Natural Gas Squeezes Toward $3.40 as Record Shorts Cover, LNG Demand Hits 20.4 Bcf/d and Output Drops 3.3 Bcf/d

The NYMEX December natural gas contract was trading at $3.209 per MMBtu at 3:36 p.m. ET on Monday, November 9. That was up $0.211, or 7.04%, from Friday’s settlement of $2.998. The contract opened at $3.032 and dipped to $2.988 in early trade. It then accelerated through the session to an intraday high of $3.239, a gain of 8.04% at its peak. Volume reached 223,825 contracts, 43% above Friday’s 156,459. A rally on volume that heavy reflects fresh positioning and forced buying, not a quiet drift.

It was the biggest one-day gain since September 24, when the front month added 9.06% from $3.023 to $3.297. It also lifted prices to their highest level since October 15, when the contract settled at $3.236. Over three weeks the move has been steep. The front month bottomed at an intraday low of $2.497 on October 26 and closed that day at $2.602. From that close, gas has gained 23.3% in ten sessions. From the November 2 close of $2.856, the rally measures 12.4%.

Three forces drove Monday’s jump. Weekend weather models turned cooler for the Atlantic seaboard, reducing confidence in the record-warm November that the market had priced. Money managers held the largest short-only position in US natural gas futures on record, so even a modest cooling forced them to buy back contracts. Demand for gas at LNG export terminals also hit a record 20.4 Bcf/d on Monday, with almost every US plant running at or near full capacity.

Gas-linked funds moved with the futures. The United States Natural Gas Fund (UNG) rose 8.03% to $10.10. The 2x leveraged BOIL gained 10.96% to $18.58, while the inverse KOLD dropped 10.65% to $28.82. Cheniere Energy (LNG) climbed 2.94% to $285.48 on record terminal throughput. Gas producers moved less. EQT rose 0.79% to $49.79, Expand Energy (EXE) 1.48% to $85.85 and Antero Resources (AR) 0.32% to $36.19. Producer stocks lagging the futures shows that equity investors saw the move as a short squeeze rather than a lasting change in the price outlook.

The broader energy complex moved the opposite way. WTI crude fell 4.51% to $86.73 and Brent dropped 5.91% to $92.51. Gas rallying while oil sank confirms that Monday’s move came from gas-specific factors: weather, positioning and LNG. The key question for the week is whether those forces can hold prices above $3.20 into Friday’s storage report.

A Record Short Position Turned a Weather Shift Into a Squeeze

Positioning explains why Monday’s move was so violent. Through October, money managers built the largest bearish bet on US natural gas in the history of federal positioning data. In the week to October 27, short-only positions across seven benchmark Henry Hub contracts rose to 625,150, according to CFTC data. That was the largest since records began in May 2013, breaking a record set just one week earlier at 599,731. The short-only position hit another record the following week.

The net position was just as one-sided. In mid-October, the net short across those contracts reached 192,728, the most bearish level in more than six years and the largest net short since February 2020. At the same time, bullish bets fell to their lowest in almost two years. Funds had committed fully to one view: a Super El Niño would deliver the warmest US winter on record and leave heating demand far below normal.

That level of conviction creates its own risk. When almost every fund is positioned the same way, any data that challenges the view forces them to cover at the same time. Over the weekend, forecasts shifted toward cooler weather on the Atlantic seaboard, the most populated heating region in the country. The shift was not dramatic. It did not need to be. Short sellers had to buy back contracts to limit losses, and that buying pushed prices well beyond what the forecast change alone would justify.

The pattern has played out before this year. In late January, a winter storm hit a market positioned for mild weather. Money managers cut short-only positions by more than 53,000 contracts in a single week, the largest weekly reduction in more than a year. The front month surged from $3.103 on January 16 to an intraday high of $7.827 on January 28, a 152% move in eight sessions. That squeeze set the 52-week high, and it shows how quickly gas can move when weather surprises a crowded market.

The current setup is less extreme than January, because the weather shift is milder and the season is earlier. The fuel is the same, though. Short positions remain near record levels after one day of covering. If forecasts keep trending cooler through the week, additional rounds of short covering could push the December contract toward $3.40. If forecasts revert to record warmth, the shorts will rebuild and prices will fall back toward $3. The positioning makes the market highly sensitive to each new weather model run.

