Tuesday, July 28, 2026
Field notes · Alaska energy · part two
The Alaska system nobody has proposed
Four real, separately-pursued pieces — wellhead gas conversion, submerged cargo transport, Cook Inlet carbon storage, and a stranded ammonia plant — already exist on paper or in the ground. Nobody has combined them. Put together, they route around almost every objection that has stopped Alaska LNG for fifty years.
research log · Prudhoe Bay → wellhead conversion → Arctic Ocean → market
01
Four pieces that already exist
None of this requires inventing new physics. Every piece below is a real project, a real patent, or a real published design — just never assembled together.
1. Wellhead gas-to-commodity conversion
Converting North Slope gas to methanol at Prudhoe Bay was fully engineered by a 1982 DOE-funded study (Arctic Enterprises Inc.) — a fuel-cell-powered submarine tanker system, methanol instead of LNG, specifically to avoid cryogenic cargo. Ammonia conversion is being separately explored today through a DOE Arctic Innovator proposal for a North Slope plant.
2. Submerged, weather-independent transport
Equinor's Subsea Shuttle Tanker has moved from a 2019 concept to published, DNV-referenced structural and hydrodynamic engineering — proof that an autonomous underwater cargo vessel is a tractable near-term problem, provided the cargo isn't LNG.
3. Real, mapped, on-site carbon storage — no pipeline required
A DOE-backed project, ASRC Energy Services' "North to the Future" hub, is already developing large-scale CO2 storage directly on the North Slope, for any local emitter — ammonia, hydrogen, methanol. Note: neither of Alaska's two live ammonia proposals actually pipes CO2 to Cook Inlet. One (Prisco's Mighty Pipeline) ships finished ammonia south via the existing TAPS oil line; the other (AGDC/Mitsubishi) ships raw gas south and converts it at the Cook Inlet end. The ASRC hub is what would let conversion carbon stay on the North Slope entirely, with no pipeline in either direction.
4. A stranded industrial asset and a growing market
Nikiski's ammonia plant sat idle from 2013 until AGDC began exploring reviving it. Meanwhile methanol's global shipping market is expanding for unrelated reasons — ice-class methanol tankers, EU methane penalties pushing ships toward it as fuel — giving either commodity a buyer base LNG-to-Asia doesn't have.
02
What it avoids
| Documented pipeline impact | Avoided by this system? |
|---|---|
| Permafrost degradation, 807-mile corridor | Yes — no overland pipeline |
| 10,000+ acres of wetlands converted | Yes |
| Central Arctic Herd caribou disruption | Yes |
| Cook Inlet beluga whale / vessel traffic +42-74% | Yes — cargo never transits the inlet |
| $13.2–16.9B pipeline capital cost | Yes, replaced by conversion plant + fleet cost (undetermined) |
This doesn't make North Slope gas carbon-neutral. It makes the transport method stop being the thing everyone sues over.
04
The smaller, nearer-term version: a domestic shuttle
Everything above was scaled for export. But Alaska has a real, dated, purely domestic problem too: Railbelt gas demand runs about 70 Bcf a year, existing Cook Inlet contracts don't cover it past the early 2030s, and two competing foreign LNG import terminals are now being built at Nikiski to plug the gap. There's a smaller, cheaper answer sitting in the same toolkit.
A real industry proposal, Qilak LNG, already studied a floating liquefaction plant off Point Thomson supplied by ice-breaking tankers — and found the shipping distance to ice-free water is just 600 miles, a fraction of what Yamal's Arctic tankers travel. Nothing stops that same plant from shipping methanol instead of LNG, on a short coastal run down to Cook Inlet instead of across to Asia.
Why methanol, and why submerged
Methanol needs no cryogenic tank — the reason every LNG submarine concept from 1981 onward ended up needing a nuclear reactor. A short, submerged, methanol-carrying shuttle could plausibly run on conventional or battery power, closer in scale to Equinor's small CO2 shuttle than to a 360-meter Arctic gas carrier. And going under the water, not through it, means skipping the seasonal first-year ice Qilak's own tankers still had to push through.
What it would replace
Instead of importing foreign LNG through a new Nikiski terminal, Cook Inlet would receive Alaskan methanol — burned directly in converted dual-fuel turbines, a real and already-deployed technology, or reconverted to pipeline-grade gas and injected straight into Enstar's existing system.
Monday, July 27, 2026
Field notes · Arctic transport · 1958–2026
The idea that keeps surfacing
For sixty-five years, engineers have proposed moving Arctic gas by submarine instead of pipeline. It has never once been built. But the two problems that always sank the idea — cryogenic cargo and impassable ice — now have a joint answer nobody has assembled yet.
research log · Prudhoe Bay → Norway, under the ice
01
A route no one finished
Every few decades, someone proposes solving the same problem: North Slope gas is stranded behind a pipeline that keeps failing to get built, and the surface ships meant to carry it keep failing against the ice. Each time, an engineering team works out that a submarine could do it instead. Each time, the study gets filed, and nothing gets built.
That's not really one story. It's the same argument, restated by a different institution, roughly every decade, since 1958 — General Dynamics, the U.S. Maritime Administration, the Department of Energy, a Cambridge-trained Navy captain, and, most recently, the Kurchatov Institute in Russia. What follows is the record, assembled from congressional testimony, a declassified-adjacent DOE contract report, and one peer-reviewed history most of the industry has forgotten exists.
02
Descent
Six and a half decades of the same idea, surfacing on schedule.
Saunders-Roe / Mitchell Engineering
First serious feasibility study for a commercial cargo submarine — 50,000-tonne nuclear ore carrier for year-round Arctic iron ore. Concluded feasible and economically justified. Nothing was built.
General Dynamics proposes to the oil majors
Sixteen nuclear submarine tankers, 275 m long, to carry North Slope oil to East Coast refineries. The producers said no and built the Trans-Alaska Pipeline instead.
Commerce Department orders a second look
Post-embargo study by Newport News, Westinghouse, Bechtel and Mobile Shipping concludes submarine tankers are "technically feasible" and compare favorably on cost. Industry gives no reply.
General Dynamics testifies to Congress
Electric Boat VP James Murphy tells House subcommittees a fleet of LNG submarine tankers could be built for "billions less" than the $43-billion Alaska gas pipeline. Congress approves the pipeline waiver anyway. Neither is ever built.
DOE funds the methanol variant
Arctic Enterprises Inc., under contract to the Department of Energy, designs a 165,000-ton, fuel-cell-powered submarine tanker — not for LNG, but for methanol converted from North Slope gas at the wellhead. Route: Prudhoe Bay to a Norwegian fjord, under the icecap. Delivered cost: $25/barrel, of which $6.80 was shipping. Filed and forgotten.
Post-Soviet design bureaus pick it up
Malakhit, Lazurit and Rubin — the design houses behind Soviet nuclear submarines — propose civilian tanker and container conversions to replace Russia's icebreaker fleet, including a Typhoon-class hull redesigned as a cargo vessel.
Kurchatov Institute and Gazprom restart design work
A 180,000-ton nuclear submarine gas carrier, driven by a shortage of sanctioned ice-class tankers for Arctic LNG 2. Putin calls it feasible. No keel has been laid.
The chokepoint argument returns
The Iran war closes the Strait of Hormuz for weeks; a fifth of global LNG trade is disrupted. Polar LNG revives a nearshore North Slope liquefaction concept, explicitly citing the crisis. Ice-class methanol tankers enter service — but only to 1A class, nowhere near the polar icecap.
