Energy in Alberta timeline

Overview of events and reports of fossil fuel development and Alberta energy events since 1715.


This is a brief overview of the history of energy development in Alberta since 1715. The timeline includes federal programs that affected energy development in Alberta and includes past programs and major announcements by the province’s energy department.

It is not detailed and some information may have been missed.

To find a reference, select expand all and use control F to find a term.

  • Energy history – 1700s


    The first known reference to the Athabasca oil sands is made by Captain Swan. He was a Cree chief acting as a middleman between the native hunters of the west and the fur factories of Hudson Bay. Swan tells Governor James Knight in council at York Fort in 1715 about a river feeding the Churchill River where he found “Gum or pitch.” In 1719 Swan returns to York Fort, where Henry Kelsey has replaced Knight as governor. He gives Kelsey a sample of “that Gum or pitch that flows out of the Banks of that River.”


    Alexander Mackenzie writes of bituminous seeps among Alberta’s Athabasca oil sands into which a 6-metre pole can be inserted "without the least resistance."


    The first published record of coal in Alberta is attributed to Peter Fidler. He is a surveyor, explorer, mapmaker and fur trader for the Hudson’s Bay Company. According to his journal, Fidler first observes coal near the Red Deer River at Kneehills Creek. This is a short distance from present-day Drumheller.

  • Energy history – 1800s


    Coal gas is first used to light streetlamps in London, England.


    Natural gas is piped through hollow logs to Fredonia, New York.


    Coal gas is first used in streetlamps in Montreal.


    Coal gas is first used in streetlamps in Toronto.


    Geological Survey of Canada is established to explore for coal and other minerals.


    Abraham Gesner of Halifax, Nova Scotia opens a plant in New York to convert coal into kerosene. This is a new synthetic lamp oil (replacing whale oil). The plant uses Gesner’s patented process of fractional distillation.


    American chemist Benjamin Silliman applies fractional distillation to Pennsylvania rock oil (crude oil) and discovers it produces high-quality lamp oil (kerosene).


    Natural gas is discovered in New Brunswick.


    Entrepreneurs establish small, primitive oil refineries in Ontario, eastern Europe and the U.S.


    James Miller Williams of Hamilton, Ontario creates the world’s first vertically integrated oil company. It combines all aspects of the business from exploration to retail sales into 1 company.


    Natural gas is discovered in southwestern Ontario.


    Chemical engineer Herman Frasch invents a process to extract sulphur compounds from oil using copper oxide powder. Until then, the foul smell of sulphur had prevented oil from being widely used as a fuel.


    The first coal-powered electricity generators are developed near present-day Lethbridge.


    The Geological Survey of Canada investigates Athabasca oil sands.


    Sixteen Ontario producing and refining companies merge to form the Imperial Oil Company.

    1882 to 1883

    The first coal mine in Alberta opens in Lethbridge (originally called Coalbanks) in 1882. The first mine in Edmonton opens in 1883. The Lethbridge area has more than a dozen underground coal mines with each mine in excess of 100,000 tonnes. The last of these closed in the mid-1960s.


    A Canadian Pacific Railway (CPR) crew drilling for water near Medicine Hat, Alberta accidentally discovers natural gas 55 kilometres northwest of Medicine Hat. The name of the site at the time is Langevin Siding. By 1910 it is called Carlstadt. After the First World War, the name is changed again to Alderson.

    The first CPR locomotive arrives in Medicine Hat, signalling great changes in the coal industry of the future province. The first branch line built from CPR’s main Alberta line is the North Western Coal and Navigation Company’s 174-km narrow-gauge line. It runs from Dunmore to Lethbridge in the southwest. It is constructed to carry coal from Lethbridge to sell to the CPR as fuel for its locomotives. The line contributes to greater employment in the area through coal mining, railway development, increased flow of goods and crop exports.

    Canada’s first single-phase AC generators are commissioned in Calgary by the Bow River Lumber Company and in Ottawa at Chaudière Electric.


    A second well is drilled just a few metres from the Langevin Siding site. This one produces enough gas to light and heat several buildings.


    The Geological Survey of Canada collects natural gas information and presents a paper to the Royal Society of Canada. The paper was called On Certain Borings in Manitoba and the Northwest Territory. Of course, there is no reference to Alberta, since Alberta did not become a province until 1905.


    The Canadian government establishes Banff National Park, the first national park in Canada and the second in North America. The Banff Hot Springs represent the most famous example of direct-use geothermal energy in Alberta’s history.

    The No. 1 Mine begins coal production in Canmore, Alberta. Mining at Canmore continues until 1979.


    The Banff Springs Hotel was constructed in the summer. The exterior is Rundle stone, a brown sandstone, quarried near Canmore.


    Drilling for natural gas begins in southwestern Ontario.


    Several more natural gas wells are drilled in the Medicine Hat area, producing gas for homes and factories.


    A natural gas well drilled at Niagara Falls, Ontario begins exporting gas to Buffalo, New York.


    The Canadian Electrical Association is formed to represent the industry.

    Edmonton Electric Lighting and Power Company is founded. It receives approval to build a coal-fired generating plant on the banks of the North Saskatchewan River. Source: Edmonton Power Historical Foundation


    Parliament passes a bill authorizing funds for the Geological Survey of Canada to investigate the Athabasca oil sands as a source of petroleum.

    The first hydro-generator in Alberta is built on the Bow River. Source: Centre for Energy


    Drilling begins at the Athabasca oil sands. Crews strike a reservoir of natural gas which blows wild for 21 years.


    Natural gas from Ontario is piped to Windsor, Ontario and across the river to Detroit, Michigan.


    Imperial Oil’s refinery operations are consolidated at Sarnia, Ontario.

  • Energy history – 1900s


    Prior to 1900, most of Alberta’s population lived along the main CPR railway line or along branch lines under CPR control. In the early 1900s, this trend shifts somewhat. Various railways and branch lines lay tracks farther north away from CPR’s main southern rail line. Northern rail routes are responsible for establishing early coal communities, such as Drumheller, Forestburg and Nordegg, north of CPR’s main line.


    As known natural gas supplies dwindle, the Ontario government bans exports to the U.S.

    Medicine Hat develops its own gas utility.


    Edmonton Electric Lighting and Power Company is purchased by Edmonton, becoming the first municipally owned electric utility in Canada. Source: Edmonton Power Historical Foundation


    Alberta is proclaimed a province on September 1, 1905. The province is named after Princess Louise Caroline Alberta, the fourth daughter of Queen Victoria. The inauguration ceremony features an address by Prime Minister Sir Wilfred Laurier. Approximately 12,000 Albertans are in attendance to witness the ceremony.


    2 cement plants open in Alberta, one near Edmonton and the other near Exshaw (west of Calgary) becomes the largest in Canada

    1907 to 1912

    The Alberta Legislature Building is constructed, the top 4 stories use Paskapoo sandstone from the Glenbow quarry near Calgary.

    1908 to 1909

    Old Glory is the name of the first major gas discovery. Development of the Bow Island gas field leads to the first pipelines delivering natural gas to Alberta communities.


    Calgary Power is formed. Later renamed TransAlta, the company develops into Canada’s largest investor-owned utility.


    Following the British decision to convert Royal Navy ships from coal to bunker oil, the Canadian government urges industry to find and develop domestic oil supplies.

    Martin Nordegg opens the largest mine in Alberta and creates a model town that bears his name to this day. By 1923, Nordegg was producing the largest amount of coal of all the mines in Alberta.

    Calgary Power builds the first large-scale hydro plant in Alberta, the run-of-river Horseshoe plant. Source: TransAlta


    A 270 km pipeline begins carrying natural gas from Bow Island, Alberta to Calgary. This will allow natural gas to replace coal gas as a heating, lighting and cooking fuel. The 40 cm pipeline is completed in just 86 days.

    1914 to 1918

    The First World War establishes oil as a key strategic commodity.


    May 14 is a victorious day for Arthur W. Dingman. He and his associates savour the fruits of their risk-taking with a natural gas discovery at Turner Valley on the edge of Kananaskis Country. Learn more about the Turner Valley Gas plant here.


    Sydney Ells demonstrates the first commercial use of oil sands. In 1915, he ships several tonnes of Athabasca oil sands by water, sleigh and rail to Edmonton for a road-paving experiment.

    The Public Utilities Board (PUB) becomes Alberta’s first regulatory agency with the primary responsibility of regulating utility rates and service. Since utility service is limited at the time, the PUB has extended jurisdiction over other matters. This includes the cancellation of subdivision plans, approval of utility franchise agreements, regulation of the sale of shares and securities within the province, approval of tariffs for provincial railways and approval of highway crossings by railway branch lines. Alberta Government Telephones, Alberta’s only telecommunications company at the time, also applies to the PUB for its rates.


    The Soldier Settlement Board (SSB) comes into being with the mandate to provide land for returning war veterans. The veteran would acquire title to the surface, but the minerals were reserved in the SSB name and administered by the Government of Canada.


    Oil is discovered at Norman Wells, Northwest Territories.


    Edmonton switches to natural gas for heating, lighting and cooking following completion of a 130-km pipeline from Viking, Alberta.


    The discovery of a decade earlier leads the way to a deeper zone find just a few kilometres away. Royalite No. 4 puts Turner Valley on the oil and gas map.


    The Alberta Salt Company is the first salt mine in Alberta, the salt was found along the banks of the Athabasca River.


    Karl Clark, chemist and oil sands researcher, perfects a hot water separation process while working for the Research Council of Alberta and the University of Alberta. It is the basis of today’s thermal extraction process. Learn more at the Bitumount heritage site.


    R. C. Fitzsimmons forms the International Bitumen Company and builds a small-scale pilot plant near Bitumount, 80 km north of Fort McMurray.


    Under the Natural Resources Transfer Agreement, the Dominion of Canada transfers mineral rights to the province of Alberta. It grants the province rights to all minerals, oil and natural gas. Approximately 81% of the sub-surface mineral rights are owned by the province.

    Alberta’s first royalty regulation follows a royalty system similar to the U.S. with a fixed flat percentage royalty rate such as 5%, 12.5% or 16.67%.


    Alberta Department of Lands and Mines is established.


    First Alberta Royalty Regulation.


    The Turner Valley Conservation Board is established.


    The falling price of milk affects the profitability and viability of milk producers in Alberta. To provide price stability, the Government of Alberta declares milk a public utility. The Public Utilities Commission (renamed the Alberta Utilities Commission (AUC) in 2008) begins setting the minimum price that milk producers receive (the wholesale price). The commission is also put in charge of licensing and regulating milk producers and distributors. In 1969, the Government of Alberta creates the Alberta Milk Control Board. While the AUC’s jurisdiction over the regulation of milk production is surrendered to the board, it continues to set minimum wholesale prices. In 1991 the Government of Alberta deregulates the minimum retail price of milk.


