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
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 through 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).
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’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 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 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 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.
There are approximately 390 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.
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 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.
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 Quebec, approximately 99% is from renewable sources. With an installed capacity of approximately 37.2GW, 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.
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 CAD1.043 billion. That threshold rises to CAD1.565 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 CAD415 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. 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.
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.
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, 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.
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 the 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.
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.
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); generators connected to the distribution system (ie, distribution tariff credits); storage facilities (ie, tariff treatment, market participation and alternative use to transmission facilities); and owners of distribution facilities (ie, review of performance-based regulation framework).
In October 2020, the OEB’s governance structure was amended under the Fixing the Hydro Mess Act, 2019. The OEB’s restructuring sought to, among other things, increase accountability and encourage a greater separation between the OEB’s management, administrative and adjudicative functions. This was achieved by introducing the following new statutory offices within the OEB:
Furthermore, the IESO is in the process of formulating the necessary market rule changes to implement its Market Renewal Programme over the next two to three years.
See 3.1 Principal Climate Change Laws and/or Policies.
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.
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 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.
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, eg, 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.
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.
IESO market rules provide for inter-jurisdictional energy trade as well as for the export of capacity.
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.
Hydro-Québec operates 15 existing interconnections with the Province of Ontario, the Province of New Brunswick, the State of New York and New England. Two additional interconnections with the north-eastern states are currently under study, including the Hertel–New York interconnection project, which consists of building a 400 kV underground direct-current line that will connect to the 1,250 MW Champlain Hudson Power Express project to serve the clean electricity needs of New York City, and the 1,200 MW New England Clean Energy Connect Project linking Quebec to Massachusetts via Maine and New Hampshire. The new 320 kV direct-current line between Quebec and the State of Maine obtained final approval from the Canada Energy Regulator in May 2021 but the timing of construction in Maine is now uncertain because of local opposition and a citizen initiative to be decided on 2 November 2021.
Canadian Electricity Supply Mix 1
Jurisdiction – Canada total
Total 2020 generation (TWh) – 626.5.
Jurisdiction – Alberta
Total 2020 generation (TWh) – 81.5.
Jurisdiction – British Columbia
Total 2020 generation (TWh) – 69.5.
Jurisdiction – Manitoba
Total 2020 generation (TWh) – 31.7.
Jurisdiction – Saskatchewan
Total 2020 generation (TWh) – 22.9.
Jurisdiction – Ontario
Total 2020 generation (TWh) – 143.8.
Jurisdiction – Quebec
Total 2020 generation (TWh) – 212.6.
Jurisdiction – New Brunswick
Total 2020 generation (TWh) – 10.3.
Jurisdiction – Newfoundland and Labrador
Total 2020 generation (TWh) – 44.9.
Jurisdiction – Nova Scotia
Total 2020 generation (TWh) – 6.9.
Jurisdiction – Prince Edward Island
Total 2020 generation (TWh) – 0.7.
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: “...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.
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 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 early Q2 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).
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.
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 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.
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 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.
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:
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. Beginning in 2023, the strategy proposes to increase the price of carbon by CAD15 per tonne each year, until it reaches CAD170 per tonne by 2030.
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 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 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.
In 2008, British Columbia enacted the Carbon Tax Act, which applied a broad-based carbon tax. As of 1 April 2021, the carbon tax rate is CAD45/tonne of carbon dioxide equivalent, scheduled to increase to CAD50/tonne on 1 April 2022. 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 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.
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.
As of 1 April 2019, Ontarians have been subject to the federal carbon tax. However, with effect from 1 January 2022, eligible emitters in Ontario will become 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.
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. 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 programme to help reduce the greenhouse gas emissions in the province. The new programme was enacted through amendments to the Environment Act and the adoption of 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 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.
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’s Clean Energy Act restricts the operation and use of thermal generation by BC Hydro, except for in 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 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.
SaskPower currently has three coal power plants, accounting for approximately 30% of power produced. SaskPower’s goal is to reduce emissions of carbon dioxide 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.
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.
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 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 2021, the 10 MW Highfield Solar project, the province’s first utility-scale solar generation project, and the 200 MW Golden South Wind Energy project are expected to begin operation.
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.
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 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 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.
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.
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. 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 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 EAA 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 km or more 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 electrical 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 for constructing and operating 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 EAA. 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 the 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 EAA, 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 government 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 effect 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. See4.4 Proponent's Eminent Domain, Condemnation or Expropriation Rights.
Vertically integrated electrical utilities normally have monopoly rights to provide all utility services in the particular province, including the 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. See 1.2 Principal State-Owned or Investor-Owned Entities for further information on HONI.
