The structure and ownership of the power industry varies among Canada’s ten provinces; each has its own legislature making laws governing the industry within the province, including the mandate and authority of the provincial utility regulator. Eight provinces maintain the traditional vertically integrated utility structure. In all but two of those provinces, the electric utility is a provincially owned corporation (a Crown corporation) that, for the most part, provides monopoly generation, transmission, distribution and retail supply services. Two provinces, Alberta and Ontario, have unbundled industry structures with their own unique features.
The Canadian federal government does not play a role in the structure and ownership of the power industry in Canada. The federal government has jurisdiction over the export of electricity from Canada and the construction and operation of international transmission lines and designated transmission lines that would cross provincial boundaries. Federal jurisdiction over these matters is exercised by the Canada Energy Regulator, pursuant to the Canadian Energy Regulator Act. Certain federal jurisdiction also applies to the operation and production of power at nuclear facilities.
Structure and Ownership of the Power Industry in Canada
Provinces That Have a Vertically Integrated Utility Structure
Of the eight provinces that have a vertically integrated utility structure, four have populations greater than one million people.
British Columbia’s vertically integrated utility, British Columbia Hydro and Power Authority (BC Hydro), was established as a Crown corporation by statute. BC Hydro is responsible for generating, purchasing, distributing and selling electricity throughout the majority of the province, as well as the construction and operation of the vast majority of the transmission system in the province. Public utilities in British Columbia are regulated by the British Columbia Utilities Commission (BCUC), pursuant to the Utilities Commission Act. The BCUC regulates the rates charged by electric utilities and is responsible for regulating the construction and operation of facilities by electric utilities.
SaskPower was established as a vertically integrated Saskatchewan Crown corporation, pursuant to the Power Corporation Act. SaskPower is responsible for and has the exclusive right to supply, transmit, distribute and sell electricity in Saskatchewan. Saskatchewan does not have a public utilities regulator.
Manitoba’s vertically integrated Crown corporation is Manitoba Hydro, which was established by the Manitoba Hydro Act. It is responsible for and has the exclusive right to supply, transmit, distribute and sell electricity in Manitoba. Manitoba Hydro is regulated by the Public Utilities Board, which exercises its authority pursuant to the Public Utilities Board Act.
Hydro-Québec is Québec’s vertically integrated Crown corporation, which was established by the Loi sur Hydro-Québec (Hydro-Québec Act). Hydro-Québec has a monopoly on the distribution of electricity in Québec throughout nearly all of the province. It is regulated by the Régie de l’énergie, pursuant to the Loi sur sa Régie de l’énergie (Act respecting the Régie de l’énergie).
In 1995, the Electric Utilities Act was enacted to restructure the Alberta electricity industry by unbundling the vertically integrated electric utilities into three functional units: generation, transmission and distribution. While the generation, transmission and distribution functions would remain subject to rate regulation, the policy objective of the Alberta government was to deregulate generation.
In 2001, an unregulated wholesale electricity market (the power pool) was established, where prices were and continue to be set by competitive market forces based on price and quantity bids from generators to the power pool and the demand for electricity purchased by load customers from the power pool.
In 2018, the Electric Utilities Act was amended to provide for the establishment and operation of a capacity market in Alberta within the existing wholesale electricity market. The capacity market was never implemented in Alberta as the legislative changes to implement the capacity market were repealed on 30 October 2019, following a review by the Alberta Department of Energy. Consequently, the power pool continues to operate as an energy-only market.
Except for a limited number of municipalities that own generating facilities and transmission facilities, all such facilities in Alberta are investor-owned. Similarly, except for distribution systems owned by municipalities within their boundaries and by rural electrification associations (co-operatives) within their service areas, all distribution systems in Alberta are investor-owned.
The Alberta Utilities Commission (AUC) is the public utilities regulator in Alberta. It regulates the power industry pursuant to its authority under the Electric Utilities Act, the Hydro and Electric Act and the Public Utilities Act.
Ontario’s electricity sector was formerly vertically integrated with virtually all generation and transmission owned and operated by provincially owned Ontario Hydro, and distribution owned and operated by Ontario Hydro as well as more than 300 municipal utilities. In 1999-2002, the Ontario electricity sector was competitively restructured. Ontario Hydro was broken up into Ontario Power Generation (OPG), which continued to own and operate most of the Ontario Hydro’s generation assets; Hydro One Networks Inc (HONI), which continued to own and operate Ontario Hydro’s transmission assets; and the Independent Market Operator, since renamed the Independent Electricity System Operator (IESO), which was mandated by the then-newly enacted Electricity Act, 1998, to manage the reliability of the provincial transmission grid, administer Ontario’s wholesale electricity market and undertake electricity system planning.
Restructuring also resulted in a consolidation of the more than 300 distribution utilities. Today there are fewer than 70, some of which are investor-owned and some of which remain municipally owned; government policy continues to encourage further consolidation.
Transmission and distribution utilities are rate-regulated by the Ontario Energy Board (OEB) under the Ontario Energy Board Act (OEB Act). The OEB also regulates construction of transmission and distribution infrastructure. Several years ago, the Ontario government took steps to privatise HONI; today, the government owns less than 50% of HONI. There have also been recent initiatives to introduce new entrants and competition into the transmission sector.
There has been significant government intervention in the electricity sector since market opening in 2002, including various price freezes and other forms of price regulation; this effectively undermined any merchant generation market. Almost all new generation since 2002 has, as a result, been procured by the IESO (and its predecessor, the Ontario Power Authority) pursuant to government directives.
When the market was restructured, it was intended that OPG, which owned the majority of generation in the province, would further divest its generation assets; in the interim, OPG was subject to a market power mitigation framework. This planned OPG divestiture did not transpire and today most OPG generation is rate-regulated by the OEB.
There are approximately 129 generating units in Alberta. The principal investor-owned power generation entities are TransAlta Corporation, Heartland Generation and Capital Power. ENMAX (wholly-owned by The City of Calgary) owns power generation facilities both in and outside Calgary. The City of Medicine Hat owns and operates a power plant within its boundaries.
There are three investor-owned transmission companies, AltaLink and ATCO Electric, Alberta PowerLine, that own the bulk of the transmission facilities in Alberta. Transmission facilities are also owned by ENMAX, EPCOR (wholly-owned by the City of Edmonton) and the City of Medicine Hat. Montana Alberta Tie owns and operates a merchant intertie that enables the import and export of electricity between Alberta and Montana, USA.
There are two investor-owned distribution companies that serve most of Alberta outside the larger Alberta municipalities, FortisAlberta and ATCO Electric. The municipalities of Edmonton (through EPCOR), Red Deer, Calgary (through ENMAX), Medicine Hat and Lethbridge own and operate their own distribution systems.
Approximately 80% of the generation capacity in British Columbia is owned by BC Hydro and Columbia Power Corporation, also a Crown corporation. The remaining 20% is owned by private investors, including independent power producers that either consume electricity on site for industrial operations or, as required, sell it to BC Hydro. Approximately 92% of the transmission assets and approximately 93% of the distribution assets in British Columbia are owned by BC Hydro. FortisBC, an investor-owned corporation, owns the approximate 8% of remaining transmission assets and 4% of the distribution assets in the province. The remaining distribution assets are owned by municipalities.
The transmission, distribution and retail segments of the power industry in Saskatchewan, as well as almost all generation, are owned by SaskPower. Approximately 20% of installed generation is privately owned. Each of these projects sells electricity to SaskPower under long-term agreements.
Virtually all generation in Manitoba and the entirety of the transmission, distribution and supply segments are owned by Manitoba Hydro. There are two privately held wind power projects that sell electricity under long-term agreements to Manitoba Hydro.
The former generation arm of Ontario Hydro, OPG, continues to own a majority of provincial generation capacity (principally nuclear and hydro generation). OPG is owned by the province. The balance of provincial generation is owned by a mix of investor-owned companies.
Approximately 98% of provincial transmission assets are owned by HONI, which until several years ago was owned by the province. The province now owns a minority stake in HONI. There have been some recent initiatives aimed at introducing new entrants and competition in the transmission sector.
Distribution facilities are owned by HONI (mainly rural distribution networks) and over 60 local distribution companies, some of which are investor-owned and some of which remain municipally owned.
Most electricity end-use consumers are served by local distribution utilities. Competitive electricity retailers serve some commercial and residential end-use consumers; however, government legislation and regulations have largely driven competitive retailers out of the low-volume residential market.
More than 90% of electricity production and nearly all transmission and distribution facilities are owned and operated by Hydro-Québec. The remaining facilities are owned by the private sector, nine small municipalities and co-operatives. Of all electricity produced in Québec, approximately 99% is from renewable sources. Hydro-Québec operates three main divisions: Hydro-Québec Production generates electricity, TransÉnergie transmits electricity in the province and for export, and Hydro-Québec Distribution distributes and sells electricity to consumers in the province. With an installed capacity of approximately 36.9 GW, Hydro-Québec is one of the world’s largest producers of clean energy.
