Section XVI: Power

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• Overview

• Quebec — Power Industry and Laws

• Ontario — Power Industry and Laws

• Alberta — Power Industry and Laws

• British Columbia — Power Industry and Laws

1. Overview

The generation, distribution and transmission of electric power is primarily governed by the laws of the individual provinces, with each province selecting its method of regulation — such as rate-regulated government-owned utilities or open markets with private utility providers — and its supply mix based on policy considerations and available resources.

Privately held generators or a mix of private and government-owned corporations provide the power generation in Newfoundland and Labrador, Prince Edward Island, Nova Scotia, Ontario and Alberta. Generation is primarily provided by rate-regulated government corporations in Quebec, Saskatchewan, New Brunswick, Manitoba and British Columbia. Independent power producers that generate electricity for their own use and for sale to the power grid and utilities exist throughout the country.

There are a variety of regulatory regimes that control the wholesale and retail prices of electricity. Alberta is deregulated, and Ontario is partially deregulated (and is often referred to as having a hybrid market). Most other provinces generally have a regulated price structure where the price of electricity is set by a regulatory board based upon the cost of generating and delivering the power to customers. A summary of the main laws governing the power industry in Quebec, Ontario, Alberta and British Columbia is set out below.

1.1 Energy boards and commissions

There are several statutes at both the federal and provincial level that govern Canada’s electricity sector. In many cases, these statutes provide for ongoing regulation by federal or provincial agencies and tribunals.

At the federal level, the Canada Energy Regulator oversees interprovincial and international aspects of the energy industry. It is responsible for regulating the construction and operation of international and designated interprovincial power lines and the export out of Canada and import into Canada of electricity.

Power lines that are completely within the borders of one province are usually regulated by a regulatory tribunal set up by that province, such as the Alberta Utilities Commission (AUC), the British Columbia Utilities Commission, the Ontario Energy Board (OEB) and Quebec’s Régie de l’énergie (Régie). Energy tribunals, whether federal or provincial, typically review, among other things, economic and technical feasibility and environmental and socio-economic impacts of proposed projects subject to their jurisdiction.

In addition, utility companies that supply electricity within a province are usually regulated by that province’s energy tribunal. The mandate of the various tribunals varies from province to province, depending upon how electricity is regulated in that province.

1.2 Supply mix

Canada is blessed with significant hydroelectric resources, and hydroelectric generation accounts for a meaningful portion of electricity production in Quebec, Manitoba, British Columbia, Newfoundland and Labrador, and, to some extent, Ontario, Alberta and the other provinces.

Quebec, Manitoba, British Columbia and Ontario have significant heritage hydroelectric assets that are regulated and supply electricity to local ratepayers at regulated rates. Quebec, Newfoundland and Labrador, British Columbia and Manitoba are undertaking significant new hydroelectric development, and Ontario is redeveloping some of its hydroelectric projects in northern Ontario and assessing the feasibility of new and small (less than 10 megawatts (MW)) hydroelectric projects.

Nuclear generation supplies a portion of the baseload requirements in Ontario and New Brunswick. In Ontario, work has begun on a 300 MW small modular nuclear reactor (SMR) at the Darlington Nuclear Generating Station to reach commercial operation in 2030, and the government has announced its intent to add three more 300 MW SMRs at Darlington in the coming years. Also in Ontario, pre-development studies are underway for 4,800 MW of new nuclear reactors at the Bruce Power site. Refurbishments are planned or underway for existing generators at each of Bruce and Pickering Nuclear Generating Stations. The Darlington refurbishment project was completed ahead of schedule in February 2026.

Saskatchewan, Ontario, Alberta and New Brunswick have signed a Memorandum of Understanding (MOU) to advance the development of nuclear power generation to support the need for affordable, reliable and sustainable electricity grids by 2050. This is consistent with the federal government’s recently issued Nuclear Energy Strategy for Canada, which, among other things, includes a commitment for the construction of two large-scale nuclear reactors to start by 2035 and a further 5 reactors to be planned or under development by 2040. At the opposite end of the spectrum, Quebec closed its only nuclear power facility (but is currently assessing its revival) and British Columbia’s policy expressly excludes nuclear energy development.

Canada also has significant natural gas resources. As a result, natural gas-fired and some coal-fired generation can be found in several Canadian provinces. The ability to quickly ramp up or ramp down these forms of energy supply often means that they are used to support peak system demand periods, augmenting baseload generation and intermittent forms of generation, such as wind and solar.

Natural gas resources provide a significant source of electricity in some provinces. For example, in Alberta, more than half of the electricity is generated from natural gas. Also, approximately 5% of electricity in Canada is generated from coal, and this amount is forecasted to continue to decrease. Currently, the provinces of Saskatchewan, New Brunswick and Nova Scotia generate a portion of their electricity from coal. The Saskatchewan government recently announced plans to extend the operational life of coal-fired power plants within the province. Alberta and Ontario have completely phased out coal-fired generation. Nova Scotia has a legislated target to eliminate coal-fired generation by 2030. New Brunswick is also taking steps to phase out coal by 2030.

Every province has set its own renewable energy targets and plans for how it proposes to achieve those targets. In most cases, this has taken the form of government support by offering long-term power purchase agreements at favourable prices to encourage renewable energy development, including through standard offer programs, requests for proposals (RFPs) and competitive bidding programs.

1.3 Emerging technologies

Small Modular Reactors

In 2020, Canada released the Small Modular Reactor (SMR) Action Plan, which is described as Canada’s plan for the development, demonstration and deployment of SMRs for multiple applications. The Action Plan incorporated input from the federal government, provinces and territories, and other stakeholders such as Indigenous Peoples and industry.

Ontario, New Brunswick, Saskatchewan and Alberta are parties to an MOU to establish a framework that will maximize the potential to access market opportunities in Canada and internationally. As part of the MOU, the participating provinces most recently issued the Strategic Plan for the Development of Small Nuclear Reactors, which identifies key actions that provinces can take to enable a decision on whether to proceed with SMRs.

In June 2026, the federal government released the Nuclear Energy Strategy for Canada (the Nuclear Strategy). The Nuclear Strategy outlines four strategic pillars, the first of which is focused on enabling new nuclear power plants across Canada. The Nuclear Strategy calls for the construction of two large-scale nuclear reactors, with at least one reactor located outside Ontario to start by 2035, and a further five large-scale reactors to be planned or under development by 2040. The Nuclear Strategy diverges from previous documents, including the Action Plan, by first calling for the development of large-scale reactors over SMRs. However, the Nuclear Strategy still aims to support the development of SMRs by calling for a Canadian-made microreactor design to be finalized by 2035 and deployed to remote communities by the late 2030s.

In Ontario, Ontario Power Generation (OPG) is committed to building four SMR projects at the Darlington Nuclear Site as outlined in the Action Plan and Strategic Plan. In April 2025, OPG received a licence to construct the first 300 MW SMR at the Darlington site, and construction is currently underway. In March 2026, OPG applied to the Canadian Nuclear Safety Commission (CNSC) for a Licence to Operate the first SMR. The licensing process will involve a public hearing. OPG is staging the construction of the three remaining SMRs at the Darlington site. In June 2026, the federal government announced a C$715-million loan guarantee transaction that will allow the Williams Treaties First Nations to eventually own a significant minority interest in the Darlington SMR project.

The Canada-Alberta Memorandum of Understanding signed in December 2025 included a commitment to develop a nuclear generation strategy to create competitive nuclear power generation in the province to serve Alberta and interconnected markets by 2050. Alberta released the Nuclear Energy Engagement Panel Report (the Report) in April 2026, which will inform a roadmap and regulatory framework to develop a nuclear industry in Alberta. The Report is based on feedback from Albertans, Indigenous communities, municipalities, industry and other stakeholders, and found that overall, those surveyed are supportive of nuclear energy development in Alberta. In addition, Alberta and Saskatchewan entered into a separate bilateral MOU in May 2024, which focuses on addressing industrial decarbonization and grid reliability in concert with advancing the development of SMRs in both provinces.

In Alberta, SMR technology has been proposed for use at remote rural sites that are heavy energy users, such as oil sands projects. For example, in April 2025, an Initial Project Description for the 4,800 MWe Peace River Nuclear Power Project in Alberta was submitted to the Impact Assessment Agency of Canada, and the impact assessment began in April 2026.

Saskatchewan received federal support in early 2026 to develop the SMR Safety, Licensing and Testing Centre at the University of Regina. The testing facility will ensure that Canadian businesses and researchers can safely develop and deploy SMRs. In April 2026, Saskatchewan and Bruce Power signed an MOU to inform and support Saskatchewan’s plans to evaluate large nuclear reactor technologies in the province.

Blue and Green Hydrogen

In December 2020, the federal government released a Hydrogen Strategy for Canada (Strategy), noting that as the third-largest producer of hydrogen, the third-largest hydroelectricity producer, and with one-fifth of the world’s large-scale Carbon Capture Utilization and Storage (CCUS) projects, Canada already has some of the infrastructure and supply chains it needs to produce and export green and blue hydrogen. Canada has also been a leader in much of the research and development (R&D) and technology development related to hydrogen energy and will not need to look far for expertise as it continues developing its capabilities.

