Canada’s Missing Barrels
Alberta’s visible oil-sands growth has cheaper exits. The proposed million-barrel west-coast line needs rerouted barrels, a bigger boom or public risk.
When I wrote a recent assessment of Mark Carney’s Alberta pipeline deal, the cleanest reading was that Ottawa had given Alberta political option value rather than a financed pipeline. That remains the right reading, but the evidence has moved. The project is now more concrete politically because Trans Mountain has been put in the frame as the public-sector vehicle. At the same time, the commercial case has become weaker because the visible barrel denominator is smaller than the proposed pipe and the cheaper exit routes are already lining up.
The July announcement makes the public-risk question harder to treat as theoretical. The proposed west-coast pipeline would carry 1 million barrels per day, would be built by government-owned Trans Mountain in coordination with Pembina, and would be majority-owned by the federal government through Trans Mountain and Alberta through the Alberta Petroleum Marketing Commission. Pembina would hold 10% during construction, with an option for another 10% after the project enters operation, while funding details are still being negotiated. That is not a completed financing package, but it is also no longer only tone and process. Carney has not written the TMX-scale cheque. He has crossed the public-proponent line.
That matters because Alberta’s argument is still being framed as if the province has a large visible barrel problem that only a new west-coast pipe can solve. It does not. Alberta production can grow, and probably will, but the useful question is not whether oil-sands output rises. The useful question is whether the visible growth requires a new 1 million barrel per day west-coast pipeline after existing routes, Trans Mountain optimization, Enbridge optimization and southbound proposals are counted.
The Alberta Energy Regulator’s base case has total raw bitumen production rising from 3.558 million barrels per day in 2024 to 4.061 million barrels per day in 2034. That is about 503,000 barrels per day of additional raw bitumen over a decade. AER is explicit that raw bitumen is not the same thing as marketable pipeline crude: raw bitumen is extracted, viscous material that must be blended or upgraded to meet pipeline transport specifications.
The next step is the one the public argument usually skips. AER’s crude bitumen removals forecast implies that by 2034 upgraded bitumen removals rise by about 48,000 barrels per day, non-upgraded bitumen removals rise by about 329,000 barrels per day, and pentanes-plus diluent for bitumen transportation rises by about 183,000 barrels per day. Add those together and the visible oil-sands-related pipeline stream is roughly 560,000 barrels per day, but about a third of the increment is the light hydrocarbon needed to move the heavier barrel, not new bitumen production.
That 560,000 barrel per day pipeline-stream increment is the denominator. It is not small, but it is also not a million new barrels looking for a new west-coast pipe. It is a mature-asset growth case built out of optimization, incremental expansions and diluent-heavy transport volume. That is a very different commercial story from a new oil-sands boom large enough to justify another 1 million barrel per day export corridor.
The capacity comparator is just as awkward for Alberta’s claim. Trans Mountain has already launched an open season for incremental firm transportation contracts and said future projects would add about 90,000 barrels per day by early 2027 and another 210,000 barrels per day through the Mainline Optimization Project by the end of 2028, lifting total system capacity from roughly 890,000 to about 1.19 million barrels per day. That is the lower-risk west-coast option sitting directly beside the proposed new line: more flow through the existing Crown-owned pipes before a new corridor has to be justified.
The southern route is also not standing still. Enbridge has approved Mainline Optimization Phase 1, adding 150,000 barrels per day to the Mainline and 100,000 barrels per day to Flanagan South in 2027, supported by long-term take-or-pay contracts from Edmonton to Houston. Enbridge has also tested another possible 250,000 barrel per day phase. South Bow’s Prairie Connector is still a proposed project with permitting and final-investment-decision risk, but it is also a large southbound option and has been reported as having 20-year binding commitments for about 80% of proposed capacity. The contrast is not that every alternative barrel of capacity is guaranteed. It is that the alternatives are closer to existing refinery relationships, lower-risk than a new west-coast megaproject, and in some cases already supported by shippers.
This changes the meaning of Alberta’s complaint. The visible 2034 growth case has exits. A new million-barrel west-coast line therefore needs one of three things: rerouted barrels from existing pathways, a larger oil-sands growth wave than the forecast shows, or a toll and risk structure made attractive by the public balance sheet. The first is a displacement story, not a growth story. The second needs upstream FIDs and long-dated shipper commitments that are not visible. The third is the TMX lesson wearing a new hard hat.
The market side does not rescue the argument. Alberta’s crude is not generic oil flowing into a generic global demand pool. It is mostly heavy, sour, diluted bitumen that depends on complex refineries, long-lived transport-fuel demand and discounts wide enough to make the upgrading and coking hardware pay. California, one of the more natural Pacific heavy-crude markets, is losing refining capacity: the EIA says the planned Phillips 66 Wilmington and Valero Benicia closures amount to 17% of California refinery capacity and 11% of West Coast refining capacity, with replacement fuel more likely to come as refined-product imports from Asia than as new crude demand into California refineries.
China is not a simple answer either. It will keep buying crude, including heavy and sour barrels when the price and refinery slate work, but its oil demand story is changing. Heavy-truck electrification is now being pushed by policy, battery suppliers and infrastructure owners, and CATL’s partnership with Sinopec to build 10,000 battery-swap stations explicitly targets range bottlenecks for passenger vehicles and heavy-duty trucks. That does not eliminate Chinese demand for imported crude, but it weakens the diesel-growth story that helps heavy-crude refining economics. The remaining growth wedge is increasingly petrochemical feedstock, where Alberta’s diluted bitumen is not the advantaged molecule compared with lighter streams such as ethane, LPG and naphtha.
What this means is that even the 300 kbpd Mainline Optimization is looking risky given market dynamics. Increasingly, heavy crude refineries will be buying oil on spot markets and the price is going to go down faster than light crude, outside of specific events which push it the other way briefly. Albertan suppliers who are betting on hundreds of thousands of new barrels of their less valuable product finding a market are already making a questionable wager.
The original assessment was that the deal was ugly optics, not a funded pipeline. That remains true, but it is no longer sufficient. The better current framing is that the project is more politically real and less commercially necessary. Ottawa has made the public vehicle more visible, Alberta has made the political demand louder, and the production and capacity numbers have made the missing-barrel problem harder to ignore.
Carney still has a political win even if no pipeline is built. He can say Ottawa opened the door, gave Alberta a route into the Major Projects process, kept the north-coast tanker fight out of the center of the proposal, and let the commercial stack prove itself or fail. If shippers, tolls, Indigenous agreements, Pathways commitments, upstream FIDs or buyers do not materialize, Ottawa can argue that it did not block the pipeline. The market declined to build it. He’s turned Smith and Poilievre’s ammunition into duds in the lead up to the referendum on having a referendum about separation.
For Alberta, that is the uncomfortable part. The province is not short of plausible egress for the visible forecast barrels. It is asking Canada to validate optionality for a larger oil-sands future than the current production forecast shows. That may be useful politics. It may even be useful bargaining. It is not yet a market case.
My earlier conclusion survives, but the update is harsher. Alberta’s visible barrels have cheaper exits, while the proposed million-barrel west-coast line needs barrels not in the forecast, buyers not yet visible, shippers not yet signed or a public balance sheet willing to repeat the TMX lesson. Until one of those appears, the missing barrels are the story.
Subscribe to TFIE Strategy Briefing for the deeper professional layer behind public energy claims: denominator checks, capital filters, comparator cases and decision context for infrastructure bets.