Gulf Coast LNG Expansion: 75 mtpa Proposed, Far Fewer Funded

The headline figure is 75 million tonnes per annum (mtpa) of new Gulf Coast LNG expansion capacity, but that number is not a delivery schedule. The single largest piece, Sempra’s roughly 27 mtpa Port Arthur North proposal, sits at the Federal Energy Regulatory Commission’s (FERC) pre-filing stage, and its first train is targeted for 2H2034.

Since August 2025, developers have filed expansions at seven export terminals across Louisiana and Texas. Two announcements put the wave back on investors’ radar: Sempra’s Port Arthur news and a September 2026 notice for the Cloud Connector pipeline.

The same wave contains two different investments. One is contracted, financed growth that could run for decades. The other is a cluster of proposals that could arrive into a global gas glut around 2029-2030.

Here is how to separate the projects with money and signed buyers behind them from the ones that remain paperwork, and what to watch before backing any of them.

Seven proposals, 75 million tonnes: what is actually on the table

The scale is real. According to Oil & Gas Watch records, the proposals add about 75.1 mtpa, roughly a 14% rise on all operating, under-construction or previously proposed U.S. export capacity. That capacity comes from a country that has built nine export terminals in the past decade, and 24 other proposals predate August 2025.

U.S. LNG export dominance has been built in under a decade, which explains why the same coastal sites keep attracting new trains and why expansion capital continues to follow proven operators.

The headline weakens once you line it up against later project-level reporting.

These figures do not compare like with like. Some describe new trains, some describe whole-terminal expansions, and some describe concepts that have not been formally filed. The developer of Rio Grande is itself disputed between sources.

Pre-filing is not an approval Port Arthur North (docket PF26-14-000) is in FERC pre-filing. LNG Industry reports a formal application expected in July 2027, a FERC decision in July 2028 and a first train in 2H2034.

The 75 mtpa figure is a ceiling of ambition, not a supply forecast. If you anchor on it, you will overestimate near-term supply and misjudge which companies carry real execution risk.

Why developers keep building on the same ground, and who is buying the gas

The demand story is familiar. EIA data show U.S. exports averaged 17.4 Bcf/d (billion cubic feet per day) in 1H2026, up 23% year on year, with 18.7 Bcf/d forecast for 1H2027. The Strait of Hormuz disruption helped double U.S. shipments to Asia over the same half.

Less obvious is why almost every proposal involves an existing site.

The brownfield advantage

A brownfield expansion adds capacity at a site that already operates or is under construction. Existing terminals come with land, marine access, storage, pipelines, a workforce and established customer relationships, so they are cheaper and faster to extend than a new site. New trains still need project-specific review.

Venture Global’s 26 May 2026 CP2 filing argued that Hormuz disruptions are raising demand for cargoes sourced outside the strait. This buyer-side pull is what U.S. sites are positioned to capture. The industry has developed quickly since Cheniere shipped the first U.S. export from Sabine Pass in 2016, a capability that shale fracking made possible.

Hormuz disruptions have pushed buyers toward securing supply through long-term agreements rather than chasing spot cargoes, which is why signed offtake now separates serious U.S. projects from speculative ones.

Structural versus cyclical demand

• Structural: Europe replacing Russian gas, Asian coal-to-gas switching, long-term energy security contracting
• Cyclical: price spikes, weather, outages, Hormuz rerouting

S&P Global Energy estimated in July 2026 that LNG is a roughly $44 billion annual business that could become the second-largest U.S. net export within five years, with the U.S. holding more than one-third of the global market. Its finding of negligible household gas price effects came from an industry-backed study and remains contested. The IEA puts North America at more than 85% of expected global LNG supply growth in 2026.

Structural demand justifies 20-year contracts. Cyclical spikes can make every project look stronger than its long-run economics support, so your question for any developer is which kind of demand its expansion depends on.

How the money is lining up: FIDs, financing and offtake across the wave

The table below sorts projects by their financing evidence. A final investment decision (FID) is the point at which sponsors commit capital to build.

Three groups emerge from the table. Contracted, financed trains backed by infrastructure funds, sovereign wealth funds and energy majors form the first. Texas LNG sits in a pending middle. The bottom rows show no financing or buyers in the research.

Capital is abundant According to Reuters, alternative investors took part in about $20.35 billion of LNG and midstream deals in 2026, more than twice the total for all of 2024.