Provincially, Ontario, Quebec, Alberta and British Columbia have all followed suit, introducing their own hydrogen development plans with immediate action items, including research and development funding and regulatory renewal. In particular, British Columbia moved from a largely strategy-based framework to a specific regulatory regime for hydrogen facilities. In 2025, British Columbia adopted legislation that establishes a dedicated regulatory framework for hydrogen manufacturing facilities and sets out detailed regulatory requirements for different classes of facilities. The legislation established streamlined permitting pathways and regulatory requirements for proponents of hydrogen projects, regulated by the British Columbia Energy Regulator.

In 2024, the federal government released a Progress Report to the Strategy. According to the Progress Report, approximately 80 low-carbon hydrogen production projects have been announced in Canada, representing an expression of interest of over C$100-billion in potential investment. These projects include “hydrogen hubs” in Alberta, British Columbia and Ontario. Other large-scale investments in hydrogen energy include hydrogen production and liquefaction assets in Eastern Canada, green hydrogen production plants in Quebec, and fuel-cell vehicles and hydrogen fueling infrastructure in Central and Western Canada. With these public and private investments, as well as the hydrogen strategies committed by the federal and provincial governments, including the 2030 Quebec Green Hydrogen and Bioenergy Strategy, Canada is poised to be a leader in the hydrogen energy sector as it continues to develop.

Energy Storage

In 2024, Ontario initiated expedited and long-term capacity procurements aimed at increasing utility-scale storage resources to support the wide-scale integration of renewable resources, like wind and solar. While Ontario adopted a technology-agnostic position on energy storage — including thermal, flywheel, compressed air, pumped hydro and hydrogen storage solutions deployed in the province — battery storage has been the most widely adopted solution to date. Most recently, in June 2026, Ontario’s Independent Electricity System Operator (IESO) Long-Term (LT) 2 (window 1) RFP successfully procured a total of 640 MW of capacity through 20-year contracts issued to each one of three new-build battery storage facilities.

Both Ontario and Alberta have a number of new large-scale battery storage facilities that have reached commercial operation. This includes the 250 MW/1,000 MWh Oneida facility in May 2025, the 80 MW/320 MWh Sanjon facility in January 2026 and the 300 MW/1200 MWh Hagersville facility in February 2026. There are nine 20 MW, one 80 MW and one 10 MW battery storage facilities energized in Alberta, bringing the total installed generation capacity of battery storage to 270 MW in the province.

2. Quebec — Power Industry and Laws

2.1 Electricity sector and regulatory framework main factors

Quebec has a regulated electricity market. Quebec’s Régie de l’énergie (Régie) is the regulatory agency that supervises and regulates the transmission and distribution of electric power in Quebec. Hydro-Québec, a Crown corporation, is responsible for furnishing a guaranteed annual supply of 165 terawatt hours (TWh) of “heritage pool electricity.” This “heritage pool” is approximately equal to the total energy output of Hydro-Québec’s “heritage” facilities and is the main supply source for the Quebec market, meeting around 90% of local load needs.

2.1.1 Hydro-Québec

Hydro-Québec (HQ), whose sole shareholder is the Quebec government, is the largest power utility in Canada and one of the largest electric utilities in North America. Under its incorporating statute, HQ is given broad powers to generate, supply and deliver electric power throughout the province. HQ is also authorized to purchase all of the electric power produced by independent power producers in Quebec. Other private electricity producers may also be called upon to supply the required energy through long-term or short-term contracts.

In recent years, HQ has undergone a series of organizational changes and now constitutes a single entity structurally organized in three main groups (Strategy and Finance, Energy Planning and Customer Experience, and Operations and Infrastructure), and has increased its commitment to developing renewable energy sources in the province, including by adopting the Wind Power Development Strategy in 2024 (as further described in Section XVI.2.2, Quebec’s energy supply mix and energy strategy below). HQ is responsible for generation, transmission and distribution activities, including:

• Generating power for the Quebec market and selling power on wholesale markets
• Operating the province’s transmission system and managing power flows throughout the province
• Distributing electricity to Quebec customers, with an almost exclusive right to distribute throughout the province, and managing energy supplies (including power management programs such as dynamic pricing, rate options and energy efficient programs). Note, in order to meet needs beyond the annual heritage pool electricity, HQ buys power on open markets
• Designing and carrying out projects for the construction and refurbishment of generation and transmission facilities (e.g., integrating new renewable energy sources, constructing or refurbishing generation facilities)
• Developing and operating large-scale wind farms, consistent with the Wind Power Development Strategy, discussed in Section XVI.2.2 below

2.1.2 Quebec’s Régie de l’énergie

The Régie is the agency responsible for regulatory supervision of the transmission and distribution of electric power. Electricity rates in Quebec are subject to its approval. The Régie was created by virtue of the Act respecting the Régie de l’énergie (Régie Act) with the powers needed to regulate the electricity and natural gas sectors in response to the requirements of the liberalization of the North American electricity market, including guaranteed non-discriminatory access to markets. In 2000, the Régie Act was amended to introduce more competition into the electricity market, to make the Régie’s mode of operation more flexible, to broaden its sources of funding, and to establish the procedure for setting the rates and conditions applicable to the transmission and distribution of electric power. The Régie Act was further amended in 2025 to explicitly give the Régie the mission to monitor Quebec’s energy sector and to ensure a fair balance between public interest, the protection of consumers in Quebec and the fair treatment of electric power carriers and distributors. As part of its new mission, the Régie must also promote the meeting of energy needs, an orderly energy transition at the lowest cost, innovation, and the maximizing of the economic, social and environmental benefits of energy for Quebecers, explicitly tying the Régie’s mission into Quebec’s energy transition plan, the Action Plan 2035, as further described in Section XVI.2.2 below.

The Régie sets the rates and conditions for the transmission of electric power by HQ, as electricity carrier, as well as for the distribution of electric power by the HQ, as electricity distributor, and may review such rates every three years. In fixing and modifying rates, the Régie favours the use of incentives to improve carrier and distributor efficiency and ultimately protect consumer interests. Hence, HQ’s transmission and distribution activities (as well as those of municipal distributors) are subject to the conventional form of regulation based upon the cost of service for those activities. However, notwithstanding the foregoing, since Bill 69, An Act to ensure the responsible governance of energy resources and to amend various legislative provisions, has come into force (as further described in Section XVI.2.2 below), the Quebec government may now set a maximum domestic rate increase, which the Régie must follow when reviewing electricity rates applicable to HQ.

More specifically, the Régie effectively regulates the generation, transmission and distribution segments of the Quebec electricity market as follows:

• HQ electricity distribution activities: Approving terms of service, approving supply plan and contract specifications, setting and reviewing rates every 3 years, supervising calls for tender, producing finding reports, approving supply contracts, and managing consumer complaints (including those of both HQ and municipal redistributors).
• HQ transmission activities: Setting local and point-to-point charging rates, applying regulatory incentive mechanisms to promote efficiency gains, approving terms of service, adopting transmission system reliability standards, authorizing investment projects, and managing consumer complaints.
• Reliability standards for the transmission system in Quebec: Appointing the Reliability Coordinator and reviewing the reliability model, reviewing, adopting and implementing mandatory transmission system reliability standards, monitoring the compliance of entities subject to reliability standards, particularly through implementing standards developed between the Régie, the North American Electric Reliability Corporation and the Northeast Power Coordinating Council (two organizations with North American expertise in establishing and monitoring the application of transmission reliability standards), monitoring the compliance of entities covered by reliability standards, and, in the event of a contravention of these standards, imposing a remedial action plan, financial penalties and, in some cases of non-compliance, corrective measures.
• Approval of Power Purchase Agreements: As further described in Section XVI.2.2 below, HQ is no longer required to enter into calls for tender to enter into power purchase agreements with electricity producers, but the Régie must approve such power purchase agreements (except in cases where the power purchase agreements are authorized directly by the Quebec government or not required by regulation).
• Production of electric power: The Régie can confer exclusive power distribution rights, however, it may not prevent electricity producers from consuming the electricity they produce themselves. Bill 69 now authorizes any renewable electricity producers to enter into exclusive distribution agreements with entities other than HQ if the producer is producing renewable electric power and if such power is distributed to a single consumer to meet the needs of its installations, and if the consumer’s installations are adjacent to the production site. However, such exclusive distribution agreements need to be authorized by the Quebec government. The option of entry into power purchase agreements between private party electricity producers and private party offtakers, as set out in Bill 69, is intended to grant more flexibility and to enable the development of projects driving economic development in areas not connected to the HQ grid. Before Bill 69, the option to enter into private power purchase agreements was reserved for electricity producers generating power from forest biomass, but has now been expanded to allow any renewable energy producer to enter into such agreements.

2.2 Quebec’s energy supply mix and energy strategy

In 2024, Quebec's electricity generation production totalled 185 TWh, mainly generated through hydroelectricity (93%), followed by wind (6%) and other energy sources (1.3%, including diesel, solar energy and biomass).

