Trans Mountain: Why Ottawa Bought a Pipeline and What the C$34bn Expansion Changed

Trans Mountain is the pipeline that turned a national political crisis into Canada’s most important piece of export infrastructure, at a price no private owner would have paid. The 1,180-kilometre system from Edmonton to Burnaby was built in 1953 and expanded with a twinned line that tripled capacity to 890,000 barrels a day in 2024. Its ownership by the federal government, its C$34 billion cost, the 18-month toll dispute with shippers and the unresolved question of who buys it next make it a case study in what happens when infrastructure becomes a matter of state. This article explains why Ottawa bought the pipeline, what the expansion changed for Canadian oil producers and Asian refiners, how the tolls were finally settled and where the sale process stands in October 2026. It is part of the Canada Company Stories hub.

Why did Kinder Morgan walk away in 2018?

Kinder Morgan walked away because the political and legal risk of building through British Columbia had become impossible for a private company to price. The Houston-based pipeline operator had owned Trans Mountain since 2005 and proposed the expansion in 2012 at an estimated cost of C$5.4 billion, later C$7.4 billion. The project was approved by the federal cabinet in November 2016, but B.C.’s NDP government, elected in 2017 with Green Party support, promised to use “every tool in the toolbox” to stop it, and the City of Burnaby, several First Nations and environmental groups pursued court challenges.

In April 2018 Kinder Morgan Canada suspended all non-essential spending and set a 31 May deadline for governments to give it certainty. The federal government of Justin Trudeau, which saw the pipeline as essential to getting Alberta crude to markets other than the United States, responded by agreeing to buy the existing pipeline, the expansion project and the Puget Sound line for C$4.5 billion. The deal closed on 31 August 2018, the day after the Federal Court of Appeal quashed the project’s approval over inadequate Indigenous consultation and marine shipping review. Ottawa re-approved the project in June 2019 after a new consultation round.

The purchase created a Crown corporation, Trans Mountain Corporation, owned through the Canada Development Investment Corporation (CDEV). The logic was that only a government could absorb the regulatory and political risk; the cost of that logic became clear over the next five years.

How did the cost go from C$7.4 billion to C$34 billion?

The cost rose because of a combination of route changes, construction in difficult mountain terrain, the COVID-19 pandemic, the 2021 B.C. floods, inflation and a project management structure in which the owner had no commercial discipline to stop spending. The estimate moved to C$12.6 billion in February 2020, C$21.4 billion in February 2022, C$30.9 billion in March 2023 and finally C$34.2 billion (including a C$3.4 billion financing cost) by the time the line entered service. In total, the final figure was roughly 4.6 times the 2017 estimate and more than six times the original 2012 number.

The Parliamentary Budget Officer (PBO) has tracked the value of the asset throughout. Its November 2024 report valued the pipeline, on a going-forward discounted cash flow basis, at C$33.4 billion if shipper contracts are renewed after their initial 15–20 year terms and C$29.6 billion if the system reverts to cost-of-service tolling. Both figures are below the amount invested once the purchase price and pre-2024 capital are included, and the PBO concluded that a sale at either value would require the government to write off its C$8.3 billion of shareholder equity in Trans Mountain Corporation and record a loss.

The overrun had a specific commercial consequence. Shippers had signed contracts in 2012–2013 under a tolling model that capped how much of any cost increase could be passed to them; most of the overrun was “uncapped” from the shippers’ point of view only in a limited way, which meant Trans Mountain and its owner, not the oil companies, carried the bulk of the excess. That mismatch became the heart of the toll dispute.

What changed when the expanded line started flowing in May 2024?

When commercial operations on the expanded system began on 1 May 2024, Canada gained its first large-scale ability to sell heavy crude to buyers other than American refiners, and the price of Canadian oil changed accordingly. The differential between Western Canadian Select and WTI narrowed as the new capacity relieved the chronic bottleneck on the Enbridge Mainline, which had been apportioned for most of the previous decade. The Canada Energy Regulator credits the new capacity for allowing 2025 crude production to reach a record 5.35 million barrels a day, with a December peak of 5.64 million.

Throughput ramped quickly. Trans Mountain reported an average of 555,000 bbl/d in 2024 and 761,000 bbl/d in 2025, an 86% utilisation rate for the year and 91% in the fourth quarter. In the fourth quarter of 2025, about 504,000 bbl/d went to the Westridge Marine Terminal for tanker export, 203,000 bbl/d to Washington State refineries through the Puget Sound pipeline and 100,000 bbl/d to B.C. delivery points. Since May 2024 the company has loaded well over 500 vessels at Westridge; 82 tankers loaded in the fourth quarter of 2025 alone and 66 in the first quarter of 2026.

