NG($3.002) Takes the Front Month Near a Multi-Month Low as Record Production Meets Mild Weather — Break of $2.945 Opens $2.80

The NYMEX November natural gas contract gained 9.5 cents on Tuesday to $2.697 per MMBtu, recovering from Monday’s settlement at $2.602, its lowest close since April 28. The bounce came on its second-to-last trading day, as short sellers covered positions ahead of Wednesday’s expiration. The move was technical rather than fundamental: November had sat in oversold territory for five straight sessions, the longest such stretch since April, and traders who sold the contract down from above $3.10 earlier in the month locked in profits before the roll.

The rest of the curve told the real story. December futures, which take over as the front month after Wednesday’s settlement, slipped 2 cents to $3.002 at midday and stayed under pressure into the afternoon. On Monday, December broke to a multi-month low at $2.945. The December through March contracts all declined Tuesday, and the winter strip, the average of November through March, sits at its lowest level since 2021. A rally confined to an expiring contract while every winter month falls is the signature of a market that is still bearish on the season ahead.

The physical market confirms the weakness. Next-day gas at Henry Hub in Louisiana traded at $2.52 per MMBtu, its lowest since November 2024. Spot prices and prompt futures have both fallen toward $2.50 to $2.60 in late October, a level that would have seemed unthinkable at the start of the month when December traded above $3.40.

The scale of the slide is clear on the December contract. It traded as high as $3.709 within the past 30 days and changed hands at $3.411 on October 19 before falling to $2.945 on Monday, a decline of 20.6% from the 30-day high. November dropped from $3.117 on October 16 to $2.602 on Monday, a 16.5% fall in six sessions, including a 4.94% plunge on October 23 alone.

Three forces drove the selloff. Weather forecasts call for unusually mild temperatures across the major U.S. heating markets through early November, delaying the start of heating demand. Lower 48 production has rebounded toward its record of 113.3 billion cubic feet per day after hurricane and pipeline disruptions. And LNG export plants, while running near record levels, have little spare capacity to absorb extra supply.

The thesis for this forecast is direct. Natural gas sits in a shoulder-season trap. Record production, much of it associated gas from oil wells drilling hard with crude above $100, meets a weather pattern that refuses to deliver heating demand, while LNG exports are already running near full capacity. December inherits the front-month role at $3.00 with a bearish trend and a market waiting for cold. Until forecasts turn colder, the path of least resistance runs toward $2.80.

The Expiry Mechanics: Why November Bounced and December Did Not

The divergence between November and December on Tuesday is a feature of contract expiration, and understanding it matters for traders rolling positions this week.

The November contract expires at the close of trading on Wednesday, October 28, three business days before the first calendar day of the delivery month. It is physically settled: a long position held through expiration obliges the holder to take delivery of 10,000 MMBtu at Henry Hub, spread across November. Speculators who do not want physical gas must close or roll their positions before the final bell, and that forced activity creates outsized moves in the final sessions.

Short covering drove Tuesday’s November gain. After a 16.5% decline in six sessions and a close at the lowest level since April 28, traders who had shorted November locked in profits rather than carry positions into the delivery period. Their buying lifted November by 9.5 cents. Moves into expiration week tend to be more technical than fundamental, with traders closing short bets or rolling into December in ways that exaggerate price swings.

December did not get the same support. Traders rolling short positions out of November and into December added selling pressure to the new front month even as November rose. December slipped to $3.002 at midday and remained under pressure as bearish weather forecasts dominated. The December contract is now looking for technical support as it prepares to take the front-month role.

The spread between the two contracts reveals the market’s view. December traded roughly 30 cents above November on Tuesday, a contango that reflects the expectation of higher winter demand. That spread pays traders to store gas now and deliver it in December, which supports continued storage injections into November.

History offers a cautionary note for bears. Past monthly rollovers have produced surprising strength in the new front month, as traders who rolled shorts discover the new contract has less selling pressure behind it. Some analysts expect a short counter-trend rally in December after it takes over, though not necessarily in the deferred winter contracts.

