US Gas Stuck at $2.90 While Europe Pays €73/MWh — a Record 3,985 Bcf Storage Build Is the Wall Before Winter

US natural gas futures held above $2.90 per MMBtu on Tuesday, sitting just under the $2.95 level touched earlier in September — the highest in nearly two months. The prompt contract has posted four consecutive weekly gains on late-summer cooling demand, tightening storage balances and recovering LNG feedgas flows.

At the same moment, Dutch TTF futures jumped more than 2% to above €73 per megawatt-hour, the highest level in more than three and a half years. That benchmark has risen more than 130% since the start of the year.

Convert the two into the same units and the picture becomes absurd. At €73/MWh and a euro near 1.1611, European gas costs roughly $24.80 per MMBtu. Henry Hub sits at $2.90. The spread is approximately $21.90 per MMBtu, and European gas trades at about 8.6 times the American price.

That is the single most important fact in this market, and it has been true in some form all year. The United States has the cheapest natural gas on the planet by a factor of nearly nine, and it cannot get enough of it to the buyers paying twenty-five dollars.

The reason is not molecules. Lower 48 dry gas production has run at a near-record 115.0 billion cubic feet per day. Inventories sat 5.2% above the five-year seasonal average as of August 28 and are forecast to reach a record 3,985 Bcf by the end of October.

The reason is liquefaction. Average feedgas flows to the nine major LNG export facilities climbed to 18.3 Bcf/d in early September from 17.2 Bcf/d in August, as Texas plants returned to full operations after maintenance. That is the ceiling, and it is roughly 16% of domestic production.

Henry Hub is not a global price. It is a stranded price, set by what the domestic market can absorb rather than by what the world will pay, and every forecast for this contract has to start from that constraint.

The rest of the energy complex reflected the same shock differently. Brent crude ran to $99.22, its highest since July 24, after Houthi strikes on Saudi energy infrastructure wounded 73 people.

American gas barely moved.

The $22 Spread and Why It Cannot Close

Arbitrage of this magnitude does not persist in a functioning market. It persists here because the transport mechanism is physically capped.

Moving gas from Louisiana to Rotterdam requires liquefaction, a cryogenic tanker, regasification and pipeline delivery. The binding constraint is liquefaction capacity, and building a new train takes four to six years from final investment decision to first cargo. No price signal, however extreme, changes that timeline.

US LNG exports for the third quarter of 2026 are forecast to average 16.5 Bcf/d, revised down 0.2 Bcf/d from the prior month's estimate. Even with all facilities fully operational, exports remain limited by slow growth in additional export capacity despite US price spreads to Europe and Asia staying elevated.

That sentence is the whole market. The spread is elevated. The capacity is not.

The near-term recovery has been mechanical rather than structural. Maintenance at Freeport LNG began July 10 and completed in late August, affecting 2.0 Bcf/d of nominal export capacity. Its return, plus the Texas facilities coming back, explains the jump from 17.2 to 18.3 Bcf/d. That is restored capacity, not new capacity.

Incremental additions are small and coming from unexpected directions. The Energia Costa Azul terminal on Mexico's Pacific coast shipped its first cargo on July 8, adding 0.4 Bcf/d of nominal export capacity supplied from the US Permian Basin. Pipeline exports to Mexico are forecast to average 9.6 Bcf/d in 2026 and rise to 10.0 Bcf/d in 2027 from 9.5 Bcf/d in 2025, driven partly by that terminal and partly by new Mexican gas-fired power plants.

Total US export capacity across pipeline and LNG therefore runs somewhere near 28 Bcf/d against 115 Bcf/d of production.

For a Henry Hub bull, that ratio is the problem. Domestic price cannot follow international price until the pipe between them widens, and the pipe widens on a construction schedule rather than a trading one.

For a Henry Hub bear, it is the floor. Every incremental train that comes online permanently tightens the domestic balance, and the queue of projects under construction guarantees that the export share of production rises every year.

The EIA publishes the full supply and export outlook at eia.gov.

115 Bcf/d: Record Production Is the Ceiling on Every Rally

Domestic supply is the reason $2.90 has held rather than broken higher.

Lower 48 dry gas production reached a near-record 115.0 Bcf per day, and average output across the region has remained at record highs through the summer. Abundant domestic supply is explicitly limiting the upside for prices even as demand indicators strengthen.

That production level is remarkable in context. Henry Hub has spent most of 2026 in the high $2s — a price that in prior cycles would have triggered rig count declines and voluntary curtailments. Instead output has climbed, because a substantial share of American gas is now associated production from oil wells, and those wells are being drilled on the economics of $92 crude rather than $2.90 gas.

