent since 1990.
Figure 7 Methane Emissions per Mcf of Natural Gas Produced
kG CO2e/Mcf Gross Withdrawals
Source: EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2015
Energy Information Administration & AGA calculations
Part of this improvement is the application of better industry practices, advances in technology,
and investments in lower-emitting equipment and infrastructure. This evolution toward better
practices is further evidenced by the shift toward unconventional resource production, which
has spurred the use of new extraction and control technologies. Furthermore, industry
participation in EPA’s voluntary program Natural Gas STAR has been instrumental in advancing
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20
12
20
13
20
14
20
15
15
cost-effective technologies and practices to control methane emissions. We anticipate that
control technologies for methane emissions will continue to improve and proliferate over time.
The distribution system share of industry-wide emissions is 6 percent. Therefore, an effective
emissions rate of production for distribution system natural gas emissions is less than 0.1%.
The industry and many of its observers routinely reference a natural gas emissions rate of
production as the preferred metric by which to account for emissions in relation to industry
activity. As such, it is entirely appropriate to use a similar metric for distribution systems to
maintain consistency with metrics applied to the entire value chain. However, there are
alternative metrics, some of which are laid out below. For example, another approach would be
to take the ratio of distribution system emissions and LDC throughput. A series of emissions
ratios are laid out below, and details behind the calculations can be found in the Appendix.
Table 6
Distribution System Emission Ratios
Natural Gas System Emissions as % of
Production 0.08%
Consumption 0.10%
Volumes to Consumers 0.11%
LDC Volumes to Consumers 0.18% Source: EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2015 Energy Information Administration & AGA calculations. CONCLUSION This analysis characterized new estimates for methane emissions and the implications for the
GHG profile of natural gas. The EPA Inventory affirms a low methane emissions profile for
natural gas distribution systems shaped by a declining trend.
The picture of emissions from natural gas systems is continuously evolving and becoming more
refined. Improved science and systematic data collection are essential to inform the public
debate about the effect of natural gas use on the climate and to support recognition of the
benefits of using natural gas to reduce greenhouse gas emissions.
The EPA Inventory is a continuous work in progress. Trends in natural gas system emissions are
markers that signify directionally how new information better informs understanding of the
GHG profile of natural gas production and use. New information will continue to refine the
emissions estimates in the Inventory and will offer to industry, the public, and policymakers a
better understanding where emissions occur and the levels of released methane. Better
information helps focus attention on cost-effective opportunities identified in the data.
AGA and its members are committed to supporting studies to collect accurate measurements of
emissions from natural gas utility operations. Starting in 2013, a group of 13 natural gas utilities
engaged with a research team from the Washington State University on a project to collect new
data on distribution system emissions. This work, which identified and quantified equipment-
specific leaks, formed the basis the revisions to distribution system emissions found in the
16
current EPA Inventory. In addition to this critical research, other studies have examined
emissions from other stages of the natural gas value chain, some of which were also
incorporated into this year’s Inventory. Further ongoing data collection and analysis from the
government, academia, and industry will help to inform better public understanding of natural
gas methane emissions and the role natural gas plays in reducing emissions and addressing
climate.
In addition to improvements in estimated emissions from natural gas systems, actual reductions
are expected to continue. To share three supporting examples: Currently, thirty-nine states and
the District of Columbia have policies or programs to accelerate the replacement of distribution
infrastructure, which in turn reduces emissions from pipes deemed not fit for service. In March
2016, 41 natural gas companies pledged support as founding partners for EPA’s Methane
Challenge Program to achieve emissions reductions through a voluntary best management
practice commitment framework. And EPA air standards mandating industry adoption of
reduced emission completions (RECs) went into effect in 2015 and will improve capture of
methane at the wellhead.
All told, because of improvements in technology, ongoing science, and understanding of existing
the trends reported by EPA, signs point to a continuously improving emissions profile of the
natural gas industry and help lay the foundation for natural gas as a critical component of the
energy mix for years to come.
