How Permian Natural Gas Went From Negative Prices to LNG Feedstock

In 2024, gas at the Waha Hub in West Texas sold below zero on 46% of trading days, hitting a low of -$6.41/MMBtu on 29 August. By October 2026, Permian Basin natural gas at the same hub trades around $1.55/MMBtu, according to RBN Energy. What changed?

The Permian is the most productive shale oil region in the world, and its gas was long treated as a nuisance rather than a product. Today that same gas is feeding Gulf Coast liquefied natural gas (LNG) export terminals and, potentially, Texas data centres.

Here is how gas went from liability to feedstock, what is pulling it out of the basin, and where midstream companies fit into the picture for you as an investor.

Why was Permian gas treated as a problem for so long?

A commodity with real value carried a negative price, which sounds absurd until you see the mechanism. Oil drives the drilling, and gas arrives whether anyone wants it or not.

How associated gas works

Associated gas is natural gas that comes out of the ground alongside oil. Producers drill for crude, so gas output follows oil economics rather than gas prices, a point the U.S. Energy Information Administration (EIA) made in June 2026. EIA data also shows Permian gas output has more than doubled since 2018, with marketed production recently running around 25-26 Bcf/d (billion cubic feet per day).

Some producers may even curtail oil output rather than produce gas they cannot sell, though that is reported rather than confirmed. For you, the takeaway is that supply keeps growing whatever the gas price does.

What constraints did to prices and flaring

Pipelines out of the basin did not keep pace. Gas piled up at Waha, and prices collapsed. EIA reported Waha spot prices below zero on 46% of trading days in 2024, including every day from 26 July.

Flaring (burning off gas that cannot be sold) rose with it. East Daley Analytics, via Oilprice.com, estimated flaring near 0.5 Bcf/d by June 2025, roughly the annual emissions of 2.2 million cars. Texas and New Mexico regulate flaring, though current official volumes were not located.

Source figures cover different periods, so treat each number below as its own data point.

A negative price tells you the gas had nowhere to go, not that it lacked value. That is why the pipeline fix matters more than any gas-price forecast, and why maintenance or outages can quickly recreate the problem.

Your reading of negative Waha prices should focus on infrastructure rather than demand: when takeaway pipelines are full or offline, even valuable gas has to be sold at whatever price clears the local market.

How did new pipelines turn stranded gas into marketable supply?

The recovery followed the steel. Long-haul takeaway pipelines carry gas from Waha to Gulf Coast hubs and demand centres, and each new line removed a bottleneck.

Matterhorn Express is the anchor example. It entered service in November 2024 with 2.5 Bcf/d of capacity, runs roughly 510-580 miles, and has ramped to near-full use. Ownership is led by WhiteWater (about 65%), with ONEOK (about 15%), MPLX (10%) and Enbridge (10%).

The EIA said its arrival would let producers move more gas out and could narrow the Waha-Henry Hub gap, or even turn it positive. Henry Hub is the U.S. benchmark gas price.

Waha’s turnaround From a low of -$6.41/MMBtu in August 2024 to around $1.55/MMBtu in October 2026 (RBN Energy).

Eiger Express, a 450-mile line toward the Katy area near Houston, is part of the next wave. Whistler is a related Gulf Coast-linked route, but capacity and ownership details were not found. Pipeline & Gas Journal (September 2026) called this the largest U.S. gas pipeline expansion since 2008, a claim that could not be independently verified.

Pricing improved because capacity grew, so the recovery lasts only as long as the pipes stay full and in service. Value has shifted from the wellhead gas price to the infrastructure that moves the molecules.

What is pulling Permian gas toward LNG terminals and Texas data centres?

One pull is firm and measurable. The other is still a promise.

The route from basin to export terminal runs in four steps:

1. Oil-driven drilling produces associated gas regardless of gas prices.
2. Limited pipelines trap that gas at Waha, causing negative prices and flaring.
3. New long-haul pipelines connect the basin to Gulf Coast hubs.
4. Growing LNG capacity gives that gas a large, predictable buyer.

Because associated gas keeps flowing even when prices are weak, the EIA frames it as low-cost feedstock for new LNG capacity.

The LNG pull

The EIA expects Plaquemines Phases 1-2, Corpus Christi Stage 3 and Golden Pass to add 5.3 Bcf/d of nominal capacity, expanding U.S. export capacity by almost 50%. U.S. LNG exports reportedly rose 23% in the first half of 2026 compared with the first half of 2025, though that figure is unverified.

More is due in 2027: Port Arthur Phase 1 (1.6 Bcf/d), Rio Grande Trains 1-2 (1.4 Bcf/d) and Golden Pass Train 3 (0.7 Bcf/d). This is the demand you can count on today.

U.S. LNG export growth has been strong enough to give Permian associated gas a large and predictable buyer, which is why the EIA treats it as low-cost feedstock for new terminals.

The ERCOT data-centre question

The Electric Reliability Council of Texas (ERCOT) large-load queue stands at about 474 GW of requests, roughly 90% of them data centres. The two sides of the argument are:

• Bullish: AI and cloud build-outs lift Texas power demand, and gas-fired generation is dispatchable and close to Permian supply.
• Sceptical: Many requests are speculative, renewables and storage are growing, and behind-the-meter supply could blunt any Waha uplift.

Named analyst commentary on a Permian premium in ERCOT, and a Bcf/d demand estimate, were not found, so no premium should be treated as established. Data-centre demand is an upside option that depends on projects actually being built.

How can investors play Permian gas growth through midstream, and what are the risks?

The appeal is simple. Midstream companies gather, process and move gas, and they typically earn fees on volume rather than on the gas price itself.

Contracts often run 10-20+ years, though some percent-of-proceeds elements add limited commodity linkage. This section is educational and is not investment advice.

The three midstream names

Targa Resources announced its ExxonMobil agreements in August 2026, and they extend existing acreage dedications. The new plants are Wrangler, Ranger and Ranger II.

What could go wrong

Fee-based does not mean risk-free. Your exposure runs through producer drilling decisions and asset utilisation rather than the gas price itself. The main risks are:

• Overbuild: The pipeline wave could overshoot supply growth, compressing tariffs or leaving assets underused.
• Oil prices: Falling crude cuts associated gas, even with strong LNG demand.
• Producer concentration: Permian gas sits with a relatively small set of large producers.
• Regulation: Tighter Texas and New Mexico flaring rules could change costs and customer behaviour.
• Permitting delays: FERC and DOE approvals could push back in-service dates.
• Demand realisation: ERCOT load growth depends on data centres actually being built.

Waha volatility also remains, since new pipelines ease basis risk but do not eliminate it.

For readers weighing producer exposure alongside midstream, our dedicated guide to evaluating Permian Basin operators explains how to compare breakevens and inventory depth.

What the Permian’s gas shift settles, and what it leaves open

The transformation rests on infrastructure and LNG demand, both largely confirmed. The data-centre premium and midstream returns are less certain.

Five signals show which way this is heading:

• Waha price levels against Henry Hub
• Pipeline utilisation
• LNG start-ups through 2027
• Conversion of ERCOT queue requests into built projects
• Oil-price direction

Each of these will show whether the new demand is arriving as fast as the new capacity.

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. These statements are speculative and subject to change based on market developments and company performance.