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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 supply mix based on each province’s 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, Alberta and British Columbia. Generation is primarily provided by rate-regulated government corporations in Quebec, Saskatchewan, New Brunswick and Manitoba. 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. Energy tribunals, whether they are 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 below-market 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 hydroelectric projects.
Nuclear generation supplies a portion of the baseload requirements in Ontario and New Brunswick. In Ontario, work has begun on a 300 megawatt (MW) small modular nuclear reactor at the Darlington Nuclear Generating Station, 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 Generating Station. Refurbishments are planned or underway for existing generators at each of the Darlington, Bruce and Pickering Nuclear Generating Stations.
Alberta also considers nuclear generation proposals on a case-by-case basis and both the Alberta and Saskatchewan governments have expressed interest in incentivizing the use of small modular reactor technologies within the provinces. 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 and coal resources. As a result, natural gas-fired or 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 other 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 and competitive bidding programs.
1.3 Emerging Technologies
Small Modular Reactors
Alberta, Saskatchewan, New Brunswick, Ontario and the federal government have created a series of plans and strategies to advance Small Modular Reactor (SMR) technology throughout the country.
In 2020, Canada released the Small Modular Reactor (SMR) Action Plan, which was 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 a Memorandum of Understanding (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.
The Action Plan and Strategic Plan call for SMR implementation to occur in three streams – a 300 MW SMR project at the Darlington Nuclear Site in Ontario for use by 2028 (since expanded to include three more SMRs at the Darlington Nuclear Site), followed by similar projects in Saskatchewan; two advanced SMR facilities in New Brunswick with demonstrations ready by 2030; and micro-SMRs for remote communities, with a five MW demonstration project already under way and to be completed by 2026. In Ontario, OPG is committed to building the SMR project at the Darlington Nuclear Site as outlined in the Action Plan and Strategic Plan. In New Brunswick, investments into SMR development started as early as 2018, with NB Power committing C$10-million towards an advanced research cluster in the province and Moltex Energy (Moltex) and ARC Nuclear Canada Inc (ARC Canada), each committing C$5-million. In 2021, New Brunswick committed C$20-million in funding for ARC Canada to bring SMRs to market from New Brunswick and the federal government committed C$50.5-million for Moltex to develop SMRs also in the province. In 2023, Natural Resources Canada launched the Enabling Small Modular Reactors Program to fund research and development related to SMR waste management and the creation of SMR supply chains within Canada. With this private and public support of SMRs to continue, Canada is positioning itself as a leader in this sector.
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. In late 2025, Alberta will hold public consultations regarding the addition of nuclear power to the province’s energy mix.
Blue and Green Hydrogen
In December 2020, the federal government released a Hydrogen Strategy for Canada (the 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 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 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 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, 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 procurements aimed at increasing utility-scale storage resources to support the wide-scale integration of renewable resources, like wind and solar. See further details below. 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. Both Ontario and Alberta have a number of new large-scale battery storage facilities in development that have been contracted or are soon to be contracted. There are nine 20 MW and one 10 MW battery storage facilities energized in Alberta, bringing the total installed generation capacity of battery storage to 190 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 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; Operations and Infrastructure). HQ continues to be 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). 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).
2.1.2 Quebec’s Régie de l’énergie (Régie)
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 (the 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 Act was amended to introduce more competition into the electricity market, make the Régie’s mode of operation more flexible, broaden its sources of funding, and establish the procedure for setting the rates and conditions applicable to the transmission and distribution of electric power.
The Régie sets and modifies the rates and conditions for the transmission of electric power by the electricity carrier, as well as for the distribution of electric power by the electricity distributors. 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.
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 rates; supervising calls for tender; producing finding reports, and 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 agreements between the Régie and 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, correct measures.
2.2 Quebec’s energy supply mix and energy strategy
In 2021, Quebec's electricity generation capacity totalled 47,078 MW, mainly generated through hydroelectricity (94%), followed by wind (5%) and biomass (0.6%).
Within the past decade, provincial commitments to the energy transition have repeatedly been affirmed. In 2016, the Quebec Energy Policy 2016-2030 (Policy) was released by the Quebec government. The Policy, to be implemented in multiple phases, the first of which has already been completed by adopting legislation governing its implementation, aimed to guide the province’s transition to renewable energies or low-carbon energy sources. Based upon 2013 data, the Policy set the following targets for 2030: (i) improve energy efficiency by 15%; (ii) reduce the consumption of petroleum products by 40%; (iii) eliminate thermal coal usage; (iv) increase renewable energy production by 25%; and (v) increase bioenergy production by 50%.