The Electric Utilities Act governs the provision of transmission services 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 a regulated utility service. Consistent with general rate-making principles widely applied in North America, a tariff approved by the AUC must not be unduly preferential, arbitrary or unjustly discriminatory.
The OEB Act governs the provision of transmission services 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 a regulated utility service. Transmission rates are intended to recover a transmitter’s predicted revenue requirement, including a return on capital. Consistent with general rate-making principles widely applied 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 services are bundled with the costs approved for generation and distribution services 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, this 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 predicted 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.
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, Quebec, New Brunswick and Nova Scotia each have a form of an Open Access Transmission Tariff (OATT), which is modelled on 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 electrical utility on Prince Edward Island has applied to its regulator for approval of a form of 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 obliged to provide system access service on the Alberta transmission system in a manner that provides all market participants wishing to exchange electrical 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 on 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 which 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 the approval of the municipality in which the distribution facilities are to be developed. In some provinces, such as Alberta, the right to provide utility services 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 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. See 4.4 Proponent's Eminent Domain, Condemnation or Expropriation Rights.
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 electricity 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 electricity 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 a regulated utility service. Consistent with general rate-making principles widely applied in North America, a tariff approved by the AUC must not be unduly preferential, arbitrary or unjustly discriminatory.
The provision of and operation of electricity 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 a regulated utility service. Distribution rates are intended to recover a distribution company’s predicted revenue requirement, including a return on capital. Consistent with general rate-making principles widely applied 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
Generally, in provinces that have vertically integrated utilities, the costs approved by the regulator for distribution services are bundled with the costs approved for generation and transmission services 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, this 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 the 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 AUC endeavours to issue its decision within three months of the completion of the hearing.
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.
Energy Innovation and Transition in Canada
In our summary of Trends and Developments this year, we have decided to pick up on the dominant theme of the moment – the path to net zero and the requirements for this sector to transition and innovate from what it has done in the past and how it has done it. In this respect, we consider geothermal energy, the increased role of hydrogen in the energy mix and the renewed focus on distributed energy resources. Each has a role to play on the path to net zero in Canada, and each area draws upon expertise and knowledge that exists in abundance in the Canadian energy sector but each will require new approaches to funding, with business models measuring successful outcomes.
Geothermal in Canada
Geothermal is a sustainable, abundant and developing energy resource. While on a global basis, countries have used this form of energy production for decades, we are seeing increased interest and new technologies championed as a method to reduce greenhouse gas emissions. Accordingly, the Canadian geothermal energy industry will continue to see significant project advances in 2021, with a growing number of pilot projects currently underway.
What is geothermal energy?
The heat required for non-polluting geothermal energy is naturally occurring and is produced from deep within the Earth. The energy is produced from wells that are drilled into the Earth’s crust and through which heat energy is extracted, typically by using water and steam. There are several uses for geothermal energy depending on the location of the well and the temperature of the water or heat. Low-to-medium temperature geothermal resources are useful for water and space heating purposes. High temperature geothermal resources (greater than 150°C) can be harnessed to produce electricity by using the (fresh or brine water) steam produced from geothermal heat to turn generator turbines.
Although geothermal energy is currently a small player in Canada’s energy mix, a number of promising attributes and recent innovation has led to increased interest in geothermal technology as a stable source of renewable energy. One of the key advantages of geothermal energy is its reliability and consistent power generation, meaning it has the potential to provide baseload electricity (ie, it can meet minimum power demand levels 24 hours a day, 365 days a year). Furthermore, after construction, geothermal energy emits low-to-zero greenhouse gases. Concerns with geothermal energy include the accidental release of CO2 and hydrogen sulphide emissions stored in the Earth’s groundwater that is often used to carry geothermal heat to the Earth’s surface. Additionally, the upfront costs for geothermal energy production are relatively high; it is expensive to carry out the seismic sensing, test well drilling, and other necessary preliminary investigations to ensure new geothermal plants will be capable of meeting desired production. Canada is uniquely positioned to meet these challenges, as its oil and gas industry can provide a significant portion of the required expertise (fracking, horizontal drilling, seismic) and infrastructure necessary to establish a booming geothermal industry.
Geothermal development in Western Canada
The highest temperature geothermal reservoirs in Canada are located in the Western Provinces and Territories. These provinces and territories have recently implemented measures to stimulate geothermal energy investment, and a number of promising projects in these jurisdictions are currently in development.
