Alaska Policy Commentary  ·  June 7, 2026

The Answer Was Already in Alaska Statute: What a 20-Mill Property Tax Would Actually Generate — and What Alaska Is Giving Up

The Legislature has spent weeks building an increasingly complex volumetric tax architecture to avoid the one question a mill rate makes unavoidable: what is this asset actually worth? The Department of Revenue already answered that question. Nobody is listening.

By Tom Lamb  ·  HB 381 · Special Session 2026

Alaska Statute 43.56 already levies 20 mills on the assessed value of oil and gas property statewide. It has done so for decades. It is the legal framework that has generated billions in revenue from the Trans-Alaska Pipeline. It is self-calibrating — the mill rate applies to what the property is actually worth, determined by assessment after construction, requiring no advance knowledge of what a project costs to build.

The Legislature has spent weeks debating volumetric rates, stacked municipal taxes, inflation escalators, ramp-up periods, and community impact funds — a growing architecture of complexity designed to replace a system that already works. The reason for the complexity is simple: a mill rate on assessed value makes one question unavoidable. What is this asset actually worth? That question requires knowing what the project costs to build. And that is the one number nobody will provide.

So the Legislature is building workarounds. HB 381 is not a tax structure. It is a cost-blindness mechanism made permanent in statute.

"A mill rate on assessed value makes one question unavoidable: what is this asset worth? That is precisely why it isn't in the bill."

What the Numbers Actually Show

Run 20 mills against the two cost figures in public circulation — Glenfarne's own self-prepared estimate of $44.5–$54.5 billion, and the Rapidan Energy Group independent analysis putting the total above $70 billion — and the revenue picture becomes impossible to ignore.

Structure	Annual	10 Years	20 Years
20 mills on $46.2B	$924M	$9.24B	$18.48B
20 mills on $70B	$1.4B	$14B	$28B
HB 381 volumetric rate	~$59M	~$590M	~$1.18B

HB 381 generates approximately 6% of what a standard 20-mill property tax would produce on Glenfarne's own low-end estimate — and about 4% on the Rapidan estimate. That is not a tax incentive structured to attract investment. It is a near-total elimination of Alaska's tax interest in its own resource infrastructure, made permanent, before costs are known, with no recapture mechanism and no exit.

The Department of Revenue confirmed this with its own projection: under existing law, the state was on track to receive $8.4 billion in property taxes from the pipeline by 2042. HB 381 generates approximately $590 million over the same period. Alaska is being asked to surrender $7.8 billion by 2042 — a figure its own revenue department calculated — in exchange for a volumetric rate set without knowing what the project costs to build.

What Alaska Gives Up Permanently Under HB 381

vs. 20 mills on $46.2B: $7.8 billion by 2042 · $17.3 billion over 20 years

vs. 20 mills on $70B: $13.4 billion by 2042 · $26.8 billion over 20 years

Why a Mill Rate Is the Right Structure

A mill rate on assessed property value solves every problem the Legislature has been wrestling with simultaneously — without requiring any knowledge of construction costs in advance.

It is self-calibrating. If the project costs $44.5 billion, the mill rate produces revenue proportional to $44.5 billion. If it costs $70 billion, revenue scales accordingly. Alaska never needs to know the cost in advance. The assessment does the work automatically — exactly how Louisiana's ITEP works, exactly how Texas Chapter 312 works.

It is already in statute. AS 43.56 levies 20 mills on oil and gas property. Alaska has the legal framework, the assessment methodology, and the administrative capacity. HB 381 throws all of that away for a volumetric rate nobody can validate.

It eliminates the stacking problem. The amendment packet for HB 381 includes an uncapped municipal volumetric tax stackable on top of the state rate — with no visible ceiling. A mill rate under AS 43.56 already handles municipal allocation through the existing credit mechanism. No stacking. No uncapped municipal rates. No financing uncertainty.

It gives Glenfarne bankable certainty. A known mill rate applied to certified assessed value is a number any project finance lender can model. That is the kind of tax certainty FID actually requires — not a fixed volumetric rate set without cost validation that lenders will question before committing a dollar.

It provides a genuine competitive incentive. The Legislature could offer a time-limited mill rate reduction — say 10 mills instead of 20 — for a defined period after commercial operations begin, applied to certified assessed value, restoring to 20 mills thereafter. That is competitive with Louisiana and Texas, transparent, self-calibrating, and does not require knowing costs in advance. It is a real incentive, not a blank check.

How the Revenue Should Be Distributed — and Who Should Receive It

The state should collect the full mill rate revenue and distribute it to corridor boroughs on a population basis. Not statewide — corridor boroughs only. The communities that actually host the project, bear its construction burden, absorb its infrastructure demands, and live with its long-term presence deserve the revenue it generates.

The pipeline runs from Prudhoe Bay to Nikiski — 807 miles through five organized boroughs and portions of the unorganized borough. Those are the communities in the equation. Anchorage is not in the project footprint. The pipeline does not pass through it. The terminal is not there. The gas treatment plant is not there.

Mayor LaFrance claimed Alaska LNG could cost Anchorage up to $173 million over nine years — based on a worst-case scenario assuming no new housing is built for construction workers and all of them live in Anchorage consuming city services. That scenario will not materialize. Pipeline construction workers live in man camps along the corridor, in Fairbanks, and at Prudhoe Bay. Anchorage will function as a corporate and logistics hub — generating tax revenue from office activity and procurement, not absorbing emergency services and housing costs. The Mayor's own report acknowledges that if new housing is built, the deficit drops to $23 million. Anchorage handles larger tourist influxes every summer without declaring a fiscal crisis.

The corridor borough population distribution at both cost scenarios:

Borough	Population	Share	At $46.2B	At $70B
Mat-Su Borough	121,761	40.8%	$377M	$571M
Fairbanks North Star	96,849	32.4%	$299M	$454M
Kenai Peninsula	61,920	20.7%	$191M	$290M
North Slope Borough	9,832	3.3%	$30M	$46M
Denali Borough	1,826	0.6%	$5.5M	$8.4M
Unorganized corridor	~6,000	2.0%	$18M	$28M
Total	298,188	100%	$924M	$1.4B

Now compare what these same communities receive under HB 381's ~$59 million total annual volumetric revenue:

Borough	HB 381 Est.	At $46.2B	Annual Gap	At $70B Gap
Mat-Su	~$24M	$377M	-$353M	-$547M
Fairbanks North Star	~$19M	$299M	-$280M	-$435M
Kenai Peninsula	~$12M	$191M	-$179M	-$278M
North Slope	~$2M	$30M	-$28M	-$44M
Denali	~$0.5M	$5.5M	-$5M	-$7.9M
Total	~$59M	$924M	-$865M	-$1.34B

Sen. Myers represents Fairbanks. His constituents stand to lose between $280 million and $435 million annually — every year, permanently — under the bill he published a commentary supporting this morning. Those numbers were available before he wrote it. They are available now.

