Henry Hub November NG Steadies at $3.03 After a 6% Weekly Drop as LNG Feedgas Falls to 17.0 Bcf/d and Cooler Forecasts Emerge

U.S. natural gas futures are steady to start the week. The November NYMEX contract trades at $3.03 per million British thermal units, down a fraction of a cent from Friday's $3.035 settlement. The market is holding the $3.00 level it lost and regained last week.

That recovery took effort. Front-month gas fell more than 6% over the five sessions to Friday, dropped below $3.00 on October 1 to its lowest in more than a week, and hit an intraday low of $2.912 on Friday morning. It then reversed, probing above $3.00 by late morning on reports of a pipeline outage and cooler temperature outlooks for parts of the country.

The contract is up 4.0% over the past month and down 9.7% from a year ago. September's range for the continuous contract ran from $2.82 to $3.30, with an average of $2.96. The current price sits seven cents above that average.

Three sets of fundamentals are in tension.

Storage is the bearish headline. Working gas stood at 3,415 billion cubic feet on September 25, which is 79 Bcf above the five-year average. Official projections call for inventories near 4 trillion cubic feet at the end of October, the second-highest on record.

The trend in storage points the other way. Injections have fallen short of the five-year average for seven consecutive weeks. The surplus was 185 Bcf in late August. It is expected to shrink again to roughly 62 Bcf when this week's report arrives.

Supply and demand are both softer. Production in the Lower 48 has eased to 112.2 billion cubic feet per day in early October from a record 113.3 in August and September. Gas flowing to LNG export plants has dropped to 17.0 Bcf per day from 17.9 in September as terminals undergo maintenance. Weather is forecast near normal through October 17.

Overseas, the picture is unrecognizable. European gas trades at €73.12 per megawatt-hour, equal to $24 per MMBtu, and Asian LNG at $25.74. Henry Hub is one-eighth of those prices.

The forecast rests on a market that is comfortably supplied today and tightening at the margin. That argues for a floor near $2.90 and a slow grind higher into the heating season, with $3.30 as the first objective once cooler weather arrives.

Last Week's Slide and Friday's Reversal

The path to $3.03 shows where buyers and sellers stand.

The October contract expired on September 29 at $3.011, handing the front-month position to November. November opened its tenure near $3.08 and immediately came under pressure. The market was looking at a large restart of supply: TC Energy lifted the force majeure on its Mountaineer Xpress pipeline in Appalachia after completing emergency repairs, which allowed production that had been shut in to return.

On Wednesday the contract settled at $3.026. On Thursday, October 1, it fell 2.4% to $2.953, breaking $3.00 for the first time in over a week. The trigger was a weather outlook showing near-normal temperatures across the country through mid-October, which limits demand for both air conditioning and heating.

The storage report that morning did not help the bulls. The Energy Information Administration announced an injection of 64 Bcf, matching the consensus forecast. A number in line with expectations gave the market no reason to rally, and futures were left searching for a catalyst.

Friday began with further selling. The contract reached $2.912, a decline of 5.5% from the week's opening level. That was the low.

Two developments turned it. Weather models shifted cooler for the northern and western United States later in October. And a pipeline outage raised the prospect of constrained supply in some regions. Spot prices in the West had already surged on Thursday, with sharp gains from the San Juan Basin to Southern California on pipeline constraints. Southern California prices held firm through the weekend even as other regions softened.

Futures recovered 12 cents from the low to settle at $3.035.

The weekly candle tells a clear story. A decline of more than 6% that ends with a long lower wick and a close back above the key level is a rejection of lower prices. Sellers pushed through $3.00 on two separate days and could not keep the market there.

Monday's flat trade continues the pattern. With the contract holding within a cent of Friday's close, the market is waiting for Thursday's storage data and for confirmation of the cooler forecasts.

Volume and open interest have rotated into the winter months. The November contract carries less weather premium than December and January, which are the contracts that respond most to heating demand.

The broader chart shows a series of higher lows since April. September's low was $2.82, and last week's was $2.912. Each sell-off has ended at a higher level than the one before.

Storage: 3,415 Bcf and a Surplus That Keeps Shrinking

Inventory levels are high. Inventory trends are tightening. Both statements are true, and the second is what moves price.

