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Alaska LNG has a lower modeled shipping charge to Asia than Louisiana or Texas in the U.S. Energy Information Administration’s 2026 assumptions, but its modeled liquefaction-and-pipeline charge is much higher. The Gulf Coast, meanwhile, has operating export terminals and active expansions; Alaska is a phased greenfield project whose April 2026 filing reported no executed long-term export or supply contracts. For an Asian buyer, neither location is an automatic price winner: the answer depends on the destination, actual contract terms, cargo timing and project delivery risk.
“Alaska LNG” here means the proposed North Slope-to-Nikiski project. “U.S. Gulf Coast LNG” means a regional supply base of multiple terminals, not one comparable project. Status and market figures below are dated to the cited government updates.
How the projects differ in maturity and delivery timing
The Alaska project combines North Slope gas production connections, a long pipeline across the state and a planned liquefaction and marine export terminal in Nikiski. The Federal Energy Regulatory Commission’s project description specifies a design of 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. These are project-design details, not evidence that the facilities have been built.
By contrast, Gulf Coast LNG is supplied by multiple terminals at different stages. In its September 1, 2026 update, EIA reported that Plaquemines was exporting at full capacity, Corpus Christi Stage 3 was exporting from six of seven trains, and Golden Pass had begun exports in April 2026. EIA’s U.S.-wide export average was 17.4 billion cubic feet per day in the first half of 2026, 23% above the same period in 2025; that figure is for the country as a whole, not the Gulf Coast alone.
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Alaska’s phased plan and the permit milestone
In its April 1, 2026 semiannual filing to the U.S. Department of Energy (DOE), the project sponsor described 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 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, pipeline extension to the export terminal and related infrastructure. These are sponsor targets, not verified completion dates or confirmed LNG delivery dates. The filing also records a February 2026 implementation plan submitted to FERC for compliance with early-works conditions.
The Federal Permitting Improvement Steering Council announced on December 11, 2025, that NOAA had renewed the project’s final permit the previous day, completing the last federal permitting action. That closes a permitting milestone; it does not establish construction completion, financing, a final investment decision or readiness to deliver LNG. The cited status record does not establish a definitive final investment decision.
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What EIA’s modeled cost inputs say—and do not say
EIA’s April 2026 Annual Energy Outlook 2026 Natural Gas Market Module gives the following selected assumptions in 2025 U.S. dollars per million British thermal units (MMBtu):
| Modeled charge | Alaska | Louisiana | Texas |
|---|---|---|---|
| Liquefaction and pipeline | $8.85/MMBtu (EIA, AEO 2026) | $3.51/MMBtu (EIA, AEO 2026) | $3.51/MMBtu (EIA, AEO 2026) |
| Shipping to Asia | $1.03/MMBtu (EIA, AEO 2026) | $2.63/MMBtu (EIA, AEO 2026) | $2.64/MMBtu (EIA, AEO 2026) |
In this model, Alaska’s assumed shipping charge is lower, while its assumed liquefaction-and-pipeline charge is substantially higher. EIA also assumes a $3.51/MMBtu reservation charge for each of the four Lower 48 regions shown in the module, fuel charges of 15%, and regasification at $0.12/MMBtu. These are generic model inputs, not bids, quoted freight rates or an all-in delivered cost for a buyer.
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EIA’s separate 2025 model documentation describes Alaska’s modeled LNG price as including an assumed resource price, pipeline transport to the south coast, liquefaction and international shipping. A buyer should therefore not read the two-row comparison as a complete price formula or as proof of which project will offer the lower delivered price. Actual economics depend on the specific contract and its feedgas, financing and completion costs, fuel use, freight and canal charges, destination and timing.
How destination changes the shipping comparison
Alaska’s Pacific-side location is reflected in EIA’s lower modeled shipping-to-Asia charge, but the cited material does not provide a like-for-like current sailing-time comparison from Nikiski to named Asian ports. A shorter map distance alone cannot establish a buyer’s freight cost or delivered price.
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For the Gulf Coast, route depends on the destination and canal conditions. EIA’s June 2016 analysis modeled shipments from Sabine Pass at an average carrier speed of 19.5 knots and one day of canal transit. Under those assumptions, the estimated voyage to Japan was 20 days through the expanded Panama Canal, 31 days through Suez and 34 days around the southern tip of Africa. Using then-current IHS data, the analysis estimated Panama round-trip vessel costs to northern Asian markets at $0.30–$0.80/MMBtu below Suez and $0.20–$0.70/MMBtu below 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.
How firm are Alaska’s reported buyer discussions?
The DOE filing dated April 1, 2026, reported several commercial developments, but also stated that Alaska LNG Project LLC had not entered into long-term export LNG or supply contracts. The reported arrangements differ in legal and commercial status:
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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 under a preliminary arrangement, not an executed long-term LNG supply contract. |
| JERA | Glenfarne signed a non-binding letter of intent regarding discussions for 1 MTPA of offtake | Offtake discussions, not a binding purchase commitment. |
| POSCO International | Heads of agreement setting out commercial terms for a contemplated 1 MTPA sales and purchase agreement, with separate strategic and pipe-steel arrangements | Terms for a contemplated SPA; not an executed SPA. |
| TotalEnergies | Non-binding letter of intent regarding discussions for 2 MTPA of offtake | Offtake discussions, not a binding purchase commitment. |
For a Gulf Coast purchase, terminal maturity does not by itself tell a buyer whether a particular cargo is available or where it may be delivered. EIA describes U.S. LNG contracts generally as often allowing destination flexibility and using Henry Hub futures as the feedgas index. It also describes customers such as utilities, traders and LNG marketers commonly buying on a free-on-board (FOB) basis, paying liquefaction-service charges plus feedgas cost when loading. Those are broad U.S. market patterns, not terms established for any prospective Alaska contract; the governing offer and contract control.
What U.S. export patterns mean for Asian buyers
U.S. cargo supply is not synonymous with cargoes committed to Asia. EIA’s February 2026 overview reported that 68% of U.S. LNG export volumes in 2025 went to Europe, while exports to Asia averaged 2.5 Bcf/d, down from 4.0 Bcf/d in 2024. These figures illustrate that cargo destinations respond to market conditions; an Asian buyer should check the destination and redirection provisions in the actual agreement rather than assume a U.S. terminal’s output is reserved for Asia.
A practical comparison for a buyer evaluating offers
Use project-level announcements and model assumptions to frame due diligence, then compare actual proposals on the same basis. For each candidate source, request or verify:
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- Price formula: feedgas index and pricing period, liquefaction or reservation charges, fuel and other variable charges, and any resource or pipeline component.
- Delivered logistics: FOB or delivered basis, vessel and freight responsibility, destination port, canal and route assumptions, and how shipping costs change for the actual receiving market.
- Flexibility and obligations: destination rights, diversion or redirection provisions, volume tolerances, take-or-pay or other purchase obligations, and force-majeure terms.
- Execution and credit: which facilities must be completed before supply can start, the status of financing and investment decisions, and the seller’s contractual responsibility for non-delivery.
Compare the resulting offers for the same destination, delivery period and contract basis. The EIA figures are useful for identifying a modeled trade-off—lower Alaska shipping assumptions against higher pipeline-and-liquefaction assumptions—but cannot substitute for firm commercial terms or a project-specific delivery schedule.
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