NG=F ($2.92) Bounces Off $2.80 as Record Shorts Meet a 20.8 Bcf/d LNG Pull — Close Above $3.07 Opens $3.25

U.S. natural gas spent October collapsing and is now trying to build a floor. December futures on the New York Mercantile Exchange, the front-month contract since November expired, rose 6.5 cents, or 2%, to settle at $2.921 per million British thermal units on Tuesday, a rebound driven by a drop in output in recent days. On Wednesday, futures edged up another 1% in early trading on lower production and forecasts for seasonally cooler weather in mid-November, trading in the $2.92 to $2.95 range.

The rebound comes off a deep hole. December futures settled at $3.050 on October 26 and traded as high as $3.386 on October 16. Before that, the contract’s 52-week range ran from $3.305 to $5.074, which means the current $2.92 level sits below the prior 52-week low. The December contract was down 24.1% for the year as of mid-October. Natural gas prices have fallen 4.6% over the past month and 30.9% over the past year.

The spot market has been weaker still. Next-day gas at the Henry Hub in Louisiana fell to $2.52 in mid-October, its lowest level since November 2024, and traded at $2.76 on October 27. Spot weakness reflects a market with ample supply in the producing regions and mild weather limiting demand for heating.

The selloff has been relentless in recent sessions. The front month failed at $3.00 and slid toward $2.86 last week, with technical support at $2.80 and a ceiling near $3.07. The November contract spent five straight sessions in technically oversold territory before expiring in late October, the longest such stretch since April.

The positioning explains the violence. Hedge funds have built a record short position in U.S. natural gas, the biggest on record in more than a decade, betting that prices will keep falling. That positioning is the single most important variable for the next month: a record short in a commodity that responds violently to weather forecasts sets up the conditions for a squeeze.

The forecast runs from one thesis. The supply side is heavy, with output running near record levels and a mild November forecast, but the demand side has a structural pull no previous bear market had: LNG feedgas above 20 Bcf/d at peak, European prices trading 11 times above Henry Hub, and storage that’s only 1% above the five-year average. With funds holding a record short, the $2.80 floor is more likely to hold than break, and any cold shift in the late-November forecasts targets $3.07 first and $3.25 next.

Production: Down to 110 Bcf/d in November From October’s 113.4 Bcf/d

The bullish catalyst behind Tuesday’s rebound is on the supply side. Average gas output in the Lower 48 states fell to 110.0 billion cubic feet per day so far in November, down from 113.4 Bcf/d in October and a monthly record high of 115.0 Bcf/d in August. On a daily basis, output was on track to drop to a five-month low of 108.1 Bcf/d on Tuesday.

That’s a meaningful decline. A drop of 3.4 Bcf/d from October’s average removes the equivalent of roughly 24 Bcf a week from the market, a sizable amount when weekly storage injections run in the 70 to 80 Bcf range. If the decline holds, it tightens the balance at exactly the point the market transitions from injection season to withdrawal season.

The production decline has several plausible drivers. Fall pipeline maintenance typically reduces output in October and November. Producers in the Appalachian Basin, the largest U.S. gas region, have shown sensitivity to low prices, and the slide below $3 reduces the incentive to push volumes. Weather-related disruptions can also curtail output temporarily.

The longer-term supply picture remains heavy. Dry gas production was on pace for a new annual record in 2026, with output averaging roughly 113 Bcf/d in August and September. Averaged across November through March, dry gas production is expected to run 5.4 Bcf/d above the same period a year earlier. That growth is only partly offset by a 2.1 Bcf/d increase in LNG feedgas driven by Plaquemines, Corpus Christi and the ramp of Golden Pass.

That 3.3 Bcf/d net supply surplus is the core bearish argument. Even with record LNG exports, U.S. supply growth is outpacing new demand this winter. It explains why hedge funds built a record short and why prices fell through October despite LNG feedgas hitting records.

Associated gas from oil drilling adds supply that doesn’t respond to gas prices. Permian Basin wells produce gas as a byproduct of oil, and with WTI still above $93 a barrel despite Wednesday’s 3% drop, Permian drillers keep producing regardless of where Henry Hub trades. Falling oil prices could slow that associated gas growth over time, but not this winter.

