Greenhouse Gas Emissions
from Fossil Energy Extracted
from Federal Lands and Waters
Final Report
Prepared for:
The Wilderness Society
1615 M Street NW
Washington, DC 20036
Greenhouse Gas Emissions
from Fossil Energy Extracted
from Federal Lands and Waters
Final Report
Prepared for:
The Wilderness Society
1615 M Street NW
Washington, DC 20036
Prepared by:
Stratus Consulting Inc.
PO Box 4059
Boulder, CO 80306-4059
303-381-8000
1920 L St. NW, Suite 420
Washington, DC 20036
Contacts:
Heidi Ries
Joseph Donahue
February 1, 2012
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Executive Summary
In April 2011, the Council on Environmental Quality (CEQ) released the first-ever Greenhouse
Gas Emissions Inventory for the Federal Government. The report presents the total estimated
greenhouse gas (GHG) emissions resulting from federal government agencies’ operations,
including emissions from building electricity and water consumption, employee travel, and
numerous other activities. According to the report, these emissions totaled approximately
66.4 million metric tons of carbon dioxide equivalent (MMTCO2e) in 2010. However, the
inventory does not account for emissions associated with a range of activities that are under
federal government control but are conducted by private entities. Such activities include
exploration, production, and development of fossil fuel resources on or beneath federal lands and
waters by private sector leaseholders. As this report shows, omitting GHG emissions from
private sector activities that are dependent on federal government leasing results in a substantial
underestimation of GHG emissions associated with federal agency operations.
The primary purpose of the analysis described in this report was to develop a preliminary
quantitative estimate of the magnitude of ultimate GHG emissions (including carbon dioxide,
methane, and nitrous oxide) associated with these activities (i.e., the quantity of greenhouse
gases emitted if, for example, coal mined from federal lands was combusted downstream in
various applications, such as in coal-fired power plants). A second component of this analysis
involved assembling information on the different types of indirect emissions associated with
these activities (e.g., emissions from vehicles used at a natural gas production site). This report
includes a brief assessment of the magnitude of these indirect emissions, but does not attempt
quantify them.
In 2009, the most recent year for which total U.S. GHG emissions data are available, the ultimate
downstream GHG emissions from fossil fuel extraction from federal lands and waters by private
leaseholders could have accounted for approximately 23% of total U.S. GHG emissions and 27%
of all energy-related GHG emissions. This estimate does not account for the large number of
indirect emissions sources – identified in this report – that span the entire productionconsumption continuum.
This analysis suggests that ultimate GHG emissions from fossil fuels extracted from federal
lands and waters by private leaseholders in 2010 could be more than 20-times larger than the
estimate reported in the CEQ inventory. Overall, ultimate downstream GHG emissions resulting
from fossil fuel extraction from federal lands and waters by private leaseholders in 2010 are
estimated to total 1,551 MMTCO2e. The majority of the 2010 emissions comes from leases for
extracting coal (57% of the total), followed in magnitude by offshore oil (16%), onshore natural
gas (10%), offshore natural gas (9%), and a combination of onshore oil, coalbed methane, and
natural gas liquids (collectively approximately 7%).
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The magnitude of the ultimate and indirect emissions resulting from fossil fuel extraction from
federal lands and waters by private leaseholders suggests that their exclusion from the CEQ’s
federal government inventory may result in an underestimate of the impact of GHG emissions
from federal government programs, which in turn could lead to missed opportunities to more
fully account for GHG emissions from federal government programs.
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Introduction
In April 2011, the Council on Environmental Quality (CEQ) released the first-ever Greenhouse
Gas Emissions Inventory for the Federal Government: 2010 Data (CEQ, 2011). The report
presents the total estimated greenhouse gas (GHG) emissions resulting from federal government
agencies’ operations, including emissions from building electricity and water consumption,
employee travel, and numerous other activities. However, the inventory does not account for
emissions associated with a range of activities that are under federal government agency control
but are conducted by private entities. Such activities include exploration, production, and
development of fossil fuel resources on federal lands1 by private sector leaseholders. Accounting
for these activities could increase the federal government’s total emissions of GHGs
substantially.
This report describes an analysis conducted by Stratus Consulting on behalf of The Wilderness
Society to develop a preliminary quantitative estimate of the magnitude of ultimate GHG
emissions associated with fossil fuels (i.e., onshore and offshore oil and natural gas, natural gas
liquids, coal, and coalbed methane) extracted by leaseholders2 from federal lands (this report
does not address GHG emissions resulting from wind, solar, geothermal, or biomass activities).3
In addition, the report provides an overview of the many types of indirect emissions that can
result from these activities (e.g., emissions resulting from transporting fossil fuels from federal
lands to refineries).
1. In this report, the term “federal lands” includes all offshore areas that are leased to private companies by the
federal government as well as the onshore lands.
2. This report focuses on GHG emissions resulting from the extraction of fossil fuels from federal lands by
private companies holding leases for these purposes (even in instances where the federal government holds
subsurface rights but does not hold surface rights). As such, this report does not account for emissions
resulting from extraction of fossil fuels in instances where the federal government owns the surface rights but
private or other government entities own the subsurface rights.
3. This report only covers a subset of energy extraction activities on federal lands and waters. It is focused on
fossil fuel extraction from federal lands where subsurface leasing is managed by the U.S. Department of the
Interior (DOI). The DOI, manages subsurface leasing for all federal lands, including public lands under the
jurisdiction of the Bureau of Land Management and other lands under the jurisdiction of other federal surface
management agencies (e.g., the Forest Service). The data collected from DOI sources for this analysis includes
information on all leases that are managed by the DOI.
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1.1 Background
Federal lands and waters supply a
considerable portion of the nation’s fossil
energy resources, including approximately
44% of produced coal, 36% of crude oil, and
18% of natural gas.4 Rather than developing,
extracting, transporting, and converting these
resources directly, federal agencies typically
operate through permits, leases, contracts, and
concessions to private sector firms.
Total U.S. GHG emissions and emissions
related to energy consumption
The U.S. Environmental Protection Agency (EPA)
produces a top-down GHG inventory every year
that provides estimates of the nation’s source- and
sector-specific emissions of carbon dioxide (CO2),
methane (CH4), nitrous oxide (N2O), and other
GHGs. According to the 2011 inventory, GHG
emissions in the United States in 2009 (the most
recent year for which data are available) totaled
approximately 6,600 million metric tons of carbon
dioxide equivalent (MMTCO2e). Energy-related
GHG emissions totaled 5,800 MMTCO2e.
Executive Order (E.O.) 13514, Federal
Leadership in Environmental, Energy, and
Economic Performance (74 Federal Register
52117, October 9, 2009; The White House
Source: U.S. EPA, 2011a.
Office of the Press Secretary, 2009), directed
federal agencies to meet a range of energy, water, and waste reduction targets. The order
included requirements that federal agencies inventory, report, and adopt targets for reducing their
direct and indirect GHG emissions. The CEQ developed the Federal Greenhouse Gas
Accounting and Reporting Guidance (CEQ, 2010b) to provide federal agencies with clear
information on what emissions fall within the scope of E.O. 13514 and how these emissions
should be calculated. The guidance included information on how to quantify emissions resulting
from a range of emissions categories. Table 1 lists the GHG emissions source categories
included in the guidance and ultimately accounted for in the federal government inventory.
Federal government agencies reported their emissions for 2010 and the results were made public
in April 2011.
In the first Greenhouse Gas Emissions Inventory for the Federal Government: 2010 Data, the
CEQ estimated that GHG emissions from federal government operations totaled approximately
66.4 MMTCO2e in 2010. According to the inventory, DOI, which is responsible for managing a
significant majority of federal fossil fuel leases, contributed approximately 1.3 MMTCO2e
(CEQ, 2011).
4. These estimates are based on the data for fossil fuel produced from federal lands that were collected for this
analysis (BLM, 2011; BOEMRE, 2011; ONRR, 2011), and data on total fossil fuel production for the entire
United States (EIA, 2011c, 2011d, 2011e). The estimates were produced using 2009 data, the most recent year
for which complete information is available from all sources.
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Table 1. Sources of emissions accounted for in the Greenhouse
Gas Emissions Inventory for the Federal Government: 2010
Data, released by the CEQ in April 2011
On-site fuel combustion
Non-highway vehicles, aircraft, ships, and equipment
Passenger fleet vehicles
Fluorinated gases and other fugitive emissions
On-site wastewater treatment
On-site landfills, solid waste facilities, and incinerators
Manufacturing and industrial process emissions
Purchased electricity
Purchased biomass energy
Purchased steam and hot water
Purchased chilled water
Purchased combined heat and power electricity, steam, and hot water
Transmission and distribution losses from purchased electricity
Federal employee business air travel
Federal employee business ground travel
Federal employee commuting
Off-site wastewater treatment
Off-site solid waste disposal
Source: CEQ, 2011.
However, the CEQ guidance did not include requirements for reporting emissions associated
with activities that are under federal agency control but are conducted by private entities
(including fossil fuel extraction on federal lands). Federal government agencies, therefore, did
not estimate these emissions in the reports they compiled for the inventory.5
5. This is not to say that federal agencies are not required to account for GHG emissions under other
obligations. For example, federal agencies are obligated under the National Environmental Policy Act (NEPA),
42 U.S.C. § 4321, et seq., to analyze the impacts from major federal actions that have significant impacts on
the environment, including the impacts on global climate change [however, emissions resulting from federal
leasing are not explicitly addressed in the NEPA guidance for federal agencies (CEQ, 2010a)]. Agencies
within the DOI are additionally bound by Secretarial Order 3289, which requires the analysis of potential
climate change impacts when undertaking planning, setting priorities for scientific research, developing
management plans, and making major decision regarding the potential use of resources.
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1.2 Overview
The remainder of this report is structured as follows:

