Oil and Gas

On this page:

• Production
• Trade and Transportation

Production

Crude Oil

• In 2023, British Columbia (B.C.) produced 113.2 thousand barrels per day (Mb/d) of crude oil (including condensate and pentanes plus) (Figure 3). This represented 3% of total Canadian production.
• All production is conventional light oil, condensate, and pentanes plus and is from the northeast portion of the province.
• B.C.’s remaining resource of crude oil was estimated to be 524 million barrels as of December 2021.^Footnote 6

Refined Petroleum Products (RPPs)

• B.C. has two refineries: the Prince George Refinery and the Burnaby Refinery.
• The Prince George Refinery is owned and operated by Tidewater Midstream and has a capacity of 12 Mb/d. It consumes light crude oil from B.C.
• The Burnaby Refinery is owned and operated by Parkland. It has a capacity of 55 Mb/d and mostly consumes light crude oil transported via the Trans Mountain pipeline.

Natural Gas/Natural Gas Liquids (NGLs)

• In 2023, natural gas production in B.C. averaged 6.7 billion cubic feet per day (Bcf/d) (Figure 3), accounting for 36% of Canada’s natural gas production.
• Natural gas is produced in the northeastern part of B.C., almost all from the Montney Formation. Natural gas production has almost doubled from the average of 3.7 Bcf/d produced in 2013.
• The Montney extends from northeast B.C. into Alberta. The B.C. portion was estimated to contain 385 trillion cubic feet (Tcf) of remaining recoverable, sales-quality gas at year-end 2022.
• Other significant gas resources are located in the Horn River Basin and Liard Basin. B.C.’s total potential resource for remaining recoverable, sales-quality natural gas was estimated to be 663 Tcf at year-end 2022.^Footnote 7

Renewable Natural Fuels

• Renewable natural gas (RNG) transported on FortisBC’s natural gas distribution system comes from landfills, food and agricultural waste, and wastewater facilities.^Footnote 8 As of 1 July, 2024, all FortisBC gas customers will have 1% of their gas designated as RNG.^Footnote 9
• In Q4 2023, Tidewater’s renewable diesel refinery and hydrogen plant in Prince George became operational.^Footnote 10 In Q2 2024, the refinery reached its capacity of approximately 3.0 Mb/d of renewable diesel, using canola oil, tallow, and used cooking oil to produce fuel.^Footnote 11 The facility will also produce renewable hydrogen, which will be used in the production of renewable diesel, with excess hydrogen production available for other uses.^Footnote 12

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Trade and Transportation

Crude Oil and Liquids

• There are two major crude oil pipelines in B.C.: Trans Mountain and Pembina’s NEBC/Western Pipeline system (Figure 4).
• The Trans Mountain Pipeline delivers crude oil and RPPs primarily from Edmonton, Alberta, to Kamloops, Burnaby, and the U.S. It serves several facilities, including Parkland's Burnaby Refinery, four refineries in Washington state (via a connected pipeline at the U.S. border), and the Westridge Marine Terminal. The Trans Mountain Expansion project came online in May 2024, increasing the pipeline's capacity to 890 Mb/d from approximately 300 Mb/d.
• The Western Pipeline portion of the NEBC/Western Pipeline system has 75 Mb/d of capacity and ships crude oil and NGLs from Taylor to the Prince George Refinery. The NEBC portion of the system transports liquids, including condensate produced in the Montney region, to Taylor. From Taylor, liquids can also reach markets in Edmonton and Fort Saskatchewan, Alberta, via other pipelines.
• NorthRiver’s NEBC Connector Project involves the construction and operation of two parallel pipelines that are approximately 215 km in length. One pipeline would transport condensate and the other pipeline would transport natural gas liquids. Planned construction is set to begin in the third quarter of 2024, with an in-service date expected in the second quarter of 2025.
• B.C. has four main oil and oil products storage terminals. The Kamloops Terminal is the smallest with two storage tanks. The terminal services Kamloops and the region with refined products. The Sumas Terminal has a capacity of 715,000 barrels of oil, with another 175,000 barrels under construction. The Burnaby Terminal has a storage capacity of nearly 1.7 million barrels with another 3.9 million barrels under construction, and the Westridge Marine Terminal, also in Burnaby, has a capacity of 395,000 barrels. All four are located along the Trans Mountain Pipeline.
• There is one crude-by-rail offloading facility in B.C., located in Burnaby. It is operated by Chevron and has a capacity of 8,000 b/d.^Footnote 13