Working gas in underground storage was 3,415 Bcf as of September 25, according to the Energy Information Administration. That followed a net injection of 64 Bcf. Stocks were 79 Bcf, or 2.4%, above the five-year average of 3,336 Bcf. They were 138 Bcf, or 3.9%, below the level of a year ago.

The 64 Bcf build compared with 56 Bcf in the same week of 2025 and a five-year average of 80 Bcf. It was the first week since late July in which the injection exceeded the year-ago figure. It was also the seventh consecutive week below the five-year average.

That streak is the important number. The surplus to the five-year norm has been eroding steadily. It stood at 185 Bcf in late August, 148 Bcf on September 4, 118 Bcf on September 11 and 79 Bcf on September 25. Over a month it has fallen by more than half.

Regional detail shows where the tightness sits. The East and Midwest each added 25 Bcf. Salt-dome storage in the South Central region, the facilities closest to Gulf Coast LNG terminals and the most responsive to short-term demand, fell by 4 Bcf. Every region is above its five-year average except the South Central.

A withdrawal from salt storage in late September, during injection season, indicates that demand along the Gulf Coast is absorbing more gas than is being delivered there.

The next report is due Thursday, October 8. Early estimates point to an injection of 79 Bcf for the week ended October 2. That would compare with 77 Bcf a year ago and a five-year average of 96 Bcf. If confirmed, the surplus would narrow by another 17 Bcf to 62 Bcf, or 1.8% above normal.

Official forecasts still project inventories of 3,969 Bcf on October 31, which would be 5% above the five-year average and 44 Bcf short of the record set in October 2016.

The arithmetic deserves scrutiny. Reaching 3,969 Bcf from 3,415 Bcf requires 554 Bcf of injections in five weeks, or 111 Bcf per week. Recent builds have been 44, 53 and 64 Bcf, and the next is estimated at 79. At a pace of 80 to 90 Bcf per week through October, storage would end the month near 3,800 to 3,850 Bcf.

That is a comfortable level and well short of a record. The gap between the official projection and the run rate suggests the end-of-season figure will be revised down, which would remove one of the main bearish talking points.

A market entering winter with a 2% surplus is balanced. One with a 5% surplus is oversupplied. The data are moving from the second description toward the first.

Production: Off the Record at 112.2 Bcf per Day

Supply has stopped growing for the moment, and that has been underappreciated.

Average gas output in the Lower 48 states has slipped to 112.2 billion cubic feet per day so far in October. In both August and September it averaged a record 113.3 Bcf per day. The decline is 1.1 Bcf per day, or 1%.

Part of the drop is mechanical. Pipeline maintenance is concentrated in the autumn shoulder season, when demand is lowest. The Appalachian outage that ended in late September and the constraints reported in the West last week both restricted flows. Some of the lost volume will return as work is completed.

Part of it is economic. At $3.00, dry-gas drilling in higher-cost areas is marginal. Producers that curtailed output during the summer price slump have been slow to restore it. Winter futures contracts have shown some firmness as production has tapered.

The longer trend is still upward. Federal forecasters expect dry gas production to average 111.7 Bcf per day in 2026, an increase of 4.5 Bcf per day from last year, with a further 4.6 Bcf per day in 2027. The Haynesville shale in Louisiana and East Texas is projected to add 1.4 Bcf per day this year, supported by its proximity to export terminals. The Permian Basin produces large volumes of gas as a by-product of oil drilling, and with crude at $90 that supply is insensitive to gas prices.

That associated gas is the structural weight on the market. Oil producers will keep drilling as long as crude is profitable, and the gas comes with it. Regional prices in West Texas have at times traded far below Henry Hub because pipelines out of the basin are full.

Regional dislocations are a feature of the current market. One Western hub has traded below Henry Hub from May through early October. Southern California prices have spiked on pipeline constraints. These differences reflect infrastructure limits and do not show up in the benchmark futures price.

For the Henry Hub contract, the relevant question is the national balance. Production at 112.2 Bcf per day against total demand including exports of 102.3 Bcf per day leaves roughly 10 Bcf per day for storage, or 70 Bcf a week. That matches recent injection figures.

As demand rises seasonally to 104.5 Bcf per day over the next two weeks, the surplus available for injection shrinks unless production recovers.

