What “refine our own oil” actually requires, and why Canada already does part of it.
The Receipt
Canada makes more gasoline, diesel and other refined fuel than it uses. Its refineries set a production record in 2025, and diesel is a major export, worth $4.6 billion in 2024. [1] [5] Canada also sends most of its crude oil to the United States: about 4.2 million barrels a day in 2024, most of it heavy oil from the oil sands. [6] Both are true because Canada produces two very different kinds of crude.
Canadian refineries were mostly built to run lighter crude, and they are running close to full. [2] Heavy oil sands crude needs specialized equipment. Alberta’s upgraders and one refinery near Edmonton handle part of it at home, but most goes south to U.S. refineries built to process it. [7] [16] [9] The Trans Mountain pipeline expansion has opened a route to other buyers since 2024, but the United States still takes most of it. [15]
So “refine our own oil” can mean two different things. Building plants to process heavy crude in Canada is possible but expensive, and recent projects have needed government support. Building more ordinary refineries would add capacity Canada mostly does not need, since it already makes more fuel than it burns. The gaps are in jet fuel and, to a shrinking degree, gasoline.
Neither option would lower the price at the pump. Fuel trades across North America, so Canadian prices move with the continental market whether Canada has a surplus or not. [19] And the eastern refineries that produce the surplus depend partly on American crude and on a pipeline that runs through Michigan.
Diesel reached $2.75 a litre in Canada in mid-September. [14] Everything that moves by truck now costs more to ship, and the idea that Canada should refine its own oil is back in the conversation. It is an appealing idea, and it runs straight into the way Canada’s oil actually moves.
What a Refinery Makes
A refinery splits crude into a set of products, and the mix is only partly up to the operator. The crude and the equipment set the limits; refiners adjust within them. In Canada, gasoline, diesel and jet fuel make up more than 80 percent of what comes out. [9] The rest is asphalt, petroleum coke, heavy fuel oil, gas burned inside the plant, and small amounts of chemical feedstock and lubricants. [3]
Canada’s position differs by fuel. It exports diesel: central Canada shipped out about 50,000 barrels a day in 2024 and brought in about 2,000, [4] and national diesel exports reached a record 10.8 million cubic metres. [5] Gasoline is still a net import, but imports fell 52.9 percent between 2019 and 2025. [1] Irving Oil’s refinery in Saint John, the country’s largest at 320,000 barrels a day, [2] sends more than half of what it makes to the northeastern United States. [10]
Jet fuel is the weak spot. Output in 2025 was still 2.5 percent below 2019, [1] and nearly a third of the jet fuel used in central Canada in 2024 was imported. [4]
Import totals overstate how much fuel Canada buys. Of the 485,000 barrels a day of refined products Canada imported in 2025, roughly 40 percent went to Alberta, and most of that was condensate: a light liquid bought from the United States and mixed into oil sands crude so it can flow through pipelines. [8] Nobody buys condensate at a pump, but it is counted alongside gasoline, diesel and jet fuel. Canada’s trade surplus in finished petroleum products was 10.9 million cubic metres in 2025, [1] and because condensate still sits on the import side of that figure, the surplus in the fuels people actually use is larger.
Two Kinds of Crude
Canada produced about 5.1 million barrels a day of crude oil and equivalents in 2024. [20] Most of it comes from the oil sands in one of two forms: raw bitumen, thick and high in sulphur, or synthetic crude made in Alberta’s upgraders, which is light enough for an ordinary refinery. [18] [11] Which one a refinery can use depends on its equipment.
The refineries in Ontario, Quebec and New Brunswick are built for lighter crude. Canada’s 16 refineries have 1.9 million barrels a day of capacity and ran at 90 percent of it in 2025. [2] Ontario and Quebec plants get most of their crude from western Canada by pipeline. Irving in Saint John has no pipeline connection at all and brings its crude in by ship. [2]
Raw bitumen mostly goes south. It is thinned with condensate and piped, mainly on the Enbridge Mainline, to refineries in the U.S. Midwest and Gulf Coast that spent billions on cokers, the units that break heavy oil into lighter products. [7] In 2024, 93 percent of Canada’s crude exports went to the United States, and 63 percent of those went to the Midwest. [6] Heavy crude sells at a discount, and the margin for turning it into fuel is earned wherever it is processed, which for most Canadian heavy crude is in the United States. [7]
Some of it is processed at home. Alberta’s upgraders produced about 1.24 million barrels a day of upgraded bitumen, or synthetic crude, in 2024. [16] The Sturgeon Refinery near Edmonton is a diesel-weighted plant of about 50,000 barrels a day that runs on bitumen. [9] Three-quarters of its capacity is contracted to the Alberta government under a 30-year tolling agreement. [21] Canada can process heavy crude; it has far less capacity to do so than it has heavy crude, and the extra barrels are exported.
