Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Congressional research reportApr 14, 2014
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Oil Sands and the Keystone XL Pipeline:
Background and Selected
Environmental Issues
-name redacted-, Coordinator
Specialist in Environmental Policy
-name redactedAnalyst in Environmental Policy
-name redactedAnalyst in Environmental Policy
-name redactedSpecialist in Energy and Infrastructure Policy
-name redactedSpecialist in Natural Resources Policy
April 14, 2014
Congressional Research Service
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www.crs.gov
R42611
Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Summary
If constructed, the Keystone XL pipeline would transport crude oil derived from oil sands sites in
Alberta, Canada, to U.S. refineries and other destinations. Because the pipeline would cross an
international border, it requires a Presidential Permit.
Although some groups have opposed previous oil pipelines, opposition to the Keystone XL
proposal has generated substantially more interest. Stakeholder concerns vary from local impacts,
such as oil spills or extraction impacts in Canada, to potential climate change consequences.
Arguments supporting the pipeline’s construction cover an analogous range. Proponents of the
Keystone XL Pipeline, including high-level Canadian officials and U.S. and Canadian petroleum
industry stakeholders, base their arguments supporting the pipeline primarily on increasing the
security and diversity of the U.S. petroleum supply and economic benefits, especially jobs.
A number of studies have looked into the various environmental impacts of oil sands crude. This
report focuses on selected environmental concerns raised in conjunction with the proposed
pipeline and the oil sands crude it will transport.
Greenhouse Gas Emissions
Key studies indicate that the average greenhouse gas (GHG) emissions intensity—metric tons of
GHG emissions per units of production (e.g., barrels)—of oil sands crude is higher than many
other crude oils. However, industry stakeholders point to analyses indicating that GHG emissions
from oil sands crude oil are comparable to other heavy crudes, some of which are produced
and/or consumed currently in the United States.
Due to oil sands’ increased emissions intensity, many stakeholders have voiced concern about
potential climate change consequences associated with oil sands development. In June 2013,
President Obama stated that an evaluation of the “net effects of the pipeline’s impact on our
climate” would factor into the Department of State’s (DOS’s) national interest determination in
order to determine if the project would “significantly exacerbate the problem of carbon
pollution.” Thus, DOS’s 2014 Final Environmental Impact Statement (FEIS) has received
considerable attention. Among other conclusions, the FEIS estimated that the incremental (i.e.,
net) life-cycle GHG emissions associated with the pipeline would be 1.3 million to 27.4 million
metric tons of carbon dioxide per year (0.02%-0.4% of U.S. annual GHG emissions). In addition,
the FEIS stated that the “approval or denial of any one crude oil transport project, including the
proposed project, is unlikely to significantly impact the rate of extraction in the oil sands or the
continued demand for heavy crude oil at refineries in the United States based on expected oil
prices, oil-sands supply costs, transport costs, and supply-demand scenarios.”
Some stakeholders have questioned these conclusions, arguing (1) that the project may have
greater climate change impacts than projected by DOS, and (2) that there is nothing presumed or
inevitable about the rate of expansion for the Canadian oil sands. Other stakeholders support the
FEIS analysis, arguing that as long as there is strong global demand for petroleum products,
resources such as the Canadian oil sands will be produced and shipped to markets using whatever
route necessary.
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Oil Spills and Other Local Impacts
Some groups have argued that both the pipeline’s operating parameters and the material being
transported through it impose an increased spill risk. The National Academy of Sciences National
Research Council examined this issue in a 2013 report, stating that it did not “find any causes of
pipeline failure unique to the transportation of diluted bitumen [oil sands crude].” However,
according to the Environmental Protection Agency (EPA), spills of oil sands crude may result in
different impacts than spills of other crude oils.
Other environmental concerns pertain to the region in which the oil sands resources are extracted.
Potential impacts include, among others, wildlife and ecosystem disturbance and water resource
issues. In general, these local/regional impacts from Canadian oil sands development are unlikely
to 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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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Contents
Introduction...................................................................................................................................... 1
Section 1: Oil Sands—Overview ..................................................................................................... 3
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 ..................................... 10
Section 2: Keystone XL Pipeline—Overview ............................................................................... 13
Federal Requirements to Consider the Pipeline’s Environmental Impacts.............................. 15
Presidential Permit Requirements for Cross-Border Pipelines ......................................... 16
Identification of Environmental Impacts During the NEPA Process................................. 17
Identification of Environmental Impacts During the
National Interest Determination ..................................................................................... 19
Consideration of Environmental Impacts Outside of the United States ............................ 22
Other Oil Pipelines from Canada............................................................................................. 23
Section 3: Selected Environmental Issues ..................................................................................... 25
GHG Emissions Intensity of Oil Sands Crude Oils ................................................................. 25
Life-Cycle Assessments .................................................................................................... 26
GHG Life-Cycle Assessments of Canadian Oil Sands ...................................................... 26
Canadian Oil Sands Compared to Other Crude Oils ......................................................... 29
GHG Emissions Intensities of Fossil Fuels ....................................................................... 30
Climate Change Concerns ....................................................................................................... 31
The 2014 FEIS GHG and Climate Change Analysis ........................................................ 31
Keystone XL and the Global Carbon Budget .................................................................... 34
Oil Spills .................................................................................................................................. 35
Oil Sands Crudes and Pipeline Spills ................................................................................ 36
Impacts of Spills of Oil Sands Crude ................................................................................ 44
Other Modes of Oil Transportation ................................................................................... 47
Oil Sands Extraction Concerns ................................................................................................ 49
Land Disturbances ............................................................................................................. 50
Water Resources and Quality Issues.................................................................................. 54
Figures
Figure 1. U.S. Imports of Canadian Crude Oil by Type .................................................................. 4
Figure 2. Estimated In-Place Natural Bitumen (Oil Sands) Resources by Region .......................... 5
Figure 3. EIA Estimated Proven Oil Reserves ................................................................................. 7
Figure 4. Alberta Oil Sands.............................................................................................................. 8
Figure 5. Illustration of Steam-Assisted Gravity Drainage (SAGD) ............................................. 10
Figure 6. Existing and Proposed Segments of Keystone Pipeline System .................................... 14
Figure 7. Oil Pipelines between Canada and the United States ..................................................... 23
Figure 8. Well-to-Wheel GHG Emissions Estimates for Canadian Oil Sands Crudes .................. 28
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Figure 9. Well-to-Wheel GHG Emissions Estimates for Global Crude Resources ....................... 29
Figure 10. Life-Cycle GHG Emissions Estimates for Gasoline, Natural Gas, and Coal ............... 31
Figure 11. Content of Hydrogen Sulfide (H2S) in DilBits and Selected Crude Oils ..................... 38
Figure 12. Sediment Content in DilBit Blends and Other Canadian Crude Oils ........................... 39
Figure 13. U.S. Refinery Receipts of Crude Oil by Mode of Transportation ................................ 48
Figure 14. Oil Spill Volume Per Billion-Ton Miles ....................................................................... 49
Figure 15. Illustrative Comparison of Energy Yields by Selected Sources ................................... 52
Tables
Table 1. Selected Global Crude Oil Specifications ........................................................................ 12
Table 2. National Interest Determination Milestones for the Keystone XL Pipeline..................... 21
Table 3. Major U.S.-Canadian Petroleum Import Pipelines .......................................................... 24
Table 4. Estimates of Oil Spill Frequency and Volume ................................................................. 42
Table A-1. Agencies With Jurisdiction or Expertise Relevant to Pipeline Impacts ....................... 56
Appendixes
Appendix. Additional Information ................................................................................................. 56
Contacts
Author Contact Information........................................................................................................... 57
Congressional Research Service
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 refineries and other destinations in the
United States. Policy makers continue to debate various issues associated with the proposed
pipeline. Although some groups have raised concerns over previous oil pipelines—Alberta
Clipper and the Keystone mainline pipelines, both of which are operating—the Keystone XL
proposal has generated substantially more interest among environmental stakeholders.
“Oil Sands” vs. “Tar Sands”
The terms “oil sands” and “tar sands” are often used interchangeably to describe a particular type of nonconventional
oil deposit that is found throughout the world in varying quantities. Opponents of the resource’s development often
use the term tar sands, which arguably carries a negative connotation; proponents typically refer to the material as oil
sands. Some federal government resources refer to the deposits as tar sands, some oil sands, and some have used
both terms. In its documents evaluating the Keystone XL pipeline, the Department of State (DOS) refers to the
material as oil sands. The Environmental Protection Agency (EPA) has followed suit in its letters to DOS concerning
the pipeline’s environmental impacts. In general, this report uses the term oil sands to describe the deposits in the
ground and oil sands-derived crude oil to describe the material imported into the United States. The use of this term
is not intended to reflect a point of view, but to adopt the term most commonly used by the primary executive
agencies involved in recent oil sands policy issues.
Before the Keystone XL pipeline can be constructed, its owner/operator, TransCanada,1 must
receive a Presidential Permit, which is issued by the State Department. The decision of whether to
issue this permit has provided (and continues to provide) a rallying point for environmental
groups who have voiced various concerns over the construction of the pipeline and/or further
development of the oil sands.
The Presidential Permit application—submitted by TransCanada—for the pipeline’s construction
represents a singular decision made by the Administration about whether or not the pipeline
would serve the national interest. Such a decision requires the identification of factors that would
inform that determination, as well as an assessment of the resulting impacts of both building and
not building the pipeline.
Stakeholders who raise concerns with the pipeline project are not a monolithic group. 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. For these stakeholders, 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.
Arguments supporting the pipeline’s construction also cover a range of issues. Proponents of the
Keystone XL Pipeline, including high-level Canadian officials and U.S. and Canadian petroleum
1
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.
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
industry stakeholders, base their arguments supporting the pipeline primarily on increasing the
security and diversity of the U.S. petroleum supply and economic benefits, especially jobs. An
analysis of these issues is beyond the scope of this report. For more discussion of these and other
issues, see CRS Report R41668, Keystone XL Pipeline Project: Key Issues, by (name redacted)
et al.
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 and issues. 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, related climate change concerns, pipeline oil spill risks, and
two oil sands extraction concerns: land disturbance and water resources.
•
An Appendix provides a list of agencies with jurisdiction or expertise relevant to
pipeline impacts.
