Greenhouse Gas Emissions from Fossil Energy Extracted from ...

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 Confidential

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Confidential

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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 production-consumption 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%).

Stratus Consulting (Final, 2/1/2012)

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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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1. 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.

Executive Order (E.O.) 13514, Federal Leadership in Environmental, Energy, and Economic Performance (74 Federal Register 52117, October 9, 2009; The White House 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.

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.

Source: U.S. EPA, 2011a.


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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 Federal government agency and program

Oil, natural gas (onshore), and natural gas liquids Coal and coalbed methane

DOI, BLM – Public Land Statistics: Federal Coal Leases (BLM, 2011) DOI, Office of Natural Resources Revenue – Reported Royalty Revenues (ONRR, 2011)

Oil and natural gas (offshore)

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 sub-bituminous). 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 energy-based 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, on-site 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 gas (onshore and offshore)

American Petroleum Institute – Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry (API, 2009) 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 coalbed methane

National Renewable Energy Laboratory – Life Cycle Assessment of Coal-fired Power Production (NREL, 1999) 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 Metric tons

of CH4 Metric tons

of CO2 Metric tons

of N2O Total

MTCO2e

Oil (onshore) 2,618 50,715,803 2,792 51,613,257 Oil (offshore) 9,979 193,124,514 10,632 196,542,212 Natural gas (onshore) 15,709 173,153,676 576 173,718,049 Natural gas (offshore) 13,596 149,856,705 498 150,345,144 Natural gas liquids 7,823 18,101,471 347 18,400,585 Coal 17,931 928,078,097 14,574 932,869,369 Coalbed methane 3,549 39,115,789 130 39,243,282 Total 71,204 1,552,146,054 29,549 1,562,731,898



of CH4 Metric tons

of CO2 Metric tons

of N2O Total

MTCO2e Oil (onshore) 2,617 50,710,929 2,800 51,610,868 Oil (offshore) 13,047 250,643,313 13,841 255,094,144 Natural gas (onshore) 12,756 139,473,656 466 139,931,411 Natural gas (offshore) 14,238 155,678,682 520 156,189,622 Natural gas liquids 7,582 17,424,265 336 17,713,866 Coal 15,959 867,762,984 13,579 872,208,479 Coalbed methane 3,991 43,634,114 146 43,777,322 Total 70,188 1,525,327,944 31,688 1,536,525,712



of CH4 Metric tons

of CO2 Metric tons

of N2O Total

MTCO2e

Oil (onshore) 2,390 46,141,874 2,543 46,959,493 Oil (offshore) 45,951 246,440,905 13,583 251,637,415 Natural gas (onshore) 13,795 152,044,238 507 152,540,230 Natural gas (offshore) 13,034 143,654,344 479 144,122,967 Natural gas liquids 9,025 20,822,527 401 21,167,515 Coal 16,998 884,399,361 13,833 888,946,650 Coalbed methane 4,094 45,117,415 150 45,264,595 Total 105,287 1,538,620,665 31,497 1,550,638,866



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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

Natural gas liquids 18,400,585 17,713,866 21,167,515 57,281,966

Coal 932,869,369 872,208,479 888,946,650 2,694,024,498

Coalbed methane 39,243,282 43,777,322 45,264,595 128,285,199

Total 1,562,731,898 1,536,525,712 1,550,638,866 4,649,896,477

Figure 1. Percentage of total MTCO2e emissions from fossil fuels extracted from federal lands by private leaseholders in 2010.



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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.

Figure 2. GHG emissions in MTCO2e from fossil fuels extracted from federal lands by private leaseholders in 2008–2010.



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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 2009

MTCO2e 2010

MTCO2e Total three-year

MTCO2e

Onshore 1,215,844,542 1,125,241,946 1,154,878,484 3,495,964,973

Offshore 346,887,356 411,283,766 395,760,382 1,153,931,504

Total 1,562,731,898 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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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.

Figure 3. Percentage of total three-year MTCO2e emissions from fossil fuels extracted from federal lands by private leaseholders, by location of extraction.



