Natural Gas Futures Target $3.60 as December NG Clears $3.24, LNG Feedgas Hits 19.3 Bcf/d and Shorts Cover

December Henry Hub natural gas futures on the New York Mercantile Exchange traded at $3.29 per MMBtu in the Wednesday afternoon session of November 11, and the intraday high reached $3.37. That puts the contract 6.6 cents, or 2.0%, above Tuesday’s settlement of $3.224. At the high, the gain was 4.5%. The move came on Veterans Day, when bond markets are shut and energy desks run light, so the price action carries less volume than a normal Wednesday. The direction still matters, because the market is holding a breakout that started Monday. Monday’s session lifted the front month 5% on colder weather forecasts and falling output. Tuesday then added 0.6 cents to settle at $3.224, which made it the highest close since October 15 for a second day in a row. Wednesday’s push took the contract above $3.241, the 50% retracement of the December contract’s decline from its summer levels to the late-October trough. That level had been the first upside objective on the weekly chart, and price is now trading above it rather than testing it.

The recovery from the October low is sharp. December traded at $2.90 on October 29. At $3.29, the contract has gained 39 cents, or 13.4%, in eight sessions. The week of October 26 closed at $3.050, so the current print is 7.9% above that weekly close. The front month also spent two straight sessions in technically overbought territory, the first such stretch since June. In natural gas, that tends to signal a strong rally in its early stage more often than an exhausted one.

The longer perspective keeps expectations measured. Front-month gas peaked at $7.46 on January 28 during the height of the winter shock and the Middle East supply disruption. At $3.29, the market is 55.9% below that peak. Prices are 9.1% below the $3.618 level where 2026 began. They are also 26.4% below the $4.47 average Henry Hub price of November 2025. The rally is a repricing from a deeply discounted base, not a return to crisis pricing.

Spot gas at Henry Hub tells the same story from the physical side. Next-day gas in Louisiana fell to $2.52 on October 26, the lowest since November 2024. Spot later recovered to $2.76, and the December contract now holds a premium above it that the market expects colder weather to close. The forecast below treats $3.24 as the new floor to defend. It sets $3.39 as the first resistance and $3.60 as the upside target before the December contract expires on November 25.

Two Sessions Built the Three-Week High

The rally that began Monday had three drivers, all of which pointed the same way within a 48-hour window. Weather models shifted colder for the second half of November. Lower 48 production printed its weakest monthly pace since summer. Gas flows to the nine major US LNG export terminals set a new monthly record. Each driver alone would have supported prices. Together they forced a repricing of the December contract, which had been priced for a mild start to winter.

Monday’s 5% advance was the largest single-session gain for the front month in several weeks. It took December from the $3.07 area to $3.218. Tuesday’s 0.6-cent gain to $3.224 looks small, but it confirmed that sellers could not reverse Monday’s move. A second consecutive close at a three-week high is the condition trend-following systems look for before they flip their signals. Daily trend models on the front month moved from sell to buy before the Wednesday open. That shift added systematic demand to the discretionary buying already in place.

The order of the gains matters. Monday’s rally was led by weather. Tuesday’s hold was led by LNG, because colder forecasts alone had already been priced and the export number gave buyers a second reason to stay long. Wednesday’s push above $3.30 came in thin holiday trading, which means price can travel further on smaller orders. That cuts both ways. Thin markets amplify breakouts, but a breakout made on a holiday has to be confirmed when full participation returns on Thursday and Friday.

The next confirmation point is the weekly settlement on Friday, November 13. A weekly close above $3.241 would leave December above the 50% retracement on the weekly chart for the first time since the October slide began. A weekly close above $3.30 would print the strongest weekly settlement for the contract since mid-October. Below the market, the October 29 low at $2.90 is now 39 cents away. That distance gives the bulls room to absorb a soft storage number without breaking the structure.

The intraday range on Wednesday spanned $3.18 to $3.37. A 19-cent range on a holiday is wide, and it shows how much two-way interest remains despite the directional move. Volatility-based models put the weekly range at $2.828 to $3.388, so Wednesday’s high came within 1.8 cents of the top of that band. That proximity is why $3.39 is the first ceiling that matters.

