Electricity policy of Alberta

The price of electricity had dropped in 2015 to below 4 cents/KWh for the first time since 2003, during the economic recession when oil prices, and therefore commodity prices, had decreased. The last time electricity rates were this low, was in 2003. On-peak pool prices averaged $70/MWh over the 20-year period and off-peak prices averaged $31 per megawatt-hour (MWh). On March 7, 2022 Premier Kenney announced an electricity rebate of $150. NDP energy critic, Kathleen Ganley, said that this was not sufficient and called on the UCP government to consider capping electricity rates, implementing a "rebate program or a reverse rate rider". Ganley said the government should amend the 2022 budget to "provide real relief". The UCP Minister of Natural Gas and Electricity responded that rate caps, which had been used previously did not increase future capacity and only provided short-term relief. They said that they were not fiscally responsible as future generations would pay a high cost for their implementation. When considering potential hourly power pool prices, the AESO considers market fundamentals such as the impacts of carbon pricing, the retirement of electricity generators and conversions of coal generators to gas, the price of natural gas, additions of renewable energy forms to the supply and power outages in generation units or in electricity transmission. The forecast for 2021 was $98/MWh and in 2022 it was expected to decrease by 25% to $74/MWh. In making forecasts, AESO considers Alberta Internal Load (AIL). It was projected to be higher in 2021 than 2020 because of anticipated extreme weather, pandemic recovery, oil price increase, and the province's economic growth because of oil sands production. From September 30 to December 31, 2021, TransAlta, which is one of the utility companies that dominate Alberta's generation sector, reported an increase of $405 million in profits compared to the same period in 2020. == Early history prior to deregulation ==

Compared to the rest of Canada, Alberta's cities were not large enough to be able to afford electrical systems until the 1880s and 1890s. Calgary became the first city to have an electrical system when the Calgary Electric Lighting Company (ELC) installed lights in 1887. Entrepreneurs received a permit for the construction of the Edmonton Electric Lighting and Power Company on October 23, 1891, and less than two months later on December 22 sections of Edmonton had electrical light for the first time. The permit was set to expire in 1909. In 1921, the United Farmers of Alberta (UFA) party, with origins in a small populist movement of farmers calling for publicly owned rural electrification, won a majority government, and remained in power until 1935. The estimated cost of CA$200 million was prohibitive in the 1920s. In the 1930s, Prairies were the hardest hit because of the combination of the Dust Bowl drought and the Great Depression so any plans for electrification were paused. Although all across Canada, only one in five farms had electricity by 1945, the situation for rural Albertans was complicated by the fact that the existing private power monopolies had no motivation or interest in rural electrification given the steep cost. In both the oil and gas sector and the electricity sector there were advocates of public ownership to promote, and facilitate the sectors' development while protecting them from potential private interests. The province's 1940 Royal Commission on Petroleum recommended government intervention in the embryonic oil and gas industry to promote, speed up, and expand the energy sector's development while preventing "fortune hunters" from causing "chaos" through over-production. Similarly, as in the oil and gas sector, the electricity sector had its advocates of public ownership in order to accelerate and spread electrification across the province. Despite the referendum result, the government sponsored the creation of many Rural Electrification Associations, of which some still exist today. The municipality of Edmonton, was one of the early electricity facilities to convert to natural gas from coal, when its Rossdale plant made the switch in 1955. In 1970, construction began on the Clover Bar generating station which was owned by the newly created Edmonton Power in a merger of "Edmonton's electrical distribution and power plant departments". In order to "achieve equalization of electrical rates by averaging the price of generation and transmission across the province", the Electric Energy Marketing Agency was established in 1982 with the Public Utilities Board setting the "price at which utilities sell electric energy to the agency". In a provincial-federal agreement the price of natural gas was deregulated in 1986 which resulted in a drop in the price of natural gas. Alberta let the Natural Gas Protection Plan expire. In the same year, two new departments—Energy, and Forestry and Lands and Wildlife were established replacing the Alberta Department of Energy and Natural Resources. The first coal-fired steam turbine in Alberta was the Genesee generation unit, Genesee 2, which was built in 1989 with a capacity of 410 megawatts. == Deregulation ==

