A TransCanada executive said opponents of the Alberta-to-Texas Keystone XL pipeline should consider one consequence of delays in building the oil pipeline – an increase in dirtier and more dangerous rail transport. Alex Pourbaix, president of energy and oil pipelines at the Calgary-based pipeline company, said although rail has an important role to play in moving oil sands crude to market, there are downsides to consider.
“For every mile you move a barrel of oil by rail, you emit three times the (greenhouse gases) that you do by moving it by pipeline and you have an order of magnitude higher risk of having some sort of incident, leak or spill,” Pourbaix told an energy conference in New York recently. “So from that perspective, I make the point that if you’re actually concerned about the environment, for long-haul movement of oil, you very much want to see that moving by pipeline.”
Environmental groups opposed to Keystone have broader concerns about the oil sands crude in the pipe, which they claim is much dirtier than other oil. They see pipelines as enabling oil sands extraction. Rail, however, is not immune to the same opposition. In January, 16 environmental groups sent a letter to Canadian National Railway CEO Claude Mongeau, warning that any efforts to bring Alberta oil sands crude by rail to the B.C. West Coast would “face major opposition and risks to the company.”
Meanwhile, a new report by IHS CERA stated that the life-cycle greenhouse gas (GHG) emissions from Canadian oil sands are similar to those from sources of crude that would likely be used in absence of the proposed Keystone XL pipeline, IHS said in a public comment submitted to the U.S. Department of State draft Supplemental Environmental Impact Statement (SEIS) for the controversial pipeline.
The IHS assessment is based on ongoing IHS CERA Oil Sands Dialogue research. A 2012 Oil Sands Dialogue report found that the life-cycle GHG emissions (from the extraction, processing, distribution and combustion of the refined fuel) from oil sands imported into the United States are 12% higher than the average crude oil consumed in the U.S.
That is lower than the figure used by the State Department SEIS — 17% higher than the U.S. average — and places Canadian oil sands in the same range as the most likely alternatives, such as heavy oil from Venezuela. Venezuela is the largest supplier of heavy oil to the U.S. Gulf Coast.
“With or without oil sands supply to the Gulf Coast from Keystone XL, refiners there will continue to process crude oils with similar levels of GHG emissions, given the region’s substantial capacity to refine
these types of crudes,” said Jackie Forrest, IHS senior director and head of the IHS CERA Oil Sands Dialogue. “Venezuelan crude, which is in the same GHG intensity range as oil sands, is the primary heavy crude oil used in the region today.”
President Obama is expected to make the final decision on whether to issue the necessary permit for Keystone XL early this summer.
To download the full IHS Comments on the draft Supplemental Environmental Impact Statement (SEIS) for the Keystone XL Pipeline and the IHS CERA Oil Sands Dialogue greenhouse gas study (see Oil Sands, Greenhouse Gases, and US Oil Supply: Getting the Numbers Right – 2012 Update), visit the dialogue’s homepage, http://www.ihs.com/oilsandsdialogue.
In another IHS study, the consultants said that a shift away from new upgrading and refining projects allows the limited number of oil sands workers to be deployed on new production projects where economic benefits can be greater.
Given the challenging market conditions that bitumen processing facilities face, shipping oil sands directly to market as heavy crude may have greater economic benefits than building new upgrading facilities that locally process oil sands bitumen into lighter synthetic crude oil (SCO) or refined products, the study says.
The shift away from constructing upgrading or refining facilities enables Alberta’s limited number of workers to be deployed on projects that augment heavy bitumen production, which results in more long-term jobs, government royalties, and tax revenue.
The new study examined the economic drivers that have turned the previously bullish outlook for upgrading and refining in the Canadian oil sands region on its head. Following the Great Recession, higher-than-average capital costs from a constrained labor market in Alberta and a narrowing of the price difference between light and heavy crudes have constrained investment in processing oil sands crude locally.
The rapid growth of tight oil, a lighter form of crude, has also reduced the demand for the already-upgraded bitumen in North America, making the U.S. market more favorable to imports in the form of heavy (non-upgraded) oil sands crudes. The vast refinery capacity along the the U.S. Gulf Coast is more attuned to those types of crudes from the oil sands rather than lighter SCO.
“The current reality is that, in many cases, new value-added upgrading and refining investments in Alberta have challenging economics and investors do not get a reasonable return on the billions they must commit for a bitumen processing facility,” said Forrest. “Producers would be taking additional steps and spending more money to upgrade or refine oil sands, when the strongest demand is for non-upgraded products.”
A few exceptions do exist, the study noted. Although the potential is not as strong as Asia, given the right set of conditions, the economics of a new refinery in either British Colombia or Alberta could work, it said.
The shift away from new oil sands downstream processing facilities in Alberta has the potential benefit that labor that otherwise would be devoted to constructing those facilities are redirected toward increasing oil sands production, the study said. The economic benefits of increased oil sands production over new upgrading and refining facilities include:
* Direct long-term jobs – For projects of comparable size, oil sands production facilities provide more long-term jobs than upgraders or refineries. Consequently, when construction workers are deployed to build upgraders (resulting in fewer oil sands production facilities being built) this actually reduces the number of long-term jobs in Alberta.
* Government royalties – A royalty is the price Alberta charges a producer for the resource they extract—oil sands bitumen in this case. Consequently, upgrading or refining bitumen does not generate additional royalties for the province.
* Income taxes – Facing challenging economics, Alberta upgraders may struggle to generate positive cash flow and consequently pay less income tax. Since oil sands projects generate positive returns, higher production and cash-flows results in more income tax revenue.
By devoting additional resources to build up bitumen production now, Alberta is not closing the door to bitumen processing in the future should circumstances change, the study found.
“If the future unfolds differently than expected and the economics for value-added investments strengthen, the option will always remain to upgrade and refine then,” Forrest said.
The complete study is available for download at the dialogue’s homepage, www.ihs.com/oilsandsdialogue.