Henry Hub Climbs to $3.26 as Storage Build Falls 23 Bcf Short of Normal — Break of $3.283 Opens $3.50

Natural gas futures turned higher on Thursday after a bullish storage report. November Henry Hub futures traded at $3.26 per million British thermal units, up 1.96% on the session, after slipping below $3.20 earlier in the week. The contract is now within 2.3 cents of its near-three-week high of $3.283, reached on October 13.

The week has been a whipsaw. Futures pushed to $3.283 on Monday, then moved sharply lower at midweek as recovering production and sluggish weather-driven demand in the forecast weighed on prices. Wednesday’s slide took the contract below $3.20 before Thursday’s rebound recovered most of the loss.

Futures climbed early Thursday as traders braced for bullish government storage data reflecting strong LNG demand, while a key pipeline outage raised the prospect of smaller inventory builds ahead. The storage print delivered, and futures held their gains after the 10:30 a.m. ET release.

The spot market has firmed alongside futures. Henry Hub spot prices stood at $3.00 on October 1, $2.90 on October 2, $2.96 on October 5 and $3.03 on October 6, with the most recent posted spot at $3.18. From the October 2 low of $2.90 to the latest $3.18, spot gas has risen 9.7%.

The monthly and annual picture is constructive. Natural gas futures are up 12.72% over the past month and 10.92% over the past year. As of October 9, the contract showed a 30-day return of 12.70%.

The 52-week range frames the current level. Henry Hub futures have traded between $2.54 and $5.62 over the past year. At $3.26, the contract sits 28% above the 52-week low and 42% below the 52-week high. That leaves plenty of room in both directions as the market moves from the end of injection season into winter.

The structural trend has been higher lows. The NYMEX chart shows consistent higher lows since April 2026. Each pullback since spring has bottomed above the prior one, a pattern that typically precedes a breakout when demand rises seasonally.

The forecast question is whether storage tightness can overpower mild weather. The data shows the storage surplus shrinking fast, driven by LNG exports, while forecasts call for mild temperatures through late October. The balance between those two forces will decide whether futures break above $3.283 or slip back toward $3.05.

EIA Storage: 67 Bcf Injection Falls Short of Every Benchmark

Thursday’s storage data was the catalyst. The EIA weekly storage report showed an injection of 67 billion cubic feet for the week ended October 9, falling short of expectations and historical norms. Lower 48 working gas inventories rose to 3,567 Bcf.

The miss was clear against every benchmark. Pre-report estimates called for a 74 Bcf build. Last year’s injection for the same week was 80 Bcf. The five-year average for the week stands at 90 Bcf. Thursday’s 67 Bcf came in 7 Bcf below the estimate, 13 Bcf below last year and 23 Bcf below the five-year average.

The Midwest led all regions. Regional injections showed the heaviest builds in the Midwest, while other regions added less. A light South Central build typically reflects strong demand from LNG export terminals on the Gulf Coast, which pull gas directly from that region’s storage and pipeline network.

The prior week was heavier. For the week ended October 2, the EIA reported an 85 Bcf injection, lifting inventories to 3,500 Bcf. That print fell short of historical norms but exceeded market expectations, and futures slipped after the release. Thursday’s lighter print reversed that bearish signal.

The trend over several weeks shows variable but generally below-average builds. Inventories rose 64 Bcf in the week ended September 25 to 3,415 Bcf, matching expectations but trailing the five-year average of 80 Bcf. The week ended September 11 posted a 44 Bcf injection, well below the five-year average of 74 Bcf. The week ended September 4 showed a 40 Bcf build.

Smaller-than-average builds compound over time. Every week that injections trail the five-year average, the storage surplus shrinks. Over the past six weeks, injections have repeatedly fallen short of the seasonal norm, steadily eroding the cushion that entered the fall well above average.

The market reaction confirmed the significance. Futures sustained their rally after the bullish storage print. A build that misses the five-year average by 23 Bcf, in the final weeks of injection season, sends a clear signal that demand is absorbing more supply than usual.

The next report arrives next Thursday. Another below-average build would likely push futures through $3.283 and toward $3.35.

