Oil Sands and the Keystone XL Pipeline:
Background and Selected
Environmental Issues
Jonathan L. Ramseur, Coordinator
Specialist in Environmental Policy
Richard K. Lattanzio
Analyst in Environmental Policy
Linda Luther
Analyst in Environmental Policy
Paul W. Parfomak
Specialist in Energy and Infrastructure Policy
Nicole T. Carter
Specialist in Natural Resources Policy
February 21, 2013
Congressional Research Service
7-5700
www.crs.gov
R42611
CRS Report for Congress
Pr
epared for Members and Committees of Congress
Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Summary
If constructed, the Keystone XL pipeline would transport crude oil (e.g., synthetic crude oil or
diluted bitumen) derived from oil sands in Alberta, Canada to destinations in the United States.
Because the pipeline crosses an international border, it requires a Presidential Permit that is issued
by the Department of State (DOS). The permit decision rests on a “national interest”
determination, a term not defined in the authorizing Executive Orders. DOS states that it has
“significant discretion” in the factors it examines in this determination.
Key events related to the Presidential Permit include
• September 19, 2008: TransCanada submitted an application for a Presidential
Permit for its Keystone XL pipeline.
• November 10, 2011: DOS announced it needed additional information
concerning alternative pipeline routes through the Nebraska Sandhills.
• January 18, 2012: In response to a legislative mandate in P.L. 112-78, DOS,
with the President’s consent, announced its denial of the Keystone XL permit.
• May 4, 2012: TransCanada submitted a revised permit application to DOS.
• January 22, 2013: Nebraska Governor approved TransCanada’s new route
through Nebraska.
Although some groups have opposed previous oil pipeline permits, opposition to the Keystone
XL proposal has generated substantially more interest among environmental stakeholders.
Pipeline opponents are not a monolithic group: some raise concerns about potential local impacts,
such as oil spills or extraction impacts in Canada; some argue the pipeline would have national
energy and climate change policy implications.
A number of key studies indicate that oil sands crude has a higher greenhouse gas (GHG)
emissions intensity than many other forms of crude oil. The primary reason for the higher
intensity: oil sands are heavy oils with a high viscosity, requiring more energy- and resource-
intensive activities to extract. However, analytical results vary due to different modeling
assumptions. Moreover, industry stakeholders point out that many analyses indicate that GHG
emissions from oil sands crude oil are comparable to other heavy crudes, some of which are
produced and/or consumed in the United States.
Because of oil sands’ increased emissions intensity, further oil sands development runs counter to
some stakeholders’ energy and climate change policy objectives. These objectives may vary
based on differing views concerning the severity of climate change risk and/or the need for
significant mitigation efforts. Opponents worry that oil sands crude oil will account for a greater
percentage of U.S. oil consumption over time, making GHG emissions reduction more difficult.
On the other hand, neither issuance of a Presidential Permit nor increased oil sands development
would preclude the implementation of energy/climate policies that would support less carbon
intensive fuels or energy efficiency improvements.
A primary local/regional environmental concern of any oil pipeline is the risk of a spill.
Environmental groups have argued that both the pipeline’s operating parameters and the material
being transported imposes an increased risk of spill. Industry stakeholders have been critical of
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
these assertions. To examine the concerns, Congress included provisions in P.L. 112-90 requiring
a review of current oil pipeline regulations and a risk analysis of oil sands crude.
Opponents of the Keystone XL pipeline and oil sands development often highlight the
environmental impacts that pertain to the region in which the oil sands resources are extracted.
Potential impacts include, among others, land disturbance and water resource issues. In general,
these local/regional impacts from Canadian oil sands development may not directly affect public
health or the environment in the United States. Within the context of a Presidential Permit, the
mechanism to consider local Canadian impacts is unclear.
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Contents
Introduction ...................................................................................................................................... 1
Section 1: Oil Sands—Overview ..................................................................................................... 2
Oil Sands Estimates and Locations ........................................................................................... 4
Oil Sands Extraction Processes ................................................................................................. 7
Mining ................................................................................................................................. 8
In Situ .................................................................................................................................. 9
Properties of Oil Sands-Derived Crudes Compared to Other Crudes ....................................... 9
Section 2: Keystone XL Pipeline—Overview ............................................................................... 12
Federal Requirements to Consider the Pipeline’s Environmental Impacts .............................. 13
Presidential Permit Requirements for Cross-Border Pipelines ......................................... 14
Identification of Environmental Impacts During the NEPA Process................................. 16
Identification of Environmental Impacts During the National Interest
Determination ................................................................................................................. 18
Consideration of Environmental Impacts Outside of the United States ............................ 20
Other Oil Pipelines from Canada............................................................................................. 21
Section 3: Selected Environmental Issues ..................................................................................... 23
GHG Emissions Intensity of Oil Sands Crude Oils ................................................................. 23
Life-Cycle Assessments .................................................................................................... 24
GHG Life-Cycle Assessments of Canadian Oil Sands ...................................................... 25
Canadian Oil Sands Compared to Other Crude Oils ......................................................... 27
Climate Change Concerns ....................................................................................................... 28
GHG Emissions Intensities of Fossil Fuels ....................................................................... 29
Fossil Fuels—Proven Reserve Comparisons .................................................................... 30
Other Policy Decisions ...................................................................................................... 31
Oil Spills .................................................................................................................................. 31
Oil Sands Crudes—Characteristics ................................................................................... 32
Keystone XL Pipeline Operating Parameters .................................................................... 35
Oil Pipeline Spill Data from Alberta ................................................................................. 36
Keystone XL Spill Frequency Estimates ........................................................................... 38
Spill Size Estimates ........................................................................................................... 38
Environmental Impacts of Spills of Oil Sands Crude ....................................................... 39
Recent Pipeline Spills........................................................................................................ 41
Further Study ..................................................................................................................... 43
Oil Sands Extraction Concerns ................................................................................................ 43
Land Disturbances ............................................................................................................. 44
Water Resources and Quality Issues.................................................................................. 47
Figures
Figure 1. U.S. Imports of Canadian Crude Oil by Type .................................................................. 4
Figure 2. Illustration of Estimated In-Place Oil Sands Resources by Region ................................. 5
Figure 3. EIA Estimated Proven Oil Reserves ................................................................................. 7
Figure 4. Alberta Oil Sands.............................................................................................................. 8
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Figure 5. Illustration of Steam-Assisted Gravity Drainage (SAGD) ............................................... 9
Figure 6. The Keystone XL Pipeline System ................................................................................. 13
Figure 7. Oil Pipelines between Canada and the United States ..................................................... 21
Figure 8. Well-to-Wheel GHG Emissions Estimates for Canadian Oil Sands Crudes .................. 26
Figure 9. Well-to-Wheel GHG Emissions Estimates for Global Crude Resources ....................... 27
Figure 10. Life-Cycle GHG Emissions Estimates for Gasoline, Natural Gas, and Coal ............... 29
Figure 11. Illustration of Energy from Global Fossil Fuel Sources ............................................... 31
Figure 12. Illustrative Comparison of Energy Yields by Selected Sources ................................... 45
Tables
Table 1. Selected Global Crude Oil Specifications ........................................................................ 11
Table 2. Milestones in the Keystone XL Pipeline National Interest Determination ...................... 19
Table 3. Major U.S.-Canadian Petroleum Import Pipelines .......................................................... 22
Table 4. PHMSA Comparison of Oil Pipeline Incidents in Alberta and United States .................. 37
Table A-1. Agencies With Jurisdiction or Expertise Relevant to Pipeline Impacts ....................... 50
Appendixes
Appendix. Additional Information ................................................................................................. 50
Contacts
Author Contact Information........................................................................................................... 51
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Introduction
The proposed Keystone XL pipeline has received considerable attention in recent months. If
constructed, the pipeline would transport crude oil (e.g., synthetic crude oil or diluted bitumen)
derived from oil sands resources in Alberta, Canada to destinations in the United States and
ultimately the international market. Policymakers continue to debate various issues associated
with the proposed pipeline. Although some groups have opposed previous oil pipelines—Alberta
Clipper and the Keystone mainline, both of which are operating—opposition to the Keystone XL
proposal has generated substantially more interest among environmental stakeholders.
“Oil Sands” vs. “Tar Sands”
This report uses the term “oil sands” to describe a particular type of nonconventional oil resource that is found
throughout the world in varying quantities. The terms “oil sands” and “tar sands,” among other labels, are often used
interchangeably to describe this resource. The U.S. Geological Survey states that tar sands is a “generic term that has
been used for several decades to describe petroleum-bearing rocks exposed on the Earth’s surface.”1 The natural
bitumen in the oil sands is black and sticky like "tar," a man-made material, generated as a by-product of heating coal
to extremely high temperatures. Moreover, oil sands deposits have been mined since antiquity for use as sealants and
paving materials.2
Some federal government resources refer to the deposits as tar sands, some oil sands, and some use both terms.
Opponents of oil sands development often refer to the material as tar sands, which arguably carries a negative
connotation.
Before the Keystone XL pipeline can be constructed, its owner/operator, TransCanada,3 must
receive a Presidential Permit, which is issued by the State Department. The decision to issue this
permit has provided (and continues to provide) a rallying point for environmental groups.
The Presidential Permit application—submitted by TransCanada—for the pipeline’s construction
represents a singular decision made by the Administration that the pipeline would serve the
national interest. Such a decision requires the identification of factors that would inform that
determination, as well as resulting impacts. For environmental groups opposed to the project, the
identification of specific environmental impacts associated with the project provides evidence on
which arguments against the project may be based.
Pipeline opponents are not a monolithic group and their concerns vary. Some raise concerns about
potential local impacts, such as oil spills. Some highlight the oil extraction impacts in Canada.
Some argue the pipeline would have national energy and climate change policy implications.4 For
these particular opponents, the Presidential Permit decision has been seen as a gauge of the
Administration’s support for reducing domestic fossil fuel use and greenhouse gas emissions.
Thus, the pipeline proposal has provided a vehicle to galvanize advocates interested in climate
change mitigation, particularly the reduction or replacement of fossil fuel use.
1 U.S. Geological Survey, Natural Bitumen Resources of the United States, 2006.
2 E.D. Attanasi et al., Natural Bitumen and Extra-Heavy Oil, World Energy Council, 2010 Survey of Energy Resources,
2010, at http://energy.usgs.gov/portals/0/Rooms/economics/text/WEC10NBEHO.pdf.
3 TransCanada is a public energy company, based in Canada, that owns oil and natural gas pipelines and power plants,
among other assets, in Canada, the United States, and Mexico. See http://www.transcanada.com.
4 Arguments supporting the pipeline’s construction cover an analogous range, from local job creation to national energy
security. See CRS Report R41668, Keystone XL Pipeline Project: Key Issues, by Paul W. Parfomak et al.
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This report focuses on selected environmental concerns raised in conjunction with the proposed
pipeline and the oil sands crude it will transport. As such, the environmental issues discussed in
this report do not represent an exhaustive list of concerns raised by environmental groups.
Moreover, many of the environmental concerns are not unique to oil sands. One could compose
analogous lists for all forms of energy: coal, natural gas, nuclear, biofuels, conventional crude oil.
Therefore, the oil sands/pipeline issues discussed in this report, when practicable, will be
compared to other energy sources, particularly conventional crude oil development.
• Section One provides an overview of oil sands by addressing the following
questions: what are oil sands; how are they extracted; how do oil sands crude oils
compare to other crude oils?
• Section Two provides an overview of the Keystone XL pipeline, including a
project description; a discussion of the federal requirements to consider
environmental impacts from the pipeline, including the Department of State’s
national interest determination, obligations pursuant to the National
Environmental Policy Act, and a list of recent milestones in the national interest
determination process; and information about other international oil pipelines.
• Section Three discusses selected environmental issues, including greenhouse gas
emissions intensity, broader energy policy concerns, pipeline oil spill risks, and
two oil sands extraction concerns: land disturbance and water resources.
• An Appendix contains additional information.
This report is intended to supplement other CRS reports that address different aspects of the
Keystone XL proposal, including
• CRS Report R41668, Keystone XL Pipeline Project: Key Issues, by Paul W.
Parfomak et al.
• CRS Report R42124, Proposed Keystone XL Pipeline: Legal Issues, by Adam
Vann, Kristina Alexander, and Kenneth R. Thomas.
• CRS Report R42537, Canadian Oil Sands: Life-Cycle Assessments of
Greenhouse Gas Emissions, by Richard K. Lattanzio.
Section 1: Oil Sands—Overview
The term oil sands generally refers to a mixture of sand, clay and other minerals, water, and
bitumen. Oil sands bitumen is very dense5 and highly viscous (i.e., resistant to flow). At room
temperature, oil sands bitumen has the consistency of cold molasses. This property makes it
difficult to transport.6
Bitumen can also be processed into a fuel, because it is a form of crude oil that has undergone
degradation over geologic time. At some point, the bitumen may have been lighter crude oil that
lost its lighter, more volatile components due to natural processes.
5 Oil sands bitumen contains up to 50% (by weight) asphaltenes, a class of hydrocarbon of high molecular weight.
6 This same property lends itself well to making asphalt—a mixture of asphaltenes and petrolenes—useful for road
paving.
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Companies developing oil sands reserves must partially process or dilute the bitumen before it
can be transported. This processed/diluted bitumen falls into three general categories:
• Upgraded bitumen, or synthetic crude oil (SCO). SCO is produced from
bitumen at a refinery that turns the very heavy hydrocarbons into a lighter
material.
• Diluted Bitumen (DilBit). DilBit is bitumen that is blended with lighter
hydrocarbons, typically natural gas condensates, to create a lighter, less viscous,
and more easily transportable material. DilBit may be blended as 25% to 30%
condensate and 70% to 75% bitumen.
• Synthetic bitumen (Synbit). Synbit is typically a combination of bitumen and
SCO. Blending the lighter SCO with the heavier bitumen results in a product that
more closely resembles conventional crude oil. Typically the ratio is 50%
synthetic crude and 50% bitumen, but blends, and their resulting properties, may
vary significantly.
Figure 1 illustrates the proportions of crude oil types that Canada has exported to the United
States in recent years. The figure indicates that “blended bitumen” exports, which includes both
Dilbit and Synbit, have nearly tripled in the past six years. They are also expected to constitute
most of the growth in oil sands production in the foreseeable future.7
7 Canadian Association of Petroleum Producers, Crude Oil: Forecast, Markets & Pipelines, June 2012.
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Figure 1. U.S. Imports of Canadian Crude Oil by Type
2005-2011
800
700
600
rels 500
400
s of Bar 300
Million 200
100
-
2005
2006
2007
2008
2009
2010
2011
Conventional Crude
Synthetic Crude
Blended Bitumen
Source: Prepared by CRS; data from Canada’s National Energy Board: 2005-2008 data provided in personal
communication; 2009-2011 data are available at http://www.neb-one.gc.ca/clf-nsi/rnrgynfmtn/sttstc/
crdlndptrlmprdct/stmtdcndncrdlxprttpdstn-eng.html.
Notes: Conventional crude includes conventional light, medium, and heavy crude oil. “Blended bitumen”
includes bitumen blended with light hydrocarbons (Dilbit) and/or synthetic crude oil (Synbit).
Oil Sands Estimates and Locations
Resource estimates indicate that oil sands deposits are located throughout the world in varying
amounts (Figure 2). By far, the two largest estimated deposits of oil sands are in Canada,
particularly the Province of Alberta,8 and in Venezuela’s Orinoco Oil Belt (Figure 2). As stated
by the U.S. Geological Survey, the “resource quantities reported here … are intended to suggest,
rather than define the resource volumes that could someday be of commercial interest.”9 For a
variety of reasons (e.g., technology and economics), only a small percentage—less than 0.4%
based on information in 2007—of the estimated oil sands resources are currently being
produced.10
8 Some oil sands deposits are located in northwest Saskatchewan next to the Alberta deposit, but the resource base has
not been officially determined (Canadian Association of Petroleum Producers (CAPP), Crude Oil: Forecast, Markets &
Pipelines, June 2011).
9 U.S. Geological Survey (USGS), Heavy Oil and Natural Bitumen Resources in Geological Basins of the World, 2007.
10 Ibid.
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Figure 2. Illustration of Estimated In-Place Oil Sands Resources by Region
Billion barrels
98% i
% n Ca
n
nada
92% in V
92%
e
in V n
e e
n zue
e
l
zue a
Source: Prepared by CRS; original figure and data from U.S. Geological Survey (USGS), Heavy Oil and Natural
Bitumen Resources in Geological Basins of the World, 2007. CRS added the notes regarding percentages in Canada
and Venezuela, based on the USGS report data.