The government of Alberta recently passed the Geothermal Resources Development Act (the "Act") to establish a licensing regime for deep geothermal resource operations. The Act is modelled on the provincial Oil and Gas Conservation Act and will be managed by the Alberta Energy Regulator (AER). As with oil and gas operations, a licence will be required to drill or operate a well (or to rework an existing well or facility for geothermal purposes) and the AER has broad discretionary authority over compliance and enforcement, operational matters, monitoring, and closure activities. Alberta has several projects in development and it is expected that more will be announced over the next year. Terrapin Geothermics Inc’s "Alberta No 1" project is Alberta’s first conventional geothermal power facility. In development near Grande Prairie, Alberta the facility aims to generate approximately 10 MW of baseload power, as well as also providing 985 TJ/year of baseload heat to a nearby industrial park.
Eavor Technologies is using a “closed loop” power generation facility near Rocky Mountain House, Alberta. The technology uses two vertical wells which connect many horizontal wells in a closed buried "pipe" system. Eavor then uses its "fluid" to circulate this system and collect the heat from the geothermal resource. This heat is then used to generate electricity.
Tapping into both federal and provincial funding resources and straddling carbon-based energy and renewables, a subsidiary of Razor Energy Corp (a junior oil and gas company) is developing a geothermal-natural gas hybrid power project near Swan Lake, Alberta. The first stage is expected to produce up to 3 MW of green geothermal electricity. In the planned second phase of the project a natural gas turbine will be added to optimise the geothermal power efficiency. Upon completion of both stages, this energy transition project is expected to generate 21 MW of electricity, 30% of which would be classified as renewable.
While Saskatchewan does not have legislation specifically relating to geothermal projects, it has included a number of geothermal projects in its Integrated Resource Information System, the province’s business support system that facilitates the development and regulation of the energy and resources industry. The government of Saskatchewan, along with the federal government, is funding Saskatchewan's first 20 MW power plant. The project is being developed by Deep Earth Energy Production Corp, and the project is targeted for construction completion in early 2022.
Like the AER in Alberta, the BC Oil & Gas Commission oversees all aspects of geothermal development in British Columbia. Given that British Columbia is situated on the Pacific Ocean “Ring of Fire”, British Columbia has legislation protocols in place for the development of geothermal resources. British Columbia's legislation includes the Geothermal Resources Act and the related Geothermal Operations Regulation. The Clarke Lake Geothermal Development Project, wholly owned by the Fort Nelson and Saulteau First Nations, recently received a CAD40 million commitment from the federal government and is expected to generate 7–15 MW of clean electricity and will be operational by 2024.
Like any emerging venture, geothermal energy requires significant capital investment from both the public and private sector to spur further development. On a national scale, Canada’s renewable position is currently dominated by wind and hydro technologies. Given technological advances and proper investment, geothermal energy has the potential to diversify Canada’s renewable energy portfolio as the easily accessible high-temperature geothermal resource basins offer Canada an advantage that many other jurisdictions do not have. With the large availability of subsurface data from oil and gas development and current drilling infrastructure, Canada can leverage its expertise in well exploration to establish a foothold in geothermal electrical production. Provided further legislative and regulatory schemes are implemented to attract investment opportunities, geothermal energy could provide a substantial portion of Canada’s energy needs. An established geothermal energy industry in the country would also help Canada meet its emissions reduction goals, while also creating economic opportunities for the communities where geothermal facilities are located.
The Hydrogen Economy
The Canadian government, in December 2020, issued its “Hydrogen Strategy for Canada” (the “Strategy”). The Strategy signals the growth of a hydrogen economy to be a priority, as part of the broader initiative of energy transition and innovation to drive a low-carbon future, but also as a means to drive a post-COVID-19 pandemic economic recovery. In this respect, the Strategy follows the lead shown by a number of countries worldwide. From a Canadian perspective, the Strategy cites the potential for clean hydrogen to “deliver up to 30% of Canada’s end-use energy by 2050, abating up to 190 Mt-CO2e of GHG emissions.” The Strategy is in addition to several provincial hydrogen initiatives, including in Alberta and Quebec.
Hydrogen in Canada today
Canada is presently a top-ten global producer of hydrogen, with its 3 Mt production of hydrogen coming predominantly from steam methane reformation processes, which use natural gas as a feedstock and produce CO2 as a by-product. This produces “grey” hydrogen (which is not the path to a low-carbon future), although the Quest Carbon Capture and Storage Project at the Scotford steam methane reformer units in Alberta, is a notable exception, with CO2 being captured and stored as part of that hydrogen production process. Grey hydrogen is predominantly used in Canada as feedstock in petroleum refining, bitumen upgrading, ammonia production, methanol production and steel production.
