Canada LNG Deals on a Roll - Updated Analysis

★ Original 2006 post updated with current analysis — Canadian LNG is now operational; Alaska LNG is still racing to catch up ★

Energy Geopolitics · Pacific Rim

Canada LNG
On a Roll

What the 2006 warning about Kitimat, Gazprom, and Alberta tells us about Alaska’s race against its neighbor — now that Canada has already crossed the finish line.

By Thomas A. Lamb · Originally July 21, 2006 · Expanded Analysis 2026 · AlaskaLNG Watch

Original · July 21, 2006

The Original 2006 Warning

In July 2006, while Alaska debated which gas pipeline route to build, two developments in Canada were already reshaping the Pacific LNG market. Russia’s Gazprom and Petro-Canada had advanced a 25-year supply agreement targeting a Quebec regasification terminal. Meanwhile, on the Pacific coast, Kitimat LNG inked a joint venture for the Pacific Trail Pipeline — a 290-mile link to Summit Lake designed to funnel Pacific-sourced LNG into Alberta’s oil sands and down to California and Washington State.

The Kitimat terminal was designed to handle 1 billion cubic feet per day, with WestPac Terminals eyeing a competing facility at Prince Rupert. Russia’s Putin and Canada’s Harper issued a joint G8 statement calling for LNG market development. The noose around Alaska’s Pacific market ambitions was tightening — and Juneau wasn’t paying attention.

Original Lamb commentary (2006): “I wouldn’t be surprised to see Gazprom target the Kitimat facility… [Kitimat LNG’s openness to any LNG supplier] is bad news for the Alaska LNG supporters.” That prediction proved prescient. But the scale of what followed was larger than even that warning captured.

What Has Changed Since 2006

LNG Canada’s terminal in Kitimat, British Columbia shipped its first cargo in June 2025 — officially making Canada an LNG-exporting nation. The project, a $40 billion joint venture led by Shell and including Petronas, PetroChina, Mitsubishi, and Korea Gas, now operates two processing trains with a combined capacity of 14 million tonnes per annum. It is the largest private sector investment in Canadian history.

Alaska’s project — a $44 billion, 807-mile pipeline from Prudhoe Bay to a liquefaction terminal at Nikiski — remains in development. In early 2025, the Alaska Gasline Development Corporation transferred majority control to Glenfarne Energy Transition. The pipeline targets mechanical completion in 2028 and first gas delivery in 2029, with full LNG export operations eyed for 2031.

The gap between Canada’s operational terminal and Alaska’s construction timelines is not merely symbolic. It represents a strategic head start in the race for the Asian contracts that will determine whether either project is commercially viable.

14 mtpa LNG Canada Phase 1 — operational 2025	20 mtpa Alaska LNG targeted — early 2030s	10 days Kitimat to North Asia — equal to Alaska
$109B Total Canadian LNG capex across 7 projects	11 mtpa Alaska LNG preliminary HOAs secured	2031 Alaska LNG targeted full commercial ops

Canada’s Structural Advantages Over Alaska

Shipping distance: LNG tankers from Kitimat reach North Asia in approximately 10 days — similar to Alaska’s Nikiski terminal. Both decisively beat U.S. Gulf Coast terminals, which require a month-plus journey including Panama Canal transit. A Japanese company paid $4 million above normal canal fees in 2023 simply to move up in the queue.

Feedgas cost: Canada’s LNG Canada sources gas from the Montney Formation — one of the richest and lowest-cost natural gas plays in North America. Alaska’s North Slope gas requires an 807-mile, $12 billion pipeline before a single molecule reaches the liquefaction terminal. That pipeline cost is embedded in every LNG price Alaska offers to Asia.

Asian ownership stakes: PetroChina (15%) and Korea Gas Corporation (5%) are consortium members. Tokyo Gas and Toho Gas signed 13- and 15-year purchase commitments with Mitsubishi, another LNG Canada partner. Asian utilities buying from LNG Canada are, in part, buying from themselves.

First-mover advantage: LNG Canada is already shipping cargoes. Alaska LNG’s commitments from Tokyo Gas, JERA, CPC, POSCO, and PTT are heads of agreement, not binding signed contracts. The Japan Gas Association has noted that private Japanese companies — not government officials — make LNG procurement decisions, and that project costs and economic certainty come first.

“Alaskans should consider the likelihood that Asian markets might prefer Canada LNG over Alaska LNG. With Canada LNG, those countries have ownership interests in an operating investment.”