Notes: Column bars represent “original natural bitumen in place-discovered” (ONBIP Discovered) and “total
original natural bitumen in place” (TONBIP). The latter includes ONBIP-discovered plus “prospective additional
oil,” which is “the amount of resource in an unmeasured section or portion of a known deposit believed to be
present as a result of inference from geological and often geophysical study.” These estimates are substantial y
higher than “proven reserve” estimates, discussed below. The different regions in the figure include North
America, South America, Europe, Africa, Transcaucasia, Middle East, Russia, South Asia, East Asia, Southeast Asia
and Oceania.
Perhaps a more useful estimate of oil resources is “proven reserves.” According to the Energy
Information Administration (EIA), proven energy reserves are “estimated quantities of energy
sources that analysis of geologic and engineering data demonstrates with reasonable certainty are
recoverable under existing economic and operating conditions.”11 The Government of Alberta
estimates that its proven oil sands reserves are approximately 170 billion barrels,12 which
accounts for 97% of Canada’s total proven oil reserves, 7%-10% of the total estimated resource in
Canada’s geologic basin (Figure 2).
11 See EIA Glossary at http://www.eia.gov/.
12 Government of Alberta, “About the Resource,” at http://oilsands.alberta.ca/resource.html (accessed April 6, 2012).
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U.S. Oil Sands: Resource Estimates and Extraction Efforts
Estimates of U.S. oil sands deposits vary. According to a “measured-in-place” estimate from the U.S. Geological
Survey (USGS), deposits of oil sands in the United States may contain approximately 36 billion barrels.13 This is not a
proven reserve estimate, but an estimate comparable to the “original natural bitumen” estimates in Figure 2. As that
figure illustrates, the estimated resource of oil sands in the United States accounts for approximately 2% of the total
North American oil sands resource.
The estimated resource of U.S. oil sands is located in several states in varying amounts: Alaska (41%), Utah (33%),
Texas (11%), Alabama (5%), California (5%), and Kentucky (5%).14 The deposits are not uniform. For instance, some
deposits (estimated at less than 15%)15 in Utah may be amenable to surface mining techniques. In contrast, the Alaska
deposits are buried below several thousand feet of permafrost.16 In addition, the physical/chemical properties of oil
sands can differ by location. The U.S. Bureau of Land Management (BLM) states that “Canadian tar sands are different
than U.S. tar sands in that Canadian tar sands are water wetted, while U.S tar sands are hydrocarbon wetted.” Such
differences may influence whether extraction of particular deposits is economically and technologically viable.
According to BLM, oil from oil sands deposits is not produced on a significant commercial level in the United States.17
Although prior attempts, dating back decades, have been made in several locations, various challenges hindered
commercial development.18
A comprehensive assessment of oil sands-related activities in the United States is beyond the scope of this report.
Efforts to extract U.S. oil sands continue at several locations, particularly in Utah. A Canadian company, U.S. Oil
Sands, owns leases in Utah that cover over 32,000 acres.19 As of the date of this report, the company has received a
permit to begin relatively smal -scale oil sands mining operations on approximately 200 acres of state-owned lands.20
According to the company, it plans to begin operations in late 2013,21 achieving an initial output of approximately
2,000 barrels per day.22 This project has been opposed by environmental groups, some of which are appealing the
permit decision in the court system.23
13 See USGS, Natural Bitumen Resources of the United States, 2006, at http://pubs.usgs.gov/fs/2006/3133/pdf/FS2006-
3133_508.pdf. The USGS estimates are largely based on studies from 1984 and 1995.
14 The USGS assessment identifies additional states—Oklahoma, New Mexico, and Wyoming—with potential oil
sands deposits, but these would each account for less than one percent of the total U.S. estimate.
15 See Bureau of Land Management, Draft Programmatic Environmental Impact Statement and Possible Land Use
Plan Amendments for Allocation of Oil Shale and Tar Sands Resources on Lands Administered by the Bureau of Land
Management in Colorado, Utah, and Wyoming, Appendix B, January 2012.
16 V.A. Kamath et al, “Assessment of Resource and Recovery Potential of Ugnu Tar Sands, North Slope Alaska,” in
Meyer, R.F., ed., Heavy crude and tar sands—Fueling for a clean and safe environment: Sixth United Nations Institute
for Training and Research (UNITAR) Conference on Heavy Crude and Tar Sands, Houston, Texas, February 12–17,
1995, p. 141–157.
17 Bureau of Land Management, Oil Shale and Tar Sands Programmatic EIS Information Center, at
http://ostseis.anl.gov.
18 An archived CRS report includes a history of oil sands activities in the United States. See CRS Report RL34258,
North American Oil Sands: History of Development, Prospects for the Future, by Marc Humphries.
19 See U.S. Oil Sands website, at http://www.usoilsandsinc.com.
20 See U.S. Oil Sands, Notice of Intention to Commence Large Mining Operations, 2009; Utah Department of
Environmental Quality, Administrative Hearings conducted May 2012, both available at http://www.deq.utah.gov/
locations/prsprings/index.htm.
21 U.S. Oil Sands, Press Release, “US Oil Sands Announces Q1 2012 Financial Results, Provides Operational Update
and Grant of Options,” at http://www.usoilsandsinc.com/documents/news/USO-2012-05-29-pressrelease.pdf.
22 U.S. Oil Sands, Notice of Intention to Commence Large Mining Operations, 2009.
23 See, e.g., Utah Tar Sands Resistance, at http://tarsandsutah.blueskyinstitute.org.
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Figure 3 illustrates the estimated proven oil reserves for the top 15 nations in 2012. Canada ranks
third behind Venezuela and Saudi Arabia, due to its supply of oil sands in Alberta.24
Figure 3. EIA Estimated Proven Oil Reserves
Top 15 Nations in 2012—Compared to 2000 Estimates
Source: Prepared by CRS; data from EIA, “International Energy Statistics,” at http://www.eia.gov/.
Notes: United States’ proven reserves for 2012 based on data from 2009, because that is the most recent year
of available data.
Proven reserve estimates can change dramatically over a relatively short time (Figure 3). EIA
data indicate that Canada’s proven reserve estimate increased from approximately 5 billion
barrels of oil (BBO) in 2002 to 175 BBO in 2003. Similarly, Venezuela’s estimated proven
reserves increased by more than 100 BBO between 2010 and 2011.25 The increases resulted from
the addition of oil sands in Canada and extra-heavy oil in Venezuela to the total estimated proven
reserves for each country.
Oil Sands Extraction Processes
Oil sands extraction processes are generally divided into two categories: mining and in situ
operations, which are described below. Figure 4 identifies the locations of areas accessible to
mining and in situ sites of oil sands in Alberta. According to the Government of Alberta, 80% of
the Canadian oil sands are accessible by in situ methods only.
24 EIA “International Energy Statistics,” at http://www.eia.gov/.
25 Ibid.
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Figure 4. Alberta Oil Sands
Potential Mining and In Situ Sites
Source: Government of Alberta, at http://oilsands.alberta.ca/reclamation.html#JM-
OilSandsArea.
Notes: According to the Canadian Association of Petroleum Producers, smaller oil sands
deposits are in northwest Saskatchewan next to the Alberta deposit, but the resource
base has not been official y determined (Crude Oil: Forecast, Markets & Pipelines, June 2011).
In 2011, mining operations accounted for slightly more than 50% of current production. However,
the Canadian Association of Petroleum Producers (CAPP) projects in situ production will exceed
mining by 2015, and account for approximately 60% of total production by 2025.26 Both
processes are briefly discussed below.
Mining
Oil sands deposits that are less than about 250 feet below the surface can be removed using
conventional strip-mining methods. The strip-mining process includes removal of the overburden
(i.e., primary soils and vegetation), excavation of the resource, and transportation to a processing
facility.
26 Canadian Association of Petroleum Producers (CAPP), Crude Oil: Forecast, Markets & Pipelines, June 2012.
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In Situ
Oil sands deposits that are deeper than 75 meters are recovered using one of three in situ
methods: primary production,27 cyclic steam stimulation (CSS), and steam-assisted gravity
drainage (SAGD). CSS and SAGD, which accounted for approximately 75% of Alberta’s in situ
recovery in 2010, involve injecting steam into an oil sands reservoir.28 The steam heats the
bitumen, decreasing its viscosity and enabling its collection. Based on 2010 data, SAGD accounts
for the greatest percentage of in situ recovery and is the preferred method of recovery for most
new projects.29 SADG involves a top well for steam injection and a bottom well for bitumen
production.30 Figure 5 provides an illustration of this process.
Figure 5. Illustration of Steam-Assisted Gravity Drainage (SAGD)
Source: Pembina Institute, at http://www.pembina.org.
Properties of Oil Sands-Derived Crudes Compared to Other Crudes
Crude oil is a complex mix of hydrocarbons, ranging from simple compounds with small
molecules and low densities to very dense compounds with extremely large molecules. Three key
properties of crude oils include the following:
27 According to the Energy Resource Conservation Board (ERCB), “Primary production includes those schemes that
use water and polymer injection as a recovery method.” Alberta’s Energy Reserves 2010 and Supply/Demand Outlook
2011-2020, 2011.
28 ERCB, 2011.
29 ERCB, 2011.
30 In contrast, CSS uses a vertical well to liquefy the bitumen, which is then pumped to the surface using the same well.
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• API Gravity. API31 Gravity measures the weight of a crude oil compared to
water. It is reported in degrees (º) by convention. API gravities above 10º indicate
crude oils lighter than water (they float); API gravities below 10º indicate crude
oils heavier than water (they sink). Although the definition of “heavy” crude oil
may vary, it is generally defined by refiners as being at or below 22.3º API
gravity.32
• Sulfur Content. Sulfur content in crude oil is an indication of potential
corrosiveness due to the presence of acidic sulfur compounds. Sulfur content is
measured as an overall percentage of free sulfur and sulfur compounds in a crude
oil by weight. Total sulfur content in crude oils generally ranges from below
0.05% to 5.0%. Crudes with more than 1.0% free sulfur or other sulfur-
containing compounds are typically referred to as “sour,” below 0.5% sulfur as
“sweet.”33
• Total Acid Number. Total Acid Number (TAN) measures the composition of
acids in a crude which can gauge its potential for corrosion, particularly in a
refinery. TAN value is measured as the number of milligrams (mg) of potassium
hydroxide (KOH) needed to neutralize the acids in one gram of oil. As a rule-of-
thumb, crude oils with a TAN greater than 0.5 are considered to be potentially
corrosive due to the presence of naphthenic acids.34
Table 1 compares Alberta’s different oil sands crudes with other crude oils extracted in the United
States and around the world. The data indicate that all oil sands crudes would be considered
heavy crudes. Heavy crudes are found throughout the world, including the United States. The data
indicate that oil sands crudes resemble other heavy crudes in terms of sulfur content and TAN.
31 American Petroleum Institute.
32 U.S. Energy Information Administration, Crude Oil Input Qualities, “Definitions, Sources and Explanatory Notes,”
web page, July 28, 2011, http://www.eia.gov/dnav/pet/TblDefs/pet_pnp_crq_tbldef2.asp. In the marine tanker industry,
heavy grade crudes are defined as crudes with an API below 25.7º, as bitumen emulsions, or as certain viscous fuel
oils. See McQuilling Services, LLC, “Carriage of Heavy Grade Oil,” Garden City, NY, 2011,
http://www.meglobaloil.com/MARPOL.pdf.
33 JDL Oil and Gas Exploration, Inc., “Crude Oil Basics,” web page, July 28, 2011, http://www.jdloil.com/
oil_basics.htm.
34 R.D. Kane and M.S. Cayard, “A Comprehensive Study of Naphthenic Acid Corrosion,” Paper No. 02555, Corrosion
2002, http://www.icorr.net/wp-content/uploads/2011/01/napthenic_corrosion.pdf.
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Table 1. Selected Global Crude Oil Specifications
°API
Sulfur
TAN
Source
Crude Oil Name
Gravity
(Weight %) (mgKOH/g)
Alberta Oil Sands Crude Oils
- Dilbits
Access Western Blend
21.9
3.94
1.70
Cold
Lake
20.9
3.78
0.97
Peace River Heavy
20.8
4.97
2.49
Seal
Heavy
20.5
4.64
1.86
Smiley
Colevil e
20.0
2.98
0.97
Wabasca
Heavy
20.3
4.10
1.03
Western Canadian Select
20.6
3.46
0.92
- DilSynBit
Albian Heavy
19.1
2.42
0.51
Selected Heavy Crude Oils
Western Canada
Western Canadian Blend
20.7
3.16
0.71
U.S. (California)
Hondo Monterey
19.4
4.70
0.43
Kern
River
13.4
1.10
2.36
Venezuela Pilon
16.2
2.47
1.60
Bachaquero
13.5
2.30
2.63
Tia Juana Heavy
12.3
2.82
3.90
Laguna
10.9
2.66
2.82
Boscan
10.1
5.40
0.91
Mexico Maya
21.5
3.31
0.43
Italy Tempa
Rossa
20.4
5.44
0.05
United Kingdom
Captain
19.2
0.70
2.40
Indonesia Duri
(Sumatran
Heavy)
20.8
0.20
1.27
Selected Medium and Light Crude Oils (> 22.3° API)
U.S. (Alaska)
Alaskan North Slope
32.1
0.93
0.12
U.S. (Texas)
West Texas Intermediate
40.8
0.34
0.10
U.S. (Gulf of Mexico)
Hoops Blend
31.6
1.15
1.07
Thunderhorse
28.3
0.64
0.47
Poseidon
Heavy-sour
29.7
1.65
0.41
Mars
Heavy-sour
28.9
2.05
0.51
Southern Green Canyon Heavy-Sour
28.4
2.48
0.17
Nigeria Bonga
30.2
0.25
0.55
Norway Statfjord
28.3
0.64
0.47
Dubai
Dubai Fateh Heavy
30.8
2.07
0.05
Saudi Arabia
Arabian Heavy
27.5
2.95
0.40
Arabian
Light
33.7
1.96
0.05
Sources: Canadian crude data from Crude Quality Inc., Canadian Crude Quick Reference Guide, Updated June
2, 2011, at http://www.crudemonitor.ca; Other crude oil data from: Capline, Crude Oil Assays, at
http://www.caplinepipeline.com; BP Crude Assays, at http://www.bp.com; ExxonMobil, at
http://www.exxonmobil.com/crudeoil/about_crudes_region.aspx; “Benchmark West Texas Intermediate Crude
Assayed,” Oil and Gas Journal, 1994; McQuilling Services, LLC, “Carriage of Heavy Grade Oil,” Garden City, NY,
2011, http://www.meglobaloil.com/MARPOL.pdf; Hydrocarbon Publishing Co., Opportunity Crudes Report II,
Southeastern, PA, 2011, p. 5, http://www.hydrocarbonpublishing.com/ReportP/Prospectus-
Opportunity%20Crudes%20II_2011.pdf.
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Notes: The crude oils listed above are not an exhaustive list, nor do they represent a specific percentage of
global consumption. The crudes listed above are selected examples of different crude oils from around the
world. Multiple crude oils from Venezuela are included to indicate the range of parameters in different heavy
crude oils.
Section 2: Keystone XL Pipeline—Overview
As originally proposed by TransCanada in September 2008,35 the Keystone XL pipeline would
involve two major segments (Figure 6). The first segment—approximately 850 pipeline miles in
the United States36—would cross the U.S.-Canadian border into Montana, pass through South
Dakota, and terminate in Steele City, Nebraska. The second segment—approximately 480 miles
and labeled as the “Gulf Coast Project” in Figure 6—would connect an existing pipeline in
Cushing, Oklahoma with locations in southern Texas.37
As discussed below, the Department of State (DOS) announced its denial of the Keystone XL
permit in January 2012. In February 2012, TransCanada announced that it would proceed with
development of the southern pipeline segment as a separate proposal. As this segment is within
the United States, it does not require a Presidential Permit (discussed below). Thus, the revised
permit, which TransCanada submitted on May 12, 2012, only applies to the first segment that
connects Canada with the United States.
The Keystone XL pipeline would have the capacity to deliver 830,000 barrels per day (bpd), a
substantial flow rate compared to other U.S.-Canada import pipelines (Table 3).The 36-inch-
diameter pipeline would require a 50-foot-wide permanent right-of-way along the route.
Approximately 95% of the pipeline right-of-way would be on privately owned land, with the
remaining 5% almost equally state and federal land. Private land uses are primarily agricultural—
farmers and cattle ranchers. Above ground facilities associated with the pipelines include pump
stations (with associated electric transmission interconnection facilities), mainline valves, and
delivery metering facilities.