The Super El Niño Forecast Still Points to the Warmest Winter on Record

The bearish case rests on weather, and the long-range forecasts have not changed. A strengthening El Niño is expected to deliver the warmest US winter in the modern record. October ranked as the third-warmest month since 1950 by gas-weighted heating degree days, the standard measure of heating demand. November is tracking to be the warmest on record by a wide margin. Both the core December-to-February winter and the broader November-to-March heating season are forecast to set warmth records.

The consequences for demand are large. Residential and commercial heating accounts for the biggest seasonal swing in US gas consumption. In a normal winter, heating demand pulls more than 2,000 Bcf out of storage between November and March. A record-warm winter can cut that withdrawal by hundreds of Bcf, leaving storage far above average at the end of March and putting heavy pressure on prices through spring. That is the scenario short sellers built their positions around in October.

The mild outlook has already hit prices. During the week ending October 23, benchmark futures fell more than 15%, the largest weekly decline since February, as forecasts shifted warmer for early winter. The front month dropped from $3.236 on October 15 to $2.602 on October 26, a 19.6% fall in seven sessions. Henry Hub spot prices fell to $2.42 on October 30, the lowest level in weeks. Physical buyers saw no reason to pay up for prompt gas.

Monday’s cooler shift does not overturn that outlook. It applies to a short window and a specific region. The European weather model turned colder for late in the week, and US models showed cooler conditions on the East Coast. The broader El Niño pattern still points to a mild late November. The next major checkpoint is November 19, when the National Oceanic and Atmospheric Administration releases its updated monthly and seasonal outlooks. If those maps confirm record warmth into December, the bearish case returns in full.

For traders, the weather picture creates a clear tension. The long-range forecast is bearish and well known. The short-range forecasts are volatile and capable of surprising a crowded market. Monday showed which force wins in the short term. Over the winter as a whole, though, the El Niño pattern will cap how far rallies can run. Gas can squeeze higher on any cold shot, but holding gains requires sustained cold, which the long-range models still do not show.

LNG Feedgas Hits a Record 20.4 Bcf/d as Every Terminal Runs Near Capacity

LNG exports provide the strongest structural support for US gas prices. Demand for gas at export terminals reached a record 20.4 Bcf/d on Monday, based on preliminary data. Average feedgas in November has also set a monthly record at 18.9 Bcf/d. Nearly every US export facility was running at or near full capacity. Cooler air makes liquefaction more efficient, so terminals can process more gas as winter approaches.

The plant-level data show how concentrated that demand is. Cheniere’s Sabine Pass in Louisiana, the largest US export terminal, was consuming about 5.0 Bcf/d, almost a quarter of total feedgas. Venture Global’s Plaquemines LNG was taking about 4.2 Bcf/d after starting commercial operations at its first phase at the start of November. Freeport LNG was running near capacity at almost 2.1 Bcf/d after a Train 2 outage earlier in the month. Golden Pass was at full capacity on its first train, taking about 0.8 Bcf/d.

Golden Pass marks the newest source of demand. The terminal, a joint venture between Exxon Mobil and QatarEnergy, shipped its first cargo from Train 1 on April 22, according to the EIA. Each of its three trains has nominal capacity of 0.7 Bcf/d and peak capacity of 0.8 Bcf/d. The full facility will reach 2.0 Bcf/d nominal and 2.4 Bcf/d at peak. Train 2 is due in the second half of 2026 and Train 3 in the first half of 2027. Each new train adds about 0.8 Bcf/d of baseload demand that does not depend on weather.

The scale of that demand changes the math for the whole market. One year ago, US LNG feedgas averaged about 14 Bcf/d in early November. Today’s 18.9 Bcf/d monthly average represents about 4.9 Bcf/d of additional demand, or roughly 34 Bcf a week. That extra pull offsets a large part of the heating demand lost to mild weather. Without the LNG build-out, a record-warm winter would push prices well below $3. With it, the market has a floor that did not exist two years ago.