The Shrinking Surplus: From 4.8% to 1.3% Above Average

The storage surplus tells the clearest story in the gas market. After Thursday’s report, inventories sit 1.3% above the five-year average. At 3,567 Bcf, that implies a five-year average of 3,521 Bcf for the week and a surplus of 46 Bcf.

The surplus has collapsed over six weeks. In the week ended September 4, inventories stood 4.8% above the five-year average. By September 25, the surplus had narrowed to 2.4%. On October 2, it stood at 68 Bcf above the five-year average of 3,432 Bcf, or 2.0%. Thursday’s 1.3% reading marks the smallest surplus of the season.

That trajectory matters more than the level. A 1.3% surplus is still a surplus, but the direction of travel has been firmly lower for six straight weeks. If the trend continues at the same pace, inventories would fall below the five-year average before the end of October, entering winter with a deficit rather than a cushion.

The year-over-year gap is wider. Inventories stood 130 Bcf below year-ago levels as of October 2. With Thursday’s 67 Bcf build against last year’s 80 Bcf for the same week, the gap widened to 143 Bcf, or 3.9% below year-ago levels.

The spring context shows how far the surplus has fallen. In mid-June, inventories sat at 2,759 Bcf, 151 Bcf, or 5.8%, above the five-year average. Since then, the surplus has shrunk from 151 Bcf to 46 Bcf, a drop of more than two-thirds.

The injection season started at average levels. The 2026 injection season began with working gas at 1,829 Bcf, near the five-year average. Since then, inventories have nearly doubled, but the rate of injection has slowed as summer cooling demand and LNG exports pulled more gas out of the system.

The math for the end of October is tight. To reach 3,850 Bcf by the end of October, inventories need to add 283 Bcf over the three remaining weeks, an average of 94 Bcf a week. Recent builds of 67 Bcf and 85 Bcf have fallen short of that pace. If the next three builds match Thursday’s 67 Bcf, end-October inventories would land near 3,768 Bcf, 82 Bcf below the forecast.

That shortfall is the core of the bull case. A market entering winter with less gas in storage than forecast is exposed to any cold snap.

EIA Outlook: 3,850 Bcf by Halloween and a Winter Buffer at Risk

The official forecast sets the benchmark the market is testing. The EIA’s October Short-Term Energy Outlook estimated US inventories at 3,523 Bcf at the end of September. The forecast called for inventories to build by 328 Bcf during October, slightly less than average, reaching 3,850 Bcf at the end of October. That would put inventories 2% above the five-year average entering the heating season on November 1.

The forecast is running ahead of reality. The EIA’s 2% end-October surplus assumes injections that the market hasn’t delivered. Thursday’s data puts the surplus at 1.3%, already below the forecast’s end-of-season target, with three weeks of injections left.

The injection season may run longer. While the end of October is typically considered the close of injection season, inventories can often build through mid-November depending on market and weather conditions. Mild weather through late October and into November would allow additional injections, which could help close the gap with the EIA’s forecast.

The winter assumption is neutral. The forecast assumes heating degree days this winter will be nearly unchanged from last winter on a national average basis and 1% below the previous five-winter average. Under those conditions, storage provides a buffer against periods of higher consumption or lower production.

The risk is cold weather. Prolonged periods of cold weather could increase withdrawals beyond the forecast. With the surplus already smaller than the EIA assumed, the buffer against a cold winter is thinner than the official forecast suggests.

Earlier projections were higher. In September, the outlook projected inventories approaching 4 trillion cubic feet by the end of October, which would have been the second-highest end-of-October level on record and 44 Bcf below the all-time high set in October 2016. The October forecast’s 3,850 Bcf marks a downgrade of roughly 150 Bcf in one month.

That downgrade is itself a bullish signal. When the official storage forecast falls by 150 Bcf in a single month, it confirms that demand is running stronger or production weaker than expected. Each successive downgrade reduces the market’s confidence in winter supply.

For the forecast, the EIA target is the yardstick. If end-October inventories fall short of 3,850 Bcf by more than 50 Bcf, futures are likely to price a larger winter risk premium, pushing toward $3.50.