The Keystone XL pipeline and the “Gulf Coast Project” would combine with two existing
pipeline segments to complete TransCanada’s Keystone Pipeline System. This system is depicted
in Figure 6. These existing segments include
• The Keystone Mainline: A 30-inch pipeline with a capacity of nearly 600,000
bpd that connects Alberta oil sands to U.S. refineries in Illinois. The U.S. portion
runs 1,086 miles and begins at the international border in North Dakota. The
Keystone Mainline began operating in June 2010.
• The Keystone Cushing Extension: A 36-inch pipeline that runs 298 miles from
Steele City, Nebraska to existing crude oil terminals and tanks farms in Cushing,
Oklahoma. The Cushing Extension began operating February 2011.
35 The original application and related documents are available at the Department of State Keystone XL website, at
http://keystonepipeline-xl.state.gov/archive/index.htm.
36 1,183 miles from its origin in Alberta, Canada. See U.S. Department of State, Final Environmental Impact Statement
for the Proposed Keystone XL Project, August 2011.
37 An additional 50-mile segment would connect to additional locations in Texas. For further details, see U.S.
Department of State, Final Environmental Impact Statement for the Proposed Keystone XL Project, August 2011.
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Figure 6. The Keystone XL Pipeline System
Completed, Under Construction, and Proposed Segments
Source: Nebraska Department of Environmental Quality, Nebraska’s Keystone XL Pipeline Evaluation:
Final Evaluation Report, Volume 1, Chapter 1, at https://ecmp.nebraska.gov/deq-seis/.
Federal Requirements to Consider the Pipeline’s
Environmental Impacts
When considering a Presidential Permit application, the DOS must conduct an environmental
review of its actions pursuant to the National Environmental Policy Act (NEPA, 42 U.S.C. §4321
et seq.). This process highlighted many environmental impacts associated with the construction,
operation, and maintenance of the pipeline system and associated facilities.
Issues that arose and environmental impacts identified during DOS efforts to process
TransCanada’s application for a Presidential Permit ultimately resulted in the denial of its permit
application. With TransCanada’s May 4, 2012 reapplication for a permit to construct the Keystone
XL pipeline project, the Presidential Permit process and NEPA compliance process begin anew.
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Generally, federal agencies have no authority to control siting of oil pipelines, even interstate
pipelines.38 Instead, the primary siting authority for oil pipelines generally would be established
under applicable state law (which may vary considerably from state to state).39 However, in
accordance with Executive Order 13337, a facility connecting the United States with a foreign
country, including a pipeline, requires a Presidential Permit from DOS before it can proceed.40
Key elements of the Presidential Permit process, including DOS efforts to identify environmental
impacts associated with the TransCanada’s 2008 permit application are discussed below (and
summarized in Table 2). Included in that discussion are relevant activities and requirements
associated with DOS compliance with NEPA and its obligation to determine whether the
proposed pipeline would serve the national interest.
Presidential Permit Requirements for Cross-Border Pipelines
A decision to issue or deny a Presidential Permit application is based on a determination that the
proposed project would serve the “national interest.” This term is not defined in the Executive
Orders. In the course of making that determination, DOS may consider a wide range of factors
such as the project’s potential impacts to the environment, economy, energy security, foreign
policy, and others. Regarding its determination, DOS has stated:
Consistent with the President’s broad discretion in the conduct of foreign affairs, DOS has
significant discretion in the factors it examines in making a National Interest Determination .
The factors examined and the approaches to their examination are not necessarily the same
from project to project.41
However, the Department has identified the following as key factors it considered in making
previous national interest determinations for oil pipeline permit applications:
• Environmental impacts of the proposed projects;
• Impacts of the proposed projects on the diversity of supply to meet U.S. crude oil
demand and energy needs;
38 This is in contrast to interstate natural gas pipelines, which, under Section 7(c) (15 USC §717f(c)) of the Natural Gas
Act, must obtain a “certificate of public convenience and necessity” from the Federal Energy Regulatory Commission.
39 Federal laws and regulations address other matters, including worker safety and environmental concerns. See CRS
Report R41536, Keeping America’s Pipelines Safe and Secure: Key Issues for Congress, by Paul W. Parfomak and
CRS Report RL33705, Oil Spills in U.S. Coastal Waters: Background and Governance, by Jonathan L. Ramseur.
40 This authority was originally vested in the U.S. State Department with the promulgation of Executive Order 11423,
“Providing for the performance of certain functions heretofore performed by the President with respect to certain
facilities constructed and maintained on the borders of the United States,” in 1968. Executive Order 13337, “Issuance
of Permits With Respect to Certain Energy-Related Facilities and Land Transportation Crossings on the International
Boundaries of the United States,” of April 30, 2004, amended this authority and the procedures associated with permit
review for energy-related projects, but did not substantially alter the exercise of authority or the delegation to the
Secretary of State in E.O. 11423. Due to the particular significance to Presidential Permit issuance for pipelines,
provisions in E.O 13337 will be cited in this report. For further information on the Executive Order authority and
related issues, see CRS Report R42124, Proposed Keystone XL Pipeline: Legal Issues, by Adam Vann, Kristina
Alexander, and Kenneth R. Thomas.
41 The U.S. State Department, Final Environmental Impact Statement for the Keystone XL Project, August 2011,
“Introduction” (as amended September 22, 2011), p. 1-4, available at http://keystonepipeline-xl.state.gov/archive/
dos_docs/feis/index.htm#.
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• The security of transport pathways for crude oil supplies to the United States
through import facilities constructed at the border relative to other modes of
transport;
• Stability of trading partners from whom the United States obtains crude oil;
• Relationship between the United States and various foreign suppliers of crude oil
and the ability of the United States to work with those countries to meet overall
environmental and energy security goals;
• Impact of proposed projects on broader foreign policy objectives, including a
comprehensive strategy to address climate change;
• Economic benefits to the United States of constructing and operating proposed
projects; and
• relationships between proposed projects and goals to reduce reliance on fossil
fuels and to increase use of alternative and renewable energy sources.42
DOS may consider additional factors to inform its national interest determination for a given
project. However, pursuant to E.O. 13337, for each permit application it receives for an energy-
related project, DOS must request the views of the Attorney General, Administrator of the
Environmental Protection Agency (EPA), and Secretaries of Defense, the Interior, Commerce,
Transportation, Energy, and Homeland Security (or the heads of those departments or agencies
with relevant authority or responsibility over relevant elements of the proposed project). DOS
may request the views of additional federal department and agency heads, as well as additional
local, state, or tribal agencies, as it deems appropriate for a given project. DOS must also invite
public comment on the proposed project.
If, after considering the views and assistance of various agencies and the comments from the
public, DOS finds that issuance of a permit would serve the national interest, then a Presidential
Permit may be issued. Specific to the Keystone XL pipeline, in its May 2012 Presidential Permit
application, TransCanada states
The project will serve the national interest of the United States by providing a secure and
reliable source of Canadian crude oil to meet the demand from refineries and markets in the
United States, by providing critically important market access to developing domestic oil
supplies in the Bakken formation in Montana and North Dakota, and by reducing U.S.
reliance on crude oil supplies from Venezuela, Mexico, the Middle East, and Africa. The
project will also provide significant economic and employment benefits to the United States,
with minimal impacts on the environment.43
It is during the NEPA process that DOS will determine the degree to which the proposed pipeline
project may impact the environment, as well as identify potential mitigation measures or
protections necessary to reduce the potential for adverse environmental impacts. When the NEPA
process is complete, DOS may use that assessment of environmental impacts, with other factors,
to determine if the project does, in fact, serve the national interest.
42 Ibid.
43 TransCanada Keystone Pipeline, L.P., “Application of TransCanada Keystone Pipeline L.P. for a Presidential Permit
Authorizing the Construction, Operation, and Maintenance of Pipeline Facilities for the Importation of Crude Oil to be
Located at the United States-Canada Border,” U.S. Dept. of State, May 4, 2012, pp. 1-2, available at
http://www.keystonepipeline-xl.state.gov/.
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Identification of Environmental Impacts During the NEPA Process44
The DOS review of a Presidential Permit application explicitly requires compliance with multiple
federal environmental statutes.45 Environmental requirements identified within the context of the
NEPA process has drawn considerable attention.
Pursuant to NEPA, in considering an application for a Presidential Permit, DOS must take into
account environmental impacts of a proposed facility and directly related construction. In
complying with NEPA, federal agencies must prepare an Environmental Impact Statement (EIS)
for projects determined to have “significant” environmental impacts. DOS concluded that
issuance of a Presidential Permit for the proposed construction, connection, operation, and
maintenance of the Keystone XL Pipeline and its associated facilities at the United States border
may have a significant impact on the environment within the meaning of NEPA.46 As a result, in
August 2011, DOS issued a final EIS to identify the reasonably foreseeable impacts from the
proposed Keystone XL pipeline.47 Similarly, DOS announced (June 15, 2012)48 it was preparing a
Supplement to the final EIS to assess the May 4, 2012 permit application.
EIS preparation is done in two stages, resulting in a draft and final EIS. NEPA regulations require
the draft EIS to be circulated for public and agency comment, followed by a final EIS that
incorporates those comments.49 The agency responsible for preparing the EIS, in this case DOS,
is designated the “lead agency.” In developing the EIS, DOS must rely on information provided
by TransCanada. For example, TransCanada’s original permit application included an
Environmental Report which was intended to provide the State Department with sufficient
information to understand the scope of potential environmental impacts of the project.50
In preparing the draft EIS, the lead agency must request input from “cooperating agencies,”
which include any agency with jurisdiction by law or with special expertise regarding any
environmental impact associated with the project.51 The original Keystone XL permit process
involved 11 federal cooperating agencies, including the Environmental Protection Agency (EPA),
44 For more detailed NEPA information, see CRS Report RL33152, The National Environmental Policy Act (NEPA):
Background and Implementation, by Linda Luther.
45 DOS is explicitly directed to review the project’s compliance with the National Historic Preservation Act (16 U.S.C.
§470f), the Endangered Species Act (16 U.S.C. §1531 et seq.), and Executive Order 12898 of February 11, 1994 (59
Federal Register 7629), concerning environmental justice.
46 U.S. Department of State, “Notice of Intent to Prepare an Environmental Impact Statement and to Conduct Scoping
Meetings and Notice of Floodplain and Wetland Involvement and to Initiate Consultation under Section 106 of the
National Historic Preservation Act for the Proposed TransCanada Keystone XL Pipeline,” 74 Federal Register 5020,
January 28, 2009.
47 In preparing an EIS associated with a Presidential Permit application, NEPA regulations promulgated by both the
Council of Environmental Quality (CEQ) and the State Department would apply to the proposed project. CEQ
regulations implementing NEPA (under 40 C.F.R. §§1500-1508) apply to all federal agencies. NEPA regulations
applicable to State Department actions, which supplement the CEQ regulations, are found at 22 C.F.R. §161.
48 77 Federal Register 36032 (June 15, 2012).
49 For information regarding NEPA requirements, see CRS Report RL33152, The National Environmental Policy Act
(NEPA): Background and Implementation, by Linda Luther.
50 Documents submitted by TransCanada for its initial 2008 Presidential Permit application, now archived by DOS, are
available at http://keystonepipeline-xl.state.gov/archive/proj_docs/index.htm.
51 40 C.F.R. §1508.5. Also, Executive Order 13337 directs the Secretary of State to refer an application for a
Presidential Permit to other specifically identified federal departments and agencies on whether granting the application
would be in the national interest.
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as well as state agencies. Table A-1 (in the Appendix) provides a list of various agencies and
their roles in the pipeline permitting process.
In addition to its role as a cooperating agency, EPA is also required to review and comment
publicly on the EIS and rate both the adequacy of the EIS itself and the level of environmental
impact of the proposed project.52 EPA’s role in rating draft EISs for the Keystone XL pipeline
project had a significant impact on the NEPA process for TransCanada’s 2008 Presidential Permit
application.
The State Department released its draft EIS for the proposed Keystone XL Pipeline project for
public comment on April 16, 2010.53 On July 16, 2010, EPA rated the draft EIS “Inadequate.”54
EPA found that potentially significant impacts were not evaluated and that the additional
information and analysis needed was of such importance that the draft EIS would need to be
formally revised and again made available for public review. DOS issued a supplemental draft
EIS on April 15, 2011.55 In addition to addressing issues associated with EPA’s inadequacy rating,
the supplemental draft EIS addressed comments received from other agencies and the public. On
June 6, 2011, EPA sent a letter to the State Department that rated the supplemental draft EIS as
having “Insufficient Information” and having “Environmental Objections” to the proposed
action.56 EPA acknowledged that DOS had “worked diligently” to develop additional information
in response to EPA’s comments on the draft EIS, but additional analysis was needed on several
points, including potential oil spill risks and lifecycle greenhouse gas emissions associated with
the proposed project.
In its June 6, 2011 letter, EPA refers to agreements with DOS that certain deficiencies identified
in the supplemental draft EIS would be addressed in the final EIS. On August 26, 2011, DOS did
issue the final EIS for the proposed Keystone XL Pipeline (hereafter referred to as 2011 FEIS).57
Although DOS addressed stakeholder comments, including those of EPA, in its 2011 FEIS,58 it is
unknown whether EPA made any additional comments to DOS during the 90-day public review
period marking the national interest determination (discussed below). Regardless, EPA will have
52 Rating the EIS takes place after the draft is issued. The EIS could be rated either “Adequate,” “Insufficient
Information,” or “Inadequate.” EPA’s rating of a project’s environmental impacts may range from “Lack of
Objections” to “Environmentally Unsatisfactory.” In rating the impact of the action itself, EPA would specify one of
the following: “Lack of Objections,” “Environmental Concerns,” “Environmental Objections,” or “Environmentally
Unsatisfactory.” The federal agency would then be required to respond to EPA’s rating, as appropriate. For more
information, see the U.S. Environmental Protection Agency’s “Environmental Impact Statement (EIS) Rating System
Criteria” at http://www.epa.gov/compliance/nepa/comments/ratings.html.
53 EISs prepared by DOS for TransCanada’s 2008 Presidential Permit application, now archived by DOS, are available
at http://keystonepipeline-xl.state.gov/archive/dos_docs/index.htm.
54 U.S. Environmental Protection Agency’s July 16, 2010, letter to the U.S. Department of State commenting on the
draft EIS for the Keystone XL project is available at http://yosemite.epa.gov/oeca/webeis.nsf/%28PDFView%29/
20100126/$file/20100126.PDF.
55 See footnote 53.
56 U.S. Environmental Protection Agency’s June 6, 2011 letter to the U.S. Department of State commenting on the
supplemental draft EIS for the Keystone XL project is available at http://yosemite.epa.gov/oeca/webeis.nsf/
%28PDFView%29/20110125/$file/20110125.PDF?OpenElement.
57 U.S. Department of State, Final Environmental Impact Statement for the Proposed Keystone XL Project, August 26,
2011 (with portions amended September 22, 2011), available at http://keystonepipeline-xl.state.gov/archive/dos_docs/
feis/index.htm.
58 2011 final EIS, “Appendix A, Responses to Comments and Scoping Summary Report,” available at
http://keystonepipeline-xl.state.gov/archive/dos_docs/feis/vol3and4/appendixa/index.htm.
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an opportunity to comment on NEPA documentation (i.e., the Supplement to the Final EIS)
prepared for TransCanada’s May 2012 permit application.
Identification of Environmental Impacts During the National Interest
Determination
Generally, the NEPA review is considered complete when (or if) the federal agency issues a final
Record of Decision (ROD), formalizing the selection of a project alternative. However, for a
project subject to a Presidential Permit, issuance of a final EIS marks the beginning of a 90-day
public review period during which DOS gathers additional information necessary to make its
national interest determination. For previous Presidential Permits, a ROD and National Interest
Determination were issued as the same document.59
Issuance of the ROD and National Interest Determination involve distinctly different, yet
interrelated requirements. Under NEPA, DOS must fully assess the environmental consequences
of an action and potential project alternatives before making a final decision. NEPA does not
prohibit a federal action that has adverse environment impacts; it requires only that a federal
agency be fully aware of and consider those adverse impacts before selecting a final project
alternative. That is, NEPA is intended to be part of the decision-making process, not dictate a
particular outcome.
The DOS’s national interest determination, however, does dictate a particular outcome—approval
or denial of a Presidential Permit. Issuance of a Presidential Permit is predicated on the finding
that the proposed project would serve the national interest. While NEPA does not prohibit federal
actions with adverse environmental impacts, a project’s adverse environmental impacts may lead
the DOS to determine that the project is not in the national interest.
Table 2 summarizes milestones in the national interest determination for TransCanada’s initial
permit application.60
59 U.S. Department of State, Department of State Record of Decision and National Interest Determination,
TransCanada Keystone Pipeline, LP Application for Presidential Permit, February 25, 2008.
