Enbridge and TC Energy: The Pipeline Giants That Move North American Energy

Enbridge and TC Energy are not oil and gas companies; they are the toll roads of the North American energy system, and their business model depends on being allowed to build and keep operating them. Between them the two Calgary companies carry roughly 30% of the crude oil produced in North America, a quarter of the natural gas consumed in the United States and most of the energy that crosses the Canada–US border. Their regulated, contracted cash flows have made them two of the most widely held dividend stocks in Canada, with Enbridge marking its 31st consecutive annual dividend increase in 2026. This article explains how each company is structured, what has changed since TC Energy’s South Bow spin-off, why Enbridge spent US$14 billion on American gas utilities, where the Line 5, Mainline and Coastal GasLink projects stand in October 2026, and what Keystone XL still teaches. It is part of the Canada Company Stories hub.

How did two Calgary companies end up controlling North American energy flows?

They did it by building the original cross-border lines in the 1950s and then compounding through acquisitions for seven decades. Enbridge began in 1949 as Interprovincial Pipe Line, created to move Alberta crude from the Leduc discovery east to Ontario and the US Midwest; the Mainline it built is still the largest crude system on the continent. TransCanada PipeLines, formed in 1951, built the gas Mainline from Alberta to Montreal and then expanded south through acquisitions of ANR, Columbia Pipeline Group (US$13 billion, 2016) and others. Both companies rebranded, Enbridge in 1998 and TC Energy in 2019, to reflect businesses that had become more American than Canadian.

Enbridge’s transformational deal was the C$37 billion acquisition of Spectra Energy in 2017, which brought the Texas Eastern and Algonquin gas systems and made it the largest energy infrastructure company in North America. TC Energy’s equivalent was Columbia, which gave it the Appalachian gas gathering and transmission network that now feeds LNG exporters on the Gulf Coast. The result is that Enbridge’s Mainline carried 3.1 million barrels a day in 2025 and its gas transmission network moves around 20% of US gas consumption, while TC Energy’s NGTL system in Alberta delivered an average of 24.2 billion cubic feet a day in the second quarter of 2026.

The companies share a corporate model: long-term contracts or regulated cost-of-service tolls, investment-grade balance sheets levered at 4.5–5.0 times EBITDA, and dividends that grow every year. That model made them core holdings for the Canadian pension funds and for retail investors who treat them as bond substitutes. It also means that every project delay or regulatory setback shows up directly in the share price.

What does Enbridge’s business look like after the US utility purchases?

It looks like the largest gas utility in North America attached to the largest oil pipeline, with a renewable power business on the side. In September 2023 Enbridge agreed to buy three gas distribution utilities from Dominion Energy for US$14 billion including debt: East Ohio Gas, Questar Gas in Utah and Public Service Company of North Carolina. The deals closed in 2024 and the utilities were renamed Enbridge Gas Ohio, Enbridge Gas Utah and Enbridge Gas North Carolina. Combined with Enbridge Gas in Ontario, the group now serves about seven million customers.

The logic was to shift the earnings mix toward regulated, rate-base businesses with predictable growth and away from the liquids pipeline, where volumes depend on oil sands output and on political permission. By the second quarter of 2026 the US gas utilities contributed C$380 million of adjusted EBITDA for the quarter, up from C$335 million a year earlier, as rate cases in Utah and North Carolina lifted base rates. The Ohio rate case produced a constructive staff report and Enbridge expected a settlement in 2027. Chief executive Greg Ebel describes the strategy as “all of the above”: gas, oil, power and the regulated wires and pipes that connect them.

The 2025 results show the mix. Adjusted EBITDA was C$19.95 billion, up 7%; GAAP earnings C$7.1 billion or C$3.23 a share; distributable cash flow C$12.5 billion, up 4%; and the company met its financial guidance for the 20th consecutive year. Enbridge sanctioned about C$14 billion of new projects in 2025, brought C$5 billion into service and ended the year with a C$39 billion secured backlog, which grew to C$41 billion by mid-2026. For 2026 it guides to adjusted EBITDA of C$20.2–20.8 billion and distributable cash flow of C$5.70–6.10 a share, with roughly 5% annual growth thereafter. The quarterly dividend is C$0.97, or C$3.88 a year.