In 2020, the Quebec government introduced the 2030 Plan for a Green Economy (PGE 2030). The PGE 2030 outlines several targets pertaining to public infrastructure innovation and expansion to facilitate a provincial shift towards electric power. More recent action plans and strategic plans, including Action Plan 2035, continue to underscore the importance of three objectives relating to HQ’s goal of leveraging Quebec’s renewable energy potential while mitigating associated environmental impacts: (i) phasing out fossil fuels in favour of renewable energy sources, to achieve decarbonization, (ii) optimizing the energy transition using cleantech innovation, and (iii) taking a decentralized approach to improving consumer knowledge of efficient energy use.

Building on the themes and objectives of the PGE 2030, HQ released its Action Plan 2035, setting out its strategy for meeting the province’s growing electricity demand and supporting the decarbonization of Quebec’s economy. Action Plan 2035 contemplates a need for between 8,000 and 9,000 MW of new capacity by 2035, to be met through a combination of over 10,000 MW of new wind power generation, 3,800 to 4,200 MW of new hydropower capacity (including upgrades to existing generating stations and the construction of a 1,000 MW pumped-storage facility), and several hundred megawatts of solar and battery storage. Total required investments to 2035, including reliability, growth and additional operating expenses, are estimated at C$155-billion to C$185-billion. Transmission system investments of C$45-billion to C$50-billion are planned to improve and increase existing grid capacity and connect new generating facilities. Action Plan 2035 also commits HQ to enter into strategic partnerships with First Nations and Inuit communities by offering financial partnerships and sharing economic benefits from energy development projects.

In June 2026, the Quebec government released the Plan de mise en œuvre 2026-2031 (PMO 2031), the sixth edition of the implementation plan under the PGE 2030, backed by investments of C$8.2-billion through 2031. The PMO 2031 postpones the greenhouse gas emissions reduction target of 37.5% below 1990 levels, originally set for 2030, to 2035. Of the C$8.2-billion in planned spending, C$5.6-billion is allocated to greenhouse gas reduction and energy transition, including C$2.3-billion for the transport sector (for vehicle electrification, charging infrastructure and public transit), C$1.1-billion for industrial energy productivity and emissions reduction, and C$900-million for building energy efficiency and conversion. The PMO 2031 also introduces an energy efficiency roadmap targeting electricity savings of up to 5 TWh by 2035.

Additionally, in June 2026, the Quebec government also released the Plan de gestion intégrée des ressources énergétiques (PGIRE) 2026–2050, its first long-term integrated energy resource management plan. The PGIRE targets carbon neutrality by 2050, with an interim greenhouse gas reduction target of at least 37.5% below 1990 levels by 2035. By 2050, the PGIRE calls for 100 TWh of new electricity supply from HQ, with 60 TWh to be secured by 2030 and the total reaching 295 TWh including existing generation. New resources to meet peak demand are targeted at 22 gigawatt (GW) by 2050, bringing total peak capacity to 65 GW. Energy efficiency targets are set at 50 TWh for electricity and 14 TWh for natural gas by 2050, with interim milestones of 7 TWh and 3 TWh respectively by 2030. The PGIRE projects that installed wind capacity could reach 12 to 16 GW by 2040 and 21 to 25 GW by 2050; installed solar capacity could reach 1 to 3 GW by 2040 and up to 5 GW by 2050. Implementing the PGIRE is expected to require an investment of C$87-billion over the next 25 years, through 2050. The PGIRE is to be reviewed at least every six years.

In July 2025, the government passed major legislative changes in the form of Bill 69, amending a number of laws and regulations, including several regulations respecting the Régie’s powers and procedures, the Municipal Powers Act, the Act respecting the exportation of electric power, and the Act respecting municipal and private power systems. In particular, Bill 69 amends core energy legislation, including the Act respecting the Régie de l'énergie and the Hydro-Québec Act, to provide Quebec with more flexibility and tools to achieve its energy transition and carbon neutrality goals by 2050, while supporting economic development.

The key elements of Bill 69 include:

1. Governance. The implementation of the PGIRE is a key point of Bill 69. In June 2026, the Quebec government approved the first PGIRE, which sets the plan from 2026 through 2050, covering all sources of energy consumed in the province over a 25-year period. The PGIRE aims to promote energy development within the province, with a focus on energy transition, and specifies the electric power supply target that HQ needs to achieve to satisfy the electric power needs of the Quebec market within the plan’s time frame. Bill 69 had previously set an interim power supply target of 255 TWh by January 1, 2035 (60 TWh greater than the 2022 generation levels and consistent with HQ’s Action Plan 2035). The adoption of the PGIRE formally replaces that interim target with a new official target of 100 TWh of additional electricity supply by HQ by 2050 relative to 2022, bringing the target total power supplied by HQ to approximately 295 TWh, with intermediate milestones of 15 TWh of increased power by 2030 and 60 TWh of increased power by 2040. The PGIRE also targets 22 GW of additional resources to address peak demand by 2050, for a total peak capacity of 65 GW. Further, Bill 69 requires Hydro-Québec to submit to the Régie a 15-year electric power supply plan and a 15-year electric power transmission system development plan within six months following the Régie's approval of the supply plan, neither of which have been published yet. Additionally, the PGIRE is subject to a progress report every three years and a full update at least every six years.

Bill 69 also accelerates the hearing process before the Régie, reduces the size of HQ’s board of directors, and promotes partnership facilitation between HQ and Indigenous Peoples for the development of wind power projects.

Consistent with Bill 69’s provisions facilitating partnerships between HQ and Indigenous Peoples for the development of wind power projects, HQ has entered into a series of regional wind development partnerships. For example, in late 2025, HQ, the Alliance de l'énergie de l’Est and the Première Nation Wolastoqiyik Wahsipekuk signed the Wetsok partnership agreement (named after the Wolastoqey word for “in the direction of the wind”) for wind power development across the regional county municipalities of Montmagny, L’Islet, Kamouraska, Rivière-du-Loup and Témiscouata in eastern Quebec. The Wetsok partnership contemplates the development of up to 1,500 MW of wind power capacity, representing potential investments of up to C$4.5-billion. The Wetsok partnership forms part of a broader framework for the coordinated planning of wind power development in eastern Quebec. These initiatives are consistent with HQ’s strategy, set out in its Wind Power Development Strategy and Action Plan 2035, to develop over 10,000 MW of new wind power capacity in partnership with First Nations and municipalities.

2. New energy project development. To streamline electric power procurement, Bill 69 eliminated the absolute obligation that HQ (in its role as electric power distributor) proceed by tender in order to enter into power purchase agreements with power producers and granted authority to the Quebec provincial government (independently from the Régie) to obligate HQ to enter into power purchase agreements under certain conditions at the Quebec government’s sole discretion. HQ is also permitted to enter into bilateral power purchase agreements, with the Régie’s approval where required. The Minister of Economy, Innovation and Energy (Minister) was granted increased authority over commercial and industrial developments within the province by stipulating that, under certain conditions (specified in the regulations under Bill 69), HQ will require the Minister’s approval to distribute electric power.

Pursuant to Bill 69, renewable energy producers can enter into private power purchase agreements to sell their energy to a single consumer located on a site adjacent to the production site, subject to approval by the government, but without needing approval from the Régie. Lastly, subject to government approval, Bill 69 allows the construction of privately-owned small hydroelectric facilities (100 MW capacity or less).

3. Electricity distribution. Bill 69 allows renewable energy producers to sell and distribute electricity to a single private customer for the needs of their installations. While such transactions are limited to certain contexts and require government authorization, Bill 69 deviates from previous legislation, which reserves the rights to sell and distribute electricity for HQ and for a limited number of municipal and private actors with grandfathered rights.

Further, under the Régie Act, any holder of exclusive power distribution rights in an area must provide electricity to any consumer in that area who requests it, subject to certain restrictions in the Régie Act. Bill 69 amends the Régie Act’s restrictions such that a power distributor requires authorization from the Minister before distributing to either: a consumer requesting electricity for a cryptocurrency mining project if the request is for more than 50 kilowatts (kW), or for any request of more than 5 MW.

4. Rate setting. Bill 69 reverses changes enacted by prior legislation pertaining to rate-setting. Where electric power rates were previously tied to inflation, authority to adjust rates will be returned to the Régie. To this end, the Régie will review electricity power rates every three years (instead of the previous five years) and set rates based upon what it determines to be the yearly revenue that HQ needs to operate (as both electric power distributor and carrier). The Régie is authorized to set one or more rates or conditions of service as of April 2026, thereby promoting the reduction of electric power consumption during peak periods. In some situations, HQ may request rate or terms of service modifications from the Régie outside of the scheduled reviews.

Bill 69 also eliminates protections that certain industrial rates benefited from against the indexation of HQ’s heritage pool prices, and sees that commercial and industrial rates can also be determined based on HQ’s annual revenue needs to perform its distribution activities. The Régie is authorized to spread any rate increase over the three years covered by the rate review. Bill 69 also includes mechanisms to protect residential consumers from rate hikes, such as the creation of a fund to support rate increase limits.

Since the Quebec government launched its Northern Action Plan, several new power projects have been commissioned in Quebec’s territory north of the 49th parallel. Among others, these include the Romaine hydroelectric complex, which was inaugurated in late 2023 and comprises HQ’s biggest complex since its Baie-James facilities, and the 200 MW Apuiat wind farm, which was commissioned in 2025 and marks a partnership between Boralex and Innu communities. As noted above, in recent years, HQ has partnered with various Indigenous communities and local governments to align projects with local needs and to provide local actors with management and ownership opportunities, facilitating their active role in Quebec’s energy transition.

