Canada is diversifying its energy exports as U.S. trade pressure pushes Ottawa toward new oil, LNG and critical-mineral markets.
By October 1, Ottawa is expected to announce whether it will list a new oil pipeline to the Pacific as a project of national interest. A notice in the Canada Gazette in August described the West Coast Oil Pipeline as a line of up to about 1,250 kilometres carrying one million barrels a day from Bruderheim, near Edmonton, to a deepwater port near Delta, south of Vancouver, where crude would be loaded onto very large tankers. Alberta's premier, Danielle Smith, says she expects an interim, conditional decision by that date, with final approval about a year later.
Ottawa presents the shift as a response to Washington. In November 2025, Prime Minister Mark Carney told a Toronto audience that “that decades-long process of an ever-closer economic relationship between the Canadian and U.S. economies is now over,” called the moment “a rupture, not a transition,” and set a goal of doubling non-U.S. exports over the next decade. When he suspended trade talks in August 2026, he said his government had understood early that America would use economic integration as a weapon, and “that its signature was written in pencil.”
The evidence suggests that American pressure has done far more to change Canadian energy politics than Canadian energy flows. It has helped break deadlocks between Ottawa and Alberta, pushed governments to shoulder financial risk, and made Canada readier to treat its resources as bargaining power. But the commercial and physical evidence points towards a Canada that sells more energy in more directions, the United States included, rather than one that leaves the American market. Often missed is that energy is one of the few sectors Washington has kept out of its tariffs, and one Ottawa has so far declined to turn into a weapon. That shared restraint limits Washington's leverage and Ottawa's alike.
The pressure has been real. In February 2025 the White House announced a 25 per cent tariff on Canadian imports, with a lower 10 per cent rate on energy, under emergency economic powers. Goods qualifying under the United States-Mexico-Canada Agreement (USMCA) were later exempted, while the rate on other goods rose to 35 per cent. Energy remained subject to a lower 10 per cent rate, until the Supreme Court found those tariffs unlawful. After the ruling on February 20, 2026, the administration ended them and imposed a temporary 10 per cent global tariff that exempted energy products and USMCA-qualifying goods. On July 1, the United States declined to renew the USMCA in its current form; the agreement remains in force while the three countries continue negotiations. Three weeks later, President Donald Trump imposed 50 per cent tariffs on a range of Canadian goods regardless of USMCA status, in the first use of that section of a 1930 trade law to impose tariffs, while stating that they would not apply to energy, potash, fish or critical minerals. After talks collapsed, the tariffs took effect on August 22. Canada answered with counter-tariffs on C$27.6 billion of U.S. goods from September 8, and Washington escalated to import bans on certain Canadian alcohol, dairy products and large motorcycles from September 29.
Mutual dependence is the likeliest reason energy has been spared. In 2025, according to the Canada Energy Regulator, Canada supplied 63.4 per cent of U.S. crude oil imports, close to all of its natural gas imports and 81.3 per cent of its electricity imports. Canada was also the largest source of uranium delivered to American reactor operators, at 32 per cent. The dependence runs in the opposite direction, too: the regulator's data show that 90.1 per cent of Canada's 4.3 million barrels a day of crude exports went to the United States, and that sales of oil, gas and fuels there were worth C$157.5 billion, about a fifth of all Canadian goods exports. Mr. Trump posted in August that “WE DON'T NEED CANADA, THEY NEED US!”, yet his current tariffs leave Canadian energy untouched. Mr. Carney, listing the oil, gas and power Americans buy from Canada, added, “I don't think they want us to stop sending it.” Ms. Smith opposes restricting energy exports, even as a former Alberta premier has argued that export taxes should not be ruled out. Neither government has tested that line.
At home, the result has been political realignment. The Building Canada Act, passed in June 2025, lets the federal government streamline approvals for projects it lists as being in the national interest, and a Major Projects Office opened that August. Its early referrals included an expansion of LNG Canada, the Ksi Lisims LNG terminal and several critical-mineral mines. The larger shift came on November 27, 2025, when Ottawa and Alberta signed a memorandum of understanding under which Canada agreed not to implement its planned cap on oil and gas emissions, committed to declaring a bitumen pipeline to Asian markets a project of national interest, and promised to enable exports from a deepwater port, “if necessary” by adjusting the oil tanker moratorium on the northern British Columbia coast. In return, Alberta's industrial carbon-pricing system is to ramp toward an effective credit price of C$130 a tonne, and the Pathways carbon-capture project became a precondition for the pipeline.
