NG=F ($2.86) Slips as Record 112.2 Bcf/d Output Outruns 20 Bcf/d LNG Demand — Range Holds Between $2.80 and $3.07

December natural gas futures on the New York Mercantile Exchange traded at $2.86 per million British thermal units in the afternoon session on Monday, November 2, down 3.9 cents or 1.35% from Friday’s settlement near $2.90. The contract opened at $2.912, touched a session high of $2.928 in the morning and hovered near even at $2.903 through midday before sliding into the afternoon. For the second straight session, the front month failed to challenge the psychological $3 threshold as two-week weather forecasts turned overwhelmingly mild.

The December contract is only four sessions old as the prompt month. The November contract rolled off the board at the October 28 close, and December debuted walking a tightrope around $3 before breaking below $2.900 on October 29 after a bearish storage report. Monday’s slide takes it back toward that low. Over the past month, Henry Hub futures are down 6.75%. Over the past year, they are down 33%.

The 52-week range shows how far the market has fallen since the winter. The front-month contract traded as high as $7.827 during the winter storm spike earlier in 2026 and as low as $2.483 at its trough. The 2026 shoulder-season lows sat between $2.52 and $2.64. At $2.86, the contract trades closer to the bottom of its yearly range than the top, despite entering the heating season.

The forecast thesis is direct. The U.S. natural gas market is oversupplied for the start of winter, and the global gas crisis cannot reach it. Dry gas production is running more than 4% above year-ago levels and on pace for a record 112.2 billion cubic feet per day in 2026. Storage inventories moved back above the five-year average with the first above-average injection in 11 weeks. Forecasts call for warmer-than-normal temperatures across most of the country through November 13. Meanwhile, European gas prices sit near €101 per megawatt hour, roughly 11 times the Henry Hub price, but U.S. export terminals are already running near record capacity at 20 billion cubic feet per day and cannot ship more.

That combination sets a range. The base case is $2.80 to $3.07 through mid-November, with a bearish tilt while mild weather persists. The upside requires a decisive shift to cold in late-November forecasts. The downside opens toward the $2.64 to $2.52 zone if Thursday’s storage report shows another above-average build and forecasts stay warm into Thanksgiving.

Storage Swings Back Above Average: An 80 Bcf Injection Ends 10 Weeks of Below-Normal Builds

The October 29 storage report turned the inventory story from supportive to bearish. The Energy Information Administration reported a net injection of 80 billion cubic feet for the week ended October 23, above the 75 Bcf market expectation and the prior week’s 77 Bcf build. Working gas in storage rose to 3,724 Bcf.

The size of the build broke a key pattern. The 80 Bcf injection exceeded the five-year average change for the week by 3 Bcf, ending a streak of 10 straight weeks of below-average injections. Through late summer and early October, U.S. storage had been building more slowly than normal as record LNG exports and strong power burn absorbed supply. That streak had been the main bullish argument for natural gas heading into winter. The October 23 week ended it.

Inventories now sit 38 Bcf, or 1%, above the five-year average of 3,686 Bcf, and within the five-year historical range. They remain 147 Bcf, or 3.8%, below year-ago levels. Every storage region added gas during the week. All regions sit above their five-year averages except the South Central and South Central salt caverns, the region closest to LNG export terminals on the Gulf Coast. The Mountain region shows the largest year-over-year deficit at 9.5%.

The October build sequence shows the shift. In the week ended October 2, storage rose 85 Bcf to 3,500 Bcf, 68 Bcf above the five-year average. The week ended October 9 brought a lean 67 Bcf injection to 3,567 Bcf, cutting the surplus to 45 Bcf. The week ended October 16 added 77 Bcf to 3,644 Bcf. Then the 80 Bcf build to 3,724 Bcf. The surplus narrowed through early October on record LNG demand, then stopped narrowing as power burn fell and production recovered.

The market reacted immediately. December futures extended losses the day of the report and briefly dropped below $2.900. The weekly average Henry Hub spot price stood at $3.045 at the time, putting cash prices above futures and showing that physical demand at the Gulf Coast remained firm even as the futures curve priced oversupply.