60 A more comprehensive timeline is provided in CRS Report R41668, Keystone XL Pipeline Project: Key Issues, by
Paul W. Parfomak et al.
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Table 2. Milestones in the Keystone XL Pipeline National Interest Determination
Administrative, Congressional, State, and Company Actions
Date Description
2011
August 26
DOS issues its FEIS; the 90-day public review period for the National Interest Determination begins.
October 24
The Governor of Nebraska calls the state legislature into a special session to determine if siting
legislation can be crafted and passed for pipeline routing in Nebraska.
November 10 DOS announces that additional information will be needed regarding alternative pipeline routes that
would avoid the Nebraska Sand Hills before National Interest Determination can be made. Officials
suggest that analysis needed to prepare the supplemental EIS, including additional public comment,
could be completed as early as the first quarter of 2013.
November 14 TransCanada announces that it will work with the Nebraska Department of Environmental Quality
(DEQ) to identify a potential pipeline route that would avoid the Nebraska Sand Hills.
November 22 The Governor of Nebraska signs legislation passed during the special session directing the Nebraska
DEQ to work col aboratively with the State Department to gather information necessary for a
supplemental EIS.
December 23
The Temporary Payrol Tax Cut Continuation Act of 2011 (P.L. 112-78) is enacted, including
provisions requiring the Secretary of State to issue a permit for the project within 60 days, unless
the President determines the project is not in the national interest.
2012
January18
DOS announces, with the President’s consent, that it will deny the Keystone XL permit. It states
that its decision was predicated on the fact that the 60-day deadline under P.L. 112-78 did not
provide sufficient time to obtain information necessary to assess the current project’s national
interest.
February 3
DOS issues the formal permit denial in the Federal Register (Vol. 77, p. 5614), which included a
Memorandum from the President stating that the project would, “at this time … not serve the
national interest.”
February 27
TransCanada announced that it would proceed with development of the southern pipeline segment
as a separate proposal. This segment would connect Cushing, Oklahoma with points in southern
Texas. As it would not cross the U.S. border, it would not require a Presidential Permit.
April 19
TransCanada submits to the Nebraska DEQ an initial analysis of alternative Keystone XL pipeline
routes that avoid the Sand Hills.
May 4
TransCanada submits a new Presidential Permit application to DOS, reflecting new information
regarding alternative pipeline routes through Nebraska. The NEPA process for the new project
begins, potential y drawing upon relevant documents from the 2011 final EIS.
June 15
DOS announces its plan to prepare a Supplement to the FEIS (77 Federal Register 36032).
September 5
TransCanada submits a Supplemental Environmental Report to Nebraska DEQ with a preferred
route alternative.
2013
January 4
Nebraska DEQ submits its final evaluation report to Governor Dave Heineman for approval.
January 22
Nebraska Governor Heineman approves the new route reviewed by the Nebraska DEQ.
Source: Prepared by the Congressional Research Service. Permit-related documents available at Department of
State website at, http://www.keystonepipeline-xl.state.gov/ and Nebraska DEQ website, at
http://www.deq.state.ne.us/.
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Consideration of Environmental Impacts Outside of the United States
With regard to compliance requirements under NEPA, DOS is not required to identify or analyze
environmental impacts that occur within another sovereign nation that result from actions
approved by that sovereign nation. However, to further the purpose of the NEPA, Executive
Order 12114 “Environmental Effects Abroad of Major Federal Actions,” requires federal agencies
to prepare an analysis of significant impacts from a federal action abroad. This order does not,
however, require federal agencies to evaluate the impacts of projects outside the United States
when that project is undertaken with the involvement or participation of the foreign nation in
which the project is undertaken—as is the case with Canada’s participation in the Keystone XL
pipeline project. While it is not subject to it, as a matter of policy, DOS uses the order as guidance
and includes information in the final EIS regarding the environmental analysis conducted by the
Canadian government.
Apart from any obligation under NEPA, however, DOS may take into consideration
extraterritorial project impacts, as it deems necessary, as part of its national interest
determination. For example, as noted above, factors DOS considered in making its determination
for past pipeline projects included the proposed project’s impact on broader policy objectives,
including a comprehensive strategy to address climate change, and the relationships between the
proposed project and U.S. goals to reduce reliance on fossil fuels and to increase use of
alternative and renewable energy sources. In its January 2012 denial of TransCanada’s initial
Presidential Permit application, DOS did not specifically cite these issues as playing a role in its
determination. However, it is likely that they will continue to be factors of concern to project
opponents.
As discussed below, opponents of the pipeline proposal have expressed concern over
environmental impacts outside of the United States that may occur as a direct or indirect result of
the pipeline’s construction. When it denied TransCanada’s initial permit application, DOS did not
cite environmental impacts outside the United States among the factors contributing to that
decision. The degree to which environmental impacts abroad may have influenced that initial
permit denial is unclear. In processing TransCanada’s 2012 permit application, it may be assumed
that DOS will consider environmental impacts abroad as it did for the 2008 permit application.
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Other Oil Pipelines from Canada
As illustrated in Figure 7, multiple pipelines connect Canadian oil resources with the United
States. Several of these pipelines have been constructed in recent years.
Figure 7. Oil Pipelines between Canada and the United States
Existing and Proposed
Source: Canadian Association of Petroleum Producers, Crude Oil: Forecast, Markets & Pipelines, June 2012.
Notes: The Keystone XL route in this figure identifies the developer’s originally proposed “preferred
alternative.”
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Table 3 identifies pipelines that have applied for a Presidential Permit in the past six years. The
table indicates that the Keystone XL permit process timetable, which is ongoing, has substantially
exceeded prior permit process timetables.
Table 3. Major U.S.-Canadian Petroleum Import Pipelines
Presidential Permit Activity (2006–Present)
Permit
EIS
Permit
First Year of
Capacity
Pipeline Operator Submitted
Prepared?
Issued
Operation
(bpd)
Southern
Southern
April 2007
No
June 2008
2009
186,000
Lights
Lights
(LSr)a
Keystoneb TransCanada
April 2006
Yes
March 2008
2010
591,000
Alberta
Enbridge May
2007 Yes
August
2009 2010 450,000
Clipperc
Keystone
TransCanada September
2008 Yes
Denied
NA 830,000
XLd
January 2012
Keystone
TransCanada May
2012
Forthcominge
XLd
Source: Prepared by CRS; pipeline status and capacity information from CAPP, 2011. More specific sources
identified below.
Notes:
a. 72 Federal Register 41383, July 27, 2007; 73 Federal Register 32620, June 9, 2008.
b. DOS website, at http://www.keystonepipeline.state.gov.
c. DOS website, at http://www.albertaclipper.state.gov.
d. DOS website, at http://www.keystonepipeline-xl.state.gov.
e. On June 15, 2012, DOS announced it was preparing a Supplement to the FEIS issued in August 2011.
When DOS issued the Presidential Permit for the first Keystone pipeline project in 2008, DOS
concluded that the project “would result in limited adverse environmental impacts” and would
serve the national interests of the United States for the following reasons:
It increases the diversity of available supplies among the United States’ worldwide crude oil
sources. Increased output from the [Western Canada Sedimentary Basin] can be utilized by a
growing number of refineries in the United States that have access and means of transport for
these increased supplies.
It shortens the transportation pathway for a portion of United States crude oil imports. Crude
oil supplies in Western Canada represent the largest and closest foreign supply source to
domestic refineries that do not require marine transportation.
It increases crude oil supplies from a source region that has been a stable and reliable trading
partner of the United States and does not require exposure of crude oil in high seas transport
and railway routes that may be affected by heightened security and environmental concerns.
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It provides additional supplies of crude oil to make up for the continued decline in imports
from several other major U.S. suppliers.61
Proponents of the Keystone XL pipeline may point to these statements as reasons to issue a
Presidential Permit to the XL proposal.
Section 3: Selected Environmental Issues
The environmental issues raised by opponents of the Keystone XL pipeline cover a wide range.
These issues involve both local/regional concerns—some in the United States, some in Canada—
and national/global concerns. The variety of issues raised by pipeline opponents suggest that the
stakeholders are not a monolithic group.
This section does not provide an exhaustive list of environmental issues raised by opponents of
the pipeline proposal. Instead, this section discusses several issues that (1) appear to be central to
stakeholder opposition and (2) relate to the material that would be transported in the pipeline: oil
sands crude oil. These selected environmental issues include the following:
• Greenhouse gas emissions intensity;
• Climate change policy;
• Oil spill risk; and
• Oil sands extraction impacts
GHG Emissions Intensity of Oil Sands Crude Oils62
Greenhouse gas (GHG) emissions, primarily carbon dioxide (CO2) and methane, are emitted
during a variety of stages in oil sands production. Although all fossil fuel development
activities—and other forms of energy to varying degrees—emit GHG emissions, opponents of the
Keystone XL pipeline contend that oil sands have a higher emissions intensity than other forms of
crude oil.63 In this context, emissions intensity means GHG emissions per units of production
(e.g., barrels or energy).
Industry stakeholders argue that this conclusion is overstated, asserting that GHG emissions from
oil sands crude oil are comparable to some other global crudes, some of which are produced
and/or consumed in the United States.64 The issue has generated considerable debate, attention,
and analyses from multiple parties.
61 DOS, Record of Decision and National Interest Determination, Keystone Pipeline, 2008, at
http://www.cardnoentrix.com/keystone/project/SignedROD.pdf.
62 This section is an abridged version of CRS Report R42537, Canadian Oil Sands: Life-Cycle Assessments of
Greenhouse Gas Emissions, by Richard K. Lattanzio.
63 See, e.g., NRDC, Setting the Record Straight: Lifecycle Emissions of Tar Sands, November 2010.
64 See, e.g., Canadian Association of Petroleum Producers, The Facts on Oil Sands, April 2012, at http://www.capp.ca.
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This section (1) describes the tool—life-cycle assessments—used for comparisons; (2) discusses
the oil sands life-cycle assessment results; and (3) compares oil sands emissions intensities with
other crude oils.
Life-Cycle Assessments
A life-cycle assessment (LCA) is an analytic method used for evaluating and comparing the
environmental impacts of various products.65 LCAs can be used to identify, quantify, and track
emissions of CO2 and other GHG emissions arising from the development of hydrocarbon
resources, and to express them in a single, universal metric: carbon dioxide equivalent (CO2e) per
unit of fuel or fuel use.66 The results of an LCA can be used to evaluate the GHG emissions
intensity of various stages of the fuel’s life cycle, as well as to compare the emissions intensity of
one type of fuel or method of production to another.
GHG emissions profiles modeled by most LCAs are based on a set of boundaries commonly
referred to as “cradle-to-grave,” or, in the case of transportation fuels such as petroleum, “Well-
to-Wheel” (WTW). WTW assessments for petroleum-based transportation fuels focus on the
emissions associated with the entire life cycle of the fuel. This includes
• extraction;
• transportation;
• upgrading and/or refining;
• distribution of refined product (e.g., gasoline, diesel, jet fuel); and
• combustion of the fuel.
Inclusion of the final combustion phase allows for the most complete picture of crude oil’s impact
on GHG emissions, as this phase can contribute up to 70%-80% of WTW emissions. However,
other LCAs, such as well-to-tank (WTT) assessments, may focus solely on production and/or
extraction.
Both study types are valid, but they tell different stories. Oil sands opponents often highlight
results from WTT studies, because results from WTT comparisons show oil sands crudes’
emissions intensities to be considerably higher than conventional oils. Oil sands proponents often
point to WTT results: the emission intensity differences are less pronounced due to the inclusion
of the combustion phase.
65 For a discussion of LCAs and biofuels, see (archived) CRS Report R40460, Calculation of Lifecycle Greenhouse
Gas Emissions for the Renewable Fuel Standard (RFS), by Brent D. Yacobucci and Kelsi Bracmort.
66 Greenhouse gases include carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs),
perfluorocarbons (PFCs), and sulfur hexafluoride (SF6), among many others. In order to compare and aggregate
different greenhouse gases, various techniques have been developed to index the effect each greenhouse gas has to that
of carbon dioxide, where the effect of CO2 equals one. When the various gases are indexed and aggregated, their
combined quantity is described as the CO2-equivalent.
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GHG Life-Cycle Assessments of Canadian Oil Sands
A number of published and publicly available studies have attempted to assess the life-cycle GHG
emissions data for Canadian oil sands crudes. The studies examined in this report include the
LCAs analyzed by DOS in its 2011 FEIS. A CRS survey of these studies reveals the following:
1. Canadian oil sands crudes are, on average, somewhat more GHG emission-
intensive than the crudes they would displace in the U.S. refineries, with an
average range of increases from 14%-20% over the average well-to-wheel
(WTW) for all transportation fuels sold or distributed in the United States; and
2. Well-to-tank (WTT) emissions, which omit the combustion phase, have an
average range of increase from 72%-111% over the average WTT emissions for
all transportation fuels sold or distributed in the United States.
These dramatically different ranges highlight the importance of LCA boundaries and data
presentation. When a comparison is expressed on a WTT basis rather than on a WTW basis, GHG
emissions from Canadian oil sands crudes show values that are significantly higher than reference
crudes. This difference is due to the omission of the combustion phase, which generates the vast
majority of GHG emissions and generally yields minimal variance among different crude oils.
The studies identify two main reasons for the range of increases in GHG emissions intensity:
• oil sands are heavier and more viscous than lighter crude oil types on average,
and thus require more energy- and resource-intensive activities to extract; and
• oil sands are compositionally deficient in hydrogen, and have a higher carbon,
sulfur, and heavy metal content than lighter crude oil types on average, and thus
require more processing to yield consumable fuels by U.S. standards.
Figure 8 presents a summary of the WTW GHG emissions estimates for various Canadian oil
sands crude types and production processes as reported by several studies. Variability among the
estimates is the result of each study’s design and input assumptions.67
67 Discussed in detail in CRS Report R42537, Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas
Emissions, by Richard K. Lattanzio.
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Figure 8. Well-to-Wheel GHG Emissions Estimates for Canadian Oil Sands Crudes
Source: CRS, from studies cited in CRS Report R42537, Canadian Oil Sands: Life-Cycle Assessments of Greenhouse
Gas Emissions, by Richard K. Lattanzio. Average U.S. petroleum baseline for 2005 provided by U.S. Environmental
Protection Agency (U.S. EPA), Renewable Fuel Standard Program (RFS2): Regulatory Impact Analysis, February 2010,
EPA-420-R-10-006, with data sourced from DOE/NETL, Development of Baseline Data and Analysis of Life Cycle
GHG Emissions of Petroleum Based Fuels, November 2008.
Notes: Emission intensity measured in grams of carbon dioxide-equivalent per megajoule of lower heating value
gasoline (gCO2e/MJ LHV). U.S. EPA 2005 (U.S. Average) assesses “the average life cycle GHG profile for
transportation fuels sold or distributed in the United States in 2005 [and] is determined based on the weighted
average of fuels produced in the U.S. plus fuels imported into the U.S. minus fuels produced in the U.S. but
exported to other countries for use” (NETL 2008, p. ES-5). This baseline includes Canadian oil sands, but does
not include emissions from some of the most carbon-intensive imported crude oils (e.g., Venezuelan Heavy) due
to modeling uncertainties (NETL 2008, p. ES-7; NETL 2009, p. ES-2). For information on crude oil types and
production processes, see CRS Report R42537, Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas
Emissions, by Richard K. Lattanzio.
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Canadian Oil Sands Compared to Other Crude Oils
Many of the LCA studies examined by DOS compared the GHG emission intensity of Canadian
oil sands crude oil to other crude oils. Figure 9 presents the results of one of the more
comprehensive studies, which was prepared by the U.S. Department of Energy’s National Energy
Technology Laboratory (NETL) in 2009. NETL compared WTW GHG emissions of reformulated
gasoline across various crude oil feedstocks. NETL concluded that WTW GHG emissions from
gasoline produced from a weighted average of Canadian oil sands crudes are approximately 17%
higher than that from gasoline derived from the average mix of crudes sold or distributed in the
United States in 2005 (Figure 9). This corresponds to an increase in WTT (i.e., “production”)
GHG emissions of 80% over the 2005 average production emissions for imported transportation
fuels to the United States (18 gCO2e/MJ).
Figure 9. Well-to-Wheel GHG Emissions Estimates for Global Crude Resources
Source: CRS, from NETL, An Evaluation of the Extraction, Transport and Refining of Imported Crude Oils and the
Impact of Life Cycle Greenhouse Gas Emissions, National Energy Technology Laboratory, March 27, 2009.
Notes: For further details concerning this figure and the NETL study, see CRS Report R42537, Canadian Oil
Sands: Life-Cycle Assessments of Greenhouse Gas Emissions, by Richard K. Lattanzio.
