December Natural Gas Slips to $3.23 as Storage Surplus Widens, but 20 Bcf/d LNG Keeps $3.40 in Play

December Henry Hub natural gas futures (NGZ26) traded at $3.23 per million British thermal units late on Friday, November 13, down 10.7 cents or 3.2% from Thursday’s settlement of $3.337. The contract slid through the European morning as warmer overnight weather forecasts and a rebound in production undercut Thursday’s weather-driven rally, then struggled to gain traction after the weekly storage report showed another above-average injection.

The retreat comes two days after the contract hit its highest level since October 13. December gas touched $3.397 on Wednesday, November 11, before forecasts showing a shorter cold spell sparked long liquidation and a closing price reversal. The contract settled $0.081 lower at $3.215 that day, bounced 12.2 cents to $3.337 on Thursday, and gave back most of that gain on Friday.

The week still shows a gain. December gas settled at $2.997 on Friday, November 6, and jumped 22 cents, or 7.34%, to $3.217 on Monday in the biggest one-day rally of the autumn. At $3.23, the contract is up 7.8% on the week. Over the past month, prices have risen 1.1%. Over the past year, they have fallen 29.2%.

The forces behind the week are clear. On the bullish side, flows to U.S. liquefied natural gas export terminals set new records above 20 billion cubic feet per day, Lower 48 production slipped from its August peak, and speculative funds carried a record net short position that left them exposed to any cold forecast. On the bearish side, storage keeps building faster than normal, the five-year surplus keeps widening, and the U.S. Energy Information Administration now expects a mild November to leave more gas in storage heading into winter.

The December contract expires on November 25, which leaves seven trading sessions after Friday. That short window raises the stakes on every weather model run between now and expiry.

The thesis for this forecast is that the market is caught between record export demand that sets a floor near $3.00 and a storage surplus that caps rallies until real cold arrives. The upside target sits at $3.40, a retest of Wednesday’s $3.397 high and a 5.3% gain from $3.23. A move there requires the cold forecast for November 16 to 20 to extend into the final week of the month and LNG feedgas to hold above 20 Bcf/d.

The Storage Report: 61 Bcf In, Surplus Out to 54 Bcf

Friday’s storage data explains why the rally stalled.

The Energy Information Administration reported that working gas in underground storage across the Lower 48 states rose by 61 billion cubic feet in the week ended November 6, bringing total inventories to 3,862 Bcf. The build came in below the 65 to 66 Bcf consensus, with survey estimates ranging from 60 to 82 Bcf, but it was well above the five-year average injection of 40 Bcf for the same week.

That gap matters more than the miss against expectations. A build 21 Bcf above the five-year norm widens the surplus to the five-year average. Inventories now sit 54 Bcf, or 2.0%, above the five-year average and 2.3% below year-earlier levels. The prior week’s report, for the week ended October 30, showed a 77 Bcf build to 3,801 Bcf, 1.4% above the five-year average.

The regional data shows where gas is accumulating. The East region held 938 Bcf after a 12 Bcf build, above the year-ago 913 Bcf and the five-year average of 910 Bcf. The South Central region rose 27 Bcf to 1,235 Bcf, just below its five-year average of 1,239 Bcf and well below the year-ago 1,315 Bcf. Within South Central, salt storage rose 16 Bcf to 312 Bcf, below its five-year average of 331 Bcf, while nonsalt storage reached 924 Bcf, above its five-year average of 907 Bcf. The Pacific region rose 2 Bcf to 298 Bcf.

The East surplus is the bearish detail. Consuming-region inventories above normal reduce the risk of winter price spikes in the Northeast, where pipeline constraints often drive extreme cash prices. The South Central salt deficit is the bullish detail: salt caverns can withdraw gas quickly during cold snaps, and a below-normal salt balance leaves less flexibility for Gulf Coast demand, including LNG exports.