The next report is the key near-term catalyst. The EIA will release storage data for the week ended October 30 on Thursday, November 5, at 10:30 a.m. ET. Mild weather in the final week of October reduced heating demand while production held near record levels. A second straight above-average build would widen the surplus over the five-year average and push the December contract toward $2.80. A below-average build, driven by record LNG feedgas, would ease the pressure.

The Path to Winter: EIA Projects 3,850 Bcf at the End of October and a 2% Surplus

The official forecast points to a well-supplied start to winter. The EIA’s October Short-Term Energy Outlook estimated that the U.S. held 3,523 Bcf of natural gas in storage at the end of September and projected inventories would build by 328 Bcf during October to reach 3,850 Bcf by October 31. That would put storage 2% above the five-year average at the official start of the heating season on November 1.

The October data has tracked close to that path. Storage reached 3,724 Bcf by October 23, leaving 126 Bcf to reach the EIA’s end-of-month projection. Two more weeks of builds in the 60 to 80 Bcf range would deliver that figure. The agency noted that injections often continue through mid-November depending on weather, and the current warm forecasts make continued builds likely through at least the first half of the month.

The agency’s winter assumptions are moderate. The EIA forecast assumes heating degree days this winter will be nearly unchanged from last winter on a national basis and 1% below the previous five-winter average. Under those conditions, the agency said, storage provides a buffer against periods of increased consumption or reduced production, and ample inventories limit upward price pressure.

The EIA expects inventories to remain above the rolling five-year average in most months of its forecast. The reason is supply: growth in natural gas production is projected to cover both rising LNG exports and higher domestic demand. That supply cushion is the core of the bearish case for Henry Hub through the winter.

The comparison with last year matters for sentiment. Storage sits 147 Bcf below year-ago levels, which means the market enters this winter with less gas than it held entering the last one. But the five-year average is the more relevant benchmark for price, because it reflects normal winter needs. A surplus to the five-year average, even a small one, tells the market that a normal winter can be met without stress.

The surplus is thin enough to disappear. A 38 Bcf surplus equals roughly one cold winter day of storage withdrawals at peak demand. A sustained cold snap in late November or December could flip storage back to a deficit within weeks. That is why the forecast treats weather as the swing factor rather than inventories: the storage cushion is large enough to prevent a spike in a normal winter, but not large enough to cap prices in a cold one.

For the forecast, the storage path supports the bearish tilt in the near term. Inventories near 3,850 Bcf at the start of winter, with a surplus to the five-year average and production at record levels, give the market no reason to bid Henry Hub above $3 until weather forces it.

Weather: Warmer Than Normal Through November 13 and a Moderate Winter Outlook

Weather is the dominant driver of natural gas prices in November, and the current outlook is bearish. Meteorologists expect temperatures across most of the U.S. to remain above normal through November 13, limiting heating demand during the first half of the month. Two-week forecasts were described as overwhelmingly bearish on Monday, and that outlook kept December futures from breaching $3 even as LNG demand held near records.

Heating demand normally ramps sharply through November. As temperatures fall, residential and commercial gas consumption for space heating rises, typically pushing total U.S. demand above 100 Bcf per day by late November and into the 120 to 140 Bcf per day range during cold snaps in December and January. A warm first half of November delays that ramp and extends the injection season, adding gas to storage when the market would normally start drawing it down.

The cooling demand that supported prices through the summer has rolled off. Power-sector gas burn fell by 3.1 Bcf per day in mid-October as air conditioning load faded, a key reason the October 16 and October 23 storage builds came in larger. The shoulder-season gap between cooling and heating demand is when the market is most exposed to oversupply, and a warm November extends that gap.

The winter-wide outlook is moderate. The EIA assumes heating degree days nearly unchanged from last winter and 1% below the five-winter average. That is a normal winter, not a cold one. The market’s winter strip prices that assumption, which leaves room for upside surprise if late November or December turns cold.

The weather risk is asymmetric. Natural gas prices are far more sensitive to cold surprises than to warm ones, because storage withdrawals can accelerate sharply in a cold snap and production cannot respond quickly. A single week of below-normal temperatures across the Midwest and Northeast in late November could add 15 to 20 Bcf per day of demand and push futures through $3 within days.

