Natural Gas Futures Price (NG1!) Down $3 as Shoulder Season Hits — Ras Laffan Shutdown Removes 20% of Global LNG Supply

Natural Gas Futures (NG=F) at $3.00 — Ras Laffan Is Dark, TTF Is Up 80%, and the Shoulder Season Is Doing the Bears' Work

The Most Conflicted Natural Gas Market in Years — 20% of Global LNG Supply Offline While U.S. Prices Stay Soft

Natural Gas Futures (NG=F) are trading down 3.45–3.61% on Monday, sitting near the critical $3.00 per MMBtu level that has functioned as a psychological floor throughout recent weeks. That decline is happening against a backdrop that should, in any rational supply-demand framework, be pushing prices violently higher: Iranian drone strikes shut down Qatar's Ras Laffan LNG complex on March 2, removing approximately 20% of global LNG supply from the market in a single event. QatarEnergy declared force majeure on all exports. In 2025, Qatar shipped 81 million tons of LNG — the overwhelming majority of that going to Asia. The UAE shipped another 5 million tons. Both are now offline or severely disrupted. The Strait of Hormuz, through which roughly one-fifth of global LNG supply transits, has been effectively closed to commercial shipping. European TTF front-month prices have risen nearly 80% since the start of the conflict, approaching €70 per MWh — double the pre-war price. And yet NG=F is sitting at $3.00, drifting lower, with technical resistance capping every rally attempt at $3.25–$3.50. The explanation for this paradox requires understanding the structural disconnect between the U.S. domestic natural gas market and the global LNG pricing system — and why that disconnect may not survive much longer.

Ras Laffan Shutdown — The Chain Reaction That Changed Global LNG Forever This Month

QatarEnergy's complete halt to LNG production following Iranian drone strikes on Ras Laffan Industrial City and Mesaieed Industrial City on March 2 is the most consequential single event in global LNG markets since the Russian pipeline shutoff of 2022. Qatar exported 81 million tons of LNG in 2025. The UAE contributed another 5 million tons. Up to 90% of that combined volume was destined for Asia — Taiwan, Japan, South Korea, India, Bangladesh, Thailand among the primary buyers. The force majeure declaration from QatarEnergy triggered a cascade of downstream force majeures from commodity traders who were sourcing LNG from Qatar and delivering to Asian clients. Qatar's energy minister Saad al-Kaabi confirmed that the return to normal operations at Ras Laffan would take "weeks to months" even if the war ended immediately. Analysts cited by Energy Intelligence put the minimum disruption duration at four to six weeks. This is not a brief supply interruption — it is a structural removal of a major portion of global LNG supply for a minimum of one month and potentially several months, coinciding with a period when Asian importers are trying to build storage ahead of summer cooling demand. The downstream consequences of that supply removal are already visible in the cargo diversion data and the scramble across Asia to secure alternative supply for April and May delivery.

Nine U.S. LNG Cargoes Diverted to Asia — American Gas Is Now Caught Between Two Competing Bids

At least nine U.S. LNG cargoes originally destined for European buyers have been diverted to Asia since the conflict began, according to Bloomberg. The diversion is economically rational: Asian LNG spot prices have moved above European prices in terms of incentive for U.S. exporters, making Asia the more attractive destination until European prices rise enough to compete. European gas prices approaching €70 per MWh are doing exactly that — pulling cargoes back toward Europe — and the Financial Times noted this week that the price differential has begun shifting back in Europe's favor. This cargo competition between Asian and European buyers, with U.S. LNG producers caught in the middle directing volumes to the highest bidder, is creating a dynamic that directly affects the floor under Henry Hub (NG=F) prices. During the week of March 9–13, 36 LNG vessels departed U.S. export terminals carrying approximately 133 billion cubic feet combined — slightly below the prior week but still reflecting robust export activity. As long as international LNG prices remain elevated, U.S. exporters have a powerful incentive to push volumes through terminals at maximum capacity. Every additional export cargo pulls supply out of the domestic market and provides incremental support for NG=F prices that would not exist in a normal non-war environment.