The market reaction showed which side won. A smaller-than-expected build would normally lift prices, but the surprise failed to support futures on Friday because the injection still widened the surplus heading into winter. Traders focused on the trend rather than the miss.

The next report arrives November 19 for the week ended November 13. Colder weather in the East during that week should cut the injection, and a build at or below the five-year average would stop the surplus from widening. Another build of 60 Bcf or more would push inventories above 3,920 Bcf and reinforce the bearish storage picture.

For the forecast, storage is the main cap on prices. As long as injections run above the five-year average, rallies toward $3.40 will meet sellers.

EIA’s November Outlook: A Warm Start Adds 67 Bcf to Winter Supply

The Energy Information Administration’s latest Short-Term Energy Outlook sets the official baseline for the winter, and it leans bearish for the near term.

The agency’s November Short-Term Energy Outlook said a warm start to November is putting downward pressure on U.S. natural gas prices. Its forecast assumes 13% fewer heating degree days across the United States in November than the 10-year average for the month. As a result, the EIA now expects 3,840 Bcf of natural gas in storage at the end of November, 67 Bcf more than it forecast in October.

The higher storage path flows through the entire winter. The EIA raised its projected end-of-winter storage inventories by just under 3% from October’s forecast. It now expects the Henry Hub spot price to average $2.87 per MMBtu from November through March, below Friday’s December futures price of $3.23.

That gap between the EIA’s forecast and the futures curve is a key tension. Futures at $3.23 for December delivery price in more winter risk than the EIA’s base case. If the agency’s mild-weather assumption proves correct, futures have room to fall toward its $2.87 average. If November turns colder than the EIA assumed, the forecast will be revised higher next month, and futures would be vindicated.

The production outlook adds to the supply cushion. The EIA continues to project a record year for dry gas output, raising its 2026 average to 113 Bcf/d in the November outlook, up 0.7% from its October forecast. Production during the first 12 days of November ran 1.4% above the same period a year earlier, a record for the period.

The EIA’s outlook also captures the demand side. LNG exports keep growing as new export capacity comes online, and power demand from data centers adds a structural layer of consumption. The grid operator PJM warned this week of shrinking power reserves as natural gas and electricity demand grows, a reminder that gas-fired generation remains central to meeting new load.

For the forecast, the EIA’s outlook defines the bearish case. A mild winter, record production and a storage surplus support the agency’s $2.87 average. The bullish case requires weather to break from the EIA’s assumptions, and the next two weeks of forecasts will show whether that happens.

LNG Feedgas Above 20 Bcf/d: The Demand Floor

The strongest support under natural gas prices comes from export demand, and that demand keeps setting records.

LNG feedgas deliveries set a new daily record on November 7, reaching 20.3 Bcf/d. Flows remained above 20 Bcf/d for three consecutive days through November 9 before moderating to 19.6 Bcf/d on November 11. Estimates for Thursday put flows at 20.6 Bcf/d, and forward market data showed feedgas touching 21 Bcf/d. Average flows to the nine major U.S. LNG export plants reached a record 19.3 Bcf/d in the first part of November, above October’s monthly record of 18.4 Bcf/d.

The year-to-date picture shows the scale of the shift. Feedgas deliveries averaged 18.0 Bcf/d through November 11, 15.3% higher than the same period in 2025, as domestic export capacity continues to expand. At 19.3 Bcf/d against Lower 48 production of 112.2 Bcf/d, LNG feedgas now absorbs 17.2% of domestic dry gas output.

That demand is sticky. LNG export contracts run for years, and buyers in Europe and Asia have strong incentives to keep cargoes flowing. European gas prices show why. The Dutch TTF benchmark traded at €89.86 per megawatt-hour on Friday, down 2.6% on the day but up 3.1% over the month and 187.6% over the year. At those prices, U.S. LNG cargoes earn wide margins, and export plants run at full capacity whenever they can.