The destination mix is the most important change. In 2025, 67% of Westridge loadings went to Asia. S&P Global Commodity Insights counted 374 Aframax cargoes to China, 33 to South Korea, four to India and three to Japan between May 2024 and July 2026. Zhejiang Petroleum & Chemical became China’s largest buyer of Canadian heavy crude at an estimated 178,000 bbl/d in the first eight months of 2026, up 36% on 2025, and South Korea’s refiners aimed to lift Canadian imports to as much as 16 million barrels in 2026 from 4.9 million in 2025. For the first time, Canadian oil producers have a price discovered in Asia rather than only in Cushing, Oklahoma, and the oil sands producers have made that a central part of their growth plans.

What was the toll dispute about, and how was it settled?

The dispute was about who should pay for the cost overrun: Trans Mountain proposed tolls that recovered a larger share of the C$34 billion from shippers than the oil companies believed their 2012–2013 contracts allowed. Shippers including Canadian Natural, Suncor, Cenovus, Imperial, ConocoPhillips, MEG, PetroChina and BP challenged the interim tolls before the Canada Energy Regulator (CER), which opened a hearing (RH-002-2023). The interim tolls were roughly C$11 a barrel for committed shippers, against the C$5–6 range contemplated when contracts were signed, according to reporting at the time of the filings.

After 18 months of negotiations, Trans Mountain filed a negotiated settlement with the CER on 8 July 2026. The settlement establishes a long-term framework for tolls and services, including tolls for 15- and 20-year transportation service agreements and the right for firm shippers to extend their contracts. It also raises the share of capacity that can be contracted to firm shippers from 80% to 90% of nominal capacity, which reduces the volume available for spot shipments but gives the pipeline more predictable revenue. The CER approved the settlement on 28 September 2026, found the tolls just and reasonable, cancelled the RH-002-2023 hearing and noted that no party with a commercial interest had opposed it. The framework takes effect on 1 January 2027.

Chief executive Mark Maki said the framework gives customers and stakeholders greater certainty and predictability, and that with the system running at or near capacity, the company’s focus had shifted to optimising the existing infrastructure. The settlement’s exact per-barrel tolls are in the regulatory filing rather than the public release, so what the shippers conceded, and how much of the overrun the Crown has absorbed, is not fully disclosed. What is clear is that the pipeline could not be sold while the tolls were in dispute, and Energy Minister Tim Hodgson had said as much in December 2025.

Is the pipeline actually making money?

Yes, on an operating basis, though not yet enough to justify the capital spent. Trans Mountain reported adjusted EBITDA of C$2.31 billion in 2025, up from C$1.35 billion in 2024, and net income of C$556 million against C$5 million the year before. It paid about C$1.7 billion to its parent, TMP Finance, through dividends, interest and guarantee fees in 2025, and the company says it has returned about C$2.2 billion in total since the expansion started. First-quarter 2026 revenue was C$729 million with net income of C$97 million, on a lower utilisation of 83% that the company attributed to higher tanker freight rates and customer maintenance.

The arithmetic for a buyer is simple. At roughly C$2.3–2.5 billion of EBITDA and a typical infrastructure multiple of 10–13 times, the enterprise value is in the C$25–32 billion range, which is consistent with the PBO’s estimate and below the C$38 billion or so the government has spent on purchase plus construction. The optimisation projects, discussed below, and the extended contracts in the new toll framework are the levers that could close that gap before a sale.

How much more capacity can the system add without a new pipe?

Up to 300,000 barrels a day, taking nominal capacity from 890,000 to about 1.19 million bbl/d, subject to final investment decisions and regulatory approvals. The first step, the Drag Reducing Agent project, injects chemicals that lower friction in the line and adds about 90,000 bbl/d; it is expected in service in early 2027. The second, the Mainline Optimisation Project, adds pumping horsepower and other upgrades for a further 210,000 bbl/d by the end of 2028. Energy Minister Hodgson told Bloomberg in December 2025 that optimisation could lift capacity toward 1.25 million bbl/d and that Ottawa would consider selling equity only after output had been maximised.

The constraint on the marine side is the Second Narrows in Burrard Inlet, which limits Aframax tankers to partial loads of around 550,000–600,000 barrels. The Vancouver Fraser Port Authority planned to dredge the channel starting in late 2026 to allow fuller loads, which would reduce the per-barrel shipping cost to Asia. Beyond that, Maki has described a longer-term concept to add roughly one million bbl/d of West Coast export capacity with VLCC loading in the 2032–2034 window, which overlaps with the Alberta government’s own proposal for a new one-million-bbl/d pipeline to a northern port. The two ideas compete for the same shipper commitments, and the Alberta–Ottawa negotiations over which one proceeds will shape Canadian export capacity for the 2030s.