A return to 113 Bcf per day or higher would restore the bearish supply picture. A further slip toward 111 would tighten the balance into the start of heating season. Daily pipeline flow data will show which way output is heading before the weekly storage figures confirm it.

The rig count offers little guidance. Total U.S. rigs stood at 598 last week, down one, and gas-directed drilling has been flat.

LNG Feedgas: 17.0 Bcf per Day and the Capacity Ceiling

Exports are the largest source of demand growth and, this month, a temporary drag.

Gas delivered to the nine large U.S. liquefaction plants has averaged 17.0 Bcf per day so far in October. That is down from 17.9 Bcf per day in September and from the monthly record of 18.8 Bcf per day set in April.

The decline is maintenance. Terminals schedule work in the autumn, between summer and winter demand peaks. A reduction of 0.9 Bcf per day in feedgas leaves that volume in the domestic market, where it adds to storage. Over a month it amounts to 27 Bcf.

This is the central feature of the U.S. gas market in 2026. Export plants are running as hard as they physically can. When overseas prices rise, American exporters cannot ship more because there is no spare liquefaction capacity. The link between global prices and Henry Hub is therefore broken at the margin.

The numbers show how wide the gap has become. European gas at the Dutch TTF hub trades at €73.12 per megawatt-hour. At an exchange rate of $1.1205 that is $24.00 per MMBtu. Asian spot LNG is at $25.74. Henry Hub is $3.03. The spread to Europe is $21 and to Asia nearly $23.

An exporter buying gas at Henry Hub, paying roughly $3 to liquefy it and $1 to $2 to ship it, lands a cargo in Europe for $7 to $8 and sells it for $24. Those margins guarantee that every available molecule of capacity will be used. They do not create new capacity.

New plants are the release valve. Three projects have been ramping up: Plaquemines in Louisiana, the third stage of Corpus Christi in Texas, and Golden Pass in Texas. As each train enters service it adds demand of 0.5 to 0.7 Bcf per day. The record in April reflected those additions.

When maintenance ends, feedgas should return toward 18 Bcf per day and beyond as new trains come online through the winter. That adds 1 to 2 Bcf per day of demand relative to current levels.

Canada is becoming a factor on the West Coast. Two announcements last week strengthened the outlook for Canadian LNG exports, lifting forward gas prices at Western U.S. hubs that will compete with those terminals for supply.

For the forecast, LNG has two effects. In October it is a mild negative, with lower intake adding to injections. From November it becomes a positive as maintenance ends, new capacity starts and heating demand rises at the same time.

There is also a tail risk. A hurricane or outage that shuts a major Gulf Coast terminal strands supply and sends Henry Hub lower, as has happened in past seasons. Atlantic storm activity is past its peak, though the season runs through November.

Export demand near 18 Bcf per day is 16% of U.S. production. Five years ago it was half that.

Weather: Near Normal Through Mid-October, Cooler After

In the shoulder season, weather sets the daily tone, and the outlook is turning.

Forecasts call for temperatures near normal across most of the country through October 16 or 17. Near-normal conditions in early October mean little air conditioning load and little heating load. It is the lowest-demand period of the year.

That outlook drove last week's sell-off. Milder forecasts on Thursday and Friday implied lower demand than previously expected over the following two weeks.

Friday's reversal came from a change in the later part of the forecast. Models turned cooler for the northern and western United States for the second half of October. Monday's stability in price reflects expectations that cooler weather later in the month will lift heating demand.

Seasonal demand is already rising. Total consumption including exports is projected to increase from 102.3 Bcf per day this week to 104.5 Bcf per day over the next two weeks, simply because average temperatures fall as October progresses.

The scale of weather sensitivity grows quickly from here. In early October, a cold week adds a few Bcf per day of residential and commercial heating. By late November the same temperature anomaly adds three or four times that. The market begins to price winter risk in earnest once the first sustained cold appears in two-week outlooks.

This year opened with an extreme example. A winter storm in January caused record storage withdrawals and froze wellheads across producing regions, taking a large share of output offline for days and sending prices to multi-year highs. Stocks ended the withdrawal season well below normal, and it has taken a summer of record production to rebuild them.

That memory supports a risk premium in the winter contracts. Forward curves show winter prices climbing above $4.00 in multiple years. The gap between a $3.03 November contract and winter months above $4.00 is the market's estimate of what cold weather is worth.