The renewable business has quietly become material. Over the twelve months to mid-2026 Enbridge sanctioned 1.4 gigawatts of solar and onshore wind and 1.6 gigawatt-hours of battery storage, mostly under long-term power purchase agreements with Meta to supply data centres, and it holds more than 1.5 gigawatts of further “safe-harboured” opportunities. For a company whose name is synonymous with oil, that is a notable hedge.

Why is Line 5 the most politically exposed pipeline in North America?

Because it runs under the Straits of Mackinac between Lake Michigan and Lake Huron, carries about 540,000 barrels a day of crude and natural gas liquids from Superior, Wisconsin to Sarnia, Ontario, and has been the target of a state-ordered shutdown since November 2020. Michigan Governor Gretchen Whitmer revoked the 1953 easement that allows the dual pipelines to cross the lakebed, citing the risk of a spill in the Great Lakes; Enbridge refused to comply, arguing that only the federal Pipeline and Hazardous Materials Safety Administration can order a shutdown, and Canada invoked the 1977 Transit Pipelines Treaty with the United States for the first time in its history. The line supplies refineries in Ontario and Quebec and a large share of Michigan’s propane, which is why both Ottawa and Queen’s Park treat its closure as a national economic threat.

Enbridge’s answer is a tunnel. Under a 2018 agreement with Michigan’s previous administration, the company proposed to replace the lakebed crossing with a four-mile pipeline inside a concrete-lined tunnel bored about 100 feet beneath the Straits. The project needs three sets of approvals. The Michigan Public Service Commission granted its permit in December 2023; the Michigan Department of Environment, Great Lakes and Energy (EGLE) issued state environmental permits; and on 12 August 2026 the US Army Corps of Engineers issued the federal permit after a review the company describes as more than six years long, accelerated under a 2025 presidential energy-emergency order.

The litigation is not over. On 31 July 2026 the Michigan Supreme Court ruled that the Public Service Commission must redo its permit review because it had improperly limited consideration of alternatives, a decision tribes and environmental groups had sought. In September Governor Whitmer said EGLE must take that ruling into account when considering its own permits. The Bay Mills Indian Community called the Corps’ approval a breach of treaty obligations, and several tribes had withdrawn as cooperating agencies in protest at the expedited timeline. Separately, Enbridge is relocating a 41-mile segment of Line 5 in Wisconsin around the Bad River Band’s reservation, a roughly US$1 billion project now under construction with all key permits secured and in service expected in early 2027. Line 5 is thus both a cautionary tale and a demonstration that Enbridge will spend a decade and billions to keep a 70-year-old line running.

Why did Enbridge shelve the second phase of its Mainline expansion?

Because the oil sands producers would not sign binding commitments for new capacity until the policy changes promised by Ottawa and Alberta become law. Enbridge had proposed Mainline Optimisation in two phases. Phase 1, sanctioned at US$1.4 billion, adds 150,000 bbl/d to the Mainline and 100,000 bbl/d to the Flanagan South line from Illinois to Cushing, with service expected in 2027. Phase 2 would have added a further 250,000 bbl/d as early as the end of 2028. In August 2026 the company postponed Phase 2, with chief financial officer Colin Gruending acknowledging that Enbridge may have proposed it too early and that producers were not expected to make final-investment-decision-quality commitments until there was more regulatory certainty.

The decision reveals how the pipeline business actually works. Enbridge does not build on speculation; it runs open seasons in which shippers commit volumes under long-term contracts, and it sanctions capacity only when those commitments cover the capital. The Mainline is full, apportioned for nine months of 2025, and the oil sands producers are setting production records, yet they will not sign because the federal emissions policy, the industrial carbon price and the proposed new West Coast pipeline are all in flux. Instead Enbridge is prioritising the smaller Flanagan South (100,000 bbl/d) and Southern Access Extension (50,000 bbl/d) projects, which connect to Gulf Coast and Midwest refineries and can be filled with existing supply.