For the forecast, the production dip is the near-term bullish trigger and the winter supply growth is the medium-term cap. Watch the daily production readings: if output stays below 110 Bcf/d through mid-November, the market can rally toward $3.07 even without help from the weather. If output recovers above 112 Bcf/d, the $2.80 floor comes back under pressure.

LNG Feedgas: A 20.8 Bcf/d Daily Record and the Second-Highest Export Month on Record

Liquefied natural gas exports are the largest source of new demand for U.S. gas, and they’re running at historic levels. Feedgas to U.S. export plants hit a daily record of 20.8 Bcf/d on October 18, passing 20 Bcf/d for the first time a decade after the first Lower 48 LNG cargo shipped from Sabine Pass. Weekly flows have since run between 20.6 and 21 Bcf/d at times, and peak readings touched 21.2 Bcf/d.

The monthly averages are lower but still near records. Average gas flows to the nine major U.S. LNG export plants fell to 17.7 Bcf/d so far in November, down from 18.4 Bcf/d in October and a monthly record of 18.8 Bcf/d in April. The November dip reflects maintenance and cargo timing rather than a demand slowdown, and feedgas is expected to hold near 20 Bcf/d at peak through mid-November.

October was the second-highest export month on record. U.S. LNG exports to Europe rose to 6.89 million metric tons in October, up nearly 1 million tons from 5.91 million in September, as European buyers raced to fill storage ahead of winter. Asian buyers imported 2.73 million tons in October, down slightly from 2.84 million in September. Egypt imported 0.68 million tons, and exports to Latin America rose to 0.68 million tons from 0.53 million. Another 0.59 million tons left U.S. terminals without a final destination.

New capacity keeps arriving. Golden Pass LNG, owned by QatarEnergy and Exxon Mobil, shipped its first cargo on April 22, becoming the ninth U.S. export terminal, and doubled its exports to four cargoes in October. Corpus Christi Stage 3 was completed on August 28, making Corpus Christi the second-largest U.S. terminal. Venture Global’s Plaquemines plant has run at record rates.

The growth trajectory is steep. U.S. LNG exports averaged a record 15.1 Bcf/d in 2025, then 17.4 Bcf/d in the first half of 2026. The Energy Information Administration expects exports to average 17.6 Bcf/d in 2026, up 17% from 2025, and 18.6 Bcf/d in 2027. LNG feedgas now accounts for roughly 14% of total U.S. gas demand including exports, behind only power generation and industry.

The constraint is capacity, not demand. Europe and Asia’s combined demand has risen well above what U.S. plants can supply, which means terminals run at maximum regardless of short-term price swings. That’s a structural floor under Henry Hub: every Bcf/d of LNG capacity added this winter removes supply from the domestic market permanently.

Europe Pays Up: TTF at €103.94, 11 Times Henry Hub

The gap between U.S. and European gas prices has rarely been wider. The Dutch TTF front-month contract, Europe’s benchmark, closed last week at €103.94 per megawatt hour, up €10.15 or 10.8% on the week, after trading between €93.21 and €104.36. TTF has climbed more than 200% this year. At current exchange rates, €101 to €104 equals roughly $33 to $34 per million British thermal units, more than 11 times the Henry Hub price.

Europe has started outbidding Asia. TTF touched €100 on Wednesday of last week and finished about a dollar above JKM, the Asian benchmark, at $34 against $33. A cargo goes to whoever pays the most, and this week that was Europe. TTF closed above JKM on a weekly basis for the first time in at least six months. In October, TTF and JKM averaged $28 per million British thermal units, among their highest levels since the 2022 energy crisis after Russia’s invasion of Ukraine.

The drivers are supply disruptions and low storage. The Iran war cut Qatari LNG supply through the Strait of Hormuz, and Russian pipeline flows to Europe have fallen sharply. European storage sits well below last year’s levels heading into winter. The International Energy Agency’s Global Gas Security Review, released November 3, warned of risks from low gas reserves and unstable global supplies.

