Electricity sector in Canada

Nameplate capacity

Total generation by type

Utilities generation by fuel

Note: Ontario eliminated coal in 2014.

Electricity per person and by power source

In 2009 the Canadian production of electricity was 18,566 kWh per person and domestic use about 94% of production (17,507 kWh/person).^[29] In 2008 the OECD average was 8,991 kWh/person.^[30] 64.5% of Canadian domestic electricity use was produced with the renewable sources. The non renewable electricity use, i.e. fossil and nuclear, in Canada in 2009 was 6,213 kWh/person, respectively in UK 5,579; Germany 5,811; Denmark 4,693; Spain 4,553; Finland 11,495 and the United States 12,234.^[29]

Alberta

The Sheerness Generating Station, near Hanna. Commissioned in 1986, the 760-MW coal-fired power plant is a joint venture between ATCO and TransAlta.

Alberta was the first Canadian province to implement a deregulated electricity market. The market was established in 1996, following the adoption of the Electric Utility Act, the year before. Local distribution utilities, either investor- or municipally owned, retained the obligation to supply and the 6 largest utilities were assigned a share of the output of existing generators at a fixed price. The province moved to full retail access in 2001 and a spot market, under the Alberta Electric System Operator, was established in 2003. After consumers complained about high prices in 2000, the government implemented a Regulated Rate Option (RRO), as a means to shield consumers from price volatility.^[1]

The generation sector in Alberta is dominated by TransAlta, ENMAX, and Capital Power Corporation, a spin-off of Edmonton's municipally owned company EPCOR. Although 5,700 MW of new generation was added and 1,470 of old plants were retired between 1998 and 2009,^[39] coal still accounted for 73.8% of utility-generated power in 2007, followed by natural gas, with 20.6%.^[40]

Installed capacity reached 12,834 MW in 2009, with coal (5,692 MW) and natural gas (5,189 MW) representing the bulk of the province's generation fleet. Recent additions to the grid have increased wind capacity to 657 MW, while hydroelectric capacity stands at 900 MW.^[39] Despite tougher new emission measures announced by the federal government in June 2010, industry officials believe the province will continue using coal to generate electricity into 2050.^[41] Syncrude's Mildred Lake and Aurora North Plant Sites, the coal fired Sundance Power Station and the coal fired Genesee Generating Station are the top three sources of greenhouse gases in Canada.^[42]

British Columbia

BC Hydro's Revelstoke Dam (1984).

BC Hydro was created in 1961 when the government of British Columbia, under Premier W. A. C. Bennett, passed the BC Hydro Act. This act led to the amalgamation of BC Electric Company and the BC Power Commission, and the creation of the British Columbia Hydro and Power Authority (BCHPA).^[43] BC Hydro is the main electric distributor, serving 1.8 million customers in most areas,^[44] with the exception of the Kootenay region, where FortisBC, a subsidiary of Fortis Inc. directly provides electric service to 111,000 customers and supplies municipally owned utilities in the same area.^[45]

Between 1960 and 1984, BC Hydro completed six large hydro-electric generating projects, including the 2,730 MW W. A. C. Bennett Dam and Gordon M. Shrum Generating Station and Peace Canyon on the Peace River, Mica and Revelstoke on the Columbia River, Kootenay Canal on the Kootenay River and Seven Mile Dam, on the Pend d'Oreille River.

A third dam and 900 MW generating station on the Peace River, the Site C dam near Fort St. John, has been discussed for decades and was rejected in the early 1990s.^[46] In April 2010, the British Columbia government announced moving the project to a regulatory review phase.^[47] A notice of Site C construction commencing in 2015 was issued July 2015.^[48] Revelstoke Dam built in 1984 was the last new dam built by BC Hydro.

The province's Liberal government has promoted the construction of a slew of small-scale hydro projects by private businesses. As of April 2010, 63 long-term power purchase agreements have been signed with Independent Power Producers for 2,629 MW of capacity and 10.3 TWh of energy.^[49]

In 2015 Hydropower made up 87% of total generation, the rest being biomass, wind and some natural gas.^[50]

BC Hydro via Powerex trades electricity eastward with Alberta and south to all of the western US through the Pacific-Intertie. In 2014 BC had the largest volume of electricity imports in Canada (9700 Mwh), from the Western Interconnection in the US which is 60% fossil fueled.^[50][51] BC Hydro typically imports power during off-peak hours when thermal plants in the US and Alberta have excess power for sale, Then exports hydropower during peak hours when prices are higher.^[52]

