Henry Hub ($3.19) Caught Between a Shrinking Storage Surplus and Mild Late-October Weather — $3.10 to $3.35 Range

Natural gas futures for November delivery are trading at $3.19 per million British thermal units, down about $0.05, or 1.40% to 1.50%, on the day. Futures slumped at the start of Friday’s session after Thursday’s gain. Traders are weighing a lean storage report, low production, an Appalachian pipeline outage and strong LNG demand against forecasts for mild weather through the end of the month.

Thursday was a good day for the bulls. November futures rose about 2% after the Energy Information Administration reported a smaller-than-expected storage injection, daily production dropped to a five-month low and weather forecasts showed higher demand over the next two weeks than earlier expected. Prices traded near $3.25 ahead of the report.

The week’s high came on Monday. On October 13, November futures reached $3.283, a nearly three-week high. Since then, prices have pulled back about 2.8%.

Natural gas is up sharply over the past month. The November contract has gained 9.9% to 10.0% over 30 days. Over 12 months, prices are up about 6%. A year ago, Henry Hub spot averaged $3.19 in October 2025, nearly the same level as today.

The November contract expires on October 28. After that, the December contract becomes the front month. December futures trade at a premium to November, reflecting expected winter heating demand.

Henry Hub spot prices have been volatile. The physical price at Henry Hub, Louisiana, was $3.22 on October 14, up from $3.14 on October 13 and $3.10 on October 12 and October 9. On October 8, spot traded at $3.24. Henry Hub cash has held a premium to NYMEX futures this week.

The monthly averages show a steady recovery from summer lows. Henry Hub spot averaged $2.79 in August, $2.89 in July and $2.95 in September. October is running higher.

The 2026 picture has been dramatic. Henry Hub spot averaged $7.72 in January during Winter Storm Fern, which drove record storage withdrawals. It fell to $3.62 in February and hit summer lows near $2.79. The EIA has cut its 2026 annual price forecast by more than 20%, from $4.31 in February to $3.44 in August.

The setup is a tug of war. Supply is tight in the short term: production has fallen sharply from record highs, the storage surplus is shrinking and LNG exports remain strong. But demand is soft, with mild weather expected through October 29 and storage still 45 Bcf above the five-year average. The next sections map both sides.

Storage: 67 Bcf Build Misses the 76 Bcf Forecast

Thursday’s storage report was the most bullish data point of the week.

The EIA reported a net injection of 67 billion cubic feet for the week ending October 9. The consensus forecast was 76 Bcf. Some estimates were as high as 74 to 75 Bcf. The prior week’s injection was 85 Bcf.

The 67 Bcf build was well below historical norms. The five-year average injection for the same week is 90 Bcf. Last year’s injection for the same week was 80 Bcf. This year’s build was 23 Bcf below the five-year average and 13 Bcf below last year.

Total working gas in storage rose to 3,567 Bcf. That is 45 Bcf, or 1.3%, above the five-year average of 3,522 Bcf. It is 143 Bcf, or 3.9%, below last year’s level of 3,710 Bcf. Total storage remains within the five-year historical range.

The surplus is shrinking fast. On September 4, storage was 148 Bcf above the five-year average. Five weeks later, the surplus has fallen to 45 Bcf. That is a drop of 103 Bcf in the cushion that had been weighing on prices.

All regions posted increases except the Pacific. The Midwest led all regions. The East rose 22 Bcf to 884 Bcf, 3.3% above its five-year average.

The South Central region is the weak spot. All regions are above the five-year average except South Central and South Central salt. Salt storage in South Central, which can be filled and drawn quickly, stands at 236 Bcf. That is 21.9% below last year and 15.4% below the five-year average. Salt caverns are the market’s fast-response storage. Low salt levels mean less buffer for sudden cold snaps.

The injection season is nearly over. The EIA forecasts that inventories will build by 328 Bcf during October to reach 3,850 Bcf by the end of the month. That would leave storage 2% above the five-year average entering the heating season on November 1. Mild weather could extend injections into mid-November.

The next storage report is October 22. Early estimates for the week ending October 16 will set the tone for next week.

For the forecast, the storage trend is bullish. A shrinking surplus means less cushion for winter. Another injection below 70 Bcf next week would push the surplus toward zero and support prices above $3.30.

Production: Eight-Month Low After Hurricane Isaias and Pipeline Outages

Lower production is the main reason the storage surplus has shrunk.

U.S. Lower 48 gas output averaged 110.8 billion cubic feet per day so far in October, according to financial data firm LSEG. That is down from record highs of 113.3 Bcf/d in August and September. The drop of 2.5 Bcf/d is significant in a market where small changes in supply move prices.