03
Two cargoes, one hull problem
Every version of this idea has really been arguing about one thing: what to put inside the tank. LNG carries more energy per cubic meter. Methanol is dramatically easier to contain. Under ice, in a hull, that second property may matter more than the first.
| LNG cargo | Methanol cargo | |
|---|---|---|
| Storage temperature | −162°C, cryogenic | Ambient, liquid at room temp |
| Boil-off in transit | Continuous, must be managed | None |
| Tank volume vs. fuel oil | ~1.8× | ~2.0–2.5× |
| Buoyancy state | Shifts continuously as cargo boils off | Stable through voyage |
| 1982 GD design | 14–17 subs, $700–725M each | — |
| 1982 DOE design | — | 6 subs, 165,000 DWT, fuel-cell powered |
| Current shipping market | Mature ice-class fleet (Arc7) | Growing fleet, ice-class capped at 1A |
LNG has the denser cargo and the deeper Arctic experience. Methanol has the simpler tank and the open market. No one has built a hull that takes methanol's storage and puts it under the ice LNG can't clear either.
04
Why the gap is closing now
Ice class has a ceiling
New methanol tankers ordered for 2026–27 delivery are built to 1A ice class — fine for the Baltic and the Great Lakes, nowhere near the polar icecap. Russia's own Arc7 LNG carriers, the highest ice class in commercial service, still get stuck.
Methanol shipping already exists
A ~$36B chemical tanker market already moves methanol at scale. A North Slope methanol scheme wouldn't need to invent a market — only get the cargo out from under the ice to reach one.
Chokepoints are visible again
The 2026 Hormuz closure disrupted a fifth of global LNG trade and spiked European gas prices 60% in a month. An under-ice route touches no strait, canal, or contested waterway on either end.
The design lineage still exists
Russia's Kurchatov Institute is already drawing on Malakhit, Lazurit and Rubin — the same bureaus behind three decades of submarine tanker concepts. The engineering memory hasn't been lost. It's just never been pointed at methanol.
05
Primary sources
- Veliotis, P. & Reitz, S. — "A Submarine LNG Tanker Concept for the Arctic," General Dynamics Corp., Groton, presented Gastech '81, Hamburg.
- Kronholm, W. — "Sub could mine natural gas, General Dynamics proposes," AP wire, San Diego Evening Tribune / Kingman Daily Miner, Nov. 10, 1981.
- Court, K.E., Kumm, W.H. & O'Callaghan, J.E. — "Fuel-Cell-Propelled Submarine-Tanker-System Study," Arctic Enterprises Inc., DOE Contract AC01-81FE15086, June 1982.
- McLaren, A.S. — "The Development of Cargo Submarines for Polar Use," Polar Record, Vol. 21, No. 133 (1983), pp. 369–381.
- McLaren, A.S. — "Transporting Arctic Petroleum: A Role for Commercial Submarines," Polar Record, Vol. 22, No. 136 (1984), pp. 7–23.
- H.J.Res. 341, 97th Congress — waiver of law, Alaska Natural Gas Transportation Act, 1981.
- Kovalchuk, M., Kurchatov Institute — nuclear submarine gas carrier design briefing, Offshore Marintec Russia, Oct. 2024.
Saturday, July 25, 2026
A Mailer Asking You to Vote by Mail, and an Executive Order Trying to Stop It
This summer, an Alaska household got a familiar piece of mail: a pre-filled absentee ballot application from Alaska Republicans, Inc., urging them to request their primary ballot before the August 8th deadline. It's the same kind of outreach the party has run every statewide election since 1994. What's changed is the backdrop it landed in — a presidential administration actively trying to make mail voting harder to access, through a mechanism that could eventually make mailers just like this one far less useful.
The mailer, briefly
The piece itself is unremarkable on its face: a party return address, a real state absentee ballot application enclosed, and a nudge to vote before a busy day silences your voice in the primary. Unlike a similar 2020 mailing that scrambled thousands of names and addresses in a printing error, this one appears correctly addressed. It works exactly as intended — request the form, mail it in, and the state sends you an actual ballot.
The executive order aimed at the other end of that process
In March 2026, President Trump signed an executive order targeting mail-in voting nationally. Its core mechanism puts the U.S. Postal Service in charge of deciding whose ballots get delivered at all: the order directs USPS to refuse to transmit any mail-in or absentee ballot for a voter who isn't enrolled on a new, state-specific approved list. It also has the Department of Homeland Security compiling its own lists of voting-age citizens, and threatens criminal penalties for anyone involved in producing or delivering ballots to people the administration considers ineligible.
Where this collides with a mailer like Alaska's
Here's the connection: the party's mailer is only useful if the resulting ballot actually reaches the voter and gets delivered back. Under the executive order's USPS mechanism, that delivery becomes conditional on the state having already submitted the voter's information to a federal list. A mailer that successfully gets someone to apply would, in that scenario, still run into a second checkpoint entirely outside the party's or the voter's control — whether the state complied with a separate federal list requirement for that specific voter.
Why that scenario isn't happening right now
As of this writing, none of this is actually operating. A federal judge blocked the Postal Service from carrying out the plan nationwide in early July 2026, ruling it violated a settlement from an earlier lawsuit — on top of an already-standing block covering roughly two dozen states that had separately sued. So the mailer and the order aren't currently in tension in practice; they're just aimed at fundamentally different visions of how easy mail voting should be, with one of them presently unable to take effect.
The underlying irony
Step back, and there's a real tension worth naming, separate from any question of intent: the same political coalition pushing hardest to restrict and tightly verify mail voting is also the one actively encouraging people to use it, in the here and now, through a process that hasn't yet closed the gaps that motivate the restriction. That's not necessarily contradictory — a party can mobilize turnout under today's rules while sincerely believing those rules need tightening. But it does mean the mailer in your mailbox and the executive order in the courts are, right now, working at cross purposes.
CNN, "Postal Service won't deliver mail ballots for states that don't hand over voter lists" (June 10, 2026)
CNN, "US Postal Service cannot carry out Trump order on mail ballot delivery, judge rules" (July 1, 2026)
Brennan Center for Justice, "Analyzing the President's Executive Order on Mail Voting"
Votebeat, "USPS mail ballot proposal could add new hurdles for voters and election officials" (May 29, 2026)
KRBD, "Alaska Republican Party sends thousands of absentee voting applications to incorrect addresses" (July 23, 2020)
Friday, July 24, 2026
Alaska Policy Commentary · July 24, 2026
Governor Dunleavy and the Alaska Constitution: "Maximum Benefit of Its People" Means What It Says — and HB 381 Doesn't Come Close
Article VIII of the Alaska Constitution establishes Alaska's natural resources as a public trust to be managed for the maximum benefit of its people — not for private investors. The Alaska Supreme Court has enforced this fiduciary structure. Governor Dunleavy has now called three special sessions to pass a bill that by the state's own Department of Revenue numbers transfers $14.1 billion from Alaska's people to a private New York company — without independent cost certification, without governance transparency, and without the basic fiduciary standards that constitutional duty requires.
By Tom Lamb · Post XIII in the Alaska Policy Series · July 24, 2026
The Alaska Constitution's Article VIII begins with a declaration that has no equivalent in most state constitutions. It was the first article ever written into a state constitution to deal solely with natural resources. Fifty-five delegates drafted it in Fairbanks in 1955 and 1956. Section 2 reads: "The legislature shall provide for the utilization, development, and conservation of all natural resources belonging to the State, including land and waters, for the maximum benefit of its people."
Not for the benefit of developers. Not for the benefit of private investors. Not for the benefit of a New York energy company with $48.5 million in corporate equity seeking a permanent restructuring of Alaska's tax code. For the maximum benefit of its people.
The Alaska Supreme Court has enforced this as a fiduciary obligation. In State v. Weiss, 706 P.2d 681 (Alaska 1985), the Court held that when the State holds property in trust for a designated beneficiary class, it is bound by traditional fiduciary duties. Alaska's citizens are the beneficiaries. The Governor is the trustee-in-chief. And the question this series has been building toward since May is now unavoidable: has Governor Dunleavy met his constitutional obligations under Article VIII in the way he has managed the Alaska LNG project?
