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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 Generation Station, and the government has announced its intent to add three more 300 MW SMRs at Darlington in the coming years. Pre-development studies are underway for 4,800 MW of new nuclear reactors at the Bruce Power Generating Station, and refurbishments are planned or underway for existing generators as 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. Alberta has recently added significant gas-fired generation to replace coal-fired generation, which was completely phased out as of June 2024. Ontario has also eliminated coal-fired generation, and Nova Scotia has a legislated target to eliminate coal-fired generation 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
In 2018, Canada released a Small Modular Reactor (SMR) Roadmap, concluding that the implementation of a successful SMR strategy in Canada must include funding for SMR demonstration projects, legislative and regulatory changes, public engagement, and international enabling frameworks. In December 2019, Ontario, New Brunswick, and Saskatchewan signed a Memorandum of Understanding (MOU), with Alberta joining on April 14, 2021, to establish a framework that will maximize the potential to access market opportunities in Canada and internationally. As part of the MOU, a Feasibility Report (the Report) was drafted by the energy ministers of the original MOU and the CEOs of Bruce Power, Ontario Power Generation (OPG), and SaskPower. The Report identified extensive expertise in Ontario and New Brunswick in design, construction and servicing of nuclear reactors. There is an abundance of resources in Canada, with Saskatchewan being the home to the Athabasca basin housing - the largest volume of uranium in the world.
In December 2020, Canada released an SMR Canada Action Plan (Action Plan) based on the recommendations gathered from the Roadmap. The goal of the Action Plan is to establish Canada’s leadership in the sector by anchoring jobs, intellectual property, and supply chains in the country. Investments have already started in some provinces. In March 2022, the governments of Ontario, New Brunswick, Alberta and Saskatchewan released a Strategic Plan for the Deployment of SMRs (Strategic Plan), which represents the final deliverable under the MOU. 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.
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.
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.
There are already a few large-scale investments in hydrogen energy in the country, including 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
With Ontario projecting a demand increase of 2% per year over the next 20 years due to electrification, decarbonization and economic growth, the Province 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, and there are thermal, flywheel, compressed air, pumped hydro and hydrogen storage solutions deployed in Ontario, battery storage has been the most widely adopted solution. 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. In 2023, six 20 MW battery storage facilities were 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 operator 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 of 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 load and point-to-point 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 2019, Quebec's electricity generation capacity totalled 46,380 MW, mainly generated through hydroelectricity (94%), followed by wind (5%) and biomass (0.7%). As of 2012, Quebec had an estimated 45,000 MW of untapped hydroelectric power potential with approximately 20,000 MW offering an economic potential. Quebec’s exploitable wind power potential was estimated to amount to almost eight million MW.
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 June 2024, major legislative changes (Bill 69) were tabled by the government of Quebec. This highly-anticipated bill, once adopted, will amend most of the existing energy-related legislation in Quebec, with the goal of enabling the province to achieve its carbon neutrality and energy transition goals by 2050. The bill’s key elements are as follows:
1. Governance
The implementation of an integrated energy resource management plan, to be updated every six years, is a key point of Bill 69. 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, Bill 69 suggests a yearly power supply target of 255 TWh (60 TWh greater than current generation and consistent with the Action Plan 2035). Bill 69 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.
2. New energy project development
To streamline electric power procurement, Bill 69 will eliminate 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 will be 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. Lastly, subject to government approval, Bill 69 will allow the construction of privately-owned small hydroelectric facilities (100 MW capacity or less).
3. Electricity distribution
Bill 69 will allow renewable energy producers to sell and distribute electricity to a single private customer for the needs of their installations. While such transactions will be limited to certain contexts (for which the current draft of Bill 69 lacks clear definitions) and require government authorization, Bill 69 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.
4. Rate setting
Bill 69 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). In some situations, HQ may request rate or terms of service modifications from the Régie outside of the scheduled reviews. Bill 69 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. By contrast, Bill 69 includes mechanisms to protect residential consumers from rate hikes, such as the creation of a fund to support rate increase limits.