Longer-range guidance for the winter is not yet reliable. The state of Pacific sea-surface temperatures and the behavior of the polar vortex will shape December through February, and neither can be forecast with confidence in early October.

For the next two weeks, weather is neutral to slightly supportive. The key signal will be whether the cooler pattern for the North and West holds in successive model runs and extends into the population centers of the Midwest and Northeast.

A confirmed cold shot in the final week of October would be the catalyst for a move toward $3.20 to $3.30. A reversion to warm forecasts would send the contract back to test $2.91.

Power-sector demand is the other weather-linked variable. Gas-fired generation has been strong all year as electricity consumption from data centers grows, providing a base of demand that does not depend on temperature.

The Global Gas Crisis That Henry Hub Ignores

Outside North America, gas is in its tightest market since 2022.

The Dutch TTF benchmark fell 2.2% on Monday to €73.12 per megawatt-hour after closing Friday near €74.76. It staged a sharp afternoon recovery on Friday, reversing earlier losses to trade nearly 3% higher at €75.80. In September it ranged from €69.47 to €82.57, with an average of €76.48. On September 9 it crossed €80 for the first time since 2023.

Compared with a year ago, European gas is up 121%. The 52-week low was under €26.

Asian spot LNG was assessed at $25.74 per MMBtu on Friday. It reached a four-year high of $29.56 in September. Asia has retaken its premium over Europe as mild weather on the Continent curbed early heating demand.

The cause is the Strait of Hormuz. The waterway carried roughly 19% of global LNG supply before the conflict began on February 28, most of it from Qatar. It has been functionally closed to normal traffic for seven months. Iran said this week it will not reopen the strait until the United States meets seven conditions.

Europe has been filling storage for winter at these prices. The requirement to reach high storage levels by November 1 forced buyers to compete with Asia for every available cargo through the summer.

Monday's dip in TTF reflects some relief. Middle East energy exports have recovered through alternative routes, and mild weather has slowed the start of the European heating season.

The effect on the United States is indirect. American LNG is the swing supplier to both regions, and its exporters are capturing extraordinary margins. Domestic producers selling at Henry Hub are not. The value is accruing to the owners of liquefaction capacity and to those with long-term contracts linked to international prices.

There are three ways the global situation could reach Henry Hub.

The first is new export capacity, which is being built as fast as engineering allows. Each new train raises domestic demand.

The second is policy. With European and Asian prices at eight times the U.S. level, political pressure exists on both sides: from allies wanting more supply and from domestic consumers wanting protection. The administration last week ruled out restrictions on diesel exports as part of a coordinated release of oil reserves. Gas exports have not been targeted.

The third is a resolution in the Gulf. A reopening of Hormuz would send TTF and Asian prices sharply lower. It would have little direct effect on Henry Hub, since U.S. exports are capacity-constrained in either case. Over time, lower global prices would reduce the incentive to sanction new U.S. export projects.

For the Henry Hub forecast, the global crisis is context. It guarantees that export demand stays at maximum and explains why 17 to 19 Bcf per day leaves the country regardless of domestic conditions.

Demand at Home: Power, Industry and a Slowing Economy

Domestic consumption is firm in power generation and uncertain in industry.

Electricity is the largest and steadiest use. Gas-fired plants supply the biggest share of U.S. power, and total electricity demand is rising for the first time in two decades as data centers for artificial intelligence come online. That load runs around the clock and does not vary with weather.

The federal government is also backing other sources. Over the weekend it emerged that the administration will lend one large power producer $4.2 billion to upgrade three nuclear plants. More nuclear output displaces gas at the margin over time. In the near term the growth in demand is absorbing all available generation.

Gas prices at $3.00 keep the fuel competitive against coal in most regions. Coal-to-gas switching, which adds demand when gas is cheap, is close to its maximum.

Industrial demand is the question mark. The U.S. economy added only 29,000 jobs in September, manufacturing employment grew by 9,000, and consumer confidence fell to a 12-year low. Slower activity in chemicals, fertilizers, steel and refining reduces gas use.

High interest rates add to the pressure. The 10-year Treasury yield is at 5.28%, which raises financing costs for energy-intensive industries and for the pipelines and plants that would expand gas consumption.

