Alberta Files Pacific Line as Carney Keeps Tanker Ban

Alberta submitted its 1-million-barrel-per-day Pacific Corridor pipeline proposal to the federal Major Projects Office on July 1, 2026, meeting its self-imposed submission deadline. Premier Danielle Smith unveiled a southern BC routing option on July 2 that avoids the North Coast tanker moratorium that has constrained Alberta's Pacific export options since 2019.

The same day in Vancouver, Prime Minister Mark Carney, standing alongside BC Premier David Eby, reaffirmed the tanker ban as part of the Canada-British Columbia Cooperative Prosperity Agreement. Carney confirmed the West Coast oil line still has no private-sector backer. The pipeline, if approved and built at capacity, would add 1 million barrels per day of Pacific export capacity alongside Trans Mountain's existing 890,000-barrel-per-day system.

Carney's Signed Text Ties the Ban to a Future Route and Stops Short of Calling It Permanent

The agreement says Ottawa "commits to maintaining the federal North Coast tanker ban, in accordance with the proposed route of a new trans-provincial pipeline under the bilateral agreement between Canada and Alberta." Carney and Eby said the ban would be "fully maintained." Eby said BC "will not be going to court to fight a pipeline project."

The phrase "in accordance with" is the tell. The ban holds today. It is not called permanent, and its future is tied to a pipeline route that does not yet exist.

The 2019 Act Bans Loading Crude Over 12,500 Tonnes but Exempts LNG

The Oil Tanker Moratorium Act, in force since 2019, bars vessels carrying more than 12,500 tonnes of crude or persistent oil from loading at ports on BC's north coast. Transport Canada says it restricts loading, not passage, and excludes liquefied natural gas, gasoline, jet fuel and propane.

That is why the same deal that blocks crude terminals also speeds four coastal LNG projects. Gas is outside the ban.

Ebel Calls the Ban a 'Pipeline to Nowhere' While Every Named Firm Declines to Build It

Enbridge Inc. Chief Executive Greg Ebel has led the industry push to lift the ban. The moratorium "effectively makes that export pipeline illegal," he said in an October speech to the Empire Club of Canada. "No company would build a pipeline to nowhere." Ebel said 97% of Canadian crude exports went to the U.S. in 2023, leaving producers with "the risk of having only one customer."

Enbridge will not build it. Ebel said the company will advise on the project but not lead or fund it. TC Energy Corp. has not committed. Alberta Energy Minister Brian Jean said an unnamed Fortune 500 company discussed financing the line, and Indigenous nations have sought equity, though no proponent has signed.

"We're not competitive if it takes five to 10 years to approve a project, or you can't actually ship your oil because of a tanker ban," said Lisa Baiton, chief executive of the Canadian Association of Petroleum Producers.

Smith Files a 1-Million-Barrel Line With a Loan Guarantee She Hopes Not to Use

Smith submitted the one-million-barrel-a-day proposal backed by $14 million in provincial planning funds. "Proponents will step up and it will be built with private sector money," she said. She ruled out spending $34 billion in provincial funds but cited a "loan guarantee mechanism" to backstop early development. Conservative Leader Pierre Poilievre, who holds an Alberta seat, wants the ban and the federal assessment law repealed, saying Ottawa should "get out of the way."

Trans Mountain Ran 86% Full in 2025, Hit Apportionment in June, and Peaked Near 91%

Trans Mountain shows why a new line is in question at all. Canada's only tidewater crude pipeline hit apportionment for the first time since its May 2024 expansion in June 2026, with shipper nominations exceeding its 890,000-barrel-per-day capacity. As Oil Authority reported on June 17, 2026, Asian demand surged after Hormuz supply disruptions redirected Pacific refiners toward Canadian crude. The system averaged 761,000 barrels per day in 2025, 86% of capacity, set a record 807,000 in the fourth quarter, about 91% full, and the company forecasts 88% utilization in 2026.

