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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 (formerly the National Energy Board) 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. Ontario recently announced support for the addition of four 300 megawatt (MW) small modular nuclear reactors at the Darlington Nuclear Generation Station and 4,800 MW of new nuclear reactors at the Bruce Power Generating Station. Alberta also considers nuclear generation proposals on a case-by-case basis and the Alberta government has expressed interest in incentivizing the use of small modular reactor technologies within the province. At the opposite end of the spectrum, Quebec closed its only nuclear power facility 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 and coal-fired generation can be found in most 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 will be completely phased out by the end of 2023. 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, international enabling frameworks. On 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. 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 $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.
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.
2.1 Electricity sector and Regulatory Framework main factors
Quebec has a regulated electricity market. Québec’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.”
Hydro-Québec is one of the largest electric utilities in North America. Under its incorporating statute, Hydro-Québec is given broad powers to generate, supply and deliver electric power throughout the province. Hydro-Québec is 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.
Hydro-Québec is organized in separate divisions:
- Hydro-Québec Production is responsible for generating power for the Quebec market and sells power on wholesale markets. This division is responsible for furnishing the heritage pool electricity to Hydro-Québec Distribution in order to supply Quebec customers.
- Hydro-Québec TransÉnergie is the transmission system’s operator and manages power flows throughout the province.
- Hydro-Québec Distribution is the distributor of electricity to Quebec customers with an almost exclusive right to distribute throughout the province. In order to meet needs beyond the annual heritage pool electricity, which Hydro-Québec production is obligated to supply, Hydro-Québec Distribution buys power on open markets.
- Hydro-Québec Équipement et services partagés and Société d’énergie de la Baie James is responsible for designing and carrying out projects for the construction and refurbishment of generation and transmission facilities.
2.1.2 Québec’s Régie de l’Énergie (Régie)
The Régie is the agency responsible for regulatory supervision of the transmission and distribution of electric power, and electricity rates in Quebec are subject to its approval. The Régie was created by virtue of the Act Respecting the Régie de l’énergie (Act) with the powers needed to regulate the electricity and natural gas sectors in order to respond to the requirements of the liberalization of the North American electricity market, including the guarantee 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 fixes and modifies the rates and conditions for the transmission of electricity power by the electricity carrier and the distribution of electricity power by the electricity distributors. In fixing and modifying rates, the Régie favours the use of incentives to improve the carrier’s and distributor’s efficiency to protect the interests of the consumers. Hence, Hydro-Québec’s transmission and distribution activities are subject to the conventional form of regulation based on the cost of service for those activities.
More specifically, the Régie effectively regulates the generation, transmission and distribution segments of the electricity market as follows:
- Generation: The heritage pool of 165 TWh is established on the basis of an average cost for heritage electricity supply of C$0.279 per kilowatt hour and since 2014 this cost of heritage pool electricity has been indexed to inflation, except for large-power industrial customers (Rate L). The cost of electric power over and above the heritage pool electricity is determined by way of call for tenders and supply contracts are awarded on the basis of the lowest tendered price and such other factors as the applicable transmission costs. Québec’s Régie has procedures in place to govern calls for tenders and contract awards, and has adopted a code of ethics on conducting calls for tenders presented to Hydro-Québec. The Régie also approves the process for purchasing programs for electricity from renewable sources and the Act provides that the provincial government shall determine the initial conditions for defining acquisition of blocks of energy by decree establishing supply rates, which represent the energy portion attributed to a class of consumers.
- Transmission: The Régie is responsible for setting the load and point to point rates with incentive mechanisms to improve the efficiency of Hydro-Québec TransÉnergie and to establish rates based on cost of service including a reasonable return. As required under the Act, the rates shall respect territorial uniformity. The Régie also adopts and monitors the application of reliability standards for Hydro-Québec TransÉnergie’s network and ensure the non-discriminatory access to the network.
- Distribution: The Régie sets distribution rates on a cost of service basis including a reasonable rate of return. The Régie is responsible for setting rates respecting territorial uniformity and it also approves the conditions of Hydro-Québec Distribution supply contracts.
2.2 Quebec’s energy supply mix and energy strategy
In 2013, Quebec’s electricity generation capacity totalled 43,731 MW, mainly generated through hydroelectricity (90%), but also winds power (5.5%) or biomass-based cogeneration (0.6%). Quebec has 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 amounts to almost eight million MW.
On April 7, 2016, the Québec Energy Strategy 2016-2030 (Strategy) was released, pursuant to which the government’s goals and actions in the energy sector for the period from 2016 to 2030 were defined. Pursuant to the Strategy, the government has 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%.
On June 26, 2017, the Government of Québec unveiled the Action Plan 2017-2020 (Action Plan) in order to implement the first steps of the Strategy through public investments totalling C$1.5-billion. Among other things, the Action Plan sets out the construction of a 100 MW solar power station by Hydro-Québec.
On the transmission side, Hydro-Québec’s objective is to increase exports to the United States with the contemplated development of projects with New England including the approximately 1,200 MW New England Clean Energy Connect project between the Quebec/Maine border and the City of Lewiston in Maine.
Additionally, the Plan Nord launched by the Quebec government seeks to develop Quebec’s vast territory north of the 49th parallel, which covers 72% of the province or approximately 1.2 million km2. The initiative seeks an integrated development of transport, mining and energy infrastructure. The Strategy refers to the Plan Nord by promoting the development of liquefied natural gas (LNG), natural gas, hydrocarbons and wind farm projects in this portion of Quebec.
