1. Oil pipeline capacity increased, but strong growth in Canada’s crude oil production kept western Canadian oil pipelines highly utilized.
Average annual oil production from western Canada increased from 4.5 million barrels per day (MMb/d) in 2021 to 5.1 MMb/d in 2025, a 14% increase. Canada was the fourth largest crude oil producer in the world, producing 6.5% of global supply.
The majority of Canadian oil production is exported by pipelines. Western Canada’s four major crude oil export pipelines are the Enbridge Canadian Mainline, the Trans Mountain System, the Keystone Pipeline, and the Express Pipeline. The combined capacity of these four pipelines continues to make up around 96% of all takeaway capacity (also called egress capacity) from the Western Canada Sedimentary Basin (WCSB).
From January 2021 to December 2025, around 0.9 MMb/d of capacity was added to CER-regulated western Canadian oil egress pipelines, an increase of about 20%. In 2021 and 2023, the amount of western Canadian oil that was available for export exceeded available export pipeline capacity. Expansions on the Enbridge Canadian Mainline and the Trans Mountain System added new capacity in 2021 and 2024 and helped ease constraints. Still, pipelines were, at times, operating at or near full capacity by late 2025, indicating that available capacity remained extremely tight out of the WCSB due to growing oil production.Footnote 1
A number of oil pipeline projects are being explored across Canada, including expansions to existing systems and proposals for new pipeline infrastructure that could increase takeaway capacity.
2. Western Canadian crude oil prices became less discounted relative to U.S. oil since new pipeline capacity came online.
Heavy Canadian crude oil benchmarks are priced at a discount to global light oil benchmarks. The discount shrank in mid-2024 after the start-up of the Trans Mountain Expansion Project eased tight takeaway capacity out of western Canada – increasing the relative price of Canadian crude oil. The discount (also called differential) generally remained steady through 2025.
Over the past ten years, western Canadian crude oil supply frequently exceeded what local refineries and export pipelines could accept, contributing to multiple periods where Canadian crude oil saw a sharp increase in its price discount. When this happened, rail filled more of the transportation gap. Since mid-2024, rail volumes have been lower and stable, as Canadian crude discounts stayed narrower.
3. Canadian crude oil exports have modestly diversified to non-U.S. markets, but remain mainly destined for the U.S.
With the expanded Trans Mountain System starting operations mid-2024, the share of crude oil exports going to non-U.S. destinations increased from 2% in 2021 to 10% in 2025.
Canada’s production has a greater proportion of heavier oil like bitumen. Significant refining capacity around the world is configured to use heavy oil, including about 70% of U.S. refining capacity that is optimized to process heavier crude oils than those typically produced in the U.S.
Canadian refineries process roughly one quarter of total Canadian production, leaving most production for export. Refineries located further from western Canadian production sources – namely in Ontario, Quebec, and New Brunswick – consistently rely on some imported crude oil. Refineries in Ontario and Quebec process both western Canadian crude oil supplied via pipelines that travel through the U.S. and imported crude oil supplied via pipelines and marine vessels.
Natural gas
1. Canadian natural gas production grew between 2021 and 2025, supported by low-cost, liquids-rich production in western Canada.
Canadian marketable natural gas production, which is almost entirely in western Canada, averaged 19.1 billion cubic feet per day (Bcf/d) in 2025, up 18% from 16.1 Bcf/d in 2021. As the fifth largest producer of natural gas in the world, Canada accounts for 5% of global supply.
The Montney Formation in Alberta and B.C. has led this growth, producing over half of Canada’s gas production in 2025. The Montney’s liquids-rich composition has improved production economics because natural gas liquids are extracted and marketed separately, adding an additional revenue stream and increasing the value of each unit of gas produced. Additionally, horizontal drilling and multi-stage hydraulic fracturing and continued improvements in operating practices have lowered the cost per unit of gas recovered and made more resources viable, especially tight and shale gas.
About three-quarters of Canadian production is transported by the NGTL System.
2. Exports of natural gas to the U.S. grew between 2021 and 2025, and Canada’s first material exports to other countries began in 2025 with the start-up of LNG Canada.
As Canada’s natural gas production expanded, exports increased 18% between 2021 and 2025, to 9.1 Bcf/d in 2025. Exports to the U.S. increased as U.S. natural gas demand was driven higher by Gulf Coast LNG exports, gas-fired power generation, and, more recently, increasing electricity demand from data centres.
The first ever large-scale LNG exports from a Canadian site began in the latter half of 2025 as the LNG Canada facility came online in June and operations progressed toward the project’s 1.9 Bcf/d nameplate capacity. Over 4.5 Bcf/d of additional LNG export capacity is currently proposed, planned, or under construction on the B.C. coast.