The new capacity keeps coming. Venture Global’s Plaquemines plant in Louisiana and Cheniere Energy’s Corpus Christi expansion in Texas have ramped up through 2026, and each new train adds demand for feedgas. That growth means the U.S. is exporting a rising share of its production, which tightens the domestic balance even as output stays near record levels.

Feedgas is also a source of volatility. Maintenance, weather disruptions on the Gulf Coast and outages at individual plants can cut flows by 1 to 2 Bcf/d in a day. A feedgas print below 18 Bcf/d would signal a warning for the December contract, because it would release gas back into the domestic market at the moment storage is already above normal.

For the forecast, LNG feedgas sets the floor. As long as flows hold near 20 Bcf/d, the market absorbs record production and limits storage builds. That is why December gas did not fall further when the November contract expired and why $3.00 has held as a floor this month.

Production: Down From the August Record, Recovering Fast

Supply moved from tailwind to headwind and back during the week, and production remains the variable that decides whether the storage surplus grows.

Lower 48 dry gas production peaked at a record 115.0 Bcf/d in August. Output has since slipped, with November production running near 112.1 to 112.2 Bcf/d. On November 3, daily production fell to 109.2 Bcf/d, a nine-month low, as pipeline maintenance and price-related curtailments reduced flows. That dip helped fuel the early-November rally.

The recovery came quickly. Lower 48 production was estimated at 112.2 Bcf/d on Wednesday, while demand ran at 79.1 Bcf/d. Friday’s selloff was driven in part by rebounding production, as producers restored volumes that had been curtailed when prices traded below $3.00 in October. Higher prices bring more supply, and the market’s response to $3.30 gas was to turn production back on.

The longer-term trend points higher. The EIA raised its 2026 production forecast to 113 Bcf/d, up from 112.2 Bcf/d. Production in the first 12 days of November ran 1.4% above the same period a year earlier, a record for the period. At its current pace, November production is tracking above the prior full-month November record set in 2025.

The supply response caps rallies. Producers in the Haynesville shale in Louisiana and East Texas, which sits next to Gulf Coast LNG terminals, respond to higher prices faster than other basins. Appalachian producers, constrained by pipeline capacity, adjust more slowly. Permian Basin associated gas, produced alongside oil, depends on crude prices rather than gas prices and keeps flowing regardless of Henry Hub levels.

Forward markets flagged the risk. Choppy production and record LNG demand helped lift forward prices across the United States and Canada, but a December supply surge could spoil those gains. If production returns to 114 or 115 Bcf/d in December while weather stays mild, storage would build faster than the market currently expects.

The production cycle also shapes the long-dated curve. The Calendar 2027 futures strip fell to a 59-month low of $3.00 per MMBtu in late October, a sign that the market expects ample supply next year. The March-April 2027 spread, known as the widow-maker, fell to a record low of 5 cents, showing little concern over end-of-winter shortages.

For the forecast, production sets the ceiling. Every rally above $3.30 brings curtailed volumes back online, and that supply response limits how far prices can run without sustained cold.

Weather: A Short Cold Spell Against a Mild Season Outlook

Weather drives natural gas prices in November more than any other factor, and the forecasts this week swung the market in both directions.

The rally that began Monday came on forecasts for colder temperatures. Below-average temperatures are expected in the eastern U.S. from November 16 to 20, which will raise heating demand in the most populous consuming region. Cooler conditions are forecast to persist until November 20. Traders priced the possibility that the cold would extend into the final week of November and the start of December.

That bet unwound on Wednesday. Updated forecasts called for temperatures to return to seasonal norms after November 20, and the contract fell from its $3.397 high to settle at $3.215. Thursday’s models brought back some cold risk, and the contract rose to $3.337. Friday’s overnight forecasts turned warmer again, and the price fell back to $3.23.

The pattern shows a market trading each model run. Cold forecasts lift prices, and warm revisions send them lower. With the December contract expiring on November 25, every forecast for the November 20 to 30 window has a direct effect on the contract’s final settlement.

