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 electrical 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 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

Western Canada

• Province and approximate population – Alberta 4,262,635.
1. Crown, private or municipal ownership – private and some municipal.
2. Vertically integrated or unbundled – unbundled. 
3. Primary legislation – Electric Utilities Act, Hydro and Electric Energy Act.
4. Utility regulator – Alberta Utilities Commission.
• Province and approximate population – British Columbia 5,145,785.
1. Crown, private or municipal ownership – Crown and some private.
2. Vertically integrated or unbundled – vertical.
3. Primary legislation – Utilities Commission Act, Clean Energy Act.
4. Utility regulator – British Columbia Utilities Commission.
• Province and approximate population – Manitoba 1,342,153.
1. Crown, private or municipal ownership – Crown.
2. Vertically integrated or unbundled – vertical.
3. Primary legislation – Public Utilities Board Act.
4. Utility regulator – Public Utilities Board.
• Province and approximate population – Saskatchewan 1,132,505.
1. Crown, private or municipal ownership – Crown.
2. Vertically integrated or unbundled – vertical.
3. Primary legislation – Power Corporation Act.
4. Utility regulator – no regulator.

Central Canada

• Province and approximate population – Ontario 14,223,942.
1. Crown, private or municipal ownership – Crown, private and municipal.
2. Vertically integrated or unbundled – unbundled.
3. Primary legislation – Electricity Act, Ontario Energy Board Act (OEB Act).
4. Utility regulator – Ontario Energy Board.
• Province and approximate population – Quebec 8,501,833.
1. Crown, private or municipal ownership – Crown and some municipal.
2. Vertically integrated or unbundled – vertical.
3. Primary legislation – Loi sur Hydro-Québec (Hydro-Québec Act), Loi sur la Régie de l’énergie (Act respecting the Régie de l’énergie).
4. Utility regulator – Régie de l’énergie.

Atlantic Canada

• Province and approximate population – New Brunswick 775,610.
1. Crown, private or municipal ownership – Crown.
2. Vertically integrated or unbundled – vertical.
3. Primary legislation – Electricity Act, Energy and Utilities Board Act.
4. Utility regulator – New Brunswick Energy and Utilities Board.
• Province and approximate population – Newfoundland and Labrador 510,550.
1. Crown, private or municipal ownership – Crown and private.
2. Vertically integrated or unbundled – vertical.
3. Primary legislation – Electrical Power Control Act, Public Utilities Board Act.
4. Utility regulator – Newfoundland and Labrador Board of Commissioners of Public Utilities.
• Province and approximate population – Nova Scotia 969,383.
1. Crown, private or municipal ownership – private and some municipal.
2. Vertically integrated or unbundled – vertical.
3. Primary legislation – Public Utilities Act, Utility and Review Board Act, Electricity Act.
4. Utility regulator – Nova Scotia Utility and Review Board.
• Province and approximate population – Prince Edward Island 154,331.
1. Crown, private or municipal ownership – private.
2. Vertically integrated or unbundled – vertical.
3. Primary legislation – Electric Power Act, Island Regulatory and Appeals Commission Act.
4. Utility regulator – Island Regulatory and Appeals Commission.

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 most of the province, as well as the construction and operation of most 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 electrical utilities and is responsible for regulating the construction and operation of facilities by electrical 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 Quebec’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 Quebec throughout nearly the entire province. It is regulated by the Régie de l’énergie, pursuant to the Loi sur la Régie de l’énergie (Act respecting the Régie de l’énergie).

Alberta

In 1995, the Electric Utilities Act was enacted to restructure the Alberta electricity industry by unbundling the vertically integrated electrical 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.

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

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. From 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 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.

The restructuring also resulted in the consolidation of 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 OEB Act. The OEB also regulates the 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 most of the 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. 

Alberta

There are approximately 426 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, ATCO Electric and Alberta PowerLine, which 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.

British Columbia

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.

Saskatchewan

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.

Manitoba

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.

Ontario

The former generation arm of Ontario Hydro, OPG, continues to own the 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.

Quebec

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, municipalities and co-operatives. Of all electricity produced in Quebec, approximately 99% is from renewable sources. With an installed capacity of approximately 37.2 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 Industry and/or Canadian Heritage ("the Minister") before proceeding.

Thresholds for Review

Whether a transaction is subject to notification or to pre-closing review depends on 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.

Transaction structure

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 equal to or more than CAD1.141 billion. That threshold rises to CAD1.711 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 book value of the assets of the Canadian business is equal to or more than CAD454 million.

