The Teck megaproject is dead, but there’s still hope in the oil sands

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Mark Little didn’t see it coming. It was just days before the federal cabinet was due to rule on whether Teck Resources Ltd. could proceed with its $20.6-billion Frontier oil sands mine, and the chief executive of Suncor Energy Inc. was spending a Sunday with his family.

Glancing at his social-media feed, he got a shock: Teck CEO Don Lindsay had withdrawn the application.

“I don’t know what Don’s rationale was, but from my perspective, I didn’t expect that, especially when Teck was on the Street on Friday with their earnings and such, and made comments associated with it,” Mr. Little says. “So I was surprised, as probably everybody else was.”

Mr. Little, however, knows better than just about anyone the high costs and regulatory hurdles that face any company trying to get a megaproject built. In fact, Suncor built the last one – the $17-billion Fort Hills project, completed in 2018 – with Teck as a partner.

After spending nine years in the regulatory process and gaining support from all the Indigenous groups who’d be affected by the massive open-pit mine, Teck’s decision was drastic, and it contained a key message: In an era of tepid oil prices, thanks to a global supply glut, a chronic lack of pipeline capacity for Canadian crude, and an intensifying focus on environmental issues by average Canadians and influential investors alike, sprawling new oil sands megaprojects could be a thing of the past.

That doesn’t mean the end of oil sands development. Projects have been cancelled before. Lots of them. But Suncor, Imperial Oil Ltd., Canadian Natural Resources Ltd. (CNRL) and other industry players have been forced to rethink how they invest capital in the oil sands – a resource that demands piles of it. Instead of pitching huge new projects, they’re concentrating on expanding their current mines and on steam-assisted gravity drainage – the “in situ” projects that produce heated bitumen in wells, rather than using massive shovels to scrape the Northern Alberta landscape.

These “brownfield” developments largely escape the public glare, as companies complete them gradually and without fanfare. They also require much lower oil prices to break even and rarely take years to be approved.

“That’s where we spend most of our time and attention, because that’s where the dollars are going to go and where there will be growth,” says Mark Oberstoetter, Calgary-based research director at Wood Mackenzie, the international energy consultancy. “Greenfield mines have proven challenging. We were never too optimistic on the go-ahead likelihood for Frontier, excluding the regulatory and political fighting around it.”

Suncor is investing in situ projects, as well as filing for an extension to its base mine north of Fort McMurray, as a way to keep its processing facilities operating at capacity. The company is also working on technology to pump bitumen to the surface using solvent and even radio waves rather than extreme heat, and investigating how to separate oil from mined dirt without water.

“Yes, we spend some money and build some additional assets, but a lot of the existing assets continue to be used,” says Mr. Little, who became CEO last May after holding several senior roles at Suncor, including two years as chief operating officer under Steve Williams. “It’s around sustaining our business, but we’re focused on how we can do that so our costs decline, the social benefit increases and the environmental effects decline.”

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The energy world has changed dramatically since Teck applied to build Frontier in 2011. Just a few years earlier, companies from China, Norway and the Netherlands could scarcely bid enough to gain a foothold in the world’s third-largest crude reserve. There were growing fears of a global shortage, and oil topped US$100 a barrel (bouncing back to near that level after the financial crisis). Prices now are half that. Meanwhile, the cost of building a major oil sands mine continues to climb.

The industry’s reluctance to bet big on new projects is reflected in the bonuses developers have paid to the Alberta government for leases. Last year, the province took in just $12.3-million for lands suitable for oil sands projects, compared with nearly $2-billion in the boom times of 2006.

There was no shortage of drama over whether Ottawa should approve Frontier, which was slated to pump 85,000 barrels a day starting in 2026. Alberta Premier Jason Kenney warned Prime Minister Justin Trudeau that failing to give it the go-ahead would stoke the fires of Western alienation. Mr. Kenney asserted that rejecting it would eliminate 7,000 construction jobs at a time when Alberta is in dire need of the work.