Investment Canada Act
Foreign investment in Canada’s power industry (and most other industries) is subject to the federally regulated provisions of the Investment Canada Act (ICA), enacted by the federal government of Canada. Under the ICA, subject to certain exemptions, every acquisition of control by a non-Canadian of a Canadian business, even where the business is already controlled by a foreign investor, requires either a notification or detailed review under the ICA to ensure it is likely to be of "net benefit" to Canada.
A notification involves the filing of a form with prescribed information and is typically an administrative formality; it can be filed at any time up to 30 days after implementation of the investment. A review, on the other hand, is typically a pre-closing process that requires positive approval by Canada’s Minister of Innovation, Science and Economic Development (the Minister) before proceeding.
Thresholds for Review
Whether a transaction is subject to notification or to pre-closing review depends upon whether certain enterprise value or asset thresholds are satisfied. These thresholds generally depend on a number of factors, the most relevant of which to the power industry are as follows.
Indirect transactions in which the purchaser acquires the voting shares of a non-Canadian corporation that controls a Canadian business are generally exempt from a pre-closing review.
Identity of purchaser or vendor
Where the purchaser or vendor is ultimately controlled by nationals of a WTO member country, and the purchaser is not a state-owned enterprise, a pre-closing review is only triggered where the Canadian business has an enterprise value of CAD1 billion. That threshold rises to CAD1.5 billion where the purchaser or vendor is ultimately controlled by nationals of a "trade agreement" country, which includes the USA and EU countries.
Involvement of state-owned enterprises
If the purchaser is a "state-owned enterprise", broadly defined to include entities that are influenced directly or indirectly by a foreign government, a pre-closing review is required where the Canadian business has a book value of assets of CAD398 million.
Where a transaction is reviewable, the purchaser must file an application for review prior to implementing the investment and the parties are prohibited from implementing the investment until the Minister confirms that he or she is satisfied or is deemed to be satisfied that the investment is likely to be of "net benefit to Canada". This decision is based on certain factors set out in the ICA and in view of any legally binding undertakings the purchaser is willing to make, which are typically required.
Information in an ICA application for review includes benchmark data about the Canadian business, such as historical, current and forecast revenues, employment levels and capital expenditures, as well as information about the citizenship of existing officers and directors. The purchaser is required to describe its future plans for the Canadian business with reference to these benchmarks.
Once the purchaser has filed a complete application for review, the Minister has a 45-day period within which to make a "net benefit" determination, which may be (and often is) unilaterally extended by the Minister for an additional 30 days and may be extended further with the consent of the purchaser. During this time, counsel to the purchaser will typically answer questions from the Investment Review Division and engage in negotiations over the legally binding undertakings that the purchaser is willing to accept with respect to its plans for the Canadian business. Such undertakings often include committing to maintain a Canadian head office and specified minimum levels of Canadian senior management, capital expenditures, employment levels and various other matters.
National Security Reviews
Irrespective of the value of an investment, the acquisition of control of a Canadian business or investment to establish a new Canadian business may be subjected to a national security review under the ICA. Purchasers that receive notice of a potential or actual national security review are prohibited from implementing a proposed investment pending the outcome of the review.
Where the Minister, after consultation with the Minister of Public Safety and Emergency Preparedness, is satisfied that the investment would be "injurious to national security", the Governor-in-Council may "take any measures it considers advisable" to protect national security, including prohibiting implementation of the investment or requiring written undertakings from the purchaser.
The government has issued guidelines containing a non-exhaustive list of factors that will be considered in determining whether an investment would be injurious to national security. They include the potential impact of the investment on the security of Canada’s critical infrastructure, the supply of critical goods and services to Canadians, and the potential of the investment to enable foreign surveillance or espionage.
Depending on applicable legislation in provinces that have a vertically integrated structure, utilities may require the approval of their regulator or the provincial government in order to dispose of utility assets outside the ordinary course of business or to enter into specified transactions.
The sale of generation assets requires approval of the AUC pursuant to the Hydro and Electric Energy Act. The owners of larger-scale transmission and distribution system assets in Alberta have been designated by regulation as an "owner of a public utility" under the Public Utilities Act, which, among other matters and subject to certain conditions, prohibits the issuance of shares or debt, the sale of assets outside the ordinary course of business and a change in control, unless prior approval of the AUC is obtained.
For dispositions involving a change in control of a transmission or distribution utility or the sale of assets outside the normal course of business, the AUC conducts a public interest assessment and applies a "no harm" test under which it considers, among other matters, the industry experience and financial metrics of the proposed purchaser to ensure the continued safe and adequate service to customers at just and reasonable rates. The sale of transmission and distribution businesses in Alberta is not common. When such sales have occurred, the AUC has conducted a hearing process before issuing necessary approvals. If a transaction involves an asset sale rather than a sale of shares, the AUC’s approval under the Hydro and Electric Energy Act would also be required.
The OEB has authority to review and approve the sale or lease of transmission or distribution assets, or a change in control of licensed transmission and distribution companies. All amalgamations by transmitters or distributors are reviewable pursuant to provisions of the OEB Act; these provisions are referred to as the MAAD (mergers, acquisitions, amalgamations and divestitures) provisions. In reviewing MAAD applications, the OEB applies a "no harm" test, which requires the applicant to show that ratepayers will not be worse off as a result of the transaction.
Generators are also required to notify the OEB before purchasing any interest in transmission or distribution facilities; likewise, transmitters and distributors are required to notify the OEB of any proposed acquisition of generation facilities. The OEB has the discretion to undertake a review of such transactions.
In the provinces that have a vertically integrated utility structure, overall planning of the electric system regarding reliability and sufficiency of supply may be managed by or among the utility, its regulator, or the provincial government.
The Electric Utilities Act established the independent system operator, which operates as the Alberta Electric System Operator (AESO). The AESO has numerous statutory responsibilities to, among others, assess the current and future needs of market participants and plan the capability of the transmission system to meet those needs, and make arrangements for the expansion of and enhancement to the transmission system. Every second year the AESO produces a Long-term Transmission Plan (LTP) for the entire province, which identifies the timing and location of current and future transmission needs over a 20-year period. The AESO also produces a Long-term Outlook every two years that forecasts electricity demand and generation in the province, looking forward 20 years, which helps inform the LTP.
The AESO has no authority to plan for the development of generation to meet the forecast electricity needs of Alberta. The development or retirement of generation facilities is intended to be driven by economics through price signals from Alberta’s competitive wholesale electricity market. However, the AESO is responsible for administering the (since-discontinued) Renewable Electricity Program under which the AESO conducted competitive procurement auctions for renewable generation in accordance with the Alberta government's previous policy direction, and pursuant to the Renewable Electricity Act.
Although the AESO does not own any transmission or distribution facilities in Alberta, it is responsible for directing the safe, reliable and economic operation of Alberta’s interconnected electric system (transmission, distribution and generation) (AIES). To that end, the AESO is also responsible for making technical rules regarding the operation of the AIES and for establishing and monitoring compliance with Alberta’s reliability standards. The AESO also co-ordinates reliability with electrically interconnected jurisdictions in Canada and the USA.
The AESO is also responsible for providing "system access service" to the transmission system through the use of the facilities owned by the transmission utilities.
The IESO and provincial government, along with input from local distribution utilities, are responsible for bulk and regional electricity system planning. The IESO and government regularly issue a long-term energy plan (LTEP), which identifies provincial bulk system needs; and regional plans, which identify regional system needs. Generation needs identified in the LTEP or regional plans have to date been addressed through government-directed procurements, including a number of major renewable procurements like Ontario’s former feed-in tariff (FIT) programme. Going forward, the province and IESO intend that more generation be procured through market solutions.
Transmission and distribution needs identified in the LTEP and regional plans are addressed by transmission and distribution utilities that must apply to the OEB, with support of the IESO, to construct new transmission and distribution facilities, and include the costs of such facilities in their rate base.
In 2015, Alberta’s provincial government announced its Climate Leadership Plan (CLP), under which it established as policy the phase-out of coal-fired generation by 2030 and set a target of at least 30% of Alberta’s electricity coming from renewable sources by 2030. In order to respond to the transition off coal and the integration of more renewable and natural gas generation, the provincial government decided to establish a capacity market.
The Renewable Electricity Act, which is a product of the CLP, came into force in March 2017 and prescribed the 30% by 2030 target and, to that end, established the renewable electricity program (REP) for the competitive procurement of renewable electricity by the AESO. The REP involves a series of competitive procurement auctions for the right to construct and operate projects, with a target of up to 5,000 MW of renewable electricity by 2030. While the Renewable Electricity Act is still in force, the Minister of Energy announced in June 2019 that it would not proceed with any additional rounds of procurement under the Renewable Electricity Program.