Manitoba

The Pine Falls Generating Station on the Winnipeg River

Manitoba Hydro is the crown corporation in charge of electricity generation, transmission and distribution in Manitoba. Its installed capacity stands, as of 2015, at 5,701 MW, mostly generated at 15 hydroelectricity generation stations on the Nelson, Saskatchewan, Laurie and the Winnipeg Rivers.^[53]

The company has completed the 200-MW Wuskwatim hydroelectric project in partnership with the Nisichawayasihk Cree Nation, with first power from the project in June 2012. By advancing the completion date of the project by 3 years, Manitoba Hydro hopes to cash in on lucrative exports in the Midwestern United States.^[54] The utility is currently building a new 695 MW station at Keeyask on the Nelson River, expecting completion in 2019.^[55]

The utility is also planning the construction of a third HVDC power line linking northern Manitoba and the Winnipeg area. The Bipole III project involves the construction of a 1,364 km power line and two new converter stations.^[56] With Keeyask under construction, Manitoba Hydro has also undertaken studies of one more large hydroelectric project, the Conawapa generation station.^[54]

New Brunswick

TransAlta's Kent Hills Wind Farm (2008), near Moncton. Renewable energy advocates believe New Brunswick can bolster its investments in wind power by using a community-based approach.^[57]

New Brunswick has a diversified generation mix, featuring fossil fuel, hydroelectric and nuclear capacity. Established in 1920, the provincial utility, NB Power owned 3,297 MW of installed capacity as of March 31, 2008.^[58] Since then, the company retired 2 power plants and plans to permanently shut down the 300-MW oil-fired Dalhousie generating station.^[59]

In the last decade, the government-owned utility has faced problems with the failure of a plan to switch two of its large thermal facilities to Orimulsion, a heavy bitumen fuel produced by PDVSA, the Venezuelan government oil company, and a 2-year delay in the mid-life refit of the Point Lepreau Nuclear Generating Station.^[60]

In October 2009, the provincial government signed a memorandum of understanding with Quebec to sell most of NB Power's assets to Hydro-Québec. The controversial deal was cancelled in March 2010.^[61][62]

Since then, a couple of options are discussed to modernize New Brunswick electricity infrastructure, including a plan to build a 500-MW intertie with Nova Scotia^[63] and a preliminary agreement with France's Areva to evaluate the feasibility of a second nuclear generating station at the Point Lepreau site.^[64] However, the nuclear expansion plan was shelved within hours of the election of a Progressive Conservative government led by David Alward in September 2010.^[65]

Newfoundland and Labrador

Newfoundland and Labrador Hydro, a subsidiary of government-owned Nalcor Energy, has an installed generating capacity of 7289 MW and is the fourth largest of all utility companies in Canada. It owns and operates most generation in the province, the transmission grid and sells directly to large industrial customers. The company also serves remote communities not connected to the main power grids, on Newfoundland and in Labrador.

Newfoundland Power, a subsidiary of St. John's-based Fortis Inc., is a regulated distributor serving 239,000 customers, making up 85% of all electricity consumers in the province. The company buys 90% of its energy from Newfoundland and Labrador Hydro.^[66]

Newfoundland and Labrador mainly relies on hydropower for its generation needs, supplemented by the 500-MW Holyrood Thermal Generating Station, near St. John's. The province's main power station, the 5,428-MW Churchill Falls Generating Station, was commissioned between 1971 and 1974. The generating station is owned by the Churchill Falls Labrador Corporation Limited, a joint venture between Newfoundland and Labrador Hydro (65.8%) and Hydro-Québec (34.2%). Most of the output of the plant is sold at a fixed price to the Quebec utility under a 65-year power purchase agreement due to expire in 2041.^[67][68]

The Lower Churchill Project is a planned hydroelectric project in Labrador, to develop the remaining 35 per cent of the Churchill River that has not already been developed by the Churchill Falls Generating Station. The Lower Churchill's two installations at Gull Island and Muskrat Falls will have a combined capacity of over 3,074 MW and have the ability to provide 16.7 TWh of electricity per year. The Muskrat Falls Generation Facility will consist of a dam, a spillway, and a powerhouse with four Kaplan turbines and a total generating capacity of 824 MW. Construction of the Muskrat Falls Generation Facility began in 2013 and is expected to be complete in 2019.^[69]

Nova Scotia

NS Power's 500-MW Tufts Cove Generating Station, in Dartmouth, near Halifax.