In 2017, the Quebec government unveiled the Action Plan 2017-2020 (Action Plan) to implement the first steps of the Policy through public investments totalling C$1.5-billion. Among other things, the Action Plan set out the construction by HQ of a 100 MW solar power station, the refurbishment of older power plants, and revisions to legal frameworks pertaining to Rate L (HQ’s rate for large-power industrial rate customers) and private wind power exportation.
These themes have also been echoed in more recent policy, such as the 2030 Plan for a Green Economy (PGE 2030) introduced by the Quebec government in 2020. 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 continue to underscore the importance of three objectives relating to the company’s goal of leveraging the province’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. Similarly, updates to the Quebec government’s orientations regarding land use are expected to be released soon, and it is anticipated that these will give rise to accelerated wind project development.
In 2023, legislative changes (Bill 2) were adopted to grant the Quebec government greater authority over the approval of power supply. Whereas HQ was formerly obligated to approve requests for power under 5 MW, such requests now require approval from the Minister of Economy, Innovation and Energy (Minister). Bill 2’s provisions are transitional, and specific regulations have yet to be adopted. HQ is currently not obligated to distribute electricity for requests greater than or equal to 5 MW from persons who did not enter into an agreement with HQ before December 2, 2022.
In July 2025, the government passed major legislative changes in the form of Bill 69, An Act to ensure the responsible governance of energy resources and to amend various legislative provisions (Act).
The key elements of the Act include:
- Governance
The implementation of an integrated energy resource management plan, to be updated every six years, is a key point of the Act. The first plan must be submitted by HQ for government approval by April 1, 2026. The plan must aim to promote energy development within the province, with a focus on energy transition, and must specify the electric power supply target that HQ needs to achieve to satisfy the electric power needs of provincial markets within the plan’s time frame. Ahead of the first plan, there is an interim power supply target of 255 TWh (60 TWh greater than current generation and consistent with the Action Plan 2035). The Act also requires Hydro-Québec, as electric power distributor, to provide a 15-year electric power supply plan and a 15-year electric power transmission system development plan.
The Act also includes increased disclosure requirements for HQ, the setting of common objectives between the Régie and HQ, the acceleration of hearings before the Régie, a reduction in the size of HQ’s board of directors, and partnership facilitation between HQ and Indigenous peoples for the development of wind power projects. - New energy project development
To streamline electric power procurement, the Act eliminated the absolute obligation that HQ (in its role as electric power distributor) proceed by tender to enter into power purchase agreements and grants authority to the provincial government (independently from the Régie) to obligate HQ to do so under certain conditions at its sole discretion. HQ (in its role as electric power distributor) will also be permitted to enter into bilateral power purchase agreements, with the Régie’s approval where required. The Minister was granted increased authority over commercial and industrial developments within the province by stipulating that, under certain conditions (to be specified by the Régie), HQ will require the Minister’s approval to distribute electric power.
Pursuant to the Act, with government approval, 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. Lastly, subject to government approval, the Act allows the construction of privately-owned small hydroelectric facilities (100 MW capacity or less). - Electricity distribution
The Act 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, the Act deviates from current 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. - Rate setting
The Act reverses changes enacted by prior legislation pertaining to rate-setting. Whereas 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 current five years) and set rates based upon what it determines as 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 starting in 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.
The Act also eliminates Rate L’s special protection against indexation of HQ’s heritage pool and sees that commercial and industrial rates also be set based upon the yearly revenue required by HQ to perform its distribution activities. The Régie is authorized to spread any rate increase over the three years covered by the rate review. The Act also includes mechanisms to protect residential consumers from rate hikes, such as the creation of a fund to support rate increase limits.
Additionally, the Act 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. In this new governance model, the Régie de l’énergie’s mission is to ensure Quebec’s energy needs are met while promoting an energy transition at the lowest cost, including innovation and social, economic and environmental benefits.
