Texas Natural Gas Prices Turn Negative as Producers Burn Off Excess Supply

On any given day this year in the Permian Basin, orange flares light up the West Texas sky as producers burn off natural gas they cannot sell — gas that, if it could reach Europe or Asia, would be worth tens of billions of dollars. Spot prices at the Waha Hub, the main trading point for Permian gas, hit -$9.75 per million British thermal units (MMBtu) in mid-March, meaning producers were paying buyers to take gas off their hands [1]. At the same time, European benchmark gas futures surged 60% and Asian LNG spot prices more than doubled to $25.40/MMBtu as the Iran war choked off supplies through the Strait of Hormuz [2].

This is not a new phenomenon — Waha prices went negative 49 times in 2024 and 39 times in 2025 [3] — but the scale and duration of the current episode, combined with a simultaneous global supply crisis, have turned a regional infrastructure problem into an emblem of the energy system's structural contradictions.

How Low Can It Go?

Waha Hub cash prices have closed in negative territory for 38 out of 51 trading days in 2026, a pace that could shatter the 2024 record [3]. On March 10, prices averaged -$7.15/MMBtu — the worst single-day reading on record. The following days brought little relief: -$5.40 on March 11 and -$6.34 on March 12 [3]. Analysts at EBW Analytics Group have warned that prices could reach -$10/MMBtu during spring pipeline maintenance season, when already constrained takeaway capacity shrinks further [1].

For context, the year-to-date average Waha price in 2026 is -$0.37/MMBtu, compared with $1.15 in 2025 and a five-year average of $2.88 [3]. Meanwhile, the Henry Hub benchmark in Louisiana — connected to broader pipeline networks and export terminals — has traded between $2.87 and $3.27/MMBtu through most of March [4]. That spread of $10 or more between two points within the same country captures the severity of the infrastructure bottleneck.

Source: FRED / U.S. Energy Information Administration

Data as of Mar 16, 2026CSV

The Pipeline Problem

The root cause is straightforward: the Permian Basin produces too much gas for the pipelines that serve it. Production across the basin averaged roughly 27.7 billion cubic feet per day (Bcf/d) in 2025, enough to supply over a quarter of U.S. demand, and output has grown at approximately 12% annually over the prior four years [3]. That volume is now pressing hard against the ceiling of existing takeaway capacity.

The Permian's gas surplus is largely "associated gas" — a byproduct of oil drilling. Producers aren't drilling for gas; they're drilling for oil, which at nearly $100 per barrel following the Iran war price spike is enormously profitable [1]. The gas comes out of the ground alongside the oil whether anyone wants it or not. An extensive pipeline network exists to move crude to refineries and export terminals, but gas pipeline infrastructure has not kept pace.

Relief is on the way, but not soon enough. The 2.5 Bcf/d Blackcomb pipeline, jointly developed by WhiteWater Midstream, MPLX, and Enbridge, was originally expected in July 2026 but has slipped to November [5]. Kinder Morgan plans to start a 570 million cubic feet per day (MMcf/d) expansion of the Gulf Coast Express pipeline in mid-2026 [6]. The 1.5 Bcf/d first phase of the Hugh Brinson Pipeline is slated for late 2026 [6]. In total, roughly 4.5 Bcf/d of new pipeline egress is expected between the second half of 2026 and early 2027 [5]. Morningstar DBRS estimates about 18 Bcf/d of new U.S. natural gas pipeline capacity will enter service in 2026, the highest annual total since 2008 [6].

But as East Daley Analytics CEO Justin Carlson has noted, even the Matterhorn Express pipeline, which came online in late 2024, "only gives you so long, maybe 12 to 18 months, and then you need another pipe" [5]. The cycle of production growth outrunning infrastructure is a recurring feature of the Permian, not a one-time event.

Who Pays the Price in Texas

For Permian operators, negative gas prices mean that every MCF of associated gas produced is a direct cost rather than a revenue stream. The math still works for most large producers because oil revenues dwarf gas losses — West Texas Intermediate crude surged 47% to nearly $100/barrel in the three weeks following the start of the Iran conflict [1]. For a typical Permian well producing a 3:1 oil-to-gas ratio, oil at $95/barrel can absorb gas losses of several dollars per MCF and still generate strong returns.

The pain falls disproportionately on smaller independent producers and those with gas-heavy production profiles. Companies without firm pipeline capacity commitments face the worst exposure, as they must sell into the spot market at whatever price — including deeply negative ones — that the market dictates [7]. Some operators have responded by increasing flaring, burning off gas at the wellhead rather than paying to dispose of it. Flaring events in the Permian this season are at five-year highs [1].

