Oil sands crude not as expensive to produce as it used to be
By: Jeff Lewis
August 19, 2013
CALGARY – Alberta’s oil sands, long regarded as an expensive sandbox for energy giants, are more competitive with global sources of crude than recent cost blowouts may lead investors to believe, a survey of 135 global oil and gas companies shows.
Worldwide supply costs for oil-weighted companies edged up 7% in 2012 to US$99.66 per oil-equivalent barrel, from US$92.73 per barrel in 2011, on higher reserve replacement costs, according to new research by BMO Capital Markets. The supply cost is essentially a break-even price, or the West Texas Intermediate oil price companies need in order to recover costs, plus earn a 10% return on capital.
The report pegs supply costs for oil sands projects in the range of US$50 to US$90 per barrel. That compares to the US$70 to US$90 a barrel needed to blast light, sweet crude through underground fissures in North Dakota’s Bakken shale, the Eagle Ford play in Texas and Colorado’s Niobrara shale, the bank said.
“There’s a lot of oil sands projects that are being invested in on the basis of supply costs as low as US$50, so one of the key takeaways here is really oil sands isn’t that marginal a source of supply,” Randy Ollenberger, managing director, equity research at BMO in Calgary, said in an interview. The world’s No. 3 crude deposit “is actually quite economic in the global context.”
It is a message that runs counter to a history rife with cost overruns on project expansions and stalled pipeline developments that have contributed to price discounts for Alberta’s heavy crude, frustrating investors.
The first phase of Exxon-controlled Imperial Oil Ltd.’s 110,000-barrel-a-day Kearl mine, for instance, came with a $12.9-billion price tag — as much as 40% above earlier estimates.
Royal Dutch Shell Plc faced similar challenges adding 100,000 barrels a day of fresh capacity to its Athabasca Oil Sands Project. Cost estimates for the work jumped from an initial US$3.5-billion in 2005 to US$14.3-billion in 2010.
“I think for investors outside of Canada, there’s been a lot of focus on the projects that the super-majors have pursued,” Mr. Ollenberger said. The Athabasca expansion and the Kearl projects, “on the face of it, look like they have supply costs north the US$100 mark, so I think for a lot of investors outside of Canada, that’s their perception of what the oil sands is.”
Across the oil sands sector, companies have largely abandoned grand production targets, pledging instead to wring costs from existing assets. Shell is targeting 80,000 to 85,000 barrels a day of new production over seven years from existing operations, for instance. Suncor Energy Inc., Canada’s biggest oil company, aims to produce 100,000 barrels a day through similar measures, known in industry parlance as debottlenecking.
BMO estimates new technologies could trim supply costs at some in situ, underground extraction projects to as low as US$25 per barrel.
Other estimates peg costs much higher. Although exact comparisons are tough to make, IHS Cera, assuming there is sufficient pipeline capacity for oil sands production, puts the break-even WTI price for steam-driven extraction schemes as high as US$75, with mines at more than US$100.
Oil sands-derived crude is still “among the most expensive oil” in the world to produce, said Jean-Michel Gires, formerly chief executive officer with the Canadian unit of France’s Total SA.
But companies are making improvements, he said, citing the use of solvents in projects that use steam to melt seams of bitumen buried too deep to mine.
“I think costs are under better control than they used to be just a few years ago,” said Mr. Gires, now a partner at Vancouver-based clean-tech fund Chrysalix Energy Venture Capital. The fund provides early-stage financing and hands-on experience to technology companies. It manages close to $350-million in assets.
Mr. Gires, who spent 25 years with the French oil major, has returned to the oil sands after nine months away, this time with an eye to solving some of the sector’s more intractable problems, including water use and rising greenhouse gas emissions.
There is much work to do, he said. “I keep saying for the long term, there’s a very bright future for heavy oil, if we can bring forward new solutions.”