This report is intended to complement other CRS reports that address different aspects of the
Keystone XL proposal, including the following:
•
CRS Report R41668, Keystone XL Pipeline Project: Key Issues, by (name re
dacted) et al.
•
CRS Report R42124, Proposed Keystone XL Pipeline: Legal Issues, by (name
redacted), (name redacted), and (name redacted).
•
CRS Report R42537, Canadian Oil Sands: Life-Cycle Assessments of
Greenhouse Gas Emissions, by (name redacted).
•
CRS Report R43415, Keystone XL: Greenhouse Gas Emissions Assessments in
the Final Environmental Impact Statement, by (name redacted).
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Section 1: Oil Sands—Overview
The term oil sands generally refers to a mixture of sand, clay and other minerals, water, and a
very dense2 and highly viscous (i.e., resistant to flow) form of petroleum called “bitumen.” At
room temperature, oil sands bitumen has the consistency of cold molasses. This property makes it
difficult to transport.3
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.
Companies developing oil sands reserves currently must 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 include 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.4 Canadian crude oil imports
accounted for approximately 33% of U.S. crude oil imports in 2013, up from 28% in 2012.5
2
Oil sands bitumen contains up to 50% (by weight) asphaltenes, a class of hydrocarbon of high molecular weight.
This same property lends itself well to making asphalt—a mixture of asphaltenes and petrolenes—useful for road
paving.
4
Canadian Association of Petroleum Producers, Crude Oil: Forecast, Markets & Transportation, June 2013.
5
Energy Information Administration, “U.S. Imports by Country of Origin,” at http://www.eia.gov.
3
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Figure 1. U.S. Imports of Canadian Crude Oil by Type
2005-2013
1,000
900
Millions of Barrels
800
700
600
500
400
300
200
100
2005
2006
Conventional Crude
2007
2008
2009
2010
2011
Synthetic Crude from Oil Sands or Conventional Heavy Oil
2012
2013
Dilbit and Synbit
Source: Prepared by CRS; data from Canada’s National Energy Board: 2005-2008 data provided in personal
communication; 2009-2013 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. Synthetic Crude Oil
includes crude oil produced from both oil sands and conventional heavy oil. According to Canada’s National
Energy Board, approximately 90% of the synthetic crude oil comes from oil sands (personal communication June
14, 2013).
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, 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.”6 For a
variety of reasons (e.g., technology and economics), less than 0.4%—based on information in
2007—of the estimated oil sands resources are currently being produced.7
6
7
U.S. Geological Survey (USGS), Heavy Oil and Natural Bitumen Resources in Geological Basins of the World, 2007.
Ibid.
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Figure 2. Estimated In-Place Natural Bitumen (Oil Sands) Resources by Region
Billion Barrels
98% in Canada
92% in Venezuela
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 substantially
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.”8 The Government of Alberta
estimates that its proven oil sands reserves are approximately 170 billion barrels,9 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).
8
9
See EIA Glossary at http://www.eia.gov/.
Government of Alberta, “About the Resource,” at http://oilsands.alberta.ca/resource.html (accessed April 6, 2012).
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
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.10 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%).11 The deposits are not uniform. For instance, some
deposits (estimated at less than 15%)12 in Utah may be amenable to surface mining techniques. In contrast, the Alaska
deposits are buried below several thousand feet of permafrost.13 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.14
Although prior attempts, dating back decades, have been made in several locations, various challenges hindered
commercial development.15
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.16 As of the date of this report, the company has received a
permit to begin relatively small-scale oil sands mining operations on approximately 200 acres of state-owned lands.17
According to the company, it plans to begin operations in 2015,18 achieving an initial output of approximately 2,000
barrels per day.19 This project has been opposed by environmental groups, some of which are appealing the permit
decision in the court system.20
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.21 Note that
proven reserve estimates can change dramatically over a relatively short time (Figure 3). EIA
10
See USGS, Natural Bitumen Resources of the United States, 2006, at http://pubs.usgs.gov/fs/2006/3133/pdf/FS20063133_508.pdf. The USGS estimates are largely based on studies from 1984 and 1995.
11
The USGS assessment identifies additional states—Oklahoma, New Mexico, and Wyoming—with potential oil
sands deposits, but these would each account for less than 1% of the total U.S. estimate.
12
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.
13
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, pp. 141-157.
14
Bureau of Land Management, Oil Shale and Tar Sands Programmatic EIS Information Center, at
http://ostseis.anl.gov.
15
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 (name redacted).
16
See U.S. Oil Sands website, at http://www.usoilsandsinc.com.
17
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.
18
U.S. Oil Sands, “US Oil Sands Inc. Awards Utah Project and Construction Management Contract,” January 20, 2014,
at http://www.usoilsandsinc.com.
19
U.S. Oil Sands, Notice of Intention to Commence Large Mining Operations, 2009.
20
See, e.g., Utah Tar Sands Resistance, at http://tarsandsutah.blueskyinstitute.org.
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
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 from 73 BBO in 2000 to 298 BBO in 2013.22 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.
Figure 3. EIA Estimated Proven Oil Reserves
Top 15 Nations in 2013—Compared to 2000 Estimates
350
Billion Barrels
300
250
200
150
100
50
2000
Brazil
China
Qatar
United States
Kazakhstan
Nigeria
Libya
Russia
UAE
Kuwait
Iraq
Iran
Canada
Saudi Arabia
Venezuela
0
2013
Source: Prepared by CRS; data from EIA, “International Energy Statistics,” at http://www.eia.gov/.
Notes: The 2013 estimate for the United States is based on the 2012 estimate because the 2013 estimate was
not available.
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.23
(...continued)
21
EIA “International Energy Statistics,” at http://www.eia.gov/.
22
Ibid.
23
Government of Alberta website, at http://oilsands.alberta.ca/reclamation.html#JM-OilSandsArea.
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Figure 4. Alberta Oil Sands
Potential Mining and In Situ Sites
Source: Government of Alberta, at http://oilsands.alberta.ca/reclamation.html#JMOilSandsArea.
Note: 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 officially determined (Crude Oil: Forecast, Markets & Pipelines, June 2011).
The year 2012 was the first year in which in situ operations accounted for a larger percentage
(55%) of oil sands production than mining. The Canadian Association of Petroleum Producers
(CAPP) projects in situ production to increase its share of production in coming years, accounting
for approximately 62% of total production by 2020.24 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
24
Canadian Association of Petroleum Producers (CAPP), Crude Oil: Forecast, Markets & Transportation, June 2013.
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
(i.e., primary soils and vegetation), excavation of the resource, and transportation to a processing
facility. Nearly all mined bitumen is currently upgraded to synthetic crude oil.25
In Situ
Oil sands deposits that are deeper than approximately 225 feet are recovered using one of three in
situ methods: primary production,26 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 2012, involve injecting steam into an oil sands reservoir.27 The steam heats the
bitumen, decreasing its viscosity and enabling its collection. Based on 2012 data, SAGD accounts
for the greatest percentage of in situ recovery and is the preferred method of recovery for most
new projects.28 SADG involves a top well for steam injection and a bottom well for bitumen
production.29 Figure 5 provides an illustration of this process.
In contrast to bitumen from mining operations, which generally produce synthetic crude oil, the
vast majority of bitumen from in situ operations becomes DilBit.30
25
National Research Council, Effects of Diluted Bitumen on Crude Oil Transmission Pipelines, 2013.
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 2012 and Supply/Demand Outlook
2013-2022, 2013.
27
ERCB, 2013.
28
ERCB, 2013.
29
In contrast, CSS uses a vertical well to liquefy the bitumen, which is then pumped to the surface using the same well.
30
National Research Council, Effects of Diluted Bitumen on Crude Oil Transmission Pipelines, 2013.
26
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
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:
•
API Gravity.31 API 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 22º 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-
31
American Petroleum Institute.
U.S. Energy Information Administration, Crude Oil Input Qualities, “Definitions, Sources and Explanatory Notes,”
at 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.
32
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
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-ofthumb, 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.
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
Source
Crude Oil Name
°API
Gravity
Sulfur
(Weight %)
TAN
(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 Coleville
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
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
Pilon
16.2
2.47
1.60
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
0.93
0.12
Selected Heavy Crude Oils
Venezuela
Selected Medium and Light Crude Oils (> 22.3° API)
U.S. (Alaska)
Alaskan North Slope
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
Nigeria
32.1
Southern Green Canyon Heavy-Sour
28.4
2.48
0.17
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
Arabian Heavy
27.5
2.95
0.40
Arabian Light
33.7
1.96
0.05
Saudi Arabia
Sources: Canadian crude data from Crude Quality Inc., Canadian Crude Quick Reference Guide; other crude
oil data from Capline, Crude Oil Assays; BP Crude Assays; ExxonMobil Assays; “Benchmark West Texas
Intermediate Crude Assayed,” Oil and Gas Journal, 1994; McQuilling Services, LLC, “Carriage of Heavy Grade
Oil,” Garden City, NY, 2011; Hydrocarbon Publishing Co., Opportunity Crudes Report II, Southeastern, PA, 2011.
Notes: The crude oils listed above are not an exhaustive list, nor do they represent a specific percentage of
global consumption. Multiple crude oils from certain locations are included to indicate the range of parameters.
API gravity—measured in degrees—is typically used to compare the weight of crude oils to water. An API
gravity greater than 10º indicates that the crude oil is lighter than water (i.e., it floats); an API gravity less than
10º indicates that the crude oil is heavier than water (i.e., it sinks). The average API gravity for natural bitumen
deposits is 5.4º (U.S. Geological Survey, Heavy Oil and Natural Bitumen Resources in Geological Basins of the World,
2007).
TAN (or total acid number) is the amount of potassium hydroxide (in milligrams) needed to neutralize the acid
in one gram of oil.
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Section 2: Keystone XL Pipeline—Overview
As originally proposed by TransCanada in September 2008,35 the Keystone XL pipeline would
have involved two major segments (Figure 6). The first segment—approximately 875 pipeline
miles in the United States—would cross the U.S.-Canadian border into Montana, pass through
South Dakota, and terminate in Steele City, NE. The second segment—approximately 485 miles
and labeled as the “Gulf Coast Project” in Figure 6—would connect an existing pipeline in
Cushing, OK, with locations in southern Texas.
