Provincial and Territorial Energy Profiles – Alberta

Energy Production

Crude Oil

• In 2023, Alberta produced 4.3 million barrels per day (MMb/d) of crude oil (including condensate and pentanes plus) (Figure 1). Alberta is the largest producer of crude oil in Canada, accounting for 84% of total Canadian production in 2023.
• Over three-quarters of Alberta’s crude oil production comes from the oil sands in northern Alberta. In 2023, Alberta had 8 operating oil sands mines, and 26 thermal in situ oil sands operations.^Footnote 1 In 2023, Alberta produced 3.4 MMb/d of oil sands raw bitumen. From that amount, about 1.2 MMb/d of synthetic crude oil (SCO) was produced. SCO can be transformed into refined petroleum products or in some cases used to dilute raw bitumen for transport.
• Four upgraders currently produce SCO in Alberta: Syncrude,^Footnote 2 Suncor,^Footnote 3 and CNRL Horizon^Footnote 4 (all near Fort McMurray), and Shell Scotford^Footnote 5 in Edmonton. Combined, these upgraders have the capacity to process approximately 1.4 MMb/d of bitumen.
• In 2023, Alberta also produced 373.8 thousand barrels per day (Mb/d) of conventional light oil and 145.4 Mb/d of conventional heavy oil. Alberta’s condensate and pentanes plus production was 368.9 Mb/d.
• Alberta’s remaining resource of crude oil, including the oil sands, is estimated to be 308 billion barrels as of December 2021.^Footnote 6

Refined Petroleum Products (RPPs)

• Alberta has five refineries: Strathcona (Imperial Oil),^Footnote 7 Edmonton (Suncor),^Footnote 8 and Scotford (Shell)^Footnote 9 in the Edmonton area; Sturgeon (NWR)^Footnote 10 in Redwater; and Lloydminster (Cenovus)^Footnote 11 in Lloydminster. Combined, these refineries have a total oil processing capacity of 569 Mb/d, making Alberta the province with the largest refining capacity in Canada. Alberta’s refineries process only western Canadian crude oil, including a large proportion of blended bitumen and SCO.
• As of 1 June 2020, the Sturgeon Refinery began processing bitumen through a fee-for-service tolling mechanism. Prior to this, it was only refining SCO. The Alberta government’s Alberta Petroleum Marketing Commission^Footnote 12 has a 30-year tolling arrangement to provide 75% of the required bitumen-blend feedstock to the Sturgeon Refinery (under Alberta’s Bitumen Royalty in Kind^Footnote 13 policy).
• Alberta’s refinery utilization was nearly 99% in 2023.^Footnote 14

Natural Gas/Natural Gas Liquids (NGLs)

• In 2023, natural gas production in Alberta averaged 10.9 billion cubic feet per day (Bcf/d) (Figure 1). Alberta produced 61% of Canada’s total natural gas production in 2023.
• At the end of 2022, Alberta’s total potential for recoverable, sales-quality natural gas is estimated to be 563 trillion cubic feet (Tcf), with 372 Tcf remaining after production is subtracted.^Footnote 15
• Some NGLs are fractionated into individual components (for example, ethane, propane, butane, and condensate) at field plants or fractionators in Alberta.
• Alberta has about 500 active gas processing field plants, 12 fractionators, and six straddle plants.^Footnote 16

Renewable Natural Gas (RNG)

• In 2021, Lethbridge Biogas expanded its facilities to produce RNG, which is injected into the natural gas grid and supplied to FortisBC.^Footnote 17
• The Two Hills RNG Facility captures methane emissions from manure and other organic waste.^Footnote 18 The project was developed in partnership between ATCO Future Fuel and Pacific Northern Gas Ltd. (PNG). The project was completed in 2022.