Nova Scotia Power Inc. (NSPI), a subsidiary of Halifax-based Emera, is the public utility in charge of the generation, transmission and distribution of electricity in Nova Scotia. Formerly a government-owned company, it was privatized in 1992 by the conservative government of premier Donald Cameron, in what was called at the time the biggest initial public offering (IPO) in Canadian history.^[70] From the $816 million proceeds, "$616 million was used to recapitalize Nova Scotia Power by paying down debt owed by the utility".^[71]

NS Power has a generating capacity of 2,293 MW:^[70] 5 thermal plants fired with a mix of coal, petroleum coke, fuel oil and natural gas, provide the bulk of the 13 TWh yearly supply. The company also operates the Annapolis Royal Tidal Generating Station, the only one of its kind in North America and 33 hydroelectric generating stations,^[70] most of them small ones, with the exception of the 230 MW Wreck Cove Generating Station,^[72] inaugurated in 1978.^[70]

Over the years, NS Power has been blamed by Nova Scotia residents for its poor maintenance record and its failure to quickly reconnect customers after storms.^[73] In September 2003, 700,000 Nova Scotia residents were without power for up to two weeks after the passage of Hurricane Juan.^[74] The Category 2 storm damaged 27 main transmission lines, several transmission towers, 117 distribution feeders, and 31 major electrical substations.^[75] More recently, the issue of the company's investment in the provincial grid has been raised at a leaders' debate during the 2009 election campaign.^[76] The company received praise from premier Darrell Dexter for its efforts in restoring power after the passage of Hurricane Earl in September 2010.^[77]

For information on the small utility cooperative of Riverport and public utility electric distributors (of Lunenburg, Mahone Bay, Antigonish, Berwick and Canso) see those towns' main articles. For information on their cooperative see Municipal Electric Utilities of Nova Scotia.

Ontario

The Bruce Nuclear Generating Station near Kincardine, is the world's largest nuclear station with an installed capacity of 7,276 MW (gross).

The Erie Shores Wind Farm, near Port Burwell.

Ontario electricity generation mix (totaling 132.1 TWh) in 2017.

Electricity is generated in Ontario from nuclear power, hydroelectric power, natural gas^[78] and renewables such as wind, solar and biomass. Total production in 2017 was 132.1 TWh (i.e. 132.1 billion kWh.)^[79] The various sources of generation used in 2017 are shown in the pie chart to the right. In April 2014, Ontario eliminated coal as a source of electricity generation.^[6][7] The generation mix for the current hour can be viewed at the Independent Electricity System Operator (IESO) webpage.

As noted above, total electricity production in Ontario 2017 was 132.1 TWh. Adding imports of 6.6 TWh and subtracting exports of 19.1 TWh^[80] leaves 119.6 TWh usage within Ontario. With an estimated 2017 population of 14,193,384,^[81] electricity usage per person in Ontario in 2017 was 9,307 kWh per year, or about 60% of the Canadian average shown in the table Electricity per person and by power source displayed earlier in this article. (Note that this number includes all use—commercial, industrial and institutional use as well as household use—and it is at the point of production, i.e. before subtracting transmission and distribution losses.) Usage per person in Ontario may be lower than the national average because natural gas is more widely available and has a significant cost advantage for heating.

Ontario has been considered a summer peaking grid since 2000,^[82] however due to particularly cold winter temperatures and moderate summer temperatures, Ontario was winter peaking in 2014.^[83] In its 18-Month Outlook issued September 2014, the Independent Electricity System Operator (IESO) predicts a winter 2014–2015 peak of 22,149 MW under a normal weather scenario, and a summer 2015 peak of 22,808 MW, also under a normal weather scenario.^[84] The all-time record for Ontario demand was set on August 1, 2006, when peak demand for electricity reached 27,005 megawatts.^[85] (See 2006 North American heat wave.)

Overall, Ontario is a net exporter of electricity. Ontario imports electricity, primarily from its neighbouring provinces of Quebec and Manitoba (both of which are primarily hydroelectric systems), and exports electricity, primarily to Michigan and New York State,^[80] which rely heavily on fossil fuels—coal in the case of Michigan,^[86] and natural gas in the case of New York.^[87]

In 2017, Ontario's gross exports were 19.1 TWh,^[80] i.e. roughly equal to half its hydro generation of 37.7 TWh in 2017.^[79] (Although Canada is the world's third-largest producer of natural gas,^[88] Ontario imports natural gas from the United States and from western Canada.) If all the carbon emissions associated with natural gas-fueled generation were allocated to the exports, almost all the electricity consumed within Ontario would be from non-carbon or carbon neutral sources. (Note however that the natural gas generation is not necessarily coincident with exports and natural gas plants sometimes need to be operated due to regional transmission constraints, and as backup for wind generation^[89] which is intermittent and somewhat unpredictable.)

