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Oil sands ready to take flight Raymond James report says Alberta oil sands will attract C$178 billion over next 10 years; add 2.6 million bpd to production Gary Park For Petroleum News
The Alberta oil sands will accumulate new capital expenditure of C$178 billion over the next 10 years — despite sluggish growth in the first three years of the decade — and 2.6 million barrels per day of incremental production, raising the total to 4 million bpd, predicts financial services consultant Raymond James.
The company’s report, co-written by Justin Bouchard of RJ Ltd’s energy group in Calgary, said the initial pace will be slowed because of project delays during the 2008-09 commodity downturn.
But the assessment was emphatic that the oil sands are “back in fashion … after a temporary hiatus away from the market’s spotlight.”
It said a number of companies have resumed or pushed forward with development plans — a trend it expects to continue through 2010, while oil sands merger and acquisition activity, as reflected by Sinopec’s pending C$4.65 billion purchase of ConocoPhillips’ 9.03 percent stake in Syncrude Canada, demonstrates that “outside interest in the oil sands remains robust.”
Raymond James singled out three projects among many announcements of expansions or go-aheads for new projects: Devon Energy’s doubling of output from Jackfish Phase 2 to 70,000 bpd by 2012; ConocoPhillips’ and Total’s ramping up to 110,000 bpd from 27,000 bpd by 2015 at their joint-venture Surmont Phase 2; and Phase 1 of the Husky Energy-BP joint-venture at Sunrise, targeting output of 60,000 bpd in 2014.
The forecasts are tied partly to the company’s own West Texas Intermediate price forecast of US$82 per barrel in 2010, US$95 in 2011 and US$100 in 2012 and beyond.
Two categories of projects In comparing the two distinct categories of oil sands projects — mining and in-situ — Raymond James estimated the breakeven costs at the typical in-situ operation (whether steam-assisted gravity drainage or cyclic steam stimulation) is US$55 per barrel for WTI crude and US$70 per barrel for mining projects. That is based on the company’s long-term natural gas price forecast of C$6 per thousand cubic feet.
The report favored in-situ projects, despite “some level of resource risk,” partly because of the smaller environmental footprint, but it said that investing in in-situ opportunities makes it essential to “gauge the quality of the asset and to invest with an experienced operational team.”
On the other hand, mining projects “do not carry as much risk in terms of recovery, because the recovery techniques are far more basic, and resource homogeneity is not as significant an issue as it is with in-situ development.”
The report identified inflationary pressures and environmental regulation as the chief barriers to “an even more aggressive push into oil sands development.”
It noted that during the heyday of development, inflation was so out of control that many projects experienced cost overruns of 100 percent and more.
For that reason “it is not surprising that every oil sands project announced since the downturn has been an in-situ project,” Raymond James said.
“Not only do these projects offer lower capital intensities, but they are also less exposed to inflationary pressures, largely due to a smaller portion of spending attributable to labor costs,” the report said.
It said the concern over environmental regulation relates to “the magnitude of future regulatory impact, rather than speculation over whether policy actions will be taken,” especially revolving around what the United States will do on the carbon front, given that the Canadian government has said it will follow the U.S. lead.
The report said California’s low carbon fuel standard, which is being pondered by 11 other states, restricts the carbon intensity of transportation fuel, inherently affecting the oil sands more than conventionally produced oil.
For the time being, however, Raymond James said the substantive effect of U.S. state-level regulation is immaterial for oil sands development, although it must be closely followed.
Conclusions echoed The conclusions in the report were effectively echoed at an April oil conference in Calgary, when Nicholas Olds, incoming vice president of oil sands at ConocoPhillips, said his firm remains committed to the resource despite its asset sale to Sinopec, which he said “is no reflection of a strategic shift from the oil sands.”
David McColl, the Canadian Energy Research Institute’s research director, said the ConocoPhillips-Sinopec deal puts Canada about two-thirds of the way towards a banner M&A year (without including last year’s C$20 billion Suncor Energy takeover of Petro-Canada in the comparison).
He said 2010 could be the year of megadeals, especially in the oil sands, with the Sinopec deal showing there is plenty of interest from foreign buyers in the oil sands and raising hopes for a pipeline to the British Columbia coast to open up new markets in Asia.
Even so, McColl said it makes more financial sense to export oil sands crude to the United States.
“You could say it makes sense to build a pipeline, export the product and suddenly we are no longer reliant on a single market,” he said. “But is 200,000 or 500,000 bpd out of 2, 3 or 4 million bpd going to make a big difference, or make us more diverse? It could happen, but probably isn’t going to in the long run.”
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