Production Slips 2.8 Bcf/d From the August Record

Supply is the variable that changed most quietly and most decisively over the past month. Average dry gas output in the Lower 48 fell to 112.2 billion cubic feet per day so far in November. That is down from 113.4 Bcf/d in October and 115.0 Bcf/d in the August record month. The decline from August is 2.8 Bcf/d, or 2.4%. The month-over-month drop from October is 1.2 Bcf/d, or 1.1%. Early-November daily estimates ran even lower, with one reading at 111.2 Bcf/d. Output has recovered slightly from that trough but remains well below the summer pace.

Some of the decline is seasonal. Producers schedule pipeline maintenance in October and November, before winter demand peaks, and regional constraints in Appalachia and the Haynesville trim flows during these windows. Some of it is economic. Henry Hub spot at $2.52 in late October was below the marginal breakeven for a large share of dry-gas acreage. Several operators chose to curtail volumes or delay turn-in-lines rather than sell into a sub-$3 market. When spot recovers above $3, part of that curtailed gas will come back. That cap on the rally is why the upside target sits at $3.60 and not higher.

The rig count adds context. Total US drilling activity is up 53 rigs from a year ago, a 10% increase, with 40 oil-directed and 11 gas-directed additions. The gas-directed count is up 9.1% year over year. Expand Energy, the largest gas producer, guided 2026 output at 7.45 to 7.55 Bcfe/d on roughly $3 billion of capital spending, up from 7.2 Bcfe/d last year. Its October 27 guidance is published through its investor relations channel. Growth capacity is in place. It is being held back by price, not by geology.

The official annual numbers frame the same tension. The EIA’s Short-Term Energy Outlook projects dry gas production at 112.2 Bcf/d for 2026, rising to 116.1 Bcf/d in 2027. The current November pace matches the 2026 annual figure exactly. The 2027 projection implies a 3.9 Bcf/d increase, or 3.5%. Associated gas from oil drilling in the Permian is the main source of that growth, and with WTI at $88.18, oil-directed drilling has every incentive to keep expanding.

For the December contract, the 2027 supply wave is too far out to matter. The near-term question is whether production stays below 113 Bcf/d through the end of November. If it does, the balance tightens into the expiry window and the $3.60 target comes into play. If curtailed volumes return as spot climbs, the rally is likely to stall in the $3.39 to $3.45 zone.

LNG Feedgas at 19.3 Bcf/d Sets a New Monthly Record

The single strongest bullish number in the market is LNG feedgas. Average flows to the nine major US export terminals have reached 19.3 Bcf/d so far in November. That is above October’s average of 18.4 Bcf/d, which had itself been a monthly record. The increase is 0.9 Bcf/d, or 4.9%, in one month. In early November, daily flows briefly slid to 18.1 Bcf/d during maintenance. The rebound to a record pace within a week shows that the outage was temporary and that terminal capacity is running close to its limit. On individual days in October, feedgas peaked above 21.2 Bcf/d.

The annual trend is steep. US LNG exports averaged 15.1 Bcf/d in 2025. The EIA projects 17.6 Bcf/d for 2026, a 16.6% increase. First-half 2026 export volumes reached 65.9 million tonnes, up about a quarter from the prior-year period. New liquefaction trains at Plaquemines, Corpus Christi Stage 3 and Golden Pass added capacity through the year. The current 19.3 Bcf/d pace is 1.7 Bcf/d above the 2026 annual projection, which shows how much of that capacity arrived in the second half.

The scale is easiest to see as a share of supply. At 19.3 Bcf/d against production of 112.2 Bcf/d, LNG feedgas now absorbs 17.2% of Lower 48 dry gas output. Five years ago that share was in single digits. Export demand does not depend on the weather. It runs at near-full capacity in July and January alike, as long as the international spread covers shipping and liquefaction costs. With European and Asian LNG prices more than $20 above Henry Hub, every terminal that can run, runs.

That inelastic demand reshapes how weather affects prices. A mild November used to leave the US market swimming in gas because domestic heating demand was the only marginal buyer. Today, nearly one-fifth of supply leaves the country before domestic weather matters at all. That is why storage injections over the summer were smaller than the production record alone would have implied. It is also why inventories now trail last year despite record output in August.