For the forecast, the November bounce is noise. The contract that matters from Thursday onward is December at $3.00. Its multi-month low at $2.945 on Monday reaffirmed the downtrend, and the first test for the new front month is whether it holds that level once November’s short-covering support disappears.

Storage: 3,644 Bcf, 1% Above Average After 10 Bullish Prints

The storage picture is tighter than the price suggests, and that tension sets the floor under the market. Working gas in underground storage reached 3,644 Bcf in the week ended October 16, according to the EIA’s weekly storage report, after a net injection of 77 Bcf. Inventories sit 35 Bcf, or 1.0%, above the five-year average of 3,609 Bcf and 152 Bcf, or 4.0%, below last year’s 3,796 Bcf.

The trend has been tightening. The October 16 injection landed on the tighter side of forecasts and marked the tenth consecutive weekly print that came in below five-year norms. The week ended October 9 brought a 67 Bcf injection to 3,567 Bcf, 23 Bcf below the five-year average of 90 Bcf for that week and below the 76 Bcf consensus, narrowing the surplus to 1.3% from 2.0%. The week ended October 2 brought an 85 Bcf build to 3,500 Bcf, above the 79 Bcf estimate but below the five-year norm of 96 Bcf.

The surplus to the five-year average has narrowed from 2% in early October to 1% now. Measured against last year, inventories are 4% lower, a deficit created by record LNG exports that have pulled more gas out of the domestic market.

Regional detail shows where supply is tight. The South Central region, which includes the Gulf Coast storage that feeds LNG terminals, held 1,125 Bcf, 3.4% below its five-year average and 10.0% below last year. Salt-cavern storage, the most flexible and quickly deliverable inventory, held 251 Bcf, 14.9% below the five-year average and 21.1% below a year ago. The Midwest, by contrast, held 1,065 Bcf, 2.0% above average, and the East held 900 Bcf, 2.7% above average.

The salt deficit matters for winter. Salt caverns can be withdrawn quickly during cold snaps, and a 44 Bcf shortfall against the five-year norm leaves the Gulf Coast with less cushion for a sudden demand spike.

The next report arrives Thursday, October 29, at 10:30 a.m. ET, covering the week ended October 23. Forecasts call for a build near 68 Bcf. A print well below that would extend the streak of bullish storage numbers. A print above 75 Bcf would confirm that mild weather is allowing faster refills.

Projections show inventories reaching 3,850 Bcf by the end of October, 2% above the five-year average entering the heating season on November 1.

For the forecast, storage is a floor, not a ceiling. Inventories near normal mean there is no glut to crush prices further, but no shortage to drive them higher until cold weather begins drawing stocks down.

Production: Back Toward 113.3 Bcf/d After the Isaias Dip

Supply is the dominant bearish force, and it is rebuilding. Lower 48 dry gas production hit records of 113.3 billion cubic feet per day in August and September, then dipped in early October as Hurricane Isaias shut in offshore output and pipeline force majeure events constrained flows. Output averaged 111.5 Bcf/d through the first three weeks of October and dropped to an eight-month low near 107.1 Bcf/d on October 13.

The disruptions were temporary. Hurricane Isaias shut in 1.26 Bcf/d of offshore Gulf production on October 9, 58.8% of Gulf offshore gas output. Pipeline problems in Kentucky, Texas, West Virginia and elsewhere cut flows further. As those issues resolved, output recovered. A Columbia Gas Transmission force majeure ended, restoring 1.9 million dekatherms per day of Appalachian pipeline capacity. Output averaged near 113.3 Bcf/d over the past week, matching the August and September records.

Annual numbers show the scale. U.S. gas production reached a record 107.6 Bcf/d in 2025, and federal forecasts call for 112.2 Bcf/d in 2026 and 116.1 Bcf/d in 2027. Year-to-date production through mid-October averaged 4.1% higher than the same period in 2025, putting 2026 on pace for a second consecutive annual record.