The Workaround Confession

Every element of HB 381's complexity — the volumetric rate, the stacked municipal taxes, the ramp-up abatement, the CPI escalator, the community impact fund, the 142 amendments — is a workaround for the same problem. Nobody knows what this project costs to build. A mill rate on assessed value makes that question unavoidable. So the Legislature is constructing an increasingly elaborate structure to avoid asking it.

Louisiana didn't guess. Texas didn't guess. They built frameworks that calibrated automatically to actual asset value — determined after construction, by independent assessment, with full public disclosure. Alaska already has that framework. It is called AS 43.56. It levies 20 mills. It works.

The Legislature could offer a reduced mill rate — 10 mills for a defined period — as a genuine competitive incentive, applied to certified assessed value once construction is complete. That is transparent, self-calibrating, bankable, and fair to Alaska's citizens. It requires no advance knowledge of costs. It requires no volumetric guesswork. It requires no 142 amendments trying to fix a structure that was wrong from the start.

Instead Alaska is being asked to permanently surrender between $865 million and $1.34 billion annually — to corridor communities that desperately need it — in exchange for a rate set without knowing what it should be.

And property taxes are only the beginning of the revenue picture. What flows to Glenfarne from federal tax credits over the life of this project makes the property tax gap look modest by comparison. That accounting has never been presented to the Legislature. It should be — before any vote is taken.

Tom Lamb  ·  June 7, 2026  ·  Alaska Policy Commentary

Alaska Policy Commentary  ·  June 7, 2026

The Cost Nobody Put in the Estimate: What Alaska LNG Construction Will Do to the Dalton Highway — and Who Pays

Glenfarne's $44.5–$54.5 billion cost estimate covers the pipeline. It does not cover the public road infrastructure Alaska must upgrade to make construction physically possible. Sen. Myers drives the Dalton Highway. He told us in January it's already falling apart under current traffic. He hasn't told us who pays to fix it for Alaska LNG.

By Tom Lamb  ·  HB 381 · Special Session 2026

In January 2026, Sen. Robert Myers stood before the Alaska Legislature and described the Dalton Highway in terms that every Alaskan who has driven it would recognize. "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," he said. "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."

Sen. Myers was right. He drives that highway. He knows what it looks like under current commercial traffic — 60% heavy trucks, year-round, on a gravel road with failing embankments, substandard geometry, and permafrost thawing beneath it at accelerating rates.

What Sen. Myers did not say in January — and has not said in his commentary published today supporting HB 381 — is who pays to upgrade the Dalton Highway to support Alaska LNG construction. That cost does not appear in Glenfarne's $44.5–$54.5 billion estimate. It never has. And it falls on Alaska.

"Glenfarne's estimate covers the pipeline. It does not cover the road Alaska must build to get there."

What the Dalton Highway Looks Like Today

The Dalton Highway is a 415-mile gravel road — one of the most remote highways in North America — running from Livengood north of Fairbanks to Deadhorse at Prudhoe Bay. It was built by Alyeska in 1974 specifically to support TAPS construction, at a cost of approximately $125 million — roughly $750 million in today's dollars. Alyeska built it, owned it, and maintained it for the pipeline. The state took ownership in 1978.

Today Alaska DOT&PF spends approximately $16.5 million annually just on maintenance — before any Alaska LNG construction begins. Over the past five years, the state has invested $160 million in capital improvements north of Atigun Pass alone, with another $175 million planned over the next five years. These investments are catching up with decades of deferred maintenance on a road that was never designed for the traffic volumes it now carries.

Permafrost thaw is accelerating the problem. Projections show thaw depths reaching six meters in some sections by 2033, driving per-mile stabilization costs up to $150,000 annually. The highway has steep grades, sharp horizontal curves, and failing embankment sections that DOT&PF describes as a safety and performance problem — under current traffic conditions, before Alaska LNG construction adds anything.

The Dalton Highway Today — Before Alaska LNG Construction

Annual maintenance cost: $16.5 million — one-third federally funded

Capital investment past 5 years: $160 million north of Atigun Pass alone

Planned capital investment next 5 years: $175 million

Current condition: Substandard geometry, failing embankments, permafrost thaw accelerating — rated "fair" by the state

Current traffic: 60% heavy commercial trucks — already degrading the road year-round

What Alaska LNG Construction Would Require

The Alaska LNG pipeline route crosses approximately 230 miles of federal lands, mostly in the Dalton Highway and Trans-Alaska Pipeline corridor. The Dalton is the primary overland construction access route for the northern portion of the 807-mile pipeline. There is no alternative.

TAPS construction required shipping approximately 550,000 tons of pipe alone — in addition to millions of tons of equipment, materials, fuel, and supplies. Alaska LNG would require a comparable volume of heavy haul over a road that is already strained by current North Slope oil field traffic.

Pipeline construction requires oversized loads — pipe sections, compressors, heavy equipment — that exceed the current weight and width limits on significant sections of the Dalton. Bridge reinforcements or replacements would be required. Embankment stabilization at failing sections would need to precede construction traffic. Permafrost mitigation along the corridor would need to be accelerated ahead of schedule.

None of this appears in Glenfarne's $44.5–$54.5 billion estimate. These are state infrastructure costs — not project costs. They fall on Alaska DOT&PF's budget, funded by Alaska's taxpayers, not by Glenfarne's investors.

The TAPS Lesson Nobody Is Applying

When Alyeska built TAPS, it also built the road. The haul road was a project cost — owned, funded, and maintained by the pipeline builder until the state took over. Alyeska bore the full infrastructure cost of accessing the construction corridor because it was in Alyeska's direct financial interest to do so. Getting oil to market was worth any road cost.

Sen. Myers correctly points out that Alaska LNG is different — Glenfarne makes money from pipeline tolls, not from the commodity value of the gas. That difference in business model is precisely why Glenfarne has no incentive to fund Dalton Highway upgrades. The road benefits the state. The state owns it. The state pays for it.

