Capital costs alone appear to make new Alberta refineries uneconomic, which is why oil sands producers prefer buying US refineries and renovating
A new study from the School of Public Policy says the soon to be operational refinery near Edmonton is likely to lose a dollar for every barrel of bitumen it processes and Albertans will be on the hook for 75 per cent of the loss. But North West Redwater Sturgeon Refinery management has fired back, accusing economist Brian Livingston of using “false assumptions” in his analysis.
The controversial project, the first new Canadian refinery since 1984, is designed to process 50,000 b/d of bitumen and 29,000 b/d of dilbit, producing 40,000 b/d of low sulphur diesel, 28,000 b/d of diluent, and 13,000 b/d of other lighter petroleum products.
One of several reasons the refinery is controversial is BRIK, the “bitumen royalty-in-kind program” that requires Alberta to provide 75 per cent of the bitumen (received by the government in lieu of royalties), which North West Refining processes for a fee, or toll. The government retains ownership of the finished product and markets it through the Alberta Petroleum Marketing Commission.
Prof. Brian Livingston of the School of Public Policy says this arrangement removes the incentive for the operation to be managed as efficiently as possible, exposing Alberta to losses of about $24 million a year, according to his calculations.
“They have no risk so they have no skin in the game,” he said in an interview.
The loss might be higher if the cost of feedstock (diluted bitumen) rises or the price of petroleum products drops.
But the refinery could make a profit if dilbit costs moderate or petroleum prices go up.
It all depends on the assumptions Prof. Livingston plugs into his spreadsheet.
North West Refining took exception to his calculations in an emailed statement: “The author of the School of Public Policy Report did not contact North West Refining Inc. to verify the economic assumptions on which the report is based or discuss the conclusions reached. For this reason he did not have access to complete and accurate information about the project. As a result, certain of the assumptions and guesses about important elements of the project are factually incorrect.”
The company pointed to a Conference Board of Canada study that estimates the refinery will generate $100 million profit annually.
“Financial analysis by independent third parties continues to show that the Sturgeon Refinery will provide positive results for Albertans,” the statement says.
What are readers to make of these dueling studies? Frankly, the project’s profitability one way or the other isn’t that interesting.
Readers can peruse them and make up their own minds about the likely profitability of the refinery. Or, they can wait a few months and read the company’s financial statements after its first (partial) year of operation.
But it is interesting that the Energy Diversification Advisory Committee didn’t recommend more refining and full upgrading in its report, released a few months ago, despite the fact Rachel Notley and the NDP included adding more refining at home in their 2015 election campaign. [Full disclosure: I was contracted as a copy editor for the final draft of the EDAC report.]
Instead, EDAC recommended supporting the rapid commercialization of bitumen partial upgrading technology and financial support for petrochemical expansion. The Notley government apparently agreed, since it committed $2 billion toward those goals.
So, when North West Refining argues, as it did in its statement, that “Albertans need diversification options that maximize the value of our resources and allow existing pipelines to export more value,” those options pretty clearly don’t include more refineries.
Should more refining be an option?
If it should, why hasn’t the private sector built more refineries in Alberta – or anywhere in Canada – over the past 30 years?
One reason is the cost of capital construction.
Livingston uses the example of Husky Energy and its purchase of a 50,000 barrel per day refinery – whose production is almost identical to the Sturgeon facility – in Wisconsin for $670 million, which works out to $13,000CDN per flowing barrel.
By contrast, Sturgeon’s latest capital cost estimate in April was $9.7 billion, for a cost per flowing barrel of $123,000CDN, according to Livingston’s study.
Small wonder, then, that Canadian oil sands producers have chosen to buy American refineries and convert them (adding cokers and hydrotreaters that can cost up to $1 billion to install) to process bitumen.
For instance, Cenovus Energy produced about 150,000 b/d of bitumen in 2016, has a 50 per cent interest in two US refineries operated by Phillips 66 that have a total capacity of 460,000 bpd, of which 255,000 b/d is heavy crude.
Suncor and Husky also have US refineries capable of processing bitumen.
Livingston’s numbers, buttressed by the real-life decisions of oil sands companies’ management – always a good indicator of what is economic and what isn’t – suggests that the Sturgeon refinery will be the last of its kind in Western Canada.
That said, if the North West Refining management turns out to be correct and the facility does consistently earn $100 million a year, then it will probably be able to finance the planned two expansion phases (that would triple output) on its own without Alberta taxpayers risking more money.
Either way, whether profitable or not, the Alberta government has thrown in its lot with partial upgrading and petrochemical expansion, and Sturgeon is almost certainly the last refinery that will ever be built in Alberta.
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