Review Process

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 they are satisfied or are 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. This period 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 maintaining 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 the applicable legislation in the 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.

Alberta

The sale of generation assets requires the 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 the 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.

Ontario

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 the 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, the overall planning of the electricity system regarding reliability and sufficiency of supply may be managed by or among the utility, its regulator, or the provincial government.

Alberta

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. Transmission needs identified in the LTP or arising out of the AESO’s obligation to provide “system-access service" on the transmission system are addressed by transmission utilities under direction from the AESO and approval by the AUC.

The AESO has limited authority to arrange for the development or retirement of generation to meet the forecast electricity needs of Alberta. This is intended to be driven by economics through price signals from Alberta’s competitive wholesale electricity market.

The AESO is also responsible for making detailed rules and reliability standards regarding the safe, reliable and economic operation of the Alberta interconnected electricity system, as well as the operation of the competitive market.

Ontario

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. Going forward, more generation will 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 the support of the IESO, to construct new transmission and distribution facilities, and include the costs of such facilities in their base rate. Recently, Ontario’s Electricity Act was amended to also enable the IESO, pursuant to government directive, to procure the development, construction and operation of transmission projects.

Alberta

The Alberta government, AUC, and AESO are all currently undertaking major reviews of issues that may result in significant shifts in policy for:

• self-supply facilities (ie, exemptions available for on-site generators that serve on-site load);
• storage facilities (ie, tariff treatment, market participation and alternative use to transmission facilities); and
• owners of distribution facilities (ie, planning for the integration of new technologies).

In May 2022, under the Electricity Statutes (Modernizing Alberta’s Electricity Grid) Amendment Act, 2022, the Alberta government introduced the following changes:

• removing the prohibition for unlimited self-supply with export to the grid;
• defining “energy storage” within the legislative framework and introduces requirements for regulatory approvals;
• allowing owners of transmission and distribution facilities to own energy storage in certain circumstances; and
• requiring owners of distribution facilities to prepare long-term plans to modernise Alberta’s distribution system given the development and integration of new technologies.

See 3.1 Principal Climate Change Laws and/or Policies and 3.2 Principal Laws and/or Policies to Encourage the Development of Alternative Energy Sources.

In response to announced and expected solicitations by states in the north-eastern USA for the delivery of incremental "clean energy", there are significant opportunities in Canada to develop major transmission infrastructure to deliver electricity from Canadian hydro and wind sources in response to requests for proposals.   

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.

Alberta

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 the 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.

Ontario

The wholesale electricity market, administered by the IESO, includes an hourly spot market. Amendments to the Electricity Act 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, OPG receives market settlements from the IESO and 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.

The out-of-market adjustment payments that are made to generators and other suppliers are referred to as the "Global Adjustment". The commodity price of electricity in Ontario is therefore composed of the hourly wholesale market spot price, the Global Adjustment and other upliftment charges (costs for ancillary services, administrative price charges, etc).

The Electricity Act and the OEB Act mandate a regulated price plan (RPP) to reduce residential and small business consumers’ exposure to price volatility.

Federal

The export of electricity from Canada is regulated by the Canada Energy Regulator through the issuance of blanket electricity export permits. 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.

Ontario

IESO market rules provide for inter-jurisdictional energy trade. 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). Market participants may purchase financial transmission rights in the IESO transmission rights market as a hedge against transmission congestion on the interties.

Quebec

Hydro-Québec operates 15 existing interconnections with the Province of Ontario, the Province of New Brunswick, the State of New York, and New England. Hydro-Québec is developing two additional interconnections with the north-eastern states, the Hertel-New York interconnection project and the New England Clean Energy Project. On 14 April 2022, the New York State Public Service Commission approved the contract between Hydro-Québec and the New York State Energy Research and Development Authority (NYSERDA) for the annual delivery of 10.4 TWh of electricity to New York City by way of the Champlain Hudson Power Express (CHPE) line which has now begun construction. The project will also involve building a new 400 kV underground direct-current line in Quebec, the Hertel-New York interconnection line, that will connect to the CHPE line. The governmental approval process is currently underway, and construction of the new interconnection is expected to begin in spring 2023.

On the other hand, New England Clean Energy Connect (NECEC) has halted construction of the new 1,200 MW interconnection linking Quebec to Massachusetts via Maine and New Hampshire as a result of the rejection of the project by the Maine population in a referendum vote held on 2 November 2021. The fate of the project remains uncertain at this stage pending the resolution of the legal challenges.

