August futures traded at $2.957 per MMBtu on Thursday morning, up 3.2 cents or 1.09%, ahead of the NYMEX open and the weekly storage report. Continuous front-month pricing showed $2.94, up 2.57% from the prior session. The contract had fallen to $2.85 on July 21 — a two-month low — before this week’s weather-driven bid.
The one-month performance is negative 7.70%. The twelve-month performance is negative 4.49%. printed $2.83 on July 13.
Now hold that against what is happening everywhere else in the world’s gas market.
, the European benchmark, settled at €61.95 per megawatt-hour on Thursday, down 0.96% on the day but up 50.19% over the past month and 91.44% over twelve months. Converted, that is roughly $20.70 per MMBtu. European buyers are paying approximately seven times the American price for the identical commodity.
Asian spot LNG has been trading near $26 per MMBtu, roughly 143% above pre-war levels, with analysts targeting $30 or higher through the summer and $40 if the Strait of Hormuz remains shut for six months.
That dislocation is the single most extreme relative-price distortion in the global commodity complex right now, and it exists on the same day crossed $100.64 per barrel after Houthi forces struck two Saudi tankers in the Red Sea. Every other energy market on the planet is pricing a supply crisis. American natural gas is pricing a glut, because that is exactly what it has.
The reason is structural rather than sentimental. Lower-48 dry gas production is running at record levels, storage sits above the five-year average, and the only mechanism capable of transmitting global scarcity into domestic prices — liquefaction and export capacity — is running flat out at roughly 17 to 18 billion cubic feet per day and cannot expand on command.
Until that bottleneck clears, Henry Hub trades on Texas weather and weekly injection numbers while the rest of the world fights over cargoes.
The Storage Report Is the Only Thing That Matters Today
The weekly Energy Information Administration natural gas storage report lands at 10:30 a.m. Eastern, and consensus expects a build of 29 billion cubic feet against a five-year average injection of 30 Bcf.
A print that close to the seasonal norm keeps weather in control of the tape and does nothing to resolve the surplus. That has been the defining feature of this entire injection season: above-average builds capping every rally, regardless of how hot the forecast turns or how strong LNG demand runs.
The recent history makes the point. For the week ending June 26, the agency reported an 87 Bcf injection — well above the five-year average — lifting total working gas to 2,922 Bcf. August futures fell 2.49% that week, settling at $3.205 after opening at $3.281, printing a high of $3.328 and a low of $3.151. The contract had pushed toward $3.33 early in the week on heat forecasts and could not hold it once the storage number landed. Storage killed the upside, as it has repeatedly.
The structural position is comfortable and getting more so. At the end of June, US working gas inventories stood 6% above the five-year average. The agency forecasts inventories reaching 3,966 Bcf by the end of October — 5% above the five-year average — which is a well-supplied carry-out into the heating season.
That is the number that governs winter pricing. Periods with higher-than-average inventories are associated with lower prices; as inventories move toward or below the five-year average, forecast Henry Hub prices rise. Storage remains the key indicator of market balance and price formation, and it is currently pointing in the wrong direction for bulls.
The one variable that could change the arithmetic quickly is the export side rather than the demand side. If Gulf Coast liquefaction capacity goes offline for any reason — maintenance, weather, mechanical failure — gas that would have been exported stays in the domestic system and shows up as an outsized injection the following week.
That risk is live this week, and it has a name.
Production at 110.9 Bcf/d Is the Structural Ceiling
The supply side is why every rally in this market has an expiry date.
Lower-48 dry gas output reached 110.9 billion cubic feet per day on Wednesday, up 2.5% from a year earlier. Average production so far in July has run 110.5 Bcf/d against 110.0 Bcf/d in June. The agency raised its 2026 production forecast to 111.2 Bcf/d earlier this month, and record output — led by growth in the Permian region — is explicitly cited as the reason inventories remain high enough to limit upward price pressure.
The remarkable feature is that this production is arriving without a drilling response. The rig count held unchanged at 126 last week, below February’s 2.5-year high of 134. One rig was added in an earlier week and it changed nothing. Producers are adding slowly rather than chasing, and output sits near record levels regardless of what the count does week to week.
That decoupling matters for anyone modelling a supply response. In prior cycles, low prices reduced drilling, drilling declines reduced output with a six-to-nine-month lag, and the market rebalanced. This cycle, associated gas from oil-directed Permian drilling arrives whether or not anyone is targeting natural gas — and with Brent above $100, oil-directed activity has every incentive to accelerate.
