GasCon Is the Best and the Rest Is All Drips – The Broad Impacts of NatGas’s Big Inflection Point

No doubt, there’s at least a little angst about the possibility of an overbuild. (Not unlike the worries some express about AI and data centers, which we talked about in our recent 2026 Prognostications blog.) Just a few days ago, Energy Transfer (ET) announced that it had suspended development of its 16.5-MMtpa (2.2-Bcf/d) Lake Charles LNG project, despite having secured long-term commitments for nearly 80% of its capacity. (ET said the company’s gas pipeline projects, including two out of the Permian, would provide “superior risk/return profiles.”) But we see LNG export volumes holding up, even if margins for some do get thin — we’ll explain why at GasCon 2026 in February — and we expect still more LNG projects will reach FID this year, including capacity being eyed by heavy hitters Cheniere Energy and Venture Global.

While expected growth in LNG feedgas demand may dominate, there’s also a lot happening on the power-generation front. ERCOT, the electric-grid operator for most of Texas, has said it expects power demand in its region to roughly double by the early 2030s, with most of the incremental need for electricity coming from data centers and much of the rest driven by population/economic growth and the electrification of Permian production. And while we remain skeptical of the scale of data center development, several gas-fired power projects are planned in Louisiana and the broader Southeast. Together, these may well add up to several Bcf/d of gas demand.

The gas-supply part of the equation is, well, complicated. On one hand, there’s ongoing supply-push production in the Permian, where crude-oil-focused drilling generates massive — and, thanks to rising gas-to-oil ratios (GORs), steadily growing — volumes of associated gas that need to be gathered, processed and (for nearly 90% of the natural gas and all the NGLs) transported to end users outside the basin. According to RBN’s NATGAS Permian report, of the 19 Bcf/d of gas that exits West Texas and southeastern New Mexico (stacked layers in Figure 2 below), 13 Bcf/d is piped east (dark-blue layer), predominately to the Gulf Coast — the other 6 Bcf/d is split about equally among northbound (orange layer), westbound (green layer) and Mexico-bound (light-blue layer) pipelines out of the Permian.

There’s also demand-pull production in other areas supplying gas to the Gulf Coast. These include the Eagle Ford in South Texas and the Haynesville in northwestern Louisiana and northeastern Texas, plus more distant gas-producing plays like the Marcellus/Utica in Appalachia, the Anadarko in the Midcon, and the Niobrara in the Rockies. (Some also are placing bets on the Western Haynesville in East Texas’s Freestone, Leon, Limestone and Robertson counties.) The old-school Haynesville is the coast’s biggest swing-production region. It has vast amounts of gas trapped in its rock and it’s only a hop, skip and a jump from a long list of LNG export terminals. But there’s an important catch, namely that a substantial portion of its gas reserves are economic to develop only if gas prices top $3, $4 or even $5/MMBtu. (Another topic we’ll discuss in depth at GasCon 2026.)

The increasing volumes of natural gas being pushed or pulled to the Gulf Coast will require an increasingly beefed-up and flexible network of pipelines and gas-storage facilities. Midstream companies have been responding to this need in spades. Over the past couple of years, hardly a month has gone by without the announcement of yet another greenfield project or expansion of an existing facility. Consider gas pipelines out of the Permian. Gulf Coast Express (GCX), Permian Highway Pipeline (PHP) and Whistler Pipeline added a combined 6-plus-Bcf/d of takeaway capacity in 2019-21, and Matterhorn Express brought another 2.5 Bcf/d in 2024.

That was just the beginning, though. As we noted in the introduction to today’s blog, another 10 Bcf/d of pipeline capacity out of West Texas is in the works, including 8.4 Bcf/d to the coast: 2.5 Bcf/d from the Blackcomb Pipeline to the Agua Dulce hub in late 2026; 1.5 Bcf/d from the Hugh Brinson Pipeline to the Dallas area, also in late 2026 (followed by a 700-MMcf/d expansion a year later); and an astounding 3.7 Bcf/d from Eiger Express in 2028-29. To the west, Energy Transfer in August took FID on its 1.5-Bcf/d Desert Southwest Pipeline from the Waha Hub to the Phoenix area. All that new pipe could turn the Permian’s long-lived dearth of exit capacity and abysmal local gas prices into a (temporary) glut and narrow price basis.

The anticipation of rising LNG export and power-generation demand also has been underpinning the development of new gas pipelines from the Haynesville to the coast, new pipelines along the coast, and new gas storage throughout the Gulf Coast region. Out of the Haynesville, there’s the 1.8-Bcf/d Louisiana Energy Gateway (LEG) and the 2.2-Bcf/d Momentum NG3 pipelines, both of which came online in 2025, as well as the planned 2.5-Bcf/d Pelican Pipeline, slated to start up in the latter half of 2027, and Boardwalk’s recently announced 1.5-Bcf/d Texas Gateway project, which would come online in late 2029. Along the coast, there’s another set of pipeline projects totaling 15 Bcf/d — from south to north, they include Rio Bravo (4.5 Bcf/d), Traverse (2.5 Bcf/d), Blackfin (3.5 Bcf/d), Trident (2.2 Bcf/d), and Mustang (2.5 Bcf/d). 

There’s one more category of Gulf Coast gas pipelines to keep in mind: projects to help deliver gas to new power plants and other customers in the Southeast. Examples? One is Boardwalk’s 1.16-Bcf/d Kosci Junction Pipeline, which will run 110 miles south/southeast from a Texas Gas Transmission (TGT) leg near Kosciusko, MS — Kosci for short — to an interconnect with the company’s Gulf South system. Others include Kinder Morgan’s 2.1-Bcf/d Mississippi Crossing and 1.3-Bcf/d South System Expansion 4 projects, which will help deliver gas off Kinder’s Tennessee Gas Pipeline (TGP) system, plus a slew of expansions on or near Williams’s Transco system.

And then there’s gas storage. The fluctuating gas needs of Gulf Coast LNG export terminals and power generators have been spurring the buildout of gas storage facilities in the region. More than 150 Bcf of additional storage capacity is planned. (See our Drill Down Report on the topic for more.)

It would be challenging enough to wrap your head around the complicated story tying together soaring gas demand, rising production, gas-price shifts, infrastructure additions, and gas flows. But there are still other variables at play — including political changes within the U.S. and geopolitical uncertainties around the globe — that will each have their own effects on how Gulf Coast gas markets evolve over the next five to 10 years.

To help explain how all these pieces fit together and impact each other, RBN is planning GasCon 2026. This one-day conference at Hilton Americas in Houston, slated for Wednesday, February 25, will bring together RBN’s top analysts and leading executives from across the industry to discuss the latest developments in Gulf Coast gas markets. With these markets entering the most exciting — and challenging — era ever, it’s critically important for gas industry participants to keep up with the latest on the region’s gas demand, gas supply, and the pipelines, storage and LNG export terminals that connect it all. Looking forward to seeing you there! (For more on GasCon 2026, click here.)