The combination of a soft labor market and elevated inflation has been flagged as a risk for gas demand. An economy that slows while energy costs stay high tends to see industrial consumption fall first.

Oil prices matter in two ways. Crude near $90 for West Texas Intermediate sustains drilling in the Permian, which keeps associated gas flowing. It also raises the price of competing fuels such as propane and heating oil, which supports gas demand where switching is possible.

Residential and commercial heating is the swing factor from November. A normal winter draws roughly 2,000 Bcf from storage. A cold one draws 2,500 or more. With inventories heading for 3,800 to 3,850 Bcf at the end of October, a normal winter would leave stocks near 1,800 Bcf in March, about average.

Exports to Mexico by pipeline add a further 6 to 7 Bcf per day of demand and have been stable.

Putting the pieces together, total demand of 102.3 Bcf per day rising to 104.5 is consistent with the season. The year-on-year comparison is favorable: storage is 138 Bcf below last October even after a summer of record production, which means consumption and exports have absorbed more gas than a year ago.

That deficit to last year is the cleanest evidence that underlying demand growth is keeping up with supply.

For price, domestic demand argues for stability. Power and exports provide a firm base, industry is a mild drag, and heating is the variable still to come.

The Forward Curve and What $4 Winter Gas Says

The shape of the futures curve carries as much information as the front-month price.

November at $3.03 is the lowest-priced contract of the coming winter. Prices rise through December, January and February as the market assigns value to heating demand and to the risk of cold-weather supply disruptions. Forward assessments show winter prices climbing above $4.00 in multiple years through the next decade.

That upward slope, known as contango, has practical consequences.

It rewards storage. An operator can buy gas today near $3.00, inject it and sell a January contract at a substantially higher price. That incentive encourages injections and supports the cash market in October. It also means storage will be filled as far as economics allow.

It penalizes passive long positions. Funds that hold the front-month contract and roll each month sell a cheaper contract and buy a more expensive one. In a steep contango that roll costs several percent a month. This is why exchange-traded products tracking front-month gas have lost value over time even when spot prices were flat.

It signals expectations. A November contract at $3.03 with winter above $4.00 says the market sees today's balance as loose and the winter balance as tight. The spread narrows either because the front rises as cold arrives or because the back falls as winter risk fails to materialize.

Longer-dated prices are stable. Forward curves show Henry Hub largely above $3.00 through 2036. Official projections put the 2026 average at $3.43 and the 2027 average at $3.28. Model-based estimates for the end of the current quarter are near $3.23.

Those figures frame fair value. At $3.03 the front month is below the full-year average, below the quarter-end projection and well below winter contracts.

Private forecasts for the year were considerably higher. Some institutions expected $4.10 to $5.00 for 2026 on the strength of new export capacity. Record production has kept the market below those targets.

The curve also offers hedging signals. Producers have been selling winter and 2027 contracts above $3.50 to lock in revenue, which adds supply of forward contracts and limits how far those prices rise. Utilities and industrial buyers are on the other side.

For the forecast, the curve implies a path. As November approaches expiry in late October, it converges with cash prices. December then becomes the front month at a higher level. Even with no change in fundamentals, the front-month price will step up at the roll.

A trader comparing today's $3.03 with a front-month price near $3.40 to $3.60 in early November would be observing the roll and not a rally. The relevant test is whether December and January themselves gain or lose value.

Winter contracts have shown hints of strength over the past week as production tapered.

Technical Structure: Higher Lows Above $2.82

The chart supports a cautiously constructive view.

On the daily timeframe, November gas has spent three weeks oscillating around $3.00. The contract has closed on both sides of that level multiple times, which establishes it as the pivot. Friday's low at $2.912 and close at $3.035 formed a long-tailed candle, a pattern that often marks a short-term bottom.

The sequence of lows is rising. The continuous contract bottomed at $2.82 in September and $2.912 last week. Looking back further, the market has made consistent higher lows since April. That is the definition of an uptrend, though a shallow one.

Highs have been less encouraging. September's peak was $3.30. Rallies since have stalled between $3.08 and $3.10. A move above $3.10 is needed to show that buyers can extend beyond the pivot.

Short-term resistance levels sit at $3.035 to $3.06, then $3.08 to $3.10. Above that, $3.20 is a round-number hurdle and $3.30 the September high.

