Henry Hub Climbs to $3.26 While Europe Pays €86.93 — Record 111.5 Bcf/d Output Caps the Upside Near $3.41

November natural gas futures on NYMEX traded at $3.26 per MMBtu on Tuesday, October 13, 2026, up 9.3 cents or 2.94% on the session. The move reversed a soft European morning, when the contract slipped to $3.099 at 12:31 UTC, down 0.29%, and tested the same support zone that held on Monday. By the U.S. session, buyers had pushed the contract back above $3.20.

Monday set the near-term floor. The November contract printed a four-day low of $3.092 and a lower daily high of $3.204, its fourth straight session holding support near the 200-day moving average, which sits around $3.10. The 50% retracement of the prior advance at $3.105 sits in the same zone. Tuesday’s rebound came off that cluster.

The week before was strong. November natural gas gained 6.1% for the week ended October 9 and settled Friday at $3.22, supported by lower production, hurricane-related supply disruptions and expectations of stronger heating demand. The contract fell to $3.17 last Thursday, halting a run of four straight gains after the weekly storage report showed a larger build than expected.

The monthly and annual picture shows a market in recovery. Henry Hub futures are up 11.65% to 12.57% over the past month and 6.79% to 7.67% from a year ago, depending on the print. The November contract itself is down 21.4% year to date and trades 31.6% below its 52-week high of $4.589, set on December 5, 2025. Its 52-week low of $2.916 came on August 6.

Across the Atlantic, the picture is dramatically different. Dutch TTF gas futures, Europe’s benchmark, rose 3.06% to €86.93 per megawatt-hour on Tuesday, the highest level since December 2022. TTF is up 173% from a year ago and has nearly tripled from around €32 in February. Qatar’s LNG exports remain blocked by the Strait of Hormuz disruption, and European storage sits 16 to 17 percentage points below its seasonal norm.

The thesis for this forecast is direct: U.S. natural gas is insulated from the global gas crisis by record domestic production and storage that sits above its five-year average. The bottleneck is export capacity, not demand. Henry Hub can rally on weather and LNG feedgas, but the 3.5 trillion cubic feet already in storage and output above 111 Bcf per day cap how far it can run. The $3.10 support needs to hold. A break above $3.298 opens $3.396 to $3.41.

Europe at €86.93: TTF Hits Its Highest Level Since December 2022

The global gas market is in crisis, and Europe is at the center of it. Dutch TTF futures climbed by more than 2% on the morning of October 13 and broke above €86 per megawatt-hour, the highest level since December 2022. By the close of the European session, TTF stood at €86.93, up 3.06%. Over the past month, TTF has risen 5.29%. Over the past year, it has risen 173.37%.

The cause is supply. The Strait of Hormuz disruption has cut Qatar, the world’s top LNG producer, out of the market. Roughly one-fifth of global LNG and oil supply normally passes through Hormuz. Tanker attacks near the strait over the weekend, Houthi strikes on Saudi Arabia and Iran’s declared intention to keep Hormuz closed until its demands are met have kept Qatari LNG offline. European buyers are heading into the heating season without one of their largest suppliers.

European storage is the second problem. EU gas storage sat roughly 16 to 17 percentage points below the 90% seasonal norm as of October 7, and about 11% below year-ago levels. Europe has injected gas faster than expected even without Qatari supply, but it is starting the winter from a deficit. At the end of August, EU storage sat near 64% full, the lowest late-August level in more than a decade.

The weather is turning against Europe. Updated forecasts for Northwestern Europe signal below-normal temperatures heading into the second half of October, with colder conditions expected from next weekend. That brings heating demand and power-sector gas burn forward, just as the seasonal stock-building phase ends. As injection efforts wind down, European prices will respond increasingly to winter weather forecasts.