Over the past decade, HQ has also leveraged its energy surpluses to export clean power to the United States, specifically New York and New England, including the New England Clean Energy Connect project between the Quebec/Maine border and the City of Lewiston in Maine. HQ has recently commissioned the Hertel-New York interconnection line, which aims to supply clean, renewable energy to New York City. The Hertel-New York interconnection line allows for the export of up to 1,250 MW of power.

Given steadily increasing energy supply demands, HQ announced in 2023 seven new power projects with a commercial operation date to be achieved by December 1, 2026. Totalling 1,303.36 MW of installed capacity, six of the seven projects are wind power projects. In 2024, HQ announced plans to develop itself a C$9-billion wind power project in the Saguenay-Lac-Saint-Jean region. The completion of this facility, which could produce up to 3,000 MW, will make it one of the largest of its kind in North America.

The Wind Power Development Strategy released by HQ in 2024 aims to add 10,000 MW of new wind power generation, as set out in Action Plan 2035, which requires deploying projects totalling 1,000-1,500 MW each year until 2035. The Wind Power Development Strategy includes a focus on large-scale projects of over 1,000 MW in which HQ will be an operator, shareholder and offtaker. Such large-scale projects will include early-stage project development with municipalities and First Nations, who will also be shareholders. In light of the expected increased pace of wind project development, social acceptability concerns are recognized by HQ as a key consideration in project implementation. Development zones will be established to accommodate the large-scale projects and major work and investments will be required to increase transmission system capacity and interconnection of the new wind farms to HQ’s grid.

In May 2025, HQ announced its plan to develop 3,000 MW of solar energy by 2035. It also launched its first call for tenders for solar energy. HQ set out to procure a 300 MW block of electricity generated from solar power. The duration of the supply contract must be between 20 and 25 years, with a commencement date by December 2029.

On April 10, 2026, HQ launched an additional call for offers aiming at a new block of wind energy between 5 and 10 TWh (the equivalent of 1500 to 3000 MW of installed power) to be commissioned between 2031 and 2038. The projects procured through this call for offers are intended to obtain new energy resources and replace expiring contract volumes. The quantities allocated will be adjusted to complement the anticipated commissioning of HQ’s own large-scale projects.

Additionally, in May 2026, HQ announced the creation of a new financing program, in partnership with Canada Infrastructure Bank and National Bank, to support Indigenous communities investing in large-scale wind power projects, enabling Indigenous communities to become investment partners in new energy infrastructure projects and generate recurring autonomous streams of income. The new financing program is comprised of equity and construction loans, and totals more than C$5-billion, including C$1.3-billion in equity loans.

3. Ontario — Power Industry and Laws

3.1 Policy setting and regulation

The Government of Ontario sets electricity policy, and the Ontario Energy Board (OEB) regulates Ontario’s electricity market. There is also a provincially owned corporation, the Independent Electricity System Operator (IESO), that administers the operation of the province’s electricity markets and long-term electricity supply contracts, and manages Ontario’s bulk electricity transmission system.

3.1.1 Government of Ontario

The Ontario cabinet retains authority to set policy for Ontario’s energy sector, but day-to-day oversight of Ontario’s electricity and natural gas industries is maintained by the Minister of Energy and Mines (Minister). Upon the approval of cabinet, the Minister can issue policy directives to the OEB and the IESO, and each is required to implement such policy directives. The Minister can also request that the OEB examine and advise upon any issue with respect to Ontario’s energy sector.

3.1.2 Ontario Energy Board

The OEB is the regulator of Ontario’s electricity industry. Although the OEB reports to the Minister, it operates as an independent adjudicative entity. OEB responsibilities include (i) determining the rates charged for regulated services in the electricity sector, including transmission and distribution services;, (ii) approving the construction of new transmission and distribution facilities, (iii) enforcing compliance with licensing and other requirements, (iv) providing education and public reporting for the benefit of electricity consumers, (v) hearing appeals from market rule amendments made by the IESO, (vi) monitoring and approving the IESO’s budget and fees, and (vii) monitoring electricity markets and reporting thereon to the Minister.

In Ontario, the cost for transmission and distribution (delivery) of electricity to a customer is charged separately from the commodity price of electricity. The OEB typically regulates the cost of transmission and distribution services, while the commodity cost of electricity is determined in the IESO’s wholesale spot market. In addition, the provincial government has imposed on most electricity customers an additional charge known as the “Global Adjustment,” which is mostly comprised of the payments to contract holders for procured long-term electricity supply contracts procured by the IESO on behalf of ratepayers. The Global Adjustment is typically inversely related to the IESO market price of electricity, such that the lower the market price, the higher the Global Adjustment rate and vice versa.

3.2 Market creation and Ontario Hydro’s successor corporations

Until 1998, the Ontario electricity sector was dominated by Ontario Hydro, a provincially owned company that integrated generation, transmission, system planning, electrical safety and rural and remote distribution functions. In 1998, Ontario Hydro was separated into five entities, each provincially owned, including Ontario Power Generation Inc., which assumed Ontario Hydro’s generation assets, Hydro One Inc., which assumed the transmission and rural distribution businesses of Ontario Hydro, and the IESO, which assumed responsibility for administering the electricity markets in Ontario and for directing the operation of Ontario’s electricity transmission grid. (The remaining two entities not discussed in detail are the Electrical Safety Authority and the Ontario Electricity Financial Corporation).

A fully competitive wholesale and retail market opened on May 1, 2002, but electricity price and distribution rate freezes were enacted in December 2002 due to volatile electricity prices. Although the rate freezes have long since been lifted, some elements of price smoothing and subsidy still remain.

The Ontario Power Authority (OPA) was created to act as a creditworthy counterparty through which new generation could be procured, by means of long-term power purchase or contract-for-differences agreements, and the OPA was also responsible for long-term system planning, conservation and demand management, and certain aspects of market evolution. The Ontario government merged the OPA and the IESO into one entity operating under the IESO name, effective January 1, 2015.

3.3 Independent Electricity System Operator

The IESO is a not-for-profit government-owned corporation. Following its merger with the OPA on January 1, 2015, the IESO is responsible for three main functions:

• Administering Ontario’s electricity markets
• Managing Ontario’s bulk electricity transmission system, including transmission system and regional planning, conservation and demand management
• Procurement and management of electricity contracts (the responsibilities of the former OPA)

In May 2025, the IESO launched a series of fundamental market changes pursuant to its Market Renewal Program (MRP). In connection with the MRP, amongst other changes to the IESO-administered markets, the IESO has instituted locational marginal pricing (LMP), implemented a financially binding day-ahead market (DAM), and introduced co-optimization of energy and operating reserve (OR) offers.

3.3.1 IESO physical, virtual and financial markets

The IESO issues market rules that govern the administration of the wholesale electricity markets in Ontario. The IESO is required to administer the electricity market in accordance with the market rules, and market participants are required to comply with the rules. Following its merger with the OPA on January 1, 2015, the IESO also assumed the responsibilities of the former OPA, namely procuring long-term power supply contracts as well as long-term system planning, conservation and demand management.

The IESO administers both physical markets and financial markets for electricity. In terms of physical markets, the IESO operates the day-ahead and real-time energy markets and the energy operating reserve market. The IESO also procures physical output through reliability must-run contracts with generators. The transmission rights market and inter-zonal virtual trading market are currently the only financial markets. Energy buyers and sellers have the option to enter into physical bilateral contracts, which are not part of the IESO scheduling and dispatch process and can no longer be financially settled through the IESO. Virtual bilateral contracts are also available with non-emitting generation facilities and are settled through the IESO. Intraprovincial trading is also permitted between designated IESO “zones.”

3.3.2 Day-ahead and real-time markets

In the DAM, market participants submit bids and offers a day in advance of operations in order to secure schedules and prices for the following day. The DAM is settled on an hourly basis, so schedules and prices are for an entire hour.

The IESO’s pre-dispatch balances differences between day-ahead schedules and actual real-time (RT) conditions. The IESO’s RT market (RTM) prices apply only to the energy needed to maintain this balance.

3.3.3 Wholesale prices

Under the pre-MRP wholesale market, wholesale prices were set every five minutes depending on the supply and demand in the market. The five-minute prices were then averaged to determine the Hourly Ontario Energy Price (commonly referred to as the HOEP) that is charged to load. The market operated under a two-schedule system, where out-of-market payments were made to account for deviations between economic dispatch and actual dispatch based on transmission constraints on the system. As of the implementation of MRP on or about May 1, 2025, the IESO wholesale market moved to a single-scheduling system, whereby transmission system constraints are reflected in local marginal prices, and the Ontario Electricity Market Price (Ontario Price) replaced the former HOEP.

The wholesale price of electricity is only one component of the total commodity cost for electricity in Ontario. Global Adjustment is used to pay for a variety of government programs, such as the costs of building new electricity infrastructure, guaranteed prices paid to generators under various procurement contracts, and conservation and demand management programs. The Global Adjustment rate varies monthly and is determined by a formula imposed by a regulation to the Ontario Electricity Act.