Europe’s winter need is large. Cheniere, the largest U.S. LNG exporter, puts Europe’s winter requirement at 69 million tons of LNG just to match last year’s demand and storage levels coming out of winter. U.S. LNG now accounts for 30% of EU gas supply.

The scenarios for TTF are wide. If Hormuz flows normalize by February 2027, European prices could fall toward €32 from 2027. If they don’t, TTF could reach €105 to €120 by year-end, with one risk case at €105. Qatar is mediating between Washington and Tehran, and Brent’s 13% slide over eight sessions shows markets pricing a higher chance of de-escalation.

For Henry Hub, the transatlantic spread matters through one channel: it guarantees that every available U.S. LNG cargo gets sold. With TTF at 11 times Henry Hub, there’s no price at which U.S. terminals would cut output for economic reasons. Feedgas runs at capacity until terminals hit maintenance or physical limits. That locks in roughly 18 to 21 Bcf/d of demand that no domestic weather pattern can remove.

The European crisis can’t lift Henry Hub directly because liquefaction capacity is maxed out. It does put a hard floor under U.S. export demand, and that floor is a key reason the $2.80 level should hold.

Storage: 3,724 Bcf, 1% Above the Five-Year Average but 147 Bcf Below Last Year

The storage picture is less bearish than the price action suggests. The Energy Information Administration reported a net injection of 80 Bcf for the week ending October 23, bringing total working gas in Lower 48 storage to 3,724 Bcf, according to the agency’s weekly storage report. The build exceeded the five-year average change for the week by 3 Bcf, ending ten consecutive weeks of below-average injections.

Inventories stand 38 Bcf, or 1.0%, above the five-year average of 3,686 Bcf, but 147 Bcf, or 3.8%, below year-ago levels. That’s a thin cushion going into winter. The surplus over the five-year average has narrowed sharply this autumn: it stood at 68 Bcf on October 2, shrank to 45 Bcf on October 9, dropped to 35 Bcf on October 16 and recovered only slightly to 38 Bcf on October 23.

The weekly injections have run small. Storage rose 85 Bcf in the week ending October 2 to 3,500 Bcf, then 67 Bcf to 3,567 Bcf in the week ending October 9, against a 90 Bcf five-year average. The week ending October 16 added 77 Bcf to 3,644 Bcf, against an 87 Bcf five-year average. Below-average injections for ten straight weeks show the market has been tighter than prices implied.

Regional data shows the tightness is concentrated. The South Central region, which includes the Gulf Coast storage that feeds LNG terminals, is the only region below its five-year average, holding 110 Bcf less than a year ago and 28 Bcf under the five-year average. Salt-cavern storage, the most flexible inventory in the system and the first to respond to cold snaps, sits 60 Bcf, or 18%, below year-ago levels and 36 Bcf below the five-year average. The Midwest and East hold slightly more than last year, while the Mountain region has a 9.5% year-over-year deficit.

The end-of-season projection is modest. The EIA’s latest Short-Term Energy Outlook estimates storage reached 3,850 Bcf at the end of October, 2% above the five-year average to start the heating season.

The next report lands Thursday at 10:30 a.m. ET and covers the week ending October 30. That week featured milder-than-normal temperatures across key demand regions, which suppressed early heating demand while production held near 110 Bcf/d and LNG feedgas remained elevated. A build at or above the five-year average would extend pressure on prices. A smaller-than-expected build would confirm that LNG demand is absorbing supply faster than the market assumes.

Winter Math: A Five-Year Low by March 2027 if Weather Turns Normal

The end-of-winter projection is where the bull case gets interesting. Analysts estimate U.S. gas storage could end the November 2026 to March 2027 withdrawal season at a five-year low of 1.780 trillion cubic feet on March 31, 2027. That compares with a two-year high of 1.906 Tcf at the end of the 2026 withdrawal season and a five-year average of 1.859 Tcf.

The math is straightforward. Starting the winter with 3,850 Bcf and ending at 1,780 Bcf implies roughly 2,070 Bcf of net withdrawals over five months, more than last winter’s draw despite starting from a lower base. That projection assumes normal weather. A colder-than-normal winter would push end-of-season storage below 1.7 Tcf, territory that historically triggers sharp price spikes.