That figure shows investor appetite, not guaranteed returns. Binding sales and purchase agreements (SPAs) protect volumes, but they do not protect against buyer distress or construction overruns. A project with closed financing is in a different risk class from one that has only a filing.

Educational: how an LNG export project makes money, and where the return can break

The model is simple. A developer builds liquefaction trains, which chill gas into liquid for shipping, and signs buyers to long-term contracts or tolling fees. Lenders then fund construction through non-recourse project finance, meaning loans repaid from the project’s own cash flow rather than the sponsor’s balance sheet. Binding contracts of 15-20 years are the commercial test.

Key terms:

• FID: the sponsor’s commitment to build
• SPA: a long-term contract to buy LNG
• FTA authorisation: Department of Energy (DOE) approval to export to free trade agreement countries, which is largely automatic
• Non-FTA authorisation: approval to export to all other countries, which requires a public interest review

Export authorisation mechanics matter because FTA approval is largely automatic while non-FTA approval requires a public interest review, and the gap between the two shapes which buyers a project can realistically contract with.

A project typically moves through six stages:

1. Pre-filing
2. FERC application
3. DOE authorisation
4. FID and financing
5. Construction
6. First LNG

Each link can fail. A Reuters-cited analysis flags possible global oversupply of nearly 50 bcm (billion cubic metres) in 2026 and up to 200 bcm by 2030, with the risk peaking in 2029-2030. The EIA warns that gaps between projected and actual in-service dates can shift Henry Hub prices. Cheniere reportedly pushed a Sabine Pass expansion FID from 2025 toward late 2026 or 2027, and even fast-moving Plaquemines faces uncertain Phase 2 timing.

A signed contract lowers your risk without removing it. Buyer strength and the date of first LNG matter as much as the capacity figure.

Permitting, wetlands and litigation: the risks that can move timelines and returns

Regulatory and legal exposure

Procedural risks rarely make headlines, but they move schedules. A federal court found flaws in FERC’s climate and air analysis for Commonwealth, which forced a new order in June 2025. The project still reached FID, but the delay shows that approvals can be reopened.

The Cloud Connector is a proposed 165-mile pipeline that would feed Plaquemines. It received an 11-day comment period, compared with the usual 30, under the Trump Administration’s expedited energy-emergency procedures. Its capacity and in-service date were not found, and final FERC approval has not been established.

Environmental and community pushback

Permit filings indicate the Cloud Connector could affect up to 1,428 acres of wetlands. The CP2 expansion alone could emit more than 4.8 million tons of greenhouse gases a year, comparable to about one million cars and trucks. Louisiana’s Coastal Protection and Restoration Authority reports that the state has lost nearly 2,000 square miles of land since the 1930s.

Anne Rolfes of the Louisiana Bucket Brigade argues the facilities radically alter the coast and strip away wetlands that buffer communities against intensifying hurricanes.

Breon Robinson of Healthy Gulf wants regulators to assess cumulative impacts rather than reviewing projects one at a time. James Hiatt of For a Better Bayou points to existing health effects, traffic and lost fishing grounds in southwest Louisiana. Developers counter that the projects meet regulatory requirements and supply allies seeking secure gas.

• Hurricanes and storm surge
• Rising insurance costs
• Wetland permitting conditions
• Shifts in regulatory policy

None of the seven projects has been cancelled outright, but delays have appeared, including Texas LNG’s unconfirmed FID and slippage at Sabine Pass. Treat announced dates as targets that carry a probability of delay.

What the wave changes, and what still has to be proven

This wave carries more contracts, FIDs and financing than earlier speculative rounds. The concentration of new capacity still creates a plausible oversupply window in 2029-2030. The open question is not near-term demand but what demand looks like after large U.S., Qatari and other supply arrives.

A global gas supply boost arriving from the U.S., Qatar and other producers by 2030 is what turns a strong demand story into a plausible oversupply window for projects without contracts.

Signals to watch:

1. CP2 brownfield FID (targeted early 2027)
2. Plaquemines expansion FID (1H2027)
3. Confirmation of Texas LNG’s FID
4. Port Arthur North’s FERC application (July 2027)
5. The outcome of the Cloud Connector review

The strongest positions have signed offtake, closed financing and permits in hand. Everything else is optionality priced on hope, so weigh your own exposure accordingly.

Past performance does not guarantee future results. Financial projections are subject to market conditions and various risk factors. This article is for informational purposes only and should not be considered financial advice. Investors should conduct their own research and consult with financial professionals before making investment decisions.