Canada already has one of the cleanest grids in the G7, with about 80% of its electricity from hydro, nuclear and renewables, but the last 20% and the doubling of demand expected by 2050 are the hard part. Hydro-Québec plans to invest C$155–185 billion by 2035 and add 8,000–9,000 megawatts, including more than 10,000 MW of wind; Ontario is building the West’s first grid-scale small modular reactor at Darlington (C$20.9 billion for four units) while Bruce Power refurbishes six reactors in a C$13 billion programme and plans a 4,800 MW new build. The federal Clean Electricity Regulations, finalised in December 2024, were suspended for Alberta in November 2025, exposing the fault line between provinces that have clean power and those that do not.
Canada’s grid is a federation of provincial monopolies, and the race to decarbonise it is being run at very different speeds by utilities that answer to premiers, not to Ottawa. Quebec and Ontario, with about two-thirds of the country’s generation between them, are investing on a scale that rivals any energy transition in the world: Hydro-Québec’s Action Plan 2035 is the largest capital programme in the province’s history, and Ontario’s nuclear buildout is the largest in the Western world since the 1980s. Alberta and Saskatchewan, dependent on gas and coal, have fought the federal Clean Electricity Regulations as an intrusion on provincial jurisdiction and won, at least temporarily, a suspension. This article explains what each province is building, how much it costs, who is paying, and why the politics of the grid now shape the economics of the oil sands, LNG, electric vehicles and data centres. It is part of the Canada Company Stories hub.
What is Hydro-Québec’s plan?
Action Plan 2035 calls for C$155–185 billion of investment, about 60 terawatt-hours of new supply, 3,800–4,200 MW of new hydro, more than 10,000 MW of wind and a cap of 3% on residential rate increases. Net income was C$2.9 billion in 2025 on C$18 billion of revenue.
What is Ontario building?
Four BWRX-300 small modular reactors at Darlington (C$20.9 billion, first unit connected by the end of 2030), a C$12.8 billion Darlington refurbishment completed in March 2026 ahead of schedule, Bruce Power’s C$13 billion life extension, a Pickering B refurbishment and a 4,800 MW Bruce C new build.
Why the provincial friction?
Alberta’s grid is mostly gas-fired and the Clean Electricity Regulations’ 2035 standard would have forced early retirements; the November 2025 Ottawa–Alberta MOU suspended the rules for the province in exchange for commitments on carbon pricing, methane and net zero by 2050.
Why does Canada’s grid look so different from province to province?
Because electricity is a provincial responsibility under the constitution, and each province built its system around whatever resource it had. Quebec, British Columbia, Manitoba and Newfoundland and Labrador have vast hydro resources and publicly owned utilities that developed them: Hydro-Québec alone operates about 37,000 MW across 63 hydroelectric stations. Ontario built the world’s largest fleet of CANDU heavy-water reactors in the 1970s and 1980s and now gets roughly 50–60% of its electricity from nuclear, with Bruce Power’s eight units supplying about 30% of the province and Darlington another 20%. Alberta and Saskatchewan, with coal and gas but little hydro, built thermal grids and privatised or kept them in Crown hands respectively.
The result is that national averages hide the real picture. Canada’s grid is about 80% non-emitting, which puts it ahead of every G7 country except France, but Alberta’s grid emits several times the national average per kilowatt-hour, and Saskatchewan’s still ran on coal until the 2020s. Inter-provincial transmission is thin: the links between Quebec and Ontario, or between Manitoba and Saskatchewan, carry a fraction of what flows north–south to the United States. Hydro-Québec exported 11.8 TWh in 2025 at an average of 15 cents per kilowatt-hour, nearly all of it to New England and New York, and the Champlain Hudson Power Express line to New York City is the largest new transmission project in its history.
This structure explains why federal climate policy for electricity has been so contentious. A rule that is trivially met in Quebec is existential in Alberta, and no premier will accept Ottawa dictating the composition of a provincial grid.
What is Hydro-Québec’s C$185 billion plan actually for?
It is for meeting demand that the utility expects to roughly double by 2050, while keeping Quebec’s electricity among the cheapest and cleanest in North America. Action Plan 2035, released in November 2023 under then-chief executive Michael Sabia and continued by Claudine Bouchard, who became president and chief executive in July 2025, sets out C$155–185 billion of investment through 2035, or C$12–16 billion a year. About C$45–50 billion goes to grid reliability, including a target to cut outages by 35% within seven to ten years; C$90–110 billion to growth projects; and C$20–25 billion to additional operating costs.