Last winter showed how quickly that happens. Winter Storm Fern on January 23, 2026 sent Henry Hub spot prices to a record $30.72 per million British thermal units. The storm triggered a record 360 Bcf storage withdrawal in a single week, and LNG feedgas fell as much as 43% as freeze-offs cut supply and terminals reduced intake. A similar event this winter would hit a market starting with 147 Bcf less gas in storage than a year ago.

The supply growth offsets some of that risk. Dry gas production is expected to run 5.4 Bcf/d above last winter on average from November through March, while LNG feedgas grows 2.1 Bcf/d. That 3.3 Bcf/d net surplus works out to roughly 500 Bcf over the winter, which is why analysts’ end-of-season forecasts don’t show a crisis even with higher exports.

The balance is tighter than the headline price suggests. A market starting winter 1% above the five-year average with a 3.8% year-over-year deficit and a salt-cavern shortfall of 18% has little room for a cold surprise. That’s the scenario hedge funds are betting against with their record short.

The curve reflects some of that risk. In mid-October, the January contract traded 44 cents above December, a steep contango that shows the market paying a premium for winter delivery. The December contract expires November 25, and the roll into January will test whether that winter premium holds.

For the forecast, winter math argues against chasing the downside. At $2.92, December gas prices a mild winter with ample supply. Any shift toward normal or colder-than-normal weather would leave storage on track for a five-year low by March, and that’s not a $2.80 market.

Weather: A Mild November, a Weak Polar Vortex and the Late-Month Wildcard

Weather is the swing variable, and the near-term forecast is still bearish. The latest official outlook favors above-normal temperatures across northern areas of the U.S. next week. Forecasters expect El Niño to keep much of the northern U.S. milder than normal through November. That combination limits heating demand at exactly the time the market transitions into withdrawal season.

The longer-range picture has a wildcard. Forecasters are highlighting a major polar vortex disruption that could arrive as early as November 8, potentially the earliest such event on record. Models show the powerful winds circling the Arctic could reverse direction soon, and the vortex is already very weak. When the polar vortex weakens or breaks down, cold air can spill south into North America, sharply increasing heating demand.

The timing matters. Any cold impacts from a polar vortex disruption on the U.S. would likely take several weeks to show up, if they develop at all. That points to late November and early December as the window of risk for short sellers. Speculation about a potential polar vortex disruption has already put bears on notice, with traders warning that a breakdown could bring an Arctic blast into November.

The critical forecast window is November 14 to 28. A decisive cold shift in that period, combined with a below-average storage build and continued record LNG feedgas, would be the trigger for a rally through $3.07. Without a cold shift, the market likely stays capped near $3.00 through mid-month.

Demand projections show how quickly the balance changes when weather turns. In past periods of colder forecasts, average Lower 48 gas demand including exports has jumped by 8 to 10 Bcf/d in a single week, from the 108 to 109 Bcf/d range to 116 to 118 Bcf/d. A shift of that size removes 60 to 70 Bcf a week from the balance, enough to flip a storage injection into a withdrawal.

The asymmetry is the key. A mild November is already in the price at $2.92. Hedge funds hold a record short betting on continued mild weather. If the weather stays mild, prices drift toward $2.80 slowly. If the polar vortex delivers cold air in late November, short covering could drive a move of 15% to 20% in days, as happened in past winters when weather models shifted abruptly.

That asymmetry argues for a bullish tilt despite the bearish near-term forecast. The downside from mild weather is limited by LNG demand and the $2.80 floor. The upside from cold weather is amplified by record short positioning.

Positioning: The Biggest Fund Short in More Than a Decade

Hedge funds have rarely been this bearish on natural gas. Managed money has built a record short position in U.S. natural gas futures, the biggest going back more than a decade, betting that prices will keep falling. In mid-October, funds held a net short of 157,000 contracts, and that position has grown since as prices fell through $3.

The logic behind the trade is clear. Production running near record levels, a mild November forecast, storage above the five-year average and winter supply growth that exceeds new LNG demand all point to lower prices. Funds have ridden the December contract down from $3.386 on October 16 to below $2.90, a 14% decline in less than three weeks.

