NG Reclaims $3 as 21.2 Bcf/d LNG Demand Meets a Mild November, 3,801 Bcf in Storage — $2.80–$3.25 Range Into the December Expiry

December natural gas futures on the New York Mercantile Exchange rose 2% on Friday to trade at $3.007 per million British thermal units. Colder revisions to weather forecasts and LNG feedgas on track for a daily record lifted the contract back above the $3.00 level it has failed to hold for most of the past three weeks. December closed Thursday at $2.948 after a quiet session. It has risen from $2.856 on Monday, a gain of 5.3% this week, and is 3.3% above the October 30 close of $2.910. The contract expires on November 25.

The physical market is weaker than the futures price. Next-day gas at Henry Hub, Louisiana, settled at $2.63 on November 3, after falling to $2.42 on October 30 and $2.52 on October 27, its lowest level since November 2024. The November contract expired on October 28 at $2.776. The spot market and the expiring contract both traded well below the $3.00 handle that December is now testing, and that gap shows how much of December’s price relies on expected winter demand rather than current demand.

Our thesis is that natural gas is caught between two forces of similar size, and neither is strong enough to break the range before December expires. LNG exports provide a structural floor. Feedgas to US export plants hit 21.2 Bcf per day this week and is heading for a daily record on Friday, with global prices more than ten times Henry Hub because of the Iran war. Production has slipped from a monthly record of 115.0 Bcf/d in August to 111.2 Bcf/d so far in November. Against that, the EIA’s weekly storage report showed inventories at 3,801 Bcf, 54 Bcf above the five-year average, and the November weather outlook is exceptionally mild. Injections are expected to continue until November 20.

The futures curve confirms the market is not worried about supply. The premium of March 2027 futures over April 2027 futures, the widow-maker spread that measures fear of a late-winter shortage, fell to a record low of 5 cents. The 12-month strip fell to a 26-month low of $2.84 in late October. Funds have held net short positions for 36 straight weeks.

Our base case through the December expiry on November 25 is a range of $2.80 to $3.25, with a midpoint of $3.03. A cold pattern arriving in the second half of November would push December to $3.40, 13% above the current price, close to the EIA’s $3.47 forecast for the first quarter of 2027. A continued mild pattern with storage injections running into late November would send the contract toward $2.60, 13.5% lower, where it would meet the spot market.

The Week: $2.856 to $3.007 on Lower Output and Cooler Forecasts

The December contract became the front month after November expired on Wednesday, October 28, at $2.776, up 7.9 cents on its final session. On the roll, December traded near $3.06. The following two sessions undid that. Bearish weather forecasts and a large storage build pushed December down 2.64% on October 29 and 1.83% on October 30 to $2.910. Spot gas at Henry Hub fell to $2.42 on October 30, as mild temperatures across the country cut heating demand.

The week began with more pressure. On Monday, November 2, December fell 1.45% to $2.856, its lowest close of the week, failing to break through $3.00 as two-week weather forecasts stayed overwhelmingly mild. Henry Hub spot recovered to $2.54. The contract’s intraday high of $2.977 that day showed sellers were still defending the $3.00 level.

The turn came on Tuesday. December rose 1.37% to $2.895 as production data showed output falling in recent days. Lower 48 output dropped to 111.2 Bcf/d in the first days of November from 113.4 Bcf/d in October, and some daily readings came in at 110.0 Bcf/d. Henry Hub spot rose to $2.63. On Wednesday, December added 1.73% to $2.945, reaching an intraday high of exactly $3.000, as LNG feedgas rebounded and two-week forecasts turned slightly cooler for mid-November.

Thursday was a test. The EIA’s storage report for the week ended October 30 showed a 77 Bcf injection, below the 81 Bcf the market expected but well above historical norms for the week. December traded between $2.930 and $2.956 and closed at $2.948, up 0.10%. Supportive production and LNG data offset the size of the injection, and the market treated the report as neutral.

Friday brought the break above $3.00. Cooler forecast revisions, falling output and LNG feedgas on course for a daily record lifted December 2% to $3.007 in early trading. It is the first time since the roll that December has traded convincingly above $3.00. The contract is up 5.3% from Monday’s close, but it remains below the $3.06 roll price and the October 28 intraday high of $3.093. The week has repaired some of the damage from late October without changing the broader range.