But here is what follows from that: if the state must upgrade the Dalton Highway to make Alaska LNG construction physically possible, that upgrade cost is a public subsidy to the project — one that never appears in any cost comparison, never appears in the DOR financial modeling, and never appears in the legislative debate over HB 381.

Hidden Public Costs Not in Glenfarne's Estimate

Dalton Highway upgrades: Bridge reinforcements, embankment stabilization, geometry improvements required to handle Alaska LNG construction traffic. Cost: unquantified. Borne by: Alaska DOT&PF.

Accelerated permafrost mitigation: Construction traffic and climate warming will accelerate permafrost thaw along the corridor ahead of schedule. Cost: unquantified. Borne by: Alaska DOT&PF.

Ongoing maintenance surge: Construction-weight traffic will dramatically increase road degradation above the current $16.5 million annual baseline. Cost: unquantified. Borne by: Alaska DOT&PF.

Post-construction remediation: Road damage from multi-year heavy haul construction traffic will require significant remediation. Cost: unquantified. Borne by: Alaska DOT&PF — and ultimately Alaska's taxpayers.

Sen. Myers Knew This in January

This is not a new concern. In January 2026, Sen. Myers stood before the Legislature and said the Dalton Highway is already failing under current traffic — that freight is getting damaged, costs are increasing, and projects are being delayed. He said explicitly: "It could delay the gas line."

He was raising the alarm about a road that cannot currently support the construction traffic Alaska LNG would require — five months before voting on legislation that would permanently restructure Alaska's tax code for the project.

The DOT commissioner responded by noting that DOT&PF budgets had been slashed by the Legislature last session. The Legislature that is now being asked to give Glenfarne a permanent tax concession previously cut the budget of the agency responsible for maintaining the only road that makes Alaska LNG construction physically possible.

That is the full picture the Legislature needs to see before voting on HB 381: a project whose costs are self-estimated, whose independent cost analysis has been withheld, whose profitability cliff is within the range of its own cost uncertainty — and whose construction depends on a public road that Alaska's own senator described as failing, maintained by an agency whose budget Alaska's own Legislature cut.

The Question That Should Be on the Floor Today

Before the Legislature votes on HB 381, it should require answers to three questions about the Dalton Highway alone:

Three Questions the Legislature Should Answer Before Voting

1. What is the estimated cost of Dalton Highway upgrades required to support Alaska LNG construction traffic — and who pays for them?

2. Does Glenfarne's definitive agreement with AGDC include any obligation to fund Dalton Highway improvements — and if not, why not?

3. When the Department of Revenue modeled Alaska's total financial position under HB 381, did that model include the public infrastructure costs Alaska must bear to make construction physically possible?

Sen. Myers drives the Dalton Highway. He knows what it looks like. He told the Legislature in January that it is already inadequate for current traffic and could delay the gas line. Today he published an article supporting HB 381 without mentioning that the state — not Glenfarne — will bear the cost of making that road construction-ready.

The cost Glenfarne didn't put in the estimate is the cost Alaska already owns. It is the cost of the road that makes the project possible. It is one more item in a growing list of public commitments made to a private developer — along with $1 billion in transferred assets, a 25% equity stake with no governance transparency, and now a proposed permanent tax concession — that have never been totaled up and presented to Alaska's citizens as a single number.

That number — the true total cost of Alaska's commitment to this project — is the one figure nobody has calculated. And it is the one figure the Legislature most needs before it votes.

Tom Lamb  ·  June 7, 2026  ·  Alaska Policy Commentary

Alaska Policy Commentary  ·  June 7, 2026

Sen. Myers Identified the Exact Problem With Alaska LNG — Then Drew the Wrong Conclusion

His own analysis shows a 30% cost overrun makes the project unprofitable, that Glenfarne has no balance sheet to absorb it, that Alaskan customers are contractually protected — and that the contract protecting them doesn't exist yet. Alaska already gave away its collateral. HB 381 asks it to give away the rest.

By Tom Lamb  ·  HB 381 · Special Session 2026

Sen. Robert Myers published a thoughtful piece today distinguishing Alaska LNG from the Trans-Alaska Pipeline. He is right that the comparison is misleading. He is right that Glenfarne has a different business model than an oil major. He is right that gas is a lower-value commodity than oil and that the window of opportunity, while real, is not the same as the 1970s oil emergency.

He is also right about something he apparently did not intend to prove: that the financial structure being built around Alaska LNG is far more fragile than HB 381's proponents are acknowledging — and that the protections he cites for Alaskan ratepayers do not yet exist.

"Sen. Myers built the most precise description of the project's financial vulnerability published by any Alaska legislator. He just didn't follow it to its conclusion."

The 30% Admission and What It Actually Means

Myers writes that Department of Revenue modeling shows more than a 30% cost increase will make the project unprofitable. This is the single most important number in the entire HB 381 debate — and it appeared in a pro-HB 381 article with almost no scrutiny of what it actually implies.

Run the math on Glenfarne's own figures, presented to the Senate Finance Committee on June 3:

The Profitability Cliff — By The Numbers

Glenfarne low-end estimate: $44.5 billion

30% overrun tolerance: $13.35 billion

Profitability cliff: $57.85 billion

Glenfarne high-end estimate: $54.5 billion — already 83% of the way to unprofitable on Glenfarne's own figures

Glenfarne's own uncertainty range: $10 billion — consuming 75% of the entire profitability buffer

Rapidan Energy Group independent estimate: $70+ billion — already $12+ billion past the profitability cliff Myers identified

Myers cites TAPS — originally quoted at $900 million, final cost $8 billion. He uses this to argue Glenfarne will be more cost-disciplined because it has no margin for error. That may be true. But the historical record of Arctic pipeline construction shows that cost discipline and cost reality are different things. The engineering complexity does not care about Glenfarne's business model.

If the Rapidan analysis is anywhere close to correct, the project is already past Myers' own profitability threshold — before a single shovel hits the ground. HB 381 cannot fix that. A tax concession cannot make a $70 billion project economically viable when the profitability cliff is $57.85 billion.

When Costs Overrun — Who Pays?

Myers correctly identifies that Glenfarne has no deep balance sheet. He correctly notes that infrastructure developers need to turn a profit quickly and cannot survive many up-front costs. He correctly states that oil companies had the balance sheets to absorb cost overruns because oil production was the profitable backstop.

Then he argues that costs can't be passed to Alaskan customers because of Glenfarne's contract with Enstar, and can't be passed to overseas customers because they'll find another buyer. He concludes that Glenfarne will therefore look at cost risk more carefully than TAPS builders did.