The risk to the LNG thesis is outages, not demand. A single terminal trip at Sabine Pass or Freeport can remove 2 Bcf/d overnight, and Gulf Coast fog regularly delays vessel loading through November. Traders should treat any feedgas print below 18 Bcf/d as a warning signal for the December contract. As long as flows hold above 19 Bcf/d, export demand gives the market a floor that did not exist in previous mild autumns.

Storage at 3,801 Bcf Sits Above the Five-Year Line, Below Last Year

The EIA’s Weekly Natural Gas Storage Report for the week ending October 30 showed a net injection of 77 Bcf, which took working gas in storage to 3,801 Bcf. Inventories stand 109 Bcf, or 2.8%, below the 3,910 Bcf held a year earlier. They are 55 Bcf, or 1.4%, above the five-year average of 3,747 Bcf. That split defines the current market. Against the five-year benchmark, supply is comfortable. Against last year, the cushion is thinner, and last year’s winter ended with prices near $4.50 in late November.

The week before, ending October 23, brought an 80 Bcf injection that took stocks to 3,724 Bcf. That print ended a run of ten consecutive weeks of below-average builds. It also explains why prices fell through late October: the market had grown used to tight injection numbers, and two above-average builds in a row reset expectations quickly. The October 30 build of 77 Bcf again ran above the seasonal norm. That kept inventories on track to finish the injection season at or slightly above 3,900 Bcf.

The regional detail is more supportive than the national total. The South Central region holds 1,208 Bcf after a 40 Bcf injection, split between 22 Bcf in salt caverns and 18 Bcf in non-salt facilities. South Central remains below its five-year average. That matters because this region feeds the Gulf Coast LNG terminals directly, and salt caverns are the most flexible storage in the country. Low salt inventories leave less buffer for a cold snap in Texas or Louisiana. The Pacific region holds 296 Bcf after a 1 Bcf withdrawal, an early sign that western demand has already turned seasonal.

Since March, inventories have held above the five-year average without interruption. They peaked at 7.7% above normal in April after a mild spring and record output. The surplus has since shrunk from 7.7% to 1.4%, a reduction of more than four-fifths in seven months. Strong LNG demand and hot summer power burn did that work. The direction is what matters for the winter strip: the surplus has been eroding for half a year, and colder weather in late November would accelerate the erosion.

The EIA puts gas at 40% of US power generation in 2026, falling to 39% in 2027. Power burn stays structurally high even as coal plants retire and renewables expand. Winter power demand will reinforce heating demand rather than offset it.

Friday’s EIA Report and the Week Ending November 6

The next EIA storage report is due Friday, November 13, covering the week ending November 6. The schedule is shifted by one day because of the Veterans Day holiday. The five-year average injection for the corresponding week is 60 to 62 Bcf. The year-ago comparison for the same week was a smaller injection, which leaves room for the year-over-year deficit to widen or narrow depending on the print.

Weather during that week was warmer than normal across most of the country. Meteorologists had expected above-normal temperatures through at least November 19. Mild conditions during the survey week point to an injection above the five-year average, possibly in the mid-to-high 60s or low 70s Bcf. Lower production works in the opposite direction. Early-November output averaged 111.2 to 112.2 Bcf/d, more than 1 Bcf/d below October. Over seven days, a 1.2 Bcf/d production drop removes 8.4 Bcf from the weekly balance. Higher LNG feedgas removes another few Bcf. The net effect should be a build close to, but not far above, the seasonal norm.

Three scenarios frame the reaction. A build of 60 Bcf or less would be bullish. It would shrink the surplus to the five-year average, keep the year-over-year deficit above 100 Bcf, and likely carry December through $3.39 toward $3.45. A build of 62 to 72 Bcf would be neutral to mildly bearish. The market priced most of that outcome on Monday and Tuesday, and December would likely hold the $3.24 to $3.30 band. A build above 75 Bcf would be bearish. It would push the surplus back above 2% and test support at $3.07.

Total inventories after Friday’s report should land between 3,860 and 3,880 Bcf. Last year’s injection season peaked near 3,950 Bcf, so this year’s peak is tracking below that level. That is a structurally tighter starting point for winter, even if it does not look dramatic on the five-year chart.