    The first natural gas export licence is issued by the federal Department of Trade and Commerce.

    1934 to 1935

    After more than 50 years of production, the second oil well to be discovered in Alberta is closed off (abandoned) with a few wheelbarrows of cement. The closing-off process is still in its infancy and abandonment operations continue until 1954.


    Alberta’s flat royalty rate on oil and gas is increased to 10%, with flexible treatment of low-value natural gas liquids.


    Nylon, the first plastic made from petroleum products, is invented.

    Under the Fuel Oil Licencing Act, Alberta’s 1,000 fuel dealers are required to obtain a licence from the Public Utilities Board.

    Oil leg is discovered in the Mississippian zone at Turner Valley.

    Rotary drilling rigs indicate oil exists at greater depths than oil found in earlier discoveries.


    The Petroleum and Natural Gas Conservation Board becomes the Energy Utilities Board (EUB), then the Energy Resources Conservation Board (ERCB). On June 17, 2013, the Alberta Energy Regulator (AER) takes over to provide full-lifecycle regulatory oversight of energy resource development in Alberta.


    Alberta shifts the royalty rates on oil from a flat rate of 10% to a choice of a 12.5% flat rate or a 5 to 15% royalty based on production levels.


    Pipeline is built from Portland, Maine to refineries in Montreal to overcome wartime danger to East Coast tanker traffic.

    1943 to 1945

    Canada’s first offshore oil well is drilled from an artificial island off Prince Edward Island to a depth of 4,500 metres, at a cost of $1.25 million. No commercial qualities of oil or gas are found.


    U.S. Army Corps of Engineers completes the Canol Pipeline. It is an expensive but short-lived pipeline system carrying crude oil from Norman Wells to a new refinery at Whitehorse, Yukon. It also carries refined oil products to Fairbanks and Skagway, Alaska.


    After drilling 133 dry holes across Western Canada, Imperial Oil strikes oil at Leduc, Alberta, on February 13. This transforms Canada into an oil-rich nation. Learn more at the Canadian Energy Museum.

    1947 to 1954

    This historical document about oil and natural gas production describes average daily production, footage drilled and money spent on exploration. It also includes a listing of leases and royalties paid for this time frame.


    Imperial Leduc No. 2 finds oil in the Devonian reef, which formed during the Devonian period, the Age of Fishes (395 to 345 million years ago). Until this discovery, oil experts believed oil could not be found from that time period. The town of Devon, Alberta is named after this.

    The Alberta royalty rate is capped at 16⅔%.


    Alberta Department of Lands and Mines is succeeded by two new departments: Lands and Forests, and Mines and Minerals.


    Oil replaces coal as Canada’s largest single source of energy. Pipelines are established to transport natural gas to Vancouver, Winnipeg, Toronto and Montreal.

    Detonation of an underground atomic explosive device is proposed to melt Athabasca oil sands bitumen to aid commercial development. Federal government denies approval.


    A sliding scale is established in Alberta Royalty Regulations.

    1950 to 1953

    First section of the Interprovincial Pipe Line Inc. (now Enbridge Pipelines Inc.) oil pipeline is laid from Edmonton to Superior, Wisconsin. It is extended to Sarnia, Ontario in 1953.


    First sulphur recovery plant is built in Alberta for sour gas (natural gas).


    Trans Mountain Pipeline Company line is completed from Edmonton to Vancouver.


    The Alberta Gas Trunk Line Company Limited (AGTL) (now called NOVA Gas Transmission Ltd.) is created to build and operate a provincewide natural gas transportation system. In 1957, Alberta gas begins to flow through the AGTL (NOVA) system.


    Edmonton Electric Lighting and Power Company’s Rossdale plant switches from coal to natural gas.


    First gas is exported by the Westcoast Energy Inc. pipeline system through Vancouver to U.S. markets.


    Construction of the TransCanada Pipelines system is completed from Alberta to Eastern Canada.

    The first diamond in Alberta was found by Einar Opdahl in fluvial gravels on the banks of the Pembina River, near Evansburg, east of Edson. The clear colourless diamond weighed 0.83 carats and sold for $500.


    The National Energy Board is created by the federal government to oversee interprovincial and international energy trade.


    The Gas Utilities Act is introduced. It is still a major part of legislation governing the jurisdiction of the ERCB. In the 1960s, urbanization and industrialization increase the number of utility customers by 62%.


    Alberta establishes air-quality standards that include limits on industrial emissions of hydrogen sulphide and sulphur dioxide.

    National oil policy directs that all refineries west of the Ottawa Valley must use higher-priced crude from western Canada.

    The Pacific Gas Transmission pipeline (now called Gas Transmission Northwest) is built to deliver Alberta gas to customers in the U.S. Pacific Northwest and California.


    The number of steps in oil royalty is reduced to 3.

    The royalty rate on gas is increased to 16.67% with minimum deemed royalty value maintained.


    The Great Canadian Oil Sands (now Suncor) starts mining oil sands to produce crude bitumen. At this time, Fort McMurray is a small trading post.


    In the mid-1960s, Cyclic Steam Stimulation (CSS) is piloted in the Clearwater Formation. It proves to be the key to unlocking bitumen.


    Great Canadian Oil Sands initiates the world’s first large-scale oil sands operation, the Athabasca oil sands at Fort McMurray. Total production in 1967 reaches about 2,500 barrels per day.


    Natural gas and oil deposits are found off the coast of Nova Scotia.

    Roger M. Butler develops the concept of using horizontal pairs of wells and injecting steam to extract certain deposits of bitumen considered too deep for mining. Cyclic steam injection was the previous process. Butler’s invention of Steam Assisted Gravity Drainage (SAGD) technology paves the way for scores of in situ projects, changing the oil sands industry. Source: Canadian Petroleum Hall of Fame

    Alberta mineral collectors in the 1970s made the unique iridescent gemstone Ammolite popular. Ammolite or ammonite shell is the fossilized and mineralized remains of ammonite, a group of marine molluscs that became extinct approximately 65 million years ago. Ammonites are members of the cephalopod class, which includes nautilus, squid, octopus and cuttlefish.


    The Board of Arbitration is formed to handle expropriations, formerly the jurisdiction of the Public Utilities Board. The Board of Arbitration is now the Land and Property Rights Tribunal.

    Edmonton’s electrical distribution and power plant departments merge and become Edmonton Power. Construction begins on its Clover Bar generating station. Source: EPCOR


    Alberta proposes a mineral tax assessment on remaining recoverable crude oil reserves at fair value with no change in the existing royalty structure. The plan also includes an exploratory drilling incentive system. Changes take effect in January 1973. Source: Tenure in Alberta

    Federal and B.C. governments impose moratorium on West Coast offshore oil and gas exploration.


    Arab oil embargo triggers first global energy crisis. The Alberta Energy Company Ltd. is created to initiate a capital investment program and lessen dependence on foreign oil. It would later merge with PanCanadian Energy Corporation to create Encana.

    Prime Minister Pierre Trudeau decrees ‘made-in-Canada’ crude oil prices.

    Alberta implements a price-sensitive royalty regime, rather than a fixed rate.

    Alberta implements a price-sensitive royalty regime. Prior to that, royalties were paid at a fixed rate.

    The Alberta Petroleum Marketing Act creates the Alberta Petroleum Marketing Commission (APMC).


    The Natural Gas Price Protection Plan is introduced to shelter Alberta consumers from increasing world market prices for natural gas. In 2009 it was replaced by the Natural Gas Price Protection Act. In 2022, the Utility Commodity Rebate Act was established to enable rebates on electricity, natural gas or other heating fuels.

    The Petroleum Royalty Regulation allows rebates for eligible costs of injection materials for enhanced oil recovery guidelines.

    The Alberta Petroleum Marketing Commission (APMC) is created by the Petroleum Marketing Act. The commission is the provincial Crown corporation responsible for selling conventional crude that the Alberta government receives in lieu of cash royalties. The main objective is to maximize the value of the Crown’s royalties. The Crown marketing agents are contracted to sell the Crown royalty share along with their own production. This ensures a competitive market price is received for the sales of these volumes.

    The Alberta Oil Sands Technology and Research Authority (AOSTRA) is formed to promote the development of new technologies for oil sands and heavy-oil production.

    Oil and natural gas pools are classified by ‘vintage’ for royalty calculation purposes. Vintage refers to the date of discovery of the oil or gas pool from which production occurs. Royalty rates for production from newly discovered pools are set lower to reflect the higher average finding and development costs associated with newer, smaller pools. Alberta has only 2 vintages: old, discovered before 1974; and new, discovered after 1973.

    Alberta oil & gas production: 1947-1974 is a listing of conventional oil production for the time frame. It is followed by annual numbers for 1960 to 1974. It includes footage drilled, well completions, producing wells and a listing of leases and royalties paid. (Oil sands numbers begin in 1966.)


    Alberta Department of Energy and Natural Resources is created by merging two existing departments: Lands and Forests, and Mines and Minerals.

    Natural gas prices in Canada become regulated under federal-provincial agreement.


    Alberta royalty formulas are made sensitive to the level of production from the well.

    Syncrude Canada Ltd., a consortium of oil companies and the federal and provincial governments, open an oil sands mining and upgrading project at Fort McMurray. This effort, combined with the Great Canadian Oil Sands (Suncor Energy Ltd.) operation that began in 1967, increases the total mined bitumen in the province to more than 90,000 barrels per day.

    The U.S. begins the process of natural gas deregulation.


    Alberta’s first ethylene plant officially opens at Joffre. A second ethylene plant and a polyethylene plant begin production in 1984, eventually becoming the largest in North America.

    First large oil discoveries are made at the Hibernia field off Newfoundland.

    The Canadian oil industry converts to metric.


    First permanent buried pipeline is completed in the Canadian Arctic to carry light crude oil from Norman Wells to Alberta.


    In October, the National Energy Program (NEP) reinforces the 1973 made-in-Canada price policy. The NEP seeks to achieve 3 objectives: energy security (or oil self-sufficiency); redistribution of wealth between the federal government and consumers; and greater Canadian ownership of the oil industry. Many Albertans believe the NEP is an intrusion on provincial rights because resources are owned by the provinces. It passes a large benefit to central Canada and leads to a significant number of companies and jobs leaving Alberta. The NEP ended with the 1984 election. Source: Alberta Online Encyclopedia


    Calgary Power changes its name to TransAlta Utilities. Source: TransAlta


    The Constitution Act gives each province the exclusive right to make laws in relation to the development, conservation and management of natural gas in the province.

    Alberta Energy develops an online Land Status Automated System (LSAS) for all surface information in the province. Minerals are added 5 years later. This system is in place until 2011.