Oil is the hidden driver. With Brent near $114 and WTI near $100 on the U.S.-Iran war’s supply shock, oil producers in the Permian and other basins are drilling aggressively. Every barrel of oil from those wells brings associated gas with it, regardless of gas prices. That associated gas, produced as a byproduct rather than because gas prices justify it, is the main source of downward pressure on Henry Hub. Oil-directed rig counts have risen, and gas-directed rigs reached 135 in late September before easing to 133 in the week to October 16, still higher than a year ago.

The Haynesville and Appalachian basins add dry gas. Appalachian supply has returned after maintenance and pipeline outages, and Haynesville output supports Gulf Coast LNG demand.

Production keeps a ceiling on prices. Producers cannot easily cut associated gas without cutting oil, and with crude above $100, they have no reason to. That creates a supply floor that only extreme cold or a sharp drop in oil prices can change.

For the forecast, production at 113 Bcf/d means the market needs cold weather to tighten. Mild weather with record output equals continued storage builds and pressure on prompt prices.

LNG Feedgas: Near Record, but Close to Capacity

LNG exports are the largest source of new demand for U.S. gas, and they are running near full capacity. Flows to the nine major U.S. LNG export plants averaged 18.2 to 18.3 Bcf/d through the first weeks of October, up from 17.9 Bcf/d in September and close to the monthly record of 18.8 Bcf/d set in April. Daily feedgas hit a record 20.7 Bcf/d on October 19, and flows have averaged 19.2 Bcf/d over the past two weeks.

Golden Pass, the newest export terminal on the Gulf Coast, has been running at record rates, adding to the demand surge. A Venture Global project is targeting October 31, 2026, for Phase 1 commercial operations, which would add incremental feedgas demand in November. Year-to-date LNG feedgas volumes average 2.4 Bcf/d higher than in 2025.

The problem is that the terminals are already near maximum capacity. With feedgas running at 19 to 20 Bcf/d, there is little room to absorb more gas when domestic prices fall. In a normal market, a wide gap between U.S. and overseas prices would pull more gas into exports and lift Henry Hub. In 2026, that mechanism is capped by terminal capacity.

The global price gap is enormous. Dutch TTF, Europe’s benchmark, trades near $31 per MMBtu, more than ten times Henry Hub’s $2.52 to $2.70. The U.S.-Iran war has disrupted Persian Gulf LNG supplies from Qatar and pushed European and Asian prices sharply higher. European storage fell below seasonal norms through the summer, and open interest in TTF futures and options hit a record 5.9 million contracts on October 23, up 16% from a year earlier.

That gap does nothing for Henry Hub right now. Every U.S. terminal that can run is running, and new capacity takes years to build. Until additional liquefaction trains come online, Henry Hub stays stuck at domestic prices while global buyers pay ten times more for the same molecules.

The marginal driver of Henry Hub therefore remains domestic: temperature-driven demand, weekly storage surprises and swings in Lower 48 output. LNG provides a floor under demand but cannot absorb the surplus created by record production.

For the forecast, LNG strength keeps prices from collapsing below $2.50, but it cannot lift them above $3.30 without cold weather.

Weather: The Missing Catalyst

Weather is the variable that will decide whether December holds $3.00 or breaks toward $2.80. Forecasts through early November call for milder-than-normal temperatures across much of the Lower 48, delaying the real start of heating demand and keeping the market in a shoulder-season mode where gas is needed for neither heating nor cooling.

The demand numbers reflect the mild outlook. Total U.S. gas demand forecasts for the coming week remain below the five-year average of 117 Bcf/d, which means inventories will continue to build into November instead of drawing down. Weather models were described as disjointed through mid-October, with no consistent signal of cold.

Tuesday brought a small shift. Weather model revisions turned modestly cooler, which helped November’s short-covering bounce. But the changes were not large enough to lift the winter contracts, which all fell. A modest cooling in the eight-to-14-day outlook is not the same as a sustained cold pattern.