Section 2 – Methodology. This section describes the methodology used in the analysis. It
includes an overview of the process used to quantify ultimate GHG emissions from fossil
fuel extraction from federal lands by private leaseholders. It also includes an explanation
of the approach used to identify types of indirect emissions of GHGs resulting from these
activities.

Section 3 – Results. This section summarizes the results of the quantitative analysis of
ultimate GHG emissions resulting from the extraction of fossil fuels from federal lands
by private leaseholders. It provides fuel-, location-, year-, and GHG-specific estimates. It
also includes a comprehensive list of the types of indirect emissions resulting from fossil
fuel extraction from federal lands by private leaseholders and a brief analysis of the
magnitude of these indirect emissions, which provides helpful information on the overall
scale of indirect emissions that could be accounted for in a robust calculation.

Section 4 – Conclusions. This section presents key points based on the analysis described
in this report.

References. This section includes references cited in the report.

Appendix – Sources of Indirect Emissions in the Oil and Gas Industry. This appendix
includes a comprehensive list of the specific indirect emissions that can result from oil
and natural gas extraction in general, including emissions spanning the exploration,
production, refinement, and transportation continuum. This list is drawn from the
American Petroleum Institute’s Compendium of Greenhouse Gas Emissions
Methodologies for the Oil and Gas Industry (API, 2009).
2.
Methodology
This section describes the methodology used for this analysis. It includes an overview of the
process used to quantify ultimate GHG emissions from fossil fuel extraction from federal lands
by private leaseholders. It also includes an explanation of the approach used to identify types of
indirect emissions of GHGs resulting from these activities.
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2.1 Methodology for Quantifying Ultimate GHG Emissions
from Fossil Fuel Extraction from Federal Lands by
Private Leaseholders
Quantifying ultimate GHG emissions from fossil fuel extraction from federal lands by private
leaseholders involved two broad steps: data collection and data processing. This section
describes the steps involved in each step.
2.1.1
Data collection
This section describes the data collection portion of the analysis, including the types of data
collected and the data sources.
Quantities of fossil fuels extracted from federal lands by private leaseholders
The primary data collection effort involved gathering information on the quantities of fossil fuels
extracted from federal lands by private leaseholders, based on reports by federal government
agencies. The data include the quantity of fuel extracted by relevant metric (e.g., barrels of oil,
cubic feet of natural gas, and short tons of coal), the year,6 and the state in which the lease is held
(or region, in the case of offshore data). Data were collected for the following fossil fuels:
onshore and offshore oil, onshore and offshore natural gas, natural gas liquids, coal, and coalbed
methane.7 Data were collected for three years: 2008, 2009, and 2010.
Data were collected from different DOI sources. Table 2 provides a list of these sources by fossil
fuel type.
Table 2. Sources of data on quantities of fossil fuels produced from federal leases
Fossil fuel
Oil, natural gas (onshore),
and natural gas liquids
Coal and coalbed methane
Oil and natural gas
(offshore)
Federal government agency and program
DOI, BLM – Public Land Statistics: Federal Coal Leases (BLM, 2011)
DOI, Office of Natural Resources Revenue – Reported Royalty Revenues
(ONRR, 2011)
DOI, Bureau of Ocean Energy Management, Regulation, and Enforcement –
Outer Continental Shelf Oil and Gas Production (BOEMRE, 2011)
6. This analysis uses the calendar year as its unit of temporal measure.
7. For onshore oil, onshore natural gas, natural gas liquids, coal, and coalbed methane, quantities were only
available in terms of sales volume (as indicated in royalty reports), rather than production volume. In theory,
sales volumes for a given year can be smaller or larger than production volumes for that year because
companies can vary sales depending on market conditions. For offshore oil and natural gas, quantities were
available in terms of production volume.
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Energy flows
In addition to data on fossil fuel extraction, information was gathered that would allow the
quantities of fuel to be matched to specific downstream combustion methods, each of which has
a distinct set of emissions factors for key GHGs.8 The importance of this fuel type-combustion
method matching is further discussed in the following section. The Energy Information
Administration (EIA) produces an Annual Energy Review that provides estimates of the
percentage of all fossil fuel-specific energy consumed by each end sector (including
transportation, residential, commercial, industrial, and electric power generation). These
estimates were collected for the years 2008, 2009, and 2010 (EIA, 2009b, 2010, 2011b).
Emissions factors
To determine the quantity of GHGs emitted for each unit of fossil fuel extracted, emissions
conversion factors were identified. The most widely accepted emissions factors used to calculate
GHG emissions are provided in the Intergovernmental Panel on Climate Change’s (IPCC’s)
IPCC Guidelines for National Greenhouse Gas Inventories (IPCC, 2006). These guidelines
include tables that present estimates of the quantity of CO2, CH4, and N2O emitted (in kilograms)
for every terajoule (a measure of energy content) of energy consumed. These tables include
fossil fuel- and combustion type-specific emissions factors. For example, they provide emissions
factors to estimate the kilograms of CH4, CO2, and N2O emitted for every terajoule of energy
consumed from burning sub-bituminous coal in a coal-fired power plant for electricity
generation.
For the transportation sector, the IPCC presents a number of subsector-specific sets of emissions
factors based on the type of fuel used and the combustion process used in each subsector. For
example, for on-road vehicles, different sets of emissions factors are used for light-duty vehicles
and heavy-duty vehicles. Data on the percentages of all transportation-related energy used by the
different subsectors were collected from EIA’s Annual Energy Outlook, most recently released in
October 2011 (EIA, 2011a).
For coal, GHG emissions vary depending on the type of coal combusted (e.g., lignite versus subbituminous). Information on the type of coal extracted in states where private leaseholders
extract coal from federal lands was collected from the DOI’s Public Lands Statistics, which
include reports of the states from which private leaseholders extract coal, and the EIA’s Annual
Coal Report, which provides information on the typical type of coal extracted in each state.
Table 3 combines these two sets of information.
8. For example, coal combustion for electricity generation has a different set of emissions factors from oil
combustion for residential heating.
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Table 3. Coal type by state (states with private leasing
of federal lands for coal extraction)
States with private leasing for coal
Dominant coal type
Alabama
Bituminous
Arizona
Bituminous
Colorado
Bituminous
Kentucky
Bituminous
Montana
Sub-bituminous
New Mexico
Sub-bituminous
North Dakota
Lignite
Oklahoma
Bituminous
Ohio
Bituminous
Utah
Bituminous
Washington
Bituminous
Wyoming
Sub-bituminous
Sources: EIA, 2009a; BLM, 2011.
2.1.2
Data processing
To calculate the ultimate GHG emissions from fossil fuel extraction from federal lands by
private leaseholders, the data described above were processed in several ways. This section
describes the steps taken.
Converting units
Calculating ultimate GHG emissions involved completing a number of conversions. For
example, the quantities of fossil fuels extracted by private leaseholders from federal lands are
reported in volume-based metrics (e.g., short tons, barrels, and cubic feet), but the emissions
factors provided by the IPCC are measured according the amount of energy produced by burning
the fossil fuel. For this reason, the quantities of fossil fuels extracted were converted into energybased measures using common conversion factors, such as those available at
http://www.natgas.info/html/natgasunitsconversion.html (Chandra, 2011). EIA and the
International Energy Agency also provide conversion information that was used in this analysis
[http://www.eia.gov/kids/energy.cfm?page = about_energy_conversion_calculator-basics (EIA,
2011f) and http://www.i.e.a.org/stats/unit.asp (IEA, 2011), respectively].
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Matching quantities of fossil fuels to sectors and emissions factors
As noted above, GHG emissions from each fuel type can be determined by multiplying a given
quantity of combusted fuel by an emissions factor that is specific to a particular type of
combustion. For each of the five sectors identified by the EIA, corresponding sets of combustion
type-specific emissions factors were identified in the IPCC Guidelines for National Greenhouse
Gas Inventories (IPCC, 2006). For example, the guidelines offer default sets of emissions factors
for combustion in stationary power plants (mostly appropriate for coal) or combustion in
residential settings (mostly appropriate for natural gas).
Information from the EIA was used to classify combustion type by fuel. For example, based on
EIA data, it is hypothetically possible to determine if 50% of coal should be assumed to be
combusted in stationary power plants and the other 50% combusted in industrial facilities. In this
example, two sets of emissions factors would be used to determine the GHG emissions from
coal. These classification “splits” were determined for 2008, 2009, and 2010 by consulting the
current and two most recent past Annual Energy Review publications (EIA, 2009b, 2010, 2011b).
Running calculations
Equation 1 provides a general illustration of how the above information was combined to
produce an estimate of the total amount of GHGs emitted from the combustion of a particular
quantity of fossil fuel:
Equation 1. Simplified illustration of equation used to calculate GHG emissions.
where the sector weight represents the percentage of the quantity of fossil fuel that is consumed
in the specific sector (e.g., transportation), thus using the sector-specific set of emissions factors,
and the total amount of GHG emitted for a given quantity of fossil fuel is a sum of the
calculations for each sector.
Calculations were run to determine the ultimate GHG emissions from federal leases, based on
the following:

Year

GHG (i.e., CO2, CH4, and N2O)
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
Carbon dioxide equivalent (CO2e; accounting for all three GHGs)9

Fossil fuel type

Location (onshore versus offshore).
The results of these calculations are presented in Section 3.1.
2.2 Characterization of Indirect GHG Emissions
Fossil fuel extraction can result in a wide range of indirect emissions, broadly defined in this
report as any GHG emissions caused by the exploration, production, refinement, or
transportation of fossil fuels that are not otherwise accounted for in the ultimate GHG emissions
calculations described in Section 2.1. Key categories of indirect GHG emissions include, among
other things:

Fugitive emissions (e.g., leaks in pipeline cracks)

Vented emissions (e.g., emissions of coalbed methane that are not captured when rock
formations are broken for coal extraction)

Emissions from combustion sources along the exploration, production, refinement, and
transportation continuum (e.g., emissions from boilers and other on-site equipment, onsite vehicles and employees’ personal vehicles, and trains and barges used to transport
fossil fuels).
Information on indirect GHG emissions from fossil fuel extraction from federal lands by private
leaseholders was collected from a variety of government and non-government sources. Table 4
identifies several key resources that include information on the types of indirect emissions that
can result from fossil fuel extraction along the exploration, production, refinement, and
transportation continuum.
9. Carbon dioxide equivalents are based on the 100-year global warming potentials for these gases, as cited in
the IPCC’s 4th Assessment Report on Climate Change (IPCC, 2007).
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Table 4. Sources of information on indirect emissions from production of fossil fuels from
federal leases
Oil and natural American Petroleum Institute – Compendium of Greenhouse Gas Emissions Methodologies
for the Oil and Gas Industry (API, 2009)
gas (onshore
and offshore)
U.S. General Accounting Office – Federal Oil and Gas Leases: Opportunities Exist to
Capture Vented and Flared Natural Gas, Which Would Increase Royalty Payments and
Reduce Greenhouse Gases (GAO, 2010)
International Petroleum Industry Environmental Conservation Association – Petroleum
Industry Guidelines for Reporting Greenhouse Gas Emissions (IPIECA, 2003)
Shale gas
Post Carbon Institute – Lifecycle Greenhouse Gas Emissions from Shale Gas Compared to
Coal: An Analysis of Two Conflicting Studies (Post Carbon Institute, 2011)
Coal and
National Renewable Energy Laboratory – Life Cycle Assessment of Coal-fired Power
Production (NREL, 1999)
coalbed
methane
Pace Global – Life Cycle Assessment of GHG Emissions from LNG and Coal Fired
Generation Scenarios: Assumptions and Results (Pace Global, 2009)
3.
Results
This section presents the results of the analysis of ultimate GHG emissions from extraction of
fossil fuels from federal lands by private leaseholders. It provides estimates of ultimate GHG
emissions by fuel, location, year, and GHG. It also includes a list of the types of indirect
emissions resulting from fossil fuel extraction from federal lands by private leaseholders.
Although it does not provide a quantitative estimate of the magnitude of these indirect emissions,
it provides information on the overall scale of indirect emissions that could be accounted for in a
robust calculation.
3.1 Quantification of Ultimate GHG Emissions from Fossil Fuel
Extraction from Federal Lands by Private Leaseholders
Tables 5, 6, and 7 present estimates of the GHG emissions from fossil fuels extracted from
federal lands by private leaseholders in 2008, 2009, and 2010, respectively.10 According to this
analysis, total GHG emissions resulting from the extraction of fossil fuels from federal lands by
private leaseholders was approximately 1,563 MMTCO2e in 2008, 1,537 MMTCO2e in 2009,
and 1,551 MMTCO2e in 2010. Table 8 provides an overview of total MTCO2e emissions by year
and by fossil fuel. Figure 1 shows the percentage breakdown of emissions by fossil fuel in 2010
and Figure 2 shows the breakdown of emissions by fossil fuel for all three years.
10. Note that the figures presented in Tables 5 through 9 are rounded.
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Table 5. GHG emissions from fossil fuels extracted from federal lands by private
leaseholders in 2008
Fossil fuel
Oil (onshore)
Oil (offshore)
Natural gas (onshore)
Natural gas (offshore)
Natural gas liquids
Coal
Coalbed methane
Total
Metric tons
of CH4
2,618
9,979
15,709
13,596
7,823
17,931
3,549
71,204
Metric tons
of CO2
50,715,803
193,124,514
173,153,676
149,856,705
18,101,471
928,078,097
39,115,789
1,552,146,054
Metric tons
of N2O
2,792
10,632
576
498
347
14,574
130
29,549
Total
MTCO2e
51,613,257
196,542,212
173,718,049
150,345,144
18,400,585
932,869,369
39,243,282
1,562,731,898
Table 6. GHG emissions from fossil fuels extracted from federal lands by private
leaseholders in 2009
Fossil fuel
Oil (onshore)
Oil (offshore)
Natural gas (onshore)
Natural gas (offshore)
Natural gas liquids
Coal
Coalbed methane
Total
Metric tons
of CH4
2,617
13,047
12,756
14,238
7,582
15,959
3,991
70,188
Metric tons
of CO2
50,710,929
250,643,313
139,473,656
155,678,682
17,424,265
867,762,984
43,634,114
1,525,327,944
Metric tons
of N2O
2,800
13,841
466
520
336
13,579
146
31,688
Total
MTCO2e
51,610,868
255,094,144
139,931,411
156,189,622
17,713,866
872,208,479
43,777,322
1,536,525,712
Table 7. GHG emissions from fossil fuels extracted from federal lands by private
leaseholders in 2010
Fossil fuel
Oil (onshore)
Oil (offshore)
Natural gas (onshore)
Natural gas (offshore)
Natural gas liquids
Coal
Coalbed methane
Total
Metric tons
of CH4
2,390
45,951
13,795
13,034
9,025
16,998
4,094
105,287
Metric tons
of CO2
46,141,874
246,440,905
152,044,238
143,654,344
20,822,527
884,399,361
45,117,415
1,538,620,665
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Metric tons
of N2O
2,543
13,583
507
479
401
13,833
150
31,497
Total
MTCO2e
46,959,493
251,637,415
152,540,230
144,122,967
21,167,515
888,946,650
45,264,595
1,550,638,866
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(Final, 2/1/2012)
Table 8. GHG emissions from fossil fuels extracted from federal lands by private
leaseholders in 2008–2010
Fossil fuel
2008
MTCO2e
2009
MTCO2e
2010
MTCO2e
Total three-year
MTCO2e
Oil (onshore)
51,613,257
51,610,868
46,959,493
150,183,618
Oil (offshore)
196,542,212
255,094,144
251,637,415
703,273,771
Natural gas (onshore)
173,718,049
139,931,411
152,540,230
466,189,690
Natural gas (offshore)
150,345,144
156,189,622
144,122,967
450,657,733
18,400,585
17,713,866
21,167,515
57,281,966
932,869,369
872,208,479
888,946,650
2,694,024,498
39,243,282
43,777,322
45,264,595
128,285,199
1,536,525,712 1,550,638,866
4,649,896,477
Natural gas liquids
Coal
Coalbed methane
Total
1,562,731,898
Figure 1. Percentage of total MTCO2e emissions from fossil fuels extracted from federal
lands by private leaseholders in 2010.
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Figure 2. GHG emissions in MTCO2e from fossil fuels extracted from federal lands by
private leaseholders in 2008–2010.
These estimates provide an indication of the contribution of fossil fuel extraction from federal
lands by private leaseholders to the total amount of GHG emissions included in EPA’s national
GHG inventory. As noted above, EPA produces a top-down GHG inventory every year that
includes estimates of the nation’s source- and sector-specific emissions of CO2, CH4, N2O, and
other GHGs. According to the 2011 inventory, GHG emissions in the United States in 2009 (the
most recent year for which data are available) totaled approximately 6,600 MMTCO2e, of which
5,800 MMTCO2e are attributed to energy consumption. A comparison of the GHG emissions in
Table 6 (which includes estimates of the GHG emissions from fossil fuel extraction from federal
lands by private leaseholders in 2009) to these EPA estimates suggests that ultimate GHG
emissions from these leases could have accounted for approximately 23% of total U.S. GHG
emissions and 27% of energy-related GHG emissions.
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The estimates presented in Table 7 suggest that ultimate GHG emissions from fossil fuels
extracted from federal lands by private leaseholders in 2010 could be more than 20-times larger
than the estimate of total GHG emissions in the Greenhouse Gas Emissions Inventory for the
Federal Government: 2010 Data produced by the CEQ (2011), which reported total GHG
emissions associated with federal government operations in 2010 to be approximately
66.4 MMTCO2e.
As the tables and figures show, coal extraction is consistently the largest contributor to overall
emissions in 2008, 2009, and 2010. Combined, coal and coalbed methane account for far greater