Additional consultations will occur ahead of the expected adoption of Bill 69 in late 2024.
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. Even more recently, in July of 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.
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. There is also a provincially owned corporation, the Independent Electricity System Operator (IESO) that administers the electricity market.
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. Upon the approval of cabinet, the minister of energy can issue policy directives to the OEB and the IESO, and each is required to implement such policy directives. The minister of energy 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 of energy, 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; formulating rules to govern the conduct of participants in the electricity sector; engaging in advocacy on behalf of electricity consumers; hearing appeals from decisions made by the IESO; monitoring and approving the IESO’s budget and fees; and monitoring electricity markets and reporting thereon to the minister of energy.
In Ontario, the cost for transmission and distribution of electricity to a customer is charged separately from the commodity price of electricity. The OEB typically regulates the cost of transmission and distribution service, while the commodity cost of electricity is determined in the IESO’s real-time wholesale market. In addition, the provincial government has imposed on most electricity customers an additional charge known as the Global Adjustment. The Global Adjustment rate is typically inversely related to the IESO market price of electricity, and usually the lower the market price the higher the Global Adjustment rate.
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 companies, 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 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 because of political pressure due to volatile electricity prices. The rate freezes have since been lifted, but some elements of price smoothing and subsidy still remain.
As a result of intervention in the market, 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)
3.3.1 IESO physical and financial markets
The IESO is responsible for administering the electricity markets in Ontario and for directing the operation of Ontario’s transmission grid. The IESO has issued Market Rules that govern the market for electricity and ancillary services 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. Subsequent to its merger with the OPA on January 1, 2015, the IESO also assumed the responsibilities of the former OPA for procuring long-term power contracts and for 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 real-time wholesale market and the market for ancillary services. The IESO may also procure physical output through reliability must-run contracts with generators. Currently, the transmission rights market is the only financial market. 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 Real-time wholesale market and commodity price
In the Real-Time Wholesale Market, the price of the electricity commodity is determined by the availability of supply and changes in demand. The IESO runs a real-time market, meaning purchases of electricity are made as they are needed.
Each day, the IESO forecasts the demand for electricity and makes this information available to participants in the market. Generators and other energy suppliers send in their offers to provide energy. The IESO then matches the offers to supply electricity against the forecasted demand. It first accepts the lowest-priced offers and then “stacks” up the higher-priced offers until enough have been accepted to meet customer demands. Instructions are issued to power suppliers based on the winning bids, who then provide electricity into the power system for transmission and distribution to customers. All suppliers are paid the same Market Clearing Price based on the last offer accepted. A new price is set every five minutes depending on the supply and demand in the market. The five-minute prices are averaged to determine the Hourly Ontario Energy Price (commonly referred to as the HOEP).
While long-term projections forecast growth in electricity demand by at least 2% per year (in Ontario from 2025 and onwards, energy demand is projected to outpace supply through 2040), historically there has been excess generating capacity in Ontario, which drives down wholesale market prices. For example, in Ontario there has been surplus baseload generation causing “must-run” nuclear and large hydroelectric generators to bid in at prices resulting in negative pricing. This downward pressure on wholesale prices did not translate into downward pressure on the total price paid for the electricity commodity as most electricity consumers in Ontario also pay a charge known as the Global Adjustment, which is used to pay for a variety of government programs, such as the guaranteed prices paid to generators under various procurement contracts and for conservation and demand management programs.
The Global Adjustment rate varies monthly and is determined by a formula imposed by a government regulation. It is typically inversely related to the IESO market price of electricity whereby a lower HOEP will result in a higher Global Adjustment rate.
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. However, certain large consumers pay based on their average peak demand when the use of system-wide electricity is the highest and not based on their actual consumption.
Under a program known as the Industrial Conservation Initiative (ICI), the Global Adjustment rate for large consumers — those with an average hourly peak demand greater than five MW, or between 500 kW and five MW for certain industrial and commercial customers — varies individually depending on their energy use during the five highest coincident peak hours between the period of May 1 to April 30 of each year. For example, 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 reduce their electricity costs by reducing their energy use during times of peak system-wide electricity demand.
