LNG Canada: How Kitimat Became Canada’s First Gas Export Gateway to Asia

Kitimat has become the place where Canada’s natural gas finally meets the Pacific, and the business model that got it there is as important as the molecules. For most of the 2010s, Canada proposed more than 20 LNG export terminals on the British Columbia coast and built none; the gas stayed trapped in Alberta and northeastern B.C., selling at a discount to a single American customer. LNG Canada changed that with a consortium of Asian buyers who were also owners, a pipeline built by a Canadian operator, a fiscal deal with the province and a set of agreements with First Nations that later projects have copied and extended. This article explains how the Kitimat project was financed and built, what the first year of exports has shown, why the Phase 2 decision matters, how Cedar LNG, Woodfibre and Ksi Lisims differ, and how Canadian LNG competes on cost and carbon with the US Gulf Coast. It is part of the Canada Company Stories hub.

Why did it take Canada so long to export LNG?

Because the economics never closed for a standalone developer: the gas was cheap but the pipeline, the terminal and the provincial tax regime each added cost, and the Asian buyers who could underwrite 20-year contracts preferred projects in Australia, Qatar and the US Gulf where someone else had already taken the construction risk. Between 2011 and 2017 proposals from Petronas (Pacific NorthWest LNG), Shell (LNG Canada), Chevron and Woodside (Kitimat LNG), ExxonMobil (WCC LNG) and others competed for the same gas, the same pipeline corridors and the same First Nations agreements. Petronas cancelled Pacific NorthWest in July 2017, citing market conditions, after years of federal environmental review.

Shell’s approach was different in one crucial respect: it assembled a consortium of state-backed Asian buyers as equity partners rather than seeking offtake contracts from third parties. Petronas (Malaysia), PetroChina, Mitsubishi and Korea Gas each took a stake proportional to the LNG they would lift, which meant the project’s revenue was effectively guaranteed by its owners’ home markets. The B.C. government of John Horgan added a fiscal framework in 2018 that deferred provincial sales tax on construction, exempted the project from the planned LNG income tax and set a carbon-tax arrangement for the lowest-emitting facilities. Combined with a decision to build in Kitimat, a deep-water port with an existing industrial site and strong support from the Haisla Nation, the pieces finally fit.

The final investment decision came on 1 October 2018, for a project then described as the largest private-sector investment in Canadian history at about C$40 billion including the pipeline. The lesson for the dozen failed proposals was that the gas resource was never the problem; the capital structure was.

How was the Kitimat terminal built, and what did it cost?

It was built over almost seven years by a Fluor–JGC joint venture on the site of a former methanol plant, with the two liquefaction trains and the marine terminal completed in 2025, and the total cost including Coastal GasLink was about C$40 billion. The terminal itself was budgeted at around C$18 billion at the 2018 decision; the pipeline, originally estimated at C$6.2 billion, ended up costing TC Energy and its partners about C$14.5 billion after construction through mountainous terrain, pandemic disruption, flooding and protests. The terminal’s engineering contract absorbed much of the labour-cost inflation of the period.

The facility uses gas turbines for the main refrigeration compressors, which was controversial, but its design intensity of about 0.15 tonnes of CO2 equivalent per tonne of LNG compares with a global average of 0.26–0.35. Phase 1 is expected to emit roughly 4 million tonnes of greenhouse gases a year. The project employed more than 7,000 workers at peak and the operator, LNG Canada, led by president Chris Cooper, has reported more than C$5 billion of contracts awarded to businesses in B.C., with over C$1.8 billion of Coastal GasLink’s contracts going to Indigenous and local firms.

The feed gas comes from the Montney formation in northeastern B.C. and Alberta, one of the lowest-cost gas plays in North America, carried 670 kilometres by Coastal GasLink to the coast. The pipeline is owned 35% by TC Energy, which operates it, and 65% by KKR and the Alberta Investment Management Corporation. Its history, including the C$14.5 billion cost and the Wet’suwet’en blockades of 2019–2020, is covered in the Enbridge and TC Energy article.