The Storage Number That Explains Everything — 1,848 Bcf, Only 17 Bcf Below the Five-Year Average

The single most important bearish data point for Natural Gas Futures (NG=F) right now is the storage report. U.S. working gas inventories stood at 1,848 Bcf for the week ending March 6, after a withdrawal of only 38 Bcf. That draw was smaller than the typical seasonal withdrawal for this time of year and came in near the low end of market expectations. The consequence: the storage deficit versus the five-year average narrowed dramatically to just 17 Bcf. That near-elimination of the storage deficit means the market is heading into the spring injection season with inventories very close to normal seasonal levels — removing the supply-tightness argument that had been supporting prices through late winter. NGI is estimating the next EIA Weekly Natural Gas Storage Report for the week ended March 13 will show an injection of 42 Bcf. If accurate, that first injection of the 2026 season would add to the Lower 48 year-over-year supply surplus and put downward pressure on summer strip prices, as a surplus injection season typically keeps prices capped through the warmer months. The technical ceiling of $3.25 for NG=F is entirely consistent with a market pricing in a near-normal storage position entering injection season against an export-demand floor that prevents collapse below $3.00.

Shoulder Season Demand Destruction — Total U.S. Demand Fell 10% Week-Over-Week

The seasonal demand picture for NG=F is as bearish as the storage data. Total U.S. natural gas demand dropped approximately 10% week-over-week during the March 9–13 period, with residential and commercial consumption falling a brutal 27% as temperatures warmed across the country. Heating degree days collapsed as winter's grip released, and the transition into the shoulder season — the annual period when temperatures are too warm for significant heating demand but not yet hot enough to drive air conditioning load — is historically the worst time of year for natural gas prices. FXEmpire senior analyst Christopher Lewis, with more than 20 years in commodity markets, put it with appropriate bluntness: this time of year he only shorts natural gas. The $3.50 level is his ceiling for the current environment, and he sees no reason to consider buying the market unless something externally dramatic shifts the calculus. The $3.00 level is where he identifies structural support, with $2.80 as the next floor if that breaks. That technical framework aligns precisely with the fundamental picture: a market that has strong structural reasons to stay capped by seasonal mechanics and storage normalization, with an export demand floor preventing a collapse below $2.80–$3.00.

Henry Hub Spot Price at $2.89–$3.15 — The Range That Has Contained NG=F Since Mid-February

Henry Hub spot prices climbed from approximately $2.89 per MMBtu to roughly $3.15 during the March 9–13 week, but that move was modest and constrained within the $2.89–$3.30 range that has defined trading since mid-February. That range persistence in the face of the Ras Laffan shutdown, the Hormuz blockade, and the 80% surge in European TTF prices is the clearest possible illustration of the structural insulation the U.S. domestic gas market enjoys — and its limits. West Texas cash prices staged a massive rebound on Friday March 13 after deeply negative readings earlier in the week — deeply negative cash prices in West Texas reflect regional oversupply and pipeline constraints, not national market weakness — and that rebound lifted the national average higher while masking softness in other cash markets. Planned maintenance on a critical pipeline serving Sabine Pass LNG terminal is adding near-term complexity, with limited spare pipeline capacity potentially weighing on Henry Hub and storage prices during the maintenance window. El Paso Permian spot prices stood at $4.405, Transwestern at $4.395, and El Paso Plains Pool at $5.735 — all moving in different directions depending on regional pipeline configurations and local supply-demand balances.

Technical Picture for NG=F — $3.25 Resistance Caps, $3.00 Support Holds, Short Bias Is Correct

The technical structure for Natural Gas Futures (NG=F) is definitively bearish in the near term. Resistance at $3.25 has been confirmed multiple times as a ceiling that contains every rally attempt. Support near $3.00 has held but is being tested Monday as futures drop 3.45–3.61%. A confirmed daily close below $3.00 would open the path toward $2.80, where the next meaningful support cluster sits. The Iran war has generated gap-open attempts to the upside in overnight trading — Monday's session included an initial gap higher that was immediately sold — but those gaps are being faded consistently because the domestic supply-demand fundamentals do not support the geopolitical premium that international LNG markets are pricing. The technical pattern is one of a market trying to rally on war headlines and failing, with each failed rally confirming the overhead resistance and reinforcing the bearish case. The only scenario that breaks this technical structure is a sustained disruption to U.S. LNG export infrastructure — either a pipeline constraint that physically prevents exports, or a geopolitical development that closes Gulf of Mexico export facilities — neither of which is currently in play.