Following action from Congress, DOS, and state governments (see Table 2 for details), DOS
ultimately denied TransCanada’s initial permit application in January 2012.36 TransCanada then
proceeded with construction of the Gulf Coast Pipeline. That segment did not require a permit
from DOS because it does not cross a U.S. border. (See “Presidential Permit Requirements for
Cross-Border Pipelines,” below.) The Gulf Coast Pipeline Project became operational on January
22, 2014.
In May 2012, TransCanada submitted a new permit application to DOS for the proposed
Keystone XL Pipeline. That application is for only the 875-mile northern pipeline segment.
Once complete, the entire Keystone XL pipeline system 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 in the section below, “Other Oil Pipelines from Canada”). Assuming the
pipeline were to deliver this maximum capacity each day of the year, it would transport
approximately 300 million barrels per year, a considerable volume when compared to the 420
million barrels of DilBit and synthetic crude oil Canada exported to the United States in 2013
(Figure 1).
The 36-inch-diameter pipeline would require a 50-foot-wide permanent right-of-way along the
route.37 Approximately 88% of the pipeline right-of-way would be on privately owned land; the
remaining 12% is owned by local, state, or federal governments. Rangeland and agricultural land
comprise most of the land crossed by the proposed pipeline. Additional facilities associated with
the pipeline system include pump stations (with associated electric transmission interconnection
facilities), mainline valves, and delivery metering facilities.38
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 following:
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
A more detailed timeline of events is available in CRS Report R41668, Keystone XL Pipeline Project: Key Issues, by
(name redacted) et al.
37
According to a Pipeline and Hazardous Materials Safety Administration online glossary, a “pipeline right-of-way is a
strip of land over and around pipelines where some of the property owner’s legal rights have been granted to a pipeline
company.... generally, the pipeline company’s right-of-ways extend 25 feet from each side of a pipeline unless special
conditions exist” (see http://www.phmsa.dot.gov/resources/glossary#R).
38
U.S. State Department, Final Supplemental Environmental Impact Statement for the Keystone XL Project, Section,
3.9, “Land Use, Recreation, and Visual Resources,” p. 3.9-1, January 2014, available at http://keystonepipelinexl.state.gov/documents/organization/221168.pdf
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
•
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, NE, to existing crude oil terminals and tank farms in Cushing, OK.
The Cushing Extension began operating February 2011.
Figure 6. Existing and Proposed Segments of Keystone Pipeline System
Source: TransCanada, at http://keystone-xl.com/keystone-xl-pipeline-overall-route-map/.
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Federal Requirements to Consider the
Pipeline’s Environmental Impacts
The DOS decision-making process related to a Presidential Permit application is subject to
environmental review requirements established pursuant to the National Environmental Policy
Act (NEPA, 42 U.S.C. §4321 et seq.). Compliance with NEPA is intended, in part, to assure that
DOS fully identifies and considers any significant environmental impacts associated with the
issuance or denial of a permit to construct, operate, and maintain the pipeline system and
associated facilities. The analysis of impacts prepared during the NEPA process is intended to
inform the federal decision-making process. As a result, compliance with NEPA must be
documented and demonstrated before DOS can make a final decision on the Presidential Permit.
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 2008
permit application. With TransCanada’s 2012 reapplication for a permit to construct the newly
configured Keystone XL pipeline project, the Presidential Permit process and NEPA compliance
process began anew.
Generally, federal agencies have no authority to control siting of oil pipelines, even interstate
pipelines.39 Instead, the primary siting authority for oil pipelines generally would be established
under applicable state law (which may vary considerably from state to state).40 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.41
Key elements of the Presidential Permit process, including DOS efforts to identify environmental
impacts associated with the TransCanada’s 2008 and 2012 permit applications 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.
39
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.
40
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 (name redacted) and
CRS Report RL33705, Oil Spills in U.S. Coastal Waters: Background and Governance, by (name redacted).
41
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 (name redacted), (name red
acted), and (name redacted).
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
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 applicable
Executive Orders. However, when discussing the 2008 permit application, DOS 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.”42
More recently, DOS stated that its national interest determination will involve “consideration of
many factors including: energy security; environmental, cultural, and economic impacts; foreign
policy; and compliance with relevant federal regulations and issues.”43
In addition, DOS stated that some of the key factors it considered in past decisions include the
following:
•
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;
•
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.44
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 energyrelated 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
42
The U.S. State Department, Final Environmental Impact Statement for the Keystone XL Project, August 2011,
“Introduction: 1.3 Presidential Permit Process” (as amended September 22, 2011), p. 1-4, available at
http://keystonepipeline-xl.state.gov/archive/dos_docs/feis/index.htm#.
43
See the U.S. State Department press release, “Keystone XL Final Supplemental Environmental Impact Statement
Released,” January 31, 2014, available at http://www.state.gov/r/pa/prs/ps/2014/01/221112.htm.
44
2011 final EIS.
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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 the proposed project would serve the national interest, then a Presidential
Permit must be issued. Specific to the Keystone XL pipeline, in its 2012 Presidential Permit
application, TransCanada states the following:
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.45
To ensure that environmental impacts are considered before final agency decisions are made,
NEPA requires an environmental impact statement (EIS) must be prepared for every major federal
action that may have a “significant” impact upon the environment.46 With respect to the
Presidential Permit applications submitted by TransCanada for Keystone XL, the State
Department concluded that approval of a permit did require the preparation of an EIS.47 Analysis
included in the EIS is intended to identify any significant impact of the proposed pipeline,
including anticipated impacts of taking no action (e.g., denying the permit) and potential
mitigation measures or protections necessary to reduce the potential for adverse environmental
impacts. DOS uses that assessment of environmental impacts, with other factors, to determine if
the project does, in fact, serve the national interest.
Identification of Environmental Impacts During the NEPA Process48
The DOS review of a Presidential Permit application explicitly requires compliance with multiple
federal environmental statutes.49 Environmental requirements identified within the context of the
NEPA process have drawn considerable attention.
45
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/.
46
42 U.S.C. §4332(2)(C).
47
U.S. Department of State, “Notice of Intent to Prepare a Supplemental Environmental Impact Statement (SEIS) and
To Conduct Scoping and To Initiate Consultation Under Section 106 of the National Historic Preservation Act for the
Proposed TransCanada Keystone XL Pipeline Proposed To Extend From Phillips, MT (the Border Crossing) to Steele
City, NE,” 77 Federal Register 36032, June 15, 2012.
48
For more detailed NEPA information, see CRS Report RL33152, The National Environmental Policy Act (NEPA):
Background and Implementation, by (name redacted).
49
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.
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Pursuant to NEPA, when considering an application for a Presidential Permit, DOS must take into
account environmental impacts of a proposed facility and directly related construction. The EIS
for the proposed Keystone XL Pipeline project identifies significant impacts associated with the
construction, connection, operation, and maintenance of the pipeline and its associated facilities.
In August 2011, DOS issued a final EIS that identified reasonably foreseeable impacts associated
with approving or denying a permit for the Keystone XL pipeline, as proposed in 2008.50 On
January 31, 2014, DOS released the final EIS prepared for the 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.51 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.52
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.53 The original Keystone XL permit process
involved 11 federal cooperating agencies, including the Environmental Protection Agency (EPA),
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.54 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.55
50
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.
51
For information regarding NEPA requirements, see CRS Report RL33152, The National Environmental Policy Act
(NEPA): Background and Implementation, by (name redacted).
52
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.
53
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.
54
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.
55
Issues associated with the NEPA process for the 2008 permit application are detailed in CRS Report R41668,
Keystone XL Pipeline Project: Key Issues, by (name redacted) et al.
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On March 1, 2013, the State Department released the draft EIS for the 2012-proposed Keystone
XL Pipeline project as a supplement to the final EIS prepared for the 2008 Presidential Permit
application (released in August 2011).56 In contrast to EISs prepared for the 2008 permit
application, EISs prepared for the 2012 permit application evaluated potential impacts associated
with a pipeline route from Montana to Steele City, NE, that avoids the Nebraska Sand Hills and
excludes the proposed Gulf Coast Project. The EISs expand upon and update information
included in the 2011 final EIS prepared for the 2008 permit application.
EPA provided comments on the draft EIS for the 2012 permit application.57 It rated the draft EIS
as “EO-2” (Environmental Objections—Inadequate Information). EPA stated that, while the
agency believes the draft EIS strengthens the analysis presented to date in the NEPA process, it
recommended several improvements to the analysis of the proposed project’s impacts and to
mitigate certain impacts. The recommendations for improvements to the EIS fell broadly into
categories regarding the analyses of GHGs, pipeline safety, alternative pipeline routes, and
community and environmental justice impacts.
On January 31, 2014, the State Department released the final EIS for the 2012 permit application.
Any additional or revised analysis included in the final EIS reflects DOS’s response to comments
from the public, EPA, and any federal, state, tribal, or local agency. With the release of the final
EIS, DOS begins the process to determine whether the project will serve the national interest.
Identification of Environmental Impacts During the
National Interest Determination
Generally, the NEPA process 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 the DOS
process to make its national interest determination. For previous Presidential Permits, a ROD and
National Interest Determination (NID) were issued as the same document.58
With the publication of the final EIS, the process to make the NID begins. As required in
Executive Order 13337, DOS will seek input from selected federal agencies to determine whether
issuance of a Presidential Permit for the pipeline would serve the national interest. Those
agencies have 90 days to submit relevant information to DOS. DOS also provided a 30-day public
comment period, ending on March 7, 2014.
56
See U.S. Department of State, “New Keystone XL Pipeline Application” webpage at http://www.keystonepipelinexl.state.gov/. On March 8, 2013, EPA listed the draft EIS in its weekly “Environmental Impacts Statements; Notice of
Availability,” in the Federal Register, see 78 Federal Register 15012. DOS refers to the EIS released in March 2013 as
a “Draft Supplemental” EIS. This reference apparently reflects the fact that the 2013 draft EIS draws largely from (or
supplements) documentation and analysis included in the final EIS issued in 2011 for the project proposed in the 2008
Presidential Permit application. However, for purposes of NEPA compliance, the submission of a new permit
application in May 2012 started the NEPA process anew. While it may draw from the 2011 final EIS, the 2013 draft
EIS is a new NEPA document—not a supplement to an EIS prepared for a different, albeit similar, Presidential Permit
application.