What has the first year of exports shown?

It has shown that the Kitimat location delivers on its central promise: short, reliable voyages to the buyers in Northeast Asia who pay the highest prices for LNG. The first cargo departed on 30 June 2025 aboard the GasLog Glasgow; by the time the second train started in November 2025 more than 20 cargoes had shipped, the 50th left in February 2026 and the total passed 100 before the Phase 2 decision in September 2026. The partners lift the gas in proportion to their equity, with Shell’s 40% share going into its global portfolio and the Asian partners mostly shipping to their home markets. Japanese utilities Toho Gas and Tokyo Gas signed heads of agreement for purchases from the project.

The shipping arithmetic is the project’s structural advantage. A cargo from Kitimat reaches Tokyo, Busan or Shanghai in roughly 10 days; a cargo from Sabine Pass or Corpus Christi on the US Gulf Coast takes 20–25 days via the Panama Canal, when canal slots are available, or longer around the Cape. Shorter voyages mean lower freight, lower boil-off losses and fewer vessels tied up per tonne delivered, which translates into a delivered-cost advantage of the order of US$1 per million British thermal units in normal freight markets, according to industry estimates, and more when Panama Canal congestion or Red Sea disruptions push Gulf cargoes onto longer routes.

For Canadian gas producers, the effect has been to create a second market. The AECO hub in Alberta had spent a decade trading at a deep discount to Henry Hub because of pipeline constraints and surplus supply; the 2 billion cubic feet a day that Coastal GasLink now draws off has tightened the Western Canadian balance and underpinned investment by producers such as ARC Resources, Tourmaline and Canadian Natural. Gas, unlike oil, is a market where the big Alberta producers have been willing to sign the long-term commitments that pipeline and terminal builders need.

Why did the partners decide to double capacity in September 2026?

Because Phase 1 was operating as designed, the Asian demand outlook had strengthened, and the second phase could reuse the site, the marine terminal and most of the pipeline right-of-way, which makes it cheaper per tonne than Phase 1. On 29 September 2026 Shell announced that the joint venture had taken the final investment decision on LNG Canada Phase 2, adding two trains to double capacity from 14 to 28 million tonnes a year, with an additional LNG storage tank, a condensate tank, a loading berth and expanded utilities. Commercial operations are expected in the early 2030s, and Shell will lift nearly 6 million tonnes a year of the additional volume. The partners did not disclose a cost estimate; Petronas told Malaysian media its share of the investment was equivalent to about RM94.7 billion for the project overall.

The decision triggered TC Energy’s conditional commitment to Coastal GasLink Phase 2, which adds compressor stations to nearly double pipeline capacity from about 2.1 billion cubic feet a day, with construction from early 2027 and up to 2,100 workers at five sites. In a structure that reflects lessons from the first phase, LNG Canada will act as execution manager for the pipeline work, and Coastal GasLink’s exposure to cost and schedule risk is limited. The expansion is designed to use electric-drive compression where grid power is available, an issue that links the project to BC Hydro’s capacity plans and the broader grid debate covered in the clean electricity article.

Phase 2 also advances an Indigenous equity model. MNT Investments LP, representing the Gitga’at, Gitxaała, Haisla, Kitselas and Kitsumkalum First Nations, has an option to invest up to C$1 billion in a special-purpose entity that would own the new LNG storage tank, a structure proposed in July 2026 that gives the nations a share of infrastructure cash flows without construction risk. Peak construction employment in Kitimat is expected to reach about 4,000.

What makes Cedar LNG different?