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Similar to the LCAs of Canadian oil sands crudes, assessments of other global crude oil resources
are bounded by specific design factors and input assumptions that can affect the results.68
Both opponents and proponents of oil sands development and the Keystone XL pipeline may be
able to use results from one or more of the above studies to advance their position. For example,
opponents often use WTT comparisons to highlight the GHG emissions intensity of the oil sands
extraction process. On the other hand, proponents often point out that the GHG emissions
intensity of oil sands is comparable to other heavy crudes that are used and/or produced in the
United States. Both assertions are supported by the analyses, but the above results suggest that
these assertions may not tell the complete story.
The data underlying the assertions are generated by conducting LCAs. Although LCAs have
emerged as an important analytical tool for comparing the GHG emissions of various
hydrocarbon resources, LCAs retain many variables and uncertainties. The life-cycle of
hydrocarbon fuels is complex and differs by fuel. LCAs rely on a large number of analytical
design features that are needed to model their emissions. As noted above, certain factors that
could alter the results (e.g., land use changes) are omitted, due, in part, to their additional
complexity. Therefore, comparing results across resources or production methods may be
problematic.
Climate Change Concerns
Some groups oppose the construction of the Keystone XL pipeline because they contend it would
facilitate further development of oil sands, a potential outcome that runs counter to their climate
change policy objectives.69 These objectives range from reducing the carbon intensity of the
nation’s fuel portfolio to reducing (or eliminating) all fossil fuel use. This range of objectives is
likely related to positions concerning the severity of climate change risk and/or the need for
dramatic mitigation efforts.
For example, some environmental groups are concerned that the increased imports of oil sands
crudes (and the resulting increase in emissions intensity) would undermine ongoing climate
mitigation efforts, such as support for less carbon-intensive energy (e.g., renewables) or energy
efficiency improvements.70
Others have expressed more dire predictions. A prominent climate scientist, outspoken advocate,
and leading opponent of the Keystone XL pipeline, James Hansen, is often quoted as saying that
oil sands development would be “game over” for climate change mitigation.71 Other advocates
for stringent climate change mitigation measures repeat this phrase.72
68 These are discussed in detail in CRS Report R42537, Canadian Oil Sands: Life-Cycle Assessments of Greenhouse
Gas Emissions, by Richard K. Lattanzio.
69 See, e.g., Kenny Bruno et al, Tar Sands Invasion: How Dirty and Expensive Oil from Canada Threatens America’s
New Energy Economy, May 2010, at http://www.nrdc.org/energy/files/TarSandsInvasion.pdf.
70 See, e.g., Kenny Bruno et al, Tar Sands Invasion: How Dirty and Expensive Oil from Canada Threatens America’s
New Energy Economy, May 2010; Simon Mui, “Tar Sands and GHG Emissions: Setting the Record Straight,” Natural
Resource Defense Council Switchboard, November 16, 2010.
71 A more complete quote that includes this phrase: “If Canada proceeds, and we do nothing, it will be game over for
the climate …. Canada’s tar sands, deposits of sand saturated with bitumen, contain twice the amount of carbon dioxide
emitted by global oil use in our entire history. If we were to fully exploit this new oil source, and continue to burn our
(continued...)
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A comprehensive assessment of the “game over” contention is beyond the scope of this report.
The following discussion provides additional context for this notion and the broader
energy/climate policy concerns voiced by pipeline opponents.
GHG Emissions Intensities of Fossil Fuels
How does the GHG emissions intensity of oil sands compare to other fossil fuels, particularly
coal? Authoritative analyses that provide such comparisons are sparse. One study from a peer-
review journal compares the GHG emissions intensity of oil sands with other fossil fuels. The
study found that oil sands crude oil emissions intensity is slightly less than emissions intensity
from underground coal mining, but surpasses the life-cycle emissions intensity from surface coal
mining. Figure 10 illustrates this result. CRS added the line with the arrows to focus one’s
attention on the comparison described above.
One must be cautious when singling out oil sands crudes, because other heavy crude oils would
also be comparable to coal’s emissions intensity, as indicated in Figure 9. Regardless, the relative
comparison in Figure 10 may draw the attention of certain stakeholders. If heavier crudes, such
as those derived from oil sands, were to replace crude oils in the United States with less GHG
emissions intensity, the emissions intensity of the U.S. energy portfolio would—all things being
equal—increase. Such a result would make GHG emissions reductions more difficult.
Figure 10. Life-Cycle GHG Emissions Estimates for Gasoline, Natural Gas, and Coal
GHG Emissions for Global Warming Potentials of 20 and 100 years
Source: Prepared by CRS from Burnham, A., et al, “Life-Cycle Greenhouse Gas Emissions of Shale Gas, Natural
Gas, Coal, and Petroleum,” Environmental Science and Technology, Vol. 46, 2012, pp. 619–627.
Notes: CRS added the line with the two arrows that connects the oil sands emission intensity with the
underground coal mining emission intensity.
(...continued)
conventional oil, gas and coal supplies, concentrations of carbon dioxide in the atmosphere eventually would reach
levels higher than in the Pliocene era [emphasis added] (James Hansen, “Game Over for the Climate,” New York Times,
Op-Ed, May 9, 2012).
72 See, e.g., Interview with Bill McKibben on Bill Moyers website, February 2012, at http://billmoyers.com/2012/02/
13/bill-mckibben-on-climate-change-and-the-keystone-pipeline/.
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Fossil Fuels—Proven Reserve Comparisons
How do Alberta oil sands compare to global supplies of other fossil fuels? Figure 11 compares
the total energy that would be generated if all of the proven reserves of global fossil fuels were
combusted. The data indicate that the global supply of coal’s proven reserves accounts for the
majority of potential energy from proven reserves of all fossil fuels. Alberta oil sands’ proven
reserves represent approximately 3% of the total amount of energy in global proven reserves of
fossil fuels.
Readers should also use caution when examining the comparison in Figure 11.73 Such a
comparison is problematic for a host of reasons, an exhaustive list of which is beyond the scope
of this report. In general, fossil fuels are not easily interchangeable, especially in the
transportation sector. Different fuels provide different energy services, and these relationships
may vary by location. For example, oil provides the energy for most of the U.S. transportation
sector (e.g., motor vehicles). Altering such relationships may require dramatic infrastructure
changes.
Moreover, the data in Figure 11 do not account for the cost of extracting and developing the
fossil fuel resources, which may vary by resource and location. Economic decisions are subject to
technological and policy changes. For instance, a carbon constrained policy (e.g., a carbon tax)
would favor natural gas over other fossil fuels—all else being equal—because natural gas emits
fewer GHG emissions per unit of energy than other fossil fuels.
In addition, proven reserve estimates can change, as discussed above and illustrated in Figure 3.
Ten years ago, the Alberta oil sands column in the figure below would have been absent,
according to proven reserve estimates at the time. Likewise, other energy sources (e.g., gas from
shale formations) have become economically feasible in recent years, altering the proven reserve
calculation for natural gas.
73 Other sources have provided similar comparisons, including (1) Neil Swart and Andrew Weaver, “The Alberta Oil
Sands and Climate,” Nature Climate Change, Vol. 2, March 2012; and (2) James Hansen, “Cowards in Our
Democracies: Part 2,” January 2012, at http://www.columbia.edu/~jeh1/mailings/2012/20120130_CowardsPart2.pdf.
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Figure 11. Illustration of Energy from Global Fossil Fuel Sources
Based on Proven Reserve Estimates (2008)
200
180
160
its
140
n
l U
) 120
a 17
rm
0
rm
100
e
1
h
X
80
T
h
(1
h
is
60
rit
B
40
20
0
Coal
Nat
a u
t ra
u l
Oil
Al
A berta
a
Gas
Oil Sa
Oi
n
l Sa ds
d
Source: Prepared by CRS; proven reserve data from Energy Information Administration (EIA), International
Energy Statistics, at http://www.eia.gov. Although EIA has oil data for 2010, the most recent annual data for coal
and natural gas is 2008. British Thermal Units generated by multiplying proven reserve data (in short tons,
barrels, and cubic feet) by appropriate annual heat content data, available in EIA, Annual Energy Review, October
2011, Appendices.
Notes: Other comparisons of global fossil fuels can be found at (1) Neil Swart and Andrew Weaver, “The
Alberta Oil Sands and Climate,” Nature Climate Change, Vol. 2, March 2012; and (2) James Hansen, “Cowards in
Our Democracies: Part 2,” January 2012, at http://www.columbia.edu/~jeh1/mailings/2012/
20120130_CowardsPart2.pdf.
Other Policy Decisions
The issuance of a Presidential Permit, allowing the Keystone XL pipeline construction, does not
preclude the implementation of energy/climate policies that would support less carbon intensive
fuels or encourage energy efficiency. Future policies that alter consumer behavior or affect market
decisions of energy producers could counter the relative emissions intensity increase that oil
sands would provide.
Oil Spills
A primary environmental concern of any oil pipeline is the risk of a spill. The impacts of an oil
spill depend on multiple factors, including the type of oil spilled and the size and location of the
spill.74 Location is generally considered the most important factor, as highlighted by DOS: “The
greatest concern would be a spill in environmentally sensitive areas, such as wetlands, flowing
74 See CRS Report RL33705, Oil Spills in U.S. Coastal Waters: Background and Governance, by Jonathan L.
Ramseur.
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streams and rivers, shallow groundwater areas, areas near water intakes for drinking water or for
commercial/industrial uses, and areas with populations of sensitive wildlife or plant species.”75
Based on experience with pipelines historically, the Keystone XL pipeline will likely lead to some
number of oil spills over the course of its operating life, regardless of design, construction, and
safety measures. However, the frequency, volume, and location of spills are unknown. Some
contend that proponents of the pipeline understate oil spill risks; others contend that pipeline
opponents overstate the risks.
Pipeline integrity concerns—whether real or perceived—were magnified by a 2010 pipeline spill
in Michigan and a 2011 pipeline spill in Montana. A key question for policymakers is whether the
Keystone XL proposed pipeline is different from other pipelines. For example, would the
Keystone XL project impose a greater or lesser risk of an oil spill than another oil pipeline?
Oil Sands Crudes—Characteristics
Some environmental groups have argued that the pipeline would pose additional oil spill risks due
to the material being transported.76 They have asserted that diluted bitumen (Dilbit) poses
particular concerns of volatility and corrosivity that may pose additional risks to the pipeline’s
integrity. Whether or not these issues warrant concern is debatable. Regardless, the concerns led
Congress to enact provisions in P.L. 112-90 calling for further study. These issues are discussed
below.
Volatility
According to a 2011 environmental groups’ report, “at high temperatures, the mixture of light,
gaseous condensate, and thick, heavy bitumen, can become unstable.”77 It is uncertain what
constitutes a high temperature in this context. For example, would the temperature be within the
range of the pipeline’s operating parameters? Regardless, some have questioned this conclusion.78
One of the citations in the 2011 report that is cited as support for the above statement is an
“expert viewpoint”79 that does not specifically address pipeline transportation, but seems to
discuss behavior of oil sands in the reservoir. The other is a study modeling liquid-column
75 2011 FEIS, “Executive Summary,” p. ES-9, available at http://keystonepipeline-xl.state.gov/archive/dos_docs/feis/
vol1/index.htm.
76 Anthony Swift et al, Tar Sands Pipelines Safety Risks, Joint Report by Natural Resources Defense Council, National
Wildlife Federation, Pipeline Safety Trust, and Sierra Club, February 2011 (hereafter Tar Sands Pipelines Safety
Risks); see also Anthony Swift et al, Pipeline and Tanker Trouble: The Impact to British Columbia’s Communities,
Rivers, and Pacific Coastline from Tar Sands Oil Transport, Joint Report by Natural Resources Defense Council,
Pembina Institute, and Living Oceans Society, November 2011 (hereafter Pipeline and Tanker Trouble).
77 Tar Sands Pipelines Safety Risks.
78 See Crude Quality Inc., Report regarding the U.S. Department of State Supplementary Draft Environmental Impact
Statement, May 2011; and Energy Resources Conservation Board, Press Release, “ERCB Addresses Statements in
Natural Resources Defense Council Pipeline Safety Report,” February 2011.
79 As cited by Tar Sands Pipelines Safety Risks: Expert Viewpoint (John Shaw, University of Alberta) – Phase
Behaviors of Heavy Oils and Bitumen,” Schlumberger Ltd., 2011. The cited website no longer leads to this source, but
CRS located the material using the Internet “Wayback Machine,” at http://web.archive.org.
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separation in oil pipelines—perhaps a relevant issue (discussed below)—but this study does not
appear to distinguish between different crude oil types.80
Related to the assertion of volatility, the 2011 report highlights a process—described as liquid-
column separation—that could potentially occur in pipelines when changes in pipeline pressure
causes some of the natural gas liquid component to change into a gas bubble. According to the
report, when these gas bubbles burst they release high pressure that can damage a pipeline (a
process described as cavitation). The report states that “instability of DilBit can render pipelines
particularly susceptible to ruptures caused by pressure spikes.”81
However, DOS countered this assertion stating that it “contacted the author [that NRDC cited to
support the above statement]… to address this concern and determined that it would not be valid
to infer from this research that dilbits are any more or less stable than other crude oils, or that they
are more likely to cause pressure spikes during transport in pipelines or otherwise pose an
increased risk to pipeline safety.”82
Corrosivity
Some argue that DilBit pipelines may be more likely to fail than other crude oil pipelines because
the bitumen mixtures they carry are “significantly more corrosive to pipeline systems than
conventional crude.”83 Three DilBit properties of particular interest are acidity, sulfur content, and
solids content, all of which may influence the overall corrosiveness of a given blend of crude oil.
The 2011 report also focuses on these specific DilBit properties and their potential influence on
pipeline corrosion, asserting, “Compared to ‘conventional’ crudes, DilBit blends are thicker and
more acidic, and contain more sulfur, chloride salts, and quartz sand particles. These
characteristics create a ‘combination of chemical corrosion and physical abrasion [that] can
dramatically increase the rate of pipeline deterioration.’”84
To what extent these claims may be correct is the subject of debate. Alberta’s Energy Resources
Conservation Board (ERCB), among other stakeholders, has rejected the claims from the 2011
report, stating that “there is no reason to expect this product to behave in any substantially
different way than other oil.... ”85 Additional background on the specific DilBit characteristics of
concern may offer a greater understanding of the corrosion mechanisms at issue, but not
necessarily resolve the debate.
Total Acid Number
As indicated in Table 1 (above) Canadian DilBit total acid numbers (TANs) range between 0.92
to 2.49. This range is generally higher than lighter crude oils, but comparable with other heavy
80 Changjun Li et al., Study on Liquid-Column Separation in Oil Transport Pipeline, American Society of Civil
Engineers, International Conference on Pipelines and Trenchless Technology 2009.
81 Tar Sands Pipelines Safety Risks.
82 2011 FEIS, “Potential Releases,” p. 3-13.45, available at http://keystonepipeline-xl.state.gov/archive/dos_docs/feis/
vol2/env/index.htm.
83 Tar Sands Pipelines Safety Risks.
84 Tar Sands Pipelines Safety Risks.
85 Canadian Energy Resources Conservation Board (ERCB), “ERCB Addresses Statements in Natural Resources
Defense Council Pipeline Safety Report,” Press release, Calgary, Alberta, February 16, 2011.
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oils. It is well-established that the presence of naphthenic acids in high TAN crudes can
considerably increase corrosion potential in the parts of refinery distillation units operating at
high temperature—above 400ºF.86 However, pipeline transportation of DilBit is expected to occur
at much lower temperatures: the maximum operating temperature for Keystone XL is 150ºF.
Moreover, DilBit pipeline corrosion rates may not have a direct correlation with TAN values.
There is evidence of more than 1,000 napthenic acid varieties with varying corrosivity, which
may comprise a single TAN number.87 TAN values depend upon the specific content and types of
compounds in specific crudes—which may vary significantly from crude to crude.88 Some testing
of pipeline steels has shown that Canadian oil sands crudes exhibit “very low corrosion rates”
despite high TAN numbers, in part because they contain other “inhibitor” compounds that reduce
the corrosivity of the bitumen.89 Therefore, it is uncertain whether refiners’ experiences with
corrosion from high TAN crudes can be directly extended to DilBit transmission pipelines.