than half of all MTCO2e in each of the three years. The tables also show the considerable
contributions of onshore and offshore natural gas extraction to total emissions of CH4. This
contribution is significant given the global warming potential of CH4 (one metric ton of CH4
emitted is equal to approximately 25 metric tons of CO2 emitted) (IPCC, 2007).
Table 9 presents the total GHG emissions split by the location from which the fossil fuels were
extracted. As the table shows, the vast majority of emissions in each of the three years evaluated
come from onshore locations (approximately 75% of the three-year total). This is largely driven
by the dominance of the estimated emissions from coal extraction from federal lands, which only
occurs onshore. Figure 3 presents a breakdown of the three-year totals by location.
Table 9. GHG emissions (in CO2e) from fossil fuels extracted from
federal lands by private leaseholders by location
Location
2008
MTCO2e
Onshore
1,215,844,542
Offshore
346,887,356
Total
1,562,731,898
2009
MTCO2e
2010
MTCO2e
1,125,241,946 1,154,878,484
411,283,766
Total three-year
MTCO2e
3,495,964,973
395,760,382
1,153,931,504
1,536,525,712 1,550,638,866
4,649,896,477
3.2 Characterization of Indirect GHG Emissions from Fossil Fuel
Extraction from Federal Lands by Private Leaseholders
This section provides information on the types of indirect emissions resulting from fossil fuel
extraction for federal lands by private leaseholders. It also includes a brief qualitative discussion
of the magnitude of these emissions. Although it does not provide a quantitative estimate of these
indirect emissions, it does provide information on the overall scale of indirect emissions
associated with federal government leasing that could be accounted for in a robust calculation.
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Figure 3. Percentage of total three-year MTCO2e emissions from fossil fuels extracted
from federal lands by private leaseholders, by location of extraction.
3.2.1
Catalog of indirect emissions from fossil fuel extraction from federal lands by
private leaseholders
As described in Section 2.2, a range of resources was consulted to identify types of indirect GHG
emissions resulting from fossil fuel extraction from federal lands by private leaseholders. This
section provides information on these types of indirect emissions, including the cause of the
emission and the GHG emitted.
Oil and natural gas
The range of indirect emissions that can result from onshore and offshore oil and natural gas
exploration, production, refinement, and transportation is extensive and well documented. The
American Petroleum Institute developed a compendium of GHG emissions (API, 2009) that
provides comprehensive lists of GHG emissions attributable to a large number of source
activities for each stage of the oil and gas production continuum. These lists include information
on how different activities contribute to emissions of CH4, CO2, and N2O. The appendix to this
report presents a series of tables that are drawn from the compendium and that indicate the
specific activity (e.g., operating boilers) and GHG emissions affected for numerous stages in the
oil and gas production continuum.
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In general, the types of indirect emissions that result from oil and gas production can be broken
down into the following categories (based on IPIECA, 2003; API, 2009): fugitive emissions
(i.e., emissions that can be identified and “fixed” to reduce them to “near-zero”), vented
emissions (i.e., incidental emissions that result during normal operations), and combustion
emissions (i.e., emissions resulting from the operation of various types of equipment). Table 10
presents these types of emissions, including their principle sources in the oil and gas industry
(see Figure 4 for an example of how these emissions are related).
Table 10. Categorization of indirect emissions in the oil and gas industry
Category
Principle source
Combustion source
Stationary devices
Boilers, heaters, furnaces, reciprocating internal combustion engines and
turbines, flares, incinerators, and thermal/catalytic oxidizers
Mobile sources
Barges, ships, railways, and trucks for material transport; planes/helicopters
and other company vehicles for personnel transport; and forklifts, all-terrain
vehicles, construction equipment, and other off-road mobile equipment
Process/vented emissions
Process emissions
Hydrogen plants, amine units, glycol dehydrators, fluid catalytic cracking units
and reformer regeneration, and flexi-coker coke burners
Other venting
Crude oil, condensate, and oil and natural gas product storage tanks, gasblanketed water and chemical tanks, underground drain tanks, gas-driven
pneumatic devices, gas samplers, chemical injection pumps, exploratory
drilling, loading/ballasting/transit, and loading racks
Maintenance
Decoking of furnace tubes, well unloading, vessel and gas compressor
depressurizing, compressor starts, gas sampling, and pipeline blowdowns
Non-routine activities
Pressure relief valves, fuel supply unloading valves, and emergency shut-down
devices
Fugitive emissions
General
Valves, flanges, connectors, pumps, compressor seal leaks, and catadyne
heaters
Other non-point sources
Wastewater treatment and surface impoundments
Other indirect emissions
Electricity
Off-site generation of electricity for on-site power
Steam/heat
Off-site generation of hot water and steam for on-site heat
District cooling
Off-site gaseous pressurization (compression) for on-site cooling
Source: API, 2009.
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Figure 4. Schematic of indirect GHG emissions from oil and gas operations.
Source: API, 2009.
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Coal and coalbed methane
The range of indirect emissions that can result from coal and coalbed methane extraction is
similar to that of emissions from oil and gas production, described above. Many of the types of
emissions described in Table 10 and in the API compendium (API, 2009) of GHG emissions
referenced in the appendix to this report apply to coal and coalbed methane. Similar to indirect
emissions from oil and gas production, indirect emissions from coal and coalbed methane
production include fugitive, vented, and combustion-related emissions.
Table 11 presents additional indirect GHG source activities that are particular to coal and
coalbed methane production.
Table 11. Types of indirect GHG emissions resulting from coal and coalbed
methane production
Activity
Description
Mining
Process emissions from venting of emissions from depressurization of coal when
coal is brought to the surface
Process emissions from venting of emissions from gas release when coal is
cleaned, crushed, and prepared for transport
Process emissions from mining of subsurface formations
Production
Combustion emissions from manufacture of lime, limestone, and natural gas used
to scrub coal
Combustion emissions from transportation by rail and/or barge
Combustion emissions from transport of lime, limestone, and natural gas used to
scrub coal
Process emissions from chemical emissions from limestone scrubbing reaction
Combustion emissions from mining operations (equipment operation)
Fugitive emissions from capture and processing of coalbed methane
Combustion emissions from flaring of captured coalbed methane (note: capturing
and flaring coalbed methane is uncommon)
Combustion emissions from operation of conveyor and loading equipment
Transportation Combustion emissions from operation of drilling and shovel equipment
Combustion emissions from operation of grinding equipment
Sources: NREL, 1999; Delucchi, 2003; Pace Global, 2009.
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GHG
CH4
CH4
CH4
CO2
CO2
CO2
CO2
CO2
CH4
CO2
CO2
CO2
CO2
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3.2.2
(Final, 2/1/2012)
High-level analysis of indirect emissions from fossil fuel extraction from federal
lands by private leaseholders
As the previous section suggests, there are a large number of possible indirect emissions sources
spanning the production-consumption continuum for oil, gas, coal, and coalbed methane
production. Because of the broad scope of these emissions, which include emissions of different
types of GHGs from a wide range of activities, it is difficult to quantify their aggregate
magnitude. Therefore, this report does not include any aggregate quantitative estimates of total
indirect emissions from fossil fuel extraction from federal lands by private leaseholders.
However, several sources provide estimates of the quantities of emissions from fossil fuels that
are lost upstream (e.g., through venting and fugitive) for different fossil fuels, which can help
characterize the overall scale of indirect GHG emissions associated with fossil fuel extraction
from federal lands by private leaseholders.