The market reaction showed that LNG demand sets a floor rather than a ceiling. LNG feedgas cannot climb much higher than terminal capacity, and almost every plant is already at full use. Further growth comes only as new trains start, a gradual process. The support from exports is steady and predictable, which is why it shows up in the forward curve. Daily price swings still come from weather and positioning, and those dominated Monday’s move.

A $25 Gap Between US and Global Gas Keeps Export Demand Locked In

The global market explains why US terminals run flat out. Geopolitical disruption in the Strait of Hormuz has affected more than 10 Bcf/d of global LNG supply, about 20% of the world total, according to the EIA. The outage centred on Qatari exports, which normally move through the strait. European and Asian buyers had to replace those cargoes, and they turned to the Atlantic basin, especially the US.

That shift drove a huge price gap. In mid-October, spot gas in Europe and Asia traded at roughly $28 to $30 per MMBtu, compared with about $3 at Henry Hub. That is the widest spread since the 2022 energy crisis. The cost of buying US gas, liquefying it, shipping it and regasifying it in Europe or Asia runs about $8.40 per MMBtu at a $3.10 Henry Hub price. Every cargo shipped captures a margin of about $20 per MMBtu. With that much profit on the table, US terminals will run at maximum capacity whatever happens to domestic weather.

European prices fell sharply last week on hopes of a diplomatic breakthrough. The Dutch TTF benchmark dropped 17.7%, falling from €104.10 to close the week at €85.59. Markets moved to price a peace deal before one was signed. That decline does not threaten US export flows. Even at €85, European gas trades far above the delivered cost of US LNG. The arbitrage that keeps US terminals full would survive a TTF drop of more than 50% from current levels.

The risk of a renewed rise in global prices remains. Any resumption of attacks in the Gulf would push TTF back toward €100 and widen the spread further. That would not raise US export volumes, which are already at capacity. It would, however, strengthen the case for more US terminals and support long-dated Henry Hub prices. For the December contract, global prices matter mostly as confirmation that export demand will stay at record levels through the winter.

The global picture puts a structural floor under US gas but limits its upside. Export capacity is the bottleneck. Henry Hub cannot rise toward European or Asian prices because the US cannot ship any more gas than its terminals can handle. Domestic weather, production and storage still set Henry Hub prices. Exports just raise the baseline demand those forces work against. That explains why Henry Hub trades near $3 while gas in Europe and Asia costs ten times as much.

Storage Sits at 3,801 Bcf, 1.4% Above the Five-Year Average

Storage is the core fundamental for gas prices, and the latest data are mildly bearish. The EIA reported a 77 Bcf injection for the week ending October 30, lifting Lower 48 working gas to 3,801 Bcf. The build was smaller than the 81 Bcf the market expected. It was still larger than the 70 Bcf five-year average for the same week and more than double the 33 Bcf injected a year earlier. Full data are in the EIA Weekly Natural Gas Storage Report.

At 3,801 Bcf, inventories stand 109 Bcf, or 2.8%, below year-earlier levels of 3,910 Bcf. They sit 54 Bcf, or 1.4%, above the five-year average of 3,747 Bcf. That combination describes a market that is comfortable but not oversupplied. Storage is high enough to cover a normal winter without stress, but not so high that prices have to collapse to curb supply. The year-on-year deficit has been shrinking for weeks, while the surplus to the five-year average has widened.

The regional breakdown shows where the gas sits. The South Central region added 40 Bcf, the largest share of the national build, to reach 1,208 Bcf. Within that, salt caverns added 22 Bcf and non-salt facilities 18 Bcf. The Midwest added 23 Bcf to reach 1,111 Bcf, and the East added 13 Bcf to 926 Bcf. The Mountain region gained 2 Bcf to 260 Bcf. The Pacific region drew 1 Bcf to 296 Bcf, its first withdrawal of the season.

The trend in recent weeks has been steady. Storage rose 77 Bcf in the week to October 16, reaching 3,644 Bcf. It added 80 Bcf in the week to October 23, reaching 3,724 Bcf. The latest 77 Bcf build brought the three-week total to 234 Bcf. In each case, the injection exceeded the year-ago figure, as mild weather limited demand and production stayed high. That pace means storage could finish the injection season above 3,900 Bcf.

