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C$45 billion on the shelf Norwegian oil giant deals another blow to Alberta upgrading dreams; withdraws plans for Alberta facility, looks at options in US Gary Park For Petroleum News
There’s another wooden cross on the road to the Alberta oil sands, marking billions of dollars more of lost investment.
It also marks a further setback to the Alberta’s government’s goal of keeping upgraders within its borders to benefit from the value-added end of turning bitumen into synthetic crude for refining into fuel products.
StatoilHydro joined a rapidly extending list of oil sands developers who have scrapped upgrader plans, bringing the value of delayed or deferred upgraders to at least C$45 billion. The Norwegian cited a familiar list of reasons — “prohibitive construction costs, the state of the global economy, an uncertain oil price outlook at the lack of regulatory clarity (relating to greenhouse gas emissions).”
In the process it is exploring other options, including processing arrangements with refiners in the United States, where the cost of turning bitumen into gasoline or diesel are lower and refiners are anxious to replace shrinking heavy oil imports from Mexico or Venezuela.
“These are changed circumstances and we are not unlike other companies,” said StatoilHydro Senior Vice President Bob Skinner. “Clearly, the oil sands do not look the same today at $45 (per barrel oil) as they did when the price was $115 a year ago.”
Initial phase pegged at C$4B He said his company decided to withdraw an application before Alberta regulators because approval of a permit in 2009 would have required a construction start in 2012. It announced six months ago that the facility was being delayed by two years.
In addition, Skinner said StatoilHydro did not want to tie up the regulatory process with a frivolous proposal.
StatoilHydro said earlier this year the initial phase of the planned upgrader would have been about C$4 billion — a figure it has not since revised other than to say the cost is higher — at a cost of C$40,000-$60,000 per flowing barrel and might have climbed to C$16 billion at peak capacity of 220,000 barrels per day.
StatoilHydro’s Canadian President Geir Jossang said the company will “continue to monitor the cost and price environment and reassess downstream options going forward.” But he said the decision does not put an end to his company’s goal of eventually producing 200,000 bpd from its Leismer lease, which was part of a C$2.2 billion takeover of closely-held North American Oil Sands Corp. last year.
“StatoilHydro’s long-term view of the Canadian oil sands development remains unchanged,” he said, although he did emphasize that StatoilHydro will “take another look at everything, including the concept and technology of the upgrader, if and when we decide to bring the project back to life.”
In-situ project under way The company is already building a 10,000 bpd first half of an in-situ project which is scheduled to yield its first bitumen by late 2010 and has applied for regulatory approval to double that output in 2012, Skinner said.
He said the company still hopes production from all of its oil sands leases will exceed 200,000 bpd by the early 2020s, although that is not a fixed timetable.
“If oil prices remain low for a long time it becomes problematic whether you could proceed with plans that were developed when oil prices were double what they are now,” he said.
As well, he said the costs have not been conducive to moving ahead with a fully integrated project, including an upgrader.
Steven Paget, an analyst with FirstEnergy Capital, said there is a trend by companies to back away from plans for upgraders in Alberta, partly because of lower labor costs and growing pipeline access to competing refineries in the U.S. Gulf Coast.
He noted that TransCanada has shipping commitments of 500,000 bpd for its Keystone pipeline which is “an awful lot of upgrading flowing down that line.”
David Pryce, vice president of Western Canadian operations for the Canadian Association of Petroleum Producers, said there are many risk factors that are cumulative for companies weighing major investments in Alberta and “they’re increasing the overall uncertainty.”
The list of projects that have been delayed or abandoned in the past few weeks involve plans by Shell Canada, Petro-Canada (with two minority partners), Suncor Energy, a Nexen-OPTI Canada joint-venture, Total and BA Energy.
Jossang told the Calgary Herald that project financing was not the determining factor.
“I think we are just doing what everyone else is doing in the business right now,” he said. “We are looking at ways to make sure we maintain our financial flexibility and that means we are trying to take down short-term investments and defer things we need not necessarily decide to go ahead with right now.”
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