LNG Feedgas: The Structural Demand Engine

Liquefied natural gas exports are pulling more gas out of the US system than ever. Traders have been weighing robust LNG feedgas consumption against recovering production and weaker weather demand this week. LNG feedgas has been rising even as weather demand fades.

LNG demand is structural, not seasonal. Each additional billion cubic feet per day of LNG export is gas that can’t be injected into domestic storage. If new export capacity ramps on schedule, it represents the largest structural increase in non-storage gas demand since the shale revolution.

The global market supports US exports. UK and Dutch gas prices climbed this week as hopes for a quick reopening of the Strait of Hormuz faded. Qatar, one of the world’s largest LNG exporters, ships its cargoes through the strait. Any disruption to Gulf LNG flows pushes European and Asian buyers toward US cargoes, keeping US terminals running at full capacity.

The Iran war is the link. The Strait of Hormuz is estimated to be blocking 8.3 million barrels a day of oil, 36% of Gulf crude, and the same disruption affects LNG shipments. Brent crude traded at $103.97 Thursday, and European energy prices have surged. Eurozone energy inflation hit 18.8% in September. That pricing environment makes US LNG highly profitable to export.

Regional price spreads reflect the pull. Appalachian gas prices at Texas Eastern M-2 have widened their discount to Henry Hub from June through October. Gulf Coast prices near LNG terminals command premiums, while producing regions far from export hubs trade at discounts. The pipeline network can’t move gas fast enough from Appalachia to the Gulf, which concentrates the LNG pull on South Central storage.

That explains the regional storage pattern. When LNG terminals pull heavily from the Gulf Coast, South Central storage builds slowly or even draws, while the Midwest and East continue to inject. Thursday’s report showed the Midwest leading injections, consistent with strong Gulf Coast LNG demand absorbing South Central supply.

For the forecast, LNG demand sets a floor under prices. Even in mild weather, LNG exports keep gas flowing out of the country at a pace that limits storage builds. Unless a ceasefire in the Gulf reduces global LNG prices and the incentive to export, US feedgas demand will remain elevated through winter.

Pipeline Outage: TCO Disruption Limits Future Builds

A pipeline problem added to Thursday’s bullish tone. A key outage on the Columbia Gas Transmission system could limit future inventory builds. Futures climbed early Thursday partly on the outage, before the storage data added further support.

Pipeline outages affect storage directly. When a major interstate pipeline loses capacity, gas from producing regions can’t reach storage facilities or demand centers as quickly. That reduces injections in the affected region and can force producers to curtail output if takeaway capacity is constrained.

Columbia Gas Transmission is a major Appalachian system. It moves gas from the Marcellus and Utica shale fields to markets in the East and Midwest. An outage on that network compounds the existing bottleneck between Appalachian supply and Gulf Coast demand, widening regional price spreads further.

The timing matters. Outages during the final weeks of injection season reduce the amount of gas that reaches storage before winter. If the outage extends for several weeks, it could cut injections by several Bcf per week, adding to the shortfall against the EIA’s 3,850 Bcf end-October target.

Appalachian prices tell the story. The widening discount at Texas Eastern M-2 relative to Henry Hub reflects too much gas in Appalachia and not enough capacity to move it out. A pipeline outage worsens that imbalance, depressing local prices while supporting Henry Hub, which prices gas at the Louisiana hub near LNG terminals.

The effect on futures is supportive. NYMEX futures price at Henry Hub, so constraints that keep gas trapped in producing regions tend to lift the benchmark. The outage gives futures a near-term tailwind independent of weather.

Production recovery is the counterweight. Signs of recovering supply helped push futures lower at midweek. Producers have been bringing output back after maintenance and earlier curtailments, and recovering production offsets part of the pipeline constraint. If the outage resolves quickly and production keeps rising, the supportive effect fades.

For the forecast, the pipeline outage is a short-term bullish factor. Its duration will determine how much it affects the next two to three storage reports. A prolonged outage would push the storage surplus toward zero faster and lift futures toward $3.35-$3.50.

Weather: Mild Forecasts Through October 29 Cap the Rally

Weather is the main headwind. US natural gas futures fell below $3.20 earlier this week, retreating from a near-three-week high of $3.283 reached on October 13, mainly on forecasts for relatively mild weather across the country through October 29. Mild temperatures limit both heating and cooling demand.

