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Takeover tidal wave on the way Global strategist bets U.S. securities regulator will ease oil sands reserve rules, freeing U.S. companies to buy existing Alberta sands operators Gary Park Petroleum News Canadian Correspondent
The U.S. Securities and Exchange Commission will relax its rules on what constitutes proved oil reserves, freeing major oil companies to embark on a buying binge in the Alberta oil sands, predicts a leading North American analyst.
Added momentum could come from the International Monetary Fund adopting a broader definition of measuring the bitumen deposits, boosting Canada’s oil reserves to two or three times those of Saudi Arabia, he said.
Donald Coxe, chairman and global portfolio strategist for Chicago-based Harris Investment Management and chief strategist for the Bank of Montreal, said Aug. 5 he is counting on the SEC changing rules that are more than 30 years old and opening the door to a flurry of acquisitions.
He told a conference call he believes the result will be a “disappearance” of publicly traded companies operating in the oil sands “once the SEC comes out with its rulings.
“I believe Big Oil is going to want to go (into the oil sands) and buy these companies.” Oil sands bandwagon rolling In a week when U.S. energy giant Kinder Morgan made a stunning C$6.9 billion bid for Vancouver-based Terasen followed a day later by the C$1.35 billion takeover of Deer Creek Energy by France’s Total, plenty of other energy executives and analysts climbed on the oil sands bandwagon.
John Mawdsley, senior vice president with brokerage firm Raymond James, issued a new report forecasting that the oil sands resource will deliver a “wall of profit” over the next several decades.
He said the northern Alberta deposits will eventually push Canada to third place in world oil production after Saudi Arabia and Russia.
To bolster his argument, Mawdsley noted that Suncor Energy’s C$3.4 billion Millennium expansion paid off its capital costs within two years of coming on stream, regardless of a C$1.4 billion cost overrun and is now generating “massive amounts of cash flow which will fund future expansions.”
His 128-page report said Canada is one of the few non-OPEC countries positioned to increase its oil output from reserves that are currently booked at 175 billion barrels and likely to increase.
Within 10 years, Canada’s production will trail only Saudi Arabia among all OPEC members, he said.
To underscore the attraction of the oil sands, he said a project costing C$350 million and producing 25,000 barrels per day would generate after-tax returns in the low 20 percent range over 25 years if West Texas Intermediate prices remained above US$40 per barrel. At US$60 per barrel, the profits would climb to the 25-309 percent range.
Even high prices for natural gas, needed for some extraction and processing operations, is not likely to undo the promise of the oil sands, Mawdsley said.
He said a barrel of synthetic crude that sells for US$60 per barrel can be profitably produced if gas costs US$10 per thousand cubic feet.
Mawdsley’s overall forecast projects that synthetic crude volumes will quadruple to 4 million bpd by 2020 and could eventually satisfy 25 percent of North America’s consumption.
Commenting on the Kinder Morgan-Terasen deal, Matthew Akman, a CIBC analyst, said in a note to clients that energy infrastructure growth in the United States is “limited because U.S. oil and gas production has peaked. Canada offers attractive energy production growth that attracts U.S. players.” Oil sands companies will be seized Deer Creek President and Chief Executive Officer Glen Schmidt said the expectation of long-term oil prices has prompted large companies such as Total to rapidly change their view of the oil sands, which were considered an overly expensive, fringe resource only two years ago.
He said the old yardstick is no longer an accurate instrument to measure “what’s happening today and in the future.”
For Coxe, there is little doubt that companies with existing oil sands operations, such as Suncor, Canadian Oil Sands Trust and Western Oil Sands, will be seized, despite the growth in their market values.
“The wealth of the oil companies has also grown by leaps and bounds,” he said, while cautioning investors not to buy equity in hopes of pocketing a large gain from a takeover.
Existing SEC rules prevent large chunks of oil sands holdings from being booked as reserves and would, in fact, limit Alberta’s bitumen resource to just 12 billion barrels, not the 175 billion barrels that are increasingly accepted by various authorities, including the Oil & Gas Journal.
Instead the SEC only assigns reserves once a company has built a facility to extract bitumen, in what Coxe describes as a “legal and accounting technicality.”
As well, the regulator requires companies to estimate their reserves based on prices at Dec. 31 each year, resulting in a writedown of hundreds of millions of barrels because it coincided with a slump to uneconomic heavy oil prices.
As one example, Husky Energy was forced to delete 39 percent of its heavy crude reserves, which were trading at US$12.27 per barrel on Dec. 31 against an average price for 2004 of US$28.75, while synthetic crude or upgraded heavy oil was trading at almost US$50.
In fact, by Jan. 10 this year the price of Lloydminster heavy crude was US$21.56, sufficient for Husky to return 98 percent of the of the reserves subtracted by negative revision to the proved reserve category.
That was an extreme version of the usual winter-time dip in heavy crude, which rebounds along with demand during the road-building season. SEC asked to reconsider approach Coxe said Cambridge Energy Research Associates sent a brief to the SEC, asking the commission to reconsider its approach to distinguishing proved from probable reserves and arguing that reserves that were highly profitable shouldn’t be immediately worthless.
CERA said companies should be allowed to include probable reserves in addition to proved reserves.
Coxe said in a March report that oil sands pioneers — Suncor and Syncrude Canada — struggled for decades to produce oil consistently at a cash cost of less than US$20 a barrel.
“They have long since driven wellhead costs far below that level,” although they face the risk of brutal winter weather, mechanical failures and accidents, natural gas prices, steel prices, labor rates, provincial royalties and the rising value of the Canadian dollar, he said.
But a new technology developed for the Long Lake project by Nexen and OPTI Canada should see “wellhead costs drop to single digits and stay there,” Coxe said.
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