"If Alaska LNG is as transformative as its backers say, it can carry a fair tax and survive an honest accounting of who gets paid. Alaska's state constitution requires its resources to be managed for the maximum benefit of Alaskans." — Anchorage Daily News editorial, July 23, 2026
What the Constitution Actually Requires
Article VIII is not aspirational language. It is enforceable constitutional text with a documented judicial history. The Alaska Supreme Court has established several specific principles that flow from it:
What Article VIII Requires — Documented Constitutional and Judicial Standards
Section 1 — Public Interest: Resources must be made available for "maximum use consistent with the public interest." Development that primarily benefits a private party at the expense of the public interest is constitutionally suspect.
Section 2 — Maximum Benefit: The Legislature shall provide for utilization "for the maximum benefit of its people." The DOR projects HB 381 reduces Alaska's property tax share from $8.4 billion to $829 million by 2042 — a $7.6 billion reduction. That is not maximum benefit. It is minimum benefit in exchange for maximum concession.
State v. Weiss (1985): When the State holds property in trust for a beneficiary class, it is bound by traditional fiduciary duties — including the duty to act with full information, independent verification, and undivided loyalty to the beneficiaries.
Section 13 — No Alienation of Beneficial Ownership: The Constitution authorizes leasing of resources but does not authorize alienation of beneficial ownership. Transferring 75% of publicly funded project assets to a private company for $150 million — three-tenths of one percent of the low-end project cost — raises fundamental questions about whether Alaska alienated more than it was constitutionally authorized to give.
Fiduciary duty of independent analysis: A trustee bound by fiduciary duty is required to act with full information and independent verification before committing trust assets. Alaska committed $1 billion in assets, 25% equity, and $16 billion in permanent tax concessions without independent cost certification of the project those assets are committed to.
What "Maximum Benefit" Actually Means Against the Cost Analysis
The Governor's argument for HB 381 rests on a comparison: some revenue is better than zero revenue. If the project doesn't proceed, Alaska gets nothing. Therefore any deal that produces revenue is consistent with the maximum benefit standard.
This argument has a fundamental problem. It assumes the only alternative to HB 381 as written is no project. It ignores the possibility of a better-structured deal — one that produces more revenue, protects more of Alaska's assets, and meets the constitutional standard of maximum benefit rather than minimum concession.
Run the numbers against the constitutional standard:
Maximum Benefit Standard vs. HB 381 Reality
Property tax under existing law by 2042 (DOR): $8.4 billion to state · $5.7 billion to municipalities · Total: $14.1 billion
HB 381 volumetric tax by 2042 (DOR): $829 million to state · $728 million to municipalities · Total: $1.557 billion
Revenue surrendered by 2042: $12.54 billion — permanently, irrecoverably, with no recapture mechanism and no exit
Assets transferred for $150 million: 75% of $1 billion in publicly funded project assets — the only federally permitted Pacific Coast LNG export facility in existence
25% equity option exposure: Up to 25% of $44–54 billion in construction costs — potentially $11–13.5 billion of state capital against unvalidated costs
Buyback risk: If project fails, Alaska may pay Glenfarne a price Glenfarne proposes — calculated from cost basis Alaska never independently verified
The constitutional standard is maximum benefit. HB 381 produces 11 cents of revenue for every dollar Alaska would receive under existing law by 2042. That is not maximum benefit. That is minimum benefit — dressed up as economic development policy and rushed through three special sessions under a manufactured urgency that this series documented was driven by an IRS tax credit deadline, not an LNG market window.
The Cost Problem the Governor Has Never Addressed
Every special session Dunleavy has called proceeds from a single unstated assumption: that the project is viable at the costs Glenfarne has presented. The Governor has never required independent cost certification as a condition of the tax break. He has never publicly acknowledged the Rapidan Energy Group's independent analysis putting the total project above $70 billion. He has never addressed Public Citizen's finding that comparable LNG projects average 59.7% cost overruns — or that LNG Canada, the most comparable project, ran 130% over budget.
The Hilcorp letter published July 22 contains the sentence that exposes this failure most precisely: "Negotiation of binding long-term pricing agreements requires the parties to have a clear understanding of future costs."
Hilcorp wrote that sentence to argue against the S-corp tax. But it applies with equal force to the Governor's entire approach to HB 381. Negotiation of a permanent tax restructuring worth $12.54 billion in foregone revenue requires the parties — including Alaska's citizens — to have a clear understanding of future costs. They don't. The Governor has never required them to. He has instead called three special sessions to pass a permanent tax break for a project whose costs remain self-certified, unverified, and potentially double the figure Glenfarne presented in a slide deck stamped "Strictly Private and Confidential" in a public hearing.
The Cost Unknowns the Governor Has Never Required to Be Resolved
Independent construction cost estimate: Never required. Glenfarne's self-prepared range of $44.5–$54.5 billion accepted without independent validation against Rapidan's $70B+ analysis.
Dalton Highway upgrade cost: Never quantified. $1.5–2.3 billion in public infrastructure costs borne by Alaska DOT&PF — not in Glenfarne's estimate, not in DOR modeling, not in any fiscal note.
Cost overrun risk to Alaska's equity: Never modeled. 25% equity option at $70B+ true project cost = $17.5B+ of state capital. Never presented to Legislature.
Buyback cost if project fails: Never disclosed. Confidential agreement gives Glenfarne the right to set the price Alaska pays to reclaim its own assets.
Combined public-private cost to Alaska: Never calculated. Asset transfer + equity option + tax surrender + Dalton upgrade + buyback risk = a number the DOR has never been asked to compute.
The Manufactured Urgency — And What It Conceals
The Governor's repeated special sessions have been justified by a closing market window — the claim that if Alaska doesn't act now, it will miss the opportunity to place LNG into a growing Asian market. This series documented in June that the real deadline was not a market window but an IRS tax credit deadline — the 45Q carbon capture credit and 45V clean hydrogen credit require construction commencement by December 31, 2027. The special sessions exist to protect Glenfarne's federal tax credit position, not Alaska's competitive market position.
Those federal tax credits — $595 million per year from 45Q for 12 years, up to $1.5 billion per year from 45V for 10 years — flow entirely to Glenfarne, not to Alaska. GaffneyCline, the state's hired adviser and a Baker Hughes subsidiary with a corporate alliance with Glenfarne, presented 26 slides to the Senate Finance Committee without mentioning hydrogen, ammonia, or 45V once. The Legislature's independent adviser concealed the most valuable revenue stream in the entire project from the Legislature it was hired to advise.
Under the constitutional standard of maximum benefit, the Governor had an obligation to ensure Alaska's negotiating position accounted for the full value of the project — including the federal tax credits Glenfarne would collect, the wellhead economics that determine whether producers sign binding supply agreements, and the construction cost reality that determines whether the project can be built at a price the market will bear. He did not. He called three special sessions to pass a tax break. The maximum benefit standard required more.
The 2028 Senate Race — The Political Interest That Conflicts With the Constitutional Duty
The ADN editorial published yesterday noted what this series documented weeks ago: Dunleavy has hinted at a 2028 challenge to Sen. Lisa Murkowski — a contest in which his "friendship" with Trump would be a central asset. A pipeline that advances Trump's AI-power and energy dominance agenda advances Dunleavy's political ambitions. The ADN put it precisely: "A gas line is worth wanting. But a project that demands that Alaska forgo billions, leaves its ownership and financing undisclosed, and arrives under a manufactured clock is too silty to swim in."