The risk in the trade is the crowding. When a position becomes the biggest in more than a decade, the exit door narrows. Any catalyst that forces shorts to cover, whether a cold forecast shift, a smaller storage build or a production disruption, can trigger a cascade of buying as funds race to close positions. Natural gas is especially prone to these squeezes because weather forecasts can change dramatically within a single model run.

The November contract offered a preview. During its final days before expiry in late October, the contract traded in technically oversold territory for five straight sessions, the longest stretch since April. After closing at its lowest level since April 28, the low close and the coming expiration prompted some short sellers to take profits, lifting the contract 2% in a single session.

Tuesday’s rebound followed the same pattern. December futures rose 2% on a drop in output, a modest catalyst that produced an outsized move because of short covering. Wednesday’s 1% gain extended it.

Open interest is concentrated in December. The December contract carried 297,314 contracts of open interest in mid-October, against just 27,703 in the expiring November contract. As December approaches its November 25 expiry, funds must either roll their shorts into January, which trades at a premium, or close them. Rolling into a contango curve costs money, which adds pressure on shorts to cover before expiry.

For the forecast, positioning defines the risk-reward. Record shorts in a commodity with weather risk on the horizon create asymmetric upside. The $2.80 floor has held through two tests, and every failed attempt to break it adds to the pressure on short sellers.

Power Burn and Data Centers: The Texas Moratorium and the AI Demand Story

Power generation is the largest source of U.S. gas demand, and its outlook shifted on Tuesday night. Democrat Gina Hinojosa won the Texas governor’s race on a pledge to impose an immediate moratorium on new data centers until the legislature writes protections. Texas holds an estimated 27% of planned U.S. data-center capacity, and in Georgia, the incoming governor has backed a temporary statewide pause. Two dozen of 41 local data-center ballot measures across 10 states appeared to pass in early returns.

That matters for gas because data centers have become the fastest-growing source of new electricity demand in the U.S., and natural gas supplies the largest share of new power generation built to serve them. The data-center buildout has been a key pillar of the bullish long-term case for Henry Hub, with forecasters projecting several Bcf/d of new gas demand from AI-related power by the end of the decade.

The near-term impact is limited. A moratorium on new data centers doesn’t affect facilities already operating or under construction, and gas burn for existing data centers continues regardless. The election didn’t enact any permit rule; a governor-elect needs a legislature, and moratoriums take time to implement.

The long-term impact is real. If Texas and Georgia slow data-center construction, the gas demand projected for 2028 and beyond shrinks. That weighs on deferred contracts more than the December contract, flattening the forward curve and reducing the long-term premium producers can lock in through hedging.

Power burn has already been soft this autumn. Total natural gas demand dipped from 107 Bcf/d to 104 Bcf/d in late October, with power burn demand falling 4.0 Bcf/d as cooling needs faded and heating hadn’t yet kicked in. Residential and commercial heating demand rose 1.0 Bcf/d over the same period.

The Democratic Congress adds policy uncertainty for gas more broadly. A Democratic majority is less likely to support expanded federal leasing or pipeline permitting reform. The LNG export approval process runs through the Department of Energy, where the permitting pause was lifted on January 21, 2025, opening the door to a record year of final investment decisions. Congressional oversight could add scrutiny to new approvals, but projects already under construction will proceed.

For the December contract, the data-center story is background noise. Weather, production and LNG feedgas will drive prices through year-end. For producers and investors with longer horizons, the election introduced a new risk to the demand growth that justified much of the sector’s capital spending.

Producers and LNG Exporters: EQT, Expand, Coterra and Cheniere at $2.92 Gas

Gas producers have felt the price slide most directly. At $2.92 for December delivery, Henry Hub sits near the breakeven level for higher-cost wells and well below the levels producers used to justify drilling plans for 2026. Appalachian producers, led by EQT, carry some of the lowest costs in the industry, but their realized prices sit below Henry Hub because of pipeline constraints out of the region.