Daily output fell further this week. On October 13, production was on track to drop to an eight-month low of about 107.1 Bcf/d. On Thursday, output dropped to a five-month low on a daily basis.

Several factors drove the decline. Hurricane Isaias forced production shut-ins in the Gulf of Mexico. Force majeure incidents and pipeline problems in Kentucky, Texas, West Virginia and elsewhere have curbed supply over the past month. A major Appalachian pipeline outage is also limiting flows.

Producers have also cut voluntarily. With prices near $3 and storage above average, some producers scaled back output in early October. Production held near 108 Bcf/d in the first week of the month as producers responded to weak weather demand.

Regional prices show the effects. Appalachian and Northeast cash prices have fallen sharply relative to Henry Hub as pipeline outages trap supply in the region. Texas Eastern M-2 spot prices have dropped well below Henry Hub from June to October. Meanwhile, maintenance in the Permian Basin is constraining output there.

Production is expected to rebound. The EIA forecasts 2026 production at 112.2 Bcf/d and 2027 production at 116.1 Bcf/d. Gulf of Mexico output is slowly returning after Isaias. Analysts expect production to ramp up ahead of winter to meet higher demand.

The rebound is the main risk to prices. Once hurricane shut-ins reverse and pipeline problems are fixed, production could quickly return to 112 Bcf/d or more. That would add roughly 1 to 4 Bcf/d of supply, enough to push weekly injections back toward 80 to 90 Bcf.

For the forecast, low production is temporary support. Prices could stay firm while output remains near 108 to 111 Bcf/d. A return to 113 Bcf/d would remove that support and push prices back toward $3.00.

LNG Exports: 17.6 Bcf/d in October Despite Plant Maintenance

LNG exports are a key source of demand, and they remain strong despite seasonal maintenance.

Average gas flows to the nine major U.S. LNG export plants were 17.6 Bcf/d so far in October. That is down slightly from 17.9 Bcf/d in September and below the monthly record of 18.8 Bcf/d set in April.

Daily flows have been higher recently. LNG feedgas deliveries reached 18.72 million dekatherms on a recent day, near record levels. Other data show feedgas holding near 18 Bcf/d through October. Feedgas was estimated at 18.9 Bcf/d on October 7.

Maintenance is weighing on flows. Cove Point in Maryland has been offline for maintenance. Golden Pass in Texas has been running about 50% below recent highs. Freeport LNG has been recovering from an outage that took Train 2 offline. Once these plants return to full operation, feedgas could rise above 19 Bcf/d.

New capacity is coming. Sempra Infrastructure is advancing commissioning at Port Arthur LNG in Texas. New startup activity brings the project closer to adding a major new source of demand on the Gulf Coast. Golden Pass is also ramping up.

Global demand supports U.S. LNG. The Middle East conflict has disrupted LNG shipments from Qatar, one of the world’s largest LNG exporters, through the Strait of Hormuz. That has pushed buyers in Europe and Asia toward U.S. cargoes. U.K. and Dutch gas prices have been volatile on Hormuz headlines.

LNG Canada is also growing. The export terminal in Kitimat, British Columbia, rebounded from a July slowdown, lifting feedgas intake and cargo loadings. Canadian gas prices are firming as the winter heating season approaches, supported by rising LNG export activity.

LNG demand is a structural support. U.S. LNG exports have grown steadily, adding several Bcf/d of demand over the past two years. That demand does not depend on U.S. weather, which provides a floor under prices even in mild periods.

For the forecast, LNG exports are a steady positive. A return to 18.5 Bcf/d or more as maintenance ends would add bullish pressure. Any unplanned outage at a major plant would be bearish.

Weather: Mild Through October 29, Then Colder

Weather is the biggest swing factor for natural gas, and the near-term forecast is mild.

Meteorologists expect weather across most of the country to remain milder than normal through October 29 and October 30. That should keep both heating and cooling demand low. The shoulder season between summer and winter is typically the weakest period for gas demand.

Heating degree days are low. LSEG’s two-week forecast showed 115 heating degree days, compared with a 10-year norm of 128 and a 30-year norm of 147. Heating demand is running about 10% below the 10-year average. Residential gas demand is about 5.1 Bcf/d, compared with a 10-year norm of 7.5 Bcf/d.

Cooling demand is still elevated. Cooling degree days in the two-week forecast stood at 52, compared with a 10-year norm of 47. Warm weather in the South is keeping some air conditioning demand alive. About 40% of U.S. power comes from gas-fired plants.

Demand is expected to rise next week. LSEG projects average Lower 48 gas demand, including exports, to rise from 104.7 Bcf/d this week to 106.0 Bcf/d next week. That forecast was higher than the prior day’s outlook.