The near-term forecast leaves little room for that. With warmth expected through November 13, the next two weeks are likely to bring continued storage injections or minimal withdrawals. The first meaningful cold in forecasts would likely appear in the November 14 to 28 window, and traders will watch every update of the extended-range forecasts for signs of a pattern shift.

For the forecast, weather sets the timing. Through November 13, the bearish tilt dominates and December futures are likely to test $2.80. After that, the late-November outlook decides whether the contract recovers toward $3.07 or extends lower toward $2.64.

Record Production: Dry Gas Output Up More Than 4% and on Pace for 112.2 Bcf per Day

Supply is the structural bearish force behind Henry Hub. U.S. dry natural gas production remains well above year-ago levels into late October. Year-to-date output through October 29 is more than 4% higher than a year earlier, and production remains on pace for a new annual record. The EIA forecasts dry gas production of 112.2 Bcf per day in 2026 and 116.1 Bcf per day in 2027.

Producers are adding volume, not cutting it. Expand Energy, the largest U.S. natural gas producer, released guidance on October 27 calling for 7.45 to 7.55 Bcf per day of natural gas equivalent production and roughly $3 billion in capital investment for 2026, up from 7.2 Bcf per day last year. Producers have responded to record LNG demand and strong winter strip prices by drilling more, which has pushed supply growth ahead of demand growth.

The supply-demand math for the withdrawal season is bearish. Averaged across November through March, dry gas production is expected to run 5.4 Bcf per day above the same period a year earlier. That growth is only partly offset by an increase in LNG feedgas of 2.1 Bcf per day, driven by Plaquemines, Corpus Christi and the ramp of Golden Pass. The net result is 3.3 Bcf per day of additional supply available for domestic consumption or storage through the winter, which supports a higher end-of-winter inventory and a shallower storage trough.

The EIA’s annual balance tells the same story. Domestic consumption is projected at 92.4 Bcf per day in 2026 and 93.8 Bcf per day in 2027, while LNG exports are forecast at 17.6 Bcf per day in 2026 and 18.6 Bcf per day in 2027. Production growth of 3.9 Bcf per day from 2026 to 2027 outpaces the combined 2.4 Bcf per day growth in domestic consumption and exports. Rising production is expected to outpace demand growth, creating a more comfortable supply situation.

Associated gas from oil drilling adds to the supply wave. The Permian Basin produces natural gas as a byproduct of oil drilling, and high crude prices in 2026 have kept Permian activity strong. Associated gas does not respond to natural gas prices; it flows as long as oil drilling is profitable. Stronger Permian production has driven at least one major forecaster to cut its 2027 Henry Hub forecast to $2.80 from $3.50, citing an expected supply surplus exceeding 2 Bcf per day.

For the forecast, production is the floor-breaker. As long as output runs at record levels, Henry Hub cannot sustain a rally above $3 without a weather shock. A production decline, from pipeline maintenance, freeze-offs in a cold snap or producer curtailments at low prices, would be the only supply-side catalyst for a sustained move higher.

LNG Feedgas at Records: 20 Bcf per Day, Plaquemines at 4.36 and Golden Pass Ramping

LNG exports are the strongest source of demand growth, and they hit new records in October. Total U.S. LNG feedgas climbed to roughly 20.8 Bcf per day on October 18, a record high, and averaged 19.6 Bcf per day for the week ending October 19, up 1.5 Bcf per day from the prior week. LNG exports reached a record 19.9 Bcf per day on October 18, a 1.4% increase over the previous record set on March 28. U.S. feedgas demand surpassed 20 Bcf per day for the first time a decade after the first Lower 48 LNG cargo shipped from Sabine Pass.

October as a whole set a high bar. Feedgas averaged 19.2 Bcf per day through late October, up from 18.7 Bcf per day in September and roughly 2 Bcf per day above the October 2025 average. Feedgas rebounded to 20.2 Bcf per day on October 28 after a dip, and on October 30, metered feedgas deliveries totaled 19.597 Bcf per day. Forecasts call for feedgas to hold near 20 Bcf per day through mid-November.