The spread between Europe and the U.S. is enormous. At €86.93 per megawatt-hour, TTF translates to roughly $30 per MMBtu at current exchange rates, against Henry Hub at $3.26. That is a spread of more than $26 per MMBtu. Any U.S. LNG cargo that reaches Europe earns a margin many times its shipping and liquefaction costs.

That spread is why U.S. LNG feedgas has been running near record levels. Every terminal that can operate is running at capacity. The constraint on U.S. gas prices is that export capacity is fixed in the short term. Once terminals are full, additional European demand cannot reach U.S. supply, and Henry Hub stays disconnected from TTF.

For the forecast, Europe is a floor under U.S. prices rather than a ceiling-breaker. As long as TTF stays above €80 and Qatari supply remains blocked, U.S. LNG terminals will run flat out, supporting U.S. demand. But TTF cannot pull Henry Hub much higher until new export capacity comes online.

Storage at 3,500 Bcf: An 85 Bcf Build Was the Largest Since Late June

U.S. storage is the main reason Henry Hub has not followed TTF higher. U.S. energy companies added 85 billion cubic feet of natural gas to storage in the week ended October 2, 2026, the largest weekly injection since late June. The build came after a relatively slow restocking period through the spring and summer. Preliminary estimates had pointed to a 79 Bcf increase, so the actual figure came in 6 Bcf above expectations.

The injection series shows the trend reversing. Storage rose 44 Bcf in the week ended September 11, slightly below the 49 Bcf the market expected. That took working gas in storage to 3,298 Bcf, about 3.6% below year-ago levels but 3.7% above the five-year average. The week ended September 18 added 53 Bcf. The week ended September 25 added 64 Bcf, matching expectations, above the 56 Bcf added in the same week a year earlier but below the five-year seasonal average of 80 Bcf.

Adding the three subsequent weekly builds of 53 Bcf, 64 Bcf and 85 Bcf to the September 11 total brings working gas in storage to roughly 3,500 Bcf as of October 2. That is a comfortable level heading into the heating season. The next report, covering the week ended October 9, is due Thursday at 10:30 a.m. ET.

The trajectory matters for the forecast. Earlier in the injection season, smaller-than-average builds shrank the storage surplus and supported prices. In late August, a 15 Bcf injection was the smallest of the refill season and cut the five-year surplus to 167 Bcf. The late-September and early-October builds have been larger, which rebuilt part of the cushion.

The end-of-season target is high. Storage is projected to reach 3,985 Bcf by the end of October, the highest in 10 years and about 5% above the five-year average. That would put the U.S. into the winter with the largest gas buffer in a decade.

The weather has helped the builds. Mild conditions in early October reduced heating and cooling demand, leaving more gas available for storage. Weak weather demand and signs of production recovery left futures struggling for footing early Tuesday before the afternoon rebound.

For the forecast, storage is the anchor that keeps Henry Hub in the $3 range. With 3,500 Bcf in the ground and a 3,985 Bcf end-October target, a single cold snap or a strong LNG week cannot create a supply shortage. Prices need a sustained cold winter to break meaningfully higher.

Record Production Above 111 Bcf/d Is the Ceiling on Every Rally

U.S. natural gas production is running at record levels, and that is the single biggest cap on prices. Lower 48 dry gas production averaged a record 111.5 Bcf per day in August, up from July’s record of 110.7 Bcf per day. That supply absorbs every bullish signal the market produces, from LNG feedgas records to heat waves to European demand.

Production has kept rising even as prices have struggled. Henry Hub prices remain below the levels needed to make drilling profitable for many producers, according to the Federal Reserve Bank of Kansas City’s third-quarter energy survey, even as overall drilling activity remains strong. Producers are drilling through the price signal because associated gas from oil wells keeps flowing and because long-term LNG contracts justify capacity additions.

The Permian is a major source of the growth. Associated gas from oil drilling in West Texas comes out of the ground regardless of gas prices, because producers are drilling for crude. With WTI crude at $93.68 and Brent at $105.70, oil producers have every incentive to keep drilling, and the gas comes with it. New pipeline capacity has moved more of that gas out of the basin and into a network that feeds Mexico, Gulf Coast LNG terminals and gas-fired power stations across Texas.

