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Getting Alberta Oil to Market: Pipelines, Rail and the Price Discount

Alberta produces far more oil than it uses, and nearly all of it must travel hundreds or thousands of kilometres by pipe or rail to reach a buyer. This guide explains the export system, why pipeline space shapes the price Alberta receives, and what is planned next.

Updated 2026-09-2827 min read75 sourcesDraft: fact-check pending

Why market access matters for a landlocked producer

Crude oil is worth what a refinery will pay for it, minus the cost of getting it there. For many large exporters that cost is small, because oil leaves a coastal terminal on a tanker, usually the cheapest way to move crude long distances [12]. Alberta has no coastline. Its oil must travel hundreds or thousands of kilometres by pipeline or rail before it reaches a refinery or a port, and both cost more per barrel than an ocean tanker [12].

That geography creates two problems. The first is cost: the price at Hardisty or Edmonton is roughly the buyer's price minus the toll to get there. The second is capacity. Pipelines take years to build while production grows every month, and when output exceeds what the export system can carry, storage fills and sellers cut prices to move their oil. Canadian crude can then fall "even further than transportation costs alone would suggest," in the words of the Canadian Association of Petroleum Producers (CAPP) [12].

The Canada Energy Regulator (CER), the federal agency that oversees pipelines crossing provincial or national borders, sees the same pattern. When export pipelines are not constrained, West Texas Intermediate (WTI) typically sells about US$12.50 a barrel above Western Canadian Select (WCS); in tight periods the gap has reached US$25 or more. Producers and shippers therefore value a cushion of spare pipeline capacity [13].

How much is produced, used and shipped out

Canada produced a record 5.35 million bbl/d of crude oil and equivalents in 2025. Alberta supplied 83.8 per cent and added 182,000 bbl/d in the year, mostly non-upgraded bitumen, as producers grew into pipeline space opened by the Trans Mountain Expansion [1]. Statistics Canada counts production of crude oil and equivalent products at a record 310.9 million cubic metres (m³) in 2025, and says the expanded Trans Mountain line eased the export bottleneck that had limited output in the past [3].

Very little of that oil is used at home. Alberta's refineries processed 91.4 thousand m³/d (575,000 bbl/d) of crude oil equivalent in 2024, running at 103 per cent of rated capacity [14]. The province's five refineries can process about 569,000 bbl/d, the most of any province [15].

Almost everything else leaves. The Alberta Energy Regulator (AER) reports that removals from the province (upgraded and non-upgraded bitumen, crude oil and pentanes plus) averaged 613.8 thousand m³/d, or about 3.9 million bbl/d, in 2024 [14]. Non-upgraded bitumen alone accounted for 323.1 thousand m³/d (2.03 million bbl/d) [16]. In round numbers, more than six barrels left Alberta for every barrel refined inside it (calculated from the AER figures cited).

Canada exported 4.3 million bbl/d of crude oil in 2025, worth $140.0 billion [2]. In 2024, 89 per cent of exports moved by pipeline, 9 per cent by marine vessel and 2 per cent by rail, and heavy oil made up 79 per cent of the total [17].

One customer, one region

Canada's crude export system was built with the United States as its primary customer, and only one major export pipeline, Trans Mountain, reaches a coast [13]. In 2024, 93 per cent of exports went to the U.S. The U.S. Midwest, which U.S. statistics call PADD 2 (Petroleum Administration for Defense District 2), took 2.47 million bbl/d, 63 per cent of the Canadian crude the U.S. bought [17].

That dependence eased a little in 2025. The CER counts 90.1 per cent of 2025 exports going to the U.S. [2]. Statistics Canada, using a slightly different measure, reports that exports to other countries rose 132.6 per cent to 27.2 million m³, or 10.9 per cent of the total, more than triple their 2016–2024 average share of 2.8 per cent [3]. Both agencies credit mainly the Trans Mountain Expansion [3][18].

The export pipeline system

A handful of large pipelines carry most of the oil. The Enbridge Mainline, Keystone, Trans Mountain and Express together account for about 96 per cent of crude pipeline capacity leaving the Western Canadian Sedimentary Basin (WCSB), the geological basin that underlies Alberta and parts of neighbouring provinces [19]. The AER put total design capacity to move oil out of the basin at 851.4 thousand m³/d (5.36 million bbl/d) in 2024. Average available capacity was lower, at 796 thousand m³/d, or about 5.0 million bbl/d (converted) [20].