Sulfur Content
Another factor in crude oil corrosivity is sulfur content. Crude oils sent to U.S. refineries typically
contain 0.5% to 2.5% sulfur.90 As indicated in Table 1, DilBits have sulfur content substantially
above this range—between 3% and 5%. In sour crudes (> 1% sulfur content), sulfur is present as
hydrogen sulfide (H2S),91 which can combine with water to form sulfuric acid (H2SO4), a strongly
corrosive acid. Like napthenic acid corrosion (discussed above), sulfidic corrosion is a high
temperature phenomenon, beginning above 500ºF.92 In pipelines, H2S can also interact with
napthenic acids, carbon dioxide (CO2) and solids, complicating the possible corrosion processes
at work. Research and refiner experience suggest that sulfuric and napthenic acid corrosivity can
be inhibited or augmented by the presence of specific sulfur compounds depending upon the
chemical characteristics of those compounds (e.g., how readily they decompose into H2S),
whether they are in liquid or vapor phase, and other factors.93 In some cases, H2S can form a
86 Dennis Haynes, Naphthenic Acid Bearing Refinery Feedstocks and Corrosion Abatement, Presentation to the AIChE
Chicago Symposium, 2006, p. 7; Bruce Randolph, James Scinta, Eric Vetters, et al., Challenges in Processing
Canadian Oilsands Crude – A US Refiners’ Perspective, Canadian Crude Quality Technical Association, June 25,
2008.
87 See Anne Shafizadeh et al., “High Acid Crudes,” Presentation to the Crude Oil Quality Group New Orleans Meeting,
January 30, 2003, http://www.coqa-inc.org/20030130High%20Acid%20Crudes.pdf.
88 Canadian Crude Quality Technical Association, TAN Phase III Project, Meeting Minutes of June 23, 2009,
http://www.ccqta.com/docs/documents/Projects/TAN_Phase_III/
TAN%20Phase%20III%20March%202009%20Minutes.pdf.
89 Rena Liviniuk, et al., “Organic Acid Structure – A Correlation With Corrosivity,” AM-09-20, Presented to the
National Petrochemical and Refiners Association, Annual Meeting, March 22-24, 2009, San Antonio, TX, p. 9.
90 U.S. Energy Information Administration, “Crude Oil Input Qualities: Sulfur Content, Annual,” Internet table, June
29, 2011, http://www.eia.gov/dnav/pet/pet_pnp_crq_a_EPC0_YCS_pct_a.htm.
91 H2S is generated at temperatures greater than 392°F (200°C) through a reaction between carbon-containing and
sulfur-containing compounds in the crude. Thus, H2S can be generated during the oil sands thermal extraction process.
See G.G. Hoffmann, et al., “Thermal Recovery Processes and Hydrogen Sulfide Formation,” Presented at the Society
of Petroleum Engineers International Symposium on Oilfield Chemistry, San Antonio, Texas, February 14-17, 1995.
92 H.M. Shalaby, “Refining of Kuwait’s Heavy Crude Oil: Materials Challenges,” Workshop on Corrosion and
Protection of Metals, Arab School for Science and Technology, Kuwait, December 3-7, 2005, p. 5;
http://www.arabschool.org/pdf_notes/20_REFINING_OF_KUWAITS_HEAVY_CRUDE_OIL.pdf.
93 Ibid., p.6; Heather Dettman, et al, “Refinery Corrosion: The Influence of Organic Acid and Sulphur Compund
Structure on Global Crude Corrosivity,” Presentation to the 5th NCUT Upgrading and Refining Conference 2009,
Edmonton, Alberta, September 14 - 16, 2009; Dennis Haynes, 2006, p. 8.
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protective sulfide coating that actually prevents corrosion.94 Thus, as in the case of TAN levels,
sulfur content in crude oil may not accurately reflect corrosivity, notwithstanding the common use
of sulfur content to indicate sulfidic corrosion potential in refinery equipment.95 For these
reasons, the direct application of sulfidic corrosion experience in refineries to lower temperature
crude oil pipelines may be inconsistent with chemical processes involved.
Abrasive Solids
Solids suspended in crude oil have the potential to accelerate corrosion in pipelines either by
settling out (forming corrosive conditions beneath them) or through abrasion. Abrasion has been
raised as a particular concern for DilBit pipelines because DilBit may contain significantly more
solids than conventional crudes.96 These solids, it is argued, might wear away the interior walls of
a pipeline and exacerbate wall loss from acidic corrosion. Some have compared this process to
sandblasters.97 However, CRS is not aware of publically available research that has examined
whether the conditions exist for significant internal abrasion of DilBit pipelines. Crude oils with
high solids content are also generally filtered to meet the quality specifications set by pipelines
and refiners. Thus DilBit blends may have solids content higher than other types of crudes, but
still within an acceptable range for pipeline and refinery operations.
Keystone XL Pipeline Operating Parameters
Multiple parties submitted comments to DOS, highlighting the Keystone XL pipeline operating
parameters as a particular concern.98 The 2011 environmental groups’ report claims that “the risks
of corrosion and the abrasive nature of DilBit are made worse by the relatively high heat and
pressure.”99
The report asserts the pipeline will be operating at temperatures “up to 158° F,” which is
substantially higher than conventional crude pipelines, which, according to the report, operate at
less than 100° F.100 TransCanada has stated that “oil in a line like this comes into our pipeline
between 80-120°F, and it stays within that temperature range during transport.”101 In the 2011
FEIS, DOS states that the maximum operating temperature of the proposed pipeline would not
exceed 150° F. It is uncertain whether this 150° F mark is an upper bound that might be
approached on rare occasions, or whether the operating temperature would typically hover near
94 Gregory R. Ruschau, and Mohammed A. Al-Anez, Oil and Gas Exploration and Production, Appendix S, Corrosion
Prevention, p. S6, in: CC Technologies Laboratories, Inc., Corrosion Costs And Preventive Strategies In The United
States, Report to the U.S. Federal Highway Administration, Office of Infrastructure Research and Development, Report
FHWA-RD-01-156, September 2001, http://www.corrosioncost.com/pdf/oilgas.pdf.
95 H.M Shalaby, 2005, p. 6.
96 Baker Hughes Inc., Planning Ahead for Effective Canadian Crude Processing, Sugar Land, TX, 2010, p. 4,
http://www.bakerhughes.com/assets/media/whitepapers/4c2a3c8ffa7e1c3c7400001d/file/28271-
canadian_crudeoil_update_whitepaper_06-10.pdf.pdf&fs=1497549.
97 Tar Sands Pipelines Safety Risks..
98 See 2011 final EIS, “Appendix A, Responses to Comments and Scoping Summary Report,” available at
http://keystonepipeline-xl.state.gov/archive/dos_docs/feis/vol3and4/appendixa/index.htm.
99 Tar Sands Pipelines Safety Risks.
100 Tar Sands Pipelines Safety Risks.
101 TransCanada, “TransCanada’s Keystone XL Pipeline – Know the Facts,” fact sheet, May 2011,
http://www.transcanada.com/docs/Key_Projects/know_the_facts_kxl.pdf.
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this maximum. Either way, it is below the maximum operational temperature cited by some
environmental groups.
According to the report, conventional crude pipeline pressure is 600 pounds per square-inch
(PSI), while diluted bitumen requires a pipeline pressure of 1,440 psi102 A subsequent 2011 report
lists this figure as 2,130 psi.103 Regardless, the 2011 FEIS lists the Keystone XL operating
pressure as 1,308 psi.
The degree to which the Keystone XL pipeline’s operating parameters differ from other oil
pipeline operating parameters is beyond the scope of this report. In general, the Keystone XL
operating parameters are different, because diluted bitumen (and heavy crude oils) are more
viscous (resistant to flow) than conventional crude oil. According to a 2011 review of heavy
crude transportation, “Pipelining of heavy oil presents problems like instability of asphaltenes,
paraffin precipitation and high viscosity that cause multiphase flow, clogging of pipes, high-
pressure drops, and production stops.”104
The same review describes several options that may be used “to resolve or improve pipelining of
heavy and extra-heavy crude oil.” These options include dilution with other substances and
increasing/conserving the oil’s temperature. Both of these options would reduce viscosity and
both seem to be part of the Keystone XL proposed operations.
DOS states that the proposed pipeline would satisfy the Department of Transportation’s Pipeline
and Hazardous Materials Safety Administration (PHMSA) regulations (49 CFR Part 195) that
apply to hazardous liquid pipelines. In addition, Keystone agreed to implement 57 additional
measures developed by PHMSA. In consultation with PHMSA, DOS determined that
incorporation of those conditions “would result in a Project that would have a degree of safety
over any other typically constructed domestic oil pipeline system under current code and a degree
of safety along the entire length of the pipeline system similar to that which is required in High
Consequence Areas (HCAs) as defined in 49 CFR 195.450.”105
The degree to which the additional 57 measures mitigate risk is debatable. For instance, the
primary author of the 2011 environmental groups’ report argued that only 12 of these conditions
actually differ in some way from minimum requirements.106
Oil Pipeline Spill Data from Alberta
Many stakeholders have argued a comparison of oil spill data from Alberta and the United States
indicates that internal corrosion has led to substantially more oil spills in the Alberta pipeline
system than the U.S. system.107 They reason that this difference is likely related to high
102 Tar Sands Pipelines Safety Risks.
103 Pipeline and Tanker Trouble.
104 Rafael Martinez-Palou et al., “Transportation of Heavy and Extra-Heavy Crude Oil by Pipeline: A Review,” Journal
of Petroleum Science and Engineering, Vol. 75, pp. 274-282, January 2011.
105 2011 FEIS, “Project Description,” p. 2-23, available at http://keystonepipeline-xl.state.gov/archive/dos_docs/feis/
vol1/index.htm.
106 Anthony Swift, “Clinton’s Tar Sands Pipeline ‘Safety Conditions’ are Smoke and Mirrors,” August 19, 2011, at
http://switchboard.nrdc.org.
107 2011 FEIS, Appendix A (see footnote 58).
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proportion of oil sands crudes, which have been in the Alberta system since the 1980s. In
contrast, the first dedicated oil sands crudes pipeline in the United States, the Alberta Clipper,
began operating in 2010.108
DOS rejected this assertion, stating, “[T]here is no evidence that the transportation of oil sands
derived crude oil in Alberta has resulted in a higher corrosion related failure rate than occurs in
the transportation of the variable-sourced crude oils in the U.S. system.”109
Further, DOS pointed out that a comparison of the oil spill data is problematic for various
reasons. In particular, the scopes of the data collected in each nation are different. Canadian data
includes smaller spills and spills from certain pipelines not covered by PHMSA regulations. To
address these discrepancies in data collection, PHMSA prepared a comparison of pipeline
incidents of similar scopes between the two databases. This comparison was part of the 2011
FEIS and is provided below in Table 4.
Table 4. PHMSA Comparison of Oil Pipeline Incidents in Alberta and United States
2002 - 2010
Crude Oil Pipeline Failures U.S. and Alberta \
(2002-2010)
U.S. Crude Oil Pipeline Incident Historya
Failures per
Incident/Failure Case
Failures/Year
1,000 Pipeline Miles per Year
Corrosion - External
9.8
0.19
Corrosion - Internal
22.1
0.42
Al Failures
89.3
1.70
Alberta Crude Oil Pipeline Incident Historyb
Corrosion - External
2.3
0.21
Corrosion - Internal
3.6
0.32
Al Failures
22.0
1.97
Source: Reproduced by CRS; original table from 2011 FEIS, p. 3.13-38 (Table 3.13.5-4).
Notes: The fol owing notes are included in the table in the 2011 FEIS:
a. PHMSA includes spill incidents greater than 5 gallons. U.S. had 52,475 miles of crude oil pipelines in 2008.
b. Alberta Energy and Utility Board Report, includes spills greater than and less than 5 bbls. Alberta had 11,187
miles of crude oil pipelines in 2006.
This comparison indicates that internal corrosion failures (per 1,000 miles of pipeline) were
approximately 30% higher in the U.S. system (0.42 vs. 0.32). Regardless, such comparisons are
challenging, if not impossible, considering the range of potential factors—pipeline age,
enforcement, etc.—that may affect the underlying data. For this reason, the above comparison
might be described as preliminary.
108 Tar Sands Pipelines Safety Risks.
109 2011 FEIS, “Potential Releases,” p. 3.13-38 (see footnote 82).
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Keystone XL Spill Frequency Estimates
Spill frequency estimates for the Keystone XL project have been a subject of debate. During the
NEPA process, Keystone submitted a spill frequency estimate of 0.22 spills per year. The
company derived this estimate by using historical databases from PHMSA and then applying
project-specific factors, such as regulatory requirements, material strength, and technological
advances.
However, some questioned Keystone’s modified estimate, arguing that the pipeline’s operating
parameters—temperatures and pressures higher than conventional crude pipelines—would yield
spill frequencies above historical averages, rather than below.110
Subsequent to Keystone’s estimate, the DOS estimated that a spill over 50 barrels would occur
between 1.2 to 1.8 times per year; spills of any size would occur between 1.8 to 2.5 times per
year.111
Another potential source of data is the pipeline operating history of Keystone. Keystone has
operated the Keystone Mainline pipeline and the Cushing Extension since 2010. Since that time
the Keystone pipeline has generated 14 unintentional releases. DOS cites personal
communication with PHMSA staff, who stated that these incidents are “not unusual start-up
issues that occur on pipeline and are not unique.”112 Regardless, this figure is considerably higher
than the Keystone XL spill frequency estimates DOS included in its 2011 FEIS.
Spill Size Estimates
Citing the PHMSA significant incident database,113 DOS indicates that between 1990 and 2010,
the average spill size for onshore hazardous liquid pipelines, which includes both oil and other
materials, was less than 1,000 barrels (42,000 gallons).114 Using this database, CRS calculated the
exact average spill to be 918 barrels (38,556 gallons). Per the spill size classification included in
the 2011 FEIS, the average spill would be considered a “large spill.”115
One may question whether this database is the best tool for predicting spill size from the
Keystone XL pipeline. The database includes oil and other hazardous liquids; pipelines of varying
sizes and pressures; and pipelines of varying ages. A more refined comparison may offer
policymakers a better prediction of possible spill size, but the PHMSA database is not
immediately amenable to a more tailored assessment.
110 See John Stansbury, Analysis of Frequency, Magnitude and Consequence of Worst-Case Spills from the Proposed
Keystone XL Pipeline, Submitted as a comment to the supplemental draft EIS and later cited in the 2011 FEIS.
111 2011 FEIS, “Potential Releases,” pp. 3.13-18 – 3.13-21 (see footnote 82).
112 2011 FEIS, “Potential Releases,” p. 3.13-11 (see footnote 82).
113 The significant incident database represents a subset of all incidents. To qualify as “significant” an incident must
result in one of the following: (1) a fatality or injury requiring in-patient hospitalization; (2) $50,000 or more in total
costs, measured in 1984 dollars; (3) a highly volatile liquid release of 5 barrels or more or other liquid releases of 50
barrels or more; or (4) a liquid releases resulting in an unintentional fire or explosion.
114 2011 FEIS, “Potential Releases,” p. 3.13-15 (see footnote 82).
115 Ibid.
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In its 2011 FEIS, DOS seems to suggest that “very large spills” (defined as greater than 5,000
barrels or 210,000 gallons) would require a dramatic event. According to DOS:
A very large spill from the pipeline would likely require the occurrence of an event that
would shear the pipeline such as major earth movement resulting from slides, major earth
movement resulting from an earthquake, major flood flows eroding river banks at non-HDD
crossings, mechanical damage from third-party excavation or drilling work, or vandalism,
sabotage, or terrorist actions.116
Some may argue that the July 2010 Enbridge pipeline oil spill tests this assertion (discussed
below). Moreover, an “average spill,” like the 2011 pipeline spill into the Yellowstone River
(discussed below) can require substantial cleanup efforts in certain locations.
Environmental Impacts of Spills of Oil Sands Crude
Some contend that the distinct chemical composition of oil sands crude (e.g., DilBit) would pose
a greater environmental risk from an oil spill than other crudes.117 CRS is not aware of an
authoritative study that has examined this assertion. Although parallels may be drawn between the
possible behavior of conventional crudes and DilBit, studies are scarce regarding spills of heavy
crudes with the specific composition of Canadian heavy crudes.
The behavior of crude oil spills and the fate of crude oil in the subsurface have been studied
extensively around the world for a wide range of conventional crudes and other petrochemicals in
both experimental settings and actual spills (e.g., Bemidji, Minnesota in 1979).118 These include
studies of specific chemical components that may be present in DilBit (e.g., benzene).119 Based
on extensive experience with other crudes and DilBit constituents, analysts may claim
considerable confidence in models of DilBit behavior around groundwater. For example, the
Energy Resources Conservation Board has stated that “DilBit should behave in much the same
manner as other crude oils of similar characteristics.120
116 Ibid.
117 Swift et al, p. 7.
118 See, for example, work compiled by the U.S. Geological Survey about the 1979 crude oil spill near Bemidji, MN,
which contaminated a shallow aquifer: U.S. Geological Survey, “Crude Oil Contamination in the Shallow Subsurface:
Bemidji, Minnesota,” Internet page, July 20, 2011, http://toxics.usgs.gov/sites/bemidji_page.html. See also: M.
