US midstream operators are striving to debottleneck key producing areas to unlock additional supplies to LNG export plants, writes Tray Swanson
London, 5 November (Argus) — The scale of the planned buildout in US liquefaction capacity means new export projects in Texas and Louisiana will increasingly need to tap supply from the Permian and Haynesville shale basins. But higher production from both regions and more pipeline capacity out of the Permian will be required for the two plays to satisfy the additional feedgas demand.
The US has about 17.5bn ft³/d (181bn m³/yr) of liquefaction capacity in operation and 15bn ft³/d under construction, following a spree of final investment decisions this year. More than half of this additional capacity is set to be commissioned by the end of 2028, which will require additional feedgas supplies of about 9.9bn-10.8bn ft³/d, assuming liquefaction losses of 10-20pc.
US gas production may need to grow faster than currently forecast to meet this new demand. About 3.3bn-3.6bn ft³/d of additional feedgas demand is expected to come from new facilities this year, while total gas output in the US is expected to rise by 4.4bn ft³/d, according to the US Energy Information Administration (EIA). But just 2.8bn ft³/d of this year’s new production will come from the Permian and Haynesville basins — the best positioned for supplying new Gulf coast facilities.The Marcellus and Utica basins in Appalachia — the biggest gas-producing region in the US — are less able to meet new feedgas demand, given high utilisation on pipelines connecting the basins with the Gulf coast and legal hurdles for building any new interstate pipelines.
The Gulf coast market could tighten further next year, with about 2bn-2.2bn ft³/d of additional feedgas demand scheduled to come on line but only about 700mn ft³/d of additional gas output expected from the Permian and Haynesville basins. And even larger supply deficits are projected for the following two years, if projects stick to their scheduled timelines.
But production in the Haynesville and Permian basins may be able to grow faster than current forecasts suggest, if infrastructure bottlenecks are removed. A growing network of pipelines is advancing in states with industry-friendly regulatory and permitting regimes, which could be used by Haynesville and Permian producers to ship their supply to the Gulf coast.
The Permian is set to remain the fastest-growing gas-producing play in the US, with output expected to climb to 27.7bn ft³/d this year. Growth is forecast to slow to 2pc in 2026, bringing total output to 28bn ft³/d, according to the EIA. Bottlenecks have so far limited how much Permian gas can reach the Texas-Louisiana border, where nearly 11bn ft³/d of liquefaction capacity is being built.
The initial chokepoint is in the Permian itself, where natural gas is a by-product of crude oil production and is tied to the economics of crude rather than gas. This, coupled with limited pipeline infrastructure, has often led to negative gas prices at west Texas’ Waha hub, leaving producers with little alternative other than to reinject gas into reservoirs or increase linepack — gas stored in the pipeline network. Such occasions have become more frequent since Texas regulators cracked down on flaring allowances in 2021.
Tight pipeline capacity meant Waha prices sank to a record low of -$/mn Btu in early October, when unplanned outages on westbound flows coincided with planned maintenance on eastbound flows.
Midstream firms have plans to boost pipeline capacity out of the Permian. A total 9.1bn ft³/d of eastbound capacity is set to enter service in 2026-28, most of which will directly supply export facilities on the Gulf coast. Two projects will flow southeast to the Agua Dulce hub, which has tie-ins to US developer Cheniere’s Corpus Christi terminal and fellow LNG exporter NextDecade’s Rio Grande facility. A third new line will link to the Katy hub, west of Houston. Midstream firm Energy Transfer’s 1.5bn ft³/d Hugh Brinson pipeline will ship Permian gas to the Dallas area, hundreds of miles from the coast, but that could free up more Haynesville supply to move south for export.
There are further bottlenecks at the Katy hub, especially after Texas-based WhiteWater’s 2.5bn ft³/d Matterhorn Express pipeline began shipping more Permian supply to Houston in October 2024. Less than 3bn ft³/d of pipeline capacity runs from Katy directly to the Gillis hub, north of Lake Charles, Louisiana — a key supply corridor for LNG terminals. But midstream operators plan to add 7.5bn ft³/d of capacity to the broader Texas-Louisiana LNG corridor by the end of the decade. The largest of the three projects may be in operation by the end of this year, even though flows are set to remain capped until LNG developer Venture Global’s 4.4bn ft³/d CP Express pipeline begins service in 2027.
Crude economics last year resulted in Permian gas flooding the regional market faster than new pipeline capacity could enter service. In contrast, Haynesville producers had to rein in output last year and into 2025 in response to oversupply in the US gas market that brought Henry Hub prices below their breakeven.
Haynesville production fell sharply to 14.7bn ft³/d in 2024 from 16.4bn ft³/d a year earlier, as producers curtailed operations in response to the low prices. Higher prices allowed output to rebound to 15.1bn ft³/d in January-September and production is expected to average 15.2bn ft³/d over 2025 as a whole and 15.6bn ft³/d in 2026, according to the EIA. Breakeven costs in the Haynesville are about $/mn Btu. Henry Hub prices on the Nymex 2026 calendar strip were at $/mn Btu on 3 November. Gas output in the Haynesville could rise above the 2023 record after the completion of pipeline projects that will ship Haynesville gas south to the Gillis hub on the Louisiana coast. Two large projects started up in the second half of 2025.
But the additional infrastructure from both basins will increase scope for competition between Haynesville and Permian producers and may also create issues for LNG terminals because the gas in each basin has different compositions.
Permian supply tends to require more treatment to eliminate impurities compared with Haynesville gas, specifically nitrogen and heavy hydrocarbons. Nitrogen reduces gas’ heating value and boiling point, meaning LNG terminals have to use more energy in liquefaction. Most pipelines allow for gas with nitrogen levels of about 3pc, but LNG facilities require nitrogen content to be less than 1pc.
Such shifts in feedgas composition increase the amount of maintenance terminals require.
Cheniere’s 33mn t/yr Sabine Pass facility, on the Louisiana side of the Sabine River, has reported issues with nitrogen since the Matterhorn Express began tying in to interstate pipelines such as the Texas Eastern Transmission and Transcontinental systems. Sabine Pass has had to change its liquefaction process to accommodate higher nitrogen content and different solvents are required to clean heavy hydrocarbons from the terminal’s heat exchangers, company executives say. The facility underwent planned three-week maintenance in June, its first major outage since the Matterhorn began service the previous year.
Several planned LNG export plants will use nitrogen rejection units (NRUs) to purify the feedgas on site, including Venture Global’s 28mn t/yr CP2 and compatriot energy firm Sempra’s 27mn t/yr Port Arthur facilities. NRUs can cost about $/1bn ft³ of gas treated, market participants say. But the process typically emits less methane than other methods of nitrogen removal — a key distinction for US exporters seeking to further expand their share of the European market, given the EU’s plans to regulate methane emissions of imported gas.