Trans Mountain plans to add roughly 90,000 barrels per day with drag-reducing agents by 2027, then pump stations and pipe to reach about 1.14 million by 2028. Other new egress is incremental. Enbridge's Mainline optimization and the Bridger Pipeline's 400,000-barrel expansion add capacity at the margin. S&P Global expects western Canadian output to grow about one million barrels per day this decade and spare pipeline space to disappear by the end of 2026. The proposed West Coast line is the only project large enough to close that gap, and the one without a builder.

Western Canadian Select crude was assessed at $56.23 per barrel in Thursday trading, per OilPrice.com, against a WTI settlement of $68.45 per barrel on Thursday's CME close, per TradingEconomics. The $12.46 WCS-WTI differential persists despite Trans Mountain running at full throughput, confirming that existing pipeline infrastructure cannot close the price gap.

What the Differential Costs Alberta Producers

At Trans Mountain's full 890,000-bpd throughput, a $12.46 WCS-WTI spread translates to $11.09 million per day in foregone netback revenue for Alberta heavy oil producers. That figure reaches $4.05 billion per year in unrealized producer value. Earlier this year, when the WCS-WTI spread peaked at $16.15 per barrel in April 2026, the same throughput implied a $5.25-billion annual drag. A new 1-million-bpd pipeline that narrowed the differential by $5 per barrel would generate $1.83 billion per year in additional producer netback, with each additional dollar of improvement adding $365 million annually.

Oil Sands Producers with the Most at Stake

The pipeline's largest potential shippers are Canada's four major oil sands operators. Suncor Energy produces more than 800,000 barrels per day from the base oil sands mine, Firebag, and Fort Hills. Canadian Natural Resources is Canada's largest single heavy crude producer, operating Horizon and Kirby. Cenovus Energy, which acquired Husky Energy's upstream assets in 2021, produces Christina Lake and Foster Creek bitumen that trades as WCS in export markets.

Imperial Oil, 69.6% owned by ExxonMobil, operates Kearl and Cold Lake and would rank among the highest-volume shippers on a new Pacific corridor. Kearl produces more than 270,000 barrels per day of diluted bitumen, one of the highest individual mine volumes in Canada. MEG Energy's Christina Lake project produces more than 100,000 barrels per day and the company has consistently sought expanded Pacific export access. For ExxonMobil, a confirmed Pacific corridor for Imperial's bitumen would reduce Canadian price discount exposure across the parent company's global crude trading portfolio.

Southern Route and the Federal Approval Path

Alberta's proposed southern route would reach BC ports below the North Coast tanker ban zone, avoiding the corridor that blocked Northern Gateway after a federal court rejected the project in 2016. No terminal location has been publicly confirmed, and no private-sector developer has been named. Under the Alberta-Canada energy MOU finalized in May 2026, construction targets a start as early as September 1, 2027, contingent on federal designation as a project of national interest by October 2026.

The Alberta Indigenous Opportunities Corporation is designated as the vehicle for potential Indigenous co-ownership. Sovereign wealth funds have signaled interest in acquiring minority stakes of 15% to 30%, according to June 10 reporting by Oil Authority. Indigenous consultations and BC provincial approvals remain outstanding hurdles ahead of the September 2027 construction target.

Producers Drilled 11,226 Wells in 2014 and About 4,700 by 2016 as the Workforce Shrank

The pipeline debate lands on an industry that never returned to its pre-2014 size. Producers drilled 11,226 wells in 2014. After crude collapsed that autumn, the count fell about 58% to roughly 4,700 by 2016, according to the Canadian Association of Oilwell Drilling Contractors. Active rigs fell from about 1,600 at the 2014 peak to roughly 600 in 2025, per Baker Hughes and CAOEC data.

The workforce shrank with it. Direct oil and gas extraction employment fell from about 64,300 in 2014 to about 54,200 in 2024, according to federal Canadian Industry Statistics. The drilling and services side was hit far harder, with the contractors' association reporting job losses near 57% through the downturn, because rig crews rise and fall directly with the number of wells drilled.

The near-term trend is still down. Enserva, the energy services association, forecast total wells drilled would fall about 9% in 2025, led by a 16% drop in British Columbia, with a further 4% decline in 2026. Each active rig supports scores of field jobs and service-sector spending across Western Canadian towns, which is why egress and new projects matter beyond the daily oil price.