The Strategy anticipates both “blue” or low-carbon hydrogen and “green” or zero-carbon hydrogen being part of the initiative. Blue hydrogen would be produced from natural gas using the carbon-intensive steam methane reformation process but, as with the Quest Carbon Capture and Storage Project, production would be coupled with carbon capture and storage to significantly reduce emissions. Zero carbon or green hydrogen would be produced by electrolysis of water, using power generated by non-emitting projects.
The goal is two-fold: (i) green and blue hydrogen to replace the grey hydrogen used in Canada today, and (ii) increasing the role of hydrogen in the energy supply mix. Increased use of hydrogen could include for storage of excess power and generation of power, in fuel cells to power vehicles and as a direct substitute for hydrocarbons. The Strategy also envisages Canadian-produced hydrogen to be a key part of the global trade of hydrogen.
Increasing the presence of hydrogen in the Canadian energy supply mix and increasing its demand will be impacted by cost parity, with the relative cost of blue and green hydrogen compared to hydrocarbons (and grey hydrogen) being key. Reduction of supply-side costs (equipment, renewable power, raw materials, transportation) is obvious to ensuring success (and there will be a number of ways of achieving this). On the demand-side of the energy mix, policy makers and regulators will need to address the challenge of levelling the playing field; to ensure the true cost of carbon-intensive fuels is paid by end-users and/or to mandate, in certain applications, the increased adoption of hydrogen through regulation.
Another challenge is exemplified by a recent precedent, that of Canada’s attempt to become a leader in the global production of LNG. With over 20 projects at one time vying to export LNG from Canada, there are now just a handful of liquefaction projects still in development, with just one having taken a positive FID (two further positive FIDs are potentially coming in 2021). Challenges with the Canadian regulatory process, contributing to issues relating to the cost of development in Canada, have made the export of LNG from Canada a case of an opportunity missed, but perhaps not lost – it is hoped that hydrogen exports do not go the same way.
What comes next
The hydrogen economy as a driver to a low-carbon future presents a number of fascinating regulatory, legal and commercial issues that will need to be addressed at each step of the value chain. In Canada, however, it does seem that a hydrogen economy will be a key component in a low-carbon future, as it ensures that the oil and gas industry has a place in and can provide a bridge to, that low-carbon future. This is critical given the importance of this industry to the Canadian economy but, in addition, it would also appear to play to Canada’s strengths. Canada is the fourth largest producer of natural gas globally, and existing infrastructure and expertise in the oil and gas sector would appear to make blue hydrogen an obvious opportunity for domestic supply and export.
Furthermore, Canada’s power generation capacity is among the lowest for carbon intensity in the world, with significant hydroelectric and nuclear capacity and increasing renewables capacity, making production of green hydrogen a natural fit given this generation mix.
In order to seize the opportunity, however, policy and regulatory changes will be necessary at federal and provincial levels. The Canadian government signalled its intent in its most recent budget, by moving to reduce supply-side costs for hydrogen production by introducing changes to tax legislation to facilitate increased deductibility of costs for developers (through capital cost allowances) and indicated that investment tax credits will also be offered to encourage development. Similar incentives are anticipated at provincial level.
In addition to the provision of incentives, increasing stringency in carbon-pricing regulation will be key but, given the political sensitivity of this issue, the identity of the political party in government will continue to have significant bearing on this issue. Federal regulation in the form of the Clean Fuel Standards is in the process of being implemented, intended to drive lower-carbon intensity in liquid fuels (and potentially encourage adoption of alternative technologies for transportation). Additional regulation in relation to vehicle emissions, zero-emission vehicles, emission-free zones and de-carbonisation of natural gas networks have also been highlighted as necessary, but as yet still remain forthcoming – more will need to be done.
Distributed Energy Resources
A key trend in the Canadian electricity sector is the proliferation of technology aimed at increasing efficiency and reducing emissions. In many Canadian provinces, rapid advancements in technology, specifically, distributed energy resources (DERs), have been brought into focus by net-zero targets being set and the role that DERs may play in this. However, the existing regulatory framework governing the construction and operation of electrical systems also needs to evolve at the same pace. The following discussion will identify a few of these challenges and identify trends for the modernisation of the regulatory framework.
What are DERs?
There does not appear to be agreement on a prescriptive definition of DERs between jurisdictions. In the Alberta Utilities Commission’s (AUC's) Distribution System Inquiry (24116-D01-2021), DERs have been defined by the AUC to include any technology that is connected to the distribution grid and affects the supply of and/or demand for electricity. DER technologies can include supply-side (ie, solar panels), demand-side (ie, load shedding) or energy storage facilities (ie, battery storage).