Plaquemines is the workhorse. Venture Global’s Plaquemines LNG terminal in Louisiana pulled 4.257 Bcf per day on October 30, roughly 22% of all U.S. feedgas, after hitting a record 4.359 Bcf per day on October 25. Its 30-day average stands at 4.153 Bcf per day. Sabine Pass, Cameron LNG and Corpus Christi round out the large intake terminals.

Golden Pass adds new capacity. The ninth U.S. LNG export terminal shipped its first cargo on April 22 from Train 1. Its intake averaged 570 million cubic feet per day in October, up from 345 million cubic feet per day in September, and reached nearly 800 million cubic feet per day on October 22. On October 30, it pulled 776 million cubic feet per day. Train 2 is expected to start in the second half of 2026 and Train 3 in the first half of 2027. At full build-out, Golden Pass will have 2.0 Bcf per day of nominal capacity and 2.4 Bcf per day at peak.

Terminal outages can swing demand quickly. Freeport LNG feedgas was sharply curtailed on October 26 and 27, after nearly halting, which pulled total feedgas down to 17.658 Bcf per day on October 26. Freeport recovered within days. Those outages are a recurring source of downside volatility, because every 1 Bcf per day of lost feedgas stays in the domestic market.

Cove Point added back volume after completing its annual turnaround between September 20 and October 11.

For the forecast, LNG is the demand floor. At 20 Bcf per day, exports absorb roughly 18% of U.S. dry gas production, a share that has never been higher. That demand prevents Henry Hub from collapsing toward the $2.48 52-week low. But because terminals are running near capacity, LNG cannot add much more demand this winter. The growth comes only as Golden Pass Train 2 ramps.

The Global Gap: TTF at €101, Henry Hub at $2.86 and an Export Bottleneck That Locks It In

The world is in a gas crisis, and Henry Hub is not participating. The Dutch TTF front-month contract, Europe’s benchmark, traded at €101.20 per megawatt hour late last week, up more than 200% year to date. At current exchange rates, that equals roughly $33 per million British thermal units, more than 11 times the Henry Hub price of $2.86. Asian spot LNG has traded roughly 190% above its pre-war level near $10.

The driver is the Strait of Hormuz. The Iran war has trapped roughly 20% of global LNG supply, more than 10 Bcf per day, primarily from Qatar and the United Arab Emirates. Qatar, which supplied 12% to 14% of Europe’s LNG through the strait, has kept force majeure on LNG deliveries in place until the end of November. Utilization at Qatar’s Ras Laffan complex is projected to average only 20% to 30% from November 2026 through February 2027, and Qatari LNG supply is forecast to run 9.5 million tonnes below normal through July 2027.

Europe has filled the gap with U.S. gas. More than half of U.S. LNG exports are now directed to Europe. Norwegian pipeline gas and U.S. LNG are covering current European demand and capping the upside in TTF. European storage sits well below last year’s levels, which keeps TTF elevated.

The bottleneck is export capacity. U.S. LNG terminals are running at or near their physical limits. When European prices are 11 times Henry Hub, every terminal operator has every incentive to export as much as possible, and they already are. Feedgas cannot rise much further until new trains come online. That means the global premium cannot reach U.S. producers. Henry Hub prices reflect the domestic supply-demand balance, not the global one.

The spread shows up in the winners. LNG exporters with spot exposure capture the price gap between Henry Hub and TTF, which makes the current setup highly profitable for terminal operators and traders. U.S. gas producers do not benefit unless they have contracts linked to international prices.

The bottleneck will loosen slowly. About 3 Bcf per day of additional feedgas demand is expected to come online through early 2027 from new Texas and Louisiana projects, including Golden Pass Trains 2 and 3 and Corpus Christi Stage 3. That capacity will pull more U.S. gas into the global market and gradually narrow the spread. But new capacity arrives over quarters, not weeks.

For the forecast, the global gap explains why Henry Hub can sit below $3 during the worst global gas shortage since 2022. The crisis in Europe and Asia supports LNG feedgas at maximum capacity, which provides a demand floor. It does not provide upside, because the pipe to the global market is full.

Oil, Iran and the Hormuz Deal: What Monday’s 6% Crude Collapse Means for Gas

Monday’s collapse in crude oil carries two distinct implications for U.S. natural gas. WTI fell 6.45% to $97.40 and Brent dropped 6.37% to $106.20 as Iran offered to reopen the Strait of Hormuz within two days if Washington lifts the naval blockade of Iranian ports and eases oil sanctions. Iranian and Qatari officials held a third straight day of talks in Doha on a proposal to end the war.