For Canadian export capacity, the postponement means that most of the incremental barrels in 2027–2028 will go west through the Trans Mountain system, whose own optimisation adds 300,000 bbl/d, rather than south through Enbridge. That is a historic reversal of the direction Canadian oil has flowed for 70 years.

What did the South Bow spin-off do for TC Energy?

It turned TC Energy into a pure-play natural gas and power company and handed the Keystone system, with its political baggage, to a new entity. On 1 October 2024 TC Energy completed the spin-off of its liquids pipelines business as South Bow Corporation, a Calgary company listed in Toronto and New York and led by chief executive Bevin Wirzba. South Bow owns the 4,300-kilometre Keystone pipeline from Hardisty, Alberta to the US Gulf Coast, plus the Marketlink and Grand Rapids systems. TC Energy shareholders received 0.2 South Bow shares for each TC share.

South Bow’s first two years show why TC Energy was willing to let it go. In April 2025 Keystone ruptured near Fort Ransom, North Dakota, releasing about 3,500 barrels and prompting a corrective action order from US regulators; an independent root-cause analysis in February 2026 attributed the failure to a weld fatigue crack and found no systemic issue. In July 2026 the company agreed to pay a US$26.9 million penalty for the December 2022 spill of about 13,000 barrels in Kansas, the largest on the system. Operationally the business is steady: Keystone moved about 616,000 bbl/d in the first quarter of 2026 at a 95% operating factor, the Blackrod connection entered service on schedule, and 2026 guidance is normalised EBITDA of about US$1.03 billion and distributable cash flow of about US$655 million, supporting a US$0.50 quarterly dividend.

TC Energy, meanwhile, reported second-quarter 2026 comparable EBITDA of C$2.95 billion, up 12% year on year, and comparable earnings of C$0.94 a share. It expects 2026 comparable EBITDA at the upper end of C$11.6–11.8 billion, with capital spending of C$6.0–6.5 billion, and is working toward a 4.75x debt-to-EBITDA target from 4.8x at the end of 2025. Chief executive François Poirier has sanctioned about C$3 billion of new gas projects in 2026, including Central Virginia Capacity and Clark on the Columbia systems, both backed by 20-year take-or-pay contracts and partly aimed at gas-fired power for data centres. TC Energy’s own forecast sees North American gas demand growing by about 51 billion cubic feet a day between 2025 and 2035, driven by LNG exports, power generation and industry.

What happened with Coastal GasLink, and why does Phase 2 matter?

Coastal GasLink is the 670-kilometre pipeline from Dawson Creek to Kitimat that feeds the LNG Canada terminal, and its first phase was the most expensive and contested gas pipeline in Canadian history, which is why the September 2026 go-ahead for Phase 2 is significant. TC Energy built the line between 2019 and 2023 at a final cost of about C$14.5 billion, more than double the original C$6.2 billion estimate, through terrain, weather, pandemic delays and blockades by Wet’suwet’en hereditary chiefs who opposed the route despite agreements with all 20 elected First Nations councils along it. TC Energy owns 35% of the pipeline, with KKR and the Alberta Investment Management Corporation holding the remaining 65% since 2020, and it operates the system.

Phase 2 became certain on 29 September 2026, when LNG Canada’s partners took their final investment decision to double the Kitimat terminal to 28 million tonnes a year. TC Energy’s own conditional decision had been contingent on that step. Phase 2 nearly doubles pipeline capacity from about 2.1 billion cubic feet a day by adding compressor stations along the existing right-of-way, with construction from early 2027, up to 2,100 workers at peak and in-service in the early 2030s. Critically for TC Energy’s shareholders, LNG Canada will act as execution manager for the construction, and Coastal GasLink’s capital commitments and exposure to cost and schedule risk are limited, an arrangement that reflects the lessons of Phase 1. The full story of the terminal is in the LNG Canada article.

