Provincial and Territorial Energy Profiles – Alberta

Alberta

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Table of Contents

  • Figure 1: Hydrocarbon Production

    Figure 1: Hydrocarbon Production

    Source and Description:

    Source:
    CER – Canada's Energy Future 2021

    Description:
    This graph shows hydrocarbon production in Alberta from 2010 to 2020. Over this period, crude oil production has grown from 2.2 MMb/d to 3.8 MMb/d, with almost all growth coming from the oil sands. Natural gas production has deceased from 10.9 Bcf/d to 9.7 Bcf/d.

  • Figure 2: Electricity Production (2019)

    Figure 2: Electricity Production (2019)

    Source and Description:

    Source:
    CER – Canada's Energy Future 2021

    Description:
    This pie chart shows electricity generation by source in Alberta. A total of 76.1 TW.h of electricity was generated in 2019.

  • Figure 3: Crude Oil Infrastructure Map

    Figure 3: Crude Oil Infrastructure Map

    Source and Description:

    Source:
    CER

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

    Download:
    PDF version [909 KB]

  • Figure 4: Natural Gas Infrastructure Map

    Figure 4: Natural Gas Infrastructure Map

    Source and Description:

    Source:
    CER

    Description:
    This map shows all major natural gas pipelines in Alberta.

    Download:
    PDF version [1 341 KB]

  • Figure 5: End-Use Demand by Sector

    Figure 5: End-Use Demand by Sector

    Source and Description:

    Source:
    CER – Canada's Energy Future 2021

    Description:
    This pie chart shows end-use energy demand in Alberta by sector. Total end-use energy demand was 4 091 PJ in 2018. The largest sector was industrial at 75% of total demand, followed by transportation (at 11%), commercial (at 8%), and lastly, commercial (at 6%).

  • Figure 6: End-Use Demand by Fuel (2019)

    Figure 6: End-Use Demand by Fuel (2019)

    Source and Description:

    Source:
    CER – Canada's Energy Future 2021

    Description:
    This figure shows end-use demand by fuel type in Alberta in 2018. Natural gas accounted for 2 340 PJ (57%) of demand, followed by refined petroleum products at 1 370 PJ (34%), electricity at 274 PJ (7%), biofuels at 105 PJ (3%), and other at 2 PJ (less than 1%).
    Note: "Other" includes coal, coke, and coke oven gas.

  • Figure 7: GHG Emissions by Sector (2019)

    Figure 7: GHG Emissions by Sector (2019)

    Source and Description:

    Source:
    Environment and Climate Change Canada – National Inventory Report

    Description:
    This stacked column graph shows GHG emissions in Alberta by sector every five years from 1990 to 2019 in MT of CO2e. Total GHG emissions have increased in Alberta from 172 MT of CO2e in 1990 to 276 MT of CO2e in 2019.

  • Figure 8: Emissions Intensity of Electricity Generation

    Figure 8: Emissions Intensity of Electricity Generation

    Source and Description:

    Source:
    Environment and Climate Change Canada – National Inventory Report

    Description:
    This column graph shows the emissions intensity of electricity generation in Alberta from 1990 to 2019. In 1990, electricity generated in Alberta emitted 950 g of CO2e per kWh. By 2019, emissions intensity decreased to 620 g of CO2e per kWh.

Energy Production

Crude Oil

  • In 2020, Alberta produced 3.79 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 80% of total Canadian production as of 2020.
  • Over three-quarters of Alberta’s crude oil production comes from the oil sands in northern Alberta. In 2020, Alberta had 8 operating oil sands mines, and 29 thermal in situ oil sands operations. In 2020, Alberta produced 2.99 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 1.52 MMb/d of bitumen.
  • In 2020, Alberta also produced 334.8 thousand barrels per day (Mb/d) of conventional light oil and 88.2 Mb/d of conventional heavy oil. Alberta’s condensate and pentanes plus production was 379.1 Mb/d.
  • Between January 2019 and December 2020, the Alberta government’s mandated production curtailment were put in place because oil production exceeded pipeline capacity thereby affecting oil prices in Alberta. By the end of 2020, monthly production limits were put on hold and as of December 31, 2021 the oil production curtailment policy expired.
  • At year-end 2020, Alberta’s remaining resource of crude oil, including the oil sands, is estimated to be 310 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 (Cenovus) in Lloydminster. Combined, these refineries have a total oil processing capacity of 542.4 Mb/d. This amounts to 28.5% of Canada’s total refining capacity, the largest share of any province in Canada.
  • As of 1 June 2020, the Sturgeon Refinery began processing bitumen through a fee-for-service tolling mechanism. Prior to this, it was only processing SCO. 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 SCO. In 2020, 68% of the oil processed in Alberta refineries was upgraded bitumen including pentanes plus, with the remaining 32% being crude oil and non-upgraded bitumen.
  • Alberta’s refinery utilization was 94% in 2020.

