Alberta’s Million-Barrel Pipeline Needs Missing Barrels

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Canada has made a proposed one-million-barrel-per-day west-coast pipeline more politically real just as the barrel case has become harder to defend. The official project now has a route concept from the Edmonton region to southern British Columbia, Trans Mountain as the public-sector builder and operator, and an ownership structure involving Trans Mountain, the Alberta Petroleum Marketing Commission and Pembina. Ottawa has moved beyond offering Alberta political option value and put a Crown corporation into the project structure. The missing step is evidence that one million barrels per day need the new exit.

The useful number is Alberta’s visible production growth. The Alberta Energy Regulator forecasts raw bitumen output increasing from 3.558 million barrels per day in 2024 to 4.061 million in 2034, an increase of about 503,000 barrels per day. Most of that growth comes from optimization, debottlenecking and expansion of existing facilities. AER does not expect a new greenfield oil-sands mine to enter service during the forecast period, which makes this a mature-asset growth case rather than another oil-sands boom.

Raw bitumen is not the pipeline denominator because much of it must be upgraded or blended with a lighter hydrocarbon before it can move. AER’s removals forecast shows upgraded bitumen increasing by about 48,000 barrels per day, non-upgraded bitumen by about 329,000 and pentanes-plus diluent by about 183,000. Together, the visible increase in the oil-sands-related pipeline stream is roughly 560,000 barrels per day. Almost one-third of the increment is diluent used to move the heavier barrel, not additional bitumen production.

That leaves the proposed line at nearly twice the visible growth stream. It could still be filled by taking existing barrels from Trans Mountain, Enbridge or other routes, but that would make it a displacement project competing for current traffic rather than infrastructure required by forecast growth. That distinction matters because a new corridor, pump stations and marine terminal have to be financed against long-lived contracted volume, not against a general claim that Alberta produces a lot of oil.

The real comparator is expansion of the system already in place. Trans Mountain says drag-reducing agents and its Mainline Optimization Project could add up to 300,000 barrels per day to the existing system by the end of 2028. Enbridge has taken a final investment decision on a first optimization phase adding 150,000 barrels per day to its Mainline and another 100,000 farther south on Flanagan South in 2027. South Bow is also marketing roughly 450,000 barrels per day of firm service from Hardisty to US delivery points through its proposed Prairie Connector.

These projects do not all have final regulatory approval, and their capacities are not perfectly interchangeable. They do, however, use existing corridors, facilities and refinery relationships. That usually means lower capital exposure, shorter development schedules and less volume risk than a new 1,250-kilometre pipeline with a new marine terminal. Alberta’s visible growth therefore has plausible exits before the new west-coast line is counted. This is an assessment based on the project configurations and development status, not a claim that every announced expansion will proceed.

Once those exits are included, the new project needs some combination of three commercial stories. It can win existing barrels away from other routes. It can depend on a substantially larger oil-sands expansion than the regulator currently forecasts. Or public ownership, financing and toll design can absorb enough risk to make the volume case acceptable to shippers.

The federal–Alberta Pathways Plus material is unusually candid about the second route. Alberta has agreed to implement financial supports intended to encourage the oil-production growth required to underpin the new west-coast line, Trans Mountain expansion and other egress growth. The sequence is capacity first, then policy support for the production needed to fill it. That may be a legitimate political and industrial choice, but it is different from responding to barrels that are already stranded.

The scale of that production requirement is easy to understate. One million barrels per day is almost 30% of Alberta’s current raw-bitumen output, so filling the line with genuinely new production would require another major development cycle of mines, in-situ projects, processing facilities, steam and power systems, diluent logistics and supporting infrastructure. A reasonable order-of-magnitude estimate is about C$100 billion of new upstream oil-sands investment, before the pipeline and marine terminal themselves are counted. That is consistent with Ottawa’s estimate that the complete Pathways Plus package—production growth, carbon capture and the west-coast line—could catalyse more than C$200 billion of investment. The proposal is therefore not simply an export route for growth already underway; it depends on financing and building another oil-sands megaproject program to create the barrels that would justify it.

The proposed ownership structure sharpens the issue. After Pembina’s construction-stage interest, Trans Mountain and the Alberta Petroleum Marketing Commission would own equal shares of the balance, putting majority public capital into the project from the beginning. That may reduce financing friction and keep the proposal alive through a difficult development cycle, but it does not create contracted barrels. It changes who absorbs underutilization, toll pressure and market risk if the commercial stack remains incomplete. The barrel denominator therefore belongs near the start of the decision, not after the route and ownership model have gathered political momentum.

The buyer side creates another constraint. Alberta’s main export product is diluted heavy, sour bitumen, which needs specific refinery hardware and economics; it is not a generic barrel entering a generic global pool. California has lost substantial refining capacity, while replacement supply is increasingly expected to arrive as refined products. China will continue importing crude, but its expanding battery-swapping and electric-transport systems weaken the durable diesel-growth story that supports heavy-crude refining economics over a multi-decade pipeline life.

None of this proves that a new west-coast pipeline can never secure enough volume. Higher oil prices, new upstream approvals, shipper commitments or rerouting from existing systems could change the case. The current evidence says those are requirements for the project, not details to be settled after approval.

For policymakers and capital providers, the central question is who carries the mismatch if the barrels, shippers and buyers do not appear. A politically useful option can become a poor infrastructure bet when volume risk, toll risk and market risk migrate to the public balance sheet.

The detailed production and removals arithmetic, competing-route analysis, refinery-market assessment and political implications are in Canada’s Missing Barrels at TFIE Strategy Briefing. The missing barrels are not a rhetorical flourish. They are the commercial case the project still has to establish.