Canada's oil sands producers will start 2018 with lower prices and storage headaches as a pipeline capacity crunch puts a damper on what had been a strong year for heavy crude.
TransCanada Corp.'s Keystone mainline system in South Dakota ruptured in November, choking a major outlet for oil sands bitumen headed for U.S. refineries. The outage on the line stalled delivery of almost 600,000 barrels per day and its restart at restricted pressure sent the price for Western Canada Select, the benchmark oil sands blend known as WCS, into a tailspin after a year of strong returns.
The price difference between WCS and U.S. benchmark crude had stretched to C$34.44 /bbl as of Dec. 20, compared with C$21.54/bbl a year earlier, as U.S. prices touched the highest in almost two years. The WCS discount, known as the differential, had averaged C$15.90/bbl until that date, according to data compiled by the Petroleum Services Association of Canada. On a spot basis Dec. 20 WCS sold for C$40.07/bbl, or US$31.20/bbl.
"The big thing driving the extremes in that discount for the heavy price is Keystone," Mark Oberstoetter, director of research at Wood Mackenzie's Calgary office, said in an interview. "That's a major relief valve for Canadian crude getting into U.S. refining, so until that comes back to its normal throughput rates you're just going to see a very full, pressurized system."
Pipeline capacity out of Canada's oil sands region, which had been near equilibrium as small projects fell by the wayside after the crude price collapse almost three years ago, will be a major sticking point for producers in 2018. Large upstream projects will come into service while the planned pipelines meant to serve them languish with regulators.
When Suncor Energy Inc., Exxon Mobil Corp. and Canadian Natural Resources Ltd. started major expansion projects during the 2010-2014 oil price boom, it was anticipated that Canada could have as many as five large new pipelines to carry product to refiners in the U.S. and overseas markets. Two of those projects died in the regulatory process — Enbridge Inc.'s Northern Gateway and TransCanada's Energy East — taking with them a planned 1.52 million bbl/d in transportation capacity and billions of pre-build dollars.
The Suncor-led Fort Hills oil sands mine has been ramping up production in late 2017 and is expected to produce about 175,000 bbl/d by the end of 2018.
Source: Suncor Energy Inc.
The three remaining contenders, Kinder Morgan Inc.'s Trans Mountain expansion, TransCanada's Keystone XL project and Enbridge's Line 3 expansion, with a combined incremental capacity of about 1.8 million bbl/d, would not start coming into service until late 2019, if they manage to clear regulatory hurdles. The pipeline delays at the federal, state and provincial level are a mismatch with the Alberta government's aggressive promotion of the oil sands, which has helped large production projects come online in the last two years. The latest, the Suncor-led Fort Hills project, will add between 20,000 bbl/d and 40,000 bbl/d of production in the first quarter as it ramps up to a planned 175,000 bbl/d by year end.
"We're adding more upstream projects, but we haven't added any major new relief valves or downstream projects," Oberstoetter said. "We're looking at Enbridge Line 3 maybe starting up 2020, that could be some support, but until then we're going to be filling the existing system. And any kind of interruption, such as this Keystone outage, is going to drive up that heavy differential for us."
Enbridge, the biggest operator of storage and pipeline capacity, said its system is running flat out. The company has almost 30 million barrels of storage capacity at Alberta terminals in Edmonton, Hardisty and Fort McMurray. Its network of lines make up the bulk of Canada's oil export capacity at about 2.7 million bbl/d between those storage points and the Canada-U.S. border near Gretna, Manitoba.
"The outlook for the mainline is to remain chock full even under the lowest production outlook," Guy Jarvis, head of Enbridge's liquids pipelines business, said at the company's Dec. 12 investor day.
Its lines will remain full even after Line 3 expansion goes into service, which is expected to happen in late 2019. The company still lacks permits to expand the line through Minnesota.
The tightening of pipeline space comes when Canadian storage is at a premium, analysts at Tudor, Pickering, Holt & Co. said in a Dec. 11 note.
The fourth quarter "is seasonally a build-time for inventories, with troughs in local refining demand — recent years have built 2 [million to] 4 million barrels November to December," the analysts said. "Timing on Keystone remains a question, but with storage at peak levels and naturally building, we see a scenario in which Alberta crude differentials could remain at wider-than-normal discounts well into 1Q18."
One source of potential relief is to ship oil by rail, although shipping costs between terminals in the oil sands region and U.S. refineries can exceed C$10/bbl. During the price spikes leading up to the 2014 crash in crude prices, midstream companies invested heavily in rail-loading facilities, only to let them languish when their use became cost-prohibitive.
"The loading capacity, that's definitely not constrained," Oberstoetter said. "We have probably 1 million bbl/d of loading capacity with Hardisty and Edmonton and those areas. There's definitely room on the loading capacity side."
The problem is reluctance by Canada's large railways to devote staff and specialized oil sands cars to address what could be a short-term need, Oberstoetter said. "What we understand the last month or two is it's more the lines and the actual staff," he said. "The two major rail companies have just been backed up and busy with moving grain. They don't have the operational capacity to go and change that. It can change if you sign some mid-term or long-term contracts with them. What they're saying is, we're too busy run off and deal with your crisis for one month."
Integrated oil companies like Exxon Mobil's Imperial Oil Ltd., Suncor and Hong Kong billionaire Li Ka-Shing's Husky Energy Inc. have a measure of insulation from price shocks because low prices at the oil sands facilities can be made up at the gas pump. Most integrated Canadian oil companies saw refining margins widen in the third quarter.
"As export pipeline capacity out of West Canada becomes increasingly constrained, we expect [Husky] to be relatively sheltered from impacts to a wide WTI-WCS spread given the level of integration within its upstream and downstream assets," analysts at Goldman Sachs said in a note.
Large companies like Cenovus Energy Inc., which has limited refining capability, and Canadian Natural Resources Ltd. depend largely on oil sands sales and are more vulnerable to price shocks. However, producers of that size are more likely to have locked up pipeline capacity to avoid the fallout of unplanned events.
"That's why most of those pipelines are oversubscribed now," Oberstoetter said. "Most of the marketers from those companies know what's coming and are trying to book space based on not only their projects but their next door neighbors'."
While futures contracts for WCS reflect a bearish outlook for the coming year, Oberstoetter said events in the oil sands region could offer a buffer to the capacity crunch.
"As we go into next year, there are a few seasonal things to consider," he said. "For the oil sands, which is most of production, you usually have some turnarounds for maintenance going into the spring and summer. So that will lessen supply and probably help balance out the midstream. And with refineries, they normally run their peaks in the summer for the driving season. So those two things will ultimately mean that the differential won't stay where it is right now."