Natural Gas

• Several pipelines transport natural gas within B.C. Both FortisBC and Pacific Northern Gas (PNG) operate transmission and distribution systems within the province, delivering natural gas directly to customers.
• Natural gas is exported from B.C. to other provinces via TC Energy's NOVA Gas Transmission Limited (NGTL), which connects with TC Energy's Canadian Mainline (Figure 5).
• Natural gas is exported from B.C. to the U.S. Pacific Northwest via Enbridge's Westcoast Pipeline (also referred to as the Enbridge BC Pipeline) at Huntingdon, where it connects with Williams’ Northwest Pipeline, or at Kingsgate, where the Foothills Pipeline connects with TC Energy’s Gas Transmission Northwest (GTN) system. Gas produced in B.C. may also be exported to the U.S. Midwest via Pembina's Alliance Pipeline or via NGTL, Foothills and TC Energy’s Canadian Mainline.
• In 2023, TC Energy’s West Path Delivery Program entered service. The Program, first announced in October 2019, expanded the NGTL and Foothills systems to increase export capacity to GTN. It was underpinned by approximately 0.258 Bcf/d of new firm service contracts and included the construction of approximately 119 km of pipeline and facilities. There were four separate projects, all located within Alberta and B.C. In B.C., it included the Foothills Zone 8 West Path Delivery 2022 Project, which entered service in Q1 2023, and the Foothills Zone 8 West Path Delivery 2023  Project, which entered service in Q4 2023.
• In November 2023, TC Energy achieved mechanical completion of the Coastal GasLink (CGL) Pipeline to supply gas to LNG Canada’s export facility in Kitimat.^Footnote 14 The CGL Pipeline will have an initial capacity of 2.1 Bcf/d, with potential expansion to 5.0 Bcf/d without laying new pipe but requiring new compression.

Natural Gas Liquids

• AltaGas’ Ridley Island Propane Export Terminal (RIPET) is Canada’s first propane marine export terminal. It is located approximately 10 km south of Prince Rupert. The terminal has an export capacity of 92 Mb/d with exports primarily destined for Asian markets. RIPET receives its supply from western Canada via CN’s railway network.
• Pembina's Prince Rupert Terminal started exporting propane to international markets in April 2021. Supply for the terminal is delivered by rail from western Canada. The terminal has an export capacity of 25 Mb/d. Plans for an expansion of the terminal to 45 Mb/d were deferred in May 2022.

Liquefied Natural Gas (LNG)

• Many large-scale LNG export facilities have been proposed for the B.C. Coast. All LNG export facilities will be regulated by the province of B.C., including the B.C. Energy Regulator.
• Since 2011, the Canada Energy Regulator has issued 37 export licenses to LNG facility proponents for the B.C. Coast. Some of these export licences have been revoked or consolidated.
• LNG Canada is Canada’s first large-scale LNG export facility, located in Kitimat. As of March 2024, the project was nearing completion and on track to enter service by mid-2025.^Footnote 15 The project is a joint venture between Shell, PETRONAS, PetroChina, Mitsubishi Corporation, and KOGAS. Initial production capacity is planned to be 14 million tonnes per annum (Mtpa) from the first two liquefaction units (often called “trains”) with the potential to expand to four trains in the future.
• Woodfibre LNG is a proposed small-scale LNG processing and export facility near Squamish. Construction began in November 2023 and is expected to be completed by 2027. The project has received the necessary approvals from the B.C. Energy Regulator to build and operate the facility. Woodfibre will have a production capacity of 2.1 Mtpa. The project is owned by Pacific Energy Corporation and Enbridge Inc.
• Cedar LNG is a proposed floating LNG facility in Kitimat with a capacity of 3.3 Mtpa of LNG. The project received environmental approvals, including a British Columbia Environmental Assessment Certificate, a positive Impact Assessment Decision Statement from the federal Minister of Environment and Climate Change, and a permit from the B.C. Energy Regulator to construct an 8.5 km pipeline that will connect the facility to the Coastal GasLink pipeline. A positive final investment decision was announced in June 2024.^Footnote 16
• FortisBC operates two smaller scale LNG facilities: Tilbury, on Tilbury Island near Vancouver, and Mt. Hayes, near Ladysmith on Vancouver Island.^Footnote 17
• Tilbury has been operating since 1971. It serves local markets during peak winter demand, provides LNG for ferries, and since 2017 been shipping small volumes of LNG to China.^Footnote 18 Current expansion projects would more than double Tilbury’s LNG storage capacity and increase liquefaction capacity to 2.5 Mtpa.^Footnote 19
• The Mt. Hayes LNG facility was built in 2011 and provides natural gas to customers on Vancouver Island during high demand periods or gas system outages. The Mt. Hayes facility has a storage capacity of 1.5 Bcf.
• Cryopeak’s Tamaska LNG facility began operations in 2021 in Fort Nelson.^Footnote 20 The production capacity of the facility in the current phase is 27,000 gallons of LNG per day. The plant is scalable to approximately 100,000 gallons per day under its current permit.
• Cryopeak’s Dawson Creek LNG facility also has a current capacity of 27,000 gallons of LNG per day. The Dawson Creek facility was owned by Campus Energy until 2024 when it was acquired by Cryopeak.^Footnote 21

