Canada’s oil industry faces multiple headwinds on top of an oil bust that has changed the global industry over the past few years. Canadian producers are selling their oil at hefty discounts to WTI, not only because of the heavier sour variety they are pumping out of the oil sands, but also because of limited pipeline capacity that moves the oil out of landlocked Alberta—the heart of the Canadian oil industry.
Currently there are three pipelines in the works that will take more Alberta oil either to the U.S. or to the Canadian Pacific coast: Enbridge’s Line 3 Replacement Program, Kinder Morgan’s Trans Mountain expansion project, and TransCanada’s Keystone XL pipeline. Last month, TransCanada scrapped a pipeline project to ship oil to the Canadian East Coast.
In the best-case scenario for Canada’s pipeline capacity—that is, if all three remaining pipelines clear all regulatory hurdles (which are many right now)—Canadian pipeline capacity will be in excess of 52,100 bpd in 2020, and more than 656,100 bpd in 2022, according to estimates by Bloomberg Gadfly columnist Liam Denning.
However, if only Line 3 is approved and built (the pipeline that, for now, stands the best chance of getting a go-ahead), Canada will still be 552,000 bpd short of pipeline takeaway capacity in 2022. If Keystone XL doesn’t go ahead and Line 3 and Trans Mountain proceed, the excess pipeline capacity in 2022 will be just 50,000 bpd.
But before 2020, Canada’s oil production is expected to continue to increase, and pipeline constraints will become bigger, before any of the proposed pipelines—or one, or all—comes online and eases some of the takeaway constraints.
Alberta oil is heavy and requires more energy to process it into gasoline or other refined oil products. That’s why the Western Canadian Select (WCS)—representative of the price of oil from Canada’s oil sands delivered at Hardisty, Alberta—trades at a $10 or more discount to the WTI. But the discount also reflects those pipeline constraints that have plagued Canadian producers for years. WCS also trades at a discount to the flagship Mexican crude grade of similar quality, Maya, because Canadian oil must travel further to reach the Gulf refineries than Mexico’s oil, because Mexico’s oil travels less distance. The WCS to Maya discount has been below $10 for much of the past two years, but has recently deepened to $13.20 as of November 10, according to Bloomberg estimates.
Futures prices imply the spread will surge to $17 in the next two years, as Canadian oil production grows and additional pipeline capacity—if any—is stagnant until at least late 2019.
According to IHS Markit, oil sands will remain a growth story, and nearly 500,000 bpd of new oil sands production will be added this year and next. “Over 2017-19 Canadian growth, led by the oil sands, will only be surpassed by the United States and its tight oil machine,” IHS Markit’s Kevin Birn said in June 2017.
Total Canadian production was 3.85 million bpd in 2016, and is expected to rise to 5.1 million bpd in 2030, according to the Canadian Association of Petroleum Producers (CAPP), which says that by 2030 Canada will need more pipelines to transport an additional 1.3 million bpd.
In the shorter term, until 2020, with growing domestic production and no additional pipeline capacity, Canadian producers have been shipping more oil-by-rail since the end of 2016. This, Bloomberg’s Denning notes, costs $13-$18 per barrel to get to the Gulf Coast, which leads to widening differentials in the futures and significantly lower margins for oil producers.
All Canadian producers will be affected, but those that refine domestically are in a better position to offset at least part of the discounts at which they will sell their oil in the next couple of years, Denning argues.
But it may be even more years, because none of the three proposed pipelines is a certainty yet.
Line 3 is undergoing a public hearing and public hearing comments in Minnesota, and the Minnesota Public Utilities Commission is expected to announce its Certificate of Need and Route Permit decision in April 2018.
Although it’s approved at the federal level, the Trans Mountain expansion project is pitting the new British Columbia government against the Alberta government, with BC now vowing to fight the project.
TransCanada said at its Q3 earnings call that it received contribution from 545,000 bpd of long-term, long-haul contracts during Keystone’s open season. The fate of the pipeline, however, hinges on the Nebraska Public Service Commission (PSC), which will vote on the order on the Keystone XL Pipeline Application in a public hearing next Monday, November 20.
So Alberta and Canada’s oil producers hope that at least some additional pipeline capacity will be added in a few years, to offset part of the discount of their crude sales.
By Tsvetana Paraskova for Oilprice.com