The gap between those two numbers matters. Nameplate capacity is what a pipeline was designed to carry under assumed conditions. Available capacity is what can actually flow in a given month, which changes with temperature, maintenance, flow direction and the mix of light and heavy crude being shipped [19]. Figures below are nameplate unless marked.

Pipeline Operator (parent) Route Capacity In service
Enbridge Mainline Enbridge Pipelines Inc. (Enbridge) Edmonton to Sarnia, Ont., via Gretna, Man., and the U.S. Midwest About 3.22 million bbl/d at the U.S. border; 3.23 million bbl/d available on average in 2025 [4][5] 1950 (Line 1) [4]
Trans Mountain Trans Mountain Pipeline ULC (Trans Mountain Corporation, a federal Crown corporation) Edmonton to Burnaby, B.C., with deliveries at Kamloops, Sumas and Burnaby About 890,000 bbl/d since May 1, 2024; about 300,000 bbl/d before [6] October 1953; expansion May 1, 2024 [6]
Keystone South Bow (spun off from TC Energy, 2024) Hardisty east through Saskatchewan and Manitoba to the border near Haskett, Man., then to the U.S. Midwest and Gulf Coast 591,000 bbl/d (CER profile); 622,000 bbl/d nominal (CER, 2026) [21][13] June 2010 [21]
Express Express Pipeline Ltd. (Enbridge) Hardisty to the border near Wild Horse, Alta., continuing to Casper, Wyoming About 310,000 bbl/d since 2020 [22] 1997 [22]
Milk River Milk River Pipeline Ltd. (Inter Pipeline) Near Milk River, Alta., to the border west of Coutts About 97,900 bbl/d [23] 1970 [23]
Aurora (fed by Rangeland) Aurora Pipe Line Company Ltd. (Plains) Near Carway, Alta., to the border, linking to the Glacier pipeline About 45,000 bbl/d [24][13] 1962 [24]
Southern Lights (diluent, inbound) Enbridge Southern Lights Manhattan, Illinois, to Edmonton About 180,000 bbl/d of diluent (profile also lists about 195,000) [25] 2010 [25]
Cochin (condensate, inbound) PKM Cochin ULC (Pembina) U.S. border near Elmore, Sask., to Fort Saskatchewan, Alta. About 110,000 bbl/d [26] 1979; reversed July 2014 [26]
Interactive map: Alberta's export pipelines and their capacities.

Enbridge Mainline

The Mainline is the backbone of the system. Its first line entered service in 1950, and it now runs from Edmonton to Sarnia, Ontario, crossing into the United States near Gretna, Manitoba. The CER regulates 7,550 km of it in Canada. Counting both countries, it is a bundle of eight pipelines in Canada and 12 in the U.S. totalling about 26,000 km [4]. At the Gretna border point its nameplate capacity is about 3.22 million bbl/d (about 512,000 m³/d), roughly 70 per cent of Canada's ability to ship oil out of the west [4].

In 2025 the Mainline carried an average 3.08 million bbl/d past Gretna against average available capacity of 3.23 million bbl/d. Utilization averaged 95.2 per cent, the highest since 2019 [5]. The CER cautions that upstream bottlenecks can make the line functionally full even when reported utilization is below 100 per cent [27]. The Line 3 Replacement, which entered service in October 2021, added about 370,000 bbl/d [8].

From the U.S. Midwest, connecting lines such as Flanagan South and Seaway carry Canadian heavy oil on to the Gulf Coast. In September 2024 Enbridge cut its uncommitted joint toll for heavy crude from Edmonton to Houston from US$10.93 to US$9.84 a barrel [27].

Trans Mountain and its expansion

Trans Mountain began carrying oil from Edmonton to the B.C. coast in October 1953. It delivers oil at Kamloops, Sumas and Burnaby, home of the Westridge Marine Terminal, where oil is loaded onto tankers [6]. The system also serves Washington State [28]. Until April 2024 it could move about 300,000 bbl/d [6].

The expansion took more than seven years to go from approval to service. Federal cabinet approved Kinder Morgan's plan to nearly triple capacity to 890,000 bbl/d on November 29, 2016, when it was presented as a $6.8 billion project [29]. On August 30, 2018, the Federal Court of Appeal quashed that approval, citing inadequate Indigenous consultation and a flawed review scope [30]. The next day the Government of Canada closed its purchase of the pipeline and project for $4.5 billion before closing adjustments, through Trans Mountain Corporation, a subsidiary of the Canada Development Investment Corporation [28]. After renewed consultation with 129 potentially affected Indigenous groups, cabinet approved the project again on June 18, 2019, and the court upheld that decision on February 4, 2020 [30].