In June 2017, the provincial government enacted An Act to Cap Regulated Electricity Rates, which caps electricity rates payable by consumers for energy costs on regulated electricity service at 6.8 cents/kWh. The change leaves electricity retailers unaffected, as any amounts in excess of the price cap are paid by the provincial government.
On 1 August 2018, the provincial government passed An Act to Secure Alberta’s Electricity Future, which provided for amendments to the Electric Utilities Act and, among other matters, the establishment and operation by the AESO of a capacity market in Alberta. A hearing before the AUC for the provisional rules application was completed in June 2019. However, after review by the Alberta Department of Energy, the legislation enabling the establishment of the capacity market was repealed on 30 October 2019 with the passage of the Electricity Statutes (Capacity Market Termination) Amendment Act, 2019.
The IESO is currently undertaking a Market Renewal Program that is aimed at transitioning Ontario from government-directed supply procurement to market solutions, including the development of an Ontario capacity market. The Market Renewal Program seeks to enhance the efficiency of Ontario electricity markets by:
While the Market Renewal Program previously included plans to implement an incremental capacity auction to efficiently secure capacity to meet Ontario’s future resource adequacy needs, the IESO suspended the further development of an incremental capacity auction in June 2019 and replaced it with a more modest expansion of the IESO’s existing demand response auction, which will allow generation resources to participate. However, in April 2020, due to the impacts of COVID-19 including the reduction in forecast demand, the IESO suspended the capacity auction that was planned for June 2020 and all further efforts to evolve the capacity auction. The IESO is in the process of formulating the necessary market rule changes to implement its Market Renewal initiative over the next two to three years.
On 21 June, 2018 the federal government enacted the Greenhouse Gas Pollution Pricing Act (GGPPA), a Canada-wide carbon emissions pricing scheme, for provinces without a carbon emissions pricing system. Currently, this scheme will apply in Ontario, Manitoba, Prince Edward Island (for large emitters only), Saskatchewan, Yukon and Nunavut. The federal carbon emission pricing system consists of two distinct components:
Generally, an entity registered under the output-based system is exempted from the carbon levy.
In response to announced and expected solicitations by states in the north-eastern USA for the delivery of incremental "clean energy", there may be significant opportunities in Canada to develop major transmission infrastructure to deliver electricity from Canadian hydro and wind sources in response to requests for proposals.
At the time of writing, the impacts of COVID-19 on the production, transmission and distribution of electricity in Canada are still unfolding. Currently, construction of new electricity generation and transmission facilities has been impacted by the states of public health emergency declared by provincial governments and the resulting temporary closure of non-essential businesses across Canada and workplace reorganisation. Business closures due to COVID-19 which have resulted in reductions in electricity consumption are also starting to have ripple effects.
In the Province of British Columbia, BC Hydro has sent curtailment notices to independent power producers invoking force majeure. Demand risk is generally allocated to the power purchaser under PPAs and force majeure usually does not cover reduced demand. In Ontario, COVID-19 is impacting patterns of electricity use and has reduced the overall amount of electricity demand in the province. As noted above, due to the decline in the demand for electricity, the IESO has suspended its first capacity auction which was scheduled to take place in June 2020 and has suspended all work on further efforts to evolve the capacity auction.
Furthermore, the IESO has also advised stakeholders that if demand remains low as a result of COVID-19, there is the potential for nuclear unit shutdowns to manage the surplus baseload generation conditions.
Only Alberta and Ontario have established wholesale markets through which electricity is exchanged and the wholesale price of electricity is set by competition. The other provinces have vertically integrated utilities, and the prices (ie, rates) paid by consumers for delivered electricity reflect the bundled costs of generation, transmission and distribution approved by the provincial regulator. In provinces that provide for the purchase of electricity by the utility from independent power producers (IPPs), the approved cost of electricity purchased from IPPs is included in consumer electricity rates.
The AESO operates and administers the power pool in accordance with the Electric Utilities Act. The Alberta power pool currently operates as an hourly auction, where all generators (above 5 MW) must offer all of their power into the market and must comply with the AESO’s dispatch instructions. Generators are dispatched in order of ascending price offers to meet demand in real time, with the marginal dispatched generator setting the system marginal price every minute.
All generators are paid the "pool price" for their delivered volume of energy, which is the weighted average of the system marginal price for an hour. Prices are set province-wide and there is no locational or nodal pricing in Alberta.
The wholesale electricity market, administered by the IESO, includes an hourly spot market. Initially when the Ontario market was launched in 2002, wholesale prices were to be uniform across the province, with the eventual transition to locational marginal pricing. Subsequent amendments to the Electricity Act effectively replaced Ontario’s short-lived wholesale market with a "hybrid market", whereby new generation was developed through government-directed procurements.
Generation continues to be scheduled and dispatched through the IESO spot market; however, generators are paid for their output pursuant to long-term power purchase agreements (PPAs). Generators thereby receive both IESO market settlements and out-of-market top-up payments for the difference between what they earn in market revenues and what they are owed pursuant to their PPAs. Likewise, the province’s dominant generator, OPG, receives market settlements from the IESO as well as top-up payments to reflect the difference between what OPG earns in market revenues and what it is owed pursuant to generation rates set by the OEB.
These out-of-market adjustment payments that are made to Ontario generators and other suppliers are referred to as the "Global Adjustment". The commodity price of electricity in Ontario is therefore composed of hourly wholesale market spot price, the Global Adjustment and other uplift charges; eg, costs for ancillary services, administrative price charges, etc. Notably, an important feature of Ontario’s current Market Renewal Program will be the long-awaited transition to a single schedule market and locational marginal pricing; this is expected to be implemented by 2022 or 2023.
The Electricity Act and the Ontario Energy Board Act require that residential small business consumers pay the true cost of power over time; however, the legislation also mandates a regulated price plan (RPP) to reduce residential and small business consumers’ exposure to price volatility. Under the RPP, residential and small consumer rates are reset biannually.
The export of electricity from Canada is regulated by the Canada Energy Regulator through the issuance of blanket electricity export permits issued pursuant to the Canadian Energy Regulator Act. There are no federal permits required for electricity imports.
Imports and exports between Canadian provinces are permitted, subject to market rules and tariff terms and conditions applicable in the importing and exporting provinces.
IESO market rules provide for inter-jurisdictional energy trade. Ontario published updated market rules to enable the export of capacity, which have been in effect since December 2018.
At present, market participants that wish to export electricity from Ontario to other jurisdictions must successfully bid into the IESO spot market and correspondingly offer into neighbouring markets (the same goes for imports). Ontario does not allow market participants to purchase firm physical transmission rights and therefore exports/imports can be curtailed due to internal transmission congestion or congestion on the "interties" connecting Ontario and neighbouring jurisdictions. Market participants may, however, purchase financial transmission rights in the IESO transmission rights market as a hedge against transmission congestion on the interties.
Hydro-Québec operates 15 existing interconnections with the Province of Ontario, the Province of New Brunswick, the State of New York and New England. Three additional interconnections with north-eastern states are currently under study, including the 1,000MW Champlain Hudson Power Express project to serve the clean electricity needs of New York City and the1,200 MW New England Clean Energy Connect Project linking Quebec to Massachusetts via Maine and New Hampshire .
Canadian Electricity Supply Mix 1
Jurisdiction – Canada total
Total 2019 generation (TWh) (1) – 650.7.
Jurisdiction – Alberta
Total 2019 generation (TWh) (1) – 82.8.
Jurisdiction – British Columbia
Total 2019 generation (TWh) (1) – 74.9.
Jurisdiction – Manitoba
Total 2019 generation (TWh) (1) – 36.9.
Jurisdiction – Saskatchewan
Total 2019 generation (TWh) (1) – 24.2.
Jurisdiction – Ontario
Total 2019 generation (TWh) (1) – 150.5.
Jurisdiction – Québec
Total 2019 generation (TWh) (1) – 214.8.
Jurisdiction – New Brunswick
Total 2019 generation (TWh) (1) – 12.2.
Jurisdiction – Newfoundland and Labrador
Total 2019 generation (TWh) (1) – 42.8.
Jurisdiction – Nova Scotia
Total 2019 generation (TWh) (1) – 9.6.
Jurisdiction – Prince Edward Island
Total 2019 generation (TWh) (1) – 0.6.