The amount of Global Adjustment paid by residential and small-business customers is calculated based on the amount of electricity consumed by the customer each month. Under a program known as the Industrial Conservation Initiative (ICI), however, certain large consumers pay Global Adjustment based on their average peak demand when the use of system-wide electricity is the highest, and not based on their actual consumption.

Specifically, the Global Adjustment rate for large consumers — those with an average hourly peak demand greater than 5 MW, or between 500 kW and 5 MW for certain industrial and commercial customers — varies individually depending on their energy use during the 5 highest coincident peak hours during the 12-month period beginning May 1 to April 30 of each year.

For example, generally speaking, if a business that qualifies for the ICI program on average uses 1% of electricity demand during the five highest coincident peaks of the year, its Global Adjustment rate will represent 1% of all Global Adjustment costs. Eligible large consumers can therefore reduce their Global Adjustment costs by reducing their energy use during times of peak system-wide electricity demand.

In addition to the price of the electricity commodity, ratepayers in Ontario are charged for the cost of transmission and distribution (delivery) to the customers’ locations at regulated rates determined by the OEB.

3.3.4 Operating reserve market

The IESO administers an operating reserve (OR) market, which ensures that additional supplies or demand reductions of energy are available should an unanticipated event take place in the real-time energy market creating a mismatch between generation and load. The IESO can call on this spare energy, which is offered into the OR market by dispatchable generators or dispatchable loads (e.g., to large-volume users who are able to reduce consumption) that can respond quickly to dispatch instructions from the IESO.

3.3.5 Ancillary services

Other forms of ancillary services are required to maintain the reliability of the IESO-controlled grid, including regulation service, reactive support and voltage control, and black-start capability. The IESO procures ancillary services through contracts with market participants who provide such services in accordance with the performance standards articulated in the market rules.

The IESO also procures Reliability Must-Run (RMR) contracts that allow the IESO to call on the contracted facility to produce electricity if it is needed to maintain the reliability of the electricity system. Any costs the IESO incurs for RMR contracts are recovered from all market participants as part of the IESO financial settlement process.

3.3.6 Transmission rights market

The transmission rights market allows market participants to sell and purchase transmission rights associated with intertie transactions between the IESO-administered market and neighbouring jurisdictions. The IESO conducts periodic auctions for transmission rights, which are financial instruments that entitle a holder to a settlement amount based on the difference between energy prices in two different jurisdictions. Specifically, transmission rights allow market participants who import and export power to buy financial protection ahead of time to hedge their prices for power across interties, resulting in a payment when congestion occurs on an intertie. The IESO determines which bids and offers are successful, given the clearing price for each transmission rights auction.

Since May 1, 2025 (i.e., the MRP go-live date), intertie LMPs are used for settlement of intertie transactions. Generators, dispatchable loads, price-responsive loads and intertie traders receive payments (or are charged) for their scheduled quantities of energy and operating reserves in the DAM based on the applicable day-ahead hourly LMP at the intertie. Any differences between the day-ahead schedules and actual real-time dispatch are settled using real-time LMPs.

3.3.7 IESO’s procurement of electricity contracts

In 2023, the IESO awarded a number of storage and natural gas contracts under the Expedited RFP, representing over 1,100 MW of new capacity to connect to the grid by 2026, and awarded five contracts (with one wind and four natural gas facilities) representing over 750 MW of contracted capacity under the Medium-Term 1 RFP. The IESO concluded the Long-Term 1 RFP in June 2024 with a number of storage, natural gas and biogas contracts representing a total of over 2,100 MW of new capacity scheduled to come into service between May 1, 2026, and May 1, 2028.

In 2025, the IESO carried out a second Medium-Term (MT2) RFP to recommit a portion of facilities with expiring contracts between 2026 to 2029. Pursuant to the MT2 RFP, the IESO procured approximately 3,000 MW of maximum contract capacity, which included both energy and capacity. Most recently, the IESO issued the results of its second Long-Term (LT2) RFP (window 1) to address increasing demand emerging in 2029 through the early 2030s in two streams: (i) an Energy Stream resulting in a total of 13 contracts representing over 1,100 MW of maximum contract capacity and an aggregate expected annual imputed production of 2.37 TWh, and (ii) a Capacity Stream resulting in a total of three battery storage contracts representing approximately 640 MW of new capacity resources. The IESO anticipates selecting MT3 submissions in June/July 2027 and the LT2 RFP (second window) proponents in the first quarter of 2028 for facilities that can reach commercial operation by May 1, 2032. The IESO has also recently launched a long-lead time (LLT) RFP for up to 1 TWh of energy and up to 800 MW of capacity. Successful proponents must have facilities with a lead time of at least five years that can respond to system needs for at least 40 years beginning between May 1, 2032, and May 1, 2034. LLT RFP proposal submissions are due November 26, 2026 (with registration beginning September 23, 2026), and LLT contracts are to be awarded by May 25, 2027.

3.4 Transmission and distribution

Hydro One Networks Inc. (HONI), which is a wholly owned subsidiary of Hydro One Inc. (Hydro One), is the owner and operator of over 90% of the transmission assets in Ontario. HONI also operates a significant distribution business. It is the largest local distribution company (LDC) in Ontario, serving approximately 1.5-million customers, including in the province’s rural areas. The remaining LDCs are mainly owned in part by municipalities. Transmitters and distributors, including HONI, are licensed by the OEB and are also subject to rate regulation by the OEB.

Prior to 2015, Hydro One, the parent of HONI, was a Crown corporation and wholly owned by the province. In April 2015, the Ontario government announced its intention to broaden ownership of Hydro One through an initial public offering. Hydro One completed two share offerings, and Ontario sold approximately 2.4% of the outstanding common shares to a limited partnership owned by 129 First Nations in Ontario. As a result, Ontario’s ownership interest has been reduced to approximately 47.4% of Hydro One’s total issued and outstanding common shares.

The provincial government is encouraging municipally owned LDCs to consolidate to form larger LDCs. The province expects that consolidation of LDCs will result in greater economies of scale for the benefit of ratepayers. To this end, the government announced in October 2024 amendments to the Ontario Electricity Act to remove barriers to consolidation among LDCs. The government also announced a series of measures intended to encourage additional private investment in the electricity distribution sector by removing punitive tax consequences when private sector investors acquire more than a 10% interest in municipal electrical utilities.

Ontario has also taken steps to encourage private developers to participate in the development of new large-scale transmission projects. This includes excluding privately funded construction, expansion or reinforcement of transmission lines by non-licensed electricity transmitters from the requirement under section 92 of the Ontario Energy Board Act to obtain prior leave to construct for the OEB.

4. Alberta — Power Industry and Laws

Alberta is the only province in Canada, and one of a limited number of jurisdictions in the world, with a deregulated, competitive wholesale power generation market. This market is commonly referred to as the “Power Pool,” which sets the price for electricity across Alberta for each and every hour of the year. It is operated by the Alberta Electric System Operator (AESO), which was established by the Electric Utilities Act (EUA). Currently, all electric energy bought and sold in Alberta must be exchanged through the Power Pool, and the hourly price determines the revenue for generators as well as the cost for consumers. A wide variety of contractual arrangements also exist such that the hourly price may not be the same for all market participants, but these contracts are influenced by the hourly price signal. It is this set of price signals, as opposed to a regulated “cost-of-service” model, which makes Alberta’s power market deregulated and highly responsive to supply-demand dynamics.

Significant market reform is currently underway to address current and anticipated challenges for Alberta’s energy-only market, including decarbonization, economic withholding, supply intermittency and grid reliability. Planning for the Restructured Energy Market (REM) was initiated by the AESO in early 2024. The REM will be implemented in phases, starting in mid-2027. The REM could substantially alter pricing and other market dynamics, but will not change the fundamentally deregulated and competitive nature of Alberta’s wholesale power generation market.

Interim measures to support the development of the REM began in March 2024, including the Market Power Mitigation Regulation to moderate price fluctuations and the Supply Cushion Regulation to ensure supply adequacy. Initial versions of AESO rules to facilitate the implementation of both regulations came into effect on July 1, 2024.

In April 2025, the provincial government introduced Bill 52, the Energy and Utilities Statutes Amendment Act, 2025 (Amendments), which included various legislative changes aimed at facilitating REM implementation and changes to regulations pertaining to transmission. The legislative changes are discussed in further detail in the following sections.

4.1 Policy setting and regulation

The Government of Alberta is responsible for setting electricity policy, which is primarily implemented by three entities that regulate and oversee Alberta’s electricity market: the Alberta Utilities Commission (AUC), the AESO and the Market Surveillance Administrator (MSA).

4.1.1 Alberta Utilities Commission

The AUC is an independent, quasi-judicial government agency mandated to ensure that Alberta’s utility services are provided in a manner that is fair, responsible and in the public interest. To this end, the AUC regulates electric utilities so that customers receive safe and reliable service at just and reasonable rates. Among other things, the AUC is responsible for overseeing tolls and tariffs regarding energy transmission, siting and approval of new generation and transmission facilities, establishing requirements for retail electricity markets, and adjudicating market participant conduct.

4.1.2 Alberta Electric System Operator

The AESO is the independent system operator of Alberta’s electricity system. The AESO’s primary responsibility is operating and planning Alberta’s interconnected electric system (AIES) in a safe, reliable and economic manner and ensuring fair and open access to the AIES. The AESO maintains a balance of electricity supply and demand on the AIES by monitoring the demand for electricity and dispatching electrical supply to match such demand in real time. To this end, the AESO manages power settlements under the Power Pool.