Storage: 3,801 Bcf, 54 Bcf Above the Five-Year Average

The EIA reported a net injection of 77 Bcf for the week ended October 30, bringing working gas in storage to 3,801 Bcf. That is 109 Bcf, or 2.8%, below the same week last year, and 54 Bcf, or 1.4%, above the five-year average of 3,747 Bcf. Every storage region except the Pacific added gas, and every region except South Central and South Central salt sits above its five-year average. Total inventories are within the five-year historical range.

The injection was smaller than expected but large for the season. The market had forecast an 81 Bcf build, so the result was 4 Bcf tighter than consensus. Against the five-year average for the same week, it was 16 Bcf larger, which widened the surplus. On a weather-adjusted basis, the injection was 1.0 Bcf/d, or 7 Bcf a week, tighter than the five-year norm, so higher-than-normal demand would have produced a build of 89 Bcf. That points to a market where LNG exports are absorbing supply even as mild weather limits heating demand.

The storage surplus has been rebuilding after a long decline. On August 7, inventories were 198 Bcf above the five-year average. Ten consecutive below-normal injections cut that surplus to 35 Bcf by mid-October. The week ended October 9 brought a 67 Bcf build against a five-year norm of 89 to 90 Bcf. The weeks ended October 16, October 23 and October 30 added 77 Bcf, 80 Bcf and 77 Bcf. The surplus widened to 38 Bcf and then to 54 Bcf, and mild November weather will keep it growing.

The EIA’s October Short-Term Energy Outlook expected inventories of 3,850 Bcf at the end of October, 2% above the five-year average, to begin the heating season. The actual number is 49 Bcf short of that forecast, so the market starts winter tighter than the EIA expected. With injections forecast to continue until November 20, inventories could reach 3,900 Bcf or more before the first withdrawal. That is close to the levels the US entered the past two winters with, the highest since 2016.

For the forecast, storage limits the upside. A surplus of 54 Bcf is modest, but it is growing in a month when the market normally starts to draw down. The year-on-year deficit of 109 Bcf provides some support, since last winter began with more gas. But traders price winter risk against the five-year average, and on that measure, the US has enough gas in storage to handle an average winter without stress.

LNG Feedgas: 21.2 Bcf/d and On Track for a Record

LNG exports are the most important support for US natural gas prices. Feedgas to US export plants jumped 2.8 Bcf/d to 21.2 Bcf/d this week, close to record levels, as plants returned from maintenance and new liquefaction capacity came online. On Friday, daily feedgas was on track for a record high. Feedgas hit 20.8 Bcf/d on a daily basis in October, and the nine major export plants averaged 18.4 Bcf/d for the month, up from 17.9 Bcf/d in September.

The monthly averages look softer. Flows to the nine major plants slid to 18.1 Bcf/d in the first days of November, below October’s 18.4 Bcf/d and the monthly record of 18.8 Bcf/d set in April. Day-to-day feedgas swings with plant maintenance, weather on the Gulf Coast and the timing of tanker arrivals. A record daily reading on Friday shows capacity is available, but sustaining that level over the full month will depend on plants running without outages.

Global prices give US exporters every incentive to run at full capacity. Gas at the Dutch TTF benchmark and the Japan-Korea Marker traded near 46-month highs of $32 per MMBtu in late October. TTF reached €103.94 per megawatt-hour, eleven times Henry Hub. The Iran war, which began on February 28, has disrupted LNG shipments from Qatar through the Strait of Hormuz, and buyers in Europe and Asia have turned to US cargoes. US LNG exports to Europe reached 6.89 million tons in October, the second-highest monthly total on record.

The US cannot export more gas than its plants can liquefy. US prices have reacted little to the global spike, because the country produces all the gas it consumes and its LNG plants are already running at capacity. Higher international prices widen margins for exporters but do not raise US demand. New liquefaction units under construction will add capacity as they come online, and each new train adds demand that cannot be reversed by weather.

For the forecast, LNG sets the floor. With feedgas near 21 Bcf/d, exports are absorbing about 19% of Lower 48 production. Even in a mild November, that demand keeps the storage build smaller than it would otherwise be. A drop in feedgas from an outage or maintenance would remove that support quickly and push December toward $2.70. A sustained record pace would keep December above $2.90, even with mild weather.

