Keystone XL: Greenhouse Gas Emissions Assessments in the Draft Environmental Impact Statement
Released: 2014-03-10T00:00:00

Background

In 2008—and again in 2012—the Canadian company TransCanada submitted to the U.S. Department of State an application for a Presidential Permit authorizing construction and operation of pipeline facilities to import crude oil across the U.S.-Canada border. The proposed Keystone XL Pipeline would transport crude oil derived from Canadian oil sands deposits in Alberta as well as crude oil produced from the Bakken region in North Dakota and Montana to a market hub in Nebraska for further delivery to U.S. Gulf Coast refineries. A decision to issue or deny the Presidential Permit on the project is based on the U.S. Department of State's determination of whether the proposed pipeline serves the national interest. A national interest determination rests on a number of factors, including energy security; foreign policy; environmental, social, and economic impacts; and compliance with relevant federal regulations.

On June 25, 2013, President Obama announced a national "Climate Action Plan" to reduce emissions of carbon dioxide (CO 2 ) and other greenhouse gases (GHG), as well as to encourage adaptation to expected climate change. During his speech, the President made reference to the proposed Keystone XL Pipeline and stated that an evaluation of the pipeline's impact on climate change would factor into the State Department's national interest determination:

Allowing the Keystone pipeline to be built requires a finding that doing so would be in our nation's interest. And our national interest will be served only if this project does not significantly exacerbate the problem of carbon pollution. The net effects of the pipeline's impact on our climate will be absolutely critical to determining whether this project is allowed to go forward.

Both supporters and opponents of the proposed Keystone XL Pipeline reacted positively to the President's comments, signaling that an assessment of the net effects of the pipeline's impact on the climate—as well as the significance of those effects—is still under intense debate.

The State Department's GHG Emissions Assessment

The effects of the proposed Keystone XL Pipeline on climate change could be analyzed, in part, by an assessment of the GHG emissions attributable to the project. Such an analysis could encompass a variety of activities and implications relative to the pipeline, including the GHG emissions associated with the proposed pipeline's construction and operation, as well as the GHG emissions attributable to the crude oils that would be transported through the pipeline. An assessment would be dependent upon many factors, most notably, the availability and quality of GHG emissions data for the industry, the scope of industry activities included within the assessment, and the assumptions made about how to model these activities. Many secondary considerations may also impact an assessment. These include assumptions regarding global crude oil markets, refinery inputs and outputs, transport options, economics, policy considerations, and the end-use consumption of petroleum products. Different values attached to these varying factors return different estimates for the GHG emissions attributable to the construction and operation of the proposed pipeline as well as the crude oils transported through it.

A number of publicly available studies have attempted to assess the GHG emissions of crude oils derived from Canadian oil sands deposits ("oil sands crudes"). Some of these studies have also made estimates for the GHG emissions attributable to the crude oils that would be transported through the proposed pipeline. The State Department, in its March 2013 Draft Environmental Impact Statement ( DEIS ) for the Keystone XL Pipeline, has produced one such assessment. As the DEIS will be a primary component for the national interest determination, this report focuses on the State Department's analysis and comments on its methodology and conclusions. Where applicable, the report supplements the DEIS analysis with relevant additional information. As the State Department's assessment is based on the findings of several published studies of oil sands crudes, this report also comments on their respective methodologies and conclusions. For a more extensive investigation of the GHG emissions assessments of oil sands crudes and their comparison to other global crude oils ("reference crudes"), see CRS Report R42537, Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas Emissions , by [author name scrubbed].

Reported Findings

The DEIS includes an analysis of the GHG emissions that would be attributable to the proposed Keystone XL Pipeline. It reports both "direct" GHG emissions from the construction and operation of the proposed pipeline as well as "indirect" emissions attributed to the production and use of the oil sands crudes that would be transported through the proposed pipeline. The State Department defines the indirect GHG emissions as "incremental GHG emissions." This value is generated by examining the full GHG emissions profile of oil sands crudes (i.e., the aggregate GHG emissions released by all activities from the extraction of the resource to the end-use combustion of refined fuels), comparing this profile to those of other reference crudes it may displace in U.S. refineries, and then estimating the difference between a scenario where the proposed Keystone XL Pipeline is constructed and a scenario where it is not. Thus, for the purposes of its analysis, the State Department incorporates the direct emissions attributed to the operation of the pipeline into the reported incremental indirect emissions.

