Diesel is at record highs. Why won’t Canada build more refineries?

Truckers and farmers paying record prices for diesel this fall have been asking a reasonable question: if Canada has so much oil, why can’t it make more of its own fuel?

The numbers tell a more complicated story. Canada produced a record 5.35 million barrels of crude a day in 2025, and roughly four million barrels a day went to the United States.

Canada’s 16 refineries, on the other hand, processed about 1.6 million barrels a day, running at 90 per cent of capacity, according to the Canada Energy Regulator.

That is more than enough to keep Canadians moving on the roads. The country burns roughly 830,000 barrels of gasoline a day, and the industry’s regulator says Canadian refineries produce most of the gasoline, diesel and jet fuel that Canadians consume.

“But where it comes from depends on whether you’re in B.C. or Ontario or Atlantic Canada,” said Patrick O’Rourke, managing director, institutional equity research at ATB Capital Markets.

What he means is that for large pockets of the country, it makes more sense to buy diesel, gasoline and jet fuel from the United States, because there isn’t a Canadian refinery nearby.

For most of the past few decades, O’Rourke said, refining simply wasn’t a good business. Profit margins were razor thin. On top of that, the Americans had already paid to build the infrastructure.

“Refining was not a great business and the U.S. refiners, meanwhile, made heavy capital investments on the Gulf Coast and in the Midwest to process Alberta’s heavy sour crudes,” said O’Rourke.

Those refineries spent billions retooling to handle the thick, sulphur-heavy oil that comes out of Alberta’s oilsands. Because they already exist and are largely paid off, a new Canadian plant would be competing against them from scratch.

Physics matters too. “It’s a lot easier to ship crude than it is to ship a refined product,” said Kevin Birn, chief analyst for Canadian oil markets at S&P Global.

Crude moves in bulk through a single pipeline, while gasoline, diesel and jet fuel each have their own specifications and handling needs. Refineries tend to be built close to the people who buy their fuel.

Add Canadian construction costs and regulation, and the math rarely worked.

“Environmental regulations and the capital cost for building things in Canada made it prohibitive to build refineries here,” Birn said. “Refinery profitability goes through cycles and for a long time it was quite low, so it didn’t incentivize us.”

Alberta’s most recent attempt to refine where it mines shows just how hard the economics can be. “Investment in new refineries in Alberta are certainly not without risk,” added Birn.

The Sturgeon refinery northeast of Edmonton, originally known as the North West Upgrader, was meant to be a low-risk, low-cost way to turn more bitumen into higher-value fuel at home.

The original plan was simple. The province would collect bitumen from producers instead of cash royalties and sell it to new Alberta upgraders. Private companies would build and finance the plants and carry the risk of thin margins.

According to a University of Calgary School of Public Policy paper by Ted Morton, 11 upgrading projects were either underway or in active development prior to the 2008 global financial crisis.

Representing over $100 billion in investment, these initiatives would have boosted upgrading capacity by three million barrels per day — more than tripling the existing output.

Morton noted that because of this expected growth, the region east of Edmonton was nicknamed “Upgrader Alley” in anticipation of becoming a major refining hub similar to Houston’s refinery row.

The 2008 financial crisis killed that model, and when the dust settled only one project, North West, was still standing.

Rather than let it go, Ed Stelmach’s government took on a much bigger role. Under a “take or pay” deal, the province agreed to keep ownership of the bitumen, pay the refinery a toll to process it for 30 years, and sell the finished products itself, even if prices fell below cost.

Then, costs soared. As four premiers and six energy ministers cycled through Edmonton, a $6.5-billion cap on the province’s exposure to construction costs disappeared, and the final bill reached roughly $10 billion.

In his paper, Morton called the project “a multi-billion-dollar boondoggle.” The refinery began commercial operations in 2020, years behind schedule, and the province took a 50 per cent ownership stake the following year.

These days, running a refinery is far more profitable, with margins that are “incredible,” O’Rourke said.

That’s because the U.S.-Iran conflict disrupted shipping through the Strait of Hormuz and Ukrainian attacks have knocked out Russian refining capacity, leaving the world short of refined products such as gasoline and diesel even though crude supplies are still available.

Yet even so, nobody appears to be rushing to build.

In California, for example, refineries are closing as the state pushes to phase out gas-powered vehicles and refiners face a shrinking market.

Each closure leaves California more reliant on imported fuel, which pushes up the state’s pump prices. On the desolate coast between San Francisco and Los Angeles, one pump recently made the news by posting $10 per gallon for unleaded gasoline.

So, whose gas is in your tank? It’s mostly Canadian. According to the Canada Energy Regulator, the country’s refineries turn out more gasoline, diesel, heating oil and jet fuel than Canadians use.

Canada even sends gasoline the other way — it is the largest supplier of gasoline imports to the U.S. and is the main supplier to several northeastern states, according to the U.S. Energy Information Administration.

But Canada does buy some of its fuel from abroad. Imports of refined petroleum products rose three per cent in 2025 to 485,000 barrels a day, nearly 80 per cent of which came from the U.S., the Canada Energy Regulator reported.

That number needs context, though.

First, most of it isn’t gasoline. Alberta, perhaps surprisingly, is Canada’s biggest importer, at about 200,000 barrels a day – about 40 per cent of the import volume. Much of that is condensate, a light liquid used to thin bitumen so it can flow through pipelines. Think of condensate feeding the oilsands, not cars.

It’s worth mentioning also that Alberta’s appetite for condensate is set to grow. If new export pipelines are eventually built, O’Rourke said, “we’re going to have to grow our own domestic condensate production considerably.”

Don’t, however, expect a wave of new upgraders to solve that issue. “Because energy companies make those investments on 20, 30, 40-year capital cycles, they’re more likely to squeeze extra barrels out of existing refineries in Alberta,” he said.

Second, imports are regional. Some parts of the country don’t make enough fuel locally and aren’t well connected to the regions that have a surplus.

British Columbia is the clearest case, relying on refineries in Washington state, which in 2025, supplied 34,000 barrels a day of refined products to Canada’s western-most province.

Geography is the final hurdle.

In Canada, no pipeline carries western crude all the way to Atlantic Canada, so refineries there rely partly on imported oil.

And proposals for a cross-country route, like the Northern Shield line that would run from Hardisty, Alta., to Sarnia, Ont., remain “pretty far down the list of pipelines likely to be built,” O’Rourke said.

For the refined fuel products, the same logic points south.

It just makes sense if you’re short diesel in Ontario to get it from the closer Midwestern market “than to ship from Alberta,” Birn said.