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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, gas-blanketed 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 GHG

Mining Process emissions from venting of emissions from depressurization of coal when coal is brought to the surface

CH4

Process emissions from venting of emissions from gas release when coal is cleaned, crushed, and prepared for transport

CH4

Process emissions from mining of subsurface formations CH4

Production Combustion emissions from manufacture of lime, limestone, and natural gas used to scrub coal

CO2

Combustion emissions from transportation by rail and/or barge CO2

Combustion emissions from transport of lime, limestone, and natural gas used to scrub coal

CO2

Process emissions from chemical emissions from limestone scrubbing reaction CO2

Combustion emissions from mining operations (equipment operation) CO2

Fugitive emissions from capture and processing of coalbed methane CH4

Combustion emissions from flaring of captured coalbed methane (note: capturing and flaring coalbed methane is uncommon)

CO2

Combustion emissions from operation of conveyor and loading equipment CO2

Transportation Combustion emissions from operation of drilling and shovel equipment CO2

Combustion emissions from operation of grinding equipment CO2

Sources: NREL, 1999; Delucchi, 2003; Pace Global, 2009.



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3.2.2 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, well-maintained 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.

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Argonne National Laboratory. 2011. GREET 1_2011 Model. Available: http://greet.es.anl.gov/. Accessed 11/29/2011.

BLM. 2011. 2010 Public Land Statistics: Federal Coal Leases, Table 3-35. U.S. Department of the Interior Bureau of Land Management. Available: http://www.blm.gov/public_land_statistics/pls10/pls3-35_10.pdf. Accessed 8/31/2011.

BOEMRE. 2011. Outer Continental Shelf Oil and Gas Production. Bureau of Ocean Energy Management, Regulation and Enforcement. Available: http://www.boemre.gov/stats/OCSproduction.htm. Accessed 8/29/2011.

CEQ. 2010a. Draft NEPA Guidance on Consideration of the Effects of Climate Change and Greenhouse Gas Emissions. February 18. Available: http://www.whitehouse.gov/sites/default/files/microsites/ceq/20100218-nepa-consideration-effects-ghg-draft-guidance.pdf. Accessed 11/29/2011.

CEQ. 2010b. Federal Greenhouse Gas Accounting and Reporting Guidance. October 6. Available: http://www.whitehouse.gov/sites/default/files/microsites/ceq/ghg_guidance_document_0.pdf. Accessed 9/1/2011.

CEQ. 2011. Greenhouse Gas Emissions Inventory for the Federal Government: 2010 Data. Available: http://explore.data.gov/Geography-and-Environment/FY2010-Federal-Government-Greenhouse-Gas-Inventory/vzm3-edjq. Accessed 10/20/2011.



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Chandra, V. 2011. Natgas.info. Available: http://www.natgas.info/html/natgasunitsconversion.html. Accessed 9/18/2011.

Delucchi, M. 1993. Emissions of Greenhouse Gases from the Use of Transportation Fuels and Electricity, Volume 2: Appendixes A – S. Report No. ANL/ESD/TM-22-Vol.2. Argonne National Laboratory, Argonne, IL. November.

Delucchi, M. 2003. Appendix E: Methane emissions from natural gas production, oil production, coal mining, and other sources. In A Lifecycle Emissions Model (LEM): Lifecycle Emissions from Transportation Fuels, Motor Vehicles, Transportation Modes, Electricity Use, Heating and Cooking Fuels, and Materials. UCD-ITS-RR-03-17E. University of California, Davis. Available: http://www.its.ucdavis.edu/publications/2003/UCD-ITS-RR-03-17E.pdf. Accessed 9/18/2011.

Dones, R., T. Heck, and S. Hirschberg. 2004. Greenhouse gas emissions from energy systems: Comparison and overview. Encyclopedia of Energy 3:77–95.

EIA. 2009a. Annual Coal Report – 2009. DOE/EIA-0584(2009). U.S. Energy Information Administration. Available: http://www.eia.gov/cneaf/coal/page/acr/acr.pdf. Accessed 8/31/2011.

EIA. 2009b. Annual Energy Review – 2008. U.S. Energy Information Administration. Available: http://www.eia.gov/FTPROOT/multifuel/038408.pdf. Accessed 9/13/2011.