57
Letter from the U.S. Environmental Protection Agency’s Cynthia Giles, Assistant Administrator for Enforcement and
Compliance Assurance to Jose Fernandez and Kerri-Ann Jones, Assistant Secretaries, U.S. Department of State,
available online at http://epa.gov/compliance/nepa/keystone-xl-project-epa-comment-letter-20130056.pdf.
58
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.
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Issuance of the ROD and NID involve distinctly different, but 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 NID, 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. To illustrate the relationship between the
NEPA process and NID process, Table 2 summarizes milestones in the Presidential Permit
process for TransCanada’s 2008 and 2012 permit application.59
59
A more comprehensive timeline is provided in CRS Report R41668, Keystone XL Pipeline Project: Key Issues, by
(name redacted) et al.
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
Table 2. National Interest Determination Milestones for the Keystone XL Pipeline
Administrative, Congressional, State, and Company Actions
Date
Description
2011
August 26
DOS issues its FEIS for the 2008 permit application, starting the NID 90-day public review period.
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.
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 collaboratively with the State Department to gather information necessary for a
supplemental EIS.
December 23
The Temporary Payroll 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 announces that it will proceed with development of the southern pipeline segment as a
separate proposal.
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, potentially drawing upon relevant documents from the 2011 final EIS.
June 15
DOS announces its plan to prepare an EIS for the 2012 Presidential Permit application, that will
supplement information included in the 2011 final EIS (77 Federal Register 36032).
September 5
TransCanada submits a Supplemental Environmental Report to Nebraska DEQ with a preferred
route alternative.
2013
March 1
DOS releases draft EIS for the 2012 Keystone XL Pipeline project.
April 22
EPA submits its comments, rating the proposed project and draft EIS as “EO-2,” meaning EPA has
“Environmental Objections” to certain adverse project’s impacts and that the draft EIS includes
“Insufficient Information.” EPA recommends action that could be taken to reduce certain adverse
project impacts and additional analysis that should be included in the final EIS.
2014
January 31
DOS releases the final EIS for the 2012 Keystone XL Pipeline project; DOS begins NID process,
starting the 90-day time period for federal agencies to provide DOS with information to make its
determination begins.
February 5
30-day public comment period begins, ending March 7th.
Source: Prepared by the Congressional Research Service. Permit-related documents available 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
NEPA does not require DOS 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, these issues continued to generate concern among some stakeholders. It
is uncertain whether or the degree to which environmental impacts abroad will affect DOS’s
determination that the proposal will serve the national (i.e., U.S.) interest.
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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 (Solid Lines) and Proposed (Dashed Lines)
Source: Canadian Association of Petroleum Producers, Crude Oil: Forecast, Markets & Transportation, June 2013.
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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
Submitted
EIS
Prepared?
First Year of
Operation
Capacity
(bpd)
June 2008
2009
186,000
Yes
March 2008
2010
591,000
May 2007
Yes
August 2009
2010
450,000
TransCanada
September 2008
Yes
Denied
January 2012
NA
830,000
TransCanada
May 2012
Final EIS
issued January
2014
NA
830,000
Pipeline
Operator
Southern
Lights
(LSr)a
Southern
Lights
April 2007
No
Keystoneb
TransCanada
April 2006
Alberta
Clipperc
Enbridge
Keystone
XLd
Keystone
XLd
Permit
Issued
Source: Prepared by CRS; pipeline status and capacity information from CAPP, 2011. More specific sources
identified below.
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.
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.60
Some stakeholders may point to these statements as reasons to issue a Presidential Permit to the
XL proposal.
Section 3: Selected Environmental Issues
Environmental issues related to the Keystone XL pipeline and the oil sands crude oil it would
carry cover a wide spectrum. These issues involve both local/regional concerns—some in the
United States, some in Canada—and national/global concerns. This section does not provide an
exhaustive list of environmental issues. Instead, this section discusses several key issues,
including the following:
•
greenhouse gas emissions intensity;
•
climate change policy;
•
oil spill risk; and
•
oil sands extraction impacts.
GHG Emissions Intensity of Oil Sands Crude Oils61
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, some have
raised concern that oil sands have a higher emissions intensity than other forms of crude oil.62 In
this context, emissions intensity means GHG emissions per units of production (e.g., barrels).
Other stakeholders, including the Alberta government and industry associations, 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.63
The issue has generated considerable debate, attention, and analyses from multiple parties.
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.
60
DOS, Record of Decision and National Interest Determination, Keystone Pipeline, 2008, at
http://www.cardnoentrix.com/keystone/project/SignedROD.pdf.
61
This section is an abridged version of CRS Report R42537, Canadian Oil Sands: Life-Cycle Assessments of
Greenhouse Gas Emissions, by (name redacted).
62
See, e.g., NRDC, Setting the Record Straight: Lifecycle Emissions of Tar Sands, November 2010.
63
See e.g., Alberta Government “Oil Sands” website, at http://oilsands.alberta.ca/ghg.html; and Canadian Association
of Petroleum Producers, The Facts on Oil Sands, April 2012, at http://www.capp.ca.
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Life-Cycle Assessments
A life-cycle assessment (LCA) is an analytic method used for evaluating and comparing the
environmental impacts of various products.64 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.65 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, “Wellto-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. Focusing on the WTT assessment would
show oil sands crudes’ emissions intensities to be considerably higher than conventional oils,
because the assessment is weighted more proportionally to the production phase. Focusing on the
WTW assessments returns values for the emission intensity differences which are less
pronounced due to the inclusion of the combustion phase.
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 2014 FEIS. A CRS survey of these studies reveals the following:
1. Canadian oil sands crudes are generally more GHG emission-intensive than other
crudes they may displace in U.S. refineries, emitting an estimated 17% more
64
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 (name redacted) and (name redacted).
65
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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GHGs on a life-cycle basis than the average barrel of crude oil refined in the
United States;
2. compared to selected crude oil imports, Canadian oil sands crudes emit an
estimated 2%-19% more GHGs on a life-cycle basis (well-to-wheels (WTW));
and
3. they emit an estimated 9%-102% more GHGs on a well-to-tank (WTT) basis,
which omits the combustion phase.
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.66
66
Discussed in detail in CRS Report R42537, Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas
Emissions, by (name redacted).
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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 (name redacted). 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 (name redacted).
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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.
Note: 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 (name redacted).
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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.67
Parties from both sides of the issue may be able to use results from one or more of the above
studies to advance their positions. For example, some stakeholders often use WTT comparisons to
highlight the GHG emissions intensity of the oil sands extraction process. On the other hand,
other groups 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 and combustion of co-products) may be omitted,
due, in part, to their additional complexity. Therefore, comparing results across resources or
production methods may be problematic.
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 peerreview 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.
67
These are discussed in detail in CRS Report R42537, Canadian Oil Sands: Life-Cycle Assessments of Greenhouse
Gas Emissions, by (name redacted).
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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.
Note: The source article included both the 20 and 100 year time horizons for comparison purposes. The effects
of short-lived GHGs, such as methane, are more pronounced in the 20-year time horizon. Most researchers use
the 100-year horizon and the Intergovernmental Panel on Climate Change recommends using the longer time
horizon. CRS added the line with the two arrows that connects the oil sands emission intensity with the
underground coal mining emission intensity.
Climate Change Concerns
During a June 2013 speech, President Obama stated that an evaluation of the “net effects of the
pipeline’s impact on our climate” would factor into the State Department’s national interest
determination in order to determine if the project would “significantly exacerbate the problem of
carbon pollution.”68 Therefore, the 2014 FEIS GHG emission and climate change discussion has
generated considerable debate among stakeholders. The first section below discusses the DOS
analysis in its 2014 FEIS of GHG emissions related to the proposed pipeline and potential climate
change impacts.
The second section discusses oil sands development and its potential impact on the so-called
“global carbon budget.” Many stakeholders have raised concerns that the pipeline’s approval
would facilitate further development of oil sands, a potential outcome, they argue, that runs
counter to maintaining a specific carbon budget.
The 2014 FEIS GHG and Climate Change Analysis
Among the various impacts identified in the project’s environmental impact statement are those
involving GHG emissions. As required under NEPA, the 2014 FEIS identifies anticipated direct
and indirect impacts of the project as proposed by TransCanada as well as various project
68
White House, “Remarks by the President on Climate Change,” Georgetown University, Washington, DC, June 25,
2013, http://www.whitehouse.gov/the-press-office/2013/06/25/remarks-president-climate-change.
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alternatives, including analysis of the “no action alternative” (i.e., an assessment of the impacts
associated with denying TransCanada’s permit application). The 2014 FEIS finds the following:69
•
the GHG emissions released during the construction period for the project would
be approximately 0.24 million metric tons of carbon dioxide equivalents
(MMTCO2e)70 due to land use changes, electricity use, and fuels for construction
vehicles (equivalent to 0.004% of U.S. annual GHG emissions);71
•
the GHG emissions released during normal operations would be approximately
1.44 MMTCO2e/year due to electricity use for pumping stations, fuels for
maintenance and inspection vehicles, and fugitive emissions (equivalent to
0.02% of U.S. annual GHG emissions);
•
the total, or gross, life-cycle GHG emissions (i.e., the aggregate GHG emissions
released by all activities from the extraction of the resource to the refining,
transportation, and end-use combustion of refined fuels) attributable to the oil
sands crude transported through the proposed pipeline would be approximately
147 to 168 MMTCO2e per year (equivalent to 2.2%-2.6% of U.S. annual GHG
emissions);
•
the incremental, or net, life-cycle GHG emissions (i.e., GHG emissions over-andabove those from the crude oils expected to be displaced in U.S. refineries) is
estimated to be 1.3 to 27.4 MMTCO2e per year (equivalent to 0.02%-0.4% of
U.S. annual GHG emissions); but
•
according to the State Department’s market analysis, “approval or denial of any
one crude oil transport project, including the proposed project, is unlikely to
significantly impact the rate of extraction in the oil sands or the continued
demand for heavy crude oil at refineries in the United States based on expected
oil prices, oil-sands supply costs, transport costs, and supply-demand
scenarios.”72
The 2014 FEIS presents the crude oil market analysis separately from the GHG emissions
assessment. By determining that the most likely scenario is one in which oil sands production
would be unaffected by expected market conditions, the Final EIS implies that the “incremental”
life-cycle GHG emissions attributable to the oil sands crudes transported through the proposed
pipeline are negligible. With this determination, the only difference in estimates between
competing scenarios would be attributable to the operational GHG emissions of the alternative
modes of transportation (e.g., GHG emissions from rail cars, trucks, or tankers versus the
pipeline). The FEIS reports that the annual operational emissions attributed to the “no action”
69
2014 FEIS, pp. ES-15, ES-16, 4.14-39.
“Carbon dioxide equivalent” is a metric used to compare emissions of various greenhouse gases based upon their
global warming potential as indexed against one unit of carbon dioxide.