Support is at $3.00, then $2.953, which was Thursday's close, and $2.912. Below that, $2.85 and the September low at $2.82 are the main levels. A break of $2.82 would end the series of higher lows and open $2.75.

The range for the past month is therefore $2.82 to $3.30, a span of 48 cents or 16%. Price is 21 cents above the bottom and 27 cents below the top.

Momentum indicators are neutral. The contract is close to its short-term moving averages, which have flattened. The monthly trend signal has been negative for much of the year, a reflection of the decline from January's spike.

Volatility has contracted. Daily ranges of 8 to 12 cents compare with 20 cents or more during the summer. Low volatility at the bottom of a seasonal cycle typically precedes expansion as winter approaches.

Speculative positioning has been light. Managed-money accounts reduced exposure during the summer slump, which leaves room for buying if a weather catalyst emerges.

Seasonal tendencies favor the upside from here. Gas prices have historically firmed between early October and late November as the injection season ends and the first cold arrives. The pattern is not reliable in years with very high storage, and it has been strong in years when the surplus was shrinking, as it is now.

The technical conclusion is a market building a base. The trend of higher lows is intact, the pivot at $3.00 has been reclaimed, and the low at $2.912 defines risk. Confirmation requires a close above $3.10.

A failure back below $2.91 would negate Friday's reversal and return the focus to $2.82.

The Level Map

Resistance starts at Friday's settlement of $3.035 and extends to $3.06. The $3.08 to $3.10 zone is the first meaningful barrier, where the contract opened its run as front month and where recent rallies have stopped. A daily close above $3.10 is the trigger for a move higher.

Above it, $3.20 is the next reference and $3.23 the quarter-end model projection. The September high at $3.30 is the main objective. Beyond that, $3.43 is the official average-price forecast for the year, and $3.50 the next round number.

Support begins at $3.00. Below it, $2.953 and $2.912 are last week's closing low and intraday low. The $2.85 level is minor support. The September low at $2.82 is the line that preserves the uptrend. Under it, $2.75 and the summer lows come into view.

From $3.03, the first resistance at $3.10 is 2.3% above. The $3.30 target is 8.9% above. Friday's low at $2.912 is 3.9% below, and the September low at $2.82 is 6.9% below.

For trade construction, a long position at $3.03 with a stop below $2.90 risks 13 cents for 27 cents to $3.30, a ratio of 2 to 1. A long entered on a dip to $2.95 with the same stop risks 5 cents for 35 cents.

A breakout entry on a close above $3.10 with a stop at $2.98 risks 12 cents for 20 cents to $3.30 and 33 cents to $3.43.

Shorts have a narrower case. Selling near $3.10 with a stop above $3.15 risks 5 cents for 19 cents to $2.91. It is a range trade that works while mild weather persists.

Contract specifications matter for sizing. Each futures contract covers 10,000 MMBtu, so a one-cent move is worth $100. A move from $3.03 to $3.30 is $2,700 per contract. The smaller contract is one-quarter of that size.

For holders of exchange-traded products, the levels apply with caveats. The main unleveraged fund tracks the front-month contract and suffers from roll costs in contango. The leveraged long and inverse products reset daily and are suitable only for short holding periods.

Gas-weighted producers trade on the forward curve more than the front month. Their earnings depend on realized prices over the next four quarters, which are closer to $3.40 to $3.80 than to $3.03. LNG exporters benefit from volume and from the spread to international prices, and they have less exposure to Henry Hub direction.

The roll calendar is the other date to mark. November expires in late October. Positions held into the final days face thin liquidity and convergence with cash prices.

The most important level on the map is $2.912. As long as it holds, last week's reversal stands and the path of least resistance is sideways to higher.

Catalysts and Scenarios

The week's main event is Thursday's storage report at 10:30 a.m. ET for the week ended October 2. The estimate is an injection of 79 Bcf against a five-year average of 96 Bcf. A figure at or below 79 would cut the surplus to 62 Bcf or less and support prices. A build above 90 would suggest the tightening trend has stalled.

Weather model runs twice a day will matter as much. The market needs confirmation that cooler air reaches the northern tier in the second half of October.

Daily production and LNG feedgas flows are the other indicators. Output recovering toward 113 Bcf per day would be bearish. Feedgas rising back above 17.5 Bcf per day would be supportive.