The season ahead is a coin flip. Federal forecasts assume heating degree days this winter will be nearly unchanged from last winter nationally and 1% below the five-winter average. Under those conditions, storage near normal provides a buffer against periods of high demand. A prolonged cold snap could pull withdrawals well beyond forecasts and tighten the market quickly.

Cold carries production risk too. Extreme cold can freeze wells and cut output for days, as past winter storms have shown. A cold snap that simultaneously lifts demand and cuts supply would produce the sharpest price spikes.

The calendar works against bears from here. Heating demand rises steadily from November through January regardless of anomalies, as baseline temperatures fall. Even a mild November uses more gas for heating than a mild October. The question is how fast demand ramps, not whether it does.

For the forecast, weather is binary. Forecasts that stay mild through mid-November would push December through $2.945 toward $2.80. A shift to colder-than-normal outlooks for the second half of November would trigger the counter-trend rally that some expect after the roll, with $3.30 to $3.40 the target.

EQT Buys Range: A $50 Billion Bet on Appalachian Gas

The biggest corporate story in the gas market landed Monday. EQT Corporation agreed to acquire Range Resources in an all-stock deal that creates the largest U.S. natural gas producer, with a pro forma enterprise value above $50 billion. Range shareholders will receive 0.987 EQT shares for each share held, valuing Range’s equity at $12.8 billion and implying $54.91 per share, a 20.6% premium to Friday’s close.

The combined company will be large. It will produce more than 9 billion cubic feet of gas equivalent per day, equal to 7% of total U.S. production, with more than 30 years of drilling inventory across nearly 3 million net acres in the Appalachian Basin and more than 3,700 miles of midstream infrastructure. EQT describes it as the only vertically integrated gas producer in the country, owning production, pipelines and the largest gas marketing platform.

The economics focus on cost. EQT said the deal improves its unlevered free cash flow breakeven to less than $2 per MMBtu, meaning the combined company can generate cash even at today’s depressed prices. It expects $325 million of annual synergies within two years, with a longer-term opportunity above $600 million. The transaction is expected to close in the first quarter of 2027.

The market’s reaction split. EQT shares fell 4.6% in premarket trading Monday, as investors weighed dilution, while Range rose 10.1% on the premium. EQT shareholders will own 73% of the combined company and Range holders 27%. EQT canceled its third-quarter earnings call but planned to release results after the close on Tuesday.

The deal matters for gas prices in two ways. First, it signals that the industry’s largest players see long-term demand growth from LNG exports and data centers, and they are consolidating to capture it. Second, it shows producers betting on scale and low costs rather than higher prices: a sub-$2 breakeven means the combined company can keep producing even if Henry Hub stays below $3.

The near-term effect is bearish. Consolidation tends to support disciplined production over time, but the focus on cost leadership suggests the merged company will keep output high. Appalachian supply is not going away.

For the forecast, the EQT-Range deal is a long-term vote of confidence in U.S. gas demand, not a near-term price catalyst. It confirms that supply will remain abundant through 2027.

Demand Drivers: Data Centers, Power Burn and Exports

The long-term demand story for U.S. natural gas is strong, even as the near-term price is weak. U.S. energy companies expect 2026 to mark a second consecutive year of record production because global demand for LNG exports and fuel for data centers is growing.

Data centers are the new force. The AI build-out requires enormous amounts of electricity, and natural gas is the fuel that can be dispatched quickly to meet it. Anthropic’s IPO filing this week disclosed compute commitments between $542 billion and $567 billion, and hyperscalers including Microsoft, Alphabet and Amazon are spending at a combined pace above $600 billion on infrastructure. Much of that capacity will run on gas-fired power, either directly or through the grid.

Total U.S. gas demand, including exports, remained strong entering the fourth quarter, with year-to-date demand higher on record LNG feedgas and higher electric power consumption. Power burn during the summer held up as hot weather in the South kept air conditioners running.