— Joe Paskvan, former Alaska State Senator, January 2026

Head-to-Head: Canada vs. Alaska LNG

Factor	LNG Canada (Kitimat, B.C.)	Alaska LNG (Nikiski, AK)
Status	Operational — first cargo June 2025	Development — FID not yet reached
Export Capacity	14 mtpa (Phase 1) / up to 28 mtpa with Phase 2	20 mtpa targeted
Total Project Cost	~$40 billion (committed)	$44B+ est.; real costs may exceed $70B
Pipeline Required	Coastal GasLink: 670 km (complete)	807-mile AK pipeline: ~$12B, starting 2026
Feedgas Source	Montney Formation — low-cost, abundant	North Slope — vast but stranded & costly
Asian Equity Partners	PetroChina (15%), Korea Gas (5%), Mitsubishi (15%)	No equity partners yet; HOAs only
Binding Asian Contracts	Long-term commitments with Japanese utilities	Preliminary HOAs only — no binding deals
GHG Profile	~60% below global LNG average	Under review; Arctic construction adds complexity
Federal Support	Govt fast-tracked via Major Projects Office	Trump admin priority; $30B loan guarantees

Canada Is Not Standing Still

British Columbia has become the epicenter of a second wave of LNG development that, if fully realized, would flood the Pacific market with Canadian supply before Alaska’s first LNG cargo is ever loaded.

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Operational · 2025

LNG Canada Phase 1 — Kitimat

Both trains operational. Shell-led consortium. 14 mtpa capacity. Shipping to Japan, South Korea, China, and Taiwan. Phase 2 expansion to 28 mtpa under consideration.

Expected · 2027

Woodfibre LNG — Near Squamish, B.C.

Under construction. 0.3 Bcf/d export capacity. Operated using hydroelectric power, giving it one of the lowest carbon intensities of any LNG project globally.

Expected · 2028

Cedar LNG — Kitimat (Floating)

FID reached June 2024. Floating LNG facility backed by the Haisla Nation. 0.39 Bcf/d capacity, adding 3 mtpa alongside LNG Canada — and signaling deepening Indigenous partnership in Canadian LNG.

Proposed · ~2029

Ksi Lisims LNG — Pearse Island, B.C.

Nisga’a Nation-backed project, 12 mtpa capacity, added to Canada’s Major Projects Office fast-track roster by Prime Minister Carney in late 2025.

Proposed · Early 2030s

LNG Canada Phase 2

Would double Kitimat capacity to 28 mtpa. No FID yet, but environmental approvals already in place. CEO has described the case for expansion as “very strong.”

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Canada’s Energy Regulator has authorized 18 LNG export projects with a combined 29 Bcf/d of potential capacity. Even if only a fraction are built, Canada will be a dominant Pacific LNG supplier through the 2030s — precisely the decade Alaska is targeting for market entry.

Alaska’s Case — Still Alive, But Narrow

Scale and market diversification: Alaska LNG’s 20 mtpa target exceeds LNG Canada’s current Phase 1 capacity. At that volume, Alaska could serve multiple Asian markets simultaneously. Glenfarne CEO Brendan Duval has argued that Alaska LNG is “naturally competitive” independent of geopolitical factors.

The Panama Canal problem: Alaska’s Nikiski terminal offers a slight 5-to-6-day shipping edge to North Asia. More importantly, both Pacific-coast suppliers avoid the Panama Canal entirely — and with canal bottlenecks and drought constraints growing, Pacific supply commands a resilience premium Gulf Coast LNG cannot match.

The tariff wildcard: U.S. tariff policy under the Trump administration has created new demand for Alaska LNG. Japan, South Korea, and Taiwan are weighing equity stakes partly as a mechanism to soften trade tensions with Washington. Treasury Secretary Scott Bessent confirmed these discussions in 2025.

Federal loan guarantees: Alaska LNG is eligible for approximately $30 billion in federal loan guarantees — substantially derisking the project’s debt financing in a way no Canadian LNG project can replicate.

The honest assessment, however, is sobering. Alaska LNG has not secured a single binding commercial contract with an Asian buyer. ExxonMobil, BP, and ConocoPhillips have all withdrawn at various points, citing cost concerns. The $44 billion cost estimate dates to 2023; informed observers suggest $70 billion would be a more realistic floor.

The Gazprom Thread: How 2006 Still Echoes

The 2006 post identified Gazprom’s maneuvering through Canada as a strategic threat to Alaska. Russia’s invasion of Ukraine in 2022 dramatically restructured global LNG markets — collapsing European dependence on Russian pipeline gas and creating a surge in LNG demand that accelerated construction timelines across North America, including LNG Canada.

Ironically, Russia’s aggression did for Canadian LNG what decades of Alaskan advocacy could not: it created an urgent, politically-backed global appetite for Western supply alternatives. Canada crossed the finish line. Alaska is still building the starting blocks.