Natural gas. Delucchi (2003) estimates that total natural gas lost to the atmosphere from
venting and fugitive emissions from wellhead to end-use consumer in modern, wellmaintained natural gas production systems can be as high as 2% of total gas throughput,
and that losses in old or poorly maintained systems can be substantially higher (one
example indicates a loss rate of 6%).11 This estimate is consistent with ones by the
Department of Energy and the EPA, which suggest that approximately 1.8% and 1.4%
(respectively) of the natural gas produced in the United States is lost as vented or fugitive
emissions in the production, processing, transmission, storage, and distribution stages
(U.S. EPA, 1996; U.S. DOE, 2011). According to the General Accounting Office and the
EPA, natural gas vented and flared from onshore lease sites totaled around 126 billion
cubic feet in 2008 (GAO, 2010). Transportation of natural gas also contributes to total
GHG emissions from this sector. Approximately 3 billion kilowatt hours of electricity
were used to transport natural gas in 2003. Using default emissions factors from the EPA
Green Power Equivalency Calculator, this energy consumption translates into
approximately 2 MMTCO2e in GHG emissions (U.S. EPA, 2011b).
Overall, it is estimated that approximately 13% of all natural gas produced in the United
States is lost to fugitive emissions, venting, flaring, or other combustion before reaching
its end use (U.S. DOE, 2011). Based on default settings used in the Argonne National
Laboratory’s GREET model, for every million British thermal unit (BTU) equivalent of
natural gas delivered to end uses for combustion in power plants or other stationary
sources, approximately 15 to 20 kilograms of CO2e is emitted during production and
transportation (Argonne National Laboratory, 2011).12 EPA estimates that the CH4
11. Citing EIA data, Delucchi (2003) reports that in 1983, about 7% of all natural gas produced internationally
was vented or flared.
12. One million cubic feet of natural gas contains the equivalent of one million BTUs.
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emissions resulting from these losses are equivalent to approximately 220 MMTCO2e in
2009 (U.S. EPA, 2011a). It is estimated that the production, processing, transportation,
and distribution stages account for 65%, 8%, 20%, and 7% of these emissions,
respectively (U.S. EPA, 2011a; WorldWatch Institute, 2011).

Coal. Delucchi (1993) estimates that the amount of upstream CO2 emissions resulting
from coal production, refining, and transportation is equal to approximately 3% of total
CO2 emissions from coal combustion downstream. Other studies estimate that the
upstream indirect emissions from coal production and transport account for as much as
8% to 20% of the total GHG emissions from coal (Spadaro et al., 2000; Dones et al.,
2004; Weisser, 2007). According to the EPA, CH4 emissions from coal production
(e.g., releases at mines) totaled approximately 71 MMTCO2e in 2009 (U.S. EPA, 2011a).
The WorldWatch Institute (2011) estimates that total upstream emissions of GHGs from
coal production and transportation are approximately 120 MMTCO2e. Based on default
settings used in the GREET model, for every million BTU equivalent of coal delivered to
U.S. refineries, approximately 5 kilograms of CO2e are emitted during coal production
and transportation to power plants (Argonne National Laboratory, 2011).13

