NG ($2.829) Drops 7.5% in Two Sessions While TTF Holds $29 — Winter Strip Keeps a 35-Cent Premium

November Henry Hub natural gas futures traded at $2.829 per million British thermal units around noon ET on Wednesday, October 21, 2026, down 13.4 cents or 4.5% on the session. The move extends a two-day slide that began on Tuesday, when the prompt contract tested below $3.00 in early trading and settled at $2.963, down 3.1% from Monday’s $3.058 settle. That Tuesday close was the first sub-$3 settlement in more than two weeks. Across two sessions, the contract has dropped 22.9 cents, or 7.5%.

The selling reflects weather, not supply. Forecasts call for mild temperatures through late October, limiting both heating and cooling demand, and warm November outlooks pushed the market toward expectations that storage injections could continue well into November. Physical Henry Hub spot gas traded at $2.85 earlier in the day, in line with futures. Natural gas is down 4.2% over the past month and 17.6% from a year ago.

The decline comes against a striking global backdrop. Dutch TTF gas, Europe’s benchmark, traded near €88 per megawatt-hour, or $29 per MMBtu, on October 19, its highest level in nearly four years. Asian spot LNG reached $26.39 per MMBtu. The war with Iran has cut LNG flows through the Strait of Hormuz by 80%, and Qatar shipped less than a quarter of its prewar volume in September. U.S. gas at $2.829 trades at roughly one-tenth of the European price.

This forecast runs on one thesis. Henry Hub cannot capture the global gas crisis because U.S. LNG export plants are already running near their maximum, so the $26 spread between Europe and Louisiana cannot pull more American gas overseas. That leaves U.S. prices driven by domestic weather and storage. Mild weather is pushing the November contract down, but the storage picture is tightening underneath: the surplus to the five-year average has shrunk from 2.0% to 1.3% in a week, production has fallen 2.5 billion cubic feet per day from its August and September records, and the government’s October storage target looks hard to reach. Near term, November can trade between $2.75 and $3.10 on weather. The winter strip carries a premium that rewards the first cold forecast.

The November contract expires in late October, which concentrates weather risk into the final week of trading. A shift to colder forecasts for early November would produce a sharp short-covering rally. Continued mild forecasts would keep pressure on prompt prices while the December contract, which carries a premium of 35 cents or more, holds up better.

Two Weeks of Weather-Driven Selling: From $3.30 to $2.829

The November contract traded near $3.30 through much of September and early October before the weather shifted. On October 1, it settled at $2.967, briefly below $3, as mild autumn weather and soft seasonal demand outweighed tighter supply. It recovered and gained 6% in the week ended October 9, helped by a smaller-than-expected storage injection.

The reversal began last week. On Thursday, October 15, November futures surrendered most of an early advance as Appalachian cash prices plunged amid a major pipeline outage and winter contracts faced mounting selling. On Friday, October 16, futures fell 12 cents, or 4%, to settle at $3.116, the lowest close since October 6, on mild weather, lower demand forecasts and a small increase in output. The contract finished that week down 3% after the prior week’s 6% gain.

The selling accelerated this week. On Monday, October 19, November traded 4.9 cents lower to $3.07 during the session as forecasts for milder October weather reduced heating demand expectations, outweighing below-expected storage builds, strong LNG demand and lower domestic output. It settled at $3.058. On Tuesday, strong production signals and benign shoulder-season forecasts pushed the contract below $3 in early trade, and it settled at $2.963. Wednesday’s drop to $2.829 extended the slide.

From the $3.30 area in September, the contract has fallen 14%. From the October 16 settle of $3.116, it has lost 9.2%. The $2.829 level sits below the October 1 settle of $2.967 and marks the lowest prompt-month price since September.

Prices have moved up and down with each weather forecast update. Shoulder season, the period between summer cooling demand and winter heating demand, typically produces this kind of chop because neither demand driver is fully active. In late October, small changes in forecast temperatures for the first two weeks of November can swing heating demand estimates by several billion cubic feet per day, and the prompt contract reacts to each revision.