The supply side is specific. Quebec needs about 60 TWh of additional electricity by 2035. The plan expects 8,000–9,000 MW of new capacity: 3,800–4,200 MW of new hydro, including upgrades to existing stations and potential new dams; more than 10,000 MW of installed wind, contributing 1,500–1,700 MW of firm capacity; 500–1,000 MW of solar, storage and other sources; 400–600 MW from converting the Bécancour gas plant for peak use; and 1,600–1,800 MW of avoided demand through efficiency, equivalent to about 21 TWh of savings. The wind programme is the largest in the country, with Hydro-Québec co-developing multi-gigawatt projects with First Nations and regional governments rather than running open auctions.
Financially, the utility can afford it. Hydro-Québec reported net income of C$2.9 billion in 2025, up 9%, on revenue of about C$18 billion; it invested C$7.8 billion in the province, contributed C$4.4 billion to the Quebec government and sold 184.9 TWh domestically. The plan caps residential rate increases at 3% a year, which means industrial customers and exports will carry a larger share of the cost. The December 2024 memorandum of understanding with Newfoundland and Labrador to renew the Churchill Falls contract to 2075, replacing the 1969 agreement that gave Quebec the output at a fraction of market value, adds a further dimension: it would bring new capacity at Gull Island and Churchill Falls but at prices far above the historic contract. The agreement remained subject to ratification by both provinces in 2026.
Why is Ontario betting on nuclear again?
Because the province faces a 75% increase in demand by 2050, needs 111 TWh of new energy, and already has the supply chain, regulator and workforce for nuclear. Ontario’s Independent Electricity System Operator (IESO) has forecast that electrification of transport, the Honda and Volkswagen battery plants, data centres and population growth will push demand from about 150 TWh today toward 260 TWh by mid-century. Minister of Energy and Electrification Stephen Lecce’s 2025 integrated energy plan set out a programme that the government calls the largest nuclear expansion in the Western world.
The first element is refurbishment. Ontario Power Generation (OPG) completed the C$12.8 billion refurbishment of Darlington’s four units when Unit 4 reconnected to the grid in March 2026, four months ahead of schedule and about C$150 million under budget, extending the 3,500 MW station’s life by 30 years. Bruce Power, a private partnership of TC Energy, OMERS, the Power Workers’ Union and the Society of United Professionals, is spending C$13 billion of private money to replace major components in six of its eight units: Unit 6 returned in September 2023, Unit 3 on 8 June 2026, seven months ahead of schedule and, according to TC Energy, about 15% cheaper than Unit 6; Unit 4 began in February 2025, with Units 5, 7 and 8 to follow through 2030. OPG is also planning to refurbish the four Pickering B units rather than close them.
The second element is new build. On 4 April 2025 the Canadian Nuclear Safety Commission issued a licence to construct the first of four GE Vernova Hitachi BWRX-300 small modular reactors at Darlington, and in May 2025 the province approved a C$20.9 billion budget for all four 300 MW units: C$6.1 billion for the first reactor and C$1.6 billion for shared infrastructure, with the rest for the remaining three. The first unit is meant to connect to the grid by the end of 2030. In 2026 the regulator cleared the reactor-building basemat, the first diaphragm-wall rings were installed, OPG applied for an operating licence, and on 23 June 2026 the Williams Treaties First Nations announced a C$700 million investment in the project. Beyond Darlington, Bruce Power is pursuing a federal impact assessment for up to 4,800 MW of new capacity at Bruce C, with the IESO approving C$300 million for pre-development work, and OPG is studying large reactors at Wesleyville.
How does Bruce Power’s private model work?
Bruce Power leases the station from OPG, which still owns the site, and sells its output to the IESO under a long-term contract at a price that rises as refurbished units return, which allows it to fund C$13 billion of refurbishment without provincial capital. TC Energy, which holds 48.3%, reported a C$1.1 billion equity share of the Unit 3 refurbishment cost and said it expected to return about C$150 million to Ontario ratepayers through a cost-sharing mechanism. In the second quarter of 2026 the plant’s availability was 98.5% with no forced outage days. The company, led by chief executive Eric Chassard, also produces medical isotopes, including cobalt-60 for sterilisation and lutetium-177 for cancer treatment, in its reactors.
The structure matters because it demonstrates that nuclear refurbishment can be done on time and on budget by a private operator with a regulated offtake. Ontario’s 2023 decision to pursue Bruce C and the SMRs rests on that track record, and TC Energy’s willingness to keep Bruce Power when it spun off its oil pipelines, described in the Enbridge and TC Energy article, shows that the pipeline company sees nuclear as a core growth business rather than a legacy asset.
What are the Clean Electricity Regulations, and why did Alberta fight them?