To plan for future needs, the AESO forecasts load and generation growth to determine when, where and what type of transmission facilities are required to be built. Historically, the AESO was required to operate the transmission system in a manner that ensured unconstrained access; however, this is no longer required. In July 2025, the government introduced amendments to the Transmission Regulation, enacted pursuant to the Energy and Utilities Statutes Amendment Act, 2025, which provide the AESO with a revised approach to transmission system planning. Now, the AESO is directed to consider a cost-benefit analysis when deciding whether it should make arrangements for the expansion or enhancement of the transmission system.

In July 2025, the Alberta government also directed the AESO to allocate financial transmission rights (FTRs) to incumbent generators for an 8-year transition period. Incumbent generators are those who have made a financial investment decision on or before July 9, 2025. FTRs will provide incumbents with compensation for a pre-allocated volume, allowing incumbents to mitigate congestion risk for a fixed volume. The payment will be for the difference between the generators’ local price and a system reference price for the volume of FTRs.

The AESO also implements transmission tariffs for the purpose of recovering the costs of building, maintaining and operating the AIES. These tariffs, which are subject to AUC approval, are structured to achieve a fair allocation of costs among stakeholders and to support a competitive market.

Historically, generators have paid the costs of connecting their generating units to the AIES, and consumers have paid all other costs of transmission by way of a usage-based tariff. However, the amendments to the Transmission Regulation are expected to implement a new Transmission Reinforcement Payment (TRP), calculated on cost-causation principles and payable by new generators.

Pursuant to the REM, the AESO has developed REM Independent System Operator (ISO) rules to facilitate REM implementation. The REM ISO rules were approved by the Minister of Affordability and Utilities in March 2026, pursuant to the Restructured Energy Market ISO Rules Regulation. Most REM ISO rules are not yet in force and are expected to come into effect on a phased basis with at least 30 days’ notice. A soft launch of the REM is expected in early Q3 2027.

The AESO has recently faced a surge of large load connection requests, particularly from data centres. This is discussed in further detail below.

4.1.3 Market Surveillance Administrator

Established by the EUA, the MSA acts as a monitor of Alberta’s electricity market to ensure its fair, efficient and openly competitive operation. The MSA has a broad mandate to observe and investigate the Alberta market to assess market participants’ conduct and investigate complaints received. If the MSA determines that a participant violated market rules or the principles of a fair, efficient and openly competitive market, such matter is referred to the AUC for adjudication.

4.2 Alberta’s Power Pool

Alberta’s Power Pool is an independent, central, open-access pool that functions as a spot market, matching demand for power with the lowest-cost supply to establish an hourly pool price. The Power Pool is governed by competitive market forces of supply and demand, where electricity is purchased and sold on a “real-time” basis as it is produced and consumed. The AESO manages power settlements under the Power Pool. The AESO accepts offers to sell power from generators and bids from various sources of “load” (purchasers of power) through an online trading platform. In 2025, Alberta’s wholesale electricity market comprised 409 participants and approximately C$5.36-billion in energy transactions.

4.2.1 Setting the Power Pool price

Alberta’s wholesale electricity market has a single hourly market where generators submit bids to supply electricity. Suppliers offer a price for their power seven days ahead of the delivery hour. As long as they have an acceptable operational reason, suppliers may change their volumes at any time and may change their offer price up to two hours prior to the delivery hour. Suppliers cannot change their offer price after this point. Pursuant to the Supply Cushion Regulation, the AESO is authorized to direct long lead-time assets online when the AESO’s supply cushion is forecasted to be below the baseline reserve of 932 MW. The REM initially contemplated creating a multi-settlement market with a DAM, followed by a real-time market. However, in the Restructured Energy Market Final Design released in August 2025, the AESO chose to remove the DAM from the REM due to stakeholder concerns about the REM’s complexity

Based on these offer prices from power suppliers, the AESO generates a “merit order” that sorts the offers from lowest to highest price for every hour of the day. AESO then dispatches the lowest price offers at the bottom of the merit order, moving incrementally up through the merit order until all demand for power has been supplied for that hour. The hourly pool price, which is paid for all MWs sold in that hour, is set by the last offer accepted in the merit order. The REM will shorten the interval over which the pool price is calculated.

Imports and certain forms of non-dispatchable generation must offer their power generation to the Power Pool as a “zero-price” offer, meaning their power generation is offered on a “price-taker” basis. These zero-price offers are first in the merit order, and these suppliers will receive the pool price otherwise established by fixed-price offers. “Price-takers” do not have any effect on determining the hourly pool price and must “take the price” set by the Power Pool.

Suppliers of dispatchable generation may also choose to be price-takers if they want to ensure that their generation is dispatched. For example, suppliers of low-cost baseload generation (e.g., cogeneration) typically offer a portion of their generation capacity at the zero price to guarantee that their generation is accepted into the Power Pool. It is quite costly and burdensome to shut-in baseload generation, and facility owners generally seek to avoid the situation where the baseload generation capacity is not dispatched due to the offer price being higher than the settled pool price.

Historically, a single pool price has applied across the entire province. In July 2025, the provincial government directed the AESO to implement LMP for producers. Whenever transmission capacity is a binding constraint on the dispatch of in-merit generation, constrained generation will be paid the LMP instead of the system marginal price. Costs associated with line losses will be recovered through the LMP. LMP enables the move towards market-based congestion management.

4.2.2 Offering and selling electricity into the Power Pool

Three categories of sellers are eligible to offer and sell electricity through the Power Pool: (i) marketers, who trade electricity within Alberta, (ii) importers, who import electricity through interprovincial ties with Saskatchewan, British Columbia or the international tie with Montana and sell this electricity into the Power Pool, and (iii) generators.

4.2.3 Bidding and purchasing electricity from the Power Pool

There are also three categories of eligible purchasers who may acquire electricity from the Power Pool: (i) retailers, who market and sell electricity to small commercial and residential consumers through the competitive retail market, (ii) direct access customers, who are generally large industrial customers that purchase their electricity on a wholesale basis through the Power Pool, and (iii) exporters, who purchase electricity from the Power Pool and export it to British Columbia, Saskatchewan or Montana. In order to become a Power Pool participant, one must obtain a licence from the AESO.

4.2.4 Commercial arrangements in the Power Pool

The generation and sale of electricity in Alberta is governed by the EUA, which requires that all electricity entering or leaving the AIES must be exchanged through the Power Pool. There are generally three methods of selling electricity in Alberta: through the Power Pool at the hourly pool price, through a direct sales agreement, and through a forward financial contract. These are detailed below.

1. Power Pool sales: As discussed, the AESO creates an hourly index, or pool price, based on the highest price offer needed to balance supply and demand. The hourly pool price is charged to the purchaser and paid to the seller who participated in the wholesale market during that particular hour. Currently, the maximum pool price is capped such that all offer and bid prices for electricity must be between C$0/MWh and C$999.99/MWh.

The recently enacted Market Power Mitigation Regulation applies a secondary offer price cap that limits generators’ offers to the greater of (a) C$125/MWh or (b) 25 times the day-ahead gas price. The secondary offer cap will only apply to non-renewable and non-storage generators that have 5% or more total market share. The secondary offer cap will only be triggered for those generators that have already earned two-twelfths of their annualized capital costs from the Power Pool in a given month and will apply for the balance of that month.

Pursuant to the REM, the energy market offer cap will increase to C$1,500/MWh and then will increase further to C$2,000/MWh in 2032 after nearly five years of REM operation. The energy price cap will be set at C$3,000/MWh. These increases are intended to provide stronger investment signals, and staging the rollout allows for markets to adjust. Market-clearing prices (but not bids) can exceed the offer cap and go up to the wholesale cap through an administrative scarcity-pricing mechanism where there is limited supply in the wholesale market and the market must turn to ancillary services. The price floor will remain at $0/MWh initially but will decrease to negative C$100/MWh in 2032.

2. Direct sales agreements: A direct sales agreement is a privately negotiated contract between two parties relating to the sale or purchase of electricity prior to the actual production and consumption of such electricity. A direct sales agreement allows a generator to bargain directly with a consumer to establish a set price for electricity, instead of using the pool price. Despite the fact that the price is determined through negotiation, is independent of the pool price, and payment occurs outside the Power Pool, the flow of electricity from seller to buyer still occurs through the Power Pool in real time and must be reported to the AESO. The AESO needs to know the amount of power purchased so that volumes sold into and taken out of the Power Pool may be adjusted to reflect the direct sales agreement.

The delivery of electricity in real time through the Power Pool under the direct sales agreement does not require generation and consumption in real time. This is because the AESO balances the difference in volumes actually generated and consumed by the parties versus the volumes contracted for in the direct sales agreement. If a generator produces less volume than the amount specified, the difference is considered a purchase from the spot market at the hourly pool price and is billed to the generator. Similarly, if a buyer consumed less volume than the amount specified, the difference is considered a sale to the spot market at the pool price and is paid to the suppliers.