    The Alberta government creates the Electric Energy Marketing Agency. The Public Utilities Board sets the price at which utilities sell electric energy to the agency. The aim is to achieve equalization of electrical rates by averaging the price of generation and transmission across the province.

    The Petroleum Incentives Program Act is implemented to encourage development of oil and gas in Alberta following the 1980 National Energy Program. Source: Canada's Petroleum Heritage

    1982 to 1986

    Organization of the Petroleum Exporting Countries (OPEC) attempts to set production quotas low enough to stabilize prices. These attempts meet with repeated failure as various OPEC members produce beyond their quotas. During most of this period, Saudi Arabia acts as the swing producer, cutting its production in an attempt to stem the free fall in prices. In August 1985, the Saudis link their oil price to the spot market for crude. By early 1986, they increase production from 2 MMBPD to 5 MMBPD. Crude oil prices plummet below $10 per barrel by mid-1986. Despite the fall in prices, Saudi revenue remains about the same with higher volumes compensating for lower prices. Source: West Texas Research Group


    The Oil and Gas Servicing Incentive Program Regulation is introduced. It authorizes the minister to make grants available for eligible well-servicing costs of wells, batteries and pipelines.

    1984 to 1985

    The Progressive Conservative government under Prime Minister Brian Mulroney replaces the Liberal government in 1984. The new government signs the Western Energy Accord in 1985, eliminating the National Energy Program.


    The federal government deregulates oil prices and opens Canada’s borders to imports and exports.

    Oil Royalty holiday programs are introduced to reward successful explorers where previous grant-oriented programs only favoured activity.

    Oil royalty holiday programs are introduced to reward successful explorers. Previous grant-oriented programs only favoured activity.

    Commercial production begins at Imperial’s Cold Lake Cyclic Steam Stimulation injection project. This method involves injecting high-pressure steam into the bitumen to soften and separate it from the sand.

    1985 to 1986

    The federal government and East Coast petroleum-producing provinces reach agreements to jointly manage offshore oil and gas resources.


    Alberta, British Columbia, Saskatchewan and the federal government sign the Agreement on Natural Gas Markets and Prices. It begins the process of natural gas price deregulation in Canada.

    After 70 years of production, the Turner Valley Gas Plant is shut down. It is now a provincial and national historic site.


    The price of natural gas is deregulated by a federal-provincial agreement. With a resulting decline in natural gas prices, the provincial government allows the Natural Gas Protection Plan to expire.

    The Alberta Department of Energy and Natural Resources is succeeded by two new departments: Energy, and Forestry, Lands and Wildlife.


    Alberta Energy adds minerals to the online LSAS, which was developed in 1982. This system is in place until 2011.


    Alberta Energy publishes a monthly Alberta Average Market Price (AMP) for natural gas/residue gas, given in units of $/1000 3 and $/GJ. This test specifies that the minimum valuation price that may be applied to the Crown's royalty share of production is 80% of the AMP ($/GJ) in effect during the month of sale. The AMP is effective for the production years 1988 to 1993.


    Genesee 2, using coal-fired steam turbine equipment, is the first Genesee generation unit to be completed. Its capacity is 410 megawatts.


    Canadian refiners eliminate lead as a gasoline additive, completing a phase-out that began in 1973.

    The Royalty Simplification project is initiated by the Minister of Energy and Industry to streamline royalty calculation and processing. It continues in 1992 with an industry CEO on the steering committee.

    The Gas Utilities Statutes Amendment Act is passed by the Alberta Legislature. It gives non-industrial consumers in Alberta the choice of entering into contracts for gas supply, subject to regulations.

    The New York Mercantile Exchange starts trading natural gas futures contracts for delivery at Henry Hub, Louisiana.


    The Lloydminster upgrader begins processing heavy oil.

    The Canadian Association of Petroleum Producers is created. It merges the Canadian Petroleum Association and the Independent Petroleum Association of Canada. The association represents about 200 producers. Their collective production represents nearly 95% of Canada’s total crude oil and natural gas output.

    Royalty rates are modified and an additional vintage distinction, called “Third Tier”, is introduced for conventional oil pools discovered after August 31, 1992.

    The United Nations Conference on Environment and Development in Rio de Janeiro takes place in June. Canada and more than 160 other nations adopt a philosophy of sustainable development. They agree to begin limiting emissions of greenhouse gases that may contribute to global climate change.


    Major royalty changes are introduced, including increased price sensitivity and select price inflation indexing.

    A third tier vintage is introduced, and heavy oil vintages are separated from light.

    The Alberta Energy Company (AEC, now EnCana) starts reporting daily natural gas spot prices at its gas storage facility at AECO-C near Suffield, Alberta.

    The Cowley Ridge wind plant, near Pincher Creek, Alberta is completed, becoming the first commercial wind farm in Canada.


    Initial implementation of the new royalty system (a result of the 1990-92 Royalty Simplification project). Industry submits estimated royalty payments.

    Functions of Alberta’s Department of Forestry, Land and Wildlife are merged into the Department of Environmental Protection. The Department of Energy is reorganized into 5 new divisions. The AOSTRA is moved under the Department of Energy and eventually moves to Alberta Innovates. AOSTRA promotes the development of new technologies for oil sands and heavy-oil production.


    The Alberta Gas Reference Price is implemented. It is a monthly weighted average of an intra-Alberta consumer price and an ex-Alberta border price, reduced by allowances for transporting and marketing gas. (Gas Royalty Guidelines 1994)

    Alberta adopts the Electricity Utilities Act to deregulate the energy supply market.

    The Alberta Energy and Utilities Board (AEUB) is created. It merges the Public Utilities Board and the Energy Resources and Conservation Board (ERCB) (previously the Petroleum and Natural Gas Conservation Board). The aim is to provide a more streamlined and efficient regulatory process. In 2013 the ERCB becomes the Alberta Energy Regulator.

    A generic royalty regime for new oil sands projects is recommended. It would provide a smaller royalty share at the beginning of a development and a larger share for the government after the developers have recovered their costs.


    The EUB passes rules implementing natural gas customer choice for small consumers in Alberta.

    1996 to 1998

    Alberta establishes 3 new independent bodies (the Balancing Pool, Transmission Administrator and Market Surveillance Administrator) to ensure open and competitive access to deregulated power markets.

    1996 to 1997

    The Electric Utilities Act (EUA) passes in 1996. The AEUB holds a hearing to restructure tariffs to implement changes to the electric utility industry introduced in the EUA. Each major utility must apply to separate its generation, transmission and distribution costs. The framework for further restructuring of the electric utility industry is established through the Electric Utilities Amendment Act that passes in 1997.


    The Kyoto Protocol treaty is negotiated in December 1997 at the city of Kyoto, Japan. It comes into effect on February 16, 2005.

    The Hibernia oil platform is towed to the Hibernia oil field and positioned on the ocean floor in June. It begins producing oil on November 17. The platform stands 224 metres high, which is half the height of New York’s Empire State Building and 33 metres taller than the Calgary Tower.

    The generic oil sands royalty regime, the Oil Sands Royalty Regulation, 1997, comes into effect on July 1. It establishes generic royalty terms for all new oil sands projects. Prior to this, royalties for oil sands projects were prescribed in separate Crown agreements, or contracts, for each project. The new regime created a level play field across all projects and encouraged more projects. At the same time, the federal government extends its accelerated capital cost allowance to oil sands projects to encourage their development.

    Industry feedback indicated that royalty and related administration cost are approximately one third of the pre ‘94 level. Industry and royalty business rules and business practices continue to evolve as part of the 1990-92 Royalty Simplification project.


    Alberta Oil sands: Update on the generic royalty regime is presented in October at the 7th UNITAR conference on heavy crude. The paper explains the generic oil sands royalty regime and its implementation.

    1998 to 2006

    The Energy department conducts a royalty and related information review before setting up the 2007 Royalty Review Panel.


    Alberta Department of Energy is reorganized and renamed the Department of Resource Development. The new department is also responsible for forest industry development and rural utilities.

    In July the Ethane and NGLs task force – delivered their final report to the Minister.

  • Energy history – 2000 to 2009


    Alberta establishes retailer licensing and codes of conduct for deregulated electricity markets.

    The Alberta government implements the Energy Tax Refund.

    Following a major expansion, an ethylene-based petrochemical plant in Joffre becomes the largest co-generation plant in Canada and the second largest in the world. Source: Centre for Energy

    Alliance natural gas pipeline begins commercial service after construction is completed from Fort St. John, B.C. to Chicago, Illinois.

    Syncrude’s Aurora project is the first remote oil sands plant in Alberta. The project costs about $600 million. Source: Syncrude.

    Based on the success of the Alberta Oil Sands Technology and Research Authority, the government broadens its focus on energy research. It creates the Alberta Energy Research Institute (AERI) to explore more opportunities and technologies related to energy and greenhouse gas emission research. AERI will eventually grow into Alberta Innovates in 2010.


    Alberta Department of Resource Development becomes the Department of Energy.

    The Alberta government provides rebates to consumers of natural gas as natural gas prices reach record levels. Later in 2001, the Natural Gas Price Protection Act is implemented to develop a formal structure for the 2003 Natural Gas rebate program.

    The electric utility industry is restructured. The Energy Utilities Board no longer regulates wholesale electricity prices and customers can choose their electricity retailer.

    Alberta Justice files a statement of claim on behalf of Alberta Energy. The claim is for the Soldier Settlement Board minerals and revenues earned by Canada since October 1, 1930. Returning war veterans were given surface titles in 1917.


    Natural gas in coal, or coalbed methane (CBM), is commercially produced in Alberta for the first time. In late 2002, an internal review begins of government rules and regulations related to CBM development. This review also includes the collection of CBM production and geological data.

    BioGem Power Systems partners with the Iron Creek Hutterite Colony to build Alberta’s first commercial biogas system. The system uses manure produced at the colony as its feedstock and sells electricity into the provincial grid.

    AltaLink assumes control of Alberta’s largest transmission system (previously owned by TransAlta) to become the first independent transmission provider in Canada. Source: AltaLink.

    The natural gas royalty framework is revised to be based on in-stream components.

    Cenovus Foster Creek becomes the first commercially viable steam-assisted gravity drainage (SAGD) project. This would soon become the key recovery method for extracting in-situ bitumen.

    Alberta’s first propylene facility becomes operational in Redwater, processing off-gas from the Suncor Energy Inc. oil sands upgraders.

    The Alberta mineral development strategy was developed to enhance the potential development of base and precious metals, gemstones, industrial minerals and other solid minerals.