Based on its review of the available GHG emissions assessments, as well as an analysis of North American crude oil transport infrastructure and global crude oil markets , the State Department finds the following:

Approval or denial of the proposed Project is unlikely to have a substantial impact on the rate of development in the oil sands, or on the amount of heavy crude oil refined in the Gulf Coast area. If the proposed Keystone XL Pipeline were not built, but other proposed pipelines were (e.g., the Northern Gateway, the Trans Mountain expansion, and the TransCanada proposal to ship crude oil east to Ontario), there would be a 0.4%-0.6% reduction in Canadian oil sands production by 2030, and a decrease in the incremental indirect life-cycle GHG emissions of oil sands production in the range of 0.07-0.83 million metric tons of carbon dioxide equivalents (MMTCO 2 e) annually. If all proposed pipelines were denied, there would be a 2%-4% reduction in Canadian oil sands production by 2030, and a decrease in the incremental indirect life-cycle GHG emissions of oil sands production in the range of 0.35-5.30 MMTCO 2 e annually.

In summary, the DEIS reports that the proposed Keystone XL Pipeline "would be responsible for incremental GHG emissions in the range of 0.07 ... 5.30 MMTCO 2 e annually," and places these numbers in context by noting U.S. GHG emissions totaled 6,822 MMTCO 2 e in 2010 (excluding emissions/removals from land use, land-use change, and forestry), and global CO 2 emissions from fuel combustion totaled 30,326 MMCO 2 e. The incremental pipeline emissions would represent an increase of 0.001%-0.08% over the total domestic GHG inventory for the United States in 2010 and would be equivalent, at most, to the annual GHG emissions from the energy used in a little over 1 million passenger vehicles or the annual CO 2 emissions from the energy used in a little over a quarter million homes in the United States.

See Table A-1 for a summary of this estimate as well as other selected pipeline scenarios and their GHG equivalencies.

Methodology

The proposed Project would be responsible for incremental GHG emissions in the range of 0.07 ... 5.30 MMTCO 2 e annually.

How does the State Department calculate this estimate, and what does it say about the cumulative effects of the pipeline?

1. Emissions Profiles of Oil Sands Crudes

State Department Calculations

The State Department's first step in calculating the GHG emissions attributable to the proposed pipeline is to develop a "life-cycle assessment" of the Canadian oil sands resource. Life-cycle assessment (LCA) is an analytic method used for evaluating and comparing the environmental impacts of various products (in this case, the climate change implications of a petroleum resource). LCAs can be used in this way to identify, quantify, and track emissions of carbon dioxide and other GHG emissions arising from the development of the resource, and to express them in a single, universal metric of carbon dioxide equivalent (CO 2 e) GHG emissions per unit of fuel or fuel use. This figure is commonly referred to as the "emissions intensity" of the fuel. 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. Emissions intensities modeled by LCAs are delimited by the scope of activities chosen to be in the assessment. Many LCAs are based on a set of boundaries commonly referred to as "cradle-to-grave," or, in the case of transportation fuels such as petroleum, "Well-to-Wheels" (WTW). WTW assessments focus on the emissions associated with the entire life-cycle of the fuel, from extraction, transport, and refining of crude oil; to the distribution of refined product to retail markets (e.g., gasoline, diesel, jet fuel); to the combustion of the fuel in end-use vehicles. The State Department has chosen a WTW assessment for the DEIS. Other analyses have used different sets of boundaries to compare the relative impact of oil sands crudes against reference crudes. Other choices include Well-to-Tank (WTT) or Well-to-Refinery Gate (WTR), and each establish different (i.e., more specific) life-cycle boundaries to evaluate emissions. Inclusion of the final combustion phase allows for the most complete picture of petroleum's impact on GHG emissions, as this phase can contribute up to 70%-80% of WTW emissions. However, other boundaries can be used to highlight the differences in emissions associated with particular stages as well as experiment with certain boundary assumptions.

A number of publicly available studies have attempted to assess the life-cycle GHG emissions intensity of oil sands crudes. The State Department—in conjunction with the consultancy firm ICF International LLC—in the Keystone XL Project's August 2011 Final Environmental Impact Statement employs the results of four published LCAs in its analysis. The use of these studies is reproduced in the March 2013 DEIS conducted by the State Department and the contractor Environmental Resources Management. The four LCAs used by the State Department—Jacobs 2009, TIAX 2009, NETL 2008, and NETL 2009 —employ slightly different design parameters, input assumptions, and industry data to model the GHG emissions intensities of oil sands crudes. Thus, each returns slightly different findings. As one example, the U.S. Department of Energy's assessment (NETL 2009) looks at both oil sands mining and in situ production techniques, and examines the GHG emissions profiles for the extraction, transportation, and refining of these crudes into gasoline, diesel, and jet fuel products. NETL reports the average GHG emissions intensity of oil sands crudes to be 106.3 grams of carbon dioxide equivalent for each megajoule of energy released by its combustion as gasoline (gCO 2 e/MJ LHV gasoline). NETL compares this result to a baseline value of 91 gCO 2 e/MJ LHV gasoline, which it reports as "the weighted average of transportation fuels sold or distributed in the United States in 2005." Overall, the four LCAs return emissions estimates for several different types of oil sands production techniques in the range of 101-120 gCO 2 e/MJ LHV gasoline. The State Department uses these results to report the following key finding in the DEIS :