The broader season outlook leans mild. The EIA’s forecast assumes November heating degree days 13% below the 10-year average. A mild November leaves more gas in storage and reduces the risk of early-winter shortages. The market will need a sustained cold pattern, not a five-day dip, to change that picture.

The cash market showed what cold can do. Next-day prices at Algonquin Citygate, the main New England hub, rose by $1.67 on the day, a 91% jump, while Tennessee Zone 6 prices rose 95% to 98%. Those spikes show how quickly Northeast prices respond to cold when pipeline capacity tightens. Henry Hub futures, priced at the Louisiana hub, react less sharply, but sustained Northeast cold would still lift demand nationally.

Weekend forecasts will set the tone for Monday. If the models extend below-normal temperatures in the East beyond November 20, December gas has a path back to $3.30 to $3.40. If the models confirm a return to normal or warmer temperatures, the contract is likely to test $3.18 and $3.10.

For the forecast, weather is the swing factor. The upside target of $3.40 depends on the cold spell extending. Without that, the storage surplus and production response keep prices in a $3.05 to $3.30 range into expiry.

Fund Positioning: A Record Short Meets a Volatile Tape

The speculative positioning in natural gas futures explains why prices can move so sharply on forecast changes.

Speculative funds held a record net short position of 636,576 contracts in natural gas futures earlier this month. That position built up through October, when the November contract collapsed below $2.90 on warm forecasts and the market priced in an oversupplied winter. Funds bet that record production and a growing storage surplus would keep prices low.

The record short created fuel for the early-November rally. When cold forecasts and record LNG flows arrived, funds holding short positions faced losses and bought back contracts to cover. Monday’s 7.34% jump to $3.217 was the biggest rally of the autumn, a classic short-covering move. The rally extended to $3.397 on Wednesday before forecasts turned.

Positioning also explains the reversal. Once shorts covered, the buying pressure faded. Wednesday’s closing price reversal, a session that set a new high and then closed lower, signaled that the marginal buyer had disappeared. Friday’s 3.2% decline confirmed that sellers had regained control without fresh short covering.

The remaining short position still matters. Even after this week’s covering, funds likely remain net short by a wide margin. That creates two-way risk. If weather turns cold for longer than forecast, another wave of covering could push prices through $3.40 quickly. If weather stays mild, funds have little reason to cover, and their positions add to selling pressure as contracts approach expiry.

The expiry dynamic adds volatility. The December contract expires on November 25. Funds holding short positions in December must either cover or roll into January before expiry. That roll can create price swings in the final week of trading, especially if weather forecasts shift.

The January contract sits higher on the curve. Winter months carry a premium because of heating demand. When December expires, the front month will become January, which typically trades above December. That roll will lift the front-month price on continuous charts even if prices for each individual contract do not change.

For the forecast, positioning cuts both ways. A record short provides fuel for rallies on cold forecasts, but it also means the market has strong conviction that supply exceeds demand. The upside target at $3.40 requires a weather catalyst strong enough to force another round of covering.

The Global Picture: TTF at €89.86 and Exports at Full Tilt

U.S. natural gas prices are increasingly tied to global markets through LNG exports, and the global backdrop supports demand for American gas.

European gas prices remain elevated. The Dutch TTF benchmark traded at €89.86 per megawatt-hour on Friday, down 2.6% on the day but up 187.6% from a year earlier. European prices climbed to a two-week high and rose 7% in one session earlier this week, driven by colder weather and supply concerns. At those levels, Europe pays a large premium over U.S. Henry Hub prices, which keeps American LNG flowing across the Atlantic.

The price gap drives export economics. Converting TTF to U.S. dollars per MMBtu puts European prices far above Henry Hub’s $3.23. After liquefaction, shipping and regasification costs, U.S. exporters earn wide margins on every cargo. That spread gives export plants every incentive to run at full capacity, which is why feedgas keeps setting records.