Natural Gas/Natural Gas Liquids (NGLs)

  • In 2020, Alberta’s natural gas production averaged 9.72 billion cubic feet per day (Bcf/d) (Figure 1). Alberta’s gas production represented 63% of total Canadian natural gas production in 2020.
  • At year-end 2020, Alberta’s total potential for recoverable, sales-quality natural gas is estimated to be 563 trillion cubic feet (Tcf), with 380 Tcf remaining after production is subtracted.
  • Alberta’s NGL production in 2020 was about 416.8 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.
  • Alberta has nearly 500 active gas processing field plants, 13 fractionators, and 8 straddle plants.

Electricity

  • In 2019, Alberta generated 76.1 terawatt hours (TW.h) of electricity (Figure 2), which is approximately 12% of total Canadian generation. Alberta is the third largest producer of electricity in Canada and has an estimated generating capacity of 16 330 megawatts (MW).
  • About 89% of electricity in Alberta is produced from fossil fuels– approximately 36% from coal and 54% from natural gas. The remaining 10% is produced from renewables, such as wind, hydro, and biomass.
  • Alberta, along with Ontario, are the only jurisdictions in Canada that have competitive generation and retail markets for electricity.
  • Some of Alberta’s largest electricity generators include TransAlta, Heartland Generation, Suncor, ENMAX, and Capital Power.
  • In 2019, Alberta’s coal fleet was the largest in Canada with a total capacity of 5 555 MW.
  • Under Alberta’s climate change legislation, emissions from coal-fired generation will be phased out in the province by 2030. However, power generators in Alberta (including Capital Power, Heartland Generation, and TransAlta) have decided to advance plans for coal-to-gas conversions with most coal-fired facilities expected to switch by 2022, and all by 2024.
  • The Shepard Energy Centre is Alberta’s largest natural gas-fired power station. It is located east of Calgary and has a capacity of 860 MW.
  • In 2019, Alberta’s wind fleet had a capacity of roughly 1 467 MW, ranking it 3rd highest in the country after Ontario and Quebec. Most of Alberta’s wind turbines are located in southern and central-east Alberta.
  • Significant growth is expected for wind and solar generation in Alberta, with over 2 000 MW of new projects expected between 2019 and 2023. The 465 MW Travers Solar project, the largest solar installation in Canada, is under construction and expected to be operational in late 2022.
  • 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 November 2020, microgeneration capacity totaled 95 MW across more than 6 000 sites, with solar accounting for approximately 93% of total capacity.
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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 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 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 Asia via the Westridge Marine Terminal in Burnaby, B.C. TC Energy’s Keystone Pipeline and Enbridge’s Express Pipeline both originate in Hardisty and export crude oil to refining markets in the U.S. Midwest and the Gulf Coast. The Enbridge Mainline also connects to Hardisty.
  • Plains Midstream’s Milk River and Aurora pipelines are two smaller CER-regulated pipelines that also transport crude across the border from Alberta to Montana. Milk River connects to the much longer provincially-regulated Bow River Pipeline, 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 also owned by Plains Midstream Canada.
  • Alberta also receives crude oil from Norman Wells, Northwest Territories (NWT), via the Enbridge Norman Wells pipeline.
  • Alberta’s two main import pipelines for condensate are Enbridge’s Southern Lights and Pembina’s Cochin. 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, which delivers crude oil from Edmonton to Superior, Wisconsin, became fully operational in October 2021. The project roughly doubled the pipeline’s capacity to 760 Mb/d. Line 3 forms a part of the Enbridge Mainline.
  • The Trans Mountain Expansion project will transport crude oil from Edmonton to the Westridge Marine Terminal and Parkland refinery in Burnaby, B.C. The expansion will twin the existing Trans Mountain pipeline and increase the pipeline’s capacity to 890 Mb/d from 300 Mb/d. Construction of the new pipeline began in November 2019 and is expected to be complete December 2022.
  • 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. 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.

Natural Gas

  • Major pipelines that transport Alberta’s natural gas to other provinces and to the U.S. include: Nova Gas Transmission Ltd. (NGTL), TC Canadian Mainline, Foothills, and Alliance (Figure 4). The first three are owned by TC Energy.
  • 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 Canadian Mainline transports natural gas to eastern Canada and the U.S. The pipeline extends from the Alberta/Saskatchewan border across Saskatchewan, Manitoba and Ontario, and through a portion of Quebec. It connects with the Trans-Québec & Maritimes 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. Foothills Alberta is operated in conjunction with the NGTL System.
  • The 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.
  • ATCO Gas is Alberta’s largest natural gas distributor and serves over 1.1 million customers in nearly 300 communities. Apex Utilities Inc. (previously AltaGas Utilities Inc.) distributes natural gas to over 80 000 residential, rural, and commercial customers in over 90 communities across Alberta. ATCO and Apex Utilities Inc. are both regulated by the Alberta Utilities Commission (AUC).
  • Provincial natural gas projects and pipelines are regulated by the Alberta Energy Regulator and the AUC.

