Why rising oil prices may not signal a rebound for Canada’s oil companies

The price of crude is on the rise, but in Canada, new carbon taxes, regulations and pipeline hurdles may take the industry permanently out of contention

Investor turning the tap on an oil pipeline, but only a dribble comes out

(Illustration by Iker Ayestaran)

The past two years have been brutal for the Canadian oil sector. Prices plummeted (Western Canadian Select fell from US$92 a barrel in 2013 to just US$14 in early 2016); investment dropped 62% (or $50 billion); and wells drilled fell from 10,400 to 3,500 a year, according to the Canadian Association of Petroleum Producers (CAPP). The Haynes and Boone Oil Patch Bankruptcy Monitor notes that 17 Canadian energy companies failed.

The industry is accustomed to boom and bust, however, and has adapted: conserving capital, leaning on suppliers to cut costs, and innovating to increase productivity. Moreover, the oil market is tightening—albeit in fits and starts—and recovery appears to be in sight. Still, many in Canada’s oilpatch fear they will miss out on the upswing, if and when it comes.

“We have governments that are going to impose additional regulatory compliance costs on companies that already operate in a very high-cost environment,” says Gary Leach, president of the Explorers and Producers Association of Canada. The Alberta government alone is introducing a carbon tax, a 100-megatonne emission cap for the oilsands and a commitment to decrease fugitive methane emissions by 40%. Ottawa, meanwhile, has vaguely vowed to impose a nationwide carbon pricing scheme. “Canada’s done serious damage to its reputation as a reliable place to invest,” Leach says.

So even if oil does rebound, Canadian stocks might underperform. Not only could their near-term profitability be hampered, but they may also have difficulty growing (or even just maintaining) production levels in the more distant future. So if you think the oil sector is due for a rebound, are you better off in domestic names or U.S. and multi-national producers?

It’s important to understand how businesses are adapting to low prices. “We see companies retooling the design of their projects to lower capital costs,” says Kevin Birn, senior director of Canadian Oil Sands Dialogue with IHS Markit. The Alberta Energy Regulator has approved at least 25 new projects, but many may never be built. Take BlackPearl Resources’ Blackrod thermal project, located south of Fort McMurray. The first phase of the enterprise, which will produce 20,000 barrels per day, will cost $800 million. BlackPearl (TSX: PXX) initially had a partner, but by the time the approval process was completed, the partner had decided to invest elsewhere. “We do not have plans to go out and build at Blackrod, but we would entertain a partnership with someone else if they want to come in and carry us for the first phase,” BlackPearl CEO John Festival told Reuters in September.

Management teams are instead focused on optimizing existing production. “For oilsands facilities over the next 20 to 30 years, it will be how you manage and perform with what you have,” says Birn. For those companies that have already built their sites and infrastructure (such as roads, power lines, labour pools and work camps), operating costs are quite low. “If you look at the study we did, some of the oilsands facilities break even below US$20 WTI (West Texas Intermediate) on a cash cost basis,” says Birn. “It’s a much lower threshold than what a lot of people think.”

Another factor limiting Canadian producers’ upside is the absence of new take-away capacity. If no new pipelines are built before 2040, the National Energy Board (NEB) estimates the industry will forgo $106 billion of investment and produce 500,000 fewer barrels a day than under a business-as-usual scenario. “Without the pipeline capacity, the oil is more constrained inland, and differentials are higher when you ship by rail, so it’s less money back to the producers. And that’s what really drives the less-investment scenario,” says Shelley Milutinovic, the NEB’s chief economist.

Prime Minister Justin Trudeau is expected to green-light Kinder Morgan’s Trans Mountain Expansion in December, but the project will almost certainly face legal challenges from First Nations, environmentalists and local municipalities, further delaying (and possibly preventing) construction. TransCanada Corp. (TSX: TCA) has just begun the NEB review process for Energy East, which is encountering significant opposition in Quebec and won’t be built for several years at best. The other options are still less likely.

“A lack of pipelines doesn’t prevent you from shipping your oil out; there are alternatives using rail,” notes University of Calgary economist Trevor Tombe. “But the cost is higher. Anything that increases the cost per barrel is going to lower margins and profitability, and therefore lower investment.”

Though it’s still unclear how emissions policies will be implemented, Tombe says, “there’s not the level of uncertainty that would prevent a firm from calculating the policy-relevant costs.” The new rules’ intent, he points out, is to reward efficient companies with less emissions-intensive production, like Cenovus Energy (TSX: CVE) and Imperial Oil (TSX: IMO), and encourage others to adopt technology that will “take the carbon out of the barrel.” Ultimately, the price of the commodity is the single most significant factor affecting the level of energy investment, Tombe concludes. “Unless prices return to over $60, we’re really not likely to see a lot of new investments.”

A decade ago, Canada’s oilpatch—being one of the few places firms could invest and meaningfully increase their reserves—was awash with investment. Over the next decade, Birn says, “growth will be different. It will come with a lower price tag. It will be more modest than in the past, affected by the pace of price recovery and future pipeline capacity.”