17
APPENDIX A.1 CALCULATION OF EMISSIONS RATES
Table 7
Source: EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2015 Energy Information Administration & AGA calculations
Relevant Source
[A] CH4 Natural Gas Systems (Bcf) 339 EPA
[B] NG Fraction of Total Energy Content from Oil & Gas Production 25% EIA
[C] CH4 Petroleum Production Field Operations 81
[D] = [B] * [C] NG Fraction of CH4 from Petroleum Production Field Operations, Net (Bcf) 35 EIA, EPA
[E] U.S. Gross Natural Gas Production (Bcf) 32,895 EIA
[F] Methane Content of U.S. Pipeline NG 90% AGA Estimate
([A]+[C])/([D]*[E]) Natural Gas Leakage - NG System as % of Total NG Production 1.21% Calculation
[F] Methane Emissions - Distribution Systems (Bcf) 23 EPA
[G] U.S. Natural Gas Consumption (Bcf) 27,306
[H] U.S. Natural Gas Volumes Delivered to Consumers (Bcf) 25,072
[I] LDC Natural Gas Volumes Delivered to Consumers (Bcf) 14,454
[K] Methane Content of Distribution System Natural Gas 90% AGA Estimate
Natural Gas Leakage - Distribution Systems as % of
[F] / ([D] * [K]) Production 0.08%
[F] / ([G] * [K]) Consumption 0.09%
[F] / ([H] * [K]) Volumes Delivered to Consumers 0.10%
[F] / ([I] * [K]) LDC Volumes Delivered to Consumers 0.18%
Emissions Rates Calculations Based on EPA Inventory (2015)
EIA
Calculation
18
A.2 Table 8
2015 Data and Methane Emissions (Mg) for the Natural Gas Distribution Stage
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION (PHMSA), OFFICE OF PIPELINE SAFETY (OPS) (2013) B EPA/GRI (1996), METHANE EMISSIONS FROM THE NATURAL GAS INDUSTRY C EPA (2016D) D 2014 GHGRP – SUBPART W DATA F EIA (2015D, 2015E, 2015F) – NUMBER OF CONSUMERS (RESIDENTIAL, COMMERCIAL, AND INDUSTRIAL) AA EMISSION FACTORS LISTED IN THIS TABLE ARE FOR POTENTIAL EMISSIONS (UNLESS OTHERWISE INDICATED IN A FOOTNOTE). SEE
DETAILED EXPLANATION OF METHODOLOGY ABOVE. BB EMISSION FACTORS REPRESENT ACTUAL EMISSIONS AND CAN BE USED TO CALCULATE EMISSIONS DIRECTLY. 1 ACTIVITY DATA FOR 2014 AVAILABLE FROM SOURCE. 2 RATIOS RELATING OTHER FACTORS FOR WHICH ACTIVITY DATA ARE AVAILABLE. *THE VALUES IN THIS TABLE ARE NET EMISSIONS FOR THESE SOURCES.
Source: EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2015
Activity
Calculated
Potential
Emissions (kt)
Pipeline Leaks*
Mains—Cast Iron 27,770 milesa,1 60.09 Mscf/mile-yrc,bb 32,137
Mains—Unprotected steel 55,863 milesa,1 44.72 Mscf/mile-yrc,bb 48,116
Mains—Protected steel 484,749 milesa,1 5.02 Mscf/mile-yrc,bb 46,899
Mains—Plastic 706,594 milesa,1 1.5 Mscf/mile-yrc,bb 20,383
Services—Unprotected steel 3,297,457 servicesa,1 0.75 Mscf/servicec,bb 47,769
Services Protected steel 14,330,139 servicesa,1 0.07 Mscf/servicec,bb 18,561
Services—Plastic 47,517,936 servicesa,1 0.01 Mscf/servicec,bb 12,497
Services—Copper 895,398 servicesa,1 0.25 Mscf/serviceb 4,386
Meter/Regulator (City Gates)* -
M&R >300 4,026 stationsc,d,2 12.7 scfh/stationc,d,bb 8,626
M&R 100-300 14,692 stationsc,d,2 5.9 scfh/stationc,d,bb 14,625
M&R <100 7,853 stationsc,d,2 4.31 scfh/stationb 5,710
Reg >300 4,402 stationsc,d,2 5.15 scfh/stationc,d,bb 3,825
R-Vault >300 4,328 stationsc,d,2 0.3 scfh/stationc,d,bb 219
Reg 100-300 13,316 stationsc,d,2 0.85 scfh/stationc,d,bb 1,910
R-Vault 100-300 12,060 stationsc,d,2 0.3 scfh/stationc,d,bb 610
Reg 40-100 39,958 stationsc,d,2 0.97 scfh/stationc,d,bb 6,539
R-Vault 40-100 8,144 stationsc,d,2 0.3 scfh/stationc,d,bb 412
Reg <40 16,943 stationsc,d,2 0.13 scfh/stationb 380
Customer Meters
Residential 53339363 Outdoor meterse 77.31 scfy/meterb,c 79,424
Commercial/Industry 5611121 meterse 505.4 scfy/meterb,c 54,619
Routine Maintenance
Pressure Relief Valve Releases 1264340 milemaina,1 0.05 Mscf/mileb 1,228
Pipeline Blowdown 2168588 milesb,2 0.1 Mscfy/mileb 4,304
Upsets
Mishaps (Dig-ins) 2168588 milesb,2 1.59 Mscfy/mileb 67,091
Regulatory Reductions (kt)
Voluntary Reductions (kt) -41.2
Total Reductions (kt) -41.2