Federal competition law is governed by the Competition Act. Transactions that involve a "merger" may be subject to review by and/or may require certain clearances from the Commissioner of Competition (Commissioner). The Competition Act defines "merger" very broadly: “... the acquisition or establishment, direct or indirect, by one or more persons, whether by purchase or lease of shares or assets, by amalgamation or by combination or otherwise, of control over or significant interest in the whole or a part of a business of a competitor, supplier, customer or other person”. The substantive test applied by the Commissioner in deciding if a merger will ultimately be challenged following a review is whether it “would or would be likely to prevent or lessen competition substantially” in a relevant market.
Certain large transactions, measured primarily based on transaction-size and party-size thresholds being exceeded, trigger mandatory pre-merger notification filings with the Commissioner and such transactions cannot close until a statutory waiting period has expired and/or the Commissioner’s review has been completed. The Competition Act provides a process to obtain an advance ruling certificate or similar comfort from the Commissioner that he or she will not challenge the proposed transaction, which, among other things, allows parties to complete their transaction with substantive comfort that a post-closing challenge is unlikely and in some cases exempts the transaction from the formal pre-merger notification filing requirement.
In Alberta, "offer control" is capped. Offer control means the ultimate control and determination by a market participant of the "price–quantity" offers made to the power pool in respect of the maximum capability of one or more generating units. Offer control is set by regulation at a maximum of 30% of the sum of the maximum capability of generating units in Alberta and is determined by the Market Surveillance Administrator (MSA) at least annually.
As part of deregulation of the Ontario electricity sector and the opening of the market in 2002, the province mandated that Ontario’s dominant generator, OPG (the former generation arm of Ontario Hydro), be required to further divest its generation assets. In the interim, OPG was subject to a market power mitigation framework under which OPG was required to rebate to ratepayers revenues in excess of a weighted average spot market price. As a result of ensuing policy and regulatory changes, OPG did not end up divesting its generation portfolio.
Consequently, in 2006, most OPG generation (nuclear and hydro) was made subject to OEB cost of service rate regulation. Moreover, the plan for OPG to divest itself of generation assets and reduce its market share has not transpired. While for some time, OPG was precluded from participating in certain new generation procurement and development programs, these restrictions have waned.
Notably, in early Q2 2020, OPG closed a CAD2.8 billion acquisition of interests from TC Energy of interests in three Ontario natural gas-fired power plants (ie, 683 MW Halton Hills generating Station, 900 MW Napanee generating Station and TC Energy’s interest in the 550 MW Portland Energy Centre).
At the federal level, the Competition Bureau of Canada is the agency responsible for the surveillance of anti-competitive behaviour and the enforcement antitrust legislation in Canada.
The MSA, established by the Alberta Utilities Commission Act, has responsibility to carry out surveillance in respect of the supply, generation, transmission, distribution, trade, exchange, purchase or sale of electricity in Alberta. The MSA has authority to investigate:
The MSA has the authority to enter and inspect premises, make inquiries of employees and former employees, demand the production of records, temporarily remove documents and make copies, and request access to computer systems to obtain records from data. The MSA has the authority to refer non-compliance matters to the AUC for consideration and potential enforcement measures.
There are two agencies that monitor anti-competitive behaviour and undertake enforcement activity:
The MSP monitors, investigates and reports on IESO market design and structural issues, and on activities and behaviour of market participants, which may include market manipulation and gaming. The MSP records its findings and recommendations in semi-annual reports published by the OEB. The MSP’s recommendations often include broad proposals for remedying market design flaws and inefficiencies, and curbing inappropriate or anomalous behaviour. The MSP has broad investigatory powers, which include the power to issue subpoenas for document production, compel testimony and undertake searches and seizures; however, the MSP does not have any enforcement authority.
MACD monitors the operation of the market and compliance with applicable market rules and reliability standards. MACD does this through prevention, monitoring, auditing, investigation and enforcement activities. In addition to monitoring and enforcing compliance with the market rules and reliability standards, MACD enforces compliance with the IESO’s general conduct rule that proscribes conduct aimed at undermining, manipulating, interfering with or exploiting the market. MACD’s enforcement authority includes the authority to levy substantial financial penalties.
In May 2019, Alberta repealed its Climate Leadership Act, which had enacted portions of its Climate Leadership Plan, including carbon emissions pricing regime using a CAD20/tonne levy in 2017, and a CAD30/tonne levy in 2018 for various types of fuels, stricter emissions intensity reduction targets for large facilities and a renewable electricity target of 30% by 2030. Most large emitters were exempted from this carbon levy while it was in force due to registration, reporting, remittance and emissions reduction obligations under the Carbon Competitiveness Incentive Regulation (now the Technology Innovation and Emissions Reduction Regulation), made under the recently amended Emissions Management and Climate Resilience Act.
The Technology Innovation and Emissions Reduction Regulation requires facilities emitting more than 100,000 tonnes of carbon dioxide equivalent per year (or facilities that opt in so they may apply for a carbon levy exemption) to meet specific emissions intensity benchmarks. Most benchmarks are based on industry-wide standards set by regulation, or facility-specific standards based on an existing facility’s baseline emissions in prior years. Where emissions for a facility exceed the benchmark, the facility must reduce its net emissions by applying emissions offsets, emissions performance credits or fund credits against its actual emissions level.
The purchase and use of fund credits to meet emissions targets is unlimited; however, the use of other credits is capped each year, such that a facility may address only a portion of its excess emissions through performance credits and emissions offsets, which expire dependent on their vintage.
In 2008, British Columbia enacted the Carbon Tax Act, which applied a broad-based carbon tax. As of 1 April 2019, the carbon tax rate is CAD40/tonne of carbon dioxide equivalent, increasing by CAD5/tonne per year until it reaches CAD50/tonne in 2021. For large emitters, British Columbia enacted the Greenhouse Gas Industrial Reporting and Control Act in 2016, establishing performance standards across different industrial sectors, and establishing mechanisms for emissions offsets through the purchase of credits or through emission offsetting projects. The Greenhouse Gas Emission Reporting Regulation, requires facilities emitting more than 10,000 tonnes of carbon dioxide equivalent per year to report their emissions.
In 2010, British Columbia enacted the Clean Energy Act, which established a mandate for BC Hydro to pursue the province’s energy objectives of energy self-sufficiency, demand-side management and conservation measures to reduce electricity consumption by 66% and generate at least 93% of electricity in British Columbia from clean or renewable resources, among other targets. The province has also set targets to achieve emissions reductions of up to 80% below 2007 levels by 2050 under the Climate Change Accountability Act.
The Management and Reduction of Greenhouse Gases Act and associated regulations in Saskatchewan were passed in 2010, with portions of the Act coming into force on 1 January 2018. The Act provides for the provincial government to set greenhouse gas emission baselines, and annual reduction targets for emitters producing in excess of 1,500,000 tonnes of carbon dioxide equivalent per year.
On 8 November 2018, Manitoba introduced the Climate and Green Plan Act (CGPA), which replaced and repealed the Climate Change and Emissions Reductions Act and the Sustainable Development Act. The CGPA mandates the minister to establish a greenhouse gas emissions reduction goal for Manitoba, every five years – beginning after the first year that the act has been in force. If a greenhouse gas emissions reduction goal has not been achieved in a given five-year period, the amount of the emissions reduction shortfall is to be added to the emissions reduction goal in the next five-year period.
On 31 October 2018, Ontario passed the Cap and Trade Cancellation Act, 2018 (CTCA), which discontinued the provincial cap-and-trade carbon tax system implemented by the former Liberal government. Compensation was awarded to the 27 participants of the former programme in the total amount of CAD5.09 million. As of 1 April 2019, Ontarians are subject to the federal carbon tax, which is discussed in 1.7 Announcements Regarding New Policies.
On 29 November 2018, in "A Made-in-Ontario Environmental Plan", the province reaffirmed its commitment to reduce its greenhouse gas emissions by 30% below 2005 levels by 2030. This is in line with Canada’s 2030 greenhouse gas reduction targets under the Paris Agreement.
In 2013, Québec adopted a cap-and-trade system for greenhouse gas emissions allowances. The system is currently linked with California’s cap-and-trade system but the US Federal government in the Fall of 2019 challenged California’s right to agree to such a linkage and the matter is before the courts. Hydro-Québec PPAs provide that "green credits", if any, are for the benefit of Hydro-Québec.
Effective as of 1 April 2020, New Brunswick has enacted a provincial carbon tax to replace the federal government’s backstop carbon pricing system. The new carbon tax was introduced by way of amendments to the Gasoline and Motive Fuel Tax Act.
On 1 January 2019,Nova Scotia implemented a cap-and-trade program to help reduce the greenhouse gas emissions in the province. The new program was enacted through amendments to the Environment Act and the adoption of the Cap-and-Trade Program Regulations.
The government of Canada has enacted regulations limiting the intensity of emissions from new and old coal-fired generation projects to 420 tonnes per gigawatt hour per year. Coal-fired generation plants must meet these emissions standards or retire at the end of their useful life, currently set by regulation at 50 years.
