Provincial and Territorial Energy Profiles – Alberta


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Table of Contents
  • Figure 1: Hydrocarbon Production

    Figure 1: Hydrocarbon Production

    Source and Description:

    CER – Canada's Energy Future 2019

    This graph shows hydrocarbon production in Alberta from 2008 to 2018. Over this period, crude oil production has grown from 1.9 MMb/d to 3.9 MMb/d, with all growth coming from the oil sands. Natural gas production has deceased from 12.4 Bcf/d to around 10.5 Bcf/d.

  • Figure 2: Electricity Generation by Fuel Type (2018)

    Figure 2: Electricity Generation by Fuel Type (2018)

    Source and Description:

    CER – Canada's Energy Future 2019

    This pie chart shows electricity generation by source in Alberta. A total of 81.0 TW.h of electricity was generated in 2018.

  • Figure 3: Electricity Capacity and Primary Fuel Sources Map

    Figure 3: Electricity Capacity and Primary Fuel Sources in Alberta Map

    Source and Description:

    CER, Natural Resources Canada

    This map shows electricity generation facilities in Alberta. Facilities are shown by capacity and by primary fuel source.

    PDF version [1008 KB]

  • Figure 4: Crude Oil Infrastructure Map

    Figure 4: Crude Oil Infrastructure in Alberta Map

    Source and Description:


    This map shows all major crude oil pipelines, rail lines, and refineries in Alberta.

    PDF version [446 KB]

  • Figure 5: Natural Gas Infrastructure Map

    Figure 5: Natural Gas Infrastructure in Alberta Map

    Source and Description:


    This map shows all major natural gas pipelines in Alberta.

    PDF version [513 KB]

  • Figure 6: End-Use Demand by Sector (2017)

    Figure 6: End-Use Demand by Sector (2017)

    Source and Description:

    CER – Canada's Energy Future 2019

    This pie chart shows end-use energy demand in Alberta by sector. Total end-use energy demand was 3 805 PJ in 2017. The largest sector was industrial at 75% of total demand, followed by transportation (at 11%), commercial (at 9%), and lastly, residential (at 6%).

  • Figure 7: End-Use Demand by Fuel (2017)

    Figure 7: End-Use Demand by Fuel (2017)

    Source and Description:

    CER – Canada's Energy Future 2019

    This figure shows end-use demand by fuel type in Alberta in 2017. Natural gas accounted for 2 125 PJ (56%) of demand, followed by refined petroleum products at 1 319 PJ (35%), electricity at 285 PJ (7%), biofuels at 73 PJ (2%), and other at 2 PJ (0%).
    Note: "Other" includes coal, coke, and coke oven gas.

  • Figure 8: GHG Emissions by Sector

    Figure 8: GHG Emissions by Sector

    Source and Description:

    Environment and Climate Change Canada – National Inventory Report

    This stacked column graph shows GHG emissions in Alberta by sector every five years from 1990 to 2017 in MT of CO2e. Total GHG emissions have increased in Alberta from 173 MT of CO2e in 1990 to 273 MT of CO2e in 2017.

Energy Production

Crude Oil

  • In 2018, Alberta produced 3.91 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 over 82% of total production.
  • Over three-quarters of Alberta’s crude oil production comes from the oil sands in northern Alberta. In 2018, Alberta produced 3.04 MMb/d of oil sands raw bitumen. From that amount, 1.09 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 are currently operational in Alberta: Syncrude, Suncor, and CNRL Horizon (all near Fort McMurray); and Shell Scotford in Edmonton. Combined, these upgraders have the capacity to process 1.46 MMb/d of bitumen.
  • In 2018, Alberta also produced 370 thousand barrels per day (Mb/d) of light oil and 119 Mb/d of heavy oil. Alberta’s condensate and pentanes plus production was 374 Mb/d.
  • In 2018, western Canadian oil supply outgrew pipeline capacity to export it and record wide crude price differentials resulted. Alberta government mandated production curtailment effective January 2019. The curtailment legislation has been extended to 31 December 2020.
  • At year-end 2018, Alberta’s remaining resource of crude oil, including the oil sands, is estimated to be 312 billion barrels.