Whittaker, S.J.T. Pollard, and T.E. Fallick, “Characterisation of Refractory Wastes at Heavy Oil-Contaminated Sites: A
Review of Conventional and Novel Analytical Methods,” Environmental Technology, Vol. 16, No. 11, November 1,
1995, pp. 1009-1033; S Khaitan et al., “Remediation of Sites Contaminated by Oil Refinery Operations,”
Environmental Progress, Vol. 25, No. 1, April 2006, pp. 20-31.
119 See, for example: Lisa M. Geig et al., “Intrinsic Bioremediation of Petroleum Hydrocarbons in a Gas Condensate-
Contaminated Aquifer,” Environmental Science and Technology, vol. 33, no. 15 (1999), pp. 2550-2560; Paul E.
Hardisty, et al., “Characterization of LNAPL in Fractured Rock,” Quarterly Journal of Engineering Geology &
Hydrogeology, Vol. 36, No. 4, November 2003, p. 343-354; J.L. Busch-Harris, e al., “In Situ Assessment of Benzene
Biodegradation Potential in a Gas Condensate Contaminated Aquifer,” Proceedings of 11th Annual International
Petroleum Environmental Conference, Albuquerque, NM, October 12-15, 2004; John A. Connor, et al., “Nature,
Frequency, and Cost of Environmental Remediation at Onshore Oil and Gas Exploration and Production Sites,”
Remediation, Vol. 21, No. 3, Summer 2011, pp. 121-144; Bruce E Rittmann, et al., Natural Attenuation for
Groundwater Remediation, National Academy Press, 2000.
120 Canadian Energy Resources Conservation Board (ERCB), “ERCB Addresses Statements in Natural Resources
Defense Council Pipeline Safety Report,” Press release, Calgary, Alberta, February 16, 2011.
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All spilled oil begins to “weather” or separate into different components over time. In general,
heavier oils, like DilBit, are more persistent and may present greater technical challenges in oil
removal operations than lighter crude oils. For a land spill, the heavier and more viscous
components (i.e., the asphaltenes) would likely remain trapped in soil pores above the water table.
It is also likely that the lighter constituents would partly evaporate and not be transported down
through the soil with the heavier components.
However, if an oil spill reached the water table, some of the more soluble portions would likely
dissolve into the groundwater and be transported in the direction of regional groundwater flow.
The ultimate extent, shape, and composition of a groundwater contaminant plume resulting from
a DilBit spill would depend on the specific characteristics of the soil, aquifer, and the amount and
duration of the accidental release.
The heavier components of a DilBit spill would be difficult to remove from the soil during
cleanup operations, and may require wholesale soil removal instead of other remediation
techniques.121 These challenges may come at a higher cost. In an oil spill model prepared for
EPA, the model estimates that spills of heavy oil will cost nearly twice as much to clean up as
comparable spills of conventional crude oil.122
Crude oils may contain multiple compounds that present toxicity concerns. DOS stated that
“based on the combination of toxicity, solubility, and bioavailability, benzene was determined to
dominate toxicity associated with potential crude oil spills.”123 Benzene and other BTEX
compounds (benzene, toluene, ethyl benzene, and xylene) are generally in greater proportions in
the lighter crude oils and particularly in refined products like gasoline.124 In its 2011 FEIS, DOS
compared the BTEX content of crude oil derived from oil sands (DilBit and DilSynBit) with
conventional crude oils from Canada. The BTEX content of oil sands crudes ranged from 5,800
parts per million (ppm) to 9,100 ppm. The BTEX contents of conventional crude oils ranged from
5,800 ppm to 29,100 ppm.125
Other toxic compounds of concern in crude oils are polycyclic aromatic hydrocarbons (PAHs).
Generally, PAHs are more toxic than BTEX and evaporate at a slower rate, but they are less
soluble in water. The National Research Council’s Oil in the Sea report stated that with
weathering/evaporation and the resulting loss of BTEX, PAHs become more important
contributors to the remaining oil’s toxicity.126
Unlike BTEX, the 2011 FEIS does not include a comparison of PAH concentrations across
different crude oils. DOS states that PAH concentrations of crude oils that would be transported in
121 One such other method is “pump and treat,” which involves cleaning soil and groundwater contamination by
pumping and capturing the contaminated groundwater, then treating it at the surface to remove the contaminants. The
same technique may be used to extract soil gas vapor from contaminated soil above the water table. For more
information, see Environmental Protection Agency, Basics of Pump-and-Treat Ground-Water Remediation
Technology, EPA/800/8-90003, March 1990.
122 Dagmar Etkin, Modeling Oil Spill Response and Damages Costs, Proceedings of the 5th Biennial Freshwater Spills
Symposium, 2004, at http://www.environmental-research.com.
123 2011 FEIS, “Potential Releases,” p. 3.13-80 (see footnote 82).
124 For a comprehensive discussion, see National Research Council, Oil in the Sea III: Inputs, Fates, and Effects,
National Academies of Science, February 2003.
125 2011 FEIS, “Potential Releases,” Table 3.13.5-6, p. 3.13-45 (see footnote 82).
126 National Research Council, 2003, p. 126.
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the Keystone XL pipeline are unknown, because this information is proprietary.127 Some
commenters, including EPA, took issue with this during the EIS review process.128
Heavy metals may also be a concern. A 2011 NRDC report states that Dilbit contains quantities of
heavy metals, particularly vanadium and nickel, that are “significantly larger” than conventional
crude oil.129 Assuming conventional oil means lighter crudes, this statement is largely correct.130
However, the heavy metal concentrations in DilBit are similar to some other heavy crude oils,
such as Mexican and Venezuela crudes that are processed in Gulf Coast refineries.131 Most, if not
all, of this crude oil arrives in the United States via vessel.132
Recent Pipeline Spills
Two relatively recent pipeline oil spills—the 2010 Enbridge spill in Michigan and the 2011
ExxonMobil spill in Montana—generated interest among policymakers and stakeholders. These
incidents may be instructive.
2010 Enbridge Spill
On July 26, 2010, an Enbridge pipeline released oil sands crude oil133 into Talmadge Creek, a
waterway that flows into the Kalamazoo River (Michigan).134 The spill volume was estimated at
almost 850,000 gallons.135 Response operations, led by EPA, continue. The oil spill liability trust
fund (OSLTF) has allocated approximately $56 million for response activities and nearly $1
million for natural resource damage assessment activities.136 As of September 2012, Enbridge
estimated the cost of the spill to be approximately $810 million, which does not include potential
federal and state penalties.137
The National Transportation Safety Board (NTSB) issued an accident report in July 2012,
concluding the following:138
127 2011 FEIS, “Potential Releases,” p. 3.13-31 (see footnote 82).
128 See footnote 56 regarding EPA’s June 6, 2011 comments.
129 Anthony Swift, Susan Casey-Lefkowitz, and Elizabeth Shope, Tar Sands Pipelines Safety Risks, Natural Resources
Defense Council (NRDC), February 2011.
130 Based on a comparison of crude oil assays from sources listed in Table 1.
131 2011 FEIS, “Potential Releases,” Table 3.13.5-7 (see footnote 82).
132 Although a considerable percentage of oil imports come from Mexico (e.g., approximately 12% of crude oil imports
in 2010), the EIA states that “Mexico does not have any international pipeline connections, with most exports leaving
the country via tanker from three export terminals in the southern part of the country.” EIA, Country Analysis Briefs, at
http://www.eia.gov/cabs/Mexico/Full.html.
133 National Transportation Safety Board, Accident Report: Enbridge Incorporated Hazardous Liquid Pipeline Rupture
and Release- Marshall, Michigan, July 25, 2010, July 2012, at http://www.ntsb.gov/.
134 For more up-to-date information, see EPA’s Enbridge oil spill website at http://www.epa.gov/enbridgespill/
index.html.
135 National Transportation Safety Board, Accident Report: Enbridge Incorporated Hazardous Liquid Pipeline Rupture
and Release- Marshall, Michigan, July 25, 2010, July 2012, at http://www.ntsb.gov/.
136 Personal communication with the U.S. Coast Guard (February 13, 2013).
137 Enbridge Inc., Third Quarter Financial Report, 2012, at http://enbridge.com/InvestorRelations/FinancialInformation/
InvestorDocumentsandFilings.aspx.
138 National Transportation Safety Board, Accident Report: Enbridge Incorporated Hazardous Liquid Pipeline Rupture
(continued...)
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• the probable cause of the pipeline rupture was corrosion fatigue cracks that grew
and coalesced from crack and corrosion defects under disbonded polyethylene
tape coating, producing a substantial crude oil release that went undetected by the
control center for over 17 hours;
• the rupture and prolonged release were made possible by pervasive
organizational failures at Enbridge;
• the Pipeline and Hazardous Materials Safety Administration’s (PHMSA) weak
regulation for assessing and repairing crack indications contributed to the
accident.
In addition to identifying factors that led to the incident, NTSB listed factors that increased the
severity of the incident:
• Enbridge’s failure to identify and ensure the availability of well-trained
emergency responders with sufficient response resources;
• PHMSA’s lack of regulatory guidance for pipeline facility response planning, and
• PHMSA’s limited oversight of pipeline emergency preparedness that led to the
approval of a deficient facility response plan.
The Enbridge spill arguably questions the DOS assertion (above) that a major oil spill from a
pipeline would require a dramatic event. Although the Enbridge pipeline was over 40 years old
and was constructed under different standards and technology,139 the spill raises concerns about
the U.S. pipeline regulatory framework in general.
2011 ExxonMobil Spill
On July 1, 2011, an ExxonMobil pipeline spilled approximately 63,000 gallons of crude oil into
the Yellowstone River.140 In an October 2012 report, PHMSA stated:141
The cause of the release was determined to be a severed pipeline near the south shore of the
Yellowstone River that occurred after a prolonged period of high runoff and flooding. Debris
caught on the pipe over time increased the stresses until ultimately the critical stress of the
pipe was exceeded.142
The report indicates that a critical valve was not closed for 46 minutes after the initial alarm,
contributing to approximately 70% of the total spill volume.143 In addition, the report stated that
PHMSA had required the pipeline company to modify its operating instructions so that certain
pipeline valves would be closed immediately after an abnormal event.
(...continued)
and Release- Marshall, Michigan, July 25, 2010, July 2012, at http://www.ntsb.gov/.
139 For example, NTSB states: “since the late 1960s, coating technology has advanced significantly. The coatings
available today follow the pipe’s contour better and are more resistant to disbonding.” NTSB Accident Report, 2012.
140 The estimate is from ExxonMobil’s website, at http://www.exxonmobil.com/Corporate/safety_env_spill.aspx.
141 NTSB did not conduct an investigation for this incident.
142 PHMSA Report, October 201, available at http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/
Other%20files/ExxonMobil_HL_MT_10-2012.pdf.
143 PHMSA Report, October 2012.
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Initially, EPA oversaw the oil spill response, and in August 2011, over 1,000 personnel were
engaged in cleanup and shoreline assessment efforts.144 In September 2011, EPA transferred
oversight authority to the Montana Department of Environmental Quality (MT DEQ). As of
November 2012, response efforts continue, but operations have “transitioned from emergency
cleanup into long-term monitoring, assessment and reclamation.”145
As of February 2013, the federal government has allocated $3.7 million from the Oil Spill
Liability Trust Fund to address response activities ($3.2 million) and natural resource damage
assessment ($0.5 million).146 ExxonMobil has reportedly spent $135 million for response and
repair costs.147
Further Study
DOT officials acknowledge that they have not performed any specific studies nor reassessments
of pipeline safety risks that might be unique to DilBit.148 In addition, DOS points out that “a
focused, peer-reviewed study of the potential corrosivity/erosivity of WCSB oil sands derived
crude oils relative to other crude oils has not yet been conducted.”149
Some in Congress have called for a review of DOT pipeline safety regulations to determine
whether new regulations for Canadian heavy crudes are needed to account for any unique
properties they may have. Accordingly, P.L. 112-90 requires PHMSA to review whether current
regulations are sufficient to regulate pipelines transmitting “diluted bitumen,” and analyze
whether such oil presents an increased risk of release (§16).
Oil Sands Extraction Concerns
Opponents of the Keystone XL pipeline and oil sands development often highlight the
environmental impacts that pertain to the region in which the oil sands resources are extracted. In
general, these local/regional impacts from Canadian oil sands development may not directly
affect public health or the environment in the United States. DOS points out that, pursuant to
NEPA or applicable Executive Orders, it is not required to analyze the environment or activities
outside of the United States (see “Consideration of Environmental Impacts Outside of the United
States”). Still, pursuant to DOS policy and in response to concerns that the proposed project
“would contribute to certain continental scale environmental impact,”150 DOS included a
summary of information regarding environmental analyses and regulations related to the
144 See EPA Update on Yellowstone River Oil Spill (Silvertip Pipeline), August 12, 2011, at http://www.epa.gov/
yellowstoneriverspill/.
145 Montana Department of Environmental Quality, Silvertip Pipeline Crude Oil Release: Site Update, November 2012,
at http://deq.mt.gov/statesuperfund/silvertipoilspill/default.mcpx.
146 Personal communication with U.S. Coast Guard, February 14, 2013.
147 Matthew Brown, “Feds Say Delay Made Oil Spill Worse,” Associated Press, January 2, 2013, at
http://bigstory.ap.org/article/apnewsbreak-feds-say-delay-worsened-oil-spill.
148 The Honorable Cynthia L. Quarterman, Administrator, Pipeline and Hazardous Materials Safety Administration,
U.S. Department of Transportation, Testimony before the U.S. House Committee on Energy and Commerce,
Subcommittee on Energy and Power, Hearing on “The American Energy Initiative,” June 16, 2011.
149 2011 FEIS, “Potential Releases,” p. 3.13-43 (see footnote 82).
150 2011 FEIS, “Cumulative Impacts” section, p. 3.14-61 available at http://keystonepipeline-xl.state.gov/archive/
dos_docs/feis/vol2/env/index.htm.
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Canadian portion of the proposed Keystone XL Project and WCSB oil sands production. This
inclusion reflects the level of interest these issues have received in recent years.
The scope and degree of the extraction-related impacts is a subject of some debate. A
comprehensive assessment of extraction-related concerns is beyond the scope of this report.151
The following sections include discussions of two selected topics: land disturbance and water
resource issues.
Land Disturbances
Both oil sands mining and in situ operations disturb the surrounding land to some degree. Land
disturbances from mining operations include
• clearance and excavation of a relatively large surface area,
• storage of removed overburden (e.g., vegetation soil), and
• construction of tailings ponds to contain extraction process wastestreams.
Many stakeholders associate in situ operations with “minimal land disturbances.”152 However,
some research suggests the comparison between the two processes is more complicated. A 2009
study described the different impacts from the two processes in the following manner:
Surface mining and in situ recovery affect the landscape in different ways. Land use of
surface mining is comprised largely of polygonal features (mine sites, overburden storage,
tailing ponds and end pit lakes); whereas in situ development is mostly defined by linear
features that extend across the lease area (networks of seismic lines, access roads, pipelines
and well sites).153
Although the actual extraction site at in situ operations impacts substantially less land than at
mining sites, some contend that in situ processes may ultimately create a larger disturbance,
because the dispersed nature of in situ operations increases landscape fragmentation.154 In
addition, one study finds that in situ operations disturb more land (per unit of oil) than mining,
when natural gas requirements are considered.155 As noted above, in situ operations require
energy (i.e., natural gas) to generate the steam needed to extract the underlying resource.
According to the study, the land disturbances from the natural gas development contribute a
major portion of in situ’s total land disturbance.
151 Perhaps the most comprehensive assessment of potential environmental concerns was prepared by the Royal Society
of Canada. See P. Gosselin et al., Environmental and Health Impacts of Canada’s Oil Sands Industry, The Royal
Society of Canada, Expert Panel Report, Ottawa, Ontario, December 15, 2010.
152 P. Gosselin et al., Environmental and Health Impacts of Canada’s Oil Sands Industry, The Royal Society of
Canada, Expert Panel Report, Ottawa, Ontario, December 15, 2010.
153 Sarah M Jordaan et al, “Quantifying Land Use of Oil Sands Production: a Life Cycle Perspective,” Environmental
Research Letters, 2009.
154 See, e.g., Dan Woynillowicz et al, Oil Sands Fever, Pembina Institute, 2005; Pembina Institute, Mining vs. In Situ:
Factsheet, 2012; Sarah M Jordaan et al, “Quantifying Land Use of Oil Sands Production: a Life Cycle Perspective,”
Environmental Research Letters, 2009.