Canadian supply adds to the picture. Montney Shale well productivity has surged as drilling technology advances, solidifying its dominance in Canada’s natural gas production. Higher Canadian output reduces U.S. import needs and adds to North American supply.

Hurricane season has created short-term disruptions. Production dipped during recent Gulf storms, and futures struggled early Tuesday as production started to recover from hurricane impacts. Gulf hurricanes also threaten operations at major LNG export terminals, which can increase domestic supply availability by cutting export demand. That combination of production recovery and LNG risk weighed on prices before Tuesday’s afternoon bounce.

The forecast from official energy statisticians reflects the production picture. Henry Hub is projected to average $3.48 per MMBtu in 2026 and $3.16 in 2027, with monthly prices reaching a low of $2.60 in April and May 2027 before ending that year at $3.90 in December. The 2026 average is inflated by January, when Henry Hub averaged $7.72 after winter storm Fern. Excluding January, prices are forecast to average $3.09 from February through December in both 2026 and 2027.

For the forecast, production sets the ceiling. As long as Lower 48 output stays above 111 Bcf per day, Henry Hub will struggle to hold above $3.40 without a major weather event.

LNG Feedgas Near Record Levels as Every Terminal Runs Flat Out

LNG exports are the demand engine that supports Henry Hub. Combined feedgas to U.S. LNG export terminals has run near the highest levels of the year, with deliveries near 19.6 Bcf per day during September’s rally. That compares with 18.3 Bcf per day in early September and 17.2 Bcf per day in August, when maintenance at major terminals reduced flows.

The recovery came as terminals returned from maintenance. Freeport LNG finished a two-month turnaround on August 27 and pushed nominations back toward 2 Bcf per day. Cheniere’s Corpus Christi facility returned to full operations after its own maintenance. Combined feedgas hit 18.5 to 19.2 Bcf per day in late August, the highest since April.

New capacity is adding to the total. The Golden Pass LNG terminal has been ramping up, adding export capacity in the second half of 2026. Earlier in the summer, LNG feedgas demand averaged 19.1 Bcf per day, 3.2 Bcf per day higher than a year earlier. Supply growth has not kept pace with LNG demand growth through the summer.

The global pull is the strongest in years. With Qatari supply blocked by the Hormuz disruption, European and Asian buyers are competing for every available cargo. TTF at €86.93 and East Asian LNG prices well above U.S. levels mean every U.S. terminal earns maximum margins.

The constraint is physical. U.S. LNG export capacity is fixed in the near term. Once all terminals run at capacity, additional global demand cannot pull more U.S. gas overseas. That is why the TTF-Henry Hub spread has widened to more than $26 per MMBtu: arbitrage cannot close it because the export pipe is full.

Weather risk to terminals is the near-term threat. Gulf hurricanes can force LNG terminals to shut temporarily, cutting feedgas demand by several Bcf per day for days at a time. That would leave more gas in the domestic market and push Henry Hub lower even as European prices rise.

Recovery in LNG feedgas after maintenance-related disruptions is one of the sources of demand that could support prices into the winter. Sustained gains depend on weather, production and export activity.

For the forecast, LNG feedgas is the floor under Henry Hub. As long as terminals run near 19 Bcf per day and global prices stay elevated, U.S. gas has a reliable demand source that keeps prices from collapsing. But it cannot by itself drive a breakout.

The Winter Premium: December Trades $0.315 Above November

The futures curve shows the market pricing a colder winter. The November-December spread stood at $0.315 in favor of December, with the December contract near $3.452 and November near $3.137 in recent trading. That positive carry means later months trade above the nearby: the market is paying toward storage and pricing a seasonal winter premium.