Production: From a 115.0 Bcf/d Record to 111.2 Bcf/d

Production has been falling from record highs. Lower 48 output averaged a monthly record of 115.0 Bcf/d in August, held near 113.3 Bcf/d in September and fell to 113.4 Bcf/d in October. In the first days of November, it has averaged 111.2 Bcf/d, with some daily readings at 110.0 Bcf/d. From the August record, that is a decline of 3.8 Bcf/d, or 3.3%.

Several factors explain the drop. Producers routinely schedule maintenance in the shoulder months between summer cooling demand and winter heating demand. Low spot prices, with Henry Hub at $2.42 on October 30 and $2.52 on October 27, its lowest since November 2024, gave producers in gas-focused basins less reason to run at full rates. Some producers have also curtailed output in response to weak prices, holding wells in reserve until the winter strip rewards them.

The decline has not changed the year’s picture. Dry gas production was on pace for an annual record in 2026, averaging 113 Bcf/d in August and September. Record output and a mild spring kept inventories above the five-year average every week since March, peaking at 7.7% above normal in April. The EIA’s outlook expects production to reach a record 116.1 Bcf/d in 2027, outpacing new LNG demand and keeping prices lower on average.

Associated gas from oil drilling adds supply that does not respond to gas prices. With Brent near $97 a barrel and WTI near $90.52, oil drilling in the Permian Basin remains profitable. Each new oil well produces gas as a byproduct, and that gas flows into the market whatever Henry Hub pays. The oil price fell 12% to 16% this week on hopes of a US-Iran deal, but it remains high enough to keep associated gas growing.

For the forecast, the production dip is temporary support. Output at 111.2 Bcf/d is the main reason December rallied this week, and it helped turn Thursday’s storage report from bearish to neutral. But producers can bring back volumes quickly once prices recover above $3.00. A return to 113 Bcf/d would add 1.8 Bcf/d of supply, enough to offset a large part of any weather-driven demand gain. Production caps rallies more than it supports dips.

Weather: An Exceptionally Mild November With Cooler Revisions

Weather is the biggest short-term driver of natural gas, and the November outlook has been bearish. Two-week forecasts at the start of the week were described as overwhelmingly mild, and heating demand across the country has been dismally low for the season. Spot gas fell to its lowest level in nearly two years in late October because of the warmth, and the November futures contract closed at its lowest level since April 28 before it expired.

The forecasts have started to cool. On Wednesday, two-week outlooks showed seasonally cooler weather in mid-November, which should raise heating demand. Friday’s rally came on further cooler revisions, and temperatures across the central US have started to moderate. Gas demand is rising as the heartland cools. These are small changes against a mild baseline, but in a market priced near $3.00, a few degrees of cooling can move December by 10 to 15 cents.

The big risk is a cold outbreak in late November or December. A polar vortex event in the last two weeks of November would arrive just as December approaches expiry and would push the contract through $3.25. The 52-week range on the continuous contract runs from $2.190 to $7.430, and the high came during a winter cold spike. Cold weather can lift prices sharply even with storage above average, because withdrawals of 200 to 300 Bcf a week can erase a surplus in a few weeks.

The EIA’s winter assumptions are moderate. Its outlook assumes heating degree days this winter will be nearly unchanged from last winter and 1% below the previous five-winter average. Under those conditions, storage provides a buffer against periods of higher demand or lower production. The EIA warns that prolonged cold could increase withdrawals beyond its forecast. Its Q4 Henry Hub forecast is $3.30, and its Q1 2027 forecast is $3.47.

For the forecast, weather will decide which side of the range December tests. The mild pattern has been priced, and cooler revisions are lifting the contract. A cold pattern starting after November 15 would carry December to $3.40. Mild weather through Thanksgiving would leave December to expire near the spot market, between $2.60 and $2.80. Forecasts beyond ten days are unreliable, so the market will continue to swing with each model run.

The Futures Curve: A 5-Cent March-April Spread and a 26-Month-Low Strip

The shape of the futures curve shows how little supply risk the market is pricing. The premium of March 2027 over April 2027, which reflects the risk of shortages at the end of winter, fell to a record low of 5 cents per MMBtu. In tight markets, that spread can widen to more than $1, as traders pay for protection against late-winter shortages. At 5 cents, traders are betting storage will be ample when the heating season ends.