Alberta has never owned and operated its own provincial power company, unlike most other Canadian provinces. In the 1990s, in response to power brownouts, the Alberta government under the premiership of Ralph Klein believed that competition would increase and prices decrease if more companies were producing power in the province. He believed that deregulation would make Alberta more attractive to business. The government created a strategy of power purchase agreements (PPAs) through which the winning bids in an auction would acquire the right to provide a portion of all the power produced in Alberta from 1996 to 2016. The PPAs would make all the decisions and cover costs of constructing power generation plants as well as bearing responsibility for all the financial risks. They would sell the power back to the grid with the "risks and rewards of fluctuating prices." With electricity generation in this deregulated market, there is competition to sell energy in the electricity market at a price that is competitively determined. Private capital builds new generation plants and owners take on financial risks. This contrasts with the vertically integrated provincial government Crown corporations in other Canadian provinces, such as BC Hydro, SaskPower, Manitoba Hydro, Hydro-Québec and, historically, Ontario Hydro, that provide some utility services, In most Canadian provinces there is a conventional cost of service regulated power system. According to Brennan, in 2008, some generation companies own both generation and transmission in Alberta. In the EOM system, decisions about where facilities will be built, which technologies and the kind of energy source to be used remains with the producer often works with private investors who assume any risks associated with those choices. In a capacity market there is less price volatility as the electricity producer is not only paid to generate power, but also to maintain a higher level of capacity to be able to respond to demand peaks. According to the IEA, from 1999 to 2009, in most provinces in Canada changes were made to the electricity sector's structure towards some market liberalization. From province to province the approaches to changing regulation and market design differed. The report said, that competitive wholesale markets were being fostered in the 1990s as part of the liberalization process. Of all the Canadian provinces, it was only Alberta that had an effective open market at the wholesale and retail level. According to the IEA, a few dominant integrated utilities provide the bulk of electricity generation, transmission and distribution services provide. The report recommended unbundling these services. == Agencies ==

In 1996, Alberta began to restructure its electricity market away from traditional cost-of-service regulation to a market-based system which included the creation of arms length electricity sector agencies under the 1996 Electric Utilities Act. They were established to oversee the province's electricity system; to create an electricity system that is "reliable", "affordable", and that also reduces pollution that harms Albertans' health and the environment, while ensuring a competitive market for industry investors. Alberta Electric System Operator (AESO) The AESO has no industry affiliation and does not own market assets. It is an independent system operator that leads the planning and operation of the Alberta Interconnected Electric System (AIES) and the Balancing Pool. AESO facilitates open access to the grid by promoting a competitive electricity market. AESO engages with the electricity industry by consulting with retailers, electricity generators, and transmission facility owners such as AltaLink, ATCO, ENMAX, and EPCOR. AECO is governed by an independent board of directors appointed by the province's energy minister. Regulated Rate Option (RRO) refers to the default regulated rate for electricity or floating rate option for small business and residential consumers that did not enter into a contract with one of the thirty retail electricity providers. RROs can change monthly. AUC regulates the five investor- and municipally owned companies that they approved to provide the Regulated Rate Option (RRO) service to AlbertansAltaGas Utilities, City of Lethbridge, Direct Energy Regulated Services (DERS), ENMAX Power. These RROs providers include Epcor Distribution and FortisAlberta for wire services, and ENMAX Power and EPCOR Energy for electricity. Based on geographic location in the province, the government has designated only one RRO electricity and natural gas provider for residential and business electricity consumers. Province-wide, there are only five RRO providers. Since then they have reported 42 EEAs, of which only two reached a level 3 in which the AESO had to call for "shedding of electricity load" or reducing service to consumers. The first occurred on July 24, 2006 While the average wholesale pool price on-peak times was approximately CA$70/MWh since 2000, and CA$31/MWh during off peak times, The Power Pool matched the lowest-priced supply with demand functioning as spot market by establishing a pool price that was revised each hour based on 60 marginal prices each minute. Following the creation of the Power Pool, the price of electricity rose significantly, from the lowest price in North America to the third highest by 2001. == Electricity generation mix ==