The salt-cavern data offer a short-term signal. Salt storage in the South Central region can inject and withdraw gas quickly, so it responds first to changes in supply and demand. A 22 Bcf salt injection late in October shows the market still had excess gas to put away. When salt storage shifts to withdrawals, it usually signals that winter demand has started in earnest. That shift has not happened yet, and until it does, the storage picture will cap rallies.

Friday’s Storage Report Moves to November 13 With a Build Near 45–67 Bcf Expected

Because of the Veterans Day holiday on Wednesday, November 11, the EIA will publish its next storage report on Friday, November 13, a day later than usual. The report covers the week ending November 6. Estimates range from 45 Bcf to 67 Bcf. The five-year average injection for that week is about 60 to 62 Bcf. A year earlier, the build was 44 Bcf. The spread of estimates is wide, and that makes the report a significant event for the December contract.

The range reflects disagreement over how much the weather shifted early in November. A build near 45 to 55 Bcf would fall below the five-year average and point to tighter balances. That would be bullish, and it would support the short-covering rally into the weekend. A build near 67 Bcf would exceed the five-year average and widen the storage surplus. That would be bearish, and it could trigger a sharp reversal of Monday’s gains.

The year-ago comparison matters for the headline. If the build comes in near 67 Bcf, it would be 23 Bcf larger than the 44 Bcf injected a year earlier. That would shrink the year-on-year deficit from 109 Bcf to about 86 Bcf. The market watches that gap closely because last winter’s storage path is a natural benchmark for this one. A shrinking deficit tells traders that this year’s supply cushion is catching up with last year’s despite record LNG exports.

The report also marks the approach of the season’s turning point. The injection season usually runs into mid-November before withdrawals begin. With mild weather forecast, injections are expected to continue through about November 20. The longer the injection season runs, the higher storage peaks before winter draws begin. A peak near 3,900 Bcf would leave the market well supplied going into December. A peak below 3,850 Bcf would leave less room for error if cold weather arrives.

Traders should expect volatility on Friday morning. The December contract has moved more than 2% on each of the last four storage reports. With short positions still large and the price at a three-week high, the reaction to a surprise in either direction could be larger. A build at or below 55 Bcf would favour a test of $3.30 to $3.33. A build above 65 Bcf would put Friday’s settlement at $2.998 and the $2.92 area back in play.

Production Slides 3.3 Bcf/d to 108.8 Bcf/d as Appalachian Producers Curtail

Supply is moving in gas’s favour. Lower 48 dry gas production fell 3.3 Bcf/d to 108.8 Bcf/d last week. South Central output dropped 2.6 Bcf/d to 50.4 Bcf/d, and the East shed 0.8 Bcf/d to 34.8 Bcf/d. Early November production averaged 111.2 Bcf/d, down from 113.4 Bcf/d in October. A decline of more than 2 Bcf/d in a month is substantial. If it holds, it removes about 15 Bcf a week from the market.

Producers are cutting deliberately. Several Appalachian producers, including EQT and Antero Resources, have signalled curtailments despite the start of the heating season. Antero plans to curtail 15 to 20 Bcfe of production in the fourth quarter of 2026 to avoid selling into weak regional prices. That follows a record third quarter, when Antero’s net production reached 4.2 Bcfe/d, up 23% from a year earlier. Producers are holding gas in the ground rather than selling it at prices near $2.50.

EQT, the largest US gas producer, has long used curtailments as a pricing tool. In its second-quarter 10-Q, it said it implements strategic curtailments from time to time in response to price volatility and to optimise in-basin pricing. It also warned that low prices could lead to further adjustments to its 2026 development schedule. With EQT shares at $49.79, near the bottom of their 52-week range of $47.94 to $68.24, the company has every reason to protect prices by holding back volumes.

The production response is a key source of support in a mild winter. In past warm winters, prices fell until producers cut output. This year, producers are cutting before prices collapse, which limits the downside. A 3.3 Bcf/d weekly decline is larger than the swing in heating demand that most weather revisions produce. If production stays near 109 Bcf/d through November, the supply cushion that drove October’s sell-off will shrink.