The monthly federal energy outlook, due in the coming days, will update the end-of-October storage projection. A reduction from 3,969 Bcf would be notable.

The bullish scenario combines a storage build under 79 Bcf, cooler forecasts that hold, and production staying near 112 Bcf per day. November closes above $3.10 and moves toward $3.20 and then $3.30 by the time it expires. December takes over as front month near $3.50 or higher. In this case the storage surplus disappears by early November, and the market enters winter balanced.

The base case is range trading between $2.91 and $3.10. Weather stays near normal through mid-month, injections run 75 to 90 Bcf per week, and production and feedgas fluctuate with maintenance. The contract drifts around $3.00 and waits for late-October temperature forecasts. This is the most likely path for the next one to two weeks.

The bearish scenario requires warm weather to return to the outlook, production to rebound above 113 Bcf per day, and LNG maintenance to extend. Injections exceed 95 Bcf, the surplus stops shrinking, and November breaks $2.91. The September low at $2.82 would be tested, with $2.75 beneath it. A hurricane-related outage at a Gulf Coast export terminal would produce the same result more abruptly.

Weighing the three, the range has the highest near-term probability and the bullish path has the edge beyond that. Seven straight weeks of below-average builds, a production dip, a 138 Bcf deficit to last year and the seasonal rise in demand all lean the same way.

The risk to that view is weather. A warm October and November, which has occurred in several recent years, would let storage overshoot and push the surplus back above 100 Bcf.

There is also a ceiling in the near term. With stocks above the five-year average and export plants in maintenance, a sustained move above $3.30 before real cold arrives is unlikely.

Outside events with potential impact include developments in the Strait of Hormuz, which affect global gas far more than Henry Hub, and U.S. economic data, which bear on industrial demand.

The time horizon matters. Over two weeks the market is range-bound. Over six to eight weeks, the direction is higher unless winter fails to arrive.

Verdict: Neutral Near Term, Bullish Into Winter, Buy Dips Toward $2.95 With a $3.30 Target

The forecast for November natural gas is neutral for the coming two weeks and bullish into the heating season.

The supportive facts are the trend in storage and the behavior of price. The surplus to the five-year average has fallen from 185 Bcf to 79 Bcf in a month and is on course for 62 Bcf this week. Injections have trailed the norm for seven weeks. Stocks are 138 Bcf below last year despite record summer output. Production has eased to 112.2 Bcf per day from 113.3. Salt storage on the Gulf Coast drew down in late September. Futures rejected $2.912 on Friday and closed back above $3.00, extending a run of higher lows that began in April.

The limiting facts are also plain. Inventories at 3,415 Bcf are above average and heading toward the high end of the historical range. Weather is near normal through October 17. LNG feedgas is down 0.9 Bcf per day on maintenance. Associated gas from oil drilling keeps coming at $90 crude. The U.S. market is disconnected from a global price of $24 because export capacity is full.

That balance supports buying weakness and avoiding strength. The preferred entry is $2.93 to $2.97, near last week's lows, with a stop on a daily close below $2.90. At the current $3.03 the contract is a hold.

The target is $3.30, the September high, a gain of 8.9%. It becomes reachable once cooler weather is confirmed for late October. A secondary target of $3.43, the official full-year average forecast, applies to the December contract after the roll.

The bullish view is invalidated by a daily close below $2.82. That would break the pattern of higher lows and indicate that supply is overwhelming seasonal demand. The next support in that case is $2.75.

The bear case is invalidated by a close above $3.10.

Instrument choice matters. Because of contango, those seeking winter exposure are better served by December or January futures, or by gas-weighted producers, than by rolling front-month contracts or holding funds that do so. Leveraged products are for short-term use only.

Position size should allow for weather. A single model run can move the contract 3% in an hour, and the market has traded a 48-cent range in a month.

The official projection of 3,969 Bcf at the end of October requires injections of 111 Bcf a week. Current builds are running at 64 to 79. A downward revision to that estimate would remove the most-cited bearish argument and would likely coincide with a test of $3.10.

The rating is hold at $3.03, buy on dips toward $2.95, with $3.30 as the target. Thursday's storage report and the late-October temperature outlook will decide whether the contract breaks $3.10 or revisits $2.91.

That's TradingNEWS