Refined Petroleum Products (RPPs)

  • Alberta has five refineries: Strathcona (Imperial Oil), Edmonton (Suncor), and Scotford (Shell) in the Edmonton area; Sturgeon (NWR) in Redwater; and Lloydminster (Husky) in Lloydminster. These have a total capacity of 542 Mb/d (27% of total Canadian refining capacity) and give Alberta the largest refining capacity in Canada.
  • The Sturgeon Refinery is Canada’s first new refinery in over 30 years. Construction was completed in May 2018. Sturgeon was designed to process bitumen into diesel and other RPPs. However, as of the end of 2018, it has only processed synthetic crude oil rather than bitumen. The Alberta government’s Alberta Petroleum Marketing Commission 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 policy).
  • Alberta’s refineries process only western Canadian crude oil, including a large proportion of blended bitumen and synthetic crude oil. Refineries in the province processed approximately 80% light oil, including synthetic crude oil, in 2018.

Natural Gas/Natural Gas Liquids (NGLs)

  • In 2018, Alberta’s natural gas production averaged 10.5 billion cubic feet per day (Bcf/d) (Figure 1). Alberta’s gas production represented 65% of total Canadian natural gas production in 2018.
  • At year-end 2018, Alberta’s total potential for recoverable, sales-quality natural gas is estimated to be 563 trillion cubic feet (Tcf), with 387 Tcf remaining after production is subtracted.
  • In 2018, Alberta’s NGL production was about 515 Mb/d, not including condensate and pentanes plus, which are included with crude oil.
  • Some NGLs are fractionated into individual components (for example, ethane, propane, butane, and condensate) at field plants or fractionators in Alberta.


  • In 2018, Alberta generated 81 terawatt hours (TW.h) of electricity (Figure 2), which is approximately 13% of total Canadian generation. Alberta is the 3rd largest producer of electricity in Canada and has a generating capacity of 16 332 megawatts (MW).
  • Some of Alberta’s largest electricity generators include TransAlta, Heartland Generation, Suncor, ENMAX, and Capital Power.
  • About 91% of electricity in Alberta is produced from fossil fuels – approximately 43% from coal and 49% from natural gas. The remaining 8% is produced from renewables, such as wind, hydro, and biomass (Figure 3).
  • Alberta’s coal fleet is the largest in Canada and has a total capacity of 5 555 MW. Coal-fired generation is scheduled to be gradually phased out by 2030 under Alberta’s Climate Change legislation.
  • The Shepard Energy Centre is located east of Calgary and has a capacity of 860 MW. It is Alberta’s largest natural gas-fired power station.
  • Alberta’s wind fleet has a capacity of 1 467 MW, ranking it 3rd highest in the country after Ontario and Quebec. Most of Alberta’s wind turbines are located in southern Alberta near Pincher Creek.

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 areas to pipeline hubs in Hardisty and Edmonton (Figure 4). Alberta also receives crude oil from Norman Wells, Northwest Territories via Enbridge’s Norman Wells pipeline.
  • The majority of Alberta’s crude oil production is exported to the United States (U.S.) and other provinces. The main pipelines that transport crude oil outside of Alberta are Enbridge’s Mainline, TC Energy’s Keystone, Trans Mountain, and Enbridge’s Express. Smaller pipelines to the U.S. include Plains Midstream’s Milk River and Aurora-Rangeland systems.
  • Alberta contains two main import pipelines for condensate: Enbridge’s Southern Lights and Kinder Morgan’s Cochin. These pipelines transport condensate from the U.S. to distribution centres in Edmonton and Fort Saskatchewan, where it is then delivered by pipeline, rail, and truck to heavy oil and oil sands projects for use as diluent.
  • RPPs are moved within Alberta by truck and rail, and by the Alberta Products Pipeline. This line transports an average of 48.4 Mb/d of RPPs and connects Edmonton refineries to markets in southern Alberta.
  • Alberta is a large supplier of RPPs, such as gasoline and diesel, to markets in neighboring provinces. Products are transported to British Columbia (B.C.) largely via Trans Mountain, and to Saskatchewan and Manitoba primarily via the Enbridge Mainline.
  • Alberta has 16 crude oil rail loading facilities with a total capacity of approximately 800 Mb/d. In 2018, approximately 5% of Alberta’s crude oil production was exported by rail.

