|Incremental well-to-wheels GHG emissions from WCSB Oil Sands Crudes Compared to Well-to-Wheels GHG Emissions from Displacing Reference Crudes Click to enlarge.|
The State Department the long-anticipated and voluminous (Final Supplemental EIS) for the proposed Keystone XL oil pipeline project. The document is posted on State’s , which it has run since the beginning of the Keystone XL Presidential permit process in 2008.
The analysis in the Final Supplemental EIS builds on the Draft Supplemental Environmental Impact Statement released on 1 March 2013 (earlier post) as well as the documents released in 2011 as part of the previous Keystone XL Pipeline application. Notable changes since the prior Draft Supplemental Environmental Impact Statement include an expanded analysis of potential oil releases; an expanded climate change analysis; an updated oil market analysis incorporating new economic modeling; and an expanded analysis of rail transport.
The proposed route evaluated differs from the route analyzed in the 2011 Final Environmental Impact Statement in that it would avoid the environmentally sensitive Nebraska Department of Environmental Quality (NDEQ)-identified Sand Hills Region and no longer includes a southern segment from Cushing, Oklahoma, to the Gulf Coast area. That portion of the pipeline has already been built.
Market analysis: cross-border pipeline constraints have a limited impact on crude flows and prices. The earlier 2011 Final EIS was developed contemporaneously with the start of strong growth in domestic light crude oil supply from tight oil formations, such as those formations found in North Dakota’s Bakken region. Domestic production of crude oil has increased significantly, from approximately 5.5 million bpd in 2010 to 6.5 million bpd in 2012 and 7.5 million bpd by mid-2013.
Rising domestic crude production is predominantly light crude, and it has replaced foreign imports of light crude oil. However, demand persists for imported heavy crude by US refineries that are optimized to process that kind of oil. Meanwhile, Canadian production of bitumen from the oil sands continues to grow, the vast majority of which is currently exported to the United States to be processed by US refineries that want heavy crude oil.
Both the 2011 Final EIS and the Draft Supplemental EIS published in March 2013 discussed the transportation of Canadian crude by rail as a possibility. Due to market developments since then, the Supplemental EIS notes that the transportation of Canadian crude by rail is already occurring in substantial volumes. It is estimated that approximately 180,000 bpd of Canadian crude oil is already traveling by rail, and industry investments in rail are increasing.
Rail loading facilities for the Canadian oil sands are estimated to have a capacity of approximately 700,000 bpd of crude oil, and by the end of 2014 this will likely increase to more than 1.1 million bpd. Most of this capacity (approximately 900,000 to 1 million bpd) is in areas that produce primarily heavy crude oil (both conventional and oil sands), or is being connected by pipelines to those oil production areas.
Supply-demand cases were paired with four pipeline configuration scenarios: an unconstrained scenario that allows pipelines to be built without restrictions; a scenario in which no new cross-border pipeline capacity to US markets is permitted, but pipelines from the WSCB to Canada’s east and west coasts are built; a scenario where new cross-border capacity between the United States and Canada is permitted, but Canadian authorities do not permit new east-west pipelines; and a constrained scenario that assumes no new or expanded pipelines carrying WCSB crude are built in any direction.
Updated model results indicated that cross-border pipeline constraints have a limited impact on crude flows and prices. If additional east-west pipelines were built to the Canadian coasts, such pipelines would be heavily utilized to export oil sands crude due to relatively low shipping costs to reach growing Asian markets. If new east-west and cross-border pipelines were both completely constrained, oil sands crude could reach US and Canadian refineries by rail.
Varying pipeline availability has little impact on the prices that US consumers pay for refined products such as gasoline or for heavy crude demand in the Gulf Coast. When this demand is not met by heavy Canadian supplies in the model results, it is met by heavy crude from Latin America and the Middle East.
The State Department report notes that several analysts and financial institutions have stated that denying Keystone would have significant impacts on oil sands production. State commented that to the extent that other assessments appear to differ from the analysis the State Department report, they typically do so because they have different focuses, near-term time scales, or production expectations, and/or include less detailed data and analysis about rail.
New data and analysis indicate that rail will likely be able to accommodate new production if new pipelines are delayed or not constructed.
Over the long term, lower-than-expected oil prices could affect the outlook for oil sands production, and in certain scenarios higher transportation costs resulting from pipeline constraints could exacerbate the impacts of low prices. The primary assumptions required to create conditions under which production growth would slow due to transportation constraints include: 1) that prices persist below current or most projected levels in the long run; and 2) that all new and expanded Canadian and cross-border pipeline capacity, beyond just the proposed Project, is not constructed.
The dominant drivers of oil sands development are more global than any single infrastructure project. Oil sands production and investment could slow or accelerate depending on oil price trends, regulations, and technological developments, but the potential effects of those factors on the industry’s rate of expansion should not be conflated with the more limited effects of individual pipelines.