    The Alberta government passes the Electric Utilities Act, to further develop a fair, open and competitive electricity market. Under the act, the Power Pool of Alberta merges with the provincial transmission administrator to form the Alberta Electric System Operator (AESO). AESO is an independent system operator that manages the competitive electricity wholesale spot market.

    2003 to 2009

    The Natural Gas Rebate Program ran from January 2003 to March 31, 2009 to protect consumers from high natural gas prices.

    In September 2003, a pre-consultation is held with a number of coalbed-methane stakeholder groups to identify and prioritize issues. Landowners, agriculture producers, academics, the energy industry and environmental groups participate. This leads to the formation of the Coalbed Methane/Natural Gas in Coal Multi-Stakeholder Advisory Committee (MAC). A MAC historical document outlines the terms of reference, preliminary findings and progress into MAC II. MAC provided advice and guidance on the Coalbed Methane consultation process. In 2006, MAC presented its final report, Coalbed Methane/Natural Gas in Coal. One of the recommendations out of MAC was the government should set up a process to facilitate issues around split-title ownership, in 2009, the Freehold oil and gas issues: stakeholder consultation report explored options.

    2003 to 2004

    In December of 2003, Alberta became the first jurisdiction in North America to put a price on carbon by passing the Climate Change and Emissions Management Act. The act outlined mandatory reporting for every person who releases or permits the release of a specified gas into the environment as outlined in Specified Gas Reporting regulation that came into effect in January of 2004.


    Changes are introduced to Alberta’s retail electricity and natural gas industries, providing consumers with a choice of utility retailers. A customer choice website is developed to help Albertans select providers. This later becomes the Utilities Consumer Advocate.

    For the first time in Alberta’s history the total annual bitumen production exceeds 1 million barrels per day.

    2004 to 2009

    An industry/government task force is established to explore competitive opportunities with the refining and petrochemical industries. The Hydrocarbon Upgrading Task Force and related reports are produced in this 5-year span.

    2004 to 2013

    The $200-million Innovative Energy Technologies Program (IETP) was created to drive innovation, research and technology development. The program was fully subscribed in 2013 and is no longer accepting applications. The IETP provided royalty adjustments to 40 pilot and demonstration projects that used innovative technologies to increase recoveries from existing reserves and encouraged the responsible development of oil, natural gas and in situ oil sands reserves.

    Successful applicants received a royalty adjustment of up to 30% of approved project costs, industry provided the remaining project costs. The total industry/government commitment to this fully subscribed program was $1.15 billion with Alberta Energy contributing $195 million in royalty credits and industry contributing the remaining $955 million. This cost will be recovered over time with increased resource volumes.

    The IETP contributed a portion of its funding to CO2 Royalty Credit projects. The paper, Fundamental Geochemical Processes between CO2, Water and Minerals was developed in order to provide knowledge around the mechanisms and fundamental processes.

    Successful applicants had to submit Annual and final intellectual property reports on any new technology developed. The following table lists project reports by project name linking to the non-license section of open government. Files requiring specialized software (identified in the annual report table of contents) are only available upon request. All reporting requirements under the program have been completed.

    IETP approved project reports table

    OperatorProject nameTargeted resourceFinal report
    ARC resources Ltd.03-050 Redwater Immiscile CO2 vertical pilotOil2012
    Canadian Natural Resources Ltd.01-022 Brintnell Field Horsetail polymer floodOil sands2007
     06-098 Water management through water treatment technologiesOil sands2013
     02-033 Brintnell Field Horsetail polymer floodOil sands2009
    Cenovus Energy Inc.06-101 Suffield main Sand Alkali surfactant associative polymer floodOil2017
    Cenovus FCCL Ltd.05-075 Air injection and displacement for recovery with oil horizontalOil sands2016
    Conoco Phillips Canada Ltd.01-013 Surmount SAGD pilotOil sands2008
    Deer Creek Energy Ltd./Total E&P Joslyn Ltd.01-025 Joslyn LP SAGD project phase 1Oil sands2009
    Encana Corporation3-063 Deep Basin dev. and measurement of marginal zones phase 1Gas2010
     03-064 Basin dev tight gas horizontal well stimulationsGas2009
     04-074 Horseshoe Canyon CBM high well densityGas2012
     05-081 Deep Basin dev and measurement marginal zones phase 2Gas2012
     01-003 Air injection and gas displacement solutionGas2011
     01-006 LP SAGD artificial lift bench scale testingOil sands2005
     03-053 Suffield conventional heavy oil chemical floodOil2011
    Encana/Cenovus FCCL Ltd.02-034 Air repressuring at Christina Lake SAGD bitumenOil sands2011
    Husky Oil Operations Ltd.01-023 Taber S alkaline-surfactant-polymer floodOil2011
     03-055 Advanced  alkali-surfactant-polymer processOil2012
     03-059 Rainbow Keg River O pool enhanced gas recoveryGas2010
    Imperial Oil Resources03-047 Cold Lake solvent assisted SAGD pilotOil sands2014
     06-094 Cyclic solvent test pilotOil sands2018
    Laricina Energy Ltd.03-061 Saleski oil sands pilot phase 1Oil sands2009
     05-077 Saleski SAGDOil sands2013
    MGV Energy Inc.01-024 Horizontal MGS project cancelled
    MGV/Quicksilver Resources Canada Inc.01-014 Mannville horizontal NGC projectGas2007
    Paramount/MEG Energy Corp.01-001 Gas re-injection and production experiment (GRIPE)Gas2011
    Paramount Resources Ltd.01-004 Bitumen de-methanizationGas2005
     01-005 Gas Pool prod and shut in pressure data analysisGas2005
    Pengrowth Corporation03-056 Quaternary acid gas injection Judy Creek BHL "A"Oil2010
     05-085 Bodo East associative polymer pilot floodOil2013
    Penn West Petroleum Ltd.02-030 South Swan Hills unit CO2 enhanced oil recoveryOil2010
     05-088 Horizontal multi-state fracturing low perm sandstoneOil2013
    Perpetual Energy Inc.06-095 Low-pressure electro-thermally assisted driveOil sands2017
    Petrobank Energy Resources Ltd.01-019 Whitesands experimental projectOil sands2009
    Petro-Canada02-041 SAGP process for bitumen prod using prod gas and an ejectorOil sands2007
    Suncor Energy Inc.01-018 Low Pressure SAGD artificial lift pilotOil sands2006
    CO2 Royalty Credit
    Programs (4)*
    See Alberta Innovates for more or see
    Fundamental Geochemical Processes Between CO2, Water and Minerals

    *The objective of the CO2 Projects Royalty Credit Program was to encourage projects and application of technology that would lead to the expanded production of Alberta’s oil and gas resources through use of CO2 (carbon dioxide) injection into geological formations. The demonstration projects injected a mixture consisting mainly of CO2 for enhanced recovery of oil, natural gas, or coal bed methane.

    Success stories

    The IETP has contributed to some of the largest economic and technical successes in enhanced oil recovery through its support of the first field wide polymer flood in Canada. Additionally, the IETP also funded the first Steam Assisted Gravity Drainage project in a carbonate rock formation in Alberta, with the potential to tap into an additional 300 billion barrels of bitumen.

    Taber S, alkali-surfactant-polymer flood, also known as the Taber S,ASP or alkali-surfactant-polymer flood (Project 01-023) used enhanced oil recovery (EOR) to recover more oil from wells that were considered depleted. Funding from IETP supported the first field wide alkali-surfactant-polymer flood (ASP) in Canada. The Taber S, ASP has projected incremental royalties of more than $60 million. IETP funding directly supported polymer improvements, enhanced additives, injection scheme development, improvement to water treatment technologies and continued growth in the technology.

    In 2011, A report was commissioned about IETP projects using polymers. The report shows that the anticipated incremental recovery from polymer flooding would amount to around an additional 45,000 barrels per day of production over the next 20 years. That is a reserve addition of around 300 million barrels of oil.

    Cenovus Energy Christina Lake Air Re-Pressurization project, solved an issue that is unique to Alberta's bitumen producing regions. Gas over bitumen is when natural gas pools are found above bitumen reservoirs, complicating the development of the resources. IETP funding supported the utilization of air injection to safely and effectively manage the pressures within the gas zone overlying an active Steam Assisted Gravity Drainage (SAGD) bitumen recovery project.

    Through this and other active projects Gas over Bitumen projects, it was determined that gas and bitumen recovery operations schemes (SAGD) can co-exist be effectively operated in communication with an overlying gas zone if the system is in close pressure balance. Alberta Energy commissioned an Audit of the process. Technology that allows for improved performance multiple resources from a single area translates to more royalties for Albertans.

    News releases

    Five innovative energy pilot projects to launch (April 19, 2013) backgrounder

    Province supports six innovative energy projects (July 14, 2011) backgrounder

    Province supports nine innovative energy projects (May 14, 2009)

    Province supports new projects to study innovative energy (November 13, 2007)

    Province supports three innovative energy projects (March 20, 2007)

    Projects will advance the development of province's energy resources (November 4, 2005)

    For more information email: [email protected]

    2004 to 2014

    The Alberta Energy Oil Sands Production Profile: 2004 – 2014 report gives a detailed overview of oil production volumes and extraction technologies.


    The Alberta government forms a steering group made up of representatives from environmental organizations, First Nations, industry and government. They produce Alberta’s Mineable Oil Sands Strategy (MOSS). Their draft document is Mineable Oil Sands Strategy: for discussion and their final report is Multistakeholder Committee Final Report.

    Genesee Unit 3 is completed. The 450-megawatt unit is Canada’s first generation facility to use supercritical combustion technology for greater fuel efficiency and significantly lower emissions.

    Alberta’s Electricity Policy Framework: Competitive-Reliable-Sustainable (2005), examined the regulated rate option (RRO); short and long-term adequacy; and other inter-related market issues.

    The executive committees of Alberta Energy, Alberta Environment and Alberta Sustainable Resource Development commit to strengthening the ways they work together. They adopt a sustainable resource and environmental management (SREM) approach. It involves taking joint responsibility to achieve agreed-upon natural resource and environmental outcomes. It builds upon successful models of co-operative integration such as Water for Life. It calls for a change in how the 3 departments conduct their day-to-day business, both within and across departments. It lays a roadmap to align policies and information sharing, and streamline regulatory processes. SREM produces the Land-use Framework (LUF).

    2005 to 2006

    The second-highest record land sale is recorded. In total, 9,196 parcels are sold for a total bonus of $2,165,464,637.16. The average price per hectare is $693.82. Learn more in tenure statistics.


    Alberta’s Nine-Point Bioenergy Plan is announced. It provides $239 million in bioenergy funding to support alternative energy development in the province.

    The Alberta government approves an allocation of $200 million over 4 years to create the Energy Innovation Fund (EIF). The EIF supports building world-class knowledge, expertise and leadership to responsibly develop our vast energy resources for current and future generations.