Persistent price differentials between North American and Asian/European natural gas markets created strong incentives for LNG exports from North America. The top destinations for LNG exports from Canada in 2025 were the Republic of Korea (38%), Japan (31%), and China (22%).
3. Even with large capacity expansions, natural gas pipelines out of western Canadian production areas were utilized at high levels between 2021 and 2025. Limited spare capacity contributed to natural gas prices in western Canada being more heavily discounted compared to other North American locations.
Between January 2021 and December 2025, more than 4 Bcf/d of capacity was added to key natural gas pipeline pathways that connect western Canadian production to domestic and international markets. Much of this new capacity entered service in 2025 and was associated with the start-up of the provincially-regulated Coastal GasLink pipeline and west coast LNG exports. By the end of 2025, new capacity additions were largely utilized by increased natural gas production,Footnote 2 although some spare capacity remained at the delivery points that service the still ramping-up LNG Canada facility. Additionally, about 1.3 Bcf/d of the new capacity was added at key points supplying demand within Alberta, representing an increase of approximately 21%. Alberta accounts for more than half of Canadian natural gas demand, consuming 7.1 Bcf/d in 2025.
Major pipelines leaving the WCSB – namely the NGTL System, BC (or Westcoast) Pipeline, and Alliance Pipeline – were largely at capacity between 2021 and 2025, particularly during peak demand. Average combined flows across the six key points that represent the primary pathways for gas leaving western Canada grew by 17% between 2021 and 2025.
Tight and sometimes constrained pipeline capacity contributed to challenging pricing dynamics for western Canadian natural gas producers. Annual prices in western Canada averaged C$1.6/GJ in 2025 compared to C$4.7/GJ for Henry Hub (the most prominent North American benchmark price). North American natural gas price volatility increased in recent years, and differentials widened, resulting in more heavily discounted western Canadian prices. Brief negative price events occurred in western Canada every year between 2021 and 2025, at times leading to short-term production cuts to balance the market.
4. Natural gas pipeline flows to Ontario changed in response to shifting supply and demand dynamics, whereas the Maritimes had limited supply options.
Central Canada obtained increasing amounts of natural gas from western Canada between 2021 and 2025, reflecting Central Canada’s growing demand and imports from the U.S. levelling off due to heightened competition for U.S. natural gas supply.
The Maritime provinces continued to rely on LNG imports during peak demand periods due to limited local natural gas supply and storage infrastructure as well as pipeline constraints. Limited pipeline capacity into the U.S. Northeast reduces the ability of Maritime and Northeastern U.S. markets to access increasing supplies from the U.S. Appalachian basin.
Natural gas liquids
1. Growing demand for diluent in the oil sands has been met by higher domestic diluent production and more pipeline imports of U.S. diluent.
As western Canada’s bitumen and heavy oil production has increased, so has the region’s demand for diluent, primarily condensate and pentanes plus, which is used to blend into that production so that it can flow through pipelines.
Western Canadian condensate and pentanes plus production has increased steadily over the past five years, rising from 390 Mb/d in 2021 to 464 Mb/d in 2025 (a 20% increase), helping to meet the growing diluent demand in western Canada.
Approximately one-third of condensate and pentanes-plus demand over the past two years was met through imports from the United States via two CER-regulated pipelines: Southern Lights and Cochin. Both pipelines are operating at or near capacity.
2. New rail and marine infrastructure has enabled the growth and diversification of Canada’s propane exports.
New marine export terminals in B.C. have provided Canadian producers with access to international markets in Asia and other overseas destinations. In 2019, Canada’s first propane export terminal, AltaGas’s Ridley Island Propane Export Terminal, began exporting liquefied propane to Asia. A second propane export terminal, Pembina Pipeline’s Prince Rupert Terminal, commenced exports in April 2021. Additional capacity is being developed, notably the Ridley Island Energy Export Facility (a joint venture between AltaGas and Royal Vopak).
Canada exported 80 Mb/d of propane via marine in 2025, increasing its 2021 export volumes by one third.
Rail has remained the dominant transportation mode for Canadian propane and butane movements, particularly from western Canadian production regions to the U.S. Midwest and Gulf Coast, central Canada, and marine export terminals on the west coast of B.C.
3. The amount of ethane left in Canada’s natural gas stream has increased significantly, while the amount of ethane production has remained relatively flat.
Unlike other NGLs, ethane is not typically moved by rail or truck. Pipeline networks integrate domestic and imported supply of ethane to meet ethane demand at petrochemical facilities in Alberta and Ontario, which has been relatively steady.