For TC Energy’s NGTL system, which gathers the gas in Alberta and northeastern B.C., the expansion locks in demand growth for a decade. Valhalla North and Berland River added about 400 million cubic feet a day in 2026 for roughly C$0.5 billion, and the company’s Greater Edmonton delivery offering is fully subscribed. Gas, unlike oil, is a market where Canadian producers can still sign the long-term commitments that pipeline builders need.

What does Keystone XL still teach about cross-border infrastructure?

It teaches that a project can be commercially sound, fully contracted and still fail if it becomes a political symbol. TC Energy proposed Keystone XL in 2008 as an 830,000 bbl/d line from Hardisty to Steele City, Nebraska, connecting to the Gulf Coast. The Obama administration rejected it in 2015, the Trump administration approved it in 2017, construction began in 2020 with C$1.5 billion of Alberta government equity and a C$6 billion loan guarantee, and President Biden revoked the permit on his first day in office in January 2021. TC Energy wrote off the project, Alberta lost its investment, and a US$15 billion claim under the old NAFTA investor-state provisions was dismissed in 2024 on jurisdictional grounds.

When President Trump returned to office and said in February 2025 that Keystone XL should be built “now”, South Bow, as the owner of the Keystone system, responded through a spokesperson that the company had moved on and would not seek to revive the project, while continuing to look at other ways to move Canadian oil. That answer is the most honest assessment of the project’s lesson: once a pipeline has been cancelled twice, no board will commit capital on the strength of a single administration’s enthusiasm, however sincere. The broader Canada–US trade environment of 2025–2026, covered in the Canada–US trade war article, has only reinforced the preference for routes that do not depend on a presidential permit.

How are data centres changing the gas pipeline business?

They are giving gas transmission companies their first large new source of domestic demand in a decade, and both Enbridge and TC Energy have redirected capital toward it. TC Energy’s Central Virginia Capacity project will deliver up to 400 million cubic feet a day for gas-fired generation serving data-centre load, with 20-year contracts and in-service in 2028 and 2030. Enbridge’s Texas Eastern and East Tennessee rate cases, and its Bay Runner Twin project (2.6 billion cubic feet a day for Rio Grande LNG by 2030), reflect the same demand pull, while its Meta-backed solar and wind projects show that the hyperscalers are buying both fuels at once.

The shift matters because it diversifies away from the oil sands question. Enbridge’s gas transmission and utilities now account for well over half of its EBITDA, and TC Energy is entirely gas and nuclear. The data-centre buildout in Virginia, Ohio, Texas and Alberta, where the Canadian AI sector is also seeking sovereign compute capacity, is being underwritten by pipeline contracts that will outlast the current generation of chips.

What can founders and investors learn from Enbridge and TC Energy?

The central lesson is that the most durable businesses are those that earn a toll on activity they do not have to predict. Neither company bets on the oil price or the gas price; they charge for moving molecules under contracts that run 15–20 years. Founders building platforms, marketplaces or infrastructure software can apply the same test: are you exposed to the volume of activity, or to the price of the underlying commodity? The former scales with the economy; the latter is a trade.

Second, both companies demonstrate the value of a spin-off when one business taints the valuation of another. TC Energy’s investors could not value its gas growth while Keystone’s spills and politics dominated the narrative; South Bow now trades on its own merits, and TC Energy has re-rated. The same logic has driven Canadian conglomerates from Brookfield to Constellation Software to separate businesses with different risk profiles.

Third, the Mainline Phase 2 postponement shows the discipline of contracted capital. Enbridge could have built on the expectation that the oil sands would fill the line, as Trans Mountain’s owners effectively did; it chose not to, and its balance sheet is better for it. Growth that is not underwritten by customer commitments is speculation, whatever the sector.

Fourth, and most specific to Canada, the Line 5 and Keystone XL experiences show that political permission is a perishable asset. A pipeline approved by one administration can be cancelled by the next; a 70-year-old easement can be revoked. Companies that depend on cross-border infrastructure now treat the Canada–US relationship as a risk to be diversified, which is why the West Coast gas and oil terminals matter so much and why the comparison with the UK Company Stories hub, where National Grid faces similar regulatory cycles, is instructive.

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