Environmental analysis. According to the analysis, Keystone XL would emit approximately 0.24 million metric tons of CO2 equivalents (MMTCO2e) per year during the construction period. These emissions would be emitted directly through fuel use in construction vehicles and equipment, as well as, land clearing activities including open burning, and indirectly from electricity usage.
During operations, approximately 1.44 MMTCO2e would be emitted per year, largely attributable to electricity use for pump station power, fuel for vehicles and aircraft for maintenance and inspections, and fugitive methane emissions at connections. The 1.44 MMTCO2e emissions would be equivalent to GHG emissions from approximately 300,000 passenger vehicles operating for 1 year, or 71,928 homes using electricity for 1 year.
The total lifecycle emissions associated with production, refining, and combustion of 830,000 bpd of oil sands crude oil transported through Keystone XL is approximately 147 to 168 MMTCO2e per year. The annual lifecycle GHG emissions from 830,000 bpd of the four reference crudes examined in the Supplemental EIS are estimated to be 124 to 159 MMTCO2e. The range of incremental GHG emissions for crude oil that would be transported by the proposed Project is estimated to be 1.3 to 27.4 MMTCO2e annually. The estimated range of potential emissions is large because there are many variables such as which reference crude is used for the comparison and which study is used for the comparison.
However, the State Department report cautions, the above estimates represent the potential increase in emissions attributable to Keystone XL if one assumed that approval or denial of the project would directly result in a change in production of 830,000 bpd of oil sands crudes in Canada.
…such a change is not likely to occur under expected market conditions. … 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.
… If WTI-equivalent prices fell to around approximately $65 to $75 per barrel, if there were long-term constraints on any new pipeline capacity, and if such constraints resulted in higher transportation costs, then there could be a substantial impact on oil sands production levels.
Alternatives. The State Department conducted analysis on three broad categories of alternatives to Keystone XL:
No Action Alternative—which addresses potential market responses that could result if the Presidential Permit is denied or the proposed Project is not otherwise implemented;
Major Route Alternatives—which includes other potential pipeline routes for transporting WCSB and Bakken crude oil to Steele City, Nebraska; and
Other Alternatives—which include minor route variations, alternative pipeline designs, and alternative sites for aboveground facilities.
The No Action Alternative includes analysis of three alternative transport scenarios that are believed to meet Keystone XL’s purpose if the Presidential Permit for the proposed Project were denied, or if the pipeline were otherwise not constructed. Under the alternative transport scenarios, other environmental impacts would occur in lieu of the proposed Project.
The Supplemental EIS includes analysis of various combinations of transportation modes for oil, including truck, barge, tanker, and rail. These scenarios are considered representative of the crude oil transport alternatives with which the market would respond in absence of Keystone XL.
Rail and Pipeline Scenario. Under this scenario, WCSB and Bakken crude oil (dilbit or synbit) would be shipped via rail from Lloydminster, Saskatchewan (the nearest rail terminal served by two Class I rail companies), to Stroud, Oklahoma, where it would be temporarily stored and then transported via existing and expanded pipelines approximately 17 miles to Cushing, Oklahoma, where the crude oil would interconnect with the interstate oil pipeline system.
This scenario would require the construction of two new or expanded rail loading terminals in Lloydminster, Saskatchewan (the possible loading point for WCSB crude oil), one new terminal in Epping, North Dakota (the representative loading point for Bakken crude oil), seven new terminals in Stroud, and up to 14 unit trains (consisting of approximately 100 cars carrying the same material and destined for the same delivery location) per day (12 from Lloydminster and two from Epping) to transport the equivalent volume of crude oil as would be transported by the proposed Project.
Rail and Tanker Scenario. This scenario assumes crude oil would be transported by rail from Lloydminster to a western Canada port (assumed to be Prince Rupert, British Columbia), where it would be loaded onto Suezmax tankers (capable of carrying approximately 986,000 barrels of WCSB crude oil) for transport to the US Gulf Coast via the Panama Canal.
Bakken crude would be shipped from Epping to Stroud via BNSF Railway or Union Pacific rail lines, similar to the method described above. This scenario would require up to 12 unit trains per day between Lloydminster and Prince Rupert, and up to two unit trains per day between Epping and Stroud. This scenario would require the construction of two new or expanded rail loading facilities in Lloydminster with other existing terminals in the area handling the majority of the WCSB for shipping to Prince Rupert. Facilities in Prince Rupert would include a new rail unloading and storage facility and a new marine terminal encompassing approximately 4,200 acres and capable of accommodating two Suezmax tankers. For the Bakken crude portion of this Scenario, one new rail terminal would be necessary in both Epping, North Dakota, and Stroud, Nebraska.
Rail Direct to the Gulf Coast Scenario. The third transportation scenario assumes that WCSB and Bakken crude oil would be shipped by rail from Lloydminster, Saskatchewan, and Epping, North Dakota, directly to existing rail facilities in the Gulf Coast region capable of off-loading up to 14 unit trains per day. These existing facilities would then either ship the crude oil by pipeline or barge the short distance to nearby refineries. It would largely rely on existing rail terminals in Lloydminster, but would likely require construction of up to two new or expanded terminals to accommodate the additional WCSB shipments out of Canada. One new rail loading terminal would be needed in Epping to ship Bakken crude oil. Sufficient off-loading rail facilities currently exist or are proposed in the Gulf Coast area such that no new terminals would need to be built under this scenario.