Exports to Mexico add a steady pipeline outlet, running near 7 Bcf/d. Canadian imports run near 7 Bcf/d, a supply source that moves with Canadian production and prices.

The demand growth is structural but slow. Data center power demand builds over years, not weeks, and LNG demand cannot grow until new terminals come online. That means near-term prices still depend on weather and production, while the long-term curve reflects the structural demand growth.

The forward curve captures the split. Deferred contracts for winter 2027-28 trade well above the prompt, reflecting expected demand growth as new LNG capacity and data centers come online. Federal forecasts call for Henry Hub to average $3.48 per MMBtu in 2026, $3.30 in the fourth quarter of 2026 and $3.47 in the first quarter of 2027, all above current prompt prices.

For the forecast, structural demand supports a recovery toward $3.30 to $3.50 later in the winter. It does not prevent near-term weakness when mild weather meets record supply.

The Oil Connection: $100 Crude Is Flooding the Gas Market

The U.S.-Iran war has created a paradox for natural gas. The same conflict that pushed Brent crude up 80% this year to $114 and global LNG prices to ten times Henry Hub has made U.S. gas cheaper, not more expensive.

The mechanism runs through associated gas. When oil prices are high, producers in the Permian Basin and other oil-focused regions drill more wells. Those wells produce oil, but they also produce natural gas as a byproduct. That associated gas must be sold, flared or reinjected, and most of it flows into the U.S. pipeline system regardless of gas prices.

High oil prices therefore increase gas supply. Oil-directed rig counts have risen over the past several months in response to $100-plus crude, and the associated gas from those wells is the main source of downward pressure on Henry Hub. Production at 113 Bcf/d, a record, reflects that dynamic.

The connection explains why Henry Hub trades at $2.52 to $2.70 while European gas trades near $31 per MMBtu. U.S. gas cannot reach global markets beyond what LNG terminals can export, so the extra associated gas stays in the domestic market and pushes prices lower.

A ceasefire would cut both ways. If the U.S.-Iran war ended and oil fell toward $90, oil drilling would slow over the following months, reducing associated gas supply and supporting Henry Hub. But the effect would take three to six months to show up in production, and it would also reduce global LNG prices, weakening the long-term export demand case.

An escalation would also cut both ways. A further oil spike would encourage even more oil drilling and associated gas. But if escalation disrupted global LNG supply further, it would increase pressure for U.S. exports, though terminal capacity limits the near-term effect.

Talks in Tehran on Monday between Iran, Saudi Arabia, Turkey and Pakistan produced only a promise to keep talking, and Houthi attacks on Saudi energy infrastructure continued Tuesday with a fire near the Ras Tanura export terminal. Oil remains high, and associated gas will keep flowing.

For the forecast, $100 oil is a structural bearish force on U.S. gas. Until oil drilling slows, associated gas will cap rallies.

Technical Map: December’s $2.945 Floor, $3.20 Pivot, $3.40 Ceiling

With December taking over as the front month after Wednesday’s settlement, its chart is the one that matters.

Support begins at $3.002, Tuesday’s midday level, and $3.00, the round number December has been fighting to hold. Below that, $2.945 is Monday’s multi-month low, the level that reaffirmed the downtrend. A daily close below $2.945 would open a move toward $2.85, then $2.80, where December would trade near the level the November contract held before its expiry bounce. Below $2.80, the $2.60 to $2.70 zone, where November and Henry Hub spot traded this week, becomes the next target.

Resistance starts at $3.10, a level December traded through on its slide. Above that, $3.20 is the pivot: a daily close above it would break the series of lower highs and signal that the counter-trend rally many expect after the roll has begun. The $3.234 level, the bottom of December’s 30-day range before the October slide, sits next. The $3.39 to $3.41 zone, where December traded on October 16 and 19, is the major ceiling. Above that, $3.709, the 30-day high, caps the structure.

The trend is bearish. December has made lower highs and lower lows since mid-October, falling from $3.709 to $2.945, a decline of 20.6%. The winter strip sits at its lowest since 2021. The April 2027 contract, a gauge of the summer strip, is also in a downtrend.