EIA. 2010. Annual Energy Review – 2009. U.S. Energy Information Administration. Available: http://205.254.135.24/FTPROOT/multifuel/038409.pdf. Accessed 9/13/2011.

EIA. 2011a. Annual Energy Outlook: Transportation Sector Energy Use by Fuel Type Within a Mode, Reference Case. U.S. Energy Information Administration. Available: http://www.eia.gov/forecasts/aeo/. Accessed 9/15/2011.

EIA. 2011b. Annual Energy Review – 2010. U.S. Energy Information Administration. Available: http://205.254.135.24/totalenergy/data/annual/. Accessed 9/13/2011.

EIA. 2011c. Coal Data: U.S. Coal Production, Annual. U.S. Energy Information Administration. Available: http://www.eia.gov/coal/data.cfm#production. Accessed 11/29/2011.

EIA. 2011d. Natural Gas Data: Natural Gas Gross Withdrawals and Production, Annual. U.S. Energy Information Administration. Available: http://www.eia.gov/dnav/ng/ng_prod_sum_dcu_NUS_a.htm. Accessed 11/29/2011.

EIA. 2011e. Petroleum and Other Liquids Data: Crude Oil Production, Annual. U.S. Energy Information Administration. Available: http://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm. Accessed 11/29/2011.



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EIA. 2011f. What is Energy? U.S. Energy Information Administration. Available: http://www.eia.gov/kids/energy.cfm?page = about_energy_conversion_calculator-basics. Accessed 9/18/2011.

GAO. 2010. Federal Oil and Gas Leases: Opportunities Exist to Capture Vented and Flared Natural Gas, Which Would Increase Royalty Payments and Reduce Greenhouse Gases. GAO-11-34. U.S. Government Accountability Office. Available: http://www.gao.gov/products/GAO-11-34. Accessed 8/31/2011.

Howarth, R., R. Santoro, and A. Ingraffea. 2011. Methane and the greenhouse gas footprint of natural gas from shale formations. Climatic Change Letters DOI: 10.1007/s10584-011-0061-5.

IEA. 2011. International Energy Agency Unit Converter. Available: http://www.i.e.a.org/stats/unit.asp. Accessed 10/27/2011.

IPCC. 2006. IPCC Guidelines for National Greenhouse Gas Inventories, Vol. 2: Energy. Intergovernmental Panel on Climate Change. Available: http://www.ipcc-nggip.iges.or.jp/public/2006gl/vol2.html. Accessed 8/29/2011.

IPCC. 2007. IPCC Fourth Assessment Report: Climate Change 2007. Chapter 2 – Changes in Atmospheric Constituents and in Radiative Forcing. Intergovernmental Panel on Climate Change.

IPIECA. 2003. Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions. International Petroleum Industry Environmental Conservation Association. Available: http://www.ipieca.org/sites/default/files/publications/GHG_Guidelines.pdf. Accessed 9/2/2011.

NETL. 2011. Life Cycle Greenhouse Gas Analysis of Natural Gas Extraction & Delivery in the United States (updated May 23, 2011). National Energy Technology Laboratory. Presented at Cornell University Lecture Series. Available: http://www.netl.doe.gov/energy-analyses/pubs/NG_LC_GHG_PRES_12MAY11.pdf. Accessed 10/24/2011.

NREL. 1999. Life Cycle Assessment of Coal-fired Power Production. NREL/TP-570-25119. National Renewable Energy Laboratory. Available: http://www.nrel.gov/docs/fy99osti/25119.pdf. Accessed 9/1/2011.

ONRR. 2011. Statistical Information: Reported Royalty Revenues, Sales Volumes. Office of Natural Resources Revenue. Data obtained directly from ONRR on January 9, 2012.

Pace Global. 2009. Life Cycle Assessment of GHG Emissions from LNG and Coal Fired Generation Scenarios: Assumptions and Results. Available: http://www.lngfacts.org/resources/LCA_Assumptions_LNG_and_Coal_Feb09.pdf. Accessed 9/2/2011.