Combustion of fossil fuels, including petroleum-based products such as crude oil, is a major source of global GHG emissions, which contribute to human-induced climate change. [Western Canadian Sedimentary Basin] crudes are more GHG-intensive than the other heavy crudes they would replace or displace in U.S. refineries, and emit an estimated 17 percent more GHGs on a life-cycle [WTW] basis than the average barrel of crude oil refined in the United States in 2005.

Evaluation Considerations

The State Department references several third-party sources for the raw data on the GHG emissions intensities of oil sands crudes. Thus, the DEIS is less an independent and original assessment, than a comparative analysis of multiple other studies, each presenting significant variations in both reported findings and input assumptions. Life-cycle assessment has emerged as an influential methodology for collecting, analyzing, and comparing the GHG emissions and climate change implications of various hydrocarbon resources. However, because of the complex life-cycle of fuels and the large number of analytical design features that are needed to model their emissions, LCAs retain many uncertainties. As noted previously, the NETL 2009 LCA—from which the State Department sources many of the estimates for oil sands crudes—has many specified design parameters and input assumptions. The LCA is also four years old and utilizes data that are over eight years old (e.g., GHG emissions intensities of the oil sands crudes are compared against a 2005 U.S. baseline). Opponents to the Keystone XL Pipeline are critical of many of the exclusions in the NETL 2009 LCA, including the tightly delimited boundaries and the omission of co-product emissions (e.g., petroleum coke). The DEIS states that "adjusting the NETL results to include other product emissions could increase the differential in incremental emissions from WCSB oil sands compared to the 2005 U.S. average crude oils by roughly 30 percent." Conversely, proponents of the Keystone XL Pipeline point to the many recent advances in energy efficiency and GHG mitigation technologies that Canadian oil sands producers have made. They highlight the 2012 formation of the Canada's Oil Sands Innovation Alliance (COSIA), an industry group focused on accelerating the pace of improvement in environmental performance through collaborative action and innovation. 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, (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. Proponents suggest that these and other advances may make the GHG emissions intensity estimates for oil sands crudes more in line with other reference crudes.

2. Total Emissions Attributable to the Proposed Pipeline

State Department Calculations

The second step in the State Department's analysis is to determine the total, or "gross," GHG emissions that would be attributable to the crude oils transported through the proposed pipeline. Because the throughput of a pipeline is commonly expressed in barrels per day (bpd), the GHG emissions intensities for the various oil sands crudes must be converted into a value that can be assigned to a barrel. This calculation requires an understanding of the mix of oil sands inputs that goes into a barrel at the start of the pipeline as well as the yield of refined products that are produced from a barrel at the end of the pipeline. Further, an estimate must be made for how many barrels of crude oil would be transported annually through the proposed pipeline.

While implicit in its analysis, the State Department does not report a value for the total, or "gross," annual GHG emissions attributable to the crude oil transported through the proposed pipeline. Without access to the State Department's input assumptions and conversion factors, CRS cannot calculate a value for these emissions that would be consistent with the findings in the DEIS .

Evaluation Considerations

Third-party analyses have produced estimates which could be used to determine the total, or "gross," GHG emissions that would be attributable to the crude oils transported through the proposed pipeline. For example, IHS CERA's 2012 study, Oil Sands, Greenhouse Gases, and U.S. Oil Supply: Getting the Numbers Right-2012 Update, compares the data from various published LCAs to determine the WTW GHG emissions for oil sands and other reference crudes on a "per barrel of refined product basis." IHS CERA estimates emissions for an "average of oil sands crudes refined in the United States in 2011" to be in the range of 517-547 kg CO 2 e/barrel of refined products (or, 9%-12% higher than an average barrel refined in the United States). Based on these results, and assuming that the full 830,000 bpd pipeline capacity is used to transport only oil sands crudes to Gulf Coast refineries, the total life-cycle GHG emissions attributable to the oil sands crudes transported through the proposed pipeline would range from 157 to 166 MMTCO 2 e a year. These emissions would represent an increase of 2.3%-2.4% over the total domestic GHG inventory for the United States in 2010, and would be equivalent to the annual GHG emissions from the energy used in 32.7 million to 34.6 million passenger vehicles or the annual CO 2 emissions from the energy used in 8.1 million to 8.5 million homes in the United States. (See Table A-1 for a summary of selected pipeline scenarios and their GHG equivalencies.)