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Energy Use

Total Energy Consumption

• End-use demand in B.C. was 1,187 petajoules (PJ) in 2020. The largest sector for energy demand was industrial at 48% of total demand, followed by transportation at 27%, residential at 14%, and commercial at 11% (Figure 6). In 2020, B.C.’s total energy demand was the fourth largest in Canada, but the sixth largest on a per capita basis.
• In 2020, RPPs, including gasoline and diesel, were the main fuel types consumed in B.C., accounting for 398 PJ, or 34% of total end-use demand. Natural gas, electricity, and biofuels accounted for 362 PJ (31%), 209 PJ (18%), and 214 PJ (18%), respectively (Figure 7).
• B.C. is the largest bioenergy consumer in Canada primarily because of its large pulp and paper industry.

Refined Petroleum Products (RPPs)

• B.C.’s motor gasoline demand in 2022 was 918 litres per capita, 11% below the national average of 1,035 litres per capita.
• B.C.’s diesel demand in 2022 was 891 litres per capita, 15% above the national average of 772 litres per capita.
• Most of the gasoline consumed in B.C. comes from Alberta, delivered primarily via the Trans Mountain Pipeline. Gasoline is also produced in B.C.’s two refineries. Gasoline consumed in B.C. may also be imported via ship or barge from the U.S. Pacific Northwest.

Natural Gas

• B.C. consumed an average of 0.62 Bcf/d of natural gas in 2023, which was 5.2% of Canada’s natural gas demand.
• B.C.’s largest consuming sector for natural gas was the industrial sector, which consumed 0.29 Bcf/d in 2023. The residential and commercial sectors consumed 0.19 Bcf/d and 0.14 Bcf/d, respectively.

Electricity

• In 2020, electricity consumption per capita in B.C. was 11.3 megawatt-hours (MWh). B.C. had the seventh highest electricity consumption per capita and consumed 23% less than the national average.
• B.C.’s industrial sector consumed the most electricity in 2020, at 23.3 terawatt-hours (TWh). The residential and commercial sectors consumed 20.2 TWh and 14.5 TWh, respectively.

GHG Emissions

• B.C.’s GHG emissions in 2022 were 64.3 megatonnes of carbon dioxide equivalent (MT CO₂e).^Footnote 22 Emissions have increased 26% since 1990 and 3% since 2005.
• B.C.’s emissions per capita are one of the lowest in Canada at 12.0 tonnes of CO₂e, which is 34% below the national average of 18.2 tonnes per capita.
• The largest emitting sectors in B.C. are transportation at 36% of emissions, upstream and downstream oil and gas at 24%, and manufacturing and heavy industries (including smelting, cement, and chemicals) at 17% (Figure 8).
• B.C.’s GHG emissions from the oil and gas sector in 2022 were 15.2 MT CO₂e. Of this total, 14.6 MT were attributable to production, processing, and transmission and 0.6 MT were attributable to petroleum refining and natural gas distribution.
• Most electricity produced in B.C. comes from renewable sources. In 2022, B.C.’s power sector generated 0.3 MT CO₂e emissions, which represents 0.6% of Canada’s total GHG emissions from power generation.
• The greenhouse gas intensity of B.C.’s electricity grid, measured as the GHGs emitted in the generation of the province’s electric power, was 14 grams of CO₂e per kilowatt-hour (g of CO₂e per kWh) electricity generated in 2022. This is a 46% reduction from the province’s 2005 level of 25 g of CO₂e per kWh. The national average in 2022 was 100 g of CO₂e per kWh (Figure 9).