US LNG Export Surge Puts Domestic Gas Pricing on a Global Footing
Pipeline additions and Corpus Christi Stage Three expansion are set to double US LNG export capacity, with Midwest power markets already feeling the pull.
NYMEX Henry Hub front-month gas climbed 3.15% to $2.95/MMBtu by 06:36 UTC on Wednesday (2026-09-02), while ICE Endex TTF front-month gained 4.46% to €69.77/MWh in the previous session. The simultaneous move higher across both basins signals a global gas market where US supply growth is no longer automatically capping domestic prices.3
The infrastructure behind that shift is accelerating fast. EIA estimates the US could add 44.9 billion ft3/d of pipeline capacity during 2026-27, with 31.6 billion ft3/d already under construction. Texas accounts for 29.7 billion ft3/d of planned takeaway, Louisiana another 8.4 billion ft3/d. The recently completed Matterhorn Express — a 580-mile pipe — has already added 2.5 billion ft3/d of Permian takeaway capacity, moving gas to the Katy Hub area near Houston.5
RBAC Inc.'s 26Q2 GPCM Base Case projects US LNG exports more than doubling from 14.9 billion ft3/d in 2025 to 32.4 billion ft3/d by 2035. Getting there requires the current build-out to stay on schedule and find buyers. Neither is guaranteed.5
Cheniere Energy's operational focus is squarely on execution at Corpus Christi Stage Three, where completing the phased expansion is the priority. Cheniere's established complexes and its base of committed customers keep it near the front among LNG exporters, but the operational question is whether the final trains come online without delays.6
The export queue is longer than it looks. Golden Pass — the 9th US LNG terminal — shipped its first cargo on April 22, 2026, with Corpus Christi and Corpus Christi Liquefaction Stage 3 now treated by EIA as one co-located terminal despite using different liquefaction train technologies.1
US LNG exports are expected to average around 17 billion ft3/d in 2026, rising further in 2027 as additional capacity enters service. Projects totaling more than 2.8 trillion cubic feet of annual export capacity reached final investment decisions during 2025, setting up a multi-year supply wave aimed at markets where European storage and Asian demand patterns are shifting.2
Asian buyers are already positioning for it. JERA's integrated report from July (2026-07-31) shows the Japanese utility building a flexible LNG portfolio centered on JERA Global Markets, supported by its own fuel transportation fleet. Its current and future destination-restricted LNG volumes of roughly 40 million tons per year sit alongside a growing tranche of destination-free volumes — a bet on optionality as US contract terms and Asian demand growth pull in different directions.4
Platts JKM LNG front-month rose 4.01% to $23.61/MMBtu by 06:36 UTC on Wednesday (2026-09-02), putting Asian spot in the same neighborhood as European gas on an energy-equivalent basis and keeping the Atlantic LNG arbitrage open. US cargoes are flowing east, with the Henry Hub-TTF spread covering liquefaction costs.3
But the consensus among primary markets tracked for PJM real-time is bearish, with all three signals pointing lower and a bearish strength reading of 100%. PJM Western Hub spot power settled at $73.72/MWh on Tuesday (2026-09-01). Physical gas flowing into Midwest power generation has not moved to reflect the export-driven tightness that futures markets are pricing.3
The geography explains part of the gap. Pipeline capacity originating in Texas and Louisiana is designed to feed Gulf Coast LNG terminals, not Midwest power plants. Yet gas molecules that might otherwise have flowed north are increasingly committed to export contracts, and the futures curve is starting to reflect that competition for supply even as physical balances stay loose.5
US consumers — domestic and commercial alike — are becoming more sensitive to global supply, weather and geopolitical events as domestic prices increasingly track the export market. For Midwest power buyers, Henry Hub is no longer a purely domestic benchmark but a proxy for global gas tightness.2
The physical market will have to reconcile with the futures curve before the next tranche of Corpus Christi Stage Three capacity enters service. If the bearish PJM consensus holds, gas stays relatively cheap for regional power generation. If the forward curve proves right, Midwest generators will eventually bid against Gulf Coast LNG load for the same molecules — and $73.72/MWh PJM power will look like a relic of a less connected market.3