In 2011, the Quebec government launched its Northern Action Plan to advance integrated development of transport, mining and energy infrastructure in Quebec’s vast territory north of the 49th parallel (covering over 1.2 million km2 and representing 72% of the province’s surface area). Several new power projects were commissioned. 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 is scheduled for commissioning in late 2024 and marks a partnership between Boralex and Innu communities. In recent years, HQ has partnered with various Indigenous communities and governments to align projects with local needs and to provide local actors with management and ownership opportunities.
Several Quebec municipalities have also been chosen as North American sites for battery manufacturing. The municipalities of Shawinigan, Trois-Rivières, and Bécancour are leading this novel supply chain effort with several projects in development. In 2023 alone, over C$1.2-billion was invested by the Government of Canada, the Government of Quebec and by a consortium formed by the Ford Motor Company and South Korean companies EcoProBM and SK On to support cathode manufacturing in Bécancour. Battery supply chain developments within the Greater Montréal Area have also been announced, notably Volta Energy Solutions’ development of a copper foil plant in Granby and Northvolt’s development of lithium-ion battery production facilities in McMasterville and Saint-Basile-le-Grand.
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.
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. HQ also launched another Request for Proposals (RFP) in 2023, which included a novel geographic criterion – to be eligible, submitted projects have to be specifically located in target areas identified as strategic regions for infrastructure integration into HQ’s power 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. The duration of the supply contract must be between 20 and 25 years, with a commencement date by December 2029.
3. Ontario — Power Industry and Laws
3.1 Policy setting and regulation
Two entities set electricity policy and regulate Ontario’s electricity market: the Government of Ontario and the Ontario Energy Board (OEB). There is also a provincially-owned corporation, the Independent Electricity System Operator (IESO), that administers the operation of the electricity market 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 entity. OEB responsibilities include: determining the rates charged for regulated services in the electricity sector including transmission and distribution services; approving the construction of new transmission and distribution facilities; enforcing rules governing the conduct of participants in the electricity sector; providing education and public reporting for the benefit of electricity consumers; hearing appeals from market rule amendments made by the IESO; monitoring and approving the IESO’s budget and fees; and 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.” 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.
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.
As a result of market intervention, merchant generation effectively ceased. 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 in January 1, 2015, the IESO is responsible for two main functions:
- Administering Ontario’s electricity markets
- 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 local marginal pricing (LMP), implemented a full financially binding Day-Ahead Market (DAM), and introduced co-optimization of energy and operating reserve offers.
3.3.1 IESO physical 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 Market 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 may also procure 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.
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 Real-Time Energy Market (RTM) balances differences between day-ahead schedules and actual real-time conditions. RTM prices apply only to the energy needed to maintain this balance.
3.3.3 Wholesale prices
Under the previous real-time 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. As of May 1, 2025, the Ontario Electricity Market Price (Ontario Price) replaced the HOEP. According to the IESO, the Ontario Price takes into account system conditions and the availability of transmission capacity. It also incorporates a day-ahead price that provides operational certainty.
Unlike the HOEP, which was posted in real time, the Ontario Price is available after the fact. First, the IESO determines a base price that reflects the cost of supply needed to generate electricity. Second, the base price is adjusted to reflect transmission capacity. Third, local prices are averaged to create a provincial hourly day-ahead price. Lastly, the IESO calculates an adjustment to account for small differences between the amount of energy that was settled in the day-ahead market and what was used in real time.
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 five highest coincident peak hours between the period 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.
Starting May 1, 2025 (i.e., the MRP go-live date), intertie locational marginal prices (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 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 recent years, the IESO launched, among other things, an Expedited RFP for 1,500 MW for resources that can be in service May 1, 2026, a Medium-Term RFP for 700 MW for resources that can be in service between May 1, 2024 and May 1, 2026, and a Long-Term 1 RFP for 2,200 MW for resources that can be in service by May 1, 2027. In 2023, the IESO awarded 17 storage contracts under the Expedited RFP representing 1,177 MW of new capacity to connect to the grid by 2026, and awarded five contracts under the Medium-Term RFP with one wind and four natural gas facilities. The IESO concluded the Long-Term 1 RFP in June 2024 with 13 contracts representing a total of approximately 2,194 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 RFP (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. The IESO is currently engaging in a second Long-Term RFP (LT2 RFP) to address increasing demand emerging in 2029 through the early 2030s in two streams (to be administered in multiple procurement LT2 windows): (i) an Energy Stream seeking a total of 14 GWh; and (ii) a Capacity Stream seeking a total of 1600 MW of new capacity resources. The IESO anticipates selecting the LT2 RFP (first window) proponents in 2026. The IESO is also in the early stages of a long-lead time RFP (LLT RFP). The development of the LLT RFP is ongoing.