3. Incremental Emissions Attributable to the Proposed Pipeline (Adjusted for Refinery Inputs)

State Department Calculations

In order to determine a value for the "incremental" life-cycle GHG emissions attributable to the proposed pipeline, the State Department considers a scenario wherein the crude oils transported through the proposed pipeline would displace an equivalent volume of other crude oils currently processed at the Gulf Coast refineries. Hence, the difference in their respective GHG emissions profiles would return a value for the "increment." If oil sands crudes were determined to be slightly more emissions-intensive than the current mix of crude oils in Gulf Coast refineries, they would be responsible for those additional GHG emissions above the current level.

The DEIS uses the findings from the NETL 2009, Jacobs 2009, and TIAX 2009 LCAs to compare GHG emissions profiles for Canadian oil sands crudes against three reference crudes: Venezuelan Bachaquero, Mexican Maya, and Middle Eastern Sour. Bachaquero and Maya are chosen with the assumption that as the heavy crudes currently in the input mix at U.S. refineries, they are likely to be the first displaced by an increased use of oil sands crudes. Middle Eastern Sour is chosen with the assumption that as the world's balancing crude, it may ultimately be the one that is backed out of the world market by increased production of the oil sands. In each case, the GHG emissions profile for oil sands crudes is higher than that of the reference crude. Based on the results, and with the assumption that Gulf Coast refinery capacity is held constant, the DEIS then calculates the difference in GHG emissions that would be attributable to oil sands crudes if the full 830,000 bpd capacity of the proposed pipeline displaced an equal volume of the reference crudes in Gulf Coast refineries. For example, using the findings from Jacobs 2009, oil sands crudes transported by the pipeline would add an additional 3.7 MMTCO 2 e GHG emissions a year if they displaced Venezuelan crudes; whereas using the findings from NETL 2009, oil sands crudes transported by the pipeline would add an additional 20.7 MMTCO 2 e GHG emissions a year if they displaced Middle Eastern crudes. Because uncertainty remains as to which reference crudes would be displaced, the DEIS reports "the full range of incremental GHG emissions associated with the displacement of the reference crudes by the WCSB oil sands crude as 3.3 to 20.8 MMTCO 2 e a year across the three studies. " These emissions would represent an increase of 0.05%-0.30% over total domestic GHG inventory for the United States in 2010. The DEIS states this overall range "is equivalent to annual GHG emissions from combusting fuels in approximately 770,800 to 4,312,500 passenger vehicles or the CO 2 emissions from combusting fuels used to provide the energy consumed by approximately 190,400 to 1,065,400 homes for one year." (See Table A-1 .)

Evaluation Considerations

For some, an evaluation of the total, or "gross," life-cycle GHG emissions of the oil sands crudes transported through the proposed pipeline would serve as an adequate assessment of the pipeline's impact on the climate. For others, this value must be adjusted by the GHG emissions profiles of the crude oils they are projected to displace in U.S. Gulf Coast refineries. This adjustment is based on two determining factors: (1) the assumption that the refinery capacity and the input mix at Gulf Coast facilities is held constant, and (2) the choice of reference crudes to be displaced.

First, the assumption that refinery capacity and crude oil inputs are held constant is backed by the State Department's market analysis, which finds that the "approval or denial of the proposed Project is unlikely to have a substantial impact ... on the amount of heavy crude oil refined in the Gulf Coast area." The DEIS notes that U.S. refinery throughput has remained constant over recent years, and that "U.S. refineries have not materially changed ... indeed, the major projects that have gone ahead both in [the Midwest] PADD 2 and on the Gulf Coast (PADD 3) have been geared to increasing heavy crudes processing. Having made significant investments in equipment to process heavy sour crude, refiners have strong [economic] incentive to obtain such crudes." Thus, the DEIS determines that (1) no new capacity would be added or installed on the Gulf Coast to refine the additional crude oils made available from the proposed pipeline, (2) oil refineries optimized for heavy crudes would only process heavy crudes, (3) oil sands imports would only displace other heavy imports, and (4) any growing domestic light oil production from shale or tight oil plays—in the Bakken, the Eagle Ford, or others—would only displace light crude imports. Further, the DEIS assumes that the projected drop-off in domestic tight oil production by the late 2020s would dissuade Gulf Coast refiners optimized for processing heavier crudes from switching. But critics of the State Department's analysis argue that increased transport of oil sands crudes out of Canada could serve to optimize operating capacity at Gulf Coast refineries or even encourage an expansion in investments. They maintain that any additional production capacity (of oil sands crudes or others) would not simply substitute for current levels, but add to them, increasing the incremental, or "net," GHG emissions attributable to the proposed pipeline. Similarly, these commentators have pointed to recent evidence showing that domestic light oil production is not only backing out imported light crudes but also displacing the market for heavier crudes. They contend that this switch, even in the short to medium term, could have significant impacts on the use of oil sands crudes in U.S. refineries and the GHG emissions attributable to the sector.