71
EPA reports that total domestic GHG emissions for all sectors in 2012 to be 6,502 MMTCO2e. EPA, Draft Inventory
of U.S. Greenhouse Gas Emissions and Sinks, 1990-2012, http://www.epa.gov/climatechange/ghgemissions/
usinventoryreport.html.
72
Final EIS, p. ES-16. The State Department bases its analysis primarily on three market projections: (1) the crude oil
input mix at Gulf Coast refineries remains constant, (2) rail and other non-pipeline transport options would fully
accommodate all projected growth in oil sands production, and (3) at no point would the global price of oil fall—or the
marginal cost of production increase—far enough that investment in new oil sands projects would be deemed
uneconomical (i.e., below the breakeven cost of production).
70
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alternatives range from 4.0 to 4.4 MMTCO2e per year (an increase of 29%-42% over the 3.1
MMTCO2e per year in operational emissions for the proposed project inclusive of the existing
southern leg).
Some stakeholders have questioned many of the conclusions in the 2014 FEIS and argue that the
project may have greater climate change impacts than the DOS projects. They contend that there
is nothing presumed or inevitable about the rate of expansion for the Canadian oil sands.73
Current oil sands projects face a challenging financial environment, and up-front production costs
and price differentials are comparatively higher for oil sands crudes, making new investment
sensitive to changes in supply costs and global prices. Commentators have highlighted the many
reported instances where current price discounts for oil sands crudes have dampened investment
and project development, including questions about whether rail transport will be used if the
pipeline is not built.74 They stress that oil market projections and transportation options are rife
with uncertainty, and that the proposed Keystone XL Pipeline could have a much more significant
impact on expansion if a number of key variables differ from the DOS assumptions. These
variables include lower global oil prices than projected; higher rail costs than projected; higher
new project costs than expected; greater competition from shale oil and tight oil plays; and future
carbon pricing or procurement policies in the United States or Canada. Any decrease or delay in
oil sands development could have significant impacts on the rate of growth in global GHG
emissions both directly (by curtailing production)75 and indirectly (by allowing more time for the
development of energy-efficiency strategies, the promulgation of climate policies, and the
deployment of lower-carbon energy technologies).
On the other hand, other stakeholders agree with a market analysis similar to the one outlined in
the 2014 FEIS. They argue that as long as there is strong global demand for petroleum products,
resources such as the Canadian oil sands will be produced and shipped to markets using whatever
route necessary. They see future investment affected only in scenarios where the global price of
oil falls below supply costs for an extended period of time. They see current production affected
only in scenarios that assume all pipeline transport capacity is frozen and no other transport
capacity (such as rail or tanker) is available.76 They contend that incentives are too great for oil
sands producers and the Canadian and Albertan governments to leave the oil in the ground; and
that once the oil is extracted, the market would likely respond by adding adequate transport
capacity over time. They contend that scaling up transport is logistically and economically
feasible, based on past and present evidence in the Powder River Basin and the Bakken, as well
73
See, for example, Natural Resources Defense Council et al., “Request for Supplemental Environmental Impact
Statement for the TransCanada Keystone XL Pipeline Based on Significant New Information,” Submitted to the U.S.
Department of State, June 24, 2013; Oil Change International, “Cooking the Books: How The State Department
Analysis Ignores the True Climate Impact of the Keystone XL Pipeline,” April 2013; and Rep. Henry Waxman et al.,
“Letter to the Hon. Kerry-Ann Jones,” Submitted to the U.S. Department of State, July 10, 2013.
74
See for example, Canadian Imperial Bank of Commerce, “Too Much of A Good Thing: A Deep Dive Into The North
American Energy Renaissance,” Institutional Equity Research Industry Update, August 15, 2012; TD Economics,
“Pipeline Expansion is a National Priority,” Special Report, December 17, 2012; Goldman Sachs, “Getting the Oil Out
of Canada: Heavy Oil Diffs Expected to Stay Wide and Volatile,” June 2, 2013.
75
As an example, the non-governmental organization Carbon Tracker Initiative has conducted a market analysis of
forecasted supply costs and breakeven prices for Canadian oil sands projects. They estimate the cumulative GHG
emissions from KXL-enabled “incremental production” through 2050 would be 5,145 to 5,880 MMTCO2e,
http://www.carbontracker.org/kxl.
76
Scenario results as indicated by the State Department’s modeling in Ensys 2010 WORLD Model in the market
analysis for the 2011 Final EIS as updated in the 2014 Final EIS.
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as the oil sands region itself.77 Furthermore, they estimate that GHG emissions intensities for the
Canadian oil sands are currently within the range of many other heavy crude oils, and that in the
future Canadian oil sands emissions intensities will only decrease (due to efficiency improvement
and technological advances), while those of other crudes around the world will likely increase
(due to a heavier resource base). They note also that the government of Alberta has implemented
policies to help mitigate and reduce the GHG emissions associated with oil sands production.
These include (1) a mandatory GHG intensity reduction program for large industrial emitters,78
(2) a fund for clean energy investment that is capitalized by the reduction program, and (3)
dedicated funding for the construction of large-scale carbon capture and sequestration (CCS)
facilities.79
Keystone XL and the Global Carbon Budget
Some stakeholders are concerned with the effect that Canadian oil sands development would have
on what is referred to as the “global carbon budget.” The global carbon budget is a scientifically
estimated maximum amount of net worldwide GHG that could be emitted without exceeding a
proposed temperature target of 3.6°F above pre-industrial levels (a 2°C target). Some consider
that such a temperature target would avoid the worst effects of greenhouse-gas induced climate
change, and it has been agreed as a political consideration in international negotiations to address
climate change under the United Nations Framework Convention on Climate Change. If this
estimation is correct, all countries’ emissions (net of any sequestration or “sinks”) would have to
stay within a given carbon budget to avoid exceeding the 2oC temperature cap. Based on studies
published during the past several years, the International Energy Agency (IEA)80 and the U.N.
Intergovernmental Panel on Climate Change (IPCC),81 among others, have estimated carbon
budget scenarios. The IPCC finds that in order to have at least a 66% chance of limiting global
warming to, or below, 2°C above pre-industrial levels, no more than 1 trillion tons of carbon can
be released into the atmosphere from the beginning of the industrial era through the end of this
century. The report estimates that 531 billion tons of that budget have been emitted as of 2011 and
that current global GHG emissions are on track to reach the threshold in 2040. Similarly, the IEA
estimates that “no more than one-third of proven reserves of fossil fuels can be consumed prior to
2050 if the world is to achieve the 2°C goal.”
Some have argued that the DOS Final EIS does not properly consider the potential impact of
using up the shared global carbon budget, estimating that the capacity of the proposed Keystone
XL project is equivalent to the net oil production growth budgeted by the IEA for the entire
77
Reports by the two major rail operators in Canada, Canadian National (CN) and Canadian Pacific Railway System
(CPRS), indicate crude and fuel oil car-loadings in Western Canada increased from nominal amounts in early 2011 to
approximately 160,000 bpd by April 2013 (however, “not all of the crude oil loaded by rail in western Canada is
necessarily exported to the United States,” and “approximately half of the crude oil hauled by rail in western Canada
was light, and half was heavy.” Final EIS, pp. 1.4-52-56. Further, crude-by-rail loading facilities have expanded
considerably in the past several years, with capacity expected to reach 720,000 bpd in WCSB by the end of 2014. Final
EIS, p. 1.4-61. The analysis also determines that the expansion of rail network capacity and rail tank car fleets could be
accommodated without encountering capacity issues. Final EIS, pp. 1.4-74, 1.4-80.
78
See Government of Alberta, Climate Change and Emissions Management Amendment Act,
http://www.qp.alberta.ca/574.cfm?page=2007_139.cfm&leg_type=Regs&isbncln=9780779738151.
79
Government of Alberta, Alberta’s Oil Sands Fact Sheet: Carbon Capture and Storage,
http://www.oilsands.alberta.ca/FactSheets/Carbon_Capture_FSht_June_2012_Online.pdf.
80
IEA, “World Energy Outlook,” 2012, http://www.worldenergyoutlook.org/publications/weo-2012/.
81
IPCC, Fifth Assessment Report (AR5), 2013, http://www.ipcc.ch/report/ar5/.
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OECD Americas region.82 Others have calculated that the GHG emissions from oil sands projects
currently producing or under construction would themselves reach the 2°C threshold if all the oil
sands resources were consumed.83
As with the assessment of incremental life-cycle GHG emissions, an understanding of the
“incremental carbon budget” that can be attributable to the proposed Keystone XL pipeline would
be dependent upon a market analysis that examines whether approval or denial of any one crude
oil transport project, including the proposed project, would significantly impact the rate of
extraction in the oil sands.84 For example, if extraction is likely to occur regardless of whether the
pipeline is built, then the approval or denial of the pipeline may have little effect on total net
carbon emissions. Conversely, if oil sands extraction is dependent on the pipeline, then
incremental carbon emissions could be high.
There is no political agreement in the United States on a domestic carbon budget, on the
appropriateness of the global 2°C target, or on the validity of any target. Some stakeholders may
contend that the project is such a large increment of emissions that it should be “the line in the
sand” for making a climate-protective decision.85 Conversely, others may argue that the project’s
share of incremental emissions is small and therefore not a significant addition of risk. Some
policy makers may not be sure of where any lines should be drawn or whether the project is the
“right” place to draw one, especially one drawn unilaterally by the United States.
Oil Spills
A primary environmental concern of any oil pipeline is the risk of a spill. 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 oil spill
risks are understated; others contend that pipeline risks are overstated.
Pipeline integrity concerns—whether real or perceived—were magnified by a 2010 pipeline spill
in Michigan and a 2013 pipeline spill in Arkansas, both of which involved oil sands crude oil.86 A
82
Carbon Tracker Initiative, “KXL: The Significance Trap,” March 2014, http://www.carbontracker.org/kxl.