Canadian Electricity Supply Mix 1

Jurisdiction – Canada total

Total 2021 generation (TWh) – 636.8.

• Hydro – 59.7%.
• Natural gas – 11.9%.
• Coal – 7.4%.
• Nuclear – 12.9%.
• Wind – 5.8%.
• Solar – <1%.
• Petroleum – <1%.
• Biomass/fuel geothermal – <2%.

Western Canada

Jurisdiction – Alberta

Total 2021 generation (TWh) – 85.1.

• Hydro – 2.4%.
• Natural gas – 54.7%.
• Coal – 35.6%.
• Nuclear – 0%.
• Wind – 4.9%.
• Solar – <1%.
• Petroleum – <1%.
• Biomass/fuel geothermal – 1.9%.

Jurisdiction – British Columbia

Total 2021 generation (TWh) – 62.5.

• Hydro – 89.8%.
• Natural gas – 2.1%.
• Coal – 0%.
• Nuclear – 0%.
• Wind – 2.7%.
• Solar – <1%.
• Petroleum – <1%.
• Biomass/fuel geothermal – 5.2%.

Jurisdiction – Manitoba

Total 2021 generation (TWh) – 34.0.

• Hydro – 96.9%.
• Natural gas – <1%.
• Coal – 0%.
• Nuclear – 0%.
• Wind – 2.6%.
• Solar – <1%.
• Petroleum – <1%.
• Biomass/fuel geothermal – <1%.

Jurisdiction – Saskatchewan

Total 2021 generation (TWh) – 25.2.

• Hydro – 14.6%.
• Natural gas – 43.3%.
• Coal – 38.6%.
• Nuclear – 0%.
• Wind – 3.1%.
• Solar – 0%.
• Petroleum – <1%.
• Biomass/fuel geothermal – <1%.

Central Canada

Jurisdiction – Ontario

Total 2021 generation (TWh) – 146.4.

• Hydro – 24.7%.
• Natural gas – 9.5%.
• Coal – 0%.
• Nuclear – 52.9%.
• Wind – 10.8%.
• Solar – 1.5%.
• Petroleum – <1%.
• Biomass/fuel geothermal – <1%.

Jurisdiction – Quebec

Total 2021 generation (TWh) – 212.0.

• Hydro – 94.1%.
• Natural gas – <1%.
• Coal – 0%.
• Nuclear – 0%.
• Wind – 5%.
• Solar – <1%.
• Petroleum – <1%.
• Biomass/fuel geothermal – <1%.

Atlantic Canada

Jurisdiction – New Brunswick

Total 2021 generation (TWh) – 15.4.

• Hydro – 19.4%.
• Natural gas – 8.8%.
• Coal – 15.4%.
• Nuclear – 32%.
• Wind – 6.7%.
• Solar – 0%.
• Petroleum – 14.5%.
• Biomass/fuel geothermal – 3.3%.

Jurisdiction – Newfoundland and Labrador

Total 2021 generation (TWh) – 46.6.

• Hydro – 96.7%.
• Natural gas – <1%.
• Coal – 0%.
• Nuclear – 0%.
• Wind – <1%.
• Solar – 0%.
• Petroleum – 2.1%.
• Biomass/fuel geothermal – 0%.

Jurisdiction – Nova Scotia

Total 2021 generation (TWh) – 7.3.

• Hydro – 13.7%.
• Natural gas – 9.1%.
• Coal – 60.4%.
• Nuclear – 0%.
• Wind – 14.4%.
• Solar – 0%.
• Petroleum – <1%.
• Biomass/fuel geothermal – 1.7%.

Jurisdiction – Prince Edward Island

Total 2021 generation (TWh) – 1.0.

• Hydro – 0%.
• Natural gas – 0%.
• Coal – 0%.
• Nuclear – 0%.
• Wind – 94.8%.
• Solar – 0%.
• Petroleum – 4.9%.
• Biomass/fuel geothermal – <1%.

Federal

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 (the "Commissioner"). The Competition Act defines "merger" very broadly as “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 “prevents or lessens, or is 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.

Alberta

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.

Ontario

As part of the deregulation of the Ontario electricity sector and the opening of the market in 2002, the province mandated that OPG 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 OPG was precluded for some time from participating in certain new-generation procurement and development programmes, these restrictions have now waned. Notably, in spring 2020, OPG closed a CAD2.8 billion acquisition of interests from TC Energy in three Ontario natural gas-fired power plants (ie, the 683 MW Halton Hills generating station, the 900 MW Napanee generating station and TC Energy’s interest in the 550 MW Portland Energy Centre).