But this logic has a fatal gap. If costs can't go to Alaskan customers, can't go to overseas customers, and Glenfarne has no balance sheet to absorb them — where do cost overruns above the profitability cliff actually go?

Myers never answers this. The answer his own analysis produces is: they go to equity holders. And Alaska is an equity holder — with a 25% stake in 8 Star Alaska and an option to invest up to 25% of construction costs across all three subprojects after FID. On Glenfarne's own low-end estimate, 25% of construction costs is approximately $11 billion of state capital. At the Rapidan estimate, north of $17 billion.

Myers has described a cost overrun structure where the entity with no balance sheet builds the project, ratepayers are supposedly protected by contract, overseas customers won't absorb overruns, and the residual risk falls on equity. Alaska is the equity. Alaska has no protection in that structure that Myers does not acknowledge.

The Enstar Protection That Doesn't Exist Yet

Myers describes the Enstar contract as if it is an established protection for Alaskan ratepayers. It is not. As of today, Glenfarne and Enstar have signed a non-binding letter of intent — dependent on the negotiation of definitive agreements and approval by the Regulatory Commission of Alaska. The RCA has not approved it. The definitive agreements have not been negotiated. The protection Myers cites does not yet legally exist.

But the deeper problem is structural. Enstar is a regulated utility operating under an RCA-guaranteed 11.6% return on investment — paid by ratepayers regardless of how much Enstar pays for gas. That regulatory structure means that even if a cost-protection agreement is eventually executed, the RCA rate case process is the ultimate backstop. If Enstar's costs rise beyond what the contract anticipated, it goes back to the RCA. The RCA approves rate increases. Ratepayers pay.

This is not hypothetical. Enstar filed a rate case in May 2025 requesting a 5.77% increase — approximately $8.95 more per month per residential customer — citing rising costs. Enstar has already sued Hilcorp over a supply contract dispute, warning of a potential catastrophic gas shortage, with storage at half its target level heading into winter. This is a utility already under financial and operational strain, before Alaska LNG exists, before any cost overruns occur.

The Enstar Protection — What Myers Says vs. What the Record Shows

Myers says: Glenfarne has a contract with Enstar preventing cost increases from being passed to Alaskan customers.

Record shows: Glenfarne and Enstar have a non-binding letter of intent. No definitive agreement. No RCA approval. No legal protection in place.

Myers says: Costs can't be passed to Alaskan customers.

Record shows: Enstar operates under an RCA-guaranteed 11.6% return paid by ratepayers regardless of gas cost. It is already raising rates and suing suppliers. The RCA rate case process is the ultimate cost pass-through mechanism — and it has never failed to allow Enstar to recover its costs from ratepayers eventually.

Alaska Already Gave Away Its Collateral

Myers correctly identifies the core problem with Glenfarne versus oil majors: oil majors have assets — leases, ownership stakes — that can be used as collateral. Developers don't have assets until the pipeline is built.

What Myers does not address is that Alaska already solved Glenfarne's collateral problem — by giving Glenfarne the assets.

In March 2025, AGDC transferred 75% of 8 Star Alaska to Glenfarne. That transfer included every permit, right-of-way, engineering study, and planning document accumulated through nearly $1 billion in public investment since 2014. It included the sole federally permitted LNG export facility on the U.S. Pacific Coast — a permit that took a decade to obtain and cannot be replicated. It included access to $30 billion in potential DOE federal loan guarantees that attach to the project.

In exchange, Glenfarne committed to spend approximately $150 million on pre-FID development costs. On a project valued at $44.5–$54.5 billion by Glenfarne's own estimates, $150 million is three-tenths of one percent of the low-end cost.

Alaska gave Glenfarne the collateral it needed. The assets that oil majors bring to the table — the leases, the ownership stakes, the balance sheet backing — were substituted by Alaska's own publicly funded project assets, transferred to a private New York company for a development commitment worth 0.3% of project cost.

"Myers says developers don't have assets until the pipeline is built. Alaska solved that problem by giving Glenfarne the assets. The collateral is gone. HB 381 asks Alaska to give up the tax revenue too."

And the operating agreements governing what Glenfarne can do with those assets — including whether it can pledge its 75% interest as collateral for third-party financing — are contained in a secret agreement the Legislature cannot see. Senator Giessel demanded disclosure. AGDC cited confidentiality requiring Glenfarne's approval. The Legislature voting on HB 381 does not know whether the collateral Alaska provided has already been pledged to outside lenders.

HB 381 Is the Last Concession in a Series Alaska Has Already Made

Myers frames HB 381 as a necessary tax adjustment for a new type of project with a different business model. That framing misses where Alaska actually stands in the sequence of concessions it has already made.

The Concession Sequence — What Alaska Has Already Given

Concession 1: 75% of all project assets — permits, rights-of-way, engineering, a decade of public investment — transferred for $150 million in development spending. Collateral provided.

Concession 2: 25% equity stake in a Delaware LLC whose governance the Legislature cannot see, with no disclosed operating agreements.

Concession 3: Option to invest up to 25% of construction costs after FID — potentially $11–17 billion of state capital against unvalidated costs.

Concession 4 (proposed — HB 381): Permanent elimination of property tax authority. Fixed volumetric rate set before costs are known. No recapture. No clawback. No exit.

Proposed addition (GaffneyCline recommendation): Stabilization clause — if future tax increases or regulatory changes hurt investor profits, taxpayers cover the losses. Open-ended. No ceiling.

Each individual concession seems manageable in isolation. Together they represent an uncapped, unvalidated, permanently committed exposure of public resources to a private project whose costs sit within striking distance of Myers' own profitability cliff — and whose developer has a corporate equity base of $48.5 million against a project it values at $44.5 billion.

What Myers Gets Right — And What Follows From It

Sen. Myers is correct that Alaska faces a genuine energy crisis. Southcentral's Cook Inlet gas supply is declining. Enstar is already suing suppliers and warning of catastrophic shortages. The urgency of Phase 1 — the pipeline to deliver North Slope gas to Alaskans — is real and serious.

But the energy security argument for Phase 1 does not require — and does not justify — permanently eliminating property tax authority on the export terminal that serves Asian markets. HB 381 treats all three subprojects identically. The local energy crisis is an argument for building the pipeline. It is not an argument for a blank check on the export terminal whose economics Myers' own analysis shows are already dangerously close to the profitability cliff.

Myers ends with a warning about generals fighting the last war. It is a fair warning — but it applies to both sides of this debate. Alaska should not reflexively apply TAPS standards to a different project. It also should not reflexively surrender its tax authority and its assets to any developer who arrives with a promising slide deck, simply because previous gas line efforts failed.