The spot market is diverging by region. Natural gas spot prices strengthened across Appalachia and the Northeast on Tuesday even as futures fell, and Northeast spot prices at Tennessee Zone 4, Columbia Gas and Algonquin Citygate have traded below Henry Hub through October. A major Columbia Gas Transmission pipeline restriction remained in effect in Appalachia last week, which disrupted regional flows and weighed on local cash prices before they recovered.

Storage: 3,567 Bcf, Surplus Narrowed to 45 Bcf or 1.3%

The government’s storage data shows supply tightening even as prices fall. The EIA Weekly Natural Gas Storage Report for the week ending October 9 showed a 67 billion cubic foot injection, below a consensus range of 73 to 77 Bcf and 23 Bcf below the five-year average of 90 Bcf for that week. Total working gas in Lower 48 storage rose to 3,567 Bcf. Stocks stood 143 Bcf below the same week in 2025 and 45 Bcf above the five-year average of 3,522 Bcf. That surplus narrowed from 2.0% the prior week to 1.3%.

The 67 Bcf print was the third straight bullish surprise. For the week ending October 2, the EIA reported an 85 Bcf injection that topped expectations but fell short of historical norms, lifting inventories to 3,500 Bcf, 68 Bcf above the five-year average and 130 Bcf below a year earlier. For the week ending September 25, the injection was 64 Bcf against a five-year average of 80 Bcf, leaving stocks at 3,415 Bcf. Futures jumped 37 ticks on the October 15 release.

The South Central region shows the tightest conditions. Salt cavern storage, which can inject and withdraw quickly and serves Gulf Coast LNG plants and industrial users, held 236 Bcf for the week ending October 9, down 21.9% from a year earlier and 15.4% below the five-year average. Nonsalt storage in the region stood at 861 Bcf, down 6.0% year over year and 0.9% below average. South Central inventories remain below both year-ago levels and the five-year average, reflecting demand pressure from LNG exports.

The October storage target looks difficult to reach. The EIA’s October Short-Term Energy Outlook forecast inventories would reach 3,850 Bcf at the end of October, 2% above the five-year average to start the heating season on November 1. From 3,567 Bcf on October 9, reaching 3,850 Bcf requires 283 Bcf of injections over the three weeks through October 30, or 94 Bcf per week. Recent weekly injections have run between 64 and 85 Bcf. If injections continue at that pace, end-October storage would land closer to 3,780 to 3,800 Bcf, below the government forecast and roughly in line with the five-year average rather than 2% above it.

The next storage report arrives Thursday, October 22, covering the week ending October 16. Mild weather during that week likely produced a larger injection than in prior weeks, which would weigh on prices if it exceeds expectations. A third straight below-average build would narrow the surplus further toward zero.

Production: Down 2.5 Bcf/d From the 113.3 Bcf/d Record

Domestic output has fallen from record levels, which supports the storage tightening. Average gas production in the Lower 48 states slid from record highs of 113.3 billion cubic feet per day in August and September to 110.8 to 111.3 bcfd so far in October. That is a decline of up to 2.5 bcfd, or 2.2%, a significant reduction in daily supply.

Several factors drove the drop. Hurricane Isaias forced shut-ins in the Gulf of Mexico. Force majeure incidents and other problems hit pipelines in Kentucky, Texas, West Virginia and elsewhere in recent weeks. The Columbia Gas Transmission restriction in Appalachia constrained flows from the largest U.S. producing region. Some producers may also be curtailing output in response to prices below $3, which squeeze margins in higher-cost basins.

Production is recovering at the margin. October’s average was slightly higher on Friday than on Thursday, and hints of higher production sent prices tumbling on Monday. Production headlines have become a direct price driver: any sign that output is returning toward 113 bcfd adds supply that would push injections higher and pressure prices.

The supply response matters for the winter outlook. If production stays near 111 bcfd through November while LNG exports run at 18 bcfd or more, storage withdrawals would begin earlier and run larger once heating demand arrives. If production returns to 113 bcfd, the extra 2 bcfd would add 14 Bcf per week to supply, enough to keep injections running into November even with modest heating demand.