Coal-generated electricity was the backbone of Alberta's electrical sector. In 2013 coal accounted for 55% of the total, natural gas represented 35%, and renewable and alternative energy represented 11%. These cleaner sources included "wind, hydro, biomass and co-generation". which underlie the three Western provinces of Alberta, British Columbia, and Saskatchewan. Lignite, which is used mainly for electricity generation, is easy to mine and has been used in Alberta since the 1800s to produce electricity. Coal-fired power plants burning coal to generate electricity were the "backbone" of Alberta's electricity system. The IEA reported that Alberta had the second highest GHG emission levels in Canada (190 Mt) represented 27% of Canada's total emissions. Only Ontario was higher with 234 Mt accounting for 33% of the nation's emissions in 2006. The next biggest source of electricity came from natural gas which had increased its representation from at 29% in 2004 to 35% in 2013. By 2013, renewable and alternative energy represented 11% of the generation mix and included wind farms, hydroelectric, biomass and co-generation. By the end of December, 2021, TransAlta had completed full conversion from thermal coal to natural gas at its Keephills Unit 3 facility, which is located near Keephills, Alberta. TransAlta retired Sundance Power Station Unit 1 in 2017, 2 in 2018, and 3 in 2020, 5 in 2021. Sundance 6 was converted to natural gas in 2021. Keephills Generating Station Unit 1 in Duffield was retired in 2021. Keephills Units 2, and 3 were converted to natural gas in 2021. Both Sheerness Unit 1 and 2 were converted to natural gas in 2021 and 2020. Provincial and federal carbon prices and carbon taxes were among the factors that turned coal into a liability instead of an asset, according to TransAlta. Sundance Power Station units 4 & 5 began operations in 2021. Milner Power's H. R. Milner Generating Station in Grande Cache in west central Alberta was commissioned in 1972 as a coal-fired power station. In 2011, the Alberta Utilities Commission granted Milner's interim approval to expand from a 150-megawatt coal-fired facility to a 500-megawatt facility without any public hearing or notice of application. Concerns were raised by Ecojustice and the Pembina Institute as federal greenhouse gas regulations were coming in effect in 2015. and was fully phased out June 16, 2024. Natural gas Natural gas has been a major contributor to Alberta's electricity generation mix, second only to coal for many decades. In Alberta's oil sands, steam generated for oil extraction and upgrading activities is also used to generate power. A typical oil sands cogeneration plant captures exhaust heat from the gas turbine in a boiler or steam generator, sending low-pressure steam to a neighboring bitumen plant. Cogeneration facilities tend to operate continuously regardless of the price for power to support industrial activities. Renewables The wind sector, particularly in southern Alberta has seen significant growth from 1.1% of total generation in 2005, to 12% in 2023. In the 1950s, hydroelectric power provided 50% of Alberta's electricity, but by 2010, this has decreased to 7%. In 2018, there were no proposals for hydroelectric projects. Hydroelectricity has been Canada's biggest source of electricity historically. However, many facilities are aging and are in need of expensive repairs. The high cost of construction has often led to overruns and with many other less expensive renewable options, future hydroelectric projects should be considered with caution. Wind The first commercial wind farm in Canada, the TransAlta's Cowley Ridge wind plant, near Pincher Creek, Alberta was completed in 1993. Only 40% of wind turbines in Canada were commissioned before 2010. Over time they got bigger and taller, and their capacity and sophistication increased, according to the federal Natural Resources department's senior wind engineer. By 2010 wind capacity had reached 657 MW and hydroelectric capacity produced 900 MW. There is over 388,500 MW untapped geothermal generation in Alberta. In 2020, Alberta's total installed generating capacity was 16,515.13 MW by way of comparison. Terrapin Geothermics' CA$90-million-dollar Greenview Geothermal Power Plant (Alberta No. 1) in the Municipal District of Greenview No. 16, which is expected to be online by 2023, received CA$25.45 million in funding from Natural Resources Canada (NRCan). The facility will be the first to produce geothermal energy in Alberta. == Hydrogen ==

Pennsylvania-based Air Products is constructing a CA$1.3-billion "net-zero hydrogen energy complex" near Edmonton which when completed in 2024 will use natural gas to produce the clean-burning hydrogen fuel. Air Products already has three hydrogen facilities in the province. Hydrogen will be used to generate electricity. == Environmental policies ==