The provincial government, as part of its Climate Leadership Plan, entered into off-coal agreements with the owners of all six coal-fired power plants in Alberta with anticipated service lives beyond 2030 to cease operations by 2030 in exchange for approximately CAD1.3 billion in total compensation. Under the agreements, the provincial government has agreed to make annual payments to the owners until 2030 to cover the expected remaining undepreciated value of the generation assets beyond 2030, in exchange for commitments to reinvest certain amounts in the electric industry in Alberta, as well as the maintenance of a significant business presence in Alberta.
British Columbia’s Clean Energy Act restricts the operation and use of thermal generation by BC Hydro, except for cases of emergency or for transmission support services.
Pursuant to the Cessation of Coal Use Regulation (2007), Ontario mandated the retirement of all coal-based generation facilities, or to convert them to cleaner-burning fuels by 2015, and, in accordance with the Regulation, Ontario phased out its last remaining coal-fired generation facility in 2014. Ontario has since enacted the Ending Coal For Cleaner Air Act, which stipulates that coal cannot be used in the future to generate electricity in Ontario.
As previously referenced, the provincial government established the Renewable Electricity Program, pursuant to the Renewable Electricity Act, in an effort to achieve its target of obtaining at least 30% of electricity production from renewable sources by 2030 (being approximately 5,000 MW).
The first REP procurement competition was completed in December 2017, with the AESO procuring 595.6 MW of renewables from four proponents at a weighted average price of CAD37/MWh and with a target in-service date in December 2019. Two further REP rounds were completed in December 2018 with the AESO procuring 363 MW and 400MW of renewables at weighted average prices of CAD38.69/MWh and CAD40.14/MWh, respectively. Round 2 of the REP included a requirement that a project have a 25% threshold level of equity participation by indigenous communities. A fourth REP round was announced in February 2019, but later cancelled in June 2019. No further procurement competitions are scheduled at this time.
The payment mechanism for the first round of REP was based on an Indexed Renewable Electricity Credit (IREC) set out in a 20-year Renewable Energy Support Agreement (RESA) between the AESO and each successful bidder. The amount of support paid for the renewable project will be determined based on the difference between the bid price (strike price) and the pool price. The IREC paid is automatically adjusted so that when the pool price is below the bidder’s strike, the bidder will be paid the difference between those values, and when the pool price rises above the strike price, the bidder will be required to pay the AESO the amount above the strike price. As outlined in the Renewable Electricity Act, the government will provide funding for the cost of each RESA to the AESO on a monthly basis, for payment to the generators that are counterparties to a RESA.
Renewable generation projects are also eligible for emissions performance credits under the Technology Innovation and Emissions Reduction Regulation, which can be consumed to offset emissions costs from other operations, or sold in the marketplace to other regulated emitters.
Pursuant to the Clean Energy Act, BC Hydro is obligated to develop and file with the provincial government an integrated resource plan with a view to meeting the government’s target of 93% renewable electricity generated on an annual basis. BC Hydro also administers feed-in tariff and standing offer programmes for smaller generation projects (up to 15 MW) for fixed volumes and prices on an annual basis. However, BC Hydro announced on 14 February 2019 that it was suspending its Standing Offer and Micro Standing Offer Programs indefinitely, and would not be accepting new applications, nor awarding new electricity purchase agreements, except for five new First Nations clean energy projects announced on 14 March 2018.
SaskPower has committed to a target of 50% generation capacity from renewables by 2030, including 30% from wind power, despite no legislated requirement to do so. Included in its plans for procuring new renewables are competitive procurement processes for up to 120 MW of solar projects by 2025 and 1,600 MW of wind projects by 2030. The first competitions closed in Q4 of 2017, and awarded long-term power purchase agreements for a 10 MW solar project and a 200 MW wind project. A second round of procurement for a 10 MW solar project SaskPower began in January 2019, and a 200 MW wind project began in November 2019.
In December 2018, the Green Energy Repeal Act, 2018 (GERA) received royal assent, which, as its name suggests, repealed the Green Energy And Economy Act (GEEA). The centrepiece of the former GEEA was a feed-in tariff (FIT) programme, which provided stable, standard-offer prices for electricity generated from renewable resources, with costs borne by ratepayers. The effort to repeal the former act was made after the Province elected not to proceed with 758 wind and solar contracts on the basis that these contracts were not required and would result in higher rates.
GERA also amended the Planning Act and the Environmental Protection Act to increase the powers of the province and municipalities to reject renewable energy projects and enable the government to refuse to approve renewable energy projects where demand for the electricity that would be generated by the project has not been demonstrated to the satisfaction of the government.
The construction and operation of a federally regulated power plant, such as an offshore wind project, requires the approval of the CER pursuant to the Canadian Energy Regulator Act. Depending on the size and scope of the project, the proponent may also be required to conduct an impact assessment before the Impact Assessment Agency under the Impact Assessment Act.
The construction and operation of a power plant in Alberta requires the approval of the AUC, pursuant to the Hydro and Electric Energy Act. Before the AUC can approve the construction of a hydroelectric project, the provincial legislature must first pass a bill authorising the hydroelectric development, following which the AUC can issue the requisite approval. Generation projects having a capacity of 100 MW or greater that will use a non-gaseous fuel and hydroelectric developments having a capacity of 100 MW or greater require an environmental impact assessment to be conducted in accordance with the Environmental Protection and Enhancement Act. The use of water from a water body or the diversion of water will require an approval under the Water Act.
The construction and operation of generation facilities is governed by the Environmental Assessment Act (EAA) and the Environmental Protection Act (EPA). It may also be necessary to obtain a permit or authorisation under the Endangered Species Act, 2007.
The specific legislative and regulatory requirements for approvals to construct and operate a generation facility vary between provinces. Depending on the scale of a project, an environmental screening or an environmental assessment may be required. In some jurisdictions, the regulator may conduct public hearings or proceedings to consider applications before issuing approvals.
The construction and operation of a federally regulated power plant, such as an offshore wind project, requires the approval of the CER pursuant to the Canadian Energy Regulator Act. The Act prescribes a time limit of 300 days to render a decision from the time the CER determines the application is complete. The CER considers a number of factors in determining whether to approve an application, including the environmental effects and cumulative environmental effects of the project; safety and security considerations; the health, social and economic effects of the project; the rights, interests and concerns of the Indigenous peoples of Canada; and the effects of the project that hinder or contribute to the federal government’s ability to meet its environmental obligations and its commitments in respect of climate change.
The construction and operation of a power plant in Alberta requires the approval of the AUC, pursuant to the Hydro and Electric Energy Act. The AUC must have regard to the social, economic and environmental effects of a project to determine whether it is in the public interest. Because Alberta’s wholesale electricity market is intended to send price signals for generation development and retirements, the AUC must not consider the economics of a project and whether the electricity to be produced by a generator is needed in Alberta. Larger-scale generation projects that are opposed by affected parties may be subjected to a public hearing process. The AUC endeavours to issue a decision within three months of concluding the process.
Non-renewable generation facilities must undertake an environmental assessment under the EAA and Ontario Regulation 116/01: Electricity Projects. Depending on the type and size of the facility, it may be necessary to undertake a full environmental assessment under the EAA or a more limited environmental screening report. In addition to completing an environmental assessment, it will be necessary to obtain specific environmental compliance approvals under the EPA. For example, a gas-fired generation facility will require an environmental compliance approval for air and noise emissions.
To construct and operate a renewable generation facility, a proponent must obtain a renewable energy approval under the EPA. The renewable energy approval regime is intended as a "one-window" approach that eliminates the need to undertake an environmental assessment and obtain separate environmental compliance approvals.
Regulators and governmental agencies generally have the authority to impose conditions in approvals that are intended to reasonably mitigate potential adverse effects on the environment, including air, water, land, wildlife and aquatic life; and the potential effects on people, including land use and disturbance, socioeconomic impacts, visual, noise, safety and use of the environment. Related to mitigation of adverse effects, regulators and agencies normally have the authority to prescribe conditions pertaining to construction methods, equipment to be used, reclamation and maintenance. Proponents are also required to comply with all applicable laws and technical codes and standards.
In some provinces where the use of public land (Crown land) is needed, land use authorisations may be obtained from the provincial government. Where a generating facility is proposed to be built on private land, the proponent may negotiate a lease or land purchase with the landowner. In some provinces, the legislation enables a proponent to expropriate land.
The forced taking of land typically carries with it the obligation of the proponent to compensate the landowner based on the fair market value of the land and potentially other factors.