A Governor with a personal political interest in demonstrating alignment with a President who has made Alaska LNG a national security priority has a conflict of interest in negotiating Alaska's financial terms with the project's developer. That conflict doesn't make Dunleavy corrupt. It makes him human. But it makes the absence of independent fiduciary checks — independent cost certification, independent legal counsel on the governance agreements, independent financial analysis of the total commitment — more serious, not less. A trustee with a conflict of interest is precisely the trustee who most needs external oversight.
Alaska's Constitution built that oversight into the system. Article VIII's maximum benefit standard is judicially enforceable. State v. Weiss established the fiduciary duty. The Alaska Supreme Court has held that the State's resource management obligations are enforceable by citizen beneficiaries. Those tools exist. They have not been invoked. They should be.
What the Third Special Session Should Require Before Any Vote
The Governor has the authority to call a third special session. He also has a constitutional obligation to ensure that what passes in that session meets the maximum benefit standard his office is bound to uphold. Those are not in conflict — but they require something he has not yet demanded: honest accounting.
What Maximum Benefit Requires Before the Third Special Session Votes
1. Independent construction cost certification — not Glenfarne's self-prepared estimate. An independent engineering assessment benchmarked against LNG Canada's actual cost experience, stress-tested against $8 JKM, and publicly released.
2. Full public disclosure of the 8 Star Alaska operating agreements — including the buyback mechanism, the clawback milestones, the equity dilution terms, and the FID definition. A Legislature that cannot see the contract cannot evaluate whether the tax break meets the constitutional standard.
3. A complete fiscal analysis of Alaska's total financial commitment — asset transfer value, 25% equity option at realistic cost scenarios, permanent tax surrender, Dalton Highway upgrade costs, and buyback risk — presented as a single number to the Legislature and the public.
4. A public accounting of federal tax credits — 45Q and 45V — flowing to Glenfarne over the project's life, compared against Alaska's revenue under HB 381. The Legislature cannot evaluate maximum benefit without knowing the full value being distributed between Alaska and the developer.
5. A mill rate alternative analysis — what Alaska would receive under a time-limited reduced mill rate on certified assessed value, compared to HB 381's volumetric rate. The constitutional standard requires the Legislature to consider whether a better deal is available before accepting a worse one.
Alaska's constitution is not aspirational. It is enforceable. The maximum benefit standard is not a suggestion. It is a fiduciary obligation that the Alaska Supreme Court has held binds the State when it manages resources in trust for its citizens. Governor Dunleavy has called three special sessions without meeting that standard. The third session is his last opportunity to do so before the Legislature votes on a permanent, irrevocable commitment of Alaska's natural resource revenues to a private developer whose costs have never been independently certified and whose governance structure Alaska's own senators cannot see.
The fifty-five delegates who wrote Article VIII in Fairbanks in 1955 understood exactly this risk. They had watched Alaska's fish traps concentrate the wealth of Alaska's resources in private hands for decades. They wrote the maximum benefit clause specifically to prevent the State from becoming an instrument for transferring public resource wealth to private parties at below-market terms. That is precisely what HB 381 does — and precisely what the Constitution was written to prevent.
A gas line is worth wanting. Maximum benefit for Alaska's people is worth requiring. They are not in conflict — unless the deal is structured in a way that serves the developer's interests at the expense of the constitutional standard. That is the question the third special session must answer. It has not been answered yet.
Tom Lamb · July 24, 2026 · Post XIII · Alaska Policy Series · thomasalamb.blogspot.com
Sources: Alaska Constitution Article VIII §§1–2, 13; State v. Weiss 706 P.2d 681 (Alaska 1985); Anchorage Daily News editorials June 17 and July 23 2026; Alaska Beacon; Department of Revenue HB 381 fiscal analysis; Public Citizen "Billions Over Budget" June 2026; Hilcorp Alaska letter July 22 2026; Alaska Constitutional Convention records 1955–1956. This post discusses legal concepts in the context of public policy analysis. It is not legal advice. The author is not an attorney.
Alaska Policy Commentary · July 24, 2026
Hilcorp's July 22 Letter Isn't Really About Alaska LNG — It's About a Permanent S-Corp Tax That Stays Whether the Pipeline Gets Built or Not
Read past the tax policy arguments and Hilcorp's seven-page letter reveals the real concern: the Senate created a new income tax specifically targeting Hilcorp and its owner — and if HB 381 passes with that provision, the tax is permanent regardless of whether Alaska LNG ever gets built. Hilcorp isn't protecting the pipeline. It's protecting its balance sheet from a tax that outlasts the project.
By Tom Lamb · Alaska Policy Series · July 24, 2026
Hilcorp Alaska sent a seven-page letter to the Alaska Legislature dated July 22, signed by Senior Vice President Luke Saugier. The stated subject is the pass-through entity tax provision in HB 381 — a new income tax the Senate added that Hilcorp says is targeted specifically at it and its owner. The letter objects to the tax on multiple grounds: it's structurally unworkable, it would reduce Cook Inlet investment, it raises constitutional concerns under Alaska's single-subject rule, and it would harm the economics of the Alaska LNG Project.
But read past those arguments and the real concern becomes clear. The Senate didn't just add a tax on Alaska LNG pipeline revenues. It created a new income tax on S-corporations and pass-through entities — structured specifically to target Hilcorp and its owner, Jeff Hildebrand. And here is the problem Hilcorp's lawyers identified that most observers missed: that tax doesn't go away if Alaska LNG fails.
If HB 381 passes with the S-corp provision intact, Alaska has a new permanent income tax on Hilcorp's Cook Inlet operations, its North Slope investments, and its owner's personal income — regardless of whether the pipeline ever reaches FID, regardless of whether a single molecule of North Slope gas ever flows to Nikiski, regardless of whether the project is abandoned in 2027 or 2035. Hilcorp isn't writing this letter to protect Alaska LNG. It's writing it to protect its balance sheet from a tax that was explicitly designed to target it and will outlast the project that supposedly justified it.
That is the real message. Everything else in the letter is supporting argument.
"The proposed income tax was developed to target Hilcorp and its owner." That tax stays on Alaska's books whether the pipeline is built or not. Hilcorp isn't protecting the project. It's protecting itself from a permanent tax that outlasts it.
What Hilcorp Actually Is — and Isn't
Hilcorp is the operator of both Prudhoe Bay and Point Thomson — the two fields that will supply Alaska LNG's gas. As operator it manages the fields, proposes drilling programs, plans development, and executes capital investments. That is significant authority. But operating a field is not the same as owning the gas in it.
Who Actually Owns Alaska LNG's Gas Supply
Point Thomson — primary gas source: ExxonMobil 62.36% · Hilcorp 36.99% · Others 0.65%
Prudhoe Bay — secondary gas source: ExxonMobil 36.4% · ConocoPhillips 36.08% · Hilcorp 26.36% · Chevron 1.16%
Gas Sale Precedent Agreement status: As of May 18, 2026, all three major producers — Hilcorp, ExxonMobil, and ConocoPhillips — have signed Gas Sale Precedent Agreements with Glenfarne. All three are non-binding. No binding supply contracts have been executed by any party.
Bottom line: ExxonMobil owns the majority of the gas at both fields. ConocoPhillips owns a third of Prudhoe Bay gas. Both have signed non-binding precedent agreements — not binding supply contracts. Hilcorp — as operator — cannot sell what the majority owners haven't executed binding agreements to sell. And a new income tax makes those binding agreements harder to finalize.
The letter acknowledges this indirectly. Saugier writes that Hilcorp holds "minority interests" in the units. He writes that "negotiation of binding long-term pricing agreements" is still ongoing. The Gas Sale Precedent Agreement Hilcorp signed is preliminary and non-binding. The binding commercial agreement — the one Glenfarne needs for FID — has not been executed.