TTF at €70/MWh — Europe's 80% Surge vs. U.S. Shoulder Season Softness Is the Global Story

The divergence between European TTF natural gas prices and U.S. Henry Hub (NG=F) prices is the defining feature of the global gas market right now and it has critical implications for where U.S. domestic prices ultimately settle. TTF front-month, tracked by Argus Media, has risen nearly 80% since the start of the Iran conflict. At approximately €70 per MWh as of early this week, European gas prices are double their pre-war levels. In 2022, when Russia shut off most pipeline gas flows, TTF peaked above €320/MWh. The current disruption — with roughly 20% of global LNG supply offline — has not reached those catastrophic levels, but the trajectory is concerning if Ras Laffan remains shut for the full four-to-six-week minimum estimate. Europe's storage position is the critical variable: underground gas stores are at their lowest levels for this time of year since 2022, meaning Europe is entering the injection season needing to aggressively purchase LNG cargoes in a market where the primary alternative supply source — Qatari LNG — is offline. The EU's impulse, as articulated by Commission President Ursula von der Leyen, is to revisit wholesale price caps. Argus Media's Natasha Fielding correctly identifies that impulse as counterproductive: capping wholesale prices would reduce Europe's ability to compete for LNG cargoes on international spot markets, undermining the very storage rebuild that European energy security requires heading into next winter. The 2022 market correction mechanism — which would trigger a cap above €180/MWh with a €35/MWh spread to the LNG reference price — expired in 2025. Any new cap mechanism faces the same structural problem: in 2022, LNG was the corrective alternative to expensive pipeline gas. Now LNG is the source of the problem, making any cap-and-reference-price arithmetic essentially arbitrary.

Taiwan at 30% Qatar Dependency, Bangladesh at Risk, India Unable to Source — The Asian Vulnerability Map

The vulnerability distribution among Asian LNG importers reveals which economies face the most acute near-term supply crisis and which have structural buffers. Taiwan relies on Qatari LNG for approximately 30% of its supply — the highest concentration exposure among major Asian importers and a direct energy security risk given the Ras Laffan shutdown timeline of weeks to months. South Korea's Qatar dependency sits at 15%, and Japan's at just 5% — with Japan importing significantly more LNG from Australia, providing geographic and counterparty diversification that insulates it from the Middle East disruption. Bangladesh faces the most acute vulnerability: as a price-sensitive buyer without significant alternative supply contracts, it risks being priced out of the spot market entirely — a scenario that already played out in 2022–2023 when LNG spot prices spiked above what Bangladesh's import infrastructure could support economically. India's position is troubling: Indian LNG buyers including GAIL have been searching for alternative cargoes with very limited success, with GAIL managing to secure only one cargo for March delivery after multiple unsuccessful attempts. The GAIL situation is particularly significant because India is one of the world's largest LNG importers, and its inability to source spot cargoes at scale reflects the genuine tightness of available supply after Qatar's force majeure declaration removed a massive volume of globally traded LNG. Taiwan, Thailand, South Korea, and Bangladesh are all actively seeking LNG cargoes for April and May delivery. Some have succeeded. Bangladesh and India have not found adequate coverage. That unmet demand is the structural bid under international LNG prices.

The EU Price Cap Debate — Why Arbitrary Caps Would Handicap Europe's LNG Competition

The political impulse to cap wholesale gas prices is understandable but dangerous. Argus Media's analysis of the 2022 precedent is directly applicable to the current situation. When the EU introduced its market correction mechanism in 2023 — designed to trigger at €180/MWh with a €35 spread above the LNG reference price — it was activated after prices had already declined. The mechanism never fired. It expired in 2025. If the Commission introduces a new cap now, it faces a fundamental structural problem that did not exist in 2022: there is no LNG reference price that can function as a corrective mechanism because LNG is the disrupted supply source, not the alternative to disruption. Any flat price cap would be arithmetically arbitrary — the Commission would essentially be picking a number with no credible market-clearing mechanism behind it. The downstream consequences are serious: clearing houses could demand higher collateral from traders, stretching credit lines and reducing market liquidity. Participants could migrate to less regulated, more opaque venues, reducing price transparency and increasing volatility. And the cap itself would send a signal to international LNG sellers that the European market has an artificial ceiling — reducing the incentive to divert U.S. LNG cargoes toward Europe at the moment when Europe most needs to attract them. The paradox is that a price cap designed to protect European households from high gas prices could actually cause gas prices to be higher later by preventing Europe from rebuilding its storage buffer during the current spring and summer injection season.