Oil. According to the EPA, CO2 and CH4 emissions from oil production, transportation,
refining, and distribution totaled approximately 31.4 MMTCO2e in 2009 (U.S. EPA,
2011a). Dones et al. (2004) estimate that upstream indirect emissions from oil
production, transportation, refining, and distribution account for as much as 12% of the
total GHG emissions associated with oil. Based on default settings used in the GREET
model, for every million BTU equivalent of oil delivered to U.S. refineries,
approximately 8 kilograms of CO2e are emitted during oil production and transportation
(Argonne National Laboratory, 2011).14
Recently, several studies have evaluated the lifecycle GHG implications of developing shale gas
resources and compared the resulting emissions to production of other fossil fuels, such as coal.
A study by Cornell University, for example, estimates that lifecycle GHG emissions from shale
gas are 20–100% higher than from coal when considered over a 20-year period that assumes that
70% of natural gas consumption is not used to generate electricity (Howarth et al., 2011). A
similar study conducted by the National Energy Technology Laboratory estimates that on an
electricity-generation comparison basis, natural gas base load has approximately half of the GHG
emissions that coal has over a 20-year period (NETL, 2011). A third study, conducted by the
Post Carbon Institute, suggests that lifecycle GHG emissions from shale gas are higher than
13. One metric ton of coal contains approximately 22 million BTU in heat content (EIA, 2011c).
14. One barrel of oil contains approximately 6 million BTU in heat content (U.S. EPA, 2011b).
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those from coal when evaluated over a 20-year period but are lower than those from coal over a
100-year basis (Post Carbon Institute, 2011).
Santoro et al. (2011) estimate that the indirect emissions from shale gas (per unit of end-use
energy consumed) range between 8% and 11% of the direct emissions. According to their
analysis, the largest component of indirect emissions from shale gas is due to CO2 emissions
from fuel combustion in production engines (approximately 35% of all indirect emissions),
followed by processing to remove sulfur (31%), exploration and development activities (15%),
land disturbances and resource use (10%), and transmission and distribution (9%).
This section of the report reviewed the many types of indirect emissions that can result from
fossil fuel extraction from federal lands by private leaseholders. Because of the broad scope of
these emissions, which include emissions of different GHGs from a wide range of activities, it is
difficult to quantify their aggregate magnitude.
4.
Conclusions
This report presents a preliminary quantitative estimate of the magnitude of ultimate GHG
emissions resulting from fossil fuel extraction from federal lands by private leaseholders. It
suggests that in 2009, the most recent year for which total U.S. GHG emissions data are
available, the estimated 1,537 MMTCO2e in ultimate downstream GHG emissions from fossil
fuel extraction from federal lands by private leaseholders could have accounted for
approximately 23% of total U.S. GHG emissions and 27% of energy-related GHG emissions.
This estimate does not account for the large number of possible indirect emissions sources that
span the production-consumption continuum and that are currently omitted from federal
government accounting.
Ultimate downstream GHG emissions resulting from fossil fuel extraction from federal lands by
private leaseholders in 2010 are estimated to total 1,551 MMTCO2e. This estimate suggests that
ultimate GHG emissions from fossil fuels extracted from federal lands by private leaseholders
could be more than 20-times larger than the estimation of total GHG emissions in the
Greenhouse Gas Emissions Inventory for the Federal Government: 2010 Data produced by the
CEQ (2011), which estimated total GHG emissions associated with federal government
operations in 2010 to be approximately 66.4 MMTCO2e. The majority of the 2010 emissions
comes from leases for extracting coal (57% of the total), followed in magnitude by offshore oil
(16%), onshore natural gas (10%), offshore natural gas (9%), and a combination of onshore oil,
coalbed methane, and natural gas liquids (collectively approximately 7%).
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This disparity suggests that excluding emissions from extraction of fossil fuels from federal
lands by private leaseholders from the federal government inventory could result in missed
opportunities to more fully account for federal government programs that affect or contribute to
U.S. GHG emissions. There is an opportunity for federal agencies to take stock of the GHG
emissions that result from activities under their control, but that are not currently included in the
CEQ guidance.
References
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Industry. Available:
http://www.api.org/ehs/climate/new/upload/2009_GHG_COMPENDIUM.pdf. Accessed
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Marcellus Shale Gas Development. A Technical Report from the Agricultural, Energy, and
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U.S. DOE. 2011. Life Cycle Greenhouse Gas Inventory of Natural Gas Extraction, Delivery, and
Electricity Production. U.S. Department of Energy. Available: http://www.netl.doe.gov/energyanalyses/pubs/NG-GHG-LCI.pdf. Accessed 11/29/2011.
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U.S. Environmental Protection Agency. Available:
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U.S. EPA. 2011a. 2011 Inventory of Greenhouse Gas Emissions and Sinks. U.S. Environmental
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A. Sources of Indirect Emissions in the Oil and
Gas Industry
API’s Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry
(API, 2009) provides a comprehensive list of the types of indirect emissions that can result from
oil and gas exploration, production, refinement, and transportation (including vented emissions,
fugitive emissions, and incidental combustion emissions from on-site vehicles and other
sources). The following tables present information drawn from this resource. The tables are
separated by the type of activity involved (e.g., production versus transportation).
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Appendix (Final, 2/1/2012)
Table A.1. Indirect emissions from conventional oil and gas exploration and production
Source type
Combustion sources –
stationary devices
Source
Boilers/steam generators
Dehydrator reboilers
Heaters/treaters
Internal combustion engine
generators
Fire pumps
Reciprocating compressor
drivers
Turbine electric generators
Turbine/centrifugal compressor
drivers
Well drilling
Flares
Incinerators
Combustion sources – mobile
Mobile drilling equipment
sources
Other company vehicles
Planes/helicopters
Supply boats, barges
Site preparation, construction,
and excavation
Indirect sources
Electricity imports
Process heat/steam imports
Cogeneration
Vented sources – process vents Dehydration processes
Dehydrator kimray pumps
Gas sweetening processes
Vented sources – other venting Storage tanks and drain vessels
Exploratory drilling
Well testing and completions
Pneumatic devices
Chemical injection pumps
Gas sampling and analysis
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CO2
X
X
X
X
CH4
X
X
X
X
N2O
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Negligible
amounts of
GHG
emissions
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Appendix (Final, 2/1/2012)
Table A.1. Indirect emissions from conventional oil and gas exploration and production
(cont.)
Source type
Vented sources –
maintenance/turnarounds
Vented sources – non-routine
activities
Fugitive sources
Vented sources – non-routine
activities
Fugitive sources
Source
Mud degassing
Low pressure gas well casing
Compressor blowdowns
Compressor starts
Gathering pipeline blowdowns
Vessel blowdown
Well completions
Well unloading and workovers
Emergency shutdown/
emergency safety
Pressure relief valves
Well blowouts (when not flared)
Equipment component leaks
Wastewater treatment
Blowdown [e.g., emergency
safety blowdown (ESB)]
Fire suppression
Air conditioning/refrigeration
Page A-3
Confidential
SC12618
CO2
CH4
X