The expanded system began commercial service on May 1, 2024 [6]. In November 2024 the Parliamentary Budget Officer (PBO) put the project's cost at $34.2 billion and valued the pipeline at $29.6 billion to $33.4 billion, so whether taxpayers gain or lose will depend on the eventual sale price [7]. Ottawa has said it does not intend to be the long-term owner [31].

The added capacity changed where Canadian oil goes. The CER calculates that the expansion raised western Canada's export pipeline capacity by 13 per cent, and that exports to countries other than the U.S. more than tripled [18]. In 2025 Trans Mountain averaged 761,000 bbl/d, 85 per cent of available capacity [5], and deliveries to Westridge averaged about 459,000 bbl/d (calculated from CER monthly data) [32]. CAPP reports that many of these barrels went to California and China, and that exports to China hit a record of roughly 480,000 bbl/d in October 2025 [12].

Keystone and Express

Keystone runs from Hardisty east across Saskatchewan and Manitoba and crosses into the U.S. near Haskett, Manitoba, with 1,233 km regulated by the CER. It entered service in June 2010 and has a nameplate capacity of 591,000 bbl/d [21]. On October 1, 2024, TC Energy spun off its liquids pipelines into a new company, South Bow, which now owns Keystone [21]. Keystone ran at 99.7 per cent utilization in 2024, carrying a record 624,000 bbl/d [27]. Throughput slipped to 585,000 bbl/d in 2025, partly because of an oil release in North Dakota in April 2025 [5].

Express runs from Hardisty to the border near Wild Horse, Alberta, and on to Casper, Wyoming, serving the U.S. Rockies. It opened in 1997 with capacity of 172,000 bbl/d and has been expanded to about 310,000 bbl/d since 2020 [22]. A further 30,000 bbl/d expansion reached a final investment decision on November 7, 2025, and is planned for 2027 [13].

Smaller lines and the feeder network

Two small pipelines cross into Montana. Inter Pipeline's Milk River line runs 70 km from the Bow River pipeline to the border west of Coutts [23]. Plains' Aurora line crosses near Carway, and the CER counts it together with the Rangeland system that feeds it [24][13].

Behind the export lines sits a large network of pipelines inside Alberta. Pipelines are generally grouped into gathering lines at the wellhead, feeder lines that move oil to hubs, and large-diameter transmission lines [33]. Enbridge's regional oil sands system in the Athabasca region, for example, includes the Athabasca, Waupisoo and Woodland pipelines and the Norlite diluent line [34].

Hubs, storage and blending: Edmonton and Hardisty

Edmonton is the start of both the Enbridge Mainline and Trans Mountain [4][6]. Three of Alberta's refineries (Imperial's Strathcona, Suncor's Edmonton and Shell's Scotford) sit in the Edmonton area, with the Sturgeon refinery nearby at Redwater [15]. Imported diluent arrives there too: Southern Lights ends at Edmonton and Cochin at Fort Saskatchewan [20]. Canadian Light Sweet, a representative benchmark for light sweet crude, is priced at Edmonton [12].

Hardisty, about 200 km southeast of Edmonton, is Canada's most important heavy oil hub [35][36]. Keystone and Express start there [21][22], and it is the pricing point for WCS [12]. Gibson Energy's Hardisty Terminal alone holds about 14 million barrels in 43 tanks, and the company says it handles one in four barrels exported from western Canada [36].

Storage is the shock absorber between production and pipelines. In 2018 the federal regulator counted more than 88 million barrels of crude oil and diluent storage in western Canada, most of it at Edmonton and Hardisty [37].

Batches, blends and WCS

Pipelines do not carry one uniform liquid. They move oil in batches, one grade after another, to limit mixing between different crudes, and a batch can take about 20 days to travel from Edmonton to Chicago [33]. Every marketable crude stream needs its own storage and pipeline access, which complicates marketing [35].

Western Canadian Select was created partly to solve that problem. In 2004 four heavy oil producers combined about 20 conventional and oil sands streams into one large blend [35]. The streams are blended at the Hardisty terminal, with diluent added to meet a specification of about 20.5 to 21.5 degrees API gravity and 3.0 to 3.5 per cent sulphur by weight [35]. WCS prices now govern the selling price of most heavy oil produced in western Canada [35].

Nominations and apportionment

Shipping space is allocated month by month. Shippers submit nominations, requests to move a stated volume, for committed (contracted) or uncommitted service, and the Mainline verifies them with shipper certificates, upstream supply checks and affidavits that the destination can receive the oil [4].

