Here’s what’s in this article:
- Alberta’s reliance on fossil fuels presents a significant decarbonization challenge, with potential nuclear power providing a solution. Installing nuclear capacity could avoid 53 million tons of CO₂ emissions annually, highlighting the need for a shift in energy sources.
- Alberta’s current grid is heavily dependent on gas-fired cogeneration, with Suncor playing a major role in this system. The province’s median cogeneration capacity remains low, emphasizing the limitations in transitioning to cleaner energy sources without substantial investment.
- Suncor like all oilpatch majors flirted with wind power but soon realized wind is a drag on resources, cannot replace or displace natural gas in Suncor’s operations and hence does not reduce CO₂, and won the company no “green points” with ESG activists. So it divested from wind.
- Suncor’s oilsands extraction and processing produces vast amounts of CO₂. By integrating nuclear power into its processes, Suncor could significantly reduce emissions, potentially avoiding up to 7.7 million tons of CO₂ each year at Base Plant alone.
- However, despite the benefits of nuclear energy, the lengthy licensing process poses a significant barrier to its implementation in Alberta. Reducing the duration of this process is crucial for enabling timely investment and infrastructure development for nuclear energy.
- Suncor faces a dilemma in considering nuclear energy for its operations, with high capital costs and regulatory hurdles complicating implementation. Streamlined licensing could pave the way for nuclear solutions, making it a viable option for sustainable energy in Alberta.
Over the years, there’s been much talk, and unfortunately no meaningful action, about nuclear power in Alberta. The province’s grid is nearly entirely fossil powered. A late November week showed a demand baseload of just over 10,200 MW. If you didn’t know anything about Alberta’s grid, you’d think a 10,200 baseload would present an easy decarbonization challenge: simply install 10,200 of nuclear generation capacity. That would avoid 53 million tons of CO₂ emissions per year.
But not so fast. The largest component of Alberta’s baseload supply is “Cogeneration,” which is gas fired. There are 41 cogen units connected to the provincial grid, and they range in electricity generation capacity from 5 to 856 MW. Half have a capacity of less than 95 MW; three quarters less than 202.
As recently as early October 2024, the Alberta cogen fleet median capacity was 45 MW, and three quarters of the fleet was less than 120, and the maximum was 510. So somebody added a lot of capacity to one plant. That somebody was Suncor, and the plant was their Base Plant, a complex of oilsands surface mines near Fort McMurray.
Alberta in 2023 produced roughly 1.2 trillion kWh of natural gas, according to the provincial energy regulator. Oilsands processors used roughly 420 billion kWh of that. Yes, decarbonizing the process heat side of all oilsands would avoid 78 million tons of CO₂ annually. Added to the CO₂ avoided from decarbonizing the provincial baseload electrical supply, that’s 131 million tons of avoided emissions each year. Totally possible, simply by building a fleet of nuclear power reactors.
Suncor is an integrated oil patch major. By trailing twelve-month revenue, it is the second-biggest oil patch company in Alberta, with $50.73 billion as of September 2024 (Cenovus is #1, with TTM revenue of $55.99 billion). Suncor makes money by selling bitumen and related value-added products, which it produces at several locations in the Athabasca oilsands. It also sells electricity generated at the same locations. Of the 41 cogen units connected to the Alberta grid, Suncor owns and/or operates five. Two, Firebag and MacKay River, are co-located with in-situ bitumen extraction based on steam-assisted gravity drain (SAG-D), which requires roughly 2,480 kWh (226 cubic meters) of natural gas to make the steam to produce 11,900 kWh (1 cubic meter) of bitumen.
If Suncor didn’t cogenerate electricity at its SAG-D operations, i.e., if it only produced bitumen, then that ratio would be just under 2,100 kWh of gas per cubic meter bitumen produced (0.174 kWh gas per kWh bitumen). So the additional roughly 386 kWh of gas for cogen with SAG-D, which generates maybe 115 kWh of grid electricity, must be worth it. At the 2024 average Alberta pool price of 6.4 cents per kWh, the 115 kWh of energy sold to the grid per cubic meter of bitumen produced at a SAG-D cogen operation fetched $7.36.

Suncor also extracts bitumen at surface mines. Its gas-to-bitumen ratio with cogen at those sites is roughly 0.131 kWh gas per kWh bitumen (142 cubic meters of gas per cubic meter bitumen). Base Plant is co-located with a surface mining operation, which might explain the big powergen capacity increase. Cogen with surface mining yields roughly 141 kWh of electricity per cubic meter of bitumen produced—$9.06 at the 2024 average price. For the gas, the company paid an average of 0.48 cents per kWh in the nine months up to October 2024. For the 423 kWh of gas used to make the 141 kWh of grid electricity with surface mining cogen, Suncor paid $2.05. So the powergen fuel cost was 1.45 cents per kWh.
How would nuclear-generated steam compare cost-wise with the “purchased gas” that Suncor uses at its bitumen-processing operations? Nuclear fuel costs are cheap, less than what Suncor paid for purchased gas in 2024. But capital cost, and capital payback duration, is where it gets you. There are no nuclear plants in Alberta (see previous sentence), so somebody would have to build one. Co-located at a Suncor oilsands operation? Then Suncor would have to build it, or buy it, and get a license to build/install and operate. If not co-located, then the heat for steam would be electric, from the Alberta grid. Heat pump is viable for process heat, but the powergen part would obviously be superfluous.
If nuclear was ever in consideration at all as the energy source for the expanded Base Plant, it likely took Suncor several seconds, possibly minutes, to rule it out.
A version of this article appeared in the January 2025 Look Ahead edition of the CNWC Newsletter. For more CNWC content, please visit that link.