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Post Carbon Institute. 2011. Lifecyle Greenhouse Gas Emissions from Shale Gas Compared to Coal: An Analysis of Two Conflicting Studies. Available: http://www.postcarbon.org/reports/PCI-Hughes-NETL-Cornell-Comparison.pdf. Accessed 10/24/2011.

Santoro, R., H. Howarth, and R. Ingraffea. 2011. Indirect Emissions of Carbon Dioxide from Marcellus Shale Gas Development. A Technical Report from the Agricultural, Energy, and Environment Program at Cornell University. June 30.

Spadaro, V., L. Langlois, and B. Hamilton. 2000. Greenhouse gas emissions of electricity generation chains: Assessing the difference. IAEA Bulletin 42(2).

The White House Office of the Press Secretary. 2009. Executive Order. Federal Leadership in Environmental, Energy, and Economic Performance. October 5. Available: http://www.whitehouse.gov/assets/documents/2009fedleader_eo_rel.pdf. Accessed 9/1/2011.

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/energy-analyses/pubs/NG-GHG-LCI.pdf. Accessed 11/29/2011.

U.S. EPA. 1996. Estimate of Methane Emissions from the Natural Gas Industry. U.S. Environmental Protection Agency. Available: http://www.epa.gov/ttnchie1/ap42/ch14/related/methane.pdf. Accessed 11/29/2011.

U.S. EPA. 2011a. 2011 Inventory of Greenhouse Gas Emissions and Sinks. U.S. Environmental Protection Agency. Available: http://www.epa.gov/climatechange/emissions/usgginventory.html. Accessed 8/29/2011.

U.S. EPA. 2011b. Green Power Equivalency Calculator. U.S. Environmental Protection Agency. Available: http://www.epa.gov/greenpower/pubs/calculator.htm. Accessed 11/29/2011.

Weisser, D. 2007. A Guide to Life-Cycle Greenhouse Gas (GHG) Emissions from Electric Supply Technologies. Available: http://www.iaea.org/OurWork/ST/NE/Pess/assets/GHG_manuscript_pre-print_versionDanielWeisser.pdf. Accessed 11/29/2011.

WorldWatch Institute. 2011. Comparing Life-Cycle Greenhouse Gas Emissions from Natural Gas and Coal. Available: http://www.worldwatch.org/system/files/pdf/Natural_Gas_LCA_Update_082511.pdf. Accessed 11/29/2011.

Confidential

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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).

Stratus Consulting Appendix (Final, 2/1/2012)

Page A-2 Confidential

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Table A.1. Indirect emissions from conventional oil and gas exploration and production

Source type Source CO2 CH4 N2O

Negligible amounts of

GHG emissions

Combustion sources – stationary devices

Boilers/steam generators X X X Dehydrator reboilers X X X Heaters/treaters X X X Internal combustion engine generators

X X X

Fire pumps X X X Reciprocating compressor drivers

X X X

Turbine electric generators X X X Turbine/centrifugal compressor drivers

X X X

Well drilling X X X Flares X X X Incinerators X X X

Combustion sources – mobile sources

Mobile drilling equipment X X X Other company vehicles X X X Planes/helicopters X X X Supply boats, barges X X X Site preparation, construction, and excavation

X X X

Indirect sources Electricity imports X X X Process heat/steam imports X X X Cogeneration X X X

Vented sources – process vents Dehydration processes X Dehydrator kimray pumps X Gas sweetening processes X X

Vented sources – other venting Storage tanks and drain vessels X X Exploratory drilling X X Well testing and completions X X Pneumatic devices X X Chemical injection pumps X X Gas sampling and analysis X X



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Table A.1. Indirect emissions from conventional oil and gas exploration and production (cont.)