If nominations exceed the space available, the pipeline apportions them. The CER defines apportionment as the percentage by which each shipper's nominated volume is cut to fit the pipeline's uncommitted capacity [4]. Under 10 per cent apportionment, a shipper that nominated 100 barrels may ship 90 [4]. This follows from the common carrier principle: a common carrier must accept all products offered, and when space runs short it prorates capacity so each shipper gets an equal share of its request [38]. Apportionment can differ between lines and locations on the same system in the same month [4].

How much capacity is exposed to apportionment depends on the contracts. All Mainline capacity is offered as uncommitted service [4]. Keystone offers both committed and uncommitted service and reserves a minimum of 35,000 bbl/d for the latter [21]. Cochin reserves 10 per cent of its capacity for uncommitted service [26]. On Trans Mountain, uncommitted tolls are set at a premium to committed tolls [6]. Where the uncommitted slice is small, apportionment percentages can look extreme: CER data show Keystone's uncommitted nominations apportioned by 97 to 99 per cent in several months of late 2023 and early 2024 [32].

What the numbers show

The CER publishes monthly apportionment data for the major lines [32]. The record shows how tight the system became before new capacity arrived:

Apportioned shippers must store oil, send it by rail or sell it locally at whatever price buyers offer, so rising apportionment is a sign that export space is tightening. The CER's role is to publish these data, approve the tariffs that set out apportionment rules and hear shipper complaints [38]. After years of heavy apportionment, Trans Mountain introduced verification limits based on shippers' history in March 2015 [6].

Crude by rail

Rail is the overflow valve. Oil is loaded into specialized tank cars at terminals and moved by train. In 2018 the federal regulator counted about 1.2 million bbl/d of crude rail loading capacity in the WCSB across 22 major terminals, about 60 per cent of it in the Edmonton and Hardisty regions. Rail can reach refineries that pipelines do not serve, but it is often more expensive [39].

The cost gap is large. In 2014 the National Energy Board, the CER's predecessor, estimated that rail cost roughly double or triple the pipeline tolls from Alberta to U.S. markets [40]. For scale, Enbridge's uncommitted toll for heavy crude from Edmonton to Houston was US$9.84 a barrel after a cut in September 2024 [27]. The CER still says it generally costs less per barrel to ship by pipeline [8]. Rail therefore grows when the WCS discount is wide enough to cover the extra cost, and shrinks when pipelines have room.

Year Crude-by-rail exports (average bbl/d)
2013 126,200
2014 161,000
2017 131,800
2018 242,200
2019 281,400
2020 169,700
2022 143,500
2024 88,700
2025 77,200
2026 (January to July) 80,200

Annual averages calculated from CER monthly export data [41].

The 2018–2020 surge

Rail exports hit a then-record 327,229 bbl/d in October 2018 as pipelines filled [37]. The CER calls 2019 the annual high for rail, and the monthly record of 412,000 bbl/d came in February 2020 [8].

Government got involved directly. Shortly before the spring 2019 election, Alberta's NDP government signed $3.7 billion in contracts to move 120,000 bbl/d with Canadian Pacific and Canadian National [42]. The UCP government that followed moved the contracts to the private sector in February 2020. Premier Jason Kenney put the cost to taxpayers at $1.3 billion, while the NDP argued the contracts would have been profitable [42].

The surge faded as pipeline space arrived. The CER credits the Line 3 Replacement in October 2021 (370,000 bbl/d) and the Trans Mountain Expansion in May 2024 (590,000 bbl/d) with pulling barrels off rail. Narrower price differentials made rail uneconomic, and by 2025 rail carried just 1.8 per cent of crude exports [8]. In its outlook the CER assumes a base of "structural" rail, about 77,000 bbl/d, that persists where producers or refineries lack pipeline connections [13].

The WCS–WTI differential

WTI is a light, sweet (low-sulphur) U.S. crude and North America's main benchmark. WCS is a heavy, sour (high-sulphur) blend made mostly from Alberta bitumen, which yields fewer valuable products and is harder to refine [43]. WTI is priced at Cushing, Oklahoma, and WCS at Hardisty [12]. The gap between them is the differential, and it has three main parts.

  1. Quality. Heavy, high-sulphur crude yields more asphalt and heavy fuel oil unless a complex refinery upgrades it, so it trades below light sweet crude [12].
  2. Transport. WCS must be shipped a long way to reach buyers, and pipeline tolls for heavy crude are higher than for light crude because it takes more pumping and moves more slowly [12]. The CER estimates that when pipelines have room, quality and transport together leave WTI about US$12.50 above WCS [13]. CAPP uses about US$13 as the theoretical level that matches pipeline costs to the Gulf Coast plus the quality discount [12].
  3. Congestion. When production outruns export capacity, oil backs up into storage and sellers compete for scarce space, pushing the discount well beyond the cost of transport [12][13].

