Author: Lennie Kaplan
As I predicted back in June 2026, Premier Danielle Smith and the UCP government are now expected to announce a package of royalty incentives in early November to reach their oil production roadmap target of 8 million bpd by 2035 to align with prospects for expanded pipeline egress.
Last year, Premier Smith mandated the Alberta Energy Ministry to produce a roadmap to reach 8 million bpd by 2035.
Apparently, the Ministry has finally prepared an internal roadmap document, but a recent access to information (ATI) request for that document yielded just six blank pages. So, let’s fill in the blanks a bit through this commentary.
Reaching 8 million bpd of oil production by 2035 is critical to the sustainability of Alberta government finances, over the medium to long term, given the Alberta budget’s heavy reliance on non-renewable resource revenues (NRRR) to fund the ongoing and rising costs of programs and services.
In this commentary, I estimate the royalty incentives the Alberta government will need to provide, between 2027 and 2050, so that optimization, expansion and brownfield and greenfield projects clear their respective investment hurdle rates to reach the 8 million bpd government target by 2035, under upside, base and downside cost and price scenarios.
The analysis incorporates TIER carbon pricing under the May 2026 Canada–Alberta Implementation Agreement, as well as the Alberta government’s net zero emissions commitment by 2050 (Alberta NZE 2050).
The Alberta Energy Regulator (AER) recently released its Alberta Energy Outlook (AEO ST-98). It shows that reaching the 8 million bpd pathway will be demanding.
ST-98 projects about 5.5 million bpd in oil production by 2035. Reaching 8 million bpd then requires roughly 2.5 million bpd of new capacity by 2035, and close to 2.9 million bpd by 2050, as the production base begins to decline after 2035. This is equivalent to about 25 new SAGD phases or mines, plus pipeline egress well beyond the proposed one million bpd Pacific Link line.
I estimate that Alberta oil production will need to rise by about 390,000 bpd per year on average between 2027 and 2035, roughly double the fastest sustained growth the oil sands have ever achieved.
Expansions would carry the largest share (1.1 million bpd in 2035), followed by greenfield projects (725,000 bpd), optimization projects (650,000 bpd) and brownfield projects (625,000 bpd).
After 2035, optimization volumes decline, and ST-98 base production erodes, so sustaining the 8 million bpd requires roughly 150,000 to 250,000 bpd of new capacity every year between 2036 and 2050, and with it, likely a continuing royalty incentive program.
Without the fiscal incentive package, the province reaches about 7.5 million bpd in 2035, about 500,000 bpd short, because only part of the brownfield project inventory and almost none of the greenfield project inventory clear their FID hurdles.
Alberta NZE 2050 abatement is the main reason later greenfield projects need higher incentives: a 2045 greenfield FID faces higher abatement costs over most of its life and a shorter period before 2050 from which to recover its capital costs.
My calculations suggest that optimization projects are already largely profitable in all cases.
Brownfield projects sit close to the FID hurdle in the base case (IRR of 14.5% vs 15% IRR in 2030), but later brownfield projects will need more relief as carbon and abatement costs rise under Alberta NZE 2050.
Greenfield projects need WTI prices near US$100.00 per barrel to earn FID of 16% IRR under BAU, about US$20.00 above the ST-98 price path. Royalty relief lowers that breakeven to about US$85.00 per barrel, but only when combined with a capex credit, as well.
The Alberta government’s upcoming fiscal incentive package is likely to be concentrated on brownfield and greenfield projects.
In the base case, optimization projects need no relief; expansions need, on average, 25% of royalties initially waived; brownfield, 40% of royalties initially waived; and greenfield, 95% of royalties waived initially, plus a capital top-up of about 20% of capex, because even a full royalty holiday is not enough for higher-cost greenfield projects at the FID 16% hurdle rate.
I estimate that the base case royalty relief package at $115 billion, in nominal terms, between 2027 and 2050, is comprised primarily of $95 billion of royalty relief and $18 billion of capital top-ups. Base case royalties rise from $550 billion cumulative under BAU to $800 billion cumulative under royalty relief over the period 2027 to 2050 — a net fiscal gain of $250 billion, after relief and top-ups, because the barrels would not exist without the incentives. However, in the downside case, the cost of royalty relief is $240 billion, mostly due to $145 billion in capital top-ups, contributing to a net fiscal loss of $80 billion.
I find that royalty relief alone cannot reach the 8 million bpd target, except in the upside case. With relief capped at 100% and no capital support, 2035 oil production would fall short by 900,000 bpd in the base case and 2.5 million bpd short in the downside case.
As it finalizes the design of the royalty incentive package, the Smith government should consider the following issues.
· Establish a targeted program: Project-specific relief (brownfield and greenfield, predominantly) should be emphasized, with approval contingent on the economics of the project;
· Make relief price sensitive: The relief schedule should be tied to WTI prices to avoid over-paying when prices are high and under-delivering when prices are low;
· Prioritize by category: While expansions and brownfields may need some targeted relief, it is greenfield projects that will likely need the most relief, plus capital support, to reach their FID hurdle rates;
· Match projects with egress: A staged relief program, such as greenfield tied to firm egress, will best match cost to need. Roughly 3 million bpd of additional takeaway is required by 2035, but the proposed Pacific Link pipeline provides only about 1 million bpd of that takeaway;
· Execution: About 390,000 bpd of production growth per year will require labour, fabrication, diluent and regulatory throughput well beyond recent peaks;
· Plan for the downside: If WTI settles near $60.00 per barrel, no affordable royalty package reaches 8 million bpd by 2035. Thus, the Alberta government should define a fiscal ceiling on its relief package and an explicit fallback target on oil production by 2035;
· Required relief appears to rise over time. Carbon and abatement costs will rise significantly under Alberta NZE 2050, so later greenfield projects will likely need more relief to reach FID hurdle rates.
How much will Alberta taxpayers be taking on through royalty incentives to unlock billions in required new investment to support new pipeline egress? Albertans are awaiting answers to that question by early November.
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 in the Clean Energy Strategic Advisory Committee (CESAT) and the 2009-10 Alberta Competitiveness Review.