GHG emissions

Vented sources – maintenance/turnarounds

Mud degassing X Low pressure gas well casing X Compressor blowdowns X Compressor starts X Gathering pipeline blowdowns X Vessel blowdown X Well completions X Well unloading and workovers X

Vented sources – non-routine activities

Emergency shutdown/ emergency safety

X

Pressure relief valves X Well blowouts (when not flared) X

Fugitive sources Equipment component leaks X Wastewater treatment X


Blowdown [e.g., emergency safety blowdown (ESB)]

X

Fire suppression X Fugitive sources Air conditioning/refrigeration X



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Table A.2. Indirect emissions from oil sands and heavy oil upgrading



GHG emissions


Boilers/heaters X X X Fire pumps X X X Fire pumps X X X Internal combustion engine generators

X X X

Reciprocating compressor drivers X X X Turbine electric generators X X X Turbine/centrifugal compressor drivers

X X X

Turbines X X X Mining equipment X X X Flares X X X Catalytic oxidizers X Incinerators X X X


Mining equipment X X X Other company vehicles X X X Planes/helicopters X X X Site preparation, construction, and excavation

X X X

Indirect sources Electricity imports X X X

Process heat/steam imports X X X Vented sources – process vents

Flue gas desulfurization process vents

X

Sulfur recovery units X Catalytic cracking X Catalyst regeneration X Steam methane reforming (hydrogen plants)

X

Delayed coking X Flexi-coking X Catalytic reforming X Thermal cracking X Ventilation and degasification X Ash processing unit X Surface mining X



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Table A.2. Indirect emissions from oil sands and heavy oil upgrading (cont.)



GHG emissions

Vented sources – other venting

Storage tanks X Water tanks X Loading racks X Sand-handling X Pneumatic devices X Casing gas vents X


Compressor blowdowns X Compressor starts X Equipment/process blowdowns X Heater/boiler tube decoking X Vessel blowdown X


Emergency shut down X Pressure relief valves X

Fugitive sources Equipment component leaks X X Wastewater treatment X X Sludge/solids handling X Wastewater collection and treating X Exposed mine faces X Tailing ponds X


Fire suppression X

Fugitive sources Air conditioning/refrigeration X



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Table A.3. Indirect emissions from coalbed methane production



GHG emissions


Boilers/steam generators X X X Dehydrator reboilers X X X Fire pumps X X X Internal combustion engines and generators

X X X

Reciprocating compressor drivers X X X Turbine electric generators X X X Turbine/centrifugal compressor drivers X X X Flares X X X


Mining equipment X X X Other company vehicles X X X Site preparation, construction, and excavation

X X X

Indirect sources Electricity imports X X X Process heat/steam imports X X X

Vented sources – process vents

Dehydration processes X Dehydrator kimray pump X Gas sweetening processes X X


Water handling, tanks X Coal seam drilling and well testing X Coal handling X


Gas sampling and analysis X Compressor starts and blowdowns X Gathering pipeline blowdowns X Vessel blowdowns X Well workovers X


Gathering pipeline leaks X Pressure relief valves X Well blowdowns (when not flared) X

Fugitive sources Equipment component leaks X Wastewater treatment X X


Fire suppression X




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Table A.4. Indirect emissions from gas processing



GHG emissions


Boilers/steam generators X X X Dehydrator reboilers X X X Heaters/treaters X X X Fire pumps X X X Internal combustion engine generators X X X Reciprocating compressor drivers X X X Turbine electric generators X X X Turbine/centrifugal compressor drivers X X X Flares X X X Catalytic and thermal oxidizers X Incinerators X X X


Other company vehicles X X X Planes/helicopters X X X Supply boats, barges X X X



Dehydration processes X X Dehydrator kimray pumps X X Gas sweetening processes X X Sulfur recovery units X


Storage tanks and drain vessels X X Pneumatic devices X X Chemical injection pumps X X


Gas sampling and analysis X X Compressor blowdowns X X Compressor starts X X Vessel blowdown X X


Emergency shutdown/emergency safety X X Pressure relief valves X X

Fugitive sources Equipment component leaks X X Wastewater treatment X X


Blowdown (ESB) X Fire suppression X




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Table A.5. Indirect emissions from CO2 capture and sequestration



GHG emissions


Boilers/steam generators X X X Dehydrator reboilers X X X Heaters/treaters X X X Fire pumps X X X Internal combustion engine generators X X X Reciprocating compressor drivers X X X Turbine/centrifugal compressor drivers

