Skip to main content
The Globe and Mail
Support Quality Journalism
The Globe and Mail
First Access to Latest
Investment News
Collection of curated
e-books and guides
Inform your decisions via
Globe Investor Tools
Just$1.99
per week
for first 24 weeks

Enjoy unlimited digital access
Enjoy Unlimited Digital Access
Get full access to globeandmail.com
Just $1.99 per week for the first 24 weeks
Just $1.99 per week for the first 24 weeks
var select={root:".js-sub-pencil",control:".js-sub-pencil-control",open:"o-sub-pencil--open",closed:"o-sub-pencil--closed"},dom={},allowExpand=!0;function pencilInit(o){var e=arguments.length>1&&void 0!==arguments[1]&&arguments[1];select.root=o,dom.root=document.querySelector(select.root),dom.root&&(dom.control=document.querySelector(select.control),dom.control.addEventListener("click",onToggleClicked),setPanelState(e),window.addEventListener("scroll",onWindowScroll),dom.root.removeAttribute("hidden"))}function isPanelOpen(){return dom.root.classList.contains(select.open)}function setPanelState(o){dom.root.classList[o?"add":"remove"](select.open),dom.root.classList[o?"remove":"add"](select.closed),dom.control.setAttribute("aria-expanded",o)}function onToggleClicked(){var l=!isPanelOpen();setPanelState(l)}function onWindowScroll(){window.requestAnimationFrame(function() {var l=isPanelOpen(),n=0===(document.body.scrollTop||document.documentElement.scrollTop);n||l||!allowExpand?n&&l&&(allowExpand=!0,setPanelState(!1)):(allowExpand=!1,setPanelState(!0))});}pencilInit(".js-sub-pencil",!1); // via darwin-bg var slideIndex = 0; carousel(); function carousel() { var i; var x = document.getElementsByClassName("subs_valueprop"); for (i = 0; i < x.length; i++) { x[i].style.display = "none"; } slideIndex++; if (slideIndex> x.length) { slideIndex = 1; } x[slideIndex - 1].style.display = "block"; setTimeout(carousel, 2500); }

Oilfield pumpjacks, belonging to Vesta Energy, produce crude on wells in the Duvernay oil formation north of Red Deer, Alta., on Aug. 14, 2019.

Larry MacDougal/The Canadian Press

Canadian oil doesn’t stay put for long – at least, not in normal times. Four out of every five barrels produced in Canada are exported, most of them to the United States. But the pandemic has shifted global oil markets about as far away from normal as they’ve ever been, and the towering storage tanks that rise in clusters out of the Canadian Prairies are perilously close to full.

With global oil demand down by 30 per cent, owing to an estimated 60-per-cent decrease in driving and air passenger travel at just 5 per cent of prepandemic levels, the U.S. market is swimming in crude nobody needs or wants. Storage capacity from Houston to Cushing, Okla., the main U.S. oil hub, is filling up fast. Dozens of tankers are bobbing off the California coast, unable to unload their cargo – a stark picture of just how clogged North America’s oil infrastructure has become.

This past Monday, U.S. oil futures went negative for the first time ever, as holders of May contracts found themselves unable to sell them as their expiry dates approached. The topsy-turvy price reflected the risk they’d actually end up having to take delivery of physical crude at a time when there’s nowhere to put the stuff.

Story continues below advertisement

Canada’s situation is just as alarming. The country’s oil distribution and storage system wasn’t designed for such a sharp dive in demand. The Energy Information Administration (EIA) says Canadian oil exports to the U.S. have fallen at least 14 per cent from the start of 2020. Producers such as Saudi Arabia are filling supertankers to the brim, keeping it off the market until selling it is no longer a losing proposition. But the mostly landlocked Canadian industry doesn’t have that luxury.

And so a temporary home to store oil has, for now, become more sought-after than the product itself.

Canadian companies have so far cut production by 700,000 barrels a day (b/d). Husky Energy Inc. is down by about 80,000. ConocoPhillips is reducing output at its Surmont oil sands project by 100,000 b/d, and Athabasca Oil Corp. has shut off its 9,000 b/d Hangingstone oil sands project. Analysts and industry officials estimate between one million to two million barrels of daily production could be stopped entirely as storage facilities get close to full around mid-May. That would represent 20 per cent to 40 per cent of Canadian output.