Shoulder-season weather typically suppresses demand. Late October sits between the summer cooling season and the winter heating season. When temperatures are mild, power plants burn less gas for air conditioning and households use little gas for heating. That leaves more gas available for storage injections.

The forecast extends two weeks. Mild weather through October 29 means the remaining three storage reports of the traditional injection season could show larger builds than the past two weeks. Larger builds would slow the shrinking of the surplus and weigh on futures.

The bearish weather tilt was clear at midweek. Futures moved sharply lower Wednesday on signs of recovering supply and sluggish weather-driven demand in the forecast. The market is balancing a bullish storage trend against a bearish near-term weather outlook.

Winter forecasts matter more. The EIA assumes heating degree days nearly unchanged from last winter and 1% below the five-winter average. A colder winter would push demand sharply higher, while a milder one would leave storage comfortable. Early-season cold snaps in November often trigger the biggest price moves of the year.

Power burn adds a structural element. Natural gas generates 43% of US electricity. Every additional gigawatt of 24/7 data center capacity running on gas adds 0.15 Bcf per day of power burn. Power burn gains have materialized across several regions in 2026, led by the Mountain region, while Pacific demand declined through October 14. Data center demand has grown, though not as fast as some expected.

The 52-week high shows what weather can do. Henry Hub futures reached $5.62 within the past year, a level driven by winter demand. With storage tighter than forecast and the surplus shrinking, a cold November could push futures well above $4.

For the forecast, weather caps the near-term rally and sets the medium-term direction. Mild weather through October 29 likely keeps futures below $3.40. A shift to colder forecasts for November would quickly lift the contract toward $3.50.

Oil and Energy Inflation: The Broader Energy Backdrop

The oil market provides context for gas. December Brent fell 1.97% to $103.97 Thursday, while November WTI rose 0.61% to $94.47. Brent is up 66% from a year earlier, driven by the Iran war and the Strait of Hormuz disruption.

The oil-to-gas ratio shows how cheap US gas is. With WTI at $94.47 and Henry Hub at $3.26, oil trades at 29 times the price of gas per unit. On an energy-equivalent basis, one barrel of oil contains roughly six times the energy of one million British thermal units of gas. A ratio of 29 means US gas is trading at a deep discount to oil relative to energy content.

That discount supports demand. Industrial users switch to gas where possible when oil is expensive. LNG exporters earn wide margins selling US gas into global markets priced near oil-linked levels. The cheaper US gas is relative to global energy, the stronger the incentive to export it.

Producer prices confirm the energy surge. The September Producer Price Index showed unprocessed energy materials up 22.2% in a single month, with crude petroleum up 28.3%. Natural gas and gas fuels also rose. Residential electric power prices increased, while commercial electric power declined 0.6%.

Energy inflation drives Fed policy. US producer prices rose 1.3% in September and 6.3% over 12 months. Energy accounted for more than 80% of the 2.6% jump in final demand goods prices. October Fed hike odds jumped from 22.1% to as high as 49% after the September CPI. A tighter Fed would slow economic growth, which could reduce industrial gas demand over time.

The dollar matters for LNG. A weaker dollar makes US LNG cheaper for foreign buyers, supporting exports. The dollar index faded to 101.74 after Wednesday’s CPI, from an 18-month high. A sustained dollar decline would add to LNG demand.

Geopolitical risk cuts both ways for gas. A ceasefire in the Gulf would lower oil prices, reduce global LNG prices and narrow the margin for US exports, which would weigh on Henry Hub. Escalation would push global LNG prices higher and keep US terminals running at full capacity.

For the forecast, the energy backdrop is supportive. High oil prices, strong global LNG demand and a weak-to-stable dollar all favor US gas exports. That keeps the floor under Henry Hub firm even when domestic weather is mild.

Production Recovery: The Bearish Counterweight

Supply is the variable that could cap the rally. Low but recovering production weighed on futures early Wednesday. Signs of recovering supply contributed to the sharp midweek decline.

Production has been running below peak levels. Maintenance, pipeline constraints and earlier price-driven curtailments reduced output during parts of the summer and early fall. As prices rose above $3 and maintenance ended, producers began bringing volumes back.

