For years, Alberta's deposits of tarry bitumen attracted billions in investment from the world's oil giants. The vast resource was sold to investors as North America's Saudi Arabia, home to more than half of global oil reserves not controlled by sovereign governments.

Those days are gone.

Today, the sector is reeling amid a price shock that has sapped billions from corporate budgets and forced a dramatic rethink about the companies' role in global energy markets.

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By one estimate, as much as 1.2 million barrels per day of future production capacity has been put on hold since the downturn began last summer, representing tens of billions of dollars' worth of squelched investment.

Some analysts say only a fraction of it will be resurrected, as companies grow apprehensive about reviving costly blueprints in the face of rapidly shifting patterns of supply and demand, stubbornly high costs and persistent export constraints.

At the same time, the oil sands have lost ground as new technologies uncork a flood of cheaper shale oil in the United States and OPEC kingpin Saudi Arabia keeps pumping record volumes of low-cost crude, exacerbating a global glut.

"The fundamental issue is the competitive environment has changed drastically over the last five years," said Samir Kayande, analyst at ITG Investment Research in Calgary.

"The analogy that I think is appropriate is basically like tech. In the last few years, a new technology has emerged, and so the incumbents who have made good money in the past doing things the old way are the ones who are threatened. And it's really the upstarts who have the potential for being the large, significant players in the future."

The shift has far-reaching implications. For Alberta, it points to a cooling market for everything from labour to construction materials, a sharp reversal that stands to bolster oil-sands returns after years of escalating costs and project delays.

Over the long-term, analysts say, a slimmer production outlook will ease demand for multibillion-dollar pipelines designed to transport ever-increasing volumes of crude to Canada's coasts, potentially delaying projects such as Enbridge Inc.'s Northern Gateway or TransCanada Corp.'s Energy East well into next decade.

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To be sure, companies are still pumping vast sums into the oil sands. There are questions, too, about the long-term viability of shale production, which requires constant investment to offset steep production decline rates. Oil prices have also steadied above $60 (U.S.) a barrel in recent weeks, fuelling hopes of a tentative recovery.

But the price collapse since last summer has jolted confidence in northern Alberta, accelerating a slowdown analysts say has been building for years as investment in U.S. shale oil gathered momentum and major companies focus on boosting shareholder returns over hosing money at megaprojects.

Investment in the oil sands this year is expected to fall by about a quarter from levels a year ago, to $25-billion (Canadian), according to industry forecasts. Led by the oil sands, sector-wide cash flow after taxes is expected to plunge by two-thirds to $21.5-billion, according to ARC Financial Corp.

Some of the world's largest oil companies are suddenly cautious, balking at future investments as spending winds down on expansions that have been in the works for years. Others, such as ConocoPhillips Co., have sold down their holdings.

Imperial Oil Ltd. said spending in the first three months of the year fell by 15 per cent, or roughly $200-million from a year ago as work on its $2-billion (U.S.) Nabiye project and a multibillion-dollar expansion of its Kearl mine neared completion. No decisions have been made on the next project on the company's radar, a $7-billion (Canadian) development called Aspen.

"It's that next phase of growth that will really be the question for us in whatever business environment we're facing in the years ahead," chief executive Rich Kruger said in April. Imperial is majority controlled by Exxon Mobil Corp.

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Such caution reflects, in part, the industry's ongoing struggle to claw back costs – a perennial concern that led Total SA of France and Norway's Statoil ASA to mothball projects long before oil prices hit the skids last year.

Estimates vary, but some industry watchers expect the break-even cost of wringing oil from Alberta's sands could fall by as much as 15 per cent as the sector's supply chain adjusts to lower prices. Suncor Energy Inc. said in April its cash operating costs fell sharply in the first quarter, by as much as 20 per cent, and that it expects to capture further savings over time.

Still, the industry is to a large degree playing catch up. "There are a lot of inefficiencies in the system that don't get corrected as quickly as they do for tight oil developments," said Chris Cox, analyst at Raymond James Ltd. in Calgary.

"You don't realize 20- to 30-per-cent cost savings within a year, like we're seeing right now for the cost of drilling wells in the U.S."

Indeed, Royal Dutch Shell PLC now expects to start pumping oil from its Carmon Creek oil-sands project in 2019, two years later than initially planned. The delay comes after the company scrapped plans for a 200,000-barrel-a-day mining venture and shows even lower-cost projects are under the microscope.

Such moves add up to an abrupt gear change for a region once considered a key driver of North American production growth, with some now predicting output will flatline at about 3 million barrels per day by the end of the decade – well short of bullish forecasts made before the advent of shale technologies.

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"I think from a broader perspective, the oil sands are once again very marginal in terms of rate-of-return," Mr. Cox said.

That means newer projects will increasingly have to match the economics of U.S. tight oil, which has rapidly undermined one of the historic advantages of oil sands.

"It's not the size that matters," ITG's Mr. Kayande said. "The companies that win are the ones that can deploy capital competitively."