X X X

Turbine electric generators X X X Well drilling X X X Flares X X X Incinerators X X X


Marine, road, or railroad tankers X X X Other company vehicles X X X Planes/helicopters X X X

Indirect sources Electricity imports X X X Vented sources – process vents Dehydration processes X X

Dehydrator kimray pumps X X Gas sweetening processes X X

Vented sources – other venting Intermediate storage X X Storage tanks X X Loading/unloading/transit X X Pneumatic devices X X Chemical injection pumps X X


Maintenance X X Gas sampling and analysis X X Compressor blowdowns X X Compressor starts X X Pipeline blowdowns X X Vessel blowdown X X


Emergency releases X X



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Table A.5. Indirect emissions from CO2 capture and sequestration (cont.)



GHG emissions

Fugitive sources Well leakage X X Equipment and pipeline leaks X X Wastewater treatment X X Fugitive emissions from ships X X Physical leakage from geological formations

X X


Fire suppression X




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Table A.6. Indirect emissions from natural gas storage and liquefied natural gas operations


Negligible amounts of GHG

emissions


Boilers/steam generators X X X Dehydrator reboilers X X X Heaters and heat exchangers X X X Fire pumps X X X Internal combustion engine generators

X X X

Pump engines X X X Reciprocating compressor drivers X X X Turbine electric generators X X X Turbine/centrifugal compressor drivers

X X X

Flares X X X Catalyst and thermal oxidizers X Incinerators X X X Vapor combustion units X


Marine vessels X X X Other company vehicles X X X


Vented sources – process vents Dehydration processes X Dehydrator kimray pumps X Gas treatment processes X X

Vented sources – other venting Gas sampling and analysis X Liquefied natural gas cold box X Gas sampling and analysis X Revaporization X Storage tanks X Loading/unloading/transit X Pneumatic devices X Chemical injection pumps X Chemical injection pumps X



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Table A.6. Indirect emissions from natural gas storage and liquefied natural gas operations (cont.)



emissions


Compressor blowdowns X Compressor starts X Pipeline blowdowns X Vessel blowdown X Compressor station venting X Storage station venting X


Emergency shutdown / emergency safety

X

Pressure relief valves X Fugitive sources Pipeline leaks X

Process equipment leaks X Storage wellheads X Vapor handling system X Wastewater treatment X X


Blowdown (ESB) X Fire suppression X




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Table A.7. Indirect emissions from liquid transportation and distribution



emissions

Combustion sources – stationary

Reciprocating compressor drivers X X X Turbine electric generators X X X Turbine/centrifugal compressor drivers X X X Boilers/steam generators X X X Heaters X X X Fire pumps X X X Internal combustion engine generators X X X Pumps X X X Flares X X X Catalyst and thermal oxidizers X X Incinerators X X Vapor combustion units X X X


Barges X X X Marine, road, or railroad tankers X X X Other company vehicles X X X Planes/helicopters X X X



Storage tanks X Loading/unloading/transit X Pneumatic devices X


Pump station maintenance X


Breakout/surge tanks X

Fugitive sources Pipeline leaks X Process equipment leaks X Wastewater treatment X X


Fire suppression X

Fugitive sources Air conditioning/refrigeration X Leak detection (SF6 emissions) X



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Table A.8. Indirect emissions from natural gas transportation and distribution



emissions


Boilers/steam generators X X X Dehydrator reboilers X X X Heaters X X X Fire pumps X X X Internal combustion engine generators

X X X

Reciprocating compressor drivers X X X Turbine electric generators X X X Turbine/centrifugal compressor drivers

X X X

Flares X X X Catalyst and thermal oxidizers X Incinerators X X X


Other company vehicles X X X Planes/helicopters X X X


Vented sources – process vents Dehydration processes X Dehydrator kimray pumps X Gas treatment processes X X

Vented sources – other venting Gas sampling and analysis X Storage tanks X Loading/unloading/transit X Pneumatic devices X Chemical injection pumps X


Compressor blowdowns X Compressor starts X Compressor station blowdowns X Pig traps and drips X Vessel blowdown X Pipeline blowdowns X


