Plunging oil prices have slowed costly project to tap Canada's huge energy reserves, adding to concerns of a dramatic oil-price spike when the economy recovers.

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FORT McMURRAY, Alberta —

Bitumen has been mined in Alberta since 1967, though for a long time it wasn’t considered profitable. It wasn’t even considered oil.

“We were kind of a curiosity,” said Don Thompson, head of the Oil Sands Developers Group, based in Fort McMurray.

All that changed when oil companies devised better ways to recover this sticky type of oil. High crude prices and an increasingly hostile international environment for oil exploration also provided a boost.

Now the oil sands are home to some of the biggest construction projects in history, and they provide the bulk of Canada’s massive energy reserves.

But a recent downturn in prices, provoked by the financial crisis, has some oil companies reining in plans to invest additional billions of dollars in their Alberta fields.

Last month, Royal Dutch Shell said it was postponing any decision on further expanding the Albian Sands Energy project beyond the near-doubling now under way.

The company will “wait for costs to come down before making any further investment decisions,” Shell Chief Executive Jeroen van der Veer told investors in a conference call.

Critics who see the oil sands as a carbon-dioxide-spewing environmental menace have long pressed for a slowdown in the frenetic pace of development there. But industry experts fear that a slowdown in oil-sands development — at a moment when no other major oil reservoirs are being found elsewhere in the world — could provoke a worse spike in oil prices when global economic growth resumes.

The International Energy Agency, an organization of petroleum-consuming countries, says more than $1 trillion a year must be invested in energy sources if the world is to meet projected demand in 2030.

More and more of the world’s oil reserves are in the hands of national oil companies, some of which don’t have the technical prowess or the political will to develop new fields, the Paris-based agency said in mid-November.

It warned that delayed spending could be “setting up a supply crunch that could choke economic recovery.”

Ultimately, though, a slowdown could lead to falling construction costs, setting the stage for a renewed boom in the oil sands.

“People will have more realistic expectations of costs, prices and profits,” said Fadel Gheit, a New York oil analyst with Oppenheimer & Co.

The promised oil patch

International oil behemoths Shell and Chevron waited decades to jump heavily into Alberta’s oil sands, finding easier-to-extract oil elsewhere.

In 1999, the companies teamed up with Calgary-based Western Oil Sands to build the Albian Sands project, the first oil-sands mine built since the 1970s. Last year, Houston-based giant Marathon bought Western Oil Sands amid a push to acquire new reserves.

When the influential Oil and Gas Journal in 2003 finally recognized the oil sands as a repository like others, its tally of Canada’s oil reserves skyrocketed. Oil sands account for 173 billion barrels of Canada’s 179 billion barrels of reserves.

The price of crude also began to rise in 2003, while nationalistic regimes in oil-rich countries like Russia and Venezuela limited foreign oil companies’ access to new reserves.

Producers flocked to Alberta like they never had before, and not only from traditional oil hubs in the U.S. or Britain. PetroChina, a Chinese state oil firm, tried to buy Canadian operator Husky Energy in 2005.

In 2008, these companies invested about $20 billion in new or expanded operations here.

There are 87 oil-sands projects running in Alberta, including three mines and dozens of drilling operations, according to the provincial government. A fourth mine is scheduled for startup by year-end.

Unlike oil regions such as the Gulf of Mexico, where companies could spend hundreds of millions of dollars drilling dry holes, finding pay dirt in the oil sands has been as easy as looking down.

“There’s zero exploration risk; it’s all economic risk for pay and cost,” Gheit said.

Demand raises costs

But the oil-sands development frenzy coincided with a construction boom in China and other rapidly developing countries, which greatly increased the costs of material and labor — and the risk a project won’t pencil out.

In 2001, it cost industry pioneer Suncor Energy about $3.3 billion to expand its mine to churn an extra 100,000 barrels per day of bitumen.

In late September, Greg Stringham, president of the Canadian Association of Petroleum Producers, said the same project would cost $10 billion to $17 billion.

Projects built early on have become extremely profitable. In 2007, Suncor spent about $28 to extract a barrel of oil — when the annual average price of crude futures on the New York Mercantile Exchange was $72 per barrel.

But break-even prices for new projects vary from $70 to $80 a barrel, said David Hobbs, an analyst with Cambridge Energy Research Associates.

Oil prices have fallen well below that point — crude closed at $54.43 on Friday — as the global economic downturn reduced demand, prompting many oil-sands developers to hit the brakes.

Tighter credit markets also make it difficult for some companies to borrow money for capital investment.

One big producer, Petro-Canada, said last week it would put construction of an upgrader in Edmonton on hold because of falling oil prices.

“We’re facing a lot of uncertainty in the financial markets,” said Petro-Canada senior vice president, Neil Camarta.

Suncor Energy said in late October it will postpone the completion of a planned upgrader — a $12 billion venture — by about a year.

But some producers are looking forward to catching their breath after half a decade of trying to catch up with soaring development costs.

“I think the pendulum is just swinging,” Suncor Energy CEO Rick George said in a conference call.

Oil companies must also plan for another set of costs looming in the horizon: managing their carbon emissions, either by paying taxes or devising ways to curb them.

That could add $6 to $9 per barrel, lifting total production costs to $40 to $45 per barrel, said a recent Rand report.

Even then, said the report, synthetic crude from Alberta “seems likely to be economically competitive with conventional petroleum unless future oil prices are relatively low.”

Ángel González: 206-515-5644 or