    The Oil Sands Ministerial Strategy committee is directed by cabinet to develop a co-ordinated short-term action plan to address the social, environmental and economic impacts of oil sands developments. Investing in our Future: Responding to the Rapid Growth of Oil Sands Development Final Report is released in December.

    During the first quarter, the highest average price per hectare for petroleum and natural gas sales is $774.57.

    Development of regional land-use planning begins. It starts with Albertans asking for a broader land-use management plan, followed by a series of ideas, groups and consultations. The Land Use Secretariat and the first regional advisory councils are created. The Alberta Land Stewardship Act makes it possible to support regional plans.

    2006 to 2011

    The Incremental Ethane Extraction program (IEEP) under the Incremental Ethane Extraction Regulation is established in 2006, with an approved budget of $350 million. The program provides credits to petrochemical companies that reduce greenhouse gas emissions by extracting ethane from the refinery process off-gases. The ethane is upgraded to higher-value petrochemical products such as ethylene and derivatives. The program is amended in 2011. See: Incremental ethane extraction program guidelines and ethane facilities map.


    Grants are issued from February 2007 to March 2011 under the Bioenergy Grant Program. The following 3 recipients were feature stories:

    • In 1993, the Alberta-Pacific Forest Industries (Al-Pac) pulp mill opened near Boyle, the grant enabled the company to use bark and other waste from the process to generate power for the mill. They also developed a biomethanol product for use in antifreeze, windshield washer fluid, biodiesel and other products.
    • Enerkem developed a full-scale commercial waste-to-biofuels plant, located at the Edmonton Waste Management Centre. The plant opened June 4, 2014. Operating at full production, it will convert 115,000 tonnes of waste to 38 million litres of bioethanol. In 2020, the plant reported that it was diverting about 30% of Edmonton’s waste, see trash is a biofuel treasure. The plant started making methanol in 2016, and in 2017 completed the installation of equipment to convert the methanol into higher-priced ethanol.
    • West Fraser Mills Ltd.'s pulp mill in Hinton has 5 boilers where 2 byproducts of the pulping process, black liquor and hog fuel, are burned in order to recover cooking chemicals and to produce the steam used for process heating and to generate electricity for the mill. Black liquor is comprised mainly of a wood-derived substance called lignin, while hog fuel is made up of all the waste that is left over when bark is removed from trees. The mill produces almost 260,000 megawatt hours of electricity annually. This includes 11,000 megawatt hours of electricity for the grid – enough power for more than 1,500 households.

    The Alberta government eliminates the Alberta Royalty Tax Credit Program. The decision follows a review and consultation with industry and stakeholders.

    The city of Lethbridge names Ammolite as the city’s official gemstone. 

    The Oil Sands Consultations Multistakeholder Committee Final Report and the Aboriginal Consultation Final Report are released in July. The reports set out a vision and identify principles to guide the future development of Alberta’s oil sands. The creation of the Oil Sands Sustainable Development Secretariat is recommended to address rapid growth issues in the oil sands regions of Alberta.

    The Alberta government set up an expert royalty review panel to review royalties and the tax regime for oil sands, conventional oil and gas and coalbed methane.

    The panel report is released on September 18.

    Canada’s premiers release A Shared Vision for Energy in Canada. It highlights the importance of energy conservation, supply, demand and infrastructure to Canada’s continued prosperity. In 2012, all premiers except B.C.’s agree to renew this vision.

    Drake Landing Solar Community is announced in September. The planned neighbourhood near Okotoks is heated by a district system that gathers solar energy. It stores it underground in the summer, then uses it to heat homes during the winter. Source: Drake Landing Solar Community.

    An Examination of the Alberta Energy and Utilities board Security Measures related to the Alta Link 500 KV hearing is conducted by Justice D.W. Perras.

    2007 to 2009

    Premier Stelmach announces Alberta’s New Royalty Framework on October 25. The framework increases royalties generated by an internationally competitive energy industry. From the framework: “The government will implement shallow rights reversion (SSR) to maximize extraction of the resource. Under this policy, mineral rights to shallow gas geological formations that are not being developed would revert back to the government and be made available for resale.” SSR means that the rights above the top of the shallowest productive zone in an agreement will be severed from the agreement at continuation. Agreements purchased after January 1, 2009 are subject to SRR. For more information, see Information Letter 2013-13. The Alberta Royalty Tax Credit Program (ARTC) is eliminated.

    2007 to 2011

    From 2007 to 2011 TranAlta’s built Keephills 3, it was Canada’s most advanced coal-fired facility using supercritical boiler technology which featured higher boiler temperatures, higher pressures and a high-efficiency steam turbine. To reduce sulphur emissions by 60 to 80%, but still produce the same amount of power as conventional facilities. By the end of 2021, Keephills 3 was converted from coal to natural gas.


    The governments of Alberta and Canada release Canada’s Fossil Energy Future: The Way Forward on Carbon Capture and Storage. It provides advice on how governments and industry can work together to facilitate and support the development of carbon capture and storage opportunities in Canada.

    Alberta’s Micro-Generation Regulation is introduced, making it easier for individual Albertans to produce their own renewable power. The regulation allows Albertans to generate their own environmentally friendly electricity and receive credit for extra power sent into the electricity grid.

    Syncrude is the first company to have a certified reclaimed site in the Alberta Oil Sands near Fort McMurray.

    On January 1, 2008, the Alberta Utilities Commission Act splits the Alberta Energy and Utility Board (EUB) into 2 new regulatory bodies. It becomes the Energy Resources Conservation Board (ERCB) and the Alberta Utilities Commission (AUC). The AUC is responsible for the distribution and sale of electricity and natural gas to Alberta consumers. On June 17, 2013 the Alberta Energy Regulator (AER) succeeds the ERCB to provide full-lifecycle regulatory oversight of energy resource development in Alberta.

    On June 30, 2008, Alberta Energy announces the Bitumen Valuation Methodology (BVM). The BVM determines a value to calculate oil sands royalty for bitumen produced in oil sands royalty projects where all or a substantial portion of the production is upgraded on site, sold or transferred to affiliates. The Bitumen Valuation Methodology (Ministerial) Regulation is implemented on January 1, 2009. More information is in Information bulletin 2012-07.

    The Land-use Framework (LUF) is developed under the Sustainable Resource and Environmental Management initiative.

    In November 51 kimberlite bodies were discovered in the Buffalo Head Hills area in north-central Alberta. This volcanic rock type is most likely to contain economic deposits of diamonds. These kimberlites had the highest diamond content results to date, 28 contained diamond and 3 (kimberlites K14, K91 and K252) contained estimated diamond grades of > 12 carats per hundred tonnes (cpht). The Buffalo Head Hills kimberlite K252 has the highest estimated diamond grades in Alberta with a preliminary mini-bulk (22.8 t) sample grade of 55 cpht. The biggest diamond found to date in the Ashton K14 complex, at Buffalo Hills, north of Edmonton is 1.3 carats. The diamond is a single crystal, of silvery grey appearance with many dark inclusions making it an industrial grade diamond.

    The Launching Alberta’s Energy Future: Provincial Energy Strategy is released in December 2008 to chart the course of Alberta’s energy future. The strategy is a long-term action plan for Alberta to achieve clean energy production, wise energy use and sustained economic prosperity. The Renewable Fuels Standard is part of the Provincial Energy Strategy.

    2008 to 2009

    In 2008, the Alberta government appoints a nuclear power expert panel to prepare a report on nuclear energy. In March 2009, the panel releases their report. By April, nuclear power consultation begins. It involves a workbook open for public feedback, randomly enrolled discussion groups, stakeholder discussion groups, and a telephone survey. Participants include 4,832 individual Albertans and a broad range of stakeholder groups. Results from the consultation are released on December 14, 2009 and compiled in a report. In Alberta, power generation options are proposed by the private sector in the province. Any nuclear power proposal would be considered on a case-by-case basis, the same as other power generation proposals.

    In April 2008, the Carbon Capture Development Council is created. In July 2008, Premier Ed Stelmach announces a $2-billion fund to advance carbon capture and storage (CCS) projects. The projects should reduce emissions by up to 5 million tonnes annually by 2015. In 2009, 4 project proponents sign letters of intent with the Alberta government.

    In August, the government releases a request for expressions of interest to determine if bitumen royalty in kind could work in Alberta, requests for proposal followed in 2009.


    The Alberta New Royalty Framework announced in 2007 comes into effect January 1, 2009.

    The Oil Sands Royalty Regulation 2009, the Natural Gas Royalty Regulation and the Petroleum Royalty Regulation take effect.

    The Bitumen Valuation Methodology (Ministerial) Regulation provides a method that is used to determine the value of bitumen in the calculation of royalty for oil sands projects where 40% or more of production is either upgraded on site, or sold or transferred to affiliates.

    The province announces a 3-point incentive program for the energy sector. Energy Economics - Understanding Royalty (revised December 2010) explains previous royalties in Alberta. Royalties were also compared in this commissioned report Alberta's royalty system: Jurisdictional comparison.

    The Oil Sands Sustainable Development Secretariat releases a 20-year plan, Responsible Actions: A Plan for Alberta’s Oil Sands. The Fort Hills lease substitution agreement is signed to extend the term of two oil sands leases.

    Under the Electric Statutes Amendment Act, 2009 (also known as Bill 50), the Alberta government approves the need for 4 critical transmission infrastructure (CTI) projects. It also gives cabinet the authority to designate future transmission facilities as CTI. The Electric Utilities Amendment Act (also known as Bill 8) removes this authority. It now requires all future transmission infrastructure projects to go through a full needs assessment process before the AUC. The Alberta government no longer has the authority to approve the need for future CTI. In the summer a number of electricity transmission information sessions are held around the province. An Alberta Energy poster promotes the event. The findings were published in a report, Powering our economy: Critical Transmission Review Committee Report. The government's response report was Investing in the Economy: North-South Corridor Transmission Reinforcement.

    A report was commissioned to produce an Assessment and Analysis of the State-Of-the-Art Electric Transmission Systems with Specific Focus on High-Voltage Direct Current (HVDC), Underground or Other New or Developing Technologies then the government responded with the summary of the Electric Transmission Assessment report.

    A memorandum of understanding is signed with Houston’s Rice University to share nanotech expertise to advance clean energy efforts.

    EPCOR announces plans to transfer its power generation business to the newly created Capital Power Corporation, which will operate as a stand-alone public company. Source: Capital Power.