See Oil Change International, “Petroleum Coke,” The Coal Hiding in the Tar Sands, January 2013,
http://priceofoil.org/content/uploads/2013/01/OCI.Petcoke.FINALSCREEN.pdf; and James Hansen, “Game Over for
the Climate,” New York Times, May 9, 2012, http://www.nytimes.com/2012/05/10/opinion/game-over-for-theclimate.html?_r=0, who estimates that “Canada’s tar sands … contain twice the amount of carbon dioxide emitted by
global oil use in our entire history,” and that “the concentration of carbon dioxide in the atmosphere has risen from 280
parts per million to 393 p.p.m. over the last 150 years. The tar sands contain enough carbon—240 gigatons—to add 120
p.p.m. ... If we turn to these dirtiest of fuels, instead of finding ways to phase out our addiction to fossil fuels, there is
no hope of keeping carbon concentrations below 500 p.p.m.—a level that would, as earth’s history shows, leave our
children a climate system that is out of their control.”
84
If the project is considered in the context of this “global carbon budget,” then it requires a close examination of the
energy produced per ton of GHG emitted. The question that would be important to address in this context is whether
the same investment can be made in another energy source (e.g., efficiency or domestic oil production) that results in
less net GHG emissions per unit of energy delivered. Fundamentally the consideration of the project is being done in
the context of an economic system that places no price on carbon.
85
For example, see non-governmental advocacy organizational initiatives such as “Draw the Line,”
http://www.drawthelineattarsands.com/.
86
A 2011 pipeline spill into the Yellowstone River in Montana also received attention, but that spill did not involve oil
sands crude oil. On July 1, 2011, an ExxonMobil pipeline spilled approximately 63,000 gallons of crude oil into the
(continued...)
83
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key question for policy makers is whether the Keystone XL would impose a greater or lesser risk
of an oil spill than another oil pipeline. In particular, do the properties of oil sands crude oil entail
a greater risk of a pipeline spill than other crude oils? If an oil spill occurs, how would an oil
sands crude oil spill differ from other crude oil spills? In addition, how do the oil spill risks from
a pipeline compare to other modes of oil transportation. These issues and other spill-related topics
are discussed below.
Oil Sands Crudes and Pipeline Spills
Some environmental groups have argued that the pipeline would pose additional oil spill risks due
to the material being transported. One vehicle for these arguments was a 2011 report from several
environmental groups.87 In that report, the authors asserted that certain characteristics of DilBit
may pose greater risks of a spill than other crude oils. Other organizations, including Canadian
agencies, questioned these conclusions.88 To examine these issues, Congress enacted P.L. 112-90,
which, among other provisions, directed the Secretary of Transportation to:
complete a comprehensive review of hazardous liquid pipeline facility regulations to
determine whether the regulations are sufficient to regulate pipeline facilities used for the
transportation of diluted bitumen. In conducting the review, the Secretary shall conduct an
analysis of whether any increase in the risk of a release exists for pipeline facilities
transporting diluted bitumen.
Pursuant to that act, the Department of Transportation’s Pipeline and Hazardous Materials Safety
Administration (PHMSA) contracted with the National Academy of Sciences’ National Research
Council (NRC)89 to conduct a study. In June 2013, the NRC issued a report (hereinafter, NRC
report) that analyzed whether transportation of DilBit by pipelines poses an increased likelihood
of release compared to other crude oils.90 The central findings of the report included the
following:
The committee does not find any causes of pipeline failure unique to the transportation of
diluted bitumen. Furthermore, the committee does not find evidence of chemical or physical
(...continued)
Yellowstone River. In an October 2012 report, PHMSA stated: “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.” PHMSA Report available at http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/
Other%20files/ExxonMobil_HL_MT_10-2012.pdf.
87
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 Swift et al., Tar Sands Pipelines
Safety Risks, 2011); 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).
88
See e.g., Energy Resources Conservation Board, Press Release, “ERCB Addresses Statements in Natural Resources
Defense Council Pipeline Safety Report,” February 2011; and Crude Quality Inc., Report regarding the U.S.
Department of State Supplementary Draft Environmental Impact Statement, May 2011.
89
Organized by the National Academy of Sciences in 1916, the National Research Council has become the principal
operating agency of both the National Academy of Sciences and the National Academy of Engineering in providing
services to the government, the public, and the scientific and engineering communities.
90
National Research Council, Effects of Diluted Bitumen on Crude Oil Transmission Pipelines, 2013 (hereinafter, NRC
report).
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properties of diluted bitumen that are outside the range of other crude oils or any other aspect
of its transportation by transmission pipeline that would make diluted bitumen more likely
than other crude oils to cause releases.91
The following sections discuss these and related issues in greater detail.
Corrosion
The 2013 NRC report describes internal pipeline corrosion as an electrochemical process that
typically causes damage to the bottom of the pipeline when water is present. Some have argued
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.”92 Crude oil properties of particular interest are acidity and sulfur content, which are
discussed below.
Acidity
Crude oil acidity is generally measured by total acid number (TAN).93 As indicated in Table 1
(above) Canadian DilBit TANs range between 0.92 to 2.49. This range is generally higher than
lighter crude oils, but comparable with other heavy 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 570ºF.94 However, pipeline transportation of DilBit is expected to occur at
much lower temperatures: the operating temperature for Keystone XL is expected to be between
42ºF and 135ºF.95 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.96 TAN values depend upon the specific
content and types of compounds in specific crudes—which may vary significantly from crude to
crude.97 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.98 Therefore, it is uncertain whether
refiners’ experiences with corrosion from high TAN crudes can be directly extended to DilBit
transmission pipelines.
Sulfur Content
91
NRC report, p. 2.
Swift et al., Tar Sands Pipelines Safety Risks, 2011
93
TAN is the amount of potassium hydroxide (in milligrams) needed to neutralize the acid in one gram of oil.
94
NRC report, 2013.
95
2014 FEIS, p. 3.13-15.
96
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.
97
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.
98
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.
92
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Sulfur content may be another indicator of crude oil corrosivity. Crude oils sent to U.S. refineries
typically contain 0.5% to 2.5% sulfur.99 As indicated in Table 1, DilBits have sulfur contents
substantially above this range—between 3% and 5%—as do other heavy crude oils. In some sour
crudes (> 1% sulfur content), sulfur content may indicate hydrogen sulfide (H2S),100 which acts as
a corrosive acid when dissolved in water.
However, the NRC report states that most of the sulfur in bitumen is contained in stable
compounds, instead of the corrosive H2S. Figure 11 provides a comparison of H2S content in
selected DilBits with other crude oils. The figure indicates that (based on the samples tested) the
DilBit samples contained relatively lower concentrations of H2S than the other tested crude oils.
Figure 11. Content of Hydrogen Sulfide (H2S) in DilBits and Selected Crude Oils
Source: Reproduced from Reproduced by CRS from National Research Council, Effects of Diluted Bitumen on
Crude Oil Transmission Pipelines, 201, Figure 3-9.
Notes: Data provided to the NRC by the Canadian Crude Quality Technical Association.
99
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.
100
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.
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Erosion
In the context of pipeline transport, erosion is a mechanical process in which solid particles in the
crude oil damage pipeline walls. Some have raised this process as a particular concern for DilBit
pipelines.101
The 2013 NRC report compared the sediment contents in various DilBit blends with light,
medium, and heavy Canadian crude oils. Figure 12 illustrates the results of this comparison. As
the figure indicates, the sediment contents in DilBit blends are similar to those in other Canadian
crude oils.
Moreover, crude oils with high solids content are also generally filtered to meet the quality
specifications set by pipelines and refiners. The 2013 NRC report points out that Canadian
pipeline regulations require that sediment and water content in crude oil not exceed 0.5% by
volume, while U.S. regulations allow ratios up to 1% by volume. Crude oil pipeline imports from
Canada would be meeting the more stringent standards of Canada during their transit within the
United States.
Figure 12. Sediment Content in DilBit Blends and Other Canadian Crude Oils
Source: Reproduced by CRS from National Research Council, Effects of Diluted Bitumen on Crude Oil Transmission
Pipelines, 201, Figure 3-7.
Notes: Data in NRC figure obtained from CrudeMonitor, at http://www.crudemonitor.ca.
101
Swift et al., Tar Sands Pipelines Safety Risks, 2011.
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Volatility
According to the NRC report, a liquid that has a relatively high fraction of hydrocarbons with
high vapor pressure can theoretically increase the potential for a process known as column
separation—the transformation of the liquid into a vapor phase. Such an event can create a
pressure surge, which can increase the potential for pipeline damage, if a pipeline is already
weakened by corrosion, cracking, or deformities from earlier mechanical damage.102
During the 2011 EIS process, some contended that the “instability of DilBit can render pipelines
particularly susceptible to ruptures caused by pressure spikes.”103 However, the NRC report stated
that DilBit does not contain a high percentage of light (high vapor pressure) hydrocarbons and
thus the potential for column separation “should be indistinguishable from that of other crude
oils.”104
Keystone XL Pipeline Operating Parameters
Some parties have expressed concern about the Keystone XL pipeline operating parameters,
particularly the operating temperature and pipeline pressure.105 In general, parties contended that
the Keystone XL pipeline would be operating at temperatures and pressures well above
conventional crude oil pipelines.
In the 2014 FEIS, DOS states that the operating temperature is “expected to be approximately
between 42°F and 135°F.”106 However, one of the parameters unique to Keystone XL (“Special
Condition 15,” discussed below) appears to allow for temperatures higher than 150°F, subject to
specific testing results and PHMSA approval.107 Although the FEIS does not discuss whether or
not operating temperatures will approach or breach 150°F during the pipeline’s operation, Special
Condition 15 appears to allow that possibility.
As to the operating pressure, DOS states the following: “the design of the proposed Project
pipeline system is based on a maximum 1,308 pounds per square inch gauge (psig) discharge
pressure at each pump station.... There would be situations where, due to elevation changes, the
hydraulic head created would result in a maximum operating pressure of up to and including
1,600 psig.”108
How do the Keystone XL operating parameters compare to other DilBit pipelines? The NRC
collected operating parameter data from five Canadian pipeline operators transporting DilBit. The
102
NRC report, p. 63.
Swift at al., Tar Sands Pipelines Safety Risks, 2011.
104
NRC report, p. 65.
105
See 2014 FEIS, Volume V, “Comments and Responses;” see also 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; and Swift et al., Tar Sands Pipelines Safety Risks, 2011.