The EIA expects a cooler October overall. Its forecast assumes about 236 heating degree days in October, 7% more than the 10-year average. Late October could bring the first real cold of the season.

The winter outlook is mild. The EIA assumes heating degree days this winter will be nearly unchanged from last winter and 1% below the five-winter average. A mild winter would limit price upside.

The Northeast is different. The Northeast is expected to be cooler than the rest of the country, supporting regional heating demand. Northeast winter forward prices are strong, with Algonquin Citygate and Iroquois Zone 2 commanding significant premiums.

For the forecast, weather is a near-term headwind. Mild conditions through October 29 limit upside for the November contract. A shift to colder forecasts for early November would be the main trigger for a rally.

The November Contract Expiry: October 28

The November contract expires on October 28, which affects price behavior over the next two weeks.

As the expiry approaches, the November contract converges toward the physical Henry Hub price. With Henry Hub cash trading at a premium to futures this week, that convergence could support November prices.

The December contract trades at a premium. December futures reflect early winter heating demand. When November expires, the front-month price will jump to December’s level. That roll can create an apparent price increase even if the market does not move.

Expiry periods can be volatile. Traders closing positions before expiry can cause sharp moves. Low liquidity in the final days can amplify swings.

The October 28 date is crowded. The Fed decision, the UK Budget and several major earnings reports all fall on the same day. Natural gas is less affected by those events than other markets, but broad risk-off moves can still spill over.

Storage reports before expiry matter. The October 22 report, covering the week ending October 16, will be the last storage report before the November contract expires. A small injection would support November prices into expiry. A large injection would weigh on them.

For the forecast, expiry dynamics favor a narrow range for November futures, with a mild upward bias as the contract converges to cash. The bigger picture will come from the December contract after the roll.

Supply vs. Demand: The Winter Balance

The longer-term question is whether supply will keep up with winter demand.

Supply growth is strong. Production hit records of 113.3 Bcf/d in August and September before the recent dip. The EIA expects production to average 112.2 Bcf/d in 2026 and rise to 116.1 Bcf/d in 2027. That growth is driven by Permian Basin output and new pipeline capacity.

Demand growth is also strong. The EIA forecasts U.S. natural gas consumption of 92.37 Bcf/d in 2026, up from 91.86 Bcf/d in 2025. Consumption is expected to rise to 93.83 Bcf/d in 2027. LNG exports, data center power demand and industrial use are all growing.

Analysts expect supply growth to outpace winter demand, even with LNG gains. That suggests prices will remain range-bound this winter unless weather is unusually cold.

Storage provides a buffer. The EIA expects inventories to reach 3,850 Bcf by the end of October, 2% above the five-year average. That gives the market a cushion against cold snaps or supply disruptions.

The risk is a repeat of last winter. Winter Storm Fern in January 2026 drove Henry Hub spot to an average of $7.72 for the month, with record storage withdrawals. A similar event this winter would send prices sharply higher.

Data center demand is a new factor. AI data centers are driving electricity demand growth, and much of that power comes from gas. That adds a steady source of demand that grows regardless of weather.

Energy markets globally are tight. Brent crude is above $105, and global LNG markets are stressed by the Hormuz disruption. U.S. gas remains cheap compared with global prices, which supports LNG export demand.

For the forecast, the winter balance looks manageable. Ample storage and rising production should limit sustained price spikes. Weather remains the wild card.

Natural Gas Equities and ETFs

Natural gas producers and related funds give another view of market sentiment.

The United States Natural Gas Fund (UNG) tracks front-month futures and is subject to roll costs as contracts expire. When later contracts trade at a premium, as December does to November, UNG loses value at each roll. That makes UNG better for short-term trades than long-term holdings.

Leveraged funds like BOIL amplify daily moves. They are designed for short-term trading and can lose value quickly in volatile markets.

Producers benefit from higher prices. EQT, the largest U.S. gas producer, focuses on Appalachia. Regional price weakness in Appalachia due to pipeline outages hurts producers there, even when Henry Hub is firm.

LNG exporters benefit from global demand. Cheniere Energy, the largest U.S. LNG exporter, earns fees on liquefaction and benefits from strong global prices. The Hormuz disruption has kept international LNG demand high.

Energy stocks overall are mixed. Energy was the worst-performing S&P 500 sector on Thursday, down 1.58%, before rebounding Friday. ConocoPhillips hit a record high Friday morning.

For the forecast, equity markets are not sending strong signals for gas. Producers are focused on balancing output with demand, while LNG exporters are benefiting from global tightness.