    2009 to 2010

    In 2009, Alberta Energy’s Tenure Branch begins a business process review (BPR) of its continuation business. (Continuation refers to the system that allows lessees to retain the productive rights in their agreements past the initial term’s expiry date.) The review’s objective is to find efficiencies in continuation operational processes and improve clarity in the business rules. The project includes the creation of a BPR committee in 2010. Members include the Canadian Associations of Petroleum Producers, Petroleum Landmen, Petroleum Land Administration, and the Explorers and Producers of Canada ad Energy Resources Conservation Board (later known as the Alberta Energy Regulator).

  • Energy history – 2010 to 2019


    After 9 years of negotiations, Alberta Justice returns mineral titles and revenues earned by Canada since 1930 to Alberta. In 1917, surface land titles were provided to returning war veterans through the Soldier Settlement Board (SSB).

    Almost half of the oil sands production (47%) is collected in 2010 through in-situ methods.

    In April, the Alberta government releases Retail Market Review.

    The highest bonus amount collected by Alberta Energy in 1 year for petroleum and natural gas rights is $2.388 billion.

    More than $2.39 billion is netted in a record land sale. This surpasses every other year and is the first time the province has exceeded $2 billion in sales. The province also establishes a new high for the average price per hectare. The July 7 sale netted an average price of $2,185.03 per hectare, exceeding the previous high of $2,084.86.

    Negotiations on Bitumen Royalty in Kind (BRIK) begin in May 2010. By February 2011, an agreement is signed.

    2010 to 2011

    In May, a Royalty Competitiveness Review is announced. Industry is informed by webinar. New Well Royalty Regulation is approved in March 2011.

    Commissioned by Alberta and industry, an advanced metering study measured electricity consumption behaviour.

    The AUC is directed to gather information and report back to the minister on key initiatives on conservation, green energy sources and the regulatory process. They include reviewing the regulatory approval process for hydroelectric facilities; determining how smart grid technology can be used to modernize the electricity system; advanced metering infrastructure to help consumers make more informed decisions on wise electricity use; and reviewing the rules for the regulation of consumer choices for both natural gas and electricity.

    In April, Alberta, B.C. and Saskatchewan launch the New West Partnership. This creates an economic powerhouse of 9 million people with a combined GDP of more than $550 billion. In December, these provinces united to improve access to Asian markets. See the memorandum of understanding. In December 2011, the western premiers commit to an Ottawa mission.

    The ERCB report more than 2,300 successful oil wells were drilled in 2010, more than double the numbers drilled in 2009. (In 2014, the ERCB becomes the Alberta Energy Regulator.)

    The Regulatory Enhancement Task Force deliver reports from 2010 to 2011 to better integrate oil and gas policy and the regulatory system. In January 2011, the task force makes 6 recommendations to government in their final report Enhancing Assurance:

    • establish a policy management office tasked with developing a public engagement process, risk assessment and management approach;
    • establish a single oil, gas, oil sands and coal regulator;
    • provide a clear public engagement process;
    • establish a common risk assessment and management approach;
    • establish a performance measurement framework and public reporting mechanism; and
    • develop an effective mechanism to address landowner concerns.

    2010 to 2015

    In July 2010, the minister of energy established the Transmission Facilities Cost Monitoring Committee to review transmission facility project records. The committee reported to the Utilities Consumer Advocate the terms of reference are in Ministerial Order 64-20104. Committee reports:

    2010 to 2013

    In February 2010, the Oil Sands Administrative and Strategic Information System (OASIS) project begins to meet the anticipated growth of oil sands projects. OASIS enables project operators to create and submit oil sands royalty (OSR) project applications online, through the Electronic Transfer System (ETS). OASIS also enhances submission, validation and tracking of royalty and related information. For more information, see oil sands royalties.

    An amendment (Bill 24) to the Carbon Capture and Storage Funding Act is introduced in November 2010. It guides how large-scale CCS projects will proceed in Alberta. In March 2011, the Alberta government announces that international experts will guide commercial-scale deployment of CCS (news release). In July 2012, the ERCB approves the Quest project with conditions. In February 2013, the funding agreement for the Swan Hills Synfuels project is cancelled.


    Alberta Energy’s online Land Status Automated System originally developed in 1982 for all surface and mineral information in the province is upgraded to 2 new systems. Alberta Mineral Information (AMI) containing Crown mineral dispositions and activities is launched in January. Geographic Land Information Management and Planning System containing Alberta surface public lands is launched in March. The systems contain more than 2.3 million components. Of these, 1.5 million pertain to wells. For more information, see searches.

    The 5-year Incremental Ethane Extraction program (IEEP) that was approved in 2006 expands in 2011 to support continued growth of Alberta’s petrochemical sector. Ethane extraction during bitumen upgrading reduces greenhouse gas emissions and boosts value-added production.

    The federal government partners with industry to bring new natural gas technology to market. The federal government will contribute $750,000 towards a project facilitated by the not-for-profit industry and stakeholder association, Petroleum Technology Alliance Canada. Alberta Energy is contributing $250,000 towards the total project cost. A clean energy centre is established for biomass technologies.

    Alberta implements a Renewable Fuels Standard on April 1. It requires an annual average of 2% renewable diesel in diesel fuel and 5% renewable alcohol in gasoline sold in Alberta.

    In June, the Alberta Electric System Operator (AESO), the province’s electricity system planner, releases a long-term transmission plan.

    In July, Alberta hosts Canada’s energy and mines ministers’ conference in Kananaskis. A Canadian energy strategy is discussed and a national action plan review scheduled for 2012.

    In October, the AUC introduces changes to utility disconnection and reconnection practices to protect vulnerable customers. This AUC initiative co-ordinates energy companies, social agencies and the privacy commissioner.

    The Oil Sands Information Portal launches in November. It allows easy access to data, making Alberta industry information more transparent. It includes searchable data, highlighting things such as facility-specific water use, greenhouse gas emissions, tailings pond size, and land disturbance and reclamation.

    2011 to 2012

    The AER commissioned a 2 phase technical factor study to determine Enhanced Oil Recovery (EOR) potential in Alberta, economic factors like oil prices and future estimates are not addressed in this study. Identification of Enhanced Oil Recovery Potential in Alberta – Phase 1 created an analyzed an inventory to determine potential success factors then Identification of Enhanced Oil Recovery Potential in Alberta – Phase 2 used findings in phase 1 to apply screening criteria to all oil pools in Alberta.

    In December 2011, the Critical Transmission Review Committee was charged with reviewing timing, technology and forecasts in the AESO’s plan for critical transmission infrastructure between Edmonton and Calgary. CTRC also identified appropriate changes to the Electric Statutes Amendment Act, 2009 in their report, Powering our economy: Critical Transmission Review Committee Report. The government’s response was, Investing in the Economy: North-South Corridor Transmission Reinforcement. In March, the Alberta government appoints the Retail Market Review Committee (RMRC), an independent committee to review the electricity retail market. They are to help address the volatility and costs associated with the variable, or default, rate in Alberta’s competitive market.

    Electricity planning is on the schedule for the last quarter of 2011 and the first quarter of 2012. In December, the Alberta government announces the Critical Transmission Review Committee. This independent expert panel will examine plans for 2 high-voltage transmission lines between the Edmonton and Calgary regions. Their report is released in February. Ten days later, the government accepts the recommendations, issues a response and agrees to review the variable, regulated retail electricity rate. In March, the Alberta government appoints the Retail Market Review Committee (RMRC), an independent committee to review the electricity retail market. They are to help address the volatility and costs associated with the variable, or default, rate in Alberta’s competitive market.

    2011 to 2014

    The RMRC makes recommendations to strengthen the electricity market. The Power for the people and Highlights are released in January 2013 with 41 recommendations. Of those, 33 recommendations are accepted in principle and referred to an MLA implementation team. The team works with consumers, industry, regulators and others to ensure effective, affordable and sensible solutions are in place. Finally in December of 2014, the MLA-RMRC implementation team reports on the recommendations from the RMRC to benefit electricity consumers.

    The RMRC makes recommendations to strengthen the electricity market. The RMRC Report and Highlights are released in January 2013 with 41 recommendations. Of those, 33 recommendations are accepted in principle and referred to an MLA implementation team. The team works with consumers, industry, regulators and others to ensure effective, affordable and sensible solutions are in place. Finally in December of 2014, the MLA-RMRC implementation team reports on the recommendations from the RMRC to benefit electricity consumers.


    The New West Partnership (Alberta, B.C. and Saskatchewan) announce new rules to streamline registration on July 1, 2012. In September 2012, Premier Redford and other members promote the New West Partnership in China.

    The Oil Sands Sustainable Development Secretariat produces Comprehensive Regional Infrastructure Sustainability Plans (CRISP). CRISP is the new long-term and collaborative approach to planning infrastructure in Alberta’s 3 oil sands areas.

    Canadian premiers agree to develop a Canadian Energy Strategy. Strategy documents can be found on the Canada’s Premiers site.

    On June 7, the Plains Midstream Canada’s Rangeland pipeline has a release into the Red Deer River via Jackson Creek. Premier Redford issues a statement the following day.

    On July 9, 2012, rolling electrical outages occur across the province. They are caused by generation outages combined with minimal wind generation and record-high demand for power. The Alberta Electric System Operator (AESO) is the independent agency that manages Alberta’s electricity grid. It requests transmission facility operators and distribution companies to curtail power to prevent system failure.

    Under the EU pathway study, several reports were commissioned to study the lifecycle of the GHG associated with crude oils used in the European Union.

    On August 22, the Lower Athabasca Regional Plan is announced. It is the first regional plan under the Land-use Framework (LUF).

    The Responsible Energy Development Act passes. It is a 1-stop approach, making it easier for Albertans and industry to navigate the system.

    In November, the Petroleum Registry of Alberta becomes Petrinex (Petroleum. Information. Excellence.).

    In-situ bitumen production exceeds mined production in a calendar year for the first time. In-situ production was about 992,000 barrels per day (bbl/d) or 52% and mined production was 930,000 (bb/d) or 48%.

    2012 to 2015

    In July, Minister Hughes requests that the ERCB retain an independent third party to examine elements of the province’s pipeline system. The ERCB issues a Request for Proposal (RFP) on the Alberta Purchasing Connection website. On September 10, the ERCB announces that Group 10 Engineering Ltd. has been awarded the contract. (ERCB becomes the Alberta Energy Regulator (AER) during the contract). On August 23, 2013 the Group 10 final report and Appendices are released to the public and feedback is gathered. In March 2015, the Auditor General audits Alberta’s pipeline safety and recommendations. The AER responds with a report for the Minister of Energy.


    On June 17, the AER succeeds the ERCB and is given more powers through regulatory enhancement. This includes a new registry for surface agreements and the authority to administer the Public Lands Act for energy projects.

    On July 25, the Alberta government announces an Urban Development Sub-region of more than 55,000 acres of Crown land for urban expansion in Fort McMurray.