Calgary's Downtown Vacancy Rose From 9.8% in 2014 to a 32.7% Peak, Erasing $12 Billion in Tower Value

The 2014 crash is still visible in Calgary's core. Downtown office vacancy stood at 9.8% at the end of 2014, near a boom-era low. It climbed to 17.4% within a year and peaked at 32.7% in 2021, the highest of any major Canadian city, according to CBRE. It still sat at 30.4% at the end of 2025.

The collapse hollowed the tax base. Downtown office tower values fell more than $12 billion in three years to 2019, cutting about $300 million in tax payments and shifting the load onto businesses outside the core. Tens of thousands of head-office and service jobs left downtown over the decade.

The City of Calgary has since spent public money converting empty towers to housing. Its conversion program has cleared about 2.7 million square feet across 21 projects and aims for 6 million by 2031. Even so, the city does not expect vacancy back near 20% until 2031. That decade of lost office jobs and eroded tax revenue deepened the economic alienation that polling now links to Alberta's separatist sentiment.

Zero Equalization for Alberta, $13.6 Billion for Quebec, and a Cancelled Energy East Feed the Alienation

The frustration predates this pipeline. Alberta contributes heavily to federal revenues but receives no equalization, while Quebec draws the largest share, $13.6 billion of $26.2 billion in 2025-26, according to Finance Canada. British Columbia and Saskatchewan also receive nothing.

Albertans have registered the grievance at the ballot box. In an October 2021 referendum, 61.7% voted to remove the equalization principle from the Constitution, according to Elections Alberta, though a single province's vote carries no legal force. Routes east have also stalled. TransCanada cancelled the 1.1-million-barrel Energy East line in 2017, citing changed circumstances after regulators widened its review to include greenhouse gas emissions.

These grievances feed the sentiment polling measures. In Angus Reid Institute surveys, most Albertans still favour staying in Canada, but even among them 93% say the province struggles to sell its resources as a landlocked exporter. Alberta votes on its place in the country on October 19.

Asian Buyers Will Pay for Barrels That Skip Chokepoints

Global buyers are watching. About one-fifth of seaborne oil moves through the Strait of Hormuz, and the IEA called the 2026 disruption there the largest supply shock in oil-market history. Japanese and South Korean buyers have signalled they will pay more for barrels that skip such chokepoints. Canada's regulator says more than 95% of crude exports went to the U.S. in 2024.

Alaska Has Shipped Crude Past BC Since 1985, but a Kitimat Line Would Thread Hecate Strait

Alaska has shipped crude past BC for four decades. Tankers carry more than 80 million barrels a year of North Slope crude from Valdez down the Pacific, routed since 1985 west of a voluntary zone about 70 nautical miles offshore. Foreign tankers already cross the inshore waters the law protects, because it bans loading, not transit.

The coastal case is about the route. Alaskan crude runs the open Pacific. A Canadian line ending at Kitimat or Prince Rupert would thread Douglas Channel, Hecate Strait and Dixon Entrance, where Environment Canada records gales with 5-to-7-metre seas. In 1989 the single-hulled Exxon Valdez spilled about 257,000 barrels onto 1,300 miles of shoreline. U.S. law has since required double hulls and tug escorts. The risk is real, and lower than it was.

BC Backs Gas While Resisting Crude, and the Ban's Future Rides on a Route Not Yet Drawn

Ottawa and Victoria have fought over oil before. The Supreme Court of Canada ruled in 2020 that BC could not restrict bitumen through Trans Mountain, since interprovincial lines are federal. BC's fiscal position adds pressure. Moody's and S&P downgraded the province in April 2025, its fourth cut in four years, with Moody's citing "a continued weakening in governance and fiscal and debt management." The same government backed LNG Canada and Cedar LNG, and Thursday's deal speeds four LNG terminals. British Columbia has resisted crude and tankers while supporting gas.

For now, the ban holds. Whether it bends to a route yet to be drawn, and whether a company will build the line, is unresolved.