The Clean Electricity Regulations (CER) are federal rules, finalised on 17 December 2024, that set an emissions performance standard for fossil-fuel power plants from 2035 and aim for a net-zero grid by 2050; Alberta fought them because its grid is roughly 70% gas-fired and the rules would have forced early retirements or expensive carbon capture on plants built in the 2010s and 2020s. The final version was softer than the 2023 draft: it adopted an annual emissions limit per plant rather than a strict intensity cap, allowed gas plants to run for peaking and emergencies, exempted units until they reach 20 years of age or 2035, whichever is later, and offered flexibilities for cogeneration and remote communities. Ottawa estimated the regulations would cut emissions by about 180 million tonnes between 2024 and 2050.
Alberta’s government, led by Danielle Smith, nonetheless treated the rules as unconstitutional, invoked its Sovereignty Act for the first time in late 2023 in response to the draft, and threatened to set up a provincial Crown corporation to build gas plants outside federal reach. Saskatchewan’s SaskPower said it would not comply. Both provinces argued that the 2035 date was technically unachievable and that the federal government had no authority over provincial electricity planning. The constitutional argument had force: the Supreme Court’s 2023 opinion on the Impact Assessment Act had already found parts of that federal law overreached.
The resolution came through politics rather than the courts. The memorandum of understanding signed by Prime Minister Mark Carney and Premier Smith on 27 November 2025 exempted Alberta from the Clean Electricity Regulations while the two governments negotiated a new industrial carbon-pricing agreement, with a deadline of 1 April 2026, and committed Alberta to a 75% methane reduction over a decade and a net-zero target for 2050. The same deal covered the proposed West Coast oil pipeline and the Pathways carbon-capture project, as described in the Alberta–Ottawa energy sovereignty article. For the grid, the practical effect is that Canada’s electricity decarbonisation now runs on two tracks: a federal standard for provinces that can meet it easily, and bilateral deals for those that cannot.
| Project / programme | Province | Scale | Cost | Timing |
|---|---|---|---|---|
| Hydro-Québec Action Plan 2035 | Quebec | +8,000–9,000 MW; 60 TWh | C$155–185bn | 2024–2035 |
| Darlington refurbishment | Ontario | 4 units, ~3,500 MW | C$12.8bn (C$150m under) | 2016 – Mar 2026 |
| Darlington SMRs (BWRX-300) | Ontario | 4 × 300 MW | C$20.9bn | First unit by end-2030 |
| Bruce Power life extension | Ontario | 6 units of 6,550 MW site | C$13bn (private) | 2020–early 2030s |
| Bruce C new build | Ontario | Up to 4,800 MW | Not yet estimated | Impact assessment underway |
| Site C dam | British Columbia | 1,100 MW | ~C$16bn | Completed 2024–2025 |
| Clean Electricity Regulations | Federal | ~180 Mt CO2 avoided 2024–2050 | – | Final Dec 2024; Alberta exempt from Nov 2025 |
Who pays for the transition, and what happens to electricity prices?
Ratepayers, taxpayers and industrial customers pay in different proportions in each province, and the political constraint everywhere is to keep residential bills from rising faster than inflation. Quebec has made its answer explicit: a 3% cap on residential increases, which pushes cost recovery onto industrial tariffs, exports and the provincial dividend. Hydro-Québec’s C$4.4 billion contribution to the provincial treasury in 2025 is, in effect, the fiscal room that makes the cap affordable. Ontario has used a different tool, the Ontario Electricity Rebate, which moves part of the cost of past nuclear and renewable contracts onto the provincial budget, and it is financing the SMRs through OPG’s balance sheet with provincial backing and a C$970 million federal contribution through the Canada Infrastructure Bank.
The federal government’s main lever is the tax system. The Clean Electricity investment tax credit of 15% and the Clean Technology credit of 30%, both enacted in 2024, apply to nuclear, wind, solar, storage and transmission investments by taxable and, in the case of the Clean Electricity credit, provincial Crown corporations that agree to certain conditions. The Canada Infrastructure Bank, described in the Major Projects Office article, has committed capital to the Darlington SMRs, to transmission lines and to Indigenous equity in generation projects.
Industrial demand is the wildcard. The EV battery plants in Ontario, the LNG terminals in British Columbia, the proposed data-centre clusters in Alberta and Quebec, and the electrification of the oil sands all require firm power at a scale that provincial planners did not anticipate five years ago. Hydro-Québec has already begun rationing new industrial connections, allocating blocks of power to projects it judges strategic rather than first-come, first-served, which is a significant change from the decades when cheap surplus hydro was Quebec’s main industrial lure.
How does the grid debate connect to oil, gas and the wider economy?