Ontario embraced nuclear power in the 1970s and 1980s, building 3 major nuclear facilities and 18 CANDU reactors, which in 2013 provided 59% of the province's electricity production, or kilowatt-hours equal to 65% of the electricity consumed within the province. The completion of the Darlington Nuclear Generating Station in 1993, "at a cost several times the original estimates", caused huge rate increases and a reassessment of Ontario's electricity policy. Three major policy documents, the Advisory Committee on Competition in Ontario’s Electricity System (1996), chaired by former federal minister Donald Macdonald, a government White Paper on electricity policy (1997) and the Market Design Committee report (1999) paved the way for a major overhaul of the industry.^[1]

In April 1999, Ontario Hydro was split into five successor companies: Ontario Power Generation (OPG), in charge of generation; Hydro One, a transmission and distribution utility; the Independent Market Operator, responsible for the operation of a deregulated wholesale electric market in the province; the Electrical Safety Authority and the Ontario Electricity Financial Corporation, in charge of the $38.1 billion stranded debt, derivatives and other liabilities of the former integrated public utility.^[90]

In 2001, OPG leased Canada's largest power plant, the Bruce Nuclear Generating Station to Bruce Power, a private consortium originally led by British Energy, reducing its share of the provincial generation market to 70%. The government opened the competitive market on May 1, 2002, but heat waves and droughts in the summer of 2002 caused wholesale prices to soar to peaks of $4.71/kWh in July and $10.28/kWh in September. Faced with bitter complaints from consumers, the Ernie Eves government announced a price freeze for small customers while leaving the wholesale market intact, on November 11, 2002.^[1]

Although Eves was praised for the pause in generation market deregulation the cancellation of Hydro One's initial public offering and his handling of the 2003 North American blackout, the Progressive Conservatives were defeated by Dalton McGuinty's Liberals in the provincial election of 2003. In the meantime, the phasing out of coal-fired generation — including North America's largest coal plant, the 3,640-MW Nanticoke Generating Station — became a political issue. In 2002, the Conservatives promised to shut down Ontario's 5 coal plants by 2015, while McGuinty committed to a 2007 retirement date, which was pushed back to 2014.^[91]

In April 2009, the Ontario legislature passed the Green Energy Act establishing feed-in tariffs for power from renewable sources and streamlining the approval process for new generation sites.^[92] Two months after passing the bill, Ontario announced the suspension of a competitive process for the purchase of 2 new nuclear reactors at Darlington, citing the price tag, later evaluated at $26 billion.^[93] Critics of the government strategy stress the Act will increase the price of electricity and undermine the system's reliability,^[94] while pitting some local residents against wind developers.^[95]

The impact of the Act has been notable in terms of the price impact on end consumers. Since 2009, electricity prices have risen by 95% for homeowners and by 115% for small businesses in the province of Ontario.^[96]

As of June 2018, Ontario's wind capacity stood at 4,412 MW.^[97] As of 2010, Ontario's wind capacity represented more than a third of Canada's total.^[98]

Prince Edward Island

The North Cape wind farm.

Prince Edward Island is the only Canadian province without a hydroelectric power station. The province is largely dependent on imported power from NB Power generation facilities in New Brunswick. Two submarine power lines provide more than 80% of the provincial load. Since the early 2000, the provincial government has promoted the province as a good place to set up wind farms.

Maritime Electric, a subsidiary of St. John's-based Fortis Inc., operates the integrated public utility serving most of the province, with the exception of the city of Summerside, which has been providing electric service to its residents since 1920. Both utilities own and operate diesel plants, used as peakers or during emergencies.

Electricity rates in Charlottetown are the highest of the 12 large Canadian cities surveyed by Hydro-Québec in its annual compendium of North American electricity rates. According to the document, a residential customer using 1,000 kWh per month would pay 17.29 cents/kWh, a rate two and a half times higher than the one paid by consumers in Montreal, Winnipeg or Vancouver.^[38]

In November 2009, Premier Robert Ghiz hoped to reduce the price of electricity while limiting atmospheric emissions by opening talks with the government of Quebec for a long term supply agreement.^[99][100] Negotiations, with Hydro-Québec, and other suppliers, including current supplier NB Power, are ongoing.^[101][102]

Québec

The underground Robert-Bourassa generating station is Canada's largest hydroelectric plant. The 16-unit plant has an installed capacity of 5,616-MW.