New pipelines cannot change crude quality, but they can remove most of the congestion discount.

Year Average WTI–WCS differential (US$/bbl)
2017 11.91
2018 26.48
2019 12.71
2020 12.42
2021 13.12
2022 18.78
2023 18.67
2024 15.56
2025 11.76
2026 (January to August) 15.53

Annual averages calculated from the Government of Alberta's monthly WTI and WCS prices [9].

Interactive: start from a WTI price, subtract the differential and transport, and see what reaches the field.

The 2018 blow-out and curtailment

By late 2018 Alberta's output of about 3.67 million bbl/d exceeded takeaway capacity by about 190,000 bbl/d, and storage had doubled beyond normal levels [44]. WCS traded at a record discount that year; the monthly average differential in Alberta's data reached US$45.93 in November and US$43.55 in December 2018 [9], and some trading days saw discounts near US$50 [37]. The Alberta government estimated the differential was costing the Canadian economy more than $80 million a day [44].

On December 2, 2018, the province announced mandatory production cuts effective January 1, 2019, set out in regulations issued the next day; the AER then contacted the operators subject to ministerial orders [45]. The initial cut was 325,000 bbl/d, expected to fall to an average of about 95,000 bbl/d for the rest of 2019 once excess storage was drawn down [44]. The differential narrowed quickly, to a monthly average of US$9.62 in February 2019 [9].

Curtailment was contested. Most investors and companies favoured the intervention; the exceptions were three integrated producers whose refineries had benefited from cheap Alberta crude [44]. The government eased the rules over time. In August 2019 it raised the exemption so only producers above 20,000 bbl/d were limited, leaving 16 of more than 300 producers subject to caps. In November 2019 it exempted new conventional wells, and it stopped setting monthly limits in December 2020 [46].

Before and after Trans Mountain

The discount widened again as production grew into the remaining space. It averaged US$18.70 between September 2023 and April 2024, then US$12.00 from June 2024 to July 2025, after the expansion opened [18].

How much is that worth? CAPP, an industry association, estimates the post-expansion discount has been about US$3 a barrel narrower than from 2014 to April 2024, adding $4 billion to $5 billion a year in industry revenue at December 2025 production. It also puts foregone revenue from differentials wider than about US$13 at US$49 billion from January 2010 to May 2024 [12]. The Fraser Institute, a market-oriented think tank, estimated $20.7 billion in foregone revenue from 2013 to 2017 [47]. These estimates rest on assumptions about what the discount should be, and they do not settle the separate question of the expansion's public cost [7].

The discount is not set by pipelines alone. In spring 2026, as WTI jumped during the U.S. war with Iran, the WCS discount widened to more than US$16 a barrel; analysts pointed to the WTI surge and U.S. Strategic Petroleum Reserve releases rather than a lack of Canadian pipeline space [48][49]. Alberta's data show about US$19 in May and June 2026 and US$15.69 in August [9]. The 2026 budget also flagged more Venezuelan heavy oil reaching the U.S. Gulf Coast as a competitive risk [10].

How the discount reaches Alberta's treasury

Alberta's oil sands royalty rates rise and fall with the WTI price in Canadian dollars, but the royalty is charged on a project's revenue, after subtracting the cost of diluent [50]. That revenue depends on the price the bitumen actually fetches, and most heavy oil in western Canada is sold at prices tied to WCS [35]. A wider differential therefore shrinks the base the royalty is charged on, even when WTI is unchanged.

Alberta's Budget 2026 quantifies the effect. It estimates that a US$1 widening of the light-heavy differential reduces 2026–27 revenue by about $670 million, almost as much as a US$1 drop in WTI ($680 million) [10]. The budget estimates the differential at US$11.20 in 2025–26 and forecasts it to widen to US$13.00 in 2026–27 and US$14.10 in 2027–28 as production grows [10]. For a fuller look at prices and the provincial budget, see the companion guide on oil prices and Alberta's economy.

Diluent: the barrels that travel both ways

Bitumen is too thick to flow in a pipeline on its own, so producers blend it with a light hydrocarbon called diluent, usually natural gas condensate, to make diluted bitumen, or dilbit (see the oil sands guide). Diluent flows into Alberta, is blended into bitumen and flows back out inside the export barrels.