Those numbers make for good speech fodder, but they gloss over the fact that by the time Frontier came up for a federal go-or-no-go decision, the project simply wasn’t economically viable. Its cost was pegged at nearly $21-billion – an estimate done six years ago. Teck had written down the carrying value of the project to zero, and Mr. Lindsay cautioned the project needed to clear three high hurdles.

First off, Teck would need to find a partner to help shoulder the cost and risk of the project. Oil prices would have to go much higher. And Canada’s oil industry would have to achieve its holy grail of vastly expanded transport capacity ­– that is, a major pipeline that could actually ship oil to market, not one that was barely under construction, as is the case with the $12.6-billion Trans Mountain expansion, designed to triple its capacity.

That project still faces opposition from environmentalists and some B.C. First Nations, and its completion is no fait accompli. Enbridge Inc.’s Line 3 pipeline replacement in the U.S. upper Midwest and TC Energy Corp.’s Keystone XL also face chronic delays.

The industry’s main market has changed, too. The United States has transformed itself from a captive customer for crude wrung from Canada’s oil sands into a competitor, as its own oil production surged owing to the shale revolution.

U.S. oil imports dwindled to 5.8 million b/d at the end of 2019 from 8.7 million just a decade earlier, according to the Energy Information Administration. The only supplier that has vastly expanded exports to the U.S. in that time is Canada – shipments have surged 70 per cent.

At times, however, the cost of that market concentration in the U.S. has been high in the form of deep price discounts on oil sands-derived crude as shipments crowd the pipelines.

The U.S. industry’s massive focus on investment in shale deposits in the past decade, in regions such as the Permian in Texas and the Bakken in North Dakota, has also taken a toll on the oil sands. In an environment in which investors seek rapid returns, speedy drilling-to-production times and lower costs per barrel compared with bitumen projects, a host of major U.S. producers (among them ConocoPhillips, Marathon Oil Corp. and Devon Energy Corp.) have sold their Canadian holdings despite the promise of decades of stable – albeit sometimes thin – profit margins.

“It’s made everybody think about how we deploy our capital, how we look at technology and the things we’re working on,” Mr. Little says. “But that’s as true in the North Sea as it is in the oil sands, and even in shale.”

It has played out in money being funnelled into development. Last year, the industry made $12-billion of capital expenditures in the oil sands, down from nearly $34-billion in 2014, just as the oil downturn began, according to the Canadian Association of Petroleum Producers. Production forecasts have been tempered. CAPP now sees oil sands output reaching 3.88 million b/d by 2030, up from about 3.2 million this year. In 2014, the group forecast nearly five million b/d by 2030.

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The oil sands’ vast reserve of fossil fuel remains Canada’s uncomfortable energy storehouse – one that has increasingly become a target in the fight against climate change. And with major investors now screening opportunities through an environmental, social and governmental lens, large injections of capital are harder to come by.

The most recent example is BlackRock, the world’s largest asset manager, which this year launched three “fossil-fuel-screened” exchange-traded funds that will eschew companies that generate any revenue from thermal coal or oil sands.

Mr. Oberstoetter says higher carbon emissions from oil sands production are viewed as a risk by global investors, despite the industry’s record of gradually reducing per-barrel greenhouse gas. (Overall emissions have grown with production levels, however.) Outside Alberta, it’s not well known that the province’s large emitters pay a carbon levy and have done so since 2008. Mr. Kenney maintained the program even after he scrapped a consumer carbon tax instituted by former premier Rachel Notley.

“As carbon intensity has dropped a little bit, the oil sands don’t look as bad in comparison to some other resources as they used to,” Mr. Oberstoetter says. “You’ve got some companies that are looking to innovate and keep bringing that down, as well as use other tools, whether it’s sequestration or other techniques to make this viable in a low-carbon world.”

Still, at 4.1 megatonnes of emissions a year, Frontier threatened to push Alberta close to a self-imposed 100-megatonne cap, according to a calculation used by Ottawa. A couple of weeks before it withdrew its application, Teck announced a plan to be carbon neutral by 2050, bringing it in line with Paris Accord pledges by Canada and Chile, where Teck has much of its operations.