In addition to the price of the electricity commodity, electricity customers in Ontario pay additional charges for the cost of transmission and distribution to the customers’ location at regulated rates determined by the OEB.
3.3.3 Operating Reserve market
The IESO administers an Operating Reserve (OR) market, which ensures that additional supplies of energy are available should an unanticipated event take place in the real-time energy market, such as a surge in demand, an unexpected equipment failure at a generating facility or an unexpected drop in wind velocity. The IESO can call on this spare energy capacity, which is offered into the OR market by dispatchable generators or dispatchable loads (e.g., to large-volume users who are able to cut consumption) who can respond quickly to dispatch instructions from the IESO.
3.3.4 Ancillary services
Ancillary services are required to maintain the reliability of the IESO-controlled grid, including: frequency control, voltage control, reactive power 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.
3.3.5 Reliability must-run contracts
The IESO has authority to execute 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 that the IESO incurs for RMR contracts are recovered from all Market Participants as part of the IESO settlement process.
3.3.6 Transmission rights market
The Transmission Rights Market allows a Market Participant to sell and to purchase transmission rights associated with transactions between the IESO-administered Market and an adjoining electricity jurisdiction. The Transmission Rights Market allows Market Participants who import and export power to buy financial protection ahead of time to hedge their prices for power across interties. The IESO conducts 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 zones. The IESO determines which bids and offers are successful, given the clearing price for each transmission rights auction.
3.3.7 Day-ahead commitment process
The IESO’s Day-Ahead Commitment Process requires dispatchable generators and dispatchable loads to submit offers and bids one day in advance, and generators are able to signal in advance any limits on their production for a given dispatch day. The Day-Ahead Commitment Process is intended to improve information regarding the operation of the market so as to allow the IESO and Market Participants to better gauge the adequacy of market resources and help to improve forecasts of next-day market prices.
3.3.8 IESO’s procurement of electricity contracts
On January 1, 2015, the IESO took over the functions that were previously being carried out by the OPA, including responsibility for forecasting medium and long-term demand for and reliability of electricity resources; for planning adequate generation, demand management, conservation and transmission for Ontario; and for procuring new generation through various forms of procurement processes. This capacity is spread across several fuel types including nuclear, natural gas (both Combined Heat and Power and Simple/Combined cycle), and renewables like wind, solar, hydro and bio-energy.
The IESO’s 2022 Annual Acquisition Report (AAR) signalled the IESO’s intent to launch a Request for Proposal (RFP) for at least 5,000 MW to address multiple reliability needs. As a result, 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 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.
The next series of procurements (LT2 RFP and MT2 RFP) will look to address reliability needs emerging in 2029 through the early 2030s in three streams: (i) Energy Stream seeking approximately 2,000 MW of new supply to be in service by 2030; (ii) Capacity Stream seeking 500 MW to 1,000 MW to be in service by 2031; and (iii) long lead-time resources procurement (which could include new hydroelectric assets and long lead-time duration storage) seeking 500 MW to 1,000 MW to be in service by 2034.
Ontario recently announced support for the addition of four 300 MW small modular nuclear reactors at the Darlington Nuclear Generation Station and 4,800 MW of new nuclear reactors at Bruce Power Generating Station.
3.3.9 IESO Market Renewal Project
The IESO is currently engaged in a Market Renewal project to consider and implement fundamental market design changes which are intended to provide greater certainty to market participants and lower the cost of electricity in Ontario. Currently, Ontario’s electricity market design uses a “two-schedule” energy market for determining and settling operational decisions, and in the past Ontario primarily obtained additional electricity supply by entering into long-term procurement contracts with independent power producers. It is expected that Market Renewal will fundamentally reform both of these practices by: (1) the implementation of a Single Schedule Market that will use locational pricing for generators and other resources that participate directly in the wholesale electricity market (2) the introduction of a financially binding day-ahead market; and (3) optimized intra-hour market bids and offers for both energy and operating reserve (i.e., enhanced real-time unit commitments).