The curve shape reflects the transition from injection to withdrawal season. November is the last month of the injection season for most purposes, while December brings the first sustained heating demand. A $0.315 spread compensates storage operators for holding gas from November into December and reflects the probability of cold-weather price spikes.

The 12-month outlook is higher. Natural gas is projected to trade near $3.39 by the end of this quarter and near $4.12 in 12 months, on macro models. The official forecast puts Henry Hub at $3.90 by December 2027. The curve and the forecasts agree that prices should rise into the heart of winter.

Positioning runs against the curve. Funds held a net short position of 133,000 contracts in NYMEX natural gas futures and options combined in the latest positioning data. Speculators are betting on lower prices despite a curve that prices higher winter values. That creates short-covering risk if a cold forecast hits the market.

The short positioning makes sense given the supply picture. Record production, storage on track for a 10-year high and a mild early October all support a bearish view. But a 133,000-contract net short is a large position to unwind if weather turns, and natural gas has a history of violent short squeezes on forecast changes.

Last winter offers a reminder. Henry Hub averaged $7.72 in January 2026 after winter storm Fern drove heating demand to extremes and cut supply. A single severe cold event can move prices far beyond what storage levels suggest, because withdrawal capacity and pipeline constraints limit how fast stored gas can reach consumers.

For the forecast, the curve shape supports a gradual rise from November into December, and the short positioning raises the odds of sharp upside moves on cold forecasts. The December contract near $3.45 is a realistic winter target for the front month if weather cooperates.

Weather Is the Swing Factor: Mild Early October, Colder Late-Month Outlook

Weather drives natural gas more directly than any other commodity, and the outlook is shifting. Early October brought weak weather demand across much of the U.S., which helped storage builds run larger and weighed on futures early Tuesday. Strong demand in the South countered seasonal weakness on both the East and West coasts in the latest weekly period, leaving the average national cash price nearly flat.

The outlook has started to cool. Expectations of cooler weather later in October raised hopes for increased heating consumption, which contributed to last week’s 6.1% gain. Forecasts of colder weather earlier in the month prompted utilities to position for early-season heating demand.

The U.S. heating season begins in earnest in November. Heating degree days rise sharply from late October as temperatures fall across the Midwest and Northeast, which are the largest gas-heating markets. A cold start to November would accelerate storage withdrawals and push prices toward the December contract level.

The official forecast assumes a near-normal winter. Heating degree days this winter are expected to be nearly unchanged from last winter on a national average basis and 1% below the previous five-winter average. Under those conditions, natural gas in storage provides a buffer against price spikes. A colder-than-normal winter would change that math quickly.

Hurricane season adds short-term volatility. Gulf storms can disrupt both production and LNG exports. Production losses are bullish; LNG terminal shutdowns are bearish because they leave more gas in the domestic market. The net effect depends on which disruption is larger. Futures struggled early Tuesday as production recovered from hurricane impacts, which suggests the market was pricing the end of a supply disruption.

Europe’s weather matters for U.S. prices too. Colder conditions in Northwestern Europe from next weekend would push TTF higher, strengthen the pull on U.S. LNG and support feedgas demand. That channel is indirect but meaningful, because it keeps U.S. export terminals running at maximum capacity.

For the forecast, weather is the variable most likely to break Henry Hub out of its range. A colder late-October forecast for the U.S. Midwest and Northeast would trigger short covering and push the November contract through $3.298. A continued mild pattern would leave prices testing $3.10 support.

Thursday’s EIA Storage Report: The Next Catalyst for a Breakout

The weekly storage report on Thursday, October 15, at 10:30 a.m. ET is the next major catalyst. It covers the week ended October 9 and will show whether the larger builds of late September and early October continued or slowed.

The five-year seasonal average injection for this time of year runs in the 70 to 80 Bcf range. A build well below that average would signal that LNG feedgas and early heating demand are absorbing more supply, which would support prices. A build above 85 Bcf, matching or exceeding the prior week, would signal that mild weather and record production are overwhelming demand, which would pressure prices toward $3.10.