“Producers just have to stop producing – whether they want to, whether they think they need to,” says Art Berman, a Houston-based energy analyst who has long studied oil markets in Canada and the U.S. “There simply won’t be any place to put the oil before very long.”

It isn’t as simple as flipping a switch, however – there are major technical and financial hurdles to ceasing or even just decreasing oil sands and other oil operations. Meanwhile, running out of storage space could create a previously unimaginable financial disaster.

“We’ve been dealing with volatility forever in this business. But it certainly feels like we’re dealing with unprecedented volatility,” says Ian Dundas, chief executive of Enerplus Corp., which has oil production in Canada and the U.S.

Since the crisis began, Enerplus has reduced its capital spending budget by about half and shut in some production on both sides of the border. Further cuts are possible, Mr. Dundas says. Producers will have to decide whether to reduce output based on regional oil prices, which reflect demand from refineries and available storage, and other factors – among them, production costs and corporate debt.

Story continues below advertisement

“You’ll test tank tops, but you won’t overflow. Where are we on that – three, four weeks away? We don’t really know. In North America, maybe a little bit before that," Mr. Dundas says.

“The response mechanism is pretty simple – producers shut in, and that’s happening in real time.”


It’s unclear how long it will take for U.S. storage to fill up entirely. Mr. Berman doesn’t think it’ll happen until August. RBC gives crude storage just three to six weeks.

Working commercial storage in the U.S. stands at about 653 million barrels, and by April 17, it was 60-per-cent full, according to the EIA, compared with 50 per cent in early March. The commercial numbers don’t include about 77 million barrels of spare capacity in the U.S. Strategic Petroleum Reserve, which U.S. President Donald Trump said in March could be filled “to the top” to help smaller producers suffering from the global oil price drop.

But not every bit of storage space is usable, since it has to be accessible from where the crude is produced, says Abhi Rajendran, the New York-based director of research at consultancy Energy Intelligence.

He says he believes the situation could be worse here, because Canada usually exports so much of what it produces. That means the country simply has less storage capacity. “When that whole system breaks down, it becomes pretty helter-skelter,” Mr. Rajendran says.

Story continues below advertisement

Working capacity for crude oil storage in Western Canada stands at about 40 million to 45 million barrels – roughly three-quarters of which is full, the Canadian Association of Petroleum Producers (CAPP) said this week. Storage use has been higher than normal in the past two years, as long-standing pipeline constraints have hampered producers’ ability to access markets. But facilities could now reach capacity “in just a matter of weeks," according to CAPP.

REGIONAL CRUDE OIL WORKING

STORAGE CAPACITY

(BARRELS)

ALTA.

84,900,000

B.C.

SASK.

MAN.

2,800,000

5,300,000

3,000,000

GULF COAST

CUSHING

370,666,000

76,093,000

EAST COAST

ROCKY

MOUNTAIN

WEST

COAST

22,413,000

MIDWEST

(INCLUDING

CUSHING, OKLA.)

62,487,000

25,321,000

172,561,000

U.S. working storage capacity as of September 30, 2019

THE GLOBE AND MAIL

REGIONAL CRUDE OIL WORKING STORAGE CAPACITY

(BARRELS)

ALTA.

84,900,000

B.C.

SASK.

MAN.

2,800,000

5,300,000

3,000,000

GULF COAST

CUSHING

370,666,000

76,093,000

EAST COAST

WEST

COAST

ROCKY

MOUNTAIN

22,413,000

MIDWEST

(INCLUDING

CUSHING, OKLA.)

62,487,000

25,321,000

172,561,000

U.S. working storage capacity as of September 30, 2019

THE GLOBE AND MAIL

BRITISH COLUMBIA

SASKATCHEWAN

MANITOBA

2,800,000

5,300,000

3,000,000

ALBERTA

REGIONAL

CRUDE OIL

WORKING

STORAGE

CAPACITY

(BARRELS)

84,900,000

GULF COAST

CUSHING,

370,666,000

OKLA.

76,093,000

EAST COAST

ROCKY MOUNTAIN

22,413,000

WEST COAST

25,321,000

62,487,000

MIDWEST

(INCLUDING CUSHING)

172,561,000

U.S. working storage capacity as of September 30, 2019

THE GLOBE AND MAIL

“The magnitude of the current collapse in refinery demand for oil has the potential to significantly increase storage requirements in Western Canada to unprecedented levels,” says Ben Brunnen, CAPP’s vice-president of fiscal and economic policy.