    Alberta signs the historic Framework Agreement on Sustainable Energy Development with China to increase energy trade and collaboration between the 2 jurisdictions.

    In December, the AER launches the Private Surface Agreements Registry (PSAR) as part of a Phase 2 implementation of the Responsible Energy Development Act. Under PSAR, landowners and occupants can register surface agreements made with energy companies operating on their property. If a landowner feels that a company is not meeting a term or condition of a registered agreement, they can request that the AER intervene. If the AER determines that the company is not meeting the terms of the agreement, it can issue an order to comply.

    The Building New Petroleum Markets Act is passed under the Petroleum Marketing Act (Bill 34). It boosts the government’s ability to respond more quickly to changing market conditions and empowers it to proactively seek out opportunities for Alberta’s energy products. The legislation allows the minister of energy to set the strategic priorities of the Alberta Petroleum Marketing Commission (APMC).

    2013 to 2014

    On December 19, the Independent Joint Review Panel recommends approval of the Northern Gateway pipeline. The recommendation, which was sent to the federal cabinet for final approval, marks a critical milestone toward getting Alberta’s oil to new international markets. Ministers respond to the Gateway decision in a news release. Alberta Energy commissions an Arctic Energy Gateway report to examine the technical feasibility of producers transporting bitumen blend from the oil sands north to the Beaufort Sea coastline to access world markets in the Asia-Pacific region and the Atlantic coasts.


    The AER completes its transition under regulatory enhancement to a single regulator for energy development in Alberta on March 31. In June an agreement is signed with Mexico to work collaboratively on regulatory best practices in the development of hydrocarbon resources.

    Alberta celebrates 100 years of oil and gas exploration with the centennial of the Dingman #1 well discovering oil in the Turner Valley. The Canadian Association of Petroleum producers (CAPP) produces a video celebrating the anniversary.

    In October Premier Prentice issues a statement encouraging the National Energy Board to review TransCanada's Energy East application.

    Also in November, Canada’s Gas Tax Fund supports local infrastructure priorities throughout Alberta.

    Alberta commissions a report to study detection and monitor methods for wellbore leakage, Toward a Road Map for Mitigating the Rates and Occurrences of Long-Term Wellbore Leakage.

    A report, the Energy Potential and Metrics Study – An Alberta Context was commissioned to explain energy availability, energy density and the environmental impact of a wide range of energy resources and pathways in Alberta.


    In June, steps towards a climate change strategy and a royalty review chair are announced to set up the 2015 Royalty Review Panel.

    On August 28, 2015, the Government of Alberta announced the establishment of the Royalty Review Advisory Panel. The mandate of the Panel was to identify opportunities to optimize Alberta’s royalty framework for crude oil and liquids, natural gas and oil sands.

    The energy minister visits the Nexen spill site in July. Premiers adopt the Canadian Energy Strategy (CES) at the 56th Annual Premiers’ Conference.

    The Alberta Royalty Review is officially underway in August. Community engagement sessions are announced the following month and telephone town halls with more community sessions in October.

    In November, the Climate Leadership Plan looks to transition away from coal and have 30% of the electricity grid supplied by renewable energy by 2030.

    Bitumen Quality was reviewed anonymously through aggregated assays in the Bitumen Assay Program (BAP) Aggregate Assay Information.


    Premier Notley’s statement on Alberta NEB submission supporting Trans Mountain pipeline is sent to the National Energy Board on January 12. See Alberta's NEB submission.

    Alberta’s New Royalty Framework is released on January 29, forming the Modernized Royalty Framework.

    The Petrochemicals Diversification Program is announced in February. It encourages companies to invest in the development of new Alberta petrochemical facilities by providing up to $500 million in incentives through royalty credits. Of 16 applications submitted, 2 approved projects are announced in December.

    The investment of more than $5 million is announced in February to help municipalities and farmers harness the power of the sun and support local jobs. This is part of Alberta’s Climate Leadership Plan.

    In March, Premier Notley supports the Canada-U.S. agreement to cut methane emissions and the signing of the Paris Agreement on climate change. Minister McCuaig-Boyd and the British High Commissioner to Canada Howard Drake sign a U.K.-Alberta Low Carbon Innovation and Growth Framework Agreement. Also under the Climate Leadership Plan, Terry Boston, the retired head of North America’s largest power grid, is hired to lead discussions with coal-fired electricity generation owners as the province transitions from coal to cleaner sources of power.

    The National Energy Board announces the Trans Mountain pipeline expansion project.

    The minister of Environment and Parks establishes the Energy Efficiency Advisory Panel in June.

    July is the last month to submit applications to some bioenergy programs. Look for more information in the future under the Climate leadership plan. An oil sands advisory group is added to the plan.

    Royalty programs and an early opt-in option are announced in July under the Modernized Royalty Framework.

    Court action is launched in July to protect power consumers from paying costs of unlawful “Enron clause.”

    In September, the Alberta government announces that a firm target of 30% of electricity used in Alberta will come from renewable sources such as wind, hydro and solar by 2030.

    In October an Energy Diversification Advisory Committee is created to help diversify the energy sector and explore opportunities for more investment in Alberta’s energy industries. This initiative follows advice of the Royalty Review Advisory Panel. It recommends that Alberta seize opportunities to position the energy industry for long-term success, while building on initiatives such as the Petrochemicals Diversification Program (PDP), announced in February 2016.

    In October, several programs are announced under the Climate Leadership Plan:

    In November, 5 electricity news releases are announced:

    In November, the Oil Sands Emissions Limit Act is introduced under the Climate Leadership Plan.

    Near the end of the year, the Oil Sands Sustainable Development Secretariat closes.

    In December, the micro-generation regulation is changed to increase the size limit from 1 to 5 megawatts, allowing for more green electricity.

    The Alberta Royalty Review, initiated in 2015, resulted in changes to several petroleum, natural gas and oil sands royalty related regulations that came into effect on January 1, 2017. The updated regulations included:

    In addition, the Natural Gas Royalty Regulation and Petroleum Royalty Regulation take effect.


    The boundaries of the expanded Castle Wildland Provincial Park and the new Castle Provincial Park under regional planning are set in January. This brings one of the most biologically diverse areas in Alberta under provincial protection. The parks are announced on January 20, 2017. Public input is outlined in a news release on March first. The cancellation and compensation is covered under the Mineral Rights Compensation Regulation.

    The Leduc #1 strike was a turning point in Alberta’s history. To celebrate its 70th anniversary, the minister of Energy declares February 13, 2017 Alberta Oil and Gas Celebration Day.

    In March, the province directs the Alberta Utilities Commission (AUC) to conduct a formal study to explore greener community power generation. This would help inform government as it develops policy to meet the demand for more local electricity generation.

    A drilling activity news release in April announces an increase in new wells drilled and active rigs in the first quarter of 2017. Alberta operators drilled 1,199 wells during the first 3 months of 2017 compared with 519 a year ago. This is a 131% increase in activity, according to industry figures. This is the largest increase in activity and the highest number of wells drilled overall in Western Canada from January to March.

    The province begins working with industry and experts in May to improve policies for managing old oil and gas facilities. This would better protect Albertans and the environment. A couple of weeks later, legislation is introduced that would allow Alberta to lend the Orphan Well Association (OWA) $235 million. This will speed up proper abandonment and reclamation of a growing number of oil and gas well sites that no longer have a responsible owner. Learn more about how Alberta is addressing upstream oil and gas liability and the orphan well inventory.

    Alberta is granted intervener status on the Trans Mountain Pipeline in May. The province will be allowed to make both written and oral submissions. The judicial review is advanced by municipalities, First Nations and environmental groups. It challenges the National Energy Board’s report and recommendation as well as the federal Governor in Council’s Order in Council approving expansion.

    An Act to Cap Regulated Electricity Rates is proposed in May. The price cap program was implemented in 2017 to protect Albertans from volatile electricity prices while the province transitioned to a capacity market for electricity. With government’s decision to halt the transition to a capacity market and maintain an energy-only market in 2019, the price cap was no longer needed. The price cap ensured consumers on the RRO would pay no more than 6.8 cents per kilowatt hour for electricity until May 31, 2021.

    In June the Minister sent a submission to the National Energy Board (NEB) requesting that the NEB Act be modified

    Electricity Stakeholder consultations begin in August to work towards the Capacity Market Framework.

    Premier Notley releases a statement in August to celebrate the start of construction on the Enbridge Line 3 replacement pipeline.

    Premier Notley, Japanese representatives and local officials mark a $2-billion expansion of the Japan Canada Oil Sands Ltd. (JACOS) Hangingstone project near Fort McMurray in September. This SAGD project is the culmination of the largest investment made in Alberta by JACOS in its 40 years in the province.

    A Calgary startup is revolutionizing pipeline safety and expects to double its workforce over the next 3 years. It will do so with support from the Alberta Small Business Innovation and Research Initiative at Alberta Innovates.

    The end of 2017 brings the final investment decision by Calgary-based Inter Pipeline. Two new facilities will be built in the Industrial Heartland, near Fort Saskatchewan. They will process propane into value-added plastics products. At the peak of construction, an estimated 2,300 direct full-time jobs will be created. Once complete, the facilities will employ 180 people full-time. Inter Pipeline is approved to receive royalty credits under Alberta’s Petrochemicals Diversification Program (PDP). PDP is part of the Alberta Jobs Plan to encourage investment in developing new petrochemicals facilities in Alberta. The PDP is regulated under the Energy Diversification Act.

    Regulatory changes occur in December. The Alberta government works with the AER on amending a key requirement, known as Directive 67. Now companies that walk away from wells or other oil and gas infrastructure without cleaning up will be subject to greater scrutiny and AER discretion if they apply to start new companies. Also, Carbon Competitiveness Incentives (CCIs) replace the Specified Gas Emitters Regulation. CCIs attract investment in clean technology, protect and create jobs and diversify Alberta’s economy while reducing carbon pollution.

    Inter Pipeline is approved to receive royalty credits under Alberta’s Petrochemicals Diversification Program. In February, the Energy Diversification Advisory committee releases its final report and recommendations. The Energy Diversification Act is announced in March and passes in June.

    The Regulated Rate Option is the default electricity contract for the vast majority of Albertans. But it does not apply to Medicine Hat consumers because the city operates its own power utilities. To ensure Medicine Hat residents receive the same protections as other Albertans, the province works with the municipality to develop a regulation that keeps electricity prices stable and affordable.

    2017 to 2018

    Premier Notley speaks about pipelines in November, February, April and May.