Opposition from British Columbia and coastal First Nations to a northern route appears to have shaped the result. The province's July 2026 agreement with Ottawa keeps the northern tanker ban in place without modification, guarantees compensation for environmental risk if a pipeline is imposed on the province, and does not require British Columbia to support any Alberta proposal. The proposal shifted south, with the route largely following the Trans Mountain corridor to a new terminal at Roberts Bank. Under the federal announcement of July 2, Ottawa and Alberta would be equal partners, with an equity stake reserved for Indigenous peoples and Pembina Pipeline as a private investor.
The project's own filing shows how far ambition runs ahead of commitments. Alberta's submission estimates a cost of C$35.2 billion to C$43.7 billion before escalation and financing costs, a final investment decision between early 2028 and late 2029, and completion in 2032 to 2034. It reports interest from buyers in China, South Korea, Japan, India, Taiwan and Indonesia, but leaves tolls and contracted capacity to later stages. Pembina's stake is 10 per cent during construction, and no private company has expressed interest in a majority share. The contrast with the southbound projects is revealing. South Bow's Prairie Connector, which would carry oil sands crude to the Montana border, has secured 20-year commitments from nine shippers for 465,000 barrels a day and targets an investment decision in mid-2027. On April 30, Mr. Trump signed the cross-border permit for the Bridger pipeline expansion that Prairie Connector is designed to feed, and Enbridge is adding 150,000 barrels a day to its main export system by 2027. The major new shipper commitments announced this year are for a line to the United States; the westward pipeline has yet to announce any.
The westward effort is not pointless. The Trans Mountain expansion, completed in May 2024, nearly tripled that system's capacity to 890,000 barrels a day, and the regulator found that crude exports to countries other than the United States more than tripled. The discount on Western Canadian Select heavy crude against the U.S. benchmark narrowed from an average of about US$18.70 a barrel in the months before start-up to US$12 in the year that followed. The American share of crude exports slipped from 93 per cent in 2024 to 90.1 per cent in 2025. In June 2026, crude exports to other countries rose 26.9 per cent from a year earlier, to roughly one barrel in eight. Trans Mountain ran at full capacity for the first time in June, its chief executive said that about two-thirds of departing tankers head to Asia, and planned upgrades are expected to add about 90,000 barrels a day by year-end, with a further 210,000 barrels a day targeted by the end of 2028.
Those limits became apparent this month. On September 21, the discount on Western Canadian Select stood at US$21.35 a barrel, its widest since December 2023, amid refinery maintenance in Canada and Illinois, rising output, and more Venezuelan heavy crude reaching the U.S. Gulf Coast. A former vice-president of Canada's main producers' association argued that Trans Mountain, which had kept the discount between US$12 and US$14 in earlier episodes, may no longer be able to play that same buffering role now that it was running close to full. The lesson is that capacity, more than tariffs, sets the price of a Canadian barrel. And most of that capacity still points south: about 63 per cent of Canadian crude sent to the United States goes to the Midwest, to refineries built to process heavy oil.
Global events have made the westward case look stronger than in years. The war involving the United States and Iran, which began at the end of February, had more than 10 million barrels a day of Gulf output shut in during August, and the International Energy Agency reported that North Sea crude reached US$113.48 a barrel on September 9. It expects world supply to fall by 5.7 million barrels a day this year. Asian demand for Canadian crude has risen as the war disrupted Middle Eastern supply, so this year's gains owe much to that shock, not only to tariffs. The timing is the problem. In January, before the war, the agency expected supply to grow by 2.5 million barrels a day in 2026 against demand growth of just 930,000, on top of a large surplus already in storage. A pipeline finished in 2033 will be priced in the market that follows this war, not in today's.