That is the perverse mechanism worth understanding. The Middle East conflict is driving crude to triple digits. Triple-digit crude incentivises more Permian oil drilling. More Permian oil drilling produces more associated natural gas. More associated gas depresses Henry Hub. The same war that has European gas up 91% year over year is, at the margin, bearish for American gas.
The takeaway constraints show up in basis. Permian spot prices at the regional hub have been negative on more than half of trading days this year, and flaring events have run at five-year highs — physical evidence that the basin is producing more gas than the pipeline system can move to market.
Supply is not the swing factor here. It is the wall everything else runs into.
LNG Feedgas at 17.9 Bcf/d Is the Only Real Demand Growth
Liquefaction is the single channel through which global scarcity can reach domestic prices, and it is running near capacity.
Net LNG flows to US terminals reached 17.9 Bcf/d on Wednesday, up 7.9% from the prior week. That is gas being physically pulled out of the domestic market and shipped to buyers paying $20 in Europe and $26 in Asia. The month-to-date average has been softer at 17.3 Bcf/d against 17.4 Bcf/d in June, held back by scheduled maintenance at a major Texas export facility that reduced the volume being processed and left more supply available domestically.
That maintenance effect is quantifiable in the tape. Outages at that facility prevented gas from being readied for export, increasing domestic availability, and the front month fell to a two-month low of $2.85 on July 21 as a direct consequence.
The near-term risk is meteorological. Tropical Storm Bertha threatens Gulf Coast export facilities in the coming days. The mechanism is straightforward and asymmetric: any disruption to liquefaction leaves more gas at home, which turns a weather rally into another storage build almost immediately. A storm that shuts export terminals is bearish for Henry Hub even as it is bullish for TTF and Asian spot, because it removes the only demand sink capable of absorbing surplus American production.
The structural picture is more constructive over a longer horizon. Feed gas demand from US liquefaction facilities is the primary driver behind the agency’s expectation that demand growth outpaces supply growth by 1.6 Bcf/d in 2027, after supply outpaces demand by 0.5 Bcf/d this year. That flip is what turns a 2% price decline in 2026 into a projected 33% increase in 2027 under the earlier outlook.
US exporters have been picking up part of the gap left by disrupted Persian Gulf supply, and feedgas flows reflect it. The floor that LNG demand puts under Henry Hub is real and it is not going away.
It simply has not been enough to overcome the storage surplus, and it will not be until capacity expands beyond what the current fleet of trains can physically process.
Qatar’s Force Majeure Is a Three-to-Five-Year Structural Event
The global supply shock has a specific address, and its repair timeline is measured in years rather than months.
QatarEnergy declared force majeure on long-term LNG contracts covering buyers in Italy, Belgium, South Korea and China after Iranian strikes damaged two production trains at Ras Laffan. Roughly 17% of the facility’s export capacity was taken offline, with repairs expected to take three to five years. Ras Laffan handles approximately 20% of global LNG supply.
That single sentence explains the entire European and Asian price structure. Removing 17% of a facility that supplies a fifth of world LNG is not a disruption that gets traded around — it is a permanent change to the global supply curve for the balance of this decade, occurring at precisely the moment demand for gas-fired generation is accelerating.
The force majeure has since been extended, and the practical constraint is compounded by geography. The Strait of Hormuz has been effectively closed since February 28, with transits collapsing to single digits daily at the trough. Even undamaged Qatari capacity cannot reliably reach buyers. Tanker traffic has been at a standstill, delaying the anticipated recovery in Qatari exports and intensifying competition among European and Asian buyers for the cargoes that do move.
Thursday’s escalation made it worse. Houthi forces struck two Saudi tankers in the Red Sea roughly 70 nautical miles southwest of Al Shuqaiq, with one vessel subsequently broadcasting a loss-of-manoeuvrability status. That opens the Bab el-Mandeb strait — which handles 12% to 15% of global maritime trade and had been serving as the workaround for Hormuz — as a second compromised chokepoint.
For American gas, all of this is theoretically bullish and practically irrelevant. Extended force majeure on Qatari deliveries matters enormously for the global market over time. It is not what moves Henry Hub on a storage report day. The immediate trade is domestic: production, injections, weather, and whether Gulf Coast terminals stay online.
That gap between what matters globally and what moves the front month is the defining frustration of trading this contract in 2026.
Europe Is Going Into Winter Short and Everyone Knows It
The European storage trajectory is the slow-burning crisis underneath the TTF price, and it has been deteriorating all year.
EU storage stood at roughly 28% of capacity in late March — a critically low level that raised concerns the bloc would struggle to refill inventories before the next heating season. It recovered to 37.45% by May 23, up 3.2 points from earlier in the month, but the gap to the five-year norm remained around 18 points. By June 23, storage had reached 50 billion cubic metres, equivalent to 46% of capacity.
