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by Lennie Kaplan
Showing demonstrated oil sands supply to support expanded pipeline egress will be critical to the credibility of the Alberta government’s upcoming submission to the Major Projects Office (MPO) on the proposed West Coast Oil Pipeline (WCOP). This includes a realistic identification of oil sands producers who have commercially viable projects, including greenfields, in the queue to support expanded pipeline egress capacity. A greenfield oil sands project refers to an entirely new development of a mining or in-situ oil sands project, rather than the expansion of an existing oil sands facility.
I estimate that, at a long-term oil price path of between $60.00 to $70.00 U.S. per barrel, the economics for not-yet-producing oil sands projects could be sub-optimal, with respect to internal rates of return (IRR), average breakeven oil prices, and years of payback on costs incurred. This is prior to the application of new carbon taxes, as recently announced by Prime Minister Carney and Albera Premier Danielle Smith under the Alberta TIER regime.
With potential sub-optimal returns at long-term oil prices between $60.00 and $70.00 U.S. per barrel, the economics for large greenfield oil sands projects could still be challenging and may need to be bolstered by the introduction of new royalty incentives from the Alberta government to support the significant additional pipeline egress.
The Alberta government appears to have come to that realization. Premier Danielle Smith has indicated that the Alberta government is willing to talk with industry about finding ways to stimulate investment in new oil sands developments — projects that could help fill a new bitumen pipeline to the British Columbia coast. “In this province, we have always had a preferential royalty regime for greenfield (oil sands) development…we’re open to having those types of conversations, that if there is some way that we have to stimulate greenfield investment, those are the kind of conversations we are going to be able to have.”
The Alberta government has plans to double oil production to 8 million barrels per day (bpd) by 2035 to support expanded pipeline egress. Presumably, the new 1 million bpd bitumen WCOP, plus another estimated 1 million bpd of incremental optimization and expansion pipeline egress projects could serve as an initial foundation for the Alberta government’s plan to double oil production by 2035.
Yet, according to a report by ATB Economics and Studio Energy, “building a pipeline provides a surge in economic activity that typically lasts only a few years. But then that pipeline must be filled. The latter requires investment in oil production activities and must continue even after the initial pipeline fill to ensure maximum volumes for decades.”
To meet the 8 bpd target for oil production by 2035, I have estimated there will be a need for a massive wave of new investment, running as high as $150 billion just over the next decade, including maintenance and sustaining capital, optimization, brownfield extensions and expansions, and greenfields.
As some existing oil sands operations begin to reach maturity in the mid-2030s, greenfield development will become a more critical part of the plan to enhance production levels to meet significant new pipeline egress capacity. I estimate there is about 500,000 bpd of oil sands growth through 2035, driven predominantly by brownfield, optimization and extension projects. And there is about 2 million bpd of prospective new oil sands projects that could fill the next wave of pipeline egress expansions after 2030.
A number of greenfield projects will be needed to fill new pipeline egress. Companies will have to bring forward and advance new projects, simultaneously. Currently, oil sands producers appear more focused on sustaining maturing production and maximizing return to shareholders, rather than risking capital in new greenfield developments. This practice may become more pronounced given the uncertainties and volatility prevailing in world oil markets. As well, net zero emissions (NZE) requirements by 2050 by the Canadian and Alberta governments could divert investment capital into CCS and other emissions abatement technologies, such as direct air capture (DAC) for existing facilities.
Back in October 2025, the Alberta government established a Technical Advisory Group (TAG), comprised of industry representatives from South Bow, Enbridge and Trans Mountain, to provide initial advice and recommendations on the proposed pipeline, and presumably examining oil sands supply to fill the line. TAG’s work is being supervised by an Advisory Panel. I think Albertans need to see the advice and recommendations of the TAG now to make an informed decision on the risks and benefits to taxpayers. I am calling on the Smith government to immediately release the work of the TAG.
Some in industry believe that the Canada-Alberta MOU implementation agreement (IA) does not change the reality that Alberta oil sands greenfield face competitive cost pressures to reaching positive FID. Alberta greenfield oil projects, a major element of the Alberta government evolving plan to support expanded pipeline egress, could have sub-optimal economics making additional royalty incentives a possibly. The question is how much Alberta taxpayers may have to take on through royalty incentives on the front-end to unlock the billions in required new investment to support significant new pipeline egress? The Smith government has a responsibility to Albertans to provide some answers to this question in its upcoming submission to the MPO.
Lennie Kaplan is a former senior manager in the Fiscal and Economic Policy Division of Alberta’s Ministry of Treasury Board and Finance (TB&F), where, among other duties, he worked on cross-ministry committees dealing with energy issues, including participating on the Clean Energy Strategic Advisory Committee (CESAT) and the 2009-10 Alberta Competitiveness Review
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