Prospects for new bitumen upgraders in Alberta have soured since the global recession of 2008, notes a study published by IHS on the same day plans were reported cancelled for a large project near Fort McMurray (OGJ Online, Mar. 27, 2013).
Since the recession, the study notes, capital costs in Alberta have climbed to above-average levels in part because of labor constraints, and the price differential between light and heavy crudes—crucial to upgrading economics—has wavered.
Suncor Energy cited market conditions when it confirmed expectations that it would not proceed with its planned Voyageur upgrader in partnership with Total E&P Canada Ltd. The facility was to have processed 296,000 b/d of bitumen from nearby mines operated by the companies.
The IHS study concludes that modifying existing refineries to process heavy material from the oil sands region has become more economic than building greenfield upgraders or refineries.
Before the recession, five upgraders were under construction in the oil sands region, the study says. Six other upgrading projects and two refining projects were in earlier stages of development. Only three of the upgraders under construction in 2008 have been completed; the others were cancelled or suspended, including the Voyageur project. Many of the projects in earlier stages of planning when the recession hit have been canceled.
IHS notes that two projects still under development—the North West Redwater refinery planned to be built in phases outside Edmonton and the Kitimat Clean refinery in British Columbia—have characteristics different from the generic model used in its analysis.
When upgrading plans were flourishing, the price of synthetic crude oil (SCO) produced by upgraders was much higher than bitumen blended with diluent or SCO to accommodate pipeline transportation. SCO resembles light, sweet crude oil.
But the light-heavy price differential collapsed globally during the recession, which lowered oil demand. Since then, the global spread has remained narrow because heavy-oil refining capacity has outgrown supply of heavy feedstock while the supply of light, sweet crude has risen rapidly in North America.
In western Canada, the light-heavy spread widened after the recession as production from the oil sands and tight-oil plays flooded inland refining markets, resulting in discounts.
IHS expects that by 2016 new pipelines—including the Flanagan South/Seaway twinning and Keystone XL pipeline or replacement systems if either of those projects is delayed—will connect Canadian supply with new markets.
“These connections will alleviate the crude oversupply, and Canadian light-heavy price differentials should converge with global ones,” the study says.
Before the recession, capital costs had zoomed in Alberta. IHS estimates the costs of building upgraders and refineries in the province increased by 70% during 2000-08.
Although costs sagged during the recession, the study says, they are now higher than prerecession levels and are higher in Alberta than in most other regions.
Although IHS’s analysis, based on a generic facility processing diluted bitumen, favors refinery conversion, North America might not accommodate much of that type of work.
“With ample supplies of light crude in some regions, refiners have little motivation to undertake costly investments aimed at converting refineries to consume heavy crude,” IHS explains.
For refineries built to process heavy feedstock from Alberta, the best prospective investment returns are in Asia, the study concludes. Asian demand is growing, and project costs are relatively low; costs in China, for example, are at least 30% below those of a comparable project in North America, according to the study.
The economics of a new refinery in Alberta or British Columbia “could work,” the study adds, if the project used bitumen, kept capital costs to a minimum, maximized diesel production, and didn’t oversupply its market.