The Quebec electricity sector is dominated by Canada's largest utility, government-owned Hydro-Québec. With an installed capacity of 36,810 MW, including 34,118 MW of hydropower, the utility generated and bought 203.2 TWh in 2009, almost one-third of all electricity generated in Canada. Benefiting from low generation costs, favorable interest rates and high export prices, Hydro-Québec paid $10 billion in dividends to the Quebec government between 2005 and 2009.^[68]

Since 2003, the company commissioned 8 new hydroelectric generating stations for a total of 2,343 MW^[103] and is currently building 6 new power plants: Eastmain-1-A (768 MW) and Sarcelle (150 MW) scheduled for 2012,^[104] and 4 generating stations on the Romaine River (1,550 MW) to be commissioned between 2014 and 2020.^[105] Hydro-Québec's latest strategic plan, released in 2009, outline a further 3,500 MW of new generation capacity, including 3,000 MW of additional hydro projects, to be built by 2035. The company's total investments in generation, transmission, distribution and energy efficiency for the 2009–2013 timeframe are expected to reach $25.1 billion.^[106]

Quebec also intends to increase its wind generation capacity. The government's 2006 energy strategy calls for the construction of 3,500 MW by 2015.^[107] Two calls for tenders initiated in 2003 and 2005 resulted in the signing of 22 20-year Power Purchase Agreements between Hydro-Québec and independent power producers, for a total capacity of 2,990 MW.^[108] A third one, geared at small-scale community- or First Nations-led projects, is expected to be completed by the end of 2010.^[109] The province got 99% of its electricity from renewable sources in 2013.^[110]

Saskatchewan

Boundary Dam Coal Fired Generating Station in Estevan

In 2007, Saskatchewan produced 12,362 GWh of electricity through its coal-fired power plants, on a total generation of 20,278 GWh. SaskPower, the government-owned public utility is the main power generator in the province. The company has a generating capacity of 3,371 MW and 17 generating facilities. These include three coal-fired baseload facilities (1682 MW), five natural gas-fired plants (674 MW), seven hydroelectric developments (854 MW), and two wind farms (161 MW). Two independent power producers, the Cory and Meridian cogeneration stations have a combined capacity of 438 MW, while 5 waste heat facilities have a maximum output of 31 MW.^[111]

The current state of the electric system will require heavy investments in the next decade. Discussion have been undertaken with Manitoba about building a 138-kV interconnection between the two neighbouring provinces.^[112] A new privately owned natural gas-fired combined-cycle generation turbine in North Battleford is under construction. The 260-MW facility is expected to be completed in 2013.^[113]

Yukon

Yukon Energy Corporation is the crown corporation that generates most of the power consumed in Yukon. Hydro is the main generation source, with a 93.2% share in 2007. It is supplemented by a wind turbine in Whitehorse and diesel generators in remote communities. Yukon has two separate grids. Neither are connected to the continental power grid. Yukon Electrical Company is the main distributor in Yukon.

In its Energy Strategy, released in 2009, the Yukon government has stated it wants to increase the supply of renewable energy, hydro and wind, by 20%. The government is also considering linking Yukon's two main power grids by completing the Carmacks to Stewart transmission line. No timetable has been set.^[114]

Northwest Territories

Although the Northwest Territories are not connected to the North American power grid, there are two electric networks operating in the territory, the first one in the Yellowknife area and the other in Fort Smith. In most communities, loads are served by local diesel generators. The government-owned Northwest Territories Power Corporation is in charge of power generation, while Northland Utilities, a subsidiary of ATCO, operate the distribution networks.

Nunavut

The government-owned Qulliq Energy Corporation is the only power generator serving the remote communities of Nunavut. Qulliq, operating under the name Nunavut Power, has a total of 27 diesel-powered generators, serving 25 communities. The territory is not connected to the North American power grid.

Qulliq Energy plans to build a small hydroelectric project at Jaynes Inlet, not far from the territorial capital, Iqaluit, which is currently served by two diesel generators. The 5-MW generating station, which could cost upwards of $200 million, has been delayed by lower oil prices and the financial crisis. Construction could start in 2015 or 2016.^[115]