Natural Gas Liquids

  • Alberta has many pipelines that transport natural gas liquids, including ethane, propane, butanes, and NGL mix.
  • NGLs are primarily transported out of Alberta on rail cars across North America, or as NGL mix on the Enbridge Mainline to Sarnia, Ontario, and the U.S. Midwest.
  • Plains Midstream Canada's Petroleum Transmission Company (PTC) Pipeline delivers propane and butane produced at the Empress straddle plants to rail and truck terminals on 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–the main system supplying the Alberta petrochemical industry.

Liquefied Natural Gas (LNG)

  • Ferus operates a small-scale LNG facility in Elmworth, west of Grand Prairie. The Elmworth facility produces 50 000 gallons per day and services the transportation sector, hydrocarbon drilling, mining, and power generation in Whitehorse, Yukon and Inuvik, NWT.
  • The Cavalier LNG facility near Strathmore is operated by Alberta LNG. 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.

Electricity

  • In 2019, Alberta’s net interprovincial and international electricity inflows were 2.7 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.
  • Transmission systems are owned and operated by shareholder-owned companies such as AltaLink and ATCO. Distribution systems are owned by municipally-owned companies such as ENMAX, EPCOR; or the cities of Red Deer, Lethbridge, and Medicine Hat; or by shareholder-owned companies such as ATCO and Fortis. The AUC regulates these companies’ transmission and distribution tariffs, while the Alberta Electric System Operator (AESO) works with these companies to operate the Alberta electricity system and the competitive electricity market.
  • There are more than 200 Alberta electricity market participants registered with the AESO.
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Energy Consumption and Greenhouse Gas (GHG) Emissions

Total Energy Consumption

  • Total end-use demand in Alberta was 4 160 petajoules (PJ) in 2019. The largest sector for energy demand was industrial at 74% of total demand, followed by transportation at 11%, commercial at 9%, and residential at 6% (Figure 5). 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 2 373 PJ, or 57% of consumption in 2019. RPPs and electricity accounted for 1 400 PJ (34%) and 275 PJ (7%), respectively (Figure 6).

Refined Petroleum Products

  • Alberta’s motor gasoline demand in 2019 was 1 608 litres per capita, 27% above the national average of 1 268 litres per capita.
  • Alberta’s diesel demand in 2019 was 1 815 litres per capita, more than double the national average of 855 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

  • Alberta consumed an average of 6.4 Bcf/d of natural gas in 2020. Alberta's demand represented 56% of total Canadian demand.
  • The largest consuming sector for natural gas was the industrial sector (including heavy oil and oil sands production), which consumed 5.6 Bcf/d in 2020. The residential and commercial sectors consumed 0.44 Bcf/d and 0.37 Bcf/d, respectively.

Electricity

  • In 2019, annual electricity consumption per capita in Alberta was 17.5 megawatt-hours (MWh). Alberta ranked fifth in Canada for per capita electricity consumption and consumed 17% more than the national average.
  • Alberta’s largest consuming sector for electricity in 2019 was industrial at 48.2 TWh. The commercial and residential sectors consumed 17.7 TWh and 10.2 TWh, respectively.

GHG Emissions

  • Alberta’s GHG emissions in 2019 were 275.8 megatonnes (MT) of carbon dioxide equivalent (CO2e). Alberta’s emissions have increased 60% since 1990 and 17% since 2005.Footnote 1
  • Alberta’s emissions per capita are the second highest in Canada at 63.24 tonnes CO2e– more than three times the national average of 19.4 tonnes per capita.
  • The largest emitting sectors in Alberta are oil and gas production at 51% of emissions, electricity generation at 11%, and transportation at 12% (Figure 7).
  • Alberta’s GHG emissions from the oil and gas sector in 2019 were 141.3 MT CO2e. Of this total, 135.6 MT were attributable to production, processing, and transmission and 5.7 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. In 2019, Alberta’s power sector generated 31 MT CO2e emissions, or 51% 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 620 grams of CO2e per kilowatt-hour (g CO2e per kWh) electricity generated in 2019. This is a 32% reduction from the province’s 2005 level of 910 g CO2e per kWh. The national average in 2019 was 120 g CO2e per kWh (Figure 8).
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More Information

Data Sources

Provincial & Territorial Energy Profiles aligns with the CER’s latest Canada’s Energy Future 2021 datasets. Energy Futures uses a variety of data sources, generally starting with Statistics Canada data as the foundation, and making adjustments to ensure consistency across all provinces and territories.

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