In the U.S., Reuters reports that beyond storing oil on tankers, refiners and traders are turning to more unusual tactics, such as putting crude and fuel in railcars and in unused pipelines. Even still, Mr. Brunnen doesn’t believe Canada will actually run out of physical space for oil.

“We can expect producers to be able to reduce production sufficiently if needed, as they are well aware of the depressed demand conditions and the storage constraints,” he says.

“Economic consequences, however, could be disastrous.”


The last time oil sands producers were forced to shut down in a major way was in 2016, as the wildfire known as “the Beast” devastated a massive chunk of northeastern Alberta, including significant parts of Fort McMurray.

Story continues below advertisement

Numerous operators either sharply reduced output or halted production altogether as a precaution against the inferno – among them Suncor Energy Inc., Syncrude Canada Ltd., Imperial Oil Ltd., Cenovus Energy Inc., CNOOC Ltd., Athabasca and ConocoPhillips. At the peak of the shutdowns – which in some cases lasted more than a month – more than a million barrels a day were offline. Several regional pipelines also shut down.

The situation bears little resemblance to today’s crisis. The 2016 outages occurred during an industry downturn, but they still served to lift global oil prices that spring, as demand elsewhere remained steady. As production gradually resumed, analysts estimated forgone revenue of up to $1.6-billion, representing about 30 million barrels of both raw bitumen and upgraded oil sands crude – a major hit to Alberta’s provincial budget.

But many producers were able to declare force majeure, a contract clause to remove liability for natural and unavoidable catastrophes. Oil and gas lawyer Brian Bidyk, a Calgary partner at McCarthy Tétrault, says they likely won’t have that option this time around, since they can still physically produce petroleum. “You’re just selling at a massive loss,” he says.

Besides, shutting down production requires a lot of hoop-jumping. Joint-venture partners, who might have vastly different financial circumstances or debt obligations, might disagree on the right time to shutter production. Some expenses, such as the contracted cost of shipping oil by pipelines, have to be paid whether oil is flowing or not.

The first supplies to be turned off have been those that fetch the lowest price and are cheapest to shut down – largely wells that pump conventional oil.

The oil sands are where things gets risky and expensive – from a technical perspective, shutting down production there is far from straightforward. Unlike mines, steam-assisted gravity drainage (SAGD) projects use steam to melt the bitumen so it can be pumped to the surface in wells. Companies that operate SAGD projects, such as Cenovus and MEG Energy Corp., can shut in production, but the longer they’re offline, the higher the chance of sustaining damage to underground reservoirs, limiting future rates. (Companies can extend shutdowns for a few months by injecting steam without producing oil, says Chris Cox, an analyst at Raymond James.)

Story continues below advertisement

With mining projects, such as those operated by Suncor and Imperial Oil, the complexity of a shutdown increases, as do costs. That’s because of the numerous processing systems used to extract bitumen from the oil sands and treat it so it can be shipped to market. The complexity increases for upgraded light sweet synthetic crude.

The supplies that remain online will be produced by companies with deals to supply refineries, which in the key U.S. Midwest market are already operating well under capacity.

Enerplus, for one, is somewhat insulated by its comparatively low debt level, its price hedging program, and an ability to quickly stop and restart output, especially in its North Dakota shale operations, Mr. Dundas says. The company says its Canadian operations, which involve injecting water deep underground to stimulate production, can probably be restarted without damaging reservoirs.

Others aren’t as fortunate.

“There’s no question in my mind that companies that were struggling coming into this will not get through it," Mr. Dundas says. “That’s actually healthy for the industry – more consolidation, I think, is healthy.”

Mr. Cox says there will be a number of producers “in pretty serious hardship, especially in areas where you physically can’t get oil to market. So pipeline operators will tell them, ‘We’re not going to accept your crude,’ and you’ll have nowhere to put it except for shutting it into the ground.”

Story continues below advertisement

As bitumen prices collapsed in March, Suncor reduced output at its Fort Hills oil sands project by a third. Don Lindsay, CEO of Teck Resources Ltd. – which has a 21.3-per-cent stake in Fort Hills – said early this week that Suncor and its partners are in discussion about their next moves as the market worsens.