Alberta's own condensate supply has fallen short of demand since 2004, so the province imports it [20]. In 2021 the three largest diluent sources supplied 678,000 bbl/d, 14 per cent of western Canadian crude oil and equivalent supply, up from 7 per cent in 2011; pipeline imports provided 226,000 bbl/d of it [51].

Two CER-regulated pipelines bring condensate north from the U.S. Midwest. Southern Lights averaged 176,000 bbl/d in 2025, up from 65,000 bbl/d in 2011, and Cochin averaged 95,000 bbl/d, up from 49,000 bbl/d in 2014. Alberta imported about 200,000 bbl/d of refined petroleum products in 2025, mostly condensate for the oil sands [52]. Demand for Cochin space was strong in 2026: its uncommitted nominations were apportioned by 69 to 92 per cent each month from February to June [32].

Diluent also takes up export space. The AER counts 119.4 thousand m³/d (751,100 bbl/d) of diluent, mainly pentanes plus, among 2024 removals of bitumen blends from Alberta, and forecasts 933,700 bbl/d by 2034, an increase of 24.3 per cent [16]. Demand rises in cold weather: the Mainline's throughput peaked in January and February 2025 partly because more condensate was needed to keep bitumen flowing [27].

One way to free that space is a diluent recovery unit (DRU), which separates diluent from dilbit so it can be reused in Alberta. Gibson Energy and USD Partners sanctioned a 50,000 bbl/d DRU at Hardisty in February 2020, backed by ConocoPhillips Canada, to ship the heavier product by rail to the U.S. Gulf Coast without returning the diluent [53].

Regulation, tolls and the pipelines that stalled

Who regulates what

Canada splits pipeline oversight by geography. Pipelines that cross a provincial boundary or the Canada–U.S. border are regulated by the CER. That covers about 73,000 km, roughly 10 per cent of the more than 760,000 km of hydrocarbon pipelines in Canada [54].

Pipelines entirely within Alberta are regulated by the AER. The province has more than 450,750 km of oil and gas pipelines, and companies must follow the Pipeline Act, the Pipeline Rules and the CSA Z662 technical standard from design through abandonment [55]. The feeder lines that carry oil sands output to Edmonton and Hardisty are therefore provincial, while the export lines leaving those hubs are federal.

Tolls, tariffs and settlements

A toll is the price a shipper pays to move a barrel. A tariff is the document, filed with the CER, that sets out tolls and the terms of service, and a company cannot charge a toll that is not in a filed or approved tariff [38]. The CER's job is to make sure tolls are "just and reasonable" and that there is no unjust discrimination in tolls, service or facilities [38]. Large pipelines with many shippers (Group 1) are regulated closely; smaller Group 2 lines are regulated mainly when someone files a complaint [38].

In practice many tolls are negotiated between a pipeline and its shippers and then approved by the CER [38]. The Enbridge Mainline operates under a Mainline Tolling Settlement covering July 2021 to December 2028 [4], while Express uses market-based tolls [22].

Tolls on the expanded Trans Mountain system have been charged on an interim basis, subject to a CER hearing [6]. On July 7, 2026, Trans Mountain filed a negotiated settlement with shippers, and the CER paused its tolls hearing to review it [56]. The settlement would finalize tolls back to May 1, 2024, raise firm (contracted) service from 80 to 90 per cent of capacity and take effect January 1, 2027; Trans Mountain asked for approval by October 1, 2026 [57]. No decision had been published in the sources reviewed for this guide.

Keystone XL

Keystone XL was designed to carry 830,000 bbl/d over 1,947 km from Hardisty to Steele City, Nebraska [58]. It needed a U.S. presidential permit to cross the border. The permit issued on March 29, 2019, was revoked on January 20, 2021, by Executive Order 13990, which cited climate and national interest considerations [59]. Alberta had backed the project with a $1.5 billion equity investment in 2020 and a $6 billion loan guarantee in 2021, and the province's final cost was about $1.3 billion [58]. TC Energy confirmed on June 9, 2021, that it had terminated the project, in consultation with the Government of Alberta [60].

Northern Gateway and the north coast tanker ban

Enbridge's Northern Gateway would have run 1,177 km from Bruderheim, northeast of Edmonton, to Kitimat, B.C. The Federal Court overturned its earlier approval for inadequate consultation with First Nations, and on November 29, 2016, the federal cabinet rejected it, the same day it approved the Trans Mountain Expansion and Enbridge's Line 3 Replacement [29]. The government also announced a ban on crude oil tankers along B.C.'s north coast [29]. That law took effect in 2019 and bars tankers carrying more than 12,500 tonnes of crude oil in waters off northern B.C. [61].