During operation of all No Action rail scenarios, the increased number of unit trains along the scenario routes would result in GHG emissions from both diesel fuel combustion and electricity generation to support rail terminal operations (as well as for pump station operations for the Rail/Pipeline Scenario). The total annual GHG emissions (direct and indirect) attributed to the No Action scenarios range from 28 to 42 percent greater than for Keystone XL.
Background. The proposed Keystone XL project consists of a 875-mile (1,408 km) long pipeline and related facilities to transport up to 830,000 barrels per day of crude oil from Alberta, Canada and the Bakken Shale Formation in Montana. The pipeline would cross the US border near Morgan, Montana and continue through Montana, South Dakota and Nebraska, where it would connect to existing pipeline facilities near Steele City, Nebraska for onward delivery to Cushing, Oklahoma and the Gulf Coast Area.
Keystone’s first application for the Keystone XL pipeline was submitted on 19 September 2008, and a Final EIS was published on 26 August 2011. The route proposed included the same US-Canada border crossing as the currently proposed Project but a different pipeline route in the United States.
The 2011 Final EIS route traversed a substantial portion of the Sand Hills Region of Nebraska, as identified by the NDEQ. Moreover, the 2011 Final EIS route went from Montana to Steele City, Nebraska, and then from Cushing, Oklahoma, to the Gulf Coast area.
In November 2011, the State Department determined that additional information was needed to fully evaluate the application—in particular, information about alternative routes within Nebraska that would avoid the NDEQ- identified Sand Hills Region. In late December 2011, Congress adopted a provision of the Temporary Payroll Tax Cut Continuation Act that sought to require the President to make a decision on the Presidential Permit for the 2011 Final EIS route within 60 days. That deadline did not allow sufficient time to prepare a rigorous, transparent, and objective review of an alternative route through Nebraska. As such, the Presidential Permit was denied.
In February 2012, Keystone informed the Department that it considered the Gulf Coast portion of the originally proposed pipeline project (from Cushing, Oklahoma, to the Gulf Coast area) to have independent economic utility, and indicated that it intended to proceed with construction of that pipeline as a separate project, the Gulf Coast Project. The Gulf Coast Project did not require a Presidential Permit because it does not cross an international border. Construction on the Gulf Coast Project was recently completed.
On 4 May 2012, Keystone filed a new Presidential Permit application for the Keystone XL Project. The proposed Project has a new route and a new stated purpose and need. The new proposed route differs from the 2011 Final EIS Route in two significant ways: 1) it would avoid the environmentally sensitive NDEQ- identified Sand Hills Region and 2) it would terminate at Steele City, Nebraska.
From Steele City, existing pipelines would transport the crude oil to the Gulf Coast area. In other words, the proposed Project no longer includes a southern segment and instead runs from Montana to Steele City, Nebraska.
In addition to the NDEQ-identified Sand Hills Region, the proposed Project route would avoid other areas in Nebraska (including portions of Keya Paha County) that have been identified by the NDEQ as having soil and topographic characteristics similar to the Sand Hills Region. The proposed Project route would also avoid or move further away from water wellhead protection areas for the villages of Clarks and Western, Nebraska.
The proposed route in Montana and South Dakota is largely unchanged from the route analyzed in the 2011 Final EIS except for minor modifications that Keystone made to improve constructability and in response to landowner requests.
To assist in preparing this Supplemental EIS, the Department retained an environmental consulting firm, Environmental Resources Management (ERM). ERM was selected pursuant to the Department’s interim guidance on the selection of independent third-party contractors. This guidance is designed to ensure that no conflicts of interest exist between the contractor and the applicant and that any perceived conflicts that would impair the public’s confidence in the integrity of the work are mitigated or removed.
ERM works at the sole and exclusive instruction of the Department and is not permitted to communicate with Keystone unless specifically directed to do so by Department officials.
The Final Supplemental EIS is not a decisional document on whether to approve or deny the proposed project. The Final Supplemental EIS is a technical assessment of the potential environmental impacts related to the proposed pipeline. It responds to over 1.9 million comments received since June 2012.
The Presidential Permit review process now will focus on whether the proposed Project serves the national interest, which involves consideration of many factors: including, energy security; environmental, cultural, and economic impacts; foreign policy; and compliance with relevant federal regulations and issues. During this time, the Department will consult with, at least, the eight agencies identified in Executive Order 13337: the Departments of Defense, Justice, Interior, Commerce, Transportation, Energy, Homeland Security, and the Environmental Protection Agency.
A 30-day public comment period will begin with the publication of a Federal Register notice on 5 February 2014 and will close on 7 March 2014.