The report will also be the last full storage print before the forecast window flips to colder weather. Traders will watch whether the South Central salt injection slows. A salt injection below 10 Bcf would signal that Gulf Coast demand from LNG terminals is pulling gas faster than the region can store it, which supports the cash market at Henry Hub directly. That signal matters more for December than the headline national number, because Henry Hub is physically located in the South Central region.

Weather Forecasts Lift Demand From 114.7 to 120.0 Bcf/d

Weather is the reason the market moved on Monday, and the forecast shift was large. Average Lower 48 gas demand, including exports, was estimated at 114.7 Bcf/d this week. Forecasts call for 120.0 Bcf/d next week. That is an increase of 5.3 Bcf/d, or 4.6%, in seven days. One week earlier, the same projection for the following week stood at 116.4 Bcf/d against 108.0 Bcf/d at the time. Demand forecasts have been revised higher in consecutive updates, and the upward revisions themselves are what drive buyers into the market.

The pattern is a classic transition from autumn to winter. The early November forecast called for above-normal temperatures through November 19. The updated outlook brings cooler conditions across the central and eastern United States through November 20, with colder risks building in the final ten days of the month. Heating demand in the Midwest and Northeast, the two largest consuming regions, rises nonlinearly as temperatures fall below 50 degrees Fahrenheit. A modest shift in the temperature forecast therefore produces a disproportionate jump in heating degree days.

The comparison between supply and demand is now stark. At 120.0 Bcf/d of projected demand and 112.2 Bcf/d of dry production, demand outruns domestic output by 7.8 Bcf/d. Canadian pipeline imports cover part of that gap, and storage covers the rest. When demand exceeds production plus imports, the market moves from injection to withdrawal. If the forecast holds, the first net withdrawal of the season could arrive in the week ending November 20 or 27. That is earlier than the market had expected two weeks ago.

The weather risk is not one-sided. Some regional forecasts still show warmth across parts of the central and northern United States next week. Those pockets of warmth limit the demand surge. A forecast that reverses warmer over the weekend could easily wipe out 15 to 20 cents from the December contract within a session. Weather models updated on Thursday and Friday will matter as much as the storage report.

The longer-range outlook is mixed. NOAA’s seasonal outlook favors a warmer-than-normal winter for much of the southern tier, which caps the potential for sustained extreme cold. December futures price the full month of December, though, and December heating demand rises sharply every year regardless of the anomaly. Even a mild December will lift demand well above November levels. That seasonal step is the base of the $3.60 target, and it does not require an exceptional cold snap.

The Qatar Shock and the $22 Transatlantic Spread

The global gas market is in its tightest condition in years, and that backdrop explains why US exports run at full capacity. No LNG cargo has transited the Strait of Hormuz since July 12. Qatar, the world’s second-largest LNG exporter, has lost 17% of its export capacity and delayed European deliveries into December, with 35 cargoes under force majeure. Doha says it can resume normal shipments within weeks of a reopening, but the timing of that reopening depends on the conflict, not on Qatar. Hostile incidents in the strait reached 37 in October, and 10 more have been recorded in the first eleven days of November.

The global supply shortfall is historic. The International Energy Agency projects that global LNG supply will fall 3% in 2026, a reduction of 20 billion cubic meters. That would be the largest annual decline on record. Qatar has responded partly by signing 7 million tonnes per annum of US LNG purchase agreements, effectively buying American cargoes to meet its own contractual obligations to Asian and European buyers.

International prices reflect the scarcity. Northwest European LNG trades at $25.37 per MMBtu, and Northeast Asian LNG at $26.50. Against Henry Hub at $3.29, the European spread is $22.08 and the Asian spread is $23.21. European LNG costs 7.7 times as much as US gas, and Asian LNG costs 8.1 times as much. Dutch TTF spot prices are up about 70% year over year. Under these conditions, every US terminal operates at maximum utilization, because each cargo earns a margin many times larger than its shipping and liquefaction costs.

The global market is also volatile. European gas futures fell 9% on November 9 on reports of progress in diplomacy with Iran. A diplomatic breakthrough that reopened Hormuz would let Qatari cargoes resume, compress the transatlantic spread, and reduce the urgency of European purchases of US gas. Even in that scenario, the spread would remain wide enough to keep US terminals running. A collapse from $22 to $10 would still leave every cargo profitable. The reopening risk therefore affects sentiment more than physical flows.