Second, a determination of which reference crudes would be displaced at Gulf Coast refineries is left open by the State Department's analysis, as the DEIS reports a range of values for several different scenarios. Nevertheless, determining the emissions intensities of reference crudes requires calculations similar to those performed on the oil sands, and thus harbors many of the same uncertainties. In addition, the quality of the data and the transparency in presentation for many of the reference crudes are not as robust as data on the oil sands. Some, even, have yet to be modeled (e.g., Bakken tight oil). This is primarily a function of changing conditions as well as the difficulty in accessing necessary data from the field. A lack of equivalence can impede the ability to make meaningful comparisons. Comparisons are also complicated by the fact that emissions factors for Canadian oil sands crudes and reference crudes will change over time, and it is not clear how these changes will impact their respective GHG emissions. On one hand, secondary and tertiary recovery techniques will become more common in conventional oil, increasing the GHG emissions of reference crudes. In contrast, oil sands surface mining is expected to have a relatively constant energy intensity for a long period of time, and in situ techniques may be expected to become more efficient. Exploration for new oil reservoirs will also continue (with the possibility of commercializing both greater and lesser emissions-intensive resources), while the location and extent of Canadian oil sands is well understood.

4. Incremental Emissions Attributable to the Proposed Pipeline (Adjusted for Market Factors)

State Department Calculations

The State Department's final step in calculating the GHG emissions attributable to the proposed pipeline is to consider the effects that projected changes in market factors might have on the production of oil sands crudes. In the end, the State Department aims to calculate a value for the difference in overall GHG emissions between two primary scenarios: one in which the proposed Keystone XL Pipeline is built, and one in which it is not. This difference returns a value for the "incremental GHG emissions" for which "the proposed Project would be responsible." These scenarios are based on various market projections and modeling assumptions. The steps in the State Department's calculations are as follows:

Determining a "business-as-usual" scenario. The State Department begins by referencing several third-party market projections/forecasts for both current and future crude oil prices and production volumes. These include analyses from the U.S. Department of Energy, Energy Information Administration (EIA), the Canadian Association of Petroleum Producers (CAPP), and Canada's National Energy Board (NEB). Each projection reaches out to the period 2030-2035. The business-as-usual scenario for Canadian oil sands producers is one in which "the industry and market react based on normal commercial incentives." Thus, it is assumed that projects currently proposed, approved, and under construction will go forward, and that adequate takeaway capacity will be available to Canadian oil sands producers to allow for announced production targets. Estimating the effects of not constructing adequate takeaway capacity becomes the "counterfactual" scenario the DEIS must calculate .

Determining a "no expansion" scenario. The State Department reports that no new pipeline capacity has been added to the oil sands region since 2011 and that existing pipeline capacity could be fully utilized by 2016. The DEIS further notes that other proposed pipeline projects (e.g., the Enbridge Northern Gateway project to Kitimat, British Columbia, and the Kinder Morgan Trans Mountain pipeline expansions to the Canadian West Coast) "face significant opposition from various groups, and ... may continue to be delayed." Thus, for the purposes of the DEIS analysis, the State Department chooses to assess a "no expansion" scenario which assumes that pipeline capacity would be frozen at 2010 levels for at least 20 years along three routes: (1) from the WCSB to the United States; (2) from the WCSB to the Canadian West Coast; and (3) from PADD 2 (Midwest) to PADD 3 (Gulf Coast) in the United States.

Assess ing the potential for rail capacity . In the event that no new pipelines are constructed, rail and other non-pipeline transport options would be tasked with accommodating any production growth. Based on the CAPP 2012 outlook for Canadian production (a projected 3.6 million bpd increase by 2030), rail would need to expand by approximately 175,000 bpd each year to 2030 in order to keep up with (and prevent shut-in of) the increases in Western Canadian crude supplies. To assess if this expansion is credible, the State Department reviews the recent example of rail takeaway for crude oil in the Bakken (an expansion of 700,000 bpd over four years between 2009 and 2012, or an increase of 175,000 bpd annually) and the past example of rail takeaway for coal in the Powder River basin (a total expansion of 6.7 million bpd equivalents over 28 years between 1980 and 2008, or an increase of 240,000 bpd equivalents annually). Based on this evidence, the DEIS concludes that "there is no indication that the rail logistics system would not be able to continue to scale up at this rate, or more, over many years."