Other oil sands producers have made similar commitments. Suncor, for instance, pledged four years ago to reduce its emissions intensity by 30 per cent by 2030 (though, overall emissions increased by 11 per cent as Fort Hills started up). It has put real money behind the effort, investing in a wind farm and announcing last fall that it would spend $1.4-billion on two gas-fired co-generation units. They will replace petroleum coke-fired units and feed excess power to the provincial grid.

Frontier was designed to be an open-pit mine, the most visible and disruptive method of oil sands extraction. The development, which received the approval of a joint review panel in July, 2019, would have eventually produced 260,000 b/d and included an ore preparation plant, a bitumen processing facility and a tailings pond. Teck promised to employ state-of-the-art methods for dealing with carbon emissions, water use and tailings.

Oil sands tailings remain one of the industry’s thorniest problems, owing to the environmental and financial risks they present. There are already 1.4 trillion litres of the residue in holding ponds right now, and regulators have granted approvals for mining projects based on the likelihood that technology will be developed to reduce and eventually clean up the toxic lakes. The industry’s best scientists are working on possible solutions, but they’re still not ready for wide commercial use.

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Uncertainty around how Canada and the rest of the world will address climate change was just one of the major risks highlighted in the joint review panel’s Teck report. The other was future oil prices.

Analysts’ estimates for a break-even West Texas Intermediate (WTI) oil price for Frontier ranged from US$65 a barrel to more than US$80. (Estimates for building a new steam-driven project are in the low US$50s a barrel.) That future now looks unlikely. Crude prices tumbled to a 14-month low this week, as fears about the impact of the coronavirus on global economies pummelled financial markets. On Friday, WTI closed at US$49.25 a barrel.

But over the past five years, average monthly U.S. crude prices have only exceeded US$65 in seven months, all of them in 2018. Meanwhile, the price differential between Western Canada Select (WCS) heavy crude blend and WTI has at times ballooned well beyond US$30 a barrel, as shipments overwhelmed the available pipeline capacity. When that happens, especially when WTI prices are also weak, it puts most oil sands producers below break-even levels (especially given the added cost of blending condensate with bitumen so it can be shipped via pipeline).

That price spread blew out in late 2018, owing to a supply glut in Western Canada as several U.S. refineries underwent maintenance. The Alberta government, then led by Ms. Notley, curtailed heavy oil production as a way to shrink the differential, a move that worked, but created deep divisions in the industry.

Some oil sands producers, including CNRL, Cenovus Energy Inc. and MEG Energy Corp., supported the move. Suncor, Husky Energy Inc. and Imperial Oil, which also have refining operations, opposed it.

Mr. Kenney’s government has kept the OPEC-style production curbs in place, but has eased them, and allowed an exemption for any production that companies can ship by rail. The initial limit was 3.56 million b/d, and that has since been lifted to 3.81 million. By the end of January, 2019, the WCS discount had shrunk to about US$10 a barrel, and it now sits around US$13.95, according to NE2 Group.

In reaction to the curtailment, Imperial Oil put the brakes on a $2.6-billion, steam-driven oil sands project called Aspen. It has since said it is expanding its current operations in the Cold Lake region of Northeastern Alberta. “While curtailment continues, there continues to be uncertainty around long-term investment economics, and the ability to get product out of Alberta and to maximize value of our production,” Imperial CEO Bradley Corson said in late January. “So while curtailment exists, we’ve said Aspen is off the table. And I don’t see that changing.”

Suncor, meanwhile, has deferred a go-ahead decision for a major steam-driven project called Meadow Creek to beyond 2023, and instead will concentrate on finding ways to extract more production from existing projects and expanding a development called Firebag, which has been operating for the past 16 years.

“We have more opportunity around increasing our production volumes faster and at a lower cost through our existing assets before we go and deploy some of this additional capital,” Mr. Little says. It will also allow the company to develop new technology to improve efficiency and lessen environmental impact by the time the project proceeds, he says.

