Access to world markets for Canadian oil has been available since 1956 when the Westridge dock was constructed in Burnaby, B.C., and linked to the Trans Mountain pipeline.
The dock’s export capacity has rarely been used to its full potential in more than 60 years — yet the oil industry and politicians continue to make the argument that Canada needs new pipelines to get oil to world markets.
Here are four reasons that argument doesn’t fly.
1) Existing Export Capacity Isn’t Being Used
In 2011, the National Energy Board (NEB) provided Kinder Morgan with a favourable and unprecedented ruling when it allocated guaranteed access to the dock under 10-year take-or-pay contracts with five crude oil shippers.
Kinder Morgan promised that 79,000 barrels a day of tidewater access would lead to the development of international markets for Alberta’s crude.
Guaranteed access means the dock can service 60 crude oil tankers a year. But according to statistics compiled by Port Metro Vancouver, not even a third of that number were loaded during 2016 — and most of those tankers went to U.S. ports. The equivalent of one tanker was loaded with Alberta’s heavy oil and destined for a non-U.S. port during the entire year. Seventeen went to U.S. destinations.
If Canadian oil needs to get to world markets as desperately as some claim, why isn’t existing access being used? It’s because there is no demand for it.
2) Energy East Won’t Reduce Reliance on Foreign Oil
“The lamentable state of crude oil pipeline infrastructure makes parts of this country reliant on foreign oil and our petroleum exporters dependent on the United States, which buys Canadian product at a deep discount,” wrote Conservative Senator Michael MacDonald in the Hill Times.
Eastern Canada has a dependency on imported oil because the refineries located there are configured to process primarily light oil. Energy East is intended to facilitate the transport of diluted bitumen from Alberta’s oilsands so will not reduce eastern Canada’s reliance on imported crude to any significant degree.
But there is another source of dependency on imported oil that is rarely acknowledged. Oilsands producers are dependent on imported condensate as a diluent for bitumen blending purposes. This is because oilsands heavy does not flow down a pipeline unassisted — it’s too dense.
Canada does not produce enough condensate to meet oilsands producers’ demand. Since 2005, condensate imports from the U.S. have increased significantly. For every three barrels of increased oilsands production, a barrel of condensate is imported. Thus, as oilsands production expands, Canada’s import dependency expands with it.
So if we want to see a reduction in Canada’s reliance on foreign oil imports we must advocate for a reduction in oilsands production or an increase in upgrading and refinery capacity in Alberta. Otherwise, the minute bitumen is shipped along a pipeline, it generates a growing dependency on crude imports.
3) Canadian Oil Producers Are Not Truly Dependent on U.S. Markets
Some suggest that Canadian producers are somehow dependent on U.S. markets. The majority of Canadian producers are not “dependent” on the US. They have integrated refinery operations there. To a significant extent Canadian producers supply their own crude to themselves or their joint-venture partners as U.S. refiners.
When Suncor sells into its Commerce City, Colorado, refinery, or Cenovus supplies its facilities in Wood River, Illinois, and Borger, Texas, owned in a joint venture with Phillips 66, or Husky supplies its refinery in Toledo, Ohio, it owns in partnership with BP, or Imperial and its parent, ExxonMobile, deliver crude from their joint venture to ExxonMobile’s U.S. facilities, it is hardly accurate to suggest that they are “dependent” on the U.S. market.
4) Canadian Oil Is Not Selling at a ‘Discount’
Many argue that the U.S. “buys Canadian product at a deep discount,” but that’s incorrect. There is a natural price discount between U.S. oil and Canadian heavy oil that will always exist because of quality and transportation cost differences.
Oil is traded in U.S. currency. Canadian crude is priced against a benchmark to U.S. produced light oil; West Texas Intermediate (WTI). To examine the differential and whether there is a discount that is outside the expected natural range requires that we compare WTI to Canadian crude prices. To do this for oilsands crude is to look at the price for WTI as compared to the price for Western Canadian Select (WCS)—the highest grade of Canadian heavy.
The natural discount for WCS compared to WTI, according to the National Energy Board is about 30 per cent — or roughly $20 US per barrel. A price differential of WCS to WTI of less than $20 U.S. would therefore be considered a “premium” price for WCS. WCS has been trading at “premium” since 2014. Currently, the differential is only $14 U.S. a barrel.
Robyn Allan is an independent economist and was an expert intervenor at the National Energy Board Trans Mountain Expansion hearing.
Photo: Jon Olav Eikenes via Flickr