Price signals are working against a rapid recovery. With November futures below $3 and the 2027 government forecast at $3.16, producers have less incentive to bring shut-in volumes back quickly or add new drilling. Associated gas from oil wells offers one source of growth: with WTI crude near $98, oil-focused producers in the Permian Basin and elsewhere have strong incentives to drill, and their wells produce gas as a byproduct regardless of gas prices. That associated gas puts a floor under production even when Henry Hub is weak.

For prices, the production picture is mildly bullish. Output 2.5 bcfd below record levels, combined with record export demand, is the main reason storage injections have run below average for three weeks. A sustained recovery to 113 bcfd would remove that support.

LNG Feedgas: 18.1 Bcf/d in October, Little Spare Capacity

U.S. LNG exports are running near maximum capacity. Average gas flows to the nine major U.S. LNG export plants reached 18.1 bcfd so far in October, up from 17.9 bcfd in September and just below the monthly record of 18.8 bcfd set in April. Daily feedgas reached a five-month high of 18.9 bcfd on October 16. Sabine Pass flows hit 4.8 bcfd, and Golden Pass feedgas reached a record 0.7 bcfd as the new plant ramped up.

Gulf Coast LNG feedgas demand at record highs, combined with pipeline constraints, has pushed Henry Hub physical prices above futures at times this month. The export plants draw directly from Gulf Coast supply, which explains why South Central salt storage sits 15.4% below its five-year average.

The key point for prices is that U.S. export capacity has little room to grow in the near term. With feedgas at 18.1 to 18.9 bcfd against a record of 18.8 bcfd, the plants are running close to their limits. That means the enormous price gap between U.S. and global gas cannot be arbitraged away. At $29 TTF and $2.829 Henry Hub, the spread is $26 per MMBtu, far more than the $3 to $5 cost of liquefying, shipping and regasifying a cargo. In a market with spare export capacity, that spread would pull every available molecule overseas and drive Henry Hub sharply higher. With no spare capacity, it simply widens.

New capacity is coming. Golden Pass is ramping up, and additional plants under construction will add export capacity over 2026 and 2027. Each new train lifts the ceiling on U.S. exports and links Henry Hub more closely to global prices. Over the medium term, that is the structural bullish case for U.S. gas: as export capacity grows, more of the global premium flows back to Henry Hub.

In the near term, LNG demand provides a floor rather than a driver. Export plants will take 18 bcfd or more regardless of whether Henry Hub trades at $2.80 or $3.30, because their contracts and the global spread make every cargo profitable. That steady demand absorbs a large share of U.S. production and limits how far storage can build, but it cannot push prices higher because it cannot grow.

The government’s outlook reflects that balance. Production growth is supplying increases in LNG exports and domestic demand, which keeps inventories near or above the five-year average and limits upward price pressure.

Europe’s Crisis: TTF at €88, Storage at 74.6%, Qatar Down 75%

The global gas market is in a supply crisis centered on the Strait of Hormuz. Since the U.S.-Israeli strikes on Iran on February 28, LNG traffic through the strait has collapsed. The strait handled 20% of global LNG trade before the war, almost entirely from Qatar and the UAE. By October, commercial tanker transit through Hormuz had fallen 80% below normal levels. QatarEnergy declared force majeure on deliveries through December 2026.

Qatar’s exports show the scale. Qatar shipped 1.6 million tonnes of LNG in September, less than a quarter of its prewar average, and October shipments are expected near 0.6 million tonnes. Qatar extended its force majeure in late August, canceling five cargoes through early November for Italian utility Edison. Any return of Qatari LNG before winter is no longer possible.

Europe enters winter with depleted storage. EU underground gas storage stood at 74.6% of capacity on October 18, against a five-year seasonal average of 89% and the EU’s 90% target. German storage was particularly low at 61%. EU storage is lower than in any October since records began in 2011. On October 2, storage stood at 71.5% against 82.6% a year earlier.