Cedar LNG is the first LNG export project in the world majority-owned by an Indigenous nation, and it is built on a floating platform rather than on land. The Haisla Nation, whose territory includes Kitimat, holds 50.1% and Pembina Pipeline Corporation 49.9%; the partners took their final investment decision in June 2024 and expect to begin liquefying gas in late 2028. The project’s approved capacity is 3 million tonnes a year, and in 2026 Cedar applied to the B.C. Environmental Assessment Office to raise liquefaction capacity by 25% to 3.75 mtpa, with pipeline throughput rising from 400 to about 500 million cubic feet a day, to improve the return on the investment.

The financial structure is deliberately simple. Cedar estimates capital spending of about US$3.4 billion for the export facilities plus roughly US$600 million of other costs. The floating liquefaction unit is being built in South Korea and will be towed to a berth in Douglas Channel, which avoids most of the site-construction risk that drove LNG Canada’s and Coastal GasLink’s overruns. Gas arrives through a short connector from Coastal GasLink, so there is no new long-distance pipeline to permit. Revenue comes from tolling agreements: ARC Resources has signed a 20-year commitment as a major supplier, and Pembina has said it sees enough demand for a possible expansion. The plant is designed to run on hydroelectricity from BC Hydro, which gives it one of the lowest emissions intensities of any LNG facility.

Haisla Chief Councillor Crystal Smith has framed the project as a way for the nation to own, rather than merely be consulted on, the resources on its territory. The federal and B.C. governments supported it with loan guarantees and export development financing, and the model, in which a First Nation is majority owner and a listed company is operator and minority partner, has become the reference point for the Indigenous equity provisions in Ottawa’s 2025 Building Canada Act and the Trans Mountain equity offer.

Where do Woodfibre and Ksi Lisims stand?

Woodfibre is under construction and smaller; Ksi Lisims is larger and still awaiting a final investment decision. Woodfibre LNG, on the site of a former pulp mill near Squamish, north of Vancouver, is owned 70% by Pacific Energy, part of Indonesian businessman Sukanto Tanoto’s RGE group, and 30% by Enbridge. It is designed for 2.1 million tonnes a year, will run on BC Hydro electricity, and markets itself as the world’s first net-zero LNG facility. Its distinctive feature is regulatory: the Squamish Nation is both a project partner and, under a 2015 agreement, an environmental regulator with its own assessment process, the first time a Canadian industrial project has recognised a non-treaty Indigenous government in that role. Construction, including a tunnel breakthrough reported in 2026, is advancing toward start-up around 2027, with about 1,500 workers at peak and 100 long-term operating jobs.

Ksi Lisims LNG is the most ambitious of the follow-on projects. Proposed by the Nisga’a Nation, Western LNG and Rockies LNG, a consortium of Canadian gas producers, it would place a floating terminal at Pearse Island on Nisga’a treaty land near the Alaska border, with capacity of about 12 million tonnes a year, nearly as much as LNG Canada’s first phase. It received its B.C. environmental certificate on 15 September 2025 and was named by Ottawa in November 2025 as a project for fast-tracking. The 750-kilometre Prince Rupert Gas Transmission pipeline, which the Nisga’a and Western LNG bought from TC Energy, would bring the gas from northeastern B.C.; its construction is expected to employ 10,000–12,000 workers. The combined capital cost of terminal and pipeline has been put at about C$20 billion. The project has signed offtake agreements with buyers including Australia’s Santos and Glencore and, according to the federal energy minister, the first Canadian LNG supply deal with a European buyer. Its obstacles are the opposition of the Gitanyow hereditary chiefs to the pipeline route, consent from only two of six northwestern B.C. First Nations, and the financing decision itself, which the partners had hoped to take by the end of 2025 and which remained pending in October 2026.

How does Canadian LNG compete with the US Gulf Coast?

Canada competes on distance, feed-gas cost and carbon intensity; the US Gulf competes on scale, speed of construction and a deep contractor market. The United States exported over 85 million tonnes of LNG in 2024 and is adding capacity at Plaquemines, Corpus Christi, Golden Pass and Rio Grande that will take it well past 150 mtpa by the end of the decade. Against that, Canada’s 14 mtpa in operation and roughly 30 mtpa under construction or sanctioned is modest. But the Gulf projects sell on a Henry Hub-plus-fee basis, and their delivered cost to Asia includes 20–25 days of shipping and Panama Canal tolls or the longer route around Africa.