Assess ing the incremental cost of rail versus pipeline transport. The DEIS estimates the cost for rail transport to the Gulf Coast to be approximately $15.50 per barrel. This is compared to CAPP's estimate for pipeline tariff for the same transport of approximately $8-$9.50 per barrel. Based on future cost saving assumptions which the State Department projects for rail transport, the DEIS concludes "that the incremental increase in cost of rail compared to pipeline transport is $5 per barrel."

Determining the effects that the incremental cost of rail transport may have on oil sands production. To assess the potential impacts that a $5 change in the cost of transportation would have on the rate of production, the DEIS turns to the market projections in EIA's 2011 International Energy Outlook (IEO). The IEO projects crude oil production for three price cases (i.e., high, low, and reference price projections), and "oil sands/bitumen (Canada)" production figures are reported for each price case. Comparing the reported production volume for each price, the State Department calculates the change in volume for every $5 increment in price. Assuming that "a change in oil price can be considered equivalent to a change in costs," the DEIS determines that a $5 increment in cost would cause a decrease in oil sands production of approximately 90,000 bpd in 2030 (or 2.1% of the projected volume for that year). The DEIS performs a similar calculation using the NEB/CAPP projections to report a decrease of approximately 210,000 bpd in 2030 (or 4% of the projected volume for that year). Thus, the DEIS reports that "if all proposed pipelines were denied, there would be a 2%-4% reduction in Canadian oil sands production by 2030."

The State Department then focuses on a scenario wherein only the Keystone XL Pipeline is not built, such that only the 830,000 bpd capacity would be subject to the $5 cost increase and the 2%-4% reduction in volume. In this instance, the DEIS reports a "20,000 to 30,000 bpd" change, or "0.4% - 0.6% reduction in Canadian oil sands production by 2030" "if the proposed Keystone XL Pipeline project were not built, but other proposed pipelines were."

Calculating the incremental GHG emissions for which the proposed Project would be responsible. Having calculated the decreases in oil sands production attributable to the lack of pipeline infrastructure, the DEIS uses these values to estimate the GHG emissions attributable to the proposed Keystone XL pipeline, and reports the following:

... should the proposed Project be denied, a 0.4 to 0.6 percent reduction in WCSB production could occur by 2030, and in the scenario of all pipeline projects not being built, a 2 to 4 percent decrease in WCSB oil sands production could occur. This infers that of the 3.3 to 20.8 MMTCO2e annual incremental GHG emissions, the proposed Project would be responsible for incremental GHG emissions in the range of 0.07 to 0.83 MMTCO2e annually, and in the scenario where all pipelines were not constructed, the incremental GHG emissions would be 0.35 to 5.3 MMTCO2e annually.

These emissions would represent an increase of 0.001%-0.078% over the total domestic GHG inventory for the United States in 2010 and would be equivalent to the annual GHG emissions from the energy used in 14,500 to 1,104,100 passenger vehicles or the annual CO 2 emissions from the energy used in 3,600 to 272,700 homes in the United States. (See Table A-1 for a summary of selected pipeline scenarios and their GHG equivalencies.)

Evaluation Considerations

The State Department bases its market analysis on 2011 projections for the 2030 production profile of the oil sands and other benchmark crudes. The "reference case"—or "business as usual"—scenario for these projections is made under the assumption that industry and market forces react based on normal commercial incentives. The construction of adequate takeaway capacity to accommodate projected production growth is commonly understood to be a normal commercial operation. Thus, instead of modeling how the construction of the proposed pipeline might affect the short- to medium-term growth of the industry, the State Department chooses instead to model how industry and market forces may react to the denial of the proposed project in the medium to long term. This is posited as the counterfactual scenario against which the reference case is compared. The D EIS concludes that if the proposed pipeline is denied, the rate of development in the oil sands and the amount of heavy crude oil refined in the Gulf Coast area is unlikely to be substantially impacted because the market would likely respond by adding broadly comparable transport capacity over time. This claim is supported by two assumptions: (1) that rail and other non-pipeline transport options can fully accommodate all future projected growth of the oil sands in the medium to long term, and (2) that at no point would the global price of oil fall—or the marginal cost of production increase—such that investment in new oil sands projects will be deemed uneconomical (i.e., below the breakeven cost of production).