The first implication runs through global LNG. A deal that reopens Hormuz would restore Qatari LNG exports over time and bring as much as 10 Bcf per day of trapped supply back to world markets. That would pull TTF sharply lower from €101 toward the €40s to €50s that forecasters expect once Gulf flows normalize. Most projections see Hormuz LNG flows normalizing in February 2027, with TTF falling to roughly €44 in the first quarter of 2027 and about €32 from 2027 onward.

For Henry Hub, a deal is bearish at the margin but not dramatically. U.S. LNG terminals are already full, so lower European prices would not reduce feedgas immediately; terminals would keep running as long as the spread covers costs, which it would even at €40. The bearish channel is sentiment: a collapse in the global gas premium would remove a supporting narrative for U.S. gas bulls and could push speculative traders to sell.

The second implication runs through associated gas. Lower oil prices, if sustained, reduce the incentive for Permian drilling over time. Fewer oil wells mean less associated gas, which is bullish for Henry Hub over a 6- to 12-month horizon. That effect is slow. Drilling programs respond to oil prices with a lag of several months, and current Permian activity reflects oil prices that have averaged well above $90 through the second half of 2026.

The risk is the reverse scenario. If talks collapse or the U.S. strikes Iran after Tuesday’s midterm elections, crude would rebound above $104 and global gas markets would tighten further. TTF could push toward €105 to €120. Henry Hub would see only modest support, again because export capacity limits pass-through.

Iran talks carry real uncertainty. At least 10 attacks on Gulf shipping have been reported since October 31, and prediction markets price a 50% chance the ceasefire ends through escalation by November 15. Israel reportedly urged the U.S. to strike Iran immediately after the vote.

For the forecast, the oil link matters more for Europe than for Henry Hub. U.S. gas will move on weather, storage and production through November. The Iran outcome shapes the 2027 outlook, when new export capacity begins connecting U.S. supply to global prices.

The Forecast Landscape: EIA at $3.30 for the Fourth Quarter, Forecasts Split Between $2.80 and $4.00

The official outlook sits above the current price. The EIA’s Short-Term Energy Outlook expects the Henry Hub spot price to average $3.30 in the fourth quarter of 2026 and $3.47 in the first quarter of 2027, as heating demand rises. For 2027 as a whole, the agency projects $3.16, citing production growth outpacing new LNG demand. The next outlook is due on November 10, and traders will watch for any revision to the winter price path given the October storage data.

The EIA’s fourth-quarter average implies a recovery. With October and early November trading near $2.90, reaching a $3.30 quarterly average would require December prices well above $3.50. That is achievable in a cold December but not in a mild one. The EIA forecast assumes a normal winter, and the current weather outlook leans warmer than normal.

Private forecasts are split widely. One major forecaster cut its 2027 Henry Hub forecast to $2.80 from $3.50, citing stronger Permian production and an expected supply surplus above 2 Bcf per day. Another raised its second-half 2026 forecast to $3.80 from $3.60 and expects $4.00 in 2027, citing strong LNG feedgas demand and new export trains. The $1.20 gap between those 2027 views shows how much uncertainty surrounds the balance between record production and record exports.

The bearish view rests on supply. Production growth of 5.4 Bcf per day year over year through the winter, against LNG feedgas growth of 2.1 Bcf per day, leaves the domestic market oversupplied. The bullish view rests on export capacity: as Golden Pass, Corpus Christi Stage 3 and other projects add roughly 3 Bcf per day through early 2027, more U.S. gas reaches the global market, tightening domestic balances.

Market pricing sits between the two. December futures at $2.86 price a mild start to winter and ample supply. The winter strip prices some recovery into January and February, consistent with normal heating demand. The 2027 strip prices a modest increase as new export capacity comes online.

A mild winter case anchors the bearish target. If weather stays warm through December, storage would remain above the five-year average and prices could fall back toward the 2026 lows of $2.52 to $2.64. Supply growth is expected to outpace new LNG demand through 2027 in most private balances.