The production decline in November suggests producers are responding. Output fell from 113.4 Bcf/d in October to 110.0 Bcf/d in November, with daily readings down to a five-month low of 108.1 Bcf/d. Some of that reflects maintenance, but sustained prices below $3 tend to prompt producers to curtail volumes or defer turning wells online until prices recover.

Hedging cushions the blow. Large producers like EQT, Expand Energy and Coterra typically hedge a significant share of their next-year production, locking in prices well above current spot levels. The steep contango in the curve, with January trading 44 cents above December in mid-October, lets producers sell winter and 2027 production at higher prices than the prompt month.

LNG exporters sit on the opposite side of the trade. Cheniere, the largest U.S. LNG exporter, buys gas at Henry Hub prices and sells liquefied cargoes linked to global benchmarks. With TTF at €103.94, equivalent to $33 to $34 per million British thermal units, and Henry Hub below $3, the spread is among the widest in history. Cheniere’s long-term contracts capture most of that spread through fixed liquefaction fees, while its spot cargoes earn windfall margins.

The ProShares and United States Commodity Funds products offer direct exposure. The United States Natural Gas Fund (UNG) tracks front-month futures and carries the cost of rolling contracts in a contango curve. The leveraged BOIL and inverse KOLD funds amplify daily moves, making them popular trading vehicles during weather-driven swings but poor long-term holdings because of decay.

The energy sector has lagged. S&P 500 energy stocks fell 0.85% on Tuesday, and the Democratic sweep added rotation pressure on fossil fuel names as solar stocks rallied 8% on Wednesday. Gas producers face both lower commodity prices and a less favorable political backdrop.

For equity investors, the gas price matters more than politics in the near term. A rally to $3.25 on a cold forecast would lift producer shares sharply, while a break below $2.80 would extend their slide.

The Technical Map: $2.80 Floor, $3.00 Pivot, $3.07 Ceiling and $3.25 Above

December natural gas futures sit in a defined range after the October collapse. The contract settled at $2.921 on Tuesday and traded in the $2.92 to $2.95 range on Wednesday. Support at $2.80 has held through recent tests, and a floor near $2.80 is what buyers are trying to establish. Resistance at $3.00 is the pivot, and the ceiling sits at $3.07, a level the contract failed to clear in late October.

The range structure is clear. December traded as high as $3.386 on October 16, then fell to $3.050 by October 26 and slid below $3.00 into the $2.86 area last week. The contract’s prior 52-week range ran from $3.305 to $5.074, so the current level marks a new low for the contract’s history. A range between $2.85 and $3.25 has framed recent trading.

Momentum is oversold. The expiring November contract spent five straight sessions in technically oversold territory in late October, the longest stretch since April. December’s 2% gain on Tuesday and 1% gain on Wednesday are the first signs of momentum turning, though technical signals on the daily chart still lean toward selling.

The volatility-based range is wide. Current volatility implies a range of $2.40 to $2.92 on the downside and a broader short-term target band of $2.50 to $3.39. Natural gas regularly moves 3% to 5% in a single session on weather model shifts, so stops placed within 10 cents of the current price will get hit on noise.

The resistance stack above the current price runs $3.00, $3.050 (the October 26 settlement), $3.07 (the late-October ceiling), $3.25 (the top of the recent range) and $3.386 (the October 16 high). A close above $3.07 would confirm a short squeeze and open a path to $3.25.

Support below runs $2.86 (last week’s low area), $2.80 (the floor), $2.52 (the Henry Hub spot low from mid-October) and $2.50 (the lower bound of the short-term target band). A close below $2.80 would signal that the record short has more room to run and put $2.50 in play.

The risk-reward favors the upside from current levels. From $2.92, the distance to $3.07 is 15 cents, a 5.1% gain, and to $3.25 is 33 cents, an 11.3% gain. The distance to $2.80 is 12 cents, a 4.1% drop. With a record short base and a polar vortex risk on the horizon, the upside move is more likely to be fast and the downside move more likely to be slow.