Reading the Subtext — Five Sentences That Reveal the Real Argument
The letter's surface argument is about the tax. Its subtext is about Hilcorp's seat at the table. Five passages reveal what is actually being communicated:
Five Passages — What They Actually Mean
"Every molecule of natural gas expected to supply the project will originate from fields operated by Hilcorp."
Not ownership — indispensability. Without Hilcorp's operational cooperation, there is no gas flowing to the pipeline regardless of who owns the working interests.
"Hilcorp has worked closely with the developer of the Alaska LNG Project."
Past tense. Not "Hilcorp is a committed partner going forward." The framing signals that continued engagement is conditional — not guaranteed.
"Negotiation of binding long-term pricing agreements requires the parties to have a clear understanding of future costs."
Translation: we haven't signed a binding supply agreement. The tax makes it harder to get there. FID cannot happen without binding gas supply agreements. Hilcorp is the upstream negotiating party.
"Exempting only the Alaska LNG Project from the proposed tax does not eliminate the increased costs created by the tax; it merely imposes them elsewhere in the value chain."
This is Hilcorp saying: you cannot exempt Glenfarne and leave us exposed. Our costs flow directly into Glenfarne's gas costs. You cannot solve the midstream tax problem while creating an upstream tax problem.
"The proposed income tax must be understood in its broader context... this bill does not establish a generally applicable tax across that broad universe of businesses. Instead, the provision was developed to target Hilcorp and its owner."
This is not a legal argument. It is a grievance. Hilcorp is telling the Legislature: you have singled us out while making us responsible for delivering the gas the project needs. That is not a sustainable position.
The Tax That Outlasts the Project — Why This Is Hilcorp's Existential Concern
The Senate's pass-through entity tax provision was not drafted as a sunset clause tied to Alaska LNG's commercial operations. It was not drafted to expire if the project fails to reach FID. It was not drafted to disappear if Glenfarne walks away in 2027 or 2035. It is a permanent structural change to Alaska's income tax code — one that Hilcorp's own letter says was "developed to target Hilcorp and its owner."
Consider what that means in practice. If HB 381 passes with the S-corp provision and Alaska LNG fails — through cost overruns, financing collapse, gas supply economics that don't pencil out, or any of the other risks this series has documented — the pipeline never gets built. The property tax break Glenfarne received never generates offsetting revenue because there are no operations. The clawback is invoked. Alaska pays to reclaim its own assets at a price Glenfarne sets.
And Hilcorp still pays the new income tax. Every year. On its Cook Inlet operations. On its North Slope investments. On Jeff Hildebrand's personal income from his Alaska operations. Permanently. Because the Senate attached a targeted income tax to a pipeline bill without building in any mechanism to remove it if the pipeline fails.
What HB 381's S-Corp Tax Actually Does to Hilcorp
If Alaska LNG succeeds: Hilcorp pays a new income tax on its Alaska operations — reducing the after-tax wellhead netback it needs from Glenfarne — increasing Glenfarne's gas costs — pushing project economics closer to the 30% profitability cliff the DOR identified.
If Alaska LNG fails: Hilcorp still pays the new income tax. Permanently. On Cook Inlet. On the North Slope. Because the tax wasn't written to go away when the project does.
If Hilcorp reduces Cook Inlet investment in response: Southcentral Alaska's gas supply tightens before North Slope gas arrives — creating the near-term supply crisis the pipeline was supposed to prevent.
Constitutional risk: If Hilcorp's single-subject challenge succeeds in court, HB 381 may be thrown out entirely — taking both the pipeline tax break and the S-corp provision with it, but after years of legal uncertainty that delayed project financing.
The Legislature created a scenario where Hilcorp loses in every outcome. Pay the tax and reduce Cook Inlet investment. Pay the tax and make North Slope gas supply economics worse. Watch the project fail and pay the tax anyway. Challenge the law in court and create years of uncertainty that makes FID financing impossible.
That is not a legislative strategy designed to advance Alaska LNG. It is a legislative accident — a targeted income tax provision attached to an energy bill without thinking through what happens if the energy project it was supposed to fund never materializes. Hilcorp's letter, read in this light, is not a defense of the pipeline. It is a company protecting itself from a permanent tax that was written without an exit.
The Legislature and Glenfarne built HB 381 around the pipeline and terminal — the midstream and downstream infrastructure. The upstream gas supply was treated as a given. ExxonMobil, ConocoPhillips, and Hilcorp would eventually sign gas supply agreements, gas would flow, and the pipeline would run. HB 381 never addressed upstream economics.
Hilcorp is now saying what this series has been saying since May: the upstream is not a given. The economics run through the gas producer. If you make the operator's costs higher, you make Glenfarne's gas more expensive, which affects offtake pricing, which affects FID financing. You cannot solve the midstream tax problem while creating an upstream tax problem.
Sen. Myers identified this in his June 7 commentary — noting that Glenfarne makes money from tolls, not from the commodity value of the gas. That means the gas price negotiated between Hilcorp and Glenfarne directly determines whether the toll revenue covers debt service. A new tax on Hilcorp increases the gas price it needs to negotiate — which reduces Glenfarne's margin — which makes the project economics tighter — at a moment when the project is already, per the DOR, within 30% of its profitability cliff.
The Constitutional Argument — The Most Dangerous Point in the Letter
Buried near the end of page four is the argument that has received the least attention and may have the most legal consequence. Hilcorp's lawyers are raising Article II, Section 13 of the Alaska Constitution — the single-subject requirement:
"HB 381 combines amendments to Alaska's property tax statutes intended to establish a volumetric tax framework for a future natural gas pipeline project with provisions substantially restructuring the State's income tax laws. Those subjects appear too disparate and insufficiently related to satisfy Alaska's constitutional single-subject requirement."
This is not a policy argument. It is a legal argument that the bill as passed by the Senate may be unconstitutional on its face — regardless of whether it makes economic sense, regardless of whether the Governor signs it, regardless of what the conference committee decides. If Hilcorp's single-subject challenge is correct, HB 381 could be thrown out in Alaska Superior Court within months of enactment.
The letter notes that "members of the Conference Committee" acknowledged the structural problems with the pass-through entity tax "moments before the legislation was passed." A Legislature that passed a constitutionally questionable provision while acknowledging its structural problems in the same breath has created exactly the legal vulnerability Hilcorp is now exploiting.
The Precedent Agreements — and Why They Don't Solve the Problem
On May 18, 2026, Glenfarne announced that all three major North Slope producers — ConocoPhillips, ExxonMobil, and Hilcorp — had signed Gas Sale Precedent Agreements. This was presented as a significant milestone. It is a milestone — but a limited one. All three agreements are non-binding. No binding supply contracts have been executed. FID cannot happen without binding contracts.
Hilcorp owns 37% of Point Thomson and 26% of Prudhoe Bay. It is the operator. It signed a non-binding precedent agreement two months ago. Today it is writing a seven-page letter to the Legislature saying the new income tax makes it "extraordinarily difficult" to finalize the binding supply agreements those precedent agreements were supposed to lead to.
ExxonMobil owns 62% of Point Thomson and 36% of Prudhoe Bay. It signed a non-binding precedent agreement. It has said nothing publicly about HB 381 — no letter to the Legislature, no public statement of support or opposition to the tax structure that supposedly threatens the project it is the majority gas owner of.
ConocoPhillips owns 36% of Prudhoe Bay gas. Same precedent agreement. Same public silence on HB 381.
Hilcorp's letter is a warning from the minority operator who has engaged publicly. The silence from ExxonMobil and ConocoPhillips — the majority owners who have not — is a louder signal than anything in Hilcorp's seven pages. Three non-binding precedent agreements and one alarmed letter do not constitute a committed gas supply for a $44–54 billion pipeline project.