Electricity

• In 2021, Alberta generated 73.9 terawatt-hours (TWh) of electricity (Figure 2), or approximately 12% of Canada’s total generation. Alberta had the third highest electricity generation in Canada.
• Some of Alberta’s largest electricity generators include TransAlta, Heartland Generation, Suncor, ENMAX, and Capital Power.
• In 2021, 85% of electricity in Alberta was generated from fossil fuels. Approximately 22% of Alberta’s electricity was generated from coal and 63% was from natural gas. The remaining 15% was produced from renewables, such as wind (9%), hydro (3%), and bioenergy (2%).
• By June 2024, Alberta had fully phased out coal-fired generation. Under Alberta’s climate change legislation,^Footnote 19 emissions from coal-fired generation was to be phased out in the province by 2030. However, power generators in Alberta (including Capital Power,^Footnote 20 Heartland Generation,^Footnote 21 and TransAlta^Footnote 22) decided to advance plans for coal-to-gas conversions.
• In 2021, Alberta’s estimated generating capacity was 16,024 megawatts (MW), the fourth highest in Canada.
• The Shepard Energy Centre^Footnote 23 is Alberta’s largest natural gas-fired power station. It is located east of Calgary and has a capacity of 860 MW.
• In 2021, Alberta’s wind fleet had a capacity of roughly 1,529 MW, ranking 3rd highest in the country after Ontario and Quebec. Most of Alberta’s wind turbines are located in southern and central-east Alberta.
• Greengate’s 465 MW Travers Solar project,^Footnote 24 the largest solar installation in Canada began construction in 2021 and was operational in 2023.
• The 216 MW Dunmore Solar Project^Footnote 25 is under construction in Cypress County and is anticipated in service in 2025.
• Alberta’s Micro-Generation Regulation allows Alberta residents to generate electricity from renewable or alternative energy sources and sell the surplus to the Alberta grid in exchange for energy credits, with a limit of 5 MW of installed capacity. As of May 2024, microgeneration capacity totaled 258 MW across more than 20,000 sites, with solar accounting for approximately 95% of total capacity.^Footnote 26
• Alberta’s electricity market is deregulated, and prices can change in real time in response to market dynamics. Alberta, along with Ontario, are the only jurisdictions in Canada that have competitive generation and retail markets for electricity.

Energy Transportation and Trade

Crude Oil and Liquids

• Alberta has a vast network of crude oil and condensate pipelines that gather and deliver crude oil from production regions to pipeline and storage hubs in Edmonton and Hardisty (Figure 3).
• The Enbridge Mainline^Footnote 27 system is Canada’s largest transporter of crude oil. The Mainline starts in Edmonton and delivers light and heavy crude oil, RPPs, and NGLs to markets in the Prairies, U.S. Midwest, and Ontario.
• The Trans Mountain Pipeline^Footnote 28 also starts in Edmonton and transports crude oil and RPPs to refineries and terminals in British Columbia (B.C.) and Washington. Crude oil delivered by Trans Mountain is also exported to international markets via the Westridge Marine Terminal in Burnaby, B.C.
• South Bow’s (formerly TC Energy) Keystone Pipeline^Footnote 29 and Enbridge’s Express Pipeline^Footnote 30 both originate in Hardisty^Footnote 31 and export crude oil to refining markets in the U.S. Midwest and the Gulf Coast. The Enbridge Mainline also connects to Hardisty.
• Milk River Pipeline Ltd.’s Milk River^Footnote 32 pipeline and Plains Midstream’s Aurora Pipeline^Footnote 33 are two smaller CER-regulated pipelines that also transport crude oil across the border from Alberta to Montana. Milk River connects to the much longer provincially regulated Bow River Pipeline,^Footnote 34 owned by Inter Pipeline Ltd. The Bow River system gathers and transports crude oil from oil fields in southeastern Alberta and transports it to Hardisty and Milk River. Aurora connects to the provincially regulated Rangeland Pipeline, which starts in Edmonton and is owned by Plains Midstream Canada.
• Alberta also receives crude oil from Norman Wells, Northwest Territories (NWT), via the Enbridge Norman Wells^Footnote 35 pipeline.
• Alberta’s two main import pipelines for condensate are Enbridge’s Southern Lights^Footnote 36 and Pembina’s Cochin.^Footnote 37 These pipelines transport condensate from the U.S. to distribution centres in Edmonton and Fort Saskatchewan, where it is then used as diluent in oil sands projects.
• Enbridge Line 3 Replacement Project,^Footnote 38 which delivers crude oil from Edmonton to Superior, Wisconsin, became fully operational in October 2021. The project roughly doubled the capacity of Line 3 to 760 Mb/d. Line 3 forms a part of the Enbridge Mainline.
• The Trans Mountain Expansion Project (TMEP) twinned the existing Trans Mountain pipeline and increased the pipeline’s capacity to 890 Mb/d from 300 Mb/d. Construction of the new pipeline began in November 2019 and was completed in 2024. TMEP was granted final leave to open on 30 April 2024 by the CER, and officially began commercial operations in May 2024.
• Alberta is a large supplier of RPPs, such as gasoline and diesel, to markets in neighbouring provinces. Products are transported to B.C. largely via Trans Mountain, and to Saskatchewan and Manitoba primarily via the Enbridge Mainline.
• RPPs are moved within Alberta by truck and rail, and by the Alberta Products Pipeline.^Footnote 39 This line transports an average of 48.4 Mb/d of RPPs and connects Edmonton refineries to markets in southern Alberta. The Alberta Products Pipeline is regulated by the Alberta Energy Regulator (AER).
• Alberta has 16 crude oil rail loading facilities with a total capacity of approximately 802 Mb/d.^Footnote 40