The Technical Map: $3.10 Floor, $3.30 Ceiling

The November contract is trading in a range defined by recent highs and lows.

The key resistance is $3.283, Monday’s nearly three-week high. Above that, $3.30 is a round-number level. The November contract settled at $3.301 on October 6. A daily close above $3.30 would signal a breakout.

Above $3.30, the next resistance is $3.35 and then $3.40. A move to $3.50 would require a significant shift toward colder weather.

On the downside, the first support is $3.15. Below that, $3.10 matches the Henry Hub spot price on October 9 and October 12. The $3.00 level is a key psychological support. Below $3.00, the next support is $2.95, the September Henry Hub average.

The trend is up. November futures have gained about 10% over the past month, making higher lows since early September. The rally from summer lows near $2.80 has been steady.

Momentum has slowed. The pullback from $3.283 to $3.19 shows buyers losing energy as mild weather forecasts persist. A break below $3.10 would end the uptrend.

Spot and futures are converging. Henry Hub cash at $3.22 on October 14 was above the futures price. As November approaches expiry, that gap should narrow, which supports futures.

For the forecast, the key levels are $3.10 on the downside and $3.30 on the upside. A daily close above $3.30 targets $3.40. A daily close below $3.10 targets $3.00.

Scenarios Into the November Contract Expiry on October 28

Base case: range $3.10 to $3.35 (55% probability). Mild weather continues through October 29. Production stays near 110 to 111 Bcf/d as hurricane shut-ins slowly reverse. LNG feedgas holds near 17.5 to 18.5 Bcf/d. The October 22 storage report shows an injection of 70 to 80 Bcf. November futures trade between $3.10 and $3.35, with a test of $3.30 as the contract converges with cash. A move to $3.30 from $3.19 is a gain of 3.4%.

Bull case: $3.40 to $3.50 (20% probability). Weather forecasts shift colder for early November. Production stays below 110 Bcf/d because of continued pipeline problems. LNG feedgas rises above 18.5 Bcf/d as Cove Point and Golden Pass return. The October 22 storage report shows another injection below 70 Bcf, pushing the surplus below 30 Bcf. November futures break $3.30 and move to $3.40 to $3.50.

Bear case: $3.00 or lower (25% probability). Production rebounds quickly to 112 Bcf/d or more as Gulf output returns and pipeline problems are fixed. Weather stays mild into November. The October 22 storage report shows an injection above 85 Bcf. LNG maintenance extends. November futures fall through $3.10 and test $3.00, with $2.95 possible.

The base case is favored. Supply is tight but improving. Weather is mild but expected to cool. The storage surplus is shrinking, but inventories remain above average.

Natural Gas Price Forecast Verdict: Hold $3.10, Test $3.30, Range-Bound Into Expiry

November natural gas futures are at $3.19, down about 1.4% on the day. The setup is neutral with a modest bullish bias into the October 28 expiry.

The bull case rests on four points. First, the 67 Bcf storage injection fell 9 Bcf short of the 76 Bcf forecast and 23 Bcf below the 90 Bcf five-year average. Second, the storage surplus has shrunk from 148 Bcf above the five-year average on September 4 to just 45 Bcf. Third, production averages 110.8 Bcf/d in October, down from records of 113.3 Bcf/d, and fell to an eight-month daily low near 107.1 Bcf/d. Fourth, LNG feedgas holds near 17.6 Bcf/d in October despite maintenance, with near-record daily flows recently.

The bear case rests on four points. Weather is expected to stay milder than normal through October 29, with heating degree days about 10% below the 10-year norm. Total storage of 3,567 Bcf remains 1.3% above the five-year average, and the EIA expects 3,850 Bcf by the end of October. Production is expected to rebound as hurricane shut-ins and pipeline problems clear. And analysts expect supply growth to outpace winter demand.

The $3.30 level is the key resistance. A daily close above it would break the recent range and open $3.40.

The forecast is a range of $3.10 to $3.35 into the November contract expiry, with a test of $3.30. The trigger for a breakout is a colder weather shift for early November combined with an October 22 storage injection below 70 Bcf. The invalidation level is a daily close below $3.10, which would point to $3.00.

The risk-reward is balanced. From $3.19, the distance to the $3.30 target is $0.11. The distance to the $3.10 invalidation level is $0.09. That is a ratio of 1.2 to 1. The bull-case target of $3.40 improves the ratio to 2.3 to 1.

The verdict is neutral to mildly bullish: hold $3.10, test $3.30, range-bound into expiry. A colder forecast and another lean storage print would put $3.40 to $3.50 in play. A production rebound and a large injection would send prices back to $3.00.

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