Natural Gas

  • Many pipelines transport Alberta natural gas to other provinces and to the U.S. Alberta’s major gas pipeline systems include Nova Gas Transmission Ltd. (NGTL), Canadian Mainline, Foothills, and Alliance (Figure 5). The first three are owned by TC Energy.
  • The NGTL System is connected to Enbridge’s BC Pipeline (Westcoast) system at the Alberta/B.C. border, to the Foothills pipeline in Alberta and at the Alberta/B.C. border, and Canadian Mainline at the Alberta/Saskatchewan border.
  • The NGTL System is comprised of approximately 24 500 kilometres (km) of pipelines and facilities that extend to most areas of Alberta. NGTL has over 1 100 receipt points, over 300 major delivery points, and is connected to nine underground storage facilities in Alberta. Deliveries on NGTL are over 12.4 Bcf/d.
  • NGTL is expanding in order to accommodate new supply, primarily from the Montney formation in northeast B.C. and northwest Alberta. The North Montney Mainline Project, consisting of 206 kilometres (km) of new pipe and two compressor stations, is planned to be fully placed into service throughout 2020. The proposed 2021 NGTL System Expansion Project will add about 350 km of new pipe and additional compression in northwest Alberta, increasing intra-Alberta capacity by about 2 Bcf/d.
  • The Canadian Mainline is over 14 000 km long and transports gas from the NGTL System near Empress, Alberta to Canadian and U.S. markets east of Alberta. The Canadian Mainline connects with the Trans-Québec & Maritimes pipeline near the Ontario/Quebec border.
  • TC Energy is proposing a $200 million expansion of its Canadian Mainline, adding 0.5 Bcf/d of capacity to serve Ontario and Quebec markets, with an expected completion by 2022.
  • TC Energy’s Foothills pipeline system is connected to the NGTL System at the southern part of the system and consists of several segments: Foothills BC, Foothills SK, and Foothills Alberta. Foothills BC exports natural gas to the U.S. Pacific Northwest via the Kingsgate, B.C. export point. Foothills SK exports natural gas to the U.S. Midwest via the Monchy, Saskatchewan export point. Foothills Alberta is operated in conjunction with the NGTL System.
  • Alliance pipeline originates in northeastern B.C., crosses Alberta, and enters the U.S. at Alameda, 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.
  • The NGTL System facilitates the operation of the Nova Inventory Transfer (NIT) hub, the largest and most liquid natural gas hub in Canada. NIT, also known as the intra-Alberta or AECO-C price, is the main Canadian price benchmark for natural gas in western Canada.
  • ATCO Gas is Alberta’s largest natural gas distributor and serves over 1.1 million customers in nearly 300 communities. AltaGas Utilities distributes natural gas to over 80 000 residential, rural, and commercial customers in over 90 communities across northern Alberta. ATCO and AltaGas are both regulated by the Alberta Utilities Commission (AUC).
  • NGLs are primarily transported out of Alberta on rail cars, or as NGL mix on the Enbridge Mainline to Sarnia, Ontario and the U.S. Midwest.
  • The only specification propane pipeline delivering outside of Alberta is Plain Midstream’s Petroleum Transmission Company (PTC) pipeline. PTC has a capacity of 15 Mb/d and runs from Empress, Alberta through Regina, Saskatchewan to Fort Whyte, Manitoba, delivering to truck and rail terminals along the way.
  • Pembina’s 68 Mb/d Vantage Pipeline transports ethane from Tioga, North Dakota to Empress, Alberta, to connect with the Alberta Ethane Gathering System, the main system supplying the Alberta petrochemical industry.
  • Provincial natural gas projects and pipelines are regulated by the Alberta Energy Regulator and the AUC.

Liquefied Natural Gas (LNG)

  • Encana operates the Cavalier small-scale LNG facility near Strathmore. The facility has been in operation since 2013 and supplies up to 6 500 gallons per day of LNG to the transportation sector, including rail.
  • Ferus operates a small-scale LNG facility in Elmworth, near Grand Prairie. The Elmworth facility will have a capacity of 150 000 gallons per day after an expansion, which is expected to be completed by the end of 2019. Ferus produces LNG for the transportation sector, hydrocarbon drilling, mining, and for power generation in Whitehorse, Yukon and Inuvik, Northwest Territories.