"Three non-binding precedent agreements and one alarmed letter do not constitute a committed gas supply for a $44–54 billion pipeline project. ExxonMobil owns 62% of Point Thomson. It has said nothing about HB 381. That silence is more informative than any statement Glenfarne has made."
The Wellhead Economics — Why the Tax Makes a Bad Situation Worse
Hilcorp's letter is ultimately about money — specifically, about whether producers can earn a sufficient return at the wellhead to justify signing binding long-term gas supply contracts with Glenfarne. The new income tax makes that calculation worse. But the baseline was already razor thin.
Henry Hub natural gas today is $2.94/MMBtu. The 2018 AGDC benchmark estimated producers would need $1–2/MMBtu at the wellhead. That benchmark was established when Henry Hub averaged $3.15/MMBtu. Eight years of inflation have not been applied to it publicly. And the wellhead price is what producers actually receive after deducting the pipeline tariff from whatever Asian buyers pay.
The Wellhead Pricing Cascade — Today's Market
Asian LNG spot price (JKM) today: ~$12–13/MMBtu
Less liquefaction cost at Nikiski: ~$3.00–3.50/MMBtu
Less pipeline tariff (807 miles): ~$3.00–4.00/MMBtu
Less shipping to Asia: ~$1.50–2.00/MMBtu
Wellhead netback to producers at $12–13 JKM: $2.50–4.50/MMBtu — barely above the 2018 benchmark
JKM in 2024 dropped below $8/MMBtu. At $8 JKM: wellhead netback = negative to zero.
Effect of new income tax on Hilcorp: Reduces after-tax netback — meaning Hilcorp needs a higher wellhead price from Glenfarne to achieve the same return. That higher price increases Glenfarne's input costs, pushing it closer to the 30% profitability cliff Sen. Myers identified.
Cook Inlet gas — the gas Hilcorp produces for Southcentral Alaska today — trades at approximately $7–9/MMBtu under long-term contracts. That is three to four times the wellhead netback producers would receive from Alaska LNG at current Asian market prices. Hilcorp invests $400–500 million annually in Cook Inlet because the return justifies it. The question its letter is really asking is whether the North Slope gas supply economics — already marginal at current JKM prices — remain viable after a new income tax reduces the after-tax netback further.
The answer matters because binding gas supply agreements cannot be signed at a price that doesn't work for the producer. And FID cannot happen without binding gas supply agreements. The tax is the trigger — but the underlying wellhead economics are the structural problem no tax break or tax increase fully resolves.
Before the conference committee finalizes HB 381, the Legislature should require answers to three questions that Hilcorp's letter makes unavoidable:
Four Questions the Conference Committee Must Answer
1. What are the commercial pricing terms in the three non-binding Gas Sale Precedent Agreements — and at what wellhead price do producers need to sign binding supply contracts to achieve acceptable returns at current Asian LNG market prices?
2. What is the impact of the new income tax on Hilcorp's required wellhead price — and has the Department of Revenue modeled how that price increase affects Glenfarne's project economics and FID timeline?
3. If Hilcorp's single-subject constitutional challenge is correct, what happens to HB 381 when challenged in Alaska Superior Court — and has the Legislature obtained independent constitutional counsel's opinion?
4. Why have ExxonMobil and ConocoPhillips — who signed Gas Sale Precedent Agreements in May 2026 — said nothing publicly about HB 381, the tax structure that supposedly threatens the project they are the majority gas owners of?
What Hilcorp Doesn't Say — The Pipeline Cost Problem That Dwarfs the Tax
Hilcorp's letter covers seven pages. It does not mention — once — the construction cost of the Alaska LNG pipeline. That omission is not accidental. Construction cost is Glenfarne's problem, not Hilcorp's. But it is directly connected to Hilcorp's wellhead economics — and its absence from the letter is the most important thing the Legislature should notice.
A more expensive pipeline requires a higher toll to service its debt. A higher toll reduces the wellhead netback to producers. A lower wellhead netback makes binding supply agreements harder to justify economically. The S-corp tax and the construction cost problem converge at exactly the same point — the wellhead price producers need to sign binding agreements — and Hilcorp chose to address only one of them.
What Hilcorp's Letter Doesn't Mention — But the Legislature Must
Construction cost overruns — not mentioned: Public Citizen's June 2026 analysis shows average LNG project cost overruns of 59.7%. LNG Canada — the most comparable project — ran 130% over budget. Applied to Glenfarne's $44.5B low-end estimate, the project could cost $71–102 billion. Every dollar of overrun increases the pipeline tariff — reducing Hilcorp's wellhead netback — making binding supply agreements harder to justify regardless of the tax outcome.
Dalton Highway upgrade — not mentioned: Alaska DOT&PF faces $1.5–2.3 billion in road upgrades to support construction traffic — borne by the state, not Glenfarne. Construction delays from an inadequate road increase costs and delay the revenue that would service the pipeline debt — further compressing wellhead returns.
Asian LNG price volatility — not mentioned: JKM fell below $8/MMBtu in 2024. At that price, wellhead netback to producers goes negative even without a new income tax. The S-corp tax is not the largest risk to binding supply agreements. Market price volatility is — and it can't be legislated away.
DOR's 30% profitability cliff — not mentioned: DOR modeling shows more than a 30% construction cost increase makes the project unprofitable. The S-corp tax adds pressure at the margin. A 59.7% average industry cost overrun destroys the economics entirely. Hilcorp chose not to say so — because doing so would require acknowledging the project may not work regardless of how the tax question is resolved.
Removing the S-corp tax makes the project slightly less unviable. It does not make it viable. A Legislature that removes the tax, passes HB 381, and declares the path to FID clear will have solved the smallest of the problems standing between Alaska and a working gasline — while leaving the largest ones untouched.
Hilcorp's letter is a focused legal and economic argument designed to remove a specific tax. It is not a comprehensive assessment of whether Alaska LNG can be built at a price the market will bear. The Legislature should read it as what it is — a well-constructed defense of Hilcorp's financial interests — and not mistake it for a project feasibility endorsement.
The real question this letter raises is not whether the pass-through entity tax is constitutional. It is whether anyone has actually secured the gas supply, the construction financing, and the market economics needed to build a project whose construction costs will likely dwarf the tax dispute that consumed three special sessions. Hilcorp's letter is silent on all of those questions. The Legislature should not be.
Tom Lamb · July 24, 2026 · Alaska Policy Series · thomasalamb.blogspot.com
Sources: Hilcorp Alaska LLC letter to Alaska Legislature dated July 22, 2026 (via Alaska Landmine); Petroleum News working interest data; Alaska Beacon; Alaska Landmine; Public Citizen "Billions Over Budget" June 2026; EIA Short-Term Energy Outlook July 2026; Trading Economics Henry Hub July 24 2026; Alaska DOT&PF project records. This post is independent public policy analysis and makes no allegation of legal wrongdoing by any party.
Thursday, July 23, 2026
Alaska Policy Commentary · July 23, 2026
The Cost Will Kill This Project: Why Alaska LNG's Own Numbers Show It Cannot Be Built at a Price the Market Will Bear
Glenfarne estimates $44.5–$54.5 billion. Public Citizen's analysis of comparable LNG projects shows average cost overruns of 59.7%. LNG Canada — the most comparable project — ran 130% over budget. Apply historical overrun rates to Alaska LNG and the project could cost more than $100 billion. At $100 billion, the math doesn't work at any realistic LNG price. Alaska is being asked to permanently restructure its tax code for a project the numbers say cannot be built at a price anyone will pay.
By Tom Lamb · Post XII in the Alaska Policy Series · July 23, 2026
The Alaska Legislature just voted down HB 381 on a 19-19 House tie — ending a second consecutive special session without passing the tax break Glenfarne says it needs to finance the project. Governor Dunleavy has called a third special session. The same debate will resume. The same arguments will be made. The Legislature will be told, again, that the tax structure is the obstacle between Alaska and its gasline.