One of the Alberta's government's major legislations in terms of jurisdiction over the Energy Resources and Conservation Board (ERCB) was the 1960 Gas Utilities Act. By 2013, shale gas had become a significant part of the gas supply. A 2012 Natural Resources Canada study concluded that environmental impacts from shale gas in terms of GHG emissions were significantly less than those of coal. which corroborated findings in the United States. Based on the December 2020 IEA's tenth edition of their annual market report on coal, globally the shift towards clean energy away from carbon-intensive fuels, such as coal, to reduce GHG emissions, accelerated. The IEA report said the demand for coal had peaked globally in 2013. Factors that contributed to the decrease in global demand, included the increase in the production of gas as part of the United States shale revolution, the accelerated increase in wind and solar energy production, and increase in enactment of public policies related to climate change. In 2017 and 2018 there was a brief rebound in the demand for coal. Although the global share of electricity generation only fell from 40% in 2009 to 36.5% in 2019, most of coal-generators were in India and China. == Market components ==

Alberta's electricity market consists of six fundamental components and features. Generation Seventeen firms supply electricity into the grid. Five of those providers—ATCO Power, Enmax, Capital Power Corporation, TransAlta and TransCanada Corp.—supply about 80% of the province's generation capacity. The generation sector in Alberta is dominated by TransAlta (formerly Calgary Power), ENMAX, and Capital Power Corporation, a spin-off of Edmonton's municipally owned company EPCOR. Utility companies in Alberta also include the wind generating Bullfrog Power, TransAlta Corporation, Alberta Power limited, AltaLink, ATCO Power and FortisAlberta. Although 5,700 megawatts of new generation was added and 1,470 megawatts from old plants were retired between 1998 and 2009, coal still accounted for 73.8% of utility-generated power in 2007, followed by natural gas, with 20.6%. Calgary-based utility company TransAlta reported an increase of $405 million in the three-month period from September 30 to December 31, 2021, compared to 2020. Although 5,700 megawatts of new generation was added and 1,470 megawatts from old plants were retired between 1998 and 2009, coal still accounted for 73.8% of utility-generated power in 2007, followed by natural gas, with 20.6%. Residential sector The residential sector includes home heating and cooling systems, household appliances, water heaters, and lighting. Retail consumers have the option to buy electricity at competitive prices from third-party sellers like Just Energy or at regulated prices through the local utility like ENMAX and EPCOR. Electricity costs for end-users According to Statista in 2021, compared to other Canadian provinces and territories, the electricity costs for end-users in Alberta at 16.6 cents per kWh, was below the average of 17.9 cents per kWh. The highest rates were in the Northwest Territories and Nunavut at 38.2 and 37.6. The lowest costs were in Québec at 7.3. Manitoba at 9.9, British Columbia at 12.6, New Brunswick at 12.7, Ontario at 13, and Newfoundland and Labrador at 13.8 were all lower than Alberta. Statista said Québec's electricity was less expensive because of the number of hydroelectric dams throughout the province. Following the restructuring and deregulation that began in 1996 electricity rates for consumers increased disproportionately to the cost of generating electricity. Electricity rates in Alberta dropped to less than 4 cents per kWh in 2015. Industrial sectors The industrial sector includes mining activities, such as oil sands, coal-mining, manufacturing activities, construction and forestry. Industrial consumers account for approximately 28% of electricity consumed in Ontario. This consumption is projected to remain stable. Cross border wholesale market Alberta imports and exports according to market conditions with Montana and neighbouring provinces, British Columbia and Saskatchewan. BC and Saskatchewan have agreements with Alberta called "interties" through which the Available Transfer Capability (ATC) is specified. The power trade between the two provinces is based in part on geography. Alberta historically has had coal and natural gas, while B.C.'s generation is largely hydro-electric. Whether for reasons of temporary high demand, short supply or both, commercial parties in Alberta buy electricity from its western neighbour through Alberta Electric System Operator. By contrast, commercial parties might export electricity in Alberta during off-peak periods. During that period, B.C. uses that power to reduce its hydroelectric generation or that energy is wheeled through to the Pacific Northwest wholesale electricity market. Commercial parties in Alberta buy electricity from B.C. during periods of peak consumption, on unusually cold or hot days or when a larger-than-normal number of generators are down for maintenance. Historically, British Columbia bought electricity from Alberta during off-peak periods. More recently, purchases from Alberta tend to take place when there is an abundance of wind generation during periods of low demand in Alberta. This trade benefits both provinces to make use of their generating and storage capacity and use assets more efficiently. Also, it puts competitive pressure on power prices in both provinces. Electricity imports from Alberta represent just 3% of all imports into B.C. In fact, B.C. exports six times as much as it imports from Alberta, which helps to substantially reduce greenhouse gas emissions there. ==See also==