Henry Hub Breaks $2.90 With Storage Heading to a Record 3,985 Bcf While Europe Sits 65% Full

U.S. natural gas futures trade at $2.8476 per MMBtu, down $0.0684 or 2.35%, against a prior settlement of $2.9160. The contract has fallen below $2.90 and retreated from eight-week highs.

On the same session, European gas trades at €78.36, up 3.33%. UK gas sits at 195.64, up 3.62%. Brent crude cleared $100.566, up 2.70%. Heating oil added 2.80% to $4.6958.

Every energy price on the board is higher except the one traded at Henry Hub in Louisiana.

That divergence is the entire story of this market and it has nothing to do with sentiment. It is a physical supply problem that runs in opposite directions on either side of the Atlantic. The U.S. is producing more gas than it has ever produced. Europe is entering winter with the emptiest storage in fifteen years while its Middle East supply routes burn.

The American numbers explain the weakness precisely. Output across the Lower 48 has risen to 112.9 bcfd so far in September, up from August's monthly high of 112.2 bcfd — a record on top of a record. Gas inventories stood 5.2% above the five-year seasonal average as of August 28.

Demand is not the problem. Forecasts call for above-average temperatures across the U.S. South through September 17, which keeps air-conditioning load elevated and gas burn in the power sector strong. Feedgas flows to the nine major LNG export plants have climbed to 18.1 bcfd in September from 17.2 bcfd in August, as Texas facilities returned to full operations after maintenance. Demand for U.S. LNG from Europe and Asia has risen sharply as buyers replace disrupted Middle Eastern supplies.

Strong domestic demand plus record export demand plus a geopolitical crisis, and Henry Hub is down 5.99% over twelve months.

The thesis running through this piece: American producers have solved the supply side so completely that no combination of weather, exports and war can lift the front of the curve above $3.00, and the winter strip is where the actual trade lives. The Energy Information Administration published its September Short-Term Energy Outlook today with a forecast that says exactly that.

The Split: US Gas -5.99% On The Year, European Gas +134.96%

Put the twelve-month changes side by side and the dislocation is the widest in the energy complex.

Henry Hub is down 5.99% over twelve months and up 1.92% over the past month. European gas is up 134.96% over twelve months and 28.90% over the past month. UK gas is up 141.26% on the year and 30.67% on the month.

That is a 141-point annual performance gap between two grades of the same molecule.

Physical geography is the reason and it cannot be arbitraged away quickly. Natural gas is expensive to move. Getting American gas to Europe requires liquefaction at minus 162 degrees Celsius, specialized tankers, and regasification terminals at the destination. That infrastructure is finite, fully booked, and takes years to expand. Until it does, the two markets can price at multiples of each other indefinitely.

The rest of the complex sits in between. Coal at $147.60 is up 42.13% over twelve months and 14.42% over the month — bid because European and Asian utilities substituting away from gas at these prices have nowhere else to go. Heating oil at $4.6958 has more than doubled at 101.22% over twelve months. Propane is up 17.95% on the month. Naphtha has gained 44.80% on the year.

Every substitutable fuel is being repriced by the same Middle East disruption. Henry Hub is the exception because American supply is domestic, landlocked and abundant.

The comparison to crude sharpens it. West Texas Intermediate at $95.70 is up 50.29% over twelve months. Brent at $100.566 is up 49.00%. Crude and gas are produced from many of the same wells by many of the same companies, and one is up 50% while the other is down 6%.

That relationship — crude at a wide premium to gas — is itself a datapoint about associated gas production. Every barrel of crude pumped at $95 brings gas to the surface regardless of whether the gas price justifies it. High oil prices actively suppress gas prices by flooding the market with byproduct supply that no producer will curtail while the liquids economics work.

That mechanism is why $100 Brent is bearish for Henry Hub rather than bullish.

Record Production At 112.9 Bcfd Is The Ceiling

Output across the Lower 48 states has risen to 112.9 bcfd so far in September, up from August's monthly high of 112.2 bcfd. Production has been at or near record levels for the entire summer.

That number is the ceiling on price and it deserves to be understood mechanically rather than treated as background.

At 112.9 bcfd, the United States is producing roughly 41 trillion cubic feet on an annualized basis. Domestic consumption growth has been forecast at roughly 1.0 bcfd across a two-year window while LNG exports were forecast to grow 4.3 bcfd, or 36%, over the same period. Production is expanding faster than the combined demand growth of both channels.

The supply is coming from the gas-rich basins. Appalachia and Haynesville have been forecast to increase output while Bakken, Eagle Ford and the rest of the Lower 48 decline by a combined 1.3 bcfd. That composition matters: Appalachian and Haynesville gas is dry, low-cost and located near either the Northeast demand center or the Gulf Coast liquefaction complex.

The Permian adds the uncontrollable component. Associated gas produced alongside $95 crude flows regardless of the gas price, because the operator is drilling for oil. At current crude levels, Permian activity is economic at almost any gas price, and every incremental oil rig adds gas supply that responds to nothing happening at Henry Hub.

Pipeline exports provide a partial release valve. Total U.S. natural gas exports by pipeline have been estimated to average 9.6 bcfd in 2026, rising to 10.0 bcfd in 2027 from 9.5 bcfd in 2025. Growth is driven by rising demand from the Energia Costa Azul LNG terminal on Mexico's Pacific Coast, supplied from the Permian Basin, which shipped its first cargo on July 8 and brought 0.4 bcfd of nominal export capacity online. Exports to Mexico have also increased to supply newly commissioned gas-fired power plants.

Those numbers are the honest constraint. Roughly 0.5 bcfd of incremental pipeline export capacity in a market producing 112.9 bcfd is a rounding error against a production base that added 0.7 bcfd in a single month.

The market clears at whatever price forces the marginal producer to stop. That price is nowhere near $2.85.

Storage 5.2% Above Average And Heading To 3,985 Bcf

U.S. gas inventories stood 5.2% above their five-year seasonal average as of August 28. The most recent weekly injection reported was 30 Bcf, following a prior build of 15 Bcf.

Those weekly builds are lean in absolute terms — a 30 Bcf injection is below what a normal September week produces — and the market has repeatedly tried to trade them as bullish. Futures advanced ahead of an expected lean build in early September, and futures dipped anyway when the 30 Bcf print landed alongside significant storage deficits and high temperatures.

That failure to rally on bullish weekly data is the tell. When a market cannot go up on good news, the structural position is heavier than the flow suggests.

The forward projection is where the bearishness becomes explicit. The Energy Information Administration expects natural gas inventories to reach a record 3,985 billion cubic feet at the end of October 2026, sitting 5% above the five-year average. That would be the highest level heading into winter since 2016.

Read that carefully. The United States is on track to enter the 2026-27 heating season with more gas in storage than at any point in a decade, at a moment when Europe enters the same season with the emptiest storage in fifteen years.

The consequence for price is straightforward. A storage cushion of 3,985 Bcf means the market can absorb a cold December without a supply scare, and a supply scare is the only thing that produces the kind of spike gas traders position for. Without it, the winter contango collapses toward the spot price.

The seasonal calendar is also turning against the front month. Injection season runs through October, and September through November is historically when inventories build fastest as cooling demand fades and heating demand has not yet arrived. Above-average temperatures through September 17 delay that transition but do not cancel it.

This week's weekly storage report is the next scheduled reading. The federal closure on Monday, September 7 has already pushed the weekly petroleum status report to Thursday at 12:00 p.m. and 2:00 p.m. Eastern.

Today's STEO And The Sub-$3.00 Assumption

The Energy Information Administration published its September Short-Term Energy Outlook today, and the price outlook reflects reduced LNG feedgas demand and record natural gas production.

The core assumption in the prior edition was blunt: prices will remain below $3.00 per MMBtu in the coming months, driven by robust production and reduced feedgas demand. Henry Hub at $2.8476 is trading inside that forecast.

The inventory projection carries the same message. A record 3,985 Bcf at the end of October 2026, 5% above the five-year average and the highest entering winter since 2016.

The historical context for how far this forecast has moved is worth stating. A year earlier, the agency's outlook had the Henry Hub spot price rising from an average of $2.91/MMBtu to $3.70/MMBtu in the fourth quarter and $4.30/MMBtu the following year, on the reasoning that flat production would meet rising LNG exports. Production did not stay flat. It went to 112.9 bcfd.

That forecast miss is instructive for anyone building a bullish case on export growth. LNG exports have grown exactly as projected — feedgas is at 18.1 bcfd against 17.2 bcfd a month ago — and the price has fallen anyway, because supply grew faster.

The electricity demand assumption has also been revised down. On August 3, the Texas governor announced a pause on new data center development, and the forecast for Texas electricity demand was lowered as a result. Load growth in Texas is now expected at 6% in 2027 against a prior forecast of 14%.

That revision removes a substantial piece of the structural demand story. Data center gas burn was the argument for a permanently higher Henry Hub floor, and the state that hosts the largest concentration of that buildout has paused approvals.

The forward model estimate has Henry Hub at $3.0286 by the end of the current quarter — 6.4% above spot — and $3.83 in twelve months, 34.5% above.

Those two numbers frame the trade precisely. Almost nothing happens this quarter. The move is in the twelve-month strip.

LNG Feedgas At 18.1 Bcfd Is The Only Bullish Input

Average gas flows to the nine major U.S. LNG export plants have climbed to 18.1 bcfd in September, up from 17.2 bcfd in August. An earlier reading in the first days of the month put the figure at 18.3 bcfd. Texas facilities returned to full operations after maintenance.

Nearly a full bcfd of incremental export demand in a single month is a real number, and it is the only genuinely bullish input in the U.S. balance right now.

The demand behind it is external and it is intensifying. Buyers in Europe and Asia have raised purchasing sharply to replace disrupted Middle Eastern supplies and replenish inventories ahead of the winter heating season. Continued disruptions to LNG flows from the Persian Gulf have removed a supply source that European and Asian utilities had counted on.

Japan and Korea are competing directly with European buyers for the same cargoes. That competition sets the marginal price for U.S. LNG on the water, and it is why East Asian and European delivered prices trade at large multiples of Henry Hub.

The arbitrage is enormous and it is capped by physical capacity rather than by economics. With Henry Hub at $2.8476 and European gas at €78.36, every cargo that can be loaded, shipped and regasified is being loaded, shipped and regasified. The nine major plants are running at or near capacity.

That is precisely why the export bid cannot lift Henry Hub. Feedgas demand is constrained by liquefaction trains, not by price. An arbitrage of this width would normally pull the domestic price up until it closed. It cannot, because there is no more capacity to fill.

The number to watch is not the price spread but the feedgas figure itself. Each incremental bcfd of feedgas removes supply from the domestic balance permanently. At 18.1 bcfd against 112.9 bcfd of production, exports absorb 16% of Lower 48 output.

New capacity coming online is the mechanism that eventually tightens the domestic market. Energia Costa Azul added 0.4 bcfd of nominal capacity in July. Additional trains under construction will add more.

Until those trains start, 18.1 bcfd is close to the ceiling.

Europe At 65% Full — The Lowest In Fifteen Years

European storage facilities are 65% full, their lowest level for this point in the calendar in fifteen years.

That figure is the reason European gas is up 134.96% over twelve months and UK gas is up 141.26%, and it is the single most important number in the global gas market right now.

Storage percentages matter because European winter demand cannot be met by pipeline flow alone. The continent draws down inventory through the heating season, and the level it starts from determines whether it reaches spring with a cushion or with a crisis. Entering winter at 65% against a fifteen-year comparison means the margin for a cold winter has largely been spent before the season begins.

The buying competition compounds it. Japan and Korea are scrambling for the same LNG shipments, and Asian buyers have historically been willing to pay above European prices to secure cargoes. A European utility bidding against an Asian one for a limited number of American cargoes produces exactly the price action visible in the €78.36 print.

The supply that would normally fill the gap is the supply that is on fire. Persian Gulf LNG flows have been disrupted, and the disruptions have persisted long enough that buyers have stopped treating them as temporary and started restructuring their procurement.

That restructuring is the durable part. A European utility that loses confidence in Qatari and Emirati cargoes signs long-term contracts with American suppliers instead. Those contracts underwrite the next wave of U.S. liquefaction capacity, which is what eventually tightens Henry Hub.

The timeline is the problem for anyone long the front month. Contract signings happen in months. Liquefaction trains take three to five years. The European crisis is happening now and the American benefit arrives at the end of the decade.

For the winter, the European situation creates a genuine tail risk that flows back to Henry Hub. If a cold European winter empties storage completely, buyers will bid U.S. cargoes at any price, and the arbitrage would become wide enough that even fully utilized export terminals would run above nameplate.

That is the scenario the December contract above $4 is partially pricing.

The Hormuz Problem Europe Cannot Solve

Escalating U.S.-Iran hostilities have raised fresh concerns over prolonged disruptions to energy shipments through the Strait of Hormuz, and the gas market is exposed to that waterway more than most participants appreciate.

The events of the past twenty-four hours: the U.S. military destroyed five Iranian oil tankers near Kharg Island. Iran claimed attacks on two American vessels and eight oil tankers in the Gulf, warned shipping crews near Kuwaiti and Bahraini ports to abandon their vessels, and launched ballistic missiles toward Jordan. Iran-backed Houthi militants attacked Saudi energy facilities including the 400,000-barrel-a-day Jazan refinery.

For crude, Hormuz is a transit chokepoint with partial alternatives — Saudi Arabia has rerouted volumes through the East-West pipeline to Yanbu on the Red Sea, lifting Bab el-Mandeb throughput to 8.1 million barrels a day in the second quarter from 5.4 million a day in the fourth quarter of 2025.

For LNG, there is no equivalent workaround. Qatari LNG has one route to global markets and it runs through the Strait. There is no pipeline alternative, no rerouting option and no substitute loading port. A vessel that cannot transit Hormuz is a cargo that does not exist.

That structural asymmetry is why European gas is up 28.90% in a month while Brent is up 14.63%. The gas market has less optionality.

The flare-up adds to already simmering concerns about global LNG supply and could add demand for American exports — and affect pricing — should the war drag into the winter months.

The phrase "should the war drag into winter" is the entire uncertainty. A conflict that resolves in October leaves Europe with a difficult but manageable heating season. A conflict that persists through January with Qatari cargoes unavailable produces a European gas price that has no analytical ceiling.

Henry Hub captures a fraction of that upside because export capacity is fixed. The producers who sell into that capacity capture more of it, and the equity leverage in the tag list below reflects that distinction.

The physical market has already shown what a domestic disruption looks like. Gulf Coast physical prices surged past $7 on a single day before surrendering roughly two-thirds of that move when Tropical Storm Edouard came ashore near the Texas-Louisiana border.

Weather: Heat Through September 17 And A Turning Calendar

Forecasts call for above-average temperatures across the U.S. South through September 17, which keeps air-conditioning demand elevated and supports gas consumption in the power sector. September has been described as potentially becoming the hottest on record.

That is real demand and it is why the contract reached eight-week highs before this week's fade.

The problem is that it is a two-week story arriving at the wrong end of the calendar. Cooling demand peaks in July and August and declines through September regardless of temperature anomalies. Heating demand does not begin in earnest until November. The intervening window is when storage builds fastest and when prices are structurally weakest.

Traders have been positioning around exactly this. Futures advanced on increasingly bullish September heat forecasts and tested the $3 mark. They then dipped despite high temperatures and significant storage deficits when the 30 Bcf injection landed. Steamy forecasts failed to rally the market.

That is the pattern of a market where weather is not the binding constraint. When production runs at 112.9 bcfd and storage sits 5.2% above the five-year average, a heat wave changes the weekly injection by a handful of Bcf and changes nothing about the seasonal balance.

The hurricane channel is the one weather input that can genuinely move Henry Hub, and it cuts both ways. A storm that shuts in Gulf of Mexico production is bullish. A storm that knocks out an LNG export terminal or a Gulf Coast power load center is bearish, because it removes more demand than supply. Tropical Storm Edouard demonstrated the second: physical prices fell back across the Gulf Coast and Southeast, surrendering two-thirds of a surge past $7.

Hurricane season runs through November and the Gulf Coast now hosts both the majority of U.S. liquefaction capacity and a substantial share of production. Concentration of infrastructure in one weather-exposed region is the structural volatility source in this market.

The transitioning autumn weather calendar is one of the three factors cited for the current pressure, alongside near-record production and declining power demand.

Technicals: $2.90 Broke, $2.483 Is The Floor

The chart has broken a level this week and the structure below it is thin.

Henry Hub has fallen below $2.90, retreating from eight-week highs. The prior settlement at $2.9160 is now resistance, and the market reached above $2.95 in early September — the highest in nearly two months — before failing.

The 52-week range runs from a low of $2.483 to a high of $7.827. At $2.8476 the contract sits 14.7% above its annual low and 63.6% below its annual high. That distribution tells you where this market has spent its time: near the bottom of a range whose upper reaches were set by a single winter event.

Immediate resistance is $2.90, then $2.95, then the $3.00 psychological line. $3.00 has been the level the market has repeatedly tested and failed. The channel's lower support has been identified near $3 as a key technical floor tested repeatedly at the beginning of 2026 — and price is now beneath it.

Below spot, the first reference is $2.80. Then $2.75, and the $2.50 area. The 52-week low at $2.483 is 12.8% beneath current price.

A break and sustained close below $3 opens the path toward $2/MMBtu — a level viewed as unsustainable given LNG export dynamics, but possible in a severe warm-winter scenario. At $2/MMBtu, production curtailments and rig count reductions would emerge within weeks, tightening the market faster than seasonal trends suggest.

That self-correcting mechanism is the genuine floor. It is not a technical level — it is the point at which Appalachian and Haynesville operators shut in dry gas wells because the netback stops covering the cost of moving the molecule. Producers have demonstrated repeatedly that they will curtail rather than sell below cash cost.

The all-time high for the contract is $15.78, set in December 2005.

Momentum has turned lower on the daily chart after the failed run at $3.00, and the market is anchored to the bearish end of its range — one where robust LNG export demand and Middle East supply disruptions provide a floor while domestic overproduction and a transitioning weather calendar cap the ceiling.

That framing is accurate and it defines the range: $2.483 to $3.00.

The Winter Curve: December Above $4 And The Polar Vortex Tail

The front month is not the trade. The winter strip is.

The December 2026 futures contract has been trading above $4/MMBtu, reflecting market expectations of a winter recovery. Against a spot price of $2.8476, that is a contango of more than 40% across roughly three months.

That structure tells you the market fully expects the seasonal transition to lift prices and has already paid for it. Anyone buying the front month expecting a winter rally is buying the wrong instrument — the rally is priced into December, and holding a front-month position through roll dates surrenders the carry.

The channel framing puts the mid-range around $4/MMBtu as the most likely destination heading into the 2026-27 winter. The upper boundary near $5/MMBtu is reachable only under a significantly colder-than-normal winter. The lower support near $3 has functioned as a technical floor and has now been breached to the downside.

The tail scenario is the one worth sizing. A polar vortex repeat could revisit the $7-plus range seen in January 2026. That is 146% above spot, and it is the reason nobody sells this market naked despite the bearish fundamentals.

The counterweight to the tail is the storage projection. Entering winter with a record 3,985 Bcf — the highest since 2016 and 5% above the five-year average — means a cold snap draws down a large cushion rather than threatening a shortage. The 2026 January spike happened against a tighter starting inventory.

Henry Hub prices have been expected to remain subdued through summer at roughly $2.80 to $3.00 before firming into the fourth quarter as the heating season approaches and LNG feedgas demand peaks. Spot at $2.8476 sits at the bottom of that band.

The twelve-month model estimate at $3.83 sits between the $4 December contract and current spot, which is a forecast that the winter premium partially deflates.

For a trader, the honest read is that the risk-reward on the front month is poor in both directions — $2.483 below and $3.00 above — while the December-to-March strip carries the actual optionality on a European supply crisis meeting an American export constraint.

Trading The Complex: UNG, BOIL, KOLD And Producer Leverage

The instruments matter as much as the direction in a market with 40% contango.

The exchange-traded products that track natural gas hold futures contracts and must roll them forward as they expire. In a contango market — where December trades above $4 while spot sits at $2.8476 — every roll sells a cheaper expiring contract and buys a more expensive deferred one. That decay is structural and it compounds.

A holder of a long gas ETP who is correct that prices rise from $2.8476 to $3.50 by December can still lose money, because the fund paid the contango on every roll along the way. The leveraged versions amplify both the directional move and the roll cost.

The inverse products carry the opposite dynamic. In steep contango, a short gas position earns the roll yield, which means the bearish instrument can profit even if spot goes nowhere. That asymmetry currently favors the short side of the ETP complex regardless of the fundamental view — a fact that has nothing to do with whether gas is cheap.

The producers offer cleaner exposure to the structural story and messier exposure to the price. Appalachian and Haynesville-focused operators sell dry gas into a market at $2.8476, which is at or near their marginal economics. Their leverage is enormous on the way up and their balance sheets are the constraint on the way down.

The Gulf Coast liquefaction owner captures a different economic. Its revenue comes from liquefaction fees on volumes contracted long in advance, not from the commodity price. That business earns more when export capacity runs full — which it currently does at 18.1 bcfd — and is largely indifferent to whether Henry Hub trades at $2.50 or $3.50. In a market where the arbitrage between $2.8476 domestic gas and €78.36 European gas is capped by physical capacity, owning the capacity is where the spread accrues.

That is the cleanest expression of the current setup. Domestic price suppressed by record production. International price exploding on supply disruption. The bottleneck between them is liquefaction, and the bottleneck earns the difference.

The diversified producers with Permian associated gas carry the least attractive profile: they add supply that suppresses the price of a product they sell.

Natural Gas Price Forecast: Levels, Scenarios, Probabilities

The executable map for the front month.

Upside, in order: $2.90 as the prior settlement and immediate resistance, 1.8% above spot. $2.95 as the early-September high. $3.00 as the psychological line and the broken channel support, 5.4% above. Then $3.0286 as the quarter-end model estimate. Above that, $3.50, and the twelve-month estimate at $3.83 representing 34.5% upside. The December contract above $4 sits on a different curve point.

Downside, in order: $2.80 as the first shelf, 1.7% below. $2.75 as the next reference. $2.50 as the round number. $2.483 as the 52-week low, 12.8% below. Beneath that, $2.00 is the level at which production curtailments and rig reductions emerge within weeks.

Base case at 52% probability: Henry Hub holds $2.60 to $3.00 through the end of injection season. Record production at 112.9 bcfd and storage tracking toward 3,985 Bcf cap every rally, while LNG feedgas at 18.1 bcfd and residual heat through September 17 prevent a collapse. Target range $2.75 to $2.95, consistent with the sub-$3.00 assumption in the current outlook.

Bull case at 28% probability: the Hormuz disruption extends into the heating season, European storage fails to recover from 65%, Asian buyers outbid Europe for U.S. cargoes, and an early cold snap accelerates the seasonal transition. Feedgas pushes toward 19 bcfd as new capacity commissions. Henry Hub clears $3.00 and works toward $3.50, with the December contract validating above $4. Upside 23% to $3.50.

Bear case at 20% probability: production extends beyond 113 bcfd, the October storage figure prints at or above the projected 3,985 Bcf, temperatures normalize after September 17, and a warm start to winter delays heating demand. Henry Hub loses $2.80 and tests $2.50, with the $2.483 52-week low in play. Downside 12.8%.

The distribution skews bearish on the front month and bullish on the winter strip. That is not a contradiction — it is what a 40% contango is telling you.

The variable that resolves both is European weather in December, and nobody has that forecast in September.

Verdict: Capped Front, Live Winter, And The Curve Knows It

Henry Hub at $2.8476, down 2.35%, is the weakest energy price on a board where Brent gained 2.70%, European gas rose 3.33%, UK gas added 3.62% and heating oil climbed 2.80%.

The bearish case is documented and mechanical. Lower 48 production has risen to 112.9 bcfd from August's record 112.2 bcfd. Storage sits 5.2% above the five-year seasonal average and is projected to reach a record 3,985 Bcf at the end of October — the highest entering winter since 2016 and 5% above the five-year norm. The official price assumption is that Henry Hub stays below $3.00 in the coming months. The Texas data center pause cut expected 2027 state load growth from 14% to 6%, removing a piece of the structural demand argument. Associated gas from $95 crude flows regardless of the gas price. The market failed to rally on a lean 30 Bcf injection and failed at $3.00 twice. And the calendar turns from cooling to injection season regardless of what the South does through September 17.

The bullish case is real and it lives on a different part of the curve. LNG feedgas at 18.1 bcfd is up nearly a full bcfd from August with Texas facilities back at full rates. European storage at 65% is the emptiest in fifteen years entering a heating season with Persian Gulf LNG disrupted and no rerouting option, because Qatari cargoes have exactly one path to market. Japan and Korea are bidding against Europe for the same American molecules. European gas is up 134.96% and UK gas 141.26% over twelve months. The December contract trades above $4 against $2.8476 spot. And a polar vortex repeat revisits the $7-plus range seen in January 2026.

The verdict is a capped front month and a live winter. American producers have solved supply so completely that no combination of heat, exports and war lifts the prompt above $3.00, while the physical constraint between the cheapest gas on earth and the most expensive is liquefaction capacity that cannot expand this decade.

Hold $2.80 and the range survives. Lose $2.483 and the curtailment mechanism becomes the only floor. Clear $3.00 and the winter premium starts pulling the front month with it.

That's TradingNEWS