Alaska LNG has a lower modeled shipping charge to Asia than Louisiana or Texas, but a much higher modeled liquefaction-and-pipeline charge. Gulf Coast LNG has the advantage of an established export base; Alaska is a phased greenfield project whose April 2026 filing said it had not yet executed long-term export or supply contracts. For an Asian buyer, neither option is a universal price winner: the relevant comparison is a destination-specific delivered-cost offer, the contract’s legal firmness and flexibility, and the likelihood that cargoes will be available when needed.
What exactly is being compared?
Alaska LNG is a specific proposed project: North Slope gas would travel through a long in-state pipeline to a planned liquefaction and export terminal at Nikiski. “U.S. Gulf Coast LNG” is a regional category, not one project. It includes operating terminals as well as facilities and trains still ramping up.
That difference matters to procurement. A Gulf Coast buyer can evaluate offers from an existing export market, although a terminal’s existence does not mean its cargoes are committed to Asia. An Alaska buyer is assessing both gas supply and the execution of a new pipeline-and-export system.
What is Alaska LNG’s project status and design?
Integrated project in the federal record
The historic FERC project description sets out a liquefaction facility designed for up to 20 million metric tons per annum (MTPA), an approximately 807-mile, 42-inch pipeline, a gas treatment plant, a short connection to Prudhoe Bay production, a 63-mile lateral to Point Thomson, and eight compressor stations. The permitting dashboard described the mainline as crossing Alaska to a terminal and marine export facility in Nikiski. These are planned project components in the record, not evidence that the facilities are built.
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Phased implementation and target dates
In its April 1, 2026 semiannual filing, Alaska LNG Project LLC described a plan divided into two financially independent phases. Phase One is a roughly 739-mile, 42-inch pipeline to be built in three or four sections, potentially including the 63-mile Point Thomson lateral. The sponsor targeted mechanical completion in 2028 and first gas in 2029. Phase Two would add the liquefaction terminal, gas treatment plant, compressor stations, the pipeline extension to the export terminal, and related infrastructure. The filing also reported a February 2026 implementation plan submitted to FERC for compliance with early-works conditions.
The Permitting Council announced on December 11, 2025 that NOAA had renewed the final permit on December 10, completing the last federal permitting action. That is a permitting milestone; it does not establish construction completion, financing, a final investment decision, or a commercial delivery date.
How firm is Alaska LNG’s buyer interest?
The April 1, 2026 DOE filing reported several commercial discussions and preliminary arrangements. Their status is not interchangeable with executed long-term supply contracts.
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| Counterparty | Reported arrangement | What it does—and does not—establish |
|---|---|---|
| PTT | Preliminary cooperation agreement involving strategic participation and potential procurement of 2 MTPA over 20 years | Potential procurement and a preliminary agreement, not an executed long-term LNG sales contract |
| JERA | Glenfarne signed a non-binding letter of intent concerning discussions for 1 MTPA of offtake | Non-binding discussions, not committed offtake |
| POSCO International | Heads of agreement setting out commercial terms for a contemplated 1 MTPA sales and purchase agreement, alongside separate strategic and pipe-steel arrangements | A contemplated SPA and related arrangements; the filing still reported no executed long-term export or supply contract |
| TotalEnergies | Non-binding letter of intent concerning discussions for 2 MTPA of offtake | Non-binding discussions, not committed offtake |
The same DOE filing explicitly said Alaska LNG Project LLC had not yet entered into long-term export LNG or supply contracts. Buyers should therefore distinguish the stated volume and duration of a potential arrangement from a legally binding delivery commitment.
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What do EIA’s modeled cost assumptions show?
The U.S. Energy Information Administration’s April 2026 AEO 2026 Natural Gas Market Module uses the following selected charge assumptions, expressed in 2025 dollars per million British thermal units (MMBtu):
| Modeled charge | Alaska | Louisiana | Texas |
|---|---|---|---|
| Liquefaction and pipeline fees | $8.85/MMBtu | $3.51/MMBtu | $3.51/MMBtu |
| Shipping to Asia | $1.03/MMBtu | $2.63/MMBtu | $2.64/MMBtu |
The model also assumes a $3.51/MMBtu reservation charge for the four Lower 48 regions shown, a 15% fuel charge, and $0.12/MMBtu for regasification. Those are model inputs, not offers from a seller or a buyer’s contracted delivered cost. In separate 2025 model documentation, EIA describes Alaska’s modeled LNG price as including an assumed resource price, pipeline transport to the south coast, liquefaction, and international shipping.