106
2014 FEIS, p. 3.13-15.
107
Special Condition 15 states: “under no circumstances may the pump station discharge temperatures exceed 150°F
without sufficient justification that Keystone’s long-term operating tests show that the pipe coating will withstand the
higher operating temperature for long-term operations, and approval from the appropriate PHMSA region(s)” (2014
FEIS, Appendix B, “Potential Releases and Pipeline Safety”).
108
2014 FEIS, p. 2.1-40.
103
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highest reported operating temperature was 122°F and the highest reported operating pressure
was 1,440 psig. Thus, both the “expected” maximum temperature (135°F) and the potential
maximum operating pressure (1,600 psig)109 of the Keystone XL pipeline would exceed operating
parameter data presented in the NRC report. It is uncertain whether or not these potential
temperature and pressure differences are a cause for concern.
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 (“Special Conditions”) developed by PHMSA. In consultation with PHMSA, DOS
determined that incorporation of those conditions “would result in 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 proposed pipeline system, similar to that required in [High
Consequence Areas (HCAs)] as defined in 49 Code of Federal Regulations (CFR) 195.450.”110
DOS compares the Special Conditions with existing regulatory requirements in Appendix B to the
2014 FEIS. The degree of safety provided by the additional 57 measures has been a subject of
debate. The primary author of the 2011 environmental groups’ report argued that only 12 of these
conditions actually differ in some way from minimum requirements.111
Keystone XL Spill Frequency and Volume Estimates
Oil spill frequency and volume estimates for the Keystone XL project have been a subject of
debate during the permit process. Comparing various estimates is difficult, because the estimates
may or may not
1. include different years of underlying data;
2. apply to different pipeline segments (e.g., the 875-mile northern U.S. portion or
the entire 1,938-mile pipeline from Canada to the Gulf Coast);
3. apply to different components of the pipeline (e.g., the mainline or the mainline
and supporting equipment, such as tanks and valves); and
4. include additional assumptions or adjustments.
In the 2014 FEIS, DOS used PHMSA data to analyze crude oil pipeline spill incidents that
occurred between 2002 and 2012. DOS stated that “Although the results were not a direct
indicator of the nature of possible incidents that could occur in association with the proposed
[Keystone XL pipeline], they could be used to provide insight into what could potentially occur
with respect to spill volume, incident cause, and incident frequency.”112
Based on the PHMSA data, DOS calculated spill frequency rates and average volumes for crude
oil. The PHMSA records do not differentiate between types of crude oil: heavy, light, etc. Table 4
109
It is uncertain whether those surveyed in the NRC report accounted for pressure changes that might result from
elevation changes as was done in the DOS FEIS.
110
2014 FEIS, “Potential Releases,” p. 3.13-4.
111
Anthony Swift, “Clinton’s Tar Sands Pipeline ‘Safety Conditions’ are Smoke and Mirrors,” August 19, 2011, at
http://switchboard.nrdc.org.
112
2014 FEIS, “Potential Releases,” p. 4.13-8.
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provides the spill frequency and volume estimates for individual components of the pipeline
system: mainline pipeline, tanks, mainline valves, and other components, such as pump station
equipment. For example, the table indicates that mainline pipelines and tanks have a lower
frequency of spills than valves and other components, but a higher average spill volume.
Table 4. Estimates of Oil Spill Frequency and Volume
Based on DOS Analysis of PHMSA Data (January 2002-July 2012)
Average Volume
Per Spill in
Barrels (Gallons)
Estimated Number of Spills
Per Year for 875-Mile
Proposed KXL a
Estimated Spill Volume Per
Year for 875-Mile Proposed
KXL in Barrels (Gallons)
0.00025
1,116
(46,872)
0.22
246
(10,332)
0.00017
1,720
(77,240)
0.15
258
(10,836)
Mainline
Valves
0.00005
34
(1,428)
0.04
1
(42)
Other
componentsb
0.00168
173
(7,266)
1.47
254
(10,668)
0.00215
362c
(15,204)
1.88
681
(28,602)
Pipeline
Component
Oil Spills Per
Mile-Year
Mainline Pipe
(>16”)
Tanks
Total
Source: Prepared by CRS; Incident rate per mile-year from 2014 FEIS, Table 4.13-1; average volume per
pipeline component from Tables 6-9 in Appendix K to the 2014 FEIS.
Notes:
a.
The estimated number of spills per year calculated by multiplying incident rates (per mile-year) by number
of miles in the proposed Keystone XL pipeline (875 miles from the Canadian border to Steele City, NE).
b.
According to the 2014 FEIS, other components “include pump station equipment, but exclude tanks, valves,
and mainline pipe” (Appendix K, p. 18).
c.
The total average volume does not equate to the sum of the average volume from each component. This
approach would overstate the total average volume, because it would give the same weight to the
infrequent, large volume spills as the more frequent, lower volume spills.
CRS used Tables 6-9 in Appendix K to the 2014 FEIS to calculate the total volume average by dividing the
total number of incidents from the four pipeline component categories (1,098 incidents between 2002 and
2012) by the total volume from these incidents (397,303 barrels).
Using the frequency rates and average volumes listed in Table 4, DOS estimated the annual spill
frequency (0.46 releases per year) and volume (518 barrels per year) that would result from the
entire Keystone XL pipeline project—1,938 miles from its origin in Canada to the Gulf Coast.113
This estimate only includes the spill frequency and volume estimate for mainline pipelines greater
than 16” in diameter. By comparison, Table 4 provides the estimated number of spills and spill
volume that would occur along the 875-mile northern segment of the Keystone XL pipeline (the
segment under consideration for a Presidential permit). The table lists the individual component
estimates as well as an estimate for the entire system. For instance, based on PHMSA data, a spill
from the KXL mainline would occur 0.22 times per year (or once about every five years); a spill
from any of the components, including the mainline, would occur 1.88 times per year.
113
See Table ES-7 in the Executive Summary and Table 5.3-3 in the 2014 FEIS.
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Some would argue that using the PHMSA data as a guidepost for Keystone XL incidents would
overestimate spill frequency, because the data include older pipelines that may have been built to
less stringent standards. Moreover, pipeline proponents contend the Special Condition would
provide additional protection from incidents.114 In the 2014 FEIS, DOS states that “the
application of the Special Conditions and various studies that indicate more modern pipelines are
less likely to leak, it is reasonable to expect a sizable reduction in spills when compared to the
historic spill record.”115
On the other hand, the spill frequency for the existing Keystone pipeline,116 which began
transporting approximately 590,000 bpd of oil sands crudes in 2010, has exceeded the historical
spill frequency estimate. Based on DOS analysis in the 2014 FEIS, Keystone operators reported
12 incidents during the first year of operation. Although the vast majority of the incidents were
minor, one incident resulted in a spill of approximately 400 barrels (16,800 gallons). According to
DOS, “11 of the 12 reported incidents resulted in a small spill, eight of which were less than 1
bbl.... all reported first-year incidents for the existing Keystone pipeline system involved discrete
elements of the pipeline system (i.e., pumping stations, mainline valves); none involved mainline
pipe or tanks.”117
U.S. and Alberta Pipeline Spill Data
Some stakeholders have argued that 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.118 They reason that this difference is likely related to high
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 2010.119
Both the NRC report and DOS120 have pointed out that existing pipeline spill data are limited in
their ability to analyze potential risks associated with the transportation of oil sands crude oils
compared to other crude oils. The NRC report stated the following:
The information contained in the U.S. and Canadian incident records is insufficient to draw
definitive conclusions. One reason is that the causal categories in the databases lack the
specificity needed to assess the particular ways in which transporting diluted bitumen can
affect the susceptibility of pipelines to failure. Another reason is that incident records do not
contain information on the types of crude oil transported and the properties of past shipments
114
When TransCanada submitted a spill frequency estimate in 2009, the company derived its estimate by using
historical databases from PHMSA and then applying project-specific factors, such as regulatory requirements, material
strength, and technological advances. TransCanada, Keystone XL Project Pipeline Risk Assessment and Environmental
Consequence Analysis, 2009 (Appendix P of the 2014 FEIS).
115
2014 FEIS, p. 4.13-30.
116
The existing Keystone pipeline system analyzed by DOS includes the Keystone pipeline extending from Hardisty,
Alberta, to Patoka, IL, and the Cushing Extension extending from Steele City, NE, to Cushing, OK.
117
2014 FEIS, p. 4.13-31.
118
2011 FEIS, Appendix A.
119
Swift et al., Tar Sands Pipelines Safety Risks, 2011.
120
The 2014 FEIS states “given how incident data are reported, it is not possible to distinguish dilbit, SCO, and Bakken
oil spills from the general population of crude oil spills, nor is it possible to distinguish pipelines carrying dilbit, SCO,
or Bakken oil from other crude oil pipelines” (p. 4.13-29).
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in the affected pipeline. Because many pipeline releases involve cumulative and timedependent damage, there is no practical way to trace the transportation history of a damaged
pipeline to assess the role played by each type of crude oil and its properties in transport.121
DOS pointed out that a comparison of U.S. and Alberta 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.122 To
address these discrepancies in data collection, PHMSA prepared a comparison of pipeline
incidents of similar scopes between the two databases for the 2011 FEIS. The comparison
indicated 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. DOS did not include this table in its 2014 FEIS, but states that “incident statistics
from Alberta show that incident frequencies and corrosion-based incidents are similar for
pipelines in the United States and Alberta.”123
Impacts of Spills of Oil Sands Crude
If an oil spill occurs, its impacts would depend on multiple factors, including the type of oil
spilled, the volume of oil spilled, and the location of the spill.124 Although location is generally
considered the most important factor, EPA stated (in comments during the EIS process) that spills
of oil sands crude (e.g., DilBit) may result in different impacts than spills of other crude oils.125
The 2013 NRC report did not examine this particular issue and CRS is not aware of an
authoritative study that has assessed this topic. 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.
Spill Behavior
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, MN, in 1979).126 These include studies
121
NRC report, p.47.
For similar reasons, the 2013 NRC report stated (p. 45) that the Alberta data were not useful in its study.
123
2014 FEIS, p. 4.13-29.
124
See CRS Report RL33705, Oil Spills in U.S. Coastal Waters: Background and Governance, by (name redact
ed).