The energy shock behind European prices is linked to the broader commodity market. Oil prices surged earlier this year during the U.S.-Iran conflict, with Brent reaching $113.43 at the end of October before falling back toward $97. Attacks on Saudi energy infrastructure revived supply concerns this week. Higher oil prices raise the value of oil-indexed LNG contracts in Asia and support spot LNG prices globally.

Asian demand adds a second outlet. Japan, South Korea, China and India compete for LNG cargoes, and winter demand in North Asia typically lifts spot prices from November through February. U.S. exporters can send cargoes to whichever market pays more, which gives American gas access to the highest bidder.

The global link also creates risk. A mild European winter or a drop in Asian demand would narrow the spread and could slow U.S. export growth. However, with European storage drawn down after the energy shock and new U.S. export capacity contracted under long-term deals, a sharp drop in feedgas is unlikely this winter.

The macro backdrop adds one more layer. The U.S. dollar index reached a 19-month high of 103.30 on Friday, which makes dollar-priced commodities more expensive for foreign buyers. A strong dollar can weigh on global energy demand at the margin, but LNG contracts are typically locked in, so the effect on U.S. export volumes is limited.

For the forecast, global markets support the demand floor under Henry Hub prices. As long as European prices stay elevated and new U.S. export capacity keeps ramping up, LNG feedgas will absorb a growing share of domestic production and limit how far prices can fall.

Technical Picture: $3.177 Reversal Trigger, $3.314 50-Day and $3.40 Target

The December contract’s chart shows a market testing a key reversal signal after a sharp rally, with clear levels on both sides.

Wednesday’s closing price reversal top at $3.397 marks the main resistance. A trade above that level would negate the reversal signal and open the way for a resumption of the uptrend. The upside target for this forecast sits at $3.40, a retest of that high and a 5.3% gain from $3.23.

The confirmation level sits at $3.177. A trade below that price would confirm the closing price reversal top and signal the start of a near-term correction. Friday’s decline to $3.23 brought the contract within 5.3 cents of that trigger.

The 50-day moving average sits at $3.314. December gas traded above that level on Thursday and fell below it on Friday. A daily close above $3.314 would signal that the uptrend remains intact. A failure to reclaim it would keep the bias neutral to bearish.

Retracement zones frame the next moves. The intermediate range runs from $3.652 to $2.830, with a retracement zone between $3.241 at the 50% level and $3.338 at the 61.8% level. Friday’s price sits just below the bottom of that zone. The short-term range runs from $2.830 to $3.397, with a retracement zone from $3.047 to $3.114. A move into that zone would be a normal pullback within an uptrend.

The main bottom sits at $2.830, the trend-change level set in late October when the November contract collapsed. A break below $2.830 would signal a return to the October downtrend. The long-term range runs from $5.164 to $2.830.

The floor pivots from Thursday’s session put support at $3.099, a pivot at $3.155 and resistance at $3.249. Friday’s price traded between the pivot and resistance.

Volume and open interest will confirm the next move. A break below $3.177 on rising open interest would signal fresh shorts entering, while a break on falling open interest would point to long liquidation ahead of expiry, a weaker and more temporary signal. A push above $3.314 on rising open interest would show new buyers rather than short covering alone.

The technical verdict: neutral between $3.177 and $3.314, bearish below $3.177 with targets at $3.114 and $3.047, constructive above $3.314 with the upside target at $3.40. A close above $3.397 would open the next leg toward $3.50 and the top of the intermediate range at $3.652.

Power Demand and Data Centers: The Structural Bid

Beyond weather and exports, natural gas demand has a structural growth driver that supports prices over the long run.

Data center developers are turning to natural gas to power their facilities, and the price risk they face varies widely by location. At some hubs, pricing is stable and predictable; at others, it can swing sharply with weather and pipeline constraints. That variation is shaping where developers choose to build and how they hedge fuel costs.

