CALGARY, Alberta (Reuters) - The U.S. shale oil revolution is forcing Canada’s oil sands industry to question whether there is a future in processing its crude into lighter oil, a tried-and-true way of wringing the most money out of a resource considered crucial to the country’s prosperity.
Suncor Energy Inc (SU.TO), which nearly 50 years ago pioneered the practice in Canada of mining and then upgrading the oil sands bitumen into refinery-ready light crude at the same site, served notice this month that the era of the integrated project may be ending.
It said it was reexamining a plan to build a multibillion-dollar upgrading plant in northern Alberta and taking a C$1.5 billion ($1.5 billion) charge to account for lower projected cash flow. The reason: cheap oil from North Dakota and elsewhere is making it uneconomical over the long haul to build such complexes.
“Why would you spend billions of dollars to build an upgrader to create a product that is looking to be oversupplied in the markets you can access today?” said Jackie Forrest, director of global oil for consultancy IHS CERA.
The Suncor move is more evidence of a shift from upgrading that is already well underway. Imperial Oil Ltd (IMO.TO), for example, is building the C$12.9 billion Kearl development - the next major oil sands project to come online - without a processing plant.
Once considered a sure winner by most Canadians, the oil sands industry is now on the defensive on several fronts, struggling to prove it can deliver its raw materials to refiners at a competitive price and at an acceptable environmental cost
The dilemma over upgrading points to more problems ahead as oil sands producers compete for capital against the developers of the cheaper, less damaging shale oil.
With less-processed heavy oil competing with the increased Bakken flows for pipeline space to U.S. refineries, a glut in Western Canada has built up, generating a wide discount on Canadian crude against benchmark West Texas Intermediate. That has created an immediate problem, not the least for Alberta, the province at the center of Canada’s oil industry.
Alberta Premier Alison Redford blames the so-called “bitumen bubble” for a forecast C$6 billion shortfall in revenues in the coming fiscal year. Deep budget cuts are in the offing.
As a result, the province is pushing for ways to shore up its budget against the falling revenue stream, while unions are calling for more upgrading to create jobs.
The industry, however, seems to be moving in the opposite direction. The problem is, building a new upgrader - a tangle of pipes and vessels that transforms raw bitumen into an oil product easily used by standard refineries - costs billions of dollars and may make little sense over the long term.
In the short term, on-site processing would allow producers to boost the price of their product by upgrading it, and the wide price spread between cheap heavy oil and more expensive light crude would mean hefty margins.
Indeed, the gap has recently ballooned to more than $40 a barrel under U.S. benchmark West Texas Intermediate, compared with a historical differential of less than $20.
But it takes years to build upgrading plants. In the meantime, new pipelines to export markets are expected to be built over the next decade - whether they are big ones such as TransCanada Corp’s (TRP.TO) Keystone XL pipeline or incremental expansions.
If that happens the discount on heavy oil should shrink. That would leave the multibillion-dollar upgrading plants less able to compete with shale oil.
To be sure, the Keystone XL project - connecting the oil sands with the U.S. Gulf Coast - is facing a full-scale push back from U.S. environmental groups, and final approval from Washington is not guaranteed.
If the pipeline gets built, it would move 830,000 barrels a day of Alberta crude to Texas refineries, many of which are configured to process the heavier grades that are now imported from Venezuela, Mexico and elsewhere.
On today’s pipeline network, it costs about $8.50 a barrel to ship crude to the U.S. Gulf region from Alberta, traders say. When new pipelines are built, the light-heavy oil price spread is expected to come close to the shipping cost.
“You expect those bottlenecks will be gone, and once we get global pricing, we’ve actually seen fairly narrow differences between light and heavy crude,” said IHS’s Forrest.
Against that backdrop, Suncor says it hasn’t made a final decision on the proposed Voyageur upgrader, the centerpiece of its expansion strategy.
“We’re looking at all options,” Chief Executive Steve Williams said this month. “At one extreme you could go ahead with the project as it is. At the other extreme you could cancel the whole project and go ahead with nothing.”
Williams fingered the U.S. shale boom as the main reason for the indecision, as oil coaxed to the surface using hydraulic fracturing does not need expensive upgrading to be run in standard refineries.
Oil production in North Dakota has jumped to 730,000 bpd today from just over 100,000 bpd in 2006, making it the No. 2 oil-producing state after Texas. Large volumes of that crude is transported on the same pipelines as the Alberta oil, contributing to the disappearing spare capacity.
In the past year, both Bakken oil and upgraded light synthetic crude, which have similar specs, have climbed in tandem to around par with WTI, from around $13 a barrel below.
A recent PriceWaterhouseCoopers study said shale oil is likely to make the largest single contribution to total U.S. oil output growth by 2020, and that increased global shale output could lead to lower crude prices than are currently projected.
Those barrels have begun to replace some heavy crude in the U.S. market, squeezing the economics on upgrading plants that would pump out products to compete, said Reynold Tatzlaff, PwC’s Canadian energy leader.
That’s not to say upgrading is dead. Existing plants pump out more than 1 million barrels of light synthetic crude a day. Privately held North West Upgrading Inc and Canadian Natural Resources Ltd (CNQ.TO) are proceeding with a C$5.7 billion stand-alone upgrader and refinery near Edmonton.
But the North West plant will get help from a steady supply of bitumen from the Alberta government as part of an initiative to generate more valued-added dollars. Expansions, such as one that Canadian Natural is planning at its Horizon oil sands project, come cheaper than starting from scratch, though it is not rushing to start the project.
Mike Deising, a spokesman for Alberta Energy Minister Ken Hughes, said he could not comment on various companies eschewing upgraders, saying they all employ different forecasts.
In another trend working against upgrading, oil sands mining is giving way to less-centralized steam-driven production methods, which are less costly to expand and which can ship diluted bitumen directly into the market. Several U.S. refineries have been retooled to run more of the heavy crude.
Meanwhile, notorious construction cost overruns and a string of outages at existing upgraders have raised questions about reliability of returns and operations.
For more than a decade, most tar sands projects in Alberta blew well through their budgets as the rush to develop the resources stretched Alberta’s skilled labor pool thin. Companies sought to bolster manpower by importing workers from around the world, and the rush to develop drove up the costs of steel, other materials and equipment.
Several plants proposed before the 2008-2009 financial crisis were canceled, as credit dried up.
“It’s been the perception that any and nearly all upgraders have been plagued with fires, maintenance issues, cold weather issues. They’re expensive to run, and even more so, they’re expensive to build,” said Wood Mackenzie analyst Mark Oberstoetter.
Editing by Frank McGurty, Janet Guttsman and Bob Burgdorfer