    The Renewable Electricity Program launched in 2017 expecting to attract over $10 in investment and create of 7000 jobs, 3 companies were chosen resulting in almost $1 billion of private-sector investment in green power generation in Alberta. The successful bids have set a record for the lowest renewable electricity pricing in Canada. In 2018 the second and third rounds opened. The Alberta Electric System Operator (AESO) administered the competitive and transparent process for companies to bid on building renewable energy projects in our province. Since June 2019, no further REP rounds were administered, for more information, contact at [email protected].


    In March, an agreement is reached on the Power Purchase Arrangement.

    An Act to Secure Alberta’s Electricity Future is announced in April to create a capacity market for electricity in Alberta.

    The AER releases methane reduction draft directives in April.

    In May, 9 Alberta oil sands technologies receive more than $70 million through the Oil Sands Innovation Challenge. This will support economic growth in the oil sands sector.

    The Act to Enable Clean Energy Improvements was passed on June 6, it came into force January 1, 2019. Under the act, the Clean Energy Improvement Program (CEIP) was developed to help people make energy efficient upgrades to their properties without having to put money down. The cost of the upgrade is recovered through the owner’s property taxes. This can be paid off at anytime, repayment remains with the property. Accessing affordable financing is one of the biggest barriers property owners face when deciding to invest in energy efficiency and renewable energy upgrades. The main focus of these upgrades are on-site renewable energy such as solar power, upgraded insulation and high-efficiency heating. Municipalities that wish to participate need to pass a bylaw and will work with Energy Efficiency Alberta (EEA) to develop and deliver the program to residents. EEA will administer the program on behalf of the municipality.

    In August, the AER announces the integrated decision approach to improve approvals. To date, this approach has saved industry more than $140 million, with an expected $600 million in direct savings by 2021. In several pilots, the regulatory review was reduced from an estimated 5 years to just 15 months.

    The grand opening of Fort Hills and $400-million investment by Nexen occur in September.

    In November and December, Premier Notley announces several initiatives to protect Alberta resources: fighting for more value for Alberta oil; protecting the value of resources; and fighting for full value of natural gas.


    Production limits were introduced in January 2019 to align production with export capacity, protecting the value of the province’s oil by helping prevent Canadian crude from selling at large discounts. The initial target in January 2019 was 3.56 million barrels per day, this gradually increased to 3.81, the limit ended in December 2020. The curtailment policy expired in December 2021.

    The Royalty Guarantee Act announced in June provides certainty that no major changes will be made to the current oil and gas royalty structure for a period of at least 10 years and the production limit is changed for August and September.

    The electricity capacity market plans are cancelled in July. In fall 2019, government launched a review to examine concerns from consumer representatives about certain parties gaining too much control of Alberta’s electricity market following the expiry of Power Purchase Arrangements (PPAs). At the same time, electricity suppliers raised concerns about unnecessary market control mitigation strategies.

    In August the National Energy Board (NEB) becomes the Canadian Energy Regulator (CER).

    The electricity capacity market plans are cancelled in July 2019, then in October the Electricity Statutes (Capacity Market Termination) Amendment Act , Bill 18 received royal assent was introduced to return to an energy-only market.
    News release

    In August the National Energy Board (NEB) becomes the Canadian Energy Regulator (CER). In September the Associate Minister of Natural Gas agreed with the CER decision to revise natural gas pipeline storage during maintenance periods.
    News release

    2019 to 2020

    An AER review was announced in September in October the ethics commissioner reported and the minister asked the interim board to implement recommendations.

    2019 to 2022

    Since 2019, Ontario, New Brunswick and Saskatchewan worked together to develop a plan for small modular reactors in Canada through an interprovincial memorandum of understanding (MOU). Alberta joined the MOU in April 2021. The plan, A Strategic Plan for the Deployment of Small Modular Reactors was released in March. It highlights how SMRs can provide safe, reliable and zero-emissions energy to power our growing economy and population while creating new opportunities to export Canadian knowledge and expertise around the world.

  • Energy history – 2020 to present


    The Technology innovation and Emissions Reduction (TIER) came into effect January 1.

    Preliminary agreement with the federal government signed for methane emission reduction.

    In April, Premier Kenney issued a statement on the federal government’s energy stimulus package.

    Review finds protections are in place for the electricity market.

    The Site Rehabilitation Program is announced in April it will begin in May.

    In May, a helium royalty rate is set at 4.25%.

    Coal development news:

    The Utility Payment Deferral Program successfully supported Albertans through the initial months of the COVID-19 pandemic. More than 245,000 electricity customers and 181,000 natural gas customers – representing 16% of each consumer base – have deferred utility payments through the program, which concluded on June 18, 2020.

    The program applied to bills for residences, farms and small businesses.

    Most participants repaid their deferred payments by June 18, 2021. The outstanding payments were added to a small, temporary rate rider – a fee paid by all utility customers in the province – with one for natural gas and one for electricity. Rate riders are commonly used to address unanticipated costs incurred by a regulated utility provider. The amount was determined on August 18, 2021, by the Alberta Utilities Commission. From November 1, 2021 to February 2022, “Utility Deferral Adjustment” rate riders – one for electricity and one for natural gas – appeared on consumer utility bills.

    • Electricity rate rider – 0.045 cents per kilowatt-hour (an average residential consumption of 600 kilowatt-hour pays 27 cents per month).
    • Natural gas rate rider – 3.7 cents per gigajoule (an average residential winter consumption of 21 gigajoules pays 78 cents per month).

    The 10-year Petrochemical Incentive grant program is announced in July.

    The Carbon Capture and Storage project Shell Quest reached a milestone, since 2015, 5,000,000 tonnes of emissions have been safely captured.

    A mineral advisory council is announced to help unlock the geological potential for lithium, vanadium, uranium, rare earth elements, diamonds, and potash.

    The Natural gas vision and strategy is announced in October.

    Alberta signs a memorandum of understanding (MOU) with New Brunswick, Ontario and Saskatchewan to support the development of small modular nuclear reactors (SMRs).


    Electricity sector stakeholders were consulted in the Energy Storage engagement in April and May. The outcome was the introduction of the Electricity Statutes Amendment Act in November as a way to both address producer and consumer interactions, and use the power grid to encourage adoption and investment in emerging energy systems and technologies.

    Starting on May 1, the Preserving Canada’s Economic Prosperity Act, gave the Minister of Energy the authority, if necessary, to restrict the export of crude oil and natural gas from Alberta. A new agreement for the Sturgeon refinery was announced in July.

    Building a future for critical and rare earth minerals, was announced in November, the details of which were included in the mineral strategy and action plan.

    Hydrogen roadmap was announced during the same month, ensuring Alberta on the path to a bright hydrogen future.

    Also in November a $2.5 billion investment for a major petrochemical facility is announced for northwest Alberta as part of the recovery plan.

    The Technology Innovation and Emissions Reduction (TIER) program announces through Alberta Innovates that the program's 23 projects are expected to support a total of 1,307 project-related jobs for Albertans while contributing $169 million to the province's GDP.

    Also in November, an MOU is signed to expand market access with Japan.

    The year ends with the expiry of the curtailment policy on oil production limits and the delivery of a coal policy report.


    The first progress report on methane emissions reduction indicates the reduction goal will be reached by 2025. Emissions from the oil and gas sector decreased by about 34% between 2014 and 2020.

    A MOU is signed in January strengthening Alberta’s relationship with Alaska.

    On March 4th, all new coal-related exploration and development activities in the Eastern Slopes was restricted, the reinstated 1976 coal policy also remains in place.

    The Electricity Statutes (Modernizing Alberta’s Electricity Grid) Amendment Act, 2022 was proclaimed on March 6.

    In mid-March, the province invested $13 million to support 22 projects through Alberta Innovates. Thirteen projects are receiving funding through the Digital Innovation in Clean Energy (DICE) program and nine through the Clean Resources business unit.

    On March 23, 2022, the Government of Alberta issued an order-in-council directing the Alberta Utilities Commission (AUC) to inquire into and report to the Minister of Energy on matters relating to hydrogen blending into natural gas distribution systems. This hydrogen inquiry report published in June represents a summary of the Commission’s findings, observations and considerations for options for this inquiry, based on feedback from stakeholders on a variety of hydrogen blending related issues and its own expertise.

    Alberta: a leader in responsible energy development is a report released in May. It outlines how the province has taken care to develop its energy resources in a manner that exceeds its environmental and social responsibilities by working with industry, Indigenous communities, the public and researchers to create a cleaner energy future.

    AESO released a Net-zero Emissions Pathways Report in June.

    A pilot project in Alberta’s industrial heartland is announced in August to reduce red tape, streamline regulatory approvals and help attract new investment, the Industrial Heartland Designated Industrial Zone framework will pilot in September for an October implementation.

    Alberta calls on the federal government to streamline natural gas export project approvals in September.

    A fall Utilities Consumer Advocate advertising campaign reminds Albertans about their options for purchasing energy for their homes and a natural gas rebate program is announced for October, how the rebate works was explained, see the affordability action plan for more information.

    A Carbon Capture Utilization and Storage update in October announced 19 new proposals for a total of 25 proposals in 2022.

    In November, more than $161 million in funding is announced for the Alberta Petrochemical Incentive Program (APIP) to grow Alberta’s clean hydrogen sector, the first project is an expansion of a Fort Saskatchewan ethylene production facility.

    New and amended regulations are planned for the mineral strategy in December.


    Alberta seeks input on developing hydrogen fuelling stations to help support future low-emission transportation needs in January.

    The minister issues a statement on the energy sector outlook, these continue monthly.

    An advisory panel is announced in February to develop a long-term vision for Alberta’s energy future and recommend steps the province should take to ensure the industry continues to thrive, the final report is due in June.

    Steps to grow the mineral sector are announced in March.

    Alberta is on track to meet and exceed it’s methane emission reduction goal, the Emissions Reduction and Energy Development Plan is also announced, learn more about the plan.

    A mandate letter is issued to the minister in July.

    $45 million is announced for hydrogen technologies in August.

    In August, the Alberta Utilities Commission (AUC) paused approvals of new renewable electricity generation projects over one megawatt until Feb. 29, 2024, to review the use of agricultural land and public land for wind and solar projects, land reclamation and the role of municipal governments in land selection for project development and review, learn more in the fact sheet.

    Funding is announced in September for a multi-year study that will explore how small modular nuclear reactors could be safely, technically and economically deployed for oil sands operations.

    In November, Alberta hits the oil and gas section methane reduction target 3 years early and announces a new carbon capture incentive program.

    Two new pilot projects are announced in December to speed up oil and gas reclamation.

    The premier and minister welcome the opening of the Steveville Helium Purification Facility.


    In January, the minister of Energy and Minerals and minister of Environment and Protected Areas issued statements on the progress of cleaning up well liabilities in the AER’s Liability Management Performance Report.

    Alberta refreshed the AER board in April to help guide the future of Alberta’s energy sector.


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