As Canada’s liquids-rich natural gas production has grown since 2021, twice as much ethane is being left in the natural gas shipped on major CER-regulated natural gas pipelines. More ethane could be produced out of the gas stream if needed to meet increased petrochemical demand.
Refined petroleum products
1. Canadian refineries have operated at high utilization rates since demand returned to pre-pandemic levels, and the origin and type of crude oil they process varies across the country.
Canada has 16 operating refineries that, in total, can process approximately 1.9 MMb/d of crude oil. Canadian refineries have operated at utilization rates averaging 88–90% since 2022, as refined petroleum product (RPP) supply and demand have returned to pre-pandemic levels. These refineries maintained a relatively stable regional product mix, with transportation fuels, including motor gasoline and distillate fuel oil (including diesel fuel), making up most of Canadian refinery production and domestic demand.
Canada’s refining capacity is concentrated in Alberta, Ontario, Quebec, and New Brunswick, and some regions rely on RPP supply from other provinces or countries to meet demand. Western Canada generally produces enough RPPs to meet its needs, with Alberta supplying some volumes to British Columbia (which also imports foreign supply), Saskatchewan, Manitoba, Yukon, and Northwest Territories. Further east, Ontario, Quebec, and Atlantic Canada also rely on supply from other provinces to meet regional demand, as well as imports, primarily from the United States.
Pipelines, marine vessels, rail, and trucks move RPPs between refining centres and regional demand markets across Canada. While western Canada, Ontario, and Quebec rely primarily on pipeline transportation of RPPs, Atlantic Canada and Northern Territories depend more on other modes of transportation due to the absence of pipeline infrastructure.
Refineries in western Canada have processed mostly synthetic and heavy crude oil, almost exclusively from domestic production. Ontario and Quebec refineries received most of their crude oil supply from western Canada via pipelines that pass through the U.S., while also importing some U.S.-produced supply. These supplies for Ontario and Quebec were mostly light, medium, and synthetic crude oils. New Brunswick, home of Canada’s largest refinery, relies predominantly on foreign conventional light and medium crude oils.
Economic regulation
1. Tolls on most major CER-regulated pipelines continued to be determined through negotiated settlements between pipeline companies and interested parties.
Since 2021, negotiated tolling settlements were reached on several major CER-regulated oil and liquids pipelines, including the Enbridge Canadian Mainline, the Trans Mountain System, and the Trans-Northern Pipelines System, as well as natural gas pipelines, including the Alliance Pipeline, the BC (or Westcoast) Pipeline, the NGTL System and the TC Canadian Mainline.
2. The CER continued to require CER-regulated pipeline companies to set aside funds to cover future pipeline abandonment costs.
Companies using abandonment funding trusts need an estimated $16.3 billion (in 2023 dollars) to cover future pipeline abandonment costs, and they contribute money to their trusts each year. As of 31 December 2025, approximately $4.7 billion had been set aside by these companies in their trusts, and the remainder will be set aside in future years.
Companies using either an abandonment funding letter of credit or surety bond need an estimated $367 million (in 2028 dollars) to cover future pipeline abandonment costs. As of 31 December 2025, letters of credit and surety bonds covered $233 million and $134 million, respectively, for a total of $367 million.
Financial information
1. Rate base and revenues for Group 1 companies have increased significantly since 2021, reflecting capital projects that were completed to increase capacity.
Since 2021, the total rate base for Group 1 pipeline companies increased by $39.2 billion (or 101.3%) primarily due to the Trans Mountain Expansion Project coming into service in 2024 (which drove Trans Mountain’s $33 billion rate base increase since 2021) and expansions on the NGTL System (whose rate base grew $5 billion).
Total annual revenues for Group 1 pipeline companies have also increased by approximately 38% since 2021, totaling about $14.2 billion in 2025. The three largest total annual revenues were generated by the NGTL System ($3.8 billion), the Enbridge Canadian Mainline ($3.0 billion), and the Trans Mountain System ($2.9 billion).
2. Indigenous Communities are increasingly acquiring ownership stakes in large energy infrastructure in Canada.
The increase in ownership by Indigenous Communities has been facilitated by CER-regulated pipeline companies reorganizing their corporate structures as limited partnerships. This approach makes it easier for multiple Indigenous partners to hold ownership interests in a company, particularly when there are multiple minority owners. For example, in July 2025, 38 First Nations, through the Stonlasec8 Indigenous Alliance Limited Partnership, purchased a 12.5% ownership stake of the CER-regulated BC (or Westcoast) Pipeline. This was supported by a $400 million loan guarantee from the federal Indigenous Loan Guarantee Program.