The risk is that curtailments reverse quickly. Producers turn wells back on as soon as prices improve, and the shut-in volumes come back within days. EQT has done this repeatedly, reversing curtailments when prices rose. A move above $3.30 could prompt producers to restore output and put a ceiling on the rally. The relationship between price and supply is tight. Low prices bring cuts, and higher prices bring volumes back. That feedback loop tends to keep the December contract in a range rather than trending.

Henry Hub Spot at $2.63 Shows the Physical Market Lagging the Futures Rally

Physical gas prices tell a softer story than the futures. The Henry Hub spot price stood at $2.63 per MMBtu on November 3, up from $2.54 on November 2 and $2.42 on October 30. Spot prices averaged $2.99 in October and $2.95 in September. In January, during the winter storm squeeze, the monthly average hit $7.72. The current spot level sits below the futures price, a sign that prompt physical demand is weaker than what the market is pricing for December.

The gap between spot and futures is normal for this time of year. Futures for December delivery carry a winter premium, because December demand typically exceeds November demand. A spot price near $2.60 and a December futures price above $3.20 imply a winter premium of about $0.60. That premium reflects expected cold, and if the cold fails to arrive, it shrinks as the December contract approaches expiry on November 25.

The convergence risk matters for December contract holders. In the final days before expiry, the futures price has to move toward the expected spot price for December delivery. If mild weather keeps physical prices near $2.60, the December contract will lose its premium and fall toward that level. That is the trade short sellers have been betting on. Monday’s rally widened the premium, which increases the potential reward for shorts if the weather stays mild.

Spot prices also reveal regional differences that the benchmark hides. Mild weather in late autumn has kept spot prices under pressure across most of the country. Strong storage builds have left hubs well supplied. The Henry Hub price in Louisiana is supported by LNG demand along the Gulf Coast, which pulls gas toward the export terminals. Inland hubs far from the coast face weaker demand and wider discounts. The national picture is tighter near the Gulf and looser inland.

The physical market will provide the best test of whether Monday’s rally holds. If spot prices climb toward $3 this week as cooler air arrives on the East Coast, the futures rally will have physical support. If spot prices stay below $2.70, the December premium will look stretched. A futures price far above spot rarely lasts into expiry unless the weather forecast changes. Spot gas is now the market’s reality check against the short-covering rally.

Gas Producers and ETFs Show Where the Market Sees Risk

The equity and fund markets offer a second view of Monday’s move. UNG, which holds front-month futures, rose 8.03% to $10.10. That leaves the fund near the bottom of its 52-week range of $8.94 to $17.03, 40.7% below its high. BOIL, which delivers twice the daily move in gas futures, rose 10.96% to $18.58. It remains 80.2% below its 52-week high of $93.70, set during January’s squeeze. KOLD, the inverse fund, fell 10.65% to $28.82, still well above its 52-week low of $13.44.

The leveraged funds show the cost of trying to trade gas swings. BOIL’s 80% drop from its high reflects both the fall in gas prices since January and the decay that leveraged daily-reset funds suffer in volatile markets. KOLD’s position near the middle of its range shows that bearish traders have done well in 2026, but not without painful reversals. The scale of Monday’s moves in both funds, about 11% each way, shows how much daily volatility the gas market is producing.

Producer stocks barely moved. EQT gained 0.79%, Expand Energy 1.48% and Antero 0.32%. Producer shares trade on longer-term expectations for gas prices, hedges and production volumes. A one-day squeeze in the December contract does little to change their outlook, especially when the winter forecast remains mild. Expand Energy at $85.85 is just 3.1% above its 52-week low of $83.25, a sign that equity investors are still pricing a weak winter.

Cheniere was the standout among gas-linked stocks. Shares rose 2.94% to $285.48, within reach of the 52-week high of $330.73 and far above the low of $186.20. Cheniere earns fees and margins on liquefaction and benefits from record utilisation and wide global spreads. Its stock reflects the structural strength of LNG demand rather than domestic weather. Cheniere’s 53.3% rise from its 52-week low captures how much the export story has changed the US gas market.