Kitimat’s feed gas comes from the Montney at prices that have often been well below Henry Hub, and the voyage to Japan is less than half as long. On the carbon side, Cedar and Woodfibre, running on hydroelectricity, and the electrification planned for later phases give B.C. LNG an emissions intensity that Japanese and Korean buyers, who face their own decarbonisation targets, increasingly price in. The trade-off is construction cost: B.C. labour, terrain and permitting made LNG Canada’s first phase far more expensive per tonne than a Gulf Coast brownfield expansion, which is why the second phase, on an existing site with an existing pipeline corridor, matters so much to the economics.

The geopolitical dimension has grown since 2025. Canada’s search for export markets beyond the United States, described in the export diversification article, has made LNG the clearest example of a product that physically cannot be tariffed by Washington on its way to Tokyo. Japan’s and South Korea’s governments have in turn encouraged their utilities to take Canadian cargoes as a diversification from Qatar, Australia and the United States.

What role does electricity play in the next phase?

A decisive one, because the B.C. government’s climate policy effectively requires new LNG facilities to be net-zero by 2030, which in practice means electric-drive compression powered by BC Hydro. Cedar and Woodfibre are designed that way from the start. LNG Canada’s second phase will use electrification where grid power is available, but the North Coast transmission system does not yet have the capacity to serve a 14 mtpa expansion fully, which is why the province and BC Hydro have been planning a North Coast Transmission Line and why the Phase 2 announcement was careful about the extent of electrification.

The issue connects the LNG story to the national grid debate. BC Hydro’s Site C dam, completed in 2024–2025, added 1,100 megawatts, but the utility has since launched calls for new wind and solar power, and the demand from LNG, mining and electrified industry on the North Coast is one of the main drivers. The parallel challenges facing Hydro-Québec and Ontario’s nuclear fleet are covered in the clean electricity article; the common thread is that decarbonising heavy industry requires grid investment that lags the industrial projects by several years.

What can founders and investors learn from LNG Canada?

The first lesson is that a decade of failure can be ended by a change in capital structure rather than a change in technology or market. Nothing about the gas, the port or the demand was different in 2018 from 2013; what changed was that Shell assembled buyers as owners, the province fixed the fiscal terms and the Haisla were brought in as partners rather than obstacles. Founders who find their market “not ready” should ask whether the problem is the product or the deal structure around it.

Second, Cedar LNG shows the value of designing out construction risk. A floating unit built in a Korean shipyard, a short connector to an existing pipeline, electricity from the grid and a tolling model with a 20-year supplier commitment each remove a category of risk that sank earlier projects. The Phase 2 structure at LNG Canada, in which the terminal owner manages the pipeline construction and the pipeline owner’s exposure is capped, applies the same thinking.

Third, Indigenous equity has moved from a social-licence cost to a financing tool. The Haisla’s 50.1% of Cedar, the MNT option on the Phase 2 storage tank and the Nisga’a’s ownership of Ksi Lisims and its pipeline are structures in which nations earn infrastructure returns and projects gain partners with legal standing to defend them. Investors in Canadian resource projects should now treat the quality of these partnerships as a leading indicator of whether a project will be built, as the Major Projects Office framework makes explicit.

Finally, LNG Canada demonstrates that geography is a durable advantage only when it is combined with execution. Kitimat is ten days from Asia, but so was it in 2013. The projects that will capture the advantage in the 2030s are those that reach a final investment decision in the 2026–2028 window, before the next LNG supply glut, and those that can prove the low-carbon credentials Asian buyers will be paying for. Japan’s own energy strategy, which drives much of this demand, is covered in the Japan Company Stories hub.

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