Applicable environmental laws and regulatory policy in each province govern the requirements for decommissioning power plants. For example, in Alberta an approval from the AUC is required to discontinue operations of a power plant. Pursuant to the Environmental Protection and Enhancement Act, a remediation certificate must be obtained from Alberta Environment and Parks (AEP) to abandon, remediate and reclaim the site of a power plant. AEP may also require applicants for remediation certificates to provide financial or other security or insurance in respect of the remediation certificate.
The terms and conditions of approvals or other orders from AEP frequently identify methods or parameters for carrying out remediation activities. There are no specific obligations in Alberta to fund decommissioning or reclamation activities over the physical life of the power plant.
The construction and operation of international transmission lines and designated transmission lines that will cross provincial boundaries, dependent on their size and scope, require approval by the CER under the Canadian Energy Regulator Act. Federally regulated power lines may also require an impact assessment by the Impact Assessment Agency of Canada pursuant to the Impact Assessment Act.
The Hydro and Electric Energy Act governs the construction and operation of transmission lines and associated facilities.
The construction and operation of transmission lines are governed by the OEB Act. Under the OEB Act, transmission lines are defined as power lines operating at above 50 kV. The Environmental Assessment Act governs the environmental assessment process required for power lines that are 115 kV or higher and more than 2 km in length.
The CER Act requires federally regulated power lines to be issued a Permit, or, in the case of a “designated project:, a Certificate issued by the CER and the approval of the Governor in Council. Transmission lines that have a voltage equal to or greater than 345 kV or require 75 or more kilometres of right of way are considered a "designated project" under the Impact Assessment Act and the Physical Activities Regulations, and will require an environmental assessment.
Provinces That Have a Vertically Integrated Utility Structure
The legislative and regulatory requirements to construct and operate provincial transmission facilities vary between provinces. Approvals may be required from the provincial electric utility regulator, along with approvals from the applicable environmental ministry. Depending on the scale of a project, approval by the provincial cabinet or a provincial minister may be required. In some jurisdictions, the regulator may conduct public hearings or proceedings to consider applications before issuing approvals.
The Hydro and Electric Energy Act sets out a two-part approval process for the construction and operation of a transmission line and associated facilities. When the AESO, as the transmission system planner, determines that there is a need to construct a transmission line, it must prepare a needs identification document (NID) and file it with the AUC for approval of the need for the proposed project.
The transmission utility that will be responsible to construct and operate the transmission line must file an application with the AUC for approval of the facilities proposed by the AESO in the NID. The NID and transmission facility applications can be considered by the AUC concurrently or sequentially.
Transmission lines that will cross private lands are often considered by the AUC in a public hearing to address matters such as routing, pole or tower design and locations, the effect of poles or towers on land use, visual impacts of the transmission line, and safety. The AUC endeavours to issue its decision within three months of concluding a hearing process.
Construction of intra-provincial transmission lines greater than 2 km in length requires a leave to construct approval from the OEB. The connection of new transmission facilities to the provincial transmission grid also requires the IESO to undertake a system impact assessment to consider any reliability implications. Lastly, transmission lines that are 115 kV or higher and more than 2 km in length require assessment under the Environmental Assessment Act. The level of the environmental assessment depends on the voltage and length of the proposed line.
OEB leave to construct under the OEB Act is the principal approval required to construct a transmission line greater than 2 km in length. The OEB applies a public interest test under which the OEB considers the interests of consumers with respect to prices and the reliability and quality of electricity service, including whether the proposed transmission facility is needed and whether it is preferable to other alternatives to satisfy the same need. Several years ago, the OEB Act was amended to provide the government with authority to designate priority transmission projects and to designate proponents to develop priority transmission projects.
Priority designation relieves the proponent of the obligation to prove need in order to obtain leave to construct approval. Under the Environmental Assessment Act, projects may be subject to a class-type environmental screening or a full individual environmental assessment. Transmission lines that are higher voltage and of greater length require full individual environmental assessments.
Regulators and governmental agencies generally have the authority to impose conditions in approvals that are intended to reasonably mitigate potential adverse effects on the environment and potential effects on people, including land use and disturbance, visual, and safety. Related to mitigation of adverse effects, regulators normally have the authority to prescribe conditions pertaining to the construction methods and right-of-way maintenance. Proponents are also required to comply with all applicable laws and technical codes and standards.
Each province has its own regime to enable a proponent to obtain access to land to construct, operate and maintain transmission facilities. In some provinces, where the use of public land (Crown land) is needed, land use authorisations may be obtained from the provincial government. Where a transmission line is proposed to cross private land, the proponent may negotiate a transmission line right-of-way agreement with the landowner, or, failing that, the legislation in several provinces enables a proponent to expropriate land or obtain a right of entry order.
The forced taking of land typically carries with it the obligation of the proponent to compensate the landowner for the fair market value of the affected land and, in addition to that for right of entry orders, the value of the loss of land use (ie, reduced agricultural operations), adverse effect on the remaining land and any damage to land.
Vertically integrated electric utilities normally have monopoly rights to provide all utility services in the particular province, including transmission service required to deliver electricity for sale at the distribution level.
In Alberta, there are no specified transmission service territories. However, and with certain exceptions, legislation requires the AESO to determine which transmission utility is eligible to apply to the AUC for approval to construct and operate a transmission facility based on the utility’s historical transmission operations within a distribution service area established pursuant to the Hydro and Electric Energy Act. For example, ATCO Electric’s transmission business unit has historically operated within the service area established for ATCO Electric’s distribution business unit.
In Ontario, OEB transmission licences provide transmitters with the exclusive right to provide transmission services within their service territory. HONI owns and operates approximately 98% of the provincial transmission grid. There are several other small licensed transmitters. Recently, there have been government policy initiatives to encourage new entrants and competition in the transmission sector.
The Electric Utilities Act governs the provision of transmission service and the regulation of transmission rates and terms and conditions of service. The AUC has the responsibility to set just and reasonable rates and terms and conditions (the tariff) in respect of regulated utility service. Consistent with general rate-making principles applied widely in North America, a tariff approved by the AUC must not be unduly preferential, arbitrary or unjustly discriminatory.
The Ontario Energy Board Act governs the provision of transmission service and the regulation of transmission rates and terms and conditions of service. The OEB has the responsibility to set just and reasonable rates and terms and conditions (the tariff) in respect of regulated utility service. Transmission rates are intended to recover a transmitter’s forecast revenue requirement, including a return on capital. Consistent with general rate-making principles applied widely in North America, a tariff approved by the OEB must not be unduly preferential, arbitrary or unjustly discriminatory.
Provinces That Have a Vertically Integrated Utility Structure
In the provinces that have vertically integrated utilities, the costs approved by the regulator for transmission service are bundled with the costs approved for generation and distribution service to derive the bundled electricity rates paid by consumers.
Generally, utility rates are set using the traditional cost of service methodology to calculate a utility’s revenue requirement that is recovered through approved rates. The revenue requirement includes the return on equity, cost of debt, depreciation expense, taxes, and operating and maintenance costs.
Some provinces have a public review process by the provincial utility regulator, which may involve public hearings, with a process for written interrogatories, the filing of written evidence, cross-examination of other parties’ witnesses in an oral hearing and the presentation of arguments. If appeals of a regulator’s decisions are permitted, it is usually specified in the regulator’s governing legislation.
Pursuant to the Electric Utilities Act, the AESO is responsible for providing "system access service" on the transmission system through the use of the transmission facilities of all transmission facility owners (TFOs). The AESO is required to apply to the AUC for approval of the AESO’s tariff, which includes the rates charged for each class of system access service and the terms and conditions. The rates charged by the AESO are intended to recover the annual forecast amounts to be paid by the AESO to the TFOs for use of their transmission facilities, the AESO’s own administrative costs, the cost of transmission line losses and the cost of ancillary services obtained by the AESO.
The annual amount the AESO pays each TFO is based on the TFO’s annual revenue requirement approved by the AUC on a forecast basis. The rate base of each TFO is set on the basis of historic capital cost, plus capital additions, less depreciation. The typical debt to equity capital structure for the rate base and the return on equity rates for TFOs are set in a generic cost of capital proceeding at regular intervals.
TFO revenue requirement applications are considered by the AUC in a public hearing process involving written interrogatories to the TFO, intervener evidence, interrogatories regarding intervener evidence, written reply evidence from the TFO, cross-examination of each party’s witnesses at the hearing, written arguments and written reply arguments. The AUC endeavours to issue its decision within three months of the completion of arguments.
Comprehensive AESO tariff applications filed every three years follow a similar process.
Appeals of AUC decisions may be made to the Alberta Court of Appeal with permission from the Court on questions of law or jurisdiction. The Alberta Utilities Commission Act also permits AUC decisions to be reviewed by a review panel, for which the AUC has established threshold criteria.
