NYMEX WTI and ICE Brent crude prices have surged to two-and-a-half-year highs, but the same cannot be said for oil produced in Canada. Western Canada Select (WCS), a benchmark that tracks heavy oil from Alberta, suffered a sharp selloff in the fourth quarter of 2017, trading at a nearly $30-per-barrel discount relative to WTI in December.
Western Canada Select traded a nearly $30-per-barrel discount to WTI due to midstream constraints.
The unusually large differential is the result of a confluence of factors that is contributing to an abundance of oil in Canada. The Canadian market is dealing with midstream bottlenecks while heavy crude producers such as Colombia and Venezuela are seeing output declines and OPEC producers are cutting production. These conditions, which should remain in place for the foreseeable future, have altered the Western Hemisphere’s heavy crude market.
Oil from Canada typically trades at a discount to U.S. benchmark WTI as a result of quality issues, the cost of transporting product long distances to refineries in the U.S., as well as congestion on the handful of pipelines that connect Alberta to its southern neighbor.
Against this backdrop, the discount for WCS versus WTI fluctuated between $10 and $15 per barrel for much of 2017. But the differential between the two oil benchmarks widened considerably in late November after an oil spill from the Keystone pipeline in South Dakota led to its temporary shutdown. The two-week outage at the 590,000 barrel-per-day (b/d) pipeline led to a rapid buildup in oil inventories in Canada, as oil producers had difficulty moving oil out of the country. For the week ending on December 8, oil storage in Alberta and Saskatchewan hit 31.8 million barrels, a record high according to Genscape, and up roughly double from October levels. WCS traded nearly $30 below WTI.
Oil production levels from Alberta have approached the region’s pipeline capacity, a problem that continues to worsen as new upstream production comes online.
The outage was temporary, but highlighted chronic bottlenecks that have plagued Canada’s oil industry for some time. Oil production levels from Alberta have approached the region’s pipeline capacity, a problem that continues to worsen as new upstream production comes online. According to Genscape, heavy oil production in Canada averaged 239,000 b/d below pipeline capacity in 2016. By the first half of 2017, average output was just 138,000 b/d below the limit. By August 2017, output exceeded the ability of Alberta’s pipeline network by 21,000 b/d. Because a handful of projects that were planned years ago are starting to come online—such as Suncor’s $17 billion Fort Hills oil sands mining project, which is nearly complete and will add 194,000 b/d within one year—the pipeline shortage will likely be exacerbated. Genscape estimates the shortfall will expand to 338,000 b/d by the end of this year.
Discount likely to remain wide
The worsening pipeline shortage suggests that the wide WCS discount will likely persist for quite some time. The solutions to the bottleneck are not immediately on the horizon.
In the past, railroads have been called upon to ease the pressure on pipelines, and more oil is now hitting the rails—Genscape says that Alberta rail facilities reported oil shipments at over 100,000 b/d for three consecutive weeks between November and December, the first time that level was reached since early 2014. However, Canada’s rail industry is also facing bottlenecks of its own, racing to work through a backlog of grain shipments that had faced delays. As new oil production continues to come online, the rail industry will not likely be able to fill the gap that has occurred due to overstretched pipelines.
It could be years before a major pipeline comes online in Canada.
Ultimately, Canada’s oil industry needs more pipeline capacity. However, it could be years before a major pipeline comes online. Enbridge is replacing its decades-old Line 3 pipeline that runs from Alberta to Wisconsin, which will double the line’s capacity to 760,000 b/d when completed. Enbridge says it will finish the project by late 2019, but legal challenges in Minnesota put the timeline into doubt. TransCanada’s Keystone XL pipeline appeared to clear a final hurdle when it received a greenlight from Nebraska regulators, but the approval was for an alternative route that could create fresh legal challenges and tie up the project for several more years. Kinder Morgan is hoping to move forward with its Trans Mountain expansion, which will triple the existing line’s capacity from 300,000 b/d to 890,000 b/d, taking Alberta oil to Canada’s Pacific coast. But that too faces legal questions, and Kinder Morgan says the project might not be completed until the second half of 2020.
More oil from the Middle East?
Canadian oil producers are suffering from a steep selloff in the price for their crude, but U.S. refiners are benefitting from discounted barrels. For example, HollyFrontier Corp., a U.S.-based refiner that processes heavy crude, has seen its share price rise nearly 40 percent since early November.
Gulf Coast refineries equipped to handle heavy crude have been dealing with declining heavy oil imports from Mexico, Colombia, and Venezuela.
Canadian bottlenecks are having ripple effects in the global oil market. Gulf Coast refineries equipped to handle heavy crude have been dealing with declining heavy oil imports from Mexico, Colombia, and Venezuela. Mexico’s mature oil fields have suffered from long-term decline. The slide in output could eventually be reversed with new investment from international companies, but that will take time. Pipeline issues and declining output in Colombia led to reduced shipments in 2017. U.S. imports from the South American nation dipped to just 277,000 b/d in October, down from an average of 480,000 b/d in 2016.
Venezuela is suffering from problems of a higher magnitude. An economic and fiscal crisis has compounded years of neglect in the nation’s oil industry, leading to accelerated declines in output. U.S. heavy oil imports from Venezuela plunged in 2017 with little prospect of a rebound. By October, American refiners imported only 562,000 b/d from the OPEC producer, down from an average of 800,000 b/d in 2016.
Problems in Latin American producers have at times been a boon to Canada. In mid-2017, WCS prices increased because of declining heavy oil imports from Latin America into the Gulf Coast. Canada filled the void left behind by Mexico, Venezuela, and Colombia. The WCS discount to WTI temporarily narrowed to just $5 per barrel in mid-2017. However, Canada’s pipeline problems and new supply ultimately caused WCS prices to fall sharply in the fourth quarter.
Iraq has taken advantage of the current situation and is the fastest growing source of heavy sour oil to the U.S.
Lower volumes moving from Canada to the U.S due pipeline capacity limits and declining availability of heavy oil from Latin America mean Gulf Coast refineries have to look elsewhere for heavy oil. Iraq and Saudi Arabia are two possibilities. But the OPEC cuts have led to production restraint and have impacted shipments to the U.S. Saudi Arabia has deliberately tried to cut exports to the American buyers in an effort to drain U.S. inventories. Iraq, however, has taken advantage of the current situation and is the fastest growing source of heavy sour oil to the U.S., according to Argus Media and the EIA, with volumes reaching as high as 800,000 b/d last year, versus just 250,000 b/d at the beginning of 2016. Iraq could take even more market share in the current environment. Whatever the case, the combination of pipeline constraints, falling supply in Latin America, and OPEC’s cuts will continue to shake up North America’s heavy market.