The right lesson from the last war is not to give away everything Alaska has before the new one starts. It is to negotiate from the strength of what Alaska actually holds — the only federally permitted Pacific Coast LNG export facility in existence, in a world where Asian buyers are desperate for non-Russian supply — rather than from the weakness of decades of failed attempts that no longer define Alaska's negotiating position.

Alaska gave away its collateral. HB 381 asks it to give away its tax revenue too. At some point, a senator who correctly identifies the financial fragility of this project needs to ask: what exactly does Alaska get to keep?

Tom Lamb  ·  June 7, 2026  ·  Alaska Policy Commentary

BLACKBOARD POLITICS REVISITED: 20 YEARS LATER, SAME SONG

We need more money, we need more money, we need more money!!!!!!

Some things never change.

Back on December 31, 2005, I wrote about the Anchorage School Board's endless demand for more funding — even after Governor Murkowski handed them $90 million. Twenty years later, the Anchorage School District is staring down a $90 million structural budget deficit for 2026-27, and the School Board is again considering major cuts to programs and staff. Same dollar figure. Same complaint. Same song, different decade.

The Tax Warning Came True

In 2005 I warned that without reform, Alaskans would eventually be voting on new taxes to fund education. That day has arrived. Anchorage voters faced a one-time tax levy in April 2026 that could direct nearly $12 million to the district. I take no pleasure in being right about that.

State Funding Still Broken

The core problem I identified in 2005 — that the state funding formula was flawed — remains unresolved. Alaska's school districts are now estimated to be about $1,400 per student behind in purchasing power because education funding has not kept pace with inflation for over a decade. The Legislature approved a permanent $700 increase to the Base Student Allocation, which provided some stability — but it didn't close the overall funding gap.

The Numbers Don't Lie: What Are We Actually Buying?

Here is where the comparison gets uncomfortable for the Anchorage School Board.

The Anchorage School District's adopted 2025-26 budget was $916 million, serving approximately 47,000 students — that works out to roughly $19,500 per pupil.

Now look at Edmonton. Edmonton Public Schools runs 214 schools serving 120,014 students on a budget of CA$1.42 billion for 2025-26. That's CA$11,832 per student. Converting at the 2025 average exchange rate of roughly US$0.716 per Canadian dollar, Edmonton spends approximately $8,472 USD per student — less than half of what Anchorage spends.

District	Students	Budget	Per Pupil (USD)
Anchorage School District	~47,000	$916 million USD	~$19,500
Edmonton Public Schools	120,014	CA$1.42B (~$1.02B USD)	~$8,472

Edmonton is educating more than twice as many students, in a decentralized system with lean central administration, for less than half the per-pupil cost in adjusted dollars. And yet Anchorage's School Board still insists there is nothing left to cut.

To be fair, Alaska's cost of living is genuinely higher than Alberta's, and Edmonton has its own funding battles with the province. Edmonton trustees have called their provincial funding formula "broken," approving a budget while barely able to add four new teaching positions despite an influx of over 3,000 new students. A decentralized system doesn't protect you from a broken state funding formula.

But that's precisely the point. Edmonton is fighting its funding battles with lean administration and money closer to classrooms. Anchorage is fighting its funding battles while spending more than twice as much per student — with a bureaucracy that has had twenty years of warnings and done little structural reform.

At $19,500 per pupil, Anchorage taxpayers deserve better answers than "we need more money."

The Case for Decentralization — Still Valid

In 2005 I pointed to the Edmonton Public School system as a model for decentralized management — putting budgeting decisions in the hands of principals, teachers, and parents at each school rather than a bloated central administration. San Diego Unified has been doing exactly this since 2011-12, using school site-based budgeting where individual principals and their communities have as much say as possible in how money is spent. Anchorage still hasn't followed suit.

The Anchorage School District claims it has made administrative cuts, pointing to a reduction of 109 full-time administrative positions between 2012 and 2026. That's something — but it still doesn't address the fundamental structural problem: money flows through a central bureaucracy before it ever reaches a classroom.

What Still Needs to Happen

The solution I proposed in 2005 remains sound: let each school build its own budget, have it approved at the state level, and fund it 100% — with strings attached. No money siphoned off for central PR departments. No administrative empire-building. Put the incentives where they belong: with the principal, the teachers, and the parents who show up every day.

Twenty years of the same argument should tell us something. The Anchorage School Board has had two decades to reform. Instead, they've perfected the tantrum.

It's time to try something different.

June 5, 2026  ·  ANWR / AIDEA / Alaska Energy

The Market Has Spoken — Again

Three lease sales. Three failures. And AIDEA keeps bidding with your money.

Today's results, in plain numbers:

The Trump administration offered 58 tracts on 689,000 acres. Nine bids arrived — on five tracts. Total winning bids: $3.7 million. The only two bidders were Hex Energy LLC and the Alaska Industrial Development and Export Authority (AIDEA). Fifty-three of fifty-eight tracts went completely unbid.

Less than three weeks ago, I wrote about AIDEA's plan to spend $190 million in public funds on seismic exploration in ANWR's Coastal Plain — approved without a public hearing, posted on a state notice website on a Sunday, with the board chair declining to answer questions. The argument was simple: a state development authority with no oil expertise was playing oil company with Alaskan taxpayer money, after the private market had twice declined to show meaningful interest.

Today, the private market declined a third time. And AIDEA showed up again anyway.

A Brief History of the Market Saying No

It is worth counting the rejections, because they keep accumulating — and because each one is attributed to a different external excuse while the underlying pattern goes unremarked.

Sale	Date	Private Bids	Total Revenue	Outcome
Sale #1	Jan. 2021	2 companies	$16.5M	Both private leases relinquished. AIDEA leases later canceled, then restored after lawsuit.
Sale #2	Jan. 2025	Zero	$0	Complete bust. No revenue. No leases.
Sale #3	June 5, 2026	1 company (Hex Energy)	$3.7M	53 of 58 tracts unbid. AIDEA again the primary buyer.

The Congressional Budget Office once projected $946 million in revenue from the first two sales alone. Actual cumulative revenue across all three sales is roughly $20 million — about two cents on every projected dollar.

The AIDEA Problem Gets Worse, Not Better

AIDEA showed up again today — with public money — to bid on acreage the private oil industry chose not to touch. It did so while simultaneously holding six existing leases on 308,000 acres and a board-approved plan to spend $175 million on permitting and regulatory work on those leases, plus another $15 million earmarked specifically for new bids in this sale.