That linkage is the structural bear case for Henry Hub in a high-oil environment. WTI at $92.85 and Brent at $98.61 make Permian oil drilling extremely profitable, and every Permian oil well produces gas that reaches the market regardless of what the gas price is doing. The current oil shock is therefore bearish for domestic gas prices at the margin, which is the opposite of what the headline correlation would suggest.

Elevated forecast US crude production reinforces it. Output is projected to average 13.6 million barrels per day in 2026 and 13.8 million in 2027 — roughly half a million barrels per day above prior estimates. More oil wells mean more associated gas.

The demand side has been strong enough to absorb it without a price collapse but not strong enough to force a breakout. Persistent heat across the continental US has continued to boost air-conditioning demand, supporting power-sector gas consumption through what is normally the shoulder period.

Electricity data confirms the burn. Lower-48 electricity output for the week ended August 22 rose 6.1% year over year to 100,895 gigawatt hours, and output across the trailing 52 weeks rose 2.2% to 4,365,212 GWh.

A 6.1% year-over-year weekly increase in power generation is a meaningful demand signal, and it has been enough to offset record production but not to overcome it.

Storage Heading to a Record 3,985 Bcf at End-October

The inventory picture is the most bearish component of the domestic balance and it is getting worse rather than better.

Gas inventories stood 5.2% above their five-year seasonal average as of August 28. Forecasts put natural gas inventories at a record 3,985 billion cubic feet at the end of October 2026 — an increase of 19 Bcf versus the prior month's projection and 5% above the five-year average.

A record end-of-injection-season inventory is the single strongest argument against a sustained rally. Winter price spikes happen when the market enters the withdrawal season without a cushion. Entering with a record cushion means it takes an extraordinary weather event to produce scarcity pricing.

That expectation is directly embedded in the price forecast. Henry Hub spot is projected to average $2.87 per MMBtu in the third quarter, revised down 50 cents from a prior estimate, with high storage heading into winter cited as the reason.

Current pricing at $2.90 sits almost exactly on that forecast, which means the market and the agency agree on where fair value sits given the fundamentals as they stand.

Monthly estimates put Henry Hub futures around $2.78 to $2.89 for August 2026, again consistent with where the contract has traded.

The weekly storage report is the highest-frequency test of whether the surplus is building or eroding. Injections running below the five-year average would begin narrowing the 5.2% surplus and would be the first genuine bullish development in the domestic balance. Injections above average widen it and cap any rally at $3.00.

Storage data is published at eia.gov, with the release schedule shifted this week by Monday's federal holiday closure.

The counterpoint to the storage bear case is that record inventory measured in Bcf is a smaller cushion measured in days of demand than it was a decade ago, because both domestic power burn and export demand have grown substantially. A 3,985 Bcf peak against 115 Bcf/d of production and rising export capacity is not the same buffer that 3,985 Bcf represented in 2016.

Feedgas at 18.3 Bcf/d and the Liquefaction Bottleneck

Export demand is the swing factor and it has been improving.

Average feedgas flows to the nine major LNG export plants rose to 18.3 Bcf/d in early September from 17.2 Bcf/d in August, as major facilities in Texas returned to full operations following maintenance. That 1.1 Bcf/d increase is roughly 1% of total Lower 48 production redirected from the domestic balance to export.

The timing coincided with stronger demand for US LNG in both Europe and Asia, where buyers are seeking supplies to refill storage ahead of the winter heating season amid continued disruptions to LNG flows from the Persian Gulf.

That is the mechanism through which the Middle East conflict reaches Henry Hub, and it works entirely through the export channel. American gas is not directly affected by Hormuz. American export terminals are affected by the fact that every cargo they can produce now has a bidder paying $24.80.

Maintenance at Freeport and other export terminals had reduced Gulf Coast feedgas demand through June and July, which contributed to the summer price weakness. The return of that capacity is a large part of why the prompt contract has strung together four consecutive weekly gains.

The ceiling remains firm. Even with Freeport fully operational, exports stay limited due to slow growth in additional export capacity, and the third-quarter LNG export forecast was revised down rather than up.

International prices rose in July to levels last reached in early April, as LNG vessel traffic through the Strait of Hormuz slowed considerably after strikes on vessels resumed on July 7.

For the domestic price, every additional Bcf/d of feedgas is directly bullish because it removes supply from the storage calculation. Sustained feedgas above 19 Bcf/d would meaningfully tighten the domestic balance and put $3.20 in play. Feedgas falling back toward 17 Bcf/d on unplanned outages would take the prompt contract back toward $2.70.

Facility outages are therefore the highest-frequency bullish and bearish risk in this market, and they are unforecastable.

Qatar's Force Majeure and the Hormuz Channel

The international supply shock has a specific source, and it is more severe than most US-focused coverage acknowledges.

Qatar has largely suspended LNG shipments and extended force majeure on cargoes bound for European and Asian markets through the autumn, amid continued shipping disruptions through the Strait of Hormuz. The world's largest LNG facility has effectively been removed from the seaborne market.

The strait carried approximately one-fifth of global daily oil and LNG supply before the conflict began in late February. Escalating fighting between the US and Iran has underscored the difficulty of reaching a resolution that reopens it, with Iran warning that energy infrastructure across the region — including US oil and gas facilities — could be vulnerable to further attacks.

Tuesday added another data point. Houthi drones and ballistic missiles struck Saudi Aramco installations and energy infrastructure across southern Saudi Arabia, wounding 73 people and forcing operations at several facilities to halt.

Expectations do not have Hormuz throughput returning to pre-war levels until late in the first quarter or early in the second quarter of 2027.

For the global LNG market, that means Qatari volumes stay out for at least two more quarters, and the shortfall has to be met from Atlantic Basin supply — principally the United States, with contributions from Australia, Nigeria and Algeria.

The demand competition is intense. Japan and Korea are competing directly with European buyers for the same cargoes, which is why the Asian and European benchmarks have converged upward together rather than one drawing cargoes from the other.

US producers are the structural beneficiary of all of this, and it is why the December contract trades well above the prompt. But the benefit flows to export terminal owners and to producers with export linkage far more than it flows into the Henry Hub spot price, which remains set by the domestic balance.

That distinction is the single most common error in analysis of this market.

Europe at 65% Full — the Lowest in Fifteen Years

The European storage position is the reason TTF is at €73 and the reason it may go higher.

European storage facilities were 65% full — the lowest level for that point in the calendar in fifteen years — with added buying competition from Asia as Japan and Korea compete for cargoes. Europe is heading into winter with inventories depleted and little room for another supply shock.

Reduced inflows have slowed the refill, leaving the market increasingly vulnerable as the heating season approaches.

Context matters for calibrating the risk. Europe has cut gas consumption by roughly 15% to 20% compared with 2021, with industry reducing use, renewables expanding and heat pumps replacing some gas-fired heating. Global LNG supply has also increased, and Europe now has more import terminals and can attract cargoes when prices rise.

That makes an outright physical shortage far less likely than during the 2021–2022 crisis. Prices remain well below the €350/MWh peak reached in 2022.

But lower consumption does not remove the vulnerability. A cold winter against 65% storage with Qatar under force majeure is the scenario that takes TTF toward and through €100, and forecasts have been revised toward an average near €60/MWh across the fourth quarter of 2026 and the first quarter of 2027.

The macro consequence is already being priced. Eurozone headline inflation could run closer to 3.5% in the second half of 2026 under current wholesale gas pricing, against a baseline just above 3%. The ECB has already responded to an energy-driven inflation shock and is expected to raise the deposit rate to 2.50% on Thursday.

For US natural gas, European desperation is bullish only to the extent that American terminals can serve it. At 18.3 Bcf/d of feedgas against a hard capacity ceiling, that translation is capped.

The one channel that does transmit fully is producer economics. Cheniere and other export-linked names capture the spread directly, which is why energy equities have outperformed the commodity all year.

Cooling Demand, Power Burn and What the Physical Market Said

Domestic demand has been the surprise of the late summer, and the physical market revealed how tight things briefly got.

Hot weather across the continental US kept cooling demand elevated well past the normal seasonal peak, supporting gas consumption for power generation. Near-record high temperatures were forecast across the southern and eastern US and most of the East Coast from August 31 through September 5, with triple-digit readings driving air-conditioning load.

The physical market responded far more violently than futures. Southeast air-conditioning demand strained natural gas pipelines operating under operational flow orders, and spot prices climbed above $7 per MMBtu before the Labor Day weekend.

That is a genuinely striking number. Physical gas trading at more than double the futures price indicates localised delivery constraints rather than a national supply shortage, but it demonstrates how little slack exists in the pipeline network during peak load.

The reversal was equally sharp. Physical prices for the Labor Day weekend package plummeted on Friday, led lower by a steep reversal in the Eastern Lower 48 and South Louisiana after meteoric gains the previous day, as thunderstorms swept down the Atlantic coast and Southeast cooling demand dropped.

That whipsaw — above $7 one day, collapsing the next — is what a market with adequate supply and inadequate transport looks like. The molecules exist. Getting them to the right node during a load spike does not always work.

For the futures contract, the read is mixed. Physical spikes confirm that demand can overwhelm regional infrastructure, which supports higher volatility. But they also confirm that the constraint is regional and transient rather than national and structural, which is why the front contract stayed under $3.00 through the entire episode.

Power burn will decline seasonally from here as cooling demand fades and before heating demand begins. That shoulder period is typically the weakest stretch of the year for gas prices, and it arrives with storage at a record.

The December Contract Above $4 and What the Curve Is Saying

The forward curve carries more information than the spot price, and it is unambiguously bullish about winter.

The December 2026 futures contract already trades above $4 per MMBtu, against a prompt month at $2.90. That is a contango of more than $1.10, or roughly 38%, across three months.

Henry Hub prices are expected to remain subdued through the remainder of the summer near $2.80 to $3.00 before firming into the fourth quarter as the heating season approaches and LNG feedgas demand peaks.

The magnitude of the winter recovery depends almost entirely on weather. A cold fourth quarter drives prices toward $4 to $5 per MMBtu in the base case. A polar vortex repeat could revisit the $7-plus range seen in January 2026.

Longer-dated pricing extends the structure. Estimates for December 2027 sit near $4.19 per MMBtu, indicating the market expects the tighter balance to persist rather than to be a single-winter phenomenon.

That curve shape has a direct trading consequence for anyone holding leveraged gas products. A contango of 38% across three months means roll costs are severe, and holding a long position through the curve destroys returns even if the spot price is flat. The inverse instruments benefit from the same structure.

The historical range gives context for how far this can go in either direction. Henry Hub hit a 14-year high of $9.85 per MMBtu on August 29, 2022 during the European crisis, and a multi-decade low of $1.63 in June 2020. The 2022 annual average was $6.42, the highest since 2008.

At $2.90, the contract sits in the lower third of its post-2020 range with a curve pricing a substantial winter recovery.

The gap between $2.90 spot and $4-plus December is where the entire trade sits. Either the market is right about winter and the prompt converges upward, or storage at a record proves adequate and the December contract converges down.

Weather decides which.

Weather Remains the Only Variable That Actually Matters

Every other input in this market — production, storage, exports, geopolitics — sets the range. Weather determines where inside it the price lands.

That is a less satisfying conclusion than a fundamental thesis, but it is accurate. The 5.2% storage surplus, the 115 Bcf/d of production and the 18.3 Bcf/d feedgas ceiling together define a market that trades between roughly $2.50 and $3.50 under normal conditions. Only a demand shock large enough to overwhelm a record inventory produces prices outside that band, and only weather can generate one.

The heating degree day picture for October through December is therefore the highest-value forecast in this market, and it is not reliably forecastable at eight weeks.

The base case is straightforward. Normal winter weather against a record 3,985 Bcf of end-October storage produces a comfortable withdrawal season, prices in the $3.20 to $4.00 range through the coldest months, and a spring reset back toward $2.75.

The bull case requires sustained below-normal temperatures across the population-weighted heating regions, plus feedgas holding above 19 Bcf/d, plus at least one unplanned production disruption. That combination pushes prices toward $5 and, in an extreme scenario, back to the $7 handle seen in January 2026.

The bear case requires a mild start to winter. With storage at a record, a warm November alone would collapse the December contract's premium and drag the whole curve lower, potentially toward $2.50 on the prompt.

The asymmetry favours the bulls in magnitude and the bears in probability. Cold weather produces larger moves; mild weather is more likely against a record inventory.

International prices provide a floor mechanism the domestic market did not have five years ago. With TTF at €73 and Asian buyers competing, any US price weakness increases the economic incentive to run export terminals at maximum capacity, which pulls gas out of domestic storage. That linkage puts a soft floor under Henry Hub somewhere in the mid-$2s that did not exist before the export buildout.

Producers and the Equity Expression of the Same Trade

The equity complex captures the international spread far more directly than the commodity does, which is why the two have diverged all year.

Cheniere Energy is the purest expression. Its economics are driven by liquefaction volumes and contracted fees rather than by the Henry Hub price, and a world in which Qatar is under force majeure and TTF trades at €73 is a world in which every train it operates runs at maximum utilisation.

Upstream producers occupy a different position. EQT, Coterra and Chesapeake sell into a domestic market at $2.90 and benefit only indirectly from the international spread, through the demand pull that export terminals exert on the domestic balance. Their leverage is to the winter contract rather than to the prompt.

The energy sector broadly has led every S&P sector in 2026, up 43% through August, and energy equities were bid on Tuesday while the Dow shed 570.78 points. Solaris Energy Infrastructure gained 15.34% and the power generation complex — Bloom Energy up 9.56%, NuScale up 12.63% — ran hard on the same theme.

That rotation reflects a market paying for physical energy capacity rather than for the commodity itself, which is the correct read on where the value accrues when the constraint is infrastructure.

For the leveraged commodity products, the curve structure matters more than the direction. A 38% contango between the prompt and December means long leveraged exposure bleeds on the roll while inverse exposure gains, independent of spot price movement. Anyone using those instruments for a directional winter view is fighting the calendar as well as the market.

The cleanest expression of the actual thesis — that US gas is stranded cheap while global gas is scarce — is export infrastructure rather than either the commodity or the upstream producers.

Total capital committed to US LNG capacity remains the constraint that resolves this over years rather than months.

Levels: $3.00 and $3.20 Above, $2.78 and $2.60 Below

Map the price structure.

Resistance begins at $2.95, the level touched earlier in September and the highest in nearly two months. Above it, $3.00 is the round number that has capped every rally since the summer lows. Beyond that, $3.20 represents the top of the normal-conditions band and the level that requires feedgas above 19 Bcf/d or a storage surplus that starts narrowing. The December contract above $4.00 is the winter reference rather than a prompt-month target.

Support starts at $2.87, the forecast third-quarter average and the level the market has converged on. Then $2.78, the low end of the monthly estimate range. Below that, $2.70 marks the summer consolidation zone, and $2.50 is the level that a mild November against record storage would produce.

The historical floor sits far lower. Henry Hub reached $1.63 in June 2020, though that required a demand collapse rather than an inventory surplus.

Percentage distances from $2.90: $3.00 is 3.4% up, $3.20 is 10.3% up, $4.00 is 37.9% up. Support at $2.78 is 4.1% down and $2.50 is 13.8% down.

The prompt contract has posted four consecutive weekly gains, which is the longest positive streak of the summer and indicates the downtrend from the July highs has at least paused.

For the international benchmark, TTF above €73 is the highest in more than three and a half years, with €80 cited as a near-term target and forecasts revised toward a €60 average for the fourth quarter and first quarter. The 2022 peak at €350 marks the extreme tail.

The relationship worth tracking is the spread rather than either leg. At $21.90 per MMBtu, the arbitrage is wide enough that every incremental unit of US export capacity is economically guaranteed for years. Narrowing of that spread — through Qatari cargoes returning or European storage recovering — is the development that would remove the structural bid under US export infrastructure.

Nothing in the current geopolitical picture suggests that is imminent.

Verdict: Cheapest Gas on Earth, and It Cannot Get Out

Natural gas at $2.90 with the December contract above $4.00 and European TTF at €73 per megawatt-hour describes a market where the price signal is screaming and the infrastructure cannot answer. Converted to common units, European gas costs roughly $24.80 per MMBtu against Henry Hub's $2.90 — a spread near $21.90 and a ratio of about 8.6 to one — while Qatar sits under extended force majeure through the autumn, Hormuz throughput is not expected back at pre-war levels until late in the first quarter or early in the second quarter of 2027, and European storage is 65% full, the lowest for the period in fifteen years. None of that translates into the US price, because feedgas to the nine major export plants runs 18.3 Bcf/d against 115.0 Bcf/d of near-record Lower 48 production, third-quarter LNG exports were revised down to 16.5 Bcf/d, and inventories sit 5.2% above the five-year average on a path to a record 3,985 Bcf at end-October. Henry Hub is a stranded price, and $2.87 is the forecast third-quarter average the market has converged on almost exactly. The four consecutive weekly gains are real and driven by genuine tightening — Freeport's 2.0 Bcf/d back online after August maintenance, electricity output up 6.1% year over year in the week to August 22, physical Southeast spot above $7 on operational flow orders before Labor Day — but each of those is a restoration or a transient, not a structural change. The forecast: hold $2.87 and clear $2.95 and the prompt opens $3.00, then $3.20, requiring feedgas sustained above 19 Bcf/d and injections running below the five-year average to narrow the surplus — roughly 3.4% to 10.3% of upside. A mild start to the heating season against record storage collapses the December premium and takes the prompt toward $2.78, then $2.70, then $2.50, and there is nothing structural beneath that until the mid-$2s where export economics begin pulling molecules out of storage. Weather is the only variable that decides which, and a 38% contango between the prompt and December means anyone expressing a winter view through leveraged products is paying a roll cost that will eat the trade before the weather arrives. Bias is neutral between $2.78 and $3.00, constructive on a close above $2.95, and the real trade here has never been the commodity — it has been the terminals standing between $2.90 gas and $24.80 buyers.

That's TradingNEWS