Regulated transmitters’ revenue requirement applications are considered by the OEB in a public hearing process involving written interrogatories to the transmitter, intervener evidence, interrogatories regarding intervener evidence, written reply evidence from the transmitter, cross-examination of each party’s witnesses at the hearing, written arguments and written reply arguments. The OEB endeavours to issue its decision within approximately six months of the completion of arguments.
Appeals of OEB decisions may be made to the Ontario Divisional Court on questions of law or jurisdiction, and with leave from the Ontario Divisional Court to the Ontario Court of Appeal. Transmitters or others who are the subject of OEB decisions may, before exercising appeal rights, seek reconsideration by the OEB.
British Columbia, Saskatchewan, Manitoba, Québec, New Brunswick and Nova Scotia each have a form of an Open Access Transmission Tariff (OATT), which is modelled after the USA's Federal Energy Regulatory Commission OATT. The purpose of an OATT is to ensure that users of a transmission system are able to access service on an open, non-discriminatory and non-preferential basis. The electric utility in Prince Edward Island has applied to its regulator for approval of a form of an OATT. The legislature of Newfoundland and Labrador’s Electrical Power Control Act requires the provision of simultaneous, open, non-discriminatory and non-preferential access to, interconnection with and use of the transmission system.
The AESO is statutorily obligated to provide system access service on the Alberta transmission system in a manner that provides all market participants wishing to exchange electric energy a reasonable opportunity to do so. There are no transmission rights in Alberta and access to the transmission system by market participants is open, non-discriminatory and non-preferential, pursuant to the terms of the AESO’s tariff approved by the AUC.
A fundamental principle upon which Ontario’s restructured electricity market was premised was the principle of "open access"; ie, the obligation by transmitters and distributors to provide generators, retailers and consumers with non-discriminatory access to their transmission and distribution system. This principle is embedded in the Electricity Act. This principle has, in part, been modified by amendments that provide that transmitters provide priority connection for renewable or other non-emitting resources.
In most Canadian provinces, the construction and operation of distribution facilities is addressed through agreements between distributors and municipalities. See 6.1.2 Regulatory Process for Obtaining Approvals to Construct and Operate Distribution Facilities.
The construction and operation of distribution facilities in Canadian provinces is largely exempt from regulation by the provincial utilities regulator. Instead, the location, construction and operation of distribution facilities within municipal boundaries may be subject to approval of the municipality in which the distribution facilities are to be developed. In some provinces, such as Alberta, the right to provide utility service within the boundaries of a municipality is vested in the municipality.
Some municipalities enter into franchise agreements with distribution utilities that grant them the right to construct and operate a distribution system within municipal boundaries.
To the extent that a regulatory approval is required to construct and operate distribution facilities, approving authorities generally have authority to require compliance with all applicable laws and technical codes and standards.
Each province has its own regime to enable a proponent to obtain access to land to construct, operate and maintain distribution facilities. In some provinces, where the use of public land (Crown land) is needed, land use authorisations may be obtained from the provincial government. Where a distribution line is proposed to cross private land, the proponent may negotiate a right-of-way agreement with the landowner, or, failing that, the legislation in several provinces enables a proponent to expropriate land or obtain a right of entry order.
The forced taking of land typically carries with it the obligation of the proponent to compensate the landowner for the fair market value of the affected land and, in addition to that for right of entry orders, the value of the loss of land use (ie, reduced agricultural operations), adverse effect on the remaining land and any damage to land.
Municipalities may grant access for the construction, operation and maintenance of distribution facilities to be located within their boundaries.
Vertically integrated utilities generally have monopoly rights to provide utility services, including distribution service. In Alberta, distribution utilities have monopoly rights to provide service within a service area prescribed by the AUC, pursuant to the Hydro and Electric Energy Act. In Ontario, no person may own or operate an electric distribution system unless licensed to do so by the OEB. Distribution licences granted by the OEB provide distributors with the right to provide services within their service territory, which in practice is an exclusive right.
The provision of electric distribution in Alberta is governed by the Electric Utilities Act. Pursuant to the Electric Utilities Act, the AUC has the responsibility to set just and reasonable rates and terms and conditions (the tariff) in respect of regulated utility service. Consistent with general rate-making principles applied widely in North America, a tariff approved by the AUC must not be unduly preferential, arbitrary or unjustly discriminatory.
The provision of and operation of electric distribution is governed by the OEB Act. Any person who owns or operates a distribution system must hold a licence pursuant to the OEB Act. The OEB has the responsibility to set just and reasonable rates and terms and conditions (the tariff) in respect of regulated utility service. Distribution rates are intended to recover a distribution company’s forecast revenue requirement, including a return on capital. Consistent with general rate-making principles applied widely in North America, a tariff approved by the OEB must not be unduly preferential, arbitrary or unjustly discriminatory.
Generally, in the provinces that have vertically integrated utilities, the costs approved by the regulator for distribution service are bundled with the costs approved for generation and transmission service to derive the approved bundled electricity rates paid by consumers.
Except where a provincial regulator has adopted a different approach to the regulation of distribution service rates, such as performance-based regulation, the traditional cost of service methodology is generally applied to calculate the distribution portion of the utility’s revenue requirement for recovery through approved rates charged to consumers. The revenue requirement includes the return on equity, cost of debt, depreciation expense, taxes, and operating and maintenance costs.
Some provinces have a public review process by the provincial utility regulator, which may involve public hearings, with a process for written interrogatories, the filing of written evidence, cross-examination of other parties’ witnesses in an oral hearing and the presentation of arguments. If appeals of a regulator’s decisions are permitted, it is usually specified in the regulator’s governing legislation.
The deemed debt to equity capital structure for rate base and the rate of return on equity for distribution utilities are set by the AUC in a generic cost of capital proceeding at regular intervals. The AUC has adopted a form of performance-based regulation (PBR) to set rates for distribution utilities, rather than the traditional cost of service methodology, in order to mimic competition, create incentives for the utility to reduce costs through efficiency and thereby keep distribution service rates lower than might otherwise be the case. Alberta has five-year PBR terms.
The PBR framework approved by the AUC provides a formulaic rate-setting mechanism that adjusts rates annually due to an inflation indexing mechanism, less a productivity offset. A distribution utility may apply for approval to recover specific costs if they cannot be recovered under the "inflation less productivity" mechanism, and subject to the satisfaction of certain other criteria. The AUC also applies a "capital tracker" mechanism to fund certain capital-related costs.
The AUC typically conducts a public hearing process each time it resets the five-year PBR plans for distribution utilities and when it considers capital tracker applications that may result in the adjustment of rates resulting from approved PBR plans. The hearing process can involve written interrogatories to the utility, intervener evidence, interrogatories regarding intervener evidence, written reply evidence from the utility, cross-examination of each party’s witnesses at the hearing, written arguments and written reply arguments. The AUC endeavours to issue its decision within three months of the completion of arguments.
Appeals of AUC decisions may be made to the Alberta Court of Appeal with permission from the Court on questions of law or jurisdiction. The Alberta Utilities Commission Act also permits AUC decisions to be reviewed by an AUC review panel, for which the AUC has established threshold criteria.
The Impact of COVID-19 on the Power Sector
COVID-19 has triggered material reductions in the demand for electricity and significant changes in demand patterns in all Canadian jurisdictions. Whether and how demand will re-bound is difficult to assess and the situation will, no doubt, vary from province to province. This article considers the impact of COVID-19 on four provinces; Alberta, Québec, Ontario and British Columbia.
In Alberta, indicators show that the pandemic has exacerbated what was already a softening in the electricity market. The biggest driver of electricity demand in Alberta is the oil and gas industry. Before the advent of COVID-19, depressed world oil prices and constrained pipeline transportation capacity had already resulted in a decline in electricity demand and the 20-year annual rate of growth in electricity demand was forecasted at 0.9%, approximately half the rate of growth experienced in the previous 20-year period.
In the month following the introduction of stay-at-home orders, however, Alberta’s demand for electricity fell by a full 10%, reflecting decreases due to business shut-downs and closures, a shift to working from home, the knock-on effects of COVID-19 impacts in the United States and COVID-19 related decreases in the demand for oil and gas.
It remains to be seen whether and how COVID-19 will affect the construction of new generation capacity in Alberta. For example, petroleum companies seeking to reduce their electricity costs by constructing on-site co-generation facilities or other behind the fence generation may decide to scale back on their investment in new generation facilities. Pre-COVID-19, the mandated replacement of almost 6,000 MWs of coal-fired capacity by 2030 was another significant driver of investment in new generation in the Province and, in particular, in the renewable energy sector, spurred on by a series of provincial government procurements.
Depending whether and how quickly electricity demand re-bounds to pre-COVID-19 levels, it is conceivable that some renewable energy projects, now in the development stage, will simply not proceed. Finally, companies looking for ways to cut costs in a post-COVID-19 economic down-turn, may be less concerned about achieving sustainability targets through the use virtual power purchase agreements to secure supplies of “green” energy, thus reducing the pool of financing available to renewable project developers in the province.