The prior report set the tone. The 85 Bcf injection for the week ended October 2, the largest since late June and 6 Bcf above the preliminary estimate of 79 Bcf, halted a four-session rally and pushed futures down to $3.17 last Thursday. The market treated that build as a bearish surprise.

The storage report interacts with the end-of-season target. With storage near 3,500 Bcf as of October 2 and a projected end-of-October level of 3,985 Bcf, the remaining four weekly reports of October would need to add roughly 485 Bcf combined, or about 121 Bcf per week, to hit the target. That pace is well above recent builds, which suggests the end-of-October total could come in below the 3,985 Bcf projection unless injections accelerate sharply. A shortfall against the projection would be modestly bullish.

The report also carries a regional dimension. South Central storage, which includes salt caverns that can inject and withdraw quickly, has run at its highest levels since 2016 in some periods. Regional imbalances can create price dislocations even when national storage looks comfortable.

The weekly storage report has historically moved the contract by several percent on surprises. With the November contract sitting at the edge of a consolidation range between $3.092 and $3.298, a storage surprise in either direction could trigger the breakout.

For the forecast, Thursday is the decision point. A build below 70 Bcf supports a breakout above $3.298 toward $3.41. A build above 90 Bcf sends the contract back to $3.10 and possibly toward the 20-day average near $3.05.

Henry Hub Spot and the Cash Market: $2.90 to $3.03 in Early October

The cash market shows a tighter picture than futures. The Henry Hub spot price stood at $3.03 per MMBtu on October 6, up from $2.96 on October 5 and $2.90 on October 2. It was $3.00 on October 1 and $3.02 on September 30. Spot prices have held near $3.00 through the start of October, in line with the futures curve.

The spot-futures relationship confirms the market’s structure. With spot near $3.00 and November futures at $3.26, the curve slopes upward from the prompt month into winter. That contango pays storage operators to keep injecting gas, which is consistent with the late-season builds.

Regional cash markets have diverged. Strong demand in the South countered seasonal weakness on both coasts. Southern demand reflects late-season cooling in Texas and the Gulf states, plus gas burned for power as electricity demand stays elevated. Coastal weakness reflects mild weather and the transition from summer cooling to winter heating.

The third-quarter price forecast was cut earlier in the season. The Henry Hub spot price was forecast to average $2.87 per MMBtu in the third quarter of 2026, down 50 cents from the prior month’s forecast, driven by reduced LNG feedgas demand during maintenance and robust production. That forecast assumed prices would stay below $3.00 in the following months because of near-record storage levels heading into October.

Prices have outperformed that forecast. Henry Hub spot has held near $3.00 and futures have climbed above $3.20, as LNG feedgas recovered and the global gas crisis pulled more U.S. supply overseas. The market has priced in more export demand than the forecast assumed.

The producer economics remain tight. With spot near $3.00, many producers are operating below profitable levels, according to the Kansas City Fed survey. That creates a medium-term floor: if prices fall too far, dry gas drilling slows and supply growth eases.

For the forecast, the cash market supports the $3.00 to $3.10 zone as a floor. Spot prices near $3.00 with futures at a premium leave room for the curve to converge higher as winter approaches.

Natural Gas Equities: EQT, Coterra, Cheniere and the Producer Squeeze

Natural gas equities reflect the split between U.S. prices and global demand. Producers like EQT, Coterra and Expand Energy face Henry Hub prices that sit below profitable drilling levels for many operators, even as overall drilling activity remains strong. Their earnings depend on Henry Hub, which has risen only modestly.

LNG exporters are in a different position. Cheniere Energy, the largest U.S. LNG exporter, earns fees and margins on liquefaction that benefit directly from the wide spread between Henry Hub and international prices. With TTF at €86.93 and Henry Hub at $3.26, every cargo Cheniere ships captures a margin many times its costs. Exporters with available spot capacity are earning windfall profits.