The IESO is currently in the implementation phase. The Market Renewal initiatives, including the Incremental Capacity Auction, are expected to go into effect May 1, 2025.
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 and serves 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 on a cost-of-service basis.
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. A public consultation was initiated by the Ontario Energy Board on this issue in July 2023, and recently ended in June 2024 with the issuance of an updated OEB Handbook to Electricity Distributor and Transmission Consolidations and associated Filings for Consolidation Applications.
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.
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 need, the AESO forecasts load and generation growth to determine when, where and what type of transmission facilities are required to be built.
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. Currently, generators pay 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. Forthcoming amendments to Alberta's Transmission Regulation are expected to reallocate transmission costs to some or all generators on a cost causation basis going forward. The amendments are also expected to allow some level of ongoing congestion on the AIES.
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 2023, Alberta’s wholesale electricity market was comprised of 276 participants and approximately C$15.8-billion in energy transactions.
4.2.1 Setting the Power Pool price
Currently, 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. Among the expected REM design outcomes is the introduction of a day-ahead market pursuant to which generators lock in offers, usually before the next operating day. This is expected to provide generators with the ability to accurately predict their availability with more certainty and price stability but may have the opposite effect for generators without this ability, such as renewables.
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.
Currently, 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.
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.
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. 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. In addition, the REM is expected to raise the pool price cap in certain circumstances and may allow for negative offer and bid prices.
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 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.
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 option (RRO) (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.
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 latter 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 RRO. The RRO allows residential customers the option to purchase their power at regulated rates established on a monthly basis by the AUC. 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. Proposed changes to the RRO, which are expected to come into effect by January 2025, include renaming the RRO to the “Rate of Last Resort” and setting the RRO every 2 years rather than on a monthly basis.
4.4 Supply mix
4.4.1 Current supply mix
As of December 31, 2023, Alberta had 20,777 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 2023 (approximately 57%) followed by renewables (approximately 34%) and coal and dual fuel (using both coal and natural gas) (approximately 6%).
The largest renewable source of installed generation capacity in Alberta is wind. As of December 31, 2023, Alberta ranks second out of all Canadian provinces and territories with to 4,481 MW of installed generation capacity from wind. Wind generation currently constitutes about 22% of Alberta’s installed generation capacity.
Following the expiry of the Generation Approvals Pause Regulation, the Government of Alberta issued policy guidance to the AUC that is intended to apply to renewable energy projects approved on or after March 1, 2024. This policy guidance 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 will also be required to post reclamation security with the province or the landowner on which infrastructure is sited. While installed generation capacity from renewables increased by 1,375 MW in 2023, 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.
5. British Columbia — Power Industry and Laws
British Columbia has a regulated electricity market. The British Columbia Utilities Commission (BCUC) is an independent regulatory agency that regulates electricity utilities pursuant to the Utilities Commission Act (UCA). 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 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.
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 builds 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.
BC Hydro is nearing completion 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 will add 5,100 gigawatt hours of electricity each year and will provide 1,100 MW of dependable capacity to the system. Site C’s earliest in-service date is currently projected to be 2025. Even with Site C coming online, British Columbia will require new renewable power to achieve its objectives under the CleanBC Roadmap to 2030.
One of the key initiatives aimed at supporting British Columbia’s energy objectives is BC Hydro’s upcoming Call for Power. In April 2024, BC Hydro launched its first competitive Call for Power in over 15 years to acquire new sources of clean, renewable electricity. Prior to launching this Call for Power, BC Hydro completed an engagement process to seek input from First Nations, independent power producers and other stakeholders regarding BC Hydro’s approach to acquire approximately 3,000 gigawatt-hours (gWh) per year. The objectives of this Call to Power are to acquire energy from: i) clean or renewable resources that are cost-effective for BC Hydro’s ratepayers, ii) projects that are ready to come online as early as Fall 2028; and iii) projects that have a meaningful First Nations partnership component. The Request for Proposals are due in September 2024. As part of the Call for Power, the province is providing $140 million to the B.C Indigenous Clean Energy Initiative to support Indigenous-led power projects.