Total Potential Emissions (kt) 480.3
Total Net Emissions (kt) 439.1
2015 EPA Inventory Values
Activity Data Emissions Factor
19
A.3 – Estimated Emissions from Distribution Main Pipeline Calculations
Table 9 Miles of Distribution Main Pipeline
Year Steel
Unprotected Bare
Steel Unprotected
Coated
Steel Cathodically
Protected Bare
Steel Cathodically
Protected Coated
Plastic Cast/Wrought
Iron Total Miles
1990 74,212 34,729 26,353 439,185 311,386 58,292 945,964
1991 74,142 28,674 20,455 453,272 255,681 56,158 891,352
1992 72,279 27,340 23,657 445,449 267,283 52,917 892,014
1993 72,215 27,120 22,768 458,934 293,547 54,190 931,410
1994 73,834 25,390 24,280 485,021 333,689 58,148 1,002,669
1995 71,060 22,998 23,613 479,675 353,735 50,625 1,003,798
1996 66,489 21,923 41,705 442,821 350,699 51,542 1,001,771
1997 63,630 21,536 19,637 459,641 385,373 47,669 1,003,085
1998 65,273 21,366 30,530 454,433 400,627 47,587 1,022,086
1999 62,795 21,739 14,891 444,407 415,210 45,865 1,007,459
2000 62,124 20,731 14,874 454,432 447,586 44,726 1,046,790
2001 62,062 19,164 16,482 456,796 496,504 44,270 1,097,623
2002 64,662 17,948 15,338 472,152 525,815 45,523 1,144,665
2003 53,754 17,727 15,141 466,749 501,278 40,588 1,097,911
2004 57,297 18,554 18,682 470,417 531,365 40,581 1,139,663
2005 54,655 17,715 14,817 452,957 535,338 39,758 1,117,784
2006 52,683 19,111 14,651 468,174 619,427 37,129 1,214,042
2007 51,772 19,020 13,650 474,925 601,947 37,669 1,201,138
2008 51,077 19,247 12,923 472,994 610,832 36,815 1,205,991
2009 47,740 19,528 13,147 470,813 620,610 35,429 1,209,486
2010 49,639 16,205 17,303 465,832 619,360 34,462 1,204,432
2011 48,155 15,937 14,176 474,002 644,749 33,586 1,232,278
2012 47,692 16,037 13,647 473,545 661,139 32,418 1,246,251
2013 43,892 16,724 12,971 473,263 674,207 30,888 1,253,661
2014 41,824 16,671 12,603 473,210 689,077 29,358 1,264,318
2015 39,920 15,910 12,019 472,433 705,837 27,726 1,275,747
Source: Department of Transportation Form 7100
20
Table 10
EPA Emissions Factors for Distribution Pipeline Main by Material
Source: Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2015
EFs between 1992 and 2011 is linearly interpolated using EFs from 1992 GRI and Lamb et. al.,
Cast
Iron
Unprotected
Steel
Protecte
d Steel Plastic
1990 238.70 110.19 3.07 9.91
1991 238.70 110.19 3.07 9.91
1992 238.70 110.19 3.07 9.91
1993 229.30 106.74 3.17 9.47
1994 219.90 103.30 3.28 9.02
1995 210.50 99.85 3.38 8.58
1996 201.10 96.41 3.48 8.14
1997 191.70 92.96 3.58 7.70
1998 182.30 89.52 3.69 7.25
1999 172.90 86.07 3.79 6.81
2000 163.50 82.62 3.89 6.37
2001 154.10 79.18 3.99 5.93
2002 144.69 75.73 4.10 5.48
2003 135.29 72.29 4.20 5.04
2004 125.89 68.84 4.30 4.60
2005 116.49 65.39 4.40 4.16
2006 107.09 61.95 4.51 3.71
2007 97.69 58.50 4.61 3.27
2008 88.29 55.06 4.71 2.83
2009 78.89 51.61 4.81 2.39
2010 69.49 48.17 4.92 1.94
2011 60.09 44.72 5.02 1.50
2012 60.09 44.72 5.02 1.50
2013 60.09 44.72 5.02 1.50
2014 60.09 44.72 5.02 1.50
2015 60.09 44.72 5.02 1.50
Mscf/mile-yr
21
Table 11 Installed Pipeline Main and Estimated Potential Emissions from Main Pipe
Source: Department of Transportation Form 7100
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2014
AGA Calculations
Installed Main
Pipe
Estimated
Emissions from
Main Pipe
(Thousand Miles) (MMTe)
1990 946 14.6
1991 891 13.8
1992 892 13.3
1993 931 13.2
1994 1,003 13.3
1995 1,004 11.9
1996 1,002 11.3
1997 1,003 10.5
1998 1,022 10.2
1999 1,007 9.5
2000 1,047 9.1
2001 1,098 8.7
2002 1,145 8.5
2003 1,098 7.3
2004 1,140 7.2
2005 1,118 6.6
2006 1,214 6.2
2007 1,201 5.8
2008 1,206 5.4
2009 1,209 4.9
2010 1,204 4.4
2011 1,232 4.0
2012 1,246 4.0
2013 1,254 3.9
2014 1,264 3.8
2015 1,276 3.7
22
Prepared by the American Gas Association
400 North Capitol Street NW
Washington, DC 20001
(202)-824-7000
www.aga.org
Principal Author
Richard Meyer
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