See above for our interview with Evan Pivnick of Clean Energy Canada.

Alberta currently has just over 1200 MW of coal generating capacity left on its system. The Genesee units 1, 2 and 3 at Warburg will be converted to natural gas before the calendar turns to 2023.

At that point, Canada’s fourth-largest province will be fully transitioned from coal-fired electricity. It represents quite a shift, as coal represented more than half of Alberta’s fuel mix just eight years ago.

So how did this happen? Industry experts and elected leaders attribute it to aggressive policies from both the federal and provincial government, as well as shifting market dynamics, like lower natural gas prices and competitive solar and wind.

Timeline for coal exit

Coal’s dominance in Alberta’s electricity market has declined steadily since the 1980s, when coal-fired generation provided over 80% of the province’s electricity.

When the Alberta New Democratic Party (NDP) government was elected in 2015, coal power remained over 50% of the province’s installed capacity.

Previous federal regulations had required 12 of Alberta’s 18 coal-fired units to be retired by 2029. But in 2015, Rachel Notley’s Alberta NDP government accelerated the phase-out of the province’s six youngest coal units, owned by TransAlta, ATCO, and Capital Power. The provincial government also announced it would align with the Federal government’s 2030 target to phase out coal altogether.

In November 2016, the government announced off-coal agreements with TransAlta, ATCO and Capital Power. Through those pacnts, the provincial government would pay out a total of C$1.36 billion ($1.03 billion) over 14 years (2017–2030), with the funds coming from the province’s carbon tax on large industrial emitters.

The agreements were confidential, so details other than the level of compensation are not publicly known.

But in a 2019 report, the non-partisan Parkland Institute at the University of Alberta noted some general details were made public; for example, the three companies agreed to keep their headquarters and a small number of employees in Alberta, and to keep investing in the province’s power system.

Evan Pivnick, Program Director for Clean Energy Canada, told Power Engineering that because Alberta is a private deregulated market, the government had to offer incentives for companies to move faster.

“It had less to do with what the goal was, rather than what the markets did in response to a suite of incentives and regulations that were put in place,” he said. “There were lots of reasons for companies to jump off.”

Underlying all of this were lower natural gas prices and competitive wind and solar options.

“From a from a cost perspective, the ability to stand up new generation has been relatively seamless, and we have seen the vast majority of it go to natural gas,” said Pivnick.

In mid-2017, ATCO and TransAlta—the two biggest coal power producers in Alberta—announced plans to convert their coal units to natural gas. ATCO planned to make the swicth by 2020, and TransAlta planned to do the same by the end of 2023. ATCO ultimately chose to sell all its Canadian-based fossil-fuel assets, including nine units in Alberta.

In January 2022, TransAlta officially stopped burning coal across all of Canada. The conversion of Keephills Unit 3 from coal to natural gas was the last of three planned conversions at the power producer’s facilities in Alberta. At the time, the company said it had spent C$295 million ($232.27 million) on coal-to-gas conversion projects at its Keephills, Sundance and Sheerness facilities.

TransAlta has retired 3,794 MW of coal-fired generation since 2018 and converted another 1,659 MW of capacity to natural gas.

Even as recently as March 2019, coal plants provided 35% of the province’s electricity. But Alberta Associate Minister of Natural Gas and Electricity Dale Nally said that over the past two years, around 5,000 MW – or 30% — of the installed coal-fired capacity was either converted to natural gas or retired altogether.

That leaves Capital Power’s Genesee coal-fired units as the last remaining units. The company has plans to repower units 1 & 2 as natural gas-fired combined cycle units. Doing so would also include 210 MW of battery storage. Genesee Unit 3 is undergoing a dual-fuel transition and will shift to 100% natural gas-fired in 2023.

As a result, just over a decade after Alberta commissioned its last coal plant (Keephills 3), the phase-out once scheduled for 2030 is nearly complete.

Pivnick also attributed the speed of the phaseout to a changing provincial government that brought environmental, labor and other groups together. That administration created a large fund to help transition coal workers and get buy-in from their communities.

“This isn’t as easy as pulling one piece out and putting a new piece in,” he said. “If you do this right and you put a plan in place, you can actually see this happen. And you can see it happen far quicker than most folks will project or anticipate.”

Alberta vs. Ontario phaseout

Alberta’s coal phaseout is worth comparing to the transition of another Canadian province many believe was ahead of its time.

In 2001, Ontario had five coal-fired generating stations totaling about 8,800 MW. In 2003, the province committed to phase out coal power entirely, with an end date of Dec. 31, 2014.

During the transition, coal-fired electricity was replaced by a mix of baseload, intermittent and peaking capacity, along with a strong conservation and demand management approaches.

Included was the refurbishment of two nuclear units at Bruce Power (+1,500 MW) which were returned to service in 2012, the addition of new combined cycle facilities, a peaking plant and combined heat and power facilities (+5,500 MW) and renewable resource additions (+5,500 MW).

Ontario met its goal and officially marked the end of coal in 2014. In 2019, roughly 94% of the electricity generated in Ontario was emission-free.

Pivnick said that as in Alberta, Ontario’s coal phaseout required the political will to make it happen. But he said Ontario leaned more heavily on health-related arguments rather than a focus on climate change.

“Its coal was located closer to communities, there was an easier case to be made,” he said.

Alberta Associate Minister of Natural Gas and Electricity Dale Nally noted the province’s primary focus in its coal phaseout is to ensure a healthy market that provided competitive prices and stability for investors. He said one difference is that while Ontario has a wholesale market, it also has the Ontario Power Generator, a Canadian crown corporation subsidized through taxpayers, providing over half of the province’s electricity.