That means AIDEA may now hold leases from three separate rounds of a program that private industry has declined to participate in meaningfully each time. The pattern is consistent: every time the market signals disinterest, the state agency steps in, acquires more acreage, and asks Alaskans to fund the development work that would justify the acquisition.

"If AIDEA's leases really contain 4 billion barrels of recoverable oil — as the authority claimed in April — those leases should be selling themselves. Private companies should be lining up to sublease them. They are not."

No private oil company operates this way. No private investor would fund it. That is precisely the point.

Four Questions Still Without Answers

After the $190 million plan was approved without public hearings last month, I raised four questions. Today's auction makes them more urgent, not less.

1. What is the specific, auditable return mechanism for the $190 million? Not a general assertion of future oil revenue — a concrete, reviewable plan for how public funds become public returns, with timelines and accountability.
2. What is the downside scenario? If seismic results are inconclusive, if subleasing fails, if oil prices remain unfavorable — what happens to the money? Who is accountable, and to whom?
3. Why was $190 million approved without a public hearing? This amount exceeds the annual general fund budget of more than half of Alaska's executive branch agencies. A Sunday notice posting is not a substitute for public process.
4. Why is AIDEA bidding on new acreage that private industry just passed on — while simultaneously holding existing leases it lacks the expertise and capital to develop on its own?

What the Market Is Actually Saying

There is a tendency in Alaska energy politics to attribute each failed lease sale to a different external cause: Biden-era cancellations, legal uncertainty, restrictive royalty conditions, low global oil prices. Each explanation contains a grain of truth. Taken together across five years and three administrations, they form something else: a verdict.

The private oil industry is sophisticated. ExxonMobil, ConocoPhillips, and BP have active operations on Alaska's North Slope. They employ geologists, risk analysts, and economists whose careers depend on correctly evaluating resource potential. When they pass on ANWR — repeatedly, across different regulatory environments — they are making a judgment that the risk-adjusted return does not justify the capital commitment.

When that judgment is expressed three separate times, across five years, the response should not be for a state agency to spend $190 million of public money trying to prove the market wrong.

The model AIDEA is running — acquire leases private capital declines, spend public funds proving up the resource, hope to sublease to a private operator — transfers the geological risk entirely onto Alaskan taxpayers while any development upside flows to the private operators AIDEA hopes to eventually attract. Heads, industry wins. Tails, the public loses.

The market has spoken three times. The question is whether Alaska's legislature and the public are listening.

Alaska Policy Commentary  ·  June 3, 2026

Alaska LNG and the Lessons of 2008: When Fiduciary Responsibility Is Abandoned, Everyone Pays

The financial structure being built around Alaska LNG shares five precise structural parallels with the conditions that caused the 2008 financial crisis — self-certified valuations, obscured risk, institutional failure, authoritative cover without independent analysis, and permanent commitments with no exit. Alaska's citizens are the ones holding the bag.

By Tom Lamb  ·  HB 381 · Special Session 2026

In 2008, the global financial system collapsed because institutions that should have known better accepted self-certified valuations, obscured risk through complexity, and created permanent financial commitments without independent stress-testing. Regulators had excessive confidence in measures they had in place. Executives believed their own projections. And when the underlying assets proved worthless, there was no exit — only losses that fell on those least able to bear them.

Sixteen years later, Alaska is replicating that structure — not in mortgage-backed securities, but in the financial architecture being built around the Alaska LNG project. The parallels are not rhetorical. They are structural, precise, and deeply concerning for anyone who remembers what happened the last time fiduciary responsibility was abandoned at scale.

"In 2008, authoritative endorsement substituted for independent analysis. In Alaska, the same substitution is happening — with public money, under legislative time pressure, for a private developer who refuses to disclose independent cost figures."

Parallel One: Self-Certified Valuations Accepted Without Independent Verification

The 2008 crisis was driven by mortgage originators accepting self-certified income statements — borrowers declaring their own income without documentation, lenders accepting those declarations because the incentive structure rewarded volume over accuracy. The underlying asset values were never independently stress-tested.

Today, Glenfarne presented the Alaska Senate Finance Committee with a slide labeled "Glenfarne Estimates 2026" — the company's own internal cost figures, ranging from $44.5 to $54.5 billion. These were not produced by an independent engineering firm hired by the Legislature. They were not benchmarked publicly against comparable projects. They were prepared by the developer seeking the tax concession and presented as the answer to the cost question the Legislature has been asking for months.

The low end — $44.5 billion — is essentially unchanged from the 2018 AGDC estimate of $46.2 billion, despite eight years of construction cost inflation that drove comparable infrastructure costs 40–50% higher across North America. Independent analysts at Rapidan Energy Group put the export phase alone at up to $60 billion.

In 2008, lenders accepted what borrowers told them about their own income. Alaska is being asked to permanently restructure its tax code based on what the developer says about its own costs. The structure is identical.

2008 vs. Alaska LNG: The Valuation Parallel

2008: Mortgage borrowers self-certified income. Lenders accepted without verification. Ratings agencies assigned AAA without independent stress-testing underlying assets.

Alaska LNG: Glenfarne self-certifies project costs. Legislature asked to accept without independent validation. AGDC board and Governor's office assign credibility without independent stress-testing the cost basis.

Parallel Two: Complexity Used to Obscure Risk

In 2008, mortgage-backed securities were structured through layers of financial engineering — tranches, derivatives, credit default swaps — that made the underlying risk nearly impossible for any single party to see clearly. Each layer seemed manageable in isolation. The aggregate exposure was catastrophic.

Alaska's exposure to Alaska LNG is structured the same way. Consider the layers:

Alaska's Layered Exposure — Each Individually Manageable, Collectively Undisclosed

Layer 1: 75% of all project assets — permits, rights-of-way, engineering studies, decades of public investment — transferred to a private New York company for $150 million in development spending.

Layer 2: 25% equity stake in a Delaware LLC whose operating agreements the Legislature cannot see, with no governance transparency for a minority owner of a public asset.

Layer 3: Option to invest up to 25% of construction costs across all three subprojects after FID — potentially $11–17 billion of state capital against unvalidated costs.

Layer 4: Permanent elimination of property tax authority through HB 381 — the one remaining financial lever — before a single independent cost figure has been validated.

Layer 5: A proposed stabilization clause recommended by GaffneyCline — if future tax increases or regulatory changes hurt investor profits, taxpayers cover the losses. Open-ended. No ceiling.