Pipeline operators benefit from volume. Kinder Morgan and others that move gas from production basins to LNG terminals and power plants earn fees on throughput. Record production and record LNG feedgas both increase volumes.

The energy sector overall has been the market’s best performer in 2026. The Energy Select Sector SPDR, XLE, is up 44.60% year to date through Monday, gaining 1.43% on Monday alone. Most of that performance has come from oil, with WTI near $93.68 and Brent above $105. Gas-weighted producers have lagged oil-weighted producers because of the gap between oil and gas prices.

Leveraged natural gas ETFs track the front month. The United States Natural Gas Fund, UNG, holds near-month futures and suffers from roll costs in contango markets. The ProShares Ultra Bloomberg Natural Gas fund, BOIL, offers two times daily leverage, and ProShares UltraShort Bloomberg Natural Gas, KOLD, offers two times inverse exposure. With the November-December spread at $0.315, the roll into December costs UNG holders.

Natural gas stocks to watch include CNX, EQT and Kinder Morgan as winter approaches, with shifting supply, storage trends and heating demand putting the sector in focus amid hopes for a sustained price recovery.

For the forecast, the equity picture confirms the thesis. Exporters are winning, producers are squeezed and the U.S. price is held down by supply. A cold winter would lift producers; a mild one would leave exporters as the only clear winners.

Technical Map: $3.092 Floor, $3.204 Trigger, $3.298 Ceiling, $3.41 Target

The chart has compressed into a clear consolidation. The November contract has held support near the 200-day moving average for four straight sessions, with Monday’s four-day low at $3.092 and Monday’s lower high at $3.204 defining the near-term range.

The support levels are clustered. The first is $3.10 to $3.105, where the 200-day moving average and the 50% retracement of the prior advance coincide. The second is $3.092, Monday’s four-day low. The third is $3.05, the rising 20-day moving average, which was tested two weeks ago and could serve as dynamic support. The fourth is $3.0437, the S1 pivot from Monday’s session. Below that, $2.817 marks the higher swing low that formed last month, and $2.916 the 52-week low from August 6.

The resistance levels are layered. The first is $3.15 to $3.17, the R1 pivot and last Thursday’s level. The second is $3.204, Monday’s high and the trigger for resumed upside momentum. The third is $3.298, the recent high and the top of the consolidation. Above that, $3.317 marks the September high and $3.370 the 60-session high from September 24. The $3.396 June high and the $3.41 measured-move target form a resistance zone.

The weekly chart supports eventual upside. Last week brought a bullish continuation signal with a weekly close above the prior week’s high of $3.18. That created a higher weekly low and higher weekly high, suggesting the weekly uptrend from the $2.817 swing low remains intact.

The 20-day and 200-day averages are converging. The rising 20-day average near $3.05 is approaching the 200-day near $3.10. A crossover of the shorter average above the longer one would signal improving short-term momentum and could act as a timing indicator for the next leg higher.

The distance math from $3.26 sets the risk-reward. Downside to $3.10 is 16 cents, or 4.9%. Downside to $3.05 is 21 cents, or 6.4%. Upside to $3.298 is 3.8 cents, or 1.2%. Upside to $3.41 is 15 cents, or 4.6%. Upside to $3.452, the December contract level, is 19.2 cents, or 5.9%.

The trigger levels are clear. A daily close above $3.298 confirms the breakout and targets $3.396 to $3.41. A daily close below $3.092 breaks the consolidation and exposes $3.05 and possibly $2.817.

What Could Break the Range: Hormuz, Hurricanes and the First Cold Snap

Several catalysts could push natural gas out of its $3.09 to $3.30 range in the coming weeks.