For the forecast, the landscape argues for patience on the long side. The EIA’s $3.30 fourth-quarter forecast is achievable only with a cold December. The near-term setup favors the lower end of the forecast range until weather proves otherwise.

Equities and ETFs: UNG, BOIL and KOLD Mechanics and Producers Under Pressure

Natural gas exchange-traded products amplify the futures move. The United States Natural Gas Fund, UNG, holds front-month futures and rolls them each month. During contango, when later contracts trade above nearer ones, the roll costs the fund value. The winter strip currently trades above December, which means UNG faces roll costs as it moves from December into January. That makes UNG a weak vehicle for a sustained bullish view on Henry Hub.

The leveraged products move twice as hard. ProShares Ultra Bloomberg Natural Gas, BOIL, delivers twice the daily return of its futures benchmark, and ProShares UltraShort Bloomberg Natural Gas, KOLD, delivers twice the inverse. Because they reset daily, both lose value in choppy, range-bound markets. In a sustained downtrend, KOLD gains; in a sharp rally, BOIL gains. In the current $2.80 to $3.07 range, both decay.

The Henry Hub futures contract trades as NG on NYMEX, with the e-mini QG contract offering a smaller size for retail and smaller institutional traders. The December contract expires on November 25.

Producers have been pressured by sub-$3 prices. EQT, Expand Energy and Coterra Energy, the largest U.S. gas producers, earn more as Henry Hub rises. With the front month below $3 and the year-over-year price down 33%, their realized prices have fallen. Expand Energy’s October 27 guidance of 7.45 to 7.55 Bcf per day of production and $3 billion in capital investment signals the company is growing volumes rather than cutting them, which adds to the supply wave and keeps pressure on prices.

Coterra carries meaningful oil exposure through its Permian operations, which ties its results more closely to crude. Monday’s oil collapse is a headwind for its oil revenue but irrelevant to its gas output.

Cheniere Energy, the largest U.S. LNG exporter, fell 2.81% before Monday’s open as investors weighed the possibility that a Middle East settlement would ease the global gas premium. Cheniere profits from the spread between Henry Hub and international prices. A Hormuz deal that pulls TTF and Asian LNG prices lower would compress that spread, even though Cheniere’s terminals would keep running at full capacity.

For the forecast, the equity picture confirms the commodity view. Producers face low realized prices and keep growing volumes, which sustains oversupply. Exporters face spread compression risk from a Hormuz deal. Leveraged ETFs decay in a range. The setup favors patience until weather or storage forces a directional move.

The Support Map: $2.80, the $2.64 to $2.52 Zone and the $2.483 52-Week Low

The downside levels for December natural gas sit in two distinct tiers.

The first support is $2.80, the floor that held through late October as December futures tested a falling trendline. That level marks the lower boundary of the post-rollover range and the level where buyers stepped in after the October 29 storage report pushed the contract below $2.900. It sits 2.1% below the current price. A daily close below $2.80 would confirm that weather and storage are overwhelming LNG demand and open a deeper decline.

Below that, the next meaningful zone is the $2.64 to $2.52 band, which marks the 2026 shoulder-season lows. Natural gas traded there during the spring and early summer before cooling demand and record LNG feedgas pulled prices higher. A return to that zone would require a combination of warm weather into late November, another above-average storage build and continued record production. The top of the zone sits 7.7% below spot, and the bottom 11.9% below.

The 52-week low of $2.483 sits 13.2% below the current price and marks the outer boundary of the downside. A break below that level would require a mild winter extending through December and evidence that production growth is accelerating beyond current forecasts.

The probability distribution favors testing the first level. Two weeks of warm weather through November 13, record production and a likely above-average storage build on Thursday make a test of $2.80 the most probable near-term outcome. The $2.64 to $2.52 zone requires the warm pattern to extend into late November, which current forecasts do not yet show.

LNG demand anchors the downside. At 20 Bcf per day, feedgas absorbs a record share of production and prevents a collapse. Any large terminal outage, like Freeport’s curtailment in late October, would add supply back to the domestic market and accelerate a move toward $2.64.

For risk management, $2.80 is the line. Above it, the base case is a range with a bearish tilt. Below it on a daily close, the forecast shifts to $2.64, with $2.52 the extended downside.