3. Forward financial contracts: Forward financial contracts are agreements under which one party agrees to pay the other the difference between the price specified in the contract and the hourly pool price for the contract period. Forward financial contracts involve the flow of money and not the delivery of electricity. This arrangement allows a generator to hedge their risk by ensuring they will receive the contracted price for the duration of the contract. Without such a forward financial contract, the generating asset could either be idled or run at a loss any time the pool price is lower than the generator’s operating costs. The downside for the generator is that it will lose out on additional profits any time the pool price exceeds the contract price. Since the forward financial contract occurs outside the Power Pool and is independent of the flow of electricity, it allows for the participation of parties aside from Power Pool-licensed purchasers and sellers.

4.2.5 Ancillary services

The AESO must also procure system support services, known as “ancillary services,” from generators to assist in electricity transmission by balancing supply and demand. Ancillary services ensure the stability of the AIES so that electricity is efficiently and reliably transmitted throughout Alberta and system-wide blackouts and brownouts are avoided. These ancillary services are similar to those seen in other jurisdictions, such as Ontario, and include operating reserve, transmission must-run, black start and load shed schemes. Starting in 2022, the AESO ran a pilot project on fast frequency response, which is a fast-acting transmission service that allows for recovery from events such as the sudden loss of electricity imports from interties or internal generation.

Historically, the AESO recovered costs for ancillary services from load. Pursuant to the amendments to the Transmission Regulation, the AESO is authorized to recover ancillary services costs from the electricity market participant or class of participant that contributes to the need for those services. For example, the AESO may recover costs associated with ancillary services from renewable generators.

The REM introduces a new ancillary service, R30, which is a 30-minute ramping product. R30 ensures that the system has flexibility to respond to sudden changes in demand, such as those caused by extreme weather. The R30 product is procured by the AESO separately from energy. The AESO will prepare a demand curve for the R30 product, which will be used to determine the volume to be procured, and thus the price. The R30 demand curve will be capped at C$3,000/MWh to align with the energy market price cap.

4.3 Electricity market

The electricity market in Alberta can be divided into three distinct areas: generation, transmission and distribution, and load (including the retail market). Generally speaking, generation is completely deregulated, with the exception of facility permitting requirements; transmission and distribution are almost fully regulated, with the exception of government-mandated critical transmission infrastructure; and load is generally deregulated, with the notable exception of the retail market regulated rate of last resort option (RoLR) (see Section XVI.4.3.4, Load).

4.3.1 Generation

Prior to 1996, the power generation market was regulated under a utility-based cost of service model, whereby generators built and operated plants in return for a regulated power rate. Following the generation market’s deregulation, power purchase arrangements (PPAs) were introduced to govern the sale of power from the then-existing power plants.

The PPAs expired over various terms, with the last PPA expiring on December 31, 2020. Following expiry, the underlying facilities were returned to the original owner for dispatch into the Power Pool or decommissioning.

Generation plants added after market deregulation in 1996 were not subject to PPAs and have been built, and continue to be built, with private risk capital. With the exception of projects developed under the now-complete Renewable Electricity Program (pursuant to which the Government of Alberta procured renewable generation capacity between 2016 and 2019), generation developers and owners are not guaranteed a government-mandated price for their electricity, but instead take all financial risks that the Power Pool price will generate an acceptable rate of return.

Generators can hedge these financial risks by entering into direct sales agreements or financial forward contracts. Alternatively, generators pass the risks onto third parties through alternative contractual relationships. For example, in tolling arrangements, a third party agrees to pay the facility owner a fixed capacity payment, along with ongoing operating and maintenance costs, in return for the right to offer and sell the generation capacity into the Power Pool.

Deregulation also eliminated the requirement for developers to establish a market need for new generation capacity via a regulatory proceeding prior to the construction and operation of such capacity. Instead, development of new capacity is determined on a competitive market basis, with the Power Pool price and transmission capacity providing the “development signal” to prospective generation developers. If a prospective developer forecasts that the future supply and demand will produce a pool price capable of providing an acceptable rate of return for new generation capacity and determines that there is sufficient transmission capacity for their generation to be delivered to the AIES, the developer should proceed with the development, construction and operation of new capacity. Facilities continue, however, to be subject to AUC and other regulatory approvals regarding siting, environmental protection, water usage and other facility-permitting requirements.

Historically, generators paid a refundable Generating Unit Owner’s Contribution (GUOC) as part of the interconnection process. In 2024, the provincial government directed the AESO to implement a cost allocation framework for new transmission infrastructure by requiring new generators to contribute to transmission infrastructure costs by replacing the GUOC with an upfront and non-refundable Transmission Reinforcement Payment (TRP). Funds collected from the TRP must be used to offset the AESO’s annual transmission-related revenue requirement.

4.3.2 Transmission

In Alberta, the electricity transmission system remains a natural monopoly and is regulated under a cost-of-service model, with the AESO and the AUC setting the transmission tariff. The tariff is set at a rate where the transmission facility owner is meant to recover operating costs and receive a reasonable rate of return on its investment. Electricity transmission continues to be regulated by the AUC based on both “need” and “facilities” requirements.

Owners of transmission facilities retain ownership of their respective components of the system, but the transmission system as a whole is operated by the AESO. There are four main transmission facility owners in the province: ATCO Electric Ltd., EPCOR Energy Inc., ENMAX Power Corporation and AltaLink Management Ltd., the last of which owns more than half of Alberta’s transmission system and serves approximately 85% of its population. All entities eligible to trade power through the Power Pool have open access to the transmission grid.

4.3.3 Distribution

Distribution provides electricity to individual customers at a local level. The Hydro and Electric Energy Act creates statutory monopolies for each distribution facility owner’s service area. Investor-owned and certain municipally owned electricity distributors are rate-regulated under a performance-based regulation formula approved by the AUC. Performance-based regulation provides a proxy for a competitive market to incentivize efficiencies and cost reductions while ensuring that electricity service remains safe and reliable. Rural electrification associations (REAs) provide electricity distribution to rural communities. REAs are not rate-regulated by the AUC.

Distribution facility owners are responsible for connecting and disconnecting customers, building new services, operating and maintaining their infrastructure, sending distribution charges to the retailer, and providing meter-reading services. There are four main distribution facility owners in the province: FortisAlberta, ATCO Electric, ENMAX Power Corporation and EPCOR Energy Inc.

4.3.4 Load

Load is composed of two constituents: (i) direct access customers, primarily large volume industrial and commercial consumers of power who are registered Power Pool participants and directly purchase their electricity requirements from the Power Pool on a wholesale basis, and (ii) the retail market, representing lower volume commercial power consumers and residential power consumers. The market is currently fully deregulated for industrial and commercial customers who either act as self-retailers interacting directly with the Power Pool or who have access to competitive retailers as their electricity provider.

The retail market, primarily made up of residential customers, has access to electricity either from competitive electricity retailers or through a government-mandated RoLR. Retail customers may elect to sign a contract with a competitive retailer where the rates and terms of service are not regulated. Customers who choose not to contract with a competitive retail supplier automatically receive power from the default RoLR provider for their region at the regulated rate. The RoLR allows residential customers the option to purchase their power at regulated rates established every two years by the AUC.

4.4 Supply mix

4.4.1 Current supply mix

As of December 31, 2025, Alberta had 23,242 MW of installed electricity generation capacity and approximately 26,000 kilometres (km) of transmission lines. Natural gas accounted for the majority of Alberta’s installed generating capacity in 2024 (approximately 61%), followed by renewables (approximately 32%). The largest renewable source of installed generation capacity in Alberta is wind. As of December 31, 2024, Alberta ranks second out of all Canadian provinces and territories with 5,588 MW of installed generation capacity from wind. Wind generation currently constitutes about 25% of Alberta’s installed generation capacity.

In late 2024, the Government of Alberta issued the Electric Energy Land Use and Visual Assessment Regulation. The Regulation imposes limits and conditions on developments that occur on Class 1 or Class 2 agricultural lands, native grasslands, or within 35 km of provincial parks or “pristine viewscapes.” Developers are also required to post reclamation security with the province or the landowner on which infrastructure is sited. While installed generation capacity from renewables increased by 1,669 MW in 2024, the pace of growth of the renewable sector in the province has since slowed and installed capacity of all types plateaued in 2025.

4.4.2 Data centres

Alberta has implemented new policy and legislation to make the province attractive for data centre development. In 2024, Alberta released a policy document titled Alberta’s AI Data Centre Strategy: Powering the Future of Artificial Intelligence (AI Strategy). The AI Strategy focuses on developing on-grid and off-grid power solutions to avoid compromising the affordability and reliability of the electricity system. Alberta is facing unprecedented demand for large-load data centres to connect to the grid. By Q3 of 2025, the cumulative requested load for data centres in the province reached nearly 20,000 MW.

In June 2025, the AESO implemented a cap of 1,200 MW for large-load projects seeking to connect to the grid and started a process to allocate that load amongst qualified project developers. The entirety of the 1,200 MW capacity went to two data centre projects in development near Edmonton.