No major Permian-focused E&P has announced bankruptcy specifically due to negative gas prices in 2026, but the sustained pressure is squeezing margins for gas-weighted producers. EBW Analytics Group noted that "continued negative pricing in the Permian is expected for much of the spring" and that "as regional production likely ebbs lower, it may dent national-level headline output" [3] — suggesting that some curtailment of production, the market's intended response to price signals, may already be underway.

A World Away: Global Shortages

While Texas burns off gas, the rest of the world is scrambling for molecules. The catalyst is the U.S.-Israel military campaign against Iran that began on February 28, 2026, which triggered Iranian retaliation including the effective closure of the Strait of Hormuz — the waterway through which roughly 20% of the world's oil and LNG flows [2][8].

The most consequential supply hit came when Iranian drone strikes damaged two LNG production trains at Qatar's Ras Laffan Industrial City, the world's largest LNG complex. QatarEnergy declared force majeure, reducing near-term global LNG supply by almost a fifth [2]. Repairs could take up to five years [1].

The price impact has been severe:

• Europe: Dutch TTF futures, the continental benchmark, jumped 35% in a single session to over 60 euros per megawatt-hour ($20/MMBtu), roughly double pre-war levels. European gas prices have increased by a cumulative 60% since the conflict began [2][8]. The Bruegel think tank projects that a three-month disruption would push prices to approximately €85/MWh ($28/MMBtu) [9].

• Asia: LNG spot prices more than doubled to $25.40/MMBtu, with projections of $30-40/MMBtu if the Strait closure persists through summer [1]. Henning Gloystein of the Eurasia Group noted that "Asia is in full price competition, with any country that can switch from gas to coal doing so" [1]. Thailand, Bangladesh, South Korea, and Taiwan are among the most exposed importers.

• U.S. domestic: Even within the United States, the EIA's March Short-Term Energy Outlook projects Henry Hub prices averaging $3.76/MMBtu for 2026, up from $3.53 in 2025, with winter 2026-2027 futures trading above $5/MMBtu [10]. The January 2026 cold snap briefly sent Henry Hub to $30.72/MMBtu on January 23 — a reminder that the U.S. domestic market is not immune to price spikes even amid a Permian glut [4].

Source: BOE Report / Natural Gas Intel

Data as of Mar 12, 2026CSV

The Environmental Toll of Flaring

Flaring — the controlled burning of gas at the wellhead — converts methane into CO2, which is less potent as a greenhouse gas but still a significant emission source. The Environmental Defense Fund estimates that the combined climate and health damages of flaring across three major U.S. basins totaled $5.6 billion in 2023, with the market value of the flared gas itself at only $559 million — a damage-to-value ratio of roughly 10 to 1 [11].

The climate cost of flaring runs between $17 and $24 per thousand cubic feet (Mcf) across major flaring regions, using the EPA's updated Social Cost of Carbon of approximately $248 per metric ton — nearly four times the previous estimate of $66 [11]. CO2 from combustion accounts for 85-95% of climate damages, because well-functioning flares destroy over 95% of the methane. But flares do not always function well: satellite and aerial surveys have repeatedly found that actual emissions exceed operator self-reports by a factor of four or more [12].

Health damages vary dramatically by geography. In the Eagle Ford shale near San Antonio and Austin, health costs reach $31.49/Mcf due to population proximity. In the Permian, the figure is $7.91/Mcf. In the sparsely populated Bakken of North Dakota, it drops to $1.70/Mcf [11].

The irony is stark: if the gas being flared in West Texas could reach European power plants, it would displace coal-fired generation that produces roughly twice the CO2 per unit of electricity. The climate arithmetic strongly favors delivering the gas over burning it at the wellhead — but the pipelines and LNG export capacity to do so do not yet exist at sufficient scale.

The EIA projects U.S. LNG exports will grow 9% in 2026 and 11% in 2027 as three new liquefaction facilities ramp up operations [10]. But that growth timeline, set before the Iran crisis, now collides with a global market desperate for supply today.

Market Signal or Market Failure?

Negative prices are, in economic theory, the market working as designed. When the price of a commodity drops below zero, it signals that supply has outstripped the capacity to transport, store, or consume it. The rational response — reduced drilling, curtailed production, investment in infrastructure — should eventually rebalance the market. And there is evidence that this mechanism is operating: EBW Analytics projects Permian production will "ebb lower" in the near term, and rig counts have shown modest declines [3].

Free-market advocates point out that the pipeline buildout underway is itself a market response. Billions of dollars in private capital are flowing into projects like Blackcomb, Hugh Brinson, and the Gulf Coast Express expansion precisely because the negative basis differential at Waha represents a profit opportunity for midstream companies [6]. No government mandate was required — the price signal was sufficient.