The Resistance Map: $2.928, $3.00, $3.045 Cash, $3.07 and the $3.30 EIA Average

The upside levels define how much cold the market needs to see.

The first resistance is $2.928, Monday’s session high. A move back above that level would show buyers absorbing the warm forecasts. It sits 2.4% above the current price.

The second is $3.00, the psychological threshold December futures have failed to break since debuting as the prompt month. A daily close above $3.00 would be the first sign that weather or storage has shifted. It sits 4.9% above spot.

The third is $3.045, the weekly average Henry Hub cash price from late October. Cash prices trading above futures reflect firm physical demand at the Gulf Coast from LNG terminals. A futures move to the cash level would close the discount and signal that the market has stopped pricing oversupply.

The fourth and primary upside target is $3.07, the level from which natural gas has fallen 6.75% over the past month. Reclaiming the month-ago price would erase the October decline. It sits 7.3% above spot and would require a decisive cold shift in late-November forecasts.

Above that, $3.30 marks the EIA’s fourth-quarter average forecast, 15.4% above spot. Trading at that level in November would mean the market has priced a colder-than-normal December. The $3.47 first-quarter 2027 EIA forecast and the $3.80 second-half 2026 private forecast define the outer bullish boundary.

The path higher requires sequencing. December futures need a daily close above $2.928 to stabilize, above $3.00 to break the post-rollover range, and above $3.07 to recover the October decline. Each step needs a catalyst. A below-average storage build on Thursday would support the first. A cold shift in the November 14 to 28 forecasts would support the second and third.

The resistance is soft relative to weather risk. Natural gas can move 10% to 15% in days on a cold forecast shift. If late-November forecasts turn sharply colder, December could gap through $3.00 and $3.07 within a session. That asymmetry, slow grind lower in warm weather and fast spike higher in cold, defines the trade.

Natural Gas Price Forecast and Verdict: Range $2.80 to $3.07, Bearish Tilt Through November 13

The forecast rests on a domestic market that is oversupplied for the start of winter and cut off from a global shortage. December natural gas futures fell 1.35% to $2.86, failing again to break $3. Dry gas production runs more than 4% above year-ago levels and is on pace for a record 112.2 Bcf per day in 2026. Storage swung back to a 38 Bcf surplus over the five-year average after the first above-average injection in 11 weeks. Forecasts call for warmer-than-normal temperatures through November 13. Through the winter, production growth of 5.4 Bcf per day outpaces LNG feedgas growth of 2.1 Bcf per day.

Against that, LNG demand provides a firm floor. Feedgas hit a record 20.8 Bcf per day on October 18 and is forecast to hold near 20 Bcf per day through mid-November. Europe’s TTF trades near €101, roughly 11 times Henry Hub, keeping U.S. terminals at maximum utilization. But that global premium cannot reach Henry Hub, because export capacity is full.

The base case, with the highest probability through mid-November, is a range between $2.80 and $3.07. The floor is defended by record LNG demand and the late-October trendline support. The ceiling is set by the $3 threshold and the month-ago price. Inside that range, the tilt is bearish while warm forecasts hold.

The bear case targets $2.64, 7.7% below the current price, with $2.52 as the extension. It needs Thursday’s storage report to show another above-average build, warm forecasts to extend into late November and production to hold at record levels. A daily close below $2.80 would confirm the move.

The bull case activates on a daily close above $3.07. That would require a decisive cold shift in the November 14 to 28 forecasts, a below-average storage build and continued record LNG feedgas. The next targets would be the EIA’s $3.30 fourth-quarter average, then $3.47.

The asymmetry favors the downside in the near term and the upside on weather risk. December sits 2.1% above its first support and 7.3% below its primary resistance. A warm first half of November grinds prices lower; a cold late November spikes them higher. The EIA’s $3.30 quarterly forecast is achievable only with a cold December.

The verdict is bearish with a weather-driven upside risk: December natural gas trades the $2.80 to $3.07 range through mid-November, with a test of $2.80 likely while forecasts stay warm through November 13, a daily close below $2.80 opening $2.64, and a daily close above $3.07 on a late-November cold shift opening the $3.30 EIA target.

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