For Asian buyers, Alaska LNG’s clearest modeled advantage is lower shipping cost to Asia; its modeled liquefaction-and-pipeline charge is substantially higher than the comparable Louisiana and Texas assumptions. Gulf Coast LNG, meanwhile, comes from an established export region with operating terminals and active capacity ramp-ups. Alaska has completed the reported federal permitting process, but remains a phased development, and its April 2026 Department of Energy filing said no long-term export or supply contracts had been executed. The better fit depends on destination, timing, actual contract terms and delivery risk—not on shipping cost alone.
These are not two equally mature projects
Alaska LNG is a specific proposed supply chain: North Slope gas would travel south through a major in-state pipeline to a planned liquefaction and export terminal in Nikiski. “U.S. Gulf Coast LNG” is a regional category, not one project. It includes existing export terminals as well as facilities and trains still ramping up.
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The distinction matters to procurement. A buyer comparing Alaska with Gulf Coast supply is weighing a new integrated pipeline-and-terminal development against a market that already has operating export capacity. The federal permitting milestone for Alaska is meaningful, but it is not equivalent to construction completion, financing, a final investment decision or a firm cargo delivery date.
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What Alaska LNG plans to build—and what its timeline means
The integrated project design
The project description in the Federal Energy Regulatory Commission record sets out a proposed facility designed for up to 20 million metric tons per annum. Its planned components include 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, eight compressor stations, and a liquefaction and marine export facility in Nikiski. These are design figures for the proposed integrated project, not evidence that the facilities have been built.
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A phased implementation plan
In its April 1, 2026 semiannual filing with DOE, the 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 of that pipeline in 2028 and first gas in 2029. Those are sponsor targets for the pipeline phase, not verified completion dates or a date when LNG cargoes will be available.
Phase Two would add the liquefaction terminal, gas treatment plant, compressor stations, the pipeline extension to the export terminal and related infrastructure. The DOE filing also noted an implementation plan filed with FERC in February 2026 for compliance with early-works conditions. Buyers should therefore distinguish the targeted timing for pipeline gas from the separate work needed to create export-ready LNG supply.
Permitting is a milestone, not a startup date
The Federal Permitting Improvement Steering Council announced on December 11, 2025, that NOAA had renewed the final permit on December 10, completing the last federal permitting action. That closes a federal permitting milestone; it does not establish that construction, financing or a final investment decision is complete.
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The April 1, 2026 DOE filing reported commercial discussions and preliminary arrangements with several prospective buyers. Their legal status differs, so announced interest should not be treated as executed long-term supply:
- PTT: A preliminary cooperation agreement involving strategic participation and potential procurement of 2 MTPA over a 20-year term.
- JERA: Glenfarne signed a non-binding letter of intent covering discussions for 1 MTPA of offtake.
- POSCO International: A heads of agreement set out commercial terms for a contemplated 1 MTPA sales and purchase agreement, alongside separate strategic and pipe-steel arrangements.
- TotalEnergies: A non-binding letter of intent covering discussions for 2 MTPA of offtake.
The same filing explicitly said Alaska LNG Project LLC had not yet entered into long-term export LNG or supply contracts. A preliminary agreement, heads of agreement or non-binding letter of intent is not the same as an executed long-term sales and purchase or supply contract.
What EIA’s modeled cost assumptions say about delivery to Asia
The U.S. Energy Information Administration’s April 2026 AEO 2026 Natural Gas Market Module gives selected export-cost assumptions in 2025 dollars per million British thermal units (MMBtu). These are generic model inputs used to assess export economics, not seller offers, quoted freight rates or a buyer’s contracted delivered price.
| Modeled charge | Alaska | Louisiana | Texas |
|---|---|---|---|
| Liquefaction and pipeline fee | $8.85/MMBtu | $3.51/MMBtu | $3.51/MMBtu |
| Shipping to Asia | $1.03/MMBtu | $2.63/MMBtu | $2.64/MMBtu |
In this model, Alaska’s shipping charge is lower, while its assumed liquefaction-and-pipeline charge is higher. The two rows do not add up to an all-in price comparison: EIA’s model also includes other components, and the table does not establish a contract price or prove which source would be cheaper for a particular buyer.