The 12-month strip, the average of the next 12 monthly contracts, fell to a 26-month low of $2.84 in late October. That means the market expects prices to average below $3.00 for the next year, even with record LNG exports and the Iran war. On October 16, the November-to-March winter strip settled at an average of $3.26, so the market still prices some premium for winter months. That premium is modest compared with past winters.

The gap between spot and futures has narrowed this week but remains wide. Henry Hub spot traded at $2.63 on November 3 against a December contract near $2.90. That contango of 27 cents reflects expectations of higher demand later in the month. As December approaches expiry on November 25, the futures price and the spot price must converge. Either the spot market rises as cold weather arrives, or December falls to meet it.

Positioning adds to the bearish structure. Funds have held net short positions in natural gas futures for 36 straight weeks, and they recently held a record net short. Commercial participants, mainly producers and merchants, are also net short as they hedge future production. Open interest across natural gas futures fell by 69,600 contracts in the latest weekly data, a sign that traders are closing positions rather than adding new bets.

For the forecast, the curve and positioning create asymmetric risk. A record fund short in a market with a growing storage surplus can stay short for a long time. But if weather turns cold, those shorts would have to cover quickly, and that buying could push December well above fundamental value. The 5-cent March-April spread shows the market is not prepared for a cold winter, and that unpreparedness is the main upside risk for December.

Global Gas: TTF at 11 Times Henry Hub and the Hormuz Effect

The global gas market is in crisis while the US market is not. TTF in Europe and the Japan-Korea Marker in Asia traded near $32 per MMBtu in late October, their highest levels in 46 months. That is more than ten times the Henry Hub price. The gap reflects the disruption of Qatar’s LNG exports through the Strait of Hormuz since the Iran war began on February 28, along with the long-term loss of Russian pipeline gas to Europe after the 2022 invasion of Ukraine.

Europe is paying the price. Euro-area energy inflation reached 20.8% in October. The Bank of England’s November forecast assumed UK natural gas at 216 pence per therm, 81% above its July assumption. European storage facilities have struggled to refill, and governments are preparing for a winter in which LNG cargoes from the US will matter more than ever. US cargoes to Europe reached 6.89 million tons in October.

The US price barely responds because export capacity is fixed in the short term. US LNG plants are already liquefying as much gas as they can, and new trains under construction will not add capacity fast enough to change winter balances. Higher global prices widen exporters’ margins but do not create more demand for US gas. Henry Hub responds to domestic weather and production, not to TTF.

A peace deal with Iran would affect global prices more than US prices. If Hormuz reopens and Qatar’s exports normalize, TTF and the Japan-Korea Marker would fall sharply, narrowing the gap with Henry Hub. US exports would stay near capacity, because even at half the current global price, exporting US gas remains highly profitable. The oil market priced a deal this week, sending Brent down 12% to 16%, but gas markets have not reacted the same way.

For the forecast, global gas is a background support for US prices, not a driver. As long as TTF stays at multiples of Henry Hub, US LNG plants will run at full capacity and absorb 21 Bcf/d of supply. That demand cannot rise much further this winter, so global prices will not push Henry Hub higher. What they guarantee is that LNG demand will not fall, and that sets the floor under December.

Power Burn and Coal Switching at $3.00 Gas

Electricity generation is the second-largest source of US gas demand, and it responds to price. At Henry Hub prices below $3.00, gas is cheaper than coal for most power plants, and generators burn more gas. When prices rise above $3.50, some generators switch back to coal. That switching creates a natural buffer: lower gas prices increase power demand, and higher prices reduce it.

The current price sits in a zone where gas remains competitive. With spot gas between $2.42 and $2.63 in recent days and December near $3.00, power plants have strong incentives to burn gas. The US electricity mix in late 2025 had gas at 36% of generation, coal at 16%, nuclear at 20% and renewables making up most of the rest. Demand growth from data centers has added a structural layer of electricity demand that did not exist five years ago.

That data-center demand faces new uncertainty. Thursday’s sell-off in technology stocks came on fears that a Democratic Congress would regulate AI and data-center expansion more tightly. The Nasdaq fell 5.52% and the Philadelphia semiconductor index dropped more than 12%. Data centers are major consumers of electricity, and much of that power comes from natural gas. Slower data-center growth would cut one of the most important sources of long-term gas demand growth.