Federal

At the federal level, the Competition Bureau of Canada is the agency responsible for the surveillance of anti-competitive behaviour and the enforcement of antitrust legislation in Canada.

Alberta

The MSA, established by the Alberta Utilities Commission Act, has the 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:

• possible contraventions of legislation governing the electricity industry;
• when it appears to the MSA that the conduct of a market participant does not support the fair, efficient and openly competitive operation of the electricity market; and
• any matter that relates to or affects the structure and performance of the electricity market.

The MSA has the authority to enter and inspect premises, make enquiries 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.

Ontario

There are two agencies that monitor anti-competitive behaviour and undertake enforcement activity:

• the Market Surveillance Panel (MSP), a panel of the OEB; and
• the Market Assessment and Compliance Division (MACD), a division of the IESO.

The MSP monitors, investigates, and reports on IESO market design and structural issues, and on the 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 MACD monitors the operation of the market and compliance with applicable market rules and reliability standards. The MACD does this through prevention, monitoring, auditing, investigation and enforcement activities. Furthermore, the MACD enforces compliance with the IESO’s general conduct rule that proscribes conduct aimed at undermining, manipulating, interfering with or exploiting the market.

Federal

In June 2018, the federal government enacted the Greenhouse Gas Pollution Pricing Act (GGPPA), a federal backstop carbon emissions pricing scheme for provinces without a satisfactory carbon emissions pricing system. The federal carbon emissions pricing system – which was upheld by the Supreme Court of Canada in March 2021 – consists of two distinct components:

• a carbon levy applied to fossil fuels, currently set at CAD50/tonne, increasing by CAD15 per year until the carbon price reaches CAD170/tonne in 2030; and
• an output-based pricing system for large facilities producing 50,000 tonnes or more of carbon emissions per year, which include most thermal generation facilities.

In December 2020, the federal government published a comprehensive climate-change strategy entitled A Healthy Environment and a Healthy Economy, driven by the objective for Canada to achieve net-zero emissions by 2050. This strategy introduced changes, including an increase in the yearly carbon levy from CAD10 to CAN15 starting in 2023. The goals of this strategy were enacted into law through the Canadian Net-Zero Emissions Accountability Act, which received royal assent in June 2021. This Act creates a framework for achieving Canada’s net-zero goal by 2050.

In March 2022, the federal government introduced the 2030 Emissions Reduction Plan. This plan outlines a roadmap for greater climate action until 2030 and requirements for climate action plans following 2030. 

Alberta

In May 2019, Alberta repealed its Climate Leadership Act, which had enacted portions of its Climate Leadership Plan, including a carbon emissions pricing regime for consumers. In the absence of an Alberta carbon pricing scheme, the federal GGPPA applies to consumers, as discussed above.

Alberta’s carbon pricing scheme for industry came into effect on 1 January 2020. The Technology Innovation and Emissions Reduction Regulation requires facilities emitting more than 100,000 tonnes of CO₂ 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 regulations, 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.

British Columbia

In 2008, British Columbia enacted the Carbon Tax Act, which applied a broad-based carbon tax. As of 1 April 2022, the carbon tax rate is CAD50/tonne of carbon dioxide equivalent. 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 CO₂ 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 to 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.

Saskatchewan

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 1.5 million tonnes of CO₂ equivalent per year.

Manitoba

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.

Ontario

As of 1 April 2019, Ontarians have been subject to the federal carbon tax. Since January 2022, eligible emitters in Ontario have been subject to a provincial Emissions Performance Standards Program governed by the Emissions Performance Standards Regulation (O Reg 241/19) in lieu of the federal OPBS.

Quebec

In 2013, Quebec adopted a cap-and-trade system for greenhouse gas emissions allowances. The system is currently linked to California’s cap-and-trade system. Most recent Hydro-Québec PPAs provide that "green credits", if any, are for the benefit of Hydro-Québec.

New Brunswick

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.

Nova Scotia

On 1 January 2019, Nova Scotia implemented a cap-and-trade programme to help reduce greenhouse gas emissions in the province. The new programme was enacted through amendments to the Environment Act and the adoption of cap-and-trade programme regulations.

Federal

The government of Canada has enacted regulations limiting the intensity of emissions from new and old coal-fired generation projects to 420 tonnes per GWh 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.

Alberta

The provincial government, as part of its 2018 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 electricity industry in Alberta, as well as the maintenance of a significant business presence in Alberta.