The grid is feeling the strain. PJM, the largest U.S. grid operator, covering 13 states from Illinois to New Jersey, warned this week of shrinking power reserves as natural gas and electricity demand grows. New data center load is arriving faster than new generation, and gas-fired plants are the main source of dispatchable power that can be built quickly.

The EIA expects U.S. natural gas power capacity to grow through 2027, but its share of electricity generation is set to slip as solar power expands. That means gas will burn in more plants, but the rise in solar output will limit growth in gas burned per megawatt-hour of total generation. The net effect still adds demand, especially during winter evenings when solar output falls and heating load peaks.

Winter power burn matters for the near term. In cold weather, gas-fired plants compete with residential and commercial heating for supply. In regions with tight pipeline capacity, such as New England and parts of the Mid-Atlantic, that competition drives cash prices sharply higher. This week’s 91% to 98% jumps in Algonquin Citygate and Tennessee Zone 6 prices showed that risk.

The data center buildout adds to that pressure. Many new facilities sit in Virginia, Texas, Ohio and Georgia, regions where gas is the marginal fuel for power. Each new gigawatt of data center load requires 0.15 to 0.2 Bcf/d of gas when served by combined-cycle plants. Across dozens of gigawatts of planned capacity, that adds several Bcf/d of demand over the next few years.

The structural bid shows up in the forward curve. Even with the Calendar 2027 strip near a 59-month low of $3.00, prices for winter months in later years trade well above that level. The January 2033 contract traded at $4.464, and December 2032 at $4.133, reflecting expectations that demand growth will tighten balances over time.

For the forecast, power demand is a long-term support rather than a near-term catalyst. It will not lift December gas to $3.40 on its own, but it adds a layer of demand that makes extreme price drops less likely.

Bull Case: The Path to $3.40

The upside case for December natural gas rests on five drivers, and the weekend weather models will decide whether they combine.

The first is extended cold. Below-normal temperatures are expected in the eastern U.S. from November 16 to 20. If weekend forecasts extend that cold into the final week of November, heating demand would rise sharply before the December contract expires on November 25. That would lift prices toward the $3.397 high.

The second is record LNG demand. Feedgas set a daily record of 20.3 Bcf/d on November 7, with estimates as high as 20.6 to 21 Bcf/d this week. Sustained flows above 20 Bcf/d absorb 17% to 18% of domestic production and limit storage builds.

The third is short covering. Speculative funds held a record net short position of 636,576 contracts. A shift in weather forecasts would force another wave of covering, which could push prices through resistance faster than fundamentals alone would suggest.

The fourth is a smaller storage build. The next EIA report on November 19 covers a week with colder weather in the East. A build at or below the five-year average would stop the surplus from widening and shift the storage narrative.

The fifth is the salt deficit. South Central salt storage sits at 312 Bcf, 19 Bcf below its five-year average. Salt caverns serve Gulf Coast demand, including LNG exports. A cold snap that pulls on salt storage would tighten the market faster than the overall surplus suggests.

The price path is defined. The first target is $3.249, Thursday’s floor pivot resistance. The second is $3.314, the 50-day moving average. The third is $3.338, the 61.8% retracement and Thursday’s settlement area. The primary upside target is $3.40, a retest of Wednesday’s $3.397 high. A move from $3.23 to $3.40 is a gain of 17 cents, or 5.3%.

Beyond $3.40, a close above $3.397 would negate the reversal top and open a move toward $3.50 and the top of the intermediate range at $3.652. That scenario requires a sustained cold pattern into early December.

The bull case does not require a supply shock. It requires the weather to cooperate for 10 days and LNG flows to hold near record levels. Given record exports and a heavily short speculative market, the upside can arrive quickly if forecasts turn.

Bear Case: $3.177 Breaks and $2.83 Comes Back Into View

The downside case depends on mild weather and production growth continuing to fill storage.

The first risk is warm forecasts. If weekend models confirm a return to normal or above-normal temperatures after November 20, the market would lose its main bullish catalyst. December gas would likely fall below $3.177 and confirm the reversal top.