For Henry Hub, the main channel is indirect. Global scarcity guarantees full-capacity US export demand. Full-capacity export demand guarantees that storage cannot build as freely as in past autumns. And slower storage builds guarantee that winter weather will tighten the balance faster than the five-year average implies.

Ten Sessions Left for NGZ26 and the January Carry

The December contract, NGZ26, expires on November 25, which leaves ten trading sessions including Wednesday. Expiry dynamics will shape price action from here. Two weeks ago, the November contract expired at $2.776 after a 6.4% decline from its first prompt-month day. Between July 1 and its expiry, it fell $0.54, or 16%. Over the same period, December fell 23.4% and January fell 20.6%. The deferred winter months fell further than the prompt month during the autumn slide. They now have more room to recover.

The structure of the curve tells traders what is expected. On the earlier snapshot, the December-January carry stood at $0.44, meaning January traded 44 cents above December. With December at $3.29, January would trade near $3.73 at that spread. That premium reflects the expectation that January brings the coldest weather of the year and the steepest storage withdrawals. When November expired, December became prompt at a 28.4-cent premium, a 10.2% contango jump. A similar jump will appear on continuous charts when January becomes the front month on November 26.

Traders using continuous contracts such as NG1! should plan for that roll. A chart reading $3.40 on November 25 could show $3.80 on November 26 with no change in underlying value. The upside target of $3.60 applies to the December contract specifically. If the carry holds near 40 cents, January’s equivalent target is $4.00, which also sits just below the 52-week moving average at $4.083 on the weekly chart.

Expiry week behavior in natural gas follows a familiar pattern. Short sellers who held December into the final sessions must buy back or roll. When the weather turns colder in the final ten days, that forced buying produces sharp gains in the last three or four sessions. The October contract and the November contract both expired near their lows because weather was mild at expiry. December faces the opposite setup. Its final sessions coincide with the forecast cold turn after November 20.

Open interest in December was 297,314 contracts on the earlier snapshot. That is a large position to roll in ten sessions. Rolling flows will widen or narrow the December-January spread depending on whether longs or shorts are more eager to exit. A narrowing carry, with December gaining on January, would confirm that near-term tightness is real.

A Crowded Short Meets an Overbought Tape

Positioning is the factor most likely to stretch the rally beyond fundamentals. On the earlier snapshot, money managers held a net short position of 157,000 contracts in Henry Hub futures and options. That is a heavily bearish stance built during the October decline, when warm weather, record output, and the 80 Bcf storage print gave sellers every reason to press. The position was profitable while December traded at $2.90. At $3.29, much of that profit has disappeared, and shorts entered after mid-October are now losing money.

A short position of that size behaves like stored fuel. When weather forecasts turn colder and the price breaks above a technical level, shorts buy to limit losses, and those purchases push prices further. Monday’s 5% gain had the profile of short-covering: a large move on a forecast shift with no change in the storage data. Tuesday’s flat session showed that the first wave of covering was finished. Wednesday’s rise above $3.30 suggests that a second wave has begun, triggered by the 50% retracement breakout at $3.241.

The overbought signal points the same way. The front month spent two consecutive sessions in overbought territory on the 14-day relative strength measure, the first such stretch since June. In a market with a large net short, overbought readings tend to persist rather than reverse, because the covering flow keeps buying into strength. The June stretch preceded a summer rally that lasted several weeks. Overbought conditions are a warning of short-term fatigue, not a sell signal, in this setup.

The risk is symmetrical. If the weather forecast reverses warmer, shorts who have not yet covered will add to their position, and late longs who bought the breakout will sell. A failure back below $3.24 would trap the Wednesday buyers and could send the contract quickly to $3.07. That is why the stop-loss logic in the technical section uses $3.24 rather than a deeper level.

Volume will tell traders whether covering is genuine. Holiday trading on Wednesday did not offer a real test. Thursday and Friday, with full participation and the storage report, will. A rise above $3.39 on above-average volume would indicate that the net short is being liquidated in earnest. A drift higher on light volume would indicate that the rally is running on thin liquidity and remains vulnerable. The weekly positioning data released Friday will show how much of the 157,000-contract short had been covered by Tuesday’s close.