Directly, because the decarbonisation of heavy industry is now the main driver of new electricity demand and the main constraint on it. The oil sands producers’ Pathways carbon-capture project and their plans to electrify steam generation depend on Alberta’s grid having clean, firm capacity it does not currently have. The LNG terminals at Kitimat, Squamish and Prince Rupert are designed for electric compression that BC Hydro cannot yet fully supply on the North Coast, as the LNG Canada article explains. The battery plants and electric-arc steel furnaces of southern Ontario are why the province’s demand forecast rose so sharply. In each case, the industrial project is moving faster than the grid investment it needs.
The other link is exports. Hydro-Québec’s business model has relied for decades on selling surplus power to New England and New York at prices far above what Quebec customers pay. As domestic demand rises, that surplus shrinks: exports fell to 11.8 TWh in 2025 from 35.6 TWh in 2022, partly because of low reservoir levels and partly because of growing provincial consumption. The Champlain Hudson line to New York, due to begin operation in 2026, and the New England Clean Energy Connect line to Massachusetts are long-term commitments that Quebec must honour even as it rations new industrial connections at home. The trade and tariff environment of 2025–2026 has added a further complication, with Ontario briefly threatening to surcharge power exports to the United States during the 2025 trade dispute.
What can founders and investors learn from Canada’s grid transition?
The first lesson is that demand forecasting has become the central skill of the utility business, and its errors are expensive in both directions. Ontario spent the 2010s with surplus power and paid to curtail it; it now faces a 75% increase in demand and is building reactors to meet it. Hydro-Québec was selling surplus to New York in 2022 and rationing industrial connections by 2025. Founders in energy, data centres or manufacturing should treat power availability as a site-selection variable as important as labour or tax, and should negotiate firm supply early rather than assume the grid will be there.
Second, repetition beats novelty in capital projects. The CANDU refurbishments at Darlington and Bruce came in ahead of schedule because they followed a sequence in which each unit learned from the last. The BWRX-300 programme at Darlington is designed on the same principle, with four identical units and a supply chain built for a series. Investors evaluating any first-of-a-kind project should look for evidence that the proponent has planned the second and third units, not just the first.
Third, public ownership can be a financing advantage when it is paired with commercial discipline. Hydro-Québec can borrow on the province’s credit and plan over decades, which no private utility could do for a C$185 billion programme; Bruce Power shows that a private operator with a regulated offtake can execute C$13 billion of work on budget. The combination of both, as in the Darlington SMRs with OPG as owner and private vendors and First Nations as partners, is becoming the Canadian template, visible also in the Cameco and the uranium revival.
Fourth, regulation that ignores regional difference will be defeated by regional politics. The Clean Electricity Regulations were carefully designed and still had to be suspended for the one province that could not meet them. Policy that offers Alberta a credible path, through carbon pricing, gas with capture, and perhaps SMRs of its own, is more likely to reduce emissions than a national standard that Alberta simply refuses. The same tension between national targets and regional grids is playing out in Germany and Australia, as the Germany Company Stories hub shows, and Canada’s bilateral approach is one possible answer.
Frequently Asked Questions
How clean is Canada’s electricity grid?
About 80% of Canada’s electricity comes from non-emitting sources: roughly 60% hydro, 13–15% nuclear and a growing share of wind and solar. That puts Canada behind only France among G7 countries. The national figure hides large differences: Quebec, British Columbia and Manitoba are over 95% clean, Ontario over 90%, while Alberta and Saskatchewan still rely mainly on natural gas and, until recently, coal.
What is the Darlington SMR project?
Ontario Power Generation is building four GE Vernova Hitachi BWRX-300 small modular reactors of 300 MW each at its Darlington site east of Toronto, the first grid-scale SMRs in the G7. The Canadian Nuclear Safety Commission issued a construction licence for the first unit on 4 April 2025, the province approved a C$20.9 billion budget for all four in May 2025, and the first reactor is planned to connect to the grid by the end of 2030. The Williams Treaties First Nations announced a C$700 million investment in June 2026.
What is Hydro-Québec’s Action Plan 2035?
It is the utility’s strategy to meet about 60 TWh of additional demand by 2035 through C$155–185 billion of investment, adding 8,000–9,000 MW of capacity from new and upgraded hydro, more than 10,000 MW of wind, solar, storage and energy efficiency, while capping residential rate increases at 3% a year and cutting outages by 35%. Hydro-Québec reported net income of C$2.9 billion in 2025 and invested C$7.8 billion in Quebec that year.
Are the Clean Electricity Regulations still in force?
Yes for most of Canada, but not for Alberta. The regulations were finalised on 17 December 2024 and set emissions limits on fossil-fuel power plants from 2035 with a net-zero goal for 2050. Under the memorandum of understanding signed by Prime Minister Mark Carney and Premier Danielle Smith on 27 November 2025, Alberta is exempt while the two governments negotiate a new industrial carbon-pricing agreement, and Alberta committed to net zero by 2050 and a 75% methane reduction.
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