Natural Gas

• Major pipelines that transport Alberta’s natural gas to other provinces and to the U.S. include: Nova Gas Transmission Ltd. (NGTL),^Footnote 41 TC Canadian Mainline,^Footnote 42 Foothills,^Footnote 43 and Alliance^Footnote 44 (Figure 4). The first three are owned by TC Energy. Alliance is owned by Alliance Pipeline Ltd., which is a wholly-owned subsidiary of Pembina Pipeline Corporation.
• The NGTL System extends through most of Alberta and transports western Canada-produced natural gas to markets in Canada and the U.S. NGTL has been adding capacity in recent years to accommodate increasing production from the Montney Formation in northeastern B.C. and northwest Alberta. Overall, the NGTL System currently has a $9.9 billion infrastructure program underway that will add 3.5 Bcf/d of incremental delivery capacity from 2020 to 2024.
• The TC Canadian Mainline transports natural gas to eastern Canada and the U.S. The pipeline extends from the Alberta border across Saskatchewan, Manitoba and Ontario, and through a portion of Quebec. It connects with the Trans-Québec & Maritimes^Footnote 45 pipeline near the Ontario/Quebec border.
• The Foothills pipeline system is connected to the southern part of the NGTL System and consists of several segments: Foothills BC, Foothills SK, and Foothills Alberta.
• The Alliance Pipeline originates in northeastern B.C., crosses Alberta, and enters the U.S. at Elmore, Saskatchewan. Alliance transports liquids-rich natural gas from B.C. and Alberta and delivers it to the Aux Sable gas processing and fractionation facility near Chicago, Illinois.^Footnote 46
• ATCO Gas^Footnote 47 is Alberta’s largest natural gas distributor and serves over 1.1 million customers in nearly 300 communities. Apex Utilities Inc.^Footnote 48 (previously AltaGas Utilities Inc.) distributes natural gas to over 82,000 residential, rural, and commercial customers in over 90 communities across Alberta. ATCO and Apex Utilities Inc. are both regulated by the Alberta Utilities Commission^Footnote 49 (AUC).
• Provincial natural gas projects and pipelines are regulated by the Alberta Energy Regulator^Footnote 50 and the AUC.

Natural Gas Liquids

• Alberta has many pipelines that transport natural gas liquids, including ethane, propane, butanes, and NGL mixes.
• NGLs are primarily transported out of Alberta on rail cars across North America, or as NGL mixes on the Enbridge Mainline to Sarnia, Ontario, and the U.S. Midwest.
• Plains Midstream Canada's Petroleum Transmission Company (PTC) Pipeline^Footnote 51 delivers propane and butane produced at the Empress straddle plants to rail and truck terminals in the Prairies. PTC has a capacity of 15 Mb/d and runs from Empress, Alberta, through Regina, Saskatchewan, to Fort Whyte, Manitoba.
• Pembina’s 68 Mb/d Vantage Pipeline transports ethane from Tioga, North Dakota, to Empress to connect with the Alberta Ethane Gathering System^Footnote 52 (AEGS). AEGS is the main system that supplies ethane to Alberta’s petrochemical industry.

Liquefied Natural Gas (LNG)

• Cryopeak^Footnote 53 operates a small-scale LNG facility in Elmworth, west of Grand Prairie. The Elmworth facility supplies the transportation sector, hydrocarbon drilling, mining, and power generation in Whitehorse, Yukon and Inuvik, NWT. It was formerly owned by Ferus NGF^Footnote 54 and has been operating since 2014.