Recovering output adds to storage. Every additional Bcf per day of production either goes into storage, LNG feedgas or domestic consumption. In a mild-weather period, much of the new supply flows into storage, which could increase the next few weekly builds and slow the shrinking of the surplus.

Appalachian constraints limit the effect. Production growth in Appalachia, the largest gas-producing region, can’t reach Gulf Coast LNG terminals because of pipeline bottlenecks. The widening discount at Texas Eastern M-2 shows that new Appalachian supply is trapped regionally. The Columbia Gas Transmission outage makes that constraint worse.

Haynesville and Permian production matters more for Henry Hub. Gas from Louisiana’s Haynesville shale and associated gas from the Permian Basin in Texas can reach Gulf Coast terminals directly. Production growth in those regions has a bigger effect on Henry Hub prices than Appalachian growth.

Permian output is tied to oil. With WTI at $94.47, Permian oil producers have strong incentives to drill, and associated gas output rises with oil production. That creates a steady supply of gas regardless of gas prices, which caps how high Henry Hub can climb in mild weather.

Gas producers are positioned for winter. Producers like EQT, Coterra and Chesapeake have been managing output to balance price and volume. At $3.26, most can operate profitably, which supports continued output growth. A rally above $3.50 would likely bring more supply back quickly.

For the forecast, production recovery acts as a ceiling. It limits how fast the storage surplus shrinks during mild weather and caps rallies above $3.40 until winter demand arrives. The pipeline outage temporarily offsets part of that effect.

Technical Map: $3.283 Ceiling, $3.05 Floor

The chart has a clear range. Resistance sits at $3.283, the near-three-week high reached on October 13. Thursday’s rally brought futures within 2.3 cents of that level. A break above it would target $3.35 and then $3.50.

Support starts at $3.20, the level futures dipped below earlier this week. Below that, $3.18, the most recent posted spot price, serves as a reference. The $3.04-$3.05 area, where Henry Hub traded during recent choppy sessions, forms the key floor. Below that, the early-October spot low at $2.90 is the next major support.

The range has held all week. Futures fluctuated in a span bordered by pivotal technical floors and ceilings as fundamentals painted a mixed picture. Weather demand faded while LNG feedgas consumption climbed, keeping prices inside the band.

Higher lows define the longer trend. Consistent higher lows since April 2026 show buyers stepping in at progressively higher levels. The spot price path, from $2.90 on October 2 to $3.18 most recently, extends that pattern into October.

Momentum favors a test of resistance. The 12.72% monthly gain and the bullish storage print give futures upward momentum. A daily close above $3.283 would confirm a breakout from the three-week range and likely trigger trend-following buying.

The 52-week range offers upside room. With futures at $3.26 and the 52-week high at $5.62, the contract has substantial room to rally in winter. The 52-week low at $2.54 sets the downside extreme, 22% below current levels.

The daily close sets the bias. A close above $3.283 targets $3.35 within days. A close below $3.20 would signal the storage rally has faded and put $3.05 back in play. Next Thursday’s storage report and updated weather forecasts for early November are the likely triggers.

Equities and ETFs: How the Market Is Positioned

Gas-linked equities and funds give traders different ways to express a view. The United States Natural Gas Fund (UNG) tracks front-month futures, while leveraged products like BOIL and KOLD offer two-times long and short exposure. Producers like EQT, Coterra and Chesapeake offer equity exposure to gas prices, and Cheniere Energy offers exposure to LNG export volumes.

Producers benefit from higher prices and volumes. At $3.26 gas, Appalachian and Haynesville producers operate profitably. A move toward $3.50-$4.00 in winter would expand margins significantly. Regional price discounts in Appalachia, however, reduce the realized price for producers like EQT whose output faces pipeline constraints.

LNG exporters benefit from global demand. Cheniere profits from the spread between US gas prices and global LNG prices. With European and Asian prices elevated by the Gulf disruption, that spread remains wide. Higher Henry Hub prices narrow the spread slightly but are offset by higher global prices.

The broader energy sector is leading. Energy (XLE) has been one of the top two large-cap sectors in October, alongside consumer staples. Investors rotating away from AI and technology stocks have moved into energy and defensive sectors, supporting gas-linked equities.