X
X
X
X
X
X
X
X
N2O
Negligible
amounts of
GHG
emissions
X
X
X
X
X
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.2. Indirect emissions from oil sands and heavy oil upgrading
Source type
Combustion sources –
stationary devices
Combustion sources –
mobile sources
Indirect sources
Vented sources – process
vents
Source
Boilers/heaters
Fire pumps
Fire pumps
Internal combustion engine
generators
Reciprocating compressor drivers
Turbine electric generators
Turbine/centrifugal compressor
drivers
Turbines
Mining equipment
Flares
Catalytic oxidizers
Incinerators
Mining equipment
Other company vehicles
Planes/helicopters
Site preparation, construction, and
excavation
Electricity imports
Process heat/steam imports
Flue gas desulfurization process
vents
Sulfur recovery units
Catalytic cracking
Catalyst regeneration
Steam methane reforming
(hydrogen plants)
Delayed coking
Flexi-coking
Catalytic reforming
Thermal cracking
Ventilation and degasification
Ash processing unit
Surface mining
Page A-4
Confidential
SC12618
CO2
X
X
X
X
CH4
X
X
X
X
N2O
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Negligible
amounts of
GHG
emissions
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.2. Indirect emissions from oil sands and heavy oil upgrading (cont.)
Source type
Vented sources – other
venting
Vented sources –
maintenance/turnarounds
Vented sources – nonroutine activities
Fugitive sources
Vented sources – nonroutine activities
Fugitive sources
Source
Storage tanks
Water tanks
Loading racks
Sand-handling
Pneumatic devices
Casing gas vents
Compressor blowdowns
Compressor starts
Equipment/process blowdowns
Heater/boiler tube decoking
Vessel blowdown
Emergency shut down
Pressure relief valves
Equipment component leaks
Wastewater treatment
Sludge/solids handling
Wastewater collection and treating
Exposed mine faces
Tailing ponds
Fire suppression
Air conditioning/refrigeration
Page A-5
Confidential
SC12618
CO2
X
X
CH4
N2O
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Negligible
amounts of
GHG
emissions
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.3. Indirect emissions from coalbed methane production
Source type
Combustion sources –
stationary devices
Combustion sources –
mobile sources
Indirect sources
Vented sources – process
vents
Vented sources – other
venting
Vented sources –
maintenance/turnarounds
Vented sources – nonroutine activities
Fugitive sources
Vented sources – nonroutine activities
Fugitive sources
Source
Boilers/steam generators
Dehydrator reboilers
Fire pumps
Internal combustion engines and
generators
Reciprocating compressor drivers
Turbine electric generators
Turbine/centrifugal compressor drivers
Flares
Mining equipment
Other company vehicles
Site preparation, construction, and
excavation
Electricity imports
Process heat/steam imports
Dehydration processes
Dehydrator kimray pump
Gas sweetening processes
Water handling, tanks
Coal seam drilling and well testing
Coal handling
Gas sampling and analysis
Compressor starts and blowdowns
Gathering pipeline blowdowns
Vessel blowdowns
Well workovers
Gathering pipeline leaks
Pressure relief valves
Well blowdowns (when not flared)
Equipment component leaks
Wastewater treatment
Fire suppression
Air conditioning/refrigeration
Page A-6
Confidential
SC12618
Negligible
amounts of
GHG
N2O emissions
X
X
X
X
CO2
X
X
X
X
CH4
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.4. Indirect emissions from gas processing
Source type
Combustion sources –
stationary devices
Combustion sources –
mobile sources
Indirect sources
Vented sources – process
vents
Vented sources – other
venting
Vented sources –
maintenance/turnarounds
Vented sources – nonroutine activities
Fugitive sources
Vented sources – nonroutine activities
Fugitive sources
Source
Boilers/steam generators
Dehydrator reboilers
Heaters/treaters
Fire pumps
Internal combustion engine generators
Reciprocating compressor drivers
Turbine electric generators
Turbine/centrifugal compressor drivers
Flares
Catalytic and thermal oxidizers
Incinerators
Other company vehicles
Planes/helicopters
Supply boats, barges
Electricity imports
Process heat/steam imports
Dehydration processes
Dehydrator kimray pumps
Gas sweetening processes
Sulfur recovery units
Storage tanks and drain vessels
Pneumatic devices
Chemical injection pumps
Gas sampling and analysis
Compressor blowdowns
Compressor starts
Vessel blowdown
Emergency shutdown/emergency safety
Pressure relief valves
Equipment component leaks
Wastewater treatment
Blowdown (ESB)
Fire suppression
Air conditioning/refrigeration
Page A-7
Confidential
SC12618
CO2
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
CH4
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Negligible
amounts of
GHG
N2O emissions
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.5. Indirect emissions from CO2 capture and sequestration
Source type
Combustion sources –
stationary devices
Source
Boilers/steam generators
Dehydrator reboilers
Heaters/treaters
Fire pumps
Internal combustion engine generators
Reciprocating compressor drivers
Turbine/centrifugal compressor
drivers
Turbine electric generators
Well drilling
Flares
Incinerators
Combustion sources – mobile Marine, road, or railroad tankers
sources
Other company vehicles
Planes/helicopters
Indirect sources
Electricity imports
Vented sources – process vents Dehydration processes
Dehydrator kimray pumps
Gas sweetening processes
Vented sources – other venting Intermediate storage
Storage tanks
Loading/unloading/transit
Pneumatic devices
Chemical injection pumps
Vented sources –
Maintenance
maintenance/turnarounds
Gas sampling and analysis
Compressor blowdowns
Compressor starts
Pipeline blowdowns
Vessel blowdown
Vented sources – non-routine Emergency releases
activities
Page A-8
Confidential
SC12618
CO2
X
X
X
X
X
X
X
CH4
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Negligible
amounts of
GHG
N2O emissions
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.5. Indirect emissions from CO2 capture and sequestration (cont.)
Source type
Fugitive sources
Vented sources – non-routine
activities
Fugitive sources
Source
Well leakage
Equipment and pipeline leaks
Wastewater treatment
Fugitive emissions from ships
Physical leakage from geological
formations
Fire suppression
Air conditioning/refrigeration
Page A-9
Confidential
SC12618
CO2
X
X
X
X
X
CH4
Negligible
amounts of
GHG
N2O emissions
X
X
X
X
X
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.6. Indirect emissions from natural gas storage and liquefied natural
gas operations
Source type
Combustion sources –
stationary devices
Source
Boilers/steam generators
Dehydrator reboilers
Heaters and heat exchangers
Fire pumps
Internal combustion engine
generators
Pump engines
Reciprocating compressor drivers
Turbine electric generators
Turbine/centrifugal compressor
drivers
Flares
Catalyst and thermal oxidizers
Incinerators
Vapor combustion units
Combustion sources – mobile Marine vessels
sources
Other company vehicles
Indirect sources
Electricity imports
Process heat/steam imports
Vented sources – process vents Dehydration processes
Dehydrator kimray pumps
Gas treatment processes
Vented sources – other venting Gas sampling and analysis
Liquefied natural gas cold box
Gas sampling and analysis
Revaporization
Storage tanks
Loading/unloading/transit
Pneumatic devices
Chemical injection pumps
Chemical injection pumps
Page A-10
Confidential
SC12618
CO2
X
X
X
X
X
CH4
X
X
X
X
X
N2O
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Negligible
amounts
of GHG
emissions
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.6. Indirect emissions from natural gas storage and liquefied natural
gas operations (cont.)
Source type
Vented sources –
maintenance/turnarounds
Vented sources – non-routine
activities
Fugitive sources
Vented sources – non-routine
activities
Fugitive sources
Source
Compressor blowdowns
Compressor starts
Pipeline blowdowns
Vessel blowdown
Compressor station venting
Storage station venting
Emergency shutdown / emergency
safety
Pressure relief valves
Pipeline leaks
Process equipment leaks
Storage wellheads
Vapor handling system
Wastewater treatment
Blowdown (ESB)
Fire suppression
Air conditioning/refrigeration
Page A-11
Confidential
SC12618
CO2
X
CH4
N2O
X
X
X
X
X
X
X
Negligible
amounts
of GHG
emissions
X
X
X
X
X
X
X