But critics argue the situation reveals multiple market failures. First, the associated gas problem is a classic negative externality: producers drilling for oil impose costs on gas markets and the atmosphere through gas they never intended to produce. The economics of $100 oil overwhelm the signal sent by -$10 gas, meaning the gas market's price mechanism cannot function independently. Second, the infrastructure lag — production growing at 12% annually while pipelines take years to permit and build — represents a coordination failure between upstream and midstream investment [5][7].

The global dimension adds another layer. The fact that gas worth -$10 in West Texas would be worth $25 in Asia represents the largest commodity arbitrage opportunity in the energy markets. That it cannot be captured reflects not just physical infrastructure constraints but also regulatory timelines for LNG export terminal approvals, Jones Act shipping restrictions, and the multi-year construction cycles for liquefaction capacity. These are not features of a smoothly functioning market.

What Created This Mismatch — And Will It Recur?

The current crisis results from the convergence of several factors:

Production surge: Permian oil output has risen steadily as operators deployed more efficient drilling techniques and consolidated acreage through a wave of mergers in 2023-2024. Each new oil well brings associated gas, and the basin's gas-to-oil ratio has been increasing as operators drill deeper formations [7].

Warm winter: The 2025-2026 winter was milder than average across much of the United States, suppressing heating demand and leaving storage inventories 1.7% above the five-year average entering spring [10]. The brief but intense cold snap in late January — which sent Henry Hub to $30.72 — was an exception that proved the rule of otherwise weak domestic demand.

Pipeline timing: The Matterhorn Express pipeline (2.5 Bcf/d), which came online in late 2024, absorbed much of the overhang for about a year. But production growth refilled the capacity gap faster than expected, and subsequent pipeline projects faced construction delays [5].

Geopolitical shock: The Iran war, beginning February 28, 2026, simultaneously made oil more valuable (encouraging more drilling and thus more associated gas) and disrupted global LNG supply (creating shortages the U.S. cannot fully address due to pipeline and export constraints) [2][8].

This combination makes clear that the mismatch is partly structural and partly cyclical. The structural elements — associated gas from oil drilling, multi-year pipeline permitting, and limited LNG export capacity — will persist regardless of the geopolitical situation. The cyclical elements — war-driven oil prices, Hormuz disruptions, and weather patterns — can amplify or dampen the problem but did not cause it. Waha went negative 49 times in 2024 without any war in the Middle East [3].

Are the Shortages Real?

The shortages outside Texas are genuine in the physical sense: the Strait of Hormuz disruption has removed real molecules from the global supply chain, and QatarEnergy's force majeure represents actual production losses that could persist for years [2]. European storage levels, while adequate for the current heating season, face uncertainty about refill rates for next winter. Asian spot LNG buyers are competing intensely for available cargoes.

Within the U.S., the situation is more nuanced. The Henry Hub price of $3.03/MMBtu on March 16 is elevated relative to the $2.82 at the start of the year but not at crisis levels [4]. The EIA projects supply growth of 1.1 Bcf/d in 2026 against demand growth of only 0.6 Bcf/d — a modest surplus at the national level [10]. The January price spike to $30.72 was a localized, weather-driven event, not a systemic shortage.

The deeper question is whether market segmentation — the inability to move gas from where it is cheap to where it is expensive — constitutes a form of artificial scarcity. Producers in West Texas would happily sell gas at $3/MMBtu or even $1/MMBtu rather than flare it, but they cannot reach buyers willing to pay those prices because the pipeline and export infrastructure does not exist. This is not strategic withholding or financial manipulation; it is a physical constraint that produces the economic equivalent of two separate markets operating under radically different conditions.

The Road Ahead

The near-term outlook hinges on two variables: the duration of the Iran conflict and the timing of new pipeline capacity. If Blackcomb enters service on its revised November schedule and the Gulf Coast Express expansion comes online mid-year, the worst of the Waha negativity should ease by late 2026 [5][6]. EBW Analytics projects that the combination of new pipeline capacity and higher oil prices could create "a huge supply tailwind" in the second half of the year [3].

But the longer-term pattern is clear. The Permian Basin will continue producing record volumes of associated gas as long as oil prices support drilling. Pipeline capacity will continue to be built reactively, arriving after the constraint rather than before it. And U.S. LNG export capacity, while growing, will not reach the scale needed to meaningfully connect West Texas supply with global demand until the late 2020s.

The flames burning above the Permian are a visible reminder that energy markets are not a single, frictionless system. They are a patchwork of regional infrastructure, regulatory regimes, and geopolitical accidents — one where gas can be worthless in one place and priceless in another, separated by a few thousand miles of pipeline that does not yet exist.