Global Liquefied Natural Gas (LNG) export capacity is set to surge to record levels, creating a “tsunami” of new supply. Industry forecasts project nearly a 40% jump in global export capacity by 2030, with about 290 bcm/year (~220 Mtpa) of new projects (Some have reached Final Investment Decision or under construction stage) becoming operational, according to iea.org. Qatar’s massive North Field expansions (from 77 to 142 Mtpa by 2030) and a renaissance of the U.S. LNG projects are driving this wave. For example, U.S. capacity is rising rapidly:
- Cheniere’s Corpus Christi Stage 3 (Texas) began deliveries in early 2025 (7 trains adding 3.1 Bcf/d ≈27 Mtpa by 2026), and
- Venture Global’s Plaquemines (Louisiana) launched Phase 1 (1.3 Bcf/d) in Dec 2024, with Phase 2 (another 1.3 Bcf/d) due in late 2025.
By 2028, U.S. export capacity could reach ~21.2 Bcf/d (25.2 Bcf/d peak) with projects like Golden Pass (Texas), Rio Grande (Texas) and Port Arthur (Texas/Los Angeles) becoming operational. Such rapid supply growth clashes with softening demand in key markets. Institute for Energy Economics and Financial Analysis (IEEFA) notes that Europe, Japan and South Korea (over half of world LNG demand) saw falling LNG imports in 2023, and demand is unlikely to rebound strongly. Asian growth is slowing too: for example, China – the world’s top LNG buyer – now sees analysts forecasting a 6–11% drop in LNG imports for 2025 as industrial demand weakens and tariff policy blunts coal-to-gas switching. In contrast, U.S. domestic gas demand is rising modestly, driven by power and data centers: Texas is already planning multi-gigawatt gas-fired plants co-located with new AI/data-center hubs (the “Stargate” project in Abilene could alone add ~0.66 Bcf/d of gas demand by ~2027).
Figure: Long-term LNG export forecasts by region and LNG as share of global gas, 2000–2050. (Source: Thunder Said Energy model.)
In practice, this excess has already begun to depress prices. Henry Hub–linked US LNG is driving global pricing in an oversupplied regime. Timera Energy notes that as North American LNG grows from ~22% of global supply in 2023 to ~34% by 2030, the US will increasingly set the marginal price. If U.S. netback prices (LNG export margin) fall below plants’ variable costs, many cargos can be cancelled – sending gas back into the domestic market. Indeed, analysts warn that portfolio buyers now routinely include optionality to cancel cargos rather than buy at a loss. (For example, during the 2020 downturn, US buyers canceled dozens of cargos when European prices dipped below Henry Hub, a pattern that could recur if Asian demand stays weak.) This cargo-flexibility acts as a “soft floor” under Henry prices, capping how low Asian/European prices can fall. Overall, the LNG market is shifting from a tight, destination-contract world to one where spot trading dominates and gas behaves more like a global oil market.
Texas at the Center of LNG’s Global Surge
According to iea.org, the United States, and Texas in particular, sits at the heart of this story. North America was already the largest source of new LNG FIDs, with ~70% of global projects sanctioned in 2022–23. After a pause in 2024 (permits were frozen), U.S. approvals roared back in 2025, again dominating new capacity approvals. This pipeline of projects means US exports will nearly triple over the next decade. Thunder Said forecasts US exports growing from ~80 Mtpa today to ~240 Mtpa by 2035. Much of that new capacity comes from Texas:
- Cheniere’s Corpus Christi expansion (Stage 3) will reach 3.1 Bcf/d nominal by 2026, making it the 2nd-largest US terminal.
- Two new greenfield Gulf Coast projects—NextDecade’s 27 Mtpa Rio Grande LNG and Sempra’s Port Arthur LNG (and Golden Pass via QatarEnergy) – should be in service by 2027–28, adding tens of millions of tons.
In total, U.S. export capacity could hit ~15.4 Bcf/d (18.7 peak) once Plaquemines Phase 2 and CC 3 finish, and ~21.2 Bcf/d by 2028 after Golden Pass, Rio Grande and Port Arthur complete. Texas will shoulder a large share of this: the Permian and Haynesville basins are expanding pipelines (e.g. EPIC’s Young gas line, ET’s 1.5 Bcf/d Hugh Brinson line) to feed LNG terminals. East Daley Analytics notes that by end-2025, ~17 Bcf/d of Permian/E. Texas gas will be needed to supply the Haynesville and LNG export demand, with rigs doubling to 72 in the Haynesville. New demand from data centers and AI power in Texas will further strengthen domestic gas markets even as exports climb.
Taken together, these trends mean price volatility and investment opportunity. In the short term (2025–26) Europe and Asia may face softer prices as inventories and pipeline gas fill gaps, but by 2027 the glut of LNG will likely push spot prices sharply lower. Low gas prices will favor canceling marginal cargos: Timera’s model shows a very elastic LNG supply curve due to U.S. shutdown optionality. In other words, if Henry Hub jumps (due to U.S. supply tightness or surge in domestic demand), it directly raises the “cancellation strike price” for US exports and brings more U.S. volume back to the domestic market.
| For investors, this means U.S. gas hubs will be the main swing factor in global LNG pricing in the next 2–3 years. |
From this, the looming LNG wave presents both risks and rewards. On one hand, an oversupplied market suggests near-term price weakness; on the other hand, it underscores the value of flexibility and infrastructure. Projects with low operating costs (e.g. U.S. shale-to-LNG trains) and flexible contracts will win, while less flexible projects may struggle. Meanwhile, expanding downstream capacity (LNG shipping, regas terminals) will be crucial. Strategically, our analysis suggests focusing on resilient assets: Texas pipelines and greenfield LNG trains (especially with destination-flex contracts), as well as hedge strategies tied to Henry Hub movements. Institutions combining energy transition goals with LNG exposure—such as LNG-to-hydrogen hubs or carbon-capture-enabled projects—may find long-term value.