It isn't. The obstacle is the cost. And no tax break — however structured, however generous — changes what it costs to build an 807-mile Arctic pipeline and LNG terminal from Prudhoe Bay to Nikiski.
"Apply historical LNG cost overrun rates to Alaska LNG and the project could cost more than $100 billion. At $100 billion, the math doesn't work at any realistic LNG market price. No tax break fixes that."
What LNG Projects Actually Cost vs. What Developers Say They Will Cost
Public Citizen published a comprehensive analysis in June 2026 examining more than twenty LNG export terminals operating or under construction in the United States, Canada, and Mexico. The findings are unambiguous and directly applicable to Alaska LNG.
LNG Project Cost Overrun Reality — Public Citizen June 2026
Average cost overrun — completed projects: 59.7% above original estimate
Average cost overrun — projects still under construction: 38% above original estimate already
LNG Canada — most comparable project: Required a custom-built pipeline over hundreds of miles of challenging terrain — ran more than 130% over budget
New Fortress Energy: Forced into sweeping restructuring in March 2026 — split company in two, transferred Brazilian assets to creditors — as direct result of LNG cost overruns
Applied to Alaska LNG at 59.7% average overrun: $44.5B becomes $71B · $54.5B becomes $87B
Applied to Alaska LNG at LNG Canada's 130% overrun: $44.5B becomes $102B · $54.5B becomes $125B
Glenfarne's CEO Brendan Duval has said the company "understands what the pipeline costs to build and can confirm the project is economically viable." He made that statement in May 2026. He has not released the Worley contractor bids that supposedly support it. The Legislature has been voting on a tax break for a project whose developer says it's viable but won't show the numbers that prove it.
The Pricing Chain — What the Gas Actually Has to Sell For
The cost overrun problem isn't just about construction. It's about what the gas has to sell for to make the construction cost worthwhile. Every dollar added to construction cost must be recovered through the pipeline tariff — which flows directly into the delivered cost of gas to Asian buyers.
Henry Hub natural gas today: $2.94/MMBtu. The EIA forecasts $3.50–3.70/MMBtu for 2026–2027. North Slope producers need approximately $1–2/MMBtu at the wellhead — a benchmark established in 2018 that hasn't been updated publicly despite 8 years of inflation.
The Alaska LNG Pricing Cascade — What Asian Buyers Pay vs. What's Left for Alaska
Asian LNG spot price (JKM) today: ~$12–13/MMBtu
Less liquefaction cost at Nikiski: ~$3.00–3.50/MMBtu
Less pipeline tariff (807 miles): ~$3.00–4.00/MMBtu — higher if construction costs overrun
Less shipping to Asia: ~$1.50–2.00/MMBtu
Wellhead netback to producers at $12–13 JKM: $2.50–4.50/MMBtu — barely above the 2018 benchmark
JKM in 2024 dropped below $8/MMBtu. At $8 JKM: wellhead netback = negative to zero.
At $100B construction cost: Pipeline tariff rises sharply to service debt — wellhead netback to producers goes negative even at $13 JKM. Project is unfinanceable.
Sen. Myers told the Legislature that Department of Revenue modeling shows more than a 30% cost increase makes the project unprofitable. Glenfarne's own high-end estimate of $54.5 billion is already 22% above its low end. The average LNG project overrun is 59.7%. LNG Canada — the most comparable project — ran 130% over. Myers' own 30% profitability cliff is almost certainly already breached before a shovel hits the ground.
LNG Canada — The Comparison That Ends the Argument
LNG Canada is the project most comparable to Alaska LNG. It required a custom-built pipeline over hundreds of miles of challenging terrain in a remote northern environment — just like Alaska LNG. Its original cost estimate was approximately $14 billion Canadian. Its final cost was over $40 billion Canadian — more than 130% over budget. It is the only recently completed project that directly mirrors Alaska LNG's physical and logistical profile.
LNG Canada was built by Shell, PETRONAS, PetroChina, Mitsubishi, and Korea Gas Corporation — a consortium of the world's most experienced LNG developers with combined balance sheets measured in hundreds of billions of dollars. They still ran 130% over budget. Glenfarne is a privately held company that has raised $48.5 million at the corporate level and has no prior mega-project completion record.
Rep. Kevin McCabe wrote in May that LNG Canada Phase 2 is moving toward FID by end of 2026 and that Alaska should feel competitive pressure. He is right that Canada is moving. What he did not note is that LNG Canada Phase 1 — the comparable project — ran 130% over budget. Phase 2, building on existing infrastructure at the same site, faces dramatically lower cost and execution risk than Phase 1. Alaska LNG has no existing infrastructure. It starts from zero. In the most challenging Arctic construction environment in North America.
What a $100 Billion Project Means for Alaska
Apply LNG Canada's 130% overrun to Glenfarne's low-end estimate of $44.5 billion and the project costs $102 billion. Apply it to the high end and it costs $125 billion. These are not worst-case scenarios conjured by opponents. They are the outcome of applying the most comparable completed project's actual cost experience to Alaska LNG's own developer estimates.
What Alaska Has Committed Against a Potentially $100B+ Project
Assets transferred to Glenfarne: 75% of $1 billion in publicly funded project assets — for $150 million in development spending
25% equity stake: Option to invest 25% of construction costs after FID — potentially $25 billion of state capital at $100B total cost
Property tax permanently surrendered: $16 billion over 30 years per Alaska Beacon — gone regardless of whether the project is ever built
Buyback mechanism: If project fails and Alaska seeks to reclaim assets, Glenfarne proposes the price — based on "value added" from a cost basis Alaska never independently verified
DOE loan guarantees: Up to $30 billion in potential federal loan guarantees that attach to the project — potentially backed by US taxpayers if the project fails
The Glenfarne defense — repeated in multiple legislative hearings and in the Alaska Landmine — is that "the private sector is taking on 100% of the financial risk" and "Alaska has no exposure to cost overruns." That claim has two problems.
First, Alaska's 25% equity option means the state can be called to invest up to 25% of total construction costs after FID. At $100 billion total cost, that is $25 billion of state capital — against a project whose economics are already underwater at that price point. Second, the DOE loan guarantee program that Glenfarne is pursuing transfers default risk to federal taxpayers. "The private sector bears all the risk" is true only in the narrow sense that Glenfarne's $150 million pre-FID development spending is at risk. After FID, the risk spreads to state equity, federal loan guarantees, and North Slope gas producers whose wellhead netback goes negative.
The Tax Break Cannot Fix a Cost Problem
The DOR testified that under current property tax law the project faces up to $750 million annually in tax burden by 2033 — making financing "substantially more difficult." That is a real number and a real problem. HB 381 addresses it by replacing the property tax with a volumetric rate generating approximately $59 million annually — a $691 million annual reduction in tax burden.
That $691 million annual reduction sounds significant. Against a project that may cost $100 billion to build, requiring perhaps $6–8 billion annually in debt service, it is a rounding error. The tax break improves project economics at the margin. It does not change the fundamental cost problem. A project that costs $100 billion to build cannot be made financeable by reducing its annual tax burden from $750 million to $59 million.
GaffneyCline — the state's own adviser and a Baker Hughes subsidiary — testified that the project faces a "narrow window of viability" even with the tax break. That testimony came before Public Citizen's analysis showed average LNG cost overruns of 59.7% and before anyone applied LNG Canada's 130% overrun to Alaska LNG's numbers. "Narrow window of viability" was the optimistic assessment.
What Happens When the Project Fails
HB 381 is dead — for now. But the third special session will bring the same pressure, the same arguments, and the same fundamental cost problem that no legislative session can solve. If the Legislature eventually passes a clean tax break and the project proceeds to FID — what happens when construction costs overrun?