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 1.3-million customers, primarily 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 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 OEB 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. The Restructured Energy Market (REM) is expected to require at least 3 years to develop and will be implemented in phases over the next 5 or more years. The REM could substantially alter pricing and other market dynamics but is not expected to 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 includes various legislative changes aimed at facilitating the implementation of the Restructured Energy Market 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 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 balance 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 ensures unconstrained access; however, this is no longer required. In July 2025, the government introduced amendments to the Transmission Regulation, 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 Government also directed the AESO to allocate financial transmission rights (FTRs) to incumbent generators. 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 pay all other costs of transmission by way of a usage-based tariff. However, the amendments to the Transmission Regulation are expected to enable the reallocation of transmission costs to some or all generators.
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 2024, Alberta’s wholesale electricity market was comprised of 384 participants and approximately C$7.6-billion in energy transactions.
4.2.1 Setting the Power Pool price
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.
Based on these offer prices from power suppliers, the AESO generates a “merit order” that sorts the offers from the lowest price to the 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 may 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 will be 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 its 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 locational marginal pricing (LMP). 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.
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: marketers, who trade electricity within Alberta; 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 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: retailers, who market and sell electricity to small commercial and residential consumers through the competitive retail market; direct access customers, generally large industrial customers who purchase their electricity on a wholesale basis through the Power Pool; and 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.
- 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) $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 market operation. Also, the energy price cap will be set at $3,000/MWh. The price floor will remain at $0/MWh initially but will decrease to negative $100/MWh in 2032. - 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. - 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 maintaining system stability through voltage and frequency control. 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.
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 contribute to the need for those services. For example, the AESO may recover costs associated with ancillary services from renewable generators.
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.4.3.3, 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.
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 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 consumers of power 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 RRO 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, 2024, Alberta had 23,122 MW of installed electricity generation capacity and approximately 26,000 km of transmission lines. Natural gas accounted for the majority of Alberta’s installed generating capacity in 2024 (approximately 60%) 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, it remains to be seen if the recent policy guidance will slow the pace of growth of the renewable sector in the province once implemented.
4.4.2 GHG Emission Management
In 2020, Alberta implemented the Technology Innovation and Emissions Reduction (TIER) system to manage emissions from 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 MW-hour. 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 MW-hour. 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.
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.
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, deliver 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 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 February 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 of 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. In April 2024, BC Hydro launched its first competitive Call for Power in over 15 years to acquire new sources of clean, renewable electricity. As part of the Call for Power, BC Hydro required eligible projects to include at least 25% Indigenous equity participation by one or more British Columbia First Nations whose asserted traditional territory included the location of a proposed project. In December 2024, BC Hydro awarded ten Electricity Purchase Agreements (EPA) to successful proponents that will provide nearly 5,000 gigawatt-hours (GWh) per year of clean and renewable electricity.
In late 2024, BC Hydro completed the construction and filling of the Site C Clean Energy Project (Site C), a third dam and hydroelectric generating station on the Peace River in northeastern British Columbia. Site C has added 5,100 gigawatt hours per year of electricity and will provide 1,100 MW of dependable capacity to the system. Even with Site C coming online, British Columbia will require new renewable power to achieve its objectives under the CleanBC Roadmap to 2030.
In May 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 May 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.
The Clean Power Action Plan also set out BC Hydro’s plan for a new Call for Power. In May 2025, BC Hydro issued further request for proposals for a Call for Power, which mirrored the requirements from the 2024 Call for Power. The 2025 Call for Power will procure 5000 GWh/year of clean and renewable energy. BC Hydro anticipates awarding Electricity Purchase Agreements in early 2026.
In 2025, BC Hydro also launched a Request for Expressions of Interest (RFEOI) for Capacity to interest from organizations capable of delivering reliable and cost-effective capacity and/or baseload energy resources. BC Hydro has stated that the responses to the RFEOI will inform the development of long-term procurement strategies.