That trajectory is not sufficient. The chief financial officer of one of Europe’s largest producers warned this week that the region is unlikely to reach its gas storage target ahead of winter, describing the position as very fragile. That is unusually direct language from an operator with every commercial incentive toward optimism.
TTF pricing reflects the arithmetic. At €61.95 per megawatt-hour, the benchmark is up 50.19% over the past month and 91.44% year over year. It rose to €55.6 in late March during a 73% monthly surge that marked the strongest gain since September 2021. It has kept going.
Regulatory flexibility has been introduced to accommodate the shortfall — the storage regulation now carries a flexibility margin allowing member states to miss targets without triggering enforcement. That is an acknowledgement of reality rather than a solution.
The consequence for the global market is that Europe becomes a price-insensitive buyer through the autumn. A continent facing the possibility of physical shortage does not optimise procurement cost; it secures molecules. That is what keeps TTF structurally elevated regardless of what happens on any individual day, and it is why Thursday’s 0.96% decline is noise inside a 50% monthly move.
For US producers and exporters, this is the demand backdrop of a lifetime. For US consumers of the front-month contract, it remains an abstraction, because the pipe between the two markets is full.
Asia Is the Marginal Buyer and It Is Paying Whatever It Takes
The Asian bid is what sets the ceiling on global LNG pricing, and it has been relentless.
Spot cargoes into Asia have been trading near $26 per MMBtu, roughly 143% above pre-war levels. Analysts have been targeting $30 or higher through the summer, with $40 in play if the Strait of Hormuz remains shut for six months. That is a market where buyers are competing on availability rather than price.
The demand-destruction response is already visible and is itself a bearish signal for the medium term. Thailand has ordered coal plants to run at full capacity. Bangladesh has boosted coal consumption. South Korea and Taiwan have been switching fuels away from gas. Those substitutions are rational at $26 and become permanent if the price stays there long enough for capital decisions to follow.
That is the mechanism that eventually caps this market. Gas at $26 in Asia is not a price at which power generation economics work for import-dependent economies. Every month of elevated pricing pushes more baseload demand toward coal, nuclear restarts and renewables — and once that capital is committed, it does not switch back when LNG normalises.
The knock-on effects reach beyond gas. US propane exports have risen as Asian buyers replace lost Persian Gulf supply, and the spread between the American Henry Hub benchmark and European and Asian import prices widened sharply as Hormuz LNG flows were reduced.
For Henry Hub specifically, the Asian bid matters only through the export channel. Every cargo the US can physically load sells instantly at a spectacular margin. The constraint is loading capacity, not demand.
The structural read: global LNG is in a genuine shortage that will persist for years given the Ras Laffan repair timeline. American gas is in a genuine surplus that will persist until liquefaction capacity catches up with production. Both statements are true simultaneously, and the arbitrage between them is the largest in the history of the commodity.
The Arbitrage Is Enormous and the US Cannot Capture It
A seven-to-one price ratio between Henry Hub at $2.94 and TTF at roughly $20.70 per MMBtu should not persist in a market with functioning transport. It persists because the transport does not exist at sufficient scale.
Liquefaction is the bottleneck. US feedgas capacity utilisation is running at 17.3 to 17.9 Bcf/d against production of 110.9 Bcf/d — meaning roughly 16% of American gas production is being exported as LNG while the remaining 84% is trapped in a domestic market that cannot consume it fast enough. Building an additional train takes years and billions of dollars, and the projects currently under construction were sanctioned when the world looked entirely different.
The evidence of trapped supply is unambiguous at the basin level. Permian spot prices have printed negative on more than half of trading days this year, and flaring has run at five-year highs. Producers in West Texas are, on many days, paying to have gas taken away while European utilities pay $20 for the same molecule.
This is why the front-month contract has spent five weeks trading sideways in a range while the global market repriced by 50%. There is no transmission mechanism.
The situation resolves over time rather than through price. The agency’s forecast has supply growth outpacing demand by 0.5 Bcf/d in 2026 before falling behind by 1.6 Bcf/d in 2027, driven mainly by additional feedgas demand as new export facilities come online. That flip is when the arbitrage begins to close from the American side — not because European prices fall, but because US domestic prices rise toward global parity as export capacity absorbs the surplus.
For anyone positioning, the practical implication is that the trade is not long Henry Hub. It is long the entities that own the toll booth between the two markets, or long the 2027 and 2028 sections of the curve rather than the front month.
The front month will keep trading Texas weather and weekly injections until the physical constraint clears.