For context, the same EIA assumptions include a $3.51/MMBtu reservation charge for the four Lower 48 regions shown, a 15% fuel charge and $0.12/MMBtu for regasification. The reservation figure is not an Alaska-specific value. EIA’s separate 2025 model documentation explains that its modeled Alaska LNG price includes an assumed resource price, pipeline transport to the south coast, liquefaction and international shipping. The underlying assumptions and the way charges are treated matter when comparing a model result with an actual offer.
A buyer’s delivered-cost analysis needs project-specific terms for feedgas, liquefaction, fuel consumption, financing and completion costs, freight and canal charges, destination and timing. The EIA numbers are useful for identifying cost components and modeled differences; they are not bids from Alaska LNG or Gulf Coast sellers.
How destination and routing affect the shipping comparison
Alaska’s Pacific-side location aligns with its lower Asia shipping charge in EIA’s 2026 assumptions. But those assumptions do not provide a matched port-to-port sailing-time comparison between Nikiski and specific Asian receiving ports. A buyer should not turn a general geographic advantage into a guaranteed transit-time or delivered-cost result.
For Gulf Coast cargoes, a June 2016 EIA analysis illustrates how route choice can change the calculation. For shipments from Sabine Pass to Japan, assuming average carrier speed of 19.5 knots and one day of canal transit, it estimated 20 days through the expanded Panama Canal, 31 days through Suez and 34 days around the southern tip of Africa. Based on IHS data available at the time, the analysis estimated Panama round-trip vessel costs to northern Asian markets at $0.30–$0.80/MMBtu less than Suez and $0.20–$0.70/MMBtu less than the Cape route.
Those voyage and cost estimates are historical illustrations, not present-day freight quotations. EIA also noted that Panama need not be the lowest-cost route for markets west of northern Asia, including India and Pakistan. Actual freight economics depend on the receiving port, route conditions, canal charges and the terms of the shipping arrangement.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.What the Gulf Coast’s operating base changes for buyers
The Gulf Coast comparison includes both operating capacity and projects still ramping up. 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. Across the United States—not the Gulf Coast alone—LNG exports averaged 17.4 Bcf/d in January through June 2026, 23% more than in the first half of 2025.
An operating export base gives buyers a more mature source market than a proposed greenfield chain, but it does not mean a particular Gulf Coast cargo is available to Asia at a given time. EIA reported in February 2026 that 68% of U.S. LNG export volumes in 2025 went to Europe, while Asian exports were 2.5 Bcf/d, down from 4.0 Bcf/d in 2024. U.S. cargo destinations respond to market conditions; buyers need to assess destination rights and redirection provisions in the actual contract.
Contract structure and flexibility need to be compared directly
EIA describes common U.S. LNG contracting patterns as including destination flexibility and feedgas indexed to Henry Hub futures. Customers such as LNG marketers, utilities and traders generally buy on a free-on-board basis, paying liquefaction-service charges plus feedgas cost when loading. These are general patterns in the U.S. market, not terms established for a prospective Alaska LNG contract.
For either source, a buyer should assess the contract itself rather than assume that a market convention applies. Relevant terms include the price formula and index exposure, delivery basis, volume and timing obligations, destination and diversion rights, fuel and freight responsibilities, and remedies if supply or infrastructure milestones are delayed. The April 2026 DOE filing’s statement that Alaska had no executed long-term export or supply contracts makes those terms a future commercial question for that project.
A buyer’s decision framework
- Set the receiving point first. Compare freight to the intended terminal, not to “Asia” as a single destination. Northern Asian routes and markets west of northern Asia can have different economics.
- Separate modeled charges from offers. Use EIA’s 2026 assumptions as a reference for cost components, then request comparable project-specific offers and clarify what each includes.
- Test cargo timing against project milestones. Gulf Coast operating capacity and ramp-ups differ from Alaska’s phased pipeline and terminal buildout; a pipeline target is not an LNG delivery date.
- Check legal firmness. Distinguish executed supply and sales contracts from preliminary cooperation agreements, heads of agreement and non-binding letters of intent.
- Price flexibility and exposure. Compare feedgas indexation, destination rights, freight and canal responsibilities, and the consequences of delays or changes in volume.
On the available evidence, Alaska is most notable for its modeled Pacific shipping advantage, while Gulf Coast LNG offers a more mature operating supply base. Neither point settles the procurement decision: the buyer needs destination-specific economics and firm, comparable contract terms.
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