Who will own Trans Mountain next?

The most likely outcome is a mixed ownership structure in which Indigenous groups hold a meaningful minority stake and a pension fund or infrastructure consortium holds the rest, but as of October 2026 only the first part has been formally offered. On 22 September 2026 the Finance Department wrote to First Nations along the route offering a combined 15% stake in the pipeline, to be split equally among participating groups and financed through a low-rate government loan. Each participating nation would receive C$2.5 million as compensation for revenue it could have earned had Indigenous ownership existed earlier, plus up to C$100,000 for participation costs, with Ottawa covering independent due-diligence advisers. Details were to be presented at meetings in Vancouver, Victoria, Kamloops and Edmonton in late October 2026, after consultations with 129 First Nations.

Earlier Indigenous-led bidders, including Project Reconciliation, Chinook Pathways (a partnership with Pembina Pipeline) and Nesika Services, had argued since 2019 that any sale should include a majority or at least material Indigenous stake, and the 2024 finance documents contemplated a special-purpose vehicle holding the collective interest. The Carney government’s version is smaller than those groups hoped for but structured to proceed quickly. The remaining 85% has no announced process; Hodgson’s December 2025 comments suggested that Ottawa wanted the tolls settled and the optimisation projects underway first, both of which are now in motion.

The buyer universe for the majority stake is well defined. Canadian pension funds such as CPP Investments, OMERS and the Ontario Teachers’ Pension Plan already own pipelines and regulated utilities, and Brookfield’s infrastructure arm, profiled in the Brookfield story, is a natural bidder. The sticking point is price: a sale at the PBO’s valuation forces the government to recognise a loss, which is politically awkward, while a sale above it requires the buyer to believe in contract renewals two decades out.

What did Trans Mountain change for the rest of the energy sector?

It changed the bargaining position of every Canadian oil producer and of the two private pipeline companies that previously controlled all export routes. Enbridge’s Mainline, which carried 3.1 million bbl/d in 2025, lost its monopoly on incremental barrels, and the differential compression that followed added billions to producer cash flows. The Enbridge and TC Energy story covers how those companies have responded with their own optimisation projects rather than new lines.

It also established a template for public ownership of energy infrastructure that the federal government has since reused. The Canada Infrastructure Bank, the Indigenous loan guarantee programme and the Major Projects Office, created in 2025, all draw on the Trans Mountain experience: the state takes construction and political risk, Indigenous communities are offered equity, and the asset is meant to be sold once de-risked. The West Coast gas terminals, covered in the LNG Canada article, followed a different, privately financed path, which makes the comparison instructive.

Finally, Trans Mountain reset expectations about megaproject costs. Every subsequent proposal, from the Pathways carbon-capture network to Alberta’s new pipeline, is judged against a C$34 billion benchmark that was once unthinkable, which helps explain why proponents now prefer staged, incremental investments and why shippers insist on cost caps before they commit.

What can founders and investors learn from Trans Mountain?

The first lesson is that political risk is a cost like any other, and when the private sector cannot price it, the state ends up paying far more than a market would have. Kinder Morgan’s shareholders exited with a C$4.5 billion cheque and no construction risk; Canadian taxpayers took on a project whose cost quadrupled. For founders, the analogous situation is a contract or market that only works with a government partner: price the dependency explicitly, and be realistic about who holds the downside.

Second, an asset built at the wrong price can still be a good business at the right price. At C$2.3 billion of EBITDA, growing with optimisation, Trans Mountain is a solid infrastructure asset for whoever buys it at the PBO’s valuation. The sunk cost is the government’s problem, not the next owner’s. Investors who distinguish between the economics of the asset and the history of its financing often find value that others, anchored on the headline number, miss.

Third, the toll settlement shows the value of patience in a dispute between parties who need each other. Shippers could not move their oil anywhere else; Trans Mountain could not sell without settled tolls. Eighteen months of negotiation produced a framework with longer contracts and more firm capacity, which left both sides better off than a regulatory ruling would have. Similar dynamics appear across Canadian infrastructure, from the Pacific Gateway ports to the railways.

Fourth, the Indigenous equity model, now being tested at Trans Mountain, Cedar LNG, Coastal GasLink and the Darlington SMRs, is becoming the standard way large Canadian projects secure social licence. Founders in resource, infrastructure and even technology sectors in Canada should treat Indigenous partnership as a design parameter from day one, not a late-stage consultation requirement.

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