The Trans Mountain expansion, in service since May 2024, gave that crude another way out. Exports to countries other than the United States more than tripled, and the discount on Western Canadian Select against West Texas Intermediate narrowed from about US$18.70 a barrel to US$12.00. [15]
Why Jet Fuel Is Squeezed
Diesel and jet fuel come from overlapping parts of the barrel. Refiners decide where one ends and the other begins by setting cut points, the temperatures at which each product is drawn off. Shift kerosene, the base of jet fuel, into the diesel pool and diesel output rises while jet output falls. Kpler, a commodity data firm, described it in June 2026: yield optimization is a zero-sum game, and the barrel can be reshaped but not expanded much. [12]
Gasoline has more routes. Catalytic cracking, alkylation, isomerization and reforming all make gasoline out of heavier material. Jet fuel depends on the kerosene cut, which diesel and gasoline also draw on. That may be part of why Canadian gasoline output set records while jet fuel stayed below 2019, though weaker air travel since the pandemic and the economics of importing jet fuel may count for as much or more.
Two Ideas in One Slogan
The first idea is to process Canada’s heavy crude at home: build cokers and upgraders here and keep the margin that now goes to U.S. refiners. It has been tried. In 2020, Suncor deferred a planned $2-billion coker at its Montreal refinery; chief executive Mark Little said it “wasn’t the prudent investment for the shareholder,” and the company directed its capital to lower-cost oil sands expansion instead. [13] Sturgeon began commercial operation in 2020 with that Alberta government tolling agreement behind it. [9] [21] It showed the technology works in Canada, and that the economics needed public backing. New capacity of this kind would cost billions, take years to approve and build, and need a steady supply of heavy crude in a market whose long-term demand is uncertain.
The case for doing it anyway deserves full weight. A private refiner has to clear a return target. A government can count other benefits: a domestic outlet for heavy crude if U.S. trade is disrupted, less need for imported condensate, upgrading value that now accrues in the United States, and protection if the discount on heavy crude widens again. Alberta’s support for Sturgeon, and the public investment in Trans Mountain that changed what producers earn on their crude, suggest governments already weigh those benefits. Seen that way, the question is not whether a new plant pays for itself, but whether its strategic value justifies support the market would not provide.
The second idea is more ordinary refining capacity to make more gasoline, diesel and jet fuel. Canada already makes more refined product than it uses, and its refineries are running near their limit. [1] [2] For jet fuel, the Canada Energy Regulator has noted that raising central Canadian jet output substantially would likely require significant changes to existing refineries. [4]
Why a Surplus Doesn’t Lower the Price
Diesel has climbed as refinery outages in Russia and the Middle East tightened world supply. [14] Canada is part of an integrated North American market for crude and refined products. [19] A refiner with extra diesel can sell it at home or across the border, so the price at home follows what that diesel would fetch elsewhere. The surplus decides where Canadian diesel goes, and the market decides what it costs. What the surplus does secure is supply: in a disruption, the fuel physically exists in Canada.
A U.S. ban on diesel exports, which President Donald Trump publicly backed on September 22, would make the difference plain. It would push on the price Canadians pay. It would not change where Canada’s heavy crude goes or what Canadian refineries can process, and refining more oil at home would not help, because the diesel Canada already makes is the product a ban would reprice.
Where the Pressure Points Are
The heavy crude side depends on one customer. Trans Mountain has widened the list of buyers, but the United States still takes the great majority of Canada’s crude, so tariffs, regulation or a policy shift in Washington would reach most of those exports. [6] [15]
The surplus side has its own dependence. Western Canadian crude bound for Ontario refineries crosses the United States: Enbridge’s Line 5 runs from Superior, Wisconsin, through Michigan to Sarnia, [17] and Line 9 carries crude on to Montreal. [2] The crude Ontario and Quebec refineries import comes almost entirely from the United States: 126,000 barrels a day into Quebec and 87,000 into Ontario in 2025, each more than 99 percent American. New Brunswick, home to the Irving refinery, imported 270,000 barrels a day, 54 percent of it American. [2] Canada’s diesel surplus is partly made from American crude and largely delivered across American territory. Our analysis of a U.S. diesel export ban looks at how that splits eastern and western Canada, including the 1977 treaty that protects pipeline transit.
In our assessment, the relationship is often described as mutual dependence, and the infrastructure is indeed shared. The ability to act on it is not. Washington can restrict diesel exports, put tariffs on Canadian crude or steer U.S. refinery output toward its own market, and Canada has no lever of comparable size. Trans Mountain shows that new infrastructure can change those terms. Whether domestic processing follows comes down to cost, scale and political will.
What Would Change This Assessment
Every figure here comes from public records, used directly: federal statistics, regulator reports and the companies’ own published material. None of the companies named was approached. Any of the following would change this assessment:
- A new material Canadian heavy-crude refinery, upgrader-to-products project or coker expansion reaches final investment decision without extraordinary public subsidy or non-market risk transfer.
- Annual Canadian crude-refinery utilization stays below 85 percent for two consecutive calendar years, excluding capacity idled for major conversion projects, while domestic refined-product demand does not fall comparably.
- Canada records a negative annual finished-petroleum-product trade balance by volume for two consecutive calendar years in Statistics Canada Table 25-10-0081-01.
- Non-U.S. destinations account for at least 25 percent of Canadian crude exports for two consecutive calendar years.
- https://thereceipts.ca/issues/canada-refining-paradox/