Prices reflect that scarcity. Dutch TTF futures traded around €88 per megawatt-hour, or $29 per MMBtu, on October 19, the highest in nearly four years. TTF first broke above €70 in September and reached €73.67 that month. Asian spot LNG rose to $26.39 per MMBtu as TTF held near $28.59 in mid-October, with the Asian-European spread flipping to a $2.21 discount as Atlantic cargoes competed for both markets.

Policy responses are under discussion. EU energy ministers meet in Luxembourg on October 29 to consider whether the bloc needs coordinated cuts in gas demand if Hormuz stays shut. The EU’s ban on Russian LNG takes full effect on January 1, in the middle of the heating season, which removes another supply source.

For Henry Hub, Europe’s crisis is mostly irrelevant in the short term because export capacity is full. Its importance lies in two areas. First, it guarantees that every U.S. LNG cargo finds a buyer at a premium, which keeps feedgas at maximum. Second, it raises the stakes on U.S. weather: a cold U.S. winter that forced exporters to compete with domestic heating demand for the same Gulf Coast gas would tighten U.S. markets faster than in normal years.

Weather: Mild October, Warm November Outlook, and the Winter Question

Weather is the dominant driver of Henry Hub in late October, and current forecasts are bearish. Mild temperatures through late October are limiting both heating and cooling demand. Warm forecasts for November pushed U.S. gas to a two-week low on Tuesday. Expectations that storage injections could continue well into November, rather than turning to withdrawals as heating demand arrives, have weighed on the November contract.

Demand forecasts have shifted with each update. As of October 16, LSEG forecast U.S. gas demand, including exports, rising from 103.87 bcfd that week to 106.8 bcfd over the following two weeks. Weather-driven gas demand recovered moderately for weeks two and three of the forecast period at one point, narrowing projected storage builds into the end of the injection season. Those forecasts have since turned milder.

The winter outlook is mixed. Some forecasters expect an El Niño pattern this winter, which typically brings milder weather to parts of the northern United States and could reduce heating demand. Europe’s weather outlook is also warmer than normal, which would ease pressure on depleted storage there. But short-lived cold spells could still create peaks in electricity and gas demand on both continents, and with storage thin, those peaks would produce sharp price spikes.

The calendar matters for the November contract. November futures expire in late October, and the contract’s final days will trade almost entirely on forecasts for the first two weeks of November. A shift toward colder forecasts in that window would force short sellers to cover, since the contract would settle against physical delivery during a period of rising demand. A continued mild outlook would let November expire near its lows.

The winter contracts trade on a longer horizon. December through February futures, the heart of winter, have followed the prompt contract lower but carry a premium. On Monday, December futures traded at $3.411 in early trading, against a November settle of $3.058, a spread of 35 cents. That contango reflects the market’s expectation that heating demand will lift prices once withdrawals begin.

Weather forecasts are the main reason the November contract is the weakest point on the curve. A single cold forecast for mid-November would likely narrow the November-December spread sharply as November rallies toward December.

The Futures Curve: December at a 35-Cent Premium, 52-Week Range $3.305 to $5.074

The shape of the futures curve tells a clearer story than the prompt price. The December 2026 contract traded at $3.411 per MMBtu on Monday, October 19, with a session range of $3.311 to $3.411 and a prior settle of $3.386. Its 30-day range runs from $3.234 to $3.709. December fell 2.7% in the week to October 19 but was up 0.5% over the month. Open interest stood at 247,930 contracts.

The December contract’s 52-week range runs from $3.305, set on October 1, to $5.074, set on January 30. At $3.411 on Monday, December sat 32.8% below its 52-week high and 3.2% above its low. Wednesday’s selloff likely pushed December closer to that $3.305 low. A break below it would mark a new low for the winter contract and signal the market is pricing a mild winter.