Hydro-Québec also launched on June 28, 2019 a request for proposals for the allocation of a 300 MW block of capacity for the Quebec blockchain industry.
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, but if the parties choose, they can submit specific data to the IESO and ask the IESO to provide a market settlement service.
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 (in Ontario from 2025 and onwards, energy demand will outpace supply), in the short term 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 and usually 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 coincident peak hours. 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. The Ontario government launched a review of the effectiveness of the ICI program in November 2018, and it is possible that the program could be significantly changed or cancelled as a result of that review.
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 2021 Annual Acquisition Report (AAR) signalled the IESO’s intent to launch a Request for Proposal (RFP) for at least 1,000 MW to address multiple reliability needs. As a result, the IESO launched an Expedited RFP for 1,000 MW for resources that can be in service in 2025/2026 and a Long-Term RFP for 2,200 MW for resources that can be in service by 2027/2028. Both RFPs are technology agnostic, but require the facility to provide at four to eight (or more) hours of continuous energy when required by the IESO. In Q2 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. The Long-Term RFP is expected to close in Q1 2024.
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 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 day-ahead market using market bid and offers (enhanced real-time unit commitments) that are financially binding, and (3) the implementation of an Incremental Capacity Auction for procuring longer-term electricity supply.
The IESO has been carrying out extensive stakeholder consultation regarding Market Renewal since 2016. The high-level designs for the primary Market Renewal initiatives were released in the latter part of 2018 and early 2019. The IESO has now moved into the detailed design phase. The Market Renewal initiatives, including the Incremental Capacity Auction, are expected to be implemented in 2023/2024.
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 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.
The province has also taken steps to encourage private developers to participate in the development of new large-scale transmission projects.
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.
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 electric 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. 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.
In addition, the AESO is responsible for administering the Renewable Electricity Program (REP), which procured renewable generation capacity between 2016 and 2019. For more information regarding the REP, see Section XVI.4.4.1, “Current Supply Mix”.
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 2022, Alberta’s wholesale electricity market was comprised of 250 participants and approximately C$19.9-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.
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.
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., coal and 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.
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”).
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 REP, 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, water usage and other facility permitting requirements.
In Alberta, the power 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 85% of its population. All entities eligible to trade power through the Power Pool have open access to the transmission grid.
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.
4.4 Supply mix
4.4.1 Current supply mix
As of December 31, 2022, Alberta had 18,344 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 2022 (approximately 60%) followed by renewables (31%) and coal (7%).
The largest renewable source of installed generation capacity in Alberta is wind. As of December 31, 2021, Alberta ranks third out of all Canadian provinces and territories with 43 wind installations with the capacity to generate up to 3,618 MW of electricity. Wind generation currently constitutes about 20% of Alberta’s existing generation capacity.
More solar and wind generation is expected to come online as the winning bids in the REP competition and a separate solar procurement auction complete construction of their respective projects. The aim of the REP was to procure renewable energy generation to support the transition away from coal. Broadly speaking, the REP functioned through competitive bids for government support of renewable projects by awarding 20-year contracts to eligible projects that can be developed at the lowest attribute price per MW hour. Four projects were awarded long-term supply contracts in REP Round 1 amounting to 595.6 MW of wind generation. Five projects were selected for REP Round 2. While three of these projects withdrew from the program in 2022, the remaining projects will deliver 314 MW of wind generation to the AIES. Three wind projects providing 400 MW of generation were selected for REP Round 3. The weighted average bid price for the first round of bids was C$37 per MWh, setting a record for the lowest renewable electricity pricing in Canada. A long-term contract for 94 MW of solar generation was also awarded under a separate provincial procurement auction. While the target dates for commercial operations was December 1, 2019, for the Round 1 projects and mid-2021 for the other projects, completion dates have generally been delayed due to impacts from the COVID-19 pandemic. The provincial government has indicated there will be no more procurement rounds under the REP. However, private power purchase agreements have emerged as a leading source of investment into renewable electricity generation such that the end of the REP may not ultimately slow the pace of growth of the renewable energy sector in the province.
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.
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 to determine that 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 and required BC Hydro to achieve electricity self-sufficiency by the year 2016. Currently, BC Hydro’s system generates approximately 98% of its power from clean or renewable sources. The Clean Energy Act also prohibits certain projects from proceeding, e.g., the development or proposal of energy projects in parks, protected areas, or conservancies, ensures that the benefits of the heritage assets are preserved and provides for the establishment of energy efficiency measures.
In December 2018, British Columbia released a clean energy plan (CleanBC). CleanBC sets out targets and measures to reduce the province’s reliance on fossil fuels and to increase the use of electricity across all sectors. In 2021, British Columbia released the CleanBC Roadmap to 2030, which builds on the 2018 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.
Accordingly, on June 15, 2023, the provincial government announced that BC Hydro will conduct a new call for power from IPPs, the first since 2008. The details of the call for power are being developed through an extensive engagement and consultation process, with a focus on outlining the key terms of the call, options for First Nation economic participation, and technical matters. A BC Hydro task force comprised of technical experts and representatives of First Nations has been formed to advise on the development of the program. The call for power is expected to be launched in 2024, and will prioritize projects that offer 100% clean, renewable electricity. The program will also include C$140-million to the BC Indigenous Clean Energy Initiative to support Indigenous-led projects.