The confidential AGDC document revealed that if Alaska tries to invoke the clawback and reclaim the project, Glenfarne proposes the buyback price. At $100 billion in actual construction costs, "value added" by Glenfarne is enormous — and the price Alaska pays to reclaim what it already owned could be catastrophic. The Senate passed asset protection amendments requiring no-cost return of assets. Those amendments are in a dead bill. If they don't survive into whatever passes in the third special session, Alaska has no clawback protection against a project that cost 130% more than estimated.
The Legislature is being asked to make a permanent, irrevocable tax commitment for a project whose historical peer — LNG Canada — ran 130% over budget, whose developer has a corporate equity base of $48.5 million, whose wellhead economics go negative at Asian LNG prices seen as recently as 2024, and whose cost overrun risk falls ultimately on state equity, federal loan guarantees, and North Slope producers whose supply agreements are non-binding.
The Hidden Public Infrastructure Cost Nobody Added to the Project Total
Glenfarne's $44.5–$54.5 billion estimate covers the pipeline, the gas treatment plant, and the LNG terminal. It does not cover what Alaska must spend to make construction physically possible. That cost falls entirely on Alaska DOT&PF — and it has never appeared in any project cost estimate, any legislative fiscal note, or any Department of Revenue revenue modeling.
The Alaska LNG pipeline parallels the Dalton Highway corridor for approximately 230 miles — from the GTP at Prudhoe Bay south to the point where the pipeline route departs toward the Interior. The Dalton Highway is the only overland construction access route for that section. There is no alternative. Every pipe section, every compressor, every piece of heavy equipment, every load of construction materials for the northern pipeline section moves up that road.
Sen. Robert Myers said it himself in January 2026: "Trucks are going up that road, things are getting beat up because of all of the potholes and the washboard and everything that we're dealing with. Freight gets damaged. That means you're either having to fix it on site or order replacements. That increases costs. It delays projects. It could delay the gas line." The DOT commissioner responded by noting that DOT&PF budgets had been slashed by the Legislature last session — the same Legislature that is now being asked to grant a $16 billion permanent tax break to the project that road must support.
Dalton Highway Upgrade Cost — Documented Per-Section Benchmarks
MP 397–414 reconstruction (17 miles): $43 million — $2.5M per mile. Included raising grade 7 feet, replacing culverts, flood protection. Alaska DOT&PF actual expenditure.
MP 289–305 permafrost reconstruction (16 miles): $74.5 million in IIJA funds — $4.7M per mile. Required literally raising the highway to address permafrost subsidence. Alaska's most expensive per-mile Dalton project.
MP 18–37 reconstruction (19 miles): Substandard geometry, failing embankments, Hess Creek Bridge replacement. Cost consistent with $3–5M per mile range.
Permafrost acceleration baseline: Southern reaches face thaw depths reaching 6 meters by 2033 — driving per-mile costs up to $150,000 annually for stabilization and resurfacing maintenance before any Alaska LNG construction traffic begins.
Apply those benchmarks to the 230-mile Alaska LNG construction corridor and the upgrade cost picture becomes clear:
| Cost Category | Low | High |
|---|---|---|
| Full reconstruction to heavy haul standard (230 miles at $3–5M/mile) | $690M | $1.15B |
| Bridge upgrades and replacements (est. 15 structures at $15–25M each) | $225M | $375M |
| Accelerated permafrost stabilization (230 miles × $150K/mile × 10 years) | $345M | $345M |
| Post-construction road remediation (230 miles at $1–2M/mile) | $230M | $460M |
| Total estimated Dalton Highway upgrade cost | $1.49B | $2.33B |
For context: Alyeska built the entire 415-mile Dalton Highway from scratch in 1974 for approximately $125 million — roughly $750 million in 2026 dollars. Alyeska paid for it because it was their project. Alaska LNG construction would require upgrading 230 miles of existing state-owned road at a cost approaching the full replacement value of the original highway — and every dollar falls on Alaska DOT&PF, not on Glenfarne.
The Dalton upgrade cost alone — $1.5–2.3 billion — represents 3–5% of Glenfarne's low-end project estimate. It has never been included in any cost comparison. It has never appeared in the DOR's revenue modeling. It has never been the subject of a legislative appropriation request. The Legislature that cut DOT&PF's budget last session is now voting on a $16 billion tax break for a project that requires that same DOT&PF to spend $1.5–2.3 billion to make construction physically possible.
The Complete Hidden Public Cost Alaska Is Not Counting
Dalton Highway upgrade: $1.49–$2.33 billion — borne by Alaska DOT&PF. Not in Glenfarne's estimate.
Ambler Road: $2 billion — borne by AIDEA revenue bonds backed by Alaska. Not in any Alaska LNG cost analysis.
Interior road network upgrades south of Dalton: Unquantified. Not estimated. Not requested.
DOT&PF maintenance surge during 5+ years of construction: Annual baseline $16.5M multiplied by construction traffic surge — unquantified. Not estimated.
Total documented hidden public infrastructure cost: $3.49–$4.33 billion — none of which appears in Glenfarne's estimate, the DOR's revenue modeling, or any legislative fiscal note.
Add these hidden public costs to Glenfarne's low-end estimate of $44.5 billion and the true total cost to Alaska — public and private combined — is already $48–49 billion before a single historical cost overrun is applied. Apply the 59.7% average LNG overrun to the private construction cost alone and the combined public-private total approaches $75–80 billion. Apply LNG Canada's 130% overrun and it exceeds $105 billion.
None of these numbers have been presented to the Legislature in a single document. The DOR modeled revenue against Glenfarne's self-prepared private construction estimate. Nobody modeled Alaska's total financial commitment — private equity option plus permanent tax surrender plus hidden public infrastructure costs plus buyback risk — against realistic construction cost scenarios.
That document should exist before the third special session convenes. It should be publicly available. And it should be the starting point — not the afterthought — of any serious legislative debate about whether Alaska LNG can be built at a cost the market will bear.
Before the Legislature convenes for a third time on Alaska LNG, it should require one thing that has never been provided: an independent assessment of whether Alaska LNG can be built at a cost that produces positive wellhead economics for gas producers at realistic Asian LNG market prices.
Not Glenfarne's self-prepared estimate. Not the 2018 AGDC figure inflation-adjusted. Not Worley's contractor bids that Glenfarne controls and hasn't released. An independent engineering and economic assessment, commissioned by the Legislature, benchmarked against LNG Canada's actual cost experience, stress-tested against JKM prices at the 2024 low of $8/MMBtu, and presented publicly before any vote on any tax structure.
If that assessment shows the project is viable at realistic costs and market prices, Alaska should offer a fair competitive tax incentive — structured as a time-limited mill rate reduction on certified assessed value, as every comparable jurisdiction does. If that assessment shows the project is not viable at realistic costs and market prices, the Legislature should say so clearly and stop consuming special sessions, public funds, and legislative bandwidth on a project the numbers say cannot work.
The cost will kill this project. The only question is whether Alaska finds that out before or after it has permanently surrendered its tax authority, committed its equity, and signed away its clawback rights. The third special session is the last opportunity to find out before it's too late.
Tom Lamb · July 23, 2026 · Post XII · Alaska Policy Series · thomasalamb.blogspot.com
Sources: Public Citizen "Billions Over Budget" June 2026; Alaska Beacon; Alaska Public Media; GaffneyCline House Finance testimony May 2026; EIA Short-Term Energy Outlook July 2026; Trading Economics Henry Hub July 23 2026 $2.94/MMBtu; Sen. Myers commentary June 7 2026; Glenfarne cost presentation Senate Finance June 3 2026; Hilcorp Alaska letter July 23 2026; American Prospect June 2026. This is independent public policy analysis.
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