The January peak shows how high winter prices can go. Henry Hub spot averaged $7.72 per MMBtu in January 2026, a winter spike that then collapsed to $3.62 in February and $3.04 in March. Monthly spot averages since then have stayed in a tight range: $2.77 in April, $2.94 in May, $3.15 in June, $2.89 in July, $2.78 in August and $2.95 in September.

The current spot price of $2.85 sits inside that range. The futures market expects a modest winter premium rather than a repeat of January’s spike, with December near $3.30 to $3.40 and the government’s Q4 forecast at $3.30.

The contango between November and December has trading implications. Holders of storage can buy November gas, inject it, and sell December forward at a 35-cent premium, locking in a profit that covers storage costs. That trade adds demand for prompt gas and supports November against further declines. It also means that as long as storage capacity is available, the November contract has a soft floor tied to the December price minus storage costs.

The longer curve shows prices largely above $3 through 2036, with seasonal winter peaks. That structure reflects the market’s view that LNG export growth will tighten the U.S. balance over time. For the near term, the curve says the market sees today’s sub-$3 prices as a weather-driven dip rather than a structural shift.

Forecasts: EIA Sees $3.30 for Q4, $3.48 for 2026, $3.16 for 2027

Official forecasts sit well above current prices. The EIA’s October Short-Term Energy Outlook, released October 6, expects the Henry Hub spot price to average $3.48 per MMBtu in 2026 and $3.16 in 2027, a decline of 32 cents or 9%. The outlook puts the fourth quarter of 2026 at $3.30 and the first quarter of 2027 at $3.47 as heating demand picks up.

At $2.829, November futures trade 14% below the EIA’s fourth-quarter forecast. For the quarter to average $3.30, prices would need to rise meaningfully in November and December. The EIA’s forecast assumes inventories reach 3,850 Bcf by the end of October, a level that now looks hard to reach given recent injection rates. If storage ends October closer to 3,780 Bcf, the starting cushion for winter would be thinner than the EIA assumed, which would support prices once withdrawals begin.

The EIA sees ample inventories as the main cap on prices. Inventories remain above the rolling five-year average in most months of its forecast as production growth supplies rising LNG exports and domestic demand. The EIA Administrator said relatively high inventories entering winter provide a cushion for heating demand.

The International Monetary Fund’s October World Economic Outlook, which uses futures prices, assumes Henry Hub at $3.10 for 2026, rising to $3.60 by 2031. Other projections place November near $3.15, December near $3.27, January 2027 near $3.43 and December 2027 near $3.65.

The gap between forecasts and the current prompt price reflects timing. Forecasters model averages over months and quarters, which smooth out short-term weather swings. The November contract is trading on forecasts for the next two to three weeks, which are mild. If those forecasts turn colder, prices could close the gap with official forecasts quickly.

The 2027 forecast decline reflects production growth outpacing new LNG demand. That view assumes Hormuz remains disrupted only through mid-2027 and that U.S. production returns to record levels. A faster reopening of Hormuz would reduce global prices and ease pressure on U.S. exports. A longer disruption would keep U.S. LNG at maximum and support Henry Hub.

Oil-Gas Ratio at 34.5: Gas Cheap Against Crude

U.S. natural gas has rarely been cheaper relative to crude oil. With WTI crude at $97.72 per barrel and November gas at $2.829 per MMBtu, the oil-to-gas price ratio stands at 34.5 to 1. On an energy-equivalent basis, a barrel of oil contains roughly six times the energy of an MMBtu of gas, which means a ratio near 6 would represent parity. At 34.5, gas is trading at a deep discount to oil on an energy basis.

That discount reflects the U.S. gas market’s isolation. Oil trades as a global commodity, and Brent at $109.04 carries the war-risk premium from Hormuz. U.S. gas cannot fully access global markets because export capacity is limited, so it trades on domestic supply and demand. The oil shock has lifted crude while U.S. gas has fallen.

High oil prices affect gas supply through associated gas. Oil-focused producers in the Permian Basin and other shale regions produce gas as a byproduct, and with WTI near $98, they have strong incentives to drill. That associated gas adds supply regardless of Henry Hub prices, which helps explain why U.S. production reached records of 113.3 bcfd in August and September even as gas prices traded below $3.