Electricity

• In 2023, Alberta’s net interprovincial and international electricity inflows were 0.1 TWh. Alberta trades electricity with B.C., Saskatchewan, and Montana.
• Alberta has approximately 26,000 km of transmission lines and more than 200,000 km of distribution lines.^Footnote 55
• Transmission systems are owned and operated by shareholder-owned companies like AltaLink^Footnote 56 and ATCO.^Footnote 57 Distribution systems are owned by municipally-owned companies like ENMAX,^Footnote 58 EPCOR;^Footnote 59 or the cities of Red Deer, Lethbridge, and Medicine Hat; or by shareholder-owned companies like ATCO and Fortis.^Footnote 60 The AUC regulates these companies’ transmission and distribution tariffs, while the Alberta Electric System Operator^Footnote 61 (AESO) works with these companies to operate the Alberta electricity system and the competitive electricity market.

Energy Consumption and Greenhouse Gas (GHG) Emissions

Total Energy Consumption

• Total end-use energy demand in Alberta was 3,867 petajoules (PJ) in 2020. Industrial energy demand made up 75% of total demand, followed by transportation at 10%, the commercial sector at 10%, and residential at 6% (Figure 5). In 2020, Alberta’s total end-use demand was the largest in Canada, and the largest on a per capita basis, mainly due to the oil and gas industry.
• Natural gas was the main fuel type consumed in Alberta, accounting for 2,253 PJ, or 58% of consumption in 2020. RPPs and electricity accounted for 1,239 PJ (32%) and 285 PJ (7%), respectively (Figure 6).

Refined Petroleum Products

• Alberta’s motor gasoline demand in 2022 was 1,219 litres per capita, 18% above the national average of 1,035 litres per capita.
• Alberta’s diesel demand in 2022 was 1,393 litres per capita, 80% above the national average of 772 litres per capita.
• Alberta has a net surplus of RPPs and nearly all the gasoline consumed in Alberta is produced within the province.

Natural Gas

• In 2023, Alberta consumed an average of 6.9 Bcf/d of natural gas. Alberta’s natural gas demand is 58% of total Canadian demand.
• The largest consuming sector for natural gas was the industrial sector (including heavy oil and oil sands production), which consumed 6.2 Bcf/d in 2023. The residential and commercial sectors consumed 0.39 Bcf/d and 0.35 Bcf/d, respectively.

Electricity

• In 2020, annual electricity consumption per capita in Alberta was 17.9 megawatt-hours (MWh). Alberta ranked fourth in Canada for per capita electricity consumption (behind Quebec, Newfoundland and Labrador, and Saskatchewan), consuming 23% more than Canada’s average.
• In 2020, Alberta’s industrial sector consumed 50.2 TWh of electricity. Its commercial and residential sectors consumed 16.9 TWh and 11.9 TWh, respectively.

GHG Emissions

• Alberta’s GHG emissions in 2022 were 269.9 megatonnes of carbon dioxide equivalent (MT CO₂e).^Footnote 62 Alberta’s emissions have increased 52% since 1990 and 7% since 2005.
• Alberta’s emissions per capita are the second highest in Canada at 59.8 tonnes CO₂e, which is over three times the national average of 18.2 tonnes per capita.
• The largest emitting sectors in Alberta are oil and gas production at 59% of emissions, transportation at 9%, and industry at 8% (Figure 7).
• Alberta’s GHG emissions from the oil and gas sector in 2022 were 158.3 MT CO₂e. Of this total, 153.6 MT were attributable to production, processing, and transmission and 4.7 MT were attributable to petroleum refining and natural gas distribution.
• Alberta’s electricity sector produces more GHG emissions than any other province because of its size and reliance on coal-fired generation (before it was phased out in June 2024). In 2022, Alberta’s power sector generated 19.4 MT CO₂e emissions, or 41% of total Canadian GHG emissions from power generation.
• The greenhouse gas intensity of Alberta’s electricity grid, measured as the GHGs emitted in the generation of the province’s electric power, was 470 grams of CO₂e per kilowatt-hour (g CO₂e per kWh) electricity generated in 2022. This is a 48% reduction from the province’s 2005 level of 910 g CO₂e per kWh. The national average in 2022 was 100 g CO₂e per kWh (Figure 8).

Energy Authorities

• Alberta Energy
• Alberta Energy Regulator
• Alberta Utilities Commission
• Alberta Electric System Operator (AESO)
• CER–Canada’s Renewable Power: Alberta

Date modified:

2024-09-10