The setup for a bounce exists. December’s move to a multi-month low on Monday came after a steep selloff, and if confirmed as a bottom, it could lead to a two-to-three-week counter-trend rally. November’s five-session oversold streak and its short-covering bounce show that sellers have been aggressive and positioning may be stretched.

The roll is the key event. Past monthly rollovers have produced surprising strength in the new front month. If December holds $2.945 through its first sessions as the prompt contract, a rally toward $3.20 becomes likely. If it breaks $2.945 in the first days, the downtrend extends.

The trading range for the coming week is $2.85 to $3.20 for December, with a bearish bias as long as it stays below $3.10.

Natural Gas ETFs and Equities: UNG, BOIL, KOLD and the Producers

The futures moves flow directly into the ETFs and equities that traders use for gas exposure. The United States Natural Gas Fund holds front-month futures and rolls them monthly, so it will shift from November to December exposure this week. The roll from a $2.70 November contract into a $3.00 December contract creates a contango cost: the fund sells cheaper November gas and buys more expensive December gas, which erodes returns over time in a contango market.

The leveraged products amplify the moves. BOIL, a 2x long gas ETF, and KOLD, a 2x short gas ETF, magnify daily moves in front-month futures. KOLD has benefited from October’s 16% to 21% decline in prompt gas, while BOIL has suffered. Leveraged ETFs also suffer from volatility decay over time, making them suitable only for short-term positioning around events like weather shifts and storage reports.

Producer stocks are pricing in the merger news and the price slide. EQT fell 4.6% premarket Monday on dilution concerns from the Range acquisition, while Range rose 10.1% on the 20.6% premium. EQT released third-quarter results after the close on Tuesday without a conference call. Coterra Energy, a diversified oil and gas producer, has exposure to both Permian associated gas and Appalachian dry gas.

Cheniere Energy, the largest U.S. LNG exporter, benefits from the wide gap between Henry Hub and global prices. With Henry Hub near $2.70 and TTF near $31, Cheniere’s export margins are among the widest in its history. Its constraint is capacity, not demand.

The equity picture shows where value sits. LNG exporters earn the spread between cheap U.S. gas and expensive global gas, making them the clearest beneficiaries of the current setup. Producers with sub-$2 breakevens, like the combined EQT-Range, can generate cash even at depressed prices. High-cost producers face margin pressure.

For the forecast, the ETFs track December from Thursday onward. KOLD remains favored while December stays below $3.10, and BOIL becomes attractive only on a confirmed break above $3.20.

What Could Break the Range: Cold, Storage, Freeze-Offs

The bearish setup is strong, but four developments could reverse it, and gas markets can move 10% to 20% in a week when they do.

The first is a colder weather outlook. A shift in the eight-to-14-day forecasts toward below-normal temperatures across the Midwest and East for the second half of November would lift December quickly. Heating demand in those regions dominates winter consumption, and a cold pattern arriving as baseline temperatures fall would accelerate the transition from injections to withdrawals. Tuesday’s modest cooler revisions hinted at that possibility.

The second is a bullish storage surprise. Thursday’s report for the week ended October 23 is expected to show a build near 68 Bcf. A print well below that, say under 60 Bcf, would extend the streak of tighter-than-normal reports to 11 weeks and narrow the surplus to the five-year average toward zero. That would shift attention from abundant supply to the 4% deficit against last year and the 14.9% salt-storage shortfall.

The third is a production disruption. An early-season cold snap that freezes wells, a renewed pipeline force majeure or late-season Gulf storm activity could cut output by 2 to 5 Bcf/d for days or weeks. With LNG demand near 20 Bcf/d, the market has little slack to absorb a supply drop.

The fourth is new LNG capacity. The Venture Global project targeting October 31 for Phase 1 commercial operations would add feedgas demand. Each new train adds incremental demand that absorbs supply.