Whereas DERs have been defined by the Ontario Energy Board (OEB) in a presentation "Defining the Scope & Approach to Work Based on Stakeholder Input" (20 February 2020) as “any resource capable of providing energy services located at the distribution system level (in front or behind the meter)”. The working definition states that:
What are the benefits and issues with DERs?
DERs are generally seen as a positive development which may contribute to the reduction in CO2 emissions, decreased use of transmission lines, increased self-consumption, and the increasing independence of customers from the centralised power grid. Moreover, there is strong consensus among regulators and utilities that DERs can help avoid or defer investment in new distribution capacity (subject to the decision by the AUC, discussed below). Further studies are required to determine whether DERs provide other ancillary benefits such as distribution resiliency and reliability, reducing distribution operation and maintenance costs and increased voltage and power quality.
Local governments in Canada have also recognised the need to reduce CO2 emissions (eg, the City of Toronto’s climate action strategy) and DERs may assist local governments in achieving their net-zero objective. DERs employ small-scale technologies to produce, store or dispatch electricity closer to the end use of power. In many places, implementation of DERs results in decentralisation of the power grid and reduced reliance on large, remote power stations that have traditionally been carbon intensive (ie, coal or natural gas fired generation in Alberta).
DERs, however, may create operational and economic issues for electrical utilities. The implementation of DERs within the current regulatory framework in Alberta and Ontario, for example, poses several challenges. One of the primary issues with DERs in the current provincial regulatory framework is tariff avoidance, which was succinctly set out by the AUC:
"[...] tariff avoidance is a key motivation for installing DERs. This incentive is present in all DER-related installations and configurations used for self-supply, including supply-side DERs, demand-side DERs, self-supply with export and microgrids. Transmission and distribution tariffs, in conjunction with rate designs that have historically focused primarily on recovering total revenue requirements, rather than sending accurate price signals, and which have relied on, and are constrained by, simple metering arrangements, have created strong incentives to avoid tariffs. As explained [...] tariff avoidance leads to cost shifting among customers, and uneconomic bypass of the grid, contrary to the public interest. Left unchecked, cost transfers resulting from tariff avoidance will strengthen the incentive for other customers to similarly bypass the system, exacerbating the harm and launching a vicious cycle of rising utility rates and more customers choosing to bypass the system by way of self-supply."
Future rate design will need to address the primary consequence of tariff avoidance, which is cost shifting from one group of customers to another, and the restrictions placed on utilities, particularly in relation to ownership and control of DERs, from replacing tariffs lost to DERs. Furthermore, changes to legislation may be needed to broaden and align the permitted use of non-wire solutions by allowing contracts for DERs to be capitalised, thus allowing utilities to earn a return on their investment.
Current status of DERs in Ontario and Alberta
Ontario and Alberta are seen as leaders in Canada for the development of a regulatory framework to deal with DERs. The OEB convened three proceedings to develop a more comprehensive regulatory framework that facilitates investment and operation of DERs on the basis of value to consumers, and supports effective DER integration so the benefits of sector evolution can be realised: (i) Utility Remuneration (EB-2018-0287); (ii) Responding to Distributed Energy Resources (EB-2018-0288); and (iii) by combining (i) and (ii) into the Framework for Energy Innovation: Distributed Resources and Utility Incentives (EB-2021-0118). The OEB is in the process of studying DERs and soliciting comments from parties interested in contributing to the development of a DER regulatory framework in Ontario.
The AUC convened proceeding 24116 and released its final report on its Distribution System Inquiry on 19 February 2021, examining the need to modernise Alberta’s distribution system to realise benefits from advancing technologies. As a result of feedback from stakeholders, the AUC committed to a number of actions to address identified undue regulatory barriers to new technology adoption, such as:
It is not clear when the AUC will propose changes to its governing legislation to remove regulatory barriers and allow new electricity technologies to develop.
Looking ahead in the electricity industry
Both the OEB and AUC recognise the need for amendments, to the least extent possible, to existing legislation, regulations and rules to accommodate DERs and to address issues that may not have been contemplated at the time of drafting. Furthermore, both regulators also appear to acknowledge that transition in the electricity industry is already underway. The AUC has indicated that the most efficient solution to the uneconomic bypass issue is to set rates based on the costs to produce and deliver network services.
On 7 June 2021, the AUC issued Decision 26090-D01-2021, wherein the AUC phases out distribution connected generation (DCG) credits, on a declining basis, over a four-year period because they unnecessarily increase the payments ratepayers make for transmission service, and these additional payments are not offset by a proven quantifiable benefit to the ratepayers. There were several findings in this decision of interest to DERs:
While neither the OEB nor the AUC has provided comprehensive direction on how issues related to DERs will be addressed, there are several areas where changes or clarifications can be expected: