Henry Hub Stuck at $2.94 as Warm November Outweighs Europe’s €85 Gas Crisis — $2.90 Floor in Focus

U.S. natural gas futures barely moved on Thursday, November 5, even as the rest of the energy complex swung wildly. The front-month December NYMEX contract traded near $2.94 per million British thermal units after the government’s weekly storage report, down roughly 0.5% on the day. Spot gas traded around $2.95 earlier in the session before slipping ahead of the data. The contract had posted two straight gains coming into Thursday as production estimates held at relatively light levels and LNG demand proved durable.

The contrast with global markets is stark. European gas at the Dutch TTF hub traded near €85 per megawatt hour, roughly $28 per MMBtu, after hitting a four-year high above €101.82 at the end of last week. Asian LNG, measured by the JKM benchmark, traded at $29.35 per MMBtu on Wednesday. U.S. gas is trading at roughly one-tenth of the price that Europe and Asia pay for the same molecule.

The longer view shows how far Henry Hub has fallen from its own highs. Front-month futures are down 5.4% over the past month and 32.4% from a year ago. The 2026 average of daily futures closes stands at $3.08, well below the Energy Information Administration’s forecast of $3.48 for the full year. At $2.94, the front month sits 15.5% below that forecast and 6.9% below the EIA’s $3.16 projection for 2027.

Spot prices are even softer. Henry Hub cash gas traded at $2.63 on November 3, up from $2.54 on November 2 and $2.42 on October 30, after trading at $2.86 on October 28. That leaves the December futures contract at a premium of roughly 30 cents to spot, a contango that reflects expectations of colder weather ahead.

The thesis for this forecast is direct. Henry Hub has decoupled from the global gas crisis. The Iran war knocked out part of Qatar’s LNG industry, throttled tanker traffic through the Strait of Hormuz and pushed European prices up 170% from a year ago. But U.S. LNG export plants are already running near maximum capacity, so higher prices overseas cannot pull more American gas out of the country. U.S. storage sits at 3,801 Bcf, 54 Bcf above the five-year average. Heating demand is near historic lows for early November. Until weather turns cold, Henry Hub is trapped in a $2.80 to $3.20 range, priced by domestic fundamentals, not global panic.

The Storage Report: 77 Bcf Injected, Below the 81 Bcf Estimate

The Energy Information Administration reported a 77 Bcf net injection into Lower 48 natural gas storage for the week ended October 30. The market expected an 81 Bcf build. The prior week saw an 80 Bcf injection. The miss of 4 Bcf was modest, equal to roughly a third of a standard deviation, and came in on the supportive side for prices.

Total working gas in storage reached 3,801 Bcf. That is 109 Bcf, or 2.8%, below the 3,910 Bcf held at the same point a year earlier. But it is 54 Bcf, or 1.4%, above the five-year average for this time of year.

The surplus widened despite the smaller-than-expected injection. A week earlier, storage stood at 3,724 Bcf, just 38 Bcf above the five-year average. The 77 Bcf build was larger than the five-year average injection for the same week, which pushed the surplus up by 16 Bcf. That is the key detail traders focused on. A build that misses estimates but still beats the seasonal norm adds to the cushion.

The recent pattern has shifted. For 10 straight weeks through mid-October, injections came in below the five-year average, steadily narrowing the storage surplus. That streak broke on October 29, when an 80 Bcf injection beat expectations and briefly sent the newly prompt December contract below $2.900. Thursday’s 77 Bcf build continued the new trend of above-average injections, even if it came in slightly below forecasts.

Earlier in the fall, storage was tighter. On October 9, the EIA reported a 67 Bcf injection that undershot consensus and lifted inventories to 3,567 Bcf. On October 16, a 77 Bcf build also missed estimates. A September report showed a 53 Bcf build that extended six weeks of below-normal injections and sparked a 5.8% rally in November futures to $3.377. Since mid-October, mild weather has allowed injections to accelerate.

The refill season started at 1,829 Bcf in March, near the five-year average. The market needed roughly 2,000 Bcf of injections over the April-to-October season to reach a comfortable 3,800 Bcf pre-winter target. At 3,801 Bcf, that target has been met.

For the forecast, the storage picture is neutral to slightly bearish. Inventories are comfortable, the surplus is growing, and another above-average injection is expected next week. That limits upside until heating demand arrives.

The Surplus Math: Above Average, Below Last Year

The storage numbers cut two ways, and that split shapes the price outlook. Against the five-year average, U.S. inventories look comfortable at 54 Bcf above normal. Against last year, they look tight at 109 Bcf below. Which comparison matters more depends on the winter ahead.

The five-year average smooths out extremes. It includes years of heavy storage like 2024, when the market entered winter with the most gas in storage since 2016 and Henry Hub spot prices fell to an inflation-adjusted record low of $1.21 in November. It also includes tighter years. Being 54 Bcf above that average means the U.S. enters winter with a modest buffer.

The year-over-year comparison is less comforting. Storage at 3,801 Bcf is 2.8% below last year’s 3,910 Bcf. Last winter showed what can happen when cold arrives. Henry Hub spot prices spiked after a cold end to November and an even colder start to December, and LNG feedgas volumes averaged close to 19 Bcf per day in early December. The EIA had projected winter 2025-26 Henry Hub prices near $4.30.

The surplus trend matters more than the level. From mid-October onward, the five-year surplus grew from 38 Bcf to 54 Bcf in a single week. If mild weather continues through mid-November, the surplus could widen further, potentially reaching 70 to 90 Bcf by the time the withdrawal season begins. That would weigh on prices.

Regional storage is uneven. National totals mask variations between the East, Midwest, South Central and Pacific regions. Some regional cushions are less comfortable than the national number suggests. A cold snap in a region with thin storage can spike local prices even when national inventories look ample.

The end-of-season target is in sight. The EIA’s pre-winter forecast had pointed to roughly 3,985 Bcf of storage at the peak. At 3,801 Bcf with two or three more weeks of injections likely, the market could approach 3,950 Bcf before withdrawals begin. That would be a healthy starting point for winter.

For the forecast, the surplus is the main reason Henry Hub has not followed global prices higher. Comfortable storage means the U.S. market can absorb a normal winter without stress. Only a colder-than-normal winter would draw storage down fast enough to tighten the market.

Weather: Above-Normal Temperatures and Heating Demand Near Historic Lows

Weather is the dominant driver of Henry Hub prices in November, and it is not cooperating with bulls. The National Oceanic and Atmospheric Administration favors above-normal temperatures across the contiguous United States for November 4 through November 10, though confidence varies by region. Official guidance leans against any type of broad early heating-demand surge.

Heating demand sits near historic lows for this time of year. Mild autumn temperatures have limited early-season gas consumption for space heating. That is the reason storage injections have accelerated since mid-October, breaking the streak of below-average builds.

Moderate fall temperatures cut demand twice. They lower power demand, since less air conditioning is needed than in summer, while also limiting early-season heating. That combination creates conditions for robust storage injections over several weeks. Forecasters expect another above-average build in next week’s report.

The longer-range outlook is warmer than anticipated. Weather models extend only to mid-November with any confidence, and those runs have trended warm. Beyond that, the December demand picture depends on whether colder air arrives. Historically, demand picks up sharply in December as heating season begins in earnest. That is why the December contract trades at a premium to spot.

The bullish weather case is a sudden pattern change. A polar vortex disruption or a strong cold front in late November or early December could flip the market quickly. Last winter, a cold end to November followed by an even colder start to December sent spot prices spiking. Gas markets can move 10% to 20% in a few days when forecasts shift from warm to cold.

The bearish weather case is a prolonged mild pattern. If above-normal temperatures persist through Thanksgiving and into early December, injections will continue past the usual end of the refill season. Storage could exceed 3,950 Bcf, and the December contract could slide toward $2.70 as the cold-weather premium evaporates.

The futures curve already reflects winter expectations. The December contract trades well above spot, and January and February contracts carry even higher premiums. That structure means the market expects cold, and a warm December would force those premiums to collapse.

For the forecast, weather is the single variable that decides whether Henry Hub breaks out of its range. Until the forecasts turn colder, the path of least resistance is sideways to lower.

Production: Near Record Highs, With Uncertain Declines

Supply is the other side of the balance, and it remains heavy. U.S. dry gas production has run near record levels through 2026. Production estimates earlier in the year showed output near 111 Bcf per day, up 4.3% from 2025. The EIA forecasts dry gas production rising to a record 116.1 Bcf per day in 2027, outpacing new LNG demand.

This week brought signs of softer output. Production estimates held at relatively light levels on Wednesday, which helped futures post a second straight gain. A decline in output outweighed pressure from forecasts of persistently warm weather and a slowdown in LNG export activity. But whether those production declines are real or reflect data lags and pipeline maintenance remains uncertain.

Pipeline disruptions add short-term volatility. In October, an outage on the TC Energy Columbia Gas Transmission system idled 1.9 Bcf per day of transport capacity, tightening regional supply. Such outages can lift prices in specific regions without changing the national balance.

Producers respond to price. At $2.94, many gas-focused drillers in the Haynesville and Appalachian basins earn thin margins. Sustained prices below $3 tend to slow drilling activity and production growth over several months. But associated gas from oil wells in the Permian Basin keeps flowing regardless of gas prices, since it is a byproduct of crude production.

The oil crash matters for gas supply. Brent crude fell 19.6% in three sessions to $94.62 on Wednesday before bouncing to $97 on Thursday. Lower oil prices could slow Permian drilling over time, which would reduce associated gas output. That is a slow-moving effect, playing out over quarters rather than weeks.

Record production is the main reason the EIA expects lower prices in 2027. Its forecast for a $3.16 Henry Hub average next year, down from $3.48 in 2026, assumes supply growth outpaces demand growth even as new LNG export capacity comes online.

For the forecast, production is a cap on prices. Even if winter turns cold, record output gives the market the ability to meet higher demand. That makes a sustained move above $3.50 unlikely without a severe, prolonged cold spell.

LNG Exports: Running Near Capacity, Unable to Absorb More

LNG exports are the main link between Henry Hub and the global gas market, and that link is maxed out. U.S. LNG plants are already exporting almost as much as they can. Feedgas deliveries to export terminals have run around 17.6 to 18.5 Bcf per day for much of the year and averaged close to 19 Bcf per day last December. LNG demand proved durable this week, supporting Wednesday’s gains, even as signs of a slowdown in export activity emerged.

That ceiling explains the decoupling. European gas prices have tripled in 2026, and Asian LNG prices have surged. In a normal market, those price signals would pull more U.S. gas overseas and lift Henry Hub. But export capacity is fixed in the short term. Terminals cannot liquefy more gas than their trains are built to handle. So the global price spike stops at the dock.

International demand reaches Henry Hub only through actual export capacity and gas purchases. Even though gas prices have tripled in Europe, that does not automatically tighten domestic U.S. supply. The relevant measure is how much gas actually flows to the terminals, not how high prices are overseas.

LNG feedgas rebounded sharply in late October, supporting the November contract into its expiration. Durable LNG demand this week helped offset bearish weather patterns. But with terminals near capacity, upside from LNG is limited to keeping plants running at full tilt rather than adding new demand.

New capacity is coming. The EIA projected LNG feedgas demand would rise by another 7% on average in 2026 as new export trains come online, and forecasters cite new export capacity as a reason for higher prices in 2027. Each new train adds roughly 0.5 to 1 Bcf per day of demand once it reaches full operation. But those additions arrive gradually.

Maintenance is a downside risk. Earlier this year, maintenance at Freeport LNG removed 2.0 Bcf per day of capacity from July 10 until late August, which weighed on Henry Hub prices during that stretch. Any unplanned outage at a major terminal this winter would leave more gas in the domestic market and push prices lower.

The export economics are extraordinary. With Henry Hub at $2.94 and TTF near $28, the spread exceeds $25 per MMBtu. Even after liquefaction, shipping and regasification costs, U.S. exporters earn enormous margins on every uncommitted cargo. That ensures terminals run flat out, but it cannot pull more gas than the terminals can process.

For the forecast, LNG is a steady source of demand that supports a floor near $2.80 but cannot drive a breakout. The global crisis is visible in export margins, not in Henry Hub prices.

The Global Gas Crisis: TTF Hits a Four-Year High, Then Slides 16%

Outside the U.S., gas markets are in crisis. The Dutch TTF benchmark, which sets prices across continental Europe, topped €100 per MWh at the end of last week for the first time since 2022, peaking above €101.82, a four-year high. TTF is up 170% from a year ago and has risen more than 200% in 2026.

The cause is the Iran war. Missile attacks in March 2026 damaged Qatar’s Ras Laffan LNG complex, the world’s largest LNG export facility. Roughly 15.6 million tonnes per year of capacity, about 4% of global supply, went offline for an estimated three to five years. Two of Qatar’s 14 LNG trains were destroyed and will remain idle for years. The rest of Qatar’s capacity sits behind the Strait of Hormuz, its only export route.

Hormuz has been the bottleneck. LNG tanker transit through the strait fell 80% below normal levels in October. QatarEnergy extended its force majeure on LNG deliveries to European buyers through December 2026. Qatar had supplied about 8% of EU LNG imports in 2025. Qatari and UAE LNG exports were projected to be down 45% year over year in the third quarter.

This week brought relief. TTF fell sharply as traders bet that the Democratic sweep in the U.S. midterm elections could speed an end to the war. On Wednesday morning, the front-month contract traded at €89.59, down 2% by 9 a.m. in Amsterdam, and closed down more than 3.8%. By Thursday morning, TTF traded around €85, down 3.2% on the day and more than 16% below last week’s peak. Qatar said it saw hope for an interim agreement as mediators continued exchanging proposals, and Qatar lifted LNG tanker traffic through Hormuz to a two-month high.

Asian prices are similarly elevated. JKM traded at $29.35 per MMBtu on Wednesday, while TTF was at $28.01 equivalent, down 7.25% that day, and the UK’s NBP at $28.09. JKM and TTF both reached $34 per MMBtu on October 30 as the Middle East situation and an extended outage at Norway’s Oseberg field worried buyers.

The decline does not end the crisis. Iranian strikes on commercial vessels in the Strait of Hormuz continued this week, and the U.S. conducted limited defensive strikes on Iranian targets. Even if the strait reopens, the destroyed Qatari trains will stay offline for years.

For Henry Hub, the global crisis is visible but not transmitted. U.S. gas trades on domestic storage and weather. The global shock shows up in LNG export margins and in the willingness of foreign buyers to sign long-term contracts for future U.S. capacity.

Europe’s Storage Problem: 71% Full, Russian LNG Ban Looming

Europe enters winter with the thinnest storage buffer in 15 years. EU underground gas storage stood at roughly 71% full entering the fourth quarter, with Germany at just 57%. A separate reading put EU storage at 74.6% in October, about 14 percentage points below the roughly 89% five-year average for that time of year. Other data showed storage near 29% of a different capacity measure. However it is measured, Europe is short.

Refilling is painfully expensive. With TTF near $23 to $28 per MMBtu, more than double pre-war levels, refilling storage from spot cargoes costs billions. Increasing gas storage to 75% would cost more than €7 billion at prices from earlier this fall. It is too late for a return of Qatari LNG before winter, leaving Europe with almost no buffer against cold weather.

A regulatory deadline adds pressure. The EU’s ban on Russian LNG takes effect in January 2027. That removes another source of supply just as Europe faces its tightest winter in years. The chairman of Japan’s Jera, the world’s largest LNG buyer, said this month he does not expect Qatari supply back soon and expects spot prices to rise further because of Europe’s low storage and the Russian LNG ban.

U.S. LNG fills the gap. The U.S. is expected to supply two-thirds of Europe’s LNG imports this year. That reliance is why U.S. export terminals run flat out and why foreign buyers are signing long-term contracts for new U.S. capacity.

Asian competition tightens the market further. Europe must bid against Asian buyers for uncommitted LNG cargoes. A bullish Asian outlook requires TTF to stay competitive to attract supply. There are early signs that prices above $20 per MMBtu are beginning to reduce Asian LNG demand, which would narrow the TTF-Asia spread and send more cargoes to Europe.

Fuel switching is a pressure valve. With TTF near €100 per MWh, factories and power plants that can run on either gas or oil have a strong reason to burn gasoil instead. That shift moves some of the gas shock into the diesel market, contributing to the tight distillate supply visible in U.S. inventory data, where distillate stocks hit their lowest since 2003.

For Henry Hub, Europe’s crisis is a long-term bullish factor. It locks in demand for U.S. LNG for years, supports investment in new export capacity and ensures existing terminals run at maximum. But in the short term, it does not change U.S. supply and demand.

The Decoupling: Why Henry Hub Trades at One-Tenth of Global Prices

The spread between U.S. and global gas prices is one of the widest in history. Henry Hub at $2.94 per MMBtu compares with TTF near $28 and JKM near $29. That is a spread of roughly $25 per MMBtu, or a ratio of nearly 10 to 1. In normal markets, the spread runs closer to $5 to $10, reflecting the cost of liquefaction, shipping and regasification.

The mechanism is physical. Natural gas moves across oceans only as LNG, which requires liquefaction plants on the export side and regasification terminals on the import side. The U.S. has a fixed amount of liquefaction capacity. When that capacity is full, no amount of overseas demand can pull more U.S. gas abroad. The excess stays home and gets priced by domestic fundamentals.

That is why the Hormuz shock has barely reached Henry Hub. U.S. storage is slightly above normal, production is near record highs, and LNG plants are already exporting almost as much as they can. Global prices tripled while U.S. prices fell 32% year over year.

The beneficiaries are the exporters. Companies that own liquefaction capacity and sell uncommitted cargoes into the spot market capture the spread. Long-term offtake contracts, often priced at Henry Hub plus a fixed liquefaction fee, mean buyers who locked in U.S. supply years ago are paying a fraction of spot global prices.

The decoupling will narrow over time. New U.S. LNG export trains coming online in 2026 and 2027 add demand. As each train starts, more U.S. gas flows overseas, tightening the domestic balance. The EIA projects rising feedgas demand. Forecasters who expect higher 2027 prices cite this new capacity.

A Middle East resolution would narrow the spread from the other side. If Hormuz reopens and the undamaged Qatari trains resume full exports, global prices would fall sharply. TTF could drop back toward €50 per MWh, about $16 per MMBtu, and JKM similarly. That would compress the spread but would not lower Henry Hub, since U.S. prices are already set by domestic factors.

For the forecast, the decoupling means Henry Hub traders should watch U.S. weather, storage and production rather than European or Asian headlines. The global crisis affects the long-term demand outlook but not this week’s price.

Spot Versus Futures: A 30-Cent Contango Prices in Winter

The structure of the market tells its own story. Henry Hub spot gas traded at $2.63 on November 3. December futures trade near $2.94. That 31-cent premium, or contango, reflects expectations that winter demand will lift prices above current spot levels.

Spot prices have been volatile. Cash gas traded at $2.86 on October 28, fell to $2.68 on October 29 and dropped to $2.42 on October 30 as warm weather limited demand and storage injections accelerated. It rebounded to $2.54 on November 2 and $2.63 on November 3. That $0.44 swing in five trading days shows how sensitive spot prices are to short-term weather and pipeline conditions.

The futures roll shaped recent price action. The November contract expired at the end of October, and the market switched to December as the front month. December carried a higher price because of historical winter demand patterns. Henry Hub futures rose to $3.0 on October 28 when the contract rolled to December delivery, reflecting expectations of higher winter demand and rising feedgas demand for LNG exports. One measure showed the front month jumping to $3.06 on the roll.

That roll premium has eroded. The December contract briefly dipped below $2.900 on October 29 after an 80 Bcf storage injection broke the 10-week streak of below-average builds. It recovered to the mid-$2.90s this week. The roll premium is fading as warm forecasts persist.

The curve beyond December carries steeper premiums. January and February contracts typically trade at the highest prices of the year, since peak heating demand falls in those months. The November-to-March strip traded at $3.391 in mid-October. A warm December would compress those premiums, while a cold December would validate them.

Contango is a cost for long holders. Exchange-traded funds that hold front-month futures, such as the United States Natural Gas Fund (UNG) and the leveraged ProShares funds BOIL and KOLD, must roll contracts monthly. In contango, they sell cheaper expiring contracts and buy more expensive later ones, which erodes returns over time.

For the forecast, the contango shows the market expects winter to lift prices. If spot prices stay near $2.60 into late November, the December contract will converge downward toward spot at expiration on November 25. That convergence would pull December futures toward $2.70 to $2.80 unless weather turns cold.

Macro Links: Oil, the Dollar and the EIA’s Forecasts

Natural gas trades on its own fundamentals, but broader energy and macro forces shape the backdrop. Crude oil crashed 19.6% in three sessions from $117.64 to $94.62 on Wednesday before bouncing 2.69% to $97.17 on Thursday. Henry Hub barely reacted to oil’s crash, confirming that gas and oil are moving on separate drivers.

The oil link runs through associated gas. Permian Basin wells produce large volumes of natural gas as a byproduct of oil. If lower oil prices slow Permian drilling, associated gas output declines over several months. That would tighten U.S. gas supply in 2027. But at $90-plus WTI, Permian drillers remain profitable, so a near-term production slowdown is unlikely.

Distillate and fuel switching create another link. U.S. distillate inventories fell to their lowest since 2003 last week, partly because European industry is switching from gas to oil products. That cross-commodity pressure shows how the global gas crisis spills into other energy markets.

The EIA’s forecasts set expectations. The agency projects Henry Hub averaging $3.48 per MMBtu in 2026 and $3.16 in 2027. Its earlier projections showed Henry Hub at $3.03 over the final five months of 2026 and $2.64 in the second quarter of 2027. The futures curve prices April 2027 at $2.56. Some forecasters raised second-half 2026 Henry Hub forecasts to $3.80 and expect $4.00 in 2027, citing strong LNG feedgas demand and new export trains.

The gap between forecast and reality is large. With 2026 futures averaging $3.08 through November 5 against the EIA’s $3.48 forecast, the market has consistently traded below official projections. For the full-year average to hit $3.48, November and December would need to average well above $4.00, which would require severe cold.

The dollar and rates matter less for gas than for other commodities, since U.S. gas trades primarily on domestic factors. The dollar index at 101.51 and Federal Reserve hike odds near 74.5% have little direct effect on Henry Hub.

Energy equities reflect the split. Gas producers like EQT, Coterra and Expand Energy, formerly Chesapeake, trade on Henry Hub prices and production volumes. LNG exporters like Cheniere trade on liquefaction margins and contract terms, benefiting from the wide spread between U.S. and global prices.

For the forecast, macro factors are background noise. Weather and storage drive Henry Hub. Oil and global LNG matter only at the margin.

The Technical Map: $2.90 Floor, $3.06 Roll High, $3.38 September Peak

The December contract’s chart shows a market stuck in a range. Support starts at $2.900, the level where December briefly traded below after the October 29 storage report. That intraday break marked the low of the post-roll period. A daily close below $2.900 would open a path toward $2.80 and then $2.70, the area where spot prices have traded.

Resistance starts at $3.00, the round number and the level December reached on the roll. Above that, $3.06 marks the high after the contract rolled to December. A daily close above $3.06 would point toward $3.20 and then the $3.30 to $3.38 zone, where the November contract peaked in September after a short squeeze.

The September rally shows what a breakout looks like. November futures surged 5.8% in a single session to $3.336 after a light 53 Bcf storage build, running through four resistance levels as shorts covered. The session high hit $3.377. That move came when the storage surplus was shrinking. The current setup has the surplus growing, which makes a similar squeeze less likely without a weather catalyst.

The broader trend is down. Henry Hub front-month futures are down 32.4% from a year ago and 5.4% over the past month. The 2026 average of $3.08 sits above current prices, meaning gas has spent most of the year higher than it trades now.

Spot price levels add context. Henry Hub cash traded between $2.42 and $2.86 over the past week. December futures at $2.94 sit above that entire range. Convergence at expiration on November 25 would pull December toward spot unless the weather changes.

Volatility is low for the season. Gas typically gets more volatile in November and December as weather forecasts shift. The current range of roughly $2.90 to $3.06 is narrow for a heating-season contract. Low volatility before winter often precedes a sharp move once a weather catalyst arrives.

For traders, the setup is clear. A daily close above $3.06 on a cold forecast shift targets $3.20 to $3.38. A daily close below $2.90 on continued warmth targets $2.70 to $2.80.

Natural Gas Forecast Verdict: Neutral Near Term, Bullish Into December on Weather

Natural gas futures were neutral on Thursday, and the forecast for the next two weeks is neutral with a bullish tilt into December. The front-month December contract at $2.94 is down roughly 0.5% after a 77 Bcf storage injection came in below the 81 Bcf estimate. Henry Hub spot traded at $2.63 earlier this week. Futures are down 5.4% over a month and 32.4% from a year ago.

Domestic fundamentals cap the upside. Storage stands at 3,801 Bcf, 54 Bcf above the five-year average, and the surplus grew by 16 Bcf in a week. NOAA favors above-normal temperatures through November 10, and heating demand sits near historic lows. Production runs near record levels, and the EIA expects output to climb to a record 116.1 Bcf per day in 2027. LNG export plants are running near capacity and cannot absorb more gas.

The global crisis is real but disconnected. TTF topped €101.82 per MWh last week, a four-year high, before sliding 16% to €85 on Iran peace hopes. Qatar’s Ras Laffan damage removed 4% of global LNG supply for years, and Hormuz LNG transit fell 80% in October. Europe enters winter with storage near 71% and faces a Russian LNG ban in January. U.S. gas trades at roughly one-tenth of European and Asian prices because export capacity is maxed.

The upside case rests on weather. Storage is 109 Bcf below last year, and last winter showed how fast prices spike when cold arrives in late November and December. The December contract carries a 30-cent premium to spot that a cold shift would validate.

Base case for the next 10 trading days: range trade between $2.80 and $3.10 as weather forecasts and weekly storage reports set direction. A daily close above $3.06 on a colder outlook targets $3.20, then $3.38. A daily close below $2.90 on persistent warmth targets $2.70 as the contract converges toward spot before the November 25 expiration. Henry Hub is waiting on cold, not on Qatar.

That's TradingNEWS