The equity picture confirms the futures analysis. Investors see the LNG build-out as the durable story, which is why Cheniere trades near highs. They see domestic gas prices as weighed down by a mild winter, which is why producers trade near lows. Monday’s futures squeeze moved the leveraged funds but left producer valuations largely unchanged. Equity markets are signalling that the rally is a positioning event rather than a reset of the winter outlook.

Gas-to-Oil Ratio Near 27 Shows How Cheap US Gas Has Become

The relationship between gas and oil prices highlights how cheap US gas is. WTI crude fell 4.51% on Monday to $86.73 per barrel. Brent dropped 5.91% to $92.51. At those levels, the ratio of WTI to Henry Hub futures is about 27 to 1. On an energy-equivalent basis, a barrel of oil contains about 5.8 times the energy of an MMBtu of gas. A ratio near 27 means gas trades at less than a quarter of oil’s price per unit of energy.

That gap has widened sharply in 2026. Oil prices surged after the Iran conflict began in March, reaching a 52-week high of $119.48 for WTI and $126.10 for Brent. Gas prices did not follow, because US gas is largely a domestic market limited by export capacity. Oil trades globally and responded fully to the supply disruption. US gas could only respond through the export channel, which was already at capacity.

The oil decline on Monday reflected the same diplomatic optimism that hit European gas last week. Markets moved to price a resolution in the Gulf, which would ease supply concerns. For US gas, falling oil has a mixed effect. Lower oil prices reduce drilling for crude in oil-focused basins like the Permian. Those wells produce associated gas as a by-product, so less oil drilling means less gas production. That supports gas prices over the medium term.

The effect works with a lag of several months. A sustained drop in oil prices leads to fewer new wells, and associated gas output falls only as existing wells decline. The South Central production drop of 2.6 Bcf/d last week reflects short-term factors such as maintenance and curtailments, not a response to oil prices. If WTI stays below $90 into 2027, the Permian slowdown could tighten gas supply next year. That supports the deferred part of the gas curve more than the December contract.

The gas-to-oil ratio also matters for power markets. Cheap gas keeps power generators burning gas rather than coal, which supports demand during mild weather. Gas-fired power demand helps absorb some of the heating demand lost to the El Niño. It is not enough to offset a record-warm winter, but it softens the downside. At $3.20, gas remains one of the cheapest power-generation fuels in the world, and that sustains demand from utilities across the country.

Technical Map Above: $3.239 Ceiling, the $3.33 Zone and $3.50

The first resistance level is Monday’s intraday high of $3.239, just 3 cents above the current price. A settlement above $3.239 would confirm the breakout and open the path to the October congestion zone. That zone runs from $3.283, the October 13 close, to the intraday highs of $3.330 on October 13 and $3.334 on October 14. Breaking through $3.334 would mean a 3.9% gain from current levels.

Above the October highs, the next level is $3.40, a round number that has acted as resistance repeatedly since February. The front month last settled above $3.40 on February 6, at $3.422, after the January squeeze faded. A move to $3.40 would require a 6.0% rally from current levels. It would likely need both a smaller-than-expected storage build on Friday and a cooler shift in the November 19 seasonal outlook.

The $3.50 level marks the outer target for this rally. It sits 9.1% above the current price and would bring the December contract back to levels last seen in early February, when the front month traded between $3.465 and $3.509 on February 4 and 5. Reaching $3.50 would need a sustained cold snap, not just a cooler forecast. It would also require short sellers to cover a large part of their record position, which would add fuel to the move.

Momentum supports further upside in the short term. The contract has posted higher lows since October 26, rising from $2.497 to $2.839 on November 4, $2.919 on November 5, $2.920 on November 6 and $2.988 on Monday. Each dip has found buyers at a higher level. Monday’s close near the session high and the 43% jump in volume both signal strength. That pattern is typical of a short-covering rally, and it tends to continue until the weather news turns.

The main technical risk is the gap between futures and physical prices. A December contract above $3.20 against spot gas near $2.63 leaves a large premium that must be justified by colder weather. If the market fails to settle above $3.239 this week, the rally will look like a one-day squeeze. A settlement above $3.239 would target $3.33. A settlement above $3.334 would bring $3.40 into play before the December contract expires on November 25.