No single layer appears catastrophic in isolation. Together they represent an uncapped, unvalidated, permanently committed exposure of public resources to a private project whose cost basis has never been independently verified. That is precisely the structure that made 2008 possible.

Parallel Three: Institutional Fiduciary Failure

The 2008 crisis was ultimately a fiduciary failure — not primarily corruption or willful fraud, but institutions acting with excessive confidence in their own risk management, abandoning the independent verification standards that fiduciary duty requires. Regulators trusted the system. Executives trusted their models. Nobody independently stress-tested the underlying assumptions.

The Alaska record shows the same pattern. AGDC was granted sweeping unilateral authority to negotiate and execute the Glenfarne agreement — transferring 75% of publicly funded assets under a secret agreement without independent cost validation, without legislative approval, and without disclosed governance terms. The AGDC board chairman declared in April 2025 that no additional feasibility studies were required for private investment. The Governor's office characterized deal terms publicly that the lead developer subsequently contradicted.

A fiduciary entrusted with Alaska's interests was required to act with full information, independent verification, transparency, and undivided loyalty to the state's citizens. At every step, the opposite occurred. That is not necessarily corruption — it may well be, as the Hoover Institution concluded about 2008, a case of self-deception rather than willfulness. But self-deception at the fiduciary level produces the same losses as fraud. The citizens who bear the consequences cannot distinguish between them.

Parallel Four: Authoritative Cover Without Independent Analysis

In 2008, rating agencies provided AAA cover for instruments whose underlying value had never been independently stress-tested. Their authoritative imprimatur substituted for the independent analysis that investors should have demanded. The AAA rating was the answer to every question about underlying risk — until it wasn't.

In Alaska, the AGDC board, the Governor's office, and now a special legislative session provide authoritative cover for a project whose cost basis has never been independently validated. When Senator Giessel asked for disclosed governance agreements, the answer was no. When the Legislature asked for independent cost figures, it received a self-prepared Glenfarne spreadsheet stamped "Strictly Private and Confidential" — in a public hearing.

The Governor publicly claimed a legally binding deal with South Korea was imminent in late 2025. Glenfarne subsequently clarified that the LNG portion of the agreement remained non-binding. The authoritative cover and the underlying reality were not the same thing. They rarely are when fiduciary standards have been abandoned.

"In 2008, the AAA rating was the answer to every question about underlying risk — until it wasn't. In Alaska, the special session is being used the same way: as authoritative cover for a decision that hasn't been independently validated."

Parallel Five: Permanent Commitments With No Exit

The final and most damaging parallel is the exit problem. In 2008, when the underlying assets proved worthless, holders of previously AAA-rated securities found them unmarketable. They could not exit positions that had been structured as permanent commitments. The losses were locked in.

HB 381 creates the same trap for Alaska. Once passed, the property tax restructuring is permanent — a statute, not a contract, with no bilateral termination rights, no recapture provisions, no performance conditions, and no clawback if the project fails to deliver. The 2040 sunset is a binary cliff, not a renegotiation mechanism — and as it approaches, it creates pressure on Alaska to extend rather than walk away.

If the project's true cost makes the economics unworkable — if the Rapidan analysis is closer to correct than Glenfarne's self-prepared estimate — Alaska cannot recover the tax revenue it permanently surrendered. The concession is gone regardless of whether the project is ever built, whether gas ever flows, whether a single Alaskan household ever benefits.

The Critical Distinction: Who Bears the Downside

In 2008, institutions that created the instruments also held them — executives lost along with everyone else, which is why historians concluded it was self-deception rather than pure fraud. The losses were shared.

In Alaska, Glenfarne's downside is capped at $150 million in pre-FID development costs. Alaska's downside is not capped at all — 25% equity exposure to $44–70 billion in construction costs, permanent elimination of property tax authority, and an open-ended stabilization clause. The asymmetry is complete. If the project fails, Glenfarne loses $150 million. Alaska loses everything it committed — permanently.

What the Legislature Must Do Before Voting

The 2008 crisis produced the Dodd-Frank Act, stress-testing requirements, independent valuation standards, and mandatory disclosure rules — all designed to prevent institutions from accepting self-certified valuations, obscuring risk through complexity, and making permanent commitments without independent verification. The world learned that lesson at catastrophic cost.

Alaska is about to repeat it on a smaller but locally devastating scale. The Legislature has the opportunity — and the fiduciary obligation — to stop it. Three things must happen before any vote on HB 381:

The Minimum Standard of Fiduciary Responsibility

1. Independent cost validation. The Legislature must commission or require an independent engineering estimate — not Glenfarne's self-prepared figures — benchmarked against comparable completed projects and reconciled with the Rapidan analysis.

2. Governance transparency. The operating agreements of 8 Star Alaska must be disclosed to the Legislature before it votes to permanently restructure the tax code for that entity's benefit. A minority owner of a public asset cannot be denied visibility into its own investment.

3. Committed financing in place. Tax certainty is one FID condition. It is not a substitute for a committed financing stack. The Legislature should not deliver its permanent concession until the global capital markets have delivered theirs.

The project may well be worth building. The energy security argument is real. North Slope reserves need a route to market. But Alaska LNG will not be the first energy project in history to be worth building and still structured in a way that exposes the public to unacceptable risk.

In 2008, the world learned that fiduciary responsibility cannot be waived under time pressure, that self-certified valuations are not a substitute for independent analysis, and that permanent financial commitments made without stress-testing produce losses that fall on those who had no voice in the decision.

Alaska's Legislature has a voice. It should use it — before the vote, not after.

Tom Lamb  ·  June 3, 2026  ·  Alaska Policy Commentary

Alaska Policy Commentary  ·  June 3, 2026

Glenfarne Just Released Their Cost Estimates. Would a Serious Financing Institution Accept Them?

Today's Senate Finance hearing revealed Glenfarne's self-prepared 2026 cost figures for Alaska LNG. The numbers don't survive contact with project finance reality — and the global capital markets have already signaled their answer by staying silent.

By Tom Lamb  ·  HB 381 · Special Session 2026

Glenfarne presented their 2026 cost estimates to the Alaska Senate Finance Committee today. The headline figures: $44.5 billion on the low end, $54.5 billion on the high end. The Legislature was apparently expected to find this reassuring. It shouldn't. These numbers create more financing problems than they solve — and they reveal why, fifteen months after Glenfarne became lead developer, there is still no committed financing for this project.