  • In 2018, Alberta’s net interprovincial and international electricity inflows were 2.9 TW.h. 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 with 235 generating stations. The main transmission companies serving the province include AltaLink, ATCO, ENMAX, and EPCOR.
  • The Alberta Energy System Operator (AESO) operates the Alberta electricity system and the AUC regulates privately-owned and certain municipally-owned utility providers.
  • There are more than 200 Alberta electricity market participants registered with the AESO.
  • The 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 February 2019, microgeneration accounts for 44 MW of capacity across more than 3 000 sites, with solar accounting for approximately 90% of the capacity.

Energy Consumption and Greenhouse Gas (GHG) Emissions

Total Energy Consumption

  • End-use demand in Alberta was 3 805 petajoules (PJ) in 2017. The largest sector for energy demand was industrial at 75% of total demand, followed by transportation at 11%, commercial at 9%, and residential at 6% (Figure 6). Alberta’s total energy demand was the largest in Canada, and the largest on a per capita basis.
  • Natural gas was the largest fuel type consumed in Alberta, accounting for 2 125 PJ, or 56% of consumption in 2017. RPPs and electricity accounted for 1 319 PJ (35%) and 285 PJ (7%), respectively (Figure 7).

Refined Petroleum Products

  • Alberta has a net surplus of RPPs and nearly all of the gasoline consumed in Alberta is produced within the province.
  • Alberta is the 3rd largest market in Canada for RPPs, after Ontario and Quebec. Total 2018 demand in Alberta for RPPs was 365 Mb/d, or 19% of Canadian RPP demand. Of Alberta’s total demand, an estimated 117 Mb/d was for motor gasoline and 144 Mb/d was for diesel.
  • Alberta’s per capita RPP consumption in 2018 was 5 005 litres (31 barrels) – 65% above the national average of 3 038 litres per capita.

Natural Gas

  • Alberta consumed an average of 6.17 Bcf/d of natural gas in 2018. Alberta's demand represented 55% of total Canadian demand for natural gas in 2018.
  • The largest consuming sector for natural gas was the industrial sector (including heavy oil and oil sands production), which consumed 5.4 Bcf/d in 2018. The residential and commercial sectors consumed 0.43 Bcf/d and 0.37 Bcf/d, respectively.


  • In 2017, annual electricity consumption per capita in Alberta was 18.7 megawatt hours (MW.h). Alberta ranked 4th in Canada for per capita electricity consumption and consumed 28% more than the national average.
  • Alberta’s largest consuming sector for electricity in 2017 was industrial at 51.8 TW.h. The commercial and residential sectors consumed 17.2 TW.h and 10.3 TW.h, respectively. Alberta’s electricity demand has grown 22% since 2005.

GHG Emissions

  • Alberta’s GHG emissions in 2017 were 272.8 megatonnes (MT) of carbon dioxide equivalent (CO2e). Alberta’s emissions have increased 58% since 1990. Footnote 1
  • Alberta’s emissions per capita are the 2nd highest in Canada at 64.3 tonnes CO2e – more than three times the national average of 19.6 tonnes per capita.
  • The largest emitting sectors in Alberta are oil and gas production at 50% of emissions, electricity generation at 16%, and transportation at 11% (Figure 8).
  • Alberta’s GHG emissions from the oil and gas sector in 2017 were 137.1 MT CO2e. Of this total, 130.8 MT were attributable to production, processing, and transmission and 6.4 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. In 2017, Alberta’s power sector generated 44.3 MT CO2e emissions, or 60% of total Canadian GHG emissions from power generation.

More Information

Data Sources

Provincial & Territorial Energy Profiles aligns with CER’s latest Canada’s Energy Future 2019 datasets. Energy Future uses a variety of data sources, generally starting with Statistics Canada data as the foundation, and making adjustments depending on individual province/territory circumstances.  Adjustments are necessary to ensure consistency and comparability across provinces/territories.

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