What the original post warned — that Gazprom was targeting the Kitimat market and that Canadian LNG was bad news for Alaska’s Pacific ambitions — proved entirely correct in structure, even if the mechanism differed. Russia’s energy weaponization did not capture Kitimat; it accelerated it.

Updated Analysis · 2026

The Verdict:
Canada Won Round One

The 2006 warning that Canadian LNG deals were “bad news for Alaska LNG supporters” understated the case. Canada has not merely competed with Alaska for Pacific market share — it has lapped it. LNG Canada is operational. Cedar LNG and Woodfibre LNG are under construction. Ksi Lisims is on the federal fast track. Alaska is still finalizing its engineering study.

This does not mean Alaska LNG is dead. The project’s scale, its stranded-gas economics, and the geopolitical tailwind from Asian allies seeking to balance trade relationships with Washington give it a credible path forward. Glenfarne has moved faster in 2025 than any Alaska developer in memory.

But the window is narrowing. If Alaska LNG reaches full export operations in 2031 as targeted, it will enter a Pacific market already served by at least 14–17 mtpa of Canadian capacity, with more on the way. It will arrive not as the pioneer it once hoped to be, but as the late entrant. Thomas Lamb’s 2006 instinct was right: Canada’s moves matter enormously to Alaska’s gas future. In 2026, they matter more than ever.

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Thomas A. Lamb · Energy Analysis · Original Post: July 21, 2006 · Expanded Analysis: 2026
Sources: LNG Canada, Alaska Beacon, Globe & Mail, U.S. EIA, Glenfarne Group, Alaska Landmine, CNBC, Global Energy Monitor

Fool’s Gold Pipeline - Lessons From LNG Failures

Energy Intelligence Review Est. 2009  ·  Volume XIV  ·  Analysis & Commentary

Special Report  ·  LNG Policy Failures

Fool's Gold Pipeline

Lessons the LNG industry keeps forgetting — and keeps paying for.

By Thomas A. Lamb  ·  Originally 2009  ·  Expanded Analysis 2024

When former Alaska Governor Wally Hickel compared a natural gas pipeline to Valdez to a gold mine, he forgot one crucial lesson of history: the richest-looking veins have a way of turning to fool's gold. Geopolitics, market saturation, cost overruns, and safety catastrophes have derailed LNG projects for eight decades. The pattern is always the same — and the warnings are always ignored.

By the Numbers

$400→$1,000 Cost per ton/year of LNG capacity — 2000 to 2008 alone

128 People killed in the 1944 Cleveland LNG tank failure

AUS$200B Australia's first LNG wave capex — beset by cost overruns & labour crises

3–4 mo. Average time to fill a single skilled LNG role during project peaks

A History of Hard Lessons

October 1944 — Cleveland, Ohio

The Tank That Started It All

East Ohio Gas Company's LNG storage tank ruptured, spilling liquefied gas into the city's sewer system. With no dike retaining wall and metal rationing producing brittle, low-nickel steel, 128 people perished when the gas vaporized and exploded. The industry's first great lesson — materials and containment standards matter — would take decades to fully absorb.

February 1973 — Staten Island, New York

The "Empty" Tank

During a cleaning operation, 42 workers were inside a TETCo LNG tank supposedly drained ten months earlier. Residual gas ignited, sending a plume of combusting fuel through the tank. The lesson — never assume an LNG vessel is inert — had to be learned in blood.

2004–2008 — Global LNG Markets

The Cost Explosion Nobody Predicted

As late as 2003, the LNG industry confidently assumed costs would keep falling along a learning curve. Instead, greenfield construction costs rocketed from roughly $400 per ton of annual capacity to over $1,000 — driven by a simultaneous global scramble for EPC contractors, surging raw material prices, a weakening dollar, and a chronic skills shortage. The optimists were wrong, and investors bore the bill.

2006–2009 — Alaska & the Sempra Play

The Valdez Mirage

Proponents of an Alaska North Slope-to-Valdez LNG pipeline — including former Governor Wally Hickel and attorney Bill Walker — promoted the scheme partly on the viability of selling gas to California's Sempra LNG terminal in Baja Mexico. What they missed: Shell Oil had already locked up 50% of Sempra's expansion capacity, and Russia's Gazprom was quietly claiming the rest. The market was foreclosed before a single pipe was laid.

2009 — Russia Enters the U.S. Market

Gazprom's Quiet Conquest

While Alaskans debated pipelines, Gazprom Marketing & Trading USA quietly signed deals for over 350 million cubic feet per day of U.S. physical supply — entering the American market from both coasts simultaneously. A state-controlled company using energy as geopolitical leverage had outmaneuvered years of Alaskan planning. The warning signs had been visible since at least 2006; they were simply ignored.