Metering and pressure regulating station

X

Pressure relief valves X Pipeline dig-ins X



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Table A.8. Indirect emissions from natural gas transportation and distribution (cont.)



emissions

Fugitive sources Pipeline leaks X Process equipment leaks X Wastewater treatment X


Upsets X Fire suppression X




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Table A.9. Indirect emissions from refining



GHG emissions


Boilers/steam generators X X X Heaters X X X Fire pumps X X X Internal combustion engine generators X X X Pumps X X X Reciprocating compressor drivers X X X Turbine electric generators X X X Turbine/centrifugal compressor drivers X X X Flares X X X Catalyst and thermal oxidizers X Incinerators X X X Coke calcining kilns X X X


Company vehicles X X X



Sulfur recovery units X Catalytic cracking X Catalytic reforming X Catalyst regeneration X Steam methane reforming (hydrogen plants)

X

Delayed coking X Flexi-coking X Asphalt production X Thermal cracking X


Heater/boiler tube decoking X

Fugitive sources Fuel gas system leaks X Wastewater collection and treating X X


Storage tanks X Loading racks X Pneumatic devices X


Compressor starts X Equipment/process blowdowns X



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Table A.9. Indirect emissions from refining (cont.)



GHG emissions


Emergency shut down X Pressure relief valves X Fire suppression X

Fugitive sources Other process equipment leaks X Sludge/solids handling X Air conditioning/refrigeration X



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Table A.10. Indirect emissions from petrochemical manufacturing



emissions


Boilers/steam generators X X X Heaters X X X Fire pumps X X X Internal combustion engine generators X X X Pumps X X X Reciprocating compressor drivers X X X Turbine electric generators X X X Turbine/centrifugal compressor drivers X X X Flares X X X Catalyst and thermal oxidizers X Incinerators X X X





Catalyst regeneration X Steam methane reforming (hydrogen plants)

X

Chemical production X X X Vented sources – other venting

Storage tanks X Loading racks X

Fugitive sources Fuel gas system leaks X Wastewater collection and treating X X


Pneumatic devices X


Compressor starts X Equipment/process blowdowns X Heater/boiler tube decoking X


Emergency shut down X Pressure relief valves X Fire suppression X

Fugitive sources Other process equipment leaks X Sludge/solids handling X Air conditioning/refrigeration X



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Table A.11. Indirect emissions from minerals and mining operations



GHG emissions


Boilers/steam generators X X X Heaters X X X Fire pumps X X X Internal combustion engines X X X Turbines X X X Flares X X X Catalytic oxidizers X Incinerators X X X


Mining equipment X X X Other company vehicles X X X Site preparation, construction, and excavation

X X X



Surface mining X Ventilation and degasification X


Water tanks X Coal seam drilling and well testing X Coal-handling X

Fugitive sources Equipment and pipeline leaks X X Wastewater treatment X


Fire suppression X




SC12618

Table A.12. Indirect emissions from retail and marketing



GHG emissions

Combustion sources - stationary

Boilers/steam generators X X X Heaters X X X Thermal oxidizers X


Marine tankers X X X Other company vehicles X X X Railroad tankers X X X Road tankers X X X

Indirect sources Electricity usage X X X Vented sources Service station storage tanks X Vented sources – non-routine activities

Fire suppression X

Fugitive sources Process equipment leaks X Air conditioning/refrigeration X



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Table A.13. Indirect emissions from electricity and heat/steam generation



GHG emissions

Combustion sources – stationary

Turbine electric generators X X X Boilers/steam generators X X X Internal combustion engine generators X X X



Vented sources Natural gas venting (maintenance on fuel line to natural gas fuel sources)

X X

Fugitive sources Natural gas equipment leaks (natural gas fuel line)

X X


Fire suppression X


STRATUS CONSULTING

1881 Ninth Street, Suite 201 Boulder, Colorado 80302 phone 303.381.8000 fax 303.381.8200 (headquarters)

1920 L Street, N.W., Suite 420 Washington, D.C. 20036 phone 202.466.3731 fax 202.466.3732

w w w . s t r a t u s c o n s u l t i n g . c o m

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