Technical Map Below: $3.04, $2.92 and the $2.497 Low

The first support level is $3.040, Friday’s intraday high, 5.3% below the current price. Just under it sits $2.998, Friday’s settlement, and $2.988, Monday’s intraday low. Together they form a 5-cent support band. A settlement below $2.988 would erase Monday’s entire gain and signal that the squeeze has failed. That would put short sellers back in control.

Below $2.988, the next support sits at $2.919 to $2.920, the November 5 and 6 intraday lows. That level marks the base of last week’s consolidation, when the front month held between $2.92 and $3.04 for three sessions. A drop to $2.92 would mean a 9.0% decline from current levels. It would likely follow a storage build above 65 Bcf on Friday or a warmer turn in the weather models.

The next level is $2.839, the November 4 intraday low, 11.5% below the current price. That level marks the start of the higher-lows sequence that has supported the rally. Losing $2.839 would break the short-term uptrend and expose the October lows. The front month traded between $2.497 and $2.648 on October 26, the low point of the post-La Niña sell-off. A return to that zone would require the record-warm forecast to hold and storage to keep building above average.

The floor of the 52-week range sits at $2.483, set on April 28. That level marks the spring low, when mild weather and full storage pushed prices down to multi-month lows. A drop to $2.483 from current levels would be a 22.6% decline. That would require a combination of record warmth, large storage builds and a reversal of producer curtailments. It is the bear-case target for December if the winter forecast proves accurate.

The downside map shows where the risk concentrates. The first 5.3% down to $3.04 covers normal volatility after a large up day. The 9.0% drop to $2.92 would need a bearish storage report. The 22.6% drop to $2.483 would need the full Super El Niño scenario to play out. Short sellers have the weather on their side over the full winter. In the short run, they face a market that has just shown it can rally 8% in a day on a modest forecast shift.

Event Risk and the Verdict on Natural Gas Futures

The next two weeks carry the heaviest concentration of risk for the December contract. Daily weather model runs will drive the price through the week, with traders focused on whether this weekend’s cooler shift for the East Coast holds or fades. Friday’s storage report on November 13 covers the week ending November 6, with estimates between 45 and 67 Bcf against a five-year average near 61 Bcf. NOAA’s monthly and seasonal outlooks on November 19 will set the winter narrative. The December contract expires on November 25.

The bullish case rests on positioning and structural demand. Money managers hold a record short of 625,150 contracts in short-only terms, leaving them highly exposed to any cooler forecast. LNG feedgas hit a record 20.4 Bcf/d on Monday, and the November average of 18.9 Bcf/d is the highest ever. Production fell 3.3 Bcf/d to 108.8 Bcf/d last week as Appalachian producers curtail. Storage, at 3,801 Bcf, is only 1.4% above the five-year average and 2.8% below last year. The global price gap of about $25 per MMBtu keeps every US terminal running at capacity.

The bearish case rests on weather and physical prices. The long-range outlook still points to the warmest November and winter on record. Henry Hub spot traded at just $2.63 on November 3, leaving the December contract with a premium above $0.55 that only cold weather can justify. Storage builds have exceeded year-ago levels for three straight weeks, and injections could continue until November 20. Producers will restore curtailed output as soon as prices rise, putting a ceiling on any rally.

The balance favours continued strength in the short term and caution beyond it. Monday’s squeeze has momentum, record LNG demand and falling production behind it. The record-warm winter forecast and weak physical prices limit how far the rally can go before the December contract expires.

The verdict on natural gas futures is bullish in the short term from $3.209, with a target of $3.33 to $3.40. A settlement above Monday’s $3.239 high targets the $3.33 October resistance zone this week. A storage build below 55 Bcf on Friday would extend the move toward $3.40. The $2.988 to $3.040 band is the line that defines the trade. A settlement below $2.988 cancels the squeeze and sends the December contract back toward the $2.92 consolidation floor. Beyond the next two weeks, a warmer November 19 outlook would put $2.839 and the October lows near $2.50 back in focus. The short squeeze can run, but the El Niño forecast still decides where gas trades in December.

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