British Columbia

British Columbia’s Clean Energy Act restricts the operation and use of thermal generation by BC Hydro, except in cases of emergency or for transmission support services.

Ontario

Pursuant to the Cessation of Coal Use Regulation (2007), Ontario mandated the retirement of all coal-based generation facilities, or their conversion 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.

Saskatchewan

SaskPower currently has three coal power plants, accounting for approximately 30% of power produced. SaskPower’s goal is to reduce emissions of CO₂ from facilities by at least 50% from 2005 levels by 2030. To reach this goal, SaskPower is working to institute green technologies such as carbon capture and storage.

Alberta

The provincial government established the Renewable Electricity Program (REP), 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). Three REP procurement competitions were completed in 2017 and 2018, resulting in the AESO procuring 1,358.6 MW of renewables. In June 2019, the Alberta government announced that there would be no further procurement competitions under the REP.

Renewable generation projects are 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.

Certain small-scale renewable generation projects are eligible under the Small Scale Generation Regulation, for the removal of responsibility for participation in the competitive market for those project proponents that enter into a benefit agreement with a community group.

British Columbia

Pursuant to the Clean Energy Act, BC Hydro is obliged 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 established the Standing Offer and Micro Standard Offer Programs to encourage the development of small clean or renewable electricity projects throughout British Columbia. However, BC Hydro announced on 14 February 2019 that it was suspending the two programmes 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.

Saskatchewan

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 the fourth quarter 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 2021, the 10 MW Highfield Solar project, the province’s first utility-scale solar generation project began operation. In 2022, two wind generation projects began operation, the 200 MW Golden South Wind Energy project and the 175 MW Blue Hill Wind Facility.

Ontario

In December 2018, the Green Energy Repeal Act (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.

In the spring of 2022, Ontario released Ontario’s Low-Carbon Hydrogen Strategy (the "Strategy"). The Strategy was issued following the publication of other hydrogen policies throughout Canada, including by the federal government and by provincial governments in Quebec, Alberta and British Columbia. The Strategy is grounded in eight immediate actions to increase the province’s capacity to produce green hydrogen and blue hydrogen. Many of the actions seek to develop the low-carbon hydrogen industry by leveraging Ontario’s clean electricity capabilities.

Quebec

On 14 July 2021, the government of Quebec issued an order-in-council launching calls for tender for a 300 MW block of wind energy and a 480 MW block of renewable energy. The deadline for submitting proposals is 21 July 2022. In addition, Hydro-Québec announced as part of its 2020–2029 strategic plan that it is looking to add an additional 5,000 MW (in addition to the above-noted calls for tender) production capacity by 2035, of which 3,000 MW will be sourced from wind energy projects to be developed in partnership with private and local partners which will be awarded by private agreements prior to 2026, and the remaining 2,000 MW will originate from improvements to Hydro-Québec’s hydroelectric facilities.

On 19 April 2022, Hydro-Québec announced the formation of a partnership with Énergir and Boralex Inc. for the development of three wind energy projects totalling 1,200 MW on the territory of the Seigneurie de Beaupré. As a result, it is expected that 1,800 MW remain available as part of the 3,000 MW block earmarked for wind energy projects with private and local partners.

Nova Scotia

In February 2022, Nova Scotia’s procurement administrator issued a request for proposals for wind and solar energy projects that will generate 350 MW of electricity. This procurement is intended to supply 10% of Nova Scotia’s electricity and will reduce the province’s greenhouse gas emissions by over one million tonnes each year. Up to five projects are expected to be selected to receive a 25-year power purchase agreement with Nova Scotia Power.

Federal

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.

Alberta

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 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 approval under the Water Act.

Ontario

The construction and operation of generation facilities is primarily governed by the Environmental Assessment Act (EAA) and the Environmental Protection Act (EPA).

The 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.

Federal

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 CER considers a number of factors in determining whether to approve an application, including:

• the project’s environmental effects;
• safety and security considerations;
• the health, social and economic effects;
• the rights, interests and concerns of the indigenous peoples of Canada; and
• the effects on climate change commitments.

Alberta

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.

Ontario

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. This 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 government agencies generally have the authority to impose conditions in approvals that are intended to reasonably mitigate potential adverse effects on the environment and on people. 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.

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 in addition to that for right-of-entry orders, the value of the loss of land use, any adverse effect on the remaining land, and any damage to land.

Applicable environmental laws and regulatory policies in each province govern the requirements for decommissioning power plants. For example, in Alberta, 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.