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The comparison points to a real trade-off within the model: Alaska’s assumed shipping charge to Asia is lower, while its assumed liquefaction-and-pipeline charge is substantially higher. The table does not establish which source would deliver LNG at the lower total cost. An actual buyer would need project-specific terms for feedgas, pipeline and liquefaction charges, fuel consumption, freight and canal costs, financing and completion, destination, and timing.
How does the destination affect shipping?
Alaska’s Pacific-side location is reflected in EIA’s lower modeled shipping-to-Asia charge, but the cited material does not provide a matched current sailing-time comparison from Nikiski to named Asian ports. A shorter geographic route by itself is not a guaranteed delivered-cost advantage.
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Clear out junk files and repair common Windows errorsFree Scan →Scan for outdated or missing drivers - takes under a minuteDriver Scan →For context, EIA’s June 2016 route analysis modeled Gulf Coast shipments from Sabine Pass. Assuming an average carrier speed of 19.5 knots and one day of canal transit, it estimated a 20-day voyage to Japan through the expanded Panama Canal, 31 days through Suez, and 34 days around the southern tip of Africa. Based on then-current IHS data, it estimated Panama round-trip vessel cost to northern Asian markets at $0.30–$0.80/MMBtu less than the Suez route and $0.20–$0.70/MMBtu less than the Cape route. These are historical route illustrations, not current freight quotations. EIA also noted that Panama need not be the lowest-cost route for markets west of northern Asia, including India and Pakistan.
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For a purchase decision, compare shipping to the actual receiving port and account for the route and canal exposure in the offer. A northern Asian destination and a destination farther west may not favor the same route.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.What does the Gulf Coast’s operating base offer?
EIA’s September 1, 2026 update reported that Plaquemines was exporting at full capacity, Corpus Christi Stage 3 was exporting from six of its seven trains, and Golden Pass had begun exports in April 2026. Across the United States—not the Gulf Coast alone—LNG exports averaged 17.4 billion cubic feet per day (Bcf/d) in the first half of 2026, 23% above the first half of 2025.
This supports a maturity distinction, not a guarantee that a particular buyer can secure a particular cargo. Operating terminals and active ramp-ups provide a more established export base than Alaska’s proposed pipeline and terminal. Buyers still need to check the seller, available volumes, delivery schedule, and contract commitments.
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How do U.S. contract patterns affect Asian buyers?
EIA describes U.S. LNG contracts generally as often offering destination flexibility and feedgas indexed to Henry Hub futures. It also explains that customers such as LNG marketers, utilities, and traders generally buy on a free-on-board (FOB) basis, paying liquefaction-service charges plus feedgas cost when a cargo is loaded. These are general U.S. market patterns; they are not terms established for a prospective Alaska LNG contract.
Destination flexibility can matter because cargoes may be redirected as market conditions change. EIA reported in February 2026 that 68% of U.S. LNG export volumes in 2025 went to Europe, while exports to Asia were 2.5 Bcf/d, down from 4.0 Bcf/d in 2024. Those figures illustrate that U.S. cargo destinations respond to market conditions; they do not show that a terminal’s supply is committed to Asia. A buyer should review destination rights, redirection provisions, and any associated costs in the actual contract.
How should a buyer compare the two options?
Use the same destination, timing, and commercial assumptions for each offer. The EIA figures are useful for identifying modeled cost components, but they cannot replace a binding seller quote or project-specific contract evaluation.
- Confirm availability and timing. Separate cargoes from operating or ramping facilities from Alaska’s sponsor-targeted milestones for a phased project. Treat targets as targets, not guaranteed delivery dates.
- Check legal commitment. Identify whether the volume is backed by an executed sales and purchase agreement, a heads of agreement, a preliminary cooperation agreement, or a non-binding letter of intent.
- Build the delivered-cost comparison. Compare feedgas pricing, pipeline and liquefaction charges, fuel, reservation charges where applicable, shipping to the receiving port, canal exposure, and regasification. Keep model assumptions separate from offered contract terms.
- Review flexibility and exposure. Check the price index, FOB or other delivery basis, destination and redirection rights, volume obligations, and what happens if a project milestone slips.
- Test route fit. Use destination-specific freight and timing rather than treating “Asia” as one port or assuming a shorter route always produces the lower delivered cost.
The evidence available as of the dates above supports a buyer-specific comparison, not a universal winner. Alaska’s modeled shipping advantage comes with a higher modeled pipeline-and-liquefaction charge and substantial execution steps; Gulf Coast LNG has a more established export base, but the cargo and contract terms still determine whether it suits a particular Asian buyer.
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