OPG, Capital Power to Explore Small Modular Nuclear Reactors in Alberta
Ontario Power Generation (OPG) and North American power producer Capital Power Corp. will jointly examine the feasibility of developing small modular reactors (SMRs) in Alberta, including possible ownership and operating structures.
The companies on Jan. 15 announced they signed a two-year commitment agreement to assess the feasibility of jointly owning and operating SMRs in Alberta that will supply electricity to Alberta’s electricity market—Canada’s only energy-only market.
Capital Power, a publicly traded company headquartered in Edmonton that holds a 7.7-GW, 30-facility fleet, said the partnership with OPG presents a new potential pathway with which the company can meet demand growth. “We are at the forefront of electrification, which will drive continual growth in demand for power. The deployment of SMR technology will provide an important source of safe, reliable, flexible, affordable, and clean baseload electricity in Alberta in the future,” noted Avik Dey, president and CEO of Capital Power.
Vetting the Viability of 300-MWe Reactors
During a streamed press conference on Monday, officials from the companies suggested the study will evaluate SMRs of about 315 MWe each. The partners will review a range of technologies, including GE Hitachi’s BWRX-300, Capital Power told POWER.
Dey suggested a potential in-service timeframe target of “between 2030 and 2035,” though he noted the agreement kicks off “formative work.” That will include engagement with partners and stakeholders to advance regulatory and permitting, as well as pinning down the project’s technical and financial viability, he said. “The first two years in our commitment to each other is really focused on understanding the technology and building the case for the deployment of the technology here in Alberta.”
Ken Hartwick, OPG president and CEO, said the partners are exploring SMRs over large-scale nuclear reactors like CANDUs, which make up the bulk of Canada’s existing fleet, owing to several requirements. “We like [CANDU] technology, but our decision to go with SMRs—and they are about 315 MW each—was really driven by the need to be able to basically get to the ‘M’ in SMR, which modularization,” he said. “They’re better for certain grids that don’t need 1,000 MWs or 2,000 MWs at a particular site,” he said.
Dey underscored the installations must fit within the framework of the existing Albera market structure. Modularization is also important, given its significance in bringing “plants on stream in a reasonable time period, at reasonable cost estimates,” he said. Alberta, he noted, is bringing online more than 2 GW of natural gas–fired generation capacity this year. “So over the course of the next five to 10 years, at least until 2030, we have enough supply in the province to meet the province’s energy demand currently,” he said. “A 300-MW facility is actually right-sized for the market that we have here, notwithstanding the growing demand.”
On Monday, Alberta’s Minister of Affordability and Utilities Nathan Neudorf also suggested the provincial government is evaluating how its transmission grid can best support an optimal buildout. “The modular part is extremely attractive because you could couple three or four [SMRs] together like they’re doing in Ontario,” he said. “Or we could look at a region of our province that is more remote and on a single line where we could place a single SMR that can reach a significant community that way.”
Economics will be another key consideration. While the potential project doesn’t yet have a capital estimate, the feasibility assessment is expected to shed light on potential requirements. “We need to work in partnership with government and stakeholders to accelerate the regulatory and permitting and then really determine the ecosystem in which these modular units will operate,” Dey said. “So safe operations, fuel waste, all of those things will be considered over the next couple of years as we look to assess the viability of it.”
A Fresh Opportunity for Energy-Intensive Alberta
While still nascent, the development opens a pivotal opportunity for Alberta, Canada’s most energy-reliant province. According to the Alberta Electric System Operator (AESO), a non-profit entity that manages and operates the provincial power grid, the province is powered by 426 qualified generating assets with a combined capacity of 18.3 GW. As of January 2024, the region had a combined maximum capacity of 20 GW. More than 71% of its power was gas-fired, 9% wind, 7% coal, 5% solar, 4% dual fuel, and 2% hydro.
But the AESO notes the province’s grid is rapidly transforming. In step with the provincial government’s enactment of a coal phaseout in 2015, Alberta is now down to only two coal power units: the 400-MW Genesee Unit 1 and the 420-MW Unit 2, which Capital Power owns and operates.
Capital Power is scheduled to complete the units’ repowering by 2024 with natural gas combined cycle technology. The units will use Mitsubishi Power M501JAC gas-fired combustion turbines and Vogt triple-pressure heat recovery steam generators to boost their combined capacity to 1,332 MW. Capital Power also owns and operates the 466-MW Genesse Unit 3, a dual-fuel facility that completed upgrades in 2023 to enable it to burn 100% natural gas as its primary fuel source.
Still, the AESO has cautioned that decarbonizing its power system by 2035 as proposed by Canada’s August 2023–released draft Clean Electricity Regulations (CER) is not feasible. “Unlike other provinces, Alberta does not have enough non-emitting base load electricity like hydro and nuclear. Nor is there enough time to build these by 2035,” the Alberta government noted in September 2023, as part of its response to the CER.
“To reach net zero, we would need to transform our entire power system—which took decades to develop—in just 12 years. The province has a plan to keep rapidly cutting GHG emissions as we approach 2035, but achieving net zero electricity by that time isn’t feasible or realistic,” it said.
The province has underscored that Alberta has limited intertie connection capacity with neighboring jurisdictions, and it cannot rely on significant increases in non-emitting imports/exports to balance its system because “current ties are constrained. “Increasing intertie capability by significant volumes to balance intermittent generation across regions will take significant time and coordination between jurisdictions, beyond the 2035 horizon,” it notes.
Meanwhile, implementing carbon capture on its natural gas power fleet will require federal clarity, and supportive infrastructure could take “many years to develop, approve, and operationalize,” it suggests. And while Alberta leads Canada’s wind and solar power production, their intermittency poses reliability impacts.