125
See comments from EPA on the DOS draft Supplemental Environmental Impact Statement, submitted in a letter
from Cynthia Giles to Jose Fernandez and Kerri-Ann Jones, April 22, 2013.
126
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.
122
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of specific chemical components that may be present in DilBit (e.g., benzene).127 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 Canadian Energy
Resources Conservation Board has stated that “DilBit should behave in much the same manner as
other crude oils of similar characteristics.”128
All spilled oil begins to “weather” or separate into different components over time. 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.
Cleanup Issues
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.129 The 2014 FEIS states
DilBit intermixed with sediment and trapped in the river bed and shoreline results in a
persistent source of oil and has the potential to present additional response and recovery
challenges.130
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.131
127
See, for example: Lisa M. Geig et al., “Intrinsic Bioremediation of Petroleum Hydrocarbons in a Gas CondensateContaminated 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 et 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.
128
Canadian Energy Resources Conservation Board (ERCB), “ERCB Addresses Statements in Natural Resources
Defense Council Pipeline Safety Report,” Press release, Calgary, Alberta, February 16, 2011.
129
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.
130
2014 FEIS, p. 4.13-88.
131
Dagmar Etkin, Modeling Oil Spill Response and Damages Costs, Proceedings of the 5th Biennial Freshwater Spills
Symposium, 2004, at http://www.environmental-research.com.
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Recent pipeline oil spills have generated interest among policy makers and stakeholders. For
example, a 2010 Enbridge pipeline spill released approximately 850,000 gallons of oil sands
crude oil into Talmadge Creek, a waterway that flows into the Kalamazoo River (Michigan).132
The spill demonstrates particular challenges associated with heavier crude oil spills, like oil sands
crude oils. As of the date of this report, response activities continue,133 because, according to
EPA, the oils sands crude “will not appreciably biodegrade.”134 The oil sands crude oil is
submerged at the river bottom, mixed with sediment, and EPA has ordered Enbridge to dredge the
river to remove the oiled sediment.135 As a result of this order, Enbridge estimated in December
2013 its response costs would be approximately $1.122 billion.136
Toxicity
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.”137 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.138 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.139
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.140
Unlike BTEX, the 2011 and 2014 FEIS documents do not include a comparison of PAH
concentrations across different crude oils. DOS states that PAH concentrations of crude oils that
would be transported in the Keystone XL pipeline are unknown, because this information is
132
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/.
133
For more up-to-date information, see EPA’s Enbridge oil spill website at http://www.epa.gov/enbridgespill/
index.html.
134
Letter from Cynthia Giles (EPA) to DOS, commenting on the draft SEIS, April 22, 2013.
135
EPA Removal Order, March 14, 2013, at http://www.epa.gov/enbridgespill/ar/enbridge-AR-1720.pdf.
136
See Enbridge Inc., Management’s Discussion and Analysis, February 2014, at http://enbridge.com/
InvestorRelations/FinancialInformation/InvestorDocumentsandFilings.aspx.
137
2014 FEIS, p. 4.13-46.
138
For a comprehensive discussion, see National Research Council, Oil in the Sea III: Inputs, Fates, and Effects,
National Academies of Science, February 2003.
139
2011 FEIS, “Potential Releases,” Table 3.13.5-6, p. 3.13-45.
140
National Research Council, 2003, p. 126.
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proprietary.141 Some commenters, including EPA, took issue with this during the 2011 EIS review
process.142
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.143 Assuming conventional oil means lighter crudes, this statement is
largely correct.144 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.145 Most, if not all, of this crude oil arrives in the United States via vessel.146
Other Modes of Oil Transportation
Although pipelines and oil tankers transport the vast majority of oil within the United States,
other modes of transportation have increased in recent years (Figure 13). As Figure 13
illustrates, the volume of crude oil carried by rail increased by 423% between 2011 and 2012; the
volume moving by barge, on inland waterways as well as along intracoastal routes, increased by
53%; and the volume of crude oil shipped by truck rose 38% between 2011 and 2012. Some
portion of these recent increases is likely related to the status of proposed Keystone XL pipeline.
141
2011 FEIS, “Potential Releases,” p. 3.13-31.
U.S. Environmental Protection Agency’s July 16, 2010, letter to the U.S. Department of State commenting on the
2010 draft EIS.
143
Swift et al., Tar Sands Pipelines Safety Risks, 2011.
144
Based on a comparison of crude oil assays from sources listed in Table 1.
145
2011 FEIS, “Potential Releases,” Table 3.13.5-7.
146
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.
142
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Figure 13. U.S. Refinery Receipts of Crude Oil by Mode of Transportation
Source: Prepared by CRS; data from EIA, Refinery Capacity Report, Table 9, June 2013.
Notes: EIA collects annual data from petroleum refineries, including their receipts of crude oil by different
modes of transportation. Although this information does not precisely measure crude oil transportation within
the United States, the data provide an approximate comparison of crude oil transportation by different modes.
The data only capture the method by which the crude oil is ultimately delivered to the refinery. For example, if a
producer shipped crude via pipeline to an intermediate destination (e.g., tank farm), and then shipped the oil to a
refinery via barge, the pipeline transport leg would not be captured in this dataset. CRS is not aware of a more
comprehensive, and up-to-date, source of crude oil transportation data.
Each mode of oil transportation involves some risk, and each has historically resulted in oil spills.
Figure 14 illustrates the relative risk of oil spills by mode of transportation, comparing spill
volume to the volume/distance transported. Over the period 1996-2007, railroads consistently
spilled less crude oil per ton-mile than trucks or pipelines; barges and domestic tanker ships have
much lower spillage rates than trains. However, the data in the figure precede the recent dramatic
increase in oil by rail transportation.
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Figure 14. Oil Spill Volume Per Billion-Ton Miles
Barrels Spilled Per Billion-Ton-Miles
Crude Oil and Petroleum Products in Domestic Transportation
350
300
250
200
150
100
50
1990-1995
Pipelines
1996-2001
Tank Vessels/Barges
Tanker Trucks
2002-2007
Rail
Source: Prepared by CRS; oil spill volume data from Dagmar Etkin, Analysis of U.S. Oil Spillage, API Publication
356, August 2009; ton-mile data from Association of Oil Pipelines, Report on Shifts in Petroleum Transportation:
1990-2009, February 2012.
Notes: Pipelines include onshore and offshore pipelines. The time periods were chosen based on the available
annual data for both spill volume and ton-miles. The values for each time period are averages of annual data for
each six-year period.
In addition, in its 2014 FEIS the State Department used PHMSA and Coast Guard data to
compare oil spill frequency and volume by mode of transportation. Between 2002 and 2009, DOS
found that
1. pipeline transport has the highest number of barrels released per ton-mile
compared to rail and marine transport; and
2. rail transport has the highest number of reported releases per ton-mile compared
to pipeline and marine transport.147
Oil Sands Extraction Concerns
Although local/regional impacts from Canadian oil sands development may not directly affect
public health or the environment in the United States, stakeholders often highlight the
environmental impacts that pertain to the region in which the oil sands resources are extracted.
DOS points out that, pursuant to NEPA or applicable Executive Orders, DOS NEPA analysis need
not include the environment or activities outside of the United States (see “Consideration of
Environmental Impacts Outside of the United States”). However, DOS included—“as a matter of
policy”—a summary of information regarding environmental analyses and regulations related to
147
2014 FEIS, p. 5.3-9 and Figures 5.3.3-1 and 5.3.3-2.
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Oil Sands and the Keystone XL Pipeline: Background and Selected Environmental Issues
the Canadian portion of the proposed Keystone XL Project and Canadian oil sands production.148
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.149
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 can disturb the land to varying degrees. For example,
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.
In contrast, many stakeholders associate in situ operations with “minimal land disturbances.”150
For example, the 2014 FEIS states that “in situ recovery is less disturbing to the land surface than
surface mining and does not require tailings ponds.”151 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).152
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.153 In
addition, one study finds that in situ operations disturb more land (per unit of oil) than mining,
when natural gas requirements are considered.154 As noted above, in situ operations require
148
2014 FEIS, Section 4.15.4 (“Extraterritorial Concerns”).
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.
150
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.
151
2014 FEIS, p. 4.15-107.
152
Sarah M Jordaan et al., “Quantifying Land Use of Oil Sands Production: a Life Cycle Perspective,” Environmental
Research Letters, 2009.
153
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.
154
Sarah M Jordaan et al., “Quantifying Land Use of Oil Sands Production: a Life Cycle Perspective,” Environmental
Research Letters, 2009.
149
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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.
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.155 Figure 15 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 conventional oil development from California, but still greater than oil
sands mining operations in Canada.156 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.157 Therefore, the factor of natural gas plays an important role in
energy yield estimates.
155
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.
156
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.
157
Alberta Chamber of Resources, Oil Sands Technology Roadmap, 2004.
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Figure 15. Illustrative Comparison of Energy Yields by Selected Sources
Energy Produced Per Amount of Disturbed Land (Range of Low to High)
6
In situ
Energy Yield (petajoules/hectare)
5
4
3
In situ +
natural gas
California oil
2
Mining
1
Mining +
natural gas
Alberta oil
0
Conventional
Oil Sands
Mining
Oil Sands
In Situ
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 blue columns), but provide data that include natural gas
components in supplementary information (represented above by the striped columns).
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 ecosystem that supports a wide range of
biodiversity and provides key ecological services. For example, the boreal forest has been
described as the “world’s largest and most important carbon storehouse.”158 The 2010 study that
provided data for Figure 15 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.159
158
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.
159
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.
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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 capability.”160 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.”161
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.162 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.163
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 2012 indicate that approximately 7% of the total disturbed
area has been permanently reclaimed.164 Of the permanently reclaimed land, 2% has been
certified per Alberta requirements (equating with 0.14% 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
skepticism as to whether reclamation to an equivalent land capability can be achieved in a
reasonable time frame.”165
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.”166
160
Alberta Environmental Protection and Enhancement Act, Section 146 (as of December 2013), at
http://www.qp.alberta.ca/documents/Acts/E12.pdf.
161
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.
162
See, e.g., 43 CFR Section 3101.1-2 and BLM Onshore Oil and Gas Lease Form (Form 3100-11), Section 12.
163
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.
164
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.
165
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.
166
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.
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Water Resources and Quality Issues
While the water resource impacts from oil sands development are generally considered a
Canadian domestic issue, 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
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