Some of that discussion centres on how much it’ll cost to lower production further or shut the project down into next winter, should heavy oil prices remain well below break-even levels, Mr. Lindsay told analysts on a conference call.

“If you’re going to do that," he said, “you’d want to make sure that you were going to be shut down for a long enough period to justify that, versus sustaining operating losses on fewer barrels operating.”

Deep-pocketed players with access to credit will fare best through the worst of the shutdown. But the impact on Canada’s oil industry will linger long after oil starts flowing again at more normal volumes, with any expansion plans likely on hold.

“When they come out of this, they’re going to have more debt and a desire to have less debt than when they entered," Mr. Cox says. “That’s going to be a further drag, when you think about industry growth in production, industry employment. Even if this lasts for a couple months, it’s going to have side effects for a couple years.”


Enbridge Inc.'s storage facility in Hardisty, Alta., holds more than 10 million barrels of crude, making it the key hub in the country. It won’t reveal how full its tanks and salt caverns are, “given market sensitivities.” But the company better known for its pipelines says it’s trying to come up with storage and transportation solutions for its oil-producer customers.

Spokesman Jesse Semko says Enbridge is also having regular conversations with Ottawa and the Alberta government. But between regulatory approvals and permits, building new permanent storage would take a minimum of six months, and probably longer, he says.

Temporary storage using prebuilt production tanks is an option, Mr. Semko adds. "Depending on permitting requirements, those could take weeks to months to construct.”

Solutions can’t come fast enough for Alberta Energy Minister Sonya Savage. She says the province’s oil is sloshing near the top of storage tanks. “It’s dangerously close,” she says. “Even refined products are looking for storage, because refineries have over-produced. Every possible place is filling up.”

To help producers weather the pandemic, the federal government has announced $2.4-billion to help laid-off workers clean up orphaned oil and gas wells, plus a liquidity backstop for small and mid-sized energy companies through Business Development Bank and Export Development Canada.

At CAPP, Mr. Brunnen says those are positive first steps, but likely won’t be enough to keep many companies afloat. The industry, he says, needs about $27-billion in liquidity to the end of the year to address the negative cash-flow indications of the COVID crisis. “There’s still a need to address some of the mid-sized to large companies,” he says. “That remains a gap.”

Back in Houston, Mr. Berman believes market forces will be strong enough to halt production before storage capacity runs out. The way to avoid that most dire outcome, he says, will be to scale down production “to some absurdly low amount” or if there’s some increase in demand. More likely, it’ll be a combination of those two options.

But if storage in Canada and the U.S. hits capacity, oil production would have to drop to zero, Mr. Berman said.

A continent-wide shutdown, he notes, “has never happened before, in the history of the United States or Canada. That’s part of the reason I don’t believe it’s going to happen."

Then he adds, “But it could.”

Sign up for the Coronavirus Update newsletter to read the day’s essential coronavirus news, features and explainers written by Globe reporters and editors.

Report an error Editorial code of conduct
Due to technical reasons, we have temporarily removed commenting from our articles. We hope to have this fixed soon. Thank you for your patience. If you are looking to give feedback on our new site, please send it along to feedback@globeandmail.com. If you want to write a letter to the editor, please forward to letters@globeandmail.com.

Welcome to The Globe and Mail’s comment community. This is a space where subscribers can engage with each other and Globe staff. Non-subscribers can read and sort comments but will not be able to engage with them in any way. Click here to subscribe.

If you would like to write a letter to the editor, please forward it to letters@globeandmail.com. Readers can also interact with The Globe on Facebook and Twitter .

Welcome to The Globe and Mail’s comment community. This is a space where subscribers can engage with each other and Globe staff. Non-subscribers can read and sort comments but will not be able to engage with them in any way. Click here to subscribe.

If you would like to write a letter to the editor, please forward it to letters@globeandmail.com. Readers can also interact with The Globe on Facebook and Twitter .

Welcome to The Globe and Mail’s comment community. This is a space where subscribers can engage with each other and Globe staff.

We aim to create a safe and valuable space for discussion and debate. That means:

  • Treat others as you wish to be treated
  • Criticize ideas, not people
  • Stay on topic
  • Avoid the use of toxic and offensive language
  • Flag bad behaviour

Comments that violate our community guidelines will be removed.

Read our community guidelines here

Discussion loading ...

To view this site properly, enable cookies in your browser. Read our privacy policy to learn more.
How to enable cookies