The Capacity Argument . The State Department notes that while no new additional pipeline capacity has been added from Canada into the United States or to the Canadian West Coast since 2011, a number of projects are proposed, including those entailing modifications and/or use of existing rights of way. While the DEIS appropriately recognizes that some proposed projects (e.g., the Enbridge Northern Gateway project, and the Kinder Morgan Trans Mountain expansion) may experience delays, it also recognizes that many interstate pipelines that do not cross international borders face less regulatory review (e.g., the Enbridge Flanagan South and Trunkline conversion, among others). For these reasons, the DEIS considers an assessment which assumes that pipeline capacity would be frozen at 2010 levels as "unlikely." Nevertheless, for the purposes of its analysis, the State Department examines options for transporting all new production of oil sands crudes by rail and other non-pipeline transport options. It surmises that scaling up transport is logistically and economically feasible based on past and present evidence in the Powder River Basin and the Bakken. Given the identified commercial demand for oil sands crudes in Gulf Coast refineries, the DEIS concludes that the market would respond by adding sufficient transport capacity over time. Critics, however, disagree, as expansion would require significant infrastructure development, including loading and unloading facilities, tract capacity, and rail tank car availability. The State Department grants that "if the rate of production is substantially higher than indicated in the CAPP 2012 forecast, and if there are delays in the delivery of new rail cars and terminals ... it is possible that some short-term shut-in [until third quarter of 2017] of WCSB heavy crude could occur." (An emissions estimate for this scenario is included in Table A-1 .) This short- to medium-term reduction is supported by other market analyses of the oil sands (e.g., CIBC, TD Economics, Goldman Sachs, and IEA). IEA reports that the failure to build needed oil sands pipelines—particularly Keystone XL—could result in persistent price discounts and slow expansion of the sector; and Goldman Sachs estimates that rail capacity would peak at 500,000 bpd over the next three to four years, further noting that most of the current and future shipments would be light crude oil, not oil sands crudes. Most of the third-party market analyses do not report conditions for the medium to long term, as some assume that transport logistics would be worked out by the market in the long term and others do not speculate.

The Cost Argument . To assess the potential impact of increased production costs on the oil sands (whether transportation costs or others), the State Department reviews information regarding "breakeven costs" for different types of oil sands projects. The "breakeven cost" is often expressed as the lowest price of a benchmark crude that is necessary to enable a potential production project to cover all its costs and earn a commercial rate of return on capital employed—typically 10%-15%. A long-term increase in production costs acts as an increase in the breakeven costs for producers. The State Department posits the argument that if the cost of production for new oil sands projects were to raise above the breakeven cost for an extended period of time, conditions would lend themselves to a potential decrease in oil sands production and a dampening of future investment. To assess if this scenario may occur, the State Department references the Canadian NEB's breakeven costs for new oil sands projects. NEB reports breakeven costs at $51-$61 per barrel for new in situ crude; $66-$76 per barrel for mining (without upgrader); and $86-$96 per barrel for mining (with upgrading). Comparing these breakeven costs to price projections of benchmark crudes, the State Department reports that based on AEO 2013 projections, both Brent and WTI prices are above the band of breakeven costs for in situ and for mining without upgrading for all years through 2040, and that based on WEO projections, oil prices are above the breakeven costs for all projects from 2015 through 2035. With this, the DEIS concludes that most oil sands projects have breakeven costs low enough that incremental increases in production costs (including transportation costs) would not curtail future development.

Critics of the State Department's analysis note that the DEIS accurately characterizes the current market conditions encountered by oil sands producers but fails to adequately assess the full range of potential market scenarios. Critics highlight the DEIS analysis which states that

... discounts for the marker heavy grade WCS have been growing in recent months. Prior to the advent of current logistics constraints, WCS discounts versus Brent were generally of the order of $15–$20/barrel, (primarily reflecting differences in refining values of the two crudes. These discounts deepened to the $30–$40 per barrel range in 2011 and through much of 2012. Recently, the discount widened further to the $50–$60 per barrel range.... [T]he severe pricing discounts indicate these crudes are not able to move further and access coastal markets, notably in the Gulf Coast where their value would match that of heavy Venezuelan crudes and Mexican crudes such as Mayan.

They argue that the State Department's market analysis fails to properly account for the short- to medium-term effects of these discounts on future production estimates and fails to consider the uncertainties that are inherent in all cost and price projections. They note that recent estimates of oil sands production costs have increased over those reported in the DEIS , current rail transport costs are higher than those reported in the DEIS (an emissions estimate for this scenario is included in Table A-1 ), and benchmark crude oil price projections are lower than those reported in the DEIS — all conditions that would place downward pressure on oil sands development and investment.