The near-term effect is limited. Data centers under construction will be completed, and electricity demand from existing facilities will not fall. Regulation from the new Congress, which takes office on January 3, 2027, would take months or years to affect construction plans. But the gas market priced part of its long-term bullish case on AI-driven power demand, and any slowdown in that story weakens the argument for higher prices in 2027 and beyond.

For the forecast, power burn is a stabilizer near $3.00. Lower prices increase gas use in power plants, which supports the floor at $2.80. Higher prices above $3.50 would reduce power burn and limit rallies. Within the $2.80 to $3.25 range, power demand does not drive the price but keeps it from moving too far in either direction. Weather and LNG decide where December trades within that range.

The EIA Outlook: $3.30 for Q4, $3.47 for Q1 2027, $3.16 for 2027

The EIA’s Short-Term Energy Outlook frames the medium-term view. It expects Henry Hub to average $3.30 in the fourth quarter of 2026 and $3.47 in the first quarter of 2027. For the full year, it expects $3.48 in 2026 and $3.16 in 2027. The lower 2027 forecast reflects dry gas production rising to a record 116.1 Bcf/d, outpacing growth in LNG demand.

The fourth-quarter forecast implies higher prices from here. With October spot averaging $2.99 and November starting with spot near $2.50, December and the rest of the quarter would need to average well above $3.30 to hit the EIA’s number. That would require colder weather than the current outlook suggests. The futures market agrees with the direction but not the size: the winter strip at $3.26 on October 16 was close to the EIA’s view, but prices have fallen since then.

The EIA’s storage forecast supports a comfortable winter. It expected inventories of 3,850 Bcf at the end of October, 2% above the five-year average. The actual level is 3,801 Bcf, 49 Bcf lower. The EIA notes that inventories can build into mid-November depending on weather, and they are likely to do so this year. Its winter forecast assumes storage stays above the rolling five-year average in most months, because production growth keeps pace with rising LNG exports and domestic demand.

The long-term outlook is more bullish. The EIA’s Annual Energy Outlook, published in April, expects Henry Hub to rise through the early 2030s, staying between $5 and $6 per MMBtu in most cases before declining after 2040. That forecast reflects LNG export capacity roughly doubling and domestic demand growth from power generation and industry. Energy executives surveyed by a regional Federal Reserve bank expect $4.28 in five years.

For the forecast, the EIA’s numbers point to modest upside from current levels. December at $3.007 sits 9% below the EIA’s Q4 average and 13% below its Q1 forecast. Those forecasts assume normal winter weather. If the winter is normal, prices should drift higher. If it is mild, the EIA’s numbers will be revised down. The EIA’s next outlook arrives in December, after the December contract expires.

The Technical Map: $3.00 Pivot, $3.093 Resistance, $2.85 Support

The $3.00 level is the pivot for December natural gas. The contract failed to break above $3.00 on Monday, reached exactly $3.000 intraday on Wednesday, held below it Thursday and broke above it on Friday. A daily settlement above $3.00 would confirm the breakout and turn the level into support. A failure to close above it would leave the contract in the $2.85 to $3.00 range that has held this week.

The first resistance above $3.00 is the October 28 intraday high of $3.093, followed by the $3.06 roll price. A move through $3.093 would open the $3.25 level, the top of our base-case range and close to the winter strip settlement of $3.26 on October 16. Above $3.25, the next target is $3.30, the EIA’s fourth-quarter average forecast, and then $3.40, where the contract would price a cold late-November pattern. From $3.007, $3.25 is 8% higher and $3.40 is 13% higher.

Support starts at $2.948, Thursday’s close, followed by the $2.85 to $2.86 zone where December found buyers on Monday and Tuesday. Below that, $2.80 is the bottom of our base-case range and a level the contract held through Thursday’s storage report. A break below $2.80 would point to $2.776, the November expiry price, and then $2.60 to $2.65, the zone where spot Henry Hub gas traded this week.

The technical picture has improved this week. The contract has posted four straight higher closes, from $2.856 on Monday to $2.948 on Thursday, with Friday adding another gain. It closed Monday at its lowest level of the week and has made higher lows since. The November contract was technically oversold for five straight sessions in late October, the longest stretch since April, and that oversold condition has started to unwind.