U.S. LNG Export Infrastructure — 133 Bcf Departed Last Week, Sabine Pass Maintenance Adds Near-Term Complexity

The 36 LNG vessels that departed U.S. export terminals during the March 9–13 week carrying approximately 133 Bcf represent the physical mechanism through which global LNG tightness transmits into NG=F price support. Every Bcf that leaves the U.S. as LNG is a Bcf that does not go into domestic storage — and in a market where the storage deficit has narrowed to just 17 Bcf, the export draw is the primary reason prices have not collapsed below $2.80. Planned maintenance on a critical pipeline serving Sabine Pass LNG is adding near-term complexity to this export flow. Limited spare pipeline capacity during the maintenance window could constrain feed gas deliveries to Sabine Pass, potentially reducing export volumes temporarily and allowing additional gas to flow into storage — a bearish near-term price signal if it materializes. Daily natural gas prices at Henry Hub were trending lower heading into the maintenance period. Whether that maintenance-driven softness represents a temporary disruption or a more sustained price depression depends on how quickly pipeline capacity is restored and whether additional maintenance windows overlap with the Sabine Pass schedule.

EQT, CRK, and EE — The Producers Caught Between Domestic Softness and Export Opportunity

EQT Corporation (EQT), Comstock Resources (CRK), and Excelerate Energy (EE) are the three natural gas-focused names most directly tied to the dynamics described above. EQT is the largest natural gas producer in the United States, with its Appalachian Basin production highly leveraged to Henry Hub prices. At $3.00–$3.15 Henry Hub, EQT's production economics are functional but not exceptional — the company benefits more meaningfully when Henry Hub sustains above $3.50, a level that current technical resistance is preventing. CRK (Comstock Resources) is a Haynesville-focused producer with significant LNG export exposure given the Haynesville's geographic proximity to Gulf Coast export terminals. Its feed gas contribution to terminals like Sabine Pass makes it more directly exposed to the export demand dynamics than a pure Appalachian producer. EE (Excelerate Energy) provides floating storage and regasification unit services — a business that becomes increasingly valuable when LNG supply disruptions drive emergency import demand from markets that lack fixed regasification infrastructure. As Asian buyers scramble for alternative supply and as Bangladesh risks being priced out of the market entirely, floating regasification capacity becomes scarce and strategically critical. All three names should be held rather than aggressively bought at current levels — the domestic price ceiling at $3.25–$3.50 limits near-term upside for producers, while the export demand floor limits the downside.

The Verdict on Natural Gas Futures (NG=F): Bear Bias Until Shoulder Season Passes, But the Global LNG Story Changes Everything If It Reaches Henry Hub

Natural Gas Futures (NG=F) near $3.00 is a short with a tight stop in the current seasonal and technical framework. The $3.25 resistance cap has been confirmed repeatedly. Domestic demand is down 10% week-over-week with the 27% residential and commercial collapse leading the decline. Storage at 1,848 Bcf is only 17 Bcf below the five-year average — the near-normalization of inventories removes the supply-tightness argument that supported winter prices. The first estimated injection of 42 Bcf for the week ending March 13 marks the transition from withdrawal to injection season, which is structurally bearish for prompt prices. The technical ceiling is $3.50, and a break above that level on a closing basis would require a specific external shock — a U.S. LNG export infrastructure disruption, a dramatically cold late-season weather pattern, or a physical pipeline constraint that prevents storage injection — none of which is currently materializing. The medium-term picture beyond the shoulder season is more constructive and potentially dramatically so. If Ras Laffan remains offline for two to three months, European TTF sustains at €70/MWh or higher, and U.S. LNG exporters continue maximizing throughput at 133+ Bcf per week, the cumulative draw on domestic storage through the injection season could be large enough to create a genuine deficit by summer — at which point the bullish re-rating of NG=F from $3.00 toward $4.00–$4.50 becomes viable. That summer scenario is the reason to hold rather than aggressively short below $3.00. The $2.80 support level is the floor of the short trade. Below $2.80, the next support is absent until the $2.50 region. Sell rallies toward $3.25–$3.50 for the next four to six weeks. Reassess when the first summer cooling demand data arrives and when Ras Laffan's restart timeline becomes clearer.

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