Project finance is not a field that takes developer self-estimates at face value. It is a field built on independent verification, benchmarking, and stress-testing every assumption a developer makes. What Glenfarne presented today will not survive that process intact.

"The global capital markets have seen Glenfarne's numbers. They haven't committed. That silence is the most honest assessment of this project's financibility available."

The Numbers Glenfarne Released Today

Glenfarne's own 2026 internal cost estimate, presented in public session to the Senate Finance Committee:

Asset	Low ($MM)	High ($MM)
Pipeline (Phase I)	$13,200	$16,900
LNG Export Terminal (Phase II)	$23,600	$28,400
Gas Treatment Plant (Phase II)	$7,700	$9,200
Total	$44,500	$54,500

Three problems with these figures are immediately apparent to anyone who works in project finance.

First, the low end is implausible. $44.5 billion in 2026 is essentially the same as the 2018 AGDC estimate of $46.2 billion — somehow lower after eight years of construction cost inflation, COVID supply chain disruption, and the steepest materials cost escalation in a generation. The Engineering News-Record Construction Cost Index rose approximately 40–50% over that same period. Every comparable infrastructure mega-project built or estimated since 2018 came in dramatically higher than pre-COVID projections. Glenfarne is asking the financing market to believe Alaska LNG is the exception.

Second, the $10 billion range is itself a financing problem. Lenders don't finance ranges. They finance fixed costs with defined contingency buffers, established through independent engineering to a level of precision sufficient for bankable debt service modeling. A $10 billion spread — 22% of the low-end estimate — signals that the cost basis is not yet at the level of detail required to close project financing.

Third, the independent benchmark gap is unresolved. Rapidan Energy Group, an independent energy consultancy, puts the export terminal phase alone at up to $60 billion — against Glenfarne's $23.6–$28.4 billion for the same component. That is a $30+ billion gap on a single line item. No project finance bank will close without reconciling that discrepancy through their own independent technical review.

What Project Finance Lenders Actually Require

Project finance for a mega-project like Alaska LNG is non-recourse debt — meaning lenders can only be repaid from the project's own cash flows. That structure demands extraordinary due diligence on costs, because if the project costs more than projected, there is no corporate balance sheet backstop.

Every major project finance lender — commercial banks, export credit agencies, the U.S. Export-Import Bank — requires independent engineers to validate cost assumptions and benchmark them against comparable completed projects. This is not optional. It is a standard condition of the due diligence process, applied regardless of how credible the developer appears to be.

Those independent engineers will run Glenfarne's figures against the global database of comparable LNG and pipeline construction costs. They will find the Rapidan analysis. They will apply post-COVID inflation adjustments. And their conclusions will determine whether the debt service math works — not what Glenfarne put in a slide deck.

What Lenders Require — What Alaska LNG Has Today

Independent validated cost estimate: Required by every major lender as a condition of due diligence. Alaska LNG has a self-prepared internal estimate with a $10 billion range that hasn't been independently validated.

Fixed EPC contract with locked cost: Required to model debt service with certainty. Alaska LNG has a provisionally selected contractor. No fixed lump-sum contract exists.

Finalized take-or-pay offtake agreements: Lenders require executed contracts covering minimum debt service quantities. Alaska LNG has 13 MTPA in preliminary LOIs with TotalEnergies, JERA, Tokyo Gas, CPC, PTT, and POSCO. None are finalized.

Committed equity: Lenders require credible equity partners with skin in the game. Alaska LNG has $50 million in development capital from Danaos Corporation — development funding, not construction equity.

Committed debt financing: Alaska LNG has none. The CEO confirmed today that financing arrangements are still being assembled and are contingent on tax legislation passing.

Glenfarne's Own Texas Project Shows What Committed Financing Looks Like

Glenfarne is simultaneously developing Texas LNG — a 4 MTPA export terminal in Brownsville, Texas, roughly one-tenth the cost of Alaska LNG. The contrast in financing progress is stark.

Texas LNG assembled a $5.7 billion committed bank group from leading financial institutions. It has a fixed lump-sum turnkey EPC contract with Kiewit — a known, bankable number that lenders could model. It was on schedule for early 2026 FID. That is what a financeable project looks like.

Alaska LNG — fifteen times larger, infinitely more complex, in a remote Arctic environment — has $50 million in development capital, preliminary letters of intent, a provisionally selected contractor, and a self-prepared cost estimate with a $10 billion range. These are not equivalent situations. The financing gap between what Texas LNG achieved and where Alaska LNG stands today is not a minor procedural difference. It is the entire problem.

"Texas LNG closed a $5.7 billion committed bank group with a fixed EPC contract. Alaska LNG — fifteen times larger — has $50 million in development capital and a self-prepared range. These are not comparable situations."

Tax Certainty Is Necessary — But Not Sufficient

To be fair to Glenfarne's core argument: tax certainty is a genuine condition of FID for LNG projects. International project finance lenders do require regulatory and tax stability before committing capital. On this narrow point, Glenfarne is correct.

But tax certainty is one condition among several that must be satisfied simultaneously. Passing HB 381 delivers Alaska's piece of the puzzle. It does not produce a validated cost estimate. It does not generate a fixed EPC contract. It does not close the Rapidan gap. It does not finalize 16 MTPA in take-or-pay offtake agreements. It does not assemble a committed bank group.

All of those conditions remain open — and the CEO confirmed today that financing won't close without them. The Legislature is being asked to deliver a permanent, irrevocable tax concession as a precondition for Glenfarne to begin assembling the rest of the financing stack. That stack may or may not come together. If it doesn't, Alaska has permanently restructured its tax code for a project that was never built.

The Question the Legislature Should Be Asking

If Glenfarne's $44.5 billion figure is credible and the project is financeable at that cost, the financing should be closeable now — or very soon. The offtake agreements are substantial. The federal permits are in place. The national security tailwind is real. Baker Hughes and POSCO are credible partners.

So why isn't there a committed bank group? Why has FID slipped from end of 2025 to sometime in 2026 — and now potentially into 2027? Why did Glenfarne extend cost evaluation another year if the numbers are solid?

The most parsimonious answer is that the financing market has seen these numbers and found them insufficient. Project finance banks don't stay silent out of politeness. They stay silent because the deal isn't bankable yet.

The Legislature should demand answers to these questions before passing HB 381 — not after. A permanent tax restructuring enacted before the financing closes is a concession Alaska can never take back, given to a project that may never get built. That is not a deal. That is a gift.

Tom Lamb  ·  June 3, 2026  ·  Alaska Policy Commentary