Oil at $88, a 5% Ten-Year and a Hawkish Fed

The macro backdrop is mixed for natural gas, and its effects run through several channels. West Texas Intermediate crude trades at $88.18 per barrel and Brent at $92.81, both supported by the Hormuz conflict and the attacks on shipping. The oil-to-gas price ratio stands at 26.8 to 1 using WTI and Henry Hub. On an energy-equivalent basis, a barrel of oil contains about six times the energy of an MMBtu of gas. At 26.8, gas is priced at less than a quarter of oil’s energy value, one of the widest discounts on record. That discount drives industrial fuel switching toward gas and supports long-run demand.

High oil prices have a second effect that cuts against gas. They push drilling activity toward oil, and oil wells in the Permian produce large volumes of associated gas regardless of the gas price. The 40 oil-directed rigs added over the past year will lift associated gas output through 2027. That is the main reason the EIA projects production rising to 116.1 Bcf/d next year, and why longer-dated gas contracts trade at a discount to the current winter strip.

Rates and the dollar weigh on commodities in general. The 10-year Treasury yield stands at 4.998%, essentially at 5%. Consumer prices rose 0.4% in the latest monthly reading, and futures now price a Federal Reserve rate hike with full certainty. The dollar index sits at 102.86. Higher rates raise the cost of holding commodity inventory and of financing new drilling, and a firm dollar makes US commodities more expensive for foreign buyers. For LNG, the dollar effect is muted because the transatlantic spread is so wide that currency shifts do not change export economics.

The OPEC+ meeting on November 29 falls after December gas expiry but before January settles. A decision to raise oil output would cut crude prices, slow oil-directed drilling in the medium term, and reduce associated gas growth in 2027. A decision to hold output would keep oil above $85 and preserve the drilling pace. Neither outcome changes the December gas balance. Both would shape the 2027 strip.

The conflict in the Gulf is the variable that links all these markets. Shipping attacks lift oil and close Qatari LNG routes. Diplomatic progress lowers both. Henry Hub is the least exposed of the three because the US is a net exporter. US gas benefits from a long conflict through export demand and loses only modestly from a resolution.

Producers and ETFs: EQT, CHK, CTRA, LNG, UNG, BOIL and KOLD

The December rally runs through the equity complex in different ways, depending on each company’s exposure to Henry Hub prices, to export margins, or to oil. EQT is the purest large-cap expression of Appalachian gas prices. Its production is almost entirely dry gas, and its realized prices follow regional hubs that trade at a discount to Henry Hub during autumn pipeline maintenance. A move from $2.90 to $3.29 in the December contract lifts EQT’s forward revenue on unhedged volumes directly. The basis discount narrows when Northeast demand rises in the cold.

Expand Energy, which trades under the CHK ticker on most platforms, has the widest operating footprint in both the Haynesville and Appalachia. Its 2026 guidance of 7.45 to 7.55 Bcfe/d with roughly $3 billion in capital spending shows the company prepared to grow when prices allow. The Haynesville assets feed directly into Gulf Coast LNG corridors, giving the company access to the strongest demand pull in the country. Coterra, NASDAQ: CTRA, combines Marcellus gas with Permian oil and is the most balanced of the three. With WTI at $88.18, the oil side of its portfolio limits the downside if gas rallies stall.

Cheniere Energy, NYSE: LNG, benefits from export volume rather than gas price. Its contracts are structured mainly on fixed liquefaction fees plus a percentage of Henry Hub. Record feedgas at 19.3 Bcf/d and a $22 transatlantic spread put its spot cargoes on the most profitable footing in years. A Hormuz reopening would compress spot margins, but contracted volumes keep the base earnings stable.

The exchange-traded products require more care. UNG holds front-month futures and rolls each month, so it loses value during contango, when the next contract is more expensive than the current one. With the December-January carry near 44 cents, the roll on November 25 will cost UNG holders a significant share of value. BOIL offers 2x daily leverage to the futures index and KOLD offers −2x daily inverse exposure. Both reset daily, so their returns over a multi-week period can diverge sharply from twice the futures move, especially in a volatile market.