The ratio also affects demand. Industrial users and power generators that can switch between oil and gas favor gas when it is this cheap. Power generation is the largest swing source of gas demand outside heating, and cheap gas keeps gas-fired plants dispatching ahead of coal and oil units. That supports gas demand during mild weather when heating demand is low.

Europe shows the opposite picture. TTF at $29 per MMBtu against Brent at $109 per barrel puts the European oil-to-gas ratio near 3.8, meaning gas is expensive relative to oil on an energy basis. The contrast between a U.S. ratio of 34.5 and a European ratio of 3.8 captures how differently the two markets have experienced the Hormuz crisis.

For Henry Hub, the oil-gas ratio is a medium-term support. As new LNG export capacity comes online, the extreme discount will narrow as more U.S. gas reaches global markets. Until then, cheap gas against expensive oil encourages demand and associated supply in roughly equal measure.

Technical Levels: $2.75 Support, $3.00 Pivot, $3.116 and $3.30 Resistance

The level map around $2.829 is defined by recent settles and the psychological $3.00 mark. The first resistance is $2.963, Tuesday’s settle. Above it, $3.00 is the round number that held as support through much of October before breaking on Tuesday. Reclaiming $3.00 would signal the weather-driven selloff has run its course. The next resistance is $3.058, Monday’s settle, followed by $3.10 to $3.116, the October 16 settle and the level where the contract traded on Friday. The $3.30 area, where the contract traded through September and early October, is the upper resistance.

On the downside, the first support sits near $2.80, a round number just below Wednesday’s level. Below it, $2.75 marks the area near August’s $2.78 spot average and April’s $2.77 spot average, the lowest monthly averages of 2026. A break below $2.75 would put the prompt contract at its weakest level of the year outside of extreme events.

Distances from $2.829 define the risk. The upside to $3.00 is 6.0%, to $3.116 is 10.1%, and to $3.30 is 16.6%. The downside to $2.80 is 1.0%, and to $2.75 is 2.8%.

For the December contract, the key level is $3.305, its 52-week low from October 1. December traded at $3.411 on Monday and likely moved closer to that low on Wednesday. Resistance sits at $3.506, the October 12 level, and $3.688 to $3.709, the top of the 30-day range.

Momentum favors sellers in the near term. The prompt contract has fallen in four of the last five sessions and broken below $3.00, a level that had held through multiple tests. Weather forecasts are the only catalyst that can quickly reverse that momentum. A storage injection below expectations on Thursday would offer support, as the 67 Bcf print did on October 15 when futures jumped 37 ticks.

The technical picture for November is bearish below $3.00 and neutral above it. For December, a hold above $3.305 keeps the winter premium intact. A break below $3.305 would signal the market is pricing a mild winter across the curve.

Catalysts: EIA Storage Thursday, November Expiry, EU Ministers October 29

The next storage report arrives Thursday, October 22, at 10:30 a.m. ET, covering the week ending October 16. Mild weather during that week likely produced a larger injection than the 67 Bcf in the prior week. An injection near the five-year average, typically 80 to 90 Bcf for mid-October, would stabilize the surplus near 1.3%. An injection above 90 Bcf would push the surplus higher and add to selling pressure. A third straight below-average build would narrow the surplus toward zero and support a rebound.

Weather model updates over the next week will drive the November contract into expiry. Forecasts for the first two weeks of November matter most. A colder shift would trigger short covering in a contract that has fallen 7.5% in two sessions. A continued mild outlook would let November expire near current levels.

Production data will be watched daily. Signs that output is recovering toward the 113.3 bcfd record would add supply and pressure prices. Continued output near 110.8 to 111.3 bcfd, as pipeline issues persist, would keep injections below average.

LNG feedgas flows will confirm export demand. Flows near 18.9 bcfd, the five-month high reached October 16, would show exports running at maximum. Any outage at a major plant would reduce demand and add supply to the domestic market, which would be bearish.