155 Sarah M Jordaan et al, “Quantifying Land Use of Oil Sands Production: a Life Cycle Perspective,” Environmental
Research Letters, 2009.
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How does land disturbance from oil sands operations compare to conventional oil development?
Almost all forms of energy production disturb the land to some degree. A 2010 study compared
land disturbances from Alberta oil sands operations with conventional oil development in Alberta
and California.156 Figure 12 illustrates the results. The figure indicates that in situ oil sands
operations have a substantially higher energy yield—energy produced per disturbed land
(measured in petajoules per hectare)—than other sources. However, when natural gas use is
included in the estimate, in situ operations’ energy yield decreases substantially, making its
energy yield equivalent to California oil, but still greater than mining operations in Canada.157
The Alberta Chamber of Resources estimates that in situ production requires approximately four
times the quantity of natural gas used for surface mining on a production volume basis.158
Therefore, the factor of natural gas plays an important role in energy yield estimates.
Figure 12. Illustrative Comparison of Energy Yields by Selected Sources
Energy Produced per Amount of Disturbed Land
6
Oil sands - in
situ
5
ctare)
e
/h 4
les
Oil sands - in
u
o
situ + natural
California oil
taj 3
e
gas
p
(
d
iel
Oil sands - Oil sands -
2
Y
mining
mining +
gy
natural gas
er
Alberta oil
n 1
E
0
Source: Prepared by CRS; data from Sonia Yeh et al, “Land Use Greenhouse Gas
Emissions from Conventional Oil Production and Oil Sands,” Environmental Science and
Technology, 44(22): 8766-8722, 2010.
Notes: Columns reflect the range of values reported by Yeh, 2010. In the main text of
the 2010 study, the authors exclude the natural gas components of oil sands mining and in
situ operations (represented above by the striped columns), but provide the data in
supplementary information. Including the natural gas component lowers the energy yield.
Such a component was not part of the conventional California and Alberta oil data.
Another factor in land disturbance assessments is the type of land disturbed. The Alberta oil sands
are located within Canada’s boreal forest, a large area that contains 35% of the world’s wetlands.
156 Sonia Yeh et al, “Land Use Greenhouse Gas Emissions from Conventional Oil Production and Oil Sands,”
Environmental Science and Technology, 44(22): 8766-8722, 2010.
157 In the main text of the 2010 study (Yeh et al), the authors exclude the natural gas components of oil sands mining
and in situ operations (represented above by the striped columns), but provide the data in supplementary information.
158 Alberta Chamber of Resources, Oil Sands Technology Roadmap, 2004.
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The forest’s ecosystems support a wide range of biodiversity and provide key ecological services.
For example, the boreal forest has been described as the “world’s largest and most important
carbon storehouse.”159 The 2010 study that provided data for Figure 12 also estimated the carbon
storage in the lands overlying the various resources (e.g., California oil, Alberta oil sands). The
study estimated that the soil carbon ratio (tons of carbon per hectare) and biomass carbon ratio
was approximately five and four times greater, respectively, in oil sands areas than in California
oil sites.160
A further consideration is the fate of the land after the resources are extracted. In Alberta, an
environmental law requires an oil sands development company to demonstrate that it has
reclaimed the land to an “equivalent land capability.”161 Subsequent regulations have expanded on
the meaning of this phrase: “The ability of the land to support various land uses after conservation
and reclamation is similar to the ability that existed prior to an activity being conducted on the
land, but that the individual land uses will not necessarily be identical.”162
The Alberta reclamation requirement is not unique. The United States has similar requirements
that may apply in certain instances. For example, the Bureau of Land Management (BLM) has
reclamation regulations that apply to oil and gas operations on federal lands.163 BLM guidance
states:
The long-term objective of final reclamation is to set the course for eventual ecosystem
restoration, including the restoration of the natural vegetation community, hydrology, and
wildlife habitats. In most cases, this means returning the land to a condition approximating or
equal to that which existed prior to the disturbance. The operator is generally not responsible
for achieving full ecological restoration of the site.164
A comparison between the U.S. and Canadian reclamation requirements and their applications is
beyond the scope of this report. However, data from Alberta indicate that reclamation has not kept
pace with land disturbance. Data from 2010 indicate that approximately 8% of the total disturbed
area has been permanently reclaimed.165 Of the permanently reclaimed land, 2% has been
certified per Alberta requirements (equating with 0.16% of the total disturbed area). The 2010
Royal Society of Canada report stated, “Because of the very small amount of land certified to
date relative to the large area that has been disturbed in the oil sands region, there is major
159 Rebecca Rooney et al, “Oil Sands Mining and Reclamation Cause Massive Loss of Peatland and Stored Carbon,”
Proceedings of the National Academy of Sciences, 109: 4933-4937, 2012.
160 Sonia Yeh et al, “Land Use Greenhouse Gas Emissions from Conventional Oil Production and Oil Sands,”
Environmental Science and Technology, 44(22): 8766-8722, 2010.
161 Alberta Environmental Protection and Enhancement Act (as of November 2010), at http://www.qp.alberta.ca/
documents/Acts/E12.pdf.
162 Alberta Conservation and Reclamation Regulation, AR 115/93. For a discussion of this regulation and its
applications, see P. Gosselin et al., Environmental and Health Impacts of Canada’s Oil Sands Industry, The Royal
Society of Canada, Expert Panel Report, Ottawa, Ontario, December 15, 2010.
163 See, e.g., 43 CFR Section 3101.1-2 and BLM Onshore Oil and Gas Lease Form (Form 3100-11), Section 12.
164 United States Department of the Interior and Department of Agriculture, Surface Operating Standards and
Guidelines for Oil and Gas Exploration and Development, (“Gold Book”), 2007, p. 43.
165 The total disturbed area includes cleared areas, disturbed areas, and areas ready for reclamation. These categories
are defined by the following source: Alberta Government, Oil Sands Mine Regional Totals for Reclamation and
Disturbance Tracking by Year, at http://environment.alberta.ca.
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skepticism as to whether reclamation to an equivalent land capability can be achieved in a
reasonable time frame.”166
Subsequent to that report, a 2012 study from the Proceedings of the National Academy of
Sciences assessed pre- and post-reclamation data at several oil sands mining sites. The study
found that lost wetlands were not being replaced, resulting in a “dramatic loss of carbon storage
and sequestration potential.”167
Water Resources and Quality Issues
While the water resource impacts from oil sands development are seen by some stakeholders as
largely a Canadian domestic issues, other stakeholders view the environmental consequences of
oil sands development as part of the global discussion about the long-term implications of
unconventional oil and gas. At issue is whether oil sands development may harm the water
resources and aquatic ecosystems and species of the northern Alberta and the northern territories.
Both oil sands in situ and surface mining techniques have water resource impacts. In situ
processes use groundwater that is brought to the surface and heated, then reinjected for the
underground steam-based separation of the oil from the sand. Surface mining operations
withdraw water from the north-flowing Athabasca River. This water is heated for use in the
complex separation process of liberating the oil from the sands. Process wastestreams are
collected in tailings ponds or lakes, which can cover a substantial area.
Mining also results in significant land disturbance which later requires remediation; how effective
remediation is at long-term restoration and protection of water resources is a subject of on-going
debate. Additionally, maintaining the mine site requires capturing and disposing of surface water
and groundwater entering the site. The potential wetlands and associated migratory bird impacts
from changes in surface water and groundwater regimes that result both from direct water use in-
situ and mining operations and indirectly through long-term changes to the landscape also are
concerns.
On a direct water use per unit of energy basis, the oil sands processes are comparable or below
the intensity of U.S. onshore oil production using freshwater for enhanced oil recovery, and
considerably below the water intensity of corn or soy biofuels.168 Water use for oil sands,
however, is likely to exceed the freshwater intensity of offshore and conventional oil production,
166 P. Gosselin et al., Environmental and Health Impacts of Canada’s Oil Sands Industry, The Royal Society of
Canada, Expert Panel Report, Ottawa, Ontario, December 15, 2010, p. 194.
167 Rebecca Rooney et al, “Oil Sands Mining and Reclamation Cause Massive Loss of Peatland and Stored Carbon,”
Proceedings of the National Academy of Sciences, 109: 4933-4937, 2012.
168 Currently there is no authoritative source comparing the water intensities of a wide range of fuels on an energy
basis. Water intensity data for shale oil and life-cycle water use for gas-to-liquids are particularly scarce. Existing data
sources all have shortcomings; therefore, this paragraph is based on information compiled from a number of different
sources, including C. King and M. Webber, “Water Intensity of Transportation,” Environmental Science & Technology,
vol . 42, no. 21 (2009), available at http://pubs.acs.org/doi/pdf/10.1021/es800367m; P. Gosselin et al., Environmental
and Health Impacts of Canada’s Oil Sands Industry, The Royal Society of Canada, Expert Panel Report, Ottawa,
Ontario, December 15, 2010, p. 51. http://www.rsc.ca/documents/expert/
RSC%20report%20complete%20secured%209Mb.pdf; DOE, Energy Demands on Water Resources: Report to
Congress on the Interdependency of Energy and Water, December 2006; Canadian Association of Petroleum
Producers, Water Use in Canada’s Oil Sands, July 2011.
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which use processes that do not employ or require freshwater inputs for their development. The
freshwater intensity of in-situ oil sands production is generally 17% to 25% percent of oil sands
mining; however, while more water efficient, in-situ production leaves in place (i.e., unrecovered)
a considerable portion of the petroleum resources. The current direct water efficiency of oil sands
production may improve as new technologies are employed.
Much of the concern with oil sands development (and other types of unconventional oil and gas
development) is the concentration of water use and impacts within a limited geographic area. One
concern is that water use for oil sands mining reduces river flows, particularly during low flows
periods. To manage these concerns, oil sands operators are required to obtain water withdrawal
licenses, and a water management framework was developed to protect in-stream flows in the
Athabasca River. The framework identifies how water withdrawals are to be reduced during low
flow periods. A report by an expert panel of the Royal Society of Canada concluded that “water
use at current levels does not threaten viability of the Athabasca River system if the Water
Management Framework … is fully implemented and enforced.”169 Another concern is
groundwater depletion. The expert panel report found that “there needs to be greater attention
directed to regional groundwater resources” which currently are not well characterized, and that
there was no evidence of a framework to limit groundwater extraction.170
In addition, the issue of water quality has generated considerable debate. Results from the
Regional Aquatic Monitoring Program (RAMP)171 are often highlighted as evidence of the
minimal impacts to water resources due to oil sands development.172 For example, the 2011
RAMP Technical Report stated that “differences in water quality measured in fall 2011 between
all test and one of the upper baseline stations in the Athabasca River were classified as
Negligible-Low compared to the regional baseline conditions.”173
However, results from several peer-reviewed studies contradict the RAMP conclusions.174 For
example, a 2012 study found that the oil sands operations “substantially increases the loadings of
toxic PPE [priority pollutant elements] to the Athabasca River and its tributaries.”175 Moreover,
seven PPE—cadmium, copper, lead, mercury, nickel, silver, and zinc—exceeded Canada or
Alberta guidelines for aquatic life protection. In addition, another 2012 study concluded that the
“lake sediments in the Athabasca oil sands region register a clear PAH legacy with the pace and
scale of industrial development of the region’s tremendous bitumen [oil sands] deposits.”176
169 P. Gosselin et al., Environmental and Health Impacts of Canada’s Oil Sands Industry, The Royal Society of
Canada, Expert Panel Report, Ottawa, Ontario, December 15, 2010, p. 284.
170 Ibid., p. 285.
171 RAMP describes itself as “an industry-funded, multi-stakeholder environmental monitoring program” that began in
1997.
172 See, e.g., Government of Alberta, Oil Sands Factsheet: Protecting the Environment, at
http://www.oilsands.alberta.ca/FactSheets/Protecting_the_Environment%283%29.pdf.
173 RAMP, 2011 Technical Report, Executive Summary, at http://www.ramp-alberta.org/UserFiles/File/
RAMP_2011_Final_Executive_Summary.pdf.
174 See annual Technical Reports and Community Reports, at http://www.ramp-alberta.org.
175 Erin Kelly et al, “Oil Sands Development Contributes Elements Toxic at Low Concentrations to the Athabasca
River and Its Tributaries,” Proceedings of the National Academy of Sciences, 107: 16178-16183, 2010.
176 Joshua Kurek et al., “Legacy of a Half Century of Athabasca Oil Sands Development Recorded by Lake
Ecosystems,” Proceedings of the National Academy of Sciences, Early Edition,s October 2012.
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Some of these contradictory findings may be addressed by the Joint Implementation Plan for Oil
Sands Monitoring, established by the Canadian and Albertan governments in October 2012.177
According to the plan, it “builds on a foundation of monitoring that is already in place, and is
intended to enhance existing monitoring activities.” Among other objectives, the plan seeks to
improve analysis of existing monitoring data to develop a better understanding of historical
baselines and changes.”
177 The plan is available at http://environment.gov.ab.ca/info/library/8704.pdf.
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Appendix. Additional Information
Table A-1. Agencies With Jurisdiction or Expertise Relevant to Pipeline Impacts
Not Including Department of State
Agency
Role/Responsibilities in the Keystone XL Pipeline
EPA
Oversees state-implemented permit programs administered pursuant to the Section
402 of the Clean Water Act (CWA) regarding National Pol utant Discharge
Elimination System (NPDES). The NPDES program covers point-source discharges of
pollutants into U.S. waters. In addition, EPA reviews and comments on U.S. Army
Corps of Engineers permit applications (per CWA Section 404).
U.S. Army Corps of
Issues permits for sections of the pipeline that require placement of dredge and fill
Engineers (Corps)
material in waters of the United States, including wetlands (pursuant CWA Section
404), or for pipeline crossings of navigable waters (pursuant to Section 10 of the
Rivers and Harbors Act);
Department of the
The Bureau of Land Management (BLM) is authorized to grant temporary use
Interior (DOI)
permits for portions of the project that would encroach on federal lands.
The National Park Service (NPS) is responsible for providing technical review of the
proposal in the vicinity of NPS-administered lands affected by the proposed Project.
The U.S. Fish and Wildlife Service is responsible for ensuring project compliance with
the Endangered Species Act and would provide a Biological Opinion if the project is
likely to adversely affect federally listed species.
U.S. Department of
The Natural Resources Conservation Service (NRCS) administers the Wetlands
Agriculture (USDA)
Reserve Program under which it purchases conservation easements and provides
cost share to landowners for the purposes of restoring and protecting wetlands.
Department of
The Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of
Transportation
Pipeline Safety (OPS) has the safety-related authority for the nation’s natural gas and
(DOT)
hazardous liquid pipelines. PHMSA evaluates risks; develops and enforces standards
for design, construction, operations and maintenance of pipelines; responds to
accidents/incidents; conducts research on promising technologies; provides grants to
states to support their pipeline safety programs; and reviews oil spill response plans.
U.S. Department of
The Office of Policy and International Affairs (PI) provides advice to DOE on existing
Energy (DOE)
and prospective energy-related policies. At the request of DOS, PI provided
assistance in the analysis of the proposed project in light of world crude oil market
demand, and domestic and global energy challenges ranging from energy price and
market volatility to the long-term technology transitions related to greenhouse gas
emissions reduction, energy efficiency, and the use of renewable resources.
The Western Area Power Administration (Western) is a federal power-marketing
agency that sells and delivers federal electric power to municipalities, public utilities,
federal and state agencies, and Native American tribes in 15 western and central
states. Western consulted with DOS to ensure cultural resources potential y
affected by any Western transmission lines are taken into account.
Montana Department
Keystone is required to obtain a Certificate of Compliance from MDEQ under the
of Environmental
Montana Major Facility Siting Act (MFSA) before the proposed project may begin
Quality (MDEQ)
construction or acquire easements in Montana through the eminent domain process.
Various state/county
Various agencies must consult on and/or consider issuing permits for projects that
agencies
cross navigable waters or state highways, or involve work potentially affecting state
streams, cultural resources, or natural resources.
Source: CRS, based on a review of the U.S. Department of State’s, Final Environmental Impact Statement for the
Proposed Keystone XL Project: Introduction, amended September 2011, p. 1-12 to p.1-17.
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Author Contact Information
Jonathan L. Ramseur, Coordinator
Paul W. Parfomak
Specialist in Environmental Policy
Specialist in Energy and Infrastructure Policy
jramseur@crs.loc.gov, 7-7919
pparfomak@crs.loc.gov, 7-0030
Richard K. Lattanzio
Nicole T. Carter
Analyst in Environmental Policy
Specialist in Natural Resources Policy
rlattanzio@crs.loc.gov, 7-1754
ncarter@crs.loc.gov, 7-0854
Linda Luther
Analyst in Environmental Policy
lluther@crs.loc.gov, 7-6852
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