Risk sentiment matters for leveraged ETFs. BOIL and KOLD experience decay over time in volatile, range-bound markets. With futures oscillating between $3.05 and $3.283, leveraged products lose value from daily rebalancing even without a directional move. These funds work best during sustained trends.

Market-wide stress affects commodity funds. The Nasdaq fell 1.05% Thursday, and broader risk-off flows can push commodity funds lower even when physical fundamentals tighten. Natural gas has held up better than most risk assets this week because its drivers, storage, weather and LNG, are largely independent of equity sentiment.

For the forecast, equity and ETF positioning supports the base case. Producers and LNG exporters are positioned for higher winter prices, and the energy sector’s leadership supports continued interest. A breakout above $3.283 would likely draw additional flows into UNG and BOIL.

Scenarios Into November: $3.05 Downside, $3.50 Upside

The base case is a range with an upward bias. If mild weather holds through October 29, storage builds come in near 70-85 Bcf and LNG feedgas stays strong, November futures trade between $3.15 and $3.35 into the end of October. The storage surplus continues shrinking toward zero, setting up a winter risk premium. Futures likely test $3.283 and break above it before the November contract expires.

The bullish case needs colder weather or further supply disruption. If forecasts shift colder for early November, the Columbia Gas Transmission outage extends and storage builds fall below 70 Bcf, futures break $3.283 and target $3.35, then $3.50, a 7.4% gain from current levels. An early-November cold snap with storage below the five-year average could push the contract toward $3.75-$4.00.

The bearish case requires mild weather and recovering supply. If temperatures stay mild into November, production recovers faster than expected and storage builds jump above 90 Bcf, futures fall below $3.20 and test $3.05, a 6.4% decline. A ceasefire in the Gulf that lowers global LNG prices would add pressure. A break below $3.05 would expose $2.90.

The probabilities favor the base and bullish cases. The storage surplus has fallen from 4.8% to 1.3% in six weeks, LNG demand is structural, the pipeline outage limits near-term builds and the EIA’s end-October forecast of 3,850 Bcf looks too high at the current injection pace. Mild weather slows the rally but doesn’t reverse the trend.

Three triggers will decide the path. First, next Thursday’s storage report, where another build below 75 Bcf would push the surplus below 1%. Second, weather forecasts for November, where any shift colder would trigger a breakout. Third, the duration of the Columbia Gas Transmission outage, which affects injection capacity.

Verdict: Bullish Bias, $3.283 Is the Breakout Line

Natural gas futures are building a case for higher prices into winter. November Henry Hub futures rose 1.96% to $3.26 Thursday after the EIA reported a 67 Bcf injection for the week ended October 9, below the 74 Bcf estimate, last year’s 80 Bcf and the five-year average of 90 Bcf. Inventories reached 3,567 Bcf, just 1.3% above the five-year average and 3.9% below year-ago levels.

The storage trend is the core of the thesis. The surplus has fallen from 4.8% above average in early September to 1.3% now, and from 151 Bcf in mid-June to 46 Bcf. Reaching the EIA’s end-October target of 3,850 Bcf would require 94 Bcf a week for three weeks, well above the recent pace. The official forecast has already been cut by roughly 150 Bcf in a month.

Demand is structural. LNG feedgas is climbing as the Gulf disruption keeps global gas prices elevated and US exports profitable. With WTI at $94.47, oil trades at 29 times the price of gas, leaving US gas deeply discounted to global energy. A Columbia Gas Transmission outage adds a near-term supply constraint.

Mild weather and recovering production cap the near-term upside. Forecasts call for mild temperatures through October 29, limiting heating and cooling demand, while producers bring output back after maintenance. Those factors kept futures in a $3.05-$3.283 range this week.

The forecast is bullish with a near-term range. Expect November futures to trade between $3.15 and $3.35 into the end of October, with a daily close above $3.283 opening a path to $3.35 and $3.50. A daily close below $3.20 would delay the breakout and put $3.05 back in play. With the surplus shrinking every week and winter approaching, the path of least resistance points higher, and $3.283 is the line that confirms it.

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