The Catalyst Calendar: Thursday’s Storage Report, Weather Models and the November 25 Expiry

Natural gas faces a run of catalysts that will decide whether the $2.80 floor holds. Thursday’s EIA storage report at 10:30 a.m. ET covers the week ending October 30, a mild week with suppressed heating demand. A build at or above the five-year average would pressure prices back toward $2.86. A build below expectations would confirm that LNG exports are absorbing supply faster than production can replace it and trigger short covering toward $3.00.

Daily weather model runs are the most important ongoing catalyst. The November 14 to 28 forecast window is where a cold shift would matter most. Any model run showing a polar vortex disruption bringing Arctic air into the central and eastern U.S. in late November would spark aggressive covering from the record short position.

Production readings matter daily. Output on track for a five-month low of 108.1 Bcf/d on Tuesday was the catalyst for the rebound. If daily production stays below 110 Bcf/d, the market has a fundamental reason to rally. If it bounces back above 112 Bcf/d, the bearish supply narrative returns.

LNG feedgas data tracks the demand floor. Feedgas averaged 17.7 Bcf/d in November so far, down from 18.4 Bcf/d in October. A return toward the 20 to 21 Bcf/d peaks recorded in October would add 2 to 3 Bcf/d of demand and tighten the balance significantly.

The December contract expires November 25. As expiry approaches, funds holding the record short must either roll into January, which trades at a premium, or close their positions. That roll pressure typically produces volatility in the final week of trading.

The Iran mediation track affects global gas prices. A U.S.-Iran deal that reopens Strait of Hormuz flows would restore Qatari LNG supply to Europe and Asia, pushing TTF lower. That wouldn’t reduce U.S. LNG exports, which run at capacity, but it would narrow the transatlantic spread and weigh on sentiment. A breakdown in talks would push TTF toward €105 to €120.

The macro calendar affects energy broadly. Friday’s U.S. jobs report and the November 10 CPI release set Fed expectations, and the December 8 to 9 Fed meeting caps the period. Natural gas is less sensitive to rates than oil, but a stronger dollar typically weighs on all commodities.

Natural Gas Price Forecast: $2.80 Floor, $3.07 First Target, $3.25 on a Cold Shift

December natural gas futures settled at $2.921 on Tuesday, up 2%, and edged another 1% higher on Wednesday as output fell to 110.0 Bcf/d in November from 113.4 Bcf/d in October. The rebound comes after a 14% slide from the October 16 high of $3.386 and leaves the contract below its prior 52-week low of $3.305.

The bear case has driven prices all autumn. Production ran near record levels, with winter output expected 5.4 Bcf/d above last year against just 2.1 Bcf/d of LNG feedgas growth. Storage stands at 3,724 Bcf, 1.0% above the five-year average. The near-term weather forecast favors above-normal temperatures across the northern U.S., and El Niño is expected to keep November mild. Hedge funds hold their biggest short in more than a decade.

The bull case is building underneath. LNG feedgas hit a record 20.8 Bcf/d in October, and exports to Europe jumped to 6.89 million tons as TTF climbed to €103.94, 11 times Henry Hub. Storage sits 147 Bcf below last year, with South Central inventories and salt caverns well below normal. Analysts project end-of-winter storage at a five-year low of 1.780 Tcf by March 2027 if weather turns normal. A weak polar vortex threatens to bring cold air into the U.S. in late November.

The forecast sets clear levels. The near-term bias is cautiously bullish above $2.80 on a closing basis. The first target is $3.07, the late-October ceiling, a 5.1% gain from $2.92. A close above $3.07 confirms a short squeeze and opens $3.25, an 11.3% gain. Above $3.25, the $3.386 October high comes into play. Support sits at $2.86 and $2.80. A close below $2.80 would extend the bear trend toward $2.52 and $2.50.

The catalysts line up over the next three weeks. Thursday’s storage report, the November 14 to 28 weather window and the November 25 December contract expiry will decide direction.

The verdict: cautiously bullish with a $2.80 floor. The mild November is in the price, LNG demand locks in 18 to 21 Bcf/d of exports no domestic weather can remove, and the largest fund short in more than a decade turns any cold shift into a squeeze. Hold $2.80 through Thursday’s storage report, and the path to $3.07 opens before the December contract expires, with a late-November polar vortex event the trigger that could carry Henry Hub through $3.25.

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