Lennie Kaplan is a former senior manager in the Fiscal and Economic Policy Division of Alberta’s Ministry of Treasury Board and Finance.As the June 2026 deadline for the new pipeline submission approaches, there are still questions swirling around the Alberta government’s business case to double Alberta oil production (raw bitumen and conventional crude oil) to 6 million barrels per day (bpd) by 2030 and 8 million bpd by 2035. Presumably, the new 1 million bpd bitumen pipeline to the northwest BC coast and another 500,000 bpd of incremental pipeline egress projects serve as an initial centrepiece for this increased oil production. The Alberta government now expects to get a proposal on the northwest BC coast pipeline before the Major Projects Office, no later than June 2026. Apparently, the word is that the Alberta government is still looking at five possible deepwater ports.Where the estimate of 6 million bpd by 2030 and 8 million bpd by 2035 of Alberta raw bitumen and conventional crude oil production comes from is a valid question. The Alberta government projects 4.8 million bpd in raw bitumen and conventional crude oil production by 2028/29, requiring a step up of about 1.2 million bpd, or 25%, to reach 6 million bpd by 2030/31. Under the high oil growth case scenario, prepared by the Canada Energy Regulator (CER), Alberta bitumen and conventional crude oil production reach 4.5 million bpd in 2030 and 4.7 million bpd by 2035, somewhat short of Alberta’s 6 million and 8 million bpd targets, respectively. Recent requests to Alberta Energy and Minerals, under Access to Information (ATI), for records associated with increasing Alberta's oil production to 6 million bpd in 2030 and 8 million bpd in 2035 reveal that no documents were prepared. This is surprising. The Alberta government has signalled numerous times that it needs more oil production and oil revenues to balance its budget over the medium-to long-term. This was reinforced with Budget 2026.Pipelines, such as the one now being proposed by the Alberta government, have high capital expenditure (capex) requirements, risks of capital cost overruns, long timelines for construction (3 to 5 years), and, as part of a robust business case, need to clearly show demonstrated oil supply to fill the line. It is estimated that to meet this expanded level of oil production would require a massive wave of new private sector investment, running as high as $150 billion over the next decade, including maintenance and sustaining capital, optimization, and expansions..I am fully supportive of new pipelines development as long as it is based on a solid business case, developed by the private sector, and not by governments. The government is simply not proficient at “being in the business of business.” In the past, Alberta governments have been unsuccessful at creating the conditions for expanding oil egress capacity. In 2013, the Alberta Petroleum Marketing Commission (APMC), a crown agency, signed a transportation services agreement (TSA) with the Energy East Pipeline Limited Partnership to purchase 100,000 barrels per day of firm capacity for a term of 20 years to transport volumes of crude oil, with a take-or-pay obligation to pay $4.6 billion in tolls over the 20-year term. Energy East did not go forward, and the APMC, fortunately, did not incur any financial commitments or liabilities. In 2019, the Alberta government committed $3.7 billion to build out oil egress rail infrastructure, with a successor Alberta government divesting of the crude-by-rail contracts at an estimated loss of $2.1 billion. In 2020, the Alberta government invested $1.5 billion in reviving the Keystone XL pipeline, to be followed by a $6 billion loan guarantee in 2021. Keystone XL ultimately did not move forward, leading to a loss of about $1.3 billion, but, fortunately, there was no draw on the loan guarantee.As noted earlier, one of the critical components of a full business case for the pipeline is a robust assessment of demonstrated oil sands supply to justify expanded egress. This includes a sober identification of oil sands producers who have commercially viable projects in the queue to support expanded egress capacity, and working with oil sands producers to assess market demand for these projects. According to a recent 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.” The question becomes: how much new incremental oil sands production could be available to fill an initial expanded pipeline egress of about 1.5 million bpd in total?According to conversations with a number of informed observers, it is estimated there is about 375,000 bpd of oil sands growth through 2030 and 500,000 bpd of oil sands growth through 2035, driven predominantly by brownfield and optimization projects. Presumably, this could be largely met by growing pipeline capacity through debottlenecking and optimization efforts at existing pipelines. In fact, some suggest that with about 600,000 bpd of planned debottlenecking and optimizations on the books, there could be sufficient pipeline capacity into the early 2030s..Of course, there is some upside to these initial numbers. It is conservatively estimated that there are about 1.5 million bpd of other potential capacity additions that could fill the incremental egress. However, the upside case for the 1 million bpd Northwest BC pipeline would likely require companies to bring on a number of new projects and to progress these projects simultaneously. Currently, companies appear more focused on sustaining maturing production, rather than risking capital in new developments. This sentiment may become even more pronounced given the uncertainties and volatility prevailing in oil markets. As well, net-zero requirements by the Canadian and Alberta governments could divert investment capital into CCUS and other emissions abatement technologies. Clearly, potential investors want and need certainty.Mitigating the risk of capital cost overruns and rebalancing the risk and reward structure will need to be addressed in developing the business case for the new pipeline. In the past, risks of capital cost overruns were largely dealt with through risk-sharing arrangements between shippers, with pipeline tolls sometimes adjusted higher for all or a portion of the cost overrun. However, the experience with the Trans Mountain Expansion (TMX) massive cost overruns will likely make shippers less likely to take on that type of exposure through adjusted tolls. In fact, assuming market forces prevail, tolls on a proposed northwest BC pipeline project could range between $10 USD per barrel and $15 USD per barrel. In light of shippers’ potential reluctance, would the Alberta government, through the Alberta Petroleum Marketing Commission (APMC), directly support the pipeline project by physically taking royalty barrels in kind and committing those volumes to a long-term take-or-pay contract at a toll above current market rates, effectively guaranteeing a return to the pipeline owner?At this point, no private sector companies have publicly emerged with a willingness to take on the financing of the $30 to $40 billion pipeline project. Although the Alberta government still claims it will not build the pipeline or significantly incentivize the private sector to take on such a build, many in the industry believe that the financing structure will eventually need to take the form of a government-led backstop that effectively rebalances risk and reward, through a combination of a fixed return on capital deployed or shifting cost risk away from the private sector proponent. Could the Alberta government take on cost risk over and above a pre-determined capital amount, helping the pipeline proponents reach a positive final investment decision (FID)?.A rigorous, evidence-based and private sector-led approach to pipeline development is needed to prevent a repeat of earlier costly pipeline episodes to taxpayers. If crown agencies, such as the APMC, the Alberta Indigenous Opportunities Corporation (AIOC) and the Heritage Fund Opportunities Corporation (HFOC), do become involved in the northwest BC coast pipeline project, there must be a comprehensive business case prepared and presented to Alberta taxpayers, to allow them to evaluate both risks and rewards.It appears that there is at least some initial interest from the AIOC. A recent request to the AIOC under Access to Information (ATI) for documents relating to the provision of loan guarantees to facilitate the purchase of an indigenous equity stake in a proposed northwest BC pipeline revealed 137 pages of withheld records. However, it does not appear that APMC has been involved in business case development. A recent request to the APMC under ATI for records created by or for the APMC CEO; VP, Operations; VP, Pricing and Analysis; Business Development Division; and the Marketing Division evaluating the feasibility of the proposed northwest BC coast pipeline turned up no documents.Demonstrated oil supply and mitigating the risk of capital cost overruns are critical elements that should be led by the private sector proponents with the necessary expertise, and not by governments. The pipeline development process must be private sector-driven and private sector-managed and based on the “hard facts on the ground.” It should not be politically-led and stage-managed by the Alberta government.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.