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.7. Indirect emissions from liquid transportation and distribution
Source type
Combustion sources –
stationary
Source
Reciprocating compressor drivers
Turbine electric generators
Turbine/centrifugal compressor drivers
Boilers/steam generators
Heaters
Fire pumps
Internal combustion engine generators
Pumps
Flares
Catalyst and thermal oxidizers
Incinerators
Vapor combustion units
Combustion sources – mobile Barges
sources
Marine, road, or railroad tankers
Other company vehicles
Planes/helicopters
Indirect sources
Electricity imports
Process heat/steam imports
Vented sources – process
Storage tanks
vents
Loading/unloading/transit
Pneumatic devices
Vented sources –
Pump station maintenance
maintenance/turnarounds
Vented sources – non-routine Breakout/surge tanks
activities
Fugitive sources
Pipeline leaks
Process equipment leaks
Wastewater treatment
Vented sources – non-routine Fire suppression
activities
Fugitive sources
Air conditioning/refrigeration
Leak detection (SF6 emissions)
Page A-12
Confidential
SC12618
CO2
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
CH4
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
N2O
X
X
X
X
X
X
X
X
X
Negligible
amounts
of GHG
emissions
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.8. Indirect emissions from natural gas transportation and distribution
Source type
Combustion sources –
stationary devices
Source
Boilers/steam generators
Dehydrator reboilers
Heaters
Fire pumps
Internal combustion engine
generators
Reciprocating compressor drivers
Turbine electric generators
Turbine/centrifugal compressor
drivers
Flares
Catalyst and thermal oxidizers
Incinerators
Combustion sources – mobile Other company vehicles
sources
Planes/helicopters
Indirect sources
Electricity imports
Process heat/steam imports
Vented sources – process vents Dehydration processes
Dehydrator kimray pumps
Gas treatment processes
Vented sources – other venting Gas sampling and analysis
Storage tanks
Loading/unloading/transit
Pneumatic devices
Chemical injection pumps
Vented sources –
Compressor blowdowns
maintenance/turnarounds
Compressor starts
Compressor station blowdowns
Pig traps and drips
Vessel blowdown
Pipeline blowdowns
Vented sources – non-routine Metering and pressure regulating
activities
station
Pressure relief valves
Pipeline dig-ins
Page A-13
Confidential
SC12618
CO2
X
X
X
X
X
CH4
X
X
X
X
X
N2O
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Negligible
amounts
of GHG
emissions
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.8. Indirect emissions from natural gas transportation and distribution (cont.)
Source type
Fugitive sources
Vented sources – non-routine
activities
Fugitive sources
Source
Pipeline leaks
Process equipment leaks
Wastewater treatment
Upsets
Fire suppression
Air conditioning/refrigeration
Page A-14
Confidential
SC12618
CO2
CH4
N2O
X
X
X
Negligible
amounts
of GHG
emissions
X
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.9. Indirect emissions from refining
Source type
Combustion sources –
stationary devices
Source
Boilers/steam generators
Heaters
Fire pumps
Internal combustion engine generators
Pumps
Reciprocating compressor drivers
Turbine electric generators
Turbine/centrifugal compressor drivers
Flares
Catalyst and thermal oxidizers
Incinerators
Coke calcining kilns
Combustion sources – mobile Company vehicles
sources
Indirect sources
Electricity imports
Process heat/steam imports
Vented sources – process
Sulfur recovery units
vents
Catalytic cracking
Catalytic reforming
Catalyst regeneration
Steam methane reforming (hydrogen
plants)
Delayed coking
Flexi-coking
Asphalt production
Thermal cracking
Vented sources –
Heater/boiler tube decoking
maintenance/turnarounds
Fugitive sources
Fuel gas system leaks
Wastewater collection and treating
Vented sources – other
Storage tanks
venting
Loading racks
Pneumatic devices
Vented sources –
Compressor starts
maintenance/turnarounds
Equipment/process blowdowns
Page A-15
Confidential
SC12618
Negligible
amounts of
GHG
N2O emissions
X
X
X
X
X
X
X
X
X
CO2
X
X
X
X
X
X
X
X
X
X
X
X
X
CH4
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.9. Indirect emissions from refining (cont.)
Source type
Source
Vented sources – non-routine Emergency shut down
activities
Pressure relief valves
Fire suppression
Fugitive sources
Other process equipment leaks
Sludge/solids handling
Air conditioning/refrigeration
Page A-16
Confidential
SC12618
CO2
CH4
Negligible
amounts of
GHG
N2O emissions
X
X
X
X
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.10. Indirect emissions from petrochemical manufacturing
Source type
Combustion sources –
stationary devices
Combustion sources –
mobile sources
Indirect sources
Vented sources – process
vents
Vented sources – other
venting
Fugitive sources
Vented sources – other
venting
Vented sources –
maintenance/turnarounds
Vented sources – nonroutine activities
Fugitive sources
Source
Boilers/steam generators
Heaters
Fire pumps
Internal combustion engine generators
Pumps
Reciprocating compressor drivers
Turbine electric generators
Turbine/centrifugal compressor drivers
Flares
Catalyst and thermal oxidizers
Incinerators
Company vehicles
Electricity imports
Process heat/steam imports
Catalyst regeneration
Steam methane reforming (hydrogen
plants)
Chemical production
Storage tanks
Loading racks
Fuel gas system leaks
Wastewater collection and treating
Pneumatic devices
Compressor starts
Equipment/process blowdowns
Heater/boiler tube decoking
Emergency shut down
Pressure relief valves
Fire suppression
Other process equipment leaks
Sludge/solids handling
Air conditioning/refrigeration
Page A-17
Confidential
SC12618
CO2
X
X
X
X
X
X
X
X
X
X
X
X
CH4
X
X
X
X
X
X
X
X
X
N2O
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Negligible
amounts
of GHG
emissions
X
X
X
X
X
X
X
X
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.11. Indirect emissions from minerals and mining operations
Source type
Combustion sources –
stationary devices
Combustion sources –
mobile sources
Indirect sources
Vented sources – process
vents
Vented sources – other
venting
Fugitive sources
Vented sources – nonroutine activities
Fugitive sources
Source
Boilers/steam generators
Heaters
Fire pumps
Internal combustion engines
Turbines
Flares
Catalytic oxidizers
Incinerators
Mining equipment
Other company vehicles
Site preparation, construction, and
excavation
Electricity imports
Process heat/steam imports
Surface mining
Ventilation and degasification
Water tanks
Coal seam drilling and well testing
Coal-handling
Equipment and pipeline leaks
Wastewater treatment
Fire suppression
Air conditioning/refrigeration
Page A-18
Confidential
SC12618
CO2
X
X
X
X
X
X
X
X
X
X
X
CH4
X
X
X
X
X
X
N2O
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Negligible
amounts of
GHG
emissions
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.12. Indirect emissions from retail and marketing
Source type
Combustion sources stationary
Combustion sources – mobile
sources
Indirect sources
Vented sources
Vented sources – non-routine
activities
Fugitive sources
Source
Boilers/steam generators
Heaters
Thermal oxidizers
Marine tankers
Other company vehicles
Railroad tankers
Road tankers
Electricity usage
Service station storage tanks
Fire suppression
Process equipment leaks
Air conditioning/refrigeration
Page A-19
Confidential
SC12618
CO2
X
X
X
X
X
X
X
X
CH4
X
X
X
X
X
X
X
Negligible
amounts of
GHG
N2O emissions
X
X
X
X
X
X
X
X
X
X
X
Stratus Consulting
Appendix (Final, 2/1/2012)
Table A.13. Indirect emissions from electricity and heat/steam generation
Source type
Combustion sources –
stationary
Combustion sources –
mobile sources
Vented sources
Fugitive sources
Vented sources – other
venting
Fugitive sources
Source
Turbine electric generators
Boilers/steam generators
Internal combustion engine generators
Company vehicles
Natural gas venting (maintenance on fuel
line to natural gas fuel sources)
Natural gas equipment leaks (natural gas
fuel line)
Fire suppression
Air conditioning/refrigeration
Page A-20
Confidential
SC12618
CO2
X
X
X
X
CH4
X
X
X
X
N2O
X
X
X
X
X
X
X
X
Negligible
amounts of
GHG
emissions
X
X
S T R AT U S C O N S U LT I NG
1881 Ninth Street, Suite 201
Boulder, Colorado 80302
phone 303.381.8000
fax 303.381.8200
1920 L Street, N.W., Suite 420
Washington, D.C. 20036
phone 202.466.3731
fax 202.466.3732
www.stratusconsulting.com
(headquarters)