The second risk is production. Output has recovered from 109.2 Bcf/d on November 3 to 112.2 Bcf/d, and producers restored curtailed volumes as prices rose. A return toward the August record of 115.0 Bcf/d in December would push storage builds higher.

The third risk is storage. Inventories sit 54 Bcf above the five-year average after a 61 Bcf build. Another above-average injection on November 19 would widen the surplus further and reinforce the EIA’s mild-winter forecast.

The fourth risk is the EIA’s price path. The agency expects Henry Hub to average $2.87 from November through March. Futures at $3.23 sit 12.5% above that forecast. If the EIA’s mild-weather assumption holds, futures have room to fall.

The fifth risk is LNG disruption. An outage at a major export plant would cut feedgas by 1 to 2 Bcf/d and release gas back into the domestic market. A feedgas print below 18 Bcf/d would signal a warning for the December contract.

The sixth risk is expiry pressure. Funds holding long positions in December must sell or roll before November 25. If weather stays mild, that selling could push the contract lower in the final days of trading.

The price path is clear. A trade below $3.177 confirms the closing price reversal top. The first target is $3.114, the top of the short-term retracement zone. The second is $3.047, the bottom of that zone. The third is $3.00, the round-number floor that held through November. A move from $3.23 to $3.00 is a decline of 23 cents, or 7.1%. Below that, the main bottom at $2.830 is the trend-change level, a decline of 12.4%.

The bear case would accelerate if weekend forecasts erase the November 16 to 20 cold, if production returns above 113 Bcf/d, or if the November 19 report shows another build above 60 Bcf. Any two of those together would put $3.00 in play before expiry. A December settlement near $3.00 would leave the January contract starting its run as front month with a storage surplus near 80 Bcf and a mild-weather forecast, a weak setup for the first full month of winter.

Verdict: Neutral Between $3.177 and $3.314, Upside Target $3.40 on Extended Cold

December natural gas futures enter the weekend at $3.23, down 3.2% on Friday but up 7.8% on the week. The contract rallied from $2.997 to a three-week high of $3.397 on record LNG demand, lower production and cold forecasts, then gave back part of the gain as forecasts turned warmer and storage kept building.

The fundamental tension is clear. LNG feedgas above 20 Bcf/d sets a demand floor, and the record speculative short gives the market fuel for rallies on any cold forecast. Against that, storage sits 54 Bcf above the five-year average after a 61 Bcf build that was 21 Bcf above normal, production is recovering toward 113 Bcf/d, and the EIA expects a mild November to leave 3,840 Bcf in storage at month-end with Henry Hub averaging $2.87 through March.

The levels are defined. On the upside, $3.249 is the first resistance, $3.314 the 50-day moving average, $3.338 the 61.8% retracement, and $3.40 the upside target, a 5.3% gain. On the downside, $3.177 is the reversal trigger, with $3.114, $3.047, $3.00 and the main bottom at $2.830 below. A move to $3.40 needs 17 cents and a move to $3.00 needs a 23-cent drop, so the risk-reward from current levels stays balanced until the weather picture clears.

The catalysts are close. Weekend weather models will set Monday’s direction. Daily LNG feedgas data will show whether flows hold above 20 Bcf/d. The EIA’s next storage report arrives November 19. The December contract expires November 25. Each of those events can move prices by 10 to 20 cents.

The verdict for traders: December natural gas is neutral between $3.177 and $3.314. A trade below $3.177 confirms the reversal top and opens $3.047 to $3.114. A daily close above $3.314 restores the uptrend and puts the $3.40 target in reach before expiry. The key driver is whether the cold forecast for November 16 to 20 extends into the final week of the month. If it does, record LNG demand and a heavily short market can carry December gas back to $3.40. If it does not, the storage surplus and recovering production will push the contract toward $3.00 into expiry, and the January contract will inherit the fight over whether winter cold can overcome a well-supplied market.

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