On the other side, the risks that would extend the decline are clear: forecasts that stay mild through mid-November, storage builds above 75 Bcf, production holding at 113 Bcf/d or higher, an LNG terminal outage that cuts feedgas, or oil staying above $100 and sustaining associated gas growth.

Natural Gas Price Forecast: Three Scenarios Into November

The forecast splits into three paths for December futures, the new front month, with weather forecasts, Thursday’s storage report and the post-roll price action deciding which plays out.

The base case, with the highest probability, is a range between $2.85 and $3.20 through mid-November. Weather stays near normal to mild, with modest cooling in the second half of November. Thursday’s storage report shows a build near 68 Bcf. Production holds near 113 Bcf/d, LNG feedgas stays at 19 to 20 Bcf/d, and the December contract tests $2.945 before stabilizing on the roll. In this scenario, December trades near $2.95 to $3.10 by mid-November, with Henry Hub spot near $2.60 to $2.80.

The bull case requires a daily close above $3.20. The triggers would be a shift to colder-than-normal forecasts for the second half of November, a storage build below 60 Bcf, and the post-roll strength that has surprised bears in recent months. In that scenario, December would clear $3.20 and target $3.40 within 30 days, a gain of 13.3% from $3.00. A close above $3.41 would open $3.709, the 30-day high. This scenario requires weather to cooperate; production and LNG alone will not drive it.

The bear case is a daily close below $2.945. The triggers would be forecasts that stay mild through mid-November, storage builds above 75 Bcf, production holding at record levels and no new LNG demand. In that scenario, December would fall toward $2.80, a decline of 6.7%, with the $2.60 to $2.70 zone as the extension where November and spot traded this week.

Weighing the scenarios, the near-term balance tilts bearish, while the medium-term setup is constructive. Record production, mild weather and capped LNG demand dominate now, but storage near normal, a 4% deficit to last year, a salt-storage shortfall and the approach of peak heating season limit the downside.

The 30-day target for December is $2.80, conditional on a daily close below $2.945. A daily close above $3.20 would shift the target to $3.40.

Verdict: Bearish Below $3.10, $2.945 Is the Line and Cold Is the Only Catalyst

Natural gas futures at $2.697 for November and $3.002 for December trade in a shoulder-season trap. November’s 9.5-cent bounce into Wednesday’s expiry was short covering, not a trend change: the contract closed Monday at its lowest since April 28, sat oversold for five straight sessions and saw Henry Hub spot fall to $2.52, the lowest since November 2024. December, which takes over as the front month on Thursday, slipped to $3.002 after breaking to a multi-month low at $2.945, and the winter strip sits at its lowest since 2021.

The fundamentals explain the weakness. Lower 48 production has rebounded toward its 113.3 Bcf/d record, driven in large part by associated gas from oil wells drilling hard with crude near $100. LNG feedgas runs at 19 to 20 Bcf/d, close to full capacity, so the tenfold gap between Henry Hub and European prices near $31 cannot pull more U.S. gas overseas. Weather forecasts call for mild temperatures through early November, keeping demand below the five-year average. EQT’s $50 billion-plus acquisition of Range, built on a sub-$2 breakeven, confirms that supply will stay abundant.

Storage provides the floor. Inventories at 3,644 Bcf sit just 1% above the five-year average after 10 straight tighter-than-normal prints, 4% below last year, with salt-cavern storage 14.9% below normal. Projections show inventories near 3,850 Bcf entering the heating season, and heating demand will rise as baseline temperatures fall regardless of anomalies.

The verdict is bearish in the near term. December below $3.10 keeps the downtrend intact, and a daily close below $2.945 would target $2.80 within 30 days, with $2.60 to $2.70 as the extension. A daily close above $3.20, which requires a colder forecast for the second half of November and a lean storage report on Thursday, would trigger the counter-trend rally that recent rollovers have produced and target $3.40. Until the weather turns, natural gas trades a market with too much supply and not enough cold, and every rally toward $3.10 is a selling opportunity.

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