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Sinking feeling in oil sands Oil prices, transportation problems, prospect of carbon tax force majors to pull back from projects; juniors weigh outright sales By GARY PARK For Petroleum News
The troubles piling up on the Alberta oil sands sector could soon turn into a full-blown crisis.
Six months ago the biggest thorn in the industry’s side was its inability to gain regulatory approval for pipelines to deliver landlocked crude bitumen to Eastern Canada, the Texas Gulf Coast and Asia, a problem that has become even more entrenched as transportation projects by TransCanada, Enbridge and Kinder Morgan face similar obstacles that could see any or all of them abandoned.
There is a growing consensus that there is little hope Enbridge’s Northern Gateway can overcome formidable resistance, while TransCanada’s chances of making a breakthrough with its Keystone XL project during President Barack Obama’s final two years in office are fading.
In addition, Kinder Morgan’s Trans Mountain expansion plan seems to get tripped up at every stage and TransCanada’s 1.1 million barrels per day Energy East proposal is rapidly being dragged into a regulatory bog.
Every bit as troublesome is evidence that the cost of extracting and processing oil sands bitumen has fallen drastically below the economic breakeven point, compounded by prospects that the Canadian and Alberta governments may finally cave in this year to demands for a carbon tax.
Suncor’s Fort Hills project As the outlook for crude prices worsens, the first domino to fall - other than moves by small operators such as Southern Pacific Resource and Laricina Energy to explore outright sales opportunities - could be the Suncor Energy-operated C$13.5 billion Fort Hills project.
Spending on the joint venture by Suncor, France’s Total and Teck Resources is scheduled to start peaking this year and next, unless the partnership decides that oil prices will make an unexpected recovery to the project’s estimated breakeven point of US$90, with Suncor calculating that US$95 oil would be needed to generate a 13 percent after-tax rate of return.
The corporate sanctioning of Fort Hills was announced in 2013 after five years of hesitation and careful planning to figure out ways to contain the costs of labor and materials.
Even when the green light was given the economic viability of the project was a matter of doubt, said Samir Kayande, an analyst at ITG Investment Research.
Now that Fort Hills is “really uneconomic” he suggested that the time may have come to shelve the plan, although other observers think it is more likely that the initial response would be to order a slowdown, rather than disbanding the work force entirely.
Chris Cox, a Raymond James analyst, said Fort Hills faces the greatest risk of any major oil sands project that is in the construction phase at a time when the economics are “pretty marginal” regardless of a strong oil price rebound.
Suncor says only that the company’s finances make allowances for long-life strategic projects to survive volatile commodity prices, giving no indication that the current timetable leading to completion of the 160,000 barrels per day first phase in 2018 (two years behind the earlier target) will be changed.
But Suncor has not hesitated to make dramatic moves in the past, notably in 2009 when it and Total stopped construction on their C$11.6 billion 200,000 bpd Voyageur upgrader plant when was about 25 percent completed.
Cenovus, Shell Cenovus Energy, the second largest oil sands producer behind Suncor, has set the supply costs for expansions of its Christina Lake and Foster Creek operations at C$40-C$50 per barrel.
The company has already suspended spending on its longer-range Telephone Lake and Narrows Lake projects, while indicating it has C$400 million-C$600 million in “discretionary capital” that could be removed at short notice from its 2015 budget of C$2.5 billion-C$2.7 billion.
Royal Dutch Shell has told employees to prepare for some layoffs and “adjustments to the organizational structure” affecting the 3,000 employees at its Albian Sands mining project, but insisted that even if oil prices had remained stable it would still be evaluating its oil sands business.
A year ago the company stopped work on its proposed 200,000 bpd Pierre River oil sands mine to reconsider the timing of various asset developments.
Price, climate challenges Business Monitor International said in a report Jan. 8 that it expects oil to trade at US$45-US$60 a barrel this year, within the range it said is “disastrous for production in several regions,” including the oil sands, Permian basin and the Bakken.
On the climate front, the oil sands face an even longer-term challenge, with a new study by the journal Nature arguing that most of Canada’s oil sands resources and Arctic fossil fuels would have to remain in the ground if the world gets serious about pledges in the 2009 Copenhagen Accord to reign in global temperatures.
The study estimated that 75 percent of Canadian oil reserves and 85 percent of its oil sands bitumen would be “unburnable” before 2050.
Co-author Paul Ekins, deputy director of the United Kingdom Energy Research Center, said unless some “whizo technology” emerges to economically and safely exploit Arctic oil and gas it too should be left in the ground.
“I think the most sobering thing from this study is the gulf that it reveals between the declared intention of politicians and policy-makers to stick to (their target of a 2-degree Celsius reduction in average global temperatures) and their willingness to actually contemplate what needs to be done if that is to be even remotely achieved,” he said. Economically recoverable slashed Alberta’s oil sands reserves are estimated to be economically recoverable at 168 billion barrels, with hundreds of billions of barrels more available for extraction depending on future oil prices.
The study slashed those reserves to 48 billion barrels while issuing a dire warning that they could be further reduced to 7.5 billion barrels as part of a global allotment of fossil-fuel use in a 2-degree Celsius scenario.
In its examination of other fossil fuels, the study concluded that most of the coal reserves in China, Russia and the United States would remain unused along with more than 260 billion barrels of oil reserves in the Middle East, which is equivalent to all of the reserves estimated to be held by Saudi Arabia.
In a separate study, the consulting firm of Wood Mackenzie said C$59 billion worth of Canadian oil and natural gas projects could be deferred in the next three years as the collapse in capital investment globally replayed the grim days of 1999 and 2009.
Mark Oberstoetter, the firm’s lead upstream research analyst, said that could affect decisions on 16 oil sands phases.
The consultancy expects Canadian work valued C$12 billion will be stalled this year, followed by C$20 billion in 2016 and C$27 billion in 2017 - curtailing 600,000 bpd of incremental production - unless there is a startling recovery in oil prices.
Calgary-based investment bank Peters & Co. forecasts Canadian producers will generate US$53 billion of cash flow in 2015 (the lowest return since 2009), prompting producers to become “increasingly conservative towards their capital spending plans.” Carbon tax The pressure on the Canadian and Alberta governments to end their resistance to a carbon tax stems from estimates by Environment Canada that there is little hope of achieving the commitment to limit greenhouse gas emissions to 611 million metric tons by 2020.
Without drastic measures, the federal government department projects those emissions will range from 727 million to 857 million metric tons.
Prime Minister Stephen Harper said a month ago that it “would be crazy economic policy” to apply unilateral penalties on the oil industry,
Regardless of that, he is under pressure to introduce penalties in an environmental policy he is expected to announce before the federal election scheduled for October.
But there is a growing school of thought that the rest of Canada should simply adopt the carbon tax introduced by British Columbia in 2008, which collects 6.67 cents per liter of gasoline.
As a result, from 2008 to 2012 per capita consumption of fuels subject to the tax dropped 17 percent in British Columbia, while rising 1.5 percent elsewhere in Canada.
The Canadian petroleum industry, especially oil sands players, have remained right-lipped about their willingness to consider such a move, not least at a time of spreading unease in the sector.
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