Electricity generation, transmission and distribution in Québec is managed by Hydro-Québec, a vertically integrated Crown corporation. Access to ample, low-cost hydro-electricity has resulted in the development of electricity-intensive industries, such as aluminum smelting, a large residential heating load and a significant electricity export market. In 2019, Québec exported almost 34 TWh of electricity, almost 42% of the electricity that was generated in Alberta in that year.
In the period 2003 to 2021, Hydro-Québec installed and planned to install close to 5,000 MW of new hydroelectric generation capacity, including the 1550 MW Riviere Romaine hydroelectricity development. Installed capacity was expected to be sufficient, in the short to medium term (ie, to 2025), to meet the Province’s growing demand for electricity, driven by a strong economy and the emergence of new types of electricity loads, such as data centers and cryptocurrency miners. Growth in domestic demand was expected to continue in the medium to longer term and Hydro-Québec also indicated intentions to increase electricity exports to neighbouring jurisdictions as a means of increasing provincial revenues.
Hydro-Québec has acknowledged that COVID-19 is likely to impact demand for electricity. Unlike many other Provinces, however, the combination of newly installed capacity, a low marginal cost of production and available inter-tie capacity gives Québec the ability to sell its surplus power into neighbouring markets, such as Ontario, at prices that undercut the prices of domestic production in those markets. This could lead to downward pressure on electricity prices and a dampening of investments in new generation in these jurisdictions.
Pre-COVID-19 projections of electricity demand in Ontario suggested an annual growth rate of 0.8% over the next 20 years. As a result of COVID-19, electricity consumption in Ontario has fallen between 10% and 12%, with a reduction of peak demand of anywhere from 5% to 17%. This reduction is due to decreases in commercial, retail and institutional loads and smaller reductions in manufacturing loads. There has been minimal disruption of the supply chain and only slight decrease in the level of exports to the United States (80% of Ontario exports go to the USA). Residential consumption, on the other hand, has increased by four percent, reflecting the “stay at home, work from home” shift in behaviour. Experts are predicting that demand is likely to re-bound relatively quickly, once the peak of the pandemic passes, citing the situation in Italy and Spain.
In Ontario, all electricity consumers pay a monthly Global Adjustment charge that reflects the difference between the wholesale market price of electricity and the costs paid to legacy generators and generators under contract with the IESO. The Global Adjustment charge comprises a significant percentage of a consumer’s total electricity cost. Under the IESO’s demand response program, known as the Industrial Conservation Initiative, larger electricity consumers (Class A Customers) can manage their Global Adjustment costs by reducing their demand during provincial peak periods, thereby also helping to defer investment in new electricity infrastructure that would otherwise be needed.
In a post-COVID-19 world, however, historical demand data and patterns may no longer be accurate predictors of provincial peaks, posing real challenges for Class A Customers seeking to mange their consumption. For example, in a one hour period in early April 2020, the difference between the IESO’s forecast of demand in Ontario and the actual demand was 914 MW.
Like Québec, electricity generation, transmission and distribution in British Columbia (BC) is managed by a vertically integrated crown corporation, BC Hydro. As in Québec, hydroelectric generation makes up the majority of electricity generation capacity in the province, with over 91% of British Columbia’s electricity generated by hydroelectric facilities.
Prior to the onset of COVID-19, BC Hydro forecasted electricity demand to increase by one percent each year, over a 20-year period, driven largely by growth in the province’s population and the emergence of a liquefied natural gas industry. Since the onset of COVID-19, BC Hydro has released updated short-term forecasts that predict a 12% decline in demand, through April 2021. This will, no doubt, create challenges for BC Hydro in terms of how its manages its power purchase contracts with independent power producers who, together, account for almost 30% of the electrical energy generated in BC.
Much like Québec, BC is a net exporter of electrical energy. BC’s extensive hydro storage reservoirs allow it to purchase electricity from the USA when prices are low and to sell electricity to the USA when prices are high, thus maintaining a positive trade revenue position (in electricity) despite relatively modest levels of net exports. In 2018, BC exported over 8.8 TWh of electricity to the USA.
This represented CAD571 million in gross revenue from trade in electricity and CAD200 million in net revenue. As a result of the economic downturn in the USA due to COVID-19, however, BC Hydro is now forecasting a decline in electricity exports and a corresponding decrease in export revenue.
Pumped Storage: Old Technology, New Uses
The generation of electricity from renewable sources is intermittent; technologies such as wind and solar only produce energy when the wind is blowing or the sun is shining. The intermittent nature of renewable generation presents challenges for the operation of the electric grid. For utility-scale renewable facilities, one solution is to pair renewable technology with storage technology.
Renewable energy sector development
The development of a robust renewable energy sector in Canada has fostered advances in battery technology and a resurgence of proposals for large pumped storage projects. While the technology that underpins pumped storage projects is not new - water in a lower reservoir is pumped to, and stored in, an upper reservoir and subsequently released from the upper reservoir, thereby generating electricity when the need arises - proposals to use pumped storage as a stand-alone source of generation or pair it with an intermittent source, are new.
In Alberta, TransAlta is promoting its Brazeau Hydro Pumped Storage Project as a backstop to intermittent renewable electricity facilities. TransAlta proposes to expand the capacity of its existing Brazeau hydroelectric plant and add pumped storage capability, yielding up to 900 MW of renewable power in any given hour. Also, in Alberta, the Canyon Creek Project, a 75 MW pumped storage project on the site of a decommissioned open pit coal mine, is closer to becoming a reality due to the recent infusion of equity by TC Energy.
Construction of the project is anticipated to commence in 2020. In Ontario, two large pumped storage projects are also being proposed. Northland Power’s 400 MW Marmora Pumped Storage Hydro Power Project, proposed for the site of an open pit iron ore mine, has been on the drawing board for some time.
More recently, TC Energy announced plans to develop the 1000 MW Meaford Tank Range Project on Canadian Army Training Centre lands. Both proposed pumped storage developments are large, long-lead, capital intensive projects and the Meaford Project, at least, faces considerable opposition from local communities.
Carbon Regulation Developments
Federal climate change legislation will be heading to the Supreme Court of Canada (SCC) in 2020 by way of provincial challenges to the federal Greenhouse Gas Polluting Price Act (CGGPA). The CGGPA imposes a carbon tax on energy consumers in provinces that have no-mandated carbon tax or cap and trade regimes of their own. In 2019, appellate courts in Ontario and Saskatchewan upheld the constitutionality of the CGGPA. In contrast, in a decision released in February 2020, the Alberta Court of Appeal held that the GCCPA is ultra vires the federal government’s jurisdiction and, accordingly, is unconstitutional.
All three of the provincial appellate decisions have been appealed to the SCC. The main protagonists are the Attorney-Generals of Canada, Ontario and Saskatchewan. The Provinces of New Brunswick, Quebec, Manitoba, Alberta and British Columbia, have intervened in the appeal and have filed written submissions.
As a result of COVID-19, the SCC hearing which was originally scheduled for March 2020, has been moved to September 2020. It is anticipated that the impact of the SCC’s decision will be far-reaching, both from an economic and an environmental perspective.
Electrification of Transportation
Continued support can be seen for the electrification of transportation in the form of rebates for the purchase of electric vehicles and funding for the research, development and installation of electrification technology, both at the federal and provincial levels. At the federal level, the Zero Emission Vehicle Infrastructure Program has recently committed CAD130 million to facilitate the installation of zero-emission vehicle charging and refueling stations at workplaces, transit stations and multi-unit residential complexes, across Canada. The Electric Vehicle and Alternative Fuel Infrastructure Deployment Initiative provides funding to both public and private entities, such as the British Columbia Ministry of Transportation and Infrastructure, Hydro Québec, Newfoundland and Labrador Hydro and the Cities of Ottawa, Surrey and North Vancouver to continue to develop infrastructure for similar infrastructure development and diversification.
Electrification initiatives at the provincial level include Quebec’s Electrification and Climate Change Fund, British Columbia’s Go Electric Incentive and Go Electric Charging Infrastructure Programs, Ontario and Quebec’s Electric Circuit Programs and Alberta’s Zero Emissions Truck Electrification Collaboration (AZTEC), being supported by Emissions Reduction Alberta. British Columbia’s Go Electric initiatives provide provincial rebates on electric vehicles and financial incentives for the installation of charging stations at workplaces and multi-unit residential buildings. The Electric Circuit Programs in Ontario and Quebec support the development of a public charging network for electric vehicles throughout the two provinces. The AZTEC project is focused on technology to design and develop to long-range fuel cell electric trucks.
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