In regard to these competing projections, it is the time horizon that is the most significant difference between the State Department's market analysis and those critical of the analysis. The State Department focuses on the year 2030, at which point market forces may have the opportunity to resolve many of the short-term obstacles to oil sands development currently encountered by producers (e.g., lack of transport infrastructure, price discounts, and competition from U.S. tight oil). Others, however, have focused on shorter-term analyses which, in some cases, have returned projections of higher costs and lower prices. They stress that these obstacles suggest continued challenges for investment and development in the sector. Whether short-term obstacles translate into longer-term challenges is dependent upon the outcome of many of the projections and variables outlined in this analysis. The construction of pipeline infrastructure is one such variable.

Concluding Observations

President Obama has stated that an evaluation of the "net effects of the pipeline's impact on our climate" in order to determine if the project would "significantly exacerbate the problem of carbon pollution" would factor into the State Department's national interest determination for the proposed Keystone XL Pipeline.

For many, the net effects of the pipeline's impact on climate are tied explicitly to its impact on the rate of development in the oil sands. Proponents of the proposed pipeline support a market analysis which concludes that the approval or denial of the proposed pipeline is unlikely to have a substantial impact on the rate of development in the oil sands, or on the amount of heavy crude oil refined in the Gulf Coast area. They argue that as long as there is strong global demand for petroleum products (whether from the United States, China, India, or the developing world), resources such as the Canadian oil sands will be produced and shipped to markets using whatever route is available. They see future investment affected only in scenarios where the global price of oil falls below the breakeven cost of production 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. There are 5.4 million bpd of oil sands projects currently under construction or regulatory review (i.e., three times 2012 production levels), and these projects are being developed under current conditions. 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 maintain that a single pipeline (in and of itself) would not affect the long-term development of the oil sands, and thus a single pipeline (in and of itself) would not affect long-term GHG emissions from the sector. Furthermore, they estimate that GHG emissions intensities for the Canadian oil sands are currently within range of many other heavy crude oils, and that in the future Canadian oil sands emissions intensities will only decrease (due to efficiencies and technological advances), while those of other crudes around the world will likely increase (due to a heavier resource base).

Others maintain that Canadian oil sands are currently the most GHG emissions intensive crudes in production (due to the energy intensity required to extract and refine the resource), and that future oil sands deposits will only become more difficult and costly to access. Further, they argue that there is nothing presumed or inevitable about the rate of expansion for the Canadian oil sands. Current oil sands projects face a challenging financial environment, and production costs and price differentials are comparatively higher for oil sands crudes, making new investment sensitive to changes in production costs and global prices. Critics highlight the many reported instances where current price discounts for oil sands crudes have dampened investment and project development. 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 State Department's 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. They argue that the State Department has failed to adequately assess these other possible scenarios, and claim that many of these could upset the breakeven costs for project development and dampen investment in the industry. A decrease or delay in investment would affect the timing and capacity of new oil sands projects. Any decrease or delay in production could have significant impacts on the rate of growth in global GHG emissions by allowing more time for the promulgation of climate policies, the development of adaptation strategies, and the migration to renewable technologies.

For still others, the net effect of the proposed pipeline does not rest solely on the fate of oil sands production in Canada, but on the direction of U.S. energy policy. They argue that while many of the decisions that may affect the development of the oil sands will be made by the market and the national and provincial governments of Canada, the choice of whether or not to approve the permit for the proposed Keystone XL Pipeline is an opportunity for the U.S. government to signal its future direction. These stakeholders have pushed for a national policy that moves the United States away from a reliance on fossil fuels. They see the decision to build the proposed pipeline as a 50-year-long commitment to a carbon-based economy and its resulting GHG emissions. As EPA notes in its comments to the DEIS, given the 50-year lifetime of new infrastructure projects such as the proposed pipeline, "the additional CO 2 e from oil sands crude transported by the pipeline could be as much as 935 million metric tons." Opponents of the proposed pipeline contend that with meaningful action on climate policy slowed or stalled in Congress, the courts, and, to some extent, the regulatory agencies (i.e., local, state, and federal environmental and land-use agencies), the sole remaining outlet to leverage a low-carbon energy policy is single action initiatives on such items as infrastructure permits. They have actively opposed the permit for the proposed Keystone XL Pipeline knowing that it may set a precedent; for if the project is allowed to go forward, it may be the case that no future infrastructure project would be held accountable for its indirect and cumulative GHG emissions.

On January 31, 2014, the State Department released the Final Environmental Impact Statement (FEIS) for the Keystone XL Pipeline, which contained revised analysis and estimates. For a detailed review of these findings see CRS Report R43415, Keystone XL: Greenhouse Gas Emissions Assessments in the Final Environmental Impact Statement , by [author name scrubbed] .

Appendix. GHG Estimates for Selected Scenarios