The first is the Hormuz disruption. If tanker attacks escalate or Iran formalizes its restricted maritime zone beyond the strait, global LNG prices would spike further and U.S. export terminals would stay at maximum utilization. If a diplomatic breakthrough reopened Hormuz and Qatari LNG returned, TTF would fall sharply and the pull on U.S. LNG would ease, removing a key support for Henry Hub. The Saudi-Houthi conflict, U.S. consideration of joining the Saudi campaign and Iran’s fortification of nuclear sites ahead of possible strikes after the November 3 midterms all point toward continued disruption.

The second is hurricane activity. A Gulf storm that shuts LNG terminals would cut feedgas demand and push Henry Hub lower. A storm that cuts offshore or onshore production would push it higher. The timing and track of any late-season storm matter more than its strength.

The third is the first cold snap. A forecast shift toward colder temperatures in the Midwest and Northeast for late October or early November would trigger short covering from funds holding a 133,000-contract net short. That alone could push the November contract through $3.298 toward $3.41 in a few sessions.

The fourth is the storage report. Thursday’s data for the week ended October 9 is the first test. A small build would support the bullish case; a large build would pressure prices.

The fifth is oil. With WTI at $93.68 and Brent at $105.70, associated gas production from oil drilling stays elevated. A drop in oil prices would slow oil drilling over time and reduce associated gas supply, which is bullish for gas in the medium term. A rise in oil prices would keep associated gas flowing.

The sixth is the macro backdrop. Wednesday’s U.S. CPI print and the Fed’s October 28 decision affect the dollar and risk appetite. A stronger dollar makes U.S. LNG more expensive for foreign buyers at the margin, though the TTF-Henry Hub spread is so wide that the effect is minimal.

For the forecast, the catalysts lean bullish in the near term. Weather is turning colder, positioning is short, and the global supply picture is tight. The main bearish risk is a Hormuz resolution, which no party has signaled.

Verdict: Bullish Bias Above $3.10, Breakout Above $3.298 Targets $3.41

Natural gas futures’ verdict for October 13 is range-bound with a bullish bias. November natural gas at $3.26, up 2.94% on the session, has held support near the 200-day moving average for four straight sessions and rebounded from a European-morning dip to $3.099. It sits within a consolidation between Monday’s low of $3.092 and the recent high of $3.298.

The bear case rests on supply. Lower 48 production hit a record 111.5 Bcf per day in August. Storage rose 85 Bcf in the week ended October 2, the largest build since late June and 6 Bcf above expectations, bringing working gas to roughly 3,500 Bcf. Storage is projected to reach 3,985 Bcf by the end of October, the highest in 10 years and 5% above the five-year average. Early October weather has been mild, and production has recovered from hurricane disruptions. The official forecast sees Henry Hub averaging $3.09 from February through December in both 2026 and 2027. Funds hold a 133,000-contract net short.

The bull case rests on global demand and the winter curve. TTF hit €86.93, the highest since December 2022 and up 173% from a year ago, with Qatari LNG blocked by the Hormuz disruption and European storage 16 to 17 points below its seasonal norm. U.S. LNG feedgas has run near 19.6 Bcf per day, with every terminal at capacity. The December contract trades $0.315 above November near $3.45, pricing a winter premium. The weekly chart shows a bullish continuation signal, with a higher swing low at $2.817. Colder weather is forecast for late October.

The levels are clear. Support at $3.10 to $3.105, then $3.092, then $3.05 and $2.817. Resistance at $3.204, then $3.298, then $3.317, $3.370 and the $3.396 to $3.41 zone.

The forecast: November natural gas holds $3.10 through Thursday’s storage report and breaks above $3.204 on a colder late-October forecast, triggering short covering through $3.298 toward the $3.396 to $3.41 zone, a 4.6% gain from current levels. The December contract near $3.45 is the winter target if cold weather arrives on schedule. A storage build above 90 Bcf or a continued mild pattern would send the contract back through $3.092 toward $3.05, a 6.4% decline. Given the short positioning, the global supply crisis and the seasonal curve, the upside path carries the higher probability, though record U.S. production keeps any rally capped well below the levels European prices would imply.

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