For a short-term trade aligned with the $3.60 December target, direct futures or BOIL held for only a few sessions remain the most precise instruments. For a longer winter position, the producer equities carry less roll decay. Cheniere carries the least exposure to a reversal in domestic weather.

Technical Map: Support at $3.07, Resistance at $3.39, Target $3.60

The technical structure has shifted from bearish to constructive within one week. On the daily chart, December trades above the longer-term exponential moving average at $3.07. That moving average was resistance during the October decline and now forms the second support level. The first support is the 50% retracement at $3.241, which the contract broke through on Wednesday. As long as December holds above $3.24 on a closing basis, the breakout remains valid.

Resistance is layered above the market. The first ceiling is $3.388, the top of the volatility-based weekly range, which Wednesday’s $3.37 high nearly reached. The second is the October 13 high of $3.28 on the November contract. Adjusted for the December premium, that high maps to the $3.45 to $3.50 area on the current front month, where sellers defended in mid-October. Above $3.50, the next significant level is the 61.8% retracement of the summer-to-October decline, at $3.58 to $3.62. That zone is the upside target at $3.60.

The weekly chart remains in a long-term downtrend. The 52-week moving average at $4.083 still slopes lower and represents the long-term resistance that separates a winter rally from a structural trend reversal. December cannot reach it before expiry under normal weather. January, trading at a 44-cent premium, would reach an equivalent level near $4.00 if December hits $3.60. A break above $4.08 on the continuous chart in December or January would mark the first long-term trend reversal since the January peak.

Below the market, the supports are clear. A close below $3.24 would neutralize the breakout and target $3.07. A close below $3.07 would reverse the daily trend and target the $2.896 level that held at the end of October. A break below $2.90 would reopen the swing low at $2.676 and invalidate the bullish forecast entirely. Each of these levels is at least 22 cents from the next, which gives traders clean reference points for stops.

The practical trading map is straightforward. Long entries on pullbacks into the $3.24 to $3.26 zone offer the best risk-to-reward ratio. A stop below $3.18, Wednesday’s intraday low, risks 6 to 8 cents per contract. A target at $3.60 offers 34 to 36 cents of reward, a ratio near 5 to 1. A breakout above $3.39 on full volume would justify adding to positions, with the stop raised to $3.24.

Verdict: Buy Dips Toward $3.24 With a $3.60 Target Before the November 25 Expiry

December natural gas at $3.29 is a buy, with a $3.60 target and protection below $3.18. The case rests on four facts that line up in the same direction for the first time this autumn. Lower 48 production has fallen to 112.2 Bcf/d, 2.8 Bcf/d below the August record. LNG feedgas has reached a record 19.3 Bcf/d, absorbing 17.2% of domestic output. Demand is projected to rise from 114.7 to 120.0 Bcf/d next week, putting consumption 7.8 Bcf/d above production. And a 157,000-contract net short gives the rally fuel to extend beyond what fundamentals alone would justify. Storage at 3,801 Bcf is 1.4% above the five-year average, which is enough to prevent a price spike. It is also 2.8% below last year, which is enough to keep the winter premium intact.

The global backdrop supports the floor. With Hormuz closed to LNG since July 12, Qatar’s capacity down 17%, and European and Asian LNG priced at $25.37 and $26.50, US export terminals will run at full capacity through winter regardless of domestic weather. That export floor did not exist in past mild autumns. It is why the October low at $2.90 is unlikely to be revisited unless the weather outlook collapses.

The risks are specific and measurable. A storage build above 75 Bcf on Friday, a weather model reversal toward warmth over the weekend, or a terminal outage cutting feedgas below 18 Bcf/d would each threaten the $3.24 support. A diplomatic breakthrough in the Gulf would weigh on sentiment through the European market, as it did on November 9. Curtailed production returning as spot climbs would cap the move near $3.45.

The base case is a test of $3.39 by Friday, a push into the $3.45 to $3.50 zone next week as colder weather after November 20 arrives, and a run toward $3.60 in the final sessions before expiry on November 25. January, at its current carry, maps that outcome to $4.00 on continuous charts after the roll. A close below $3.07 would invalidate the forecast and return the market to its October range. Above that level, the bias is bullish into expiry.

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