Global events add tail risk. EU energy ministers meet on October 29 to discuss coordinated demand cuts if Hormuz stays shut. Any escalation in Hormuz that further restricts Qatari LNG would lift TTF and Asian prices but would affect Henry Hub only through sentiment, since U.S. export capacity is already full. A diplomatic breakthrough that reopened Hormuz would lower global prices but would also leave U.S. exports at maximum, so the direct Henry Hub effect would be limited.

The Federal Reserve meets October 27 to 28 and EIA’s next Short-Term Energy Outlook arrives in early November. A downward revision to the end-October storage forecast would validate the tightening thesis.

Forecast Scenarios: $3.30 Upside, $2.70 Downside, $3.00 Pivot

The base case is a range between $2.75 and $3.10 for the November contract into its late-October expiry. Mild weather keeps pressure on prompt prices, while a narrowing storage surplus, production 2.5 bcfd below records, and LNG feedgas near maximum limit the downside. Within that range, the November-December spread of 35 cents or more gives storage operators an incentive to buy prompt gas, which supports November near $2.80. The December contract is likely to hold between $3.25 and $3.50, preserving the winter premium.

The bullish scenario needs a weather shift. A colder forecast for the first half of November, combined with a below-average storage injection on Thursday, would push November back above $3.00, 6.0% higher, and toward $3.116, 10.1% higher. If the cold outlook persists and storage ends October near 3,780 Bcf rather than the EIA’s 3,850 Bcf forecast, the winter strip would reprice higher, with December testing $3.50 to $3.70 and the prompt contract reaching $3.30, 16.6% above current levels. A production outage or further pipeline force majeure would add to the move.

The bearish scenario extends the current pattern. Continued mild forecasts through mid-November, a storage injection above 90 Bcf on Thursday, and a production recovery toward 113 bcfd would push November below $2.80 and toward $2.75, then $2.70, 4.6% below current levels. December would break its $3.305 low and test $3.20. That scenario would reflect a market pricing an El Niño winter with ample supply.

The probability weighting favors the range with a modest upward bias into winter. The storage arithmetic points to an end-October level below the EIA forecast, and production has not recovered. Weather is the swing factor, and late-October forecasts often shift quickly as the season changes. The November contract carries the most weather risk and the most potential for a sharp short-covering rally.

Verdict: Bearish Near Term Below $3.00, Bullish on the Winter Strip

November natural gas futures at $2.829 are bearish in the near term below $3.00, while the winter strip carries a bullish bias. The prompt contract has fallen 7.5% in two sessions and 14% from its September levels on mild weather forecasts that push heating demand into November. It broke below $3.00 on Tuesday for the first sub-$3 settle in more than two weeks, and momentum favors sellers until the weather changes.

The fundamental case under the weather is tighter than the price suggests. Storage injections have come in below the five-year average for three straight weeks, with the October 9 build of 67 Bcf running 23 Bcf short and narrowing the surplus to 45 Bcf, or 1.3%. South Central salt storage sits 15.4% below its five-year average. Production has fallen from 113.3 bcfd to 110.8 to 111.3 bcfd. LNG feedgas runs at 18.1 bcfd and reached 18.9 bcfd on October 16, near the 18.8 bcfd monthly record. Reaching the EIA’s 3,850 Bcf end-October target would require 94 Bcf weekly injections, well above recent rates.

The global crisis caps nothing and lifts nothing directly. TTF at $29 and Asian LNG at $26.39 sit more than $23 above Henry Hub, but U.S. export plants have little spare capacity to capture that spread. EU storage at 74.6% and Qatar exports down 75% guarantee every U.S. cargo finds a buyer, which keeps export demand at maximum.

The levels decide the call. A close above $3.00 turns the prompt contract neutral and opens $3.116 and $3.30. A close below $2.75 opens $2.70 and signals the market is pricing a mild winter. Thursday’s storage report and next week’s November weather forecasts will decide which way the contract breaks, while December’s hold above $3.305 keeps the winter premium in place.

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