“Under Alberta’s energy-only market, growth is funded by private investors, not taxpayer subsidies, and that growth is solely directed by a competitive market which provides choice to Alberta consumers,” said Nally.

Ontario’s Ministry of Energy declined an interview request for this story.

However, its website says its success in phasing out coal can be replicated in other jurisdictions, including by building broad implementation teams, managing coal supply, developing a long-term, coordinated plan to convert existing infrastructure and staying flexible in the event of a shift in supply/demand forecasts.

Overall, Canada is aiming for a net-zero electric grid by 2035.

The governments of Ontario, New Brunswick, Alberta and Saskatchewan released a strategic plan providing a path forward to advance small modular reactors (SMR) in the country.

SMRs are expected as the next evolution in nuclear innovation and technology. Their benefits are linked to the nature of their design – small and modular. SMRs can be sited on locations larger nuclear power plants cannot be. Prefabricated units of SMRs can be manufactured before being shipped and installed on site, making them more affordable than large power reactors.

The provinces’ plan outlines five priority areas for the development and deployment of SMRs:

1. Technology readiness: The strategic plan notes Canada’s early adoption of SMRs would position the country as a global nuclear technology hub, jumpstarting new economic and job growth through three SMR development streams:

Stream 1: a 300 MW SMR project constructed at the Darlington nuclear site in Ontario. In December 2021 we reported that Ontario Power Generation (OPG) selected GE Hitachi Nuclear Energy (GEH) to supply a BWRX-300 SMR for the site. The project could be completed as soon as 2028.

The strategic report adds that subsequent units in Saskatchewan would follow, with the first of those SMRs projected to be in service in 2034.

Stream 2: two fourth-generation, advanced SMRs would be developed in New Brunswick. ARC Clean Energy is targeting a deployment date by 2029, with Moltex Energy aiming to have both its spent fuel recovery system and reactor in operation by the early 2030s, both at the Point Lepreau nuclear site. ARC and Moltex Energy, along with New Brunswick Power, partnered in 2020 as part an SMR vendor 'cluster' at Point Lepreau, which currently houses a 660 MWe Candu 6 reactor. 

Stream 3:  a new class of micro-SMRs designed primarily to replace the use of diesel in remote communities and mines. Ontario Power Generation (OPG) and Seattle-based Ultra Safe Nuclear are combining on a five MW gas-cooled demonstration micro-reactor at Chalk River, Ontario, with plans to be in service by 2026. Global First Power estimated that one MMR could replace 200 million liters of diesel at a mining site over 20 years.

The report also notes Bruce Power and its partners at the Nuclear Innovation Institute have also been exploring opportunities with the Westinghouse Canada eVinci micro reactor. In October 2020, Bruce Power and Westinghouse agreed to pursue applications of eVinci, with initial deployment in Canada targeted for the mid-2020s.

• Regulatory framework: The strategic plan noted regulatory changes and clarity will be needed to ensure reasonable project costs and timelines for investor and operator approvals.

• Economics and financing: The plan calls for a robust federal funding commitment to continue advancing SMR development and deployment. It notes the growth of SMRs in Canada and around the world will drive increased uranium demand, providing new opportunities for uranium produced in Saskatchewan and potentially Alberta, and increased utilization of refinery and conversion facilities in Ontario.

• Nuclear waste management: According to the plan, the Nuclear Waste Management Organization (NWMO) is working to identify a geologic storage depository for Canada’s used fuel waste. The provinces said twenty-two communities initially expressed interest to host the site and two potential sites in Ontario are still being considered, with safety assessments and community engagement ongoing. The NWMO is planning to select a single preferred site in 2023, with operations expected to begin between 2040 and 2045.

• Indigenous and public engagement: The plan emphasizes the need to create opportunities for Indigenous communities to participate in SMR projects. These opportunities could include employment, skills development, investments, or supplier arrangements.

As the general nuclear landscape goes, Canada currently has close to 20 commercial reactors generating about 13 GW in capacity, dominated by its home-grown CANDU design. According to the World Nuclear Association, about 15% of Canada’s electricity comes from nuclear.

The ANDE tooling system performs ultrasonic inspections in a wet, defueled channel. It takes seven to eight hours to process each channel, according to Bruce Power. This ultrasonic testing measures for flaws, channel diameter, wall thickness, sag and pressure tube to calandria tube gap, and also located garter springs. This is used to verify physical integrity of the tube and to help prolong the health of the reactor core.

This is the latest announcement regarding maintenance at Bruce Power in Ontario, Canada. In January, we reported that SNC-Lavalin, along with Aecon Group Inc. and United Engineers & Constructors Inc. were awarded a fuel channel and feeder replacement contract for Bruce Unit 3. The contract is worth more than C$393 million ($310 million). Aecon holds a 55% share in the project, SNC-Lavalin has a 30% share and United Engineers & Constructors holds 15%.

For that job, the work involves modernizing reactor-related components – 480 fuel channels and calandria tubes, 960 end fittings and 980 feeder pipes. The partners will also be responsible for operations, robotics and employee management and training. Planning is expected to start in conjunction with a scheduled outage at the nuclear station in early 2022, with a project completion target of 2026.

SNC-Lavalin has been performing fuel channel inspections for Bruce Power for more than six years.

“Bruce Power and SNC-Lavalin have a long history of collaboration to ensure that nuclear safety remains paramount as we deliver clean, reliable power to Ontario homes and businesses for the long term,” said Gary Newman, Bruce Power’s Chief Engineer & Senior Vice President, Engineering.

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