Volatility is high and will rise into expiry. Daily ranges of 10 to 16 cents are normal, and Wednesday’s intraday swing from $2.840 to $3.000 covered 16 cents. As the December contract approaches its November 25 expiry, liquidity will move to January, and price swings in December can become erratic. Traders should treat these levels as zones rather than exact lines and expect weather-model updates to move the contract by several percent in a single session.

Scenario Map: $3.40 Upside, $2.80–$3.25 Base, $2.60 Downside

Our forecast covers the period through the December contract’s expiry on November 25, with three scenarios.

The base case, at 50% probability, is a range of $2.80 to $3.25, with a midpoint of $3.03. In this scenario, the second half of November brings seasonal temperatures without a sustained cold outbreak. LNG feedgas stays between 19 and 21 Bcf/d, and production recovers toward 112 Bcf/d as prices hold near $3.00. Storage injections continue through November 20 and push inventories toward 3,900 Bcf, keeping the surplus to the five-year average between 50 and 70 Bcf. December trades between the $2.85 support and the $3.093 resistance and expires near $3.00.

The bullish case, at 25% probability, is a rally to $3.40, 13% above the current price. This would need a cold pattern arriving after November 15, with the first storage withdrawal coming earlier than expected. LNG feedgas would need to set a sustained record above 21 Bcf/d, and production would need to stay near 110 to 111 Bcf/d. Record fund short positions would have to cover, adding buying pressure. December would break through $3.093 and $3.25 and approach the EIA’s Q1 2027 forecast of $3.47.

The bearish case, at 25% probability, is a fall to $2.60, 13.5% below the current price. This would follow a continued mild pattern through Thanksgiving, with injections running into the last week of November and the storage surplus widening above 80 Bcf. Production would rebound to 113 Bcf/d, and an LNG plant outage would cut feedgas below 19 Bcf/d. December would break below $2.80 and converge with the spot market, which traded between $2.42 and $2.63 in recent days.

From $3.007, the risk-reward is balanced. The bullish target is 13% higher, the bearish target 13.5% lower, and the two scenarios carry equal probability. The base-case midpoint of $3.03 is less than 1% above the current price. The signals that will decide which scenario plays out, in order of importance, are the 6-to-10-day and 8-to-14-day weather forecasts, daily LNG feedgas, daily production, next Thursday’s EIA storage report, and the date of the first storage withdrawal.

Verdict: Neutral With an Upside Tilt, Buy Dips Toward $2.85, Sell Rallies Into $3.25

December natural gas at $3.007 has gained 5.3% this week and broken back above $3.00 for the first time since the contract became the front month. Falling production, LNG feedgas heading for a daily record and cooler forecast revisions drove the rally. The contract is still below the $3.06 roll price and the $3.093 October high. Spot gas at Henry Hub traded at $2.63 on November 3, well below the futures price, and that gap has to close before the December contract expires on November 25.

The supports are structural. LNG feedgas at 21.2 Bcf/d absorbs about 19% of Lower 48 production, and global prices more than ten times Henry Hub guarantee that US export plants will keep running at capacity. Production has fallen 3.3% from its August record to 111.2 Bcf/d. Storage is 109 Bcf below last year, and the EIA expects Henry Hub to average $3.30 in the fourth quarter and $3.47 in the first quarter of 2027.

The headwinds are cyclical but strong. Inventories of 3,801 Bcf are 54 Bcf above the five-year average and still growing. The November weather outlook is exceptionally mild, and injections could continue until November 20. The March-April 2027 spread at a record low of 5 cents and the 12-month strip at a 26-month low show the market sees no supply stress this winter. Funds have been net short for 36 weeks, and producers can bring back output quickly once prices recover.

Our call is neutral with an upside tilt. We would buy dips toward $2.85 to $2.90 and sell rallies into $3.25, within a base-case range of $2.80 to $3.25 and a midpoint target of $3.03 through the November 25 expiry. A daily close above $3.093 would open $3.25 and then $3.40 if a cold pattern arrives in the second half of November. A daily close below $2.80 would invalidate the view and point to $2.60. Until the weather turns, LNG exports will keep December above $2.80 and mild temperatures will keep it below $3.25.

That's TradingNEWS