Suncor’s Fort Hills project, completed two years ago, is co-owned by Teck and Total, and has a design capacity of 194,000 b/d. Its economics have been hampered by cost overruns and low oil prices, along with the curtailment. In its fourth-quarter 2019 results, Suncor announced a $2.8-billion impairment charge related to Fort Hills, blaming the impact of lower long-term heavy oil price forecasts.

Teck also took a hit on its Fort Hills interest in the form of a $900-million writedown, and Mr. Lindsay said last week that the stake could be on the block if returns don’t improve. “We would look at doing something to realize that value, whether it’s a spinoff or some sort of transaction,” he told analysts. “If we did that, then probably Frontier would go with it."

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Teck is not the first company to cancel plans for a major oil sands project after years of preparation. Companies have proposed, reconfigured and scrapped oil sands projects in all eras, for myriad reasons. Fort Hills was built on a lease once owned by Wichita, Kan.-based Koch Industries. Koch cancelled its plans for a project in 2003, blaming Canada’s ratification of the Kyoto protocol on greenhouse gas emissions.

Thirteen years later, the company – whose billionaire owners have been known for their opposition to U.S. carbon-reduction policies – withdrew an application for a smaller oil sands project called Muskwa. This time, it blamed Ms. Notley’s New Democratic Party government for instituting more stringent greenhouse gas policies. In 2019, it sold the remainder of its oil sands leases to a unit of Calgary-based Paramount Energy Ltd. for an undisclosed sum.

Suncor has been a major developer and acquisitor of oil sands assets, and its roots in the industry go back farthest as the developer of the first commercial mining project in the 1960s. Besides building Fort Hills and expanding its long-operated mines near Fort McMurray, the company bulked up its interest in Syncrude Canada Ltd. by acquiring the stakes of its partners in deals that began as the oil price collapse took hold in 2015.

Suncor has taken a hard look at plans and has changed course when the situation demanded. In 2013, under then-CEO Mr. Williams, it cancelled plans for an $11.6-billion upgrading plant called Voyageur. The facility would have transformed heavy bitumen from its oil sands operations into synthetic light, sweet crude that is a feedstock for conventional refineries.

Mr. Williams said the heavy capital outlay would make the massive plant uncompetitive against the growing volumes of light oil being pumped out of shale formations in the U.S. for a fraction of the cost per barrel.

Total, the French oil major, decided against proceeding with a 100,000-b/d project called Joslyn in 2014, and four years later sold the land to CNRL for $225-million. CNRL has applied to the Alberta Energy Regulator to incorporate it into its own massive Horizon oil sands project as an expansion.

In 2015, Royal Dutch Shell PLC scrapped two oil sands projects – the 80,000-b/d Carmon Creek steam-driven project and the 200,000-b/d Pierre River mine development. Shell blamed the collapse in oil prices and the squeeze on export pipeline capacity for its decisions. Two years later, Shell sold its Muskeg River mine to CNRL for US$8.5-billion.

There is still uncertainty over the fate of about 20 oil sands projects that have received regulatory approvals, but whose proponents have yet to decide whether they will plow the necessary capital into developing them. Some of the companies are small and will be unable to scrape up the money needed in the current environment. Others are large producers, such as Suncor and Cenovus, that have decided to spend their money on lower-cost options. Frontier was the only project with regulatory approval that included a mine.

Les Stelmach, senior vice-president and portfolio manager for Franklin Bissett Investment Management, is reluctant to declare the end of the megaproject. Certainly, in areas where the bitumen is close to the surface, mining is the most efficient way to extract it. However, it’s likely that producers will team up and even consolidate adjacent leases, as well as share processing facilities as a way to defray costs.

“Expanding projects, or scaling up with additional phases, allows that constant innovation to be incorporated more easily,” Mr. Stelmach says.

For Suncor, the main thrust today is coaxing the most of out its current assets - or “sweating them” - after the company spent billions to complete Fort Hills and the Hebron project in the North Atlantic. It was on this path regardless of Teck’s decision.

“We have a huge focus on that, and we see some real potential, both in our in situ assets, as well as Fort Hills, to increase the performance at a substantially lower cost than greenfield," Mr. Little said. “So, it evolves all the time.”