Liquefied natural gas shows the promise and the risk more clearly. LNG Canada loaded its first cargo on June 30, 2025, from a 14-million-tonne-a-year plant at Kitimat. By June 2026, gas exports to countries other than the United States reached their highest level yet, close to a fifth of Canada's gas exports by energy content, while pipeline sales to the United States kept falling. The partners could make a final investment decision on a second phase, doubling capacity to 28 million tonnes, as early as October, according to people familiar with the matter. Ksi Lisims, led by the Nisga'a Nation, has offtake deals covering two-thirds of its planned 12 million tonnes a year, but finalized sales contracts covering only 6 million, and its original budget has more than tripled. An analyst at the Institute for Energy Economics and Financial Analysis warned of a “bull trap” in reading a war-driven price spike as a lasting shift. The energy agency's figures support a narrower version of that warning. The effective closure of Hormuz disrupted flows that had supplied almost 20 per cent of the world's LNG, and the agency estimates cumulative losses of 140 billion cubic metres from 2026 to 2030, about 15 per cent of the new supply due in that period. The expected wave of supply has been delayed, not cancelled, and three large American projects have been approved since March.
In critical minerals, Canada has begun using its position more assertively. When Vice-President JD Vance proposed a trading bloc in February, “one that guarantees American access to American industrial might,” Foreign Affairs Minister Anita Anand said Canada would not sign sector-by-sector deals and would decide within the USMCA review, suggesting a one-off minerals deal could cost Canada leverage. Ottawa says its G7 alliance is now catalysing C$19.2 billion across 69 partnerships, with European and Japanese partners prominent in the latest round. The stakes are rising: China's suspension of several expanded rare-earth export controls is scheduled to expire on November 10. Washington's decision to leave critical minerals out of its Canadian tariffs points to the same mutual dependence seen in oil.
Two constraints may matter more than tariffs. The first is Indigenous consent. The proposed pipeline would pass through the traditional territories of roughly 90 to 125 Indigenous groups, and its marine terminal would sit on Tsawwassen First Nation treaty lands. Days after the federal referral, the president of the Union of BC Indian Chiefs said in a joint statement that “southern First Nations have not yet even been consulted about a new pipeline through their territories.” Fourteen First Nations are challenging the Building Canada Act, along with an Ontario law, in court. LNG Canada, where a coalition of neighbouring First Nations holds an option to invest up to C$1 billion in the expansion, shows that consent can be earned. It cannot be decreed.
The second is climate policy, now conditional on growth. The emissions cap is gone. Under a July agreement with the five largest oil sands producers, Pathways is expected to deliver six million tonnes a year of net emissions reductions by 2035, with a further 10 million tonnes of reductions through additional measures by 2045. Critics describe the scaled-back plan as public support for a highly profitable sector. Alberta's own submission estimates that the pipeline, if it brings on new production, could add 15.5 to 18.2 million tonnes of upstream emissions a year from 2032, though far less if it merely redirects existing barrels. On those figures, the promised cuts would roughly match the new emissions, and arrive later.
Three counterarguments deserve weight. The first is that geography locks Canada into the U.S. market regardless. On volumes, that is largely right: even if every planned westward project is built on time, the arithmetic suggests the United States would still take most Canadian crude into the next decade. But lock-in is a matter of degree, and the Trans Mountain experience shows that even a modest outlet can narrow the discount and give producers a second buyer. The second is that rhetoric outruns investment. That fits oil, where governments are carrying risk that private capital has not taken on. It fits LNG less well: one terminal is operating, and the Cedar and Woodfibre projects are due to start in 2028 and 2027, respectively. The third—and strongest—is that mutual dependence puts a ceiling on U.S. pressure. That is true, but the ceiling applies to both sides. It likely explains why Washington has spared Canadian energy, and also why Canada's most powerful tool, withholding supply, is one its main producing province rejects. Canada's new assertiveness is better understood as building options than as coercion.
The strategy now faces a critical test. The national-interest listing, a possible investment decision on LNG Canada's second phase and the signing of the definitive Pathways agreements, targeted for November 15, are all close. So is Alberta's October 19 referendum, which asks whether the province should remain in Canada or whether its government should begin the constitutional process required for a future binding referendum on separation. The next annual USMCA review is due within a year. The likely path is a Canada that produces more oil and gas, ships a rising share to Asia and uses minerals as a bargaining chip, while the United States remains its largest customer by far. Whether that makes Canada an energy power depends on whether Ottawa can secure Indigenous partners, private shippers and a durable climate bargain before the current price spike fades. For Washington, the lesson may be that pressure has accelerated Canadian investment in routes around the American market without reducing America's need for Canadian energy.
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