CALGARY, Alberta (Reuters) - Even as the world’s largest energy companies exit Canada’s high-cost oil sands the country’s top producer Suncor Energy is lining up its next phase of growth in the world’s third largest crude reserves.
The preliminary plans for new projects in remote northern Alberta follow a stream of multi-billion dollar deals in which international oil majors sold off oil sands assets to Canadian producers, who are betting technology and economies of scale will make the region competitive with other plays globally.
Suncor said on Monday it will file a regulatory application for its 160,000 barrel-per-day Lewis project later this year, and in March received approval for the 80,000 bpd Meadow Creek East plant. It also plans to file an application for the 40,000 bpd Meadow Creek West project later this year.
The company has not yet taken a final investment decision on any of the projects but if sanctioned they would boost the company’s current output of 680,000-720,000 bpd by more than a third. In total, Canada produces around 4 million bpd.
Calgary-based Suncor cemented its position as the largest oil sands operator last year when it bought Canadian Oil Sands Ltd and Murphy Oil’s stake in the giant Syncrude mining and upgrading project in two deals worth over C$5 billion ($3.66 billion).
Its strategy for future growth relies on building identical smaller thermal plants to help cut costs. This is how future development across the industry is expected to look, as the exit of the majors has drawn a line for now under the megaprojects that drove the industry’s rapid expansion over the past 15 years.
Suncor will add new plants able to produce between 30,000-40,000 barrels per day every 12-18 months, chief executive Steve Williams said on a quarterly earnings call last month.
“We’re working with contractors about how do we design this once and build it many times so we get that benefit of replication ... almost like a manufacturing plant,” Williams said.
While it is encouraging to see companies thinking about future projects, it is still not a given that the economics will necessarily work or that Suncor will build them to full capacity, said Wood Mackenzie analyst Mark Oberstoetter.
The modular approach is a far cry from Suncor’s giant Fort Hills mining plant, due to be finished later this year, which will produce 194,000 bpd at a capital intensity of C$84,000 per flowing barrel of bitumen, or around C$16.5 billion in total.
Thermal projects usually cost around C$45,000-C$50,000 per flowing barrel and using the replication strategy should bring costs at Lewis and Meadow Creek East even lower, AltaCorp Capital analyst Nick Lupick said.
“They are effectively designing and building one version of a plant, and using it like a cookie-cutter,” he said. “It shows how they are focused on changing strategy to lower costs.”
Suncor has not released cost estimates for the projects and does not plan to start building until the 2020s, but estimates it could squeeze up to 400,000 bpd of additional capacity through this kind of expansion.
Oil sands producer MEG Energy also has plans to grow its 80,000 bpd Christina Lake plant by adding a series of 10,000-20,000 bpd projects that will cost C$20,000-C$30,000 per flowing barrel, eventually hitting output of 210,000 bpd.
Lower costs and smaller projects are crucial for oil sands producers as they struggle to remain competitive with cheaper and faster U.S. shale plays.
In addition to replicating thermal plants a number of companies including Suncor, MEG, Cenovus Energy and Imperial Oil are looking at new ways to improve bitumen extraction by using solvents as well as steam.
Typically, thermal projects involve drilling a pair of wells into an oil sands reservoir and pumping steam through the upper well to liquefy bitumen so it can flow out of the lower well.
The industry is only now is a position where plant replications will work, said Doug Hollies, an engineer with consultancy Codeco Oilsands Engineering in Calgary, who was involved with drilling thermal projects in the early 2000s.
“Back then we did not know what was going to come out of these wells, in every different area (of the oil sands) there would be different product,” he said.
“Now that every project virtually has been piloted it’s a lot easier to make good engineering decisions and standardise designs.”
Editing by Phil Berlowitz
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