The AESO is now implementing processes to incentivize data centres to “bring your own generation” (BYOG), in line with Alberta’s Data Centre Regulation (DCR) released in June 2026 pursuant to the Utilities Statutes Amendment Act, 2025 (Bill 8). If a data centre is bringing its own generation, it will apply for approval of a power plant with the AUC. The DCR establishes two classes of large (>75MW) data centres. A tethered data centre is associated with dedicated electricity generation that can meet the data centre’s maximum demand. A bridged data centre requires electricity supply from the grid on a transitional basis for up to three years before it is paired with dedicated generation and designated as a tethered data centre. The AESO has allocated a 1,600 MW limit of grid capacity to support bridged data centres.

Under the DCR, the AESO must prioritize a system access service request from tethered data centres over bridged data centres. If at any time the AESO determines there is insufficient electricity supply to meet demand, bridged and then tethered data centres will be the first to be curtailed before other market participants. These elements represent a significant departure from the open-access principles that generally govern service in most other provinces.

The Financial Statutes Amendment Act (2025) (No. 2) adds a new levy to ensure that large data centres bear some of the costs associated with their electricity demands.

4.4.3 Greenhouse gas emission management

In 2020, Alberta implemented the Technology Innovation and Emissions Reduction (TIER) system to manage large industrial emissions by encouraging energy-intensive facilities to reduce emissions and invest in clean technology. TIER requires facilities in the electricity sector to achieve a “good-as-best-gas” emissions benchmark. Prior to 2023, this benchmark was set at 0.37 tonnes of CO2e per MWh. Benchmark stringency will increase on an annual basis between 2023 and 2030, during which time the emissions benchmark will shift from 0.3626 to 0.3108 tonnes of CO2e per MWh. Emitters may achieve the specified emissions benchmark in different ways, including purchasing credits from facilities that have exceeded their emission reduction targets or paying into a TIER fund.

The May 2026 Implementation Agreement for the Canada-Alberta MOU (MOU Implementation Agreement) states that the federal government will put the Clean Electricity Regulations in abeyance, pending the outcome of a challenge to the constitutionality of the regulations. The abeyance is contingent on strengthening Alberta’s TIER system.

Previously, the industrial carbon price under the TIER increased each year. However, in May 2025, the Alberta government announced that it is indefinitely freezing the price of carbon emissions from large emitters under TIER at C$95 per tonne of CO2e. Now, under the MOU Implementation Agreement, the carbon price will be set at C$100 in 2027–2029 and C$115 in 2030, followed by annual increases of C$3 to reach C$130 by 2035. This change represents a significant reduction from the prior price trajectory (which would have reached C$170 by 2030). The MOU Implementation Agreement also provides that Alberta will establish a price floor regulation to ensure that TIER credits are traded at a predictable price. TIER credits have been trading for as low as C$20 due in part to actual and anticipated oversupply.

5. British Columbia — Power Industry and Laws

British Columbia has a regulated electricity and energy market. The British Columbia Utilities Commission (BCUC) is an independent regulatory agency that regulates electricity and energy utilities pursuant to the Utilities Commission Act (UCA). The British Columbia Energy Regulator (BCER) is the primary regulator of energy projects.

British Columbia has a provincially owned utility company, known as BC Hydro. It is responsible for delivering power generation and transmission to users in the province and has a virtual monopoly over these activities in the province.

There are no significant subsidies or incentives for power generation entrants in British Columbia. There are no specific barriers to investment in the British Columbia power sector by non-resident individuals or corporations. However, in certain circumstances, the change of control of any utility regulated by the BCUC may require approval from the BCUC, which is charged with the responsibility of determining whether such a change of control is in the public interest.

There is no open power market in British Columbia that is comparable to the markets in Ontario and Alberta. Any person who owns or operates equipment or facilities for the production, generation, storage, transmission, sale, delivery or provision of electricity, natural gas, steam or any other agent for the production of light, heat, cold or power to or for the public or a corporation for compensation is regulated as a public utility under the UCA, subject to several exceptions. The BCUC regulates and oversees the operation of all public utilities, including establishing service standards and prescribing rates. Further, any person wishing to develop and operate a power-generating facility must generally obtain a “certificate of public convenience and necessity” from the BCUC before beginning the construction or operation of a public utility plant or system, or an extension of either.

The province owns the significant majority of the land base in British Columbia. Anyone wishing to establish a power generation facility is likely to construct on provincial land, which may require leases or other forms of tenure and permits from provincial regulators to construct and operate such facilities. Depending on the nature of the project, a variety of environmental permits, approvals and assessments may also be required. Such requirements may also extend to projects on private land or claimed Indigenous traditional territory.

British Columbia has a large number of First Nations (Indigenous Peoples) that claim virtually all of the provincial land base as their traditional territory. As a result, legal requirements exist that may require a power developer to enter into consultations with relevant First Nations to determine the potential impact, if any, of the project on the First Nations people. Accommodation measures may be required to be undertaken by proponents for such impacts. Therefore, project proponents often reach “impact benefit agreements” or similar commercial arrangements with affected First Nations. Similar consultations and accommodation measures are required in all of Canada’s provinces and territories if a project may affect a First Nations group.

Although BC Hydro is by far the largest power generator in British Columbia, it is possible to establish or acquire an independent power producer (IPP) in British Columbia that generates power, typically from renewable sources. Energy supply contracts entered into by an IPP may be approved by the BCUC if it is in the public interest to do so. Given BC Hydro’s near-total control of the provincial transmission grid, virtually all IPPs enter into connection agreements and power sale/supply agreements with BC Hydro.

The British Columbia Clean Energy Act, introduced in 2010, sets out British Columbia’s energy objectives, including achieving electricity self-sufficiency, fostering the development of innovative technology that supports energy conservation and efficiency and the use of clean or renewable resources, and reducing greenhouse gas emissions. In 2024, the Government of British Columbia announced updates to the energy objectives in the Clean Energy Act, including replacing the existing target that requires 93% of electricity generated in British Columbia to come from clean or renewable electricity generation with a new target of 100% by 2030. The updates also introduced a new objective: ensuring that BC Hydro is ready to acquire enough electricity to meet British Columbia’s long-term climate targets.

The CleanBC plan, originally launched in 2018, introduced a range of actions to reduce emissions, build a cleaner economy and prepare for the impacts of climate change. In 2021, British Columbia released the CleanBC Roadmap to 2030, which built on the CleanBC plan and includes stronger measures to meet British Columbia’s 2030 greenhouse gas reduction target of reducing emissions by 40% below 2007 levels. The plan calls for British Columbia to increase the generation of clean or renewable electricity to 100% and includes substantial investment in the electrification of upstream oil and gas production and industrial access to electricity. These measures are anticipated to result in a significant increase in electricity demand from BC Hydro. The key initiatives aimed at supporting British Columbia’s energy objectives include BC Hydro’s recent procurements of clean and renewable energy. For example, BC Hydro completed the construction and filling of a third dam and hydroelectric generating station, anticipated to increase the province’s electricity supply by 8%. British Columbia continues to require further renewable power sources to achieve the objectives under the CleanBC Road Map to 2030.

In 2024 and 2025, BC Hydro launched competitive Calls for Power to acquire new sources of clean, renewable electricity. As part of the Calls for Power, BC Hydro required eligible projects to include at least 25% Indigenous equity participation by one or more First Nations whose asserted traditional territory included the location of a proposed project. In total, BC Hydro awarded 14 electricity purchase agreements to successful proponents of wind and solar projects for sources of clean and renewable electricity.

In 2025, the government released the Clean Power Action Plan, which provides a strategy to double the clean electricity supply in British Columbia by 2050. Given its plan to increase the generation of clean or renewable electricity, the government made a series of legislative changes in 2025 to streamline the permitting of renewable energy projects in the province. This included, for example, expanding the authority of the BCER to act as the single-window regulatory authority for renewable energy projects and designated transmission lines. The government also exempted nine wind projects from the 2024 Call for Power and the North Coast Transmission Line project from the provincial environmental assessment process. In 2025, BC Hydro filed the 2025 Integrated Resource Plan with the BCUC for review and acceptance. The Integrated Resource Plan outlines plans for future provincial electricity needs, with a projected 20-year timeframe to guide decisions on power generation. The 2025 Integrated Resource Plan identified continued need for new renewable energy generation, expanding transmission infrastructure and new firm power sources, such as geothermal and pumped storage to complement wind and solar resources. At the time of writing, BCUC’s review of the plan is still in progress.

In 2025, BC Hydro also launched a Request for Expressions of Interest (REOI) for Capacity to gauge interest from organizations capable of delivering reliable and cost-effective capacity or baseload energy resources. BC Hydro has stated that the responses to the REOI will inform the development of long-term procurement strategies.

In June 2026, BC Hydro announced Powering Growth, Fueling Opportunity, a broader electricity system strategy. The comprehensive plan is advanced to meet electricity demand projected to grow 20% by 2030, and 50% by 2050, with peak demand increasing by 44%. The three-pillar approach to meet rising electricity demands is to conserve electricity, optimize existing BC Hydro infrastructure, and build new generation and transmission projects. BC Hydro is exploring two new potential hydroelectric projects, evaluating a range of additional power resources, such as geothermal opportunities, and advancing critical transmission investments to support reliability and economic growth. The proposed North Coast Transmission Line is proposed to double electrical capacity in the area, including to assist industrial development and trade opportunities in northwestern BC. The aforementioned changes signal continued government support for large-scale electricity infrastructure investments and power generation opportunities.