Line 5

Line 5 is part of Enbridge's system to Sarnia, carrying crude oil and natural gas liquids from western Canada to refineries in Ontario and Quebec beneath the Straits of Mackinac in Michigan. On November 13, 2020, Michigan's governor and Department of Natural Resources issued a notice revoking the state easement for the crossing, intended to shut the line permanently. On October 4, 2021, Canada formally invoked the dispute settlement provision of its 1977 transit pipelines agreement with the U.S. [62].

The dispute continues. In July 2026 the Michigan Supreme Court invalidated the state utility regulator's approval of a replacement tunnel under the straits, and on August 12, 2026, the U.S. Army Corps of Engineers issued its federal permit for the tunnel. Michigan's lawsuit to shut the line was still pending, and opponents noted the Corps found major, permanent adverse effects on a cultural landscape significant to Anishinaabe peoples [63].

Safety and spills

For federally regulated pipelines, the Transportation Safety Board (TSB) received 60 reports in 2025, all classified as incidents rather than accidents. Twenty involved a release of product; 18 of those were natural gas, and only two involved crude oil or refined products. The occurrence rate of 0.9 per 1,000 km was below the 2015–2024 average of 1.3. About 21,000 km of those pipelines carried oil, and the TSB says no fatality has arisen directly from operating a federally regulated pipeline since it was created in 1990 [64].

For provincially regulated pipelines, the AER counted 277 incidents in 2025, down from 306 in 2024. The incident rate was 0.61 per 1,000 km, compared with 1.05 in 2016. Ninety-two per cent of incidents were rated low consequence and three were high consequence. Internal corrosion was the leading cause, at 38 per cent, and the largest release of the year was 159 m³ of produced water [65].

Major releases still happen. In December 2022 Keystone spilled nearly 13,000 barrels of crude into Mill Creek in Kansas; investigators traced it to a faulty weld in a pipe bend [66]. A second Keystone release in North Dakota in April 2025 shut the line until April 14, and it restarted at reduced pressure [27].

Companies must also fund the end of a line's life. The CER requires set-asides for abandonment: the Mainline's estimated cost is $2.4 billion, with $465.7 million in trust in 2025, and Trans Mountain's is $647 million, with $147.5 million in trust [4][6].

Indigenous ownership

Export pipelines cross the territories of many First Nations and Métis communities, and equity stakes are now central to the debate over new projects.

In 2022, Athabasca Indigenous Investments, a partnership of 23 Treaty 6 and Treaty 8 First Nations and Métis communities, agreed to buy an 11.57 per cent non-operating interest in seven Enbridge oil sands pipelines for $1.12 billion. A loan guarantee from the Alberta Indigenous Opportunities Corporation was key to financing the deal [34].

Trans Mountain is the next test. The federal government consulted 129 Indigenous groups before re-approving the expansion in 2019 [30], and later committed to explore Indigenous economic participation in the expansion with those communities [67]. On September 22, 2026, it offered those communities a collective 15 per cent stake, financed through a low-cost government loan. It also offered each participating nation a $2.5 million goodwill payment and up to $100,000 to cover participation costs through March 2028. Details are to be presented at meetings in Vancouver, Victoria, Kamloops and Edmonton in late October 2026, and no sale has closed [68].

Reaction has been mixed. Some leaders, including the head of the Indian Resource Council, said Ottawa should offer at least 50 per cent. Project Reconciliation, which has proposed full Indigenous ownership, set 30 per cent as a minimum. Others, such as the National Coalition of Chiefs, welcomed the offer as a way to gain influence over hiring and environmental monitoring [69]. Alberta says Indigenous co-ownership is central to its proposed West Coast Oil Pipeline [70].

What's next for egress

"Egress" is industry shorthand for export capacity out of western Canada. After Trans Mountain opened in May 2024, western Canada had spare export pipeline capacity again after a shortage that began in mid-2018 [12]. By 2026 that cushion was thinning. In the first half of 2026 the Mainline ran at about 96 per cent of available capacity, Keystone was full in most months, and Trans Mountain reached about 99 per cent in April and 96 per cent in June (calculated from CER data) [32]. Apportionment had returned on some Mainline lines [32].