2006–2016 — Australia's $200B Lesson

The People Problem

Australia's first major LNG wave attracted over AUS$200 billion in capital expenditure. It also exposed a crippling structural weakness: a small domestic workforce with almost no LNG experience. Roles took three to four months to fill. Cost overruns became endemic. Several projects faced delays or outright cancellation. The lesson — project management is fundamentally a people challenge — has still not been fully institutionalized.

2014 — Hawaii's Spreadsheet Disaster

The $1.2 Billion That Went "Poof"

The Hawaii State Energy Office spent over a year presenting a study projecting $1.2 billion in benefits from embracing LNG as a "bridge fuel." When an independent researcher corrected a single spreadsheet error — the exclusion of the actual cost of LNG — the entire projected benefit evaporated. The Energy Office initially refused to acknowledge the error. Lawmakers and the public disagreed.

✦ ✦ ✦

"If that was a gold mine, which it is, and it required a road, we would build a road. We build roads all the time."

— Bill Walker, 2009, on the Alaska LNG pipeline to Valdez  ·  The project remains unbuilt.

Seven Lessons the Industry Keeps Forgetting

01

Geopolitics Is the First Variable, Not the Last

The Alaska pipeline advocates of 2006–2009 treated Russia as a distant abstraction. In reality, Gazprom had been methodically securing contracts, facilities, and influence in U.S. markets for years. By the time Alaskan planners noticed, the market was already partially foreclosed. Energy projects that treat geopolitical competition as someone else's problem invariably find that it isn't.

Russia's demonstrated willingness to weaponize natural gas — cutting off Ukraine, pressuring European nations — should have been a central variable in every LNG feasibility study of that era. It rarely was.

02

Market Assumptions Have a Short Shelf Life

The Valdez LNG project's viability rested on Sempra's Baja terminal absorbing Alaskan gas. That assumption was quietly invalidated before the proposal gained public momentum. Shell's contractual claim on 50% of the facility, combined with Gazprom's parallel maneuvering, left no market to serve.

Broad market projections made at a project's inception are routinely obsolete by the time construction begins. The LNG industry's cost estimates — which proved catastrophically wrong in the 2004–2008 cycle — underscore this: what seemed like a learning-curve trajectory was actually a precipice.

03

Safety Engineering Cannot Be Value-Engineered Away

The 1944 Cleveland disaster was a direct consequence of wartime metal rationing. Low-nickel steel — brittle at cryogenic temperatures — was used to build a tank storing a cryogenic fuel, with no retaining dike. The lesson is not merely technical; it is organizational: cost pressures that compromise materials integrity in LNG infrastructure will eventually extract a far higher cost.

The 1973 Staten Island tank incident underscores a second principle: in LNG operations, assumptions about inert systems kill people.

04

Cost Optimism Is the Industry's Original Sin

The belief that LNG project costs were on a steady downward learning curve was held almost universally in 2003. Within five years, costs had more than doubled per unit of capacity. The drivers — contractor scarcity, raw material spikes, skills shortages, remote construction — were not unforeseeable. They were simply inconvenient to factor into business cases that needed to look attractive to investors.

05

Workforce Strategy Is Not an HR Problem

Australia's LNG boom revealed that the majority of project failures trace back, at root, to people. Skills shortages cascaded into schedule overruns, which cascaded into cost penalties that could only be addressed by spending more on labor. Treating workforce planning as a procurement afterthought, rather than a strategic constraint, has cost the industry dearly.

06

Government Studies Are Not Neutral

Hawaii's LNG episode is a case study in regulatory capture disguised as policy analysis. The state Energy Office presented a billion-dollar benefit projection, anchored it with legislative testimony, and when the central spreadsheet error was exposed, initially defended the work rather than correcting the record. Independent peer review of energy feasibility studies should be standard practice, not a courtesy reserved for whistleblowers.

07

National Security and Energy Security Are the Same Question

The most enduring lesson from the Alaska LNG debates of the 2000s: domestic energy infrastructure is national security infrastructure. An energy supply chain that can be disrupted, displaced, or captured by a geopolitical adversary is not merely an economic liability — it is a strategic vulnerability. Any LNG development strategy that fails to account for this reality is not a strategy; it is a wish.

History Doesn't Repeat. But It Rhymes.

Every generation of LNG planners has inherited the lessons of the last and proceeded to learn them again at great cost. The warnings were in the contracts, in the maps, in the geopolitical signals — and in the spreadsheets. They were simply inconvenient. The projects that succeed are those built by people who take inconvenience seriously.

© Energy Intelligence Review  ·  Inspired by Thomas A. Lamb's 2009 analysis on Alaska LNG and national energy security  ·  All analysis for educational commentary