Alberta has suffered several close calls, especially during relatively colder months, events that it says showcase “the importance of having sufficient stable baseload power sources like gas, hydro and nuclear.” So far this year, it issued an alert on Jan. 13, as the grid operator warned supply shortfalls could amount to up to 200 MW amid extreme cold temperatures in western Canada, restricted imports, and very high demand. It issued another alert for Jan. 15, citing extreme cold and several power facility outages.
Cautiously Supportive of New Nuclear
Alberta is supportive of new nuclear, though it underscores limitations. In March 2022, the province joined New Brunswick, Saskatchewan, and Ontario in a joint strategic plan outlining a path forward on SMRs. In a 2022 study evaluating its net-zero options, AESO noted SMRs “provide promising opportunities” if cost declines materialize or technologies advance dramatically. It suggests, though, that the probability of these technologies maturing and commercializing before 2035 is “highly unlikely.”
Nuclear facilities “tend to have relatively high capital costs compared to other generation technologies. The long development timelines and high capital costs challenge merchant power investment in nuclear-fission generation technology. Financial support, financial guarantees, or long-term contracts are likely required to develop nuclear fission power stations in Alberta at the time of publishing this report,” it said.
The grid operator however has more recently acknowledged the value in “monitoring and learning from other jurisdictions’ experiences deploying utility-scale electricity generation projects.”
Several provinces are watching OPG’s first SMR deployment, which will begin with the construction of the first GE Hitachi BWRX-300 reactor at its Darlington New Nuclear Project (DNNP) site east of Darlington Station in Bowmanville, Ontario. In July 2023, the Ontario government also announced approval to proceed with planning and licensing for three additional SMRs for a total of four SMRs (a combined 1.2 GW) at the DNNP. OPG has said developing DNNP as a four-unit site has cost benefits related to common cost sharing associated with the first unit’s installation, allowing the plant to perform more competitively compared to other forms of clean power generation.
Saskatchewan provincial utility SaskPower in June 2022 also selected the BWRX-300 for the province’s first two potential nuclear units, and it later shortlisted two site study areas for evaluation: Elbow and Estevan. However, SaskPower intends to decide if it will build a BWRX-300 project in 2029, potentially allowing it to leverage OPG’s experience, knowledge, and expertise. SaskPower anticipates construction of its first SMR could begin as early as 2030, with a targeted in-service date of 2034.
During a public information session in November 2023, Karim Osman, DNNP engineering director, said OPG expects a license to construct from the Canadian Nuclear Safety Commission (CNSC) in 2024, with the first round of public hearings focused on the environmental assessment for all four units scheduled this month. In fall 2024, a public hearing related to the license for the first unit will commence. “We expect to have our first unit ready for commercial operation in 2029.” Upon completion of the construction of Unit 1 is when, with the requisite approvals, we would be proceeding with Units 2, 3, and 4, and that would take us through from 2034 through 2036.”
On Monday, Hartwick noted OPG is still working to pin down cost estimates. To obtain a license to construct from the CNSC, “you go through and review all the technical specs and these types of things. That’s expected to be provided early in the new year, so January or February of 2025,” he said. “At that point, we’ll have sufficient information to be able to put a cost number for all [DNNP] four units. It’s an important step because we think the first one is going to be a little bit more expensive. We know that, and we’re spending a lot of cost to do that in Ontario. But we anticipate the other three being less, and we anticipate something like [Capital Power] being able to utilize our learnings so they get the benefit of a lower cost to build there.
Still, the SMR cost proposition will be sound, Hartwick suggested. “We are very convinced that this is very competitive with wind, solar, batteries, or the combination of those, and like, say, on days like this past weekend, will actually work.”
SMRs Potentially Larger Role for Alberta’s Oil Sands, EOR, Critical Minerals Recovery
If Capital Power embarks on building SMRs, they won’t be the first nuclear units developed for Alberta. In 2005, efforts began to develop the four-unit Peace Region Nuclear Power Plant Project in the Peace River region of Alberta, a major oil sands area, with the intent of utilizing nuclear energy for the oil sands and partly replacing natural gas for energy production for bitumen extraction and processing. But while Ontario-based Bruce Power adopted the C$10 billion project with its acquisition of Energy Alberta in 2008, the company abandoned its plans in 2011, saying it would instead focus investments on increasing reliability and safety at its existing Bruce Power nuclear-generating station in Ontario.
On Monday, Alberta’s Minister of Energy and Minerals Brian Jean suggested SMR projects could accomplish a range of ambitions, including those for Alberta’s oil sands, one of the world’s largest deposits of crude oil. He said the province has already begun some legwork. “We are exploring exciting options for a regulatory framework to make sure that we bring clarity around the province’s nuclear approach, and we’re cooperating with OPG and the government of Ontario in that regard,” he said.
Alberta is also funding a multi-year study that will look at “how SMRs could be safely technically and economically deployed for oil sands operations, which we think has a future,” Jean said. “Jurisdictions all over the world right now are pursuing SMRs as the demand for electricity and energy security grows. It becomes more and more evident every day as we see what’s going on around the world. And SMRs truly have the potential to supply non-emitting energy and a number of different applications,” he noted.
“In Alberta, there is a potential to use SMRs to decarbonize enhanced oil recovery and the critical minerals value chain—which is coming about—and we’re creating the conditions for a diverse energy mix that will incorporate various energy sources, including SMRs.”
—Sonal Patel is a POWER senior associate editor (@sonalcpatel, @POWERmagazine).
Editor’s Note: Updated with information released on Jan. 15 during a press conference hosted by OPG and Capital Power and other details.