Expansions under way or sanctioned

Alberta's Budget 2026 expects Trans Mountain, Express and Mainline optimization projects to add about 700,000 bbl/d of egress between 2026 and 2030, a government forecast [10]. CAPP lists up to 400,000 bbl/d of possible Mainline optimization and up to 360,000 bbl/d on Trans Mountain, industry estimates of opportunity rather than approved projects [12].

New pipelines under discussion

On November 27, 2025, Canada and Alberta signed a memorandum of understanding (MOU) that set a path for a new bitumen pipeline to the West Coast [61]. A second, non-binding MOU dated July 2, 2026, signed by Canada, Alberta and five oil sands producers, calls the pipeline and the Pathways carbon capture project "mutually dependent" and says Canada is pursuing a Trans Mountain expansion of an estimated 300,000 to 400,000 bbl/d [74].

The same day, Canada referred Alberta's West Coast Oil Pipeline proposal to the Major Projects Office: a 1 million bbl/d line of about 1,250 km from Bruderheim, largely following the Trans Mountain corridor to a deepwater port in southern B.C., with the final route still to be set. Canada gave notice on August 1, 2026, that it may list the project as a national-interest project under the Building Canada Act, with a decision intended by October 1, 2026 [11]. Alberta's submission estimated the cost at $35.2 billion to $43.7 billion, with a terminal at Delta, B.C.; the route crosses the territories of about 125 Indigenous communities [75]. Trans Mountain Corporation and Pembina Pipeline are development partners [70]. B.C. Premier David Eby has said the arrangement keeps the northern tanker ban in place [75].

Status, as of September 28, 2026: the West Coast Oil Pipeline is a government-led proposal. It had not yet been listed as a national-interest project, had no regulatory approval and had no final investment decision [11].

Will there be enough room?

The CER's 2026 outlook compares projected oil available for export with capacity from existing pipelines, sanctioned expansions and structural rail. In its Current Measures scenario, export supply hovers around capacity early on and then exceeds it for much of the period, by as much as 178,000 bbl/d in 2039. In its Higher scenario the gap reaches nearly 700,000 bbl/d; in its Lower scenario supply stays below capacity throughout [13]. The CER stresses that these are illustrations, not forecasts of pipeline use [13].

Supporters of new capacity argue that it protects prices and diversifies customers; CAPP expects the discount to widen again once Trans Mountain is full unless other systems expand [12]. Opponents raise climate commitments, tanker and spill risks, and Indigenous consent; environmental groups have argued since 2016 that more pipelines are hard to square with Canada's climate targets [29]. Who bears the cost also remains contested, as the PBO's Trans Mountain analysis shows [7].

Check your understanding

Eight questions drawn from this guide. Your best score is kept on this device.

FAQ

Why does Alberta oil sell for less than WTI? Mostly because of quality and distance. WCS is heavy and high in sulphur, so it yields fewer valuable products, and it must travel a long way by pipeline to reach refiners [43][12]. When pipelines have room, the CER says the gap is typically about US$12.50 a barrel; when they are full, it can reach US$25 or more [13].

What is pipeline apportionment? It is the percentage by which each shipper's monthly nomination is cut when requests exceed a pipeline's uncommitted capacity. At 10 per cent apportionment, a shipper that asked to move 100 barrels can move 90 [4].

How much oil can Trans Mountain carry, and who owns it? About 890,000 bbl/d since the expansion entered service on May 1, 2024 [6]. It is owned by the federal government through Trans Mountain Corporation, a Crown corporation, and in September 2026 Ottawa offered Indigenous communities a collective 15 per cent stake [6][68].

Is crude still shipped by rail? Yes, but much less than before. Rail exports averaged 77,200 bbl/d in 2025, 1.8 per cent of crude exports, compared with a monthly record of 412,000 bbl/d in February 2020 [8]. Rail generally costs more than pipeline transport, so it grows mainly when pipelines are full [40].

What happened to Keystone XL? The U.S. presidential permit was revoked on January 20, 2021, and TC Energy terminated the project on June 9, 2021 [59][60]. Alberta, which had invested in the project, put its final cost at about $1.3 billion [58].

Why does Alberta import condensate? Bitumen needs diluent to flow in pipelines, and Alberta's own condensate supply has not met demand since 2004 [20]. The Southern Lights and Cochin pipelines together delivered about 271,000 bbl/d from the U.S. in 2025 (sum of the two lines' averages) [52].

Is a new West Coast pipeline being built? Not yet. Alberta's 1 million bbl/d West Coast Oil Pipeline proposal was referred to the federal Major Projects Office on July 2, 2026, and a decision on listing it as a national-interest project was intended by October 1, 2026 [11]. It has no regulatory approval or final investment decision.

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